UNITED STATES SECURITIES AND EXCHANGE COMMISSION
þ | ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) |
New Jersey | 13-1086010 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
6363 Main Street Williamsville, New York (Address of principal executive offices) | 14221 (Zip Code) |
Name of | ||
Each Exchange | ||
on Which | ||
Title of Each Class | ||
Common Stock, $1 Par Value, and Common Stock Purchase Rights | New York Stock Exchange |
2006.
National Fuel Gas Companies |
Regulatory Agencies |
Other |
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Item 1 | Business |
4. The International segment operations are carried out by Horizon Energy Development, Inc. (Horizon), a New York corporation. Horizon engages in foreign and domestic energy projects through investments as a sole or substantial owner in various business entities. These entities include Horizon’s wholly-owned
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property and managed an additional 4,000 acres of timber rights.
• | Horizon Energy Development, Inc. (Horizon), a New York corporation formed to engage in foreign and domestic energy projects through investments as a sole or substantial owner in various business entities. These entities include Horizon’s wholly-owned subsidiary, Horizon Energy Holdings, Inc., a New York corporation, which owns 100% of Horizon Energy Development B.V. (Horizon B.V.). Horizon B.V. is a Dutch company that is in the process of winding up or selling certain power development projects in Europe; | |
• | Horizon LFG, Inc. (Horizon LFG), a New York corporation engaged through subsidiaries in the purchase, sale and transportation of landfill gas in Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana. Horizon LFG and one of its wholly owned subsidiaries own all of the partnership interests in Toro Partners, LP (Toro), a limited partnership which owns and operates short-distance landfill gas pipeline companies. | |
• | Leidy Hub, Inc. | |
• | Data-Track Account Services, Inc. (Data-Track), a New York corporation | |
• | Horizon Power, Inc. (Horizon Power), a New York corporation which is | |
• | Empire Pipeline, Inc., a New York corporation formed in 2005 to be the surviving corporation of a planned future merger with Empire, which is expected to occur after construction of the Empire Connector project (described below under the heading “Rates and Regulation” and under Item 7, MD&A under the headings “Investing Cash Flow” and “Rate and Regulatory Matters”).* |
2006.
PUHCA 2005.
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For further discussion of the Empire Connector project, refer to Item 7, MD&A under the headings “Investing Cash Flow” and “Rate and Regulatory Matters.”
In the International segment, rates charged for the sale of thermal energy and electric energy at the retail level are subject to regulation and audit in the Czech Republic by the Czech Ministry of Finance. The regulation of electric energy rates at the retail level indirectly impacts the rates charged by the International segment for its electric energy sales at the wholesale level.
sign certain multi-year primary term extensions.
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Additional discussion of the International segment appears below under the heading “Sources and Availability of Raw Materials,” “Competition” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.
The Energy Marketing Segment
The Energy Marketing segment contributed approximately 3.3% of the Company’s 2004 net income available for common stock.
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2006.
Coal is the principal raw material for the International segment, constituting 54% of the cost of raw materials needed in 2004 to operate the boilers which produce steam or hot water. Natural gas, oil, limestone and water combined accounted for the remaining 46% of such materials. Coal is purchased and delivered directly from the adjacent Mostecka Uhelna Spolecnost, a.s. mine in the Czech Republic for UE’s largest coal-fired plant under a contract where price and quantity are the subject of negotiation each year. The Company has been informed that this mine is expected to have reserves through 2030, although the Company has not been provided with an independent reserve study to support this information.* Natural gas is imported into the Czech Republic from sources in Russia and the North Sea and is transported through the Transgas pipeline system, which is majority owned by RWE AG, a German multi-utility. The International segment purchases natural gas from one of the eight regional gas distribution companies in the Czech Republic. Oil is also imported into the Czech Republic. The International segment purchases oil from domestic and foreign refineries.
the Company’s subsidiaries, and 45% came from outside sources. In addition, Highland purchased approximately eight million board feet of green lumber to augment lumber supply for its kiln operations.
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The gas purchased by the Energy Marketing segment originates in either the Appalachian or mid-continent regions of the United States or in Canada.
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In New York, the Utility segment has instituted a number of programs to accommodate more widespread customer choice. In Pennsylvania, the PaPUC issued a report in October 2005 that concluded “effective competition” does not exist in the retail natural gas supply market statewide. In 2006, the PaPUC reconvened a stakeholder group to explore ways to increase the participation of retail customers in choice programs. The findings of the stakeholder group are expected to be presented to the PaPUC during 2007.
As announced in February 2004,noted above, Empire is pursuing athe Empire Connector project, towhich would expand its natural gas pipeline to serve new markets in New York and elsewhere in the Northeast.* For further discussion of this project, refer to Item 7, MD&A under the headingheadings “Investing Cash Flow.Flow” and “Rate and Regulatory Matters.”
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Competition: The International Segment
Horizon competes with other entities seeking to develop or acquire foreign and domestic energy projects. Horizon, through UE, faces competition in the sale of thermal energy. Most customers can opt to install boilers to produce their thermal energy, rather than purchase thermal energy from the district heating system. In addition, UE, which sells electricity at the wholesale level, faces competition in the sale of electricity. UE must submit price bids on an annual basis for the sale of its electricity to the regional distribution company. A large percentage of the electricity purchased by the regional distribution companies is produced by the Czech Republic’s dominant state-owned energy producer.
international markets.
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this segment.
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2005.
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Current Company | ||
Positions and | ||
Other Material | ||
Business Experience | ||
Name and Age (as of | ||
Philip C. Ackerman | Chairman of the Board of Directors since January 2002; Chief Executive Officer since October 2001; | |
David F. Smith | President of | |
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Current Company | ||
Positions and | ||
Other Material | ||
Business Experience | ||
Name and Age (as of | During Past | |
November 15, 2006) | Five Years | |
Ronald J. Tanski | Treasurer and Principal Financial Officer of the Company since April 2004; President of Distribution Corporation since February 2006; Treasurer of Distribution Corporation since April 2004; Secretary and Treasurer of Supply Corporation since April 2004; Secretary and Treasurer of Horizon since February 1997. Mr. Tanski previously served as Controller of the Company from February 2003 through March 2004; Senior Vice President of Distribution Corporation | |
Matthew D. Cabell (48) | President of | |
Karen M. Camiolo | Controller and Principal Accounting Officer of the Company since April 2004; Controller of Distribution Corporation and Supply Corporation since April 2004; and Chief Auditor of the Company from July 1994 through March 2004. | |
Anna Marie Cellino | Secretary of the Company since October 1995; Senior Vice President of Distribution Corporation since July | |
Paula M. Ciprich (46) | General Counsel of the Company since January 2005; Assistant Secretary and | |
Donna L. DeCarolis | President of | |
John R. Pustulka | Senior Vice President of Supply Corporation since July | |
James D. Ramsdell | Senior Vice President of Distribution Corporation since July |
(1) | The executive officers serve at the pleasure of the Board of Directors. The information provided relates to the Company and its principal subsidiaries. Many of the executive officers also have served or currently serve as officers or directors of other subsidiaries of the Company. |
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Item 1B | Unresolved Staff Comments |
Item 2 | Properties |
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2006.
horsepower that represent 13% of this segment’s total net investment in property, plant and equipment.
The International segment had a net investment in property, plant and equipment of $227.9 million at September 30, 2004. This represents UE’s net investment in district heating and electric generation facilities.
timber, and approximately 4,000 acres of timber rights.
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For the Year Ended | |||||||||||||
September 30 | |||||||||||||
2004 | 2003 | 2002 | |||||||||||
United States | |||||||||||||
Gulf Coast Region | |||||||||||||
Average Sales Price per Mcf of Gas | $ | 5.61 | $ | 5.41 | $ | 2.89 | |||||||
Average Sales Price per Barrel of Oil | $ | 35.31 | $ | 29.17 | $ | 22.83 | |||||||
Average Sales Price per Mcf of Gas (after hedging) | $ | 4.78 | $ | 4.22 | $ | 3.69 | |||||||
Average Sales Price per Barrel of Oil (after hedging) | $ | 31.51 | $ | 27.88 | $ | 22.51 | |||||||
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | $ | 0.60 | $ | 0.56 | $ | 0.60 | |||||||
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | 73 | 75 | 100 | ||||||||||
West Coast Region | |||||||||||||
Average Sales Price per Mcf of Gas | $ | 5.54 | $ | 5.01 | $ | 2.86 | |||||||
Average Sales Price per Barrel of Oil | $ | 31.89 | $ | 26.12 | $ | 19.94 | |||||||
Average Sales Price per Mcf of Gas (after hedging) | $ | 5.72 | $ | 5.12 | $ | 2.86 | |||||||
Average Sales Price per Barrel of Oil (after hedging) | $ | 22.86 | $ | 23.67 | $ | 20.09 | |||||||
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | $ | 1.05 | $ | 1.00 | $ | 0.81 | |||||||
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | 55 | 59 | 63 | ||||||||||
Appalachian Region | |||||||||||||
Average Sales Price per Mcf of Gas | $ | 5.91 | $ | 5.07 | $ | 3.74 | |||||||
Average Sales Price per Barrel of Oil | $ | 31.30 | $ | 28.77 | $ | 23.76 | |||||||
Average Sales Price per Mcf of Gas (after hedging) | $ | 5.72 | $ | 5.10 | $ | 3.74 | |||||||
Average Sales Price per Barrel of Oil (after hedging) | $ | 31.30 | $ | 28.77 | $ | 23.76 | |||||||
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | $ | 0.54 | $ | 0.43 | $ | 0.53 | |||||||
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | 14 | 14 | 12 |
For the Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
United States | ||||||||||||
Gulf Coast Region | ||||||||||||
Average Sales Price per Mcf of Gas | $ | 8.01 | $ | 7.05 | $ | 5.61 | ||||||
Average Sales Price per Barrel of Oil | $ | 64.10 | $ | 49.78 | $ | 35.31 | ||||||
Average Sales Price per Mcf of Gas (after hedging) | $ | 5.89 | $ | 6.01 | $ | 4.82 | ||||||
Average Sales Price per Barrel of Oil (after hedging) | $ | 47.46 | $ | 35.03 | $ | 31.51 | ||||||
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | $ | 0.86 | $ | 0.71 | $ | 0.60 | ||||||
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | 36 | 50 | 73 | |||||||||
West Coast Region | ||||||||||||
Average Sales Price per Mcf of Gas | $ | 7.93 | $ | 6.85 | $ | 5.54 | ||||||
Average Sales Price per Barrel of Oil | $ | 56.80 | $ | 42.91 | $ | 31.89 | ||||||
Average Sales Price per Mcf of Gas (after hedging) | $ | 7.19 | $ | 6.15 | $ | 5.72 | ||||||
Average Sales Price per Barrel of Oil (after hedging) | $ | 37.69 | $ | 23.01 | $ | 22.86 | ||||||
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | $ | 1.35 | $ | 1.15 | $ | 1.05 | ||||||
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | 53 | 53 | 55 | |||||||||
Appalachian Region | ||||||||||||
Average Sales Price per Mcf of Gas | $ | 9.53 | $ | 7.60 | $ | 5.91 | ||||||
Average Sales Price per Barrel of Oil | $ | 65.28 | $ | 48.28 | $ | 31.30 | ||||||
Average Sales Price per Mcf of Gas (after hedging) | $ | 8.90 | $ | 7.01 | $ | 5.72 | ||||||
Average Sales Price per Barrel of Oil (after hedging) | $ | 65.28 | $ | 48.28 | $ | 31.30 | ||||||
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | $ | 0.69 | $ | 0.63 | $ | 0.54 | ||||||
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | 15 | 13 | 14 | |||||||||
Total United States | ||||||||||||
Average Sales Price per Mcf of Gas | $ | 8.42 | $ | 7.13 | $ | 5.66 | ||||||
Average Sales Price per Barrel of Oil | $ | 58.47 | $ | 44.87 | $ | 33.13 | ||||||
Average Sales Price per Mcf of Gas (after hedging) | $ | 7.02 | $ | 6.26 | $ | 5.13 | ||||||
Average Sales Price per Barrel of Oil (after hedging) | $ | 40.26 | $ | 26.59 | $ | 26.06 | ||||||
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | $ | 1.09 | $ | 0.90 | $ | 0.76 | ||||||
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | 104 | 117 | 142 |
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For the Year Ended | |||||||||||||
September 30 | |||||||||||||
2004 | 2003 | 2002 | |||||||||||
Total United States | |||||||||||||
Average Sales Price per Mcf of Gas | $ | 5.66 | $ | 5.28 | $ | 2.99 | |||||||
Average Sales Price per Barrel of Oil | $ | 33.13 | $ | 27.16 | $ | 21.03 | |||||||
Average Sales Price per Mcf of Gas (after hedging) | $ | 5.11 | $ | 4.52 | $ | 3.58 | |||||||
Average Sales Price per Barrel of Oil (after hedging) | $ | 26.06 | $ | 25.11 | $ | 21.01 | |||||||
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | $ | 0.76 | $ | 0.72 | $ | 0.67 | |||||||
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | 142 | 148 | 175 | ||||||||||
Canada | |||||||||||||
Average Sales Price per Mcf of Gas | $ | 4.87 | $ | 4.67 | $ | 2.29 | |||||||
Average Sales Price per Barrel of Oil | $ | 30.94 | $ | 26.41 | $ | 19.94 | |||||||
Average Sales Price per Mcf of Gas (after hedging) | $ | 4.87 | $ | 4.20 | $ | 3.59 | |||||||
Average Sales Price per Barrel of Oil (after hedging) | $ | 30.94 | $ | 15.85 | $ | 18.11 | |||||||
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | $ | 1.00 | $ | 1.65 | $ | 1.29 | |||||||
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | 22 | 55 | 64 | ||||||||||
Total Company | |||||||||||||
Average Sales Price per Mcf of Gas | $ | 5.51 | $ | 5.18 | $ | 2.88 | |||||||
Average Sales Price per Barrel of Oil | $ | 32.98 | $ | 26.90 | $ | 20.63 | |||||||
Average Sales Price per Mcf of Gas (after hedging) | $ | 5.06 | $ | 4.47 | $ | 3.58 | |||||||
Average Sales Price per Barrel of Oil (after hedging) | $ | 26.40 | $ | 21.84 | $ | 19.94 | |||||||
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | $ | 0.80 | $ | 0.97 | $ | 0.84 | |||||||
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | 164 | 203 | 239 |
For the Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Canada | ||||||||||||
Average Sales Price per Mcf of Gas | $ | 7.14 | $ | 6.15 | $ | 4.87 | ||||||
Average Sales Price per Barrel of Oil | $ | 51.40 | $ | 42.97 | $ | 30.94 | ||||||
Average Sales Price per Mcf of Gas (after hedging) | $ | 7.47 | $ | 6.14 | $ | 4.79 | ||||||
Average Sales Price per Barrel of Oil (after hedging) | $ | 51.40 | $ | 42.97 | $ | 30.94 | ||||||
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | $ | 1.57 | $ | 1.29 | $ | 1.00 | ||||||
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | 26 | 27 | 22 | |||||||||
Total Company | ||||||||||||
Average Sales Price per Mcf of Gas | $ | 8.04 | $ | 6.86 | $ | 5.51 | ||||||
Average Sales Price per Barrel of Oil | $ | 57.94 | $ | 44.72 | $ | 32.98 | ||||||
Average Sales Price per Mcf of Gas (after hedging) | $ | 7.15 | $ | 6.23 | $ | 5.06 | ||||||
Average Sales Price per Barrel of Oil (after hedging) | $ | 41.10 | $ | 27.86 | $ | 26.40 | ||||||
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced | $ | 1.18 | $ | 0.98 | $ | 0.80 | ||||||
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) | 130 | 144 | 164 |
United States | ||||||||||||||||||||||||||||||||
Gulf Coast | West Coast | Appalachian | ||||||||||||||||||||||||||||||
Region | Region | Region | Total U.S. | |||||||||||||||||||||||||||||
At September 30, 2004 | Gas | Oil | Gas | Oil | Gas | Oil | Gas | Oil | ||||||||||||||||||||||||
Productive Wells — Gross | 32 | 34 | — | 1,155 | 1,912 | 31 | 1,944 | 1,220 | ||||||||||||||||||||||||
Productive Wells — Net | 20 | 15 | — | 1,146 | 1,837 | 25 | 1,857 | 1,186 |
United States | ||||||||||||||||||||||||||||||||
Gulf Coast | West Coast | Appalachian | ||||||||||||||||||||||||||||||
Region | Region | Region | Total U.S. | |||||||||||||||||||||||||||||
At September 30, 2006 | Gas | Oil | Gas | Oil | Gas | Oil | Gas | Oil | ||||||||||||||||||||||||
Productive Wells — Gross | 34 | 30 | — | 1,274 | 2,138 | 31 | 2,172 | 1,335 | ||||||||||||||||||||||||
Productive Wells — Net | 21 | 14 | — | 1,266 | 2,052 | 25 | 2,073 | 1,305 |
Canada | Total Company | |||||||||||||||
At September 30, 2004 | Gas | Oil | Gas | Oil | ||||||||||||
Productive Wells — Gross | 177 | 49 | 2,121 | 1,269 | ||||||||||||
Productive Wells — Net | 124 | 34 | 1,981 | 1,220 |
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Canada | Total Company | |||||||||||||||
At September 30, 2006 | Gas | Oil | Gas | Oil | ||||||||||||
Productive Wells — Gross | 217 | 53 | 2,389 | 1,388 | ||||||||||||
Productive Wells — Net | 155 | 36 | 2,228 | 1,341 |
United States | |||||||||||||||||||||||||
Gulf | West | ||||||||||||||||||||||||
Coast | Coast | Appalachian | Total | Total | |||||||||||||||||||||
At September 30, 2004 | Region | Region | Region | U.S. | Canada | Company | |||||||||||||||||||
Developed Acreage | — Gross | 102,270 | 9,839 | 508,466 | 620,575 | 109,194 | 729,769 | ||||||||||||||||||
— Net | 76,549 | 9,469 | 481,732 | 567,750 | 74,302 | 642,052 | |||||||||||||||||||
Undeveloped Acreage | — Gross | 206,619 | — | 464,525 | 671,144 | 421,690 | 1,092,834 | ||||||||||||||||||
— Net | 115,909 | — | 440,004 | 555,913 | 316,820 | 872,733 |
United States | ||||||||||||||||||||||||
Golf | West | |||||||||||||||||||||||
Coast | Coast | Appalachian | Total | Total | ||||||||||||||||||||
At September 30, 2006 | Region | Region | Region | U.S. | Canada | Company | ||||||||||||||||||
Developed Acreage | ||||||||||||||||||||||||
— Gross | 144,610 | 10,479 | 514,222 | 669,311 | 117,955 | 787,266 | ||||||||||||||||||
— Net | 104,173 | 10,109 | 487,384 | 601,666 | 84,182 | 685,848 | ||||||||||||||||||
Undeveloped Acreage | ||||||||||||||||||||||||
— Gross | 174,503 | — | 475,909 | 650,412 | 393,169 | 1,043,581 | ||||||||||||||||||
— Net | 85,117 | — | 451,733 | 536,850 | 243,287 | 780,137 |
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Productive | Dry | |||||||||||||||||||||||||
For the Year Ended September 30 | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||||||||||
United States | ||||||||||||||||||||||||||
Gulf Coast Region | ||||||||||||||||||||||||||
Net Wells Completed | — Exploratory | — | 1.25 | 1.27 | 0.50 | — | 3.67 | |||||||||||||||||||
— Development | 0.65 | 2.10 | 0.31 | — | — | — | ||||||||||||||||||||
West Coast Region | ||||||||||||||||||||||||||
Net Wells Completed | — Exploratory | — | — | — | — | — | — | |||||||||||||||||||
— Development | 49.00 | 30.97 | 47.99 | — | — | 2.00 | ||||||||||||||||||||
Appalachian Region | ||||||||||||||||||||||||||
Net Wells Completed | — Exploratory | — | 3.00 | 3.00 | 3.00 | 0.10 | 1.00 | |||||||||||||||||||
— Development | 41.00 | 58.00 | 27.00 | — | — | 0.10 | ||||||||||||||||||||
Total United States | ||||||||||||||||||||||||||
Net Wells Completed | — Exploratory | — | 4.25 | 4.27 | 3.50 | 0.10 | 4.67 | |||||||||||||||||||
— Development | 90.65 | 91.07 | 75.30 | — | — | 2.10 | ||||||||||||||||||||
Canada | ||||||||||||||||||||||||||
Net Wells Completed | — Exploratory | 52.85 | 5.00 | 0.20 | 6.08 | 2.50 | 4.00 | |||||||||||||||||||
— Development | 10.50 | 17.16 | 33.70 | — | 5.00 | 7.90 | ||||||||||||||||||||
Total | ||||||||||||||||||||||||||
Net Wells Completed | — Exploratory | 52.85 | 9.25 | 4.47 | 9.58 | 2.60 | 8.67 | |||||||||||||||||||
— Development | 101.15 | 108.23 | 109.00 | — | 5.00 | 10.00 |
Productive | Dry | |||||||||||||||||||||||
For the Year Ended September 30 | 2006 | 2005 | 2004 | 2006 | 2005 | 2004 | ||||||||||||||||||
United States | ||||||||||||||||||||||||
Gulf Coast Region | ||||||||||||||||||||||||
Net Wells Completed | ||||||||||||||||||||||||
— Exploratory | 2.94 | 1.30 | — | 0.85 | 0.47 | 0.50 | ||||||||||||||||||
— Development | 0.78 | 0.23 | 0.65 | — | — | — | ||||||||||||||||||
West Coast Region Net Wells Completed | ||||||||||||||||||||||||
— Exploratory | — | — | — | — | — | — | ||||||||||||||||||
— Development | 92.98 | 116.97 | 49.00 | 1.00 | — | — | ||||||||||||||||||
Appalachian Region Net Wells Completed | ||||||||||||||||||||||||
— Exploratory | 3.88 | 3.00 | — | — | 4.00 | 3.00 | ||||||||||||||||||
— Development | 140.58 | 45.00 | 41.00 | 1.75 | 1.00 | — | ||||||||||||||||||
Total United States Net Wells Completed | ||||||||||||||||||||||||
— Exploratory | 6.82 | 4.30 | — | 0.85 | 4.47 | 3.50 | ||||||||||||||||||
— Development | 234.34 | 162.20 | 90.65 | 2.75 | 1.00 | — | ||||||||||||||||||
Canada | ||||||||||||||||||||||||
Net Wells Completed | ||||||||||||||||||||||||
— Exploratory | 12.60 | 21.14 | 52.85 | 1.35 | 2.00 | 6.08 | ||||||||||||||||||
— Development | 2.50 | 3.50 | 10.50 | 1.00 | — | — | ||||||||||||||||||
Total | ||||||||||||||||||||||||
Net Wells Completed | ||||||||||||||||||||||||
— Exploratory | 19.42 | 25.44 | 52.85 | 2.20 | 6.47 | 9.58 | ||||||||||||||||||
— Development | 236.84 | 165.70 | 101.15 | 3.75 | 1.00 | — |
United States | |||||||||||||||||||||||||
Gulf | West | ||||||||||||||||||||||||
Coast | Coast | Appalachian | Total | Total | |||||||||||||||||||||
At September 30, 2004 | Region | Region | Region | U.S. | Canada | Company | |||||||||||||||||||
Wells in Process of Drilling(1) | — Gross | 1.00 | 5.00 | 25.00 | 31.00 | 1.00 | 32.00 | ||||||||||||||||||
— Net | 0.67 | 5.00 | 24.05 | 29.72 | 1.00 | 30.72 |
United States | ||||||||||||||||||||||||
Gulf | West | |||||||||||||||||||||||
Coast | Coast | Appalachian | Total | Total | ||||||||||||||||||||
At September 30, 2006 | Region | Region | Region | U.S. | Canada | Company | ||||||||||||||||||
Wells in Process of Drilling(1) | ||||||||||||||||||||||||
— Gross | 5.00 | 6.00 | 54.00 | 65.00 | 5.00 | 70.00 | ||||||||||||||||||
— Net | 2.69 | 5.50 | 54.00 | 62.19 | 2.13 | 64.32 |
(1) | Includes wells awaiting completion. |
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Item 3 | Legal Proceedings |
In an action instituted in the New York State Supreme Court, Chautauqua County on January 31, 2000 against Seneca, NFR and “National Fuel Gas Corporation,” Donald J. and Margaret Ortel and Brian and Judith Rapp, “individually and on behalf of all those similarly situated,” allege, in an amended complaint which adds National Fuel Gas Company as a party defendant that (a) Seneca underpaid royalties due under leases operated by it, and (b) Seneca’s co-defendants (i) fraudulently participated in and concealed such alleged underpayment, and (ii) induced Seneca’s alleged breach of such leases. Plaintiffs seek an accounting, declaratory and related injunctive relief, and compensatory and exemplary damages. Defendants have denied each of plaintiffs’ material substantive allegations and set up twenty-five affirmative defenses in separate verified answers.
A motion was made by plaintiffs on July 15, 2002 to certify a class comprising all persons presently and formerly entitled to receive royalties on the sale of natural gas produced and sold from wells operated in New York by Seneca (and its predecessor Empire Exploration, Inc). On December 23, 2002, the court granted certification of the proposed class, as modified to exclude those leaseholders whose leases provide for calculation of royalties based upon a flat fee, or flat fee per cubic foot of gas produced. The court’s order states that there are approximately 749 potential class members. Discovery has begun on the merits of the claims.
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Regulatory Matters.”
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The
Item 4 | Submission of Matters to a Vote of Security Holders |
2004.Item 5 Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities D-CapitalizationE-Capitalization and Short-Term Borrowings andNote M-MarketN-Market for Common Stock and Related Shareholder Matters (unaudited).2004,2006, the Company issued a total of 1,8002,100 unregistered shares of Company common stock to the sixseven non-employee directors of the Company then serving on the Board of Directors, 300 shares to each such director. All of these unregistered shares were issued as partial consideration for such directors’ services during the quarter ended September 30, 2004,2006, pursuant to the Company’s Retainer Policy for Non-Employee Directors. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933, as transactions not involving a public offering.
22
Total Number of | ||||||||||||||||
Shares Purchased | Maximum Number of | |||||||||||||||
as Part of Publicly | Shares that May Yet | |||||||||||||||
Total Number of | Announced Share | Be Purchased Under | ||||||||||||||
Shares | Average Price | Repurchase Plans | Share Repurchase | |||||||||||||
Period | Purchased(a) | Paid per Share | or Programs | Plans or Programs | ||||||||||||
July 1-31, 2004 | 59,546 | $ | 26.04 | — | — | |||||||||||
Aug. 1-31, 2004 | 35,616 | $ | 26.49 | — | — | |||||||||||
Sept. 1-30, 2004 | 216,163 | $ | 27.97 | — | — | |||||||||||
Total | 311,325 | $ | 27.43 | — | — | |||||||||||
Total Number | Maximum Number | |||||||||||||||
of Shares | of Shares | |||||||||||||||
Purchased as | that May | |||||||||||||||
Part of | Yet Be | |||||||||||||||
Publicly Announced | Purchased Under | |||||||||||||||
Total Number | Average Price | Share Repurchase | Share Repurchase | |||||||||||||
of Shares | Paid per | Plans or | Plans or | |||||||||||||
Period | Purchased(a) | Share | Programs | Programs(b) | ||||||||||||
July 1-31, 2006 | 444,198 | $ | 36.32 | 94,400 | 5,621,250 | |||||||||||
Aug. 1-31, 2006 | 47,155 | $ | 37.91 | — | 5,621,250 | |||||||||||
Sept. 1-30, 2006 | 192,702 | $ | 36.46 | 147,800 | 5,473,450 | |||||||||||
Total | 684,055 | $ | 36.47 | 242,200 | 5,473,450 | |||||||||||
(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, | |
(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. |
17
Item 6 | Selected Financial Data(1) |
Year Ended September 30 | |||||||||||||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | |||||||||||||||||
(Thousands) | |||||||||||||||||||||
Summary of Operations | |||||||||||||||||||||
Operating Revenues | $ | 2,031,393 | $ | 2,035,471 | $ | 1,464,496 | $ | 2,059,836 | $ | 1,412,416 | |||||||||||
Operating Expenses: | |||||||||||||||||||||
Purchased Gas | 949,452 | 963,567 | 462,857 | 1,002,466 | 488,383 | ||||||||||||||||
Fuel Used in Heat and Electric Generation | 65,722 | 61,029 | 50,635 | 54,968 | 54,893 | ||||||||||||||||
Operation and Maintenance | 413,593 | 386,270 | 394,157 | 364,318 | 350,383 | ||||||||||||||||
Property, Franchise and Other Taxes | 72,111 | 82,504 | 72,155 | 83,730 | 78,878 | ||||||||||||||||
Depreciation, Depletion and Amortization | 189,538 | 195,226 | 180,668 | 174,914 | 142,170 | ||||||||||||||||
Impairment of Oil and Gas Producing Properties | — | 42,774 | — | 180,781 | — | ||||||||||||||||
1,690,416 | 1,731,370 | 1,160,472 | 1,861,177 | 1,114,707 | |||||||||||||||||
Gain (Loss) on Sale of Timber Properties | (1,252 | ) | 168,787 | — | — | — | |||||||||||||||
Gain (Loss) on Sale of Oil and Gas Producing Properties | 4,645 | (58,472 | ) | — | — | — | |||||||||||||||
Operating Income | 344,370 | 414,416 | 304,024 | 198,659 | 297,709 | ||||||||||||||||
Other Income (Expense): | |||||||||||||||||||||
Income from Unconsolidated Subsidiaries | 805 | 535 | 224 | 1,794 | 1,669 | ||||||||||||||||
Impairment of Investment in Partnership | — | — | (15,167 | ) | — | — | |||||||||||||||
Other Income | 6,671 | 6,887 | 7,017 | 10,639 | 6,366 | ||||||||||||||||
Interest Expense on Long-Term Debt | (83,827 | ) | (92,766 | ) | (90,543 | ) | (81,851 | ) | (67,195 | ) | |||||||||||
Other Interest Expense | (6,763 | ) | (12,290 | ) | (15,109 | ) | (25,294 | ) | (32,890 | ) | |||||||||||
Income Before Income Taxes and Minority Interest in Foreign Subsidiaries | 261,256 | 316,782 | 190,446 | 103,947 | 205,659 | ||||||||||||||||
Income Tax Expense | 92,737 | 128,161 | 72,034 | 37,106 | 77,068 | ||||||||||||||||
Minority Interest in Foreign Subsidiaries | (1,933 | ) | (785 | ) | (730 | ) | (1,342 | ) | (1,384 | ) | |||||||||||
Income Before Cumulative Effect of Changes in Accounting | 166,586 | 187,836 | 117,682 | 65,499 | 127,207 | ||||||||||||||||
Cumulative Effect of Changes in Accounting | — | (8,892 | ) | — | — | — | |||||||||||||||
Net Income Available for Common Stock | $ | 166,586 | $ | 178,944 | $ | 117,682 | $ | 65,499 | $ | 127,207 | |||||||||||
Year Ended September 30 | ||||||||||||||||||||
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(Thousands) | ||||||||||||||||||||
Summary of Operations | ||||||||||||||||||||
Operating Revenues | $ | 2,311,659 | $ | 1,923,549 | $ | 1,907,968 | $ | 1,921,573 | $ | 1,369,869 | ||||||||||
Operating Expenses: | ||||||||||||||||||||
Purchased Gas | 1,267,562 | 959,827 | 949,452 | 963,567 | 462,857 | |||||||||||||||
Operation and Maintenance | 413,726 | 404,517 | 385,519 | 361,898 | 372,063 | |||||||||||||||
Property, Franchise and Other Taxes | 69,942 | 69,076 | 68,978 | 79,692 | 69,837 | |||||||||||||||
Depreciation, Depletion and Amortization | 179,615 | 179,767 | 174,289 | 181,329 | 168,745 | |||||||||||||||
Impairment of Oil and Gas Producing Properties | 104,739 | — | — | 42,774 | — | |||||||||||||||
2,035,584 | 1,613,187 | 1,578,238 | 1,629,260 | 1,073,502 | ||||||||||||||||
Gain (Loss) on Sale of Timber Properties | — | — | (1,252 | ) | 168,787 | — | ||||||||||||||
Gain (Loss) on Sale of Oil and Gas Producing Properties | — | — | 4,645 | (58,472 | ) | — | ||||||||||||||
Operating Income | 276,075 | 310,362 | 333,123 | 402,628 | 296,367 |
23
18
Year Ended September 30 | |||||||||||||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | |||||||||||||||||
(Thousands) | |||||||||||||||||||||
Per Common Share Data | |||||||||||||||||||||
Basic Earnings per Common Share | $ | 2.03 | $ | 2.21 | (2) | $ | 1.47 | $ | 0.83 | $ | 1.63 | ||||||||||
Diluted Earnings per Common Share | $ | 2.01 | $ | 2.20 | (2) | $ | 1.46 | $ | 0.82 | $ | 1.61 | ||||||||||
Dividends Declared | $ | 1.10 | $ | 1.06 | $ | 1.03 | $ | 0.99 | $ | 0.95 | |||||||||||
Dividends Paid | $ | 1.09 | $ | 1.05 | $ | 1.02 | $ | 0.97 | $ | 0.94 | |||||||||||
Dividend Rate at Year-End | $ | 1.12 | $ | 1.08 | $ | 1.04 | $ | 1.01 | $ | 0.96 | |||||||||||
At September 30: | |||||||||||||||||||||
Number of Common Shareholders | 19,063 | 19,217 | 20,004 | 20,345 | 21,164 | ||||||||||||||||
Net Property, Plant and Equipment(Thousands) | |||||||||||||||||||||
Utility | $ | 1,048,428 | $ | 1,028,393 | $ | 960,015 | $ | 945,693 | $ | 939,753 | |||||||||||
Pipeline and Storage | 696,487 | 705,927 | 487,793 | 483,222 | 474,972 | ||||||||||||||||
Exploration and Production | 923,730 | 925,833 | 1,072,200 | 1,081,622 | 998,852 | ||||||||||||||||
International | 227,905 | 219,199 | 207,191 | 178,250 | 172,602 | ||||||||||||||||
Energy Marketing | 80 | 171 | 125 | 262 | 360 | ||||||||||||||||
Timber | 82,838 | 87,600 | 110,624 | 90,453 | 95,607 | ||||||||||||||||
All Other | 21,172 | 22,042 | 6,797 | 1,209 | 1,241 | ||||||||||||||||
Corporate | 6,124 | 1,883 | — | 2 | 4 | ||||||||||||||||
Total Net Plant | $ | 3,006,764 | $ | 2,991,048 | $ | 2,844,745 | $ | 2,780,713 | $ | 2,683,391 | |||||||||||
Total Assets(Thousands) | $ | 3,711,798 | $ | 3,719,060 | $ | 3,401,309 | $ | 3,445,231 | $ | 3,251,031 | |||||||||||
Capitalization(Thousands) | |||||||||||||||||||||
Comprehensive Shareholders’ Equity | $ | 1,253,701 | $ | 1,137,390 | $ | 1,006,858 | $ | 1,002,655 | $ | 987,437 | |||||||||||
Long-Term Debt, Net of Current Portion | 1,133,317 | 1,147,779 | 1,145,341 | 1,046,694 | 953,622 | ||||||||||||||||
Total Capitalization | $ | 2,387,018 | $ | 2,285,169 | $ | 2,152,199 | $ | 2,049,349 | $ | 1,941,059 | |||||||||||
Year Ended September 30 | ||||||||||||||||||||
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(Thousands) | ||||||||||||||||||||
Other Income (Expense): | ||||||||||||||||||||
Income from Unconsolidated Subsidiaries | 3,583 | 3,362 | 805 | 535 | 224 | |||||||||||||||
Impairment of Investment in Partnership | — | (4,158 | ) | — | — | (15,167 | ) | |||||||||||||
Interest Income | 10,275 | 6,496 | 1,771 | 2,204 | 2,593 | |||||||||||||||
Other Income | 2,825 | 12,744 | 2,908 | 2,427 | 3,184 | |||||||||||||||
Interest Expense on Long-Term Debt | (72,629 | ) | (73,244 | ) | (82,989 | ) | (91,381 | ) | (88,646 | ) | ||||||||||
Other Interest Expense | (5,952 | ) | (9,069 | ) | (6,763 | ) | (11,196 | ) | (15,109 | ) | ||||||||||
Income from Continuing Operations Before Income Taxes | 214,177 | 246,493 | 248,855 | 305,217 | 183,446 | |||||||||||||||
Income Tax Expense | 76,086 | 92,978 | 94,590 | 124,150 | 69,944 | |||||||||||||||
Income from Continuing Operations | 138,091 | 153,515 | 154,265 | 181,067 | 113,502 | |||||||||||||||
Discontinued Operations: | ||||||||||||||||||||
Income from Operations, Net of Tax | — | 10,199 | 12,321 | 6,769 | 4,180 | |||||||||||||||
Gain on Disposal, Net of Tax | — | 25,774 | — | — | — | |||||||||||||||
Income from Discontinued Operations, Net of Tax | — | 35,973 | 12,321 | 6,769 | 4,180 | |||||||||||||||
Income Before Cumulative Effect of Changes in Accounting | 138,091 | 189,488 | 166,586 | 187,836 | 117,682 | |||||||||||||||
Cumulative Effect of Changes in Accounting | — | — | — | (8,892 | ) | — | ||||||||||||||
Net Income Available for Common Stock | $ | 138,091 | $ | 189,488 | $ | 166,586 | $ | 178,944 | $ | 117,682 | ||||||||||
Per Common Share Data | ||||||||||||||||||||
Basic Earnings from Continuing Operations per Common Share | $ | 1.64 | $ | 1.84 | $ | 1.88 | $ | 2.24 | $ | 1.42 | ||||||||||
Diluted Earnings from Continuing Operations per Common Share | $ | 1.61 | $ | 1.81 | $ | 1.86 | $ | 2.23 | $ | 1.41 | ||||||||||
Basic Earnings per Common Share(2) | $ | 1.64 | $ | 2.27 | $ | 2.03 | $ | 2.21 | $ | 1.47 | ||||||||||
Diluted Earnings per Common Share(2) | $ | 1.61 | $ | 2.23 | $ | 2.01 | $ | 2.20 | $ | 1.46 | ||||||||||
Dividends Declared | $ | 1.18 | $ | 1.14 | $ | 1.10 | $ | 1.06 | $ | 1.03 | ||||||||||
Dividends Paid | $ | 1.17 | $ | 1.13 | $ | 1.09 | $ | 1.05 | $ | 1.02 | ||||||||||
Dividend Rate at Year-End | $ | 1.20 | $ | 1.16 | $ | 1.12 | $ | 1.08 | $ | 1.04 | ||||||||||
At September 30: | ||||||||||||||||||||
Number of Registered Shareholders | 17,767 | 18,369 | 19,063 | 19,217 | 20,004 | |||||||||||||||
24
Year Ended September 30 | ||||||||||||||||||||
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(Thousands) | ||||||||||||||||||||
Net Property, Plant and Equipment | ||||||||||||||||||||
Utility | $ | 1,084,080 | $ | 1,064,588 | $ | 1,048,428 | $ | 1,028,393 | $ | 960,015 | ||||||||||
Pipeline and Storage | 674,175 | 680,574 | 696,487 | 705,927 | 487,793 | |||||||||||||||
Exploration and Production | 1,002,265 | 974,806 | 923,730 | 925,833 | 1,072,200 | |||||||||||||||
Energy Marketing | 59 | 97 | 80 | 171 | 125 | |||||||||||||||
Timber | 90,939 | 94,826 | 82,838 | 87,600 | 110,624 | |||||||||||||||
All Other | 17,394 | 18,098 | 21,172 | 22,042 | 6,797 | |||||||||||||||
Corporate(3) | 8,814 | 6,311 | 234,029 | 221,082 | 207,191 | |||||||||||||||
Total Net Plant | $ | 2,877,726 | $ | 2,839,300 | $ | 3,006,764 | $ | 2,991,048 | $ | 2,844,745 | ||||||||||
Total Assets | $ | 3,734,331 | $ | 3,725,282 | $ | 3,717,603 | $ | 3,725,414 | $ | 3,429,163 | ||||||||||
Capitalization | ||||||||||||||||||||
Comprehensive Shareholders’ Equity | $ | 1,443,562 | $ | 1,229,583 | $ | 1,253,701 | $ | 1,137,390 | $ | 1,006,858 | ||||||||||
Long-Term Debt, Net of Current Portion | 1,095,675 | 1,119,012 | 1,133,317 | 1,147,779 | 1,145,341 | |||||||||||||||
Total Capitalization | $ | 2,539,237 | $ | 2,348,595 | $ | 2,387,018 | $ | 2,285,169 | $ | 2,152,199 | ||||||||||
(1) | Certain prior year amounts have been reclassified to conform with current year presentation. | |
(2) | Includes discontinued operations and cumulative effect of changes in | |
(3) | Includes net plant of |
Item 7 | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
19
6. | Other Matters, including: a.) 2006 and 2007 funding to the Company’s defined benefit retirement plan and post-retirement benefit plan, b.) realizability of deferred tax assets, c.) disclosures and tables concerning market risk sensitive instruments, |
25
Throughout MD&A,
26
Another event, which occurred
Overall, the Company emphasized debt reduction in 2004 and, to that end, has reduced its debt to capitalization ratio from .57 at September 30, 2003 to .51 at September 30, 2004.
