UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
Form 10-K
x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from ___________________ to __________________ |
Commission File Number 1-7978 |
BLACK HILLS POWER, INC.
Incorporated in South Dakota IRS Identification Number 46-0111677
625 Ninth StreetRapid City, South Dakota 57701
Registrant’s telephone number, including area code
Incorporated in South Dakota | IRS Identification Number 46-0111677 | |
625 Ninth Street, Rapid City, South Dakota 57701 | ||
Registrant’s telephone number, including area code: (605) 721-1700 | ||
Securities registered pursuant to Section 12(b) of the Act: None | ||
Securities registered pursuant to Section 12(g) of the Act: None | ||
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes | o | No | x |
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes | x | No | o |
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
YES |X| NO |_|
Yes | x | No | o |
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
This paragraph is not applicable to the Registrant. | x |
Indicate by check mark whether the registrant is not applicable toa large accelerated filer, an accelerated filer or a non-accelerated filer (as defined in Rule 12b-2 of the Registrant. |X|Exchange Act).
Large accelerated filer | o | Accelerated filer | o | Non-accelerated filer | x |
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).
Yes | o | No | x |
YES |_| NO |X|Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes | o | No | x |
State the aggregate market value of the voting stock held by non-affiliates of the Registrant.
All outstanding shares are held by the Registrant’s parent company, Black Hills Corporation. Accordingly, the aggregate market value of the voting common stock of the Registrant held by non-affiliates is $0.
Indicate the number of shares outstanding of each of the Registrant’s classes of common stock, as of the latest practicable date.
Class |
| Outstanding at February 28, |
Common stock, $1.00 par value | 23,416,396 shares |
Reduced Disclosure
The Registrant meets the conditions set forth in General Instruction I (1) (a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.
| |||||||||||
Page | |||||||||||
ITEMS | BUSINESS AND PROPERTIES | 3 | |||||||||
Safe Harbor for Forward Looking Information | 3 | ||||||||||
General | 4 | ||||||||||
Rate Regulation | 7 | ||||||||||
ITEM 1A. | RISK FACTORS | 8 | |||||||||
ITEM 1B. | UNRESOLVED STAFF COMMENTS | 10 | |||||||||
ITEM 3. | LEGAL PROCEEDINGS | 10 | |||||||||
ITEM 5. | MARKET FOR | ||||||||||
RELATED STOCKHOLDER MATTERS | 11 | ||||||||||
ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS | ||||||||||
OF OPERATIONS | 11 | ||||||||||
ITEM 8. | FINANCIAL STATEMENTS AND | ||||||||||
SUPPLEMENTARY DATA | 14 | ||||||||||
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS | ||||||||||
ON ACCOUNTING AND FINANCIAL DISCLOSURE | 43 | ||||||||||
ITEM 9A. | CONTROLS AND PROCEDURES | 43 | |||||||||
ITEM 9B. | OTHER INFORMATION | 43 | |||||||||
ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES | 45 | |||||||||
SIGNATURES | 47 | ||||||||||
INDEX TO EXHIBITS | 48 | ||||||||||
2
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES |
We are an electric utility serving customers in South Dakota, Wyoming and Montana. We are incorporated in South Dakota and began providing electric utility service in 1941. We are a wholly-owned subsidiary of Black Hills Corporation, a registered public utility holding company under the Public Utility Holding Company Act of 1935 (PUHCA).
Unless the context otherwise requires, references in this Form 10-K to “Black Hills Power,” “we,” “us” and “our” refer to Black Hills Power, Inc.
We engage in the generation, transmission and distribution of electricity. We have a solid foundation of revenues, earnings and cash flow that support our capital expenditures, dividends, and overall performance and growth.
Distribution and Transmission
Our distribution and transmission businesses serve approximately 62,000 electric customers, with an electric transmission system of 447 miles of high voltage lines and 263 miles of lower voltage lines. In addition, we jointly own 43 miles of high voltage lines with Basin Electric Cooperative. Our service territory covers a 9,300 square mile area of western South Dakota, eastern Wyoming and southeastern Montana with a strong and stable economic base. Approximately 90 percent of our retail electric revenues are generated in South Dakota.
The following are characteristics of our distribution and transmission businesses:
3
Power Sales Agreements. We sell a portion of our current load under long-term contracts. Our key contracts include:
These consumers are integrated into our control area and are treated as firm native load. We also provide 20 megawatts of unit contingent energy and capacity to the Municipal Energy Agency of Nebraska (MEAN) under a contract that expires in 2013.
Regulated Power Plants and Purchased Power. Our electric load is primarily served by generating facilities in South Dakota and Wyoming, which provide 435 megawatts of generating capacity, with the balance supplied under purchased power and capacity contracts. Approximately 50 percent of our capacity is coal-fired, 39 percent is oil- or gas-fired, and 11 percent is supplied under the following purchased power contracts with PacifiCorp:
Since 1995, we have been a net producer of energy. We reached our peak system load of 392 megawatts in August 2001. None of our generation is restricted by hours of operation, thereby providing us the ability to generate power to meet demand whenever necessary and feasible.
4
Rate Regulation
The rate freeze granted by the SDPUC, which had been in effect since 1995, expired on January 1, 2005. During this ten-year term, we were prohibited, subject to certain limited exceptions, from filing for any increase in its rates or invoking any fuel and purchased power adjustment tariff which would take effect during the freeze period. While the rate freeze has expired, we cannot raise rates without initiating a proceeding before the SDPUC and the WPSC and receiving approval from these commissions. As such, our current rates remain in effect.
Unless and until we file for and receive a rate increase, we are undertaking the risks of:
Under our current structure, we will continue to retain earnings realized from more efficient operations, sales from load growth, and off-system sales of power and energy.
Beginning in the mid-1990‘s, we initiated an effort to enter into new contracts with our largest commercial and industrial customers. Most of the new contracts contain “meet or release” provisions that grant us a five-year right to continue to serve a customer at market rates in the event of deregulation. Additionally, through our General Service Large Optional Combined Account Billing Tariff, we have allowed general service customers to aggregate their loads. This tariff also provides us with a five-year right to continue to serve those customers in the event of deregulation. Our “meet or release” contracts currently total more than 110megawatts of large commercial and industrial load. These contracts provide us with greater assurance of a firm local market for our power resources in the event deregulation occurs. These industrial and large commercial customers, together with our wholesale power sale agreements with the City of Gillette, Wyoming and MDU, equal approximately 50 percent of our firm load.
Regulatory Accounting
As it pertains to the accounting for our utility operations, we follow SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” and our financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions in which we operate. As a result of our regulatory activity, a 50-year depreciable life for the Neil Simpson II plant is used for financial reporting purposes. If we were not following SFAS 71, a 35- to 40-year life would probably be more appropriate, which would increase depreciation expense by approximately $0.6 — $1.1 million per year. If rate recovery of generation-related costs becomes unlikely or uncertain, due to competition or regulatory action, these accounting standards may no longer apply to our generation operations. In the event we determine that we no longer meet the criteria for following SFAS 71, the accounting impact to us could be an extraordinary non-cash charge to operations of an amount that could be material. Criteria that may give rise to the discontinuance of SFAS 71 include increasing competition that could restrict our ability to establish prices to recover specific costs and a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. We periodically review these criteria to ensure that the continuing application of SFAS 71 is appropriate.
See Note 1 of our Notes to Consolidated Financial Statements for information on new accounting standards adopted in 2004 or pending adoption.
5
The following specific risk factors and other risk factors that we discuss in our periodic reports from time to time should be considered for a better understanding of our Company. These factors and other matters discussed herein are important factors that could cause our actual results or outcomes to differ materially from those discussed in the forward looking statements included elsewhere in this document.
Our credit ratings could be further lowered in the future. If this were to occur, our access to capital and our cost of capital and other costs would be negatively affected.
Our issuer credit rating is “Baa2” by Moody’s Investor Services, Inc., or Moody’s and “BBB-” by Standard & Poors. Our credit rating on our First Mortgage Bonds is “Baa1” by Moody’s and “BBB” by Standard & Poor’s. Any further reduction in our ratings by Moody’s or Standard & Poor’s Rating Service could adversely affect our ability to refinance or repay our existing debt and to complete new financings.
In addition, a further downgrade in our credit rating would increase our costs of borrowing under some of our existing debt obligations.
A downgrade could also result in our business counterparties requiring us to provide additional amounts of collateral under new transactions.
Geopolitical tensions may impair our ability to raise capital and limit our growth.
Continuing conflict in Iraq or further tensions with the governments of Iran or North Korea could disrupt capital markets and make it more costly or temporarily impossible for us to raise capital, thus hampering the implementation of our stated strategy. In the past, geopolitical events, including the uncertainty associated with the Gulf War in 1991 and the terrorist attacks of September 11, 2001, have been associated with general economic slowdowns. Geopolitical tensions or other factors could retard economic growth and reduce demand for the power and fuel products that we produce or market, which could adversely affect our earnings.
We may not raise retail rates without prior approval of the South Dakota Public Utilities Commission or the Wyoming Public Services Commission. If we seek rate relief, we could experience delays in obtaining approvals and could have rate recovery disallowed in rate proceedings.
Our rate freeze agreement with the SDPUC expired on January 1, 2005. Until such time as we petition the SDPUC or the WPSC for rate relief, or either commission requires that we do so, we may not increase our retail rates. Additionally, we may not invoke any fuel and purchased power adjustment tariff that would take effect prior to the completion of a rate proceeding, absent extraordinary circumstances. As part of the process for Black Hills Corporation to obtain approval to acquire Cheyenne Light, Fuel and Power (CLF&P), a combination public utility serving electric and gas customers in Cheyenne, Wyoming and vicinity, we agreed with the WPSC that we would not raise retail rates for our Wyoming customers prior to January 1, 2006. Because we are generally unable to increase our base rates without prior approval from the SDPUC and the WPSC, our returns could be threatened by plant outages, machinery failure, increases in purchased power costs over which our utility has no control, acts of nature, acts of terrorism or other unexpected events that could cause operating costs to increase and operating margins to decline. Moreover, in the event of unexpected plant outages or machinery failures, we may be required to purchase replacement power in wholesale power markets at prices that exceed the rates we are permitted to charge our retail customers. Finally, our costs would be subject to the review of the SDPUC or the WPSC, and the commissions could find certain costs not to be recoverable, thus negatively affecting our revenues.
6
Because prices for our products and services and other operating costs for our business are volatile, our revenues and expenses may fluctuate.
The prices of energy products in the wholesale power markets have stabilized at lower levels after the price volatility experienced in the second half of 2000 and the first half of 2001. Power prices are influenced by many factors outside our control, including:
Moreover, unlike most other commodities, electricity cannot be stored and therefore must be produced concurrently with its use. As a result, wholesale power markets are subject to significant price fluctuations over relatively short periods of time and can be unpredictable.
Construction, expansion, refurbishment and operation of power generating and transmission facilities involve significant risks which could lead to lost revenues or increased expenses.
The construction, expansion, refurbishment and operation of power generating and transmission and resource recovery facilities involve many risks, including:
7
The ongoing operation of our facilities involves all of the risks described above, in addition to risks relating to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, especially in the case of newer environmental emission control technology. Any of these risks could cause us to operate below expected capacity levels, which in turn could result in lost revenues, increased expenses, higher maintenance costs and penalties. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our rights under warranties or performance guarantees may not be adequate to cover lost revenues, increased expenses or liquidated damage payments.
Our business is subject to substantial governmental regulation and permitting requirements as well as on-site environmental liabilities. We may be adversely affected by any future inability to comply with existing or future regulations or requirements or the potentially high cost of complying with such requirements.
Our business is subject to extensive energy, environmental and other laws and regulations of federal, state and local authorities. We generally are required to obtain and comply with a wide variety of licenses, permits and other approvals in order to operate our facilities. In the course of complying with these requirements, we may incur significant additional costs. If we fail to comply with these requirements, we could be subject to civil or criminal liability and the imposition of liens or fines. In addition, existing regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to us or our facilities, and future changes in laws and regulation may have a detrimental effect on our business.
We strive at all times to be in compliance with all applicable environmental laws and regulations. However, steps to bring our facilities into compliance, if necessary, could be expensive, and thus could adversely affect our results of operation and financial condition. Furthermore, with the continuing trends toward stricter standards, greater regulation, more extensive permitting requirements and an increase in the assets we operate, we expect our environmental expenditures to be substantial in the future.
Ongoing changes in the United States utility industry, such as state and federal regulatory changes, a potential increase in the number of our competitors or the imposition of price limitations to address market volatility, could adversely affect our profitability.
The United States electric utility industry is currently experiencing increasing competitive pressures as a result of:
FERC has implemented and continues to propose regulatory changes to increase access to the nationwide transmission grid by utility and non-utility purchasers and sellers of electricity. In addition, a number of states have implemented or are considering or currently implementing methods to introduce and promote retail competition. Industry deregulation in some states has led to the disaggregation of some vertically integrated utilities into separate generation, transmission and distribution businesses, and deregulation initiatives in a number of states may encourage further disaggregation. As a result, significant additional competitors could become active in the generation, transmission and distribution segments of our industry.
8
In addition, the independent system operators who oversee most of the wholesale power markets have in the past imposed, and may in the future continue to impose, price limitations and other mechanisms to address some of the volatility in these markets. These types of price limitations and other mechanisms may adversely affect the profitability of selling energy into the wholesale power markets. Given the extreme volatility and lack of meaningful long-term price history in some of these markets and the imposition of price limitations by independent system operators, we may not be able to operate profitably in all wholesale power markets.
This Annual Report on Form 10-K includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including the risk factors described in Item 1 of this Form 10-K and the following:
• Our ability to access the debt and equity markets, which will depend on general market conditions and the credit ratings for our debt obligations; |
• General economic and political conditions, including tax rates or policies and inflation rates; |
• The creditworthiness of counterparties and defaults on amounts due from counterparties; |
• The amount of collateral required to be posted from time to time in our transactions; |
• Changes in or compliance with laws and regulations, particularly those relating to taxation, safety and protection of the environment; |
• The timing and extent of changes in energy-related and commodity prices, interest rates, energy and commodity supply or volume, the cost of transportation of commodities, and demand for our services, all of which can affect our earnings, liquidity position and the underlying value of our assets; |
• The timing and extent of scheduled and unscheduled outages of power generation facilities; |
• Weather and other natural phenomena; |
• Industry and market changes, including the impact of consolidations and changes in competition; |
• The outcome of any ongoing or future litigation or similar disputes and the impact on any such outcome or related settlements; |
• The effect of accounting policies issued periodically by accounting standard-setting bodies; |
3
• Our use of derivative financial instruments to hedge commodity and interest rate risks; |
• The cost and effects on our business, including insurance, resulting from terrorist actions or responses to such actions; |
• Obtaining adequate cost recovery through regulatory proceedings; |
• Capital market conditions which may affect our ability to raise capital on favorable terms; |
• Price risk due to marketable securities held as investments in benefit plans; and |
• Other factors discussed from time to time in our filings with the SEC. |
New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events, or otherwise.
General
We are an electric utility serving customers in South Dakota, Wyoming and Montana. We are incorporated in South Dakota and began providing electric utility service in 1941. We are a wholly-owned subsidiary of the publicly traded Black Hills Corporation.
Unless the context otherwise requires, references in this Form 10-K to “Black Hills Power,” “we,” “us” and “our” refer to Black Hills Power, Inc.
We engage in the generation, transmission and distribution of electricity. We have a solid foundation of revenues, earnings and cash flow that support our capital expenditures, dividends, and overall performance and growth.
Distribution and Transmission
Distribution and Transmission. Our distribution and transmission businesses serve approximately 63,500 electric customers, with an electric transmission system of 447 miles of high voltage lines and 511 miles of lower voltage lines. In addition, we jointly own 47 miles of high voltage lines with Basin Electric Cooperative. Our service territory covers a 9,300 square mile area of western South Dakota, northeastern Wyoming and southeastern Montana with a strong and stable economic base. Approximately 90 percent of our retail electric revenues in 2005 were generated in South Dakota.
