XNYS:NFG National Fuel Gas Co Quarterly Report 10-Q Filing - 6/30/2012

Effective Date 6/30/2012

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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 quarterly period ended June 30, 2012

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission File Number 1-3880

 

 

NATIONAL FUEL GAS COMPANY

(Exact name of registrant as specified in its charter)

 

 

 

New Jersey   13-1086010

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

6363 Main Street

Williamsville, New York

  14221
(Address of principal executive offices)   (Zip Code)

(716) 857-7000

(Registrant’s telephone number, including area code)

 

 

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 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 Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§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, or a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large Accelerated Filer   x    Accelerated Filer   ¨
Non-accelerated Filer   ¨  (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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

Common stock, $1 par value, outstanding at July 31, 2012: 83,306,912 shares.

 

 

 


Table of Contents

GLOSSARY OF TERMS

Frequently used abbreviations, acronyms, or terms used in this report:

 

National Fuel Gas Companies

  

Company

  

The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure

Distribution Corporation

   National Fuel Gas Distribution Corporation

Empire

   Empire Pipeline, Inc.

ESNE

   Energy Systems North East, LLC

Horizon Power

   Horizon Power, Inc.

Midstream Corporation

   National Fuel Gas Midstream Corporation

Model City

   Model City Energy, LLC

National Fuel

   National Fuel Gas Company

NFR

   National Fuel Resources, Inc.

Registrant

   National Fuel Gas Company

Seneca

   Seneca Resources Corporation

Seneca Energy

   Seneca Energy II, LLC

Supply Corporation

   National Fuel Gas Supply Corporation

Regulatory Agencies

  

EPA

   United States Environmental Protection Agency

FASB

   Financial Accounting Standards Board

FERC

   Federal Energy Regulatory Commission

IASB

   International Accounting Standards Board

NYDEC

   New York State Department of Environmental Conservation

NYPSC

   State of New York Public Service Commission

PaPUC

   Pennsylvania Public Utility Commission

PHMSA

   Pipeline and Hazardous Materials Safety Administration

SEC

   Securities and Exchange Commission

Other

  

2011 Form 10-K

   The Company’s Annual Report on Form 10-K for the year ended September 30, 2011

Bbl

   Barrel (of oil)

Bcf

   Billion cubic feet (of natural gas)

Bcfe (or Mcfe)—represents Bcf (or Mcf) Equivalent

  

The total heat value (Btu) of natural gas and oil expressed as a volume of natural gas. The Company uses a conversion formula of 1 barrel of oil = 6 Mcf of natural gas.

Btu

  

British thermal unit; the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit.

Capital expenditure

  

Represents additions to property, plant, and equipment, or the amount of money a company spends to buy capital assets or upgrade its existing capital assets.

Degree day

  

A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.

Derivative

  

A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, options, no cost collars and swaps.

Development costs

  

Costs incurred to obtain access to proved oil and gas reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.

Dodd-Frank Act

   Dodd-Frank Wall Street Reform and Consumer Protection Act.

 

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Table of Contents

Dth

  

Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.

Exchange Act

   Securities Exchange Act of 1934, as amended

Expenditures for long-lived assets

   Includes capital expenditures, stock acquisitions and/or investments in partnerships.

Exploration costs

  

Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.

Firm transportation and/or storage

  

The transportation and/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized.

GAAP

   Accounting principles generally accepted in the United States of America

Goodwill

  

An intangible asset representing the difference between the fair value of a company and the price at which a company is purchased.

Hedging

  

A method of minimizing the impact of price, interest rate, and/or foreign currency exchange rate changes, often times through the use of derivative financial instruments.

Hub

  

Location where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas.

Interruptible transportation and/or storage

  

The transportation and/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized.

LIBOR

   London Interbank Offered Rate

LIFO

   Last-in, first-out

Marcellus Shale

  

A Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York.

Mbbl

   Thousand barrels (of oil)

Mcf

   Thousand cubic feet (of natural gas)

MD&A

   Management’s Discussion and Analysis of Financial Condition and Results of Operations

MDth

   Thousand decatherms (of natural gas)

MMBtu

   Million British thermal units

MMcf

   Million cubic feet (of natural gas)

NGA

  

The Natural Gas Act of 1938, as amended; the federal law regulating interstate natural gas pipeline and storage companies, among other things, codified beginning at 15 U.S.C. Section 717.

NYMEX

  

New York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas.

Open Season

  

A bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined time period are evaluated as if they had been submitted simultaneously.

PCB

   Polychlorinated Biphenyl

Precedent Agreement

  

An agreement between a pipeline company and a potential customer to sign a service agreement after specified events (called “conditions precedent”) happen, usually within a specified time.

Proved developed reserves

  

Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved undeveloped (PUD) reserves

  

Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required to make these reserves productive.

Reserves

  

The unproduced but recoverable oil and/or gas in place in a formation which has been proven by production.

 

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Table of Contents

Restructuring

  

Generally referring to partial “deregulation” of the pipeline and/or utility industry by statutory or regulatory process. Restructuring of federally regulated natural gas pipelines resulted in the separation (or “unbundling”) of gas commodity service from transportation service for wholesale and large-volume retail markets. State restructuring programs attempt to extend the same process to retail mass markets.

Revenue decoupling mechanism

  

A rate mechanism which adjusts customer rates to render a utility financially indifferent to throughput decreases resulting from conservation.

S&P

   Standard & Poor’s Rating Service

SAR

   Stock appreciation right

Service agreement

  

The binding agreement by which the pipeline company agrees to provide service and the shipper agrees to pay for the service.

Stock acquisitions

   Investments in corporations.

Unbundled service

  

A service that has been separated from other services, with rates charged that reflect only the cost of the separated service.

VEBA

   Voluntary Employees’ Beneficiary Association

WNC

  

Weather normalization clause; a clause in utility rates which adjusts customer rates to allow a utility to recover its normal operating costs calculated at normal temperatures. If temperatures during the measured period are warmer than normal, customer rates are adjusted upward in order to recover projected operating costs. If temperatures during the measured period are colder than normal, customer rates are adjusted downward so that only the projected operating costs will be recovered.

 

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Table of Contents

INDEX

 

           Page  
   Part I. Financial Information   

Item 1. Financial Statements (Unaudited)

  
  

a.       Consolidated Statements of Income and Earnings Reinvested in the Business - Three and Nine Months Ended June 30, 2012 and 2011

     6 - 7   
  

b.       Consolidated Balance Sheets—June 30, 2012 and September 30, 2011

     8 - 9   
  

c.       Consolidated Statements of Cash Flows—Nine Months Ended June 30, 2012 and 2011

     10   
  

d.       Consolidated Statements of Comprehensive Income—Three and Nine Months Ended June 30, 2012 and 2011

     11   
  

e.      Notes to Condensed Consolidated Financial Statements

     12 - 30   

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

     31 - 54   

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     54   

Item 4. Controls and Procedures

     54   
   Part II. Other Information   

Item 1. Legal Proceedings

     54 - 55   

Item 1 A. Risk Factors

     55   

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

     55   

Item 3. Defaults Upon Senior Securities

       

Item 4. Mine Safety Disclosures

       

Item 5. Other Information

       

Item 6. Exhibits

     56   

Signatures

     57   

 

The Company has nothing to report under this item.

Reference to “the Company” in this report means the Registrant or the Registrant and its subsidiaries collectively, as appropriate in the context of the disclosure. All references to a certain year in this report are to the Company’s fiscal year ended September 30 of that year, unless otherwise noted.

This Form 10-Q contains “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-Q at Item 2—MD&A, under the heading “Safe Harbor for Forward-Looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction and other projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions.

 

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Table of Contents

Part I. Financial Information

 

Item 1. Financial Statements

National Fuel Gas Company

Consolidated Statements of Income and Earnings

Reinvested in the Business

(Unaudited)

 

     Three Months Ended
June 30,
 
(Thousands of Dollars, Except Per Common Share Amounts)    2012     2011  

INCOME

    

Operating Revenues

   $ 328,861      $ 380,979   
  

 

 

   

 

 

 

Operating Expenses

    

Purchased Gas

     50,160        112,725   

Operation and Maintenance

     93,749        95,977   

Property, Franchise and Other Taxes

     20,432        20,179   

Depreciation, Depletion and Amortization

     74,227        57,293   
  

 

 

   

 

 

 
     238,568        286,174   
  

 

 

   

 

 

 

Operating Income

     90,293        94,805   

Other Income (Expense):

    

Interest Income

     390        325   

Other Income

     1,086        1,813   

Interest Expense on Long-Term Debt

     (21,529     (17,876

Other Interest Expense

     (828     (1,159
  

 

 

   

 

 

 

Income Before Income Taxes

     69,412        77,908   

Income Tax Expense

     26,228        31,017   
  

 

 

   

 

 

 

Net Income Available for Common Stock

     43,184        46,891   
  

 

 

   

 

 

 

EARNINGS REINVESTED IN THE BUSINESS

    

Balance at April 1

     1,275,107        1,180,531   
  

 

 

   

 

 

 
     1,318,291        1,227,422   

Dividends on Common Stock (2012—$0.365 per share; 2011—$0.355 per share)

     (30,393     (29,358
  

 

 

   

 

 

 

Balance at June 30

   $ 1,287,898      $ 1,198,064   
  

 

 

   

 

 

 

Earnings Per Common Share:

    

Basic:

    

Net Income Available for Common Stock

   $ 0.52      $ 0.57   
  

 

 

   

 

 

 

Diluted:

    

Net Income Available for Common Stock

   $ 0.52      $ 0.56   
  

 

 

   

 

 

 

Weighted Average Common Shares Outstanding:

    

Used in Basic Calculation

     83,227,602        82,687,467   
  

 

 

   

 

 

 

Used in Diluted Calculation

     83,674,823        83,782,493   
  

 

 

   

 

 

 

See Notes to Condensed Consolidated Financial Statements

 

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Table of Contents

National Fuel Gas Company

Consolidated Statements of Income and Earnings

Reinvested in the Business

(Unaudited)

 

     Nine Months Ended
June 30,
 
(Thousands of Dollars, Except Per Common Share Amounts)    2012     2011  

INCOME

    

Operating Revenues

   $ 1,313,593      $ 1,492,808   
  

 

 

   

 

 

 

Operating Expenses

    

Purchased Gas

     390,889        582,358   

Operation and Maintenance

     311,857        310,148   

Property, Franchise and Other Taxes

     70,138        63,714   

Depreciation, Depletion and Amortization

     199,925        170,617   
  

 

 

   

 

 

 
     972,809        1,126,837   
  

 

 

   

 

 

 

Operating Income

     340,784        365,971   

Other Income (Expense):

    

Gain on Sale of Unconsolidated Subsidiaries

     —          50,879   

Interest Income

     1,686        1,277   

Other Income

     4,076        4,130   

Interest Expense on Long-Term Debt

     (60,594     (55,994

Other Interest Expense

     (2,851     (4,014
  

 

 

   

 

 

 

Income Before Income Taxes

     283,101        362,249   

Income Tax Expense

     111,826        141,204   
  

 

 

   

 

 

 

Net Income Available for Common Stock

     171,275        221,045   
  

 

 

   

 

 

 

EARNINGS REINVESTED IN THE BUSINESS

    

Balance at October 1

     1,206,022        1,063,262   
  

 

 

   

 

 

 
     1,377,297        1,284,307   

Dividends on Common Stock (2012—$1.075 per share; 2011—$1.045 per share)

     (89,399     (86,243
  

 

 

   

 

 

 

Balance at June 30

   $ 1,287,898      $ 1,198,064   
  

 

 

   

 

 

 

Earnings Per Common Share:

    

Basic:

    

Net Income Available for Common Stock

   $ 2.06      $ 2.68   
  

 

 

   

 

 

 

Diluted:

    

Net Income Available for Common Stock

   $ 2.05      $ 2.64   
  

 

 

   

 

 

 

Weighted Average Common Shares Outstanding:

    

Used in Basic Calculation

     83,068,083        82,436,603   
  

 

 

   

 

 

 

Used in Diluted Calculation

     83,690,436        83,649,498   
  

 

 

   

 

 

 

See Notes to Condensed Consolidated Financial Statements

 

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Table of Contents

National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)

 

     June 30,
2012
     September 30,
2011
 
(Thousands of Dollars)              

ASSETS

     

Property, Plant and Equipment

   $ 6,438,525       $ 5,646,918   

Less—Accumulated Depreciation, Depletion and Amortization

     1,817,655         1,646,394   
  

 

 

    

 

 

 
     4,620,870         4,000,524   
  

 

 

    

 

 

 

Current Assets

     

Cash and Temporary Cash Investments

     140,815         80,428   

Hedging Collateral Deposits

     3,392         19,701   

Receivables—Net of Allowance for Uncollectible Accounts of $38,538 and $31,039, Respectively

     113,949         131,885   

Unbilled Utility Revenue

     12,212         17,284   

Gas Stored Underground

     24,787         54,325   

Materials and Supplies—at average cost

     28,137         27,932   

Unrecovered Purchased Gas Costs

     2,100         —     

Other Current Assets

     48,246         64,923   

Deferred Income Taxes

     14,727         15,423   
  

 

 

    

 

 

 
     388,365         411,901   
  

 

 

    

 

 

 

Other Assets

     

Recoverable Future Taxes

     147,652         144,377   

Unamortized Debt Expense

     13,991         10,571   

Other Regulatory Assets

     481,900         484,397   

Deferred Charges

     5,781         5,552   

Other Investments

     84,495         79,365   

Goodwill

     5,476         5,476   

Fair Value of Derivative Financial Instruments

     85,905         76,085   

Other

     2,418         2,836   
  

 

 

    

 

 

 
     827,618         808,659   
  

 

 

    

 

 

 

Total Assets

   $ 5,836,853       $ 5,221,084   
  

 

 

    

 

 

 

See Notes to Condensed Consolidated Financial Statements

 

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Table of Contents

National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)

 

     June 30,
2012
    September 30,
2011
 
(Thousands of Dollars)             

CAPITALIZATION AND LIABILITIES

    

Capitalization:

    

Comprehensive Shareholders’ Equity

    

Common Stock, $1 Par Value Authorized —200,000,000 Shares; Issued And Outstanding—83,270,363 Shares and 82,812,677 Shares, Respectively

   $ 83,270      $ 82,813   

Paid in Capital

     666,012        650,749   

Earnings Reinvested in the Business

     1,287,898        1,206,022   
  

 

 

   

 

 

 

Total Common Shareholders’ Equity Before Items of Other Comprehensive Loss

     2,037,180        1,939,584   

Accumulated Other Comprehensive Loss

     (47,940     (47,699
  

 

 

   

 

 

 

Total Comprehensive Shareholders’ Equity

     1,989,240        1,891,885   

Long-Term Debt, Net of Current Portion

     1,149,000        899,000   
  

 

 

   

 

 

 

Total Capitalization

     3,138,240        2,790,885   
  

 

 

   

 

 

 

Current and Accrued Liabilities

    

Notes Payable to Banks and Commercial Paper

     70,200        40,000   

Current Portion of Long-Term Debt

     250,000        150,000   

Accounts Payable

     88,119        126,709   

Amounts Payable to Customers

     17,761        15,519   

Dividends Payable

     30,393        29,399   

Interest Payable on Long-Term Debt

     16,320        25,512   

Customer Advances

     315        19,643   

Customer Security Deposits

     16,847        17,321   

Other Accruals and Current Liabilities

     160,899        108,636   

Fair Value of Derivative Financial Instruments

     16,193        9,728   
  

 

 

   

 

 

 
     667,047        542,467   
  

 

 

   

 

 

 

Deferred Credits

    

Deferred Income Taxes

     1,062,824        955,384   

Taxes Refundable to Customers

     65,554        65,543   

Unamortized Investment Tax Credit

     2,150        2,586   

Cost of Removal Regulatory Liability

     148,668        135,940   

Other Regulatory Liabilities

     39,657        17,177   

Pension and Other Post-Retirement Liabilities

     481,331        481,520   

Asset Retirement Obligations

     78,232        75,731   

Other Deferred Credits

     153,150        153,851   
  

 

 

   

 

 

 
     2,031,566        1,887,732   
  

 

 

   

 

 

 

Commitments and Contingencies

     —          —     
  

 

 

   

 

 

 

Total Capitalization and Liabilities

   $ 5,836,853      $ 5,221,084   
  

 

 

   

 

 

 

See Notes to Condensed Consolidated Financial Statements

 

- 9 -


Table of Contents

National Fuel Gas Company

Consolidated Statements of Cash Flows

(Unaudited)

 

     Nine Months Ended
June 30,
 
(Thousands of Dollars)    2012     2011  

OPERATING ACTIVITIES

    

Net Income Available for Common Stock

   $ 171,275      $ 221,045   

Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:

    

