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Exhibit 99.2
Financial Review
Key Events in 2001
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- In March we raised approximately $332 million through the sale of shares of our common stock.
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- We completed an initial public offering of Class A Aquila common shares in April, which raised approximately $446 million in net proceeds and left us with an 80% interest in the subsidiary.
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- In June, we exchanged $189.5 million of senior notes with interest rates ranging from 8.0% to 9.0% for $200 million of new senior notes with interest rates at 7.75%, maturing in June 2011. We also retired $204.1 million of senior notes, mortgage bonds and company-obligated preferred securities.
- •
- We formed a partnership in August with ArcLight Energy Partners Fund I, L.P. to buy a gas storage facility under construction near Sacramento, California. The cost to acquire and complete the facility is about $220 million. Our investment in this project is expected to be $25.0 million. We expect to complete the purchase in the second quarter of 2002, subject to regulatory approval.
- •
- We have agreed to acquire Midlands Electricity plc for $362 million. Midlands is the fourth-largest regional electric company in the United Kingdom. The transaction is expected to close in the first quarter of 2002. Midlands also has $1.7 billion of debt that would be non-recourse to us.
- •
- We announced in November that we would offer to acquire all outstanding publicly held shares of Aquila in exchange for shares of UtiliCorp common stock. We completed the exchange offer in January 2002 by issuing about 12.6 million UtiliCorp common shares. At that time Aquila again became a wholly owned subsidiary and public trading of its shares ceased.
- •
- In December 2001, Enron Corporation filed for bankruptcy. As a result, we made provisions for receivables and open trade positions of $40 million on an after-tax basis.
This review of 2001 performance is organized by business segment, reflecting the way we manage our businesses. Each business unit leader is responsible for operating results, expressed as earnings before interest and taxes (EBIT). Therefore, each segment discussion focuses on the factors affecting EBIT.
We use the term "Operating EBIT" to describe our recurring earnings before interest and taxes excluding items we deem to be non-recurring. The term is not meant to replace actual EBIT or other performance measures used under generally accepted accounting principles.
We generally make decisions on finance, dividends and taxes at the corporate level. We discuss those topics separately on a consolidated basis.
In 2001, our performance versus our main financial objective was as follows:
| | 2001
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| | Objective
| | Result
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| Operating earnings per share growth | | 15 | % | 17 | % |
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At the end of 2001, our three-year total shareholder return was 15.4%. Total shareholder return is a measure of the change in price of our common stock over the period plus dividends paid.
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Operating Earnings Before Interest and Taxes
A summary of our Operating EBIT by business segment is shown below.
| | 2001
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| | 2000
| | 1999
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| | (Dollars in millions, except per share)
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| Merchant Services: | | | | | | | | | | | | |
| | Wholesale Services | | $ | 296.5 | | 43.1 | % | $ | 148.3 | | $ | 40.7 | |
| | Capacity Services | | | 113.7 | | 16.5 | | | 53.6 | | | 39.0 | |
| | Minority Interest | | | (26.4 | ) | (3.8 | ) | | — | | | — | |
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| Total Merchant Services | | | 383.8 | | 55.8 | | | 201.9 | | | 79.7 | |
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| Global Networks Group: | | | | | | | | | | | | |
| | International Networks | | | 133.0 | | 19.3 | | | 114.0 | | | 129.9 | |
| | Domestic Networks | | | 166.2 | | 24.1 | | | 219.6 | | | 208.3 | |
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| Total Global Networks Group | | | 299.2 | | 43.4 | | | 333.6 | | | 338.2 | |
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| Corporate and other | | | 5.7 | | .8 | | | (12.3 | ) | | (3.9 | ) |
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| Total Operating EBIT | | $ | 688.7 | | 100.0 | % | $ | 523.2 | | $ | 414.0 | |
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| Operating Earnings Per Share—Diluted | | $ | 2.44 | | | | $ | 2.08 | | $ | 1.75 | |
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| Actual Earnings Per Share—Diluted | | $ | 2.42 | | | | $ | 2.21 | | $ | 1.75 | |
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Non-Recurring Items
Our earnings before interest and taxes (EBIT) and diluted earnings per share (EPS) for the three years ended December 31, 2001 were affected by several items that we expect will not have a continuing impact on our financial position or results of operations. The table below summarizes the effect of non-recurring items on EBIT and diluted EPS.
| | Year Ended December 31,
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| | 2001
| | 2000
| | 1999
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| | EBIT
| | EPS
| | EBIT
| | EPS
| | EBIT
| | EPS
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| | (In millions, except per share)
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| Actual | | $ | 704.7 | | $ | 2.42 | | $ | 540.0 | | $ | 2.21 | | $ | 414.0 | | $ | 1.75 |
| Gain on sale of Aquila shares(a) | | | (110.8 | ) | | (.51 | ) | | — | | | — | | | — | | | — |
| Enron exposures(b) | | | 66.8 | | | .34 | | | — | | | — | | | — | | | — |
| Communications construction and lease terminations(c) | | | 16.5 | | | .09 | | | 4.0 | | | .02 | | | — | | | — |
| Australia asset valuation reserves(d) | | | 11.5 | | | .10 | | | — | | | — | | | — | | | — |
| Gain on Uecomm IPO(e) | | | — | | | — | | | (44.0 | ) | | (.30 | ) | | — | | | — |
| Merchant asset impairments(f) | | | — | | | — | | | 10.8 | | | .07 | | | — | | | — |
| Corporate charge for technology assets and intangibles(g) | | | — | | | — | | | 12.4 | | | .08 | | | — | | | — |
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| Operating | | $ | 688.7 | | $ | 2.44 | | $ | 523.2 | | $ | 2.08 | | $ | 414.0 | | $ | 1.75 |
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- (a)
- In 2001, we sold 5.75 million shares of Aquila as part of the initial public offering of that subsidiary and realized a gain of $110.8 million.
- (b)
- In 2001, we wrote off exposures related to the Enron bankruptcy of $35.0 million in Aquila and $31.8 million in Domestic Networks.
- (c)
- In 2001, we recorded charges of $16.5 million in our communications business related to preliminary system design and leases in markets we do not intend to develop. In 2000, we recorded a charge of $4.0 million related to the construction of our fiber-optic communications network.
- (d)
- In 2001, we recorded charges of $11.5 million in our Australian networks related to valuation allowances on certain deferred taxes and collectibility of certain receivables.
- (e)
- In 2000, we recorded a $44.0 million gain on the initial public offering of 34% of Uecomm Ltd. by United Energy.
- (f)
- In 2000, we recorded an asset impairment charge of $7.8 million on certain under-performing pipeline assets and $3.0 million on certain retail assets in the United Kingdom.
- (g)
- In 2000, we recorded charges of $10.0 million related to certain information technology assets that are no longer used and $2.4 million related to certain corporate identity intangibles.
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Merchant Services
In Merchant Services, we conduct our business through Aquila, Inc. (Aquila) in two segments, Wholesale Services and Capacity Services. Wholesale Services includes our North American and European commodity and client (including our capital services business) businesses. Capacity Services primarily consists of power development, natural gas gathering and processing operations, and investments in independent power projects.
In 1999, 2000 and the first four months of 2001, we owned 100% of Aquila. In April 2001, approximately 20% of Aquila was sold to the public. In connection with the initial public offering of Aquila, we sold 5.75 million previously issued shares and realized a pretax gain of approximately $110.8 million. In January 2002, we acquired the outstanding public shares of Aquila in an exchange offer and merger. Aquila was consolidated in each year with a minority interest reflected in 2001. The following Merchant Services financial information includes 100% of Aquila before minority interest, which totaled $26.4 million for the year ended December 31, 2001.
Impact of Enron on the Commodity Markets
Enron Corporation has been the dominant company in the energy commodity markets in recent years with its proprietary electronic trading platform, EnronOnLine, processing a significant share of the trading volume in the market. When Enron's financial difficulties became public in late 2001, many companies doing business with Enron and using EnronOnLine began to look to other energy companies, including Aquila, and other trading platforms for their energy and risk management needs. Aquila experienced a 52% increase in total Btu equivalent per day volumes during the fourth quarter of 2001 over 2000. It is difficult to directly attribute this increase to the absence of Enron from the market; however, we believe a portion of the increase was Enron-related. Intercontinental Exchange (ICE), in which Aquila has a 5% ownership interest, also experienced increased activity as the markets shifted from EnronOnLine to other electronic trading platforms. Total volumes and users on ICE increased by 65% and 30%, respectively, from October to November 2001. ICE also had an increased volume of gas and power trades for next-day delivery rather than next-month delivery in response to shortened timeframes for planning. We also had an increase in the number of client transactions in the fourth quarter of 2001 compared to 2000. It is still too early to predict how transactions, volumes and earnings will be affected by the Enron bankruptcy, but overall we believe the situation has created a number of market opportunities for us.
