| · |
• | Transmission constraints; |
| · |
• | Renewable resource supply requirements; |
| · |
• | Resistance to the siting of utility infrastructure or to the granting of right-of-ways; |
| · |
• | 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. 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 adversely affect our financial condition or results of operations.
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 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.
Governmental authorities may assess penalties on us if it is determined that we have not complied with environmental laws and regulations.
If we fail to comply with environmental laws and regulations, even if caused by factors beyond our control, that failure may result in the assessment of civil or criminal penalties and fines against us. Recent lawsuits by the EPA and various states filed against others within industries in which we operate highlight the environmental risks faced by generating facilities, in general, and coal-fired generating facilities in particular.
Increased risks of regulatory penalties could negatively impact our business.
The Energy Policy Act of 2005 increased FERC's civil penalty authority for violation of FERC statutes, rules and orders. FERC can now impose penalties of $1.0 million per violation, per day. Many rules that were historically subject to voluntary compliance are now mandatory and subject to potential civil penalties for violations. If a serious violation did occur, and penalties were imposed by FERC, it could have a material adverse effect on our operations or our financial results.
Increasing costs associated with our defined benefit retirement plans may adversely affect our results of operations, financial position or liquidity.
We have a defined benefit pension plansplan that covercovers a substantial portion of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on actual return on plan assets, changes in interest rates and any changes in governmental regulations. In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans beginning in 2008.
An effective system of internal control may not be maintained, leading to material weaknesses in internal control over financial reporting.
Section 404 of the Sarbanes-Oxley Act of 2002 requires management to make an assessment of the design and operating effectiveness of internal controls. During their assessment of these controls, management or our independent auditors may identify areas of weakness in control design or effectiveness, which may lead to the conclusion that a material weakness in internal control exists.
Increasing costs associated with our health care plans may adversely affect our results of operations, financial position or liquidity.
The costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with our health care plans may adversely affect our results of operations, financial position or liquidity.
An effective system of internal control may not be maintained, leading to material weaknesses in internal control over financial reporting.
Section 404In March 2010, the President of the Sarbanes-OxleyUnited States signed PPACA as amended by the Health Care and Education Reconciliation Act of 2002 requires management to make an assessment2010 (collectively the “2010 Acts”). The 2010 Acts will have a substantial impact on health care providers, insurers, employers and individuals. The 2010 Acts will impact employers and businesses differently depending on the size of the designorganization and effectivenessthe specific impacts on a company’s employees. Certain provisions of internal controls. During their assessmentthe 2010 Acts became effective during our open enrollment period (November 1, 2010) while other provisions of the 2010 Acts will be effective in future years. Although the constitutional validity of the 2010 Acts is the subject of numerous lawsuits now pending in the federal courts, the outcome of which is uncertain, the 2010 Acts could require, among other things, changes to our current employee benefit plans and in our administrative and accounting processes. The ultimate extent and cost of these controls, management or our independent auditors may identify areaschanges cannot be determined at this time and are being evaluated and updated as related regulations and interpretations of weakness in control design or effectiveness, which may lead to the conclusion that a material weakness in internal control exists.2010 Acts become available, and as the results of pending litigation become final.
ITEM 1B. | ITEM 1B. UNRESOLVED STAFF COMMENTS |
None.
ITEM 3. | ITEM 3. LEGAL PROCEEDINGS |
Information regarding our legal proceedings is incorporated herein by reference to the "Legal Proceedings" sub caption within Item 8, Note 12,13, "Commitments and Contingencies," of our Notes to Financial Statements in this Annual Report on Form 10-K.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
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. | ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS |
| 2009 | | | 2008 | | | 2007 | |
| (in thousands) | |
| | | | | | | | |
Revenue | $ | 207,079 | | | $ | 232,674 | | | $ | 199,701 | |
Fuel and purchased power | | 91,349 | | | | 113,672 | | | | 79,425 | |
Gross margin | | 115,730 | | | | 119,002 | | | | 120,276 | |
| | | | | | | | | | | |
Operating expenses | | 80,925 | | | | 80,366 | | | | 72,762 | |
Operating income | | 34,805 | | | | 38,636 | | | | 47,514 | |
| | | | | | | | | | | |
Interest expense, net | | (11,164 | ) | | | (10,111 | ) | | | (10,903 | ) |
Other income | | 7,802 | | | | 3,785 | | | | 853 | |
Income tax expense | | (8,304 | ) | | | (9,551 | ) | | | (12,568 | ) |
Net income | $ | 23,139 | | | $ | 22,759 | | | $ | 24,896 | |
| | | | | | | | | |
For the years ended December 31, | 2010 | 2009 | 2008 |
| (in thousands) |
| | | |
Revenue | $ | 229,763 | | $ | 207,079 | | $ | 232,674 | |
Fuel and purchased power | 87,757 | | 91,349 | | 113,672 | |
Gross margin | 142,006 | | 115,730 | | 119,002 | |
| | | |
Operating expenses | 92,976 | | 80,925 | | 80,366 | |
Gain on sale of operating assets | (6,238 | ) | — | | — | |
Operating income | 55,268 | | 34,805 | | 38,636 | |
| | | |
Interest expense, net | (16,513 | ) | (11,164 | ) | (10,111 | ) |
Other income | 3,254 | | 7,802 | | 3,785 | |
Income tax expense | (10,741 | ) | (8,304 | ) | (9,551 | ) |
Net income | $ | 31,268 | | $ | 23,139 | | $ | 22,759 | |
The following tables provide certain electric utility operating statistics:statistics for the years ended December 31 (dollars in thousands):
Electric Revenue (in thousands) | |
| | | | | | | | | | | | | | |
Customer Base | 2009 | | | Percentage Change | | | 2008 | | | Percentage Change | | | 2007 | |
| | | | | | | | | | | | | | |
Commercial | $ | 59,897 | | | | 3 | % | | $ | 58,289 | | | | 4 | % | | $ | 55,991 | |
Residential | | 48,586 | | | | 4 | | | | 46,854 | | | | 3 | | | | 45,657 | |
Industrial | | 20,014 | | | | (7 | ) | | | 21,432 | | | | (2 | ) | | | 21,974 | |
Municipal | | 2,735 | | | | - | | | | 2,734 | | | | 1 | | | | 2,697 | |
Total retail sales | | 131,232 | | | | 1 | | | | 129,309 | | | | 2 | | | | 126,319 | |
Contract wholesale | | 25,358 | | | | (5 | ) | | | 26,643 | | | | 6 | | | | 25,240 | |
Wholesale off-system | | 32,212 | | | | (49 | ) | | | 63,770 | | | | 81 | | | | 35,210 | |
Total electric sales | | 188,802 | | | | (14 | ) | | | 219,722 | | | | 18 | | | | 186,769 | |
Other revenue | | 18,277 | | | | 41 | | | | 12,952 | | | | - | | | | 12,932 | |
Total revenue | $ | 207,079 | | | | (11 | )% | | $ | 232,674 | | | | 17 | % | | $ | 199,701 | |
| | | | | | | | | | | | | |
Electric Revenue |
| | | | | |
Customer Base | 2010 | Percentage Change | 2009 | Percentage Change | 2008 |
Residential | $ | 53,549 | | 10 | % | $ | 48,586 | | 4 | % | $ | 46,854 | |
Commercial | 65,997 | | 10 | | 59,897 | | 3 | | 58,289 | |
Industrial | 22,621 | | 13 | | 20,014 | | (7 | ) | 21,432 | |
Municipal | 3,029 | | 11 | | 2,735 | | - | 2,734 | |
Total retail sales | 145,196 | | 11 | | 131,232 | | 1 | | 129,309 | |
Contract wholesale | 22,996 | | (9 | ) | 25,358 | | (5 | ) | 26,643 | |
Wholesale off-system | 36,354 | | 13 | | 32,212 | | (49 | ) | 63,770 | |
Total electric sales | 204,546 | | 8 | | 188,802 | | (14 | ) | 219,722 | |
Other revenue | 25,217 | | 38 | | 18,277 | | 41 | | 12,952 | |
Total revenue | $ | 229,763 | | 11 | % | $ | 207,079 | | (11 | )% | $ | 232,674 | |
Megawatt-Hours Sold | |
| | | | | | | | | | | | | | |
Customer Base | 2009 | | | Percentage Change | | | 2008 | | | Percentage Change | | | 2007 | |
| | | | | | | | | | | | | | |
Commercial | | 723,360 | | | | 3 | % | | | 699,734 | | | | 1 | % | | | 690,702 | |
Residential | | 529,825 | | | | 1 | | | | 524,413 | | | | 1 | | | | 518,148 | |
Industrial | | 353,041 | | | | (15 | ) | | | 414,421 | | | | (5 | ) | | | 434,627 | |
Municipal | | 33,948 | | | | (1 | ) | | | 34,368 | | | | (1 | ) | | | 34,661 | |
Total retail sales | | 1,640,174 | | | | (2 | ) | | | 1,672,936 | | | | - | | | | 1,678,138 | |
Contract wholesale | | 645,297 | | | | (3 | ) | | | 665,795 | | | | 2 | | | | 652,931 | |
Wholesale off-system | | 1,009,574 | | | | (6 | ) | | | 1,074,398 | | | | 58 | | | | 678,581 | |
Total electric sales | | 3,295,045 | | | | (3 | ) | | | 3,413,129 | | | | 13 | | | | 3,009,650 | |
Losses and company use | | 159,207 | | | | 90 | | | | 83,598 | | | | (29 | ) | | | 118,253 | |
Total energy | | 3,454,252 | | | | (1 | )% | | | 3,496,727 | | | | 12 | % | | | 3,127,903 | |
| | | | | | | | | | |
Megawatt-Hours Sold |
| | | | | |
Customer Base | 2010 | Percentage Change | 2009 | Percentage Change | 2008 |
Residential | 547,193 | | 3 | % | 529,825 | | 1 | % | 524,413 | |
Commercial | 720,119 | | (0 | ) | 723,360 | | 3 | | 699,734 | |
Industrial | 382,562 | | 8 | | 353,041 | | (15 | ) | 414,421 | |
Municipal | 33,908 | | (0 | ) | 33,948 | | (1 | ) | 34,368 | |
Total retail sales | 1,683,782 | | 3 | | 1,640,174 | | (2 | ) | 1,672,936 | |
Contract wholesale | 468,782 | | (27 | ) | 645,297 | | (3 | ) | 665,795 | |
Wholesale off-system | 1,163,058 | | 15 | | 1,009,574 | | (6 | ) | 1,074,398 | |
Total electric sales | 3,315,622 | | 1 | | 3,295,045 | | (3 | ) | 3,413,129 | |
Losses and company use | 131,263 | | (18 | ) | 159,207 | | 90 | | 83,598 | |
Total energy | 3,446,885 | | (0 | )% | 3,454,252 | | (1 | )% | 3,496,727 | |
We established a new summer peak load of 430 MW in July 2007 and a new winter peak load of 407 MW in December 2008. We own 434491 MW of electric utility generating capacity and purchase an additional 50 MW under a long-term agreement expiring in 2023.