4
The following are characteristics of our distribution and transmission businesses:
• We have a diverse customer and revenue base. Our revenue mix for the year ended December 31, 2005 was comprised of 26 percent commercial, 21 percent residential, 12 percent contract wholesale, 25 percent wholesale off-system, 11 percent industrial and 5 percent municipal sales and other revenue. Approximately 81 percent of our large commercial and industrial customers are provided service under long-term contracts. We have historically optimized the utilization of our power supply resources by selling wholesale power to other utilities and to power marketers in the spot market and through short-term sales contracts. |
• We are subject to regulation by the South Dakota Public Utilities Commission (SDPUC) and the Wyoming Public Service Commission (WPSC). The retail rate freeze granted to us by the SDPUC, which had been in effect for 10 years, expired on January 1, 2005. Our current rates in South Dakota and Wyoming remain in place following the expiration of the rate freeze. The rate freeze preserved our low-cost rate structure for our retail customers at levels below the national average while allowing us to retain the benefits from cost savings and from wholesale “off-system” sales, which were not covered by the rate freeze. Our rates do not include a fuel or a purchased power adjustment, so we continue to have the flexibility in allocating our generating capacity to wholesale off-system sales. While we are not obligated to do so, we are permitted to petition the SDPUC and WPSC for a rate increase at any time, or the SDPUC and WPSC may require that we do so. We will continue to monitor our rate structure and when appropriate, file a rate case. |
• Black Hills Power and Basin Electric Power Cooperative completed the construction of an AC-DC-AC transmission tie in the fourth quarter of 2003. We own 35 percent and Basin Electric owns 65 percent of the transmission tie. The transmission tie provides an interconnection between the Western and Eastern transmission grids, enabling access to both the WECC region in the West, and the Mid-Continent Area Power Pool, or “MAPP” region in the East. Our system is located in the WECC region. The total transfer capacity of the tie is 400 megawatts - 200 megawatts from West to East and 200 megawatts from East to West. This transmission tie allows us to buy and sell energy in the Eastern interconnection without having to isolate and physically reconnect load or generation between the two electrical transmission grids. The transmission tie is bidirectional and thus accommodates scheduling transactions in both directions simultaneously. This transfer capability provides additional opportunity to sell our excess generation or to make economic purchases to serve our native load and our contract obligations, and to take advantage of the power price differentials between the two electric grids. Additionally, our system is capable of directly interconnecting up to 80 megawatts of generation or load to the Eastern transmission grid. Transmission constraints within the MAPP transmission system may limit the amount of capacity that may be directly interconnected to the Eastern system at any given time. |
• We have firm point-to-point transmission access to deliver up to 17 megawatts of power on PacifiCorp’s transmission system to wholesale customers in the Western region through 2006 and 50 megawatts from 2007 through 2023. |
• We have firm network transmission access to deliver power on PacifiCorp’s system to Sheridan, Wyoming to serve our power sales contract with Montana-Dakota Utilities Company (MDU) through 2006, with the right to renew pursuant to the terms of PacifiCorp’s transmission tariff. |
5
Power Sales Agreements. We sell a portion of our current load under long-term contracts. Our key contracts include:
• an agreement with MDU, expiring at the end of 2006, for the sale of up to 55 megawatts of capacity and energy to serve the Sheridan, Wyoming electric service territory. We entered into a new power purchase agreement with MDU for the supply of up to 74 megawatts of capacity and energy for Sheridan, Wyoming from 2007 through 2016, which is subject to regulatory approval by the WPSC; and |
• an agreement with the City of Gillette, Wyoming, expiring in 2013, to provide the city’s first 23 megawatts of capacity and energy. The agreement renews automatically and requires a seven year notice of termination. |
These consumers are integrated into our control area and are treated as firm native load. We also provide 20 megawatts of unit contingent energy and capacity to MEAN under a contract that expires in 2013.
Regulated Power Plants and Purchased Power. Our electric load is primarily served by our generating facilities in South Dakota and Wyoming, which provide 435 megawatts of generating capacity, with the balance supplied under purchased power and capacity contracts. Approximately 50 percent of our capacity is coal-fired, 39 percent is oil- or gas-fired, and 11 percent is supplied under the following purchased power contracts with PacifiCorp:
• a power purchase agreement expiring in 2023, involving the purchase by us of 50 megawatts of baseload power; and |
• a reserve capacity integration agreement expiring in 2012, which makes available to us 100 megawatts of reserve capacity in connection with the utilization of the Ben French CT units. |
Since 1995, we have been a net producer of energy. We reached our peak system load of 401 megawatts in July 2005. None of our generation is restricted by hours of operation, thereby providing us the ability to generate power to meet demand whenever necessary and economically feasible.
6
Rate Regulation
Rate Regulation
The rate freeze granted by the SDPUC, which had been in effect for us since 1995, expired on January 1, 2005. During this ten-year term, we were prohibited, subject to certain limited exceptions, from filing for any increase in our rates or invoking any fuel and purchased power adjustment tariff which would take effect during the freeze period. While the rate freeze has expired, we cannot raise rates without initiating a proceeding before the SDPUC and the WPSC and receiving approval from these commissions. As such, our rates in place during the freeze period remain in effect.
Unless and until we file for and receive a rate increase, we are undertaking the risks of:
• machinery failure; |
• load loss caused by either an economic downturn or changes in regulation; |
• increased costs of fuel commodities; |
• increased costs under power purchase contracts over which it has no control; |
• government impositions; and |
• acts of nature and other unexpected events that could cause material losses of income or increases in costs of doing business. |
Regulatory Accounting
As it pertains to the accounting for our utility operations, we follow SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” and our financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions in which we operate. If rate recovery becomes unlikely or uncertain, due to competition or regulatory action, these accounting standards may no longer apply to our generation operations. In the event we determine that we no longer meet the criteria for following SFAS 71, the accounting impact to us could be an extraordinary non-cash charge to operations of an amount that could be material. Criteria that may give rise to the discontinuance of SFAS 71 include increasing competition that could restrict our ability to establish prices to recover specific costs and a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. We periodically review these criteria to ensure that the continuing application of SFAS 71 is appropriate.
New Accounting Pronouncements
See Note 1 of our Notes to Financial Statements for information on new accounting standards adopted in 2005 or pending adoption.
7
ITEM 1A. | RISK FACTORS |
The following specific risk factors and other risk factors that we discuss in our periodic reports from time to time should be considered for a better understanding of our Company. These factors and other matters discussed herein are important factors that could cause our actual results or outcomes to differ materially from those discussed in the forward looking statements included elsewhere in this document.
Our credit ratings could be lowered in the future. If this were to occur, our access to capital and our cost of capital and other costs would be negatively affected.
Our issuer credit rating is “Baa2” by Moody’s Investor Services, Inc., or Moody’s and “BBB-” by Standard & Poors. Our credit rating on our First Mortgage Bonds is “Baa1” by Moody’s and “BBB” by Standard & Poor’s. Any reduction in our ratings by Moody’s or Standard & Poor’s Rating Service could adversely affect our ability to refinance or repay our existing debt and to complete new financings. In addition, a downgrade in our credit rating would increase our costs of borrowing under some of our existing debt obligations. A downgrade could also result in our business counterparties requiring us to provide additional amounts of collateral under new transactions.
We may not raise our retail rates without prior approval of the South Dakota Public Utilities Commission or the Wyoming Public Services Commission. If we seek rate relief, we could experience delays in obtaining approvals and could have rate recovery disallowed in rate proceedings.
Our rate freeze agreement with the SDPUC expired on January 1, 2005. Until such time as we petition the SDPUC or the WPSC for rate relief, or either commission requires that we do so, we may not increase our retail rates. Additionally, we may not invoke any fuel and purchased power adjustment tariff that would take effect prior to the completion of a rate proceeding, absent extraordinary circumstances. Because we are generally unable to increase our base rates without prior approval from the SDPUC and the WPSC, our returns could be threatened by plant outages, machinery failure, increases in fuel and purchased power costs over which we have no control, acts of nature, acts of terrorism or other unexpected events that could cause operating costs to increase and operating margins to decline. Moreover, in the event of unexpected plant outages or machinery failures, we may be required to purchase replacement power in wholesale power markets at prices that exceed the rates we are permitted to charge our retail customers. Finally, our costs would be subject to the review of the SDPUC or the WPSC, and the commissions could find certain costs not to be recoverable, thus negatively affecting our revenues.
Because prices in the wholesale power markets are volatile, our revenues and expenses may fluctuate.
A portion of the variability of our net income in recent years has been attributable to wholesale electricity sales. The related power prices are influenced by many factors outside our control, including:
• fuel prices; |
• transmission constraints; |
• supply and demand; |
• weather; |
• economic conditions; and |
• the rules, regulations and actions of the system operators in those markets. |
8
Moreover, unlike most other commodities, electricity cannot be stored and therefore must be produced concurrently with its use. As a result, wholesale power markets are subject to significant price fluctuations over relatively short periods of time and can be unpredictable.
Construction, expansion, refurbishment and operation of power generating and transmission and resource recovery facilities involve significant risks which could lead to lost revenues or increased expenses.
The construction, expansion, refurbishment and operation of power generating and transmission facilities involve many risks, including:
• the inability to obtain required governmental permits and approvals; |
• the unavailability of equipment; |
• supply interruptions; |
• work stoppages; |
• labor disputes; |
• social unrest; |
• weather interferences; |
• unforeseen engineering, environmental and geological problems; and |
• unanticipated cost overruns. |
The ongoing operation of our facilities involves all of the risks described above, in addition to risks relating to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, especially in the case of newer environmental emission control technology. Any of these risks could cause us to operate below expected capacity levels, which in turn could result in lost revenues, increased expenses, higher maintenance costs and penalties. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our rights under warranties or performance guarantees may not be adequate to cover lost revenues, increased expenses or liquidated damage payments.
Our business is subject to substantial governmental regulation and permitting requirements as well as on-site environmental liabilities we assumed when we acquired some of our facilities. We may be adversely affected by any future inability to comply with existing or future regulations or requirements or the potentially high cost of complying with such requirements.
Our business is subject to extensive energy, environmental and other laws and regulations of federal, state and local authorities. We generally are required to obtain and comply with a wide variety of licenses, permits and other approvals in order to operate our facilities. In the course of complying with these requirements, we may incur significant additional costs. If we fail to comply with these requirements, we could be subject to civil or criminal liability and the imposition of liens or fines. In addition, existing regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to us or our facilities, and future changes in laws and regulation may have a detrimental effect on our business.
9
We strive at all times to be in compliance with all applicable environmental laws and regulations. However, steps to bring our facilities into compliance, if necessary, could be expensive, and thus could adversely affect our results of operation and financial condition. Furthermore, with the continuing trends toward stricter standards, greater regulation, more extensive permitting requirements and an increase in the assets we operate, we expect our environmental expenditures to be substantial in the future.
Ongoing changes in the United States utility industry, such as state and federal regulatory changes, a potential increase in the number of our competitors or the imposition of price limitations to address market volatility, could adversely affect our profitability.
The United States electric utility industry is currently experiencing increasing competitive pressures as a result of:
• the Energy Policy Act of 2005 and the repeal of the Public Utility Holding Company Act of 1935; |
• consumer demands; |
• technological advances; and |
• greater availability of natural gas-fired power generation, and other factors. |
FERC has implemented and continues to propose regulatory changes to increase access to the nationwide transmission grid by utility and non-utility purchasers and sellers of electricity. In addition, a number of states have implemented or are considering or currently implementing methods to introduce and promote retail competition. Industry deregulation in some states has led to the disaggregation of some vertically integrated utilities into separate generation, transmission and distribution businesses, and deregulation initiatives in a number of states may encourage further disaggregation. As a result, significant additional competitors could become active in the generation, transmission and distribution segments of our industry, which could negatively affect our ability to expand our asset base.
In addition, the independent system operators who oversee many of the wholesale power markets have in the past imposed, and may in the future continue to impose, price limitations and other mechanisms to address some of the volatility in these markets. These types of price limitations and other mechanisms may adversely affect the profitability of those generating facilities that sell energy into the wholesale power markets. Given the extreme volatility and lack of meaningful long-term price history in some of these markets and the imposition of price limitations by independent system operators, we may not be able to operate profitably in all wholesale power markets.
ITEM 1B. | UNRESOLVED STAFF COMMENTS |
None.
ITEM 3. | LEGAL PROCEEDINGS |
Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” subcaption within Item 8, Note 10, “Commitments and Contingencies”, of our Notes to Financial Statements in this Annual report on Form 10-K.
10
PART II
ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS |
All of our common stock is held by our parent company, Black Hills Corporation. Accordingly, there is no established trading market for our common stock.
ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS |
In 2003, we made a non-cash dividend to our parent company, Black Hills Corporation, consisting of our 100 percent ownership in Black Hills Generation, Inc., formerly known as Black Hills Energy Capital, Inc. As a result, we no longer have any subsidiaries and operate only in the electric utility business.
| 2004 | 2003 | 2002 | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | |||||||||||
Revenue | $ | 173,745 | $ | 171,019 | $ | 162,186 | |||||
| Operating expenses | 129,936 | 119,920 | 104,026 | ||||||||
| Operating income | $ | 43,809 | $ | 51,099 | $ | 58,160 | |||||
| Income from continuing operations | $ | 19,209 | $ | 24,089 | $ | 30,217 | |||||
| 2005 | 2004 | 2003 | |||
| (in thousands) | |||||
|
|
|
|
|
|
|
Revenue | $ | 189,500 | $ | 173,745 | $ | 171,019 |
Operating expenses |
| 152,961 |
| 129,936 |
| 119,920 |
Operating income | $ | 36,044 | $ | 43,809 | $ | 51,099 |
Income from continuing |
|
|
|
|
|
|
operations | $ | 18,005 | $ | 19,209 | $ | 24,089 |
The following table provides certain electric utility operating statistics:
| 2004 | 2003 | 2002 | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
Firm electric sales - MWh | 1,959,969 | 1,994,819 | 1,966,060 | ||||||||
| Wholesale off-system - MWh | 1,090,827 | 930,706 | 979,677 | ||||||||
Electric Revenue | ||||||||
(in thousands) | ||||||||
|
|
|
|
|
| |||
|
| Percentage |
| Percentage |
| |||
Customer Base | 2005 | Change | 2004 | Change | 2003 | |||
|
|
|
|
|
|
|
|
|
Commercial | $ | 49,185 | 5% | $ | 46,791 | (2)% | $ | 47,777 |
Residential |
| 39,348 | 8 |
| 36,536 | (3) |
| 37,716 |
Industrial |
| 19,982 | 1 |
| 19,796 | 1 |
| 19,589 |
Municipal sales |
| 2,268 | 3 |
| 2,200 | 5 |
| 2,102 |
Contract wholesale |
| 23,384 | 3 |
| 22,720 | 6 |
| 21,451 |
Wholesale off-system |
| 47,647 | 25 |
| 38,228 | 13 |
| 33,743 |
Total electric sales |
| 181,814 | 9 |
| 166,271 | 2 |
| 162,378 |
Other revenue |
| 7,191 | (4) |
| 7,474 | (14) |
| 8,641 |
Total revenue | $ | 189,005 | 9% | $ | 173,745 | 2% | $ | 171,019 |
11
Megawatt Hours Sold | |||||
|
|
|
|
|
|
|
| Percentage |
| Percentage |
|
Customer Base | 2005 | Change | 2004 | Change | 2003 |
|
|
|
|
|
|
Commercial | 655,076 | 4% | 627,326 | (2)% | 641,779 |
Residential | 480,053 | 7 | 447,166 | (3) | 463,290 |
Industrial | 417,628 | 3 | 406,209 | — | 404,341 |
Municipal sales | 30,084 | 4 | 28,934 | 5 | 27,426 |
Contract wholesale | 619,369 | 1 | 614,700 | 5 | 614,888 |
Wholesale off-system | 869,161 | (6) | 926,461 | 15 | 773,801 |
Total electric sales | 3,071,371 | 1% | 3,050,796 | 4% | 2,925,525 |
We currently haveestablished a new summer peak load of 401 megawatts in July 2005 and a new winter peak load of 344356 megawatts established in December 1998 and a summer peak load of 392 megawatts established in August 2001.2005. We own 435 megawatts of electric utility generating capacity and purchase an additional 50 megawatts under a long-term agreement.agreement expiring in 2023.