Gain on Sale of Unconsolidated Subsidiaries

     —          (50,879

Depreciation, Depletion and Amortization

     199,925        170,617   

Deferred Income Taxes

     104,948        140,326   

Excess Tax Costs (Benefits) Associated with Stock-Based Compensation Awards

     (1,511     1,224   

Other

     6,618        7,351   

Change in:

    

Hedging Collateral Deposits

     16,309        (26,850

Receivables and Unbilled Utility Revenue

     23,008        (25,919

Gas Stored Underground and Materials and Supplies

     30,853        22,387   

Unrecovered Purchased Gas Costs

     (2,100     —     

Prepayments and Other Current Assets

     18,190        83,541   

Accounts Payable

     (38,590     5,506   

Amounts Payable to Customers

     2,242        (12,448

Customer Advances

     (19,328     (26,617

Customer Security Deposits

     (474     (648

Other Accruals and Current Liabilities

     17,083        36,446   

Other Assets

     (12,796     8,582   

Other Liabilities

     25,338        (17,382
  

 

 

   

 

 

 

Net Cash Provided by Operating Activities

     540,990        536,282   
  

 

 

   

 

 

 

INVESTING ACTIVITIES

    

Capital Expenditures

     (776,896     (583,739

Net Proceeds from Sale of Unconsolidated Subsidiaries

     —          59,365   

Net Proceeds from Sale of Oil and Gas Producing Properties

     —          69,435   

Other

     (1,267     (2,908
  

 

 

   

 

 

 

Net Cash Used in Investing Activities

     (778,163     (457,847
  

 

 

   

 

 

 

FINANCING ACTIVITIES

    

Changes in Notes Payable to Banks and Commercial Paper

     30,200        —     

Excess Tax (Costs) Benefits Associated with Stock-Based Compensation Awards

     1,511        (1,224

Net Proceeds from Issuance of Long-Term Debt

     496,085        —     

Reduction of Long-Term Debt

     (150,000     (200,000

Dividends Paid on Common Stock

     (88,404     (85,201

Net Proceeds from Issuance (Repurchase) of Common Stock

     8,168        (4,471
  

 

 

   

 

 

 

Net Cash Provided by (Used in) Financing Activities

     297,560        (290,896
  

 

 

   

 

 

 

Net Increase (Decrease) in Cash and Temporary Cash Investments

     60,387        (212,461

Cash and Temporary Cash Investments at October 1

     80,428        397,171   
  

 

 

   

 

 

 

Cash and Temporary Cash Investments at June 30

   $ 140,815      $ 184,710   
  

 

 

   

 

 

 

See Notes to Condensed Consolidated Financial Statements

 

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Table of Contents

National Fuel Gas Company

Consolidated Statements of Comprehensive Income

(Unaudited)

 

     Three Months Ended
June 30,
 
(Thousands of Dollars)    2012     2011  

Net Income Available for Common Stock

   $ 43,184      $ 46,891   
  

 

 

   

 

 

 

Other Comprehensive Income (Loss), Before Tax:

    

Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period

     (1,870     23   

Unrealized Gain on Derivative Financial Instruments

Arising During the Period

     30,432        26,378   

Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income

     (21,599     3,185   
  

 

 

   

 

 

 

Other Comprehensive Income, Before Tax

     6,963        29,586   
  

 

 

   

 

 

 

Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) On Securities Available for Sale Arising During the Period

     (701     8   

Income Tax Expense Related to Unrealized Gain on Derivative Financial Instruments Arising During the Period

     12,688        10,810   

Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments In Net Income

     (8,973     1,345   
  

 

 

   

 

 

 

Income Taxes—Net

     3,014        12,163   
  

 

 

   

 

 

 

Other Comprehensive Income

     3,949        17,423   
  

 

 

   

 

 

 

Comprehensive Income

   $ 47,133      $ 64,314   
  

 

 

   

 

 

 

 

     Nine Months Ended
June 30,
 
(Thousands of Dollars)    2012     2011  

Net Income Available for Common Stock

   $ 171,275      $ 221,045   
  

 

 

   

 

 

 

Other Comprehensive Income (Loss), Before Tax:

    

Foreign Currency Translation Adjustment

     —          17   

Reclassification Adjustment for Realized Foreign Currency Translation Loss in Net Income

     —          34   

Unrealized Gain on Securities Available for Sale Arising During the Period

     1,959        3,461   

Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period

     47,085        (41,602

Reclassification Adjustment for Realized Gains on Derivative Financial Instruments in Net Income

     (49,649     (13,080
  

 

 

   

 

 

 

Other Comprehensive Loss, Before Tax

     (605     (51,170
  

 

 

   

 

 

 

Income Tax Expense Related to Unrealized Gain on Securities Available for Sale Arising During the Period

     723        1,306   

Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period

     14,346        (17,136

Reclassification Adjustment for Income Tax Expense on Realized Gains from Derivative Financial Instruments In Net Income

     (15,433     (5,227
  

 

 

   

 

 

 

Income Taxes—Net

     (364     (21,057
  

 

 

   

 

 

 

Other Comprehensive Loss

     (241     (30,113
  

 

 

   

 

 

 

Comprehensive Income

   $ 171,034      $ 190,932   
  

 

 

   

 

 

 

See Notes to Condensed Consolidated Financial Statements

 

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National Fuel Gas Company

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 1—Summary of Significant Accounting Policies

Principles of Consolidation. The Company consolidates all entities in which it has a controlling financial interest. The equity method is used to account for entities in which the Company has a non-controlling financial interest. All significant intercompany balances and transactions are eliminated.

During the quarter ended March 31, 2011, the Company sold its 50% equity method investments in Seneca Energy and Model City for $59.4 million, resulting in a gain of $50.9 million. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties.

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Reclassification. Certain prior year amounts have been reclassified to conform with current year presentation. This includes the reclassification of $63.7 million from Other Regulatory Liabilities to Other Regulatory Assets on the Consolidated Balance Sheet at September 30, 2011. This reclassification pertains to pension and post-retirement benefit regulatory asset and regulatory liability balances. The Company has switched from a “gross” presentation to a “net” presentation, which is consistent with the methodology used by the various regulators in analyzing such regulatory asset and liability balances. This reclassification did not impact the Consolidated Statement of Income. In the Consolidated Statement of Cash Flows for the nine months ended June 30, 2011, the change in Other Liabilities was reduced by $1.9 million and the change in Other Assets was increased by $1.9 million.

The Company also reclassified $26.6 million from Other Regulatory Assets to Other Current Assets and $13.8 million from Other Regulatory Liabilities to Other Accruals and Current Liabilities on the Consolidated Balance Sheet at September 30, 2011. The reclassification was made to distinguish long-term regulatory assets and liabilities from current regulatory assets and liabilities. Current regulatory assets are defined as assets recoverable from ratepayers over a twelve-month period. Current regulatory liabilities are defined as liabilities which will be passed back to ratepayers over a twelve-month period. These reclassifications did not impact the Consolidated Statement of Income. However, the reclassifications did impact the Consolidated Statement of Cash Flows for the nine months ended June 30, 2011. On that statement, the line item labeled Prepayments and Other Current Assets was increased by $13.6 million and the line item labeled Other Assets was reduced by $13.6 million. Additionally, the line item labeled Other Accruals and Current Liabilities was reduced by $0.3 million and the line item labeled Other Liabilities was increased by $0.3 million.

Earnings for Interim Periods. The Company, in its opinion, has included all adjustments that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2011, 2010 and 2009 that are included in the Company’s 2011 Form 10-K. The consolidated financial statements for the year ended September 30, 2012 will be audited by the Company’s independent registered public accounting firm after the end of the fiscal year.

The earnings for the nine months ended June 30, 2012 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2012. Most of the business of the Utility and Energy Marketing segments is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility and Energy Marketing segments, earnings during the winter months normally represent a substantial part of the earnings that those segments are expected to achieve for the entire fiscal year. The Company’s business segments are discussed more fully in Note 7—Business Segment Information.

 

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Consolidated Statement of Cash Flows. For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents.

At June 30, 2012, the Company accrued $98.4 million of capital expenditures. This amount was excluded from the Consolidated Statement of Cash Flows at June 30, 2012 since it represents a non-cash investing activity at that date. Accrued capital expenditures at June 30, 2012 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet.

At September 30, 2011, the Company accrued $72.2 million of capital expenditures. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2011 since it represented a non-cash investing activity at that date. These capital expenditures were paid during the quarter ended December 31, 2011 and have been included in the Consolidated Statement of Cash Flows for the nine months ended June 30, 2012. Accrued capital expenditures at September 30, 2011 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet.

At June 30, 2011, the Company accrued $66.6 million of capital expenditures. This amount was excluded from the Consolidated Statement of Cash Flows at June 30, 2011 since it represented a non-cash investing activity at that date.

At September 30, 2010, the Company accrued $55.5 million of capital expenditures. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2010 since it represented a non-cash investing activity at that date. These capital expenditures were paid during the quarter ended December 31, 2010 and have been included in the Consolidated Statement of Cash Flows for the nine months ended June 30, 2011.

Hedging Collateral Deposits. This is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions. At June 30, 2012, the Company had hedging collateral deposits of $3.4 million related to its exchange-traded futures contracts. At September 30, 2011, the Company had hedging collateral deposits of $5.5 million related to its exchange-traded futures contracts and $14.2 million related to its over-the-counter crude oil swap agreements. In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instruments liability or asset balances.

Gas Stored Underground—Current. In the Utility segment, gas stored underground – current is carried at lower of cost or market, on a LIFO method. Gas stored underground – current normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve, which amounted to $30.5 million at June 30, 2012, is reduced to zero by September 30 of each year as the inventory is replenished.

Property, Plant and Equipment. In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center.

Capitalized costs include costs related to unproved properties, which are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. Such costs amounted to $147.8 million and $226.3 million at June 30, 2012 and September 30, 2011, respectively. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.

 

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In April 2011, the Company completed the sale of its offshore oil and natural gas properties in the Gulf of Mexico. Initial proceeds received through June 30, 2011 totaled $61.8 million. Price adjustments subsequent to June 30, 2011 reduced the final net proceeds to $55.4 million.

Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The natural gas and oil prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. At June 30, 2012, the ceiling exceeded the book value of the oil and gas properties by approximately $107.0 million.

Accumulated Other Comprehensive Loss. The components of Accumulated Other Comprehensive Loss, net of related tax effect, are as follows (in thousands):

 

     At June 30, 2012     At September 30, 2011  

Funded Status of the Pension and Other Post-Retirement Benefit Plans

   $ (89,587   $ (89,587

Net Unrealized Gain on Derivative Financial Instruments

     39,502        40,979   

Net Unrealized Gain on Securities Available for Sale

     2,145        909   
  

 

 

   

 

 

 

Accumulated Other Comprehensive Loss

   $ (47,940   $ (47,699
  

 

 

   

 

 

 

Other Current Assets. The components of the Company’s Other Current Assets are as follows (in thousands):

 

     At June 30, 2012      At September 30, 2011  

Prepayments

   $ 9,762       $ 9,489   

Prepaid Property and Other Taxes

     11,020         13,240   

Federal Income Taxes Receivable

     385         385   

State Income Taxes Receivable

     —           6,124   

Fair Values of Firm Commitments

     5,479         9,096   

Regulatory Assets

     21,600         26,589   
  

 

 

    

 

 

 
   $ 48,246       $ 64,923   
  

 

 

    

 

 

 

Earnings Per Common Share. Basic earnings per common share is computed by dividing net income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the only potentially dilutive securities the Company has outstanding are stock options, SARs and restricted stock units. The diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. Stock options, SARs and restricted stock units that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 976,870 and 833,170 securities excluded as being antidilutive for the quarter and nine months ended June 30, 2012, respectively. There were 6,512 securities excluded as being antidilutive for the quarter ended June 30, 2011. There were no antidilutive securities for the nine months ended June 30, 2011.

 

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Stock-Based Compensation. During the nine months ended June 30, 2012, the Company granted 166,000 non-performance based SARs having a weighted average exercise price of $55.09 per share. The weighted average grant date fair value of these SARs was $11.20 per share. These SARs will be settled in shares of common stock of the Company and are considered equity awards under the current authoritative guidance for stock-based compensation. The accounting for those SARs is the same as the accounting for stock options. The non-performance based SARs granted during the nine months ended June 30, 2012 vest annually in one-third increments and become exercisable on the third anniversary of the date of grant. The weighted average grant date fair value of these non-performance based SARs granted during the nine months ended June 30, 2012 was estimated on the date of grant using the same accounting treatment that is applied for stock options. There were no stock options granted during the nine months ended June 30, 2012.

The Company granted 41,525 restricted share awards (non-vested stock as defined by the current accounting literature) during the nine months ended June 30, 2012. The weighted average fair value of such restricted shares was $55.09 per share. In addition, the Company granted 68,450 restricted stock units during the nine months ended June 30, 2012. The weighted average fair value of such restricted stock units was $47.10 per share for the nine months ended June 30, 2012. Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. These restricted stock units do not entitle the participant to receive dividends during the vesting period. The accounting for these restricted stock units is the same as the accounting for restricted share awards, except that the fair value at the date of grant of the restricted stock units must be reduced by the present value of forgone dividends over the vesting term of the award.

The Company did not fully recognize a tax benefit from excess tax deductions related to stock-based compensation for calendar years 2009 through 2011 due to tax loss carryforwards. The Company expects to recognize additional tax benefits of $32.2 million as an adjustment to Paid in Capital in future years as the tax loss carryforwards are utilized.

New Authoritative Accounting and Financial Reporting Guidance. In May 2011, the FASB issued authoritative guidance regarding fair value measurement as a joint project with the IASB. The objective of the guidance was to bring together as closely as possible the fair value measurement and disclosure guidance issued by the two boards. The guidance includes a few updates to measurement guidance and some enhanced disclosure requirements. For all Level 3 fair value measurements, the guidance requires quantitative information about significant unobservable inputs used and a description of the valuation processes in place. The guidance also requires a qualitative discussion about the sensitivity of recurring Level 3 fair value measurements and information about any transfers between Level 1 and Level 2 of the fair value hierarchy. The new guidance also contains a requirement that all fair value measurements, whether they are recorded on the balance sheet or disclosed in the footnotes, be classified as Level 1, Level 2 or Level 3 within the fair value hierarchy. This authoritative guidance became effective for the quarter ended March 31, 2012. The Company has updated its disclosures to reflect the new requirements in Note 2 – Fair Value Measurements.

In June 2011, the FASB issued authoritative guidance regarding the presentation of comprehensive income. The new guidance allows companies only two choices for presenting net income and other comprehensive income: in a single continuous statement, or in two separate, but consecutive, statements. The guidance eliminates the current option to report other comprehensive income and its components in the statement of changes in equity. This authoritative guidance will be effective as of the Company’s first quarter of fiscal 2013 and is not expected to have a significant impact on the Company’s results of operations.

In September 2011, the FASB issued revised authoritative guidance that simplifies the testing of goodwill for impairment. The revised guidance allows companies the option to perform a “qualitative” assessment to determine whether further impairment testing is necessary. The revised authoritative guidance is required to be effective for the Company’s annual impairment test performed in fiscal 2013. While early adoption is permitted, the Company has not adopted the new provisions to date.

 

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In December 2011, the FASB issued authoritative guidance requiring enhanced disclosures regarding offsetting assets and liabilities. Companies are required to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. This authoritative guidance will be effective as of the Company’s first quarter of fiscal 2014 and is not expected to have a significant impact on the Company’s financial statements.