| 2009 | 2008 | 2007 |
Regulated power plant fleet availability: | | | |
Coal-fired plants | 90.3% | 93.5% | 95.4% |
Other plants | 97.7% | 89.2% | 99.4% |
Total availability | 93.5% | 91.6% | 97.2% |
| | | | | | |
| 2010 | 2009 | 2008 |
Regulated power plant fleet availability: | | | |
Coal-fired plants | 93.5 | % | 90.3 | % | 93.5 | % |
Other plants | 95.7 | % | 97.7 | % | 89.2 | % |
Total availability | 94.4 | % | 93.5 | % | 91.6 | % |
| | | | | | | | | | |
Resources | 2010 | Percentage Change | 2009 | Percentage Change | 2008 |
| | | | | |
MWh generated: | | | | | |
Coal | 1,987,037 | | 15 | % | 1,721,074 | | (1 | )% | 1,731,838 | |
Gas | 19,269 | | (59 | ) | 46,723 | | (24 | ) | 61,801 | |
| 2,006,306 | | 13 | | 1,767,797 | | (1 | ) | 1,793,639 | |
| | | | | |
MWh purchased | 1,440,579 | | (15 | ) | 1,686,455 | | (1 | ) | 1,703,088 | |
Total resources | 3,446,885 | | (0 | )% | 3,454,252 | | (1 | )% | 3,496,727 | |
| | | | | | |
| 2010 | 2009 | 2008 |
Heating and cooling degree days: | | | |
Actual | | | |
Heating degree days | 7,272 | | 7,753 | | 7,676 | |
Cooling degree days | 532 | | 354 | | 482 | |
| | | |
Variance from 30-year average: | | | |
Heating degree days | 1 | % | 8 | % | 6 | % |
Cooling degree days | (11 | )% | (41 | )% | (19 | )% |
A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30 year average.
A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30 year average.
Net income was $31.3 million in 2010 compared to $23.1 million in 2009 as a result of:
Resources | 2009 | | | Percentage Change | | | 2008 | | | Percentage Change | | | 2007 | |
| | | | | | | | | | | | | | |
MWh generated: | | | | | | | | | | | | | | |
Coal | | 1,721,074 | | | | (1 | )% | | | 1,731,838 | | | | (2 | )% | | | 1,758,280 | |
Gas | | 46,723 | | | | (24 | ) | | | 61,801 | | | | (32 | ) | | | 90,618 | |
| | 1,767,797 | | | | (1 | ) | | | 1,793,639 | | | | (3 | ) | | | 1,848,898 | |
| | | | | | | | | | | | | | | | | | | |
MWh purchased | | 1,686,455 | | | | (1 | ) | | | 1,703,088 | | | | 33 | | | | 1,279,005 | |
Total resources | | 3,454,252 | | | | (1 | )% | | | 3,496,727 | | | | 12 | % | | | 3,127,903 | |
Gross margin: Gross margin increased $26.3 million primarily due to an $18.5 million increase related to the impact of the outcome of our rate cases, an increase of $3.0 million in off-system sales margin resulting from a change in methodology used to allocate the lowest cost resource, and increased intercompany revenues of $2.4 million due to a new shared services agreement related to resources utilized by affiliated entities.
| 2009 | 2008 | 2007 |
| | | |
Heating and cooling degree days: | | | |
Actual | | | |
Heating degree days | 7,753 | 7,676 | 6,627 |
Cooling degree days | 354 | 482 | 1,033 |
| | | |
Variance from 30-year average: | | | |
Heating degree days | 8% | 6% | (7)% |
Cooling degree days | (41)% | (19)% | 74% |
Operations and maintenance: Operations and maintenance expenses increased $12.1 million primarily due to additional costs of $6.8 million associated with Wygen III which commenced commercial operation on April 1, 2010, and costs of $2.0 million associated with a major overhaul at the Ben French plant.
Gain on sale of operating assets: A $6.2 million gain on sale was recognized on the sale of a 23% ownership interest in the Wygen III generating facility to the City of Gillette.
Interest expense, net: Interest expense, net increased $5.3 million primarily due to higher net interest expense of $2.9 million compared to the same period in the prior year resulting from higher rates on long-term debt compared to rates on short-term debt and a decrease of $2.1 million in AFUDC-borrowed.
Other income: Other income decreased $4.5 million primarily due to a decrease of $3.1 million in AFUDC-equity associated with the construction of our Wygen III facility. Additionally, 2009 included a gain of $1.1 million from the sale of SO2 emission credits and a gain of $0.5 million on the sale of a 25% ownership interest in the Wygen III facility.
Income tax expense: The effective tax rate for 2010 was comparable to the same period in the prior year.
2009 Compared to 2008
Net income increased $0.4was $23.1 million or 2% in 2009 compared to $22.8 million in 2008 as a result of:
Gross margin: Gross margin decreased $3.3 million primarily due to:
| · | $6.5 million increase in other margins primarily due to an increase in transmission rates effective January 1, 2009; |
| · | Increased other income primarily due to a $7.6 million decrease in wholesale off-system margins as a result of a 46% decrease in energy prices, a 6% decrease in total MWh sold in the power markets, a $2.2 million increase of AFUDC-equity, attributable to the ongoing construction of Wygen III; and |
| · | Income tax expense decreased $1.2 million primarily due to a decrease in pre-tax net income and the favorable tax impact as a result of the increase in AFUDC-equity. |
Partially offsetting the increases to earnings was the following:
| · | Margins from wholesale off-system sales decreased $7.6 million due to a 46% decrease in energy prices and a 6% decrease in total MWh sold in the power markets; |
| · | Increase in net interest expense of $1.1 million primarily due to a new debt issuance; and |
| · | A $1.0 million decrease in retail and wholesale margins primarily due to increased coal costs and a 2% decrease in MWh sold related to lower cooling degree days. |
2008 Compared to 2007
Net income decreased $2.1 million or 9% primarily due to:to increased coal costs and a 2% decrease in MWh sold related to lower cooling degree days, partially offset by a $6.5 million increase in other margins primarily due to an increase in transmission rates effective January 1, 2009.
| · | A $2.6 million reduction in retail and wholesale sales margins due to increased fuel and purchased power costs, primarily due to increased coal costs and scheduled and unscheduled outages at Ben French, Osage and Neil Simpson I coal-fired plants. The duration of the Ben French outage was three months as we accelerated the completion of maintenance projects that were originally scheduled for this plant in 2009; |
| · | Increased operating expenses due to increased repairs and maintenance expenses and labor overhead costs; and |
| · | Increased administrative and general expenses of $1.9 million due to an increase in the workers' compensation reserve. |
Partially offsetting the decreases to earnings was the following:
| · | Margins from wholesale off-system sales increased $1.3 million. Total MWh increased 58% as we were able to take advantage of favorable market conditions and high MIDC pricing due to below normal temperatures; and |
| · | Income related to a $5.3 million increase of AFUDC, primarily attributable to the ongoing construction of Wygen III. |
Operating expenses: Operating expenses were comparable to the same period in prior year.