follows.
20
27
future impairments.*
21
As discussed below, the Company was required to discontinue hedge accounting for a portion of its derivative financial instruments, resulting in a charge to earnings in 2005.
28
Pension and post-retirement benefit costs for the Utility and Pipeline and Storage segments represented 96% and 97%, respectively, of the Company’s total pension and post-retirement benefit costs as determined under SFAS 87 and SFAS 106 for the years ended September 30, 2006 and September 30, 2005.
22
29
• | $68.6 million of impairment charges related to the Exploration and Production segment’s Canadian oil and gas assets under the full cost method of accounting using natural gas pricing at June 30, 2006 and September 30, 2006; | |
• | An $11.2 million benefit to earnings in the Exploration and Production segment related to income tax adjustments recognized during 2006; and | |
• | A $2.6 million benefit to earnings in the Utility segment related to the correction of a regulatory mechanism calculation. |
2005 Events |
• | A $25.8 million gain on the sale of U.E., which was completed in July 2005. This amount is included in earnings from discontinued operations; | |
• | A $2.6 million gain in the Pipeline and Storage segment associated with a FERC approved sale of base gas; | |
• | A $3.9 million gain in the Pipeline and Storage segment associated with insurance proceeds received in prior years for which a contingency was resolved during 2005; | |
• | A $3.3 million loss related to certain derivative financial instruments that no longer qualified as effective hedges; | |
• | A $2.7 million impairment in the value of the Company’s 50% investment in ESNE (recorded in the All Other category), a limited liability company that owns an 80-megawatt, combined cycle, natural gas-fired power plant in the town of North East, Pennsylvania; and | |
• | A $1.8 million impairment of a gas-powered turbine in the All Other category that the Company had planned to use in the development of a co-generation plant. |
• | A $5.2 million reduction to deferred income tax expense | |
• | Settlement of a pension obligation which resulted in the recording of additional expense amounting to $6.4 million, |
30
• | An adjustment to the 2003 sale of the Company’s Southeast Saskatchewan oil and gas properties in the Exploration and Production segment which increased 2004 earnings by $4.6 million; and | |
• | An adjustment to the Company’s 2003 sale of its timber properties in the Timber segment, which reduced 2004 earnings by $0.8 |
For a more complete discussion of the cumulative effect of changes in accounting, refer to Note A — Summary of Significant Accounting Policies in Item 8 of this report.
2003 Compared with 2002
The Company’s earnings were $178.9 million in 2003 compared with earnings of $117.7 million in 2002. The increase in earnings of $61.2 million was primarily the result of higher earnings in the Timber, Utility, and Pipeline and Storage segments partially offset by lower earnings in the Energy Marketing segment and losses in the Exploration and Production and International segments, as shown in the table below. This earnings fluctuation was impacted by the 2003 events listed above. Also, in 2002, earnings included a non-cash impairment of the Company’s investment in the Independence Pipeline project in the Pipeline and Storage segment in the amount of $9.9 million (after tax). Additional discussion of earnings in each of the business segments can be found in the business segment information that follows.
23
Year Ended September 30 | |||||||||||||
2004 | 2003 | 2002 | |||||||||||
(Thousands) | |||||||||||||
Utility | $ | 46,718 | $ | 56,808 | $ | 49,505 | |||||||
Pipeline and Storage | 47,726 | 45,230 | 29,715 | ||||||||||
Exploration and Production | 54,344 | (31,930 | ) | 26,851 | |||||||||
International | 5,982 | (9,623 | ) | (4,443 | ) | ||||||||
Energy Marketing | 5,535 | 5,868 | 8,642 | ||||||||||
Timber | 5,637 | 112,450 | 9,689 | ||||||||||
Total Reportable Segments | 165,942 | 178,803 | 119,959 | ||||||||||
All Other | 1,530 | 193 | (885 | ) | |||||||||
Corporate | (886 | ) | (52 | ) | (1,392 | ) | |||||||
Total Consolidated | $ | 166,586 | $ | 178,944 | $ | 117,682 | |||||||
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(Thousands) | ||||||||||||
Utility | $ | 49,815 | $ | 39,197 | $ | 46,718 | ||||||
Pipeline and Storage | 55,633 | 60,454 | 47,726 | |||||||||
Exploration and Production | 20,971 | 50,659 | 54,344 | |||||||||
Energy Marketing | 5,798 | 5,077 | 5,535 | |||||||||
Timber | 5,704 | 5,032 | 5,637 | |||||||||
Total Reportable Segments | 137,921 | 160,419 | 159,960 | |||||||||
All Other | 359 | (2,616 | ) | 1,530 | ||||||||
Corporate(1) | (189 | ) | (4,288 | ) | (7,225 | ) | ||||||
Total Earnings from Continuing Operations | $ | 138,091 | $ | 153,515 | $ | 154,265 | ||||||
Earnings from Discontinued Operations | — | 35,973 | 12,321 | |||||||||
Total Consolidated | $ | 138,091 | $ | 189,488 | $ | 166,586 | ||||||
(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. |
Year Ended September 30 | |||||||||||||
2004 | 2003 | 2002 | |||||||||||
(Thousands) | |||||||||||||
Retail Revenues: | |||||||||||||
Residential | $ | 808,740 | $ | 801,984 | $ | 538,345 | |||||||
Commercial | 137,092 | 137,905 | 86,963 | ||||||||||
Industrial | 17,454 | 23,263 | 18,332 | ||||||||||
963,286 | 963,152 | 643,640 | |||||||||||
Off-System Sales | 106,841 | 107,220 | 68,606 | ||||||||||
Transportation | 80,563 | 86,374 | 83,267 | ||||||||||
Other | 1,951 | 6,237 | (1,292 | ) | |||||||||
$ | 1,152,641 | $ | 1,162,983 | $ | 794,221 | ||||||||
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(Thousands) | ||||||||||||
Retail Revenues: | ||||||||||||
Residential | $ | 993,928 | $ | 868,292 | $ | 808,740 | ||||||
Commercial | 166,779 | 145,393 | 137,092 | |||||||||
Industrial | 13,484 | 13,998 | 17,454 | |||||||||
1,174,191 | 1,027,683 | 963,286 | ||||||||||
Off-System Sales | — | — | 106,841 | |||||||||
Transportation | 92,569 | 83,669 | 80,563 | |||||||||
Other | 14,003 | 5,715 | 1,951 | |||||||||
$ | 1,280,763 | $ | 1,117,067 | $ | 1,152,641 | |||||||
31
Year Ended September 30 | |||||||||||||
2004 | 2003 | 2002 | |||||||||||
Retail Sales: | |||||||||||||
Residential | 70,109 | 76,449 | 64,639 | ||||||||||
Commercial | 12,752 | 14,177 | 11,549 | ||||||||||
Industrial | 2,261 | 3,537 | 3,715 | ||||||||||
85,122 | 94,163 | 79,903 | |||||||||||
Off-System Sales | 16,839 | 17,999 | 21,541 | ||||||||||
Transportation | 60,565 | 64,232 | 61,909 | ||||||||||
162,526 | 176,394 | 163,353 | |||||||||||
24
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Retail Sales: | ||||||||||||
Residential | 59,443 | 66,903 | 70,109 | |||||||||
Commercial | 10,681 | 11,984 | 12,752 | |||||||||
Industrial | 985 | 1,387 | 2,261 | |||||||||
71,109 | 80,274 | 85,122 | ||||||||||
Off-System Sales | — | — | 16,839 | |||||||||
Transportation | 57,950 | 59,770 | 60,565 | |||||||||
129,059 | 140,044 | 162,526 | ||||||||||
Percent (Warmer) | ||||||||||||||||||||
Colder Than | ||||||||||||||||||||
Year Ended September 30 | Normal | Actual | Normal | Prior Year | ||||||||||||||||
2004: | Buffalo | 6,729 | 6,572 | (2.3 | )% | (7.9 | )% | |||||||||||||
Erie | 6,277 | 6,086 | (3.0 | )% | (10.1 | )% | ||||||||||||||
2003: | Buffalo | 6,815 | 7,137 | 4.7 | % | 22.9 | % | |||||||||||||
Erie | 6,135 | 6,769 | 10.3 | % | 26.9 | % | ||||||||||||||
2002: | Buffalo | 6,847 | 5,808 | (15.2 | )% | (12.6 | )% | |||||||||||||
Erie | 6,146 | 5,334 | (13.2 | )% | (16.0 | )% |
Percent (Warmer) | ||||||||||||||||||||
Colder Than | ||||||||||||||||||||
Year Ended September 30 | Normal | Actual | Normal | Prior Year | ||||||||||||||||
2006: | Buffalo | 6,692 | 5,968 | (10.8 | )% | (9.4 | )% | |||||||||||||
Erie | 6,243 | 5,688 | (8.9 | )% | (8.9 | )% | ||||||||||||||
2005: | Buffalo | 6,692 | 6,587 | (1.6 | )% | 0.2 | % | |||||||||||||
Erie | 6,243 | 6,247 | 0.1 | % | 2.6 | % | ||||||||||||||
2004: | Buffalo | 6,729 | 6,572 | (2.3 | )% | (7.9 | )% | |||||||||||||
Erie | 6,277 | 6,086 | (3.0 | )% | (10.1 | )% |
32
Effective September 22, 2004, Distribution Corporation stopped making off-system sales as a result of the FERC’s Order 2004, “Standards of Conduct for Transmission Providers,”items, as discussed more fully in the Rate Matters section below. As a result of this decision, Distribution Corporation most likely will not have any off-system sales in 2005.* However, due to profit sharing with retail customers, the margins resulting from off-system sales have been minimal and there should be no material impact to margins in 2005.*
2003 Compared with 2002
Operating revenues for the Utility segment increased $368.8 million in 2003 compared with 2002. This resulted from an increase in retail and off-system gas sales revenues of $319.5 million and $38.6 million, respectively. Transportation and other revenues also increased by $3.1 million and $7.5 million, respectively.
25
The increase in retail gas sales revenues for the Utility segment was largely a function of the recovery of higher gas costs, coupled with an increase in retail sales volumes, as shown above. The increase in retail sales volumes was primarily the result of colder weather, as shown in the degree day table above. Off-system sales revenues increased because of higher gas prices, which more than offset lower volumes. However, due to profit sharing with retail customers, the margins resulting from off-system sales were minimal. Colder weather also caused transportation revenues and volumes to increase.
The increase in other operating revenues is largely related to the three-year rate settlement which ended on September 30, 2003, as discussed above. In 2003, Distribution Corporation utilized $7.6 million of the cost mitigation reserve by recording $7.6 million of other operating revenues, compared to $2.2 million in 2002. In both years, the impact of reversing a portion of the cost mitigation reserve was offset by an equal amount of operation and maintenance expense and interest expense (thus there is no earnings impact). The increase in other operating revenues also reflects a $1.3 million decrease in refund provisions. In accordance with the three-year rate settlement discussed above, Distribution Corporation recorded refund provisions related to a 50% sharing with customers of earnings over a predetermined amount. The refund provisions associated with this earnings sharing mechanism were $4.0 million and $5.3 million in 2003 and 2002, respectively.
Earnings
2004 Compared with 2003
The Utility segment’s earnings in 2004 were $46.7 million, a decrease of $10.1 million when compared with earnings of $56.8 million in 2003. The major factors driving this decrease were an increase in pension and other post-retirement expenses of $9.9 million after tax, higher bad debt expenses of $3.8 million after tax, warmer weather in the Pennsylvania jurisdiction ($2.5 million after tax), and lower usage per customer account in the New York jurisdiction ($2.2 million after tax). These negative factors were partially offset by the absence of a refund provision in the New York jurisdiction in 2004 related to an earnings sharing mechanism in the New York jurisdiction ($2.6 million after tax), as discussed above. Other offsetting factors included a base rate increase in the Pennsylvania jurisdiction of $1.5 million after tax and lower interest expense of $4.7 million after tax.
The increase in pension and other post-retirement expenses referred to above can be attributed largely to three factors. First, in accordance with the one-year settlement extension commencing on October 1, 2003 in the New York rate jurisdiction (referred to above), the Company was required to record an additional $8.0 million before tax ($5.2 million after tax) of pension and other post-retirement expense for the year ended September 30, 2004 without a corresponding increase in revenues. Second, the Utility segment recorded $2.2 million of expense after tax associated with the settlement of a pension obligation. Third, pension and other post-retirement expenses in the Pennsylvania rate jurisdiction increased by $2.5 million after tax as the rate settlement in that jurisdiction reflected higher pension funding amounts and the amortization of previous other post-retirement deferrals.
The impact of weather on the Utility segment’s New York rate jurisdiction is tempered by a weather normalization clause (WNC). The WNC, which covers the eight month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segment’s New York customers. In 2004, the WNC preserved $1.0 million of earnings since the weather was warmer than normal in the New York service territory. For 2003, the WNC reduced earnings by approximately $3.8 million because it was colder than normal in the New York service territory.
2003 Compared with 2002
The Utility segment’s earnings in 2003 were $56.8 million, an increase of $7.3 million when compared with earnings of $49.5 million in 2002. The major factor driving this increase was the impact of colder weather in the Utility segment’s Pennsylvania jurisdiction, which contributed approximately $5.6 million to
26
In 2003, the WNC reduced earnings by approximately $3.8 million because it was colder than normal in the New York service territory. For 2002, the WNC preserved earnings of approximately $9.9 million because it was warmer than normal in the New York service territory.
33
34
Year Ended September 30 | ||||||||||||
2004 | 2003 | 2002 | ||||||||||
(Thousands) | ||||||||||||
Firm Transportation | $ | 120,443 | $ | 109,508 | $ | 88,082 | ||||||
Interruptible Transportation | 3,084 | 3,944 | 3,315 | |||||||||
123,527 | 113,452 | 91,397 | ||||||||||
Firm Storage Service | 63,962 | 63,223 | 62,733 | |||||||||
Interruptible Storage Service | 20 | 36 | 7 | |||||||||
63,982 | 63,259 | 62,740 | ||||||||||
Other | 22,198 | 24,709 | 13,247 | |||||||||
$ | 209,707 | $ | 201,420 | $ | 167,384 | |||||||
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(Thousands) | ||||||||||||
Firm Transportation | $ | 118,551 | $ | 117,146 | $ | 120,443 | ||||||
Interruptible Transportation | 4,858 | 4,413 | 3,084 | |||||||||
123,409 | 121,559 | 123,527 | ||||||||||
Firm Storage Service | 66,718 | 65,320 | 63,962 | |||||||||
Interruptible Storage Service | 39 | 267 | 20 | |||||||||
66,757 | 65,587 | 63,982 | ||||||||||
Other | 24,186 | 28,713 | 22,198 | |||||||||
$ | 214,352 | $ | 215,859 | $ | 209,707 | |||||||
Year Ended September 30 | ||||||||||||
2004 | 2003 | 2002 | ||||||||||
Firm Transportation | 338,991 | 340,925 | 290,507 | |||||||||
Interruptible Transportation | 12,692 | 10,004 | 7,315 | |||||||||
351,683 | 350,929 | 297,822 | ||||||||||
27
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Firm Transportation | 363,379 | 357,585 | 338,991 | |||||||||
Interruptible Transportation | 11,609 | 14,794 | 12,692 | |||||||||
374,988 | 372,379 | 351,683 | ||||||||||
The increase in storage revenues reflects the renewal of storage contracts at higher rates.
35
Offsetting the decreases in Supply Corporation’s firm transportation revenues was a $1.0 million increase in Empire’s firm transportation revenues, primarily due to an increase in transportation volumes.
2003 Compared with 2002
The Pipeline and Storage segment’s earnings in 2003 were $45.2 million, an increase of $15.5 million when compared with earnings of $29.7 million in 2002. A major factor in the earnings increase was the fact that 2002 included an after tax impairment charge of $9.9 millionEmpire Connector project ($15.2 million pre tax) related to the Company’s investment in Independence Pipeline Company (a partnership discontinued in 2002 that had proposed to construct and operate a 400-mile pipeline to transport natural gas from Defiance, Ohio to Leidy, Pennsylvania). Higher revenues from unbundled pipeline sales ($4.2 million after tax) were also a contributor to the earnings increase. The Empire acquisition in February 2003 contributed $3.0 million to 2003 earnings.
28
1.8 million) partially offset these increases.
Year Ended September 30 | ||||||||||||
2004 | 2003 | 2002 | ||||||||||
(Thousands) | ||||||||||||
Gas (after Hedging) | $ | 167,127 | $ | 150,982 | $ | 148,467 | ||||||
Oil (after Hedging) | 119,564 | 147,101 | 152,746 | |||||||||
Gas Processing Plant | 28,614 | 28,879 | 16,995 | |||||||||
Other | 1,815 | 1,308 | 6,627 | |||||||||
Intrasegment Elimination(1) | (23,422 | ) | (22,956 | ) | (13,855 | ) | ||||||
$ | 293,698 | $ | 305,314 | $ | 310,980 | |||||||
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(Thousands) | ||||||||||||
Gas (after Hedging) | $ | 184,268 | $ | 181,713 | $ | 167,127 | ||||||
Oil (after Hedging) | 148,293 | 107,801 | 119,564 | |||||||||
Gas Processing Plant | 42,252 | 36,350 | 28,614 | |||||||||
Other | 3,771 | (2,733 | ) | 1,815 | ||||||||
Intrasegment Elimination(1) | (31,704 | ) | (29,706 | ) | (23,422 | ) | ||||||
$ | 346,880 | $ | 293,425 | $ | 293,698 | |||||||
36
(1) | Represents the elimination of certain West Coast gas production revenue included in “Gas (after Hedging)” in the table above that is sold to the gas processing plant shown in the table above. An elimination for the same dollar amount |
Year Ended September 30 | |||||||||||||
2004 | 2003 | 2002 | |||||||||||
Gas Production(MMcf) | |||||||||||||
Gulf Coast | 17,596 | 18,441 | 25,776 | ||||||||||
West Coast | 4,057 | 4,467 | 4,889 | ||||||||||
Appalachia | 5,132 | 5,123 | 4,402 | ||||||||||
Canada | 6,228 | 5,774 | 6,387 | ||||||||||
�� | |||||||||||||
33,013 | 33,805 | 41,454 | |||||||||||
Oil Production(Mbbl) | |||||||||||||
Gulf Coast | 1,534 | 1,473 | 1,815 | ||||||||||
West Coast | 2,650 | 2,872 | 3,004 | ||||||||||
Appalachia | 20 | 10 | 9 | ||||||||||
Canada | 324 | 2,382 | 2,834 | ||||||||||
4,528 | 6,737 | 7,662 | |||||||||||
29
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Gas Production(MMcf) | ||||||||||||
Gulf Coast | 9,110 | 12,468 | 17,596 | |||||||||
West Coast | 3,880 | 4,052 | 4,057 | |||||||||
Appalachia | 5,108 | 4,650 | 5,132 | |||||||||
Canada | 7,673 | 8,009 | 6,228 | |||||||||
25,771 | 29,179 | 33,013 | ||||||||||
Oil Production(Mbbl) | ||||||||||||
Gulf Coast | 685 | 989 | 1,534 | |||||||||
West Coast | 2,582 | 2,544 | 2,650 | |||||||||
Appalachia | 69 | 36 | 20 | |||||||||
Canada | 272 | 300 | 324 | |||||||||
3,608 | 3,869 | 4,528 | ||||||||||
Year Ended September 30 | |||||||||||||
2004 | 2003 | 2002 | |||||||||||
Average Gas Price/ Mcf | |||||||||||||
Gulf Coast | $ | 5.61 | $ | 5.41 | $ | 2.89 | |||||||
West Coast | $ | 5.54 | $ | 5.01 | $ | 2.86 | |||||||
Appalachia | $ | 5.91 | $ | 5.07 | $ | 3.74 | |||||||
Canada | $ | 4.87 | $ | 4.67 | $ | 2.29 | |||||||
Weighted Average | $ | 5.51 | $ | 5.18 | $ | 2.88 | |||||||
Weighted Average After Hedging(1) | $ | 5.06 | $ | 4.47 | $ | 3.58 | |||||||
Average Oil Price/ Barrel (bbl) | |||||||||||||
Gulf Coast | $ | 35.31 | $ | 29.17 | $ | 22.83 | |||||||
West Coast(2) | $ | 31.89 | $ | 26.12 | $ | 19.94 | |||||||
Appalachia | $ | 31.30 | $ | 28.77 | $ | 23.76 | |||||||
Canada | $ | 30.94 | $ | 26.41 | $ | 19.94 | |||||||
Weighted Average | $ | 32.98 | $ | 26.90 | $ | 20.63 | |||||||
Weighted Average After Hedging(1) | $ | 26.40 | $ | 21.84 | $ | 19.94 |
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Average Gas Price/Mcf | ||||||||||||
Gulf Coast | $ | 8.01 | $ | 7.05 | $ | 5.61 | ||||||
West Coast | $ | 7.93 | $ | 6.85 | $ | 5.54 | ||||||
Appalachia | $ | 9.53 | $ | 7.60 | $ | 5.91 | ||||||
Canada | $ | 7.14 | $ | 6.15 | $ | 4.87 | ||||||
Weighted Average | $ | 8.04 | $ | 6.86 | $ | 5.51 | ||||||
Weighted Average After Hedging(1) | $ | 7.15 | $ | 6.23 | $ | 5.06 | ||||||
Average Oil Price/Barrel (bbl) | ||||||||||||
Gulf Coast | $ | 64.10 | $ | 49.78 | $ | 35.31 | ||||||
West Coast(2) | $ | 56.80 | $ | 42.91 | $ | 31.89 | ||||||
Appalachia | $ | 65.28 | $ | 48.28 | $ | 31.30 | ||||||
Canada | $ | 51.40 | $ | 42.97 | $ | 30.94 | ||||||
Weighted Average | $ | 57.94 | $ | 44.72 | $ | 32.98 | ||||||
Weighted Average After Hedging(1) | $ | 41.10 | $ | 27.86 | $ | 26.40 |
(1) | Refer to further discussion of hedging activities below under “Market Risk Sensitive Instruments” and in Note | |
(2) | Includes low gravity oil which generally sells for a lower price. |
37
volumes caused by Hurricane Rita.
30
38
2003 Compared with 2002
The Exploration and Production segment experienced a loss of $31.9 million in 2003, a decrease of $58.8 million when compared with earnings of $26.9 million in 2002. The main reason for this decrease was the loss of $39.6 million recorded upon the sale of the Company’s Southeast Saskatchewan oil and gas properties. During 2003, the Company reviewed the economics of its non-regulated business including certain oil and gas properties. The Southeast Saskatchewan properties were identified as a candidate for sale given their overall marginal contribution to earnings. Impairment charges of $28.9 million after tax recorded in 2003 related to the Company’s Canadian oil and gas assets also contributed to the decrease. Lower oil and gas revenues, as discussed above, decreased earnings by approximately $2.0 million. As an offset, the Exploration and Production segment experienced lower depletion expense of $2.9 million after tax (attributablehas been operating solely within its own cash flow from operations. Short-term borrowings have been eliminated and excess cash has been invested, resulting in higher interest income. This excess cash will be used to the production decline)fund operations and lowerfuture capital expenditures.* Lower general and administrative expenses, of $2.1 million after tax (attributablelargely due to cost-cutting efforts in Canada). Another offsetting factor was a lower effective income tax rate, which benefittedlegal costs, also increased 2005 earnings by approximately $3.4 million.
31
INTERNATIONAL
Revenues
International Operating Revenues
Year Ended September 30 | ||||||||||||
2004 | 2003 | 2002 | ||||||||||
(Thousands) | ||||||||||||
Heating | $ | 88,395 | $ | 80,752 | $ | 65,386 | ||||||
Electricity | 30,949 | 29,386 | 26,960 | |||||||||
Other | 4,081 | 3,932 | 2,969 | |||||||||
$ | 123,425 | $ | 114,070 | $ | 95,315 | |||||||
International Heating and Electric Volumes
Year Ended September 30 | ||||||||||||
2004 | 2003 | 2002 | ||||||||||
Heating Sales (Gigajoules)(1) | 8,538,554 | 8,766,567 | 8,689,887 | |||||||||
Electricity Sales (megawatt hours) | 936,877 | 973,968 | 972,832 |
2004 Compared with 2003
Operating revenues for the International segment increased $9.4 million in 2004 as compared with 2003. Substantially all of this increase can be attributed to an increase in the value of the Czech koruna compared to the U.S. dollar.
2003 Compared with 2002
Operating revenues for the International segment increased $18.8 million in 2003 as compared with 2002. Substantially all of this increase can be attributed to an increase in the value of the Czech koruna compared to the U.S. dollar.
Earnings
2004 Compared with 2003
The International segment’s earnings in 2004 were $6.0 million, an increase of $15.6 million when compared with a loss of $9.6 million in 2003. Earnings were impacted by two events. During 2004, the government in the Czech Republic enacted legislation that gradually reduces the corporate statutory income tax rate from 31% to 24% over a three-year period commencing January 1, 2004. In accordance with accounting principles generally accepted in the United States of America (GAAP), the Company recorded the full benefit resulting from the change in the income tax rate ($5.2 million) as a reduction to deferred income tax expense during 2004. During 2003, the Company recorded a $8.3 million impairment charge resulting from the Company’s change in accounting for goodwill, as discussed below. These two events account for $13.5 million of the earnings increase in the International segment. An increase in the value of the Czech koruna compared to the U.S. dollar improved earnings by approximately $1.1 million.
2003 Compared with 2002
The International segment experienced a loss of $9.6 million in 2003 compared with a loss of $4.4 million in 2002. This decrease can be attributed primarily to an $8.3 million impairment charge, resulting from the Company’s change in accounting for goodwill. The Company’s goodwill balance as of October 1, 2002 totaled $8.3 million and was related to the Company’s investments in the Czech Republic,
32
Year Ended September 30 | ||||||||||||
2004 | 2003 | 2002 | ||||||||||
(Thousands) | ||||||||||||
Natural Gas (after Hedging) | $ | 283,747 | $ | 304,390 | $ | 151,219 | ||||||
Other | 602 | 270 | 38 | |||||||||
$ | 284,349 | $ | 304,660 | $ | 151,257 | |||||||
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(Thousands) | ||||||||||||
Natural Gas (after Hedging) | $ | 496,769 | $ | 329,560 | $ | 283,747 | ||||||
Other | 300 | 154 | 602 | |||||||||
$ | 497,069 | $ | 329,714 | $ | 284,349 | |||||||
Year Ended September 30 | ||||||||||||
2004 | 2003 | 2002 | ||||||||||
Natural Gas — (MMcf) | 41,651 | 45,135 | 33,042 |
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Natural Gas — (MMcf) | 45,270 | 40,683 | 41,651 |
Operating revenues for the Energy Marketing segment decreased $20.3 million in 2004 as compared with 2003. This decrease primarily reflects lower gas sales revenue due to lower throughput, which was the result of warmer weather and the loss of several large volume but low margin customers to other marketers.
2003 Compared with 2002
39
prior year due to the loss of certain lower margin wholesale customers.