Note 2—Fair Value Measurements

The FASB authoritative guidance regarding fair value measurements establishes a fair-value hierarchy and prioritizes the inputs used in valuation techniques that measure fair value. Those inputs are prioritized into three levels. Level 1 inputs are unadjusted quoted prices in active markets for assets or liabilities that the Company can 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 at the measurement date. Level 3 inputs are unobservable inputs for the asset or liability at the measurement date. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of June 30, 2012 and September 30, 2011. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

 

Recurring Fair Value Measures    At fair value as of June 30, 2012  

(Thousands of Dollars)

   Level 1      Level 2      Level 3     Netting
Adjustments(1)
    Total  

Assets:

            

Cash Equivalents—Money Market Mutual Funds

   $ 117,813       $ —         $ —        $ —        $ 117,813   

Derivative Financial Instruments:

            

Commodity Futures Contracts—Gas

     4,396         —           —          (4,396     —     

Over the Counter Swaps—Oil

     —           —           3,124        (4,649     (1,525

Over the Counter Swaps—Gas

     —           95,114         —          (7,684     87,430   

Other Investments:

            

Balanced Equity Mutual Fund

     23,629         —           —          —          23,629   

Common Stock—Financial Services Industry

     4,304         —           —          —          4,304   

Other Common Stock

     279         —           —          —          279   

Hedging Collateral Deposits

     3,392         —           —          —          3,392   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Total

   $ 153,813       $ 95,114       $ 3,124      $ (16,729   $ 235,322   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Liabilities:

            

Derivative Financial Instruments:

            

Commodity Futures Contracts—Gas

   $ 5,558       $ —         $ —        $ (4,396   $ 1,162   

Over the Counter Swaps—Oil

     —           —           19,672        (4,649     15,023   

Over the Counter Swaps—Gas

     —           7,692         —          (7,684     8   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Total

   $ 5,558       $ 7,692       $ 19,672      $ (16,729   $ 16,193   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Total Net Assets/(Liabilities)

   $ 148,255       $ 87,422       $ (16,548   $ —        $ 219,129   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

 

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Table of Contents
Recurring Fair Value Measures    At fair value as of September 30, 2011  

(Thousands of Dollars)

   Level 1      Level 2      Level 3     Netting
Adjustments(1)
    Total  

Assets:

            

Cash Equivalents—Money Market Mutual Funds

   $ 32,444       $ —         $ —        $ —        $ 32,444   

Derivative Financial Instruments:

            

Commodity Futures Contracts—Gas

     4,541         —           —          (4,541     —     

Over the Counter Swaps—Gas

     —           75,292         —          (179     75,113   

Over the Counter Swaps—Oil

     —           —           10,420        (9,448     972   

Other Investments:

            

Balanced Equity Mutual Fund

     19,882         —           —          —          19,882   

Common Stock—Financial Services Industry

     4,478         —           —          —          4,478   

Other Common Stock

     226         —           —          —          226   

Hedging Collateral Deposits

     19,701         —           —          —          19,701   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Total

   $ 81,272       $ 75,292       $ 10,420      $ (14,168   $ 152,816   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Liabilities:

            

Derivative Financial Instruments:

            

Commodity Futures Contracts—Gas

   $ 7,833       $ —         $ —          (4,541   $ 3,292   

Over the Counter Swaps—Gas

     —           179         —          (179     —     

Over the Counter Swaps—Oil

     —           —           15,830        (9,448     6,382   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Total

   $ 7,833       $ 179       $ 15,830      $ (14,168   $ 9,674   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Total Net Assets/(Liabilities)

   $ 73,439       $ 75,113       $ (5,410   $ —        $ 143,142   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

 

(1)

Amounts represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties.

Derivative Financial Instruments

At June 30, 2012, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX futures contracts used in the Company’s Energy Marketing and Pipeline and Storage segments (at September 30, 2011, the derivative financial instruments reported in Level 1 consist of NYMEX futures used in the Company’s Energy Marketing segment). Hedging collateral deposits of $3.4 million (at June 30, 2012) and $5.5 million (at September 30, 2011), which are associated with these futures contracts, have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 at June 30, 2012 and September 30, 2011 consist of natural gas price swap agreements used in the Company’s Exploration and Production and Energy Marketing segments. The fair value of the Level 2 price swap agreements is based on an internal, discounted cash flow model that uses observable inputs (i.e. LIBOR based discount rates and basis differential information, if applicable, at active natural gas and crude oil trading markets). The derivative financial instruments reported in Level 3 consist of all of the Company’s Exploration and Production segment’s crude oil price swap agreements at June 30, 2012 and September 30, 2011. Hedging collateral deposits of $14.2 million associated with these crude oil price swap agreements have been reported in Level 1 at September 30, 2011. The fair value of the Level 3 crude oil price swap agreements is based on an internal, discounted cash flow model that uses both observable (i.e. LIBOR based discount rates) and unobservable inputs (i.e. basis differential information of crude oil trading markets with low trading volume).

The significant unobservable input used in the fair value measurement of the over-the-counter crude oil swaps is the basis differential between Midway Sunset oil and NYMEX contracts. Significant changes in the assumed basis differential could result in a significant change in value of the derivative financial instruments. At June 30, 2012, it was assumed that Midway Sunset oil was 111.5% of NYMEX. This is based on a historical twelve month average of Midway Sunset oil sales verses NYMEX settlements. During this twelve-month period, the price of Midway Sunset oil ranged from 103.2% to 125.0% of NYMEX. If the basis differential between Midway Sunset oil and NYMEX contracts used in the fair value measurement calculation at June 30, 2012 had been 10 percentage points lower, the fair value of the Level 3 crude oil price swap agreements would have changed from a net liability of $16.5 million to a net asset of $5.4 million. If the basis differential between Midway Sunset oil and NYMEX contracts used in the fair value measurement

 

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Table of Contents

at June 30, 2012 had been 10 percentage points higher, the fair value measurement of the Level 3 crude oil price swap agreements liability would have been approximately $21.8 million higher. These calculated amounts are based solely on basis differential changes and do not take into account any other changes to the fair value measurement calculation.

Based on an assessment of the counterparties’ credit risk, the fair market value of the price swap agreements reported as Level 2 and Level 3 assets (after netting arrangements) has been reduced by $0.6 million at June 30, 2012 and the fair market value of the price swap agreements reported as Level 2 and Level 3 assets (after netting arrangements) has been reduced by $2.0 million at September 30, 2011. Based on an assessment of the Company’s credit risk, the fair market value of the price swap agreements reported as Level 2 and Level 3 liabilities (after netting arrangements) at June 30, 2012 has been reduced by less than $0.1 million and the fair market value of the price swap agreements reported as Level 3 liabilities (after netting arrangements) has not been reduced at September 30, 2011. These credit reserves were determined by applying default probabilities to the anticipated cash flows that the Company is either expecting from its counterparties or expecting to pay to its counterparties.

The tables listed below provide reconciliations of the beginning and ending net balances for assets and liabilities measured at fair value and classified as Level 3 for the quarters and nine months ended June 30, 2012 and 2011, respectively. For the quarters and nine months ended June 30, 2012 and June 30, 2011, no transfers in or out of Level 1 or Level 2 occurred. There were no purchases or sales of derivative financial instruments during the periods presented in the tables below. All settlements of the derivative financial instruments are reflected in the Gains/Losses Realized and Included in Earnings column of the tables below.

 

                                                                

Fair Value Measurements Using Unobservable Inputs (Level 3)

                                

(Thousands of Dollars)

         Total Gains/Losses                
     April 1,
2012
    (Gains)/
Losses
Realized and

Included in
Earnings
    Gains/(Losses)
Unrealized and
Included in
Other
Comprehensive
Income (Loss)
     Transfer
In/Out of
Level 3
     June 30,
2012
 

Derivative Financial Instruments(2)

   $ (68,754   $ 10,392 (1)    $ 41,814       $ —         $ (16,548
  

 

 

   

 

 

   

 

 

    

 

 

    

 

 

 

 

(1)

Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended June 30, 2012.

(2) 

Derivative Financial Instruments are shown on a net basis.

 

                                                 

Fair Value Measurements Using Unobservable Inputs (Level 3)

                               

(Thousands of Dollars)

         Total Gains/Losses               
     October 1,
2011
    (Gains)/
Losses
Realized and

Included in
Earnings
    Gains/(Losses)
Unrealized and
Included in
Other
Comprehensive
Income (Loss)
    Transfer
In/Out of
Level 3
     June 30,
2012
 

Derivative Financial Instruments(2)

   $ (5,410   $ 36,526 (1)    $ (47,664   $ —         $ (16,548
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

 

(1)

Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the nine months ended June 30, 2012.

(2) 

Derivative Financial Instruments are shown on a net basis.

 

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Table of Contents

Fair Value Measurements Using Unobservable Inputs (Level 3)

                                

(Thousands of Dollars)

         Total Gains/Losses                
     April 1,
2011
    (Gains)/Losses
Realized and

Included in
Earnings
    Gains/(Losses)
Unrealized and
Included in
Other
Comprehensive
Income (Loss)
     Transfer
In/Out of

Level 3
     June 30,
2011
 

Derivative Financial Instruments(2)

   $ (71,913   $ 15,377 (1)    $ 6,083       $ —         $ (50,453
  

 

 

   

 

 

   

 

 

    

 

 

    

 

 

 
(1)

Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended June 30, 2011.

(2) 

Derivative Financial Instruments are shown on a net basis.

 

Fair Value Measurements Using Unobservable Inputs (Level 3)

                               

(Thousands of Dollars)

         Total Gains/Losses               
     October 1,
2010
    (Gains)/Losses
Realized and

Included in
Earnings
    Gains/(Losses)
Unrealized and
Included in
Other
Comprehensive
Income (Loss)
    Transfer
In/Out of

Level 3
     June 30,
2011
 

Derivative Financial Instruments(2)

   $ (16,483   $ 28,545 (1)    $ (62,515   $       $ (50,453
  

 

 

   

 

 

   

 

 

   

 

 

    

 

 

 

 

(1)

Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the nine months ended June 30, 2011.

(2) 

Derivative Financial Instruments are shown on a net basis.

Note 3—Financial Instruments

Long-Term Debt. The fair market value of the Company’s debt, as presented in the table below, was determined using a discounted cash flow model, which incorporates the Company’s credit ratings and current market conditions in determining the yield, and subsequently, the fair market value of the debt. Based on these criteria, the fair market value of long-term debt, including current portion, was as follows (in thousands):

 

     June 30, 2012      September 30, 2011  
     Carrying
Amount
     Fair Value      Carrying
Amount
     Fair Value  

Long-Term Debt

   $ 1,399,000       $ 1,595,554       $ 1,049,000       $ 1,198,585   

The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Carrying amounts for other financial instruments recorded on the Company’s Consolidated Balance Sheets approximate fair value. The fair value of long-term debt was calculated using observable inputs (U.S. Treasuries/LIBOR for the risk free component and company specific credit spread information – generally obtained from recent trade activity in the debt). As such, the Company considers the debt to be Level 2.

Temporary cash investments, notes payable to banks and commercial paper are stated at cost. Temporary cash investments are considered Level 1, while notes payable to banks and commercial paper are considered to be Level 2. Given the short-term nature of the notes payable to banks and commercial paper, the Company believes cost is a reasonable approximation of fair value.

Other Investments. Investments in life insurance are stated at their cash surrender values or net present value as discussed below. Investments in an equity mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices.

 

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Table of Contents

Other investments include cash surrender values of insurance contracts (net present value in the case of split-dollar collateral assignment arrangements) and marketable equity securities. The values of the insurance contracts amounted to $56.3 million and $54.8 million at June 30, 2012 and September 30, 2011, respectively. The fair value of the equity mutual fund was $23.6 million at June 30, 2012 and $19.9 million at September 30, 2011. The gross unrealized gain on this equity mutual fund was $1.4 million at June 30, 2012. The gross unrealized loss on the equity mutual fund was $0.7 million at September 30, 2011. The fair value of the stock of an insurance company was $4.3 million at June 30, 2012 and $4.5 million at September 30, 2011. The gross unrealized gain on this stock was $1.9 million at June 30, 2012 and $2.1 million at September 30, 2011. The insurance contracts and marketable equity securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.

Derivative Financial Instruments. The Company uses derivative instruments to manage commodity price risk in the Exploration and Production, Energy Marketing, and Pipeline and Storage segments. The Company enters into futures contracts and over-the-counter swap agreements for natural gas and crude oil to manage the price risk associated with forecasted sales of gas and oil. The Company also enters into futures contracts and swaps to manage the risk associated with forecasted gas purchases, forecasted gas sales, storage of gas, withdrawal of gas from storage to meet customer demand and the potential decline in the value of gas held in storage. The duration of the Company’s hedges does not typically exceed 5 years.

The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at June 30, 2012 and September 30, 2011. All of the derivative financial instruments reported on those line items related to commodity contracts as discussed in the paragraph above.

Cash flow hedges

For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.

As of June 30, 2012, the Company’s Exploration and Production segment had the following commodity derivative contracts (swaps) outstanding to hedge forecasted sales (where the Company uses short positions (i.e. positions that pay-off in the event of commodity price decline) to mitigate the risk of decreasing revenues and earnings):

 

Commodity

  

Units

    

Natural Gas

   138.9 Bcf (all short positions)   

Crude Oil

   2,529,000 Bbls (all short positions)   

As of June 30, 2012, the Company’s Energy Marketing segment had the following commodity derivative contracts (futures contracts and swaps) outstanding to hedge forecasted sales (where the Company uses short positions to mitigate the risk associated with natural gas price decreases and its impact on decreasing revenues and earnings) and purchases (where the Company uses long positions (i.e. positions that pay-off in the event of commodity price increases) to mitigate the risk of increasing natural gas prices, which would lead to increased purchased gas expense and decreased earnings):

 

Commodity

  

Units

Natural Gas

   6.9 Bcf (5.6 Bcf short positions (mostly forecasted storage withdrawals) and 1.3 Bcf long positions (mostly forecasted storage injections))

As of June 30, 2012, the Company’s Pipeline and Storage segment has the following commodity derivative contracts (futures contracts) outstanding to hedge forecasted sales (where the Company uses short positions to mitigate the risk associated with natural gas price decreases and its impact on decreasing revenues and earnings):

 

Commodity

  

Units

Natural Gas

   2.3 Bcf (all short positions)

 

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Table of Contents

As of June 30, 2012, the Company’s Exploration and Production segment had $69.7 million ($40.6 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that $60.1 million ($35.1 million after tax) of these gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the expected sales of the underlying commodities occur. See Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain (loss) pertaining to derivative financial instruments for the Exploration and Production, Energy Marketing and Pipeline and Storage segments.

As of June 30, 2012, the Company’s Energy Marketing segment had $1.2 million ($0.7 million after tax) of net hedging losses included in the accumulated other comprehensive income (loss) balance. It is expected that the full amount will be reclassified into the Consolidated Statement of Income (Loss) within the next 12 months as the expected sales of the underlying commodity occurs. See Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain (loss) pertaining to derivative financial instruments for the Exploration and Production, Energy Marketing and Pipeline and Storage segments.

As of June 30, 2012, the Company’s Pipeline and Storage segment had $0.7 million ($0.4 million after tax) of net hedging losses included in the accumulated other comprehensive income (loss) balance. It is expected that the full amount will be reclassified into the Consolidated Statement of Income (Loss) within the next 12 months as the expected sales of the underlying commodity occurs. See Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain (loss) pertaining to derivative financial instruments for the Exploration and Production, Energy Marketing and Pipeline and Storage segments.