10
|
| Percentage |
| Percentage |
|
Resources | 2005 | Change | 2004 | Change | 2003 |
|
|
|
|
|
|
Megawatt-hours generated: |
|
|
|
|
|
Coal | 1,728,823 | (1)% | 1,753,693 | (3)% | 1,806,444 |
Gas | 37,239 | 34 | 27,825 | (82) | 156,703 |
| 1,766,062 | (1) | 1,781,518 | (9) | 1,963,147 |
|
|
|
|
|
|
Megawatt-hours purchased | 1,399,212 | 3 | 1,361,409 | 30 | 1,048,076 |
Total resources | 3,165,274 | 1% | 3,142,927 | 4% | 3,011,223 |
|
|
|
|
| 2005 | 2004 | 2003 |
|
|
|
|
Heating and cooling degree days |
|
|
|
Actual |
|
|
|
Heating degree days | 6,488 | 6,553 | 7,065 |
Cooling degree days | 830 | 522 | 891 |
|
|
|
|
Variance from normal |
|
|
|
Heating degree days | (10)% | (9)% | (2)% |
Cooling degree days | 39 % | (13)% | 49 % |
12
2005 Compared to 2004
Electric revenue increased 9 percent for the year ended December 31, 2005 compared to the same period in the prior year. Firm commercial, residential and contract wholesale sales increased 5 percent, 8 percent and 3 percent, respectively. Cooling degree days for the year were 59 percent higher than 2004 and heating degree days were 1 percent lower than 2004. Wholesale off-system sales increased 25 percent due to a 33 percent increase in average price received partially offset by a 6 percent decrease in megawatt-hours sold.
Electric operating expenses increased 18 percent for the year ended December 31, 2005, compared to the prior year. Higher operating expenses were primarily the result of an $18.5 million increase in fuel and purchased power costs. The increase in fuel and purchased power was due to a $16.9 million increase in purchased power, which includes $2.8 million of additional purchase power costs to cover the outage of Neil Simpson II, as well as a 31 percent increase in average price per megawatt-hour, and a 3 percent increase in megawatt-hours purchased. Fuel costs increased $1.6 million due to a 12 percent increase in average cost, partially offset by a 1 percent decrease in megawatt-hours generated. Megawatt-hours produced through coal-fired generation decreased while higher cost gas generation was utilized in 2005. Purchased power and gas generation were utilized for firm load demand and peaking needs due to unscheduled plant outages and warmer weather. The increase in operating expense was also affected by increased power marketing legal expense, compensation costs and corporate allocations, partially offset by lower maintenance costs due to scheduled and unscheduled plant maintenance in 2004.
Income from continuing operations decreased $1.2 million primarily due to increased fuel and purchased power costs, legal expense, compensation costs and corporate allocations, partially offset by increased revenues, lower maintenance costs, lower interest expense due to the pay down of debt, and a $1.9 million benefit from a deferred tax adjustment.
2004 Compared to 2003
Electric revenue increased 2 percent in 2004 compared to 2003, primarily due to a 1613 percent increase in wholesale off-system sales offset by decreased transmission revenues due to lower approved rates and higher load share of our Open Access Transmission Tariff revenues.
Firm kilowatt-hour sales decreased 2 percent.
Residential and commercial sales decreases of 3 percent and 2 percent, respectively, in 2004 accounted for a $1.7 million decrease in revenue. These decreases were partially offset by a 1 percent increase in industrial sales. The 1615 percent increase in wholesale off-system salesmegawatt-hours accounted for a $5.9$4.5 million increase in revenues. Cooling degree days were 41 percent lower than 2003 and heating degree days were 7 percent lower than 2003.
Revenue per kilowatt-hour sold was 5.5 cents in 2004 compared to 5.6 cents in 2003. The number of customers in the service area increased to 62,259 in 2004 from 61,148 in 2003. Degree days, which is a measure of weather trends, were 11 percent below last year and 9 percent below normal.
Electric utility operating expenses increased $10.0 million due to a $5.9 million increase in fuel and purchased power cost, a $4.5 million increase in certain operations and maintenance costs and administrative and general costs, including scheduled and unscheduled maintenance costs, increased group insurance and corporate allocations and increased costs associated with the increase in wholesale off-system sales, partially offset by decreased interest expense of $0.9 million, primarily due to retirement of debt.
The increase in fuel and purchased power cost was due to an $11.8 million increase in purchased power costs, offset by a $5.9 million decrease in fuel costs, as prevailing gas prices made it more economical for us to purchase power for our peaking needs and increased off-system sales, rather than generate energy utilizing our gas turbines.
2003 Compared to 2002
Electric revenue increased 5 percent in 2003, compared to 2002, primarily due to an 18 percent increase in wholesale off-system sales at an average price that was 24 percent higher than the average price in 2002.13
Firm kilowatt-hour sales increased 1 percent. Residential and commercial sales increases of 2 percent and 3 percent, respectively, in 2003 accounted for a $2.1 million increase in revenue. The 18 percent increase in wholesale off-system sales accounted for a $5.8 million increase in revenues. These increases were off-set by a 4 percent decrease in industrial sales, primarily due to the closing of Homestake Mine, which had been one of our largest customers.
Revenue per kilowatt-hour sold was 5.6 cents in 2003 compared to 5.3 cents in 2002. The number of customers in the service area increased to 61,148 in 2003 from 59,948 in 2002.
Electric utility operating expenses increased $15.9 million due to a $10.1 million increase in fuel and purchase power cost, a $3.7 million increase in certain operations and maintenance costs and administrative and general costs, including pension expense, a $1.5 million increase in depreciation expense and a $2.5 million increase in interest expense due to the full year impact of $75 million of first mortgage bonds issued in August 2002.
ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
The increase in fuel cost is due to a 77 percent increase in average gas prices for combustion turbine generation facilities and a 19 percent increase in average megawatt-hour purchased power costs.
11
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
| Report of Independent Registered Public Accounting Firm | 13 | ||||
Consolidated Statements of Income | |||||
| for the three years ended December 31, 2004 | 14 | ||||
Consolidated Balance Sheets as of December 31, 2004 and 2003 | 15 | ||||
Consolidated Statements of Cash Flows | |||||
| for the three years ended December 31, 2004 | 16 | ||||
Consolidated Statements of Common Stockholder's Equity and Comprehensive Income | |||||
| for the three years ended December 31, 2004 | 17 | ||||
Notes to Consolidated Financial Statements | 18- | 36 | |||
12
Report of Independent Registered Public Accounting Firm | 15 |
Statements of Income for the three years ended December 31, 2005 | 16 |
Balance Sheets as of December 31, 2005 and 2004 | 17 |
Statements of Cash Flows for the three years ended December 31, 2005 | 18 |
Statements of Common Stockholder’s Equity and | |
for the three years ended December 31, 2005 | 19 |
Notes to Financial Statements | 20-43 |
14
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholder of
Black Hills Power, Inc.
Rapid City, South Dakota
We have audited the accompanying consolidated balance sheets of Black Hills Power, Inc. and subsidiaries (the Company) as of December 31, 20042005 and 2003,2004, and the related consolidated statements of income, common stockholder’s equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2004.2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.Ourreporting.Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Black Hills Power, Inc. and subsidiaries as of December 31, 20042005 and 2003,2004, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 2004,2005, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1, the accompanying 2003 Statement of Cash Flows has been restated.
DELOITTE & TOUCHE LLP
Minneapolis, Minnesota,
March 10, 200516, 2006
13
15
BLACK HILLS POWER, INC.CONSOLIDATED
STATEMENTS OF INCOMEYears ended December 31, 2004 2003 2002 (in thousands)
Operating revenues $ 173,745 $ 171,019 $ 162,186 Operating expenses: Fuel and purchased power 60,668 54,815 44,742 Operations and maintenance 26,030 25,207 24,335 Administrative and general 16,570 12,965 10,041 Depreciation and amortization 18,873 18,999 17,499 Taxes, other than income taxes 7,795 7,934 7,409 129,936 119,920 104,026 Operating income 43,809 51,099 58,160 Other (expense) income: Interest expense (16,019 ) (17,044 ) (13,662 ) Interest income 696 1,512 734 Other expense (213 ) (286 ) (312 ) Other income 448 430 364 (15,088 ) (15,388 ) (12,876 ) Income from continuing operations before income taxes 28,721 35,711 45,284 Income taxes (9,512 ) (11,622 ) (15,067 ) Income from continuing operations 19,209 24,089 30,217 Discontinued operations, net of income taxes (Note 11) -- 1,906 10,962 Net income $ 19,209 $ 25,995 $ 41,179 The accompanying notes to financial statements are an integral part of these financial statements.
14
Years ended December 31, | 2005 | 2004 | 2003 | |||||
| (in thousands) | |||||||
|
|
|
|
| �� |
| ||
Operating revenues | $ | 189,005 | $ | 173,745 | $ | 171,019 | ||
|
|
|
|
|
|
| ||
Operating expenses: |
|
|
|
|
|
| ||
Fuel and purchased power |
| 80,886 |
| 60,668 |
| 54,815 | ||
Operations and maintenance |
| 22,586 |
| 26,030 |
| 25,207 | ||
Administrative and general |
| 22,685 |
| 16,570 |
| 12,965 | ||
Depreciation and amortization |
| 19,543 |
| 18,873 |
| 18,999 | ||
Taxes, other than income taxes |
| 7,261 |
| 7,795 |
| 7,934 | ||
|
| 152,961 |
| 129,936 |
| 119,920 | ||
|
|
|
|
|
|
| ||
Operating income |
| 36,044 |
| 43,809 |
| 51,099 | ||
|
|
|
|
|
|
| ||
Other (expense) income: |
|
|
|
|
|
| ||
Interest expense |
| (12,907) |
| (16,019) |
| (17,044) | ||
Interest income |
| 258 |
| 696 |
| 1,512 | ||
Other expense |
| (110) |
| (213) |
| (286) | ||
Other income |
| 463 |
| 448 |
| 430 | ||
|
| (12,296) |
| (15,088) |
| (15,388) | ||
|
|
|
|
|
|
| ||
Income from continuing operations before income taxes |
| 23,748 |
| 28,721 |
| 35,711 | ||
Income taxes |
| (5,743) |
| (9,512) |
| (11,622) | ||
|
|
|
|
|
|
| ||
Income from continuing operations |
| 18,005 |
| 19,209 |
| 24,089 | ||
Discontinued operations, net of income taxes (Note 11) |
| — |
| — |
| 1,906 | ||
|
|
|
|
|
|
| ||
Net income | $ | 18,005 | $ | 19,209 | $ | 25,995 | ||
The accompanying notes to financial statements are an integral part of these financial statements.
16
BLACK HILLS POWER, INC.CONSOLIDATED
BALANCE SHEETSAt December 31, 2004 2003 (in thousands, except share amounts) ASSETS
Current assets: Cash and cash equivalents $ 344 $ 1,052 Restricted cash 3,069 -- Receivables (net of allowance for doubtful accounts of $912 and $898, respectively) - Customers 17,233 15,719 Affiliates 891 38,618 Other 1,264 1,293 Materials, supplies and fuel 11,513 9,560 Prepaid income taxes 1,872 2,813 Other current assets 474 -- 36,660 69,055 Investments 3,275 2,920 Property, plant and equipment 637,630 623,197 Less accumulated depreciation (232,401 ) (212,041 ) 405,229 411,156 Other assets: Regulatory asset 7,237 4,567 Other 13,204 15,375 20,441 19,942 $ 465,605 $ 503,073 LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities: Current maturities of long-term debt $ 1,991 $ 1,986 Accounts payable 7,551 6,929 Accounts payable - affiliate 331 7,909 Note payable - affiliate 25,074 -- Accrued liabilities 13,814 15,691 Deferred income taxes 2 239 48,763 32,754 Long-term debt, net of current maturities 157,215 210,056 Deferred credits and other liabilities: Deferred income taxes 69,233 65,633 Regulatory liability 6,021 6,337 Other 13,537 12,724 88,791 84,694 Commitments and contingencies (Notes 8 and 10)
Stockholder's equity: Common stock $1 par value; 50,000,000 shares authorized; Issued: 23,416,396 shares in 2004 and 2003 23,416 23,416 Additional paid-in capital 39,549 39,549 Retained earnings 109,307 114,098 Accumulated other comprehensive loss (1,436 ) (1,494 ) 170,836 175,569 $ 465,605 $ 503,073 The accompanying notes to financial statements are an integral part of these financial statements.
15
At December 31, | 2005 |
| 2004 | ||
| (in thousands, except share amounts) | ||||
ASSETS |
|
|
|
|
|
Current assets: |
|
|
|
|
|
Cash and cash equivalents | $ | 685 |
| $ | 344 |
Restricted cash |
| — |
|
| 3,069 |
Receivables (net of allowance for doubtful accounts of $830 and $912, respectively) - |
|
|
|
|
|
Customers |
| 19,297 |
|
| 17,233 |
Affiliates |
| 1,964 |
|
| 891 |
Other |
| 996 |
|
| 1,264 |
Materials, supplies and fuel |
| 14,236 |
|
| 11,513 |
Prepaid income taxes |
| — |
|
| 1,872 |
Deferred income taxes |
| 835 |
|
| 703 |
Other current assets |
| 820 |
|
| 474 |
|
| 38,833 |
|
| 37,363 |
|
|
|
|
|
|
Investments |
| 3,340 |
|
| 3,275 |
|
|
|
|
|
|
Property, plant and equipment |
| 653,679 |
|
| 637,630 |
Less accumulated depreciation |
| (250,583) |
|
| (232,401) |
|
| 403,096 |
|
| 405,229 |
Other assets: |
|
|
|
|
|
Regulatory asset |
| 6,941 |
|
| 7,237 |
Other |
| 11,448 |
|
| 13,204 |
| 18,389 |
|
| 20,441 | |
$ | 463,658 |
| $ | 466,308 | |
LIABILITIES AND STOCKHOLDER’S EQUITY |
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
Current maturities of long-term debt | $ | 1,996 |
| $ | 1,991 |
Accounts payable |
| 10,290 |
|
| 7,551 |
Accounts payable – affiliate |
| 1,624 |
|
| 331 |
Note payable - affiliate |
| 1,842 |
|
| 25,074 |
Accrued liabilities |
| 14,866 |
|
| 13,814 |
|
| 30,618 |
|
| 48,761 |
|
|
|
|
|
|
Long-term debt, net of current maturities |
| 155,219 |
|
| 157,215 |
|
|
|
|
|
|
Deferred credits and other liabilities: |
|
|
|
|
|
Deferred income taxes |
| 67,942 |
|
| 69,938 |
Regulatory liability |
| 5,740 |
|
| 6,021 |
Other |
| 15,460 |
|
| 13,537 |
|
| 89,142 |
|
| 89,496 |
Commitments and contingencies (Notes 8 and 10) |
|
|
|
|
|
|
|
|
|
|
|
Stockholder’s equity: |
|
|
|
|
|
Common stock $1 par value; 50,000,000 shares authorized; |
|
|
|
|
|
Issued: 23,416,396 shares in 2005 and 2004 |
| 23,416 |
|
| 23,416 |
Additional paid-in capital |
| 39,549 |
|
| 39,549 |
Retained earnings |
| 127,312 |
|
| 109,307 |
Accumulated other comprehensive loss |
| (1,598) |
|
| (1,436) |
|
| 188,679 |
|
| 170,836 |
| $ | 463,658 |
| $ | 466,308 |
The accompanying notes to financial statements are an integral part of these financial statements.