2003 Compared with 2002
2004. The Energy Marketing segment earnings in 2003 were $5.9 million, a decrease of $2.7 million when compared with earnings of $8.6 million in 2002. This decrease primarily reflects lower margins oncaused by a reduction in the benefit of storage gas sales,
33
Year Ended September 30 | ||||||||||||
2004 | 2003 | 2002 | ||||||||||
(Thousands) | ||||||||||||
Log Sales | $ | 21,790 | $ | 27,341 | $ | 21,528 | ||||||
Green Lumber Sales | 5,923 | 6,200 | 6,567 | |||||||||
Kiln Dry Lumber Sales | 27,416 | 21,814 | 15,976 | |||||||||
Other | 841 | 871 | 3,336 | |||||||||
$ | 55,970 | $ | 56,226 | $ | 47,407 | |||||||
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(Thousands) | ||||||||||||
Log Sales | $ | 23,077 | $ | 22,478 | $ | 21,790 | ||||||
Green Lumber Sales | 7,123 | 7,296 | 5,923 | |||||||||
Kiln Dry Lumber Sales | 32,809 | 29,651 | 27,416 | |||||||||
Other | 2,020 | 1,861 | 841 | |||||||||
$ | 65,029 | $ | 61,286 | $ | 55,970 | |||||||
Year Ended September 30 | ||||||||||||
2004 | 2003 | 2002 | ||||||||||
(Thousands) | ||||||||||||
Log Sales | 6,848 | 8,764 | 8,174 | |||||||||
Green Lumber Sales | 9,552 | 11,913 | 12,878 | |||||||||
Kiln Dry Lumber Sales | 15,020 | 13,300 | 10,794 | |||||||||
31,420 | 33,977 | 31,846 | ||||||||||
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(Thousands) | ||||||||||||
Log Sales | 9,527 | 7,601 | 6,848 | |||||||||
Green Lumber Sales | 10,454 | 10,489 | 9,552 | |||||||||
Kiln Dry Lumber Sales | 16,862 | 15,491 | 15,020 | |||||||||
36,843 | 33,581 | 31,420 | ||||||||||
Operating revenues for the Timber segment did not change significantly in 2004 as compared with 2003. The decrease in log sales of $5.6 million was principally due to the Company’s August 2003 sale of approximately 70,000 acres of timber properties discussed below. However, kiln dry lumber sales increased $5.6 million due to an increase in activity at the Company’s mill operations. As a result of the sale of the timber properties, a larger percentage of timber processed in the Company’s mills is now purchased from third parties.
2003 Compared with 2002
40
favorable weather conditions that allowed for an increase in harvesting.
34
2003 Compared with 2002
The Timber segment earnings in 2003 were $112.5 million, an increase of $102.8 million when compared with earnings of $9.7 million in 2002. The increase wasactivity from the Czech Republic operations, and corporate operations. Horizon LFG owns and operates short-distance landfill gas pipeline companies. Horizon Power’s activity primarily due to the sale of approximately 70,000 acres of timber properties on August 1, 2003 for approximately $186.0 million. As a result of the sale, the Company recorded a gain of approximately $102.2 million after tax. After the August sale, the Company had approximately 87,000 acres of timber property remaining.
OPERATIONS OF UNCONSOLIDATED SUBSIDIARIES
The Company’s unconsolidated subsidiaries consistconsists of equity method investments in Seneca Energy, II, LLC (Seneca Energy), Model City Energy, LLC (Model City) and Energy Systems North East, LLC (ESNE). The CompanyESNE. Horizon Power has a 50% ownership interest in each of these entities. The income from these equity method investments is reported as Operations of Unconsolidated Subsidiaries on the Consolidated Statement of Income. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties. ESNE generates electricity from an 80-megawatt, combined-cycle,combined cycle, natural gas-fired power plant in North East, Pennsylvania. Horizon Power also owns a gas-powered turbine and other assets which it had planned to use in the development of a co-generation plant. The Company is in the process of selling these
41
42
outstanding.
35
outstanding during 2006.
Year Ended September 30 | ||||||||||||
2004 | 2003 | 2002 | ||||||||||
(Millions) | ||||||||||||
Provided by Operating Activities | $ | 444.3 | $ | 326.8 | $ | 345.6 | ||||||
Capital Expenditures | (172.3 | ) | (152.2 | ) | (232.4 | ) | ||||||
Investment in Subsidiaries, Net of Cash Acquired | — | (228.8 | ) | — | ||||||||
Investment in Partnerships | — | (0.4 | ) | (0.5 | ) | |||||||
Net Proceeds from Sale of Timber Properties | — | 186.0 | — | |||||||||
Net Proceeds from Sale of Oil and Gas Producing Properties | 7.1 | 78.5 | 22.1 | |||||||||
Other Investing Activities | 2.0 | 12.1 | 5.0 | |||||||||
Short-Term Debt, Net Change | 38.6 | (147.6 | ) | (224.8 | ) | |||||||
Long-Term Debt, Net Change | (243.1 | ) | 20.7 | 139.6 | ||||||||
Issuance of Common Stock | 23.8 | 17.0 | 10.9 | |||||||||
Dividends Paid on Common Stock | (89.1 | ) | (84.5 | ) | (81.0 | ) | ||||||
Effect of Exchange Rates on Cash | 3.4 | 1.6 | 1.5 | |||||||||
Net Increase (Decrease) in Cash and Temporary Cash Investments | $ | 14.7 | $ | 29.2 | $ | (14.0 | ) | |||||
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(Millions) | ||||||||||||
Provided by Operating Activities | $ | 471.4 | $ | 317.3 | $ | 437.1 | ||||||
Capital Expenditures | (294.2 | ) | (219.5 | ) | (172.3 | ) | ||||||
Net Proceeds from Sale of Foreign Subsidiary | — | 111.6 | — | |||||||||
Net Proceeds from Sale of Oil and Gas Producing Properties | — | 1.4 | 7.1 | |||||||||
Other Investing Activities | (3.2 | ) | 3.2 | 2.0 | ||||||||
Change in Short-Term Debt | — | (115.4 | ) | 38.6 | ||||||||
Reduction of Long-Term Debt | (9.8 | ) | (13.3 | ) | (243.1 | ) | ||||||
Issuance of Common Stock | 23.3 | 20.3 | 23.8 | |||||||||
Dividends Paid on Common Stock | (98.2 | ) | (94.1 | ) | (89.1 | ) | ||||||
Dividends Paid to Minority Interest | — | (12.7 | ) | — | ||||||||
Excess Tax Benefits Associated with Stock- Based Compensation Awards | 6.5 | — | — | |||||||||
Shares Repurchased under Repurchase Plan | (85.2 | ) | — | — | ||||||||
Effect of Exchange Rates on Cash | 1.4 | 1.3 | 3.5 | |||||||||
Net Increase in Cash and Temporary Cash Investments | $ | 12.0 | $ | 0.1 | $ | 7.6 | ||||||
discontinued operations.
43
36
prices and a smaller number of derivative financial instruments outstanding at September 30, 2006 verses September 30, 2005. 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.
Expenditures for long-lived assets include additions to property, plant and equipment (capital expenditures) and investments in corporations (stock acquisitions) or partnerships, net of any cash acquired.
Year Ended | ||||
September 30, 2004 | ||||
Total Expenditures | ||||
For Long-Lived | ||||
Assets | ||||
(Millions) | ||||
Utility | $ | 55.4 | ||
Pipeline and Storage | 23.2 | |||
Exploration and Production | 77.7 | |||
International | 7.5 | |||
Timber | 2.8 | |||
All Other and Corporate | 5.7 | |||
$ | 172.3 | |||
Year Ended | ||||
September 30, | ||||
2006 | ||||
Total Expenditures | ||||
For Long-Lived | ||||
Assets | ||||
(Millions) | ||||
Utility | $ | 54.4 | ||
Pipeline and Storage | 26.0 | |||
Exploration and Production | 208.3 | |||
Timber | 2.3 | |||
All Other and Corporate | 3.2 | |||
$ | 294.2 | |||
44
International
The majority of the International segment’s capital expenditures were concentrated in improvements and replacements within the district heating and power generation plants in the Czech Republic.
All Other and Corporate
The majority of the All Other and Corporate capital expenditures were for capital improvements to the Company’s new corporate headquarters.
37
Year Ended September 30, | ||||||||||||
2005 | 2006 | 2007 | ||||||||||
(Millions) | ||||||||||||
Utility | $ | 54.0 | $ | 52.0 | $ | 51.0 | ||||||
Pipeline and Storage | 22.0 | 22.0 | 22.0 | |||||||||
Exploration and Production(1) | 93.0 | 91.0 | 89.0 | |||||||||
International | 15.0 | 26.0 | 29.0 | |||||||||
Timber | 2.0 | 1.0 | 1.0 | |||||||||
All Other and Corporate | 5.0 | — | — | |||||||||
$ | 191.0 | $ | 192.0 | $ | 192.0 | |||||||
Year Ended September 30 2007 2008 2009 (Millions) Utility $ 56.0 $ 56.0 $ 57.0 Pipeline and Storage 62.0 110.0 84.0 Exploration and Production(1) 212.0 207.0 243.0 Timber 4.0 1.0 1.0 $ 334.0 $ 374.0 $ 385.0
(1) | Includes estimated expenditures for the years ended September 30, |
Empire Connector project as discussed below.
45
Of this amount, $2.0 million, $3.4 million and $0.6 million were incurred during the years ended September 30, 2006, 2005 and 2004, respectively.
The estimated
38
Estimated capital expenditures2007 in the Timber segment will be concentrated on the construction or purchase of new facilitiesequipment and equipmentimprovements to facilities for this segment’s lumber yard, sawmill and kiln operations.*
Estimated capital expenditures in the All Other and Corporate category will be concentrated on the purchase of equipment for a 55-megawatt electric generation facility in Buffalo, New York combined with capital improvements to the Company’s corporate headquarters.
In February 2004 and August 2004, the Company repaid $125.0 million of maturing 7.75% debentures at par and $100.0 million of maturing 6.82% medium-term notes at par, respectively.
Consolidated short-term debt increased $38.6 million during 2004. Although a certain amount of short-term borrowings were initially used to repaybanks or commercial paper at September 30, 2006. However, the maturing debt discussed above, the Company was able to use cash flow from operations to repay most of this additional short-term debt. The Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures and investments in corporationsand/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. At September 30, 2004, the Company had outstanding short-term notes payable to banks and commercial paper of $26.5 million and $130.3 million, respectively. The Company has SEC authorization under the Holding Company Act to borrow and have outstanding as much as $750.0 million of short-term debt at any time through December 31, 2005. 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 theseThese credit lines, which aggregate
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2010.
39
The Company also has authorization from the SEC, in an order under the Holding Company Act, to issue long-term debt securities and equity securities in an aggregate amount of up to $1.5 billion during the order’s authorization period, which commenced in November 2002 and extends to December 31, 2005.
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40
Payments by Expected Maturity Dates | |||||||||||||||||||||||||||||
2005 | 2006 | 2007 | 2008 | 2009 | Thereafter | Total | |||||||||||||||||||||||
(Millions) | |||||||||||||||||||||||||||||
Long-Term Debt | $ | 14.3 | $ | 14.3 | $ | 9.3 | $ | 209.3 | $ | 104.1 | $ | 796.3 | $ | 1,147.6 | |||||||||||||||
Short-Term Bank Notes | $ | 26.5 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 26.5 | |||||||||||||||
Commercial Paper | $ | 130.3 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 130.3 | |||||||||||||||
Operating Lease Obligations | $ | 8.7 | $ | 7.1 | $ | 6.1 | $ | 5.2 | $ | 4.8 | $ | 2.4 | $ | 34.3 | |||||||||||||||
Capital Lease Obligations | $ | 0.8 | $ | 1.1 | $ | 0.9 | $ | 0.8 | $ | 0.4 | $ | 1.0 | $ | 5.0 | |||||||||||||||
Purchase Obligations: | |||||||||||||||||||||||||||||
Gas Purchase Contracts(1) | $ | 589.5 | $ | 87.0 | $ | 11.1 | $ | 5.8 | $ | 5.7 | $ | 68.4 | $ | 767.5 | |||||||||||||||
Transportation and Storage Contracts | $ | 134.4 | $ | 135.4 | $ | 133.0 | $ | 125.9 | $ | 69.5 | $ | 12.4 | $ | 610.6 | |||||||||||||||
Other | $ | 2.4 | $ | 0.8 | $ | 0.4 | $ | 0.4 | $ | 0.4 | $ | — | $ | 4.4 |
Payments by Expected Maturity Dates | ||||||||||||||||||||||||||||
2007 | 2008 | 2009 | 2010 | 2011 | Thereafter | Total | ||||||||||||||||||||||
(Millions) | ||||||||||||||||||||||||||||
Long-Term Debt, including interest expense(1) | $ | 93.7 | $ | 266.0 | $ | 154.7 | $ | 51.8 | $ | 238.9 | $ | 776.7 | $ | 1,581.8 | ||||||||||||||
Operating Lease Obligations | $ | 8.1 | $ | 7.2 | $ | 6.0 | $ | 4.3 | $ | 2.7 | $ | 15.7 | $ | 44.0 | ||||||||||||||
Capital Lease Obligations | $ | 1.1 | $ | 0.9 | $ | 0.5 | $ | 0.4 | $ | 0.4 | $ | 0.2 | $ | 3.5 | ||||||||||||||
Purchase Obligations: | ||||||||||||||||||||||||||||
Gas Purchase Contracts(2) | $ | 742.8 | $ | 149.4 | $ | 17.7 | $ | 6.9 | $ | 6.5 | $ | 64.7 | $ | 988.0 | ||||||||||||||
Transportation and Storage Contracts | $ | 50.7 | $ | 45.8 | $ | 31.2 | $ | 10.7 | $ | 3.4 | $ | 4.1 | $ | 145.9 | ||||||||||||||
Other | $ | 25.0 | $ | 2.9 | $ | 2.0 | $ | 2.0 | $ | 1.8 | $ | 4.6 | $ | 38.3 |
(1) | Refer to Note E — Capitalization and Short-Term Borrowings, as well as the table under Interest Rate Risk in the Market Risk Sensitive Instruments section below, for the amounts excluding interest expense. | |
(2) | Gas prices are variable based on the NYMEX prices adjusted for basis. |
The
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Expected Maturity Dates | ||||||||||||||||||||||||
2005 | 2006 | 2007 | 2008 | 2009 | Total | |||||||||||||||||||
Notional Quantities (Equivalent Bcf) | 11.3 | 8.4 | 1.8 | 1.2 | 0.3 | 23.0 | ||||||||||||||||||
Weighted Average Fixed Rate (per Mcf) | $ | 5.47 | $ | 5.68 | $ | 5.02 | $ | 4.80 | $ | 4.81 | $ | 5.47 | ||||||||||||
Weighted Average Variable Rate (per Mcf) | $ | 7.12 | $ | 6.74 | $ | 6.13 | $ | 5.58 | $ | 5.50 | $ | 6.81 |
Expected Maturity Dates | ||||||||||||||||
2005 | 2006 | 2007 | Total | |||||||||||||
Notional Quantities (Equivalent bbls) | 2,743,000 | 1,755,000 | 540,000 | 5,038,000 | ||||||||||||
Weighted Average Fixed Rate (per bbl) | $30.51 | $33.27 | $35.55 | $32.01 | ||||||||||||
Weighted Average Variable Rate (per bbl) | $46.74 | $41.31 | $38.41 | $43.95 |
Expected Maturity Dates 2007 2008 2009 Total Notional Quantities (Equivalent Bcf) 3.9 2.8 0.7 7.4 Weighted Average Fixed Rate (per Mcf) $ 6.95 $ 7.26 $ 8.63 $ 7.24 Weighted Average Variable Rate (per Mcf) $ 7.29 $ 8.37 $ 8.84 $ 7.85
Expected Maturity Dates | ||||||||||||
2007 | 2008 | Total | ||||||||||
Notional Quantities (Equivalent bbls) | 855,000 | 45,000 | 900,000 | |||||||||
Weighted Average Fixed Rate (per bbl) | $ | 37.03 | $ | 39.00 | $ | 37.13 | ||||||
Weighted Average Variable Rate (per bbl) | $ | 65.47 | $ | 68.90 | $ | 65.64 |
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2006.
basis differential.
No Cost Collars |
Expected Maturity Dates | |||||||||||||
2005 | 2006 | Total | |||||||||||
Natural Gas | |||||||||||||
Notional Quantities (Equivalent Bcf) | 5.1 | 0.4 | 5.5 | ||||||||||
Weighted Average Ceiling Price (per Mcf) | $8.31 | $ | 7.88 | $8.28 | |||||||||
Weighted Average Floor Price (per Mcf) | $4.94 | $ | 4.77 | $4.93 | |||||||||
Crude Oil | |||||||||||||
Notional Quantities (Equivalent bbls) | 105,000 | — | 105,000 | ||||||||||
Weighted Average Ceiling Price (per bbl) | $28.56 | — | $28.56 | ||||||||||
Weighted Average Floor Price (per bbl) | $25.00 | — | $25.00 |
Expected Maturity Dates | ||||||||||||
2007 | 2008 | Total | ||||||||||
Natural Gas | ||||||||||||
Notional Quantities (Equivalent Bcf) | 5.7 | 1.4 | 7.1 | |||||||||
Weighted Average Ceiling Price (per Mcf) | $ | 17.45 | $ | 16.45 | $ | 17.25 | ||||||
Weighted Average Floor Price (per Mcf) | $ | 8.12 | $ | 8.83 | $ | 8.26 |
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2007 | ||||
Crude Oil | ||||
Notional Quantities (Equivalent bbls) | 180,000 | |||
Weighted Average Ceiling Price (per bbl) | $ | 77.00 | ||
Weighted Average Floor Price (per bbl) | $ | 70.00 |
September 30, 2006.
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The following table discloses the notional quantities and weighted average strike prices by expected maturity dates for options used by the Exploration and Production segment to manage natural gas price risk. The put options provide for the Company to receive monthly payments from other parties when a variable price falls below an established floor or “strike” price. The call options provide for the Company to pay monthly payments to other parties when a variable price rises above an established ceiling or “strike” price. At September 30, 2004, the Company held no options with maturity dates extending beyond 2006.
Expected Maturity Dates | |||||||||||||
2005 | 2006 | Total | |||||||||||
Natural Gas Put Options Purchased | |||||||||||||
Notional Quantities (Equivalent Bcf) | 0.8 | 0.3 | 1.1 | ||||||||||
Weighted Average Strike Price (per Mcf) | $ | 6.05 | $ | 5.83 | $ | 5.99 | |||||||
Natural Gas Call Options Sold | |||||||||||||
Notional Quantities (Equivalent Bcf) | 0.8 | 0.3 | 1.1 | ||||||||||
Weighted Average Strike Price (per Mcf) | $ | 7.84 | $ | 8.69 | $ | 8.06 |
At September 30, 2004, the Company would have received from the respective counterparties an aggregate of approximately $0.2 million to terminate the put options outstanding at that date. The Company would have had to pay an aggregate of approximately $1.0 million to terminate the call options outstanding at that date. The Company did not have any options outstanding crude oil no cost collars at September 30, 2003.
2005. The decrease in natural gas collars from September 2005 to September 2006 is due to management’s decision to curtail hedging activity in the fourth quarter of 2006 due to the forecast of a more active hurricane season in 2006. In 2005, the Company recognized a $5.1 millionmark-to-market adjustment related to derivative financial instruments that no longer qualified as effective hedges due to production delays caused by Hurricane Rita, and management wanted to prevent this from recurring in 2006. When the hurricane season did not turn out to be as active as everyone had forecasted, the pricing strip at that time was so low that management elected to hold off on some of the hedging. Management is reviewing that policy and is in the process of looking at layering in more hedges in the future.*
Futures Contracts |
Expected Maturity Dates | ||||||||||||||||
2005 | 2006 | 2007 | Total | |||||||||||||
Net Contract Volumes Purchased (Sold) (Equivalent Bcf) | (3.5 | ) | (0.4 | ) | 0.1 | (3.8 | ) | |||||||||
Weighted Average Contract Price (per Mcf) | $ | 6.16 | $ | 6.29 | $ | 5.88 | $ | 6.17 | ||||||||
Weighted Average Settlement Price (per Mcf) | $ | 7.74 | $ | 6.96 | $ | 6.33 | $ | 7.69 |
Expected Maturity Dates | ||||||||||||||||||||||||||||
2007 | 2008 | 2009 | 2010 | 2011 | 2012 | Total | ||||||||||||||||||||||
Net Contract Volumes Purchased (Sold) | ||||||||||||||||||||||||||||
(Equivalent Bcf) | 7.2 | (0.1 | ) | (0.1 | ) | — | — | (1) | — | (1) | 7.0 | |||||||||||||||||
Weighted Average Contract Price (per Mcf) | $ | 9.63 | $ | 9.85 | $ | 9.57 | NA | $ | 6.99 | $ | 8.68 | $ | 9.67 | |||||||||||||||
Weighted Average Settlement Price (per Mcf) | $ | 10.02 | $ | 9.58 | $ | 9.14 | NA | $ | 6.91 | $ | 9.29 | $ | 9.89 |
(1) | The Energy Marketing segment has purchased 4 and 6 futures contracts (1 contract = 2,500 Dth) for 2011 and 2012, respectively. |
futures market.
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All of the counterparties (or the parent of the counterparty) were rated as investment grade entities at September 30, 2006.
The International segment’s investment in the Czech Republic is valued in Czech korunas, and, as such, this investment is subject to currency exchange risk when the Czech korunas are translated into U.S. dollars.
The following table presents the principal cash repayments and related weighted average interest rates by expected maturity date for the Company’s long-term fixed rate debt as well as the other long-term debt of certain of the Company’s subsidiaries. The interest rates for the variable rate debt are based on those in effect at September 30, 2004:
Principal Amounts by Expected Maturity Dates | ||||||||||||||||||||||||||||
2005 | 2006 | 2007 | 2008 | 2009 | Thereafter | Total | ||||||||||||||||||||||
(Dollars in Millions) | ||||||||||||||||||||||||||||
National Fuel Gas Company | ||||||||||||||||||||||||||||
Long-Term Fixed Rate Debt | $ | — | $ | — | $ | — | $ | 200 | $ | 100 | $ | 796.3 | $ | 1,096.3 | ||||||||||||||
Weighted Average Interest Rate Paid | 0 | % | 0 | % | 0 | % | 6.3 | % | 6.0 | % | 6.5 | % | 6.4 | % | ||||||||||||||
Fair Value = $1,147.9 million | ||||||||||||||||||||||||||||
Other Notes | ||||||||||||||||||||||||||||
Long-Term Debt(1) | $ | 14.3 | $ | 14.3 | $ | 9.3 | $ | 9.3 | $ | 4.1 | $ | — | $ | 51.3 | ||||||||||||||
Weighted Average Interest Rate Paid(2) | 4.1 | % | 4.1 | % | 2.8 | % | 2.8 | % | 2.8 | % | — | 3.5 | % | |||||||||||||||
Fair Value = $51.3 million |
The Company uses an interest rate collar to limit interest rate fluctuations on $41.4$22.8 million of variable rate debt included in Other Notes in the table above.below. To mitigate this risk, the Company uses an interest rate collar to limit interest rate fluctuations. Under the interest rate collar the Company makes quarterly payments to (or receives payments from) another party when a variable rate falls below an established floor rate (the Company pays the counterparty) or exceeds an established ceiling rate (the Company receives payment from the counterparty). Under the terms of the collar, which extends until 2009, the variable rate is based on London InterBank Offered Rate.LIBOR. The floor rate of the collar is 5.15% and the ceiling rate is 9.375%. The Company would have had to pay $2.2$0.1 million to terminate the interest rate collar at September 30, 2004.2006.
Principal Amounts by Expected Maturity Dates | ||||||||||||||||||||||||||||
2007 | 2008 | 2009 | 2010 | 2011 | Thereafter | Total | ||||||||||||||||||||||
(Dollars in millions) | ||||||||||||||||||||||||||||
National Fuel Gas Company | ||||||||||||||||||||||||||||
Long-Term Fixed Rate Debt | $ | — | $ | 200.0 | $ | 100.0 | $ | — | $ | 200.0 | $ | 595.7 | $ | 1,095.7 | ||||||||||||||
Weighted Average Interest Rate Paid | — | 6.3 | % | 6.0 | % | — | 7.5 | % | 6.2 | % | 6.4 | % | ||||||||||||||||
Fair Value = $1,125.2 | ||||||||||||||||||||||||||||
Other Notes | ||||||||||||||||||||||||||||
Long-Term Debt(1) | $ | 22.9 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 22.9 | ||||||||||||||
Weighted Average Interest Rate Paid(2) | 6.5 | % | — | — | — | — | — | 6.5 | % | |||||||||||||||||||
Fair Value = $22.9 |
(1) | $22.8 million is variable rate debt. It is the Company’s intention to pay off these notes within one year. As such, the notes have been classified as current. | |
(2) | Weighted average interest rate excludes the impact of an interest rate collar on $22.8 million of variable rate debt. |
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issued on April 24, 2006. On June 15, 2006, pursuant to the FERC’s regulations, the Company filed a “notification of holding company status” with the FERC. Also on that date, the Company filed an “exemption request” with the FERC, requesting exemption of the Company and its subsidiaries from the FERC’s regulations under PUHCA 2005. The exemption request has been granted by operation of law pursuant to the FERC’s regulations. 11.5%. 1, 2007.RATE MATTERS667-A, On October 11, 2000, the NYPSC approved a settlement agreement (Agreement) between Distribution Corporation, Staff of the Department of Public Service, the New York State Consumer Protection Board and Multiple Intervenors (an advocate for large commercial and industrial customers) (collectively, “Parties”) that established rates for the three-year period ending September 30, 2003. On July 25, 2003, the Parties and other interests executed a settlement agreement (Settlement) to extend the terms of the Agreement and Distribution Corporation’s restructuring plan one year commencing October 1, 2003. The Settlement was approved by the NYPSC in an order issued on September 18, 2003. As approved, the Settlement continued existing base rates, but reduced the level above which earnings are shared 50/50 with customers from the previous 11.5% return on equity to 11.0%. In addition, the Settlement increased the combined pension and other post-retirement benefit expense by $8.0 million, without a corresponding increase in revenues. Most other features of Distribution Corporation’s service remained largely unchanged. In April 2004, Distribution Corporation commenced confidential settlement negotiations with the NYPSC and other parties concerning, among other things, its revenue requirement for the year ending September 30, 2005. Those settlement discussions failed to produce an agreement prior to the expiration of the Settlement. filedcommenced a rate case by filing proposed tariff amendments and supporting testimony designedrequesting approval to increase its annual revenues by $41.3 million beginning October 1, 2004. The rate request was filed to address throughput reductionsVarious parties opposed the filing. On April 15, 2005, Distribution Corporation, the parties and increased operating costs such as uncollectibles and personnel expenses.others executed an agreement settling all outstanding issues. In accordance with standard rate case procedure,an order issued July 22, 2005, the NYPSC suspended Distribution Corporation’s filingapproved the April 15, 2005 settlement agreement, substantially as provided by law in order to allow timefiled, for an investigation and hearings. Following hearings and further proceedings, the Commission will issue an order approving, rejecting or modifying Distribution Corporation’s rate request for an anticipated effective date of late July,August 1, 2005. Distribution Corporation is unable to ascertain the outcomeThe settlement agreement provides for a rate increase of $21 million by means of the rate proceeding at this time. The existingelimination of bill credits ($5.8 million) and an increase in base rates and other provisions($15.2 million). For the two-year term of the Settlement that expiredagreement and thereafter, the return on September 30, 2004 will continue toequity level above which earnings must be in effect until the Commission issues an order concerning Distribution Corporation’sshared with rate request. On June 1, 2004, Distribution Corporation submitted a filing to the NYPSC supporting the removal of a $5 million annual bill credit originally established under the terms of the Agreement. The filing requested removal of the bill credit effective October 1, 2004. On September 28, 2004, the NYPSC issued an order rejecting Distribution Corporation’s request for the stated reason that Distribution Corporation’s earnings were adequate, in the NYPSC’s opinion, without removal of the bill credit. Distribution Corporationpayers is contemplating further action on the NYPSC’s order. In another order issued on September 28, 2004, the NYPSC directed the continuation, with modification, of four programs under the Settlement that were scheduled to expire on September 30, 2004. The effect of the NYPSC’s order was to unilaterally extend the terms of the Settlement without Distribution Corporation’s consent. Although the NYPSC’s order stated that it provided for funding of the programs, Distribution Corporation petitioned Supreme Court, Albany County for an injunction to allow the programs to expire on their own terms. Distribution Corporation’s petition was partially successful, and the proceeding remains pending. On September 20, 2001, the NYPSC issued an order under which Distribution Corporation was directed to show cause why an action for penalties of $19.0 million should not be commenced against it for alleged violations of consumer protection requirements. On December 3, 2001, Distribution Corporation filed its response which vigorously asserted that the allegations lacked merit. Distribution Corporation continues to so believe. On July 28, 2004, the NYPSC concluded the investigation of issues raised in the order without46assessing any fines or penalties. As part of the settlement of the NYPSC’s investigation, Distribution Corporation will commit $1.5 million to a new program designed to assist low-income customers who are transitioning from public assistance. Distribution Corporation has also agreed to incur costs up to $0.3 million for an audit of customer service practices. The NYPSC has agreed not to seek any penalties should any violations be uncovered during the audit. For a discussion of related legal matters, refer to Item 3, “Legal Proceedings.”April 16, 2003,June 1, 2006, Distribution Corporation filed a requestproposed tariff amendments with the PaPUC to increase annual operating revenues by $16.5$25.9 million to cover increases in the cost of providing service to be effective June 15, 2003.July 30, 2006. The PaPUC suspended the effective daterate request was filed to January 15, 2004. Distribution Corporation filed this request for several reasons including increases in theaddress increased costs associated with Distribution Corporation’s ongoing construction program as well as increases in operating costs, particularly uncollectible accountsaccounts. Following standard regulatory procedure, the PaPUC issued an order on July 20, 2006 instituting a rate proceeding and personnel expenses.suspending the proposed tariff amendments until March 2, 2007.* On October 16, 2003,2, 2006, the parties, reached a settlement of all issues. The settlement was submitted to the Administrative Law Judge, who, on November 17, 2003, issued a decision recommending adoptionincluding Distribution Corporation, Staff of the settlement.PaPUC and intervenors, executed an agreement (Settlement) proposing to settle all issues in the rate proceeding. The settlement provides forSettlement includes an increase in revenues of $14.3 million to non-gas revenues, an agreement not to file a base rate increase of $3.5 millioncase until January 28, 2008 at the earliest and authorizes deferral accounting for pension and other post-retirement benefit expenses.an early implementation date. The settlementSettlement was approved by the PaPUC at its meeting on December 18, 2003,November 30, 2006, and new rates becamewill become effective January 15, 2004.September 15, 2004, Distribution Corporation filed revised tariffs withJune 8, 2006, the PaPUC to increase annual revenues by $22.8 million to cover increases in the cost of service to be effective November 14, 2004. The rate request was filed to address throughput reductions and increased operating costs such as uncollectibles and personnel expenses. Applying standard procedure, the PaPUC suspended Distribution Corporation’s tariff filing to perform an investigation and hold hearings. With this suspension, the effective date was changed to June 14, 2005 and the proceeding remains pending.Pipeline and Storage Supply Corporation currently does not have a rate case on file with the FERC. Management will continue to monitor Supply Corporation’s financial position to determine the necessity of filing a rate case in the future. On November 25, 2003, the FERCNTSB issued Order 2004 “Standards of Conduct for Transmission Providers” (“Order 2004”). Order 2004 was clarified in Order 2004-A on April 16, 2004 and Order 2004-B on August 2, 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 principal energy affiliates will be Seneca, NFR and, possibly, Distribution Corporation.* Order 2004 provides that companies may request waivers, which the Company has done with respectsafety 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 is awaiting rulings. Order 2004 also provides an exemption for local distribution companies that are affiliated with interstate pipelines (such as Distribution Corporation), butdamaged a number of other houses in the exemption is limited, with very minor exceptions, to local distribution corporations that do not make any off-system sales and do not purchase gas in ways FERC considers to be “financial or futures transactions or hedging.” While Distribution Corporation stopped making such off-system sales effective September 22, 2004, some of its gas purchase arrangements might be considered by FERC to be “financial or futures transactions or hedging.” Supply Corporationimmediate vicinity.would like to continue operating as they do, whether by waiver, amendment or further clarificationdiffer in their assessment of the new rules, or by complying withprobable cause of the requirements applicable ifexplosion. 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 wereto have an energy affiliate. Treatingadequate program to inspect butt-fusion joints and replace those joints not meeting its inspection criteria. Distribution Corporation as an energy affiliate, without any waivers, would require changeshad 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 way Supply Corporation andvicinity of Distribution Corporation’s pipeline. Distribution Corporation operatealso had raised issues concerning the testing standards employed in the NTSB investigation. Distribution Corporation is presently reviewing alternatives by which would decrease efficiency, but probably would not increase capital or operating expenses to an extent that would be material to the financial conditionseek review of the Company.* Until there is further clarification fromNTSB’s findings and conclusions to ensure that the FERC on the scope of theseNTSB considered all
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(i) | Distribution Corporation uncovered a limited number of butt-fusions at two locations designated by the PaPUC Staff; | |