 

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Table of Contents

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the

Three Months Ended June 30, 2012 and 2011 (Thousands of Dollars)

 

Derivatives in

Cash Flow

Hedging Relationships

   Amount of
Derivative Gain or
(Loss)

Recognized in
Other
Comprehensive
Income (Loss) on

the Consolidated
Statement of
Comprehensive
Income (Loss)
(Effective Portion)
for the Three

Months Ended
June 30,
     Location of
Derivative Gain
or (Loss)
Reclassified
from
Accumulated
Other
Comprehensive
Income (Loss)
on the
Consolidated
Balance Sheet
into the
Consolidated
Statement of
Income
(Effective
Portion)
   Amount of
Derivative Gain or
(Loss)

Reclassified from
Accumulated

Other
Comprehensive
Income (Loss) on the
Consolidated
Balance Sheet

into the Consolidated
Statement of Income
(Effective Portion)
for the Three
Months Ended

June 30,
    Location of
Derivative
Gain or
(Loss)
Recognized
in the
Consolidated
Statement of
Income
(Ineffective
Portion and
Amount
Excluded
from
Effectiveness
Testing)
   Derivative Gain
or (Loss)
Recognized in
the
Consolidated
Statement of
Income
(Ineffective
Portion and
Amount
Excluded from
Effectiveness
Testing) for
the Three
Months
Ended

June 30,
 
     2012     2011           2012      2011          2012      2011  

Commodity Contracts—Exploration & Production segment

   $ 31,358      $ 25,399       Operating
Revenue
   $ 20,643       $ (5,548   Operating
Revenue
   $ —         $ 570   

Commodity Contracts—Energy Marketing segment

   $ (201   $ 737       Purchased
Gas
   $ 956       $ 1,793      Operating
Revenue
   $ —         $ —     

Commodity Contracts—Pipeline & Storage segment

   $ (725   $ 242       Operating
Revenue
   $ —         $ —        Operating
Revenue
   $ —         $ —     
  

 

 

   

 

 

       

 

 

    

 

 

      

 

 

    

 

 

 

Total

   $ 30,432      $ 26,378          $ 21,599       $ (3,755      $ —         $ 570   
  

 

 

   

 

 

       

 

 

    

 

 

      

 

 

    

 

 

 

 

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Table of Contents

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the

Nine Months Ended June 30, 2012 and 2011 (Thousands of Dollars)

 

Derivatives in

Cash Flow

Hedging Relationships

   Amount of Derivative
Gain or (Loss)
Recognized in Other
Comprehensive
Income (Loss) on the
Consolidated
Statement of
Comprehensive
Income (Loss)
(Effective Portion) for
the Nine Months
Ended June 30,
    Location of
Derivative Gain
or (Loss)
Reclassified from
Accumulated
Other
Comprehensive
Income (Loss) on
the Consolidated
Balance Sheet
into the
Consolidated
Statement of
Income

(Effective
Portion)
   Amount of Derivative
Gain or (Loss)
Reclassified from
Accumulated Other
Comprehensive
Income (Loss) on the
Consolidated Balance
Sheet into the
Consolidated
Statement of Income
(Effective Portion)
for the Nine Months
Ended June 30,
     Location of
Derivative
Gain or
(Loss)
Recognized
in the
Consolidated
Statement of
Income
(Ineffective
Portion and
Amount
Excluded
from
Effectiveness
Testing)
   Derivative Gain or
(Loss) Recognized
in the Consolidated
Statement of
Income (Ineffective
Portion and
Amount Excluded
from Effectiveness
Testing) for the
Nine Months Ended

June 30,
 
     2012     2011          2012      2011           2012      2011  

Commodity Contracts—Exploration & Production segment

   $ 40,897      $ (42,969   Operating
Revenue
   $ 38,633       $ 5,415       Operating
Revenue
   $     —         $     570   

Commodity Contracts—Energy Marketing segment

   $ 6,337      $ 1,340      Purchased
Gas
   $ 10,440       $ 7,095       Operating
Revenue
   $ —         $ —     

Commodity Contracts—Pipeline & Storage segment

   $ (149   $ 27      Operating
Revenue
   $ 576       $ —         Operating
Revenue
   $ —         $ —     
  

 

 

   

 

 

      

 

 

    

 

 

       

 

 

    

 

 

 

Total

   $ 47,085      $ (41,602      $ 49,649       $ 12,510          $ —         $ 570   
  

 

 

   

 

 

      

 

 

    

 

 

       

 

 

    

 

 

 

Fair value hedges

The Company’s Energy Marketing segment utilizes fair value hedges to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and the decline in the value of certain natural gas held in storage. With respect to fixed price sales commitments, the Company enters into long positions to mitigate the risk of price increases for natural gas supplies that could occur after the Company enters into fixed price sales agreements with its customers. With respect to fixed price purchase commitments, the Company enters into short positions to mitigate the risk of price decreases that could occur after the Company locks into fixed price purchase deals with its suppliers. With respect to storage hedges, the Company enters into short positions to mitigate the risk of price decreases that could result in a lower of cost or market writedown of the value of natural gas in storage that is recorded in the Company’s financial statements. As of June 30, 2012, the Company’s Energy Marketing segment had fair value hedges covering approximately 10.5 Bcf (8.8 Bcf of fixed price sales commitments (all long positions), 1.4 Bcf of fixed price purchase commitments (all short positions) and 0.3 Bcf of commitments related to the withdrawal of storage gas (all short positions)). For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below.

 

- 23 -


Table of Contents

Consolidated

Statement of Income

   Gain/
(Loss) on Derivative
    Gain/
(Loss) on Commitment
 

Operating Revenues

   $ 4,304,103      $ (4,304,103

Purchased Gas

   $ (196,930   $ 196,930   

 

Derivatives in Fair Value Hedging

Relationships—Energy Marketing

segment

   Location of Derivative
Gain or (Loss)
Recognized in the
Consolidated Statement
of Income
   Amount of
Derivative
Gain or (Loss)
Recognized in the
Consolidated

Statement
of Income for the
Nine
Months Ended

June 30, 2012
(In Thousands)
 

Commodity Contracts—Hedge of fixed price sales commitments of natural gas

   Operating Revenues    $ 4,304   

Commodity Contracts—Hedge of fixed price purchase commitments of natural gas

   Purchased Gas    $ (320

Commodity Contracts—Hedge of natural gas held in storage

   Purchased Gas    $ 123   
     

 

 

 
      $ 4,107   

The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over-the-counter swap positions with twelve counterparties of which eleven are in a net gain position. On average, the Company had $7.8 million of credit exposure per counterparty in a gain position at June 30, 2012. The maximum credit exposure per counterparty in a gain position at June 30, 2012 was $17.1 million. As of June 30, 2012, the Company had not received any collateral from the counterparties having credit-risk related contingency features in their derivative instrument contracts. The Company’s gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral, nor had the counterparties’ credit ratings declined to levels at which the counterparties were required to post collateral.

As of June 30, 2012, ten of the twelve counterparties to the Company’s outstanding derivative instrument contracts (specifically the over-the-counter swaps) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative instrument contracts were in a liability position (or if the current liability were larger) and/or the Company’s credit rating declined, then additional hedging collateral deposits may be required. At June 30, 2012, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $60.6 million according to the Company’s internal model (discussed in Note 2 — Fair Value Measurements). At June 30, 2012, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $15.0 million according to the Company’s internal model (discussed in Note 2 — Fair Value Measurements). For its over-the-counter crude oil swap agreements, which were in a liability position, the Company was not required to post any hedging collateral deposits at June 30, 2012.

For its exchange traded futures contracts, which are in a liability position, the Company had posted $3.4 million in hedging collateral deposits as of June 30, 2012. As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts hedging collateral based on open positions and margin requirements it has with its counterparties.

 

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The Company’s requirement to post hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value. Hedging collateral deposits may also include closed derivative positions in which the broker has not cleared the cash from the account to offset the derivative liability. The Company records liabilities related to closed derivative positions in Other Accruals and Current Liabilities on the Consolidated Balance Sheet. These liabilities are relieved when the broker clears the cash from the hedging collateral deposit account. This is discussed in Note 1 under Hedging Collateral Deposits.

Note 4—Income Taxes

The components of federal and state income taxes included in the Consolidated Statements of Income are as follows (in thousands):

 

     Nine Months Ended
June 30,
 
     2012     2011  

Current Income Taxes

    

Federal

   $ —        $ (1,825

State

     6,878        2,703   

Deferred Income Taxes

    

Federal

     85,910        112,385   

State

     19,038        27,941   
  

 

 

   

 

 

 
     111,826        141,204   

Deferred Investment Tax Credit

     (436     (523
  

 

 

   

 

 

 

Total Income Taxes

   $ 111,390      $ 140,681   
  

 

 

   

 

 

 

Presented as Follows:

    

Other Income

   $ (436   $ (523

Income Tax Expense

     111,826        141,204   
  

 

 

   

 

 

 

Total Income Taxes

   $ 111,390      $ 140,681   
  

 

 

   

 

 

 

Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes. The following is a reconciliation of this difference (in thousands):

 

     Nine Months Ended
June 30,
 
     2012     2011  

U.S. Income Before Income Taxes

   $ 282,665      $ 361,726   
  

 

 

   

 

 

 

Income Tax Expense, Computed at Federal Statutory Rate of 35%

   $ 98,933      $ 126,604   

Increase (Reduction) in Taxes Resulting from:

    

State Income Taxes

     16,845        19,919   

Miscellaneous

     (4,388     (5,842
  

 

 

   

 

 

 

Total Income Taxes

   $ 111,390      $ 140,681   
  

 

 

   

 

 

 

 

- 25 -


Table of Contents

Significant components of the Company’s deferred tax liabilities and assets were as follows (in thousands):

 

     At June 30, 2012     At September 30, 2011  

Deferred Tax Liabilities:

    

Property, Plant and Equipment

   $ 1,227,448      $ 1,062,255   

Pension and Other Post-Retirement Benefit Costs

     205,684        217,302   

Other

     68,995        70,389   
  

 

 

   

 

 

 

Total Deferred Tax Liabilities

     1,502,127        1,349,946   
  

 

 

   

 

 

 

Deferred Tax Assets:

    

Pension and Other Post-Retirement Benefit Costs

     (264,080     (263,606

Tax Loss Carryforwards

     (107,999     (71,516

Other

     (81,951     (74,863
  

 

 

   

 

 

 

Total Deferred Tax Assets

     (454,030     (409,985
  

 

 

   

 

 

 

Total Net Deferred Income Taxes

   $ 1,048,097      $ 939,961   
  

 

 

   

 

 

 

Presented as Follows:

    

Net Deferred Tax Liability/(Asset)—Current

   $ (14,727   $ (15,423

Net Deferred Tax Liability—Non-Current

     1,062,824        955,384   
  

 

 

   

 

 

 

Total Net Deferred Income Taxes

   $ 1,048,097      $ 939,961   
  

 

 

   

 

 

 

As a result of certain realization requirements of the authoritative guidance on stock-based compensation, the table of deferred tax liabilities and assets shown above does not include certain deferred tax assets that arose directly from excess tax deductions related to stock-based compensation. Cumulative tax benefits of $32.2 million and $19.1 million for the periods ending June 30, 2012 and September 30, 2011, respectively, relating to the excess stock-based compensation deductions will be recorded in Paid in Capital in future years when such tax benefits are realized.

Regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $65.6 million and $65.5 million at June 30, 2012 and September 30, 2011, respectively. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of prior ratemaking practices, amounted to $147.7 million and $144.4 million at June 30, 2012 and September 30, 2011, respectively.

The Company files U.S. federal and various state income tax returns. The Internal Revenue Service (IRS) is currently conducting examinations of the Company for fiscal 2011 and fiscal 2012 in accordance with the Compliance Assurance Process (“CAP”). The CAP audit employs a real time review of the Company’s books and tax records by the IRS that is intended to permit issue resolution prior to the filing of the tax return. While the federal statute of limitations remains open for fiscal 2009 and later years, IRS examinations for fiscal 2008 and prior years have been completed and the Company believes such years are effectively settled. During fiscal 2009, consent was received from the IRS National Office approving the Company’s application to change its tax method of accounting for certain capitalized costs relating to its utility property. Local IRS examiners proposed to disallow most of the tax accounting method change recorded by the Company in fiscal 2009 and fiscal 2010. The Company has filed protests for fiscal 2009 and fiscal 2010 with the IRS Appeals Office disputing the local IRS findings.

The Company is also subject to various routine state income tax examinations. The Company’s principal subsidiaries operate mainly in four states which have statutes of limitations that generally expire between three to four years from the date of filing of the income tax return.

 

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Note 5—Capitalization

Common Stock. During the nine months ended June 30, 2012, the Company issued 442,894 original issue shares of common stock as a result of stock option and SARs exercises and 41,525 original issue shares for restricted stock awards (non-vested stock as defined by the current accounting literature for stock-based compensation). In addition, the Company issued 118,523 original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan. The Company also issued 11,705 original issue shares of common stock to the non-employee directors of the Company who receive compensation under the Company’s 2009 Non-Employee Director Equity Compensation Plan, as partial consideration for the directors’ services during the nine months ended June 30, 2012. Holders of stock options, SARs or restricted stock will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding taxes. During the nine months ended June 30, 2012, 156,961 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.

Current Portion of Long-Term Debt. Current Portion of Long-Term Debt at June 30, 2012 consists of $250 million of 5.25% notes that mature in March 2013. Current Portion of Long-Term Debt at September 30, 2011 consisted of $150 million of 6.70% notes that matured in November 2011.

Long-Term Debt. On December 1, 2011, the Company issued $500.0 million of 4.90% notes due December 1, 2021. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $496.1 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of a change in control and a ratings downgrade to a rating below investment grade. The proceeds of this debt issuance were used for general corporate purposes, including refinancing short-term debt that was used to pay the $150 million due at the maturity of the Company’s 6.70% notes in November 2011.

Note 6—Commitments and Contingencies

Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory policies and procedures. It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs.

The Company has agreed with the NYDEC to remediate a former manufactured gas plant site located in New York. In February 2009, the Company received approval from the NYDEC of a Remedial Design Work Plan (RDWP) for this site. In October 2010, the Company submitted a RDWP addendum to conduct additional Preliminary Design Investigation field activities necessary to design a successful remediation. An estimated minimum liability for remediation of this site of $14.0 million has been recorded.

At June 30, 2012, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites (including the former manufactured gas plant site discussed above) will be in the range of $15.5 million to $19.7 million. The minimum estimated liability of $15.5 million, which includes the $14.0 million discussed above, has been recorded in Other Deferred Credits on the Consolidated Balance Sheet at June 30, 2012. The Company expects to recover its environmental clean-up costs through rate recovery.

The Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental regulations, new information or other factors could adversely impact the Company.

Other. The Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost

 

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Table of Contents

issues, among other things. While these other matters arising in the normal course of business could have a material effect on earnings and cash flows in the period in which they are resolved, an estimate of the possible loss or range of loss, if any, cannot be made at this time.

Note 7—Business Segment Information

The Company reports financial results for four segments: Utility, Pipeline and Storage, Exploration and Production, and Energy Marketing. The division of the Company’s operations into reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.

The data presented in the tables below reflect financial information for the segments and reconciliations to consolidated amounts. As stated in the 2011 Form 10-K, the Company evaluates segment performance based on income before discontinued operations, extraordinary items and cumulative effects of changes in accounting (when applicable). When these items are not applicable, the Company evaluates performance based on net income. There have been no changes in the basis of segmentation nor in the basis of measuring segment profit or loss from those used in the Company’s 2011 Form 10-K. As for segment assets, the significant changes from the segment assets disclosed in the 2011 Form 10-K involve the Exploration and Production, Utility, and Pipeline and Storage segments as well as the All Other category. Total Exploration and Production segment assets, Utility segment assets and Pipeline and Storage segment assets have increased by $474.4 million, $28.9 million, and $23.1 million, respectively, during the nine months ended June 30, 2012. The All Other category assets have increased by $35.9 million during the nine months ended June 30, 2012.

 

Quarter Ended June 30, 2012 (Thousands)

 
     Utility      Pipeline and
Storage
     Exploration
and
Production
     Energy
Marketing
     Total
Reportable
Segments
     All Other      Corporate and
Intersegment
Eliminations
    Total
Consolidated
 

Revenue from External Customers

   $ 117,240       $ 36,631       $ 138,549       $ 35,377       $ 327,797       $ 824       $ 240      $ 328,861   

Intersegment Revenues

   $ 2,703       $ 22,076       $ —         $ 579       $ 25,358       $ 4,307       $ (29,665   $ —     

Segment Profit:

                      

Net Income (Loss)

   $ 5,096       $ 12,627       $ 21,915       $ 923       $ 40,561       $ 2,815       $ (192   $ 43,184   

Nine Months Ended June 30, 2012 (Thousands)

 
     Utility      Pipeline and
Storage
     Exploration
and
Production
     Energy
Marketing
     Total
Reportable
Segments
     All Other      Corporate and
Intersegment
Eliminations
    Total
Consolidated
 

Revenue from External Customers

   $ 622,836       $ 113,976       $ 411,449       $ 161,822       $ 1,310,083       $ 2,784       $ 726      $ 1,313,593   

Intersegment Revenues

   $ 12,643       $ 64,434       $ —         $ 1,135       $ 78,212       $ 10,828       $ (89,040   $ —     

Segment Profit:

                      

Net Income (Loss)

   $ 52,725       $ 35,428       $ 74,422       $ 4,662       $ 167,237       $ 5,557       $ (1,519   $ 171,275   

 

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Quarter Ended June 30, 2011 (Thousands)

 
     Utility      Pipeline and
Storage
     Exploration
and
Production
     Energy
Marketing
     Total
Reportable
Segments
     All Other      Corporate and
Intersegment
Eliminations
    Total
Consolidated
 

Revenue from External Customers

   $ 146,215       $ 29,933       $ 130,974       $ 71,746       $ 378,868       $ 1,873       $ 238      $ 380,979   

Intersegment Revenues

   $ 3,475       $ 20,324       $ —         $ 156       $ 23,955       $ 2,810       $ (26,765   $ —     

Segment Profit:

                      

Net Income (Loss)

   $ 6,328       $ 4,503       $ 32,784       $ 1,891       $ 45,506       $ 2,713       $ (1,328   $ 46,891   

Nine Months Ended June 30, 2011 (Thousands)

                                                 
     Utility      Pipeline and
Storage
     Exploration
and
Production
     Energy
Marketing
     Total
Reportable
Segments
     All Other      Corporate and
Intersegment
Eliminations
    Total
Consolidated
 

Revenue from External Customers

   $ 750,802       $ 103,115       $ 388,571       $ 246,719       $ 1,489,207       $ 2,895       $ 706      $ 1,492,808   

Intersegment Revenues

   $ 14,680       $ 60,838       $ —         $ 156       $ 75,674       $ 7,026       $ (82,700   $ —     

Segment Profit:

                      

Net Income (Loss)

   $ 62,399       $ 24,036       $ 93,455       $ 9,122       $ 189,012       $ 34,320       $ (2,287   $ 221,045   

Note 8 – Retirement Plan and Other Post-Retirement Benefits

Components of Net Periodic Benefit Cost (in thousands):

 

Three months ended June 30,  
     Retirement Plan     Other Post-Retirement Benefits  
     2012     2011     2012     2011  

Service Cost

   $ 3,551      $ 3,693      $ 1,004      $ 1,069   

Interest Cost

     10,381        10,669        5,329        5,471   

Expected Return on Plan Assets

     (14,925     (14,776     (7,243     (7,291

Amortization of Prior Service Cost

     67        147        (534     (427

Amortization of Transition Amount

     —          —          3        135   

Amortization of Losses

     9,904        8,718        6,014        5,948   

Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)

     (2,252     (2,346     718        1,602   
  

 

 

   

 

 

   

 

 

   

 

 

 
   $ 6,726      $ 6,105      $ 5,291      $ 6,507   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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Nine months ended June 30,  
     Retirement Plan     Other Post-Retirement Benefits  
     2012     2011     2012     2011  

Service Cost

   $ 10,652      $ 11,079      $ 3,012      $ 3,207   

Interest Cost

     31,144        32,007        15,986        16,413   

Expected Return on Plan Assets

     (44,776     (44,328     (21,728     (21,873

Amortization of Prior Service Cost

     202        441        (1,604     (1,282

Amortization of Transition Amount

     —          —          8        405   

Amortization of Losses

     29,711        26,155        18,043        17,845   

Net Amortization and Deferral for

        

Regulatory Purposes (Including Volumetric Adjustments) (1)

     (1,896     (584     7,993        9,564   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net Periodic Benefit Cost

   $ 25,037      $ 24,770      $ 21,710      $ 24,279   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 

The Company’s policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher throughput of natural gas in the winter months and lower throughput of natural gas in the summer months.