17
BLACK HILLS POWER, INC.CONSOLIDATED
STATEMENTS OF CASH FLOWSYears ended December 31, 2004 2003 2002 (in thousands) Operating activities: Net income $ 19,209 $ 25,995 $ 41,179 Adjustments to reconcile net income to net cash provided by operating activities- Income from discontinued operations -- (1,906 ) (10,962 ) Depreciation and amortization 18,873 18,999 17,499 Provision for valuation allowances 14 16 14 Deferred income taxes 3,781 8,918 11,675 Change in operating assets and liabilities- Accounts receivable and other current assets (3,895 ) (2,304 ) (4,493 ) Accounts payable and other current liabilities (8,833 ) (2,284 ) 2,936 Other operating activities 3,005 (3,209 ) (5,278 ) 32,154 44,225 52,570 Investing activities: Property, plant and equipment additions (12,946 ) (25,427 ) (37,472 ) Notes receivable from associated companies, net 37,710 14,798 (42,691 ) Other investing activities (355 ) (239 ) 1,222 24,409 (10,868 ) (78,941 ) Financing activities: Dividends paid on common stock (24,000 ) (29,728 ) (31,148 ) Note payable to associated companies 25,074 -- -- Long-term debt - issuance 18,650 -- 75,000 Long-term debt - repayments (71,486 ) (3,095 ) (18,042 ) Other financing activities (5,509 ) -- -- (57,271 ) (32,823 ) 25,810 Increase (decrease) in cash and cash equivalents (708 ) 534 (561 )
Cash and cash equivalents: Beginning of year 1,052 518 1,079 End of year $ 344 $ 1,052 $ 518 Supplemental disclosure of cash flow information:
Cash paid during the period for- Interest $ 17,351 $ 17,120 $ 12,894 Income taxes $ 5,753 $ 6,745 $ 3,448
Stock dividend distribution to Black Hills Corporation, the parent company of Black Hills Power, Inc. (Note 11) $ -- $ 46,450 $ --
|
|
| Restated | |||
|
|
| (see Note 1) | |||
Years ended December 31, | 2005 | 2004 | 2003 | |||
| (in thousands) | |||||
Operating activities: |
|
|
|
|
|
|
Income from continuing operations | $ | 18,005 | $ | 19,209 | $ | 24,089 |
Adjustments to reconcile net income to net cash |
|
|
|
|
|
|
provided by operating activities- |
|
|
|
|
|
|
Depreciation and amortization |
| 19,543 |
| 18,873 |
| 18,999 |
Provision for valuation allowances |
| (82) |
| 14 |
| 16 |
Deferred income taxes |
| (2,558) |
| 3,781 |
| 8,918 |
Change in operating assets and liabilities- |
|
|
|
|
|
|
Accounts receivable and other current assets |
| (4,206) |
| (3,895) |
| (2,304) |
Accounts payable and other current liabilities |
| 4,373 |
| (8,833) |
| (2,284) |
Other operating activities |
| 4,331 |
| 3,005 |
| (3,209) |
Net cash provided by operating activities of continuing operations |
| 39,406 |
| 32,154 |
| 44,225 |
Net cash provided by operating activities of |
|
|
|
|
|
|
discontinued operations |
| — |
| — |
| 8,544 |
Net cash provided by operating activities |
| 39,406 |
| 32,154 |
| 52,769 |
Investing activities: |
|
|
|
|
|
|
Property, plant and equipment additions |
| (16,918) |
| (12,946) |
| (25,427) |
Notes receivable from associated companies, net |
| — |
| 37,710 |
| 14,798 |
Other investing activities |
| 3,076 |
| (3,424) |
| (239) |
Net cash provided by (used in) investing activities of |
|
|
|
|
|
|
continuing operations |
| (13,842) |
| 21,340 |
| (10,868) |
Net cash used in investing activities of discontinued operations |
| — |
| — |
| (8,212) |
Net cash provided by (used in) investing activities |
| (13,842) |
| 21,340 |
| (19,080) |
Financing activities: |
|
|
|
|
|
|
Dividends paid on common stock |
| — |
| (24,000) |
| (29,728) |
Note payable to associated companies |
| (23,232) |
| 25,074 |
| — |
Long-term debt – issuance |
| — |
| 18,650 |
| — |
Long-term debt – repayments |
| (1,991) |
| (71,486) |
| (3,095) |
Subsidiary cash included in stock dividend to Parent (Note 11) |
| — |
| — |
| (29,034) |
Other financing activities |
| — |
| (2,440) |
| — |
Net cash used in financing activities of continuing operations |
| (25,223) |
| (54,202) |
| (61,857) |
Net cash used in financing activities of discontinued operations |
| — |
| — |
| (15,518) |
Net cash used in financing activities |
| (25,223) |
| (54,202) |
| (77,375) |
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents |
| 341 |
| (708) |
| (43,686) |
Cash and cash equivalents: |
|
|
|
|
|
|
Beginning of year |
| 344 |
| 1,052 |
| 44,738* |
End of year | $ | 685 | $ | 344 | $ | 1,052 |
Supplemental disclosure of cash flow information: |
|
|
|
|
|
|
Cash paid during the period for- |
|
|
|
|
|
|
Interest | $ | 11,993 | $ | 17,351 | $ | 17,120 |
Income taxes | $ | 5,295 | $ | 5,753 | $ | 6,745 |
Stock dividend distribution to Black Hills Corporation, the |
|
|
|
|
|
|
parent company of Black Hills Power, Inc. (Note 11) | $ | — | $ | — | $ | 46,450 |
_________________________
* | Includes $44.2 million of |
16The accompanying notes to financial statements are an integral part of these financial statements.
18
BLACK HILLS POWER, INC.CONSOLIDATED
STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
AND COMPREHENSIVE INCOMEAccumulated Additional Other Common Stock Paid-In Retained Comprehensive Shares Amount Capital Earnings Income (Loss) Total (in thousands)
Balance at December 31, 2001 23,416 $ 23,416 $ 80,961 $ 121,875 $ (4,524 ) $ 221,728 Comprehensive Income: Net income -- -- -- 41,179 -- 41,179 Other comprehensive loss, net of tax (see Note 7) -- -- -- -- (13,531 ) (13,531 ) Total comprehensive income -- -- -- 41,179 (13,531 ) 27,648
Dividends on common stock -- -- -- (31,148 ) -- (31,148 ) Balance at December 31, 2002 23,416 23,416 80,961 131,906 (18,055 ) 218,228 Comprehensive Income: Net income -- -- -- 25,995 -- 25,995 Other comprehensive income, net of tax (see Note 7) -- -- -- -- 7,524 7,524 Total comprehensive income -- -- -- 25,995 7,524 33,519
Non-cash dividend to Parent -- -- (41,412 ) (14,075 ) 9,037 (46,450 ) Dividends on common stock -- -- -- (29,728 ) -- (29,728 ) Balance at December 31, 2003 23,416 23,416 39,549 114,098 (1,494 ) 175,569 Comprehensive Income: Net income -- -- -- 19,209 -- 19,209 Other comprehensive income, net of tax (see Note 7) -- -- -- -- 58 58 Total comprehensive income -- -- -- 19,209 58 19,267
Dividends on common stock -- -- -- (24,000 ) -- (24,000 ) Balance at December 31, 2004 23,416 $ 23,416 $ 39,549 $ 109,307 $ (1,436 ) $ 170,836 The accompanying notes to financial statements are an integral part of these financial statements.
17
|
|
|
| Accumulated |
| ||||||
|
| Additional |
| Other |
| ||||||
| Common Stock | Paid-In | Retained | Comprehensive |
| ||||||
| Shares | Amount | Capital | Earnings | Income (Loss) | Total | |||||
| (in thousands) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2002 | 23,416 | $ | 23,416 | $ | 80,961 | $ | 131,906 | $ | (18,055) | $ | 218,228 |
Comprehensive Income: |
|
|
|
|
|
|
|
|
|
|
|
Net income | — |
| — |
| — |
| 25,995 |
| — |
| 25,995 |
Other comprehensive income, |
|
|
|
|
|
|
|
|
|
|
|
net of tax (see Note 7) | — |
| — |
| — |
| — |
| 7,524 |
| 7,524 |
Total comprehensive income | — |
| — |
| — |
| 25,995 |
| 7,524 |
| 33,519 |
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash dividend to Parent | — |
| — |
| (41,412) |
| (14,075) |
| 9,037 |
| (46,450) |
Dividends on common stock | — |
| — |
| — |
| (29,728) |
| — |
| (29,728) |
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2003 | 23,416 |
| 23,416 |
| 39,549 |
| 114,098 |
| (1,494) |
| 175,569 |
Comprehensive Income: |
|
|
|
|
|
|
|
|
|
|
|
Net income | — |
| — |
| — |
| 19,209 |
| — |
| 19,209 |
Other comprehensive income, |
|
|
|
|
|
|
|
|
|
|
|
net of tax (see Note 7) | — |
| — |
| — |
| — |
| 58 |
| 58 |
Total comprehensive income | — |
| — |
| — |
| 19,209 |
| 58 |
| 19,267 |
|
|
|
|
|
|
|
|
|
|
|
|
Dividends on common stock | — |
| — |
| — |
| (24,000) |
| — |
| (24,000) |
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2004 | 23,416 |
| 23,416 |
| 39,549 |
| 109,307 |
| (1,436) |
| 170,836 |
Comprehensive Income: |
|
|
|
|
|
|
|
|
|
|
|
Net income | — |
| — |
| — |
| 18,005 |
| — |
| 18,005 |
Other comprehensive income, |
|
|
|
|
|
|
|
|
|
|
|
net of tax, (see Note 7) | — |
| — |
| — |
| — |
| (162) |
| (162) |
Total comprehensive income | — |
| — |
| — |
| 18,005 |
| (162) |
| 17,843 |
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2005 | 23,416 | $ | 23,416 | $ | 39,549 | $ | 127,312 | $ | (1,598) | $ | 188,679 |
The accompanying notes to financial statements are an integral part of these financial statements.
19
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2005, 2004 2003 and 20022003(1) BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(1) | BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
Business Description
Black Hills Power, Inc. (the Company) is an electric utility serving customers in South Dakota, Wyoming and Montana. The Company is a wholly owned subsidiary of the publicly traded Black Hills Corporation a registered public utility holding company, (the Parent).
PrinciplesBasis of ConsolidationPresentation
The consolidated financial statements include the accounts of Black Hills Power, Inc. and also the Company’s ownership interests in the assets, liabilities and expenses of its wholly-owned subsidiaries.jointly-owned facilities (see Note 3.). As discussed in Note 11, the Company has distributed the stock held in its subsidiaries in the form of non-cash dividends to the Parent. These distributions represented 100 percent ownership of the subsidiaries. Activity at the subsidiaries was recorded up to the date of distribution and has been reclassified into “Discontinued operations” in the accompanying consolidated financial statements.statements of income.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to allowance for uncollectible accounts receivable, long-lived asset values and useful lives, employee benefits plans and contingencies. Actual results could differ from those estimates.
Regulatory Accounting
The Company’s regulated electric operations are subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of the Federal Energy Regulatory Commission (FERC).
The Company’s electric operations follow the provisions of the Financial Accounting Standards Board (FASB) of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71), and its financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions regulating its electric operations. As a result of the Company’s 1995 rate case settlement, a 50-year depreciable life for Neil Simpson II is used for financial reporting purposes. If the Company were not following SFAS 71, a 35 to 40 year life would be more appropriate, which would increase depreciation expense by approximately $0.6 — $1.1 million per year. If rate recovery of generation-related costs becomes unlikely or uncertain, due to competition or regulatory action, these accounting standards may no longer apply to the Company’s regulated generation operations. In the event the Company determines that it no longer meets the criteria for following SFAS 71, the accounting impact to the Company would be an extraordinary non-cash charge to operations of an amount that could be material. Criteria that give rise to the discontinuance of SFAS 71 include increasing competition that could restrict the Company’s ability to establish prices to recover specific costs and a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. The Company periodically reviews these criteria to ensure the continuing application of SFAS 71 is appropriate.
20
At December 31, 20042005 and 2003,2004, the Company had regulatory assets of $7.2$6.9 million and $4.6$7.2 million and regulatory liabilities of $6.0$5.7 million and $6.3$6.0 million, respectively. Regulatory assets are primarily recorded for the probable future revenue to recover future income taxes related to the deferred tax liability for the equity component of allowance for funds used during construction of utility assets and for unamortized losses on reacquired debt. Regulatory liabilities include the probable future decrease in rate revenues related to a decrease in deferred tax liabilities for prior reductions in statutory federal income tax rates and also the cost of removal for utility plant, recovered through the Company’s electric utility rates.
18
Cash Equivalents
The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Reclassifications
Certain 2004 and 2003 amounts in the consolidated financial statements have been reclassified to conform to the 2005 presentation. These reclassifications had no effect on the Company's stockholders' equity or results of operations, as previously reported. The reclassifications include an adjustment to the 2004 Statement of Cash Flows for the increase in restricted cash of $3.1 million that was previously included in other financing activities when it should have been included in other investing activities.Cash Flow Statement Restatement
Subsequent to the issuance of its financial statements for the year ended December 31, 2003, the Company determined that the cash flows associated with discontinued operations should have been presented within the Statements of Cash Flows. As a result, during 2005, the Company changed the presentation of cash flows from discontinued operations to present separate disclosure of the cash flows from operating, investing and financing activities. In addition, beginning of year cash and cash equivalents in the 2003 Statement of Cash Flows was adjusted to include cash and cash equivalents from discontinued operations. A summary of the effects of these changes on the Statement of Cash Flows for the year ended December 31, 2003, is as follows (in thousands):
2003 | ||
Net cash flows from operating activities as previously reported | $ | 44,225 |
Change in net cash flows from discontinued operations | 8,544 | |
Net cash flows from operating activities as currently reported | $ | 52,769 |
Net cash flows used for investing activities as previously reported | $ | (10,868) |
Change in net cash flows used for discontinued operations | (8,212) | |
Net cash flows used for investing activities as currently reported | $ | (19,080) |
Net cash flows used for financing activities as previously reported | $ | (32,823) |
Subsidiary cash included in stock dividend | (29,034) | |
Change in net cash flows used for discontinued operations | (15,518) | |
Net cash flows used for financing activities as currently reported | $ | (77,375) |
Cash and cash equivalents beginning of year as previously reported | $ | 518 |
Cash and cash equivalents included in assets of discontinued | ||
operations beginning of year | 44,220 | |
Cash and cash equivalents beginning of year as currently reported | $ | 44,738 |
21
Materials, Supplies and Fuel
Materials, supplies and fuel used for construction, operation and maintenance purposes are generally stated at cost on a weighted-average basis. To the extent fuel has been designated as the underlying hedged item in a “fair value” hedge transaction, those volumes are stated at market value using published industry quotations. As of December 31, 2005, market adjustments related to fuel were $(0.2) million.
Deferred Financing Costs
Deferred financing costs are amortized using the effective interest method over the term of the related debt.
Property, Plant and Equipment
Additions to property, plant and equipment are recorded at cost when placed in service. Included in the cost of regulated construction projects is an allowance for funds used during construction (AFUDC) which represents the approximate composite cost of borrowed funds and a return on capital used to finance the project. The AFUDC was computed at an annual composite rate of 9.8 percent during 2004 and 2003, and 9.1 percent during 2002, respectively. The amount of AFUDC was approximately $0.2 million, $0.2 million, and $0.1 million in 2005, 2004 and $0.9 million in 2004, 2003, and 2002, respectively. The cost of regulated electric property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage, is charged to accumulated depreciation. Repairs and maintenance of property are charged to operations as incurred.
Depreciation provisions for regulated electric property, plant and equipment is computed on a straight-line basis using an annual composite rate of 3.1 percent in 2005, 3.0 percent in 2004 and 3.1 percent in 20032003.
Derivatives and 2002.Hedging Activities
The Company, from time to time, utilizes risk management contracts including forward purchases and sales and fixed-for-float swaps to hedge the price of fuel for its combustion turbines, maximize the value of its natural gas storage or to fix the interest on its variable rate debt. Certain of the contracts qualify as derivatives under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133). SFAS 133 requires that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS 133 requires that changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met.
SFAS 133 allows hedge accounting for qualifying fair value and cash flow hedges. SFAS 133 provides that the gain or loss on a derivative instrument designated and qualifying as a fair value hedging instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk be recognized currently in earnings in the same accounting period. SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, is recognized currently in earnings.
22
Impairment of Long-Lived Assets
The Company periodically evaluates whether events and circumstances have occurred which may affect the estimated useful life or the recoverability of the remaining balance of its long-lived assets. If such events or circumstances were to indicate that the carrying amount of these assets was not recoverable, the Company would estimate the future cash flows expected to result from the use of the assets and their eventual disposition. If the sum of the expected future cash flows (undiscounted and without interest charges) was less than the carrying amount of the long-lived assets, the Company would recognize an impairment loss. No impairment loss was recorded during 2005, 2004 2003 or 2002.2003.
