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, 2006
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 | (I.R.S. Employer |
| incorporation or organization) | Identification No.) |
| | |
|---|
| 6363 Main Street | 14221 |
| Williamsville, New York | (Zip Code) |
(Address of principal executive offices)
(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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one): Large Accelerated Filer X Accelerated Filer Non-Accelerated Filer
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, 2006: 83,400,866 shares.
1
GLOSSARY OF TERMS
Frequently used abbreviations or acronyms:
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
Data-Track Data-Track Account Services, Inc.
Distribution Corporation National Fuel Gas Distribution Corporation
Empire Empire State Pipeline
ESNE Energy Systems North East, LLC
Highland Highland Forest Resources, Inc.
Horizon Horizon Energy Development, Inc.
Horizon LFG Horizon LFG, Inc.
Horizon Power Horizon Power, Inc.
Leidy Hub Leidy Hub, Inc.
Model City Model City Energy, LLC
National Fuel National Fuel Gas Company
NFR National Fuel Resources, Inc.
Registrant National Fuel Gas Company
SECI Seneca Energy Canada Inc.
Seneca Seneca Resources Corporation
Seneca Energy Seneca Energy II, LLC
Supply Corporation National Fuel Gas Supply Corporation
U.E. United Energy, a.s.
Regulatory Agencies
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
NYPSC State of New York Public Service Commission
PaPUC Pennsylvania Public Utility Commission
SEC Securities and Exchange Commission
NTSB National Transportation Safety Board
Other
2005 Form 10-K The Company's Annual Report on Form 10-K for the year ended
September 30, 2005
APB 20 Accounting Principles Board Opinion No. 20, Accounting Changes
APB 25 Accounting Principles Board Opinion No. 25, Accounting for
Stock Issued to Employees
Bbl Barrel (of oil)
Bcf Billion cubic feet (of natural gas)
Board foot A measure of lumber and/or timber equal to 12 inches in length by 12
inches in width by one inch in thickness.
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.
Cashout revenues A cash resolution of a gas imbalance whereby a customer pays Supply
Corporation for gas the customer receives in excess of amounts
delivered into Supply Corporation's system by the customer's shipper.
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.
2
GLOSSARY OF TERMS (Cont.)
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.
Energy Policy Act Energy Policy Act of 2005
Exchange Act Securities Exchange Act of 1934
Expenditures for
long-lived assets Includes capital expenditures, stock acquisitions and/or investments in
partnerships.
FIN 47 FASB Interpretation No. 47, Accounting for Conditional Asset Retirement
Obligations - an interpretation of SFAS 143
FIN 48 FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes
- an interpretation of SFAS 109.
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.
LIFO Last-in, first-out
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)
MMcf Million cubic feet (of natural gas)
Order 667-A An order issued by FERC to clarify Order 667 entitled "Repeal of the
Public Utility Holding Company Act of 1935 and Enactment of the
Public Utility Holding Company Act of 2005"
Order 2004 An order issued by FERC entitled "Standards of Conduct for
Transmission Providers"
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
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.
PUHCA 1935 Public Utility Holding Company Act of 1935
PUHCA 2005 Public Utility Holding Company Act of 2005
Reserves The unproduced but recoverable oil and/or gas in place in a formation
which has been proven by production.
Restructuring Generally referring to partial "deregulation" of the 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.
SFAS Statement of Financial Accounting Standards
3
GLOSSARY OF TERMS (Concl.)
SFAS 3 Statement of Financial Accounting Standards No. 3, Reporting
Accounting Changes in Interim Financial Statements
SFAS 109 Statement of Financial Accounting Standards No. 109, Accounting for
Income Taxes
SFAS 123 Statement of Financial Accounting Standards No. 123, Accounting
for Stock-Based Compensation
SFAS 123R Statement of Financial Accounting Standards No. 123R,
Share-Based Payment
SFAS 143 Statement of Financial Accounting Standards No. 143, Accounting for
Asset Retirement Obligations
SFAS 154 Statement of Financial Accounting Standards No. 154, Accounting
Changes and Error Corrections
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.
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.
4
INDEX
Part I. Financial InformationItem 1. Financial Statements (Unaudited)Consolidated Statements of Income and Earnings Reinvested in the Business - Three and Nine Months Ended June 30, 2006 and 2005 - Pages 6-7Consolidated Balance Sheets - June 30, 2006 and September 30, 2005 - Pages 8-9Consolidated Statement of Cash Flows - Nine Months Ended June 30, 2006 and 2005 - Page 10Consolidated Statement of Comprehensive Income - Three and Nine Months Ended June 30, 2006 and 2005 - Page 11Notes to Consolidated Financial Statements - Pages 12-24Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Pages 25-46Item 3. Quantitative and Qualitative Disclosures About Market Risk - Page 46Item 4. Controls and Procedures - Page 46 Part II. Other InformationItem 1. Legal Proceedings - Pages 46-47Item 1 A. Risk Factors - Pages 47-49Item 2. Unregistered Sales of Equity Securities and Use of Proceeds- Page 49Item 3. Defaults Upon Senior Securities - The Company has nothing to report under this item.Item 4. Submission of Matters to a Vote of Security Holders - The Company has nothing to report under this item.Item 5. Other Information - The Company has nothing to report under this item.Item 6. Exhibits - Page 50Signatures - Page 51. 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, those statements that are designated with an asterisk (“*”) following the statement, as well as those statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions.
5
Part I. Financial Information
Back to Table of ContentsBack to Table of Contents
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) 2006 2005
------------------ -----------------
INCOME
Operating Revenues $415,452 $400,359
- ------------------------------------------------------------------------------- ------------------ -----------------
Operating Expenses
Purchased Gas 184,635 181,100
Operation and Maintenance 96,117 94,534
Property, Franchise and Other Taxes 16,845 16,598
Depreciation, Depletion and Amortization 46,943 45,099
Impairment of Oil and Gas Producing Properties 62,371 -
- ------------------------------------------------------------------------------- ------------------ -----------------
406,911 337,331
- ------------------------------------------------------------------------------- ------------------ -----------------
Operating Income 8,541 63,028
Other Income (Expense):
Income from Unconsolidated Subsidiaries 215 675
Interest Income 2,203 492
Other Income 546 602
Interest Expense on Long-Term Debt (18,135) (18,294)
Other Interest Expense (1,026) (4,557)
- ------------------------------------------------------------------------------- ------------------ -----------------
Income (Loss) from Continuing Operations Before
Income Taxes (7,656) 41,946
Income Tax Expense (Benefit) (7,767) 15,553
- ------------------------------------------------------------------------------- ------------------ -----------------
Income from Continuing Operations 111 26,393
- ------------------------------------------------------------------------------- ------------------ -----------------
Loss from Discontinued Operations, Net of Tax - (7,237)
- ------------------------------------------------------------------------------- ------------------ -----------------
Net Income Available for Common Stock 111 19,156
- ------------------------------------------------------------------------------- ------------------ -----------------
EARNINGS REINVESTED IN THE BUSINESS
Balance at April 1 877,599 793,409
- ------------------------------------------------------------------------------- ------------------ -----------------
877,710 812,565
Share Repurchases 44,766 -
Dividends on Common Stock
(2006 - $0.30 per share; 2005 - $0.29 per share) 24,993 24,312
- ------------------------------------------------------------------------------- ------------------ -----------------
Balance at June 30 $807,951 $788,253
=============================================================================== ================== =================
Earnings Per Common Share:
Basic:
Income from Continuing Operations $ - $0.32
Loss from Discontinued Operations - (0.09)
- ------------------------------------------------------------------------------- ------------------ -----------------
Net Income Available for Common Stock $ - $0.23
=============================================================================== ================== =================
Diluted:
Income from Continuing Operations $ - $0.31
Loss from Discontinued Operations - (0.08)
- ------------------------------------------------------------------------------- ------------------ -----------------
Net Income Available for Common Stock $ - $0.23
=============================================================================== ================== =================
Weighted Average Common Shares Outstanding:
Used in Basic Calculation 84,013,556 83,568,251
=============================================================================== ================== =================
Used in Diluted Calculation 86,016,131 84,897,466
=============================================================================== ================== =================
See Notes to Condensed Consolidated Financial Statements
6
Item 1. Financial Statements (Cont.)
Consolidated Statements of Income and Earnings
Back to 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) 2006 2005
----------------- -----------------
INCOME
Operating Revenues $2,017,189 $1,636,484
- -------------------------------------------------------------------------------- ----------------- -----------------
Operating Expenses
Purchased Gas 1,187,952 877,510
Operation and Maintenance 320,821 297,549
Property, Franchise and Other Taxes 54,147 53,551
Depreciation, Depletion and Amortization 134,267 132,438
Impairment of Oil and Gas Producing Properties 62,371 -
- -------------------------------------------------------------------------------- ----------------- -----------------
1,759,558 1,361,048
- -------------------------------------------------------------------------------- ----------------- -----------------
Operating Income 257,631 275,436
Other Income (Expense):
Income from Unconsolidated Subsidiaries 2,199 1,914
Interest Income 4,301 1,783
Other Income 1,535 5,979
Interest Expense on Long-Term Debt (54,502) (54,989)
Other Interest Expense (4,266) (8,911)
- -------------------------------------------------------------------------------- ----------------- -----------------
Income from Continuing Operations Before
Income Taxes 206,898 221,212
Income Tax Expense 70,775 86,009
- -------------------------------------------------------------------------------- ----------------- -----------------
Income from Continuing Operations 136,123 135,203
- -------------------------------------------------------------------------------- ----------------- -----------------
Income from Discontinued Operations, Net of Tax - 5,073
- -------------------------------------------------------------------------------- ----------------- -----------------
Net Income Available for Common Stock 136,123 140,276
- -------------------------------------------------------------------------------- ----------------- -----------------
EARNINGS REINVESTED IN THE BUSINESS
Balance at October 1 813,020 718,926
- -------------------------------------------------------------------------------- ----------------- -----------------
949,143 859,202
Share Repurchases 67,384 -
Dividends on Common Stock
(2006 - $0.88; 2005 - $0.85) 73,808 70,949
- -------------------------------------------------------------------------------- ----------------- -----------------
Balance at June 30 $807,951 $788,253
================================================================================ ================= =================
Earnings Per Common Share:
Basic:
Income from Continuing Operations $1.62 $1.62
Income from Discontinued Operations - 0.06
- -------------------------------------------------------------------------------- ----------------- -----------------
Net Income Available for Common Stock $1.62 $1.68
================================================================================ ================= =================
Diluted:
Income from Continuing Operations $1.58 $1.59
Income from Discontinued Operations - 0.06
- -------------------------------------------------------------------------------- ----------------- -----------------
Net Income Available for Common Stock $1.58 $1.65
================================================================================ ================= =================
Weighted Average Common Shares Outstanding:
Used in Basic Calculation 84,231,490 83,343,711
================================================================================ ================= =================
Used in Diluted Calculation 86,150,927 84,771,403
================================================================================ ================= =================
See Notes to Condensed Consolidated Financial Statements
7
Item 1. Financial Statements (Cont.)
Back to Table of Contents
National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)
June 30, September 30,
2006 2005
-------------------- -------------------
(Thousands of Dollars)
ASSETS
Property, Plant and Equipment $4,638,247 $4,423,255
Less - Accumulated Depreciation, Depletion
and Amortization 1,753,147 1,583,955
- ---------------------------------------------------------------------------- -------------------- -------------------
2,885,100 2,839,300
- ---------------------------------------------------------------------------- -------------------- -------------------
Current Assets
Cash and Temporary Cash Investments 121,626 57,607
Hedging Collateral Deposits 14,684 77,784
Receivables - Net of Allowance for Uncollectible Accounts of
$34,097 and $26,940, Respectively 233,150 155,064
Unbilled Utility Revenue 15,529 20,465
Gas Stored Underground 40,803 64,529
Materials and Supplies - at average cost 35,925 33,267
Unrecovered Purchased Gas Costs - 14,817
Prepayments and Other Current Assets 43,681 65,469
Deferred Income Taxes 51,239 83,774
- ---------------------------------------------------------------------------- -------------------- -------------------
556,637 572,776
- ---------------------------------------------------------------------------- -------------------- -------------------
Other Assets
Recoverable Future Taxes 84,667 85,000
Unamortized Debt Expense 16,000 17,567
Other Regulatory Assets 60,134 47,028
Deferred Charges 5,715 4,474
Other Investments 87,291 80,394
Investments in Unconsolidated Subsidiaries 10,206 12,658
Goodwill 5,476 5,476
Intangible Assets 40,305 42,302
Fair Value of Derivative Financial Instruments 8,266 -
Other 5,728 15,677
- ---------------------------------------------------------------------------- -------------------- -------------------
323,788 310,576
- ---------------------------------------------------------------------------- -------------------- -------------------
Total Assets $3,765,525 $3,722,652
============================================================================ ==================== ===================
See Notes to Condensed Consolidated Financial Statements
8
Item 1. Financial Statements (Cont.)
Consolidated Balance Sheets
Back to Table of Contents
National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)
June 30, September 30,
2006 2005
-------------------- -------------------
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders' Equity
Common Stock, $1 Par Value
Authorized - 200,000,000 Shares; Issued
and Outstanding - 83,309,093 Shares and
84,356,748 Shares, Respectively $ 83,309 $ 84,357
Paid in Capital 553,081 529,834
Earnings Reinvested in the Business 807,951 813,020
- ---------------------------------------------------------------------------- -------------------- -------------------
Total Common Shareholder Equity Before
Items of Other Comprehensive Loss 1,444,341 1,427,211
Accumulated Other Comprehensive Loss (102,611) (197,628)
- ---------------------------------------------------------------------------- -------------------- -------------------
Total Comprehensive Shareholders' Equity 1,341,730 1,229,583
Long-Term Debt, Net of Current Portion 1,111,746 1,119,012
- ---------------------------------------------------------------------------- -------------------- -------------------
Total Capitalization 2,453,476 2,348,595
- ---------------------------------------------------------------------------- -------------------- -------------------
Current and Accrued Liabilities
Notes Payable to Banks and
Commercial Paper - -
Current Portion of Long-Term Debt 9,502 9,393
Accounts Payable 131,540 155,485
Amounts Payable to Customers 31,576 1,158
Dividends Payable 24,978 24,445
Other Accruals and Current Liabilities 104,350 60,404
Fair Value of Derivative Financial Instruments 75,239 209,072
- ---------------------------------------------------------------------------- -------------------- -------------------
377,185 459,957
- ---------------------------------------------------------------------------- -------------------- -------------------
Deferred Credits
Deferred Income Taxes 494,957 489,720
Taxes Refundable to Customers 11,073 11,009
Unamortized Investment Tax Credit 6,270 6,796
Cost of Removal Regulatory Liability 94,166 90,396
Other Regulatory Liabilities 58,376 66,339
Pension and Other Post-Retirement Liabilities 155,579 143,687
Asset Retirement Obligation 42,940 41,411
Other Deferred Credits 71,503 64,742
- ---------------------------------------------------------------------------- -------------------- -------------------
934,864 914,100
- ---------------------------------------------------------------------------- -------------------- -------------------
Commitments and Contingencies - -
- ---------------------------------------------------------------------------- -------------------- -------------------
Total Capitalization and Liabilities $3,765,525 $3,722,652
============================================================================ ==================== ===================
See Notes to Condensed Consolidated Financial Statements
9
Item 1. Financial Statements (Cont.)