Interest expense, net: Interest expense, net increased $1.1 million primarily due to a new debt issuance.
Other income: Other income increased $4.0 million primarily due to an increase of $2.2 million in AFUDC-equity attributable to the ongoing construction of Wygen III, the sale of SO2 emission credits for $1.1 million and a gain of $0.5 million on the sale of a 25% ownership interest in Wygen III facility which was under construction.
Income tax expense: The effective tax rate decreased primarily due to the favorable tax impact as a result of the increase in AFUDC-equity.
Rate Increase Requests. On October 19, 2009, we filed a rate case with the WPSC requesting an electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred since 1995. We are seeking a $3.8 million, or approximately 38.95%, increase in annual utility revenues and anticipate that the new rates will be effective for our Wyoming customers on or around July 1, 2010, although recovery could be delayed until August 2010 as part of the regulatory process. The proposed rate increase is subject to approval by the WPSC and we cannot predict the outcome of this rate filing request.Settlement
South Dakota
On September 30, 2009, we filed a rate case with the SDPUC requesting an electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred during the past four years. We are seekingIn March 2010, the SDPUC approved a $32.0$24.1 million or approximately 26.6%, increase in annual utility revenues. The final order frominterim rates, subject to refund, effective April 1, 2010 for South Dakota customers. On July 7, 2010, the SDPUC is not expected byapproved a final revenue increase of $15.2 million and a base rate increase of $22.0 million with an effective date of April 1, 2010. The approved capital structure and return on equity are confidential. A refund of $2.6 million was provided to customers in the third quarter of 2010.
As part of the settlement stipulation, we agreed (1) to credit customers 65% of power marketing operating income with a minimum of $2.0 million per year; (2) that rates will include a South Dakota Surplus Energy Credit of $2.5 million in year one (fiscal year ending March 2011), $2.25 million in fiscal year two, $2.0 million in fiscal year three and zero thereafter; and (3) a moratorium until April 2013 for any base rate increase excluding any extraordinary events as defined in the stipulation agreement; while (4) the SDPUC agreed to adjust the power marketing sales portion of the Fuel and Purchased Power Adjustment clause to directly assign renewable resources and firm purchases to the customer load.
Wyoming
On March 1,October 19, 2009, we filed a rate case with the WPSC requesting a $3.8 million electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred since 1995. On May 4, 2010, we filed a petitionsettlement stipulation agreement with the SDPUC requesting an interim rateWPSC for a $3.1 million increase in annual revenues. On May 13, 2010, WPSC approved these new rates based on a return on equity of $24.0 million, or 20%, for South Dakota utility customers. The SDPUC approved the request for interim rates10.5% with a capital structure of 52% equity and 48% debt. Rates went into effect on March 9, 2010 effective AprilJune 1, 2010. The proposed rate increase is subject to approval by the SDPUC and we cannot predict the outcome of this rate filing request.
Rate Increase Settlement.On February 10, 2009, FERC approved a formulaic approach to the method used to determine the revenue component of our open access transmission tariff, and increased our annual transmission revenue requirement by approximately $3.8 million. The revenue requirement is based on an equity return of 10.8%, and a capital structure consisting of 57% equity and 43% debt. The new annual rates had an effective date of January 1, 2009.
In December 2006, we received an order from the SDPUC, effective January 1, 2007, approving a 7.8% increase in retail rates and the addition of tariff provisions for automatic cost adjustments. The cost adjustments require us to absorb a portion of power cost increases partially depending on earnings from certain short-term wholesale sales of electricity. Absent certain conditions, the order also restricts us from requesting an increase in base rates that would go into effect prior to January 1, 2010. South Dakota retail customers account for approximately 90% of our total retail revenues.
Wygen III Power Plant Project
In March 2008, we received final regulatory approval for construction of Wygen III. Construction began immediately and theThe 110 MW coal-fired base load electric generation facility is expected to bewas completed byand commenced commercial operations on April 1, 2010. The expectedTotal cost of construction iswas approximately $255$232.3 million, which includes estimates of AFUDC. In April 2009, we sold a 25% ownership interest to MDU. At closing, MDU made a payment to us for its 25% share of the costs to date for the on-going construction of the facility. MDU will continue to reimbursereimbursed us monthly for its 25% share of the total costs paid to complete the project. We willIn July 2010, we sold an additional 23% ownership interest in Wygen III to the City of Gillette for $62.0 million. Under both agreements, we retain responsibility for operation of the facility with a life-of-plant site lease,lease. MDU and operationsthe City of Gillette will pay us for administrative services and coalshare in the costs of operating the plant for the life of the facility. Coal supply agreements are in place between WRDC, MDU and the City of Gillette.
Critical Accounting Estimates
We prepare our financial statements in conformity with MDU.GAAP. In many cases, the accounting treatment of a particular transaction is specifically dictated by GAAP and does not require management's judgment in application. There are also areas which require management's judgment in selecting among available GAAP alternatives. We are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. Actual results may differ from our estimates and to the extent there are material differences between these estimates, judgments or assumptions and actual results, our financial statements will be affected. We believe the following accounting estimates are the most critical in understanding and evaluating our reported financial results.
The following discussion of our critical accounting estimates should be read in conjunction with Note 1, "Business Description and Summary of Significant Accounting Policies" of our Notes to Financial Statements in this Annual Report on Form 10-K.
Impairment of Long-lived Assets
We evaluate for impairment, the carrying values of our long-lived assets whenever indicators of impairment exist.
For long-lived assets with finite lives, this evaluation is based upon our projections of anticipated future cash flows (undiscounted and without interest charges) from the assets being evaluated. If the sum of the anticipated future cash flows over the expected useful life of the assets is less than the assets' carrying value, then a permanent non-cash write-down equal to the difference between the assets' carrying value and the assets' fair value is required to be charged to earnings. In estimating future cash flows, we generally use a probability weighted average expected cash flow method with assumptions based on those used for internal budgets. The determination of future cash flows, and, if required, fair value of a long-lived asset is by its nature a highly subjective judgment. Significant assumptions are required in the forecast of future operating results used in the
preparation of the long-term estimated cash flows. Changes in these estimates could have a material effect on the evaluation of our long-lived assets. There have been no impairments taken in 2010 , 2009 or 2008.
Pension and Other Postretirement Benefits
The Company, as described in Note 10 to the Financial Statements in this Annual Report on Form 10-K, has defined benefit pension plan and post-retirement healthcare plans. Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the discount rate for measuring the present value of future plan obligations; expected long-term rates of return on plan assets; rate of future increases in compensation levels; and healthcare cost projections. The determination of our obligation and expenses for pension and other postretirement benefits is dependent on the assumptions used by actuaries in calculating the amounts. Although we believe our assumptions are appropriate, significant differences in our actual experience or significant changes in our assumptions may materially affect our pension and other postretirement obligations and our future expense.
In July 2009, the Board of Directors froze our Defined Benefit Pension Plan to certain new participants and transferred certain existing participants to an age and service based defined contribution plan, effective January 1, 2010. Plan assets and obligations for the Black Hills Corporation Plan which covers eligible employees of Black Hills Power were revalued as of July 31, 2009 in conjunction with the curtailment of the plan. As a result, we recognized a pre-tax curtailment expense of approximately $0.2 million in the third quarter of 2009. In July 2009, the Board of Directors of Black Hills Corporation also approved amendments to the BHC Retiree Healthcare Plan. This plan covers eligible employees of Black Hills Power. Effective January 1, 2010, the amendment changed the plan from a cost sharing plan to an RMSA for non-union employees.
In September 2010, the bargaining unit participants in the Defined Benefit Pension Plan voted to freeze all new bargaining unit employees from participation in the Plan and to freeze the benefits of current bargaining unit participants except for the following group: those bargaining unit participants who are both 1) age 45 or older as of December 31, 2010 and have 10 years or more of credited service as of January 1, 2011; and 2) elect to continue to accrue additional benefits under the pension plan and consequently fore-go the additional age and points based employer contribution under the Company's 401(k) retirement savings plan. As a result of this freeze, we recognized a pre-tax curtailment expense of less than $0.1 million in the fourth quarter of 2010. Pension Plan benefits are based on years of service and compensation levels during the highest five consecutive years of the last ten years of service. These changes are effective January 1, 2011.
Valuation of Deferred Tax Assets
We use the liability method of accounting for income taxes. Under this 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, as well as operating loss and tax credit carryforwards. The amount of deferred tax assets recognized is limited to the amount of the benefit that is more likely than not to be realized.
In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. If we determine that we will be unable to realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would be charged to income in the period such determination was made. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretations of tax laws and the resolution of the current and any future tax audits could significantly impact the amounts provided for income taxes in our financial statements.