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Three-Year Review—Wholesale Services
| | Year Ended December 31,
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| | 2001
| | 2000
| | 1999
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| | (Dollars in millions)
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| Sales | | $ | 36,607.1 | | $ | 25,662.5 | | $ | 16,345.2 | |
| Cost of sales | | | 35,976.7 | | | 25,219.4 | | | 16,167.0 | |
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| Gross profit | | | 630.4 | | | 443.1 | | | 178.2 | |
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| Operating expenses: | | | | | | | | | | |
| | Operating expense | | | 352.4 | | | 315.6 | | | 148.8 | |
| | Depreciation and amortization expense | | | 16.2 | | | 16.5 | | | 9.6 | |
| | Impairments and other charges | | | 35.0 | | | 3.0 | | | — | |
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| Total operating expenses | | | 403.6 | | | 335.1 | | | 158.4 | |
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| Equity in earnings of investments | | | .2 | | | — | | | — | |
| Other income (expense) | | | 34.5 | | | 37.3 | | | 20.9 | |
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| Earnings before interest and taxes (EBIT) | | | 261.5 | | | 145.3 | | | 40.7 | |
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| Non-recurring items: | | | | | | | | | | |
| | Enron exposure | | | 35.0 | | | — | | | — | |
| | Retail asset impairments | | | — | | | 3.0 | | | — | |
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| Operating EBIT | | $ | 296.5 | | $ | 148.3 | | $ | 40.7 | |
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| Operating EBIT contribution to UtiliCorp | | | 43.1 | % | | 28.3 | % | | 9.8 | % |
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| Identifiable assets | | $ | 4,653.5 | | $ | 6,505.0 | | $ | 2,153.7 | |
| Average value at risk | | $ | 11.3 | | $ | 6.9 | | $ | 4.6 | |
| Total Btu equivalent per day | | | 24.6 | | | 18.4 | | | 18.0 | |
| Physical gas volumes marketed(billion cubic feet per day) | | | 13.5 | | | 12.0 | | | 10.5 | |
| Electricity volumes marketed(megawatt-hours 000's) | | | 350,000 | | | 189,900 | | | 236,500 | |
| Natural gas—average price per thousand cubic feet | | $ | 3.91 | | $ | 3.71 | | $ | 2.15 | |
| Electricity—average price per megawatt-hour | | $ | 50.24 | | $ | 49.45 | | $ | 33.68 | |
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2001 versus 2000
Sales, Cost of Sales and Gross Profit
Sales and cost of sales for our Wholesale Services operations increased 43% in 2001 compared to 2000. Gross profit increased $187.3 million or 42% in 2001 compared to 2000. These increases were primarily due to the following:
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- A volatile pricing environment for gas and electricity, particularly in early 2001, provided opportunities to execute our strategies and deliver products and services to our clients.
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- Electricity and gas volumes marketed in 2001 increased 84% and 13%, respectively, over 2000, contributing to a combined 34% increase on a total Btu equivalent per day (Tbtue/d) basis. These increases, together with a 27% increase in the number of commodity transactions executed, contributed to the increase in sales, cost of sales and gross profit.
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- A 5% increase in average gas prices also increased our sales and cost of sales.
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- A 28% increase in the number of client transactions in 2001 compared to 2000 contributed to a 34% increase in gross profit from our origination deals and from the more highly customized products we call Client Services. These products include our GuaranteedWeather® and GuaranteedGenerationSM products as well as our longer-duration gas and electric contracts.
Operating Expenses
Total operating expenses increased $68.5 million due to the write-off of approximately $35.0 million related to our trading exposures with Enron, the continued expansion of the merchant business and our strong performance resulting in higher incentive compensation expense. Also impacting operating expenses was the allocation of $11.5 million of expenses from Corporate and other. While the $35.0 million write-off represents our best estimate of our exposure based on our contracts with Enron, the ultimate outcome is subject to review by the bankruptcy courts.
2000 versus 1999
Sales, Cost of Sales and Gross Profit
Sales and cost of sales for our Wholesale Services operations increased $9.3 billion and $9.1 billion, respectively, in 2000 compared to 1999. These increases were primarily due to higher prices for electricity and natural gas in 2000.
Gross profit increased $264.9 million in 2000 compared to 1999. The increase in gross profit was primarily due to the following:
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- Strong wholesale commodity results in our gas, power and origination businesses are due to several factors, principally related to excellent execution in a favorable pricing environment. Natural gas and electricity prices increased 73% and 47%, respectively, in 2000 compared to 1999. Electricity volumes in 2000 were lower than in 1999, due to the shorter duration of our portfolio combined with higher price volatility.
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- Expansion of our GuaranteedWeather® and GuaranteedGenerationSM products compared to 1999. We started our weather business in 1997 and GuaranteedGenerationSM in 1999. Combined with our natural gas and power origination businesses, deal flow in all origination businesses combined was up 231%.
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- Gross profit in 1999 included a $19.8 million loss from the retail gas supply business we sold in January 2000.
Operating Expenses
Total operating expenses increased $176.7 million due to the expansion of Aquila's business along with higher incentive compensation expense resulting from our strong performance in 2000. Also, bad debt expense was higher in 2000 due to the expansion of our overall business and certain accounts receivable that were not collectible. Depreciation expense was $6.9 million higher primarily due to the additional
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investments in technology assets. In 2000, we also recognized impairment charges of $3.0 million on retail assets in the U.K.
Other Income (Expense)
Other income (expense) increased $16.4 million in 2000 compared to 1999. This increase mainly stems from our Merchant Notes Receivable which increased by 75% in 2000 compared to 1999, resulting in increased interest income. This increase was the result of an increase in the number of financing transactions, reflecting higher demand for capital in the exploration and production market. This increase was partially offset by fees associated with the increased amount of accounts receivable we sold in 2000 compared to 1999.
Three-Year Review—Capacity Services
| | Year Ended December 31,
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| | 2001
| | 2000
| | 1999
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| | (Dollars in millions)
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| Sales | | $ | 1,162.9 | | $ | 815.6 | | $ | 384.8 | |
| Cost of sales | | | 952.7 | | | 681.5 | | | 289.5 | |
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| Gross profit | | | 210.2 | | | 134.1 | | | 95.3 | |
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| Operating expenses: | | | | | | | | | | |
| | Operating expense | | | 92.5 | | | 66.7 | | | 48.7 | |
| | Depreciation and amortization expense | | | 39.3 | | | 32.3 | | | 29.5 | |
| | Impairments and other charges | | | — | | | 7.8 | | | — | |
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| Total operating expenses | | | 131.8 | | | 106.8 | | | 78.2 | |
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| Equity in earnings of investments | | | 32.4 | | | 18.4 | | | 34.7 | |
| Other income (expense) | | | 2.9 | | | .1 | | | (12.8 | ) |
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| Earnings before interest and taxes (EBIT) | | | 113.7 | | | 45.8 | | | 39.0 | |
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| Non-recurring items: | | | | | | | | | | |
| | Pipeline asset impairments | | | — | | | 7.8 | | | — | |
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| Operating EBIT | | $ | 113.7 | | $ | 53.6 | | $ | 39.0 | |
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| Operating EBIT contribution to UtiliCorp | | | 16.5 | % | | 10.2 | % | | 9.4 | % |
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| Identifiable assets | | $ | 1,595.1 | | $ | 1,382.1 | | $ | 935.4 | |
| Power capacity owned/controlled(megawatts) | | | 4,357 | | | 4,107 | | | 546 | |
| Gas throughput volumes(million cubic feet per day) | | | 381 | | | 449 | | | 548 | |
| Natural gas liquids—average price per gallon | | $ | .44 | | $ | .47 | | $ | .31 | |
| Natural gas liquids produced(thousand barrels per day) | | | 20 | | | 22 | | | 22 | |
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2001 versus 2000
Sales, Cost of Sales and Gross Profit
Sales and cost of sales for our Capacity Services operations increased 43% and 40%, respectively, in 2001 compared to 2000. Gross profit increased $76.1 million. These increases were primarily the result of the following factors:
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- The GPU International acquisition in December 2000 added approximately $54.9 million to gross profit in 2001 while adding $81.6 million and $26.7 million to sales and cost of sales, respectively.