Back to Table of Contents
National Fuel Gas Company
Consolidated Statements of Cash Flows
Unaudited)
Nine Months Ended
June 30,
(Thousands of Dollars) 2006 2005
------------------ ----------------------
OPERATING ACTIVITIES
Net Income Available for Common Stock $136,123 $140,276
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities:
Impairment of Oil and Gas Producing Properties 62,371 -
Depreciation, Depletion and Amortization 134,267 145,814
Deferred Income Taxes (17,430) 1,994
Income from Unconsolidated Subsidiaries, Net of
Cash Distributions 2,452 (374)
Minority Interest in Foreign Subsidiaries - 2,899
Excess Tax Benefits Associated with Stock-Based
Compensation Awards (6,515) -
Other (6,493) (9,342)
Change in:
Hedging Collateral Deposits 63,100 (8,513)
Receivables and Unbilled Utility Revenue (72,496) (91,223)
Gas Stored Underground and Materials and
Supplies 21,098 32,878
Unrecovered Purchased Gas Costs 14,817 7,532
Prepayments and Other Current Assets 21,800 1,524
Accounts Payable (24,650) 3,886
Amounts Payable to Customers 30,418 37,492
Other Accruals and Current Liabilities 49,950 63,749
Other Assets (15,753) (8,621)
Other Liabilities 16,855 (5,573)
- ------------------------------------------------------------------------------- ------------------ ----------------------
Net Cash Provided by Operating Activities 409,914 334,398
- ------------------------------------------------------------------------------- ------------------ ----------------------
INVESTING ACTIVITIES
Capital Expenditures (218,658) (157,401)
Net Proceeds from Sale of Oil and Gas Producing Properties 4 90
Other (1,578) 4,001
- ------------------------------------------------------------------------------- ------------------ ----------------------
Net Cash Used in Investing Activities (220,232) (153,310)
- ------------------------------------------------------------------------------- ------------------ ----------------------
FINANCING ACTIVITIES
Change in Notes Payable to Banks and Commercial Paper - (107,243)
Excess Tax Benefits Associated with Stock-Based
Compensation Awards 6,515 -
Shares Repurchased under Repurchase Plan (76,540) -
Reduction of Long-Term Debt (7,157) (10,740)
Dividends Paid on Common Stock (73,275) (69,847)
Dividends Paid to Minority Interest - (12,676)
Proceeds from Issuance of Common Stock 23,399 12,499
- ------------------------------------------------------------------------------- ------------------ ----------------------
Net Cash Used in Financing Activities (127,058) (188,007)
- ------------------------------------------------------------------------------- ------------------ ----------------------
Effect of Exchange Rates on Cash 1,395 (40)
- ------------------------------------------------------------------------------- ------------------ ----------------------
Net Increase (Decrease) in Cash and Temporary Cash
Investments 64,019 (6,959)
Cash and Temporary Cash Investments at October 1 57,607 57,541
- ------------------------------------------------------------------------------- ------------------ ----------------------
Cash and Temporary Cash Investments at June 30 $121,626 $50,582
=============================================================================== ================== ======================
See Notes to Condensed Consolidated Financial Statements
10
Item 1. Financial Statements (Cont.)
Back to Table of Contents
National Fuel Gas Company
Consolidated Statements of Comprehensive Income
(Unaudited)
Three Months Ended
June 30,
(Thousands of Dollars) 2006 2005
--------------- -- --------------
Net Income Available for Common Stock $111 $19,156
- ---------------------------------------------------------------------------- --------------- -- --------------
Other Comprehensive Income (Loss), Before Tax:
Foreign Currency Translation Adjustment 8,292 (15,717)
Unrealized Gain on Securities Available for Sale
Arising During the Period 1,126 134
Unrealized Loss on Derivative Financial Instruments
Arising During the Period (2,340) (4,153)
Reclassification Adjustment for Realized Losses on
Derivative Financial Instruments in Net Income 14,687 19,220
- ---------------------------------------------------------------------------- --------------- -- --------------
Other Comprehensive Income (Loss) Before Tax 21,765 (516)
- ---------------------------------------------------------------------------- --------------- -- --------------
Income Tax Benefit Related to Cumulative Translation
Adjustment - (251)
Income Tax Expense (Benefit) Related to Unrealized Gain on
Securities Available for Sale Arising During the Period 391 (35)
Income Tax Benefit Related to Unrealized Loss on
Derivative Financial Instruments Arising During the Period (931) (1,665)
Reclassification Adjustment for Income Tax Benefit on
Realized Losses on Derivative Financial Instruments
In Net Income 5,668 7,263
- ---------------------------------------------------------------------------- --------------- -- --------------
Income Taxes - Net 5,128 5,312
- ---------------------------------------------------------------------------- --------------- -- --------------
Other Comprehensive Income (Loss) 16,637 (5,828)
- ---------------------------------------------------------------------------- --------------- -- --------------
Comprehensive Income $16,748 $13,328
============================================================================ =============== == ==============
Nine Months Ended
June 30,
(Thousands of Dollars) 2006 2005
--------------- -- --------------
Net Income Available for Common Stock $136,123 $140,276
- ---------------------------------------------------------------------------- --------------- -- --------------
Other Comprehensive Income (Loss), Before Tax:
Foreign Currency Translation Adjustment 7,556 7,183
Unrealized Gain on Securities Available for Sale
Arising During the Period 3,388 1,484
Unrealized Gain (Loss) on Derivative Financial Instruments
Arising During the Period 60,275 (84,385)
Reclassification Adjustment for Realized Gains on
Securities Available for Sale in Net Income - (652)
Reclassification Adjustment for Realized Losses on
Derivative Financial Instruments in Net Income 78,412 55,062
- ---------------------------------------------------------------------------- --------------- -- --------------
Other Comprehensive Income (Loss) Before Tax 149,631 (21,308)
- ---------------------------------------------------------------------------- --------------- -- --------------
Income Tax Expense Related to Cumulative Translation
Adjustment - 112
Income Tax Expense Related to Unrealized Gain on
Securities Available for Sale Arising During the Period 1,183 519
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss)
On Derivative Financial Instruments Arising During the Period 23,178 (32,318)
Reclassification Adjustment for Income Tax Expense on
Realized Gains from Securities Available for Sale in Net Income - (228)
Reclassification Adjustment for Income Tax Benefit on
Realized Losses on Derivative Financial Instruments
In Net Income 30,253 20,845
- ---------------------------------------------------------------------------- --------------- -- --------------
Income Taxes - Net 54,614 (11,070)
- ---------------------------------------------------------------------------- --------------- -- --------------
Other Comprehensive Income (Loss) 95,017 (10,238)
- ---------------------------------------------------------------------------- --------------- -- --------------
Comprehensive Income $231,140 $130,038
============================================================================ =============== == ==============
See Notes to Condensed Consolidated Financial Statements
11
Item 1. Financial Statements (Cont.)
Back to Table of ContentsNational Fuel Gas Company
Notes to Condensed Consolidated Financial Statements
(Unaudited)
Note 1 – Summary of Significant Accounting Policies
Principles of Consolidation. The Company consolidates its majority owned entities. The equity method is used to account for minority owned entities. All significant intercompany balances and transactions are eliminated.
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.
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, 2005, 2004 and 2003 that are included in the 2005 Form 10-K. The consolidated financial statements for the year ended September 30, 2006 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, 2006 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2006. 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.
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.
Hedging Collateral Deposits.Cash held in margin accounts serve as collateral for open positions on exchange-traded futures contracts, exchange-traded options and over-the-counter swaps and collars.
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 $50.0 million at June 30, 2006, is reduced to zero by September 30 as the inventory is replenished.
Property, Plant and Equipment.Oil and gas property acquisition, exploration and development costs are capitalized under the full-cost method of accounting. All costs directly associated with property acquisition, exploration and development activities are capitalized, up to certain specified limits. If capitalized costs exceed these limits at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. The Company’s capitalized costs exceeded the full-cost ceiling for the Company’s Canadian properties at June 30, 2006. As such, the Company recognized an impairment of $62.4 million at June 30, 2006.
Accumulated Other Comprehensive Income (Loss). The components of Accumulated Other Comprehensive Income (Loss), net of related tax effect, are as follows (in thousands):
12
Item 1. Financial Statements (Cont.)
At June 30, 2006 At September 30, 2005
---------------- ---------------------
Minimum Pension Liability Adjustment $(107,844) $(107,844)
Cumulative Foreign Currency
Translation Adjustment 35,565 28,009
Net Unrealized Loss on Derivative
Financial Instruments (38,083) (123,339)
Net Unrealized Gain on Securities
Available for Sale 7,751 5,546
---------- ----------
Accumulated Other Comprehensive Loss $(102,611) $(197,628)
========== ==========
Earnings Per Common Share. Basic earnings per common share is computed by dividing 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. The diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these stock options as determined using the Treasury Stock Method. Stock options that are antidilutive are excluded from the calculation of diluted earnings per common share. For the quarters ended June 30, 2006 and 2005, 171,429 and 657,769 stock options, respectively, were excluded as being antidilutive. For the nine months ended June 30, 2006 and 2005, 57,143 and 226,322 stock options, respectively, were excluded as being antidilutive.
Share Repurchases.The Company considers all shares repurchased as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. The repurchases are accounted for on the date the share repurchase is settled as an adjustment to common stock (at par value) with the excess repurchase price allocated between paid in capital and retained earnings. Refer to Note 3 – Capitalization for further discussion of the share repurchase program.
Stock-Based Compensation.The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, restricted stock, performance units or performance shares. Stock options under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no option is exercisable less than one year or more than ten years after the date of each grant. Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. Certificates for shares of restricted stock awarded under the Company’s stock option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective. Restrictions on restricted stock awards generally lapse ratably over a period of not more than ten years after the date of each grant.
Prior to October 1, 2005, the Company accounted for its stock-based compensation under the recognition and measurement principles of APB 25 and related interpretations. Under that method, no compensation expense was recognized for options granted under the Company’s stock option and stock award plans. The Company did record, in accordance with APB 25, compensation expense for the market value of restricted stock on the date of the award over the periods during which the vesting restrictions existed.
Effective October 1, 2005, the Company adopted SFAS 123R, which requires the measurement and recognition of compensation cost at fair value for all share-based payments, including stock options. The Company has chosen to use the modified version of prospective application, as allowed by SFAS 123R. Using the modified prospective application, the Company is recording compensation cost for the portion of awards granted prior to October 1, 2005 for which the requisite service had not been rendered and is recognizing such compensation cost as the requisite service is rendered on or after October 1, 2005. Such compensation expense is based on the grant-date fair value of the awards as calculated for the Company’s disclosure using a Binomial option-pricing model under SFAS 123. Any new awards, modifications to awards, repurchases of awards, or cancellations of awards subsequent to September 30, 2005 will follow the provisions of SFAS 123R, with compensation expense being calculated using the
13
Item 1. Financial Statements (Cont.)
Black-Scholes-Merton closed form model. The Company has chosen the Black-Scholes-Merton closed form model since it is easier to administer than the Binomial option-pricing model. Furthermore, since the Company does not have complex stock-based compensation awards, it does not believe that compensation expense would be materially different under either model. There were 300,000 stock-based compensation awards granted during the quarter and nine months ended June 30, 2006. There were 57,000 and 700,000 stock options granted during the quarter and nine months ended June 30, 2005, respectively. Stock-based compensation expense for the quarters ended June 30, 2006 and June 30, 2005 totaled approximately $978,000 ($572,000 of which relates to the application of the non-substantive vesting period approach discussed below) and $101,000, respectively. Stock-based compensation expense for the nine months ended June 30, 2006 and June 30, 2005 was approximately $1,261,000 ($572,000 of which relates to the application of the non-substantive vesting period approach discussed below) and $416,000, respectively. Stock-based compensation expense is included in operation and maintenance expenses in the consolidated statement of income. The total income tax benefit related to stock-based compensation expense during the quarters ended June 30, 2006 and June 30, 2005 was approximately $362,000 and $40,000, respectively. The total income tax benefit related to stock-based compensation expense during the nine months ended June 30, 2006 and June 30, 2005 was approximately $474,000 and $166,000, respectively. There were no capitalized stock-based compensation costs during the quarters ended June 30, 2006 and June 30, 2005.
Prior to the adoption of SFAS 123R, the Company followed the nominal vesting period approach under the disclosure requirements of SFAS 123 for determining the vesting period for awards with retirement eligible provisions, which recognized stock-based compensation expense over the nominal vesting period. As a result of the adoption of SFAS 123R, the Company currently applies the non-substantive vesting period approach for determining the vesting period of such awards. Under this approach, the retention of the award is not contingent on providing subsequent service and the vesting period would begin at the grant date and end at the retirement-eligible date. For the quarter and nine months ended June 30, 2006, the Company recognized an additional $572,000 ($372,000 net of tax) of stock-based compensation expense by applying the non-substantive vesting approach for awards granted in the quarter ended June 30, 2006. For the quarter ended June 30, 2005, stock-based compensation expense would have been $2,449,000 ($1,592,000 net of tax) for pro forma recognition purposes had the non-substantive vesting period approach been used. The pro forma stock-based compensation expense would remain unchanged under the non-substantive vesting period approach for the nine months ended June 30, 2005. Pro forma stock-based compensation expense following the nominal vesting period approach is shown in the table below.
The following table illustrates the effect on net income and earnings per share of the Company had the Company applied the fair value recognition provisions of SFAS 123 relating to stock-based employee compensation for the three and nine months ended June 30, 2005:
14
Item 1. Financial Statements (Cont.)
Three Months Ended Nine Months Ended
(Thousands of Dollars, Except Per June 30, June 30,
Common Share Amounts) 2005 2005
------------------ -----------------
Net Income, Available for
Common Stock, as Reported $19,156 $140,276
Add:
Stock-Based Employee Compensation
Expense Included in Reported Net Income,
Net of Tax (1) 66 270
Deduct:
Total Stock-Based Employee Compensation
Expense Determined Under Fair Value
Based Method for all Awards, Net of
Related Tax Effects (2,073) (2,752)
-------- ---------
Pro Forma Net Income Available
For Common Stock $17,149 $137,794
======== =========
Earnings Per Common Share:
Basic - As Reported $0.23 $1.68
Basic - Pro Forma $0.21 $1.65
Diluted - As Reported $0.23 $1.65
Diluted - Pro Forma $0.20 $1.63
| | (1) | Stock-based compensation expense in 2005 represented compensation expense related to restricted stock awards. The pre-tax expense was $101,000 and $416,000, respectively, for the quarter and nine months ended June 30, 2005. |
Stock Options
Transactions during the nine months ended June 30, 2006 were as follows (in thousands, except option prices and years):
Weighted
Weighted Average
Average Remaining Aggregate
Number Exercise Contractual Intrinsic
of Options Price Life (Years) Value
---------- --------- ------------ ---------
Options Outstanding at September 30, 2005 10,997 $ 23.78
Granted - -
Exercised (178) 21.24
Forfeited - -
------- -------
Options Outstanding at December 31, 2005 10,819 23.82
Granted - -
Exercised (330) 22.34
Forfeited (3) 25.89
------- -------
Options Outstanding at March 31, 2006 10,486 23.87
Granted 300 35.11
Exercised (1,037) 22.68
Forfeited - -
------- -------
Options Outstanding at June 30, 2006 9,749 $ 24.34 4.23 $ 105,279
======= ======= ======= =========
Options Exercisable at June 30, 2006 9,353 $ 24.01 4.02 $ 104,138
======== ======= ======= =========
15
Item 1. Financial Statements (Cont.)
The total intrinsic value of stock options exercised during the quarters ended June 30, 2006 and June 30, 2005 totaled approximately $13.2 million and $4.9 million, respectively. The amount of cash received by the Company from the exercise of such stock options was approximately $17.7 million during the quarter ended June 30, 2006 and approximately $7.3 million during the quarter ended June 30, 2005. The total intrinsic value of stock options exercised during the nine months ended June 30, 2006 and June 30, 2005 totaled approximately $18.3 million and $13.4 million, respectively. For the nine months ended June 30, 2006 and June 30, 2005, the amount of cash received by the Company from the exercise of stock options was approximately $25.8 million and $15.5 million, respectively. The Company realizes tax benefits related to the exercise of stock options on a calendar basis as opposed to a fiscal year basis. As such, for stock options exercised during the quarters ended December 31, 2005 and December 31, 2004, the Company realized a tax benefit of $0.9 million and $1.1 million, respectively. For stock options exercised during the period of January 1, 2006 through June 30, 2006, the Company will realize a tax benefit of approximately $6.5 million in the quarter ended December 31, 2006. For stock options exercised during the period of January 1, 2005 through June 30, 2005, the Company realized a tax benefit of approximately $3.8 million in the quarter ended December 31, 2005. The weighted average grant date fair value of options granted during the quarters ended June 30, 2006 and June 30, 2005 is $6.67 per share and $4.28 per share, respectively. For the nine months ended June 30, 2006, 150,664 stock options became fully vested. The total fair value of these stock options was approximately $887,000. For the nine months ended June 30, 2005, 1,281,008 stock options became fully vested. The total fair value of these stock options was approximately $5.8 million. As of June 30, 2006, unrecognized compensation expense related to stock options totaled approximately $1.2 million, which will be recognized over a weighted average period of one year.