(ii) | Commencing July 6, 2006, Distribution Corporation has uncovered additional butt-fusions throughout its Pennsylvania service area as it has uncovered facilities for other purposes; when a butt-fusion has been uncovered, Distribution Corporation has notified the designated PaPUC Staff representative to permit inspection of the quality of the fusion. Distribution Corporation has removed a number of fusions for further evaluation. |
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(i) | All participants have reached a negotiated resolution of all the issues raised or which could have been raised in the proceeding, including the claim that Supply Corporation should disgorge all previous efficiency gas sales profits. | |
(ii) | Supply Corporation’s gas retention allowances on transportation services will decrease from 2% to 1.4%, which will reduce Supply Corporation’s future revenue from sales of excess “efficiency gas.” For example, if pre-settlement Supply Corporation received 100 Dth of gas for transportation under its firm transportation rate schedule, Supply Corporation would retain 2 Dth for fuel, loss and company use. Post-settlement, Supply Corporation would retain a total of 1.4 Dth for the combination of fuel, company use and “lost and unaccounted for” (LAUF). Supply Corporation may continue to sell the excess retained gas, if any, that is not consumed or lost in operations (the “efficiency gas”) and keep the proceeds. However, any profit from the purchase and sale of gas to cash out shipper imbalances will continue to be accounted for separately and refunded to customers. Supply Corporation will publicly file at FERC a semi-annual report disclosing, among other things, the quantity, price and accounting treatment of all sales of efficiency gas. The amount of net revenue from Supply Corporation’s future sales of efficiency gas will depend upon the quantity of efficiency gas that becomes available for sale and the prices which Supply Corporation receives from selling that gas.* | |
(iii) | Supply Corporation’s annual depreciation rate for transmission plant will decrease to 2.9%, and its annual depreciation rate for storage plant will decrease to 2.23%. This will result in a decrease to Supply Corporation’s depreciation expense by $5.623 million per year from the pre-settlement level of annual depreciation expense.* | |
(iv) | The settlement does not change Supply Corporation’s rates other than its gas retention allowances. No general rate cases or NGA Section 5 complaint may be filed by the settling parties to be effective before December 1, 2011. However, Supply Corporation may file limited NGA Section 4 rate cases as permitted by FERC for matters of general applicability to all pipelines (such as passing through some possible future greenhouse gas tax), and may propose seasonal rates. | |
(v) | Supply Corporation’s Other Post-Retirement Benefits Rate Allowance (the amount deemed to be recovered each year in rates to fund the Post-Retirement Plan benefits described in Note G — Retirement Plan and Other Post-Retirement Benefits) will increase from about $4.736 million to $11.0 million per year. Supply Corporation will contribute its entire Other Post-Retirement Benefits Rate Allowance to the VEBA trusts and 401(h) account described in that Note G. About $2.5 million per year of the Other Post-Retirement Benefits Rate Allowance will be applied to fully amortize over the next five years Supply Corporation’s entire other post-retirement benefits regulatory asset balance at December 1, 2006, which had been deferred for recovery under a 1995 rate case settlement. To the extent the remainder of the Other Post- |
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Retirement Benefits Rate Allowance differs from the SFAS 106 expense that Supply Corporation actually accrues for the Post-Retirement Plan, that difference will be deferred for future recovery or refund as a regulatory asset or liability. See Note G — Retirement Plan and Other Post-Retirement Benefits for extensive disclosure on the Post-Retirement Plan. | ||
(vi) | Supply Corporation’s tariff provisions on discounting gas retention allowances will be amended so as to be consistent with FERC’s current policy limiting “fuel discounts.” Certain pre-settlement discounts in gas retention allowances will also be incorporated into the tariff. The discounting changes described in this subparagraph (vi) are not expected to change Supply Corporation’s earnings as compared to pre-settlement discounting practices.* |
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1. | Changes in laws and regulations to which the Company is subject, including changes in tax, environmental, safety and employment laws and regulations; | |
2. | Changes in economic conditions, including economic disruptions caused by terrorist activities, | |
Changes in demographic patterns and weather conditions, including the occurrence of severe | ||
4. | Changes in the availabilityand/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 availabilityand/or price of derivative financial instruments; | |
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; |
58
9. | Inability to obtain new customers or retain existing ones; |
Significant changes in competitive factors affecting the Company; | ||
Governmental/regulatory actions, initiatives and proceedings, including those | ||
Unanticipated impacts of restructuring initiatives in the natural gas and electric industries; | ||
Significant changes from expectations in actual capital expenditures and operating expenses and unanticipated project delays or changes in project | ||
The nature and projected profitability of pending and potential projects and other investments; |
Occurrences affecting the Company’s ability to obtain funds from operations or from issuances of debt or equity securities to finance needed capital expenditures and other | ||
Uncertainty of oil and gas reserve estimates; | ||
Ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties; | ||
Ability to successfully identify, drill for and produce economically viable natural gas and oil reserves; | ||
Significant changes from expectations in the Company’s actual production levels for natural gas or oil; | ||
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; | ||
Significant changes in tax rates or policies or in rates of inflation or interest; | ||
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; |
49
Changes in accounting principles or the application of such principles to the Company; | ||
The cost and effects of legal and administrative claims against the Company; | ||
Changes in actuarial assumptions and the return on assets with respect to the Company’s retirement plan and post-retirement benefit plans; | ||
Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide post-retirement benefits; or | ||
Increasing costs of insurance, changes in coverage and the ability to obtain insurance. |
Item 7A Quantitative and Qualitative Disclosures About Market Risk
59
50
Item 8 | Financial Statements and Supplementary Data |
Page | |||||
Financial Statements: | |||||
Financial Statement Schedules: | |||||
For the three years ended September 30, | |||||
Supplementary Data
60
51
Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
As discussed
61
Buffalo, New York
52
62
Year Ended September 30 | ||||||||||||||
2004 | 2003 | 2002 | ||||||||||||
(Thousands of dollars, except per | ||||||||||||||
common share amounts) | ||||||||||||||
INCOME | ||||||||||||||
Operating Revenues | $ | 2,031,393 | $ | 2,035,471 | $ | 1,464,496 | ||||||||
Operating Expenses: | ||||||||||||||
Purchased Gas | 949,452 | 963,567 | 462,857 | |||||||||||
Fuel Used in Heat and Electric Generation | 65,722 | 61,029 | 50,635 | |||||||||||
Operation and Maintenance | 413,593 | 386,270 | 394,157 | |||||||||||
Property, Franchise and Other Taxes | 72,111 | 82,504 | 72,155 | |||||||||||
Depreciation, Depletion and Amortization | 189,538 | 195,226 | 180,668 | |||||||||||
Impairment of Oil and Gas Producing Properties | — | 42,774 | — | |||||||||||
1,690,416 | 1,731,370 | 1,160,472 | ||||||||||||
Gain (Loss) on Sale of Timber Properties | (1,252 | ) | 168,787 | — | ||||||||||
Gain (Loss) on Sale of Oil and Gas Producing Properties | 4,645 | (58,472 | ) | — | ||||||||||
Operating Income | 344,370 | 414,416 | 304,024 | |||||||||||
Other Income (Expense): | ||||||||||||||
Income from Unconsolidated Subsidiaries | 805 | 535 | 224 | |||||||||||
Impairment of Investment in Partnership | — | — | (15,167 | ) | ||||||||||
Other Income | 6,671 | 6,887 | 7,017 | |||||||||||
Interest Expense on Long-Term Debt | (83,827 | ) | (92,766 | ) | (90,543 | ) | ||||||||
Other Interest Expense | (6,763 | ) | (12,290 | ) | (15,109 | ) | ||||||||
Income Before Income Taxes and Minority | ||||||||||||||
Interest in Foreign Subsidiaries | 261,256 | 316,782 | 190,446 | |||||||||||
Income Tax Expense | 92,737 | 128,161 | 72,034 | |||||||||||
Minority Interest in Foreign Subsidiaries | (1,933 | ) | (785 | ) | (730 | ) | ||||||||
Income Before Cumulative Effect of Changes In Accounting | 166,586 | 187,836 | 117,682 | |||||||||||
Cumulative Effect of Changes in Accounting | — | (8,892 | ) | — | ||||||||||
Net Income Available for Common Stock | 166,586 | 178,944 | 117,682 | |||||||||||
EARNINGS REINVESTED IN THE BUSINESS | ||||||||||||||
Balance at Beginning of Year | 642,690 | 549,397 | 513,488 | |||||||||||
809,276 | 728,341 | 631,170 | ||||||||||||
Dividends on Common Stock | 90,350 | 85,651 | 81,773 | |||||||||||
Balance at End of Year | $ | 718,926 | $ | 642,690 | $ | 549,397 | ||||||||
Earnings Per Common Share: | ||||||||||||||
Basic: | ||||||||||||||
Income Before Cumulative Effect of Changes in Accounting | $ | 2.03 | $ | 2.32 | $ | 1.47 | ||||||||
Cumulative Effect of Changes in Accounting | — | (0.11 | ) | — | ||||||||||
Net Income Available for Common Stock | $ | 2.03 | $ | 2.21 | $ | 1.47 | ||||||||
Diluted: | ||||||||||||||
Income Before Cumulative Effect of Changes in Accounting | $ | 2.01 | $ | 2.31 | $ | 1.46 | ||||||||
Cumulative Effect of Changes in Accounting | — | (0.11 | ) | — | ||||||||||
Net Income Available for Common Stock | $ | 2.01 | $ | 2.20 | $ | 1.46 | ||||||||
Weighted Average Common Shares Outstanding: | ||||||||||||||
Used in Basic Calculation | 82,045,535 | 80,808,794 | 79,821,430 | |||||||||||
Used in Diluted Calculation | 82,900,438 | 81,357,896 | 80,534,453 |
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(Thousands of dollars, except per common | ||||||||||||
share amounts) | ||||||||||||
INCOME | ||||||||||||
Operating Revenues | $ | 2,311,659 | $ | 1,923,549 | $ | 1,907,968 | ||||||
Operating Expenses | ||||||||||||
Purchased Gas | 1,267,562 | 959,827 | 949,452 | |||||||||
Operation and Maintenance | 413,726 | 404,517 | 385,519 | |||||||||
Property, Franchise and Other Taxes | 69,942 | 69,076 | 68,978 | |||||||||
Depreciation, Depletion and Amortization | 179,615 | 179,767 | 174,289 | |||||||||
Impairment of Oil and Gas Producing Properties | 104,739 | — | — | |||||||||
2,035,584 | 1,613,187 | 1,578,238 | ||||||||||
Loss on Sale of Timber Properties | — | — | (1,252 | ) | ||||||||
Gain on Sale of Oil and Gas Producing Properties | — | — | 4,645 | |||||||||
Operating Income | 276,075 | 310,362 | 333,123 | |||||||||
Other Income (Expense): | ||||||||||||
Income from Unconsolidated Subsidiaries | 3,583 | 3,362 | 805 | |||||||||
Impairment of Investment in Partnership | — | (4,158 | ) | — | ||||||||
Interest Income | 10,275 | 6,496 | 1,771 | |||||||||
Other Income | 2,825 | 12,744 | 2,908 | |||||||||
Interest Expense on Long-Term Debt | (72,629 | ) | (73,244 | ) | (82,989 | ) | ||||||
Other Interest Expense | (5,952 | ) | (9,069 | ) | (6,763 | ) | ||||||
Income from Continuing Operations Before Income Taxes | 214,177 | 246,493 | 248,855 | |||||||||
Income Tax Expense | 76,086 | 92,978 | 94,590 | |||||||||
Income from Continuing Operations | 138,091 | 153,515 | 154,265 | |||||||||
Discontinued Operations: | ||||||||||||
Income from Operations, Net of Tax | — | 10,199 | 12,321 | |||||||||
Gain on Disposal, Net of Tax | — | 25,774 | — | |||||||||
Income from Discontinued Operations | — | 35,973 | 12,321 | |||||||||
Net Income Available for Common Stock | 138,091 | 189,488 | 166,586 | |||||||||
EARNINGS REINVESTED IN THE BUSINESS | ||||||||||||
Balance at Beginning of Year | 813,020 | 718,926 | 642,690 | |||||||||
951,111 | 908,414 | 809,276 | ||||||||||
Share Repurchases | 66,269 | — | — | |||||||||
Dividends on Common Stock | 98,829 | 95,394 | 90,350 | |||||||||
Balance at End of Year | $ | 786,013 | $ | 813,020 | $ | 718,926 | ||||||
Earnings Per Common Share: | ||||||||||||
Basic: | ||||||||||||
Income from Continuing Operations | $ | 1.64 | $ | 1.84 | $ | 1.88 | ||||||
Income from Discontinued Operations | — | 0.43 | 0.15 | |||||||||
Net Income Available for Common Stock | $ | 1.64 | $ | 2.27 | $ | 2.03 | ||||||
Diluted: | ||||||||||||
Income from Continuing Operations | $ | 1.61 | $ | 1.81 | $ | 1.86 | ||||||
Income from Discontinued Operations | — | 0.42 | 0.15 | |||||||||
Net Income Available for Common Stock | $ | 1.61 | $ | 2.23 | $ | 2.01 | ||||||
Weighted Average Common Shares Outstanding: | ||||||||||||
Used in Basic Calculation | 84,030,118 | 83,541,627 | 82,045,535 | |||||||||
Used in Diluted Calculation | 86,028,466 | 85,029,131 | 82,900,438 | |||||||||
63
53
At September 30 | ||||||||
2006 | 2005 | |||||||
(Thousands of dollars) | ||||||||
ASSETS | ||||||||
Property, Plant and Equipment | $ | 4,703,040 | $ | 4,423,255 | ||||
Less — Accumulated Depreciation, Depletion and Amortization | 1,825,314 | 1,583,955 | ||||||
2,877,726 | 2,839,300 | |||||||
Current Assets | ||||||||
Cash and Temporary Cash Investments | 69,611 | 57,607 | ||||||
Hedging Collateral Deposits | 19,676 | 77,784 | ||||||
Receivables — Net of Allowance for Uncollectible Accounts of $31,427 and $26,940, Respectively | 144,254 | 141,408 | ||||||
Unbilled Utility Revenue | 25,538 | 20,465 | ||||||
Gas Stored Underground | 59,461 | 64,529 | ||||||
Materials and Supplies — at average cost | 36,693 | 33,267 | ||||||
Unrecovered Purchased Gas Costs | 12,970 | 14,817 | ||||||
Prepaid Pension and Post-Retirement Benefit Costs | 64,125 | 14,404 | ||||||
Other Current Assets | 63,723 | 67,351 | ||||||
Deferred Income Taxes | 23,402 | 83,774 | ||||||
519,453 | 575,406 | |||||||
Other Assets | ||||||||
Recoverable Future Taxes | 79,511 | 85,000 | ||||||
Unamortized Debt Expense | 15,492 | 17,567 | ||||||
Other Regulatory Assets | 76,917 | 47,028 | ||||||
Deferred Charges | 3,558 | 4,474 | ||||||
Other Investments | 88,414 | 80,394 | ||||||
Investments in Unconsolidated Subsidiaries | 11,590 | 12,658 | ||||||
Goodwill | 5,476 | 5,476 | ||||||
Intangible Assets | 31,498 | 42,302 | ||||||
Fair Value of Derivative Financial Instruments | 11,305 | — | ||||||
Deferred Income Taxes | 9,003 | — | ||||||
Other | 4,388 | 15,677 | ||||||
337,152 | 310,576 | |||||||
Total Assets | $ | 3,734,331 | $ | 3,725,282 | ||||
CAPITALIZATION AND LIABILITIES | ||||||||
Capitalization: | ||||||||
Comprehensive Shareholders’ Equity | ||||||||
Common Stock, $1 Par Value | ||||||||
Authorized — 200,000,000 Shares; Issued and Outstanding — 83,402,670 Shares and 84,356,748 Shares, Respectively | $ | 83,403 | $ | 84,357 | ||||
Paid In Capital | 543,730 | 529,834 | ||||||
Earnings Reinvested in the Business | 786,013 | 813,020 | ||||||
Total Common Shareholders’ Equity Before Items Of Other Comprehensive Income (Loss) | 1,413,146 | 1,427,211 | ||||||
Accumulated Other Comprehensive Income (Loss) | 30,416 | (197,628 | ) | |||||
Total Comprehensive Shareholders’ Equity | 1,443,562 | 1,229,583 | ||||||
Long-Term Debt, Net of Current Portion | 1,095,675 | 1,119,012 | ||||||
Total Capitalization | 2,539,237 | 2,348,595 | ||||||
Current and Accrued Liabilities | ||||||||
Notes Payable to Banks and Commercial Paper | — | — | ||||||
Current Portion of Long-Term Debt | 22,925 | 9,393 | ||||||
Accounts Payable | 133,034 | 155,485 | ||||||
Amounts Payable to Customers | 23,935 | 1,158 | ||||||
Dividends Payable | 25,008 | 24,445 | ||||||
Interest Payable on Long-Term Debt | 18,420 | 18,438 | ||||||
Other Accruals and Current Liabilities | 27,040 | 44,596 | ||||||
Fair Value of Derivative Financial Instruments | 39,983 | 209,072 | ||||||
290,345 | 462,587 | |||||||
Deferred Credits | ||||||||
Deferred Income Taxes | 544,502 | 489,720 | ||||||
Taxes Refundable to Customers | 10,426 | 11,009 | ||||||
Unamortized Investment Tax Credit | 6,094 | 6,796 | ||||||
Cost of Removal Regulatory Liability | 85,076 | 90,396 | ||||||
Other Regulatory Liabilities | 75,456 | 66,339 | ||||||
Pension and Other Post-Retirement Liabilities | 32,918 | 143,687 | ||||||
Asset Retirement Obligation | 77,392 | 41,411 | ||||||
Other Deferred Credits | 72,885 | 64,742 | ||||||
904,749 | 914,100 | |||||||
Commitments and Contingencies | — | — | ||||||
Total Capitalization and Liabilities | $ | 3,734,331 | $ | 3,725,282 | ||||
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54
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(Thousands of dollars) | ||||||||||||
Operating Activities | ||||||||||||
Net Income Available for Common Stock | $ | 138,091 | $ | 189,488 | $ | 166,586 | ||||||
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: | ||||||||||||
Gain on Sale of Discontinued Operations | — | (27,386 | ) | — | ||||||||
Loss on Sale of Timber Properties | — | — | 1,252 | |||||||||
Gain on Sale of Oil and Gas Producing Properties | — | — | (4,645 | ) | ||||||||
Impairment of Oil and Gas Producing Properties | 104,739 | — | — | |||||||||
Depreciation, Depletion and Amortization | 179,615 | 193,144 | 189,538 | |||||||||
Deferred Income Taxes | (5,230 | ) | 40,388 | 40,329 | ||||||||
(Income) Loss from Unconsolidated Subsidiaries, Net of Cash Distributions | 1,067 | (1,372 | ) | (19 | ) | |||||||
Impairment of Investment in Partnership | — | 4,158 | — | |||||||||
Minority Interest in Foreign Subsidiaries | — | 2,645 | 1,933 | |||||||||
Excess Tax Benefits Associated with Stock-Based Compensation Awards | (6,515 | ) | — | — | ||||||||
Other | 4,829 | 7,390 | 9,839 | |||||||||
Change in: | ||||||||||||
Hedging Collateral Deposits | 58,108 | (69,172 | ) | (7,151 | ) | |||||||
Receivables and Unbilled Utility Revenue | (7,397 | ) | (21,857 | ) | 8,887 | |||||||
Gas Stored Underground and Materials and Supplies | 1,679 | 1,934 | 13,662 | |||||||||
Unrecovered Purchased Gas Costs | 1,847 | (7,285 | ) | 21,160 | ||||||||
Prepayments and Other Current Assets | (39,572 | ) | (42,409 | ) | 35,647 | |||||||
Accounts Payable | (23,144 | ) | 48,089 | (5,134 | ) | |||||||
Amounts Payable to Customers | 22,777 | (1,996 | ) | 2,462 | ||||||||
Other Accruals and Current Liabilities | (17,754 | ) | 18,715 | 2,082 | ||||||||
Other Assets | (22,700 | ) | (13,461 | ) | (4,829 | ) | ||||||
Other Liabilities | 80,960 | (3,667 | ) | (34,450 | ) | |||||||
Net Cash Provided by Operating Activities | 471,400 | 317,346 | 437,149 | |||||||||
Investing Activities | ||||||||||||
Capital Expenditures | (294,159 | ) | (219,530 | ) | (172,341 | ) | ||||||
Net Proceeds from Sale of Foreign Subsidiary | — | 111,619 | — | |||||||||
Net Proceeds from Sale of Oil and Gas Producing Properties | 13 | 1,349 | 7,162 | |||||||||
Other | (3,230 | ) | 3,238 | 1,974 | ||||||||
Net Cash Used in Investing Activities | (297,376 | ) | (103,324 | ) | (163,205 | ) | ||||||
Financing Activities | ||||||||||||
Change in Notes Payable to Banks and Commercial Paper | — | (115,359 | ) | 38,600 | ||||||||
Excess Tax Benefits Associated with Stock-Based Compensation Awards | 6,515 | — | — | |||||||||
Shares Repurchased under Repurchase Plan | (85,168 | ) | — | — | ||||||||
Reduction of Long-Term Debt | (9,805 | ) | (13,317 | ) | (243,085 | ) | ||||||
Proceeds from Issuance of Common Stock | 23,339 | 20,279 | 23,763 | |||||||||
Dividends Paid on Common Stock | (98,266 | ) | (94,159 | ) | (89,092 | ) | ||||||
Dividends Paid to Minority Interest | — | (12,676 | ) | — | ||||||||
Net Cash Used in Financing Activities | (163,385 | ) | (215,232 | ) | (269,814 | ) | ||||||
Effect of Exchange Rates on Cash | 1,365 | 1,276 | 3,451 | |||||||||
Net Increase in Cash and Temporary Cash Investments | 12,004 | 66 | 7,581 | |||||||||
Cash and Temporary Cash Investments At Beginning of Year | 57,607 | 57,541 | 49,960 | |||||||||
Cash and Temporary Cash Investments At End of Year | $ | 69,611 | $ | 57,607 | $ | 57,541 | ||||||
Supplemental Disclosure of Cash Flow Information Cash Paid For: | ||||||||||||
Interest | $ | 78,003 | $ | 84,455 | $ | 90,705 | ||||||
Income Taxes | $ | 54,359 | $ | 83,542 | $ | 30,214 | ||||||
65
55
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(Thousands of dollars) | ||||||||||||
Net Income Available for Common Stock | $ | 138,091 | $ | 189,488 | $ | 166,586 | ||||||
Other Comprehensive Income (Loss), Before Tax: | ||||||||||||
Minimum Pension Liability Adjustment | 165,914 | (83,379 | ) | 56,612 | ||||||||
Foreign Currency Translation Adjustment | 7,408 | 14,286 | 21,466 | |||||||||
Reclassification Adjustment for Realized Foreign Currency Translation Gain in Net Income | (716 | ) | (37,793 | ) | — | |||||||
Unrealized Gain on Securities Available for Sale Arising During the Period | 2,573 | 2,891 | 3,629 | |||||||||
Reclassification Adjustment for Realized Gains On Securities Available for Sale in Net Income | — | (651 | ) | — | ||||||||
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period | 90,196 | (206,847 | ) | (129,934 | ) | |||||||
Reclassification Adjustment for Realized Loss on Derivative Financial Instruments in Net Income | 91,743 | 97,689 | 49,142 | |||||||||
Other Comprehensive Income (Loss), Before Tax: | 357,118 | (213,804 | ) | 915 | ||||||||
Income Tax Expense (Benefit) Related to Minimum Pension Liability Adjustment | 58,070 | (29,183 | ) | 19,814 | ||||||||
Income Tax Expense Related to Foreign Currency Translation Adjustment | — | 112 | — | |||||||||
Reclassification Adjustment for Income Tax Expense on Foreign Currency Translation Adjustment in Net Income | — | (112 | ) | — | ||||||||
Income Tax Expense Related to Unrealized Gain on Securities Available for Sale Arising During the Period | 894 | 1,012 | 1,270 | |||||||||
Reclassification Adjustment for Income Tax Expense on Realized Gains from Securities Available for Sale in Net Income | — | (228 | ) | — | ||||||||
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period | 34,772 | (79,059 | ) | (49,113 | ) | |||||||
Reclassification Adjustment for Income Tax Benefit on Realized Loss on Derivative Financial Instruments In Net Income | 35,338 | 36,507 | 18,182 | |||||||||
Income Taxes — Net | 129,074 | (70,951 | ) | (9,847 | ) | |||||||
Other Comprehensive Income (Loss) | 228,044 | (142,853 | ) | 10,762 | ||||||||
Comprehensive Income | $ | 366,135 | $ | 46,635 | $ | 177,348 | ||||||
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56
Reclassification
In the International segment, rates charged for the sale of thermal energy and electric energy at the retail level are subject to regulation and audit in the Czech Republic by the Czech Ministry of Finance. The regulation of electric energy rates at the retail level indirectly impacts the rates charged by the International segment for its electric energy sales at the wholesale level.
67
57
2006.
58
68
As of September 30 2004 2003 (Thousands) Utility $ 1,426,540 $ 1,380,278 Pipeline and Storage 946,866 854,923 Exploration and Production 1,517,856 1,673,827 International 379,356 349,132 Energy Marketing 1,169 1,159 Timber 97,290 96,315 All Other and Corporate 28,442 20,541 $ 4,397,519 $ 4,376,175 As of September 30 2006 2005 (Thousands) Utility $ 1,493,991 $ 1,462,527 Pipeline and Storage 962,831 960,066 Exploration and Production 1,899,777 1,665,774 Energy Marketing 1,123 1,108 Timber 116,281 114,352 All Other and Corporate 33,338 29,275 $ 4,507,341 $ 4,233,102 Year Ended September 30 2004 2003 2002 Utility 2.8 % 2.8 % 2.8 % Pipeline and Storage 4.1 % 4.4 % 3.6 % Exploration and Production, per Mcfe(1) $ 1.49 $ 1.34 $ 1.19 International 4.2 % 4.2 % 4.2 % Energy Marketing 8.7 % 10.9 % 16.4 % Timber 6.5 % 7.0 % 3.2 % All Other and Corporate 6.2 % 1.7 % 2.7 % Year Ended September 30 2006 2005 2004 Utility 2.8 % 2.8 % 2.8 % Pipeline and Storage 4.0 % 4.1 % 4.1 % Exploration and Production, per Mcfe(1) $ 2.00 $ 1.74 $ 1.49 Energy Marketing 4.8 % 7.6 % 8.7 % Timber 5.6 % 6.2 % 6.5 % All Other and Corporate 4.1 % 4.3 % 6.2 % (1) Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note NO — Supplementary Information for Oil and Gas Producing Properties, depletion of oil and gas producing properties amounted to $1.47, $1.30$1.98, $1.72 and $1.16$1.47 per Mcfe of production in 2004, 20032006, 2005 and 2002,2004, respectively.
59
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Effective October 1, 2002,Goodwill
Year Ended | ||||||||
September 30 | ||||||||
2004 | 2003 | |||||||
(Thousands) | ||||||||
Balance at Beginning of Year | $ | 27,493 | $ | 36,090 | ||||
Liabilities Incurred and Revisions of Estimates | 3,510 | 242 | ||||||
Liabilities Settled | (831 | ) | (13,227 | ) | ||||
Accretion Expense | 1,933 | 2,602 | ||||||
Exchange Rate Impact | 187 | 1,786 | ||||||
Balance at End of Year | $ | 32,292 | $ | 27,493 | ||||
In the Company’s Utility and Pipeline and Storage segment, costs of removal are collected from customers through depreciation expense. These removal costs are not a legal retirement obligation in accordance with SFAS 143. Rather, they represent a regulatory liability. However, SFAS 143 requires thatbook value. As such, costs of removal be reclassified from accumulated depreciation to other regulatory liabilities. At September 30, 2004 and 2003, the costs of removal reclassified to other regulatory liabilities amounted to $82.0 million and $76.8 million, respectively.
Effective October 1, 2002, the Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). In accordance with SFAS 142, the Company stopped amortization of goodwill and tested it for impairment as of October 1, 2002. The Company’s goodwill balance as of October 1, 2002 totaled $8.3 million and was related to the Company’s investments in the Czech Republic, which are included in the International segment. As a result of the impairment test, the Company recognized an impairment of $8.3 million. The Company used discounted cash flows to estimate the fair value of its goodwill and determined that the goodwill had no remaining value. Based on projected restructuring in the Czech electricity market, the Company couldwas considered not be assured that the level of future cash flows from the Company’s investments in the Czech Republic would attain the level that was originally forecasted. In accordance with SFAS 142, this impairment was reported as a cumulative effect of change in accounting. Goodwill amortization amounted to $0.6 million in 2002.impaired.
60
69
Accumulated Other Comprehensive Income (Loss)
Year Ended | ||||||||
September 30 | ||||||||
2004 | 2003 | |||||||
(Thousands) | ||||||||
Minimum Pension Liability Adjustment | $ | (53,648 | ) | $ | (90,446 | ) | ||
Cumulative Foreign Currency Translation Adjustment | 51,516 | 30,050 | ||||||
Net Unrealized Loss on Derivative Financial Instruments | (56,733 | ) | (6,872 | ) | ||||
Net Unrealized Gain on Securities Available for Sale | 4,090 | 1,731 | ||||||
Accumulated Other Comprehensive Loss | $ | (54,775 | ) | $ | (65,537 | ) | ||
Year Ended September 30 | ||||||||
2006 | 2005 | |||||||
(Thousands) | ||||||||
Minimum Pension Liability Adjustment | $ | — | $ | (107,844 | ) | |||
Cumulative Foreign Currency Translation Adjustment | 34,701 | 28,009 | ||||||
Net Unrealized Loss on Derivative Financial Instruments | (11,510 | ) | (123,339 | ) | ||||
Net Unrealized Gain on Securities Available for Sale | 7,225 | 5,546 | ||||||
Accumulated Other Comprehensive Income (Loss) | $ | 30,416 | $ | (197,628 | ) | |||
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61
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Purchased Timber Rights
Year Ended September 30 | ||||||||
2006 | 2005 | |||||||
(Thousands) | ||||||||
Materials and Supplies | $ | 13,174 | $ | 10,610 | ||||
Other Assets | 3,218 | 11,510 | ||||||
$ | 16,392 | $ | 22,120 | |||||
Foreign Currency Translation
Income Taxes
StatementStatements of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents.
71
62
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Share Repurchases
72
73
Year Ended September 30 | ||||||||
2005 | 2004 | |||||||
(Thousands, except per share amounts) | ||||||||
Net Income, Available for Common Stock, As Reported | $ | 189,488 | $ | 166,586 | ||||
Add: Stock-Based Employee Compensation Expense Included in Reported Net Income, Net of Tax(1) | 336 | 543 | ||||||
Deduct: Total Stock-Based Employee Compensation Expense Determined Under Fair Value Based Methods for all Awards, Net of Related Tax Effects | (2,782 | ) | (1,861 | ) | ||||
Pro Forma Net Income Available for Common Stock | $ | 187,042 | $ | 165,268 | ||||
Earnings Per Common Share: | ||||||||
Basic — As Reported | $ | 2.27 | $ | 2.03 | ||||
Basic — Pro Forma | $ | 2.24 | $ | 2.01 | ||||
Diluted — As Reported | $ | 2.23 | $ | 2.01 | ||||
Diluted — Pro Forma | $ | 2.20 | $ | 1.99 |
(1) | Stock-based compensation expense in 2005 and 2004 represented compensation expense related to restricted stock awards. The pre-tax expense was $517,000 and $835,000, respectively, for the years ended September 30, 2005 and 2004. |
Year Ended September 30 | |||||||||||||
2004 | 2003 | 2002 | |||||||||||
(Thousands, except per share amounts) | |||||||||||||
Net Income Available for Common Stock As Reported | $ | 166,586 | $ | 178,944 | $ | 117,682 | |||||||
Deduct: Total Compensation Expense Determined Based on Fair Value at the Grant Dates | 1,318 | 3,105 | 4,641 | ||||||||||
Pro Forma Net Income Available for Common Stock | $ | 165,268 | $ | 175,839 | $ | 113,041 | |||||||
Earnings Per Common Share: | |||||||||||||
Basic — As Reported | $ | 2.03 | $ | 2.21 | $ | 1.47 | |||||||
Basic — Pro Forma | $ | 2.01 | $ | 2.18 | $ | 1.42 | |||||||
Diluted — As Reported | $ | 2.01 | $ | 2.20 | $ | 1.46 | |||||||
Diluted — Pro Forma | $ | 1.99 | $ | 2.16 | $ | 1.40 |
exercise of stock options on a calendar year basis as opposed to a fiscal year basis. As such, for stock options exercised during the quarters ended December 31, 2005, December 31, 2004, and December 31, 2003, the Company realized a tax benefit of $0.9 million, $1.1 million, and $0.1 million, respectively. For stock options exercised during the period of January 1, 2006 through September 30, 2006, the Company will realize a tax benefit of approximately $11.4 million in the quarter ended December 31, 2006. For stock options exercised during the period of January 1, 2005 through September 30, 2005, the Company realized a tax benefit of approximately $6.3 million in the quarter ended December 31, 2005. For stock options exercised during the period of January 1, 2004 through September 30, 2004, the Company realized a tax benefit of approximately $4.8 million in the quarter ended December 31, 2004. The weighted average grant date fair value per share of options granted in 2006, 2005 and 2004 2003is $6.68 per share, $4.59 per share, and 2002$4.66 per share, respectively. For the years ended September 30, 2006, 2005 and 2004, 89,665, 1,375,105 and 729,156 stock options became fully vested, respectively. The total fair value of these stock options was $4.66, $4.17approximately $0.4 million, $6.2 million and $4.32, respectively. These$3.3 million, respectively, for the years ended September 30, 2006, 2005 and 2004. As of September 30, 2006, unrecognized compensation expense related to stock options totaled approximately $0.9 million, which will be recognized over a weighted average fair values were estimated on the dateperiod of grant usingone year. For a binomialsummary of transactions during 2006 involving option pricing model with the following weighted average assumptions:
Year Ended September 30 | ||||||||||||
2004 | 2003 | 2002 | ||||||||||
Quarterly Dividend Yield | 1.12 | % | 1.10 | % | 1.07 | % | ||||||
Annual Standard Deviation (Volatility) | 21.77 | % | 22.24 | % | 21.83 | % | ||||||
Risk Free Rate | 4.61 | % | 3.33 | % | 4.88 | % | ||||||
Expected Term — in Years | 7.0 | 6.5 | 5.5 |
In September 2004, the SEC issued SAB 106. SAB 106 addresses the application of SFAS 143 to companies that follow the full cost method of accounting for oil and gas property acquisition, exploration and development costs. SAB 106 states that after adoption of SFAS 143, the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet should be excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling calculation. The Company adopted SAB 106 for purposes of the full cost ceiling calculation at September 30, 2004. The adoption of SAB 106 did not have any impact on the Company’s financial statements and did not have a material effect on the results of the ceiling test calculation.