Employer Contributions. During the nine months ended June 30, 2012, the Company contributed $31.8 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $18.9 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits. In the remainder of 2012, the Company expects to contribute $12.2 million to the Retirement Plan. Changes in the discount rate, other actuarial assumptions, and asset performance could ultimately cause the Company to fund larger amounts to the Retirement Plan in fiscal 2012 in order to be in compliance with the Pension Protection Act of 2006. In the remainder of 2012, the Company expects to contribute between $2.0 million and $3.0 million to its VEBA trusts and 401(h) accounts.

In July 2012, the Surface Transportation Extension Act, which is also referred to as the Moving Ahead for Progress in the 21st Century Act (the Act), was passed by Congress and signed by the President. The Act included pension funding stabilization provisions. The Company is currently in the process of evaluating the provisions of the Act.

 

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

Please note that this overview is a high-level summary of items that are discussed in greater detail in subsequent sections of this report.

The Company is a diversified energy holding company that owns a number of subsidiary operating companies, and reports financial results in four reportable business segments. For the quarter ended June 30, 2012 compared to the quarter ended June 30, 2011, the Company experienced a decrease in earnings of $3.7 million. The earnings decrease for the quarter is primarily due to lower earnings in the Exploration and Production segment, Utility segment, and Energy Marketing segment, partially offset by higher earnings in the Pipeline and Storage segment. For the nine months ended June 30, 2012 compared to the nine months ended June 30, 2011, the Company experienced a decrease in earnings of $49.7 million. The earnings decrease for the nine-month period was primarily driven by the recognition of a gain on the sale of unconsolidated subsidiaries of $50.9 million ($31.4 million after tax) during the quarter ended March 31, 2011 in the All Other category that did not recur during the nine months ended June 30, 2012. In February 2011, the Company sold its 50% equity method investments in Seneca Energy and Model City for $59.4 million. Seneca Energy and Model City generated and sold electricity using methane gas obtained from landfills owned by outside parties. The sale was the result of the Company’s strategy to pursue the sale of smaller, non-core assets in order to focus on its core businesses, including the development of the Marcellus Shale and the expansion of its pipeline business throughout the Appalachian region. Lower earnings in the Exploration and Production segment, Utility segment and Energy Marketing segment also contributed to the decrease in earnings for the nine-month period, partly offset by higher earnings in the Pipeline and Storage segment. For further discussion of the Company’s earnings, refer to the Results of Operations section below.

The Company’s natural gas reserve base has grown substantially in recent years from development in the Marcellus Shale, a Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York. Natural gas proved developed and undeveloped reserves in the Appalachian region increased from 331 Bcf at September 30, 2010 to 607 Bcf at September 30, 2011. The Company has spent significant amounts of capital in this region related to the development of such reserves. For the nine months ended June 30, 2012, the Company spent $500.4 million towards the development of the Marcellus Shale. However, while the Company remains focused on the development of the Marcellus Shale, the current low natural gas price environment has caused some significant changes to the Company’s near term plans. First of all, the Company has announced a reduction in drilling activity under its Marcellus Shale joint venture agreement with EOG Resources, Inc. Along with this change, the Company has reduced its estimated capital expenditures in the Appalachian region to $382.5 million for fiscal 2013. Forecasted production in the Appalachian region for fiscal 2013 has been reduced from a range of 80 to 93 Bcfe to a range of 72 to 83 Bcfe.

While the Company’s development of its Marcellus Shale acreage in the Exploration and Production segment has slowed, the Company’s Pipeline and Storage segment continues to build pipeline gathering and transmission facilities to connect Marcellus Shale production with existing pipelines in the region and is pursuing the development of additional pipeline and storage capacity in order to meet anticipated demand for the large amount of Marcellus Shale production expected to come on-line in the months and years to come. One such project, Empire’s Tioga County Extension Project, was placed in service in November 2011. Supply Corporation’s planned Northern Access expansion project is also considered significant. Just like the Tioga County Extension Project, the Northern Access expansion project is designed to receive natural gas produced from the Marcellus Shale and transport it to Canada and the Northeast United States to meet growing demand in those areas. Service for the Northern Access expansion project is expected to begin in November 2012. These projects, which are discussed more completely in the Investing Cash Flow section that follows, have or will involve significant capital expenditures.

From a capital resources perspective, the Company has largely been able to meet its capital expenditure needs for all of the above projects by using cash from operations. In addition, the Company’s December 2011 issuance of $500.0 million of 4.90% notes due in December 2021 enhanced its liquidity position to meet these needs. On January 6, 2012, the Company entered into an Amended and Restated Credit Agreement that replaced the Company’s $300.0 million committed credit facility with a similar committed credit facility totaling $750.0 million that extends to January 6, 2017.

 

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The possibility of environmental risks associated with a well completion technology referred to as hydraulic fracturing continues to be debated. In Pennsylvania, where the Company is focusing its Marcellus Shale development efforts, the permitting and regulatory processes seem to strike a balance between the environmental concerns associated with hydraulic fracturing and the benefits of increased natural gas production. Hydraulic fracturing is a well stimulation technique that has been used for many years, and in the Company’s experience, one that the Company believes has little negative impact to the environment. Nonetheless, the potential for increased state or federal regulation of hydraulic fracturing could impact future costs of drilling in the Marcellus Shale and lead to operational delays or restrictions. There is also the risk that drilling could be prohibited on certain acreage that is prospective for the Marcellus Shale. For example, New York State had a moratorium in place that prevented hydraulic fracturing of new horizontal wells in the Marcellus Shale. The moratorium ended in July 2011 and the NYDEC has issued its recommendations for shale development and production. However, the recommendations have not gone into effect to date. Due to the small amount of Marcellus Shale acreage owned by the Company in New York State, the final outcome of the NYDEC’s recommendations are not expected to have a significant impact on the Company’s plans for Marcellus Shale development. Please refer to the Risk Factors section of the Form 10-K for the year ended September 30, 2011 for further discussion.

CRITICAL ACCOUNTING ESTIMATES

For a complete discussion of critical accounting estimates, refer to “Critical Accounting Estimates” in Item 7 of the Company’s 2011 Form 10-K and Item 2 of the Company’s December 31, 2011 and March 31, 2012 Form 10-Qs. There have been no material changes to those disclosures other than as set forth below. The information presented below updates and should be read in conjunction with the critical accounting estimates in those documents.

Oil and Gas Exploration and Development Costs. The Company, in its Exploration and Production segment, follows the full cost method of accounting for determining the book value of its oil and natural gas properties. In accordance with this methodology, the Company is required to perform a quarterly ceiling test. Under the ceiling test, the present value of future revenues from the Company’s oil and gas reserves based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period (the “ceiling”) is compared with the book value of the Company’s oil and gas properties at the balance sheet date. If the book value of the oil and gas properties exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of the oil and gas properties to the calculated ceiling. At June 30, 2012, the ceiling exceeded the book value of the oil and gas properties by approximately $107.0 million. The 12-month average of the first day of the month price for crude oil for each month during the twelve months ended June 30, 2012, based on posted Midway Sunset prices, was $106.03 per Bbl. The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended June 30, 2012, based on the quoted Henry Hub spot price for natural gas, was $3.15 per MMBtu. (Note – Because actual pricing of the Company’s various producing properties varies depending on their location and hedging, the actual various prices received for such production is utilized to calculate the ceiling, rather than the Midway Sunset and Henry Hub prices, which are only indicative of 12-month average prices for the twelve months ended June 30, 2012.) If natural gas average prices used in the ceiling test calculation at June 30, 2012 had been $1 per MMBtu lower, the book value of the Company’s oil and gas properties would have exceeded the ceiling by approximately $65.8 million, which would have resulted in an impairment charge. If crude oil average prices used in the ceiling test calculation at June 30, 2012 had been $5 per Bbl lower, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately $60.7 million, which would not have resulted in an impairment charge. If both natural gas and crude oil average prices used in the ceiling test calculation at June 30, 2012 were lower by $1 per MMBtu and $5 per Bbl, respectively, the book value of the Company’s oil and gas properties would have exceeded the ceiling by approximately $111.6 million, which would have resulted in an impairment charge. These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation. For a more complete discussion of the full cost method of accounting, refer to “Oil and Gas Exploration and Development Costs” under “Critical Accounting Estimates” in Item 7 of the Company’s 2011 Form 10-K.

 

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RESULTS OF OPERATIONS

Earnings

The Company’s earnings were $43.2 million for the quarter ended June 30, 2012 compared with earnings of $46.9 million for the quarter ended June 30, 2011. The decrease in earnings of $3.7 million is primarily a result of lower earnings in the Exploration and Production segment, Utility segment and Energy Marketing segment. Higher earnings in the Pipeline and Storage segment and the All Other category, as well as a lower loss in the Corporate category partially offset these decreases.

The Company’s earnings were $171.3 million for the nine months ended June 30, 2012 compared to earnings of $221.0 million for the nine months ended June 30, 2011. The decrease in earnings of $49.7 million is primarily a result of lower earnings in the All Other category, Exploration and Production segment, Utility segment and Energy Marketing segment. Higher earnings in the Pipeline and Storage segment and a lower loss in the Corporate category partially offset these decreases. The Company’s earnings for the nine months ended June 30, 2011 include a $50.9 million ($31.4 million after tax) gain on the sale of unconsolidated subsidiaries as a result of the Company’s sale of its 50% equity method investments in Seneca Energy and Model City, as discussed above.

Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. Note that all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted.

Earnings (Loss) by Segment

 

     Three Months Ended
June 30,
    Nine Months Ended
June 30,
 

(Thousands)

   2012     2011     Increase
(Decrease)
    2012     2011     Increase
(Decrease)
 

Utility

   $ 5,096      $ 6,328      $ (1,232   $ 52,725      $ 62,399      $ (9,674

Pipeline and Storage

     12,627        4,503        8,124        35,428        24,036        11,392   

Exploration and Production

     21,915        32,784        (10,869     74,422        93,455        (19,033

Energy Marketing

     923        1,891        (968     4,662        9,122        (4,460
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Reportable Segments

     40,561        45,506        (4,945     167,237        189,012        (21,775

All Other

     2,815        2,713        102        5,557        34,320        (28,763

Corporate

     (192     (1,328     1,136        (1,519     (2,287     768   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Consolidated

   $ 43,184      $ 46,891      $ (3,707   $ 171,275      $ 221,045      $ (49,770
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Utility

Utility Operating Revenues

 

     Three Months Ended
June 30,
    Nine Months Ended
June 30,
 

(Thousands)

   2012      2011      Increase
(Decrease)
    2012      2011      Increase
(Decrease)
 

Retail Sales Revenues:

                

Residential

   $ 82,738       $ 105,001       $ (22,263   $ 438,409       $ 545,786       $ (107,377

Commercial

     9,262         12,474         (3,212     55,115         73,833         (18,718

Industrial

     1,005         807         198        3,703         4,951         (1,248
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 
     93,005         118,282         (25,277     497,227         624,570         (127,343
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Transportation

     24,850         25,016         (166     102,938         105,380         (2,442

Off-System Sales

     —           3,976         (3,976     27,010         29,564         (2,554

Other

     2,088         2,416         (328     8,304         5,968         2,336   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 
   $ 119,943       $ 149,690       $ (29,747   $ 635,479       $ 765,482       $ (130,003
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

 

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Table of Contents

Utility Throughput

 

     Three Months Ended
June 30,
    Nine Months Ended
June 30,
 

(MMcf)

   2012      2011      Increase
(Decrease)
    2012      2011      Increase
(Decrease)
 

Retail Sales:

                

Residential

     7,543         8,867         (1,324     43,476         54,075         (10,599

Commercial

     954         1,203         (249     6,109         8,044         (1,935

Industrial

     168         79         89        456         618         (162
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 
     8,665         10,149         (1,484     50,041         62,737         (12,696
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Transportation

     12,016         12,335         (319     51,663         57,916         (6,253

Off-System Sales

     —           867         (867     9,544         6,188         3,356   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 
     20,681         23,351         (2,670     111,248         126,841         (15,593
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Degree Days

 

                          Percent Colder
(Warmer) Than
 
      Normal      2012      2011      Normal(1)     Prior  Year(1)  

Three Months Ended June 30

             

Buffalo

     927         751         848         (19.0     (11.4

Erie

     885         751         814         (15.1     (7.7
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Nine Months Ended June 30

             

Buffalo

     6,551         5,171         6,674         (21.1     (22.5

Erie

     6,142         4,875         6,286         (20.6     (22.4
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

 

(1) 

Percents compare actual 2012 degree days to normal degree days and actual 2012 degree days to actual 2011 degree days.

2012 Compared with 2011

Operating revenues for the Utility segment decreased $29.7 million for the quarter ended June 30, 2012 as compared with the quarter ended June 30, 2011. This decrease largely resulted from a $25.3 million decrease in retail gas sales revenues. The decrease in retail gas sales revenues was primarily due to warmer weather combined with the recovery of lower gas costs (subject to certain timing variations, gas costs are recovered dollar for dollar in revenues). The recovery of lower gas costs resulted from lower volumes sold combined with a lower cost of purchased gas. The Utility segment’s average cost of purchased gas, including the cost of transportation and storage, was $4.46 per Mcf for the three months ended June 30, 2012, a decrease of 30.6% from the average cost of $6.43 per Mcf for the three months ended June 30, 2011.

Off-system sales decreased from $4.0 million during the quarter ended June 30, 2011 to zero during the quarter ended June 30, 2012. The lack of off-system sales during the quarter ended June 30, 2012 is a result of a change in gas purchase strategy whereby Distribution Corporation has eliminated contractual commitments to purchase gas from the southwest region of the United States during the April through October time period. With the elimination of such commitments, there is a corresponding reduction in the ability to conduct off-system sales. Distribution Corporation intends to meet its gas purchase needs through the spot market during the April through October time frame. It will continue to maintain contractual commitments to purchase gas from the southwest region of the United States during the November through March time period. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal and there is not a material impact to margins.

Operating revenues for the Utility segment decreased $130.0 million for the nine months ended June 30, 2012 as compared with the nine months ended June 30, 2011. This decrease largely resulted from a $127.3 million decrease in retail gas sales revenues. The decrease in retail gas sales revenues was primarily due to warmer weather combined with the recovery of lower gas costs (subject to certain timing

 

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variations, gas costs are recovered dollar for dollar in revenues). The recovery of lower gas costs resulted from lower volumes sold combined with a lower cost of purchased gas. The Utility segment’s average cost of purchased gas, including the cost of transportation and storage, was $5.03 per Mcf for the nine months ended June 30, 2012, a decrease of 19.6% from the average cost of $6.26 per Mcf for the nine months ended June 30, 2011.

The decrease in off-system sales revenues of $2.6 million for the nine months ended June 30, 2012 is primarily a result of the change in gas purchase strategy discussed above for the quarter ending June 30, 2012. Prior to the quarter ending June 30, 2012, off-system sales revenues and volumes had increased over the prior year. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal and there is not a material impact to margins. The decrease in transportation revenues of $2.4 million for the nine months ended June 30, 2012 is primarily due to a 6.3 Bcf decrease in throughput (primarily due to warmer weather). The decrease in transportation revenues was partially offset by a migration of customers from retail sales to transportation services. The $2.3 million increase in other operating revenues for the nine months ended June 30, 2012 was largely attributable to a regulatory adjustment to increase a previous undercollection of pension and other post-retirement benefit costs.