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- We secured power capacity prices on our generation assets above current market prices, improving our margins in 2001. We attempt to optimize asset positions with forward contracts from time to time. When we take these positions with derivative instruments, they are recorded at fair value while the underlying asset position is reflected at historical cost.
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- The additional sales and cost of sales are also the result of additional capacity brought on line.
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Operating Expenses
Total operating expenses increased $25.0 million in 2001 compared to 2000, primarily as the result of our GPU International acquisition in December 2000. In 2000, impairment charges of $7.8 million were recorded on certain pipeline related assets.
Equity in Earnings of Investments
Equity earnings increased $14.0 million in 2001 compared to 2000. Approximately $11.6 million of this increase relates to the equity investments in four independent power plants that we added to our power capacity as part of our acquisition of GPU International in December 2000.
2000 versus 1999
Sales, Cost of Sales and Gross Profit
Sales and cost of sales for our Capacity Services operations increased $430.8 million and $392.0 million, respectively, in 2000 compared to 1999. Gross profit increased $38.8 million in 2000 compared to 1999. These increases resulted primarily from the following factors:
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- Additional power capacity in the Southeast in 2000 and other contractual transactions added about $22 million to our gross profit.
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- A 52% increase in the average price of natural gas liquids contributed to a $20 million increase in gross profit.
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- Partially offsetting those increases was an 18% decrease in natural gas throughput volumes.
Operating Expenses
Total operating expenses increased $28.6 million due to establishing power development and analysis teams to support construction of power plants. In 2000, we also recognized impairment charges of $7.8 million on certain under-performing pipeline assets.
Equity in Earnings of Investments
Equity earnings decreased $16.3 million in 2000 compared to 1999. This was primarily due to the sale in late 1999 of our interest in a power project that contributed equity earnings of $17.1 million in 1999, including the gain on the sale of the project.
Current Operating Developments
Acquisitions. In August 2001, Aquila and a partner agreed to purchase a 12 Bef gas storage facility under development in Lodi, California. This facility is strategically located and is important in helping to meet the gas needs of the California energy market.
In January 2002, we acquired property and rights to develop a 12 Bcf gas storage facility near Kingman, Arizona. This facility is located to serve the Arizona, Nevada and California gas markets. The first phase of the facility, with a storage capacity of 6 Bcf, is expected to be in operation by the fourth quarter of 2003, with the full 12 Bcf planned for the fourth quarter of 2004.
Construction/Development.We currently have four power projects under construction or in development that will produce an additional 1,770 MW of power capacity. The work is largely ahead of schedule and below budget and three of the plants are expected to be on line for the 2002 cooling season.
Global Networks Group
Our Global Networks Group consists of our investments in international and domestic regulated electricity and gas utilities and communications networks. International Networks includes our investments in Canada, Australia and New Zealand. Our wholly owned Canadian electricity distribution company, UtiliCorp Networks Canada Ltd., has operations in the provinces of Alberta and British Columbia. Our Australian investments include a 34% interest in United Energy Limited, an electricity distribution company in the Melbourne area; a 25.5% interest in Multinet Gas, a gas distribution company in the Melbourne area; and a
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45% interest, held jointly with United Energy, in AlintaGas Limited, a gas distribution company in Western Australia. In New Zealand we have a 55.5% interest in UnitedNetworks Ltd., an electricity and gas distribution company based in Auckland. Domestic Networks includes our electricity and gas network businesses in Colorado, Iowa, Kansas, Michigan, Minnesota, Missouri and Nebraska. Also included are our 89% owned subsidiary, Everest Connections, a communications business that is rolling out comprehensive fiber-optic communication services in two Kansas City suburbs, and our 38% interest in Quanta Services, Inc. Quanta is the premier provider of field services to electric utilities, telecommunications and cable television companies, and governmental entities.
Three-Year Review—International Networks
| | Year Ended December 31,
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| | 2001
| | 2000
| | 1999
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| | (Dollars in millions)
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| Sales | | $ | 353.9 | | $ | 492.4 | | $ | 309.2 | |
| Cost of sales | | | 143.3 | | | 311.8 | | | 106.3 | |
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| Gross profit | | | 210.6 | | | 180.6 | | | 202.9 | |
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| Operating expenses: | | | | | | | | | | |
| Operating expense | | | 80.7 | | | 48.6 | | | 46.5 | |
| Depreciation and amortization expense | | | 55.8 | | | 45.5 | | | 42.2 | |
| Maintenance expense | | | 2.3 | | | 2.3 | | | 2.7 | |
| Taxes, other than income taxes | | | 15.8 | | | 13.5 | | | 11.6 | |
| Impairments and other charges | | | 11.5 | | | — | | | — | |
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| Total operating expenses | | | 166.1 | | | 109.9 | | | 103.0 | |
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| Equity in earnings of investments | | | 61.5 | | | 44.3 | | | 21.7 | |
| Minority interest in income of subsidiaries | | | — | | | (3.3 | ) | | (11.5 | ) |
| Gain on sale of subsidiary stock | | | — | | | 44.0 | | | — | |
| Other income (expense) | | | 15.5 | | | 2.3 | | | 19.8 | |
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| Earnings before interest and taxes (EBIT) | | | 121.5 | | | 158.0 | | | 129.9 | |
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| Non-recurring items: | | | | | | | | | | |
| Australian asset valuation reserves | | | 11.5 | | | — | | | — | |
| Gain on Uecomm initial public offering | | | — | | | (44.0 | ) | | — | |
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| Operating EBIT | | $ | 133.0 | | $ | 114.0 | | $ | 129.9 | |
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| Operating EBIT contribution to UtiliCorp | | | 19.3% | | | 21.8% | | | 31.4% | |
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| Identifiable assets | | $ | 1,864.9 | | $ | 2,174.0 | | $ | 1,792.1 | |
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| Electric sales and transportation volumes (MWH 000's) | | | 25,484 | | | 13,785 | | | 9,023 | |
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| Electric customers | | | 1,595,000 | | | 1,553,000 | | | 1,165,000 | |
| Gas customers | | | 1,200,000 | | | 1,148,000 | | | 587,000 | |
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| Total customers* | | | 2,795,000 | | | 2,701,000 | | | 1,752,000 | |
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- *
- Includes customer connections in our equity method investments in electricity and gas distribution businesses in Australia and New Zealand.
2001 versus 2000
Sales, Cost of Sales and Gross Profit
Sales and cost of sales for our International Networks businesses decreased $138.5 million and $168.5 million, respectively, in 2001 compared to 2000. Gross profit for our International Networks businesses increased $30.0 million in 2001. These changes were primarily due to the following:
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- The deconsolidation of our New Zealand operations in June 2000 decreased sales, cost of sales and gross profit by $104.6 million, $32.7 million and $71.9 million, respectively.
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- •
- Our acquisition of TransAlta's electricity distribution business in Alberta, Canada in August 2000, and subsequent sale of its lower margin retail business effective January 2001, resulted in a decrease in sales and cost of sales of $34.7 million and $136.8 million, respectively. Gross profit increased at our Alberta network by $102.1 million from a full year's operations in 2001.
Operating Expenses
Total operating expenses increased $56.2 million in 2001 compared to 2000. The purchase of our Alberta network increased total operating expenses by $79.4 million. Deconsolidating our New Zealand business decreased total operating expenses by $28.8 million. In 2001, we also recorded charges of $11.5 million relating to the realizability of deferred tax assets and interest receivable on shareholder loans in our Australian equity investments.
Equity in Earnings of Investments
Equity in earnings increased $17.2 million in 2001 compared to 2000. After the sale of a portion of our New Zealand business we now use the equity method of accounting to record our net share of that business. This increased equity earnings by $16.5 million.
Other Income (Expense)
Other income increased $13.2 million, primarily reflecting the allowed recovery of carrying costs on deferred purchased power costs ordered by Alberta regulators in December 2001.
Gain on Sale of Subsidiary Stock
United Energy completed an initial public offering of 34% of Uecomm Limited, its telecom business, which resulted in a $44.0 million gain in 2000.
2000 versus 1999
Sales, Cost of Sales and Gross Profit
Sales and cost of sales for our International Networks businesses increased $183.2 million and $205.5 million, respectively, in 2000 compared to 1999. These increases were primarily due to our acquisition of TransAlta's electricity distribution business in Alberta, Canada. Gross profit for our International Networks businesses decreased $22.3 million in 2000 compared to 1999. The deconsolidation of our New Zealand business in June 2000 resulted in a $74.9 million decrease in gross profit from the prior year, when we consolidated our New Zealand business for the full year. The purchase of our Alberta network partially offset the decreases in our New Zealand business by contributing a gross profit of $52.6 million.