74
63
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
Risk Free Interest Rate | 5.08 | % | 4.46 | % | 4.61 | % | ||||||
Expected Life (Years) | 7.0 | 7.0 | 7.0 | |||||||||
Expected Volatility | 17.71 | % | 17.76 | % | 21.77 | % | ||||||
Expected Dividend Yield (Quarterly) | 0.83 | % | 1.00 | % | 1.12 | % |
75
76
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(Thousands) | ||||||||||||
Balance at Beginning of Year | $ | 41,411 | $ | 32,292 | $ | 27,493 | ||||||
Additions — Adoption of FIN 47 | 23,234 | — | — | |||||||||
Liabilities Incurred and Revisions of Estimates | 11,244 | 8,343 | 3,510 | |||||||||
Liabilities Settled | (1,303 | ) | (1,938 | ) | (831 | ) | ||||||
Accretion Expense | 2,671 | 2,448 | 1,933 | |||||||||
Exchange Rate Impact | 135 | 266 | 187 | |||||||||
Balance at End of Year | $ | 77,392 | $ | 41,411 | $ | 32,292 | ||||||
77
Regulatory Assets and Liabilities
At September 30 | |||||||||
2004 | 2003 | ||||||||
(Thousands) | |||||||||
Regulatory Assets(1): | |||||||||
Recoverable Future Taxes (Note C) | $ | 83,847 | $ | 84,818 | |||||
Unrecovered Purchased Gas Costs (See Regulatory Mechanisms in Note A) | 7,532 | 28,692 | |||||||
Unamortized Debt Expense (Note A) | 9,882 | 11,364 | |||||||
Pension and Post-Retirement Benefit Costs (2)(Note F) | 62,664 | 47,750 | |||||||
Other(2) | 4,198 | 4,631 | |||||||
Total Regulatory Assets | 168,123 | 177,255 | |||||||
Regulatory Liabilities: | |||||||||
Cost of Removal Regulatory Liability (See Cumulative Effect Discussion in Note A) | 82,020 | 76,782 | |||||||
Amounts Payable to Customers (See Regulatory Mechanisms in Note A) | 3,154 | 692 | |||||||
New York Rate Settlements(3) | 26,048 | 30,900 | |||||||
Taxes Refundable to Customers (Note C) | 11,065 | 13,519 | |||||||
Pension and Post-Retirement Benefit Costs(3) (Note F) | 13,232 | 23,719 | |||||||
Other(3) | 28,389 | 18,013 | |||||||
Total Regulatory Liabilities | 163,908 | 163,625 | |||||||
Net Regulatory Position | $ | 4,215 | $ | 13,630 |
At September 30 | ||||||||
2006 | 2005 | |||||||
(Thousands) | ||||||||
Regulatory Assets(1): | ||||||||
Recoverable Future Taxes (Note D) | $ | 79,511 | $ | 85,000 | ||||
Pension and Post-Retirement Benefit Costs(2) (Note G) | 47,368 | 27,135 | ||||||
Unrecovered Purchased Gas Costs (See Regulatory Mechanisms in Note A) | 12,970 | 14,817 | ||||||
Environmental Site Remediation Costs(2) (Note H) | 12,937 | 13,054 | ||||||
Asset Retirement Obligation(2) (Note B) | 9,018 | — | ||||||
Unamortized Debt Expense (Note A) | 8,399 | 9,088 | ||||||
Other(2) | 7,594 | 6,839 | ||||||
Total Regulatory Assets | 177,797 | 155,933 | ||||||
Regulatory Liabilities: | ||||||||
Cost of Removal Regulatory Liability (Note B) | 85,076 | 90,396 | ||||||
New York Rate Settlements(3) | 40,881 | 53,205 | ||||||
Amounts Payable to Customers (See Regulatory Mechanisms in Note A) | 23,935 | 1,158 | ||||||
Tax Benefit on Medicare Part D Subsidy(3) | 13,791 | — | ||||||
Pension and Post-Retirement Benefit Costs(3) (Note G) | 13,063 | 12,751 | ||||||
Taxes Refundable to Customers (Note D) | 10,426 | 11,009 | ||||||
Deferred Insurance Proceeds(3) | 7,516 | — | ||||||
Other(3) | 205 | 383 | ||||||
Total Regulatory Liabilities | 194,893 | 168,902 | ||||||
Net Regulatory Position | $ | (17,096 | ) | $ | (12,969 | ) | ||
(1) | The Company recovers the cost of its regulatory assets but, with the exception of Unrecovered Purchased Gas Costs, does not earn a return on them. | |
(2) | Included in Other Regulatory Assets on the Consolidated Balance Sheets. | |
(3) | Included in Other Regulatory Liabilities on the Consolidated Balance Sheets. |
78
64
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NYPSC’s gas restructuring effort and a “cost mitigation reserve” of $5.6 million and $8.2 million at September 30, 2004 and 2003, respectively. The cost mitigation reserve is an accumulation of certain refunds from upstream pipeline companiescompanies. During 2005, under the terms of the 2005 rate settlement, Distribution Corporation transferred the remaining balance in a generic restructuring reserve (which had been established in a prior rate settlement) and certain credits which can be usedthe balances it had accumulated under various earnings sharing mechanisms to offset certain specific expense items.the CMR. The balance in the CMR at September 30, 2006 and 2005 amounted to $7.6 million and $7.0 million, respectively.
79
Year Ended September 30 | ||||||||||||||
2004 | 2003 | 2002 | ||||||||||||
(Thousands) | ||||||||||||||
Operating Expenses: | ||||||||||||||
Current Income Taxes — Federal | $ | 42,502 | $ | 37,335 | $ | 7,743 | ||||||||
State | 7,871 | 11,990 | 1,384 | |||||||||||
Foreign | 2,035 | 467 | 894 | |||||||||||
Deferred Income Taxes — Federal | 29,559 | 53,311 | 50,205 | |||||||||||
State | 9,620 | 12,983 | 9,968 | |||||||||||
Foreign | 1,150 | 12,075 | 1,840 | |||||||||||
92,737 | 128,161 | 72,034 | ||||||||||||
Other Income: | ||||||||||||||
Deferred Investment Tax Credit | (697 | ) | (693 | ) | (697 | ) | ||||||||
Minority Interest in Foreign Subsidiaries | 374 | (566 | ) | (277 | ) | |||||||||
Cumulative Effect of Change in Accounting | — | (354 | ) | — | ||||||||||
Total Income Taxes | $ | 92,414 | $ | 126,548 | $ | 71,060 | ||||||||
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(Thousands) | ||||||||||||
Operating Expenses: | ||||||||||||
Current Income Taxes — | ||||||||||||
Federal | $ | 65,593 | $ | 40,062 | $ | 42,679 | ||||||
State | 13,511 | 14,413 | 7,871 | |||||||||
Foreign | 2,212 | 1,503 | 206 | |||||||||
Deferred Income Taxes — | ||||||||||||
Federal | 19,111 | 27,412 | 29,559 | |||||||||
State | 9,024 | 2,280 | 9,620 | |||||||||
Foreign | (33,365 | ) | 7,308 | 4,655 | ||||||||
76,086 | 92,978 | 94,590 | ||||||||||
Other Income: | ||||||||||||
Deferred Investment Tax Credit | (697 | ) | (697 | ) | (697 | ) | ||||||
Discontinued Operations | ||||||||||||
Operations | — | 9,310 | (1,479 | ) | ||||||||
Gain on Sale | — | 1,612 | — | |||||||||
Total Income Taxes | $ | 75,389 | $ | 103,203 | $ | 92,414 | ||||||
Year Ended September 30 | ||||||||||||
2004 | 2003 | 2002 | ||||||||||
(Thousands) | ||||||||||||
U.S. | $ | 232,928 | $ | 383,695 | $ | 180,349 | ||||||
Foreign | 26,072 | (78,202 | ) | 8,394 | ||||||||
$ | 259,000 | $ | 305,493 | $ | 188,743 | |||||||
65
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Year Ended September 30 2006 2005 2004 (Thousands) U.S. $ 293,887 $ 223,113 $ 232,928 Foreign (80,407 ) 69,578 26,072 $ 213,480 $ 292,691 $ 259,000 Year Ended September 30 2004 2003 2002 (Thousands) Income Tax Expense, Computed at U.S. Federal Statutory Rate of 35% $ 90,650 $ 106,923 $ 66,060 Increase (Reduction) in Taxes Resulting from: State Income Taxes 11,369 16,232 7,379 Foreign Tax Differential (1,166 ) 3,318 (481 ) Foreign Tax Rate Reduction (5,174 ) — — Miscellaneous (3,265 ) 75 (1,898 ) Total Income Taxes $ 92,414 $ 126,548 $ 71,060 Year Ended September 30 2006 2005 2004 (Thousands) Income Tax Expense, Computed at U.S. Federal Statutory Rate of 35% $ 74,718 $ 102,442 $ 90,650 Increase in Taxes Resulting from: State Income Taxes 14,648 10,850 11,369 Foreign Tax Differential (3,718 ) (4,845 ) (1,166 ) Foreign Tax Rate Reduction — — (5,174 ) Reversal of Capital Loss Valuation Allowance (2,877 ) — — Miscellaneous (7,382 ) (5,244 ) (3,265 ) Total Income Taxes $ 75,389 $ 103,203 $ 92,414
Legislation was enacted
80
the Czech Republic. The miscellaneous amount shown above for 2006 includes a net reversal of $3.2 million relating to a tax contingency reserve.
At September 30 | |||||||||
2004 | 2003 | ||||||||
(Thousands) | |||||||||
Deferred Tax Liabilities: | |||||||||
Property, Plant and Equipment | $ | 568,114 | $ | 519,578 | |||||
Other | 37,051 | 21,532 | |||||||
Total Deferred Tax Liabilities | 605,165 | 541,110 | |||||||
Deferred Tax Assets: | |||||||||
Minimum Pension Liability Adjustment | (28,887 | ) | (48,701 | ) | |||||
Capital Loss Carryover | (12,546 | ) | (18,607 | ) | |||||
Unrealized Hedging Losses | (33,890 | ) | (4,509 | ) | |||||
Other | (74,624 | ) | (52,368 | ) | |||||
(149,947 | ) | (124,185 | ) | ||||||
Valuation Allowance | 2,877 | 6,357 | |||||||
Total Deferred Tax Assets | (147,070 | ) | (117,828 | ) | |||||
Total Net Deferred Income Taxes | $ | 458,095 | $ | 423,282 | |||||
At September 30 | ||||||||
2006 | 2005 | |||||||
(Thousands) | ||||||||
Deferred Tax Liabilities: | ||||||||
Property, Plant and Equipment | $ | 569,677 | $ | 567,850 | ||||
Other | 37,865 | 52,436 | ||||||
Total Deferred Tax Liabilities | 607,542 | 620,286 | ||||||
Deferred Tax Assets: | ||||||||
Minimum Pension Liability Adjustment | — | (58,069 | ) | |||||
Capital Loss Carryover | (8,786 | ) | (9,145 | ) | ||||
Unrealized Hedging Losses | (4,653 | ) | (75,657 | ) | ||||
Other | (82,006 | ) | (74,346 | ) | ||||
(95,445 | ) | (217,217 | ) | |||||
Valuation Allowance | — | 2,877 | ||||||
Total Deferred Tax Assets | (95,445 | ) | (214,340 | ) | ||||
Total Net Deferred Income Taxes | $ | 512,097 | $ | 405,946 | ||||
Presented as Follows: | ||||||||
Net Deferred Tax Asset — Current | $ | (23,402 | ) | $ | (83,774 | ) | ||
Net Deferred Tax Asset — Non-Current | (9,003 | ) | — | |||||
Net Deferred Tax Liability — Non-Current | 544,502 | 489,720 | ||||||
Total Net Deferred Income Taxes | $ | 512,097 | $ | 405,946 | ||||
66
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Company has undistributed earnings of foreign subsidiaries that relate to its operations in the Czech Republic. These earnings are considered to be permanently reinvested outside the United States and, accordingly, no U.S. income taxes have been provided thereon. In the event such earnings are distributed, the Company may be subject to U.S. income taxes and foreign withholding taxes, net of allowable foreign tax credits or deductions. At September 30, 2004, such undistributed earnings totaled $49.6 million. In addition, there was a $35.8 million positive cumulative translation adjustment attributable to this investment, and similarly, no U.S. income taxes have been provided thereon.
affiliate and recorded a tax of $3.8 million on such dividend.
67
81
Earnings | Accumulated | |||||||||||||||||||
Reinvested | Other | |||||||||||||||||||
Paid | in | Comprehensive | ||||||||||||||||||
Common Stock | In | the | Income | |||||||||||||||||
Shares | Amount | Capital | Business | (Loss) | ||||||||||||||||
(Thousands, except per share amounts) | ||||||||||||||||||||
Balance at September 30, 2003 | 81,438 | $ | 81,438 | $ | 478,799 | $ | 642,690 | $ | (65,537 | ) | ||||||||||
Net Income Available for Common Stock | 166,586 | |||||||||||||||||||
Dividends Declared on Common Stock ($1.10 Per Share) | (90,350 | ) | ||||||||||||||||||
Other Comprehensive Income, Net of Tax | 10,762 | |||||||||||||||||||
Common Stock Issued Under Stock and Benefit Plans(1) | 1,552 | 1,552 | 27,761 | |||||||||||||||||
Balance at September 30, 2004 | 82,990 | 82,990 | 506,560 | 718,926 | (54,775 | ) | ||||||||||||||
Net Income Available for Common Stock | 189,488 | |||||||||||||||||||
Dividends Declared on Common Stock ($1.14 Per Share) | (95,394 | ) | ||||||||||||||||||
Other Comprehensive Loss, Net of Tax | (142,853 | ) | ||||||||||||||||||
Cancellation of Shares | (2 | ) | (2 | ) | (52 | ) | ||||||||||||||
Common Stock Issued Under Stock and Benefit Plans(1) | 1,369 | 1,369 | 23,326 | |||||||||||||||||
Balance at September 30, 2005 | 84,357 | 84,357 | 529,834 | 813,020 | (197,628 | ) | ||||||||||||||
Net Income Available for Common Stock | 138,091 | |||||||||||||||||||
Dividends Declared on Common Stock ($1.18 Per Share) | (98,829 | ) | ||||||||||||||||||
Other Comprehensive Income, Net of Tax | 228,044 | |||||||||||||||||||
Share-Based Payment Expense(2) | 1,705 | |||||||||||||||||||
Common Stock Issued Under Stock and Benefit Plans(1) | 1,572 | 1,572 | 28,564 | |||||||||||||||||
Share Repurchases | (2,526 | ) | (2,526 | ) | (16,373 | ) | (66,269 | ) | ||||||||||||
Balance at September 30, 2006 | 83,403 | $ | 83,403 | $ | 543,730 | $ | 786,013 | (3) | $ | 30,416 | ||||||||||
Earnings | Accumulated | |||||||||||||||||||
Common Stock | Reinvested | Other | ||||||||||||||||||
Paid In | in the | Comprehensive | ||||||||||||||||||
Shares | Amount | Capital | Business | Income (Loss) | ||||||||||||||||
(Thousands, except per share amounts) | ||||||||||||||||||||
Balance at September 30, 2001 | 79,406 | $ | 79,406 | $ | 430,618 | $ | 513,488 | $ | (20,857 | ) | ||||||||||
Net Income Available for Common Stock | 117,682 | |||||||||||||||||||
Dividends Declared on Common Stock ($1.03 Per Share) | (81,773 | ) | ||||||||||||||||||
Other Comprehensive Loss, Net of Tax | (48,779 | ) | ||||||||||||||||||
Common Stock Issued Under Stock and Benefit Plans | 859 | 859 | 16,214 | |||||||||||||||||
Balance at September 30, 2002 | 80,265 | 80,265 | 446,832 | 549,397 | (69,636 | ) | ||||||||||||||
Net Income Available for Common Stock | 178,944 | |||||||||||||||||||
Dividends Declared on Common Stock ($1.06 Per Share) | (85,651 | ) | ||||||||||||||||||
Other Comprehensive Income, Net of Tax | 4,099 | |||||||||||||||||||
Cancellation of Shares | (3 | ) | (3 | ) | (63 | ) | ||||||||||||||
Common Stock Issued Under Stock and Benefit Plans | 1,176 | 1,176 | 32,030 | |||||||||||||||||
Balance at September 30, 2003 | 81,438 | 81,438 | 478,799 | 642,690 | (65,537 | ) | ||||||||||||||
Net Income Available for Common Stock | 166,586 | |||||||||||||||||||
Dividends Declared on Common Stock ($1.10 Per Share) | (90,350 | ) | ||||||||||||||||||
Other Comprehensive Income, Net of Tax | 10,762 | |||||||||||||||||||
Common Stock Issued Under Stock and Benefit Plans | 1,552 | 1,552 | 27,761 | |||||||||||||||||
Balance at September 30, 2004 | 82,990 | $ | 82,990 | $ | 506,560 | $ | 718,926 | (1) | $ | (54,775 | ) | |||||||||
(1) | Paid in Capital includes tax benefits of $6.5 million, $3.7 million and $1.5 million for September 30, 2006, 2005 and 2004, respectively, associated with the exercise of stock options. | |
(2) | As of October 1, 2005, Paid in Capital includes compensation costs associated with stock option and restricted stock awards, in accordance with SFAS 123R. The expense is included within Net Income Available For Common Stock, net of tax benefits. | |
(3) | The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt. At September 30, |
82
68
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Shareholder Rights Plan
83
69
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
84
Number of | ||||||||
Shares Subject | Weighted Average | |||||||
to Option | Exercise Price | |||||||
Outstanding at September 30, 2001 | 9,372,686 | $ | 21.92 | |||||
Granted in 2002(2) | 5,673,172 | $ | 22.26 | |||||
Exercised in 2002(1) | (247,910 | ) | $ | 15.76 | ||||
Forfeited in 2002 | (168,444 | ) | $ | 25.56 | ||||
Outstanding at September 30, 2002 | 14,629,504 | $ | 22.12 | |||||
Granted in 2003 | 233,500 | $ | 24.61 | |||||
Exercised in 2003(1) | (673,866 | ) | $ | 16.56 | ||||
Forfeited in 2003 | (123,800 | ) | $ | 23.55 | ||||
Outstanding at September 30, 2003 | 14,065,338 | $ | 22.41 | |||||
Granted in 2004 | 87,000 | $ | 24.95 | |||||
Exercised in 2004(1) | (1,571,794 | ) | $ | 18.29 | ||||
Forfeited in 2004 | (84,105 | ) | $ | 25.40 | ||||
Outstanding at September 30, 2004 | 12,496,439 | $ | 22.93 | |||||
Option shares exercisable at September 30, 2004 | 11,594,368 | $ | 22.83 | |||||
Option shares available for future grant at September 30, 2004(3) | 919,537 |
Weighted | ||||||||||||||||
Average | ||||||||||||||||
Number of | Remaining | Aggregate | ||||||||||||||
Shares Subject | Weighted Average | Contractual | Intrinsic | |||||||||||||
to Option | Exercise Price | Life (Years) | Value | |||||||||||||
(In thousands) | ||||||||||||||||
Outstanding at September 30, 2005 | 10,996,893 | $ | 23.78 | |||||||||||||
Granted in 2006 | 317,000 | $ | 35.21 | |||||||||||||
Exercised in 2006 | (2,292,639 | ) | $ | 21.77 | ||||||||||||
Forfeited in 2006 | (5,000 | ) | $ | 24.94 | ||||||||||||
Outstanding at September 30, 2006 | 9,016,254 | $ | 24.69 | 4.21 | $ | 105,096 | ||||||||||
Option shares exercisable at September 30, 2006 | 8,643,753 | $ | 24.32 | 4.01 | $ | 103,999 | ||||||||||
Option shares available for future grant at September 30, 2006(1) | 434,911 | |||||||||||||||
(1) | ||
Including shares available for restricted stock grants. |
2006:2004: Options Outstanding Options Exercisable Weighted Number Average Weighted Number Weighted Outstanding Remaining Average Exercisable Average Range of Exercise Price at 9/30/04 Contractual Life Exercise Price at 9/30/04 Exercise Price $13.90-$16.68 441,060 1.0 $ 14.23 441,060 $ 14.23 $16.69-$19.46 1,139,558 2.0 $ 18.38 1,139,558 $ 18.38 $19.47-$22.24 2,545,696 5.0 $ 21.26 2,432,296 $ 21.25 $22.25-$25.02 6,073,297 5.3 $ 23.34 5,354,957 $ 23.19 $25.03-$27.80 2,296,828 6.3 $ 27.63 2,226,497 $ 27.68 70 Options Outstanding Options Exercisable Weighted Number Average Weighted Number Weighted Outstanding Remaining Average Exercisable Average at Contractual Exercise at Exercise 9/30/06 Life Price 9/30/06 Price $18.55-$22.26 1,598,641 3.3 $ 21.31 1,568,641 $ 21.32 $22.27-$25.97 4,500,219 3.5 $ 23.33 4,480,718 $ 23.32 $25.98-$29.68 2,600,394 5.3 $ 27.85 2,594,394 $ 27.85 $29.69-$33.39 — — — — — $33.40-$37.10 317,000 9.6 $ 35.21 — — NATIONAL FUEL GAS COMPANYRestricted Share Awards
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The following table summarizes
85
Number of | Weighted Average | |||||||
Restricted | Fair Value per | |||||||
Share Awards | Award | |||||||
Restricted Share Awards Outstanding at September 30, 2005 | 64,928 | $ | 24.46 | |||||
Granted in 2006 | 16,000 | $ | 34.94 | |||||
Vested in 2006 | (38,600 | ) | $ | 24.43 | ||||
Restricted Share Awards Outstanding at September 30, 2006 | 42,328 | $ | 28.44 | |||||
Year Ended September 30 | ||||||||||||
2004 | 2003 | 2002 | ||||||||||
Shares of Restricted Stock Awarded | — | — | 100,000 | |||||||||
Weighted Average Market Price of Stock on Award Date | — | — | $ | 24.50 |
As of September 30, 2004, 98,528outstanding shares of non-vested restricted stock were outstanding. Vesting restrictionsat September 30, 2006 will lapse as follows: 2005 — 33,600 shares; 2006 — 34,600 shares; 2007 — 29,00025,000 shares; 2008 — 2,500 shares; 2009 — 4,500 shares; 2010 — 5,828 shares; and 20102011 — 1,3284,500 shares.
Compensation expense related to restricted stock under the Company’s stock plans was $0.7 million, $1.0 million and $0.7 million for the years ended September 30, 2004, 2003 and 2002, respectively.
Redeemable Preferred Stock
Long-Term Debt
At September 30 | |||||||||
2004 | 2003 | ||||||||
(Thousands) | |||||||||
Debentures(1): | |||||||||
7 3/4% due February 2004 | $ | — | $ | 125,000 | |||||
Medium-Term Notes(1): | |||||||||
6.0% to 7.50% due August 2004 to June 2025 | 749,000 | 849,000 | |||||||
Notes(1): | |||||||||
5.25% to 6.50% due March 2013 to September 2022(2) | 347,272 | 347,400 | |||||||
1,096,272 | 1,321,400 | ||||||||
Other Notes: | |||||||||
Secured(3) | 41,433 | 50,767 | |||||||
Unsecured | 9,872 | 17,343 | |||||||
Total Long-Term Debt | 1,147,577 | 1,389,510 | |||||||
Less Current Portion | 14,260 | 241,731 | |||||||
$ | 1,133,317 | $ | 1,147,779 | ||||||
At September 30 | ||||||||
2006 | 2005 | |||||||
(Thousands) | ||||||||
Medium-Term Notes(1): | ||||||||
6.0% to 7.50% due May 2008 to June 2025 | $ | 749,000 | $ | 749,000 | ||||
Notes(1): | ||||||||
5.25% to 6.50% due March 2013 to September 2022(2) | 346,665 | 347,222 | ||||||
1,095,665 | 1,096,222 | |||||||
Other Notes: | ||||||||
Secured(3) | 22,766 | 32,100 | ||||||
Unsecured | 169 | 83 | ||||||
Total Long-Term Debt | 1,118,600 | 1,128,405 | ||||||
Less Current Portion | 22,925 | 9,393 | ||||||
$ | 1,095,675 | $ | 1,119,012 | |||||
(1) | These | |
(2) | At September 30, |
71
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
attributable to the estates of individual note holders exercising put options due to the death of an individual note holder. | ||
(3) | These notes constitute “project financing” and are secured by the various project documentation and natural gas transportation contracts related to the Empire State Pipeline. The interest rate on these notes is a variable rate based on LIBOR. It is the Company’s intention to pay off these notes within one year. As such, the notes have been classified as current. |
86
2010.
The weighted average interest rate on notes payable to banks was 1.82% and 1.27% at September 30, 2004 and 2003, respectively. The weighted average interest rate on commercial paper was 1.85% and 1.18% at September 30, 2004 and 2003, respectively.paper.
72
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Company fails (i) to pay any scheduled principal or interest or 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.
87
Fair Values
At September 30 | ||||||||||||||||
2004 | 2004 | 2003 | 2003 | |||||||||||||
Carrying | Fair | Carrying | Fair | |||||||||||||
Amount | Value | Amount | Value | |||||||||||||
(Thousands) | ||||||||||||||||
Long-Term Debt | $ | 1,147,577 | $ | 1,199,189 | $ | 1,389,510 | $ | 1,520,606 |
At September 30 | ||||||||||||||||
2006 Carrying | 2006 Fair | 2005 Carrying | 2005 Fair | |||||||||||||
Amount | Value | Amount | Value | |||||||||||||
(Thousands) | ||||||||||||||||
Long-Term Debt | $ | 1,118,600 | $ | 1,148,089 | $ | 1,128,405 | $ | 1,181,599 |
73
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
88
At September 30, 2004, the Company, in the Exploration and Production segment, had purchased natural gas put options and sold natural gas call options extending through 2006. The call options sold by the Company cover a notional amount of 1.1 Bcf at a weighted average strike price of $8.06 per Mcf. The put options purchased by the Company cover a notional amount of 1.1 Bcf at a weighted average strike price of $5.99 per Mcf. These derivative financial instruments are accounted for as cash flow hedges. The call options are used to establish a ceiling price (the Company makes payments to the counterparty when a variable price rises above the ceiling price) for the anticipated sale of natural gas in the Exploration and Production segment. At September 30, 2004, the Company would have had to pay $1.0 million to terminate these call options. The put options are used to establish a floor price (the Company receives payment from the counterparty when a variable price falls below the floor price) for the anticipated sale of natural gas in the Exploration and Production segment. At September 30, 2004,2006, the Company would have received $0.2$0.9 million to terminate these put options.
no cost collars.
74
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
They are accounted for as fair value hedges. Theyhedges and are used by the Company’s Energy Marketing segment to hedge against rising prices, a risk to which this segment is exposed due to the fixed price gas sales commitments that it enters into with commercial and industrial customers. The remaining 0.4 Bcf is accounted for as cash flow hedges. The Company would have received $5.1had to pay $22.4 million to terminate these futures contracts at September 30, 2004.
2006.
2006.
All of the counterparties (or the parent of the counterparty) were rated as investment grade entities at September 30, 2006.
89
2006.
75
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Company recovers certain of its net periodic pension and post-retirement benefit costs in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorization. For financial reporting purposes, to the extent there is recovery in rates, the difference between the amounts of pension cost and post-retirement benefit cost recoverable in rates and the amounts of such costs as determined under applicable accounting principles is recorded as either a regulatory asset or liability, as appropriate. The regulatory treatment of a substantial amount of these regulatory assets and liabilities is governed by policy statements issued by the regulatory commissions having jurisdiction over the Utility and Pipeline and Storage segments. Pension and post-retirement benefit costs reflect the amount recovered from customers in rates during the year. Under the NYPSC’s policies, the Company segregates the amount of such costs collected in rates, but not yet contributed to the Retirement and Post-Retirement Plans, into a regulatory liability account. This liability accrues interest at the NYPSC-mandated interest rate, and this interest cost is included in pension and post-retirement benefit costs. For purposes of disclosure, the liability also remains in the disclosed pension and post-retirement benefit liability amount because it has not yet been contributed.
76
value as of the measurement date.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
as follows: Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2004 2003 2002 2004 2003 2002 (Thousands) Benefit Obligation at Beginning of Period $ 694,960 $ 625,470 $ 580,046 $ 467,418 $ 393,851 $ 304,548 Service Cost 14,598 13,043 11,639 6,027 5,844 4,658 Interest Cost 40,565 40,967 40,720 26,393 26,124 21,617 Plan Participants’ Contributions — — — 627 682 610 Amendments — — 420 — — — Actuarial (Gain) Loss (19,593 ) 51,302 28,880 (62,146 ) 57,983 76,972 Benefits Paid (36,998 ) (35,822 ) (36,235 ) (16,316 ) (17,066 ) (14,554 ) $ 693,532 $ 694,960 $ 625,470 $ 422,003 $ 467,418 $ 393,851 Fair Value of Assets at Beginning of Period $ 491,333 $ 485,927 $ 536,625 $ 166,494 $ 150,293 $ 161,959 Actual Return on Plan Assets 81,946 6,145 (29,898 ) 38,960 390 (18,181 ) Employer Contribution 37,085 35,083 15,435 39,720 32,195 20,459 Plan Participants’ Contributions — — — 627 682 610 Benefits Paid (36,998 ) (35,822 ) (36,235 ) (16,316 ) (17,066 ) (14,554 ) $ 573,366 $ 491,333 $ 485,927 $ 229,485 $ 166,494 $ 150,293 Funded Status $ (120,166 ) $ (203,627 ) $ (139,543 ) $ (192,518 ) $ (300,924 ) $ (243,558 ) Unrecognized Net Actuarial Loss 159,554 222,250 132,064 108,943 212,242 157,247 Unrecognized Transition (Asset) Obligation — — (3,716 ) 64,144 71,272 78,399 Unrecognized Prior Service Cost 9,171 10,274 11,451 20 26 30 Net Amount Recognized at End of Period $ 48,559 $ 28,897 $ 256 $ (19,411 ) $ (17,384 ) $ (7,882 ) Accrued Benefit Liability $ (91,587 ) $ (153,240 ) $ (75,116 ) $ (27,263 )* $ (23,163 )* $ (20,375 )* Prepaid Benefit Cost 14,536 10,782 10,944 7,852 5,779 12,493 Regulatory Assets 33,904 21,934 — — — — Intangible Assets 9,171 10,274 11,451 — — — Accumulated Other Comprehensive Loss (Pre-Tax) 82,535 139,147 52,977 — — — Net Amount Recognized at End of Period $ 48,559 $ 28,897 $ 256 $ (19,411 ) $ (17,384 ) $ (7,882 ) Discount Rate 6.25 % 6.00 % 6.75 % 6.25 %** 6.00 % 6.75 % Expected Return on Plan Assets 8.25 % 8.25 % 8.50 % 8.25 % 8.25 % 8.50 % Rate of Compensation Increase 6.11 % 6.11 % 6.11 % 6.11 % 6.11 % 6.11 % Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2006 2005 2004 2006 2005 2004 (Thousands) Benefit Obligation at Beginning of Period $ 825,204 $ 693,532 $ 694,960 $ 546,273 $ 422,003 $ 467,418 Service Cost 16,416 13,714 14,598 8,029 6,153 6,027 Interest Cost 40,196 42,079 40,565 26,804 25,783 26,393 Plan Participants’ Contributions — — — 1,559 1,017 627 Actuarial (Gain) Loss (108,112 ) 115,128 (19,593 ) (115,052 ) 110,663 (62,146 ) Benefits Paid (41,497 ) (39,249 ) (36,998 ) (21,682 ) (19,346 ) (16,316 ) $ 732,207 $ 825,204 $ 693,532 $ 445,931 $ 546,273 $ 422,003
90
Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2006 2005 2004 2006 2005 2004 (Thousands) Fair Value of Assets at Beginning of Period $ 616,462 $ 573,366 $ 491,333 $ 271,636 $ 229,485 $ 166,494 Actual Return on Plan Assets 68,649 56,201 81,946 34,785 20,577 38,960 Employer Contribution 20,907 26,144 37,085 39,326 39,903 39,720 Plan Participants’ Contributions — — — 1,559 1,017 627 Benefits Paid (41,497 ) (39,249 ) (36,998 ) (21,682 ) (19,346 ) (16,316 ) $ 664,521 $ 616,462 $ 573,366 $ 325,624 $ 271,636 $ 229,485 Funded Status $ (67,686 ) $ (208,742 ) $ (120,166 ) $ (120,307 ) $ (274,637 ) $ (192,518 ) Unrecognized Net Actuarial Loss 107,626 257,553 159,554 54,487 205,423 108,943 Unrecognized Transition Obligation — — — 49,890 57,017 64,144 Unrecognized Prior Service Cost 7,185 8,142 9,171 12 17 20 Net Amount Recognized at End of Period $ 47,125 $ 56,953 $ 48,559 $ (15,918 ) $ (12,180 ) $ (19,411 ) Accrued Benefit Liability $ — $ (117,103 ) $ (43,147 ) $ (32,918 ) $ (26,584 ) $ (27,263 ) Prepaid Benefit Cost 47,125 — — 17,000 14,404 7,852 Intangible Assets — 8,142 9,171 — — — Accumulated Other Comprehensive Loss (Pre-Tax) — 165,914 82,535 — — — Net Amount Recognized at End of Period $ 47,125 $ 56,953 $ 48,559 $ (15,918 ) $ (12,180 ) $ (19,411 ) Discount Rate 6.25 % 5.00 % 6.25 % 6.25 % 5.00 % 6.25 %* Expected Return on Plan Assets 8.25 % 8.25 % 8.25 % 8.25 % 8.25 % 8.25 % Rate of Compensation Increase 5.00 % 5.00 % 5.00 % 5.00 % 5.00 % 5.00 % Service Cost $ 16,416 $ 13,714 $ 14,598 $ 8,029 $ 6,153 $ 6,027 Interest Cost 40,196 42,079 40,565 26,804 25,783 26,393 Expected Return on Plan Assets (49,943 ) (49,545 ) (48,281 ) (22,302 ) (18,862 ) (14,898 ) Amortization of Prior Service Cost 957 1,029 1,103 4 4 4 Amortization of Transition Amount — — — 7,127 7,127 7,127 Recognition of Actuarial Loss 23,108 10,473 9,438 23,402 12,467 17,092 Net Amortization and Deferral for Regulatory Purposes (6,409 ) 1,988 722 (11,084 ) (410 ) (9,731 ) Net Periodic Benefit Cost $ 24,325 $ 19,738 $ 18,145 $ 31,980 $ 32,262 $ 32,014 Other Comprehensive (Income) Loss (Pre-Tax) Attributable to Change In Additional Minimum Liability Recognition $ (165,914 ) $ 83,379 $ (56,612 ) $ — $ — $ —
91
Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2006 2005 2004 2006 2005 2004 (Thousands) Discount Rate 5.00 % 6.25 % 6.00 % 5.00 % 6.25 % 6.25 %* Expected Return on Plan Assets 8.25 % 8.25 % 8.25 % 8.25 % 8.25 % 8.25 % Rate of Compensation Increase 5.00 % 5.00 % 5.00 % 5.00 % 5.00 % 5.00 %
* |
The weighted average discount rate was 6.0% through 12/8/2003. Subsequent to 12/8/2003, the discount rate used was 6.25%. |
77
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Retirement Plan | Other Post-Retirement Benefits | |||||||||||||||||||||||
Year Ended September 30 | Year Ended September 30 | |||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | |||||||||||||||||||
(Thousands) | ||||||||||||||||||||||||
Components of Net Periodic Benefit Cost | ||||||||||||||||||||||||
Service Cost | $ | 14,598 | $ | 13,043 | $ | 11,639 | $ | 6,027 | $ | 5,844 | $ | 4,658 | ||||||||||||
Interest Cost | 40,565 | 40,967 | 40,720 | 26,393 | 26,124 | 21,617 | ||||||||||||||||||
Expected Return on Plan Assets | (48,281 | ) | (47,260 | ) | (48,454 | ) | (14,898 | ) | (12,268 | ) | (13,551 | ) | ||||||||||||
Amortization of Prior Service Cost | 1,103 | 1,176 | 1,205 | 4 | 4 | 4 | ||||||||||||||||||
Amortization of Transition Amount | — | (3,716 | ) | (3,716 | ) | 7,127 | 7,127 | 7,127 | ||||||||||||||||
Recognition of Actuarial (Gain) or Loss | 9,438 | 2,231 | (1,061 | ) | 17,092 | 14,866 | 4,289 | |||||||||||||||||
Net Amortization and Deferral for Regulatory Purposes | 722 | 3,781 | 7,379 | (9,731 | ) | (15,423 | ) | (729 | ) | |||||||||||||||
Net Periodic Benefit Cost | $ | 18,145 | $ | 10,222 | $ | 7,712 | $ | 32,014 | $ | 26,274 | $ | 23,415 | ||||||||||||
Other Comprehensive (Income) Loss (Pre-Tax) Attributable to Change in Additional Minimum Liability Recognition | $ | (56,612 | ) | $ | 86,170 | $ | 52,977 | $ | — | $ | — | $ | — | |||||||||||
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 | ||||||||||||||||||||||||
Discount Rate | 6.00 | % | 6.75 | % | 7.25 | % | 6.25 | %* | 6.75 | % | 7.25 | % | ||||||||||||
Expected Return on Plan Assets | 8.25 | % | 8.50 | % | 8.50 | % | 8.25 | % | 8.50 | % | 8.50 | % | ||||||||||||
Rate of Compensation Increase | 6.11 | % | 6.11 | % | 6.11 | % | 6.11 | % | 6.11 | % | 6.11 | % |
discount rate change for the Retirement Plan in 2005 was to increase the projected benefit obligation by $113.0 million. The discount rate change for the Retirement Plan in 2004 caused the projected benefit obligation to decrease by $20.2 million.No. 87, “Employers’ Accounting for Pensions,” the Company recorded an additional minimum pension liability at September 30, 2004, 20032005 and 20022004 representing the excess of the accumulated benefit obligation over the fair value of plan assets plus accrued amounts previously recorded. An intangible asset, as shown in the table above, has offset the additional liability to the extent of previously Unrecognized Prior Service Cost. The amount in excess of Unrecognized Prior Service Cost iswas recorded net of the related tax benefit as accumulated other comprehensive loss. The pre-tax amount ofAt September 30, 2006, the Company reversed the additional minimum pension liability, intangible asset and accumulated other comprehensive loss isrecorded in prior years since the fair value of the plan assets exceeded the accumulated benefit obligation at September 30, 2006. The pre-tax amounts of the change in accumulated other comprehensive (income) loss at September 30, 2006, 2005 and 2004 are shown in the table above. The projected benefit obligation, accumulated benefit obligation and fair value of assets for the retirement plan were as follows: 2004 2003 2002 Projected Benefit Obligation $ 693,532 $ 694,960 $ 625,470 Accumulated Benefit Obligation $ 616,513 $ 611,858 $ 550,099 Fair Value of Plan Assets $ 573,366 $ 491,333 $ 485,927 2006 2005 2004 Projected Benefit Obligation $ 732,207 $ 825,204 $ 693,532 Accumulated Benefit Obligation $ 660,026 $ 733,565 $ 616,513 Fair Value of Plan Assets $ 664,520 $ 616,462 $ 573,366 2004,2006 was to decrease the projected benefit obligation by $20.2 million. The effects of the discount rate changes in 2003 and 2002 were to increase the Benefit Obligation of the Retirement Plan by $57.4 million and $34.0 million as$113.1 million. The effect of the end of each period, respectively.$37.1$20.9 million to the Retirement Plan during the year ended September 30, 2004.2006. The Company expects that the annual contribution to the Retirement Plan in 20052007 will be in the range of $25.0$15.0 million to $35.0$20.0 million. The following benefit payments, which reflect expected future service, are expected to be paid during the next five years and the five years thereafter: $45.2 million in 2007; $46.1 million in 2008; $47.3 million in 2009; $48.7 million in 2010; $50.0 million in 2011; and $275.6 million in the five years thereafter.