Contingencies
When it is probable that an environmental or other legal liability has been incurred, a loss is recognized when the amount of the loss can be reasonably estimated. Estimates of the probability and the amount of loss are made based on currently available facts. Accounting for contingencies requires significant judgment regarding the estimated probabilities and ranges of exposure to potential liability. Our assessment of our exposure to contingencies could change to the extent there are additional future developments, or as more information becomes available. If actual obligations incurred are different from our estimates, the recognition of the actual amounts could have a material impact on our financial position and results of operations.
| |
ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
INDEX TO FINANCIAL STATEMENTS
| |
| Page |
| |
| INDEX TO FINANCIAL STATEMENTS |
Management's Report on Internal Control over Financial Reporting | 26 |
| |
Report of Independent Registered Public Accounting Firm | 27 |
| |
Statements of Income for the three years ended December 31, 20092010 | 28 |
| |
Balance Sheets as of December 31, 20092010 and 20082009 | 29 |
| |
Statements of Cash Flows for the three years ended December 31, 20092010 | 30 |
| |
Statements of Common Stockholder's Equity and Comprehensive Income for the three years ended December 31, 20092010 | 31 |
| |
Notes to Financial Statements | 32 - 57 |
Management's Report on Internal Control over Financial Reporting
We are responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2009,2010, based on the criteria set forth in Internal Control - Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Based on our evaluation we have concluded that our internal control over financial reporting was effective as of December 31, 2009.2010.
This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management's report was not subjectreporting because this requirement is inapplicable to attestation by our registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only management's report in this annual report.companies such as ours which are known as "non-accelerated filers."
Black Hills Power
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of
Black Hills Power, Inc.
Rapid City, South Dakota
We have audited the accompanying balance sheets of Black Hills Power, Inc. (the "Company") as of December 31, 20092010 and 2008,2009, and the related 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, 2009.2010. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule 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. Our audits 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 financial statements present fairly, in all material respects, the financial position of Black Hills Power, Inc. as of December 31, 20092010 and 2008,2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009,2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
March 10, 20107, 2011
BLACK HILLS POWER, INC.
STATEMENTS OF INCOME
Years ended December 31, | 2009 | | | 2008 | | | 2007 | |
| (in thousands) | |
| | | | | | | | |
Operating revenues | $ | 207,079 | | | $ | 232,674 | | | $ | 199,701 | |
| | | | | | | | | | | |
Operating expenses: | | | | | | | | | | | |
Fuel and purchased power | | 91,349 | | | | 113,672 | | | | 79,425 | |
Operations and maintenance | | 30,339 | | | | 31,028 | | | | 25,786 | |
Administrative and general | | 24,586 | | | | 21,864 | | | | 19,965 | |
Depreciation and amortization | | 19,465 | | | | 20,930 | | | | 20,763 | |
Taxes, other than income taxes | | 6,535 | | | | 6,544 | | | | 6,248 | |
Total operating expenses | | 172,274 | | | | 194,038 | | | | 152,187 | |
| | | | | | | | | | | |
Operating income | | 34,805 | | | | 38,636 | | | | 47,514 | |
| | | | | | | | | | | |
Other (expense) income: | | | | | | | | | | | |
Interest expense | | (11,422 | ) | | | (10,836 | ) | | | (11,787 | ) |
Interest income | | 258 | | | | 725 | | | | 884 | |
AFUDC - equity | | 5,831 | | | | 3,605 | | | | 601 | |
Other expense | | - | | | | (47 | ) | | | - | |
Other income | | 1,971 | | | | 227 | | | | 252 | |
Total other expense | | (3,362 | ) | | | (6,326 | ) | | | (10,050 | ) |
| | | | | | | | | | | |
Income from continuing operations before income taxes | | 31,443 | | | | 32,310 | | | | 37,464 | |
Income tax expense | | (8,304 | ) | | | (9,551 | ) | | | (12,568 | ) |
| | | | | | | | | | | |
Net income | $ | 23,139 | | | $ | 22,759 | | | $ | 24,896 | |
The accompanying notes to financial statements are an integral part of these financial statements.
28 | | | | | | | | | |
Years ended December 31, | 2010 | 2009 | 2008 |
| (in thousands) |
| | | |
Operating revenues | $ | 229,763 | | $ | 207,079 | | $ | 232,674 | |
| | | |
Operating expenses: | | | |
Fuel and purchased power | 87,757 | | 91,349 | | 113,672 | |
Operations and maintenance | 68,884 | | 57,116 | | 55,125 | |
Gain on sale of operating assets | (6,238 | ) | — | | — | |
Depreciation and amortization | 22,030 | | 19,465 | | 20,930 | |
Taxes - property | 2,062 | | 4,344 | | 4,311 | |
Total operating expenses | 174,495 | | 172,274 | | 194,038 | |
| | | |
Operating income | 55,268 | | 34,805 | | 38,636 | |
| | | |
Other (expense) income: | | | |
Interest expense | (18,737 | ) | (15,779 | ) | (13,392 | ) |
AFUDC - borrowed | 2,224 | | 4,357 | | 2,556 | |
Interest income | 318 | | 258 | | 725 | |
AFUDC - equity | 2,748 | | 5,831 | | 3,605 | |
Other expense | (35 | ) | — | | (47 | ) |
Other income | 223 | | 1,971 | | 227 | |
Total other expense | (13,259 | ) | (3,362 | ) | (6,326 | ) |
| | | |
Income from continuing operations before income taxes | 42,009 | | 31,443 | | 32,310 | |
Income tax expense | (10,741 | ) | (8,304 | ) | (9,551 | ) |
| | | |
Net income | $ | 31,268 | | $ | 23,139 | | $ | 22,759 | |
BLACK HILLS POWER, INC.
BALANCE SHEETS
At December 31, | 2009 | | | 2008 | |
| (in thousands, except share amounts) | |
ASSETS | | | | | |
Current assets: | | | | | |
Cash and cash equivalents | $ | 1,709 | | | $ | 4 | |
Receivables – customers, net | | 19,991 | | | | 23,881 | |
Receivables – affiliates, net | | 4,146 | | | | 12,619 | |
Other receivables, net | | 5,293 | | | | 2,111 | |
Money pool note receivable | | 57,737 | | | | - | |
Materials, supplies and fuel | | 18,825 | | | | 19,309 | |
Regulatory assets, current | | 7,467 | | | | 4,382 | |
Other current assets | | 1,639 | | | | 1,348 | |
Total current assets | | 116,807 | | | | 63,654 | |
Investments | | 4,197 | | | | 3,999 | |
Property, plant and equipment | | 950,577 | | | | 843,691 | |
Less accumulated depreciation and amortization | | (293,823 | ) | | | (281,220 | ) |
Total property, plant and equipment, net | | 656,754 | | | | 562,471 | |
Other assets: | | | | | | | |
Regulatory assets - non-current | | 31,305 | | | | 33,818 | |
Other, non-current assets | | 3,730 | | | | 2,842 | |
Total other assets | | 35,035 | | | | 36,660 | |
TOTAL ASSETS | $ | 812,793 | | | $ | 666,784 | |
LIABILITIES AND STOCKHOLDER'S EQUITY | | | | | | | |
Current liabilities: | | | | | | | |
Current maturities of long-term debt | $ | 32,025 | | | $ | 2,016 | |
Accounts payable | | 24,175 | | | | 26,567 | |
Accounts payable - affiliate | | 10,030 | | | | 10,411 | |
Notes payable - affiliate | | - | | | | 70,184 | |
Accrued liabilities | | 17,892 | | | | 15,083 | |
Regulatory liability, current | | 1,238 | | | | 68 | |
Deferred income tax liability - current | | 1,853 | | | | 732 | |
Total current liabilities | | 87,213 | | | | 125,061 | |
| | | | | | | |
Long-term debt, net of current maturities | | 297,044 | | | | 149,193 | |
| | | | | | | |
Deferred credits and other liabilities: | | | | | | | |
Deferred income tax liability - non-current | | 96,207 | | | | 85,504 | |
Regulatory liabilities, non-current | | 14,955 | | | | 13,573 | |
Benefit plan liabilities | | 28,224 | | | | 29,904 | |
Other, non-current liabilities | | 10,952 | | | | 8,626 | |
Total deferred credits and other liabilities | | 150,338 | | | | 137,607 | |
Commitments and contingencies (Notes 4, 5, 9 and 12) | | | | | | | |
Stockholder's equity: | | | | | | | |
Common stock $1 par value; 50,000,000 shares authorized; Issued: 23,416,396 shares in 2009 and 2008 | | 23,416 | | | | 23,416 | |
Additional paid-in capital | | 39,575 | | | | 39,575 | |
Retained earnings | | 216,420 | | | | 193,281 | |
Accumulated other comprehensive loss | | (1,213 | ) | | | (1,349 | ) |
Total stockholder's equity | | 278,198 | | | | 254,923 | |
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY | $ | 812,793 | | | $ | 666,784 | |
The accompanying notes to financial statements are an integral part of these financial statements.
BLACK HILLS POWER, INC.