The fair value of options at the date of grant was estimated using a Binomial option-pricing model for options granted prior to October 1, 2005 and the Black-Scholes-Merton closed form model for options granted after September 30, 2005. The following weighted average assumptions were used in estimating the fair value of options at the date of grant:
June 30,
--------------------
2006 2005
---- ----
Risk Free Interest Rate 4.79% 4.04%
Expected Life (years) 6.8 6.6
Expected Volatility 19.29% 21.16%
Expected Dividend Yield (Quarterly) 0.97% 1.10%
The risk-free interest rate is based on the yield of a Treasury Note with a remaining term commensurate with the expected term of the option. The expected life and expected volatility are based on historical experience.
For grants prior to October 1, 2005, the Company used a forfeiture rate of 13.6% for calculating stock-based compensation expense related to stock options and this rate is based on the Company’s historical experience of forfeitures on unvested stock option grants. For the grant during the quarter ended June 30, 2006, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees.
Restricted Share Awards
Transactions during the nine months ended June 30, 2006 were as follows (in thousands, except fair values):
16
Item 1. Financial Statements (Cont.)
Number of Weighted Average
Restricted Fair Value per
Share Awards Award
------------ ---------------
Restricted Share Awards Outstanding at
September 30, 2005 65 $ 24.46
Granted - -
Vested (8) 23.75
Forfeited - -
------- ---------
Restricted Share Awards Outstanding at
December 31, 2005 57 24.56
Granted - -
Vested (25) 24.50
Forfeited - -
------- ---------
Restricted Share Awards Outstanding at
March 31, 2006 32 24.60
Granted 16 34.94
Vested - -
Forfeited - -
------- --------
Restricted Share Awards Outstanding at
June 30, 2006 48 $ 28.05
======= ========
As of June 30, 2006, unrecognized compensation expense related to restricted share awards totaled approximately $650,000, which will be recognized over a weighted average period of 2.1 years.
On June 20, 2006, a modification was made to a restricted share award involving one employee. The modification accelerated the vesting date of 4,000 shares from December 7, 2006 to July 1, 2006. The incremental compensation expense, totaling approximately $32,000, was included with the total stock-based compensation expense for the quarter and nine months ended June 30, 2006, as stated above.
New Accounting Pronouncements. In March 2005, the FASB issued FIN 47, an interpretation of SFAS 143. FIN 47 provides clarification of the term “conditional asset retirement obligation” as used in SFAS 143, defined as a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the Company. Under this standard, a company must record a liability for a conditional asset retirement obligation if the fair value of the obligation can be reasonably estimated. FIN 47 also serves to clarify when a company would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation. FIN 47 becomes effective no later than the end of fiscal 2006. The Company is currently evaluating the impact of FIN 47 on its consolidated financial statements.
In May 2005, the FASB issued SFAS 154. SFAS 154 replaces APB 20 and SFAS 3 and changes the requirements for the accounting for and reporting of a change in accounting principle. The Company is required to adopt SFAS 154 for accounting changes and corrections of errors that occur in fiscal 2007. Early adoption is permitted. The Company’s financial condition and results of operations will only be impacted by SFAS 154 if there are any accounting changes or corrections of errors in the future.
In June 2006, the FASB issued FIN 48, an interpretation of SFAS 109. FIN 48 clarifies the accounting for uncertainty in income taxes and reduces the diversity in current practice associated with the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return by defining a “more-likely-than-not” threshold regarding the sustainability of the position. The Company is required to adopt FIN 48 by the first quarter of fiscal 2008. The Company is currently evaluating the impact of FIN 48 on its consolidated financial statements.
17
Item 1. Financial Statements (Cont.)
Note 2 — Income Taxes
The components of federal, state and foreign income taxes included in the Consolidated Statements of Income are as follows (in thousands):
Nine Months Ended
June 30,
2006 2005
------------------- --------------------
Operating Expenses:
Current Income Taxes
Federal $68,914 $71,088
State 17,079 19,872
Foreign 2,212 1,568
Deferred Income Taxes
Federal 2,427 (7,937)
State 1,519 (2,718)
Foreign (21,376) 4,136
------------------- --------------------
70,775 86,009
Other Income:
Deferred Investment Tax Credit (523) (523)
Discontinued Operations - 15,383
------------------- --------------------
Total Income Taxes $70,252 $100,869
=================== ====================
The U.S. and foreign components of income (loss) before income taxes are as follows (in thousands):
Nine Months Ended
June 30,
2006 2005
------------------- --------------------
U.S. $248,226 $206,737
Foreign (41,851) 34,408
------------------- --------------------
$206,375 $241,145
=================== ====================
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,
2006 2005
------------------- --------------------
Income Tax Expense, Computed at
Statutory Rate of 35% $72,231 $84,401
Increase (Reduction) in Taxes Resulting From:
State Income Taxes 12,089 11,150
Dividend from Foreign Subsidiary - 3,708
Foreign Tax Differential (5,211) (1) (1,122)
Tax on Unremitted Earnings - 6,000
Reversal of Capital Loss Valuation Allowance (2,877) -
Miscellaneous (5,980) (2) (3,268)
------------------- --------------------
Total Income Taxes $70,252 $100,869
=================== ====================
| | (1) | Includes a $5.1 million deferred tax benefit relating to additional future tax deductions forecasted in the Exploration and Production segment’s Canadian division. |
| | (2) | Includes a net reversal of $3.2 million relating to a tax contingency reserve. |
18
Item 1. Financial Statements (Cont.)
Significant components of the Company’s deferred tax liabilities (assets) were as follows (in thousands):
At June 30, 2006 At September 30, 2005
--------------------------------- ----------------------------
Deferred Tax Liabilities:
Property, Plant and Equipment $577,695 $567,850
Other 39,459 52,436
--------------------------------- ----------------------------
Total Deferred Tax Liabilities 617,154 620,286
--------------------------------- ----------------------------
Deferred Tax Assets:
Minimum Pension Liability Adjustment (58,070) (58,069)
Capital Loss Carryover (9,812) (9,145)
Unrealized Hedging Losses (21,042) (75,657)
Other (84,512) (74,346)
--------------------------------- ----------------------------
(173,436) (217,217)
Valuation Allowance - 2,877
--------------------------------- ----------------------------
Total Deferred Tax Assets (173,436) (214,340)
--------------------------------- ----------------------------
Total Net Deferred Income Taxes $443,718 $405,946
--------------------------------- ----------------------------
Presented as Follows:
Net Deferred Tax Asset - Current $(51,239) $(83,774)
Net Deferred Tax Liability - Non-Current 494,957 489,720
--------------------------------- ----------------------------
Total Net Deferred Income Taxes $443,718 $405,946
================================= ============================
Regulatory liabilities representing the reduction of previously recorded deferred income taxes with rate-regulated activities that are expected to be refundable to customers amounted to $11.1 million and $11.0 million at June 30, 2006 and September 30, 2005, 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 $84.7 million and $85.0 million at June 30, 2006 and September 30, 2005, respectively.
The American Jobs Creation Act of 2004 was signed into law on October 22, 2004. This legislation included a provision which provided a substantially reduced tax rate of 5.25% on certain dividends received from foreign affiliates. In the quarter ended June 30, 2005, the Company received a dividend of $72.8 million from a foreign affiliate and recorded a tax of $3.8 million on such dividend.
A capital loss carryover of $28.0 million existed at June 30, 2006, which expires if not utilized by September 30, 2008. Although realization is not assured, management determined during this quarter that it is more likely than not that the entire deferred tax asset associated with this carryover will be realized during the carryover period. As such, the valuation allowance of $2.877 million was reversed during the quarter.
Note 3 – Capitalization
Common Stock.During the nine months ended June 30, 2006, the Company issued 1,544,606 shares of common stock as a result of stock option exercises and 16,000 shares for restricted stock awards (non-vested stock as defined in SFAS 123R). The Company also issued 6,300 shares of common stock to the non-employee directors of the Company as partial consideration for the directors’ services during the nine months ended June 30, 2006. Holders of stock options 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, 2006, 330,211 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.
On December 8, 2005, the Company’s board of directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of 8 million shares in the open market or through privately negotiated transactions. During the nine months ended June 30, 2006, the Company repurchased 2,284,350 shares
19
Item 1. Financial Statements (Cont.)
under this program, funded with cash provided by operating activities. At June 30, 2006, the Company had made commitments to repurchase an additional 49,000 shares of common stock. These commitments were settled and recorded as a reduction of the Company’s outstanding shares of common stock in July 2006.
Note 4 – 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 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. At June 30, 2006, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be $3.8 million. This liability has been recorded on the Consolidated Balance Sheet at June 30, 2006. The Company expects to recover its environmental clean-up costs from a combination of insurance proceeds and rate recovery. Other than as discussed in Note G of the Company’s 2005 Form 10-K (referred to below), the Company is currently not aware of any material additional exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could 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 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 to have a material adverse effect on the financial condition of the Company.
Note 5 – Discontinued Operations
On July 18, 2005, the Company completed the sale of its entire 85.16 percent interest in U.E., a district heating and electric generation business in the Bohemia region of the Czech Republic, to Czech Energy Holdings, a.s. for sales proceeds of approximately $116.3 million. The sale resulted in the recognition of a gain of approximately $25.8 million, net of tax, at September 30, 2005. Market conditions during 2005, including the increasing value of the Czech currency as compared to the U.S. dollar, caused the value of the assets of U.E. to increase, providing an opportunity to sell the U.E. operations at a profit for the Company. As a result of the decision to sell its majority interest in U.E., the Company began presenting the Czech Republic operations, which are primarily comprised of U.E., as discontinued operations in June 2005. U.E. was the major component of the Company’s International segment. With this change in presentation, the Company discontinued all reporting for an International segment.
The following is selected financial information of the discontinued operations for U.E.:
20
Item 1. Financial Statements (Cont.)
Three Months Ended Nine Months
Ended
June 30, June 30,
(Thousands) 2005 2005
-------------------- --------------
Operating Revenues $22,626 $122,088
Operating Expenses 25,626 99,276
-------------------- --------------
Operating Income (Loss) (3,000) 22,812
Other Income 918 2,059
Interest Expense (186) (507)
-------------------- --------------
Income (Loss) before Income Taxes
and Minority Interest (2,268) 24,364
Income Tax Expense 5,412 16,392
Minority Interest, Net of Taxes (443) 2,899
-------------------- -------------
Income (Loss) from Discontinued Operations $(7,237) $5,073
==================== =============
Note 6 – Business Segment Information
The Company has five reportable segments: Utility, Pipeline and Storage, Exploration and Production, Energy Marketing, and Timber. The division of the Company’s operations into the 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 the reportable segments and reconciliations to consolidated amounts. As stated in the 2005 Form 10-K, the Company evaluates segment performance based on income before discontinued operations, extraordinary items and cumulative effects of changes in accounting (where 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 2005 Form 10-K. There have been no material changes in the amount of assets for any operating segment from the amounts disclosed in the 2005 Form 10-K.
21
Item 1. Financial Statements (Cont.)
Quarter Ended June 30, 2006 (Thousands)
- ----------------------------------------------------------------------------------------------------------------------------------
Pipeline Exploration Total Corporate and
and and Energy Reportable Intersegment Total
Utility Storage Production Marketing Timber Segments All Other Eliminations Consolidated
- ----------------------------------------------------------------------------------------------------------------------------------
Revenue from
External Customers $186,661 $30,750 $86,600 $94,747 $15,311 $414,069 $1,192 $ 191 $415,452
Intersegment
Revenues $ 2,514 $20,298 $ - $ - $ 4 $22,816 $1,354 $(24,170) $ -
Segment Profit
(Loss):
Net Income (Loss) $ 827 $12,642 $(15,127) $ 1,045 $ 1,529 $916 $ (212) $ (593) $111
Nine Months Ended June 30, 2006 (Thousands)
- ----------------------------------------------------------------------------------------------------------------------------------
Pipeline Exploration Total Corporate and
and and Energy Reportable Intersegment Total
Utility Storage Production Marketing Timber Segments All Other Eliminations Consolidated
- ----------------------------------------------------------------------------------------------------------------------------------
Revenue from
External Customers $1,154,375 $104,835 $257,406 $446,367 $51,377 $2,014,360 $2,250 $ 579 $2,017,189
Intersegment
Revenues $ 12,317 $61,304 $ - $ - $ 4 $ 73,625 $7,938 $(81,563) $ -
Segment Profit
(Loss):
Net Income (Loss) $ 51,234 $45,384 $28,152 $ 5,909 $5,235 $ 135,914 $404 $ (195) $ 136,123
Quarter Ended June 30, 2005 (Thousands)
- ----------------------------------------------------------------------------------------------------------------------------------
Pipeline Exploration Total Corporate and
and and Energy Reportable Intersegment Total
Utility Storage Production Marketing Timber Segments All Other Eliminations Consolidated
- ----------------------------------------------------------------------------------------------------------------------------------
Revenue from
External Customers $189,175 $29,642 $77,370 $88,048 $15,028 $399,263 $1,096 $ - $400,359
Intersegment
Revenues $ 2,734 $20,956 $ - $ - $ - $23,690 $1,782 $ (25,472) $ -
Segment Profit
(Loss):
Income (Loss) from
Continuing
Operations $ (1,684) $10,843 $13,830 $ 1,548 $ 555 $25,092 $ 270 $ 1,031 $26,393
Nine Months Ended June 30, 2005 (Thousands)
- ----------------------------------------------------------------------------------------------------------------------------------
Pipeline Exploration Total Corporate and
and and Energy Reportable Intersegment Total
Utility Storage Production Marketing Timber Segments All Other Eliminations Consolidated
- ----------------------------------------------------------------------------------------------------------------------------------
Revenue from
External Customers $991,651 $98,117 $219,527 $276,106 $46,994 $1,632,395 $4,089 $ - $1,636,484
Intersegment
Revenues $ 12,732 $63,071 $ - $ - $ 1 $ 75,804 $ 6,125 $ (81,929) $ -
Segment Profit
(Loss):
Income (Loss) from
Continuing
Operations $ 45,269 $41,577 $38,984 $ 4,909 $4,201 $ 134,940 $1,522 $ (1,259) $ 135,203
22
Item 1. Financial Statements (Cont.)
Note 7 — Intangible Assets
The components of the Company's intangible assets were as follows (in thousands):
At September 30,
At June 30, 2006 2005
----------- ----------------- ----------- ---------------------
Gross Net Net
Carrying Accumulated Carrying Carrying
Amount Amortization Amount Amount
----------- ----------------- ----------- ---------------------
Intangible Assets Subject to Amortization
Long-Term Transportation Contracts $8,580 $(3,653) $4,927 $5,729
Long-Term Gas Purchase Contracts 31,864 (4,628) 27,236 28,431
Intangible Assets Not Subject to Amortization
Retirement Plan Intangible Asset 8,142 - 8,142 8,142
----------- ----------------- ----------- ---------------------
$48,586 $ (8,281) $40,305 $42,302
----------- ----------------- ----------- ---------------------
Aggregate Amortization Expense (Thousands)
Three Months Ended June 30, 2006 $666
Three Months Ended June 30, 2005 $666
Nine Months Ended June 30, 2006 $1,997
Nine Months Ended June 30, 2005 $1,997
Amortization expense for the long-term transportation contracts is estimated to be $0.3 million for the remainder of 2006 and $1.1 million annually for 2007 and 2008. Amortization expense is estimated to be $0.5 million and $0.4 million for 2009 and 2010, respectively.