Operating Expenses
Total operating expenses increased $6.9 million in 2000 compared to 1999. The purchase of our Alberta network resulted in a $37.8 million increase in total operating expenses. Deconsolidating our New Zealand business decreased total operating expenses by $28.8 million.
Equity in Earnings, Minority Interest and Other Income (Expense)
These items increased $13.3 million in 2000 compared to 1999. Since the sale of a portion of our New Zealand business, we now use the equity method of accounting to record our net share of that business. This increased equity earnings by $13.3 million and decreased minority interest in income of subsidiaries by $8.2 million. Equity earnings also increased $9.3 million from higher earnings from our Australian investments. In addition, other income decreased $17.5 million on lower interest income on loans to our equity investments.
Gain on Sale of Subsidiary Stock
United Energy completed an initial public offering of 34% of Uecomm, its telecom business, in 2000, resulting in a $44.0 million gain.
10
Current Operating Developments
Competition in Australia.The State of Victoria is deregulating its electricity market in stages. In January 2002, all customers of United Energy Limited (UEL) chose their retail electricity suppliers. A majority of UEL's gross margin comes from distribution line charges that are not affected by these customer choices.
Regulation in New Zealand.An Electricity Act came into force in August 2001. This new Act empowers the Commerce Commission to exercise control over goods and services lines businesses to promote efficient operation of markets through targeted controls. The Commerce Commission is currently developing its approach to implementing this legislation.
Purchase of United Kingdom Electricity Network.We have entered into an agreement to purchase Midlands Electricity plc, a United Kingdom electricity network from FirstEnergy Corp. The price of this investment is approximately $362 million, plus the assumption of approximately $1.7 billion of debt that would be non-recourse to us. If consummated, we expect to account for this acquisition using the equity method of accounting. Under terms of our agreement, if the transaction is not completed by April 26, 2002, either party may terminate the transaction. Although we have received the necessary regulatory approvals, those approvals require that we have a financial partner. We are in discussions with FirstEnergy to modify our agreement to allow us to complete the transaction in a manner consistent with the regulatory approvals and expect that it will close in March 2002.
Multinet Gas.In March 1999, we invested in the Multinet gas distribution business in Melbourne, Australia. Because this property's service territory overlapped with our existing electric distribution property, we expected and have been able to extract significant synergies. However, since March 1999, the Melbourne area has experienced consecutive mild winters, one of them the mildest on record. Additionally, gas volumes, normalized for weather, have not met expectations.
As a result of this unexpected financial performance, it was necessary for us to invest, in December 2001, an additional $81.9 million in the business as subordinated debt. Multinet used these funds to retire senior bank debt. In evaluating the recoverability of our total investment in that business we evaluated its cash flow potential under probable capitalization scenarios. Existing shareholder debt will likely be converted to equity as the result of recent tax law changes. Given this, cash flow forecasts indicated sufficient cash flow to service and retire the existing senior bank debt and provide a return of invested capital, including shareholder loans, to the equity holders. As a result, we have determined no impairment of this investment exists as of December 31, 2001. However, valuation reserves totaling about $4.6 million on portions of the carrying value of certain future income tax benefits were recorded at Multinet and existing accrued interest balances were written down as uncollectible.
Pulse Retail.Our Melbourne, Australia businesses are partners in the retail energy provider Pulse. Their investments consist primarily of shareholder loans. In December, the Victorian government capped increases in retail electricity prices at less than 5%, compared with an average price increase sought by retailers of around 18%. This decision dampened retailers' enthusiasm for full retail competition in the residential market, which began in January 2002. Pulse's financial outlook has been hampered by the Victorian government's actions and accordingly, the full balance of accrued interest due from Pulse on the shareholder loans and a portion of the shareholder loan balances were written off. These write-offs were approximately $3.9 million and are reflected in our 2001 financial statements. As the retail markets continue to evolve under full retail competition, our distribution businesses in Australia will continue to evaluate the remaining carrying value of their shareholder loans to Pulse.
11
Three-Year Review—Domestic Networks
| | Year Ended December 31,
| |
|---|
| | 2001
| | 2000
| | 1999
| |
|---|
| | (Dollars in millions)
| |
|---|
| Sales: | | | | | | | | | | |
| | Electric | | $ | 758.2 | | $ | 717.6 | | $ | 675.4 | |
| | Gas | | | 964.3 | | | 826.5 | | | 638.2 | |
| | Non-regulated businesses | | | 569.9 | | | 514.0 | | | 265.2 | |
| | |
| |
| |
| |
| Total sales | | | 2,292.4 | | | 2,058.1 | | | 1,578.8 | |
| | |
| |
| |
| |
| Cost of sales: | | | | | | | | | | |
| | Electric | | | 355.6 | | | 378.6 | | | 305.4 | |
| | Gas | | | 720.1 | | | 565.7 | | | 380.8 | |
| | Non-regulated businesses | | | 479.7 | | | 442.9 | | | 215.6 | |
| | |
| |
| |
| |
| Total cost of sales | | | 1,555.4 | | | 1,387.2 | | | 901.8 | |
| | |
| |
| |
| |
| Gross profit | | | 737.0 | | | 670.9 | | | 677.0 | |
| | |
| |
| |
| |
| Operating expenses: | | | | | | | | | | |
| | Operating expense | | | 359.2 | | | 292.3 | | | 268.1 | |
| | Depreciation and amortization expense | | | 162.1 | | | 129.3 | | | 115.3 | |
| | Maintenance expense | | | 55.5 | | | 54.6 | | | 50.5 | |
| | Taxes, other than income taxes | | | 39.4 | | | 39.1 | | | 57.7 | |
| | Impairments and other charges | | | 48.3 | | | 4.0 | | | — | |
| | |
| |
| |
| |
| Total operating expenses | | | 664.5 | | | 519.3 | | | 491.6 | |
| | |
| |
| |
| |
| Equity in earnings of investments | | | 28.5 | | | 52.9 | | | 13.2 | |
| Minority interest in loss of subsidiaries | | | 6.4 | | | 1.9 | | | — | |
| Other income | | | 10.5 | | | 9.2 | | | 9.7 | |
| | |
| |
| |
| |
| Earnings before interest and taxes (EBIT) | | | 117.9 | | | 215.6 | | | 208.3 | |
| | |
| |
| |
| |
| Non-recurring items: | | | | | | | | | | |
| | Enron exposure | | | 31.8 | | | — | | | — | |
| | Communications construction and lease termination | | | 16.5 | | | 4.0 | | | — | |
| | |
| |
| |
| |
| Operating EBIT | | $ | 166.2 | | $ | 219.6 | | $ | 208.3 | |
| | |
| |
| |
| |
| Operating EBIT contribution to UtiliCorp | | | 24.1 | % | | 42.0 | % | | 50.3 | % |
| | |
| |
| |
| |
| Identifiable assets | | $ | 3,512.5 | | $ | 3,584.7 | | $ | 2,370.0 | |
| Electric sales and transportation volumes(MWH 000's) | | | 13,143 | | | 12,173 | | | 12,043 | |
| Gas sales and transportation volumes(MCF 000's) | | | 216,559 | | | 241,708 | | | 247,831 | |
| | |
| |
| |
| |
| Electric customers | | | 431,000 | | | 408,000 | | | 349,000 | |
| Gas customers | | | 874,000 | | | 863,000 | | | 831,000 | |
| Appliance service contract customers | | | 139,000 | | | 156,000 | | | 170,000 | |
| | |
| |
| |
| |
| Total customers | | | 1,444,000 | | | 1,427,000 | | | 1,350,000 | |
| | |
| |
| |
| |
2001 versus 2000
Sales, Cost of Sales and Gross Profit
Sales, cost of sales and gross profit for our Domestic Networks businesses increased $234.3 million, $168.2 million and $66.1 million, respectively, in 2001 compared to 2000. Our acquisition of St. Joseph Light & Power Company in December 2000 contributed sales, cost of sales and gross profit of $104.1 million, $40.9 million and $63.2 million, respectively. Also contributing to increased sales and cost of sales were higher natural gas prices in early 2001.
12
Operating Expenses
Operating expenses increased $66.9 million in 2001 compared to 2000 primarily due to inclusion of a full year's operations of St. Joseph Light & Power, which had operating expenses of $21.9 million. Also contributing to higher operating expenses were increased bad debt expenses related to higher natural gas costs in late 2000 and early 2001 and certain industrial customer bankruptcies in 2001. Start-up operating expenses in connection with the build-out of our communications networks also contributed $30.5 million to increased operating expenses.