The Utility segment’s earnings for the quarter ended June 30, 2012 were $5.1 million, a decrease of $1.2 million when compared with earnings of $6.3 million for the quarter ended June 30, 2011. The decrease in earnings is largely attributable to warmer weather ($2.3 million). In addition, earnings were negatively impacted by higher depreciation of $0.7 million and higher income tax expense of $0.8 million. The increase in depreciation was largely due to depreciation adjustments for certain assets. The increase in income tax expense was largely due to higher state income tax and a provision to return adjustment recorded in 2012. These decreases were partially offset by lower operating expenses of $0.8 million, lower property, franchise and other taxes of $0.3 million, higher usage per account of $0.7 million and the positive earnings impact of lower interest expense of $0.4 million (largely due to lower interest on deferred gas costs). The phrase “usage per account” refers to average gas consumption per account after factoring out any impact that weather may have had on consumption. The decrease in operating expenses was due to various cost-saving measures. The decrease in property, franchise and other taxes, which includes FICA taxes, is largely due to lower personnel costs and lower property taxes (as a result of a decrease in assessed property values).

The impact of weather variations on earnings in the New York jurisdiction is mitigated by that jurisdiction’s weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segment’s New York customers. For the quarter ended June 30, 2012, the WNC preserved earnings of approximately $1.2 million, as the weather was warmer than normal. For the quarter ended June 30, 2011, the WNC reduced earnings by $0.2 million, as it was colder than normal.

The Utility segment’s earnings for the nine months ended June 30, 2012 were $52.7 million, a decrease of $9.7 million when compared with earnings of $62.4 million for the nine months ended June 30, 2011. The decrease in earnings is largely attributable to warmer weather ($10.0 million). In addition, earnings were negatively impacted by higher depreciation of $1.0 million (as a result of the adjustments discussed above), regulatory true-up adjustments of $0.9 million associated with the Lower Income Residential Assistance Program and higher income tax expense of $1.4 million (as a result of higher state income tax and a provision to return adjustment recorded in 2012). These decreases were partially offset by lower property, franchise and other taxes of $0.7 million, higher usage per account of $0.9 million and the positive earnings impact of lower interest expense of $1.1 million (largely due to lower interest on deferred gas costs). The decrease in property, franchise and other taxes, which includes FICA taxes, is largely due to lower personnel costs and lower property taxes (as a result of a decrease in assessed property values).

For the nine months ended June 30, 2012, the WNC preserved earnings of approximately $5.9 million, as the weather was warmer than normal. For the nine months ended June 30, 2011, the WNC reduced earnings by $1.0 million, as it was colder than normal.

 

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Pipeline and Storage

Pipeline and Storage Operating Revenues

 

                                                           
     Three Months Ended
June 30,
    Nine Months Ended
June 30,
 

(Thousands)

   2012      2011      Increase
(Decrease)
    2012      2011      Increase
(Decrease)
 

Firm Transportation

   $ 40,065       $ 31,208       $ 8,857      $ 124,204       $ 103,448       $ 20,756   

Interruptible Transportation

     318         305         13        1,056         1,035         21   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 
     40,383         31,513         8,870        125,260         104,483         20,777   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Firm Storage Service

     17,226         16,629         597        50,408         50,090         318   

Interruptible Storage Service

     7         —           7        7         19         (12

Other

     1,091         2,115         (1,024     2,735         9,361         (6,626
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 
   $ 58,707       $ 50,257       $ 8,450      $ 178,410       $ 163,953       $ 14,457   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 
Pipeline and Storage Throughput                 
     Three Months Ended
June 30,
    Nine Months Ended
June 30,
 

(MMcf)

   2012      2011      Increase
(Decrease)
    2012      2011      Increase
(Decrease)
 

Firm Transportation

     79,921         53,326         26,595        281,579         266,545         15,034   

Interruptible Transportation

     247         489         (242     1,511         1,709         (198
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 
     80,168         53,815         26,353        283,090         268,254         14,836   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

2012 Compared with 2011

Operating revenues for the Pipeline and Storage segment increased $8.5 million in the quarter ended June 30, 2012 as compared with the quarter ended June 30, 2011. The increase was primarily due to an increase in transportation revenues of $8.9 million, largely due to new contracts for transportation service on Supply Corporation’s Line N Expansion Project, which was placed in service in October 2011, and Empire’s Tioga County Extension Project, which was placed in service in November 2011. Both projects provide pipeline capacity for Marcellus Shale production and are discussed in the Investing Cash Flow section that follows. Additionally, effective May 2012, both transportation and storage revenues increased due to an overall net increase in tariff rates as a result of the implementation of Supply Corporation’s proposed rate case settlement. The rate case and proposed settlement are discussed further in the Rate and Regulatory Matters section. These increases more than offset a reduction in transportation revenues due to the turnback of other pipeline capacity at Niagara. The increase in transportation and storage revenues were partially offset by a decrease in efficiency gas revenues of $1.2 million (reported as a part of other revenue in the table above) resulting from lower natural gas prices and lower efficiency gas volumes. Prior to May 2012, under Supply Corporation’s previous tariff with shippers, Supply Corporation was allowed to retain a set percentage of shipper-supplied gas as compressor fuel and for other operational purposes. To the extent that Supply Corporation did not need all of the gas to cover such operational needs, it was allowed to keep the excess gas as inventory. That inventory would later be sold to buyers on the open market. The excess gas that was retained as inventory, as well as any gains resulting from the sale of such inventory, represented efficiency gas revenue to Supply Corporation. Effective with the implementation of the proposed rate settlement mentioned above, Supply Corporation implemented a tracking mechanism, thus eliminating the impact efficiency gas had to revenues and earnings prior to the proposed rate settlement.

Operating revenues for the Pipeline and Storage segment for the nine months ended June 30, 2012 increased $14.5 million as compared with the nine months ended June 30, 2011. The increase was primarily due to an increase in transportation revenues of $20.8 million, which was primarily the result of new contracts for transportation service on Supply Corporation’s Line N Expansion Project and Empire’s Tioga County Extension Project, as discussed above, which more than offset a decline in transportation revenues due to the turnback of other pipeline capacity at Niagara. The increase in transportation revenues was partially offset by a decrease in efficiency gas revenues of $6.8 million resulting from lower natural gas prices, lower efficiency gas volumes and adjustments to reduce the carrying value of Supply Corporation’s efficiency gas inventory to market value during the nine months ended June 30, 2012. To a lesser extent,

 

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the variations reflect the impact of implementing a proposed rate settlement in May 2012. As discussed above for the quarter, the proposed settlement resulted in higher transportation and storage rates and established a tracking mechanism for gas retained from customers.

Transportation volumes for the quarter ended June 30, 2012 increased by 26.4 Bcf from the prior year’s quarter. For the nine months ended June 30, 2012, transportation volumes increased by 14.8 Bcf from the prior year’s nine-month period. The large increase in transportation volumes for the quarter primarily reflects an increase in deliveries for power generation on Empire’s system. On a year-to-date basis, higher transportation volumes for power generation on Empire’s system during the quarter ended June 30, 2012 more than offset lower transportation volumes experienced by both Supply Corporation and Empire during the first six months of the fiscal year due to warmer weather during the fall and winter. Volume fluctuations generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

The Pipeline and Storage segment’s earnings for the quarter ended June 30, 2012 were $12.6 million, an increase of $8.1 million when compared with earnings of $4.5 million for the quarter ended June 30, 2011. The increase in earnings is primarily due to the earnings impact of higher transportation revenues of $5.8 million, as discussed above, combined with lower operating expenses ($2.1 million) and a lower effective tax rate ($0.8 million). The decrease in operating expenses can be attributed primarily to a decrease in other post-retirement benefits expense, a decline in compressor station maintenance costs, a gain on disposal of property, plant and equipment in the current quarter versus the write-off of expired and unused storage rights in the prior-year quarter and a decrease in the reserve for preliminary project costs. The decrease in other post-retirement benefits expense reflects the implementation of Supply Corporation’s proposed rate settlement. Absent significant changes in actuarial assumptions, it is expected that Supply Corporation will have lower post-retirement benefit costs under this proposed settlement. The proposed settlement does not include a tracking mechanism related to post-retirement benefit costs. The lower effective tax rate was due to a return to provision adjustment in the current quarter. The earnings increases were partially offset by the earnings impact associated with lower efficiency gas revenues ($0.8 million), as discussed above.

The Pipeline and Storage segment’s earnings for the nine months ended June 30, 2012 were $35.4 million, an increase of $11.4 million when compared with earnings of $24.0 million for the nine months ended June 30, 2011. The increase in earnings is primarily due to the earnings impact of higher transportation revenues of $13.5 million, lower operating expenses ($2.0 million) and a lower effective tax rate ($1.0 million), all of which are discussed above, combined with an increase in the allowance for funds used during construction (equity component) of $0.7 million mainly due to construction during the nine months ended June 30, 2012 on Supply Corporation’s Northern Access Expansion Project, Line N 2012 Expansion Project and Empire’s Tioga County Extension Project. These earnings increases were partially offset by the earnings impact associated with lower efficiency gas revenues ($4.4 million), as discussed above, and higher depreciation expense ($1.1 million). The increase in depreciation expense is mostly the result of additional projects that were placed in service in the last year offset partially by a decrease in depreciation rates as of May 2012 as a result of Supply Corporation’s proposed rate case settlement.

Exploration and Production

Exploration and Production Operating Revenues

 

     Three Months Ended
June 30,
    Nine Months Ended
June 30,
 

(Thousands)

   2012     2011     Increase
(Decrease)
    2012     2011     Increase
(Decrease)
 

Gas (after Hedging)

   $ 69,943      $ 70,849      $ (906   $ 201,655      $ 202,114      $ (459

Oil (after Hedging)

     64,664        56,058        8,606        198,056        176,088        21,968   

Gas Processing Plant

     5,966        7,379        (1,413     19,212        20,721        (1,509

Other

     (50     337        (387     108        265        (157

Intrasegment Elimination (1)

     (1,974     (3,649     1,675        (7,582     (10,617     3,035   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
   $ 138,549      $ 130,974      $ 7,575      $ 411,449      $ 388,571      $ 22,878   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 

Represents the elimination of certain West Coast gas production revenue included in “Gas (after Hedging)” in the table above that was sold to the gas processing plant shown in the table above. An elimination for the same dollar amount was made to reduce the gas processing plant’s Purchased Gas expense.

 

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Production Volumes

   Three Months Ended
June 30,
    Nine Months Ended
June 30,
 
      2012      2011     Increase
(Decrease)
    2012      2011      Increase
(Decrease)
 

Gas Production (MMcf)

               

Appalachia

     16,778         12,090        4,688        43,125         31,020         12,105   

West Coast

     1,025         826        199        2,670         2,616         54   

Gulf Coast

     —           22        (22     —           4,092         (4,092
  

 

 

    

 

 

   

 

 

   

 

 

    

 

 

    

 

 

 

Total Production

     17,803         12,938        4,865        45,795         37,728         8,067   
  

 

 

    

 

 

   

 

 

   

 

 

    

 

 

    

 

 

 

Oil Production (Mbbl)

               

Appalachia

     11         13        (2     29         35         (6

West Coast

     710         661        49        2,136         1,958         178   

Gulf Coast (1)

     —           (9     9        —           187         (187
  

 

 

    

 

 

   

 

 

   

 

 

    

 

 

    

 

 

 

Total Production

     721         665        56        2,165         2,180         (15
  

 

 

    

 

 

   

 

 

   

 

 

    

 

 

    

 

 

 

 

(1) 

The sale of Gulf Coast properties in April 2011 and various adjustments to prior months’ production resulted in negative oil production.

Average Prices

 

     Three Months Ended
June 30,
    Nine Months Ended
June 30,
 
      2012      2011      Increase
(Decrease)
    2012      2011      Increase
(Decrease)
 

Average Gas Price/Mcf

                

Appalachia

   $ 2.14       $ 4.55       $ (2.41   $ 2.70       $ 4.36       $ (1.66

West Coast

   $ 2.97       $ 4.87       $ (1.90   $ 3.74       $ 4.40       $ (0.66

Gulf Coast

     N/M         N/M         N/M        N/M       $ 5.02         N/M   

Weighted Average

   $ 2.19       $ 4.67       $ (2.48   $ 2.76       $ 4.44       $ (1.68

Weighted Average After Hedging

   $ 3.93       $ 5.48       $ (1.55   $ 4.40       $ 5.36       $ (0.96
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

Average Oil Price/Bbl

                

Appalachia

   $ 95.43       $ 92.89       $ 2.54      $ 94.24       $ 87.36       $ 6.88   

West Coast

   $ 104.24       $ 108.30       $ (4.06   $ 108.56       $ 94.74       $ 13.82   

Gulf Coast

     N/M         N/M         N/M        N/M       $ 88.57         N/M   

Weighted Average

   $ 104.11       $ 107.97       $ (3.86   $ 108.37       $ 94.10       $ 14.27   

Weighted Average After Hedging

   $ 89.70       $ 84.37       $ 5.33      $ 91.50       $ 80.78       $ 10.72   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

2012 Compared with 2011

Operating revenues for the Exploration and Production segment increased $7.6 million for the quarter ended June 30, 2012 as compared with the quarter ended June 30, 2011. Oil production revenue after hedging increased $8.6 million, largely due to a $5.33 per Bbl increase in the weighted average price of crude oil after hedging coupled with an increase in production. A $0.9 million decrease in natural gas production revenue partially offset this increase. The decrease in natural gas production revenue was due to a $1.55 per Mcf decrease in the weighted average price of natural gas after hedging, offset substantially by an increase in Appalachian natural gas production. The increase in Appalachian production was primarily due to increased development within the Marcellus Shale formation, mainly in Tioga County, Pennsylvania with additional Marcellus Shale production from Lycoming County, Pennsylvania.

 

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Operating revenues for the Exploration and Production segment increased $22.9 million for the nine months ended June 30, 2012 as compared with the nine months ended June 30, 2011. Oil production revenue after hedging increased $22.0 million due to an increase in the weighted average price of oil after hedging ($10.72 per Bbl). While oil production increased in the West Coast region, it was more than offset by the decrease in oil production stemming from the sale of this segment’s offshore oil and natural gas properties in April 2011. In addition, there was a $1.5 million increase in processing plant revenues (net of eliminations) due to a lower cost of gas used in the West Coast processing plant. Partially offsetting these increases was a $0.5 million reduction in gas production revenue after hedging as increases in Appalachian natural gas production were more than offset by the reduction in the weighted average price of natural gas ($0.96 per Mcf) combined with a decrease in natural gas production resulting from the aforementioned sale in April 2011.

The Exploration and Production segment’s earnings for the quarter ended June 30, 2012 were $21.9 million, a decrease of $10.9 million when compared with earnings of $32.8 million for the quarter ended June 30, 2011. This was largely attributable to lower natural gas prices after hedging ($17.9 million). In addition, higher depletion expense ($10.1 million), higher general, administrative and other operating expenses ($1.4 million), higher interest expense ($2.9 million), and higher lease operating expenses ($2.0 million) further reduced earnings. The increase in depletion expense is primarily due to an increase in depletable base (due to increased capital spending in the Appalachian region) and production. Higher personnel costs led to increases in general, administrative and other operating expenses. The increase in lease operating expense is largely attributable to higher transportation, compression, water disposal, equipment rental and repair costs in the Appalachian region. The increase in interest expense was attributable to an increase in the weighted average amount of debt (due to the Exploration and Production segment’s share ($470 million) of the $500 million long-term debt issuance in December 2011). In addition, the $1.7 million accrual of a new impact fee imposed by Pennsylvania in 2012 (retroactively applied to all wells) further reduced earnings. These earnings decreases were partially offset by higher natural gas production ($17.3 million), higher crude oil production ($3.1 million), higher crude oil prices ($2.5 million), and the positive earnings impact of lower income taxes ($1.6 million). The reduction in income taxes was due to changes in state allocation rates.