Amortization expense for the long-term gas purchase contracts is estimated to be $0.4 million for the remainder of 2006 and $1.6 million annually for 2007, 2008, 2009 and 2010.
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
--------------- ------------------------------
2006 2005 2006 2005
---- ---- ---- ----
Service Cost $4,104 $3,429 $2,007 $1,538
Interest Cost 10,049 10,520 6,701 6,446
Expected Return on Plan Assets (12,486) (12,386) (5,576) (4,715)
Amortization of Prior Service Cost 239 257 1 1
Amortization of Transition Amount - - 1,782 1,782
Amortization of Losses 5,777 2,618 5,850 3,116
Net Amortization and Deferral
For Regulatory Purposes (Including
Volumetric Adjustments) (1) (2,232) 1,500 (3,726) (963)
------------- ------------- ------------------- -------------------
Net Periodic Benefit Cost $5,451 $5,938 $7,039 $7,205
============= ============= =================== ===================
23
Item 1. Financial Statements (Cont.)
Nine months ended June 30,
Retirement Plan Other Post-Retirement Benefits
--------------- ------------------------------
2006 2005 2006 2005
---- ---- ---- ----
Service Cost $12,312 $10,285 $6,022 $4,614
Interest Cost 30,147 31,559 20,103 19,338
Expected Return on Plan Assets (37,457) (37,159) (16,727) (14,145)
Amortization of Prior Service Cost 718 772 3 3
Amortization of Transition Amount - - 5,345 5,346
Amortization of Losses 17,331 7,855 17,552 9,348
Net Amortization and Deferral
For Regulatory Purposes (Including
Volumetric Adjustments) (1) (1,853) 5,060 (3,777) 4,272
------------- ------------- ------------------ ------------------
Net Periodic Benefit Cost $21,198 $18,372 $28,521 $28,776
============= ============= ================== ==================
(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, 2006, the Company contributed $20.9 million to its retirement plan and $36.8 million to its other post-retirement benefit plan. The Company does not expect to make any contributions to the retirement plan during the remainder of the fiscal year. In the remainder of 2006, the Company expects to contribute $2.2 million to its other post-retirement benefit plan.
24
Back to Table of ContentsItem 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
OVERVIEW
The Company is a diversified energy company consisting of five reportable business segments. For the quarter and nine months ended June 30, 2006 compared to the quarter and nine months ended June 30, 2005, the Company has experienced an overall decrease in earnings ($19.0 million and $4.2 million, respectively) primarily due to the Exploration and Production segment recording an after-tax impairment charge of $39.5 million related to its Canadian oil and gas assets during the quarter ended June 30, 2006, which is discussed below under Critical Accounting Policies. The Company’s earnings are discussed further in the Results of Operations section that follows.
From a capital resources and liquidity perspective, the Company spent $218.7 million on capital expenditures during the nine months ended June 30, 2006, with approximately 73% being spent in the Exploration and Production segment. This is in line with the Company’s expectations. The Company is still pursuing its Empire Connector project to expand its natural gas pipeline operations. In July 2006, Empire revised the planned in-service date for the Empire Connector to extend beyond November 2007, as originally reported. The new targeted in-service date is November 2008, or sooner if feasible.* On July 20, 2006, FERC issued a Preliminary Determination regarding the non-environmental aspects of Empire’s application for FERC approval, which is discussed further in the Capital Resources and Liquidity section that follows. There are no other significant changes in the status of the project and the Company continues to await FERC approval to build and operate the project. The Company also began repurchasing outstanding shares of common stock during the quarter ended March 31, 2006 under a share repurchase program authorized by the Company’s board of directors. The program authorizes the Company to repurchase up to an aggregate amount of 8 million shares. Through June 30, 2006, the Company had repurchased 2,284,350 shares. These matters are discussed further in the Capital Resources and Liquidity section that follows.
Lastly, on April 7, 2006, the NYPSC, PaPUC and Pennsylvania Office of Consumer Advocate filed a complaint and motion for summary disposition against Supply Corporation with the FERC. The complainants allege that Supply Corporation’s rates are unjust and unreasonable, and that Supply Corporation is permitted to retain more gas from shippers than it needs for fuel and loss. It also asks FERC to determine whether Supply Corporation has the authority to make sales of gas retained from shippers (which are referred to under “Results of Operations” as “unbundled pipeline sales”). The Company believes that Supply Corporation’s rates are fair, reasonable and in the public interest and that it is authorized to make the sales in question. This matter is discussed more fully in the Rate and Regulatory Matters section that follows.
CRITICAL ACCOUNTING POLICIES
For a complete discussion of critical accounting policies, refer to “Critical Accounting Policies” in Item 7 of the 2005 Form 10-K. There have been no material changes to that disclosure other than as set forth below. The information presented below updates and should be read in conjunction with the critical accounting policies in that Form 10-K.
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, which is performed on a country-by-country basis, the present value of future revenues from the Company’s oil and gas reserves based on current market prices (the “ceiling”) is compared with the book value of those reserves at the balance sheet date. If the book value of the reserves in any country exceeds the ceiling, a non-cash charge must be recorded reduce the book value of the reserves to the calculated ceiling. As disclosed in the Company’s March 31, 2006 Form 10-Q, at March 31, 2006, the Canadian oil and gas properties passed the quarterly ceiling test but the book value of the Canadian reserves was nearly equal to the ceiling. Because of the decline in the price of natural gas since March 31, 2006, the book value of the Company’s Canadian oil and gas properties exceeded the ceiling at June 30, 2006. Consequently, SECI recorded an impairment charge of $62.4 million ($39.5 million after-tax) during the quarter ended June 30, 2006. Further decreases in the price of natural gas, absent the addition of new reserves, could result in future impairments.* For a more complete discussion of the full cost method of accounting, refer to “Oil and Gas Exploration and Development Costs” under “Critical Accounting Policies” in Item 7 of the Company’s 2005 Form 10-K.
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)RESULTS OF OPERATIONS
Earnings
The Company’s earnings were $0.1 million for the quarter ended June 30, 2006 compared to earnings of $19.2 million for the quarter ended June 30, 2005. As previously discussed, the Company began presenting its Czech Republic operations as discontinued operations in June 2005. The Company’s earnings from continuing operations were $0.1 million for the quarter ended June 30, 2006 compared to earnings from continuing operations of $26.4 million for the quarter ended June 30, 2005. The decrease in earnings from continuing operations of $26.3 million is primarily the result of lower earnings in the Exploration and Production segment offset somewhat by higher earnings in the Utility, Pipeline and Storage, and Timber segments, as shown in the table below. Earnings for the quarter ended June 30, 2006 include a $62.4 million impairment charge ($39.5 million after-tax) for the Exploration and Production segment’s Canadian oil and gas producing properties under the full cost method of accounting using natural gas pricing at June 30, 2006, which happened to be lower than the pricing at March 31, 2006, the last ceiling test measurement date. The Exploration and Production segment also recognized a $6.1 million benefit to earnings related to income taxes recognized during the quarter ended June 30, 2006.
The Company’s earnings were $136.1 million for the nine months ended June 30, 2006 compared to earnings of $140.3 million for the nine months ended June 30, 2005. The Company’s earnings from continuing operations were $136.1 million for the nine months ended June 30, 2006 compared to earnings from continuing operations of $135.2 million for the nine months ended June 30, 2005. The increase in earnings from continuing operations of $0.9 million is primarily the result of higher earnings in the Utility, Pipeline and Storage, Energy Marketing, and Timber segments, largely offset by lower earnings in the Exploration and Production segment, as shown in the table below. Earnings for the nine months ended June 30, 2006 include a $62.4 million impairment charge ($39.5 million after-tax) for the Company’s Canadian oil and gas producing properties in the Exploration and Production segment, as noted above, and a $11.2 million benefit to earnings related to income taxes, also in the Exploration and Production segment. In addition, earnings for the nine months ended June 30, 2005 include a $2.6 million gain on the sale of base gas in the Pipeline and Storage segment.
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.
Earnings (Loss) by Segment
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Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------------ ------------- ------------- --------------- ------------- ------------- ---------------
Increase/ Increase/
(Thousands) 2006 2005 (Decrease) 2006 2005 (Decrease)
- ------------------------------------ ------------- ------------- --------------- ------------- ------------- ---------------
Utility $827 $(1,684) $2,511 $51,234 $45,269 $5,965
Pipeline and Storage 12,642 10,843 1,799 45,384 41,577 3,807
Exploration and Production (15,127) 3,830 (28,957) 28,152 38,984 (10,832)
Energy Marketing 1,045 1,548 (503) 5,909 4,909 1,000
Timber 1,529 555 974 5,235 4,201 1,034
- ------------------------------------ ------------- ------------- --------------- ------------- ------------- ---------------
Total Reportable Segments 916 25,092 (24,176) 135,914 134,940 974
All Other (212) 270 (482) 404 1,522 (1,118)
Corporate (1) (593) 1,031 (1,624) (195) (1,259) 1,064
- ------------------------------------ ------------- ------------- --------------- ------------- ------------- ---------------
Total Earnings from
Continuing Operations $111 $26,393 $(26,282) $136,123 $135,203 $920
- ------------------------------------ ------------- ------------- --------------- ------------- ------------- ---------------
Earnings from Discontinued
Operations - (7,237) 7,237 - 5,073 (5,073)
- ------------------------------------ ------------- ------------- --------------- ------------- ------------- ---------------
Total Consolidated $111 $19,156 $(19,045) $136,123 $140,276 $(4,153)
- ------------------------------------ ------------- ------------- --------------- ------------- ------------- ---------------
| | (1) | Includes earnings from the former International segment’s activity other than the activity from the Czech Republic operations included in Earnings from Discontinued Operations. |
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Utility
Utility Operating Revenues
- ------------------------------- ------------------------------------------ ---------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------- ------------- ------------- -------------- --------------- -------------- --------------
Increase/ Increase/
(Thousands) 2006 2005 (Decrease) 2006 2005 (Decrease)
- ------------------------------- ------------- ------------- -------------- --------------- -------------- --------------
Retail Sales Revenues:
Residential $144,690 $152,581 $(7,891) $912,058 $794,269 $117,789
Commercial 22,362 23,676 (1,314) 155,010 134,826 20,184
Industrial 1,648 1,510 138 12,372 8,220 4,152
- ------------------------------- ------------- ------------- -------------- --------------- -------------- --------------
168,700 177,767 (9,067) 1,079,440 937,315 142,125
- ------------------------------- ------------- ------------- -------------- --------------- -------------- --------------
Transportation 16,930 17,986 (1,056) 76,205 69,545 6,660
Other 3,545 (3,844) 7,389 11,047 (2,477) 13,524
- ------------------------------- ------------- ------------- -------------- --------------- -------------- --------------
$189,175 $191,909 $(2,734) $1,166,692 $1,004,383 $162,309
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Utility Throughput
- ------------------------------- ------------------------------------------- --------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------- ------------- -------------- -------------- -------------- -------------- --------------
Increase/ Increase/
(MMcf) 2006 2005 (Decrease) 2006 2005 (Decrease)
- ------------------------------- ------------- -------------- -------------- -------------- -------------- --------------
Retail Sales:
Residential 8,740 10,698 (1,958) 55,071 63,125 (8,054)
Commercial 1,459 1,814 (355) 9,940 11,340 (1,400)
Industrial 114 120 (6) 900 721 179
- ------------------------------- ------------- -------------- -------------- -------------- -------------- --------------
10,313 12,632 (2,319) 65,911 75,186 (9,275)
Transportation 12,185 13,776 48,646 50,345 (1,699)
(1,591)
- ------------------------------- ------------- -------------- -------------- -------------- -------------- --------------
22,498 26,408 (3,910) 114,557 125,531 (10,974)
- ------------------------------- ------------- -------------- -------------- -------------- -------------- --------------
Degree Days
- ---------------------------------- -------------- -------------- -------------------- --------------------------------
Percent Colder
Three Months Ended (Warmer) Than
--------------------------------
June 30 Normal 2006 2005 Normal Prior Year
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
Buffalo 927 731 911 (21.1) (19.8)
Erie 885 812 952 (8.2) (14.7)
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
Nine Months Ended
June 30
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
Buffalo 6,514 5,816 6,551 (10.7) (11.2)
Erie 6,108 5,565 6,215 (8.9) (10.5)
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
2006 Compared with 2005
Operating revenues for the Utility segment decreased $2.7 million for the quarter ended June 30, 2006 as compared with the quarter ended June 30, 2005. The decrease for the quarter is primarily attributable to lower retail gas sales revenue, offset partially by higher other operating revenues. The $9.1 million decrease in retail gas sales revenues was largely a function of lower throughput volumes that reflect warmer weather as well as lower average usage per customer stemming from customer conservation efforts. The impact of the decrease in volumes more than offset the impact of higher gas costs (gas costs are recovered dollar for dollar in revenues). The impact of the decrease in throughput more than offset the positive impact of the New York rate case settlement that became effective August 2005, the impact of which was to increase operating revenues by $3.6 million (of which $3.5 million is reflected in other operating revenues). The rate case settlement increase consisted of a base rate increase, the implementation of a merchant function charge, the elimination of certain bill credits, and the
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)elimination of the gross receipts tax surcharge. In addition, two out-of-period regulatory adjustments recorded during the quarter ended June 30, 2005, which did not recur in 2006, also increased operating revenues. The first adjustment related to the final settlement with the Staff of the NYPSC of the earnings sharing liability for the fiscal 2001 to 2003 time period. As a result of that settlement, the New York rate jurisdiction recorded additional earnings sharing expense (as an offset to other operating revenues) of $0.9 million. The second adjustment related to a regulatory liability recorded for previous over-collections of New York State gross receipts tax. In preparing for the implementation of the recent settlement agreement in New York, the Company determined that it needed to adjust that regulatory liability by $2.7 million (recorded as a reduction of other operating revenues) related to fiscal years 2004 and prior. In the Pennsylvania jurisdiction, the impact of a base rate increase, which became effective in mid-April 2005, was to increase operating revenues by $0.4 million.
Operating revenues for the Utility segment increased $162.3 million for the nine months ended June 30, 2006 as compared with the nine months ended June 30, 2005. The increase is primarily attributable to higher retail gas sales revenues. The increase in retail gas sales revenues of $142.1 million was largely a function of the recovery of higher gas costs, which more than offset the revenue effect of lower retail sales volumes, as shown in the table above. The increase in transportation revenues was primarily due to an out-of-period adjustment of $3.9 million to correct the New York jurisdiction’s calculation of the symmetrical sharing component of the Gas Adjustment rate. The adjustment resulted when it was determined that certain credits that had been included in the calculation should have been removed during the implementation of a previous rate case settlement. The symmetrical sharing component is a mechanism included in Distribution’s New York rate settlement that shares with customers 90% of the difference between actual revenues received from large volume customers and the level of revenues that were projected to be received during the rate year. The impact of the New York rate case settlement, discussed above, was to increase operating revenues by $16.9 million (of which $11.1 million is an increase to other operating revenues). In the Pennsylvania jurisdiction, the impact of the base rate increase, which became effective in mid-April 2005, was to increase operating revenue by $7.5 million.