Depreciation and Amortization Expense
Depreciation and amortization expense increased $32.8 million in 2001 compared to 2000, primarily as the result of $16.4 million of increased depreciation related to the assets acquired in the St. Joseph Light & Power merger. Also contributing to the increase was $4.6 million of depreciation due to continued capital expenditures in our utility operations and $10.3 million due to our communications network build-out.
Impairments and Other Charges
Impairments and other charges in 2001 included $31.8 million of unsecured cash participation notes receivable that were written off following the Enron bankruptcy filing in December 2001. Also included was the write-off of $16.5 million of communications system assets not being utilized and related leases in markets not actively being developed as we concentrate on developing our communications networks in the Kansas City area.
13
Equity in Earnings of Investments
Equity in earnings decreased $24.4 million in 2001 compared to 2000, primarily due to reduced equity earnings from our investment in Quanta Services and the termination of our management fee agreement with Quanta in December 2000. The slowdown in the telecom market and the write-off of certain receivables from its telecom customers by Quanta reduced equity earnings in 2001.
2000 versus 1999
Sales, Cost of Sales and Gross Profit
Sales and cost of sales for our Domestic Networks businesses increased $479.3 million and $485.4 million, respectively, in 2000 compared to 1999. These increases were primarily due to increased natural gas prices. Gross profit for our Domestic Networks businesses decreased $6.1 million in 2000 compared to 1999. The decrease primarily related to a 1999 Kansas show-cause rate case that resulted in a $7.9 million reduction in gross profit. Costs of fuel and purchased power also increased in 2000, offset in part by higher gross profits due to a hotter summer and colder winter.
Total Operating Expenses
Total operating expenses increased $27.7 million in 2000 compared to 1999. Our communications business incurred start-up costs, depreciation expense and other charges of $23.5 million in 2000 that were not incurred in 1999. Total operating expenses of our domestic utility networks increased primarily because of higher depreciation due to continued investments in network infrastructure, and higher bad debt expense as a result of the increase in the cost of natural gas.
Equity in Earnings of Investments
Equity in earnings increased $39.7 million in 2000 compared to 1999. In 2000, we included a full year of equity earnings and management fees in equity earnings of investments and partnerships relating to our investment in Quanta. This increased equity in earnings by $40.5 million compared to 1999. We invested an additional $360 million in Quanta stock in 2000. In December 2000, we terminated our management services contract with Quanta and received payment of the management fees recorded, including a termination fee.
Current Operating Developments
Quanta Ownership. We are presently arbitrating a dispute with Quanta regarding our right to acquire additional shares of Quanta. We have informed Quanta's board of directors that we intend to present an opposition slate of directors at Quanta's 2002 annual meeting of shareholders. Although the market price of Quanta shares was below our cost basis per share at December 31, 2001, we do not believe that our investment is impaired. This conclusion is based on our evaluation of Quanta's financial condition and future prospects and our intent and ability to hold this investment.
Domestic Utility Operations. Our domestic network businesses operate in a regulated environment. Industrial and large commercial customers generally have access to energy sources, so some of the competitive pricing benefits have been transferred to these customers through open access tariffs relating to transmission lines and pipelines. Competition at the retail level is dependent on legislation in each state.
Sale of Pipeline Assets. On February 1, 2001 we entered into an agreement to sell our wholly owned subsidiary UtiliCorp Pipeline Systems for our book value of approximately $66 million. We closed this transaction in January 2002.
Missouri Rate Case. In June 2001, we filed for a $49.4 million increase in our Missouri electric rates. Approximately $39 million of the requested increase related to anticipated higher fuel and purchased power costs that did not materialize. In February 2002, we reached a negotiated settlement with the Commission staff and all interveners that will result in a $4.3 million rate reduction.
14
Corporate Matters
Corporate and Other
The table below summarizes corporate and other EBIT for the three years ended December 31, 2001. Corporate primarily contains the retained costs of the company that are not allocated to the business units.
| | 2001
| | 2000
| | 1999
| |
|---|
| | (In millions)
| |
|---|
| EBIT | | $ | 5.7 | | $ | (24.7 | ) | | (3.9 | ) |
| | |
| |
| |
| |
| Non-recurring items: | | | | | | | | | | |
| | Write-off of certain technology and corporate identity assets | | | — | | | 12.4 | | | — | |
| | |
| |
| |
| |
| Operating EBIT | | $ | 5.7 | | $ | (12.3 | ) | $ | (3.9 | ) |
| | |
| |
| |
| |
2001 versus 2000
EBIT
Corporate and other EBIT increased $30.4 million in 2001 compared to 2000 due to $12.4 million of impairments and other charges recognized in 2000. Also contributing to the increase in EBIT was the allocation of $10.8 million of expenses to our merchant business and $3.6 million of lower accounts receivable sales program costs due to reduced utilization in 2001.
Interest Expense
Interest expense and minority interests in income of partnership and trusts increased $8.1 million in 2001 compared to 2000. This was primarily due to increased long-term borrowings in late 2000 and early 2001 related to the acquisitions of our Alberta network, AlintaGas, St. Joseph Light & Power and GPU International.
Income Taxes
Income taxes increased $84.0 million in 2001 compared to 2000. This was primarily due to the increased earnings before income taxes in 2001 resulting from the factors discussed previously. Our overall effective tax rate increased from 36.4% in 2000 to 42.0% in 2001. The increase in our effective tax rate was due primarily to the effect of increased minority interest in income of subsidiaries, taxes on the gain recognized on the sale of our shares in Aquila, and valuation allowances on certain international losses.
2000 versus 1999
EBIT
Corporate and other EBIT decreased $20.8 million in 2000 compared to 1999 due to impairments and other charges of $12.4 million. These related to certain technology assets and purchased intangibles no longer used in our operations. Also contributing to the decrease in EBIT were certain project costs and other corporate costs not allocated to business units.
Interest Expense
Interest expense and minority interest in income of partnership and trusts increased $29.7 million in 2000 compared to 1999. The issuance of $250.0 million of company-obligated preferred securities in September 1999 and $100.0 million in June 2000 resulted in an increase of $15.8 million. Increased short-term and long-term borrowings to fund acquisitions and investments resulted in the remaining increase.
Income Taxes
Income taxes increased $50.0 million in 2000 compared to 1999. This was primarily due to the increased income before income taxes in 2000 resulting from the factors discussed previously. Our overall effective tax rate increased from 29.8% in 1999 to 36.4% in 2000, primarily as a result of an increase in our pretax earnings in Canada, which has higher statutory tax rates.
15
Critical Accounting Policies
We have prepared our financial statements in conformity with accounting principles generally accepted in the United States of America. These statements include some amounts that are based on informed judgments and estimates of management. Our significant accounting policies are discussed in Note 1 to the consolidated financial statements. Our critical accounting policies are subject to judgments and uncertainties that affect the application of such policies. As discussed below, while we believe these financial statements include the most likely outcomes with regard to amounts that are based on our judgments and estimates, our financial position and results of operations may be materially different when reported under different conditions or when using different assumptions in the application of such policies. In the event estimates or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information. Our critical accounting policies include:
Sales Recognition. A significant portion of our sales are recorded in connection with our trading activities and are recorded under the mark-to-market method of accounting. The market prices or fair values used in determining the value of our portfolio are our best estimates utilizing information such as closing exchange rates, over-the-counter quotes, historical volatility and the potential impact on market prices of liquidating our positions in an orderly manner over a reasonable period of time under current market conditions. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. As a result, operating results can be affected by revisions to prior accounting estimates.
Principles of Consolidation. We consolidate all operations that we control. In accordance with Emerging Issues Task Force Issue No. 96-16, we do not consolidate operations in which we have granted substantive participating and protective rights to our partners. We account for these unconsolidated investments using the equity method of accounting. See Notes 4 and 15 to the consolidated financial statements for further discussion.
Impairment of Long-Lived Assets. We review the carrying value of long-lived assets, including goodwill, whenever events or changes in circumstances indicate that such carrying values may not be recoverable. Unforeseen events and changes in conditions could negatively affect the fair value of our assets and result in impairment charges. Fair value is the amount at which an asset could be bought or sold in a current transaction between willing parties and may be estimated using a number of approaches. These approaches may include quoted market prices or valuations by third parties, present value techniques based on estimated cash flows, or multiples of earnings or sales.