The Exploration and Production segment’s earnings for the nine months ended June 30, 2012 were $74.4 million, a decrease of $19.1 million when compared with earnings of $93.5 million for the nine months ended June 30, 2011. Lower natural gas and crude oil revenues ($24.5 million) due to the sale of the offshore oil and natural gas properties in April 2011 contributed to the decrease in earnings. In the Appalachian and West Coast regions, lower natural gas prices after hedging also decreased earnings ($28.2 million). In addition, earnings were reduced by higher depletion expense ($16.7 million), higher interest expense ($4.4 million), higher lease operating expenses ($4.2 million), and higher general, administrative and other expenses ($3.6 million). The increase in depletion expense is primarily due to an increase in depletable base and production. The long-term debt issuance discussed above led to the increase in interest expense. The increase in lease operating expense is largely attributable to higher transportation, compression costs, water disposal, equipment rental and repair costs in the Appalachian region. Higher personnel costs led to increases in general, administrative and other operating expenses. In addition, the $8.1 million accrual of a new impact fee imposed by Pennsylvania in 2012 (retroactively applied to all wells) further reduced earnings. These earnings decreases were partially offset by higher Appalachian and West Coast natural gas production ($41.5 million), higher Appalachian and West Coast crude oil production ($9.1 million), higher Appalachian and West Coast crude oil prices ($16.0 million), higher processing plant revenues ($1.0 million), and the positive earnings impact of lower property and other taxes ($2.0 million). The reduction in property and other taxes was due to a revision of the California property tax liability in January 2011, which led to an increase in West Coast property taxes in 2011 that did not recur in 2012. The sale of the offshore oil and natural gas properties in April 2011 led to a further reduction of property and other taxes.

 

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Energy Marketing

Energy Marketing Operating Revenues

 

     Three Months Ended
June 30,
    Nine Months Ended
June 30,
 

(Thousands)

   2012      2011      Decrease     2012      2011      Decrease  

Natural Gas (after Hedging)

   $ 35,950       $ 71,892       $ (35,942   $ 162,923       $ 246,825       $ (83,902

Other

     6         10         (4     34         50         (16
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 
   $ 35,956       $ 71,902       $ (35,946   $ 162,957       $ 246,875       $ (83,918
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 
Energy Marketing Volume             
     Three Months Ended
June 30,
    Nine Months Ended
June 30,
 
     2012      2011      Decrease     2012      2011      Decrease  

Natural Gas – (MMcf)

     10,818         13,508         (2,690     38,857         45,863         (7,006
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

 

2012 Compared with 2011

Operating revenues for the Energy Marketing segment decreased $35.9 million and $83.9 million for the quarter and nine months ended June 30, 2012, as compared with the quarter and nine months ended June 30, 2011. The decrease for both the quarter and nine months ended June 30, 2012 reflects a decline in gas sales revenue due to a lower average price of natural gas and a decrease in volume sold. Warmer weather is primarily responsible for the decrease in volume.

The Energy Marketing segment’s earnings for the quarter ended June 30, 2012 were $0.9 million, a decrease of $1.0 million when compared with earnings of $1.9 million for the quarter ended June 30, 2011. The Energy Marketing segment’s earnings for the nine months ended June 30, 2012 were $4.7 million, a decrease of $4.4 million when compared with earnings of $9.1 million for the nine months ended June 30, 2011. These decreases were largely attributable to a decline in margin of $0.9 million and $4.3 million for the quarter and nine-month periods, respectively. The decrease in margin was primarily driven by lower volume sold to retail customers as well as a reduction in the benefit the Energy Marketing segment derived from its contracts for storage capacity.

Corporate and All Other

2012 Compared with 2011

Corporate and All Other operations recorded earnings of $2.6 million for the quarter ended June 30, 2012, an increase of $1.2 million when compared with earnings of $1.4 million for the quarter ended June 30, 2011. The increase in earnings is primarily due to higher interest income of $2.5 million, lower property, franchise and other taxes of $0.7 million, higher gathering and processing revenues of $1.1 million and lower operating expenses of $0.3 million. The Company issued $500 million of notes at 4.90% in December 2011 and repaid $150 million of 6.70% notes that matured in November 2011. The higher interest income is due to higher interest collected from the Company’s Exploration and Production segment as a result of their share of these borrowings. The increase in gathering and processing revenues are due to Midstream Corporation’s increase in gathering operations for Marcellus Shale gas in Tioga County and Lycoming County, both of which are in Pennsylvania (due to the Trout Run Gathering System being placed into service in May 2012). The decrease in operating expenses is largely due to various cost-saving measures and lower compensation costs. The factors contributing to the overall increase in earnings were partially offset by higher interest expense of $2.4 million, lower margins of $0.7 million and higher depreciation expense of $0.2 million (largely due to an increase in capital spending in the gathering operations). The higher interest expense is due to the borrowings discussed above. The lower margins are due to a decrease in revenues from the sale of standing timber.

 

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For the nine months ended June 30, 2012, Corporate and All Other operations had earnings of $4.0 million, a decrease of $28.0 million when compared with earnings of $32.0 million for the nine months ended June 30, 2011. The decrease in earnings is primarily a reflection of the gain recorded on the sale of Horizon Power’s investments in Seneca Energy and Model City of $31.4 million during the quarter ended March 31, 2011. In addition, higher interest expense of $4.0 million and higher depreciation expense of $0.2 million (due to an increase in capital spending in gathering operations) further decreased earnings. The higher interest expense is due to the borrowings as discussed above. The factors contributing to the overall decrease in earnings were partially offset by higher interest income of $4.4 million, higher gathering and processing revenues of $2.4 million, lower property, franchise and other taxes of $0.7 million, lower operating expenses of $0.5 million, higher margins of $0.3 million and a lower loss from unconsolidated subsidiaries of $0.3 million. The higher interest income is due to higher interest collected from the Company’s Exploration and Production segment as a result of their share of the borrowing discussed above. The higher margins are due to an increase in revenues from the sale of standing timber. The increase in gathering and processing revenues are due to Midstream Corporation’s increase in gathering operations for Marcellus Shale gas in Tioga County and Lycoming County, as mentioned above. The lower loss from unconsolidated subsidiaries is primarily due to the non-recurrence of renewable energy credit adjustments recorded by Seneca Energy and Model City during the quarter ended December 31, 2010. Seneca Energy and Model City were sold in February 2011. The decrease in operating expenses is largely due to various cost-saving measures and lower compensation costs.

Interest Expense on Long-Term Debt (amounts below are pre-tax amounts)

Interest on long-term debt increased $3.7 million for the quarter ended June 30, 2012 as compared with the quarter ended June 30, 2011. For the nine months ended June 30, 2012, interest on long-term debt increased $4.6 million as compared with the nine months ended June 30, 2011. This increase is due to higher borrowings. The Company issued $500 million of notes at 4.90% in December 2011 and repaid $150 million of 6.70% notes that matured in November 2011.

Other Interest Expense (amounts below are pre-tax amounts)

Other interest expense decreased $0.3 million for the quarter ended June 30, 2012 as compared with the quarter ended June 30, 2011. For the nine months ended June 30, 2012, other interest expense decreased $1.2 million as compared with the nine months ended June 30, 2011. The decrease is mainly due to lower interest expense on regulatory deferrals (primarily interest on deferred gas costs) in the Utility segment.

CAPITAL RESOURCES AND LIQUIDITY

The Company’s primary sources of cash during the nine-month period ended June 30, 2012 consisted of cash provided by operating activities, proceeds from the issuance of long-term debt, net proceeds from short-term borrowings and net proceeds from the issuance of common stock. The Company’s primary sources of cash during the nine-month period ended June 30, 2011 consisted of cash provided by operating activities, net proceeds from the sale of unconsolidated subsidiaries and net proceeds from the sale of oil and gas producing properties. During the nine months ended June 30, 2012 and June 30, 2011, the common stock used to fulfill the requirements of the Company’s 401(k) plans was obtained via open market purchases. In April 2011, the Company began issuing original issue shares for the Direct Stock Purchase and Dividend Reinvestment Plan.

Operating Cash Flow

Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization and deferred income taxes. Net income available for common stock is also adjusted for the gain on the sale of unconsolidated subsidiaries.

Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from period to period because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Utility segment’s New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire.

 

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Because of the seasonal nature of the heating business in the Utility and Energy Marketing segments, revenues in these segments are relatively high during the heating season, primarily the first and second quarters of the fiscal year, and receivable balances historically increase during these periods from the receivable balances at September 30.

The storage gas inventory normally declines during the first and second quarters of the fiscal year and is replenished during the third and fourth quarters. For storage gas inventory accounted for under the LIFO method, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve is reduced as the inventory is replenished.

Cash provided by operating activities in the Exploration and Production segment may vary from period to period as a result of changes in the commodity prices of natural gas and crude oil as well as changes in production. The Company uses various derivative financial instruments, including price swap agreements and futures contracts in an attempt to manage this energy commodity price risk.

Net cash provided by operating activities totaled $541.0 million for the nine months ended June 30, 2012, an increase of $4.7 million compared with $536.3 million provided by operating activities for the nine months ended June 30, 2011. The increase in cash provided by operating activities is primarily due to an increase in cash provided by operations in both the Utility segment and Exploration and Production segment, partially offset by a decrease in cash provided by operations in the Energy Marketing segment. The increase in the Utility segment can be attributed to the timing of gas cost recovery. The increase in the Exploration and Production segment reflects higher cash receipts from oil and natural gas production in the West Coast and Appalachian regions combined with hedging collateral account fluctuations, which both offset the loss of cash flow from the Company’s former oil and natural gas properties in the Gulf of Mexico. The variation in the Energy Marketing segment can be attributed to lower margins (cash receipts minus cash payments for gas costs), combined with hedging collateral account fluctuations.

Investing Cash Flow

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets totaled $803.2 million during the nine months ended June 30, 2012 and $594.7 million for the nine months ended June 30, 2011. The table below presents these expenditures:

 

Total Expenditures for Long-Lived Assets

 

Nine Months Ended June 30,

(Millions)

   2012     2011     Increase  

Utility :

      

Capital Expenditures

   $ 39.9      $ 39.4      $ 0.5   

Pipeline and Storage:

      

Capital Expenditures

     97.3  (1)(2)      75.0  (3)      22.3   

Exploration and Production:

      

Capital Expenditures

     598.6  (1)(2)      473.5  (3)(4)      125.1   

All Other:

      

Capital Expenditures

     67.4  (1)(2)      6.8        60.6   
  

 

 

   

 

 

   

 

 

 
   $ 803.2      $ 594.7      $ 208.5   
  

 

 

   

 

 

   

 

 

 

 

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(1)

Capital expenditures for the Exploration and Production segment include $74.2 million of accrued capital expenditures at June 30, 2012, the majority of which was in the Appalachian region. Capital expenditures for the Pipeline and Storage segment include $8.0 million of accrued capital expenditures at June 30, 2012. In addition, capital expenditures for the All Other category include $16.2 million of accrued capital expenditures at June 30, 2012. These amounts have been excluded from the Consolidated Statement of Cash Flows at June 30, 2012 since they represent non-cash investing activities at that date.

 

(2)

Capital expenditures for the Exploration and Production segment for the nine months ended June 30, 2012 exclude $63.5 million of capital expenditures, the majority of which was in the Appalachian region. Capital expenditures for the Pipeline and Storage segment for the nine months ended June 30, 2012 exclude $7.3 million of capital expenditures. Capital expenditures for the All Other category for the nine months ended June 30, 2012 exclude $1.4 million of capital expenditures. These amounts were accrued at September 30, 2011 and paid during the nine months ended June 30, 2012. These amounts were excluded from the Consolidated Statement of Cash Flows at September 30, 2011 since they represented non-cash investing activities at that date. These amounts have been included in the Consolidated Statement of Cash Flows at June 30, 2012.

 

(3)

Capital expenditures include $60.7 million of accrued capital expenditures for the Exploration and Production segment at June 30, 2011, the majority of which was in the Appalachian region. In addition, capital expenditures for the Pipeline and Storage segment include $5.9 million of accrued capital expenditures at June 30, 2011. These amounts were excluded from the Consolidated Statement of Cash Flows at June 30, 2011 since they represented non-cash investing activities at that date.

 

(4)

Capital expenditures for the Exploration and Production segment for the nine months ended June 30, 2011 exclude $55.5 million of capital expenditures, the majority of which was in the Appalachian region. This amount was accrued at September 30, 2010 and paid during the nine months ended June 30, 2011. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2010 since it represented a non-cash investing activity at that date. This amount was included in the Consolidated Statement of Cash Flows at June 30, 2011.

Utility

The majority of the Utility capital expenditures for the nine months ended June 30, 2012 and June 30, 2011 were made for replacement of mains and main extensions, as well as for the replacement of service lines.

Pipeline and Storage

The majority of the Pipeline and Storage capital expenditures for the nine months ended June 30, 2012 were related to the construction of Empire’s Tioga County Extension Project, Supply Corporation’s Line N Expansion Project, Supply Corporation’s Line N 2012 Expansion Project and Supply Corporation’s Northern Access expansion project, as discussed below. The Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2012 include $20.4 million spent on the Tioga County Extension Project, $2.5 million spent on the Line N Expansion Project, $18.8 million spent on the Line N 2012 Expansion Project, and $24.3 million spent on the Northern Access expansion project. The Pipeline and Storage capital expenditures for the nine months ended June 30, 2012 also include additions, improvements, and replacements to this segment’s transmission and gas storage systems. The majority of the Pipeline and Storage capital expenditures for the nine months ended June 30, 2011 were related to additions, improvements, and replacements to this segment’s transmission and gas storage systems. In addition, the Pipeline and Storage capital expenditure amounts for the nine months ended June 30, 2011 include $11.8 million spent on the Line N Expansion Project, $7.0 million spent on the Lamont Phase II Project and $11.2 million spent on the Tioga County Extension Project.

In light of the growing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia — specifically in the Marcellus Shale producing area — Supply Corporation and Empire are actively pursuing several expansion projects and paying for preliminary survey and investigation costs, which are initially recorded as Deferred Charges on the Consolidated Balance Sheet. An offsetting reserve is established as those preliminary survey and investigation costs are incurred, which reduces the Deferred Charges balance and increases Operation and Maintenance Expense on the Consolidated Statement of Income. The Company reviews all projects on a quarterly basis, and if it is determined that it is highly probable that the project will be built, the reserve is reversed. This reversal reduces Operation and Maintenance Expense and reestablishes the original balance in Deferred Charges. After the reversal of the reserve, the amounts remain in Deferred Charges until such time as capital expenditures for the project have been incurred and activities that are necessary to get the construction project ready for its intended use are in progress. At that point, the balance is transferred from Deferred Charges to Construction Work in Progress, a component of Property, Plant and Equipment on the Consolidated Balance Sheet. As of June 30, 2012, the total amount reserved for the Pipeline and Storage segment’s preliminary survey and investigation costs was $7.4 million.

 

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Supply Corporation and Empire are moving forward with several projects designed to move anticipated Marcellus production gas to other interstate pipelines and to markets beyond the Supply Corporation and Empire pipeline systems.

Supply Corporation has a precedent agreement with Statoil Natural Gas LLC (“Statoil”) to provide 320,000 Dth/day of firm transportation capacity for a 20-year term in conjunction with its “Northern Access” expansion project, and has executed the transportation service agreement. This capacity will provide Statoil with a firm transportation path from the Tennessee Gas Pipeline (“TGP”) 300 Line at Ellisburg and Transcontinental Pipeline at Leidy to the TransCanada Pipeline at Niagara. These receipt points are attractive because they provide routes for Marcellus shale gas from the TGP 300 Line and Transco Leidy Line in northern Pennsylvania, to be transported from the Marcellus supply basin to northern markets. Supply Corporation received from the FERC its NGA Section 7(c) Certificate authorization of this project on October 20, 2011, and received its Notice to Proceed on April 13, 2012. The project facilities involve approximately 9,500 horsepower of additional compression at Supply Corporation’s existing Ellisburg Station and a new approximately 5,000 horsepower compressor station in Wales, New York, along with other system enhancements including enhancements to the jointly owned Niagara Spur Loop Line. Service is expected to begin in November 2012. The cost estimate for the Northern Access expansion is $75 million. As of June 30, 2012, approximately $26.8 million has been spent on the Northern Access expansion project, all of which has been capitalized as Construction Work in Progress.

Supply Corporation has begun service under two service agreements which total 160,000 Dth/day of firm transportation capacity in its “Line N Expansion Project.” This project allows Marcellus production located in the vicinity of Line N to flow south and access markets at Texas Eastern’s Holbrook Station (“TETCO Holbrook”) in southwestern Pennsylvania. The FERC issued the NGA Section 7(c) certificate on December 16, 2010, and the project was placed into service on October 19, 2011. Completed cost for the Line N Expansion Project is expected to be approximately $22 million. As of June 30, 2012, approximately $20.7 million has been spent on the Line N Expansion Project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at June 30, 2012.