Income Taxes
The Company uses the liability method in accounting for income taxes. Under the liability method, deferred income taxes are recognized, at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. The Company classifies deferred tax assets and liabilities into current and non-current amounts based on the classification of the related assets and liabilities.
The Company files a federal income tax return with other affiliates. For financial statement purposes, federal income taxes are allocated to the individual companies based on amounts calculated on a separate return basis.
Revenue Recognition
Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price, delivery has occurred or services have been rendered, and collectibility is reasonably assured.
19
Certain 2003 and 2002 amounts in the financial statements have been reclassified to conform to the 2004 presentation. These reclassifications had no effect on the Company’s common stockholders’ equity or results of operations, as previously reported.
FSP 106-2
In May 2004, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP 106-2), which provides guidance on the accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (2003 Medicare Act) for employers that sponsor postretirement healthcare plans that provide prescription drug benefits. If the Plan is deemed actuarially equivalent to the prescription drug benefit under the 2003 Medicare Act, the sponsor of the Plan could be eligible for a federal subsidy. FSP 106-2 supersedes FSP 106-1 that was issued in January 2004 under the same title. FSP 106-2 is effective for the first interim period beginning after June 15, 2004. The Company provides prescription drug benefits to certain eligible employees. The actuarial measurement of the accumulated postretirement benefit obligation and net periodic postretirement benefit cost does not include the effects of the 2003 Medicare Act as it is believed the Plan is not actuarially equivalent (see Note 8).
23
(2) | PROPERTY, PLANT AND EQUIPMENT |
Property, plant and equipment at December 31, consisted of the following (in thousands):
| Lives | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| 2004 | 2003 | (in years) | |||||||||
| Electric plant: | |||||||||||
| Production | $ | 320,483 | $ | 316,544 | 25-58 | ||||||
| Transmission* | 83,488 | 122,640 | 35-50 | ||||||||
| Distribution* | 198,583 | 150,748 | 20-40 | ||||||||
| General | 31,010 | 30,205 | 7-40 | ||||||||
| Total electric plant | 633,564 | 620,137 | |||||||||
| Less accumulated depreciation and amortization | 232,401 | 212,041 | |||||||||
| Electric plant net of accumulated depreciation and amortization | 401,163 | 408,096 | |||||||||
| Construction work in progress | 4,066 | 3,060 | |||||||||
| Net electric plant | $ | 405,229 | $ | 411,156 | |||||||
_________________
|
| 2005 |
| 2004 |
| ||
|
| Weighted |
| Weighted |
| ||
|
| Average |
| Average |
| ||
|
| Useful |
| Useful | Lives | ||
| 2005 | Life | 2004 | Life | (in years) | ||
|
|
|
|
|
|
|
|
Electric plant: |
|
|
|
|
|
|
|
Production | $ | 317,792 | 45 | $ | 315,613 | 45 | 25-58 |
Transmission* |
| 69,998 | 45 |
| 83,488 | 44 | 35-50 |
Distribution* |
| 222,305 | 32 |
| 198,583 | 32 | 20-40 |
Plant acquisition adjustment |
| 4,870 | — |
| 4,870 | — | — |
General |
| 32,030 | 18 |
| 31,010 | 18 | 7-40 |
Total electric plant |
| 646,995 |
|
| 633,564 |
|
|
Less accumulated depreciation and amortization |
| 250,583 |
|
| 232,401 |
|
|
Electric plant net of accumulated |
|
|
|
|
|
|
|
depreciation and amortization |
| 396,412 |
|
| 401,163 |
|
|
Construction work in progress |
| 6,684 |
|
| 4,066 |
|
|
Net electric plant* | $ | 403,096 |
| $ | 405,229 |
|
|
__________________________
* | As part of the Common Use Transmission Open-Access Transmission Tariff FERC filing that was |
20
(3) | JOINTLY OWNED FACILITIES |
The Company uses the proportionate consolidation method to account for its percentage interest in the assets, liabilities and expenses of the following facilities:
The Company owns a 20 percent interest and PacifiCorp owns an 80 percent interest in the Wyodak Plant (Plant), a 362 megawatt coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp is the operator of the Plant. The Company receives 20 percent of the Plant’s capacity and is committed to pay 20 percent of its additions, replacements and operating and maintenance expenses. As of December 31, 2004,2005, the Company’s investment in the Plant included $73.4$73.8 million in electric plant and $34.5$38.8 million in accumulated depreciation, and is included in the corresponding captions in the accompanying Consolidated Balance Sheets. The Company’s share of direct expenses of the Plant was $6.1 million, $6.0 million $5.8 million and $5.5$5.8 million for the years ended December 31, 2005, 2004 2003 and 2002,2003, respectively, and is included in the corresponding categories of operating expenses in the accompanying Statements of Income.
24
The Company also owns a 35 percent interest and Basin Electric Power Cooperative owns a 65 percent interest in the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie placed into service in the fourth quarter of 2003. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the Western Electricity Coordinating Council (WECC) region and the Mid-Continent Area Power Pool, or “MAPP” region. The total transfer capacity of the tie is 400 megawatts – 200 megawatts West to East and 200 megawatts from East to West. The Company is committed to pay 35 percent of the additions, replacements and operating and maintenance expenses. For the twelve months ended December 31, 2004, theThe Company’s share of direct expenses was $0.2 and $0.1 million.million for years ended December 31, 2005 and 2004, respectively. As of December 31, 2004,2005, the Company’s investment in the transmission tie was $19.7 million.million, with $0.9 million of accumulated depreciation and is included in the corresponding captions in the accompanying Balance Sheets.
(4) | LONG-TERM DEBT |
Long-term debt outstanding at December 31 is as follows:
| 2004 | 2003 | |||||||
|---|---|---|---|---|---|---|---|---|
| (in thousands) | ||||||||
| First mortgage bonds: | ||||||||
| 8.06% due 2010 | $ | 30,000 | $ | 30,000 | ||||
| 9.49% due 2018 | 3,970 | 4,260 | ||||||
| 9.35% due 2021 | 28,305 | 29,970 | ||||||
| 8.30% repaid 2004 | -- | 45,000 | ||||||
| 7.23% due 2032 | 75,000 | 75,000 | ||||||
| 137,275 | 184,230 | |||||||
| Other long-term debt: | ||||||||
| Pollution control revenue bonds at 6.7% due 2010(a) | -- | 12,300 | ||||||
| Pollution control revenue bonds at 4.8% due 2014(b) | 6,450 | -- | ||||||
| Pollution control revenue bonds at 7.5% due 2024 | -- | 12,200 | ||||||
| Pollution control revenue bonds at 5.35% due 2024(b) | 12,200 | -- | ||||||
| Other(c) | 3,281 | 3,312 | ||||||
| 21,931 | 27,812 | |||||||
| Total long-term debt | 159,206 | 212,042 | ||||||
| Less current maturities | (1,991 | ) | (1,986 | ) | ||||
| Net long-term debt | $ | 157,215 | $ | 210,056 | ||||
_________________
| 2005 | 2004 | |||
| (in thousands) | ||||
First mortgage bonds: |
|
|
|
| |
8.06% due 2010 | $ | 30,000 | $ | 30,000 | |
9.49% due 2018 |
| 3,680 |
| 3,970 | |
9.35% due 2021 |
| 26,640 |
| 28,305 | |
7.23% due 2032 |
| 75,000 |
| 75,000 | |
|
| 135,320 |
| 137,275 | |
Other long-term debt: |
|
|
|
| |
Pollution control revenue bonds at 4.8% due 2014(a) |
| 6,450 |
| 6,450 | |
Pollution control revenue bonds at 5.35% due 2024(a) |
| 12,200 |
| 12,200 | |
Other(b) |
| 3,245 |
| 3,281 | |
| 21,895 |
| 21,931 | ||
|
|
|
|
| |
Total long-term debt |
| 157,215 |
| 159,206 | |
Less current maturities |
| (1,996) |
| (1,991) | |
Net long-term debt | $ | 155,219 | $ | 157,215 | |
__________________________
(a) |
|
In the fourth quarter of 2004, the Company called and refinanced $18.7 million of pollution control revenue bonds. |
(b) | At December 31, 2004, the Company had $3.1 million of cash restricted to maintain liquidity for our $2.9 million Series 94A bond issue. |
21
Substantially all of the Company’s property is subject to the lien of the indenture securing its first mortgage bonds. First mortgage bonds of the Company may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures.
Scheduled maturities are approximately $2.0 million a year for the years 20052006 through 2009.2009, and $32.0 million for the year 2010.
25
(5) | FAIR VALUE OF FINANCIAL INSTRUMENTS |
The estimated fair values of the Company’s financial instruments at December 31 are as follows (in thousands):
| 2004 | 2003 | |||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||
Cash and cash equivalents | $ | 344 | $ | 344 | $ | 1,052 | $ | 1,052 | ||||||
| Long-term debt | $ | 159,206 | $ | 190,273 | $ | 212,042 | $ | 238,331 | ||||||
| 2005 | 2004 | ||||||
| Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||
|
|
|
|
|
|
|
|
|
Cash and cash equivalents | $ | 685 | $ | 685 | $ | 344 | $ | 344 |
Long-term debt | $ | 157,215 | $ | 183,491 | $ | 159,206 | $ | 190,273 |
The following methods and assumptions were used to estimate the fair value of each class of the Company’s financial instruments.
Cash and Cash Equivalents and Restricted Cash
The carrying amount approximates fair value due to the short maturity of these instruments.
Long-Term Debt
The fair value of the Company’s long-term debt is estimated based on quoted market rates for debt instruments having similar maturities and similar debt ratings. The Company’s outstanding first mortgage bonds are either currently not callable or are subject to make-whole provisions which would eliminate any economic benefits for the Company to call and refinance the first mortgage bonds.
(6) | INCOME TAXES |
Income tax expense from continuing operations for the years ended December 31 was (in thousands):
| 2004 | 2003 | 2002 | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Current | $ | 5,731 | $ | 3,550 | $ | 10,826 | |||||
| Deferred | 3,781 | 8,072 | 4,241 | ||||||||
| $ | 9,512 | $ | 11,622 | $ | 15,067 | ||||||
22
| 2005 | 2004 | 2003 | |||
|
|
|
|
|
|
|
Current | $ | 8,301 | $ | 5,731 | $ | $3,550 |
Deferred |
| (2,558) |
| 3,781 |
| 8,072 |
| $ | 5,743 | $ | 9,512 | $ | $11,622 |
26
The temporary differences which gave rise to the net deferred tax liability were as follows (in thousands):
| Years ended December 31, | 2004 | 2003 | ||||||
|---|---|---|---|---|---|---|---|---|
Deferred tax assets, current: | ||||||||
| Valuation reserve | $ | 319 | $ | 314 | ||||
| Employee benefits | 2,984 | 2,623 | ||||||
| Other | 157 | 624 | ||||||
| 3,460 | 3,561 | |||||||
| Deferred tax liabilities, current: | ||||||||
| Prepaid expenses | 155 | -- | ||||||
| Employee benefits | 3,307 | 3,800 | ||||||
| 3,462 | 3,800 | |||||||
| Net deferred tax liability, current | $ | 2 | $ | 239 | ||||
| Deferred tax assets, non-current: | ||||||||
| Regulatory asset | $ | 1,025 | $ | 1,156 | ||||
| ITC | 362 | 460 | ||||||
| Items of other comprehensive income | 184 | 193 | ||||||
| Other | 811 | 1,402 | ||||||
| 2,382 | 3,211 | |||||||
| Deferred tax liabilities, non-current: | ||||||||
| Accelerated depreciation and other plant related differences | 66,275 | 63,615 | ||||||
| AFUDC | 2,712 | 2,808 | ||||||
| Regulatory liability | 1,460 | 1,512 | ||||||
| Items of other comprehensive income | 22 | -- | ||||||
| Other | 1,146 | 909 | ||||||
| 71,615 | 68,844 | |||||||
| Net deferred tax liability, non-current | $ | 69,233 | $ | 65,633 | ||||
| Net deferred tax liability | $ | 69,235 | $ | 65,872 | ||||
Years ended December 31, | 2005 |
| 2004 | ||
|
|
|
|
|
|
Deferred tax assets, current: |
|
|
|
|
|
Asset valuation reserve | $ | 291 |
| $ | 319 |
Employee benefits |
| 550 |
|
| 382 |
Items of other comprehensive income |
| 76 |
|
| — |
Other |
| 110 |
|
| 157 |
|
| 1,027 |
|
| 858 |
|
|
|
|
|
|
Deferred tax liabilities, current: |
|
|
|
|
|
Prepaid expenses |
| 192 |
|
| 155 |
|
|
|
|
|
|
Net deferred tax asset, current | $ | 835 |
| $ | 703 |
|
|
|
|
|
|
Deferred tax assets, non-current: |
|
|
|
|
|
Plant related differences | $ | 949 |
| $ | 598 |
Regulatory asset |
| 898 |
|
| 1,025 |
ITC |
| 271 |
|
| 362 |
Employee benefits |
| 2,929 |
|
| 2,602 |
Items of other comprehensive income |
| 217 |
|
| 184 |
Other |
| 204 |
|
| 213 |
|
| 5,468 |
|
| 4,984 |
|
|
|
|
|
|
Deferred tax liabilities, non-current: |
|
|
|
|
|
Accelerated depreciation and other plant related differences |
| 65,459 |
|
| 66,371 |
AFUDC |
| 2,640 |
|
| 2,712 |
Regulatory liability |
| 1,422 |
|
| 1,460 |
Employee benefits |
| 2,880 |
|
| 3,307 |
Items of other comprehensive income |
| — |
|
| 22 |
Other |
| 1,009 |
|
| 1,050 |
|
| 73,410 |
|
| 74,922 |
|
|
|
|
|
|
Net deferred tax liability, non-current | $ | 67,942 |
| $ | 69,938 |
|
|
|
|
|
|
Net deferred tax liability | $ | 67,107 |
| $ | 69,235 |
The following table reconciles the change in the net deferred income tax liability from December 31, 2003,2004, to December 31, 2004,2005, to the deferred income tax expensebenefit (in thousands):
| 2004 | |||||
|---|---|---|---|---|---|
| Increase in deferred income tax liability from the preceding table | $ | 3,363 | |||
| Deferred taxes associated with ITC | (508 | ) | |||
| Deferred taxes associated with other comprehensive loss | (31 | ) | |||
| Deferred taxes associated with 2003 federal income tax return true-up, primarily related to | |||||
| depreciation | 957 | ||||
| Deferred income tax expense for the period | $ | 3,781 | |||
23
2005 | ||
Decrease in deferred income tax liability from the preceding table | $ | (2,128) |
Deferred taxes associated with ITC | (517) | |
Deferred taxes associated with other comprehensive loss | 87 | |
Deferred income tax benefit for the period | $ | (2,558) |
27
The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:
| 2004 | 2003 | 2002 | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Federal statutory rate | 35 | .0% | 35 | .0% | 35 | .0% | |||||
| Amortization of excess deferred and investment tax credits | (1 | .5) | (1 | .3) | (1 | .3) | |||||
| Research and development credit | 0 | .0 | (0 | .1) | 0 | .0 | |||||
| Other | (0 | .4) | (1 | .1) | (0 | .4) | |||||
| 33 | .1% | 32 | .5% | 33 | .3% | ||||||
| 2005 | 2004 | 2003 |
|
|
|
|
Federal statutory rate | 35.0% | 35.0% | 35.0% |
Amortization of excess deferred and investment tax credits | (1.7) | (1.5) | (1.3) |
Deferred tax adjustments primarily related to |
|
|
|
plant-related changes in estimate | (8.2) | — | — |
Research and development credit | — | — | (0.1) |
Other | (0.9) | (0.4) | (1.1) |
| 24.2% | 33.1% | 32.5% |
(7) | OTHER COMPREHENSIVE INCOME (LOSS) |
The following tables display the related tax effects allocated to each component of Other Comprehensive Income (Loss) for the years ended December 31, (in thousands):
| 2004 | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Pre-tax | Net-of-tax | ||||||||||
| Amount | Tax Expense | Amount | |||||||||
| Minimum pension liability adjustment | $ | 25 | $ | (9 | ) | $ | 16 | ||||
| Amortization of cash flow hedges settled and deferred in accumulated | |||||||||||
| other comprehensive loss and reclassified into interest expense | 64 | (22 | ) | 42 | |||||||
| Other comprehensive income | $ | 89 | $ | (31 | ) | $ | 58 | ||||
| 2003 | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Pre-tax | Net-of-tax | ||||||||||
| Amount | Tax Expense | Amount | |||||||||
| Minimum pension liability adjustment | $ | 10,892 | $ | (3,813 | ) | $ | 7,079 | ||||
| Net change in fair value of derivatives designated as cash flow hedges | |||||||||||
| associated with discontinued operations | 672 | (269 | ) | 403 | |||||||
| Amortization of cash flow hedges settled and deferred in accumulated | |||||||||||
| other comprehensive loss and reclassified into interest expense | 64 | (22 | ) | 42 | |||||||
| Other comprehensive income | $ | 11,628 | $ | (4,104 | ) | $ | 7,524 | ||||
| 2002 | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Pre-tax | Net-of-tax | ||||||||||
| Amount | Tax Benefit | Amount | |||||||||
| Net change in fair value of derivatives designated as cash flow hedges, | |||||||||||
| including some of which have been classified into discontinued | |||||||||||
| operations | $ | (9,762 | ) | $ | 3,669 | $ | (6,093 | ) | |||
| Minimum pension liability adjustment | (11,443 | ) | 4,005 | (7,438 | ) | ||||||
| Other comprehensive loss | $ | (21,205 | ) | $ | 7,674 | $ | (13,531 | ) | |||
24
| 2005 | |||||
| Pre-tax |
| Net-of-tax | |||
| Amount | Tax Expense | Amount | |||
|
|
|
|
|
|
|
Minimum pension liability adjustment | $ | (94) | $ | 33 | $ | (61) |
Amortization of cash flow hedges settled and deferred in |
|
|
|
|
|
|
accumulated other comprehensive income (loss) and |
|
|
|
|
|
|
reclassified into interest expense |
| 64 |
| (22) |
| 42 |
Net change in fair value of derivatives designated as |
|
|
|
|
|
|
cash flow hedges |
| (219) |
| 76 |
| (143) |
Other comprehensive loss | $ | (249) | $ | 87 | $ | (162) |
| 2004 | |||||
| Pre-tax |
| Net-of-tax | |||
| Amount | Tax Expense | Amount | |||
|
|
|
|
|
|
|
Minimum pension liability adjustment | $ | 25 | $ | (9) | $ | 16 |
Amortization of cash flow hedges settled and deferred in |
|
|
|
|
|
|
accumulated other comprehensive income (loss) and |
|
|
|
|
|
|
reclassified into interest expense |
| 64 |
| (22) |
| 42 |
Other comprehensive income | $ | 89 | $ | (31) | $ | 58 |
28
| 2003 | |||||
| Pre-tax |
| Net-of-tax | |||
| Amount | Tax Expense | Amount | |||
|
|
|
|
|
|
|
Minimum pension liability adjustment | $ | 10,892 | $ | (3,813) | $ | 7,079 |
Net change in fair value of derivatives designated as |
|
|
|
|
|
|
cash flow hedges associated with discontinued operations |
| 672 |
| (269) |
| 403 |
Amortization of cash flow hedges settled and deferred in |
|
|
|
|
|
|
accumulated other comprehensive income (loss) and |
|
|
|
|
|
|
reclassified into interest expense |
| 64 |
| (22) |
| 42 |
Other comprehensive income | $ | 11,628 | $ | (4,104) | $ | 7,524 |
(8) | EMPLOYEE BENEFIT PLANS |
Defined Benefit Pension Plan
The Company has a noncontributory defined benefit pension plan (Plan) covering the employees of the Company. The benefits are based on years of service and compensation levels during the highest five consecutive years of the last ten years of service. The Company’s funding policy is in accordance with the federal government’s funding requirements. The Plan’s assets are held in trust and consist primarily of equity securities. The Company uses a September 30 measurement date for the Plan.