Regulatory Accounting Implications. We currently record the economic effects of regulation in accordance with the provisions of Statement of Financial Accounting Standards No. 71 (SFAS No. 71), "Accounting for the Effects of Certain Types of Regulation." Accordingly, our balance sheet reflects certain costs as regulatory assets. We expect our rates will continue to be based on historical costs for the foreseeable future. If we discontinued applying SFAS No. 71, we would make adjustments to the carrying value of our regulatory assets. Total net regulatory assets at December 31, 2001 were $308.8 million, including deferred purchased power costs of $177.5 million related to our Alberta, Canada electricity business. The Alberta government issued regulations in December 2001 that permit us to recover these deferred costs in 2002 to 2003. These regulations also provide for the current recovery of carrying costs. We, along with the other Alberta electricity distribution companies, are working with the provincial government, rating agencies and financial institutions to pursue the securitization of these balances as the lowest cost of financing to the customers.
Environmental Matters
We own or once operated former manufactured gas plant sites that may require some form of environmental remediation. As of December 31, 2001, we estimate cleanup costs on these identified sites to be $9.0 million. See Note 17 to the consolidated financial statements for further discussion.
We also are currently named as a potentially responsible party (PRP) at two disposal sites for polychlorinated biphenyl (PCB). We anticipate that future expenditures on the two sites and others where we are currently named as a PRP or have remediation liability will be less than $2 million.
In May 2000, the state of Missouri adopted a revised regulation that also requires reduction of nitrous oxide (NOx) from our power plants. We estimate the cost of compliance to be approximately $21.9 million in capital costs and $2.2 million in annual operation and maintenance costs. The new standard will be effective in May 2003.
16
In December 2000, the U.S. Environmental Protection Agency (EPA) announced that it would regulate mercury emissions from coal- and oil-fired power plants. The EPA is expected to propose regulations by December 2003 and issue final regulations by December 2004. The impact of this action on our power plants cannot be determined until final regulations are issued.
Market Risk—Trading
We are exposed to market risk, including changes in commodity prices, interest rates and currency exchange rates. To manage the volatility relating to these exposures, we enter into various derivative transactions in accordance with our policy approved by the Board of Directors. Our trading portfolios consist of natural gas, electricity, coal, global liquids, weather derivatives and interest rate contracts that are settled by the delivery of the commodity or cash. These contracts take many forms, including futures, forwards, swaps and options.
We measure the risk in our trading portfolio using value-at-risk methodologies, to simulate forward price curves in the energy markets and estimate the size of future potential losses. Value-at-risk measures the potential loss in a portfolio's value due to market volatility, over a specified time horizon, stated with a specific degree of probability. The quantification of market risk using value-at-risk methodologies provides a consistent measure of risk across diverse energy markets and products. The use of this method requires a number of key assumptions, such as:
- •
- Selection of a confidence level (we use 95%);
- •
- Estimated holding period (this is the time needed to liquidate different commodity and term positions; we use holding periods of one to five days depending on the commodity and duration of the position); and
- •
- Use of historical estimates of volatility and correlation with recent activity more heavily weighted.
The average value at risk for all commodities during 2001 was $11.3 million. Our total value at risk as approved by the Board of Directors is limited to $15.0 million. We also use additional risk control mechanisms such as stress testing, daily loss limits and commodity position limits, as well as daily monitoring of the trading activities that is performed by an independent function.
All Merchant interest and foreign currency risks are monitored within the commodity portfolios and value-at-risk calculation. The value of our commodity portfolios is impacted by interest rates as the portfolio is valued using an estimated interest discount factor to December 31, 2001. We often sell Canadian sourced natural gas into the U.S. markets accepting U.S. dollars from customers, but paying Canadian dollars to suppliers. This exposes our portfolio to currency risk and we generally hedge this exposure.
The table below shows the expected cash flows associated with the interest rate financial instruments at December 31, 2001.
| | 2002
| | 2003
| | 2004
| | 2005
| |
|---|
| | (Dollars in millions)
| |
|---|
| Fixed to variable rate | | $ | (.8 | ) | $ | (2.1 | ) | $ | (.1 | ) | $ | (.3 | ) |
| Average rate paid | | | 6.7 | % | | 6.8 | % | | 6.7 | % | | 6.7 | % |
| Average rate received | | | 4.8 | % | | 5.2 | % | | 4.8 | % | | 4.8 | % |
| | |
| |
| |
| |
| |
Market Risk—Non-Trading
We are also exposed to commodity price changes outside of price risk management activities. The following table summarizes these exposures on an EBIT basis as if our positions were completely unhedged:
| | Commodity
Price Change
| | EBIT
Impact(a)
|
|---|
| Natural gas liquids price per gallon(b) | | $ | ±.01 | | $ | 1.7 million |
| Natural gas price per MCF | | | ±1.00 | | | .3 million |
| | |
| |
|
- (a)
- Assumes the price change occurs for an entire year.
- (b)
- We have hedged approximately 54% of our forward natural gas liquids production to minimize the effect of price changes.
17
Certain Trading Activities
We engage in price risk management activities for both trading and non-trading activities. Transactions carried out in connection with trading activities are accounted for under the mark-to-market method of accounting. Under this method, our energy commodity trading contracts, including physical transactions (mainly gas and power) and financial instruments, are recorded at fair value. As part of the valuation of our portfolio, we value the credit risks associated with the financial condition of counterparties and the time value of money. We primarily use quoted market prices from published sources or comparable transactions in liquid markets to value our contracts. If actively quoted market prices are not available, we contact brokers and other external sources or use comparable transactions to obtain current values of our contracts. When market prices are not readily available or determinable, certain contracts are valued at fair value using an alternative approach such as model pricing. The market prices or fair values used in determining the value of the portfolio are our best estimates utilizing information such as closing exchange rates, over-the-counter (OTC) quotes, volatility, time value, counterparty credit and the potential impact on market prices of liquidating our positions in an orderly manner over a reasonable period of time under current market conditions. The changes in fair value of our trading contracts for 2001 are summarized below:
| | Trading Contracts
| | Long-term
Gas Contracts
| | Total
| |
|---|
| | (In millions)
| |
|---|
| Fair value of contracts outstanding at the beginning of the year | | $ | 562.4 | | $ | (912.9 | ) | $ | (350.5 | ) |
| Fair value generated during the year | | | 623.2 | | | — | | | 623.2 | |
| Contracts realized or settled during the year—entered into in 2001 | | | (429.0 | ) | | — | | | (429.0 | ) |
| Contracts realized or settled during the year—entered into in prior years | | | (191.3 | ) | | 80.4 | | | (110.9 | ) |
| Other, net | | | 25.6 | | | — | | | 25.6 | |
| | |
| |
| |
| |
| Fair value of contracts outstanding at the end of the year | | $ | 590.9 | | $ | (832.5 | ) | $ | (241.6 | ) |
| | |
| |
| |
| |
The fair value of contracts maturing in each of the next four years and thereafter are shown below:
| | 2002
| | 2003
| | 2004
| | 2005
| | Thereafter(a)
| | Total
| |
|---|
| Prices actively quoted | | $ | 297.9 | | $ | 90.7 | | $ | — | | $ | — | | $ | — | | $ | 388.6 | |
| Prices provided by other external sources | | | — | | | — | | | 71.1 | | | 28.2 | | | — | | | 99.3 | |
| Prices based on models and other valuation methods | | | 10.4 | | | 1.1 | | | 1.9 | | | — | | | 89.6 | | | 103.0 | |
| | |
| |
| |
| |
| |
| |
| |
| Fair value of contracts | | | 308.3 | | | 91.8 | | | 73.0 | | | 28.2 | | | 89.6 | | | 590.9 | |
| Long-term gas contracts | | | (79.7 | ) | | (81.5 | ) | | (85.1 | ) | | (87.8 | ) | | (498.4 | ) | | (832.5 | ) |
| | |
| |
| |
| |
| |
| |
| |
| Total price risk management assets (liabilities) | | $ | 228.6 | | $ | 10.3 | | $ | (12.1 | ) | $ | (59.6 | ) | $ | (408.8 | ) | $ | (241.6 | ) |
| | |
| |
| |
| |
| |
| |
| |
- (a)
- The fair value of our long-term contracts is composed primarily of fixed price risk that has been significantly hedged.
Credit Risk
In conducting our energy marketing and risk management activities, we regularly transact business with a broad range of entities and a wide variety of end users, trading companies and financial institutions. Credit risk is measured by the loss we would record if our counterparties failed to perform pursuant to the terms of their contractual obligations and the value of collateral held, if any, was not adequate to cover such losses.