Supply Corporation has also executed three precedent agreements for a total of 163,000 Dth/day of additional capacity on Line N to TETCO Holbrook for service beginning November 2012 (“Line N 2012 Expansion Project”). On July 8, 2011, Supply Corporation filed for FERC authorization to construct the Line N 2012 Expansion Project which consists of an additional 20,620 horsepower of compression at its Buffalo Compressor Station, and the replacement of 4.85 miles of 20” pipe with 24” pipe, to enhance the integrity and reliability of its system and to create the additional capacity. The FERC issued the NGA Section 7(c) Certificate on March 29, 2012. The preliminary cost estimate for the Line N 2012 Expansion Project is approximately $34.1 million for the incremental capacity plus approximately $8.9 million allocated to system replacement. As of June 30, 2012, approximately $21.2 million has been spent on the Line N 2012 Expansion Project, all of which has been capitalized as Construction Work in Progress.

Supply Corporation continues to market the West-to-East (“W2E”) pipeline project, which is designed to transport locally produced Marcellus natural gas supplies, principally from the dry central area of the trend, to the Ellisburg/Leidy/Corning area. Supply Corporation anticipates that the development of the W2E project will occur in phases. As currently envisioned, the initial phases of W2E, referred to as the “W2E Overbeck to Leidy” project, are designed to transport at least 425,000 Dth/day, and involves construction of a new 82-mile pipeline through Elk, Cameron, Clinton, Clearfield and Jefferson Counties to the Leidy Hub, from Marcellus and other producing areas along over 300 miles of Supply Corporation’s existing pipeline system. The W2E Overbeck to Leidy project also includes a total of approximately 25,000 horsepower of compression at two separate stations. On March 31, 2010, the FERC granted Supply Corporation’s request for a pre-filing environmental review of the W2E Overbeck to Leidy project. Supply Corporation has since withdrawn from the FERC process, which would be restarted upon the development of an adequate market to support the estimated $290 million capital cost of the project. As of June 30, 2012, approximately $5.7 million has been spent to study the W2E Overbeck to Leidy project, which has been included in preliminary survey and investigation charges and has been fully reserved for at June 30, 2012.

 

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On August 4, 2011, Supply Corporation concluded an Open Season to increase its capability to move gas north on its Line N system and deliver gas to Tennessee Gas Pipeline at Mercer, Pennsylvania, a pooling point recently established at Tennessee’s Station 219 (“Mercer Expansion Project”). Supply Corporation is continuing discussions with an anchor shipper that would take all 150,000 Dth/day of the capacity on the project. Service is expected to begin in 2014 and the estimated cost is $25 million to $30 million. As of June 30, 2012, less than $0.1 million has been spent to study the Mercer Expansion Project, all of which has been included in preliminary survey and investigation charges and has been fully reserved for at June 30, 2012.

Empire has begun service under two service agreements which total 350,000 Dth/day of incremental firm transportation capacity in its “Tioga County Extension Project.” This project transports Marcellus production from new interconnections at the southern terminus of a 15-mile extension of its Empire Connector line, in Tioga County, Pennsylvania. Completed cost for the Tioga County Extension Project is expected to be approximately $55 million, of which approximately $52.2 million has been spent through June 30, 2012. This project enables shippers to deliver their natural gas at existing Empire interconnections with Millennium Pipeline at Corning, New York, with the TransCanada Pipeline at the Niagara River at Chippawa, and with utility and power generation markets along its path, as well as to the new interconnection with TGP’s 200 Line (Zone 5) in Ontario County, New York. The FERC issued the NGA Section 7(c) certificate on May 19, 2011 and the project was placed fully in service on November 22, 2011. All costs associated with the project are included in Property, Plant and Equipment on the Consolidated Balance Sheet at June 30, 2012.

On December 17, 2010, Empire concluded an Open Season for up to 260,000 Dth/day of additional capacity from Tioga County, Pennsylvania, to TransCanada Pipeline and the TGP 200 Line, as well as additional short-haul capacity to Millennium Pipeline at Corning (“Central Tioga County Extension”). Empire is in discussions with an anchor shipper for a significant portion of the proposed capacity, with service commencing in 2014 or 2015, likely tied to a rebound in commodity pricing due to the dry gas nature of this area of the Marcellus. The Central Tioga County Extension project may involve up to 25,000 horsepower of compression at up to three new stations and a 25 mile 24” pipeline extension, at a preliminary cost estimate of $135 million. As of June 30, 2012, approximately $0.2 million has been spent to study the Central Tioga County Extension project, which has been included in preliminary survey and investigation charges and has been fully reserved for at June 30, 2012.

Exploration and Production

The Exploration and Production segment capital expenditures for the nine months ended June 30, 2012 were primarily well drilling and completion expenditures and included approximately $552.0 million for the Appalachian region (including $500.4 million in the Marcellus Shale area) and $46.6 million for the West Coast region. These amounts included approximately $198.7 million spent to develop proved undeveloped reserves.

The Exploration and Production segment capital expenditures for the nine months ended June 30, 2011 were primarily well drilling and completion expenditures and included approximately $441.2 million for the Appalachian region (including $433.5 million in the Marcellus Shale area), $28.1 million for the West Coast region and $4.2 million for the Gulf Coast region (former offshore oil and natural gas properties in the Gulf of Mexico). These amounts included approximately $165.5 million spent to develop proved undeveloped reserves. The capital expenditures in the Appalachian region included the Company’s acquisition of oil and gas properties in the Covington Township area of Tioga County, Pennsylvania from EOG Resources, Inc. for approximately $24.1 million in November 2010. The Company funded this transaction with cash from operations.

For all of fiscal 2013, the Company expects to spend $450.0 million on Exploration and Production segment capital expenditures. Previously reported 2013 estimated capital expenditures for the Exploration and Production segment were $500.0 million. In the Appalachian region, estimated capital expenditures will decrease from $442.5 million to $382.5 million. Estimated capital expenditures in the West Coast region will increase from $57.5 million to $67.5 million. The decrease in estimated capital expenditures for the Appalachian region noted above is due to an anticipated reduction in drilling and completion activity associated with a Marcellus Shale joint venture agreement with EOG Resources, Inc. The anticipated reduction in joint venture activity is largely a response to the current low natural gas price environment.

 

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In April 2011, the Company completed the sale of its offshore oil and natural gas properties in the Gulf of Mexico. Initial proceeds received through June 30, 2011 totaled $61.8 million. Price adjustments subsequent to June 30, 2011 reduced the final net proceeds to $55.4 million. Under the full cost method of accounting for oil and gas properties, the sale proceeds were accounted for as a reduction of capitalized costs. Since the disposition did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company did not record any gain or loss from this sale.

In May 2011, the Company sold the Sprayberry property in the West Coast region for $8.1 million. Under the full cost method of accounting for oil and natural gas properties, the sale proceeds were accounted for as a reduction of capitalized costs. Since the disposition did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company did not record any gain or loss from this sale.

All Other

The majority of the All Other category’s capital expenditures for the nine months ended June 30, 2012 were for the construction of Midstream Corporation’s Trout Run Gathering System and the expansion of Midstream Corporation’s Covington Gathering System, as discussed below. The majority of the All Other category’s capital expenditures for the nine months ended June 30, 2011 were primarily for the expansion of Midstream Corporation’s Covington Gathering system as well as for the construction of Midstream Corporation’s Trout Run Gathering System.

NFG Midstream Trout Run, LLC, a wholly owned subsidiary of Midstream Corporation, is developing a gathering system in Lycoming County, Pennsylvania. The project, Trout Run Gathering System, was placed in service in May 2012. The current system consists of approximately 26 miles of backbone and in-field gathering system. The complete buildout will include additional in-field gathering pipelines and compression at a cost of approximately $130 million. As of June 30, 2012, the Company has spent approximately $71.7 million in costs related to this project, including approximately $56.2 million spent during the nine months ended June 30, 2012, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at June 30, 2012.

NFG Midstream Covington, LLC, a wholly owned subsidiary of Midstream Corporation, has been expanding its gathering system in Tioga County, Pennsylvania. As of June 30, 2012, the Company has spent approximately $24.1 million in costs related to the Covington Gathering System, including approximately $7.8 million spent during the nine months ended June 30, 2012. All costs associated with this gathering system are included in Property, Plant and Equipment on the Consolidated Balance Sheet at June 30, 2012.

Midstream Corporation is planning the construction of several smaller gathering systems. As of June 30, 2012, the Company has spent approximately $2.9 million in costs related to these projects, all of which has been capitalized as Construction Work in Progress.

Project Funding

The Company has been financing the Pipeline and Storage segment projects and the Midstream Corporation projects mentioned above, as well as the Exploration and Production segment capital expenditures, with cash from operations. Going forward, while the Company expects to use cash from operations as the first means of financing these projects, it is expected that the Company will increase its use of short-term borrowings during fiscal 2012. Natural gas and crude oil prices combined with production from existing wells will be a significant factor in determining how much of the capital expenditures are funded with cash from operations. The Company also issued additional long-term debt in December 2011 to enhance its liquidity position.

The Company continuously evaluates capital expenditures and investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive oil and gas properties, natural gas storage facilities and the expansion of natural

 

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gas transmission line capacities. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s other business segments depends, to a large degree, upon market conditions.

Financing Cash Flow

Consolidated short-term debt increased $30.2 million during the nine months ended June 30, 2012. The maximum amount of short-term debt outstanding during the nine months ended June 30, 2012 was $327.8 million. The Company used its $500.0 million long-term debt issuance in December 2011 to substantially reduce its short-term debt. The Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures and investments in corporations and/or partnerships, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, repurchases of stock, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. At June 30, 2012, the Company had outstanding commercial paper and short-term notes payable to banks of $50.0 and $20.2 million, respectively.

As for bank loans, the Company maintains a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under these lines of credit are made at competitive market rates. These credit lines, which totaled $335.0 million at June 30, 2012, are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed at amounts near current levels, or substantially replaced by similar lines.

The total amount available to be issued under the Company’s commercial paper program is $300.0 million. At June 30, 2012, the commercial paper program was backed by a syndicated committed credit facility totaling $750.0 million, which commitment extends through January 6, 2017. Under the committed credit facility, the Company agreed that its debt to capitalization ratio would not exceed .65 at the last day of any fiscal quarter through January 6, 2017. At June 30, 2012, the Company’s debt to capitalization ratio (as calculated under the facility) was .42. The constraints specified in the committed credit facility would have permitted an additional $2.22 billion in short-term and/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded .65.

If a downgrade in any of the Company’s credit ratings were to occur, access to the commercial paper markets might not be possible. However, the Company expects that it could borrow under its committed credit facility, uncommitted bank lines of credit or rely upon other liquidity sources, including cash provided by operations.

Under the Company’s existing indenture covenants, at June 30, 2012, the Company would have been permitted to issue up to a maximum of $1.56 billion in additional long-term unsecured indebtedness at then current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. The Company’s present liquidity position is believed to be adequate to satisfy known demands. However, if the Company were to experience a significant loss in the future (for example, as a result of an impairment of oil and gas properties), it is possible, depending on factors including the magnitude of the loss, that these indenture covenants would restrict the Company’s ability to issue additional long-term unsecured indebtedness for a period of up to nine calendar months, beginning with the fourth calendar month following the loss. This would not at any time preclude the Company from issuing new indebtedness to replace maturing debt.

The Company’s 1974 indenture pursuant to which $99.0 million (or 7.1%) of the Company’s long-term debt (as of June 30, 2012) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement, or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

 

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The Company’s $750.0 million committed credit facility also contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the committed credit facility. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more, or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of June 30, 2012, the Company did not have any debt outstanding under the committed credit facility.

The Company’s embedded cost of long-term debt was 6.17% at June 30, 2012 and 6.85% at June 30, 2011.

Current Portion of Long-Term Debt at June 30, 2012 consists of $250.0 million of 5.25% notes that mature in March 2013. Currently, the Company expects to refund these notes in fiscal 2013 with cash on hand, short-term borrowings and/or long-term debt. The Company repaid $150 million of 6.70% notes that matured on November 21, 2011, which had been classified as Current Portion of Long-Term Debt at September 30, 2011.

On December 1, 2011, the Company issued $500.0 million of 4.90% notes due December 1, 2021. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $496.1 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of a change in control and a ratings downgrade to a rating below investment grade. The proceeds of this debt issuance were used for general corporate purposes, including refinancing short-term debt that was used to pay the $150 million due at the maturity of the Company’s 6.70% notes in November 2011.

The Company may issue debt or equity securities in a public offering or a private placement from time to time. The amounts and timing of the issuance and sale of debt or equity securities will depend on market conditions, indenture requirements, regulatory authorizations and the capital requirements of the Company.

OFF-BALANCE SHEET ARRANGEMENTS

The Company has entered into certain off-balance sheet financing arrangements. These financing arrangements are primarily operating leases. The Company’s consolidated subsidiaries have operating leases, the majority of which are with the Exploration and Production segment and Corporate operations, having a remaining lease commitment of approximately $30.7 million. These leases have been entered into for the use of compressors, buildings, meters and other items and are accounted for as operating leases.

OTHER MATTERS

In addition to the legal proceedings disclosed in Part II, Item 1 of this report, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.

During the nine months ended June 30, 2012, the Company contributed $31.8 million to its Retirement Plan and $18.9 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits. In the remainder of 2012, the Company expects to contribute $12.2 million to the Retirement Plan.

 

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Changes in the discount rate, other actuarial assumptions, and asset performance could ultimately cause the Company to fund larger amounts to the Retirement Plan in fiscal 2012 in order to be in compliance with the Pension Protection Act of 2006. In the remainder of 2012, the Company expects to contribute between $2.0 million and $3.0 million to its VEBA trusts and 401(h) accounts.

Market Risk Sensitive Instruments

On July 21, 2010, the Dodd-Frank Act was signed into law. The Dodd-Frank Act includes provisions related to the swaps and over-the-counter derivatives markets. Certain provisions of the Dodd-Frank Act related to derivatives became effective July 16, 2011, but other provisions related to derivatives will not become effective until federal agencies (including the Commodity Futures Trading Commission (CFTC), various banking regulators and the SEC) adopt rules to implement the law. For purposes of the Dodd-Frank Act, under rules adopted by the SEC and/or CFTC, the Company believes that it qualifies as a non-financial end user of derivatives, that is, as a non-financial entity that uses derivatives to hedge or mitigate commercial risk. Nevertheless, other rules that are being developed could have a significant impact on the Company. For example, banking regulators have proposed a rule that would require swap dealers and major swap participants subject to their jurisdiction to collect initial and variation margin from counterparties that are non-financial end users, though such swap dealers and major swap participants would have the discretion to set thresholds for posting margin (unsecured credit limits). Regardless of the levels of margin that might be required, concern remains that swap dealers and major swap participants will pass along their increased capital and margin costs through higher prices and reductions in thresholds for posting margin. In addition, while the Company expects to be exempt from the Dodd-Frank Act’s requirement that swaps be cleared and traded on exchanges or swap execution facilities, the cost of entering into a non-cleared swap that is available as a cleared swap may be greater. The Company continues to monitor these developments but cannot predict the impact the Dodd-Frank Act may ultimately have on its operations.

In accordance with the authoritative guidance for fair value measurements, the Company has identified certain inputs used to recognize fair value as Level 3 (unobservable inputs). The Level 3 derivative net liabilities relate to crude oil swap agreements used to hedge forecasted sales at a specific location (southern California). The Company’s internal model that is used to calculate fair value applies a historical basis differential (between the sales locations and NYMEX) to a forward NYMEX curve because there is not a forward curve specific to this sales location. Given the high level of historical correlation between NYMEX prices and prices at this sales location, the Company does not believe that the fair value recorded by the Company would be significantly different from what it expects to receive upon settlement.

The Company uses the crude oil swaps classified as Level 3 to hedge against the risk of declining commodity prices and not as speculative investments. Gains or losses related to these Level 3 derivative net liabilities (including any reduction for credit risk) are deferred until the hedged commodity transaction occurs in accordance with the provisions of the existing guidance for derivative instruments and hedging activities. The Level 3 Net Liabilities amount to $16.5 million at June 30, 2012 and represent 7.6% of the Total Net Assets shown in Part I, Item 1 at Note 2 – Fair Value Measurements at June 30, 2012.

The increase in the net fair value liability of the Level 3 positions from October 1, 2011 to June 30, 2012, as shown in Part I, Item 1 at Note 2, was attributable to an increase in the commodity price of crude oil relative to the swap price during that period. The Company believes that these fair values reasonably represent the amounts that the Company would realize upon settlement based on commodity prices that were present at June 30, 2012.

The fair value of all of the Company’s Net Derivative Assets was reduced by $0.5 million at June 30, 2012 based upon the Company’s assessment of counterparty credit risk (for the Company’s derivative assets) and the Company’s credit risk (for the Company’s derivative liabilities). The Company applied default probabilities to the anticipated cash flows that it was expecting to receive and pay to its counterparties to calculate the credit reserve.

For a complete discussion of market risk sensitive instruments, refer to “Market Risk Sensitive Instruments” in Item 7 of the Company’s 2011 Form 10-K. There have been no subsequent material changes to the Company’s exposure to market risk sensitive instruments.

 

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