STATEMENTS OF CASH FLOWSBALANCE SHEETS
Years ended December 31, | 2009 | | | 2008 | | | 2007 | |
| (in thousands) | |
Operating activities: | | | | | | | | |
Net income | $ | 23,139 | | | $ | 22,759 | | | $ | 24,896 | |
Adjustments to reconcile net income to net cash provided by operating activities - | | | | | | | | | | | |
Depreciation and amortization | | 19,465 | | | | 20,930 | | | | 20,763 | |
Provision for valuation allowances | | (111 | ) | | | (18 | ) | | | 138 | |
Deferred income taxes | | 11,600 | | | | 16,072 | | | | 3,864 | |
AFUDC - equity | | (5,831 | ) | | | (3,605 | ) | | | (601 | ) |
Other non-cash | | 351 | | | | 434 | | | | 965 | |
Change in operating assets and liabilities - | | | | | | | | | | | |
Accounts receivable and other current assets | | 13,233 | | | | (11,909 | ) | | | (11,257 | ) |
Accounts payable and other current liabilities | | 2,556 | | | | 7,821 | | | | (6,151 | ) |
Regulatory assets | | (2,205 | ) | | | (738 | ) | | | 6,471 | |
Regulatory liabilities | | 586 | | | | (518 | ) | | | 441 | |
Other operating activities | | 3,375 | | | | 736 | | | | (5,413 | ) |
Net cash provided by operating activities | | 66,158 | | | | 51,964 | | | | 34,116 | |
| | | | | | | | | | | |
Investing activities: | | | | | | | | | | | |
Property, plant and equipment additions | | (146,148 | ) | | | (132,247 | ) | | | (34,043 | ) |
Proceeds from sale of ownership interest in plant | | 32,783 | | | | - | | | | - | |
Notes receivable from affiliate companies, net | | (82,737 | ) | | | 10,304 | | | | 2,960 | |
Other investing activities | | 1,067 | | | | (225 | ) | | | (222 | ) |
Net cash used in investing activities | | (195,035 | ) | | | (122,168 | ) | | | (31,305 | ) |
| | | | | | | | | | | |
Financing activities: | | | | | | | | | | | |
Note payable to affiliate companies, net | | (45,184 | ) | | | 70,184 | | | | - | |
Long-term debt issuance | | 180,000 | | | | - | | | | - | |
Long-term debt - repayments | | (2,140 | ) | | | (2,009 | ) | | | (2,001 | ) |
Other financing activities | | (2,094 | ) | | | - | | | | - | |
Net cash provided by (used in) financing activities | | 130,582 | | | | 68,175 | | | | (2,001 | ) |
| | | | | | | | | | | |
Increase (decrease) in cash and cash equivalents | | 1,705 | | | | (2,029 | ) | | | 810 | |
| | | | | | | | | | | |
Cash and cash equivalents: | | | | | | | | | | | |
Beginning of year | | 4 | | | | 2,033 | | | | 1,223 | |
End of year | $ | 1,709 | | | $ | 4 | | | $ | 2,033 | |
| | | | | | |
At December 31, | 2010 | 2009 |
| (in thousands, except share amounts) |
ASSETS | | |
Current assets: | | |
Cash and cash equivalents | $ | 2,045 | | $ | 1,709 | |
Receivables - customers, net | 28,716 | | 19,991 | |
Receivables - affiliates | 6,891 | | 4,146 | |
Other receivables, net | 2,077 | | 5,293 | |
Money pool notes receivable | 39,862 | | 57,737 | |
Materials, supplies and fuel | 21,259 | | 18,825 | |
Regulatory assets, current | 3,584 | | 7,467 | |
Other current assets | 3,712 | | 1,639 | |
Total current assets | 108,146 | | 116,807 | |
| | |
Investments | 4,396 | | 4,197 | |
| | |
Property, plant and equipment | 962,640 | | 950,577 | |
Less accumulated depreciation and amortization | (304,800 | ) | (293,823 | ) |
Total property, plant and equipment, net | 657,840 | | 656,754 | |
| | |
Other assets: | | |
Regulatory assets, non-current | 37,740 | | 31,305 | |
Other, non-current assets | 3,610 | | 3,730 | |
Total other assets | 41,350 | | 35,035 | |
TOTAL ASSETS | $ | 811,732 | | $ | 812,793 | |
| | |
LIABILITIES AND STOCKHOLDER'S EQUITY | | |
Current liabilities: | | |
Current maturities of long-term debt | $ | 81 | | $ | 32,025 | |
Accounts payable | 14,828 | | 24,175 | |
Accounts payable - affiliate | 12,562 | | 10,030 | |
Accrued liabilities | 15,541 | | 17,892 | |
Regulatory liability, current | 1,932 | | 1,238 | |
Deferred income tax liability - current | 859 | | 1,853 | |
Total current liabilities | 45,803 | | 87,213 | |
| | |
Long-term debt, net of current maturities | 276,422 | | 297,044 | |
| | |
Deferred credits and other liabilities: | | |
Deferred income tax liability - non-current | 122,319 | | 96,207 | |
Regulatory liabilities, non-current | 28,276 | | 14,955 | |
Benefit plan liabilities | 19,581 | | 28,224 | |
Other, non-current liabilities | 9,914 | | 10,952 | |
Total deferred credits and other liabilities | 180,090 | | 150,338 | |
| | |
Commitments and contingencies (Notes 6, 10, 11 and 13) | | |
| | |
Stockholder's equity: | | |
Common stock $1 par value; 50,000,000 shares authorized; Issued: 23,416,396 shares in 2010 and 2009 | 23,416 | | 23,416 | |
Additional paid-in capital | 39,575 | | 39,575 | |
Retained earnings | 247,688 | | 216,420 | |
Accumulated other comprehensive loss | (1,262 | ) | (1,213 | ) |
Total stockholder's equity | 309,417 | | 278,198 | |
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY | $ | 811,732 | | $ | 812,793 | |
The accompanying notes to financial statements are an integral part of these financial statements.
BLACK HILLS POWER, INC.
STATEMENTS OF CASH FLOWS
| | | | | | | | | |
Years ended December 31, | 2010 | 2009 | 2008 |
| (in thousands) |
Operating activities: | | | |
Net income | $ | 31,268 | | $ | 23,139 | | $ | 22,759 | |
Adjustments to reconcile net income to net cash provided by operating activities - | | | |
Depreciation and amortization | 22,030 | | 19,465 | | 20,930 | |
Deferred income taxes | 25,626 | | 11,600 | | 16,072 | |
AFUDC - equity | (2,748 | ) | (5,831 | ) | (3,605 | ) |
Gain on sale of operating assets | (6,238 | ) | — | | — | |
Employee benefits | 4,030 | | 4,234 | | 730 | |
Other adjustments | (4,335 | ) | 240 | | 416 | |
Change in operating assets and liabilities - | | | |
Accounts receivable and other current assets | (14,541 | ) | 13,233 | | (11,909 | ) |
Accounts payable and other current liabilities | (5,525 | ) | 2,556 | | 7,821 | |
Regulatory assets | 3,883 | | (2,205 | ) | (738 | ) |
Regulatory liabilities | 3,562 | | 586 | | (518 | ) |
Contributions to defined benefit pension plan | (8,798 | ) | — | | — | |
Other operating activities | 2,389 | | (859 | ) | 6 | |
Net cash provided by operating activities | 50,603 | | 66,158 | | 51,964 | |
| | | |
Investing activities: | | | |
Property, plant and equipment additions | (78,602 | ) | (146,148 | ) | (132,247 | ) |
Proceeds from sale of ownership interest in plant | 62,000 | | 32,783 | | — | |
Notes receivable from affiliate companies, net | 17,875 | | (82,737 | ) | 10,304 | |
Other investing activities | 2,202 | | 1,067 | | (225 | ) |
Net cash (used in) provided by investing activities | 3,475 | | (195,035 | ) | (122,168 | ) |
| | | |
Financing activities: | | | |
Note payable to affiliate companies, net | — | | (45,184 | ) | 70,184 | |
Long-term debt issuance | — | | 180,000 | | — | |
Long-term debt - repayments | (52,566 | ) | (2,140 | ) | (2,009 | ) |
Other financing activities | (1,176 | ) | (2,094 | ) | — | |
Net cash (used in) provided by financing activities | (53,742 | ) | 130,582 | | 68,175 | |
| | | |
Increase (decrease) in cash and cash equivalents | 336 | | 1,705 | | (2,029 | ) |
| | | |
Cash and cash equivalents: | | | |
Beginning of year | 1,709 | | 4 | | 2,033 | |
End of year | $ | 2,045 | | $ | 1,709 | | $ | 4 | |
See Note 12 for Supplemental Cash Flows information
The accompanying notes to financial statements are an integral part of these financial statements.
BLACK HILLS POWER, INC.
STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
AND COMPREHENSIVE INCOME
| | Common Stock | | | Additional Paid-In Capital | | | Retained Earnings | | | Accumulated Other Comprehensive Income (Loss) | | | Total | |
| | Shares | | | Amount | | | | | | | | | | | | | |
| | (in thousands) | |
| | | | | | | | | | | | | | | | | | |
Balance at December 31, 2006 | | | 23,416 | | | $ | 23,416 | | | $ | 39,575 | | | $ | 145,810 | | | $ | (932 | ) | | $ | 207,869 | |
Comprehensive Income: | | | | | | | | | | | | | | | | | | | | | | | | |
Net income | | | - | | | | - | | | | - | | | | 24,896 | | | | - | | | | 24,896 | |
Other comprehensive loss, net of tax, (see Note 8) | | | - | | | | - | | | | - | | | | - | | | | (345 | ) | | | (345 | ) |
Total comprehensive income | | | - | | | | - | | | | - | | | | 24,896 | | | | (345 | ) | | | 24,551 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2007 | | | 23,416 | | | | 23,416 | | | | 39,575 | | | | 170,706 | | | | (1,277 | ) | | | 232,420 | |
Comprehensive Income: | | | | | | | | | | | | | | | | | | | | | | | | |
Net income | | | - | | | | - | | | | - | | | | 22,759 | | | | - | | | | 22,759 | |
Other comprehensive loss, net of tax, (see Note 8) | | | - | | | | - | | | | - | | | | - | | | | (72 | ) | | | (72 | ) |
Total comprehensive income | | | - | | | | - | | | | - | | | | 22,759 | | | | (72 | ) | | | 22,687 | |
Adoption of accounting pronouncement (see Note 9) | | | - | | | | - | | | | - | | | | (184 | ) | | | - | | | | (184 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2008 | | | 23,416 | | | | 23,416 | | | | 39,575 | | | | 193,281 | | | | (1,349 | ) | | | 254,923 | |
Comprehensive Income: | | | | | | | | | | | | | | | | | | | | | | | | |
Net income | | | - | | | | - | | | | - | | | | 23,139 | | | | - | | | | 23,139 | |
Other comprehensive income, net of tax, (see Note 8) | | | - | | | | - | | | | - | | | | - | | | | 136 | | | | 136 | |
Total comprehensive income | | | - | | | | - | | | | - | | | | 23,139 | | | | 136 | | | | 23,275 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2009 | | | 23,416 | | | $ | 23,416 | | | $ | 39,575 | | | $ | 216,420 | | | $ | (1,213 | ) | | $ | 278,198 | |
| | | | | | | | | |
| 2010 | 2009 | 2008 |
| (in thousands) |
Common stock shares: | | | |
Balance beginning of year | 23,416 | | 23,416 | | 23,416 | |
Issuance of common stock | — | | — | | — | |
Balance end of year | 23,416 | | 23,416 | | 23,416 | |
| | | |
Common stock amounts: | | | |
Balance beginning of year | $ | 23,416 | | $ | 23,416 | | $ | 23,416 | |
Issuance of common stock | — | | — | | — | |
Balance end of year | $ | 23,416 | | $ | 23,416 | | $ | 23,416 | |
| | | |
Additional paid-in capital: | | | |
Balance beginning of year | $ | 39,575 | | $ | 39,575 | | $ | 39,575 | |
Issuance of common stock | — | | — | | — | |
Balance end of year | $ | 39,575 | | $ | 39,575 | | $ | 39,575 | |
| | | |
Retained earnings: | | | |
Balance beginning of year | $ | 216,420 | | $ | 193,281 | | $ | 170,706 | |
Net income available for common stock | 31,268 | | 23,139 | | 22,759 | |
Adoption of accounting pronouncement | — | | — | | (184 | ) |
Balance end of year | $ | 247,688 | | $ | 216,420 | | $ | 193,281 | |
| | | |
Accumulated other comprehensive loss: | | | |
Balance beginning of year | $ | (1,213 | ) | $ | (1,349 | ) | $ | (1,277 | ) |
Other comprehensive (loss) income, net of tax | (49 | ) | 136 | | (72 | ) |
Balance end of year | $ | (1,262 | ) | $ | (1,213 | ) | $ | (1,349 | ) |
| | | |
Total stockholder's equity | $ | 309,417 | | $ | 278,198 | | $ | 254,923 | |
| | | |
Comprehensive income: | | | |
Net income | $ | 31,268 | | $ | 23,139 | | $ | 22,759 | |
Other comprehensive income (loss) , net of tax (see Note 9) | (49 | ) | 136 | | (72 | ) |
Comprehensive income | $ | 31,219 | | $ | 23,275 | | $ | 22,687 | |
The accompanying notes to financial statements are an integral part of these financial statements.
NOTES TO FINANCIAL STATEMENTS
December 31, 2010, 2009 2008 and 20072008
(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)Company, "we," "us" or "our") is an electric utility serving customers in South Dakota, Wyoming and Montana. We are a wholly-owned subsidiary of BHC or the Parent, a public registrant listed on the New York Stock Exchange.
Basis of Presentation
The financial statements include the accounts of Black Hills Power, Inc. and also our ownership interests in the assets, liabilities and expenses of our jointly owned facilities (Note 3)3). Certain prior years' data presented in the financial statementstatements have been reclassified to conform to the current year presentation. The Balance Sheet hasstatements of income for the prior periods have been modified to reflect "Regulatory assets, current," which had been previously includedthe retrospective application of a change in Other current assets and "Regulatory liabilities, current," whichthe presentation of the statement of income. This change was previously included in Accrued liabilities.made to enhance our statement of income presentation. The Statement of Cash Flows for December 31, 2008 and 2007 has beenwas modified within Netto reflect Employee benefit expense as a specific adjustment to reconcile net income to net cash provided by operating activities to reflect "Regulatory assets," whichactivities. It was previously included in Other operating activities and "Regulatory liabilities," which was previously included in Other operating activities. The Statement of Cash Flows for December 31, 2008 and 2007 has been modified within Net cash provided by operating activities to reflect “Other non-cash” which was previously included in Other operating activities.adjustments.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to allowance for uncollectible accounts receivable, unbilled revenues, long-lived asset values and useful lives, asset retirement obligations, employee benefits plans and contingency accruals. Actual results could differ from those estimates.
Regulatory Accounting
Our 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 FERC.
Our regulated utility operations follow accounting standards for regulated operations and our financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions regulating our electric operations. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply to our regulated generation operations. In the event we determine that we no longer meet the criteria for following accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations in an amount that could be material.
Our regulatory assets and 2008, we had $22.6 million and $24.6 million, respectively, in net regulatory assetsliabilities for which we recover the costs, but we do not earn a return.
Onreturn were as follows as of December 31 2009 and 2008, we had the following regulatory assets and liabilities (in thousands):
| | Recovery Period | | 2009 | | | 2008 | | Recovery Period | 2010 | 2009 |
| | | | | | | | | |
Regulatory assets: | | | | | | | | | |
Unamortized loss on reacquired debt | 14 years | | $ | 2,207 | | | $ | 2,367 | | 14 years | $ | 3,016 | | $ | 2,207 | |
AFUDC | Up to 45 years | | | 7,579 | | | | 4,995 | | Up to 45 years | 9,489 | | 7,579 | |
Defined benefit postretirement plans | Up to 17 years | | | 21,024 | | | | 26,256 | | Up to 13 years | 18,049 | | 21,024 | |
Deferred energy costs | Less than one year | | | 7,467 | | | | 4,382 | | Less than one year | 3,584 | | 7,467 | |
Flow through accounting | | Up to 35 years | 4,772 | | — | |
Other | | | | 495 | | | | 200 | | | 2,414 | | 495 | |
Total regulatory assets | | | $ | 38,772 | | | $ | 38,200 | | | $ | 41,324 | | $ | 38,772 | |
| | | | | | | | | | | |
Regulatory liabilities: | | | | | | | | | | | |
Cost of removal for utility plant | Up to 53 years | | $ | 13,678 | | | $ | 11,705 | | Up to 53 years | $ | 15,429 | | $ | 13,678 | |
Defined benefit postretirement plans | | Up to 13 years | 10,204 | | — | |
Other | | | | 2,515 | | | | 1,936 | | | 4,575 | | 2,515 | |
Total regulatory liabilities | | | $ | 16,193 | | | $ | 13,641 | | | $ | 30,208 | | $ | 16,193 | |
Regulatory assets are primarily recorded for the probable future revenue to recover the costs associated with defined benefit postretirement plans, future income taxes related to the deferred tax liability for the equity component of AFUDC of utility assets and unamortized losses on reacquired debt. To the extent that energy costs are under-recovered or over-recovered during the year, they are recorded as a regulatory asset or liability, respectively. 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, gains associated with regulated utilities' defined benefit postretirement plans and the cost of removal for utility plant, recovered through our electric utility rates. Regulatory assets are included in Regulatory assets, current and Regulatory assets, non-current on the accompanying Balance Sheet.Sheets. Regulatory liabilities are included in Regulatory liabilities, current and Regulatory liabilities, non-current on the accompanying Balance Sheet.Sheets.