Obligations and Funded Status
Change in benefit obligation:
| 2004 | 2003 | |||||||
|---|---|---|---|---|---|---|---|---|
| (in thousands) | ||||||||
Projected benefit obligation at beginning of year | $ | 44,803 | $ | 38,141 | ||||
| Service cost | 959 | 714 | ||||||
| Interest cost | 2,621 | 2,500 | ||||||
| Actuarial (gain) loss | (182 | ) | 1,110 | |||||
| Discount rate change | -- | 4,239 | ||||||
| Benefits paid | (2,025 | ) | (1,972 | ) | ||||
| Taxable wage rate and cost of living rate change | -- | 71 | ||||||
| Net increase | 1,373 | 6,662 | ||||||
| Projected benefit obligation at end of year | $ | 46,176 | $ | 44,803 | ||||
| 2005 |
| 2004 | ||||
| (in thousands) | ||||||
|
|
| |||||
Projected benefit obligation at beginning of year | $ | 46,176 |
| $ | 44,803 | ||
Service cost |
| 991 |
|
| 959 | ||
Interest cost |
| 2,700 |
|
| 2,621 | ||
Actuarial (gain) loss |
| 9 |
|
| (182) | ||
Discount rate change |
| 1,630 |
|
| — | ||
Benefits paid |
| (2,122) |
|
| (2,025) | ||
Asset transfer to affiliate |
| (592) |
|
| — | ||
Mortality assumption change |
| 519 |
|
| — | ||
Net increase |
| 3,135 |
|
| 1,373 | ||
Projected benefit obligation at end of year | $ | 49,311 |
| $ | 46,176 | ||
29
A reconciliation of the fair value of Plan assets (as of the September 30 measurement date) is as follows:
| 2004 | 2003 | |||||||
|---|---|---|---|---|---|---|---|---|
| (in thousands) | ||||||||
Beginning market value of plan assets | $ | 37,115 | $ | 25,830 | ||||
| Benefits paid | (2,025 | ) | (1,972 | ) | ||||
| Investment income | 4,754 | 6,406 | ||||||
| Employer contributions | -- | 6,851 | ||||||
| Ending market value of plan assets | $ | 39,844 | $ | 37,115 | ||||
25
| 2005 |
| 2004 | ||
| (in thousands) | ||||
|
|
| |||
Beginning market value of plan assets | $ | 39,844 |
| $ | 37,115 |
Benefits paid |
| (2,122) |
|
| (2,025) |
Investment income |
| 6,729 |
|
| 4,754 |
Asset transfer to affiliate |
| (592) |
|
| — |
Ending market value of plan assets | $ | 43,859 |
| $ | 39,844 |
Funding information for the Plan is as follows:
| 2004 | 2003 | |||||||
|---|---|---|---|---|---|---|---|---|
| (in thousands) | ||||||||
Fair value of plan assets | $ | 39,844 | $ | 37,115 | ||||
| Projected benefit obligation | (46,176 | ) | (44,803 | ) | ||||
| Funded status | (6,332 | ) | (7,688 | ) | ||||
Unrecognized: | ||||||||
| Net loss | 14,860 | 17,457 | ||||||
| Prior service cost | 922 | 1,088 | ||||||
| Net amount recognized | $ | 9,450 | $ | 10,857 | ||||
| 2005 |
| 2004 | ||
| (in thousands) | ||||
|
|
| |||
Fair value of plan assets | $ | 43,859 |
| $ | 39,844 |
Projected benefit obligation |
| (49,311) |
|
| (46,176) |
Funded status |
| (5,452) |
|
| (6,332) |
|
|
|
|
|
|
Unrecognized: |
|
|
|
|
|
Net loss |
| 12,915 |
|
| 14,860 |
Prior service cost |
| 766 |
|
| 922 |
|
| 13,681 |
|
| 15,782 |
|
|
|
|
|
|
Net amount recognized | $ | 8,229 |
| $ | 9,450 |
Amounts recognized in statement of financial position consist of:
| 2004 | 2003 | |||||||
|---|---|---|---|---|---|---|---|---|
| (in thousands) | ||||||||
Net pension asset | $ | 9,450 | $ | 10,857 | ||||
| Accumulated benefit obligation | $ | 38,302 | $ | 36,577 | ||||
| 2005 |
| 2004 | ||
| (in thousands) | ||||
|
| ||||
Net pension asset | $ | 8,229 |
| $ | 9,450 |
|
|
|
|
|
|
Accumulated benefit obligation | $ | 41,191 |
| $ | 38,302 |
The provisions of SFAS No. 87 “Employers’ Accounting for Pensions” (SFAS 87) required the Company to record a net pension asset of $9.5$8.2 million and $10.9$9.5 million at December 31, 20042005 and 2003,2004, respectively and is included in the line item Other in Other assets on the accompanying Balance Sheets.
30
Components of Net Periodic Pension Expense
| 2005 | 2004 | 2003 | |||
| (in thousands) | |||||
|
| |||||
Service cost | $ | 991 | $ | 959 | $ | 714 |
Interest cost |
| 2,700 |
| 2,621 |
| 2,500 |
Expected return on assets |
| (3,480) |
| (3,420) |
| (2,473) |
Amortization of prior service cost |
| 156 |
| 166 |
| 165 |
Recognized net actuarial loss |
| 854 |
| 1,080 |
| 1,105 |
Net pension expense | $ | 1,221 | $ | 1,406 | $ | 2,011 |
Assumptions
| 2004 | 2003 | 2002 | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | |||||||||||
Service cost | $ | 959 | $ | 714 | $ | 588 | |||||
| Interest cost | 2,621 | 2,500 | 2,406 | ||||||||
| Expected return on assets | (3,420 | ) | (2,473 | ) | (3,345 | ) | |||||
| Amortization of prior service cost | 166 | 165 | 184 | ||||||||
| Recognized net actuarial loss | 1,080 | 1,105 | 96 | ||||||||
| Net pension (income) expense | $ | 1,406 | $ | 2,011 | $ | (71 | ) | ||||
Weighted-average assumptions used to determine |
|
|
|
benefit obligations: | 2005 | 2004 | 2003 |
|
|
|
|
Discount rate | 5.75% | 6.00% | 6.00% |
Rate of increase in compensation levels | 4.34% | 4.39% | 5.00% |
|
|
|
|
Weighted-average assumptions used to determine net |
|
|
|
periodic benefit cost for plan year: | 2005 | 2004 | 2003 |
|
|
|
|
Discount rate | 6.00% | 6.00% | 6.75% |
Expected long-term rate of return on assets* | 9.00% | 9.50% | 10.00% |
Rate of increase in compensation levels | 4.39% | 5.00% | 5.00% |
Additional Information__________________________
| 2004 | 2003 | |||||||
|---|---|---|---|---|---|---|---|---|
| (in thousands) | ||||||||
| Pre-tax amount included in other comprehensive | ||||||||
| income (loss) arising from a change in the | ||||||||
| additional minimum pension liability | $ | - | $ | 11,061 | ||||
26
Assumptions
| 2004 | 2003 | |||||||
|---|---|---|---|---|---|---|---|---|
Weighted-average assumptions used to determine | ||||||||
| benefit obligations: | ||||||||
Discount rate | 6 | .00% | 6 | .00% | ||||
| Rate of increase in compensation levels | 4 | .39% | 5 | .00% | ||||
| 2004 | 2003 | 2002 | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
Weighted-average assumptions used to determine net | |||||||||||
| periodic benefit cost for plan year: | |||||||||||
Discount rate | 6 | .00% | 6 | .75% | 7 | .50% | |||||
| Expected long-term rate of return on assets* | 9 | .50% | 10 | .00% | 10 | .50% | |||||
| Rate of increase in compensation levels | 4 | .39% | 5 | .00% | 5 | .00% | |||||
_________________
* | The expected rate of return on plan assets was changed from |
The Plan’s expected long-term rate of return on assets assumption is based upon the weighted average expected long-term rate of returns for each individual asset class. The asset class weighting is determined using the target allocation for each asset class in the Plan portfolio. The expected long-term rate of return for each asset class is determined primarily from long-term historical returns for the asset class, with adjustments if it is anticipated that long-term future returns will not achieve historical results.
The expected long-term rate of return for equity investments was 10.09.5 percent and 10.510.0 percent for the 20042005 and 20032004 plan years, respectively. For determining the expected long-term rate of return for equity assets, the Company reviewed annual 20-, 30-, 40-, and 50-year returns on the S&P 500 Index, which were, at December 31, 2004, 13.22005, 11.8 percent, 13.712.5 percent, 10.410.1 percent and 10.910.3 percent respectively. Fund management fees were estimated to be 0.18 percent for S&P 500 Index assets and 0.45 percent for other assets. The expected long-term rate of return on fixed income investments was 6.0 percent; the return was based upon historical returns on intermediate-term10-year treasury bonds of 6.37.0 percent from 19501962 to 2002.2005, and adjusted for recent declines in interest rates. The expected long-term rate of return on cash investments was estimated to be 4.0 percent; expected cash returns were estimated to be 2.0 percent below long-term returns on intermediate-term treasury bonds.
31
Plan Assets
Percentage of fair value of Plan assets at September 30:
| 2004 | 2003 | |||||||
|---|---|---|---|---|---|---|---|---|
Domestic equity | 59 | .7% | 44 | .8% | ||||
| Foreign equity | 34 | .5 | 26 | .6 | ||||
| Fixed income | 2 | .6 | 3 | .8 | ||||
| Cash | 3 | .2 | 24 | .8(a) | ||||
| Total | 100 | .0% | 100 | .0% | ||||
_________________
| 2005 | 2004 |
|
|
|
Domestic equity | 52.9% | 59.7% |
Foreign equity | 40.6 | 34.5 |
Fixed income | 3.4 | 2.6 |
Cash | 3.1 | 3.2 |
Total | 100.0% | 100.0% |
(a) Allocation includes $6.9 million cash contribution made to the plan on September 30, 2003.
27
The Plan’s investment policy includes a target asset allocation as follows:
Asset Class | Target Allocation | ||||||
US Stocks | 60% (with a variance of no more or less than 10% of target). | ||||||
Foreign Stocks | 30% (with a variance of no more or less than 10% of target). | ||||||
Fixed Income | 5% (with a variance of no more than 10% or no less than 5% of target). | ||||||
Cash | 5% (with a variance of no more than 10% or no less than 5% of target). | ||||||
___________________________
* | The Plan’s investment policy has been modified for 2006 to target an allocation of 50 percent U.S. stock, 25 percent foreign stock and 25 percent fixed income. |
The Plan’s investment policy includes the investment objective that the achieved long-term raterates of return meet or exceed the assumed actuarial rate. The policy strategy seeks to prudently invest in a diversified portfolio of predominately equity-based assets. The policy provides that the Plan will maintain a passive core US Stock portfolio based on the S&P 500 Index. Complementing this core will be investments in US and foreign equities through actively managed mutual funds.
The policy contains certain prohibitions on transactions in separately managed portfolios in which the Plan may invest, including prohibitions on short sales and the use of options or futures contracts. With regards to pooled funds, the policy requires the evaluation of the appropriateness of such funds for managing Plan assets if a fund engages in such transactions. The Plan has historically not invested in funds engaging in such transactions.
Cash Flows
The Company does not anticipate any employer contributions to the Plan in 2005.2006.
32
Estimated Future Benefit Payments
The following benefit payments, which reflect future service, are expected to be paid (in thousands):
| 2005 | $2,165 | ||||
| 2006 | 2,164 | ||||
| 2007 | 2,201 | ||||
| 2008 | 2,278 | ||||
| 2009 | 2,375 | ||||
| 2010-2014 | 13,568 | ||||
28
2006 | $ | 2,163 |
2007 |
| 2,215 |
2008 |
| 2,303 |
2009 |
| 2,406 |
2010 |
| 2,558 |
2011-2015 |
| 14,763 |
Supplemental Nonqualified Defined Benefit Retirement Plans
The Company has various supplemental retirement plans for outside directors and key executives of the Company. The plans are nonqualified defined benefit plans. The Company uses a September 30 measurement date for the Plans.