We have established controls to determine and monitor the creditworthiness of counterparties, as well as the quality of pledged collateral, and use master netting agreements whenever possible to mitigate our exposure to counterparty credit risk. Master netting agreements enable us to net certain assets and liabilities by counterparty. We also net across product lines and against cash collateral, provided such provisions are established in the master netting and cash collateral agreements. Additionally, we may require counterparties to pledge additional collateral when deemed necessary.
Concentrations of credit risk from financial instruments, including contractual commitments, exist when groups of counterparties have similar business characteristics or are engaged in like activities that would cause their ability to meet their contractual commitments to be adversely affected, in a similar manner, by changes in the economy or other market conditions. We monitor credit risk on both an individual basis and a group
18
counterparty basis. A majority of our merchant portfolio is with counterparties who had investment grade credit ratings.
Currency Rate Exposure
We do not currently hedge our net investment in foreign operations. As a result, the foreign denominated assets and liabilities fluctuate in value. Historically, our net exposure to changes in foreign currency has been limited as the company's foreign investments are financed largely through foreign debt.
The table below summarizes the average value of foreign currencies used to value sales and expenses along with the related sensitivity.
| |
| |
| | Average Currency Unit Value in
U.S. Dollars
|
|---|
| | Net Investment
at December 31, 2001
| | Impact of 10% Change
on 2001 EBIT(a)
|
|---|
| | 2001
| | 2000
| | 1999
|
|---|
| | (Dollars in millions)
|
|---|
| Australia | | $ | 529.5 | | $ | ±1.2 | | $ | .52 | | $ | .58 | | $ | .65 |
| Canada | | | 164.3 | | | ±7.8 | | | .65 | | | .67 | | | .67 |
| New Zealand | | | 386.7 | | | ±3.1 | | | .42 | | | .46 | | | .53 |
| United Kingdom | | | 1.0 | | | ±2.2 | | | 1.44 | | | 1.52 | | | 1.62 |
| | |
| |
| |
| |
| |
|
| Total | | | | | $ | ±14.3 | | | | | | | | | |
| | | | | |
| | | | | | | | | |
- (a)
- Assuming a 10% change in local currency value relative to the U.S. dollar if the change occurred uniformly over the entire year, based on 2001 EBIT.
Interest Rate Exposure
We have about $1.6 billion in variable rate financial obligations. A 100-basis-point change in the variable rate financial instruments would affect net income by about $9.6 million.
Liquidity and Capital Resources
Our cash requirements arise primarily from continued growth, network construction programs, non-regulated investment opportunities, merchant working capital requirements and common stock dividends. Our ability to attract the necessary financial capital at reasonable terms is critical to our overall plan. We have an investment grade rating from credit rating agencies. A downgrade in our credit ratings to non-investment would have a negative impact on our ability to obtain capital on terms currently available to the company. Historically, we have financed acquisitions and investments initially with short-term debt and later funded them with an appropriate mix of common equity and long-term debt securities, depending on prevailing market conditions.
A primary source of short-term cash has been bank loans and commercial paper, which aggregated $548.6 million at December 31, 2001. We can issue up to $150 million of commercial paper supported by a $400 million committed revolving credit agreement. The current domestic credit agreement is composed of two parts, a one-year $250 million revolving credit agreement that expires in 2002 and a three-year $150 million revolving credit agreement that expires in 2003. Both of these allow for issuance of notes at interest rates based on various money market rates. At December 31, 2001, we had $135.0 million of commercial paper under the program described above and $305.0 million of other unsecured domestic bank loans outstanding. We also have a C$150 (US$ 94.2) million commercial paper program supported by a C$150 million credit facility, which expires in 2002, that provides liquidity to our Alberta electricity distribution business. At December 31, 2001, US$66.6 million was outstanding under this facility. In addition, we have C$80 (US$50.3) million of credit facilities that expire in 2002 with an outstanding balance of US$36.5 million.
To maintain flexibility in our capital structure and to take advantage of favorable short-term rates, we have historically sold our accounts receivable under two programs to fund part of our short-term cash requirements. The level of funding available from these programs was limited to $405 million, $275 million based on the sale of Aquila receivables and $130 million based on the sale of Domestic Networks receivables. The amount fluctuates seasonally. We had sold $220 million under the Aquila program and $77.5 million under the Domestic Networks program at December 31, 2001. In January 2002, the Aquila program was terminated.
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Under a series of master agreements with our customers, Aquila is required to post, and requires our customers to post, either cash or a letter of credit when certain agreed-upon credit limits are exceeded. As of December 31, 2001, $49.3 million of letters of credit were outstanding. We intend to replace our domestic revolving credit agreement with a new facility totaling $650 million to provide additional liquidity to support our business needs.
We have a dispute with an insurance company regarding certain indemnity agreements we have with them. These agreements relate to surety bonds issued to support our obligations under certain long-term gas supply contracts. The maximum amount that the insurance company could be required to pay under the surety bond is approximately $570 million. Notwithstanding our continued performance under the gas supply agreements and strong financial position, this company has demanded that we replace it as the surety, or alternatively, that we post collateral to secure all of their obligations thereunder. We believe that there is no merit to the insurance company's position given our full compliance with the related gas supply contracts and that a court would agree with our interpretation of the indemnity agreements.
We executed the following financing transactions, which affected our liquidity and capital resources in 2001:
- •
- In February 2001, we issued $250 million of 7.95% senior notes due in February 2011.
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- We sold 11,500,000 shares of our common stock in March 2001, which raised approximately $332 million.
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- In April 2001, our Aquila subsidiary sold 19,975,000 of Class A common stock, including 5,750,000 shares owned by us. The offering raised approximately $446 million.
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- In June 2001, we exchanged $189.5 million of senior notes with interest rates ranging from 8.0% to 9.0% for $200 million of new senior notes with an interest rate of 7.75%, maturing in June 2011.
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- Also in June 2001, we retired $204.1 million of senior notes, mortgage bonds and company-obligated preferred securities.
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- In January 2002, we completed an exchange offer and merger that resulted in the issuance of approximately 12.6 million shares of our common stock for all publicly held shares of Aquila. The holders of 1.8 million shares of Aquila common stock rejected the consideration in the merger as inadequate and are pursuing their right to receive fair value in cash.
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- On January 30, 2002, we sold 12.5 million shares of our common stock to the public, including an over-allotment of 1.5 million shares, which raised approximately $278 million in net proceeds.
Our capital structure consisted of the following components at December 31, 2001 and 2000:
| | Pro Forma
| | 2001
| | 2000
| |
|---|
| Common stock equity | | 51.7 | % | 44.2 | % | 35.0 | % |
| Company-obligated preferred securities | | 5.7 | | 6.0 | | 8.7 | |
| Short-term debt | | 4.5 | | 9.5 | | 9.7 | |
| Long-term debt | | 38.1 | | 40.3 | | 46.6 | |
| | |
| |
| |
| |
| Total Capitalization | | 100.0 | % | 100.0 | % | 100.0 | % |
The above pro forma capitalization adjusts the December 31, 2001 amounts for the issuance of approximately 12.6 million shares of common stock in the Aquila exchange offer and the issuance of 12.5 million shares of UtiliCorp United Inc. common stock in a public offering. The proceeds of approximately $278 million from the public offering were assumed to pay down short-term debt. Our intention is to maintain common equity at 50% of total capital or higher.
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Our dividend payout ratio was 48.2% in 2001 (annualized dividends of $1.20 divided by basic earnings per share of $2.49). We expect our earnings per share to grow faster than our dividend.
Cash Requirements and Contractual Obligations
We estimate future cash requirements for capital expenditures for property, plant and equipment additions will be as follows:
| | Actual
| | Future Cash Requirements
|
|---|
| | 2001
| | 2002
| | 2003
| | 2004
|
|---|
| | (In millions)
|
|---|
| Capital expenditures | | $ | 626.1 | | $ | 643.0 | | $ | 643.0 | | $ | 594.0 |
We also have contractual cash obligations including maturities of long-term debt and company-obligated preferred securities, minimum payments on operating leases and obligations under tolling agreements, power purchase contracts and fuel purchase contracts. Nearly all the power to be purchased under tolling and leasing agreements has been sold to third parties over comparable contract periods.