7892
$40.5
2004, respectively.
93
Effect of Subsidy | ||||
Service Cost | $ | (286,527 | ) | |
Interest Cost | (1,500,001 | ) | ||
Net Amortization and Deferral of Actuarial (Gain) Loss | (2,372,270 | ) | ||
Net Periodic Post-Retirement Benefit Cost | $ | (4,158,798 | ) | |
The estimated gross amount of subsidy receipts is as follows:
First Year | $ | — | ||
Second Year | $ | (649,599 | ) | |
Third Year | $ | (1,475,809 | ) | |
Fourth Year | $ | (1,672,331 | ) | |
Fifth Year | $ | (1,861,515 | ) | |
Next Five Years | $ | (11,935,959 | ) |
79
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Act for 2004. Effective July 1, 2004, the Medicare Part B Reimbursement trend assumption was changed. The effect of this change was to decrease the Accumulated Post-Retirement Benefit Obligationother post-retirement benefit obligation by $3.5 million for 2004.
follows:
Benefit Payments | Subsidy Receipts | |||||||
First Year | $ | 22,994,788 | $ | (1,475,584 | ) | |||
Second Year | $ | 24,993,192 | $ | (1,712,545 | ) | |||
Third Year | $ | 26,857,371 | $ | (1,959,704 | ) | |||
Fourth Year | $ | 28,913,929 | $ | (2,191,014 | ) | |||
Fifth Year | $ | 30,877,647 | $ | (2,413,305 | ) | |||
Next Five Years | $ | 175,465,690 | $ | (15,964,373 | ) |
2016.
Percentage of Plan | ||||||||||||||||
Assets at | ||||||||||||||||
September 30 | ||||||||||||||||
Target Allocation | ||||||||||||||||
Asset Category | 2005 | 2004 | 2003 | 2002 | ||||||||||||
Equity Securities | 60-65% | 61 | % | 53 | % | 55 | % | |||||||||
Fixed Income Securities | 25-30% | 28 | % | 32 | % | 29 | % | |||||||||
Other | 10-15% | 11 | % | 15 | % | 16 | % | |||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
Percentage of Plan | ||||||||||||||||
Target Allocation | Assets at September 30 | |||||||||||||||
Asset Category | 2007 | 2006 | 2005 | 2004 | ||||||||||||
Equity Securities | 60-75 | % | 67 | % | 63 | % | 61 | % | ||||||||
Fixed Income Securities | 20-35 | % | 26 | % | 28 | % | 28 | % | ||||||||
Other | 0-15 | % | 7 | % | 9 | % | 11 | % | ||||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||
80
94
post-retirement planPost-Retirement Plan weighted average asset allocations at September 30, 2004, 20032006, 2005 and 20022004 by asset category are as follows: Percentage of Plan Assets at September 30 Target Allocation Asset Category 2005 2004 2003 2002 Equity Securities 93% 91 % 85 % 90 % Fixed Income Securities 3% 1 % 1 % 0 % Other 4% 8 % 14 % 10 % Total 100 % 100 % 100 % Percentage of Plan Target Allocation Assets at September 30 2007 2006 2005 2004 Equity Securities 85-100 % 93 % 92 % 91 % Fixed Income Securities 0-15 % 1 % 2 % 1 % Other 0-15 % 6 % 6 % 8 % Total 100 % 100 % 100 % pensionRetirement Plan trust and the Post-Retirement Plan VEBA trusts is to achieve the target total return in accordance with the Company’s risk tolerance. Assets are diversified utilizing a mix of equities, fixed income and other securities (including real estate). Risk tolerance is established through consideration of plan liabilities, plan funded status and corporate financial condition.GH — Commitments and ContingenciesEnvironmental Matters
95
81
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(ii) Third Party Waste Disposal Sites
(iii) Other
96
Year Ended September 30 | ||||||||
2005 | 2004 | |||||||
(Thousands) | ||||||||
Operating Revenues | $ | 124,840 | $ | 123,425 | ||||
Operating Expenses | 103,155 | 112,178 | ||||||
Operating Income | 21,685 | 11,247 | ||||||
Other Income | 2,048 | 1,992 | ||||||
Interest Expense | (558 | ) | (838 | ) | ||||
Income before Income Taxes and Minority Interest | 23,175 | 12,401 | ||||||
Income Tax Expense | 10,331 | (1,853 | ) | |||||
Minority Interest, Net of Taxes | 2,645 | 1,933 | ||||||
Income from Discontinued Operations | 10,199 | 12,321 | ||||||
Gain on Disposal, Net of Taxes of $1,612 | 25,774 | — | ||||||
Income from Discontinued Operations | $ | 35,973 | $ | 12,321 |
82
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
February 6, 2003 (see Note J — Acquisitions).Empire. Supply Corporation transports and stores natural gas for utilities (including Distribution Corporation), natural gas marketers (including NFR) and pipeline companies in the northeastern United States markets. Empire transports natural gas from the United States/Canadian border near Buffalo, New York into Central New York just north of Syracuse, New York. Empire
97
The International segment’s operations are carried out by Horizon. Horizon engages in foreign energy projects through the investment of its indirect subsidiariesproceeds, as the sole or partial owner of various business entities. Horizon’s current emphasis is the Czech Republic, where, through its subsidiaries, it owns majority interests in companies having district heating and power generation plantsshown in the northern Bohemia region.
table below for the year ended September 30, 2004.
million, as shown in the table for the year ended September 30, 2004.
83
98
Year Ended September 30, 2004 | ||||||||||||||||||||||||||||||||||||||||
Pipeline | Exploration | Total | Corporate and | |||||||||||||||||||||||||||||||||||||
and | and | Energy | Reportable | Intersegment | Total | |||||||||||||||||||||||||||||||||||
Utility | Storage | Production | International | Marketing | Timber | Segments | All Other | Eliminations | Consolidated | |||||||||||||||||||||||||||||||
(Thousands) | ||||||||||||||||||||||||||||||||||||||||
Revenue from External Customers | $ | 1,137,288 | $ | 122,970 | $ | 293,698 | $ | 123,425 | $ | 284,349 | $ | 55,968 | $ | 2,017,698 | $ | 13,695 | $ | — | $ | 2,031,393 | ||||||||||||||||||||
Intersegment Revenues | $ | 15,353 | $ | 86,737 | $ | — | $ | — | $ | — | $ | 2 | $ | 102,092 | $ | — | $ | (102,092 | ) | $ | — | |||||||||||||||||||
Interest Expense | $ | 21,945 | $ | 10,933 | $ | 50,642 | $ | 7,080 | $ | 33 | $ | 2,218 | $ | 92,851 | $ | 919 | $ | (3,180 | ) | $ | 90,590 | |||||||||||||||||||
Depreciation, Depletion and Amortization | $ | 39,101 | $ | 37,345 | $ | 89,943 | $ | 15,257 | $ | 102 | $ | 6,277 | $ | 188,025 | $ | 1,071 | $ | 442 | $ | 189,538 | ||||||||||||||||||||
Income Tax Expense | $ | 31,393 | $ | 30,968 | $ | 28,899 | $ | (6,137) | $ | 3,964 | $ | 3,320 | $ | 92,407 | $ | 829 | $ | (499 | ) | $ | 92,737 | |||||||||||||||||||
Significant Item: | ||||||||||||||||||||||||||||||||||||||||
Loss on Sale of Timber Properties | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 1,252 | $ | 1,252 | $ | — | $ | — | $ | 1,252 | ||||||||||||||||||||
Significant Item: | ||||||||||||||||||||||||||||||||||||||||
Gain on Sale of Oil and Gas Producing Properties | $ | — | $ | — | $ | 4,645 | $ | — | $ | — | $ | — | $ | 4,645 | $ | — | $ | — | $ | 4,645 | ||||||||||||||||||||
Segment Profit (Loss): | ||||||||||||||||||||||||||||||||||||||||
Net Income | $ | 46,718 | $ | 47,726 | $ | 54,344 | $ | 5,982 | $ | 5,535 | $ | 5,637 | $ | 165,942 | $ | 1,530 | $ | (886 | ) | $ | 166,586 | |||||||||||||||||||
Expenditures for Additions to Long-Lived Assets | $ | 55,449 | $ | 23,196 | $ | 77,654 | $ | 7,498 | $ | 10 | $ | 2,823 | $ | 166,630 | $ | 200 | $ | 5,511 | $ | 172,341 | ||||||||||||||||||||
At September 30, 2004 | ||||||||||||||||||||||||||||||||||||||||
(Thousands) | ||||||||||||||||||||||||||||||||||||||||
Segment Assets | $ | 1,390,361 | $ | 777,800 | $ | 1,039,524 | $ | 268,119 | $ | 65,971 | $ | 143,101 | $ | 3,684,876 | $ | 73,583 | $ | (46,661 | ) | $ | 3,711,798 |
Year Ended September 30, 2006 Corporate Pipeline Exploration Total and and and Energy Reportable All Intersegment Total Utility Storage Production Marketing Timber Segments Other Eliminations Consolidated (Thousands) Revenue from External Customers $ 1,265,695 $ 132,921 $ 346,880 $ 497,069 $ 65,024 $ 2,307,589 $ 3,304 $ 766 $ 2,311,659 Intersegment Revenues �� $ 15,068 $ 81,431 $ — $ — $ 5 $ 96,504 $ 9,444 $ (105,948 ) $ — Interest Income $ 4,889 $ 454 $ 8,682 $ 445 $ 747 $ 15,217 $ 22 $ (4,964 ) $ 10,275 Interest Expense $ 26,174 $ 6,620 $ 50,457 $ 227 $ 3,095 $ 86,573 $ 2,555 $ (10,547 ) $ 78,581 Depreciation, Depletion and Amortization $ 40,172 $ 36,876 $ 94,738 $ 53 $ 6,495 $ 178,334 $ 789 $ 492 $ 179,615 Income Tax Expense (Benefit) $ 35,699 $ 33,896 $ (2,808 ) $ 3,748 $ 3,277 $ 73,812 $ 969 $ 1,305 $ 76,086 Income from Unconsolidated Subsidiaries $ — $ — $ — $ — $ — $ — $ 3,583 $ — $ 3,583 Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties $ — $ — $ 104,739 $ — $ — $ 104,739 $ — $ — $ 104,739 Segment Profit (Loss): Net Income (Loss) $ 49,815 $ 55,633 $ 20,971 $ 5,798 $ 5,704 $ 137,921 $ 359 $ (189 ) $ 138,091 Expenditures for Additions to Long-Lived Assets $ 54,414 $ 26,023 $ 208,303 $ 16 $ 2,323 $ 291,079 $ 85 $ 2,995 $ 294,159 At September 30, 2006 (Thousands) Segment Assets $ 1,471,422 $ 767,889 $ 1,209,969 $ 78,977 $ 159,421 $ 3,687,678 $ 64,287 $ (17,634 ) $ 3,734,331
Year Ended September 30, 2005 | ||||||||||||||||||||||||||||||||||||
Corporate | ||||||||||||||||||||||||||||||||||||
Pipeline | Exploration | Total | and | |||||||||||||||||||||||||||||||||
and | and | Energy | Reportable | All | Intersegment | Total | ||||||||||||||||||||||||||||||
Utility | Storage | Production | Marketing | Timber | Segments | Other | Eliminations | Consolidated | ||||||||||||||||||||||||||||
(Thousands) | ||||||||||||||||||||||||||||||||||||
Revenue from External Customers | $ | 1,101,572 | $ | 132,805 | $ | 293,425 | $ | 329,714 | $ | 61,285 | $ | 1,918,801 | $ | 4,748 | $ | — | $ | 1,923,549 | ||||||||||||||||||
Intersegment Revenues | $ | 15,495 | $ | 83,054 | $ | — | $ | — | $ | 1 | $ | 98,550 | $ | 8,606 | $ | (107,156 | ) | $ | — | |||||||||||||||||
Interest Income | $ | 4,111 | $ | 76 | $ | 4,661 | $ | 783 | $ | 438 | $ | 10,069 | $ | 19 | $ | (3,592 | ) | $ | 6,496 | |||||||||||||||||
Interest Expense | $ | 22,900 | $ | 7,128 | $ | 48,856 | $ | 11 | $ | 2,764 | $ | 81,659 | $ | 1,726 | $ | (1,072 | ) | $ | 82,313 | |||||||||||||||||
Depreciation, Depletion and Amortization | $ | 40,159 | $ | 38,050 | $ | 90,912 | $ | 41 | $ | 6,601 | $ | 175,763 | $ | 3,537 | $ | 467 | $ | 179,767 | ||||||||||||||||||
Income Tax Expense (Benefit) | $ | 23,102 | $ | 39,068 | $ | 28,353 | $ | 3,210 | $ | 2,271 | $ | 96,004 | $ | (1,425 | ) | $ | (1,601 | ) | $ | 92,978 | ||||||||||||||||
Income from Unconsolidated Subsidiaries | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 3,362 | $ | — | $ | 3,362 | ||||||||||||||||||
Significant Non-Cash Item: | ||||||||||||||||||||||||||||||||||||
Impairment of Investment in Partnership | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | (4,158 | )(1) | $ | — | $ | (4,158 | ) | ||||||||||||||||
Segment Profit (Loss): Income (Loss) from Continuing Operations | $ | 39,197 | $ | 60,454 | $ | 50,659 | $ | 5,077 | $ | 5,032 | $ | 160,419 | $ | (2,616 | ) | $ | (4,288 | ) | $ | 153,515 | ||||||||||||||||
Expenditures for Additions to Long-Lived Assets from Continuing Operations | $ | 50,071 | $ | 21,099 | $ | 122,450 | $ | 58 | $ | 18,894 | $ | 212,572 | $ | 463 | $ | 618 | $ | 213,653 |
At September 30, 2005 | ||||||||||||||||||||||||||||||||||||
(Thousands) | ||||||||||||||||||||||||||||||||||||
Segment Assets | $ | 1,401,128 | $ | 782,546 | $ | 1,213,525 | $ | 90,468 | $ | 162,052 | $ | 3,649,719 | $ | 73,354 | $ | 2,209 | $ | 3,725,282 |
8499
Year Ended September 30, 2003 | ||||||||||||||||||||||||||||||||||||||||
Pipeline | Exploration | Total | Corporate and | |||||||||||||||||||||||||||||||||||||
and | and | Energy | Reportable | Intersegment | Total | |||||||||||||||||||||||||||||||||||
Utility | Storage | Production | International | Marketing | Timber | Segments | All Other | Eliminations | Consolidated | |||||||||||||||||||||||||||||||
(Thousands) | ||||||||||||||||||||||||||||||||||||||||
Revenue from External Customers | $ | 1,145,336 | $ | 106,499 | $ | 305,314 | $ | 114,070 | $ | 304,660 | $ | 56,226 | $ | 2,032,105 | $ | 3,366 | $ | — | $ | 2,035,471 | ||||||||||||||||||||
Intersegment Revenues | $ | 17,647 | $ | 94,921 | $ | — | $ | — | $ | — | $ | — | $ | 112,568 | $ | — | $ | (112,568 | ) | $ | — | |||||||||||||||||||
Interest Expense | $ | 29,122 | $ | 14,000 | $ | 53,326 | $ | 8,700 | $ | 33 | $ | 2,507 | $ | 107,688 | $ | 521 | $ | (3,153 | ) | $ | 105,056 | |||||||||||||||||||
Depreciation, Depletion and Amortization | $ | 38,186 | $ | 35,940 | $ | 99,292 | $ | 13,910 | $ | 117 | $ | 7,543 | $ | 194,988 | $ | 238 | $ | — | $ | 195,226 | ||||||||||||||||||||
Income Tax Expense | $ | 36,857 | $ | 30,863 | $ | (17,537 | ) | $ | 876 | $ | 3,350 | $ | 72,692 | $ | 127,101 | $ | 279 | $ | 781 | $ | 128,161 | |||||||||||||||||||
Significant Item: | ||||||||||||||||||||||||||||||||||||||||
Gain on Sale of Timber Properties | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 168,787 | $ | 168,787 | $ | — | $ | — | $ | 168,787 | ||||||||||||||||||||
Significant Item: | ||||||||||||||||||||||||||||||||||||||||
Loss on Sale of Oil and Gas Producing Properties | $ | — | $ | — | $ | 58,472 | $ | — | $ | — | $ | — | $ | 58,472 | $ | — | $ | — | $ | 58,472 | ||||||||||||||||||||
Significant Non-Cash Item: | ||||||||||||||||||||||||||||||||||||||||
Impairment of Oil and Gas Producing Properties | $ | — | $ | — | $ | 42,774 | $ | — | $ | — | $ | — | $ | 42,774 | $ | — | $ | — | $ | 42,774 | ||||||||||||||||||||
Segment Profit (Loss): | ||||||||||||||||||||||||||||||||||||||||
Income Before Cumulative Effect of Changes in Accounting | $ | 56,808 | $ | 45,230 | $ | (31,293 | ) | $ | (1,368 | ) | $ | 5,868 | $ | 112,450 | $ | 187,695 | $ | 193 | $ | (52 | ) | $ | 187,836 | |||||||||||||||||
Expenditures for Additions to Long-Lived Assets | $ | 49,944 | $ | 199,327 | $ | 75,837 | $ | 2,499 | $ | 164 | $ | 3,493 | $ | 331,264 | $ | 48,293 | (1) | $ | 1,883 | $ | 381,440 | |||||||||||||||||||
At September 30, 2003 | ||||||||||||||||||||||||||||||||||||||||
(Thousands) | ||||||||||||||||||||||||||||||||||||||||
Segment Assets | $ | 1,411,808 | $ | 812,846 | $ | 969,512 | $ | 247,721 | $ | 54,134 | $ | 125,915 | $ | 3,621,936 | $ | 77,195 | $ | 19,929 | $ | 3,719,060 |
(1) | Amount represents the impairment in the value of the Company’s 50% investment in ESNE, a partnership that owns an 80-megawatt, combined cycle, natural gas-fired power plant in the town of North East, Pennsylvania. |
Year Ended September 30, 2004 | ||||||||||||||||||||||||||||||||||||
Pipeline | Exploration | Total | Corporate and | |||||||||||||||||||||||||||||||||
and | and | Energy | Reportable | All | Intersegment | Total | ||||||||||||||||||||||||||||||
Utility | Storage | Production | Marketing | Timber | Segments | Other | Eliminations | Consolidated | ||||||||||||||||||||||||||||
(Thousands) | ||||||||||||||||||||||||||||||||||||
Revenue from External Customers | $ | 1,137,288 | $ | 122,970 | $ | 293,698 | $ | 284,349 | $ | 55,968 | $ | 1,894,273 | $ | 13,695 | $ | — | $ | 1,907,968 | ||||||||||||||||||
Intersegment Revenues | $ | 15,353 | $ | 86,737 | $ | — | $ | — | $ | 2 | $ | 102,092 | $ | — | $ | (102,092 | ) | $ | — | |||||||||||||||||
Interest Income | $ | 552 | $ | 217 | $ | 1,831 | $ | 521 | $ | 312 | $ | 3,433 | $ | 15 | $ | (1,677 | ) | $ | 1,771 | |||||||||||||||||
Interest Expense | $ | 21,945 | $ | 10,933 | $ | 50,642 | $ | 33 | $ | 2,218 | $ | 85,771 | $ | 919 | $ | 3,062 | $ | 89,752 | ||||||||||||||||||
Depreciation, Depletion and Amortization | $ | 39,101 | $ | 37,345 | $ | 89,943 | $ | 102 | $ | 6,277 | $ | 172,768 | $ | 1,071 | $ | 450 | $ | 174,289 | ||||||||||||||||||
Income Tax Expense (Benefit) | $ | 31,393 | $ | 30,968 | $ | 28,899 | $ | 3,964 | $ | 3,320 | $ | 98,544 | $ | 829 | $ | (4,783 | ) | $ | 94,590 | |||||||||||||||||
Income from Unconsolidated Subsidiaries | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 805 | $ | — | $ | 805 | ||||||||||||||||||
Significant Item: | ||||||||||||||||||||||||||||||||||||
Loss on Sale of Timber Properties | $ | — | $ | — | $ | — | $ | — | $ | 1,252 | $ | 1,252 | $ | — | $ | — | $ | 1,252 | ||||||||||||||||||
Significant Item: | ||||||||||||||||||||||||||||||||||||
Gain on Sale of Oil and Gas Producing Properties | $ | — | $ | — | $ | 4,645 | $ | — | $ | — | $ | 4,645 | $ | — | $ | — | $ | 4,645 | ||||||||||||||||||
Segment Profit (Loss): Income (Loss) from Continuing Operations | $ | 46,718 | $ | 47,726 | $ | 54,344 | $ | 5,535 | $ | 5,637 | $ | 159,960 | $ | 1,530 | $ | (7,225 | ) | $ | 154,265 | |||||||||||||||||
Expenditures for Additions to Long-Lived Assets from Continuing Operations | $ | 55,449 | $ | 23,196 | $ | 77,654 | $ | 10 | $ | 2,823 | $ | 159,132 | $ | 200 | $ | 5,511 | $ | 164,843 |
At September 30, 2004 | ||||||||||||||||||||||||||||||||||||
(Thousands) | ||||||||||||||||||||||||||||||||||||
Segment Assets | $ | 1,355,964 | $ | 783,145 | $ | 1,078,217 | $ | 68,599 | $ | 140,992 | $ | 3,426,917 | $ | 77,013 | $ | 213,673 | (1) | $ | 3,717,603 |
(1) | Amount includes |
For the Year Ended September 30 | ||||||||||||
Geographic Information | 2006 | 2005 | 2004 | |||||||||
(Thousands) | ||||||||||||
Revenues from External Customers (1): | ||||||||||||
United States | $ | 2,242,155 | $ | 1,860,684 | $ | 1,867,335 | ||||||
Canada | 69,504 | 62,865 | 40,633 | |||||||||
$ | 2,311,659 | $ | 1,923,549 | $ | 1,907,968 | |||||||
85
100
Year Ended September 30, 2002 | |||||||||||||||||||||||||||||||||||||||||
Pipeline | Exploration | Total | Corporate and | ||||||||||||||||||||||||||||||||||||||
and | and | Energy | Reportable | Intersegment | Total | ||||||||||||||||||||||||||||||||||||
Utility | Storage | Production | International | Marketing | Timber | Segments | All Other | Eliminations | Consolidated | ||||||||||||||||||||||||||||||||
(Thousands) | |||||||||||||||||||||||||||||||||||||||||
Revenue from External Customers | $ | 776,577 | $ | 80,165 | $ | 310,980 | $ | 95,315 | $ | 151,257 | $ | 47,407 | $ | 1,461,701 | $ | 2,795 | $ | — | $ | 1,464,496 | |||||||||||||||||||||
Intersegment Revenues | $ | 17,644 | $ | 87,219 | $ | — | $ | — | $ | — | $ | — | $ | 104,863 | $ | 7,340 | $ | (112,203 | ) | $ | — | ||||||||||||||||||||
Interest Expense | $ | 30,790 | $ | 10,424 | $ | 55,367 | $ | 8,045 | $ | 76 | $ | 2,896 | $ | 107,598 | $ | 420 | $ | (2,366 | ) | $ | 105,652 | ||||||||||||||||||||
Depreciation, Depletion and Amortization | $ | 37,412 | $ | 23,626 | $ | 103,946 | $ | 11,977 | $ | 161 | $ | 3,429 | $ | 180,551 | $ | 115 | $ | 2 | $ | 180,668 | |||||||||||||||||||||
Income Tax Expense | $ | 31,657 | $ | 18,148 | $ | 15,108 | $ | (2,030 | ) | $ | 5,103 | $ | 4,476 | $ | 72,462 | $ | (473 | ) | $ | 45 | $ | 72,034 | |||||||||||||||||||
Significant Non-Cash Item: | |||||||||||||||||||||||||||||||||||||||||
Impairment of Investment in Partnership | $ | — | $ | 15,167 | $ | — | $ | — | $ | — | $ | — | $ | 15,167 | $ | — | $ | — | $ | 15,167 | |||||||||||||||||||||
Segment Profit (Loss): Net Income | $ | 49,505 | $ | 29,715 | $ | 26,851 | $ | (4,443 | ) | $ | 8,642 | $ | 9,689 | $ | 119,959 | $ | (885 | ) | $ | (1,392 | ) | $ | 117,682 | ||||||||||||||||||
Expenditures for Additions to Long-Lived Assets | $ | 51,550 | $ | 30,329 | $ | 114,602 | $ | 4,244 | $ | 51 | $ | 25,574 | $ | 226,350 | $ | 6,554 | $ | — | $ | 232,904 | |||||||||||||||||||||
At September 30, 2002 | |||||||||||||||||||||||||||||||||||||||||
(Thousands) | |||||||||||||||||||||||||||||||||||||||||
Segment Assets | $ | 1,248,426 | $ | 532,543 | $ | 1,161,310 | $ | 241,466 | $ | 52,850 | $ | 131,721 | $ | 3,368,316 | $ | 33,563 | $ | (570 | ) | $ | 3,401,309 | ||||||||||||||||||||
86
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Year Ended September 30 | ||||||||||||
Geographic Information | 2004 | 2003 | 2002 | |||||||||
(Thousands) | ||||||||||||
Revenues from External Customers(1): | ||||||||||||
United States | $ | 1,867,335 | $ | 1,818,980 | $ | 1,293,239 | ||||||
Czech Republic | 123,425 | 114,070 | 95,315 | |||||||||
Canada | 40,633 | 102,421 | 75,942 | |||||||||
$ | 2,031,393 | $ | 2,035,471 | $ | 1,464,496 | |||||||
At September 30 | ||||||||||||
(Thousands) | ||||||||||||
Long-Lived Assets: | ||||||||||||
United States | $ | 2,967,277 | $ | 2,975,329 | $ | 2,621,001 | ||||||
Czech Republic | 228,179 | 219,695 | 216,044 | |||||||||
Canada | 143,042 | 116,655 | 258,196 | |||||||||
$ | 3,338,498 | $ | 3,311,679 | $ | 3,095,241 | |||||||
At September 30 2006 2005 2004 (Thousands) United States $ 3,117,644 $ 2,978,680 $ 2,941,779 Canada 97,234 171,196 143,042 Assets of Discontinued Operations — — 228,179 $ 3,214,878 $ 3,149,876 $ 3,313,000
(1) | Revenue is based upon the country in which the sale originates. |
At September 30 | ||||||||
2004 | 2003 | |||||||
(Thousands) | ||||||||
ESNE | $ | 10,045 | $ | 11,113 | ||||
Seneca Energy | 5,169 | 4,445 | ||||||
Model City | 1,230 | 867 | ||||||
$ | 16,444 | $ | 16,425 | |||||
At September 30 | ||||||||
2006 | 2005 | |||||||
(Thousands) | ||||||||
ESNE | $ | 4,486 | $ | 5,298 | ||||
Seneca Energy | 5,366 | 5,839 | ||||||
Model City | 1,738 | 1,521 | ||||||
$ | 11,590 | $ | 12,658 | |||||
Note J — Acquisitions101
On February 6, 2003, the Company acquired Empire from a subsidiary of Duke Energy Corporation for $189.2 million in cash (including cash acquired) plus $57.8 million of project debt. Empire’s results of operations were incorporated into the Company’s consolidated financial statements for the period subsequent to the completion of the acquisition on February 6, 2003. Empire is a 157-mile, 24-inch pipeline that begins at the United States/ Canadian border at the Niagara River near Buffalo, New York, which is within the Company’s service territory, and terminates in Central New York just north of Syracuse, New York. Empire has almost all of its capacity under contract, with a substantial portion being long-term contracts. Empire
87
delivers natural gas supplies to major industrial companies, utilities (including the Company’s Utility segment), and power producers. The Company believes that the acquisition of Empire better positions the Company to bring Canadian gas supplies into the East Coast markets of the United States as demand for natural gas along the East Coast increases. Details of the acquisition are as follows (all figures in thousands):
Assets Acquired (see Condensed Balance Sheet below) | $ | 257,397 | ||
Liabilities Assumed (see Condensed Balance Sheet below) | (68,192 | ) | ||
Cash Acquired at Acquisition | (8,053 | ) | ||
Cash Paid, Net of Cash Acquired | $ | 181,152 | ||
Property, Plant and Equipment | $ | 220,792 | |||
Current Assets | 14,984 | ||||
Goodwill | 5,476 | ||||
Intangible Assets (see Note K) | 8,580 | ||||
Other Assets | 7,565 | ||||
Total Assets | $ | 257,397 | |||
Equity | $ | 189,205 | |||
Long-Term Debt, Net of Current Portion | 48,433 | ||||
Total Capitalization | 237,638 | ||||
Current Liabilities | 15,265 | ||||
Other Liabilities | 4,494 | ||||
Total Capitalization and Liabilities | $ | 257,397 | |||
On June 3, 2003, the Company acquired for approximately $47.8 million in cash (including cash acquired) all of the partnership interests in Toro, which owns and operates short-distance landfill gas pipeline companies that purchase, transport and resell landfill gas to customers in six states located primarily in the Midwestern United States. Toro’s results of operations were incorporated into the Company’s consolidated financial statements for the period subsequent to the completion of the acquisition on June 3, 2003. The existing landfill gas purchase and sale agreements at these facilities remained in place. The Company believes there are opportunities for expansion at many of these locations. The acquisition consisted of approximately $15.3 million in property, plant and equipment, $31.9 million in intangible assets (as discussed in Note K), $1.1 million of current assets and $0.5 million of current liabilities. Details of the acquisition are as follows (all figures in thousands):
Assets Acquired | $ | 48,319 | ||
Liabilities Assumed | (497 | ) | ||
Cash Acquired at Acquisition | (160 | ) | ||
Cash Paid, Net of Cash Acquired | $ | 47,662 | ||
Note KL — Intangible Assets
88
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
the Toro acquisition, the intangible assets represent the fair value of various long-term gas purchase contracts with the various landfills. These intangible assets are being amortized over the lives of the transportation and gas purchase contracts with no residual value at the end of the amortization period. The weighted-average amortization period for the gross carrying amount of the transportation contracts is 8 years. The weighted-average amortization period for the gross carrying amount of the gas purchase contracts is 20 years. Details of these intangible assets are as follows:
At September 30, 2004 | At September 30, 2003 | ||||||||||||||||
Gross Carrying | Accumulated | Net Carrying | |||||||||||||||
Amount | Amortization | Amount | Net Carrying Amount | ||||||||||||||
Intangible Assets Subject to Amortization | |||||||||||||||||
Long-Term Transportation Contracts | $ | 8,580 | $ | (1,782 | ) | $ | 6,798 | $ | 7,867 | ||||||||
Long-Term Gas Purchase Contracts | 31,864 | (1,839 | ) | 30,025 | 31,522 | ||||||||||||
Intangible Assets Not Subject to Amortization | |||||||||||||||||
Retirement Plan Intangible Asset (see Note F) | 9,171 | — | 9,171 | 10,275 | |||||||||||||
$ | 49,615 | $ | (3,621 | ) | $ | 45,994 | $ | 49,664 | |||||||||
Aggregate Amortization Expense | |||||||||||||||||
For the Year Ended September 30, 2004 | $ | 2,567 | |||||||||||||||
For the Year Ended September 30, 2003 | $ | 1,054 |
follows (in thousands):
At September | ||||||||||||||||
At September 30, 2006 | 30, 2005 | |||||||||||||||
Gross Carrying | Net Carrying | Net Carrying | ||||||||||||||
Amount | Accumulated Amortization | Amount | Amount | |||||||||||||
Intangible Assets Subject to Amortization: | ||||||||||||||||
Long-Term Transportation Contracts | $ | 8,580 | $ | (3,920 | ) | $ | 4,660 | $ | 5,729 | |||||||
Long-Term Gas Purchase Contracts | 31,864 | (5,026 | ) | 26,838 | 28,431 | |||||||||||
Intangible Assets Not Subject to Amortization: | ||||||||||||||||
Retirement Plan Intangible Asset (see Note G) | — | — | — | 8,142 | ||||||||||||
$ | 40,444 | $ | (8,946 | ) | $ | 31,498 | $ | 42,302 | ||||||||
Aggregate Amortization Expense | ||||||||||||||||
For the Year Ended September 30, 2006 | $ | 2,663 | ||||||||||||||
For the Year Ended September 30, 2005 | $ | 2,663 | ||||||||||||||
For the Year Ended September 30, 2004 | $ | 2,567 |
2011.