The Utility segment’s earnings for the quarter ended June 30, 2006 were $0.8 million, an increase of $2.5 million when compared with the loss of $1.7 million for the quarter ended June 30, 2005. In the New York jurisdiction, earnings increased by $3.9 million principally due to the rate case settlement in this jurisdiction that became effective in August 2005 ($2.4 million). In addition, two out-of-period regulatory adjustments recorded during the quarter ended June 30, 2005, which did not recur in 2006, also contributed to the earnings increase. The first adjustment related to the final settlement with the Staff of the NYPSC of the earnings sharing liability for the fiscal 2001 to 2003 time period. As a result of that settlement, the New York rate jurisdiction recorded additional earnings sharing expense of $0.6 million. The second adjustment related to a regulatory liability recorded for previous over-collections of New York State gross receipts tax. In preparing for the implementation of the recent settlement agreement in New York, the Company determined that it needed to adjust that regulatory liability, including accrued interest, by $3.5 million ($0.6 million of that adjustment related to the first six months of fiscal 2005 and $2.9 million related to fiscal years 2004 and prior). The increase in earnings due to the New York rate case settlement and the impact of the out-of-period adjustments recorded in 2005 was partially offset by a decline in margin associated with lower average usage per customer ($2.5 million). In the Pennsylvania rate jurisdiction, earnings decreased $1.4 million primarily due to the impact of warmer weather ($0.8 million) and lower average usage per customer ($0.8 million). These decreases were partially offset by the impact of the rate case settlement in this jurisdiction that became effective in mid-April 2005 ($0.3 million).
The impact of weather variations on earnings in the New York jurisdiction is mitigated by that jurisdiction’s 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 jurisdiction. For the quarter ended June 30, 2006 the WNC preserved earnings of approximately $1.5 million, as the weather was warmer than normal. For the quarter ended June 30, 2005 the WNC did not have a significant impact on earnings as the weather was close to normal.
The Utility segment’s earnings for the nine months ended June 30, 2006 were $51.2 million, an increase of $5.9 million when compared with the earnings of $45.3 million for the nine months ended June 30, 2005. In the New York rate jurisdiction, earnings increased by $6.9 million due primarily to the positive
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)impact of the rate case settlement in this jurisdiction ($10.9 million), discussed above, the impact of the symmetrical sharing adjustment ($2.9 million), and the two out-of-period regulatory adjustments ($4.1 million), also discussed above. These increases were partially offset by an increase in bad debt expense ($3.1 million), an increase in pension expense ($2.1 million), a decline in margin associated with lower average usage per customer ($3.2 million) and higher interest expense ($1.7 million). In the Pennsylvania rate jurisdiction, earnings decreased by $1.0 million principally due to the impacts on margin of warmer weather ($3.1 million), lower average usage per customer ($0.7 million) and a higher effective tax rate ($0.6 million). In addition, earnings decreased due to higher bad debt expense ($1.3 million). These decreases were partially offset by the impact of the rate case settlement in this jurisdiction ($4.9 million).
For the nine months ended June 30, 2006 the WNC preserved earnings of approximately $6.2 million, as the weather was warmer than normal. For the nine months ended June 30, 2005 the WNC did not have a significant impact on earnings as the weather was close to normal.
Pipeline and Storage
Pipeline and Storage Operating Revenues
- ------------------------------------ ---------------------------------------- -------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Increase/ Increase/
(Thousands) 2006 2005 (Decrease) 2006 2005 (Decrease)
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Firm Transportation $27,756 $28,349 $(593) $90,579 $89,966 $613
Interruptible Transportation 1,132 1,121 11 3,571 2,969 602
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
28,888 29,470 (582) 94,150 92,935 1,215
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Firm Storage Service 17,149 16,297 852 49,804 48,767 1,037
Other 5,011 4,831 180 22,185 19,486 2,699
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
$51,048 $50,598 $450 $166,139 $161,188 $4,951
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Pipeline and Storage Throughput
- ------------------------------------ ---------------------------------------- -------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Increase/ Increase/
(MMcf) 2006 2005 (Decrease) 2006 2005 (Decrease)
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Firm Transportation 70,620 70,944 (324) 288,270 284,537 3,733
Interruptible Transportation 2,220 7,162 (4,942) 7,774 10,004 (2,230)
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
72,840 78,106 (5,266) 296,044 294,541 1,503
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
2006 Compared with 2005
Operating revenues for the Pipeline and Storage segment increased $0.5 million for the quarter ended June 30, 2006 as compared with the quarter ended June 30, 2005. The increase was primarily due to higher firm storage revenues ($0.9 million) due to the renewal of storage contracts at higher rates. In addition, there were increased revenues from unbundled pipeline sales ($0.2 million), reported as part of other revenues in the table above, due to higher volumes. The increase was offset by a $0.6 million decrease in transportation revenue due to a rate reduction in firm gathering charges and the Utility segment’s cancellation of a portion of its firm transportation capacity based on lower usage in its service territory. Supply Corporation believes it will be able to remarket this capacity as transportation and/or storage service.*
For the nine months ended June 30, 2005, operating revenues for the Pipeline and Storage segment increased $5.0 million as compared with the nine months ended June 30, 2005. This increase was primarily due to higher revenues from unbundled pipeline sales of $4.5 million, reported as part of
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)other revenues in the table above, due to higher natural gas prices during the nine months ended June 30, 2006 compared to the same period last year. In addition, firm and interruptible transportation revenue increased by $0.6 million each ($1.2 million in total) due to additional contracts with customers and the renewal of contracts at higher rates, both of which reflect the increased demand for transportation services due to market conditions resulting from the effects of last fall’s hurricane damage to production and pipeline infrastructure in the Gulf of Mexico. Storage revenues increased by $1.0 million due to the renewal of storage contracts at higher rates. These increases were offset by a $0.6 million decrease in cashout revenues included in other revenues in the table above. Cashout revenues are completely offset by purchased gas expense.
Earnings in the Pipeline and Storage segment for the quarter ended June 30, 2006 increased $1.8 million as compared with the quarter ended June 30, 2005. The increase can be attributed to lower operation and maintenance expenses ($0.9 million). The decrease in the operation and maintenance expenses was largely due to decreased pension costs ($0.6 million) and a decrease in preliminary survey costs related to the Empire Connector Project ($0.2 million). The decrease in pension costs stems from the 2005 write-off of a regulatory asset for pensions that did not recur in 2006.
The Pipeline and Storage segment’s earnings for the nine months ended June 30, 2006 were $45.4 million, an increase of $3.8 million when compared with the nine months ended June 30, 2005. The main factors contributing to this increase were higher revenues from unbundled pipeline sales ($2.9 million), higher transportation revenues ($0.8 million), higher storage service revenues ($0.7 million), and lower operation and maintenance expense ($0.5 million) due mostly to decreases in preliminary survey costs related to the Empire Connector Project. In addition, interest expense decreased by $0.5 million due to lower debt balances. The earnings increase was partially offset by the $2.6 million gain on the FERC approved sale of base gas during the nine months ended June 30, 2005 that did not recur in 2006.
Exploration and Production
Exploration and Production Operating Revenues
- ----------------------------------- ---------------------------------------- -----------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ----------------------------------- ------------ ------------ -------------- ------------- ------------ --------------
Increase/ Increase/
(Thousands) 2006 2005 (Decrease) 2006 2005 (Decrease)
- ----------------------------------- ------------ ------------ -------------- ------------- ------------ --------------
Gas (after Hedging) $42,786 $47,117 $(4,331) $141,560 $132,381 $9,179
Oil (after Hedging) 41,282 27,666 13,616 106,938 80,185 26,753
Gas Processing Plant 8,904 8,894 10 32,986 25,943 7,043
Other (406) 760 (1,166) 1,429 1,947 (518)
Intrasegment Elimination (1) (5,966) (7,067) 1,101 (25,507) (20,929) (4,578)
- ----------------------------------- ------------ ------------ -------------- ------------- ------------ --------------
$86,600 $77,370 $9,230 $257,406 $219,527 $37,879
- ----------------------------------- ------------ ------------ -------------- ------------- ------------ --------------
| | (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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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
- ---------------------------------------------- ------------------------------------ --------------------------------------
Production Volumes Three Months Ended Nine Months Ended
June 30, June 30,
- ---------------------------------------------- ------------------------------------ --------------------------------------
Increase/ Increase/
2006 2005 (Decrease) 2006 2005 (Decrease)
- ---------------------------------------------- ---------- ---------- -------------- ------------ ---------- --------------
Gas Production (MMcf)
Gulf Coast 2,109 3,365 (1,256) 6,529 9,433 (2,904)
West Coast 983 975 8 2,933 3,000 (67)
Appalachia 1,267 1,156 111 3,766 3,499 267
Canada 2,158 2,134 24 5,830 5,959 (129)
- ---------------------------------------------- ---------- ---------- -------------- ------------ ---------- --------------
6,517 7,630 (1,113) 19,058 21,891 (2,833)
- ----------------------------------------------- ---------- ---------- -------------- ------------ ---------- --------------
Oil Production (Mbbl)
Gulf Coast 192 251 (59) 479 801 (322)
West Coast 638 630 8 1,962 1,916 46
Appalachia 19 11 8 41 23 18
Canada 66 75 (9) 221 229 (8)
- ---------------------------------------------- ---------- ---------- -------------- ------------ ---------- --------------
915 967 (52) 2,703 2,969 (266)
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Average Prices
- ----------------------------------------- --------------------------------------- ----------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ----------------------------------------- --------------------------------------- ----------------------------------------
Increase/ Increase/
2006 2005 (Decrease) 2006 2005 (Decrease)
- ----------------------------------------- ----------- ----------- --------------- ------------ ------------ --------------
Average Gas Price/Mcf
Gulf Coast $6.97 $6.92 $0.05 $8.56 $6.72 $1.84
West Coast $6.06 $6.87 $(0.81) $8.42 $6.54 $1.88
Appalachia $7.26 $6.97 $0.29 $10.29 $7.16 $3.13
Canada $5.54 $6.08 $(0.54) $7.75 $5.70 $2.05
Weighted Average $6.41 $6.69 $(0.28) $8.64 $6.49 $2.15
Weighted Average After
Hedging $6.57 $6.18 $0.39 $7.43 $6.05 $1.38
Average Oil Price/bbl
Gulf Coast $67.52 $49.83 $17.69 $62.04 $47.73 $14.31
West Coast $61.51 $42.57 $18.94 $55.40 $39.10 $16.30
Appalachia $63.15 $50.95 $12.20 $61.92 $46.71 $15.21
Canada $57.88 $41.66 $16.22 $49.25 $40.39 $8.86
Weighted Average $62.54 $44.48 $18.06 $56.17 $41.59 $14.58
Weighted Average After
Hedging $45.13 $28.62 $16.51 $39.56 $27.00 $12.56
- ----------------------------------------- ----------- ----------- --------------- ------------ ------------ --------------
2006 Compared with 2005
Operating revenues for the Exploration and Production segment increased $9.2 million for the quarter ended June 30, 2006 as compared with the quarter ended June 30, 2005. Oil production revenue after hedging increased $13.6 million due primarily to higher weighted average prices after hedging ($16.51 per barrel). Gas production revenue after hedging decreased $4.3 million due to a 1,113 MMcf decrease in production, offset slightly by higher weighted average prices after hedging ($0.39 per Mcf). Most of the decrease in gas production occurred in the Gulf Coast region (a 1,256 MMcf decline), which is consistent with the expected decline rates for the Company’s production in this region and partially attributable to last fall’s hurricane damage.
Operating revenues for the Exploration and Production segment increased $37.9 million for the nine months ended June 30, 2006 as compared with the nine months ended June 30, 2005. Oil production revenue after hedging increased $26.8 million due to a $12.56 per barrel increase in weighted average prices after hedging. This increase was offset slightly by a decrease in production (266,000 barrels). Gas production revenue after hedging increased $9.2 million. An increase in the weighted
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)average price of gas after hedging ($1.38 per Mcf) more than offset a decrease in gas production of 2,833 MMcf. The decrease in gas production occurred primarily in the Gulf Cost region (a 2,904 MMcf decline), which is partly attributable to last fall’s hurricane damage and partly attributable to the expected decline rates for the Company’s production in this region.
The Exploration and Production segment’s loss for the quarter ended June 30, 2006 was $15.1 million, a decrease of $28.9 million when compared with earnings of $13.8 million for the quarter ended June 30, 2005. The decrease for the quarter is due primarily to impairment charges of $39.5 million on this segment’s Canadian oil and gas producing properties, as previously discussed, as well as higher depletion expense of $1.7 million. The increase in depletion expense resulted mainly from higher finding and development costs. Partially offsetting these decreases were higher oil and gas revenues of $6.0 million, discussed above, a $6.1 million benefit to earnings related to income taxes and higher interest income ($0.7 million). This benefit resulted from the reversal of a valuation allowance ($2.9 million) associated with the capital loss carryforward that resulted from the 2003 sale of certain of Seneca’s oil properties. During the quarter, the Company made the determination that it expects to be in a position to fully utilize the loss carryforward and so a valuation allowance was no longer necessary. A tax benefit of $3.2 million also resulted from the favorable resolution of certain open tax issues.
The Exploration and Production segment’s earnings for the nine months ended June 30, 2006 were $28.2 million, a decrease of $10.8 million when compared with earnings of $39.0 million for the nine months ended June 30, 2005. As noted above, the decrease is primarily the result of the impairment charges of $39.5 million on this segment’s Canadian oil and gas producing properties. Further contributing to the decrease were higher lease operating expenses ($3.1 million) and higher depletion expense ($2.0 million). The increase in lease operating expenses was primarily in the West Coast region due to higher steaming costs associated with heavy crude oil production in the California Midway-Sunset and North Lost Hills fields. The higher steaming costs are due to the higher commodity price of natural gas, primarily in the second quarter of fiscal 2006, compared to the second quarter of fiscal 2005. The increase in depletion expense was mainly due to higher finding and development costs. Higher oil and gas revenues of $23.3 million and the $6.1 million impact of tax benefits recorded in the quarter ended June 30, 2006, as discussed above, partially offset these decreases. In addition, a $5.1 million benefit to earnings was realized in the quarter ended March 31, 2006 for an adjustment to a deferred income tax balance. Under GAAP, a company may recognize the benefit of certain expected future income tax deductions as a deferred tax asset only if it anticipates sufficient future taxable income to utilize those deductions. As a result of the rise in commodity prices, the Company increased its forecast of future taxable income in the Exploration and Production segment’s Canadian division and, as a result, recorded a deferred tax asset for certain drilling costs that it now expects to deduct on future income tax returns.
Energy Marketing
Energy Marketing Operating Revenues
- ----------------------------------- -------------------------------------------- ----------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ----------------------------------- -------------------------------------------- ----------------------------------------
(Thousands) 2006 2005 (Decrease) 2006 2005 (Decrease)
- ----------------------------------- ------------- -------------- --------------- ------------ ------------ --------------
Natural Gas (after Hedging) $94,516 $87,983 $6,533 $446,095 $276,032 $170,063
Other 231 65 166 272 74 198
- ----------------------------------- ------------- -------------- --------------- ------------ ------------ --------------
$94,747 $88,048 $6,699 $446,367 $276,106 $170,261
- ----------------------------------- ------------- -------------- --------------- ------------ ------------ --------------
Energy Marketing Volumes
- ----------------------------------- -------------------------------------------- ----------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ----------------------------------- -------------------------------------------- ----------------------------------------
Increase/ Increase/
2006 2005 (Decrease) 2006 2005 (Decrease)
- ----------------------------------- ------------- -------------- --------------- ----------- ------------- --------------
Natural Gas - (MMcf) 11,190 10,925 265 38,496 34,115 4,381
- ----------------------------------- ------------- -------------- --------------- ----------- ------------- --------------
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)2006 Compared with 2005
Operating revenues for the Energy Marketing segment increased $6.7 million and $170.3 million, respectively, for the quarter and nine months ended June 30, 2006, as compared with the quarter and nine months ended June 30, 2005. The increase for both the quarter and nine months ended June 30, 2006 primarily reflects higher gas sales revenue due to an increase in the price of natural gas and, to a lesser extent, an increase in throughput. The increase in throughput was due to the addition of certain large commercial and industrial customers, which more than offset any decrease in throughput due to warmer weather and greater conservation by customers due to higher natural gas prices.
The Energy Marketing segment’s earnings for the quarter ended June 30, 2006 were $1.0 million, a decrease of $0.5 million when compared with earnings of $1.5 million for the quarter ended June 30, 2005. The decrease reflects an increase in operation expense due to credits recorded in the prior year quarter that did not recur and, to a lesser extent, a decrease in gross margin for the quarter.