Allowance for Funds Used During Construction
AFUDC represents the approximate composite cost of borrowed funds and a return on capital used to finance a project. Our AFUDC for the years ended December 31 2009, 2008 and 2007 was $10.2 million, $6.2 million and $0.9 million, respectively. The equity component of AFUDC for 2009, 2008 and 2007 was $5.8 million, $3.6 million and $0.6 million, respectively. The borrowed funds component of AFUDC for 2009, 2008 and 2007 was $4.4 million, $2.6 million and $0.3 million, respectively. The equity component of AFUDC is included in Other income, and the borrowed funds component of AFUDC is netted in Interest expense on the accompanying Statements of Income.as follows (in thousands):
| | | | | | | | | |
| 2010 | 2009 | 2008 |
| | | |
AFUDC - borrowed | $ | 2,224 | | $ | 4,357 | | 2,556 | |
AFUDC - equity | 2,748 | | 5,831 | | 3,605 | |
Total AFUDC | $ | 4,972 | | $ | 10,188 | | $ | 6,161 | |
Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.
Allowance for Doubtful Accounts
We maintain an allowance for doubtful accounts which reflects our best estimate of potentially uncollectible trade receivables. We regularly review our trade receivablesreceivable allowances by considering such factors as historical experience, credit-worthiness,credit worthiness, the age of the receivable balances and current economic conditions that may affect the ability to pay.
Accounts receivable consist of sales to residential, commercial, industrial, municipal and other customers all of which do not bear interest. These accounts receivables are stated at billed amounts net of write-offs or payment received. Approximately 26% of the accounts receivable balance consists of unbilled revenue.
The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollected. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including unbilled revenue. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management's best estimate of future collection success given the existing collections environment.
Following is a summary of accounts receivables at December 31 (in thousands):
| 2009 | | | 2008 | |
| | | | | |
Accounts receivable trade | $ | 14,703 | | | $ | 18,860 | |
Unbilled revenues | | 5,547 | | | | 5,391 | |
Total accounts receivable – customers | | 20,250 | | | | 24,251 | |
Allowance for doubtful accounts | | (259 | ) | | | (370 | ) |
Net accounts receivable | $ | 19,991 | | | $ | 23,881 | |
| | | | | | |
| 2010 | 2009 |
| | |
Accounts receivable trade | $ | 21,365 | | $ | 14,703 | |
Unbilled revenues | 7,581 | | 5,547 | |
Total accounts receivable - customers | 28,946 | | 20,250 | |
Allowance for doubtful accounts | (230 | ) | (259 | ) |
Net accounts receivable | $ | 28,716 | | $ | 19,991 | |
Materials, Supplies and Fuel
Materials, supplies and fuel used for construction, operation and maintenance purposes are generally stated on a weighted-average cost 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, 2009 and 2008, there were no market adjustments related to fuel.
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. 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. Removal costs associated with non-legal obligations are reclassified from accumulated depreciation and reflected as regulatory liabilities. Ordinary repairs and maintenance of property are charged to operations as incurred.
Depreciation provisions for regulated electric property, plant and equipment isare computed on a straight-line basis using an annual composite rate of 2.8%2.2% in 2009, 3.2%2010, 2.8% in 20082009 and 3.1%3.2% in 2007. Based on a rate study, the new composite rate of 2.8% went into effect August 2009.2008.
Derivatives and Hedging Activities
From time to time we utilize risk management contracts including forward purchases and sales and fixed-for-float swaps to hedge the price of fuel for our combustion turbines, maximize the value of our natural gas storage or fix the interest on our variable rate debt. Contracts that qualify as derivatives under accounting standards for derivatives, and that are not exempted such as normal purchase/normal sale, are required to be recorded in the balance sheet as either an asset or liability, measured at its fair value. Accounting standards for derivatives require that changes in the derivative instrument's fair value be recognized currently in earnings unless specific hedge accounting criteria are met.
Accounting standards for derivatives allowsallow hedge accounting for qualifying fair value and cash flow hedges. 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 should be recognized currently in earnings in the same accounting period. Conversely, the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument should be reported as a component of other comprehensive income, net of tax, 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.
Impairment of Long-Lived Assets
We periodically evaluate whether events and circumstances have occurred which may affect the estimated useful life or the recoverability of the remaining balance of our long-lived assets. If such events or circumstances were to indicate that the carrying amount of these assets was not recoverable, we 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, we would recognize an impairment loss. No impairment loss was recorded during 2010, 2009 2008 or 2007.2008.
Income Taxes
We use 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, as well as operating loss and tax credit carryforwards. 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. We classify deferred tax assets and liabilities into current and non-current amounts based on the classification of the related assets and liabilities.
We file 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.
(2) RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS
Recently Adopted Accounting Standards
FASB Accounting Standards CodificationDisclosures About the Credit Quality of Financing Receivables and the Hierarchy of Generally Accepted Accounting Principles,Allowance for Credit Losses, ASC 105310-10-50
OnIn July 1, 2009,2010, the FASB Accounting Standards CodificationTM becameissued an amendment to ASC 310-10-50, Receivables - Disclosures. The guidance requires additional disclosures that will facilitate financial statement user's evaluation of the sourcenature of authoritative GAAP recognized bycredit risk inherent in financing receivables, how that risk is analyzed in arriving at the FASB to be applied by non-governmental entities. Onallowance for credit losses, and the effective date of this Statement, the Codification superseded all then-existing non-SEC accounting and reporting standards. All other non-SEC accounting literature not included or grandfatheredreason for any changes in the Codification became non-authoritative. This Statementallowance for credit losses. These disclosures should be provided on a disaggregated basis but exempts trade receivables that have a contractual maturity of one year or less, receivables measured at lower of cost or fair value, and receivables measured at fair value with the changes in fair value reported in earnings. (See Note 1) It is effective for financial statements issued for interim and annual reporting periods ending after September 15, 2009.
Following this Statement, the FASB will not issue new standards in the form of Statements, FASB Staff Positions,on or Emerging Task Force Abstracts. Instead, it will issue Accounting Standards Updates. The FASB will not consider Accounting Standards Updates as authoritative in their own right. Accounting Standards Updates will serve only to update the Codification, provide background information about the guidance, and provide the basis for conclusions on the change(s) in the Codification.
Business Combinations, ASC 805
The ASC for Business Combinations requires that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. It also establishes principles and requirements for how the acquirer (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree, (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase and (iii) discloses the nature and financial effects of the business combination; and requires restructuring and acquisition-related costs to be expensed. In addition, if income tax liabilities are settled for an amount other than as previously recorded, such adjustments could affect income tax expense in the period of adjustment. Effective January 1, 2009, any impact the standard will have on our consolidated financial statements will depend on the nature and magnitude of any future acquisitions we consummate including any tax-related adjustments.
Derivative and Hedging, ASC 815
The ASC for Derivative and Hedging Disclosures includes requirements for enhanced disclosures about derivative and hedging activities and their affect on an entity's financial position, financial performance and cash flows. Accounting standards for derivatives and hedging encourages, but does not require, disclosures for earlier periods presented for comparative purposes at initial adoption. Required disclosures for periods subsequent to January 1, 2009 are provided in Note 4.
Fair Value Measurements and Disclosures, ASC 820
The ASC for Fair Value Measurements and Disclosures defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. This does not expand the application of fair value accounting to any new circumstances, but applies the framework to other applicable GAAP that requires or permits fair value measurement. We apply fair value measurements to certain assets and liabilities, primarily commodity derivatives.
Financial Instruments, ASC 825
The ASC for Financial Instruments requires public companies to provide more frequent disclosures about the fair value of their financial instruments for interim and annual periods ending after June 15, 2009. These disclosures are included in Note 6.
Subsequent Events, ASC 855
The ASC for Subsequent Events establishes general standards of accounting for and disclosures of events that occur after the balance sheet date, but before financial statements are issued or are available to be issued. These standards and disclosures were applied to our financial statements issued after June 15, 2009.
Employers Accounting for Defined Benefit Pension and Other Postretirement Plans, ASC 715
The ASC for Employer's Accounting for Defined Benefit Pension and Other Postretirement Plans requires the recognition of the overfunded or underfunded status of defined benefit postretirement plans as an asset or liability in the statement of financial position, recognition of changes in the funded status in comprehensive income, measurement of the funded status of a plan as of the date of the year-end statement of financial position and provides for related disclosures. Effective for fiscal years ending after December 15, 2008, this accounting standard required the measurement of the funded status of the plan to coincide with the date of the year-end statement of financial position. Therefore, the measurement date for the funded status of our pension and other postretirement benefit plans was changed to December 31 from September 30. ASC 715 also provides guidance on an employer's disclosure about plan assets for a defined benefit pension or other postretirement plans. These disclosures are effective for fiscal years ending after December 15, 2009. See Note 9 for additional information.2010.
Recently Issued Accounting StandardsConsolidation of Variable Interest Entities, ASC 810-10-15
In June 2009, the FASB issued a revision regarding consolidations. The revised accounting guidanceamendment requires a company to consider whether an entity that is insufficiently capitalized or is not controlled through voting should be consolidated. It will requirerequires additional disclosures about the involvement with variable interest entities and any significant changes in risk exposure due to that involvement. This standard is effective for annual periods that begin after November 15, 2009. We are currently assessing the impact that the2009 with ongoing re-evaluation. The adoption of this standard willin January 2010 did not have any impact on our financial condition,statements, results of operations, and cash flows.