89
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
year. Because of the seasonal nature of the Company’s heating business, there are substantial variations in operations reported on a quarterly basis.
Net | ||||||||||||||||||||
Income | ||||||||||||||||||||
Available | Earnings Per | |||||||||||||||||||
for | Common Share | |||||||||||||||||||
Operating | Operating | Common | ||||||||||||||||||
Quarter Ended | Revenues | Income | Stock | Basic | Diluted | |||||||||||||||
2004 | ||||||||||||||||||||
(Thousands, except per common share amounts) | ||||||||||||||||||||
9/30/2004 | $ | 278,197 | $ | 27,675 | $ | 7,754 | $ | 0.09 | $ | 0.09 | ||||||||||
6/30/2004 | $ | 419,006 | $ | 72,324 | $ | 32,563 | (1) | $ | 0.40 | $ | 0.39 | |||||||||
3/31/2004 | $ | 801,677 | $ | 148,554 | $ | 77,055 | (2) | $ | 0.94 | $ | 0.93 | |||||||||
12/31/2003 | $ | 532,513 | $ | 95,817 | $ | 49,214 | (3) | $ | 0.60 | $ | 0.60 |
2003 | ||||||||||||||||||||
9/30/2003 | $ | 297,170 | $ | 122,674 | $ | 58,146 | (4) | $ | 0.71 | $ | 0.71 | |||||||||
6/30/2003 | $ | 449,530 | $ | 35,411 | $ | 2,219 | (5) | $ | 0.03 | $ | 0.03 | |||||||||
3/31/2003 | $ | 809,065 | $ | 156,703 | $ | 80,538 | $ | 1.00 | $ | 0.99 | ||||||||||
12/31/2002 | $ | 479,706 | $ | 99,628 | $ | 38,041 | (6) | $ | 0.47 | $ | 0.47 |
102
Net Income Income Income (Loss) Available Earnings from from from for Continuing Operations per Quarter Operating Operating Continuing Discontinued Common Common Share Earnings per Common Share Revenues Income Operations Operations Stock Basic Diluted Basic Diluted (Thousands, except per common share amounts) 9/30/2006 $ 294,469 $ 18,444 $ 1,968 $ — $ 1,968 (1) $ 0.02 $ 0.02 $ 0.02 $ 0.02 6/30/2006 $ 415,452 $ 8,541 $ 111 $ — $ 111 (2) $ — $ — $ — $ — 3/31/2006 $ 890,981 $ 138,967 $ 78,594 $ — $ 78,594 (3) $ 0.93 $ 0.91 $ 0.93 $ 0.91 12/31/2005 $ 710,757 $ 110,123 $ 57,418 $ — $ 57,418 (4) $ 0.68 $ 0.67 $ 0.68 $ 0.67 9/30/2005 $ 287,064 $ 34,926 $ 18,311 (5) $ 30,900 (6) $ 49,211 (5)(6) $ 0.22 $ 0.21 $ 0.58 $ 0.57 6/30/2005 $ 400,359 $ 63,028 $ 26,393 $ (7,237 )(7) $ 19,156 (7) $ 0.32 $ 0.31 $ 0.23 $ 0.23 3/31/2005 $ 735,842 $ 120,667 $ 63,981 (8) $ 6,702 $ 70,683 (8) $ 0.77 $ 0.75 $ 0.85 $ 0.83 12/31/2004 $ 500,284 $ 91,741 $ 44,830 $ 5,608 $ 50,438 $ 0.54 $ 0.53 $ 0.61 $ 0.60
(1) | Includes expense of | |
Includes expense of | ||
(3) | Includes income of $5.1 million related to income tax adjustments. | |
(4) | Includes income of $2.6 million related to a regulatory adjustment. | |
(5) | Includes a $3.9 million gain associated with insurance proceeds received in | |
(6) | Includes a $25.8 million gain related to the sale of U.E. and income of $6.0 million due to the | |
(7) | Includes $6.0 million of previously unrecorded deferred income tax expense related to U.E. | |
(8) | Includes a $2.6 million gain on a FERC approved sale of base gas. |
103
90
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(based (based on intra-day prices) and quarterly dividends declared for the fiscal years ended September 30, 20042006 and 2003,2005, are shown below:
Price Range | ||||||||||||
Dividends | ||||||||||||
Quarter Ended | High | Low | Declared | |||||||||
2004 | ||||||||||||
9/30/2004 | $ | 28.43 | $ | 24.84 | $ | .280 | ||||||
6/30/2004 | $ | 25.57 | $ | 23.75 | $ | .280 | ||||||
3/31/2004 | $ | 26.48 | $ | 24.26 | $ | .270 | ||||||
12/31/2003 | $ | 25.01 | $ | 21.71 | $ | .270 | ||||||
2003 | ||||||||||||
9/30/2003 | $ | 27.51 | $ | 22.51 | $ | .270 | ||||||
6/30/2003 | $ | 26.90 | $ | 21.60 | $ | .270 | ||||||
3/31/2003 | $ | 22.25 | $ | 18.97 | $ | .260 | ||||||
12/31/2002 | $ | 21.86 | $ | 17.95 | $ | .260 |
Price Range | ||||||||||||
Quarter Ended | High | Low | Dividends Declared | |||||||||
2006 | ||||||||||||
9/30/2006 | $ | 39.16 | $ | 34.95 | $ | .30 | ||||||
6/30/2006 | $ | 36.75 | $ | 31.33 | $ | .30 | ||||||
3/31/2006 | $ | 35.43 | $ | 30.60 | $ | .29 | ||||||
12/31/2005 | $ | 35.27 | $ | 29.25 | $ | .29 | ||||||
2005 | ||||||||||||
9/30/2005 | $ | 36.00 | $ | 27.74 | $ | .29 | ||||||
6/30/2005 | $ | 29.49 | $ | 26.20 | $ | .29 | ||||||
3/31/2005 | $ | 29.75 | $ | 26.66 | $ | .28 | ||||||
12/31/2004 | $ | 29.18 | $ | 27.01 | $ | .28 |
At September 30 | ||||||||
2006 | 2005 | |||||||
(Thousands) | ||||||||
Proved Properties(1) | $ | 1,884,049 | $ | 1,650,788 | ||||
Unproved Properties | 41,930 | 39,084 | ||||||
1,925,979 | 1,689,872 | |||||||
Less — Accumulated Depreciation, Depletion and Amortization | 929,921 | 721,397 | ||||||
$ | 996,058 | $ | 968,475 | |||||
At September 30 | ||||||||
2004 | 2003 | |||||||
(Thousands) | ||||||||
Proved Properties(1) | $ | 1,489,284 | $ | 1,647,075 | ||||
Unproved Properties | 27,277 | 30,955 | ||||||
1,516,561 | 1,678,030 | |||||||
Less — Accumulated Depreciation, Depletion and Amortization | 609,469 | 763,258 | ||||||
$ | 907,092 | $ | 914,772 | |||||
(1) | Includes asset retirement costs of |
104
Total | ||||||||||||||||||||
as | ||||||||||||||||||||
of | ||||||||||||||||||||
September | ||||||||||||||||||||
30, | Year Costs Incurred | |||||||||||||||||||
2006 | 2006 | 2005 | 2004 | Prior | ||||||||||||||||
(Thousands) | ||||||||||||||||||||
Acquisition Costs | $ | 41,930 | $ | 27,497 | $ | 6,078 | $ | 981 | $ | 7,374 |
Year Costs Incurred | ||||||||||||||||||||
Total as of | ||||||||||||||||||||
September 30, 2004 | 2004 | 2003 | 2002 | Prior | ||||||||||||||||
(Thousands) | ||||||||||||||||||||
Acquisition Costs | $ | 27,277 | $ | 7,650 | $ | 6,748 | $ | 2,884 | $ | 9,995 |
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(Thousands) | ||||||||||||
United States | ||||||||||||
Property Acquisition Costs: | ||||||||||||
Proved | $ | 5,339 | $ | 287 | $ | (8 | ) | |||||
Unproved | 8,844 | 1,215 | 3,529 | |||||||||
Exploration Costs | 64,087 | 32,456 | 10,503 | |||||||||
Development Costs | 87,738 | 49,016 | 31,881 | |||||||||
Asset Retirement Costs | 10,965 | 8,051 | 2,292 | |||||||||
176,973 | 91,025 | 48,197 | ||||||||||
Canada | ||||||||||||
Property Acquisition Costs: | ||||||||||||
Proved | (427 | ) | (1,551 | ) | 29 | |||||||
Unproved | 6,492 | 4,668 | 3,167 | |||||||||
Exploration Costs | 20,778 | 22,943 | 22,624 | |||||||||
Development Costs | 14,385 | 12,198 | 5,500 | |||||||||
Asset Retirement Costs | 279 | 292 | 1,218 | |||||||||
41,507 | 38,550 | 32,538 | ||||||||||
Total | ||||||||||||
Property Acquisition Costs: | ||||||||||||
Proved | 4,912 | (1,264 | ) | 21 | ||||||||
Unproved | 15,336 | 5,883 | 6,696 | |||||||||
Exploration Costs | 84,865 | 55,399 | 33,127 | |||||||||
Development Costs | 102,123 | 61,214 | 37,381 | |||||||||
Asset Retirement Costs | 11,244 | 8,343 | 3,510 | |||||||||
$ | 218,480 | $ | 129,575 | $ | 80,735 | |||||||
91
105
Year Ended September 30 | |||||||||||||
2004 | 2003 | 2002 | |||||||||||
(Thousands) | |||||||||||||
United States | |||||||||||||
Property Acquisition Costs: | |||||||||||||
Proved | $ | (8 | ) | $ | (13 | ) | $ | 9,316 | |||||
Unproved | 3,529 | 1,920 | 698 | ||||||||||
Exploration Costs | 10,503 | 17,947 | 25,583 | ||||||||||
Development Costs | 31,881 | 23,649 | 51,792 | ||||||||||
Asset Retirement Costs | 2,292 | 242 | — | ||||||||||
48,197 | 43,745 | 87,389 | |||||||||||
Canada | |||||||||||||
Property Acquisition Costs: | |||||||||||||
Proved | 29 | 181 | (536 | ) | |||||||||
Unproved | 3,167 | 6,217 | 2,804 | ||||||||||
Exploration Costs | 22,624 | 6,641 | 8,779 | ||||||||||
Development Costs | 5,500 | 17,745 | 15,332 | ||||||||||
Asset Retirement Costs | 1,218 | — | — | ||||||||||
32,538 | 30,784 | 26,379 | |||||||||||
Total | |||||||||||||
Property Acquisition Costs:(1) | |||||||||||||
Proved | 21 | 168 | 8,780 | ||||||||||
Unproved | 6,696 | 8,137 | 3,502 | ||||||||||
Exploration Costs | 33,127 | 24,588 | 34,362 | ||||||||||
Development Costs | 37,381 | 41,394 | 67,124 | ||||||||||
Asset Retirement Costs | 3,510 | 242 | — | ||||||||||
$ | 80,735 | $ | 74,529 | $ | 113,768 | ||||||||
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(Thousands, except per Mcfe amounts) | ||||||||||||
United States | ||||||||||||
Operating Revenues: | ||||||||||||
Natural Gas (includes revenues from sales to affiliates of $106, $77 and $72, respectively) | $ | 152,451 | $ | 151,004 | $ | 151,570 | ||||||
Oil, Condensate and Other Liquids | 195,050 | 160,145 | 139,301 | |||||||||
Total Operating Revenues(1) | 347,501 | 311,149 | 290,871 | |||||||||
Production/Lifting Costs | 41,354 | 38,442 | 39,677 | |||||||||
Accretion Expense | 2,412 | 2,220 | 1,756 | |||||||||
Depreciation, Depletion and Amortization ($1.74, $1.58 and $1.41 per Mcfe of production) | 66,488 | 67,097 | 73,396 | |||||||||
Income Tax Expense | 88,104 | 74,110 | 65,337 | |||||||||
Results of Operations for Producing Activities (excluding corporate overheads and interest charges) | 149,143 | 129,280 | 110,705 | |||||||||
Canada | ||||||||||||
Operating Revenues: | ||||||||||||
Natural Gas | 54,819 | 49,275 | 30,359 | |||||||||
Oil, Condensate and Other Liquids | 13,985 | 12,875 | 10,018 | |||||||||
Total Operating Revenues(1) | 68,804 | 62,150 | 40,377 | |||||||||
Production/Lifting Costs | 14,628 | 12,683 | 8,176 | |||||||||
Accretion Expense | 258 | 228 | 177 | |||||||||
Depreciation, Depletion and Amortization ($2.95, $2.36 and $1.83 per Mcfe of production) | 27,439 | 23,108 | 14,922 | |||||||||
Impairment of Oil and Gas Producing Properties(2) | 104,739 | — | — | |||||||||
Income Tax Expense (Benefit) | (31,987 | ) | 8,577 | 5,235 | ||||||||
Results of Operations for Producing Activities (excluding corporate overheads and interest charges) | (46,273 | ) | 17,554 | 11,867 | ||||||||
92
106
For the years ended September 30, 2004, 2003 and 2002, the Company spent $12.1 million, $1.7 million and $18.2 million, respectively, developing proved undeveloped reserves. Year Ended September 30 2006 2005 2004 (Thousands, except per Mcfe amounts) Operating Revenues: Natural Gas (includes revenues from sales to affiliates of $106, $77 and $72, respectively) 207,270 200,279 181,929 Oil, Condensate and Other Liquids 209,035 173,020 149,319 Total Operating Revenues(1) 416,305 373,299 331,248 Production/Lifting Costs 55,982 51,125 47,853 Accretion Expense 2,670 2,448 1,933 Depreciation, Depletion and Amortization ($1.98, $1.72 and $1.47 per Mcfe of production) 93,927 90,205 88,318 Impairment of Oil and Gas Producing Properties(2) 104,739 — — Income Tax Expense 56,117 82,687 70,572 Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $ 102,870 $ 146,834 $ 122,572
Year Ended September 30, | |||||||||||||
2004 | 2003 | 2002 | |||||||||||
(Thousands, except per Mcfe amounts) | |||||||||||||
United States | |||||||||||||
Operating Revenues: | |||||||||||||
Natural Gas (includes revenues from sales to affiliates of $72, $69 and $43, respectively) | $ | 151,570 | $ | 148,104 | $ | 104,954 | |||||||
Oil, Condensate and Other Liquids | 139,301 | 118,277 | 101,549 | ||||||||||
Total Operating Revenues(1) | 290,871 | 266,381 | 206,503 | ||||||||||
Production/ Lifting Costs | 39,677 | 39,162 | 42,956 | ||||||||||
Accretion Expense | 1,756 | 1,800 | — | ||||||||||
Depreciation, Depletion and Amortization ($1.41, $1.29 and $1.25 per Mcfe of production) | 73,396 | 70,127 | 80,142 | ||||||||||
Income Tax Expense | 65,337 | 62,672 | 30,253 | ||||||||||
Results of Operations for Producing Activities (excluding corporate overheads and interest charges) | 110,705 | 92,620 | 53,152 | ||||||||||
Canada | |||||||||||||
Operating Revenues: | |||||||||||||
Natural Gas | 30,359 | 26,992 | 14,621 | ||||||||||
Oil, Condensate and Other Liquids | 10,018 | 62,908 | 56,511 | ||||||||||
Total Operating Revenues(1) | 40,377 | 89,900 | 71,132 | ||||||||||
Production/ Lifting Costs | 8,176 | 33,038 | 30,109 | ||||||||||
Accretion Expense | 177 | 802 | — | ||||||||||
Depreciation, Depletion and Amortization ($1.83, $1.30 and $0.93 per Mcfe of production) | 14,922 | 26,165 | 21,707 | ||||||||||
Impairment of Oil and Gas Producing Properties(2) | — | 42,774 | — | ||||||||||
Income Tax Expense (Benefit) | 5,235 | (3,273 | ) | 4,672 | |||||||||
Results of Operations for Producing Activities (excluding corporate overheads and interest charges) | 11,867 | (9,606 | ) | 14,644 | |||||||||
93
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Year Ended September 30, | |||||||||||||
2004 | 2003 | 2002 | |||||||||||
(Thousands, except per Mcfe amounts) | |||||||||||||
Total | |||||||||||||
Operating Revenues: | |||||||||||||
Natural Gas (includes revenues from sales to affiliates of $72, $69 and $43, respectively) | 181,929 | 175,096 | 119,575 | ||||||||||
Oil, Condensate and Other Liquids | 149,319 | 181,185 | 158,060 | ||||||||||
Total Operating Revenues(1) | 331,248 | 356,281 | 277,635 | ||||||||||
Production/ Lifting Costs | 47,853 | 72,200 | 73,065 | ||||||||||
Accretion Expense | 1,933 | 2,602 | — | ||||||||||
Depreciation, Depletion and Amortization ($1.47, $1.30 and $1.16 per Mcfe of production) | 88,318 | 96,292 | 101,849 | ||||||||||
Impairment of Oil and Gas Producing Properties(2) | — | 42,774 | — | ||||||||||
Income Tax Expense | 70,572 | 59,399 | 34,925 | ||||||||||
Results of Operations for Producing Activities (excluding corporate overheads and interest charges) | $ | 122,572 | $ | 83,014 | $ | 67,796 | |||||||
(1) | Exclusive of hedging gains and losses. See further discussion in Note | |
(2) | See discussion of impairment in Note A — Summary of Significant Accounting |
Reserve Quantity Information (unaudited)
Gas MMcf | ||||||||||||||||||||||||
U.S. | ||||||||||||||||||||||||
Gulf Coast | West Coast | Appalachian | Total | Total | ||||||||||||||||||||
Region | Region | Region | U.S. | Canada | Company | |||||||||||||||||||
Proved Developed and Undeveloped Reserves: | ||||||||||||||||||||||||
September 30, 2001 | 89,858 | 98,498 | 78,457 | 266,813 | 55,567 | 322,380 | ||||||||||||||||||
Extensions and Discoveries | 6,530 | 5,770 | 4,242 | 16,542 | 20,263 | 36,805 | ||||||||||||||||||
Revisions of Previous Estimates | 1,613 | (26,063 | ) | 342 | (24,108 | ) | (20,676 | ) | (44,784 | ) | ||||||||||||||
Production | (25,776 | ) | (4,889 | ) | (4,402 | ) | (35,067 | ) | (6,387 | ) | (41,454 | ) | ||||||||||||
Sales of Minerals in Place | (14,361 | ) | — | (365 | ) | (14,726 | ) | — | (14,726 | ) | ||||||||||||||
September 30, 2002 | 57,864 | 73,316 | 78,274 | 209,454 | 48,767 | 258,221 | ||||||||||||||||||
Extensions and Discoveries | 10,538 | — | 5,844 | 16,382 | 11,641 | 28,023 | ||||||||||||||||||
Revisions of Previous Estimates | (2,278 | ) | 1,213 | 2,224 | 1,159 | (2,211 | ) | (1,052 | ) | |||||||||||||||
Production | (18,441 | ) | (4,467 | ) | (5,123 | ) | (28,031 | ) | (5,774 | ) | (33,805 | ) | ||||||||||||
Sales of Minerals in Place | — | — | — | — | (270 | ) | (270 | ) | ||||||||||||||||
Gas MMcf | ||||||||||||||||||||||||
U. S. | ||||||||||||||||||||||||
Gulf | West | |||||||||||||||||||||||
Coast | Coast | Appalachian | Total | Total | ||||||||||||||||||||
Region | Region | Region | U.S. | Canada | Company | |||||||||||||||||||
Proved Developed and Undeveloped Reserves: | ||||||||||||||||||||||||
September 30, 2003 | 47,683 | 70,062 | 81,219 | 198,964 | 52,153 | 251,117 | ||||||||||||||||||
Extensions and Discoveries | 2,632 | — | 3,784 | 6,416 | 15,925 | 22,341 | ||||||||||||||||||
Revisions of Previous Estimates | (4,984 | ) | 1,831 | (1,111 | ) | (4,264 | ) | (11,004 | ) | (15,268 | ) | |||||||||||||
Production | (17,596 | ) | (4,057 | ) | (5,132 | ) | (26,785 | ) | (6,228 | ) | (33,013 | ) | ||||||||||||
Sales of Minerals in Place | (1 | ) | (392 | ) | — | (393 | ) | — | (393 | ) | ||||||||||||||
94107
Gas MMcf | ||||||||||||||||||||||||
U.S. | ||||||||||||||||||||||||
Gulf Coast | West Coast | Appalachian | Total | Total | ||||||||||||||||||||
Region | Region | Region | U.S. | Canada | Company | |||||||||||||||||||
September 30, 2003 | 47,683 | 70,062 | 81,219 | 198,964 | 52,153 | 251,117 | ||||||||||||||||||
Extensions and Discoveries | �� | 2,632 | — | 3,784 | 6,416 | 15,925 | 22,341 | |||||||||||||||||
Revisions of Previous Estimates | (4,984 | ) | 1,831 | (1,111 | ) | (4,264 | ) | (11,004 | ) | (15,268 | ) | |||||||||||||
Production | (17,596 | ) | (4,057 | ) | (5,132 | ) | (26,785 | ) | (6,228 | ) | (33,013 | ) | ||||||||||||
Sales of Minerals in Place | (1 | ) | (392 | ) | — | (393 | ) | — | (393 | ) | ||||||||||||||
September 30, 2004 | 27,734 | 67,444 | 78,760 | 173,938 | 50,846 | 224,784 | ||||||||||||||||||
Proved Developed Reserves: | ||||||||||||||||||||||||
September 30, 2001 | 87,893 | 47,442 | 78,457 | 213,792 | 53,463 | 267,255 | ||||||||||||||||||
September 30, 2002 | 57,274 | 57,286 | 78,273 | 192,833 | 39,253 | 232,086 | ||||||||||||||||||
September 30, 2003 | 45,402 | 54,180 | 81,218 | 180,800 | 42,745 | 223,545 | ||||||||||||||||||
September 30, 2004 | 25,827 | 53,035 | 78,760 | 157,622 | 46,223 | 203,845 |
Oil Mbbl | ||||||||||||||||||||||||
U.S. | ||||||||||||||||||||||||
Gulf Coast | West Coast | Appalachian | Total | Total | ||||||||||||||||||||
Region | Region | Region | U.S. | Canada | Company | |||||||||||||||||||
Proved Developed and Undeveloped Reserves: | ||||||||||||||||||||||||
September 30, 2001 | 6,294 | 68,424 | 77 | 74,795 | 40,533 | 115,328 | ||||||||||||||||||
Extensions and Discoveries | 57 | 1,360 | 20 | 1,437 | 586 | 2,023 | ||||||||||||||||||
Revisions of Previous Estimates | 781 | 129 | 6 | 916 | (10,278 | ) | (9,362 | ) | ||||||||||||||||
Production | (1,815 | ) | (3,004 | ) | (9 | ) | (4,828 | ) | (2,834 | ) | (7,662 | ) | ||||||||||||
Sales of Minerals in Place | (200 | ) | — | — | (200 | ) | (410 | ) | (610 | ) | ||||||||||||||
September 30, 2002 | 5,117 | 66,909 | 94 | 72,120 | 27,597 | 99,717 | ||||||||||||||||||
Extensions and Discoveries | 104 | — | 46 | 150 | 729 | 879 | ||||||||||||||||||
Revisions of Previous Estimates | (365 | ) | (185 | ) | 8 | (542 | ) | (4,119 | ) | (4,661 | ) | |||||||||||||
Production | (1,473 | ) | (2,872 | ) | (10 | ) | (4,355 | ) | (2,382 | ) | (6,737 | ) | ||||||||||||
Sales of Minerals in Place | — | — | — | — | (19,434 | ) | (19,434 | ) | ||||||||||||||||
September 30, 2003 | 3,383 | 63,852 | 138 | 67,373 | 2,391 | 69,764 | ||||||||||||||||||
Extensions and Discoveries | 19 | — | 18 | 37 | 181 | 218 | ||||||||||||||||||
Revisions of Previous Estimates | 213 | (17 | ) | 11 | 207 | (144 | ) | 63 | ||||||||||||||||
Production | (1,534 | ) | (2,650 | ) | (20 | ) | (4,204 | ) | (324 | ) | (4,528 | ) | ||||||||||||
Sales of Minerals in Place | (1 | ) | (303 | ) | — | (304 | ) | — | (304 | ) | ||||||||||||||
September 30, 2004 | 2,080 | 60,882 | 147 | 63,109 | 2,104 | 65,213 | ||||||||||||||||||
Proved Developed Reserves: | ||||||||||||||||||||||||
September 30, 2001 | 6,259 | 44,304 | 77 | 50,640 | 33,676 | 84,316 | ||||||||||||||||||
September 30, 2002 | 5,111 | 41,735 | 94 | 46,940 | 24,100 | 71,040 | ||||||||||||||||||
September 30, 2003 | 2,533 | 40,079 | 139 | 42,751 | 2,391 | 45,142 | ||||||||||||||||||
September 30, 2004 | 2,061 | 38,631 | 148 | 40,840 | 2,104 | 42,944 |
Gas MMcf U. S. Gulf West Coast Coast Appalachian Total Total Region Region Region U.S. Canada Company September 30, 2004 27,734 67,444 78,760 173,938 50,846 224,784 Extensions and Discoveries 17,165 — 5,461 22,626 4,849 27,475 Revisions of Previous Estimates 6,039 7,067 3,733 16,839 (1,600 ) 15,239 Production (12,468 ) (4,052 ) (4,650 ) (21,170 ) (8,009 ) (29,179 ) Sales of Minerals in Place — — (179 ) (179 ) — (179 ) September 30, 2005 38,470 70,459 83,125 192,054 46,086 238,140 Extensions and Discoveries 11,763 1,815 11,132 24,710 6,229 30,939 Revisions of Previous Estimates 679 5,757 (7,776 ) (1,340 ) (11,096 ) (12,436 ) Production (9,110 ) (3,880 ) (5,108 ) (18,098 ) (7,673 ) (25,771 ) Purchases of Minerals in Place — 1,715 — 1,715 — 1,715 Sales of Minerals in Place — — — — (12 ) (12 ) September 30, 2006 41,802 75,866 81,373 199,041 33,534 232,575 Proved Developed Reserves: September 30, 2003 45,402 54,180 81,218 180,800 42,745 223,545 September 30, 2004 25,827 53,035 78,760 157,622 46,223 203,845 September 30, 2005 23,108 58,692 83,125 164,925 43,980 208,905 September 30, 2006 32,345 64,196 81,373 177,914 33,534 211,448
Oil Mbbl | ||||||||||||||||||||||||
U.S. | ||||||||||||||||||||||||
West | ||||||||||||||||||||||||
Gulf Coast | Coast | Appalachian | Total | Total | ||||||||||||||||||||
Region | Region | Region | U.S. | Canada | Company | |||||||||||||||||||
Proved Developed and Undeveloped Reserves: | ||||||||||||||||||||||||
September 30, 2003 | 3,383 | 63,852 | 138 | 67,373 | 2,391 | 69,764 | ||||||||||||||||||
Extensions and Discoveries | 19 | — | 18 | 37 | 181 | 218 | ||||||||||||||||||
Revisions of Previous Estimates | 213 | (17 | ) | 11 | 207 | (144 | ) | 63 | ||||||||||||||||
Production | (1,534 | ) | (2,650 | ) | (20 | ) | (4,204 | ) | (324 | ) | (4,528 | ) | ||||||||||||
Sales of Minerals in Place | (1 | ) | (303 | ) | — | (304 | ) | — | (304 | ) | ||||||||||||||
September 30, 2004 | 2,080 | 60,882 | 147 | 63,109 | 2,104 | 65,213 | ||||||||||||||||||
Extensions and Discoveries | 99 | — | 63 | 162 | 204 | 366 | ||||||||||||||||||
Revisions of Previous Estimates | 105 | (1,253 | ) | 3 | (1,145 | ) | (186 | ) | (1,331 | ) | ||||||||||||||
Production | (989 | ) | (2,544 | ) | (36 | ) | (3,569 | ) | (300 | ) | (3,869 | ) | ||||||||||||
Sales of Minerals in Place | — | — | — | — | (122 | ) | (122 | ) | ||||||||||||||||
95108
Oil Mbbl U.S. West Gulf Coast Coast Appalachian Total Total Region Region Region U.S. Canada Company September 30, 2005 1,295 57,085 177 58,557 1,700 60,257 Extensions and Discoveries 39 172 108 319 128 447 Revisions of Previous Estimates 595 (80 ) 57 572 101 673 Production (685 ) (2,582 ) (69 ) (3,336 ) (272 ) (3,608 ) Purchases of Minerals in Place — 274 — 274 — 274 Sales of Minerals in Place — — — — (25 ) (25 ) September 30, 2006 1,244 54,869 273 56,386 1,632 58,018 Proved Developed Reserves: September 30, 2003 2,533 40,079 139 42,751 2,391 45,142 September 30, 2004 2,061 38,631 148 40,840 2,104 42,944 September 30, 2005 1,229 41,701 177 43,107 1,700 44,807 September 30, 2006 1,217 42,522 273 44,012 1,632 45,644
109
Year Ended September 30, | ||||||||||||||
2004 | 2003 | 2002 | ||||||||||||
(Thousands) | ||||||||||||||
United States | ||||||||||||||
Future Cash Inflows | $ | 3,728,168 | $ | 2,684,286 | $ | 2,764,556 | ||||||||
Less: | ||||||||||||||
Future Production Costs | 676,361 | 579,321 | 546,182 | |||||||||||
Future Development Costs | 124,298 | 116,639 | 117,999 | |||||||||||
Future Income Tax Expense at Applicable Statutory Rate | 995,327 | 613,893 | 653,347 | |||||||||||
Future Net Cash Flows | 1,932,182 | 1,374,433 | 1,447,028 | |||||||||||
Less: | ||||||||||||||
10% Annual Discount for Estimated Timing of Cash Flows | 996,813 | 641,185 | 665,941 | |||||||||||
Standardized Measure of Discounted Future Net Cash Flows | 935,369 | 733,248 | 781,087 | |||||||||||
Year Ended September 30 | ||||||||||||
2006 | 2005 | 2004 | ||||||||||
(Thousands) | ||||||||||||
United States | ||||||||||||
Future Cash Inflows | $ | 3,911,059 | $ | 6,138,522 | $ | 3,728,168 | ||||||
Less: | ||||||||||||
Future Production Costs | 758,258 | 777,417 | 676,361 | |||||||||
Future Development Costs | 205,497 | 188,795 | 124,298 | |||||||||
Future Income Tax Expense at Applicable Statutory Rate | 1,019,307 | 1,868,548 | 995,327 | |||||||||
Future Net Cash Flows | 1,927,997 | 3,303,762 | 1,932,182 | |||||||||
Less: | ||||||||||||
10% Annual Discount for Estimated Timing of Cash Flows | 1,066,338 | 1,812,230 | 996,813 | |||||||||
Standardized Measure of Discounted Future Net Cash Flows | 861,659 | 1,491,532 | 935,369 | |||||||||
96
110
Year Ended September 30, | ||||||||||||||
2004 | 2003 | 2002 | ||||||||||||
(Thousands) | ||||||||||||||
Canada | ||||||||||||||
Future Cash Inflows | 343,026 | 279,772 | 888,515 | |||||||||||
Less: | ||||||||||||||
Future Production Costs | 111,519 | 85,817 | 413,006 | |||||||||||
Future Development Costs | 13,222 | 9,787 | 25,398 | |||||||||||
Future Income Tax Expense at Applicable Statutory Rate | 60,610 | 58,436 | 101,919 | |||||||||||
Future Net Cash Flows | 157,675 | 125,732 | 348,192 | |||||||||||
Less: | ||||||||||||||
10% Annual Discount for Estimated Timing of Cash Flows | 46,945 | 40,575 | 103,097 | |||||||||||
Standardized Measure of Discounted Future Net Cash Flows | 110,730 | 85,157 | 245,095 | |||||||||||
Total | ||||||||||||||
Future Cash Inflows | 4,071,194 | 2,964,058 | 3,653,071 | |||||||||||
Less: | ||||||||||||||
Future Production Costs | 787,880 | 665,138 | 959,188 | |||||||||||
Future Development Costs | 137,520 | 126,426 | 143,397 | |||||||||||
Future Income Tax Expense at Applicable Statutory Rate | 1,055,937 | 672,329 | 755,266 | |||||||||||
Future Net Cash Flows | 2,089,857 | 1,500,165 | 1,795,220 | |||||||||||
Less: | ||||||||||||||
10% Annual Discount for Estimated Timing of Cash Flows | 1,043,758 | 681,760 | 769,038 | |||||||||||
Standardized Measure of Discounted Future Net Cash Flows | $ | 1,046,099 | $ | 818,405 | $ | 1,026,182 | ||||||||
Year Ended September 30 2006 2005 2004 (Thousands) Future Cash Inflows 197,227 601,210 343,026 Less: Future Production Costs 92,234 136,338 111,519 Future Development Costs 11,520 12,197 13,222 Future Income Tax Expense at Applicable Statutory Rate (151 ) 137,524 60,610 Future Net Cash Flows 93,624 315,151 157,675 Less: 10% Annual Discount for Estimated Timing of Cash Flows 19,375 108,508 46,945 Standardized Measure of Discounted Future Net Cash Flows 74,249 206,643 110,730 Future Cash Inflows 4,108,286 6,739,732 4,071,194 Less: Future Production Costs 850,492 913,755 787,880 Future Development Costs 217,017 200,992 137,520 Future Income Tax Expense at Applicable Statutory Rate 1,019,156 2,006,072 1,055,937 Future Net Cash Flows 2,021,621 3,618,913 2,089,857 Less: 10% Annual Discount for Estimated Timing of Cash Flows 1,085,713 1,920,738 1,043,758 Standardized Measure of Discounted Future Net Cash Flows $ 935,908 $ 1,698,175 $ 1,046,099
97111
Year Ended September 30, 2004 2003 2002 (Thousands) Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $ 733,248 $ 781,087 $ 605,350 Sales, Net of Production Costs (251,194 ) (227,219 ) (163,548 ) Net Changes in Prices, Net of Production Costs 592,326 11,130 441,085 Purchases of Minerals in Place — — — Sales of Minerals in Place (5,554 ) — (27,197 ) Extensions and Discoveries 16,638 29,266 42,970 Changes in Estimated Future Development Costs (40,042 ) (35,062 ) (42,069 ) Previously Estimated Development Costs Incurred 32,653 36,423 45,310 Net Change in Income Taxes at Applicable Statutory Rate (166,055 ) 24,796 (126,263 ) Revisions of Previous Quantity Estimates (5,107 ) (3,572 ) (32,646 ) Accretion of Discount and Other 28,456 116,399 38,095 Standardized Measure of Discounted Future Net Cash Flows at End of Year 935,369 733,248 781,087 Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year 85,157 245,095 181,439 Sales, Net of Production Costs (32,201 ) (56,862 ) (41,023 ) Net Changes in Prices, Net of Production Costs 29,230 8,167 111,148 Purchases of Minerals in Place — — — Sales of Minerals in Place — (120,960 ) (3,084 ) Extensions and Discoveries 36,986 28,241 29,813 Changes in Estimated Future Development Costs (8,491 ) (14,045 ) 18,151 Previously Estimated Development Costs Incurred 5,055 29,657 12,361 Net Change in Income Taxes at Applicable Statutory Rate (2,640 ) (6,280 ) (6,910 ) Revisions of Previous Quantity Estimates (19,369 ) (41,205 ) (88,571 ) Accretion of Discount and Other 17,003 13,349 31,771 Standardized Measure of Discounted Future Net Cash Flows at End of Year 110,730 85,157 245,095 Year Ended September 30 2006 2005 2004 (Thousands) Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $ 1,491,532 $ 935,369 $ 733,248 Sales, Net of Production Costs (306,147 ) (272,707 ) (251,194 ) Net Changes in Prices, Net of Production Costs (941,545 ) 1,093,353 592,326 Purchases of Minerals in Place 7,607 — — Sales of Minerals in Place — (762 ) (5,554 ) Extensions and Discoveries 66,975 100,102 16,638 Changes in Estimated Future Development Costs (83,750 ) (89,805 ) (40,042 ) Previously Estimated Development Costs Incurred 67,048 25,038 32,653 Net Change in Income Taxes at Applicable Statutory Rate 404,176 (362,956 ) (166,055 ) Revisions of Previous Quantity Estimates 4,850 25,055 (5,107 ) Accretion of Discount and Other 150,913 38,845 28,456 Standardized Measure of Discounted Future Net Cash Flows at End of Year 861,659 1,491,532 935,369 Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year 206,643 110,730 85,157 Sales, Net of Production Costs (54,176 ) (49,467 ) (32,201 ) Net Changes in Prices, Net of Production Costs (180,216 ) 174,985 29,230 Purchases of Minerals in Place — — — Sales of Minerals in Place (238 ) (3,751 ) — Extensions and Discoveries 10,369 31,028 36,986 Changes in Estimated Future Development Costs (3,282 ) (11,007 ) (8,491 ) Previously Estimated Development Costs Incurred 4,450 12,032 5,055 Net Change in Income Taxes at Applicable Statutory Rate 82,966 (51,541 ) (2,640 ) Revisions of Previous Quantity Estimates (15,478 ) (5,990 ) (19,369 ) Accretion of Discount and Other 23,211 (376 ) 17,003 Standardized Measure of Discounted Future Net Cash Flows at End of Year 74,249 206,643 110,730
98
112
Year Ended September 30, | |||||||||||||
2004 | 2003 | 2002 | |||||||||||
(Thousands) | |||||||||||||
Total | |||||||||||||
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year | 818,405 | 1,026,182 | 786,789 | ||||||||||
Sales, Net of Production Costs | (283,395 | ) | (284,081 | ) | (204,571 | ) | |||||||
Net Changes in Prices, Net of Production Costs | 621,556 | 19,297 | 552,233 | ||||||||||
Purchases of Minerals in Place | — | — | — | ||||||||||
Sales of Minerals in Place | (5,554 | ) | (120,960 | ) | (30,281 | ) | |||||||