The Energy Marketing segment’s earnings for the nine months ended June 30, 2006 were $5.9 million, an increase of $1.0 million when compared with earnings of $4.9 million for the nine months ended June 30, 2005. Despite warmer weather and greater conservation by customers, margins increased due to a number of factors, including higher volumes and the marketing flexibility associated with stored gas. The Energy Marketing segment’s contracts for significant storage and transportation volumes provided operational flexibility resulting in increased sales throughput and earnings. The increase in gross margin more than offset an increase in operation expense.
Timber
Timber Operating Revenues
- ------------------------------- ------------------------------------------- ---------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------- ------------------------------------------- ---------------------------------------------
Increase/ Increase/
(Thousands) 2006 2005 (Decrease) 2006 2005 (Decrease)
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
Log Sales $4,063 $4,370 $18,586 $18,014 $572
$(307)
Green Lumber Sales 2,097 2,424 5,527 5,734
(327) (207)
Kiln Dry Lumber Sales 8,733 7,919 814 25,618 22,015
3,603
Other 422 315 107 1,650 1,232 418
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
Operating Revenues $15,315 $15,028 $287 $51,381 $46,995 $4,386
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
Timber Board Feet
- ------------------------------- ------------------------------------------- ---------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------- ------------------------------------------- ---------------------------------------------
Increase/ Increase/
(Thousands) 2006 2005 (Decrease) 2006 2005 (Decrease)
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
Log Sales 1,767 1,619 148 7,540 5,934 1,606
Green Lumber Sales 3,126 3,475 (349) 8,082 8,179 (97)
Kiln Dry Lumber Sales 4,240 4,110 130 13,239 11,373 1,866
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
9,133 9,204 (71) 28,861 25,486 3,375
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
2006 Compared with 2005
Operating revenues for the Timber segment increased $0.3 million for the quarter ended June 30, 2006 as compared with the quarter ended June 30, 2005. The increase for the quarter can largely be attributed to higher kiln dry lumber sales of $0.8 million primarily due to an increase in the market price of kiln dry cherry lumber. This increase was offset by a decline in both log and green lumber sales revenue. The decrease in log sales revenue is due to a decline in both cherry veneer and cherry export log volumes, which have the highest margin in the overall mix of harvested timber and have the largest impact
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)on overall log sales revenue. While there was an overall increase in log volumes of 148,000 board feet, cherry veneer and cherry export log volumes declined by 110,000 board feet. The decline in green lumber sales revenue primarily reflects a decline in processing volumes, particularly from poplar veneer green lumber sales which experienced a 478,000 board foot decline.
Operating revenues for the Timber segment increased $4.4 million for the nine months ended June 30, 2006 as compared with the nine months ended June 30, 2005. This increase can be attributed to higher kiln dry lumber sales revenue of $3.6 million due to an increase in cherry lumber sales volumes (2.5 million board feet) as a result of an increase in processing capacity from the addition of two new kilns in February 2005. Higher log sales revenue of $0.6 million, the majority being cherry export log sales as a result of greater market demand, also contributed to the increase.
The Timber segment’s earnings for the quarter ended June 30, 2006 were $1.5 million, an increase of $0.9 million when compared with earnings of $0.6 million for the quarter ended June 30, 2005. The increase is largely attributable to the impact of lower operating costs ($0.4 million) and a decline in depletion expense ($0.3 million). During the quarter ended June 30, 2006, the Timber segment changed its accounting procedures to properly include certain costs associated with lumber production in inventory. The impact of this change is reflected in operating costs. Slightly higher revenues due to an increase in cherry kiln dry lumber sales also contributed to the increase.
The Timber segment’s earnings for the nine months ended June 30, 2006 were $5.2 million, an increase of $1.0 million when compared with earnings of $4.2 million for the nine months ended June 30, 2005. Higher revenues from kiln dry lumber sales and cherry export log sales largely contributed to this increase. The impact of the increase in revenues was partially offset by increases in cost of good sold on lumber and log sales.
Corporate and All Other
2006 Compared with 2005
Corporate and All Other recorded a loss of $0.8 million for the quarter ended June 30, 2006 compared with earnings of $1.3 million for the quarter ended June 30, 2005. Earnings for the quarter ended June 30, 2005 benefited from $1.3 million of reimbursed project costs that did not recur in 2006. For the nine months ended June 30, 2006 compared with the nine months ended June 30, 2005, Corporate and All Other earnings decreased $0.1 million. An increase in interest income during 2006 resulting from the investment of proceeds received from the sale of U.E. in July 2005 offset the earnings decrease resulting from the non-recurrence of the earnings benefit in 2005 associated with reimbursed project development costs.
Interest Income
Interest income increased $1.7 million and $2.5 million, respectively, for the quarter and nine months ended June 30, 2006 as compared with the quarter and nine months ended June 30, 2005. These increases are reflective of an overall increase in the Company’s cash position compared to the prior year. The Company’s cash position in 2006 has been stronger primarily because of the investment of proceeds received from the sale of U.E. in July 2005 combined with higher cash flow from operations in the Exploration and Production segment.
Interest Charges
Other interest charges decreased $3.5 million and $4.6 million, respectively, for the quarter and nine months ended June 30, 2006 as compared with the quarter and nine months ended June 30, 2005. These decreases resulted primarily from a regulatory true-up adjustment recorded in the quarter ended June 30, 2005 in the Utility segment’s New York rate jurisdiction related to a regulatory liability recorded for previous over-collections of New York State gross receipts tax. No such adjustment was recorded in the current fiscal year.
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)Income Tax Expense (Benefit)
The Company's effective income tax rate for the quarter ended June 30, 2006 was approximately 101%, up from approximately 37% for the quarter ended June 30, 2005. While the Company experienced a loss of $7.7 million for the quarter ended June 30, 2006, it recognized a tax benefit of $7.8 million. The primary reason for the increase in the effective income tax rate was the income tax benefit of $6.1 million recognized in the Exploration and Production segment at June 30, 2006, as discussed above.
CAPITAL RESOURCES AND LIQUIDITY
The Company’s primary source of cash during the nine-month period ended June 30, 2006 consisted of cash provided by operating activities. This source of cash was supplemented by issues of new shares of common stock as a result of the exercise of stock options. During the nine months ended June 30, 2006, the common stock used to fulfill the requirements of the Company’s 401(k) plans and Direct Stock Purchase and Dividend Reinvestment Plan was obtained via open market purchases. During the quarter ended March 31, 2006, the Company began repurchasing outstanding shares of its common stock under a share repurchase program, which is discussed below under Financing Cash Flow.
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, impairment of oil and gas producing properties, deferred income taxes, income or loss from unconsolidated subsidiaries net of cash distributions, and minority interest in foreign subsidiaries.
Cash provided by operating activities in the Utility and the Pipeline and Storage segments may vary 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 Supply Corporation’s straight fixed-variable rate design.
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 balances receivable 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. The Company uses various derivative financial instruments, including price swap agreements and no cost collars in an attempt to manage this energy commodity price risk.
Net cash provided by operating activities totaled $409.9 million for the nine months ended June 30, 2006, an increase of $75.5 million compared with $334.4 million provided by operating activities for the nine months ended June 30, 2005. Higher oil and gas revenues in the Exploration and Production segment and a decrease in hedging collateral deposits at June 30, 2006 in the Exploration and Production and Energy Marketing segments were the primary reasons for this increase. Hedging collateral deposits serve as collateral for open positions on exchange-traded futures contracts, exchange-traded options and over-the-counter swaps and collars. These increases were partially offset by the loss of positive cash flow from the Company’s former Czech Republic operations, which were sold in July 2005.
Investing Cash Flow
Expenditures for Long-Lived Assets
The Company’s expenditures for long-lived assets totaled $218.7 million during the nine months ended June 30, 2006. The table below presents these expenditures:
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
- ----------------------------------------------------------- ----- ------------------------- -----------------------
Nine Months Ended June 30, 2006
(in millions of dollars)
- ----------------------------------------------------------- ----- ------------------------- -----------------------
Total
Expenditures for
Long-Lived Assets
---
- ----------------------------------------------------------- ----- ------------------------- -------------------
Utility $39.4
Pipeline and Storage 15.4
Exploration and Production 160.3
Timber 1.1
All Other and Corporate 2.5
- ----------------------------------------------------------- ----- ------------------------- -------------------
---
$218.7
- ----------------------------------------------------------- ----- ------------------------- ------------------- ---
Utility
The majority of the Utility capital expenditures for the nine months ended June 30, 2006 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, 2006 were made for additions, improvements, and replacements to this segment’s transmission and storage systems.
The Company continues to explore various opportunities to expand its capabilities to transport gas to the East Coast, either through the Supply Corporation or Empire systems or in partnership with others. In October 2005, Empire filed an application with the FERC for the authority to build and operate the Empire Connector project to expand its natural gas pipeline operations to serve new markets in New York and elsewhere in the Northeast by extending the Empire Pipeline. The application also asks that Empire’s existing business and facilities be brought under FERC jurisdiction, and that FERC approve rates for Empire’s existing and proposed services. Assuming the proposed Millennium Pipeline is constructed, the Empire Connector will provide an upstream supply link for the Millennium Pipeline and will transport Canadian and other natural gas supplies to downstream customers, including KeySpan Gas East Corporation, which has entered into precedent agreements to subscribe for at least 150 MDth per day of natural gas transportation service through the Empire State Pipeline and the Millennium Pipeline systems.* The Empire Connector will be designed to move up to approximately 250 MDth of natural gas per day.* In July 2006, Empire revised the planned in-service date for the Empire Connector to extend beyond its original November 2007 target. The new targeted in-service date is November 2008, or sooner if feasible.* FERC issued on July 20, 2006 a preliminary determination regarding non-environmental aspects of the application, in response to which Empire will file a request for rehearing on various issues by August 21, 2006. Empire anticipates that FERC will issue a final certificate authorizing construction and operation of the project on or about November 2006, after which Empire will have to decide whether it will accept the final approval on the terms contained therein.* The Company anticipates financing this project with cash on hand and/or through the use of the Company’s bi-lateral lines of credit.* As of June 30, 2006, the Company had incurred approximately $5.4 million in costs (all of which have been reserved) related to this project. Of this amount, $0.3 million and $1.4 million, respectively, were incurred during the quarter and nine months ended June 30, 2006.
The Company also has plans to extend Supply Corporation’s pipeline system from the Tuscarora storage field to the intersection of the proposed Millennium and Empire Connector pipelines (the Tuscarora Extension).* The Tuscarora Extension will be designed initially to move up to approximately 130 MDth of natural gas per day.* The project depends on market developments and its in-service date will be contingent upon the Millennium/Empire project timeline. The Company has not yet filed an application with the FERC for the authority to build and operate the Tuscarora Extension. The Company anticipates financing this project with cash on hand and/or through the use of the Company’s bi-lateral lines of credit.* There have been no costs incurred by the Company related to this project as of June 30, 2006.
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)Exploration and Production
The Exploration and Production segment capital expenditures for the nine months ended June 30, 2006 included approximately $34.7 million for Canada, $79.3 million for the Gulf Coast region ($78.7 million for the off-shore program in the Gulf of Mexico), $28.4 million for the West Coast region and $17.9 million for the Appalachian region. The significant amount spent in the Gulf Coast region is related to high commodity prices, which has improved the economics of investment in the area, plus projected royalty relief. These amounts included approximately $38.3 million spent to develop proved undeveloped reserves.
Estimated capital expenditures in 2006 for the Exploration and Production segment have been increased from $155.0 million to $207.0 million.* Estimated capital expenditures for Canada remained unchanged at $46.0 million.* Estimated capital expenditures for the Gulf Coast region have been increased from $58.0 million to $90.0 million.* Estimated capital expenditures for the West Coast region have been increased from $28.0 million to $44.0 million and estimated capital expenditures for the Appalachian region have been increased from $23.0 million to $27.0 million.* The increase in the Gulf Coast region is due to an increase in drilling and completion activity, higher working interests on new wells and facilities construction for new wells. The increase in the West Coast region is due to the acquisition of reserves and the addition of new wells and facilities construction for those wells.
Timber
The majority of the Timber segment capital expenditures for the nine months ended June 30, 2006 were made for purchases of equipment for Highland’s sawmill and kiln operations.
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, timber or natural gas storage facilities and the expansion of 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
The Company did not have any outstanding short-term notes payable to banks or commercial paper at June 30, 2006. However, 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 and other working capital needs. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. As for bank loans, the Company maintains a number of individual (bi-lateral) 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. Each of these credit lines, which aggregate to $445.0 million, are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that these lines of credit will continue to be renewed.* The total amount available to be issued under the Company’s commercial paper program is $200.0 million. The commercial paper program is backed by a syndicated committed credit facility which totals $300.0 million and extends through September 30, 2010. The Company plans to increase the size of its commercial paper program from $200.0 million to $300.0 million.*
Under the Company’s committed credit facility, the Company has agreed that its debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter from September 30, 2005 through September 30, 2010. At June 30, 2006, the Company’s debt to capitalization ratio (as calculated under the facility) was .46. The constraints specified in the committed credit facility would permit an
37
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)additional $1.37 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 would exceed .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 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, 2006, the Company would have been permitted to issue up to a maximum of $871 million 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.*
The Company’s 1974 indenture pursuant to which $399.0 million (or 36%) of the Company’s long-term debt (as of June 30, 2006) 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.
The Company’s $300.0 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 its significant subsidiaries fail to make a payment when due of any principal or interest on any other indebtedness aggregating $20.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $20.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of June 30, 2006, the Company had no debt outstanding under the committed credit facility.
The Company has an effective registration statement on file with the SEC under which it has available capacity to issue an additional $550.0 million of debt and equity securities under the Securities Act of 1933. The Company may sell all or a portion of the remaining registered securities if warranted by market conditions and the Company’s capital requirements. Any offer and sale of the above mentioned $550.0 million of debt and equity securities will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder.
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.
On December 8, 2005, the Company’s board of directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of 8 million shares in the open market or through privately negotiated transactions. As of June 30, 2006, the Company has repurchased 2,284,350 shares under this program, funded with cash provided by operating activities. During the quarter ended June 30, 2006, the Company repurchased 1,459,100 shares. In the future, it is expected that this share repurchase program will continue to be funded with cash provided by operating activities and/or through the use of the Company’s bi-lateral lines of credit.* It is expected that open market repurchases will continue from time to time depending on market conditions.*
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)OFF-BALANCE SHEET ARRANGEMENTS
The Company has entered into certain off-balance sheet financing arrangements. These financing arrangements are primarily operating and capital leases. The Company’s consolidated subsidiaries have operating leases, the majority of which are with the Utility and the Pipeline and Storage segments, having a remaining lease commitment of approximately $44.4 million. These leases have been entered into for the use of buildings, vehicles, construction tools, meters, computer equipment and other items and are accounted for as operating leases. The Company’s unconsolidated subsidiaries, which are accounted for under the equity method, have capital leases of electric generating equipment having a remaining lease commitment of approximately $7.5 million. The Company has guaranteed 50% or $3.8 million of these capital lease commitments.
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 to have a material adverse effect on the financial condition of the Company.*
Market Risk Sensitive Instruments
For a complete discussion of market risk sensitive instruments, refer to “Market Risk Sensitive Instruments” in Item 7 of the Company’s 2005 Form 10-K. There have been no subsequent material changes to the Company’s exposure to market risk sensitive instruments.