The amounts of contractual cash obligations maturing in each of the next five years and thereafter are shown below:
| | 2002
| | 2003
| | 2004
| | 2005
| | 2006
| | Thereafter
| | Total
|
|---|
| | (In millions)
|
|---|
| Long-term debt | | $ | 579.1 | | $ | 148.9 | | $ | 449.8 | | $ | 40.2 | | $ | 124.2 | | $ | 984.8 | | $ | 2,327.0 |
| Company-obligated preferred securities | | | 100.0 | | | — | | | 250.0 | | | — | | | — | | | — | | | 350.0 |
| Operating leases | | | 31.2 | | | 31.7 | | | 31.7 | | | 27.7 | | | 21.6 | | | 164.9 | | | 308.8 |
| Purchase obligations | | | 379.5 | | | 301.9 | | | 298.7 | | | 241.1 | | | 221.0 | | | 1,862.3 | | | 3,304.5 |
| | |
| |
| |
| |
| |
| |
| |
|
| Total contractual cash obligations | | $ | 1,089.8 | | $ | 482.5 | | $ | 1,030.2 | | $ | 309.0 | | $ | 366.8 | | $ | 3,012.0 | | $ | 6,290.3 |
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We expect that cash generated from operations and new financing activities will be adequate to meet these estimated cash requirements and contractual obligations.
Off-Balance Sheet Arrangements
Investments in Unconsolidated Subsidiaries and Partnerships
We have a number of equity method investments in unconsolidated subsidiaries and partnerships that are discussed in detail in Note 4 to the consolidated financial statements. In most cases we have no legal or economic obligation to make additional investments of equity or debt to fund these operations. Following are descriptions of certain commitments or conditions that could impact our financial condition, liquidity or results of operations.
New Zealand Interest
In connection with the sale of a 21% preferred and common stock equity interest in our New Zealand electricity distribution business to a financial partner in June 2000, the financial partner received an option that entitles them to sell their equity interest to us on the third anniversary of the initial sale, or on the occurrence of certain events. The purchase would be exercised at par value for the preferred stock and fair value for the common stock for a total of approximately $33.0 million. If the option were exercised we would be required to include the financial statements of this operation in our consolidated financial statements. This operation had total assets of approximately $1.0 billion and
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long-term debt of $520.6 million as of December 31, 2001. We expect to extend or remove this option before it matures and do not expect to reconsolidate our New Zealand interest.
Quanta Ownership
We are presently arbitrating a dispute with Quanta regarding our right to acquire additional shares of Quanta. We have informed Quanta's board of directors that we intend to present an opposition slate of directors at Quanta's 2002 annual meeting of shareholders. As of December 31, 2001, Quanta reported total assets of $2.0 billion, including $1.0 billion of goodwill, total liabilities of $842.5 million, including debt of $508.3 million, and equity of $1.2 billion. Quanta's revenues and net income for 2001 were $2.0 billion and $85.8 million, respectively.
Accounts Receivable Sales Programs
As of December 31, 2001, we had two programs totaling $405 million through which we sold accounts receivable. In January 2002, one program totaling $275 million was terminated.
Leases
We have operating leases of power plants, facilities and other equipment. Certain of these leases are considered synthetic leases through special purpose entities for whom we provide guarantees of their obligations in specific circumstances. See Note 17 to the consolidated financial statements for further discussion.
Credit Rating Triggers
Approximately $167.0 million of our long-term debt facilities and notes contain provisions that would make a put option exercisable by the debt holders if our Standard & Poor's (S&P) or Moody's credit ratings are reduced below investment grade. We currently have investment grade credit ratings from S&P and Moody's.
Significant Balance Sheet Movements
Total assets decreased $2.1 billion in 2001 compared to 2000. This decrease is primarily due to the following:
- •
- Decreased accounts receivable of $1.6 billion that resulted from lower natural gas and electricity prices from the record prices at the end of 2000.
- •
- Price risk management assets, current and non-current, decreased $937.9 million primarily as a result of lower forward pricing of natural gas and electricity.
- •
- Prepayment and other increased $135.8 million, primarily due to deferred purchased power costs classified as current in 2001 as they will be collected from customers in 2002, as well as cash collateral on turbines that will be released as turbines are financed at the project level.
- •
- A $276.9 million increase in property, plant and equipment, net resulted primarily from increased investment in power plant development, gas pipeline and storage and communications networks expenditures.
- •
- A $126.6 million increase in investments in subsidiaries and partnerships primarily reflects the additional investment of $81.9 million in Multinet, an additional $40 million investment in Quanta Services, Inc. and undistributed equity earnings.
- •
- Merchant notes receivables increased $102.4 million from continued growth of our structured finance business.
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- •
- Deferred charges and other assets decreased $217.0 million, primarily due to deferred purchased power costs reclassified to current as discussed above, and cash collateral on turbines not assigned to current projects.
In 2001, total liabilities decreased by $2.6 billion, company-obligated preferred securities decreased $200.0 million as we redeemed our Monthly Income Preferred Securities and reclassified $100.0 million to current maturities, and common shareholders' equity increased $752.0 million. These changes were primarily due to the following:
- •
- Decreased accounts payable of $1.6 billion that resulted from lower natural gas and electricity prices compared to the record prices at the end of 2000.
- •
- Price risk management liabilities, current and non-current, decreased $1,046.8 million primarily as a result of lower forward pricing of natural gas and electricity and deliveries on long-term prepaid gas contracts.
- •
- Customer funds on deposit decreased $247.4 million due to price fluctuations and our customers' overall position with our gas and power trading business.
- •
- Minority interest increased $139.5 million as the result of the sale of an approximately 20% interest in our Aquila business in April 2001.
- •
- Common shareholders' equity increased $752.0 million. This was primarily the result of the sale of 11.5 million shares of common stock for approximately $332 million, the sale of shares of our Aquila business which raised common equity by $212 million, the issuance of approximately $112.6 million in shares of common stock pursuant to stock option exercises and other compensation plans, and net income of $279.4 million. These increases were offset in part by common dividends paid of $134.6 million and a $51.3 million increase in accumulated other comprehensive losses related to unfavorable foreign currency movements.
New Accounting Standards
In 2001, the Financial Accounting Standards Board (FASB) issued four new Statements of Financial Accounting Standards (SFAS). SFAS No. 141, "Business Combinations," SFAS No. 142, "Goodwill and Other Intangible Assets," SFAS No. 143, "Accounting for Asset Retirement Obligations," and SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." See Note 3 of notes to consolidated financial statements for further discussion.
Effects of Inflation
In the next few years, we anticipate that the level of inflation, if moderate, will not have a significant effect on operations or acquisition activity.
Forward-Looking Information
This report contains forward-looking information. Such statements involve risks and uncertainties and there are certain important factors that could cause actual results to differ materially from those anticipated. We generally intend the words, "may," "will," "should," "expect," "anticipate," "intend," "plan," "believe," "seek," "estimate," "continue," or the negative of those terms or similar expressions to identify forward-looking statements. Some of the important factors that could cause actual results or liquidity to differ materially from those anticipated include:
- •
- Both our Merchant Services and Global Networks Group businesses are weather-sensitive. Weather can affect results significantly to the extent that temperatures differ from normal.
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- •
- We are exposed to market risk, which may cause us to incur losses from our Wholesale Services operations.
- •
- We may not be able to implement our strategy if we are unable to access or generate capital at competitive rates.
- •
- The failure to maintain our investment grade bond rating would increase our borrowing costs and limit our ability to raise additional capital.
- •
- The timing and extent of changes in interest rates could affect our financial results.
- •
- We may not be able to successfully integrate acquired businesses into our operations.
- •
- The volatility of prices of natural gas and natural gas liquids can significantly affect the earnings contribution from the Capacity Services segment of Merchant Services.
- •
- The pace of well connections to our gas gathering system can affect the earnings contribution from the Capacity Services segment of Merchant Services.
- •
- Our development of merchant power plants may not be successful or profitable.
- •
- The pace and degree of regulatory changes in the U.S. and abroad can affect new business opportunities and the intensity of competition.
- •
- The value of the U.S. dollar relative to the British pound, Canadian dollar, Australian dollar and New Zealand dollar can affect financial results from our foreign operations.
- •
- The inability to pass through increased fuel and purchased power costs in certain regulatory jurisdictions may affect the results of operations of our networks. The modification of regulations or historical practices in other jurisdictions in which we rely upon our ability to recover our costs from our customers could adversely affect our earnings.
- •
- The result of future rate proceedings could affect future growth of our networks business.
- •
- Expansion of electricity markets in the United Kingdom and Europe will affect both opportunity and competition in marketing and trading activities.
- •
- The construction of fiber-optic communications networks and start-up operations of our communications business will have a negative effect on results of operations over the next few years.
- •
- Current declines in the fair value of certain investments may become other than temporary.
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