Obligations and Funded Status
| 2004 | 2003 | |||||||
|---|---|---|---|---|---|---|---|---|
| (in thousands) | ||||||||
Change in benefit obligation: | ||||||||
| Projected benefit obligation at beginning of year | $ | 1,886 | $ | 1,676 | ||||
| Service cost | -- | 6 | ||||||
| Interest cost | 110 | 109 | ||||||
| Actuarial (gains) losses | (8 | ) | 197 | |||||
| Benefits paid | (102 | ) | (102 | ) | ||||
| Net increase | -- | 210 | ||||||
| Projected benefit obligation at end of year | $ | 1,886 | $ | 1,886 | ||||
| Fair value of plan assets at end of year | $ | -- | $ | -- | ||||
| Funded status | (1,886 | ) | (1,886 | ) | ||||
| Unrecognized net loss | 762 | 824 | ||||||
| Unrecognized prior service cost | 3 | 4 | ||||||
| Contributions | 36 | 25 | ||||||
| Net amount recognized | $ | (1,085 | ) | $ | (1,033 | ) | ||
| 2004 | 2003 | |||||||
|---|---|---|---|---|---|---|---|---|
| (in thousands) | ||||||||
Amounts recognized in statement of financial position consist of: | ||||||||
| Net pension liability | $ | (1,650 | ) | $ | (1,613 | ) | ||
| Intangible asset | 3 | 4 | ||||||
| Contributions | 36 | 25 | ||||||
| Accumulated other comprehensive loss | 526 | 551 | ||||||
| Net amount recognized | $ | 1,085 | $ | (1,033 | ) | |||
| Accumulated benefit obligation | $ | 1,650 | $ | 1,615 | ||||
| 2005 |
| 2004 | ||
| (in thousands) | ||||
|
|
|
|
|
|
Change in benefit obligation: |
|
|
|
|
|
Projected benefit obligation at beginning of year | $ | 1,886 |
| $ | 1,886 |
Service cost |
| — |
|
| — |
Interest cost |
| 110 |
|
| 110 |
Actuarial (gains) losses |
| 143 |
|
| (8) |
Benefits paid |
| (117) |
|
| (102) |
Net increase |
| 136 |
|
| — |
Projected benefit obligation at end of year | $ | 2,022 |
| $ | 1,886 |
|
|
|
|
|
|
Fair value of plan assets at end of year | $ | — |
| $ | — |
Funded status |
| (2,022) |
|
| (1,886) |
Unrecognized net loss |
| 858 |
|
| 762 |
Unrecognized prior service cost |
| 3 |
|
| 3 |
Contributions |
| 25 |
|
| 36 |
Net amount recognized | $ | (1,136) |
| $ | (1,085) |
33
| 2005 |
| 2004 | ||
| (in thousands) | ||||
|
|
|
|
|
|
Amounts recognized in statement of financial position consist of: |
|
|
|
|
|
Net pension liability | $ | (1,785) |
| $ | (1,650) |
Intangible asset |
| 3 |
|
| 3 |
Contributions |
| 26 |
|
| 36 |
Accumulated other comprehensive loss |
| 620 |
|
| 526 |
Net amount recognized | $ | (1,136) |
| $ | (1,085) |
|
|
|
|
|
|
Accumulated benefit obligation | $ | 1,785 |
| $ | 1,650 |
The provisions of SFAS 87 required the Company to record an accrued pension liability of $1.7$1.8 million and $1.6$1.7 million at December 31, 2005 and 2004, and 2003,respectively, and is included in Deferred credits and other liabilities, Other on the accompanying Balance Sheets.
Components of Net Periodic Benefit Cost
| 2004 | 2003 | 2002 | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | |||||||||||
Service cost | $ | -- | $ | 6 | $ | 22 | |||||
| Interest cost | 110 | 109 | 116 | ||||||||
| Amortization of prior service cost | 1 | (3 | ) | (2 | ) | ||||||
| Recognized net actuarial loss | 53 | 42 | 42 | ||||||||
| Net periodic benefit cost | $ | 164 | $ | 154 | $ | 178 | |||||
29
| 2005 | 2004 | 2003 | |||
| (in thousands) | |||||
|
|
|
|
|
|
|
Service cost | $ | — | $ | — | $ | 6 |
Interest cost |
| 109 |
| 110 |
| 109 |
Amortization of prior service cost |
| 1 |
| 1 |
| (3) |
Recognized net actuarial loss |
| 48 |
| 53 |
| 42 |
Net periodic benefit cost | $ | 158 | $ | 164 | $ | 154 |
Additional Information
| 2005 |
| 2004 |
| ||||
| (in thousands) |
| ||||||
Pre-tax amount included in other comprehensive |
|
|
|
|
| |||
Income (loss) arising from a change in the |
|
|
|
|
| |||
additional minimum pension liability | $ | 94 |
| $ | 25 | |||
Assumptions
| 2004 | 2003 | |||||||
|---|---|---|---|---|---|---|---|---|
| (in thousands) | ||||||||
| Pre-tax amount included in other comprehensive | ||||||||
| income (loss) arising from a change in the | ||||||||
| additional minimum pension liability | $ | 25 | $ | (169 | ) | |||
Weighted-average assumptions used to determine |
|
|
|
benefit obligations at September 30 | 2005 | 2004 | 2003 |
|
|
|
|
Discount rate | 5.75% | 6.00% | 6.00% |
Rate of increase in compensation levels | 5.00% | 5.00% | 5.00% |
|
|
|
|
Weighted-average assumptions used to determine net |
|
|
|
periodic benefit cost for plan year | 2005 | 2004 | 2003 |
|
|
|
|
Discount rate | 6.00% | 6.00% | 6.75% |
Rate of increase in compensation levels | 5.00% | 5.00% | 5.00% |
34
Assumptions
| 2004 | 2003 | |||||||
|---|---|---|---|---|---|---|---|---|
| Weighted-average assumptions used to determine | ||||||||
| benefit obligations at September 30 | ||||||||
Discount rate | 6 | .00% | 6 | .00% | ||||
| Rate of increase in compensation levels | 5 | .00% | 5 | .00% | ||||
| 2004 | 2003 | 2002 | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Weighted-average assumptions used to determine net | |||||||||||
| periodic benefit cost for plan year | |||||||||||
Discount rate | 6 | .00% | 6 | .75% | 7 | .50% | |||||
| Rate of increase in compensation levels | 5 | .00% | 5 | .00% | 5 | .00% | |||||
Plan Assets
The plan has no assets. The Company funds on a cash basis as benefits are paid.
Estimated Cash Flows
The estimated employer contribution is expected to be $0.1 million in 2005.2006.
The following benefit payments, which reflect expected future service, are expected to be paid (in thousands):
| Fiscal Year Ending | |||||
2005 | $90 | ||||
| 2006 | 90 | ||||
| 2007 | 90 | ||||
| 2008 | 90 | ||||
| 2009 | 90 | ||||
| 2010-2014 | 451 | ||||
Fiscal Year Ending |
|
|
|
|
|
2006 | $ | 103 |
2007 |
| 109 |
2008 |
| 125 |
2009 |
| 112 |
2010 |
| 115 |
2011-2015 |
| 458 |
Non-pension Defined Benefit Postretirement Plan
Employees who are participants in the Company’s Postretirement Healthcare Plan and who retire from the Company on or after attaining age 55 after completing at least five years of service to the Company are entitled to postretirement healthcare benefits. These benefits are subject to premiums, deductibles, co-payment provisions and other limitations. The Company may amend or change the Plan periodically. The Company is not pre-funding its retiree medical plan. The Company uses a September 30 measurement date for the Plan.
These financial statements
35
It has been determined that the Plan’s post-65 retiree prescription drug plans are actuarially equivalent and this Note do not reflectqualify for the effects of the 2003 Medicare ActPart D subsidy.
The effect on the accumulated postretirement benefit plan.obligation for the fiscal year ending December 31, 2005, was an actuarial gain of approximately $1.1 million. The effect on 2006 net periodic postretirement benefit cost will be a decrease of approximately $0.1 million.
30
Obligation and Funded Status
| 2004 | 2003 | |||||||
|---|---|---|---|---|---|---|---|---|
| (in thousands) | ||||||||
| Change in benefit obligation: | ||||||||
| Accumulated postretirement benefit obligation at beginning of year | $ | 8,197 | $ | 6,547 | ||||
| Service cost | 300 | 198 | ||||||
| Interest cost | 485 | 435 | ||||||
| Plan participants' contributions | 339 | 319 | ||||||
| Benefits paid and actual expenses | (516 | ) | (480 | ) | ||||
| Actuarial (gains) losses | (944 | ) | 1,178 | |||||
| Net increase | (336 | ) | 1,650 | |||||
| Accumulated postretirement benefit obligation at end of year | $ | 7,861 | $ | 8,197 | ||||
| Fair value of plan assets at end of year | $ | -- | $ | -- | ||||
| Funded status | (7,861 | ) | (8,197 | ) | ||||
| Unrecognized net loss | 1,842 | 2,930 | ||||||
| Unrecognized prior service cost | (227 | ) | (246 | ) | ||||
| Unrecognized transition obligation | 934 | 1,050 | ||||||
| Contributions | 23 | 42 | ||||||
| Net amount recognized | $ | (5,289 | ) | $ | (4,421 | ) | ||
| 2005 |
| 2004 | |||
| (in thousands) | |||||
Change in benefit obligation: |
|
|
|
|
| |
Accumulated postretirement benefit obligation at beginning of year | $ | 7,861 |
| $ | 8,197 | |
Service cost |
| 292 |
|
| 300 | |
Interest cost |
| 465 |
|
| 485 | |
Plan participants’ contributions |
| 403 |
|
| 339 | |
Benefits paid and actual expenses |
| (469) |
|
| (516) | |
Net transfer out |
| (26) |
|
| — | |
Medicare Part D subsidy |
| (1,126) |
|
| — | |
Actuarial gains |
| (233) |
|
| (944) | |
Net decrease |
| (694) |
|
| (336) | |
Accumulated postretirement benefit obligation at end of year | $ | 7,167 |
| $ | 7,861 | |
|
|
|
|
|
| |
Fair value of plan assets at end of year | $ | — |
| $ | — | |
Funded status |
| (7,167) |
|
| (7,861) | |
Unrecognized net loss |
| 409 |
|
| 1,842 | |
Unrecognized prior service cost |
| (208) |
|
| (227) | |
Unrecognized transition obligation |
| 817 |
|
| 934 | |
Contributions |
| 13 |
|
| 23 | |
Net amount recognized | $ | (6,136) |
| $ | (5,289) | |
Amounts recognized in statement of financial position consist of:
| 2004 | 2003 | |||||||
|---|---|---|---|---|---|---|---|---|
| (in thousands) | ||||||||
Accrued postretirement liability | $ | (5,289 | ) | $ | (4,421 | ) | ||
| 2005 |
| 2004 | ||
| (in thousands) | ||||
|
|
|
|
|
|
Accrued postretirement liability | $ | (6,136) |
| $ | (5,289) |
36
Components of Net Periodic Benefit Cost
| 2005 | 2004 | 2003 | |||
| (in thousands) | |||||
|
|
|
|
|
|
|
Service cost | $ | 292 | $ | 300 | $ | 198 |
Interest cost |
| 465 |
| 486 |
| 435 |
Amortization of transition obligation |
| 117 |
| 116 |
| 117 |
Amortization of prior service cost |
| (19) |
| (19) |
| (19) |
Recognized net actuarial loss |
| 74 |
| 144 |
| 78 |
Net periodic benefit cost | $ | 929 | $ | 1,027 | $ | 809 |
Assumptions
| 2004 | 2003 | 2002 | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| (in thousands) | |||||||||||
Service cost | $ | 300 | $ | 198 | $ | 160 | |||||
| Interest cost | 486 | 435 | 402 | ||||||||
| Amortization of transition obligation | 116 | 117 | 117 | ||||||||
| Amortization of prior service cost | (19 | ) | (19 | ) | (19 | ) | |||||
| Recognized net actuarial loss | 144 | 78 | 34 | ||||||||
| Net periodic benefit cost | $ | 1,027 | $ | 809 | $ | 694 | |||||
31
Weighted-average assumptions used to determine |
|
|
|
benefit obligations at September 30 |
|
|
|
| 2005 | 2004 | 2003 |
|
|
|
|
Discount rate | 5.75% | 6.00% | 6.00% |
|
|
|
|
Weighted-average assumptions used to determine net |
|
|
|
periodic benefit cost for plan year |
|
|
|
| 2005 | 2004 | 2003 |
|
|
|
|
Discount rate | 6.00% | 6.00% | 6.75% |
Assumptions
| 2004 | 2003 | |||||||
|---|---|---|---|---|---|---|---|---|
| Weighted-average assumptions used to determine | ||||||||
| benefit obligations at September 30 | ||||||||
| Discount rate | 6 | .00% | 6 | .00% | ||||
| 2004 | 2003 | 2002 | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Weighted-average assumptions used to determine net | |||||||||||
| periodic benefit cost for plan year | |||||||||||
| Discount rate | 6 | .00% | 6 | .75% | 7 | .50% | |||||
The healthcare trend rate assumption for the 20032005 fiscal year disclosurebenefit obligation determination and 2006 fiscal year expense is 11 percent for 2005 grading down 1 percent per year until a 5 percent ultimate trend rate is reached in fiscal year 2011. The healthcare cost trend rate assumption for the 2004 fiscal year benefit obligation determination and 2005 fiscal year expense and disclosure iswas 12 percent for fiscal 2004 grading down 1 percent per year until a 5 percent ultimate trend rate is reached in fiscal year 2011. The health care cost trend rate assumption for the 2003 fiscal year expense was 11 percent for fiscal 2003 grading down 1 percent per year until a 5 percent ultimate trend rate is reached in fiscal year 2009.
A 1 percent increase in the healthcare cost trend assumption would increase the service and interest cost $0.2 million or 23 percent and the accumulated periodic postretirement benefit obligation $1.5$1.3 million or 1918 percent. A 1 percent decrease would reduce the service and interest cost by $0.1 million or 1718 percent and the accumulated periodic postretirement benefit obligation $1.2$1.0 million or 15 percent.
Plan Assets
The plan has no assets. The Company funds on a cash basis as benefits are paid.
Estimated Cash Flows
The estimated employer contribution is expected to be $0.2 million in 2005.2006.
37
Estimated Future Benefit Payments
The following benefit payments, which reflect expected future service, are expected to be paid (in thousands):
| Fiscal Year Ending | |||||
2005 | $211 | ||||
| 2006 | 236 | ||||
| 2007 | 257 | ||||
| 2008 | 273 | ||||
| 2009 | 315 | ||||
| 2010-2014 | 2,103 | ||||
| Expected | Expected Medicare | Expected | |||
| Gross | Part D | Net | |||
| Benefit | (Prescription Drug | Benefit | |||
Fiscal Year Ending | Payment | Benefit) Subsidy | Payments | |||
|
|
|
|
|
|
|
2006 | $ | 227 | $ | (24) | $ | 203 |
2007 |
| 250 |
| (27) |
| 223 |
2008 |
| 267 |
| (31) |
| 236 |
2009 |
| 303 |
| (34) |
| 269 |
2010 |
| 354 |
| (36) |
| 318 |
2011 - 2015 |
| 2,136 |
| (236) |
| 1,900 |
Defined Contribution Plan
The Company also sponsors a 401(k) savings plan for eligible employees. Participants elect to invest up to 20 percent of their eligible compensation on a pre-tax basis. The Company provides a matching contribution of 100 percent of the employee’s tax-deferred contribution up to a maximum 3 percent of the employee’s eligible compensation. Matching contributions vest at 20 percent per year and are fully vested when the participant has 5 years of service with the Company. The Company’s matching contributions totaled approximately $0.5 million for 2005 and $0.4 million for 2004 and2003, and2002, respectively.
32
(9) | RELATED-PARTY TRANSACTIONS |
(9) RELATED-PARTY TRANSACTIONS
Receivables and Payables
The Company has accounts receivable balances related to transactions with other Black Hills Corporation subsidiaries. The balances were $2.0 million and $0.9 million as of December 31, 20042005 and 2003,2004, respectively. The Company also has accounts payable balances related to transactions with other Black Hills Corporation subsidiaries. The balances were $0.3$1.6 million and $7.9$0.3 million as of December 31, 2005 and 2004, and 2003, respectively.