Rate and Regulatory Matters
Energy Policy Act
On August 8, 2005, President Bush signed into law the Energy Policy Act, which, among other things, repealed PUHCA 1935 effective February 8, 2006. With repeal of PUHCA 1935, the Company is no longer subject to that act’s broad regulatory provisions, including provisions relating to the issuance of securities, sales and acquisitions of securities and utility assets, intra-company transactions and limitations on diversification. The Energy Policy Act includes PUHCA 2005, which, among other things, grants the FERC and state public utility regulatory commissions access to certain books and records of companies in holding company systems, provides (upon request of a state commission or holding company system) for FERC review of allocations of costs of non-power goods and administrative services in electric utility holding company systems, and modifies the jurisdiction of FERC over certain mergers and acquisitions involving public utilities or holding companies. On December 8, 2005, the FERC issued Order 667 to implement PUHCA 2005. The FERC clarified certain aspects of Order 667 in Order 667-A, issued on April 24, 2006. On June 15, 2006, the Company filed a “notification of holding company status” with the FERC under Order 667-A. Also on that date, the Company filed an “exemption request” with the FERC, requesting exemption from the requirements of Order 667-A regarding FERC access to books and records and record retention. The Company is unable to predict at this time what the ultimate outcome of these or future filings or legislative or regulatory changes will be.
Utility Operation
Base rate adjustments in both the New York and Pennsylvania rate jurisdictions do not reflect the recovery of purchased gas costs. Such costs are recovered through operation of the purchased gas adjustment clauses of the appropriate regulatory authorities.
39
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)New York Jurisdiction
On August 27, 2004, Distribution Corporation commenced a rate case by filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues beginning October 1, 2004. Various parties opposed the filing. On April 15, 2005, Distribution Corporation, the parties and others executed an agreement settling all outstanding issues. In an order issued July 22, 2005, the NYPSC, approved the April 15, 2005 settlement agreement, substantially as filed, for an effective date of August 1, 2005. The settlement agreement provides for a rate increase of $21 million by means of the elimination of bill credits ($5.8 million) and an increase in base rates ($15.2 million). For the two-year term of the agreement and thereafter, the return on equity level above which earnings must be shared with rate payers is 11.5%.
Pennsylvania Jurisdiction
On June 1, 2006, Distribution Corporation filed proposed tariff amendments with PaPUC to increase annual revenues by $25.9 million to cover increases in the cost of service to be effective July 30, 2006. The rate request was filed to address increased costs associated with Distribution Corporation’s ongoing construction program as well as increases in operating costs, particularly uncollectible accounts. Following standard regulatory procedure, the PaPUC issued an order on July 20, 2006 instituting a rate proceeding and suspending the proposed tariff amendments until March 2, 2007.*
On June 8, 2006, the NTSB issued safety recommendations to Distribution Corporation as a result of an investigation of a natural gas explosion that occurred on Distribution Corporation’s system in Dubois, Pennsylvania in August 2004. The explosion destroyed a residence, resulting in the death of two people who lived there, and damaged a number of other houses in the immediate vicinity.
The NTSB and Distribution Corporation differ in their assessment of the probable cause of the explosion. The NTSB determined that the probable cause was the fracture of a defective “butt-fusion joint” which had joined two sections of plastic pipe, and the failure of Distribution Corporation to have an adequate program to inspect butt-fusion joints and replace those joints not meeting its inspection criteria. Distribution Corporation had submitted to the NTSB a proposed determination of probable cause that was substantially different, namely, that the probable cause was the improper excavation and backfill operations of a third party working in the vicinity of Distribution Corporation’s pipeline. Distribution Corporation also had raised issues concerning the testing standards employed in the NTSB investigation. Distribution Corporation is presently reviewing alternatives by which to seek reviews of the NTSB’s findings and conclusions to ensure that the NTSB considered all relevant evidence, including the report of Distribution Corporation’s third-party plastic pipe expert and other relevant evidence, in reaching its determination of probable cause.
The NTSB’s safety recommendations to Distribution Corporation involved revisions to its butt-fusion procedures for joining plastic pipe, and revisions to its procedures for qualifying personnel who perform plastic fusions. Although not required by law to do so, Distribution Corporation is presently implementing those recommendations.
The NTSB also issued safety recommendations to the PaPUC and certain other parties. The recommendation to the PaPUC was to require an analysis of the integrity of butt-fusion joints in Distribution Corporation’s system and replacement of those joints that are determined to have unacceptable characteristics. Distribution Corporation is working cooperatively with the PaPUC staff to permit the PaPUC to undertake the analysis recommended by the NTSB. Specifically, Distribution has agreed to the following:
(i) Distribution Corporation will uncover a limited number of butt-fusions at three locations designated by the PaPUC;
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)| | (ii) | in a 30-day period commencing July 6, 2006, Distribution Corporation will attempt to uncover additional butt-fusions throughout its Pennsylvania service area as it uncovers facilities for other purposes; when a butt-fusion is uncovered, Distribution Corporation will notify the designated PaPUC representative to permit inspection of the quality of the fusion. |
Distribution Corporation also agreed to meet with the PaPUC following the end of the 30-day period to discuss further procedures to facilitate the analysis. At this time, Distribution Corporation is unable to predict the outcome of the analysis or of any negotiations or proceedings that may result from it. Distribution Corporation’s response to the actions of the PaPUC will depend on its assessment of the validity of the PaPUC’s analysis and conclusions.
Without admitting liability, Distribution Corporation has settled all significant third-party claims against it related to the explosion, for amounts that are immaterial in the aggregate to the Company. Distribution Corporation has been committed to providing safe and reliable service throughout its service territory and firmly believes, based on information presently known, that its system continues to be safe and reliable. According to the Plastics Pipe Institute, plastic pipe today accounts for over 90% of the pipe installed for the natural gas distribution industry in the United States and Canada. Distribution Corporation, along with many other natural gas utilities operating in the United States, has relied extensively upon the use of plastic pipe in its natural gas distribution system since the 1970s.
Pipeline and Storage
On April 7, 2006, the NYPSC, PaPUC and Pennsylvania Office of Consumer Advocate filed a complaint and a motion for summary disposition against Supply Corporation with the FERC under Sections 5(a) and 13 of the Natural Gas Act. The complainants allege that Supply Corporation’s rates are unjust and unreasonable, and that Supply Corporation is permitted to retain more gas from shippers than is necessary for fuel and loss. As a result, the complainants allege, Supply Corporation has excess annual earnings of approximately $30 million to $35 million.
In their complaint, the complainants ask FERC (i) to find that Supply Corporation’s rates are unjust and unreasonable, and (ii) to institute proceedings to determine the just and reasonable rates Supply Corporation will be authorized to charge prospectively. The complainants also ask FERC in their complaint (i) to determine whether Supply Corporation has the authority to make sales of gas retained from shippers, and (ii) if FERC concludes that Supply Corporation does not have such authority, to direct Supply Corporation to show cause why it should not be required to disgorge profits associated with such sales. In their motion for summary disposition, the complainants asked FERC (i) to find summarily that the rate at which Supply Corporation is permitted to retain gas from shippers for fuel and loss is unjust and unreasonable, (ii) to require Supply Corporation to make a compliance filing providing detailed information regarding its fuel and loss retention and use, and (iii) to establish just and reasonable fuel and loss percentages for Supply Corporation.
Supply Corporation filed answers on April 27, 2006, opposing the complaint and the motion for summary disposition, asserting that its current rates are just and reasonable, and documenting its authority to sell retained gas. Following another round of responses filed by the parties in May, FERC issued on June 7, 2006, an “Order Setting Complaint for Hearing, Suspending Hearing for Settlement Procedures, and Denying Motion for Summary Disposition.” Supply Corporation moved on June 9 for reconsideration and an extension of time. On June 23, 2006, FERC issued an “Order Granting Reconsideration in Part and Granting Extension of Time.” Read together, those two FERC Orders provide:
(i) the complainants’ motion for summary disposition was denied;
41
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)| | (ii) | the complaint was set for hearing and an investigation into Supply Corporation’s rates initiated; Supply Corporation was required to file a cost and revenue study by July 24, 2006; |
| | (iii) | the complaint was referred to a settlement Administrative Law Judge, who must report by August 22, 2006 to FERC and FERC’s Chief Administrative Law Judge on the status of the settlement discussions; |
| | (iv) | based on that report, the Chief Administrative Law Judge will either provide the parties with additional time to continue their settlement discussions, or assign the case to a presiding Administrative Law Judge (a different person than the settlement judge) for a trial-type evidentiary hearing; if settlement discussions continue, the settlement judge must continue to report status at least every 60 days; |
| | (v) | if settlement procedures fail, the Chief Administrative Law Judge will designate a presiding judge who must, within 15 days after being designated, convene a prehearing conference to establish a procedural schedule, and must issue an initial decision within 12 months after commencement of the hearing procedures; among other things, the presiding judge is authorized “to determine whether it may be appropriate to phase the proceeding and first issue an initial decision to address the fuel retention issue raised in the Motion for Summary Disposition (Phase I) and then later issue a separate initial decision to address the other issues (Phase II).” |
On June 13, 2006, FERC designated a settlement judge and scheduled an initial settlement conference, which was held on June 23, 2006. A second settlement conference was scheduled for, and held on, July 13, 2006. On July 17, the settlement judge issued an order scheduling the next settlement conference for August 7, 2006, and reporting that the parties had agreed that the complainants would make a formal settlement offer by July 27, to which Supply Corporation would respond by August 3, 2006. All discussions and offers within the FERC settlement process are confidential and privileged, although any settlement reached will be publicly submitted to FERC for approval.
On July 24, 2006, Supply Corporation publicly filed at FERC the required cost and revenue study. Supply Corporation also filed in early July a request for rehearing of the portion of the June 7 Order which authorizes the presiding judge, if one is designated, to phase the proceeding and issue a separate initial decision on fuel retention without addressing Supply Corporation’s overall costs and revenues.
This matter will be resolved by either (i) a settlement which would include the effective date of any rate changes, or (ii) the hearing process described above, in the course of which the presiding judge would issue recommended decision(s) which would be considered by FERC.* In that event, FERC would issue an order that would either be consistent or inconsistent with any recommended decision, after which any new rates would go into effect.*
Supply Corporation is engaging in settlement discussions in good faith. If this matter goes to hearing, Supply Corporation will vigorously oppose the complaint.*
On November 25, 2003, the FERC issued Order 2004. Order 2004 was clarified in Order 2004-A on April 16, 2004, Order 2004-B on August 2, 2004 and Order 2004-C on December 21, 2004. Order 2004, which went into effect September 22, 2004, regulates the conduct of transmission providers (such as Supply Corporation) with their “energy affiliates.” The FERC broadened the definition of “energy affiliates” to include any affiliate of a transmission provider if that affiliate engages in or is involved in transmission (gas or electric) transactions, or manages or controls transmission capacity, or buys, sells, trades or administers natural gas or electric energy or engages in financial transactions relating to the sale or transmission of natural gas or electricity. Supply Corporation’s energy affiliates are Seneca and NFR. Order 2004 also provides an exemption for local distribution companies that are affiliated with interstate pipelines (such as Distribution Corporation), but the exemption is limited, with very minor exceptions, to local distribution companies that do not make any off-system sales. Distribution Corporation stopped
42
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)making most off-system sales effective September 22, 2004; the Company does not expect that change to have a material effect on the Company’s results of operations, as margins resulting from off-system sales are minimal as a result of profit sharing with retail customers.* Distribution Corporation has continued making certain off-system sales permitted by a prior FERC order; FERC required Supply Corporation to provide arguments justifying the continued effectiveness of that order. Order 2004 also provides that companies may request waivers, which Supply Corporation did with respect to its relationship with Distribution Corporation. On July 20, 2006, FERC issued an order granting Supply Corporation’s request for waiver and clarification of the new rules, subject to a requirement that Supply Corporation must file by August 21, 2006 for FERC’s approval a limited amendment to its proposed Compliance Plan regarding the relationship between Supply Corporation and Distribution Corporation. The order approved Distribution Corporation’s continued sales of gas pursuant to the prior FERC order, and concluded that, so long as Distribution Corporation refrains from making other off-system sales of gas, Supply Corporation will not have to treat Distribution Corporation as an energy affiliate. Compliance with Order 2004 should not increase capital or operating expenses to an extent that would be material to the financial condition of the Company.* Future periodic reports will not include any discussion of the Company’s compliance with Order 2004 unless changed circumstances warrant.
Empire currently does not have a rate case on file with the NYPSC. Management will continue to monitor its financial position in the New York jurisdiction to determine the necessity of filing a rate case in the future. Among the issues that will be resolved in connection with Empire’s FERC application to build the Empire Connector are the rates and terms of service that would become applicable to all of Empire’s business, effective upon Empire accepting the FERC certificate and placing its new facilities into service (currently targeted for November 2008, or sooner if feasible), when Empire would become an interstate pipeline subject to FERC regulation.*
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 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 thatthe Company will be required to incur such costs. The Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be $3.8 million.* This liability has been recorded on the Consolidated Balance Sheet at June 30, 2006. The Company expects to recover its environmental clean-up costs from a combination of rate recovery and insurance proceeds.* Other than as discussed in Note G of the Company’s 2005 Form 10-K (referred to below), the Company is currently not aware of any material additional exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could impact the Company.*
For further discussion refer to Note G — Commitments and Contingencies under the heading “Environmental Matters” in Item 8 of the Company’s 2005 Form 10-K, and to Part II, Item 1, “Legal Proceedings.”
New Accounting Pronouncements
In March 2005, the FASB issued FIN 47, an interpretation of SFAS 143. FIN 47 provides additional guidance on the term “conditional asset retirement obligation” as used in SFAS 143, and in particular the standard clarifies when a Company must record a liability for a conditional asset retirement obligation. The Company is currently evaluating the impact of FIN 47 on its consolidated financial statements. For further discussion of FIN 47 and its impact on the Company, refer to Item 1 at Note 1 – Summary of Significant Accounting Policies.
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.) In May 2005, the FASB issued SFAS 154. SFAS 154 replaces APB 20 and SFAS 3 and changes the requirements for the accounting for and reporting of a change in accounting principle. The Company’s financial condition and results of operations will only be impacted by SFAS 154 if there are any accounting changes or corrections of errors in the future. For further discussion of SFAS 154 and its impact on the Company, refer to Item 1 at Note 1 – Summary of Significant Accounting Policies.
In June 2006, the FASB issued FIN 48, an interpretation of SFAS 109. FIN 48 clarifies the accounting for uncertainty in income taxes and reduces the diversity in current practice associated with the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return by defining a “more-likely-than-not” threshold regarding the sustainability of the position. The Company is currently evaluating the impact of FIN 48 on its consolidated financial statements. For further discussion of FIN 48 and its impact on the Company, refer to Item 1 at Note 1 – Summary of Significant Accounting Policies.