Extensions and Discoveries | 53,624 | 57,507 | 72,783 | ||||||||||
Changes in Estimated Future Development Costs | (48,533 | ) | (49,107 | ) | (23,918 | ) | |||||||
Previously Estimated Development Costs Incurred | 37,708 | 66,080 | 57,671 | ||||||||||
Net Change in Income Taxes at Applicable Statutory Rate | (168,695 | ) | 18,516 | (133,173 | ) | ||||||||
Revisions of Previous Quantity Estimates | (24,476 | ) | (44,777 | ) | (121,217 | ) | |||||||
Accretion of Discount and Other | 45,459 | 129,748 | 69,866 | ||||||||||
Standardized Measure of Discounted Future Net Cash Flows at End of Year | $ | 1,046,099 | $ | 818,405 | $ | 1,026,182 | |||||||
99
Year Ended September 30 2006 2005 2004 (Thousands) Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year 1,698,175 1,046,099 818,405 Sales, Net of Production Costs (360,323 ) (322,174 ) (283,395 ) Net Changes in Prices, Net of Production Costs (1,121,761 ) 1,268,338 621,556 Purchases of Minerals in Place 7,607 — — Sales of Minerals in Place (238 ) (4,513 ) (5,554 ) Extensions and Discoveries 77,344 131,130 53,624 Changes in Estimated Future Development Costs (87,032 ) (100,812 ) (48,533 ) Previously Estimated Development Costs Incurred 71,498 37,070 37,708 Net Change in Income Taxes at Applicable Statutory Rate 487,142 (414,497 ) (168,695 ) Revisions of Previous Quantity Estimates (10,628 ) 19,065 (24,476 ) Accretion of Discount and Other 174,124 38,469 45,459 Standardized Measure of Discounted Future Net Cash Flows at End of Year $ 935,908 $ 1,698,175 $ 1,046,099
Additions | Additions | |||||||||||||||||||
Balance at | Charged to | Charged to | Balance at | |||||||||||||||||
Beginning | Costs and | Other | End of | |||||||||||||||||
Description | of Period | Expenses | Accounts(1) | Deductions(2) | Period | |||||||||||||||
(Thousands) | ||||||||||||||||||||
Year Ended September 30, 2004 | ||||||||||||||||||||
Reserve for Doubtful Accounts | $ | 17,943 | $ | 20,328 | $ | — | $ | 20,831 | $ | 17,440 | ||||||||||
Deferred Tax Valuation Allowance | $ | 6,357 | $ | (3,480 | ) | $ | — | $ | — | $ | 2,877 | |||||||||
Year Ended September 30, 2003 | ||||||||||||||||||||
Reserve for Doubtful Accounts | $ | 17,299 | $ | 17,275 | $ | — | $ | 16,631 | $ | 17,943 | ||||||||||
Deferred Tax Valuation Allowance | $ | — | $ | 6,357 | $ | — | $ | — | $ | 6,357 | ||||||||||
Year Ended September 30, 2002 | ||||||||||||||||||||
Reserve for Doubtful Accounts | $ | 18,521 | $ | 16,082 | $ | 2,834 | $ | 20,138 | $ | 17,299 | ||||||||||
Additions | ||||||||||||||||||||
Balance | Charged | Additions | Balance | |||||||||||||||||
at | to | Charged | at | |||||||||||||||||
Beginning | Costs | to | End | |||||||||||||||||
of | and | Other | of | |||||||||||||||||
Description | Period | Expenses | Accounts | Deductions(3) | Period | |||||||||||||||
(Thousands) | ||||||||||||||||||||
Year Ended September 30, 2006 | ||||||||||||||||||||
Allowance for Uncollectible Accounts | $ | 26,940 | $ | 29,088 | $ | 907 | (1) | $ | 25,508 | $ | 31,427 | |||||||||
Deferred Tax Valuation Allowance | $ | 2,877 | $ | (2,877 | ) | $ | — | $ | — | $ | — | |||||||||
Year Ended September 30, 2005 | ||||||||||||||||||||
Allowance for Uncollectible Accounts | $ | 17,440 | $ | 31,113 | $ | 2,480 | (2) | $ | 24,093 | $ | 26,940 | |||||||||
Deferred Tax Valuation Allowance | $ | 2,877 | $ | — | $ | — | $ | — | $ | 2,877 | ||||||||||
Year Ended September 30, 2004 | ||||||||||||||||||||
Allowance for Uncollectible Accounts | $ | 17,943 | $ | 20,328 | $ | — | $ | 20,831 | $ | 17,440 | ||||||||||
Deferred Tax Valuation Allowance | $ | 6,357 | $ | (3,480 | ) | $ | — | $ | — | $ | 2,877 | |||||||||
(1) | Represents the discount on accounts receivable purchased in accordance with the Utility segment’s 2005 New York rate settlement. | |
(2) | Represents amounts reclassified from regulatory asset and regulatory liability accounts under various rate | |
Amounts represent net accounts receivable written-off. |
113
Item 9 | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
Item 9A Controls and Procedures
The following information includes the evaluation of disclosure controls and procedures by the Company’s Chief Executive Officer and Treasurer, along with any significant changes in internal controls of the Company.
Changes in Internal Controls Over Financial Reporting
The Company maintains a system ofis responsible for establishing and maintaining adequate internal control over financial reporting thatas defined inRules 13a-15(f) and15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed to provide reasonable assurance thatregarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with GAAP. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
100
Item 9B | Other Information |
Item 11 | Executive Compensation |
17, 200515, 2007 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004.2006. The information concerning executive compensation is set forth in the definitive Proxy Statement under the captionsheadings “Executive Compensation” and “Compensation Committee Interlocks and Insider Participation” and, excepting the “Report of the Compensation Committee” and the “Corporate Performance Graph,” is incorporated herein by reference.Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
(a) | Security Ownership of Certain Beneficial Owners |
101
(b) | Security Ownership of Management |
17, 200515, 2007 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004.2006. The information concerning security ownership of management is set forth in the definitive Proxy Statement under the captionheading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.
115
(c) | Changes in Control |
Item 13 Certain Relationships and Related Transactions
17, 200515, 2007 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004.2006. The information regarding certain relationships and related transactions is set forth in the definitive Proxy Statement under the captionheading “Compensation Committee Interlocks and Insider Participation” and is incorporated herein by reference.Item 14 Principal Accountant Fees and Services
17, 200515, 2007 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2004.2006. The information concerning principal accountant fees and services is set forth in the definitive Proxy Statement under the captionheading “Audit Fees” and is incorporated herein by reference.Item 15 Exhibits and Financial Statement Schedules Exhibit NumberDescription of Exhibits 3(i) Articles of Incorporation: • Restated Certificate of Incorporation of National Fuel Gas Company dated September 21, 1998 (Exhibit 3.1,Form 10-K for fiscal year ended September 30, 1998 in File No. 1-3880) • Certificate of Amendment of Restated Certificate of Incorporation (Exhibit 3(ii),Form 8-K dated March 14, 2005 in File No. 1-3880) 3(ii) By-Laws: • National Fuel Gas Company By-Laws as amended on December 9, 2004 (Exhibit 3(ii),Form 8-K dated December 9, 2004 in File No. 1-3880) (4)4 Instruments Defining the Rights of Security Holders, Including Indentures: • Indenture, dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 2(b) in File No. 2-51796) 102ExhibitNumberDescription of Exhibits • Third Supplemental Indenture, dated as of December 1, 1982,to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(a)(4) in File No.33-49401) • Eleventh Supplemental Indenture, dated as of May 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(b),Form 8-K dated February 14, 1992 in File No. 1-3880)
116
Exhibit | Description of | |||
Number | Exhibits | |||
• | Twelfth Supplemental Indenture, dated as of June 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(c),Form 8-K dated June 18, 1992 in File No. 1-3880) | |||
• | Thirteenth Supplemental Indenture, dated as of March | |||
• | Fourteenth Supplemental Indenture, dated as of July 1, 1993,to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1,Form 10-K for fiscal year ended September 30, 1993 in File No. 1-3880) | |||
• | Fifteenth Supplemental Indenture, dated as of September | |||
• | Indenture dated as of October 1, 1999, between the Company and The Bank of New York (Exhibit 4.1,Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) | |||
• | Officers Certificate Establishing Medium-Term Notes, dated October 14, 1999 (Exhibit 4.2,Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) | |||
• | Amended and Restated Rights Agreement, dated as of April | |||
• | Certificate of Adjustment, dated September 7, 2001, to the Amended and Restated Rights Agreement dated as of April | |||
• | Officers Certificate establishing 6.50% Notes due 2022, dated September 18, 2002 (Exhibit 4,Form 8-K dated October 3, 2002 in File No. 1-3880) | |||
• | Officers Certificate establishing 5.25% Notes due 2013, dated February 18, 2003 (Exhibit 4,Form 10-Q for the quarterly period ended March 31, 2003 in File No. 1-3880) | |||
Material Contracts: | ||||
| Contracts | |||
• | ||||
• | ||||
Compensatory plans, contracts or arrangements: | ||||
• | ||||
Form of Employment Continuation and Noncompetition Agreement, dated as of December 11, 1998, among the Company, National Fuel Gas Distribution Corporation and each of Philip C. Ackerman, Anna Marie Cellino, |
103
• | Form of Employment Continuation and Noncompetition Agreement, dated as of December 11, 1998, among the Company, National Fuel Gas Supply Corporation and | |||
• | ||||
National Fuel Gas Company 1993 Award and Option Plan, dated February 18, 1993 (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 1993 in File No. 1-3880) | ||||
• | Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated October 27, 1995 (Exhibit 10.8,Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880) | |||
• | Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated December 11, 1996 (Exhibit 10.8,Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880) | |||
• | Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated December 18, 1996 (Exhibit 10,Form 10-Q for the quarterly period ended December 31, 1996 in File No. 1-3880) |
117
Exhibit | Description of | |||
Number | Exhibits | |||
• | National Fuel Gas Company 1993 Award and Option Plan, amended through June 14, 2001 (Exhibit 10.1,Form 10-K for fiscal year ended September 30, 2001 in File No. 1-3880) | |||
• | National Fuel Gas Company 1993 Award and Option Plan, amended through September 8, 2005 (Exhibit 10.2,Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880) | |||
• | Administrative Rules with Respect to At Risk Awards under the 1993 Award and Option Plan (Exhibit 10.14,Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880) | |||
• | National Fuel Gas Company 1997 Award and Option Plan, amended through | |||
• | ||||
• | Form of Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.1,Form 8-K dated May 16, 2006 in File No. 1-3880) | |||
• | Administrative Rules with Respect to At Risk Awards under the 1997 Award and Option Plan amended and restated as of September 8, 2005 (Exhibit 10.4,Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880) | |||
• | Description of performance goals for Chief Executive Officer under the Company’s Annual At Risk Compensation Incentive Program (Exhibit 10,Form 10-Q for the quarterly period ended December 31, 2004 in File No. 1-3880) | |||
• | Description of performance goals for Chief Executive Officer under the Company’s Annual At Risk Compensation Incentive Program (Exhibit 10.2,Form 10-Q for the quarterly period ended December 31, 2005 in File No. 1-3880) | |||
• | Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas Company, as amended and restated, effective March 9, 2005 (Exhibit 10.2,Form 10-Q for the quarterly period ended March 31, 2005 in File No. 1-3880) | |||
• | National Fuel Gas Company Deferred Compensation Plan, as amended and restated through May 1, 1994 (Exhibit 10.7, | |||
• | Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 27, 1995 (Exhibit 10.9,Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880) | |||
• | Amendment to National Fuel Gas Company Deferred Compensation Plan, dated September 19, 1996 (Exhibit 10.10,Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880) | |||
• | ||||
National Fuel Gas Company Deferred Compensation Plan, as amended and restated through March 20, 1997 | ||||
• | Amendment to National Fuel Gas Company Deferred Compensation Plan, dated June 16, 1997 (Exhibit 10.4,Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880) | |||
• | Amendment No. 2 to the National Fuel Gas Company Deferred Compensation Plan, dated March 13, 1998 (Exhibit 10.1, | |||
• | Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated February 18, 1999 (Exhibit10.1,Form 10-Q for the quarterly period ended March 31, 1999 in File No. 1-3880) | |||
• | Amendment to National Fuel Gas Company Deferred Compensation Plan, dated June 15, 2001 (Exhibit 10.3,Form 10-K for fiscal year ended September 30, 2001 in File No. 1-3880) | |||
• | Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated October 21, 2005 (Exhibit 10.5,Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880) | |||
• | Form of Letter Regarding Deferred Compensation Plan and Internal Revenue Code Section 409A, dated July 12, 2005 (Exhibit 10.6,Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880) | |||
• | National Fuel Gas Company Tophat Plan, effective March 20, 1997 (Exhibit 10,Form 10-Q for the quarterly period ended June 30, 1997 in File No. 1-3880) | |||
• | Amendment No. 1 to National Fuel Gas Company Tophat Plan, dated April 6, 1998 (Exhibit 10.2,Form 10-K for fiscal year ended September 30, 1998 in File No. 1-3880) |
118
Exhibit | Description of | |||
Number | Exhibits | |||
• | Amendment No. 2 to National Fuel Gas Company Tophat Plan, dated December 10, 1998 (Exhibit 10.1,Form 10-Q for the quarterly period ended December 31, 1998 in File No. 1-3880) | |||
• | ||||
• |
104
Exhibit | ||||
Number | Description of Exhibits | |||
• | Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 17, 1997 between the Company and Philip C. Ackerman (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880) | |||
• | Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and Philip C. Ackerman, dated March 23, 1999 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) | |||
• | Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and Joseph P. Pawlowski (Exhibit 10.7, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880) | |||
• | Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and Joseph P. Pawlowski, dated March 23, 1999 (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) | |||
• | Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and Dennis J. Seeley (Exhibit 10.9, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) | |||
• | Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and Dennis J. Seeley, dated March 29, 1999 (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) | |||
• | Split Dollar Insurance and Death Benefit Agreement dated September 15, 1997, between the Company and Bruce H. Hale (Exhibit 10.11, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) | |||
• | Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and between the Company and Bruce H. Hale, dated March 29, 1999 (Exhibit 10.12, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) | |||
• | Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and David F. Smith (Exhibit 10.13, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) | |||
• | Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and between the Company and David F. Smith, dated March 29, 1999 (Exhibit 10.14, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) | |||
10 | .1 | National Fuel Gas Company Parameters for Executive Life Insurance Plan | ||
• | National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan as amended and restated through November 1, 1995 (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880) | |||
10 | .2 | National Fuel Gas Company Participating Subsidiaries Executive Retirement Plan 2003 Trust Agreement (I), dated September 1, 2003 | ||
• | National Fuel Gas Company and Participating Subsidiaries 1996 Executive Retirement Plan Trust Agreement (II), dated May 10, 1996 (Exhibit 10.13, Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880) | |||
• | Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated September 18, 1997 (Exhibit 10.9, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880) | |||
• | Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated December 10, 1998 (Exhibit 10.2, Form 10-Q for the quarterly period ended December 31, 1998 in File No. 1-3880) | |||
• | Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 16, 1999 (Exhibit 10.15, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) |
105
Exhibit | ||||
Number | Description of Exhibits | |||
• | Amendment to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 5, 2001 (Exhibit 10.4, Form 10-K/A for fiscal year ended September 30, 2001, in File No. 1-3880) | |||
• | Retirement Supplement Agreement, dated January 11, 2002, between the Company and Joseph P. Pawlowski (Exhibit 10.6, Form 10-K/A for fiscal year ended September 30, 2001 in File No. 1-3880) | |||
• | Amendment No. 1 to Retirement Supplement Agreement, dated March 11, 2004, between the Company and Joseph P. Pawlowski (Exhibit 10(iii), Form 10-Q for the quarterly period ended March 31, 2004 in File No. 1-3880) | |||
• | Administrative Rules with Respect to At Risk Awards under the 1993 Award and Option Plan (Exhibit 10.14, Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880) | |||
• | Administrative Rules with Respect to At Risk Awards under the 1997 Award and Option Plan (Exhibit A, Definitive Proxy Statement, Schedule 14(A) filed January 10, 2002 in File No. 1-3880) | |||
10 | .3 | Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas Company, as amended and restated, effective September 9, 2004 | ||
• | Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of March 20, 1997 regarding the Retainer Policy for Non-Employee Directors (Exhibit 10.11, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880) | |||
10 | .4 | Retirement and Consulting Agreement, dated September 5, 2001, between the Company and Bernard J. Kennedy | ||
(12 | ) | Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the fiscal years ended September 30, 1998 through 2003 | ||
(21 | ) | Subsidiaries of the Registrant: See Item 1 of Part I of this Annual Report on Form 10-K | ||
(23 | ) | Consents of Experts: | ||
23 | .1 | Consent of Ralph E. Davis Associates, Inc. regarding Seneca Resources Corporation | ||
23 | .2 | Consent of Ralph E. Davis Associates, Inc. regarding Seneca Energy Canada, Inc. | ||
23 | .3 | Consent of Independent Accountants | ||
(31 | ) | Rule 13a-15(e)/15d-15(e) Certifications | ||
31 | .1 | Written statements of Chief Executive Officer pursuant to Rule 13a-15(e)/15d-15(e) of the Exchange Act. | ||
31 | .2 | Written statements of Principal Financial Officer pursuant to Rule 13a-15(e)/15d-15(e) of the Exchange Act. | ||
(32 | ) | Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | ||
(99 | ) | Additional Exhibits: | ||
99 | .1 | Report of Ralph E. Davis Associates, Inc. regarding Seneca Resources Corporation | ||
99 | .2 | Report of Ralph E. Davis Associates, Inc. regarding Seneca Energy Canada, Inc. | ||
99 | .3 | Company Maps | ||
• | The Company agrees to furnish to the SEC upon request the following instruments with respect to long-term debt that the Company has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(ii)(A): | |||
Secured Credit Agreement, dated as of June 5, 1997, among the Empire State Pipeline, as borrower, Empire State Pipeline, Inc., the Lenders party thereto, JPMorgan Chase Bank (f/k/a The Chase Manhattan Bank), as administrative agent, and Chase Securities, as arranger. | ||||
First Amendment to Secured Credit Agreement, dated as of May 28, 2002, among Empire State Pipeline, as borrower, Empire State Pipeline, Inc., St. Clair Pipeline Company, Inc., the Lenders party to the Secured Credit Agreement, and JPMorgan Chase Bank, as administrative agent. | ||||
Second Amendment to Secured Credit Agreement, dated as of February 6, 2003, among Empire State Pipeline, as borrower, Empire State Pipeline, Inc., St. Clair Pipeline Company, Inc., the Lenders party to the Secured Credit Agreement, as amended, and JPMorgan Chase Bank, as administrative agent. |
106
• | ||||
• | Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and Philip C. Ackerman, dated March 23, 1999 (Exhibit 10.3,Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) | |||
Amended and Restated Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the | ||||
• | Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and between the Company and Dennis J. Seeley, dated March 29, 1999 (Exhibit 10.10,Form | |||
• | Split Dollar Insurance and Death Benefit Agreement dated September 15, 1997, between the Company and Bruce H. Hale (Exhibit 10.11,Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) | |||
• | Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and between the Company and Bruce H. Hale, dated March 29, 1999 (Exhibit 10.12,Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) | |||
• | Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and David F. Smith (Exhibit 10.13,Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) | |||
• | Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and between the Company and David F. Smith, dated March 29, 1999 (Exhibit 10.14,Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) | |||
• | National Fuel Gas Company Parameters for Executive Life Insurance Plan (Exhibit 10.1,Form 10-K for fiscal year ended September 30, 2004 in File No. 1-3880) | |||
• | National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan as amended and restated through November 1, 1995 (Exhibit 10.10,Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880) | |||
• | Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated September 18, 1997 (Exhibit 10.9,Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880) | |||
• | Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated December 10, 1998 (Exhibit 10.2,Form 10-Q for the quarterly period ended December 31, 1998 in File No. 1-3880) | |||
• | Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 16, 1999 (Exhibit 10.15,Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) | |||
• | Amendment to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, effective September 5, 2001 (Exhibit 10.4,Form 10-K/A for fiscal year ended September 30, 2001, in File No. 1-3880) | |||
• | National Fuel Gas Company and Participating Subsidiaries 1996 Executive Retirement Plan Trust Agreement (II), dated May 10, 1996 (Exhibit 10.13,Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880) |
119
107
Exhibit | Description of | |||
Number | Exhibits | |||
• | National Fuel Gas Company Participating Subsidiaries Executive Retirement Plan 2003 Trust Agreement (I), dated September 1, 2003 (Exhibit 10.2,Form 10-K for fiscal year ended September 30, 2004 in File No. 1-3880) | |||
• | National Fuel Gas Company Performance Incentive Program (Exhibit 10.1,Form 8-K dated June 3, 2005 in File No. 1-3880) | |||
• | Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of March 20, 1997 regarding the Retainer Policy for Non-Employee Directors (Exhibit 10.11,Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880) | |||
• | Retirement Benefit Agreement for David F. Smith, dated September 22, 2003,between the Company and David F. Smith (Exhibit 10.2,Form10-K for fiscal year ended September 30, 2003 in File No. 1-3880) | |||
• | Amendment No. 1 to the Retirement Benefit Agreement for David F. Smith, dated September 8, 2005, between the Company and David F. Smith (Exhibit 10.8,Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880) | |||
• | Description of performance goals for certain executive officers (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 2005 in File No. 1-3880) | |||
• | Retirement Agreement, dated August 1, 2005, between the Company and Bruce H. Hale (Exhibit 10.9,Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880) | |||
• | Commission Agreement, dated August 1, 2005, between the Company and Bruce H. Hale (Exhibit 10.10,Form 10-K for fiscal year ended September 30, 2005 in File No. 1-3880) | |||
• | Description of bonuses awarded to executive officer (Exhibit 10.1,Form 10-Q for the quarterly period ended March 31, 2006 in File No. 1-3880) | |||
• | Description of performance goals for certain executive officers (Exhibit 10.2,Form 10-Q for the quarterly period ended March 31, 2006 in File No. 1-3880) | |||
• | Noncompete and Restrictive Covenant Agreement, dated February 1, 2006, between the Company and Dennis J. Seeley (Exhibit 10.3,Form 10-Q for the quarterly period ended March 31, 2006 in File No. 1-3880) | |||
• | Description of salaries of certain executive officers (Exhibit 10.4,Form 10-Q for the quarterly period ended March 31, 2006 in File No. 1-3880) | |||
• | Description of assignment of interests in certain life insurance policies (Exhibit 10.1,Form 10-Q for the quarterly period ended June 30, 2006 in File No. 1-3880) | |||
• | Description of long-term performance incentives under the National Fuel Gas Company Performance Incentive Program (Exhibit 10.2,Form 10-Q for the quarterly period ended June 30, 2006 in File No. 1-3880) | |||
• | Description of agreement between the Company and Philip C. Ackerman regarding death benefit (Exhibit 10.3,Form 10-Q for the quarterly period ended June 30, 2006 in File No. 1-3880) | |||
10 | .1 | Agreement, dated September 24, 2006, between the Company and Philip C. Ackerman regarding death benefit | ||
• | Retirement Agreement, dated July 1, 2006, between the Company and James A. Beck (Exhibit 10.4,Form 10-Q for the quarterly period ended June 30, 2006 in File No. 1-3880) | |||
• | Contract for Consulting Services, dated July 1, 2006, between the Company and James A. Beck (Exhibit 10.5,Form 10-Q for the quarterly period ended June 30, 2006 in File No. 1-3880) | |||
12 | Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the fiscal years ended September 30, 2002 through 2006 | |||
21 | Subsidiaries of the Registrant: See Item 1 of Part I of this Annual Report onForm 10-K | |||
23 | Consents of Experts: | |||
23 | .1 | Consent of Ralph E. Davis Associates, Inc. regarding Seneca Resources Corporation | ||
23 | .2 | Consent of Ralph E. Davis Associates, Inc. regarding Seneca Energy Canada, Inc. | ||
23 | .3 | Consent of Independent Registered Public Accounting Firm | ||
31 | Rule 13a-15(e)/15d-15(e) Certifications |
120
Exhibit | Description of | |||
Number | Exhibits | |||
31 | .1 | Written statements of Chief Executive Officer pursuant toRule 13a-15(e)/15d-15(e) of the Exchange Act. | ||
31 | .2 | Written statements of Principal Financial Officer pursuant toRule 13a-15(e)/15d-15(e) of the Exchange Act. | ||
32•• | Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |||
99 | Additional Exhibits: | |||
99 | .1 | Report of Ralph E. Davis Associates, Inc. regarding Seneca Resources Corporation | ||
99 | .2 | Report of Ralph E. Davis Associates, Inc. regarding Seneca Energy Canada, Inc. | ||
99 | .3 | Company Maps | ||
• | The Company agrees to furnish to the SEC upon request the following instruments with respect to long-term debt that the Company has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A): | |||
Secured Credit Agreement, dated as of June 5, 1997, among the Empire State Pipeline, as borrower, Empire State Pipeline, Inc., the Lenders party thereto, JPMorgan Chase Bank (f/k/a The Chase Manhattan Bank), as administrative agent, and Chase Securities, as arranger. | ||||
First Amendment to Secured Credit Agreement, dated as of May 28, 2002, among Empire State Pipeline, as borrower, Empire State Pipeline, Inc., St. Clair Pipeline Company, Inc., the Lenders party to the Secured Credit Agreement, and JPMorgan Chase Bank, as administrative agent. | ||||
Second Amendment to Secured Credit Agreement, dated as of February 6, 2003, among Empire State Pipeline, as borrower, Empire State Pipeline, Inc., St. Clair Pipeline Company, Inc., the Lenders party to the Secured Credit Agreement, as amended, and JPMorgan Chase Bank, as administrative agent. | ||||
• | Incorporated herein by reference as indicated. | |||
All other exhibits are omitted because they are not applicable or the required information is shown elsewhere in this Annual Report onForm 10-K. | ||||
•• | In accordance with Item 601(b) (32) (ii) ofRegulation S-K and SEC Release Nos.33-8238 and 34-47986, Final Rule: Management’s Reports on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports, the material contained in Exhibit 32 is ‘‘furnished” and not deemed ‘‘filed” with the SEC and is not to be incorporated by reference into any filing of the Registrant under the Securities Act of 1933 or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing, except to the extent that the Registrant specifically incorporates it by reference. |
121
By | /s/ P. C. |
7, 2006
Signature | ||||||
/s/ P. C. P. C. AckermanAckerman | Chairman of the Board, | Date: December | ||||
/s/ R. T. R. T. BradyBrady | Director | Date: December | ||||
/s/ R. D. R. D. CashCash | Director | Date: December | ||||
/s/ R. E. R. E. KidderKidder | Director | Date: December | ||||
/s/ C. G. Matthews | Director | Date: December | ||||
/s/ G. L. G. L. MazanecMazanec | Director | Date: December | ||||
/s/ R. G. Reiten R. G. Reiten | Director | Date: December 7, 2006 | ||||
/s/ J. F. J. F. RiordanRiordan | Director | Date: December | ||||
/s/ R. J. R. J. TanskiTanski | Treasurer and Principal Financial Officer | Date: December | ||||
/s/ K. M. K. M. CamioloCamiolo | Controller and Principal Accounting Officer | Date: December |
122
108