Notes Payable - Affiliate
The Company also has a line of credit withborrowings from its Parent, Black Hills Corporation (the Parent), which isare due on demand. Outstanding advances were $1.8 million at December 31, 2005 and $25.1 million at December 31, 2004. Advances under this note bear interest at 0.70 percent above the daily LIBOR rate (5.09 percent at December 31, 2005). Interest expense paid on the note was $0.8 million and $0.1 million for the yearyears ended December 31, 2004. This note bears2005 and 2004, respectively.
In August 2005, the Company entered into a Utility Money Pool Agreement with the Parent; and Cheyenne Light, Fuel & Power, an electric and gas utility subsidiary of the Parent.
38
Under the agreement, the Company may borrow from the Parent. The Agreement restricts the Company from loaning funds to the Parent or to any of the Parent’s non-utility subsidiaries; the Agreement does not restrict the Company from making dividends to the Parent. Borrowings under the Agreement bear interest at 1.25 percent above the daily cost of external funds as defined under the Agreement, or if there are no external funds outstanding on that date, then the rate will be the daily one-month average LIBOR rate (3.65 percent at December 31, 2004)plus 100 basis points.
Other Balances and is payable monthly.Transactions
Other Balance and Transactions
The Company purchases coal from Wyodak Resources Development Corp., an indirect subsidiary of the Parent. The amount purchased during the years ended December 31, 2005, 2004 and 2003 and 2002 was $10.1 million, $9.6 million and $10.3 million, and $10.5 million, respectively.
In addition to the above transactions, in order to fuel its combustion turbine, the Company purchased natural gas from Enserco Energy, an indirect subsidiary of the Parent. The amount purchased during the years ended December 31, 2005, 2004 2003 and 20022003 was approximately $6.4 million, $2.7 million $6.1 million and $5.8$6.1 million, respectively. These amounts are included in “Fuel and purchased power” on the Consolidated Statements of Income.
The Company also received revenues of approximately $1.0$2.2 million for the year ended December 31, 2005 and $1.1 million for the years ended December 31, 2004 and 2003, respectively, from Black Hills Wyoming, Inc., an indirect subsidiary of Black Hills Corporation, for the transmission of electricity.
(10) | COMMITMENTS AND CONTINGENCIES |
Power Purchase and Transmission Services Agreement — PacifiCorpAgreements – Pacific Power
In 1983, the Company entered into a 40 year power purchase agreement with PacifiCorp providing for the purchase by the Company of 75 megawatts of electric capacity and energy from PacifiCorp’s system. An amended agreement signed in October 1997 reduces the contract capacity by 25 megawatts (5 megawatts per year starting in 2000). The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants. Costs incurred under this agreement were $10.1 million in 2005, $10.0 million in 2004 and $10.8 million in 2003 and $10.9 million in 2002 (net of a $1.3 million refund for prior years).2003.
In addition, the Company has a firm network transmission agreement for 36 MWsmegawatts of capacity with PacifiCorp that expires on December 31, 2006. Annual costs are approximately $0.9 million per year. The Company uses this agreement to serve the Sheridan, Wyoming electric service territory under theour contract with Montana-Dakota Utilities Company.
The Company also has a firm point-to-point transmission service agreement with PacifiCorp that expires on December 31, 2023. The agreement provides that the following amounts of capacity and energy be transmitted: 32 megawatts in 2001, 27 megawatts in 2002, 22 megawatts in 2003, 17 megawatts in 2004-2006 and 50 megawatts in 2007-2023. Costs incurred under this agreement were $0.4 million in 2005, $0.4 million in 2004 and $0.5 million in 2003 and $0.7 million in 2002.2003.
33
39
Long-Term Power Sales AgreementsThe Company has a ten-year power sales contract with the Municipal Energy Agency of Nebraska (MEAN) for 20 megawatts of contingent capacity from the Neil Simpson Unit #2 plant. The contract commenced in February 2003.The Company has a contract with Montana-Dakota Utilities Company, expiring January 1, 2007, for the sale of up to 55 megawatts of energy and capacity to service the Sheridan, Wyoming electric service territory. The Company also has a contract with the City of Gillette, Wyoming, expiring in 2012, to provide the city’s first 23 megawatts of capacity and energy. Both contracts are integrated into our control area and are treated as firm native load.
• | The Company has a ten-year power sales contract with the Municipal Energy Agency of Nebraska (MEAN) for 20 megawatts of contingent capacity from the Neil Simpson Unit #2 plant. The contract expires in February 2013. |
• | The Company has a contract with Montana-Dakota Utilities Company, expiring January 1, 2007, for the sale of up to 55 megawatts of energy and capacity to service the Sheridan, Wyoming electric service territory. The Company entered into a new power purchase agreement with MDU for the supply of up to 74 megawatts of capacity and energy for Sheridan, Wyoming from 2007 through 2016, which is subject to regulatory approval by the WPSC. The Company also has a contract with the City of Gillette, Wyoming, expiring in 2012, to provide the city’s first 23 megawatts of capacity and energy. The agreement renews automatically and requires a seven-year notice of termination. Both contracts are served by the Company and are integrated into its control area and are treated as part of the Company’s firm native load. |
Legal Proceedings
Forest Fire Claims
In September 2001, a fire occurred in the southwestern Black Hills, now known as the “Hell Canyon Fire.” It is alleged that the fire occurred when a high voltage electrical span maintained by the Company broke, and electrical arcing from the severed line ignited dry grass. The fire burned approximately 10,000 acres of land owned by the Black Hills National Forest, the Oglala Sioux Tribe, and other private landowners. The State of South Dakota initiated litigation against the Company, in the Seventh Judicial Circuit Court, Fall River County, South Dakota, on or about January 31, 2003. The Complaint seeks recovery of damages for alleged fire suppression and rehabilitation costs. A claim for treble damages is asserted with respect to the claim for injury to timber. A substantially similar suit was filed against the Company by the United States Forest Service, on June 30, 2003, in the United States District Court for the District of South Dakota, Western Division. The State subsequently joined its claim in the federal action. The State claims damages in the amount of approximately $0.8 million for fire suppression and rehabilitation costs. The United States Government’s claim for fire suppression and related costs has been submitted at approximately $1.3 million. The Company continues to investigate the cause and origin of the fire, and the damage claims. A trial date has been set for early 2005.late 2006. The Company has denied all claims and will vigorously defend this matter, the timing or outcome of which is uncertain.
On June 29, 2002, a forest fire began near Deadwood, South Dakota, now known as the “Grizzly Gulch Fire.” Before being contained more than eight days later, the fire consumed over 10,000 acres of public and private land, mostly consisting of rugged forested areas. The fire destroyed approximately 7 homes and 15 outbuildings. There were no reported personal injuries. In addition, the fire burned to the edge of the City of Deadwood, forcing the evacuation of the City of Deadwood, and the adjacent City of Lead, South Dakota. These communities are active in the tourist and gaming industries. Individuals were ordered to leave their homes, and businesses were closed for a short period of time. On July 16, 2002, the State of South Dakota announced the results of its investigation of the cause and origin of the fire. The State asserted that the fire was caused by tree encroachment into and contact with a transmission line owned and maintained by the Company.
40
On September 6, 2002, the State of South Dakota commenced litigation against the Company, in the Seventh Judicial Circuit Court, Pennington County, South Dakota. The Complaint seeks recovery of damages for alleged injury to timber, fire suppression and rehabilitation costs. A claim for treble damages was asserted with respect to the claim for injury to timber.
On March 3, 2003, the United States of America filed a similar suit against the Company, in the United States District Court, District of South Dakota, Western Division. The federal government’s Complaint likewise seeks recovery of damages for alleged injury to timber, fire suppression and rehabilitation costs. A similar claim for treble damages is asserted with respect to the claim for injury to timber. In April 2003, the State of South Dakota intervened in the federal action. Accordingly, the state court litigation has been stayed, and all governmental claims will be tried in U.S. District Court.
The state and federal government claim approximately $5.3 million for suppression costs, $1.2 million for rehabilitation costs, and $0.6 million for timber loss. Additional claims could be asserted for alleged loss of habitat and aesthetics or for assistance to private landowners.
34
The Company is completingcompleted its own investigation of the fire cause and origin. The Company’s investigation is continuing, butorigin and based upon information currently available, the Company filed its Answer to the Complaints of both the State and the United States government, denying all claims, and asserting that the fire was caused by an independent intervening cause, or an act of God. A trial date has been set for August 2006. The Company expects to vigorously defend all claims brought by governmental or private parties.
During the period of April 2003 through September 2004,June 2005, various private civil actions were filed against the Company, asserting that the Grizzly Gulch Fire caused damage to the parties’ real property. These actions were filed in the Fourth Judicial Circuit Court, Lawrence County, South Dakota. The Complaints seek recovery on the same theories asserted in the governmental Complaints, but most of the Complaints specify no amount for damage claims. The Company will vigorously defend these matters as well.
Additional claims could be made for individual and business losses relating to injury to personal and real property, and lost income.income, all arising from the Grizzly Gulch Fire. A trial date has been set for August 2006.
Although we cannot predict the outcome or the viability of potential claims with respect to either fire, based on the information available, management believes that any such claims, if determined adversely to the Company, will not have a material adverse effect on the Company’s financial condition or results of operations.
PPM Energy, Inc. Demand for Arbitration
On January 2, 2004, PPM Energy, Inc. delivered a Demand for Arbitration to the Company. The demand alleges claims for breach of contract and requests a declaration of the parties’ rights and responsibilities under an Exchange Agreement executed on or about April 3, 2001. Specifically, PPM Energy asserts that the Exchange Agreement obligates the Company to accept receipt and cause corresponding delivery of electric energy, and to grant access to transmission rights allegedly covered by the Agreement. PPM Energy requests an award of damages in an amount not less than $20.0 million. The Company filed its Response to Demand, including a counterclaim that seeks recovery of sums PPM has refused to pay pursuant to the Exchange Agreement. The Company denies all claims and will vigorously defend this matter,claims. The dispute was presented to the timing andarbitrator in August 2005. The Company cannot predict the outcome of which is uncertain.the decision.
41
Ongoing Litigation
The Company is subject to various other legal proceedings, claims and litigation which arise in the ordinary course of operations. In the opinion of management, the amount of liability, if any, with respect to these actions would not materially affect the financial position or results of operations of the Company.
(11) | DIVIDEND OF SUBSIDIARY STOCK AND DISCONTINUED OPERATIONS |
During the quarter ended March 31, 2003, the Company distributed a non-cash dividend of subsidiary stock to its parent company, Black Hills Corporation (Parent). The dividend consisted of 10,000 common shares of Black Hills Generation, Inc., formerly known as Black Hills Energy Capital, Inc., (Generation), which represents 100 percent ownership of Generation. The Company therefore no longer operates in the independent power production business. As a result, the Company no longer has any subsidiaries and operates only in the electric utility business. The Company’s investment in Generation at the time of the distribution was $46.5 million.million, including approximately $29.0 million of cash held at Generation.
The disposition was accounted for under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS 144). Accordingly, results of operations have been classified as “Discontinued operations, net of income taxes” in the accompanying Statements of Income, and prior periods have been restated. For business segment reporting purposes, Generation’s business results were previously included in the segment “Independent Power Production.”
35
Revenues and net income from the discontinued operations arewere as follows:follows (in thousands):
| 2003 | 2002 | |||||||
|---|---|---|---|---|---|---|---|---|
| (in thousands) | ||||||||
Revenue | $ | 41,485 | $ | 125,267 | ||||
| Income (loss) before income taxes and change | ||||||||
| in accounting principle | $ | 2,833 | $ | 16,674 | ||||
| Income tax (expense) benefit | (927 | ) | (6,608 | ) | ||||
| Change in accounting principle, net of tax | -- | 896 | ||||||
| Net income (loss) from discontinued operations | $ | 1,906 | $ | 10,962 | ||||
2003 | ||
Revenue | $ | 41,485 |
Income before income taxes and change in | ||
accounting principle | $ | 2,833 |
Income tax expense | (927) | |
Net income from discontinued operations | $ | 1,906 |
The financial statements and notes to financial statements have been restated to reflect our continuing operations for all periods presented. The net operating results of discontinued operations are included in the Statements of Income under the caption “Discontinued operations, net of income taxes.”
The Company has entered into an agreement with Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., to provide wholesale power for the City of Sheridan, Wyoming. Under the agreement, the Company will provide all requirements up to 74 megawatts of power to Montana-Dakota from January 1, 2007 through January 1, 2017. Power requirements above 74 megawatts are negotiable under terms specified in the agreement. The contract is pending approval by the Wyoming Public Service Commission. An existing contract provides up to 55 megawatts and expires January 1, 2007.
42
(12) | QUARTERLY HISTORICAL DATA (Unaudited) |
The Company operates on a calendar year basis. The following table sets forth selected unaudited historical operating results data for each quarter of 20042005 and 2003.2004.
| First | Second | Third | Fourth | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Quarter | Quarter | Quarter | Quarter | |||||||||||
| (in thousands) | ||||||||||||||
2004: | ||||||||||||||
| Operating revenues | $ | 41,647 | $ | 39,809 | $ | 47,921 | $ | 44,368 | ||||||
| Operating income | 11,408 | 6,560 | 12,506 | 13,335 | ||||||||||
| Income from continuing operations and | ||||||||||||||
| net income | 5,037 | 1,816 | 5,860 | 6,496 | ||||||||||
2003: | ||||||||||||||
| Operating revenues | $ | 43,762 | $ | 39,207 | $ | 46,268 | $ | 41,782 | ||||||
| Operating income | 13,652 | 10,597 | 14,495 | 12,355 | ||||||||||
| Income from continuing operations | 6,699 | 4,722 | 6,772 | 5,896 | ||||||||||
| Net income | 8,605 | 4,722 | 6,772 | 5,896 | ||||||||||
| First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||
|
| |||||||
| (in thousands) | |||||||
2005: |
|
|
|
|
|
|
|
|
Operating revenues | $ | 43,147 | $ | 42,261 | $ | 49,274 | $ | 54,323 |
Operating income |
| 9,495 |
| 8,120 |
| 5,463 |
| 12,966 |
Income from continuing operations and |
|
|
|
|
|
|
|
|
net income |
| 4,322 |
| 3,409 |
| 1,888 |
| 8,386 |
|
|
|
|
|
|
|
|
|
2004: |
|
|
|
|
|
|
|
|
Operating revenues | $ | 41,647 | $ | 39,809 | $ | 47,921 | $ | 44,368 |
Operating income |
| 11,408 |
| 6,560 |
| 12,506 |
| 13,335 |
Income from continuing operations and |
|
|
|
|
|
|
|
|
net income |
| 5,037 |
| 1,816 |
| 5,860 |
| 6,496 |
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
36
ITEM 9A. | CONTROLS AND PROCEDURES |
Evaluation of disclosure controls and procedures
Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of December 31, 2004.2005. Based on their evaluation, they have concluded that our disclosure controls and procedures are adequate and effective including consideration of the Statement of Cash Flow restatement disclosed in Note 1, to ensure that material information relating to us that is required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the required time periods.
Internal control over financial reporting
During our fourth fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
ITEM 9B. | OTHER INFORMATION |
None.
43
PART IV
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholder of
To the Stockholder of |
Black Hills Power, Inc.
Rapid City, South Dakota
We have audited the consolidated financial statements of Black Hills Power, Inc. and subsidiaries (the Company) as of December 31, 20042005 and 2003,2004, and for each of the three years in the period ended December 31, 2004,2005, and have issued our report thereon dated March 10, 2005;16, 2006 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to restatement of the statement of cash flows for the year ended December 31, 2003 as discussed in Note 1); such financial statements and report are included in the 2004your 2005 Annual Report on Form 10-K and are incorporated herein by reference.included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of the Company listed in Item 15(a)(2). This15. The financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
Minneapolis, Minnesota |
March 10, 200516, 2006
37
44
ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
(a) 1.
(a) | 1. | Financial Statements
| ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2. |
BLACK HILLS POWER, INC. SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31, 2005, 2004
45
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT. The Registrant is not required to send an Annual Report or Proxy to its sole security holder and parent company, Black Hills Corporation.
46 SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
47 INDEX TO EXHIBITS
__________________________
| |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||