Safe Harbor for Forward-Looking Statements
The Company is including the following cautionary statement in this Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, those which are designated with an asterisk (“*”) and those which are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions, are “forward-looking” statements as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The forward-looking statements contained herein are based on various assumptions, many of which are based, in turn, upon further assumptions. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including, without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:
| | 1. | Changes in laws and regulations to which the Company is subject, including changes in tax, environmental, safety and employment laws and regulations, and changes in laws and regulations relating to repeal of PUHCA 1935; |
| | 2. | Changes in economic conditions, including economic disruptions caused by terrorist activities, acts of war or major accidents; |
| | 3. | Changes in demographic patterns and weather conditions, including the occurrence of severe weather; |
| | 4. | Changes in the availability and/or price of natural gas or oil and the effect of such changes on the accounting treatment or valuation of derivative financial instruments or the Company’s natural gas and oil reserves; |
| | 5. | Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; |
| | 6. | Changes in the availability and/or price of derivative financial instruments; |
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)| | 7. | Changes in the price differentials between various types of oil; |
| | 8. | Failure of the price differential between heavy sour crude oil and light sweet crude oil to return to its historical norm; |
| | 9. | Inability to obtain new customers or retain existing ones; |
| | 10. | Significant changes in competitive factors affecting the Company; |
| | 11. | Governmental/regulatory actions, initiatives and proceedings, including those involving acquisitions, financings, rate cases (which address, among other things, allowed rates of return, rate design and retained gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements; |
| | 12. | Unanticipated impacts of restructuring initiatives in the natural gas and electric industries; |
| | 13. | Significant changes from expectations in actual capital expenditures and operating expenses and unanticipated project delays or changes in project costs or plans, including changes in the plans of the sponsors of the proposed Millennium Pipeline with respect to that project; |
| | 14. | The nature and projected profitability of pending and potential projects and other investments; |
| | 15. | Occurrences affecting the Company’s ability to obtain funds from operations, debt or equity to finance needed capital expenditures and other investments, including any downgrades in the Company’s credit ratings; |
| | 16. | Uncertainty of oil and gas reserve estimates; |
| | 17. | Ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties; |
| | 18. | Ability to successfully identify, drill for and produce economically viable natural gas and oil reserves; |
| | 19. | Significant changes from expectations in the Company’s actual production levels for natural gas or oil; |
| | 20. | Regarding foreign operations, changes in trade and monetary policies, inflation and exchange rates, taxes, operating conditions, laws and regulations related to foreign operations, and political and governmental changes; |
| | 21. | Significant changes in tax rates or policies or in rates of inflation or interest; |
| | 22. | Significant changes in the Company’s relationship with its employees or contractors and the potential adverse effects if labor disputes, grievances or shortages were to occur; |
| | 23. | Changes in accounting principles or the application of such principles to the Company; |
| | 24. | The cost and effects of legal and administrative claims against the Company; |
| | 25. | Changes in actuarial assumptions and the return on assets with respect to the Company’s retirement plan and post-retirement benefit plans; |
| | 26. | Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide post-retirement benefits; or |
| | 27. | Increasing costs of insurance, changes in coverage and the ability to obtain insurance. |
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Concl.) The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
Back to Table of Contents Refer to the “Market Risk Sensitive Instruments” section in Item 2 – MD&A.
Back to Table of ContentsEvaluation of Disclosure Controls and Procedures
The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this report.
Changes in Internal Controls Over Financial Reporting
The management of the Company maintains a system of internal control over financial reporting that is designed to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with GAAP. There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended June 30, 2006 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Part II. Other Information
Back to Table of Contents In an action instituted in the New York State Supreme Court, Kings County on February 18, 2003 against Distribution Corporation and Paul J. Hissin, an unaffiliated third party, plaintiff Donna Fordham-Coleman, as administratrix of the estate of Velma Arlene Fordham, alleges that Distribution Corporation’s denial of natural gas service in November 2000 to the plaintiff’s decedent, Velma Arlene Fordham, caused decedent’s death in February 2001. The plaintiff seeks damages for wrongful death and pain and suffering, plus punitive damages. Distribution Corporation denied plaintiff’s material allegations, asserted seven affirmative defenses and asserted a cross-claim against the co-defendant. Distribution Corporation believes, and has vigorously asserted, that plaintiff’s allegations lack merit. The Court changed venue of the action to New York State Supreme Court, Erie County. Discovery closed in October 2005, and Distribution Corporation filed a motion for summary judgment in November 2005. On February 24, 2006, the Court granted Distribution Corporation’s motion for summary judgment dismissing plaintiff’s claims for wrongful death and punitive damages. The Court denied Distribution Corporation’s motion for summary judgment to dismiss plaintiff’s negligence claim seeking recovery for conscious pain and suffering. On March 15, 2006, the plaintiff appealed the Court’s decision to the New York State Supreme Court, Appellate Division, Fourth Department. On March 29, 2006, Distribution Corporation filed a cross-appeal. A trial date has been scheduled for January 15, 2007 (although it is possible that the Court may change that date or that a trial may become unnecessary, based on the progress or outcome of the pending appeals).
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Item 1. Legal Proceedings (Concl.)
On April 7, 2006, the NYPSC, PaPUC and Pennsylvania Office of Consumer Advocate filed a complaint against Supply Corporation with the FERC under Section 5(a) of the Natural Gas Act and a motion for summary disposition against Supply Corporation under Section 13 of the Natural Gas Act. For a discussion of these matters, refer to Part I, Item 2 — MD&A of this report under the heading “Other Matters — Rate and Regulatory Matters.”
On June 8, 2006, the NTSB issued safety recommendations to Distribution Corporation, the PaPUC and certain others as a result of its investigation of a natural gas explosion that occurred on Distribution Corporation’s system in Dubois, Pennsylvania in August 2004. For a discussion of this matter, refer to Part I, Item 2 — MD&A of this report under the heading “Other Matters — Rate and Regulatory Matters.”
The Company believes, based on the information presently known, that the ultimate resolution of the Fordham case and the NTSB matter will not be material to the consolidated financial condition, results of operations, or cash flow of the Company.* No assurances can be given, however, as to the ultimate outcome of these matters, and it is possible that the outcome could be material to results of operations or cash flow for a particular quarter or annual period.* In addition, regarding the complaint filed against Supply Corporation at FERC, the Company believes that chances are remote that the complainants will succeed in challenging the authority of Supply Corporation to sell retained gas.* Nevertheless, the resolution of the rate aspects of the complaint could have a material effect on the Company’s financial condition, results of operations or cash flow.*
For a discussion of various environmental and other matters, refer to Part I, Item 1 at Note 4 and Part I, Item 2 — MD&A of this report under the heading “Other Matters — Environmental Matters.”
In addition to the matters disclosed above, 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 to have a material adverse effect on the financial condition of the Company.*
Back to Table of Contents The risk factors in Item 1A of the Company’s 2005 Form 10-K have not materially changed other than as set forth below. The information presented below updates and should be read in conjunction with the risk factors disclosed in that Form 10-K.
National Fuel’s need to comply with comprehensive, complex, and sometimes unpredictable government regulations may increase its costs and limit its revenue growth, which may result in reduced earnings.
While National Fuel generally refers to its Utility segment and its Pipeline and Storage segment as its “regulated segments,” there are many governmental regulations that have an impact on almost every aspect of National Fuel’s businesses. Existing statutes and regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company, which may affect its business in ways that the Company cannot predict.
In its Utility segment, the operations of Distribution Corporation are subject to the jurisdiction of the NYPSC and the PaPUC. The NYPSC and the PaPUC, among other things, approve the rates that Distribution Corporation may charge to its utility customers. Those approved rates also impact the returns that Distribution Corporation may earn on the assets that are dedicated to those operations. If Distribution Corporation is required in a rate proceeding to reduce the rates it charges its utility customers, or if Distribution Corporation is unable to obtain approval for rate increases from these regulators, particularly
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Item 1A. Risk Factors (Cont.)
when necessary to cover increased costs (including costs that may be incurred in connection with governmental investigations or proceedings or mandated infrastructure inspection, maintenance or replacement programs), Distribution Corporation’s revenue growth will be limited and its earnings may decrease.
In addition to their historical methods of utility regulation, both the PaPUC and NYPSC have sought to establish competitive markets in which customers may purchase supplies of gas from marketers, rather than from utility companies. In June 1999, the Governor of Pennsylvania signed into law the Natural Gas Choice and Competition Act. The act revised the Public Utility Code relating to the restructuring of the natural gas industry. The purpose of the law was to permit consumer choice of natural gas suppliers. To a certain degree, the early programs instituted to comply with the Act have not been overly successful, and many residential customers currently continue to purchase natural gas from the utility companies. In October 2005 the PaPUC concluded that “effective competition” does not exist in the retail natural gas supply market statewide. The PaPUC has reconvened a stakeholder group to explore ways to increase the participation of retail customers in choice programs. In New York, in August 2004, the NYPSC issued its Statement of Policy on Further Steps Toward Competition in Retail Energy Markets. This policy statement has a similar goal of encouraging customer choice of alternative natural gas providers. In 2005, the NYPSC stepped up its efforts to encourage customer choice at the retail residential level. These new forms of regulation may increase Distribution Corporation’s cost of doing business, put an additional portion of its business at regulatory risk, and create uncertainty for the future, all of which may make it more difficult to manage Distribution Corporation’s business profitably.
In its Pipeline and Storage segment, National Fuel is subject to the jurisdiction of the FERC with respect to Supply Corporation, and to the jurisdiction of the NYPSC with respect to Empire. These regulatory commissions, among other things, approve the rates that Supply Corporation may charge to its natural gas transportation and storage customers. Those approved rates also impact the returns that Supply Corporation may earn on the assets that are dedicated to those operations. State commissions can also petition the FERC to investigate whether Supply Corporation’s rates are still just and reasonable, and if not, to reduce those rates prospectively. If Supply Corporation is required in a rate proceeding to reduce the rates it charges its natural gas transportation and storage customers, or if Supply Corporation is unable to obtain approval for rate increases, particularly when necessary to cover increased costs, Supply Corporation’s revenue growth will be limited and its earnings may decrease.
The nature of National Fuel’s operations presents inherent risks of loss that could adversely affect its results of operations, financial condition and cash flows.
National Fuel’s operations are subject to inherent hazards and risks such as: fires; natural disasters; explosions; formations with abnormal pressures; blowouts; collapses of wellbore casing or other tubulars; pipeline ruptures; spills; and other hazards and risks that may cause personal injury, death, property damage, environmental damage or business interruption losses. Additionally, National Fuel’s facilities, machinery, and equipment may be subject to sabotage. Any of these events could cause a loss of hydrocarbons, environmental pollution, claims for personal injury, death, property damage or business interruption, or governmental investigations, recommendations, claims, fines or penalties. As protection against operational hazards, National Fuel maintains insurance coverage against some, but not all, potential losses. In addition, many of the agreements that National Fuel executes with contractors provide for the division of responsibilities between the contractor and National Fuel, and National Fuel seeks to obtain an indemnification from the contractor for certain of these risks. National Fuel is not always able, however, to secure written agreements with its contractors that contain indemnification, and sometimes National Fuel is required to indemnify others.
Insurance or indemnification agreements when obtained may not adequately protect National Fuel against liability from all of the consequences of the hazards described above. The occurrence of an event not fully insured or indemnified against, the imposition of fines, penalties or mandated programs by governmental authorities, the failure of a contractor to meet its indemnification obligations, or the failure of an insurance company to pay valid claims could result in substantial losses to National Fuel. In addition,
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Item 1A. Risk Factors (Concl.)
insurance may not be available, or if available may not be adequate, to cover any or all of these risks. It is also possible that insurance premiums or other costs may rise significantly in the future, so as to make such insurance prohibitively expensive.
Due to large insurance losses caused by Hurricanes Katrina and Rita, the insurance industry has significantly increased premiums for insurance on Gulf of Mexico properties, and has reduced the limits typically available for windstorm damage. As a result, National Fuel has determined that it is not economical to purchase insurance to fully cover its exposures in the Gulf of Mexico in the event of a named windstorm. National Fuel has procured named windstorm coverage in an amount equal to approximately three times the estimated physical damage loss sustained by National Fuel as a result of named windstorms during the 2005 hurricane season. No assurance can be given, however, that such amount will be sufficient to cover losses that may occur in the future.
Hazards and risks faced by National Fuel, and insurance and indemnification obtained or provided by National Fuel, may subject National Fuel to litigation or administrative proceedings from time to time. Such litigation or proceedings could result in substantial monetary judgments, fines or penalties against National Fuel or be resolved on unfavorable terms, the result of which could have a material adverse effect on National Fuel’s results of operations, financial condition and cash flows.
Back to Table of Contents On April 3, 2006, the Company issued a total of 2,100 unregistered shares of Company common stock to the seven non-employee directors of the Company serving on the Board of Directors, 300 shares to each such director. All of these unregistered shares were issued as partial consideration for the directors’ services during the quarter ended June 30, 2006, pursuant to the Company’s Retainer Policy for Non-Employee Directors. These transactions were exempt from registration by Section 4(2) of the Securities Act of 1933 as transactions not involving a public offering.
Issuer Purchases of Equity Securities
- ------------------------- ---------------------- ---------------------- ------------------------ ------------------------
Total Number of Shares Maximum Number of
Purchased as Part of Shares that May Yet Be
Total Number of Publicly Announced Purchased Under Share
Shares Average Price Share Repurchase Plans Repurchase Plans or
Period Purchased (a) Paid per Share or Programs Programs (b)
- ------------------------- ---------------------- ---------------------- ------------------------ ------------------------
Apr. 1 - 30, 2006 32,504 $32.50 16,600 7,158,150
- ------------------------- ---------------------- ---------------------- ------------------------ ------------------------
May 1 - 31, 2006 631,305 $34.45 515,400 6,642,750
- ------------------------- ---------------------- ---------------------- ------------------------ ------------------------
June 1 - 30, 2006 1,031,512 $34.33 927,100 5,715,650
- ------------------------- ---------------------- ---------------------- ------------------------ ------------------------
Total 1,695,321 $34.34 1,459,100 5,715,650
- ------------------------- ---------------------- ---------------------- ------------------------ ------------------------
(a) Represents (i) shares of common stock of the Company purchased on the open market with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, (ii) shares of common stock of the Company tendered to the Company by holders of stock options or shares of restricted stock for the payment of option exercise prices or applicable withholding taxes, and (iii) shares of common stock of the Company purchased on the open market pursuant to the Company’s publicly announced share repurchase program. Shares purchased other than through a publicly announced share repurchase program totaled 15,904 in April 2006, 115,905 in May 2006 and 104,412 in June 2006 (a three month total of 236,221). Of those shares, 29,821 were purchased for the Company’s 401(k) plans and 206,400 were purchased as a result of shares tendered to the Company by holders of stock options or shares of restricted stock.
(b) On December 8, 2005, the Company’s Board of Directors authorized the repurchase of up to eight million shares of the Company’s common stock. Repurchases may be made from time to time in the open market or through private transactions.
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Back to Table of Contents
(a) Exhibits
Exhibit
Number Description of Exhibit
-------- ----------------------
10.1 Description of assignment of interests in certain life insurance policies.
10.2 Description of long-term performance incentives under the National Fuel
Gas Company Performance Incentive Program.
10.3 Description of agreement between the Company and P. C. Ackerman
regarding death benefit.
10.4 Retirement Agreement between the Company and J. A. Beck.
10.5 Contract for Consulting Services between the Company and J. A. Beck.
12 Statements regarding Computation of Ratios:
Ratio of Earnings to Fixed Charges for the Twelve Months Ended June 30, 2006 and the Fiscal Years
Ended September 30, 2001 through 2005.
31.1 Written statements of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under
the Securities Exchange Act of 1934.
31.2 Written statements of Principal Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a)
under the Securities Exchange Act of 1934.
32 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99 National Fuel Gas Company Consolidated Statement of Income for the Twelve Months Ended June 30,
2006 and 2005.
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Back to Table of ContentsSIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
NATIONAL FUEL GAS COMPANY
(Registrant)
/s/R. J. Tanski
R. J. Tanski
Treasurer and Principal Financial Officer
/s/K. M. Camiolo
K. M. Camiolo
Controller and Principal Accounting Officer
Date: August 4, 2006
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EXHIBIT INDEX
(Form 10-Q)
Exhibit 10.1 Description of assignment of interests in certain life insurance policies.
Exhibit 10.2 Description of long-term performance incentives under the Natinal Fuel
Gas Company Performance Incentive Program.
Exhibit 10.3 Description of agreement between the Company and P.C. Ackerman
regarding death benefit.
Exhibit 10.4 Retirement Agreement between the Company and J.A. Beck.
Exhibit 10.5 Contract for Consulting Services between the Company and J.A. Beck.
Exhibit 12 Statements regarding Computation of Ratios:
Ratio of Earnings to Fixed Charges for the Twelve
Months Ended June 30, 2006 and the Fiscal Years Ended
September 30, 2001 through 2005.
Exhibit 31.1 Written statements of Chief Executive Officer pursuant to Rule 13a-14(a) or
Rule 15d-14(a) under the Securities Exchange Act of 1934.
Exhibit 31.2 Written statements of Principal Financial Officer pursuant to Rule 13a-14(a) or
Rule 15d-14(a) under the Securities Exchange Act of 1934.
Exhibit 32 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit 99 National Fuel Gas Company Consolidated Statement of
Income for the Twelve Months Ended June 30, 2006 and 2005.