Fair Value Measurements, ASC 820Recently Issued Accounting Standards and Legislation
Patient Protection and Affordable Care Act
In JanuaryMarch 2010, the FASB issued guidance related to improving disclosures about fair value measurements. The guidance requires separate disclosuresPresident of the amounts of transfers inUnited States signed into law comprehensive healthcare reform legislation under the PPACA as amended by the Healthcare and out of Level 1 and Level 2 fair value measurements and a descriptionEducation Reconciliation Act. The potential impact on the Company, if any, cannot be determined until regulations are promulgated under the PPACA. Included among the provisions of the reason for such transfers. In the reconciliation for Level 3, fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements shall be presented separately. These disclosures are required for interim and annual reporting periods and were effective for the Company on January 1, 2010, except for the disclosures related to the purchases, sales, issuances and settlementsPPACA is a change in the roll forward activitytax treatment of Level 3 fair value measurements,the Medicare Part D subsidy (the "subsidy") which are effectiveaffects our Non-Pension Postretirement Benefit Plan. Internal Revenue Code Section 139A has been amended to eliminate the deduction of the subsidy in reducing income for years beginning after December 31, 2012. The impact of this change in the tax treatment of the subsidy had an immaterial effect on January 1, 2011. The guidance will require additional disclosures, but will not impact our financial position, or results of operations.operations and cash flows. The Company will continue to assess the accounting implications of the PPACA as related regulations and interpretations become available.
(3) PROPERTY, PLANT AND EQUIPMENT
(2) | PROPERTY, PLANT AND EQUIPMENT |
Property, plant and equipment at December 31, consisted of the following (in thousands):
| 2009 | | | 2009 Weighted Average Useful Life | | | 2008 | | | 2008 Weighted Average Useful Life | | | Lives (in years) | |
Electric plant: | | | | | | | | | | | | | | |
Production | $ | 336,534 | | | | 53 | | | $ | 326,606 | | | | 47 | | | | 30-62 | |
Transmission | | 86,841 | | | | 44 | | | | 70,470 | | | | 45 | | | | 35-55 | |
Distribution | | 264,847 | | | | 37 | | | | 249,652 | | | | 37 | | | | 15-65 | |
Plant acquisition adjustment | | 4,870 | | | | 32 | | | | 4,870 | | | | 32 | | | | 32 | |
General | | 55,701 | | | | 22 | | | | 47,127 | | | | 23 | | | | 10-50 | |
Total electric plant | | 748,793 | | | | | | | | 698,725 | | | | | | | | | |
Less accumulated depreciation and amortization | | 293,823 | | | | | | | | 281,220 | | | | | | | | | |
Electric plant net of accumulated depreciation and amortization | | 454,970 | | | | | | | | 417,505 | | | | | | | | | |
Construction work in progress | | 201,784 | | | | | | | | 144,966 | | | | | | | | | |
Net electric plant | $ | 656,754 | | | | | | | $ | 562,471 | | | | | | | | | |
| | | | | | | | | | |
| | December 31, 2010 | | December 31, 2009 | |
| December 31, 2010 | Weighted Average Useful Life | December 31, 2009 | Weighted Average Useful Life | Lives (in years) |
Electric plant: | | | | | |
Production | $ | 475,762 | | 50 | $ | 336,534 | | 53 | 30-62 | |
Transmission | 116,056 | | 43 | 86,841 | | 44 | 35-55 | |
Distribution | 271,470 | | 37 | 264,847 | | 37 | 15-65 | |
Plant acquisition adjustment | 4,870 | | 32 | 4,870 | | 32 | 32 | |
General | 58,777 | | 22 | 55,701 | | 22 | 10-50 | |
Total electric plant | 926,935 | | | 748,793 | | | |
Less accumulated depreciation and amortization | 304,800 | | | 293,823 | | | |
Electric plant net of accumulated depreciation and amortization | 622,135 | | | 454,970 | | | |
Construction work in progress | 35,705 | | | 201,784 | | | |
Net electric plant | $ | 657,840 | | | $ | 656,754 | | | |
38(4) JOINTLY OWNED FACILITIES
(3) | JOINTLY OWNED FACILITIES |
We use the proportionate consolidation method to account for our percentage interest in the assets, liabilities and expenses of the following facilities:
| · |
• | We own a 20% interest and PacifiCorp owns an 80% interest in the Wyodak Plant (Plant)(the "Plant"), a 362 MW coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp is the operator of the Plant. We receive 20% of the Plant's capacity and are committed to pay 20% of its additions, replacements and operating and maintenance expenses. As of December 31, 2009 and 2008, ourOur investment in the Plant included $79.8 million and $79.1 million, respectively, in electric plant and $52.2 million and $50.8 million, respectively, in accumulated depreciation and is included in the corresponding captions in the accompanying Balance Sheets. Our share of direct expenses of the Plant was $8.0 million, $8.0 million and $7.3 million for the years ended December 31, 2009, 2008 and 2007, respectively, and is included in the corresponding categories of operating expenses in the accompanying Statements of Income. |
| · |
• | We also own a 35% interest and Basin Electric owns a 65% interest in the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC region and the MAPP region. The total transfer capacity of the transmission tie is 400 MW - 200 MW West to East and 200 MW from East to West. We are committed to pay 35% of the additions, replacements and operating and maintenance expenses. Our share of direct expenses was $0.1 million for each of the years ended December 31, 2009, 2008 and 2007. As of December 31, 2009 and 2008, our investment in the transmission tie was $19.6 million and $19.8 million, with $3.8 million and $2.5 million, respectively, of accumulated depreciation and is included in the corresponding captions in the accompanying Balance Sheets. |
| · |
• | The Balance Sheet includes our ownershipWe own a 52% interest in the assets and liabilitiesWygen III power plant. MDU owns 25% which was purchased in April 2009. At closing, MDU made a payment to us for its 25% share of the Wygen IIIcosts to date on the ongoing construction of the facility currently under construction. We own 75%and subsequently reimbursed us for 25% of Wygen III and MDU owns 25%. Wygen III is expectedthe total costs paid to commence operations by April 1, 2010. Included incomplete the December 31, 2009 Balance Sheet in Construction Work in Progress was $175.6 million. During 2009, we were reimbursed $48.4 million for the construction.project. Our share of direct expenses of the jointly-owned facility isare included in Operating expenses in the Statements of Income. Our share of property, plant and equipment in Wygen III and associated accumulated depreciation is included in the corresponding captions in the accompanying Balance Sheets. |
| |
• | The City of Gillette owns a 23% interest in the Wygen III power plant which was purchased in July 2010 for $62.0 million. Wygen III was placed into commercial operations on April 1, 2010. Our share of direct expenses of the jointly-owned facility are included in Operating expenses in the Statements of Income. Our share of property, plant and equipment in Wygen III and associated accumulated depreciation is included in the corresponding captions in the accompanying Balance Sheets. |
Our share of direct expenses related to our jointly owned plants for the years ended December 31 was as follows (dollars in thousands):
| | | | | | | | | | | |
Share of Direct Expenses | Ownership Percentage | 2010 | 2009 | 2008 |
Wyodak Plant | 20.0 | % | $ | 8,546 | | $ | 8,021 | | $ | 8,000 | |
Transmission Tie | 35.0 | % | $ | 154 | | $ | 100 | | $ | 123 | |
Wygen III (a) | 52.0 | % | $ | 7,618 | | $ | — | | $ | — | |
___________
(a) The Wygen III plant commenced commercial operations on April 1, 2010.
As of December 31, 2010, our interests in jointly-owned generating facilities and transmission systems included on our Balance Sheets were as follows (dollars in thousands):
| | | | | | | | | | | |
Share of Direct Expenses | Ownership Percentage | Plant in Service | Construction Work in Progress | Accumulated Depreciation |
Wyodak Plant | 20.0 | % | $ | 82,466 | | $ | 21,687 | | $ | 54,108 | |
Transmission Tie | 35.0 | % | $ | 19,644 | | $ | — | | $ | 4,111 | |
Wygen III (a) | 52.0 | % | $ | 129,340 | | $ | 194 | | $ | 2,282 | |
___________
(a) The Wygen III plant commenced commercial operations on April 1, 2010.
We hold natural gas in storage for use as fuel for generating electricity with our gas-fired combustion turbines. To minimize associated price risk and seasonal storage level requirements, we utilize various derivative instruments in managing these risks. As of December 31, 2008,2010, there were no derivative contracts outstanding. As of December 31, 2009, we had the following derivatives and related balances included in Accrued liabilities on the accompanying Balance Sheet (dollars, in thousands):
| Natural Gas Swaps | |
| | |
Notional* | | 232,500 | |
Maximum terms in months | | 10 | |
Current derivative liabilities | $ | 5 | |
Pre-tax accumulated other comprehensive loss | $ | (5 | ) |
___________________________ | | | |
| December 31, 2009 |
| |
Notional* | 232,500 | |
Maximum terms in months | 10 | |
Current derivative liabilities | $ | 5 | |
Pre-tax accumulated other comprehensive loss | $ | (5 | ) |
* Gas in MMbtus
(6) LONG-TERM DEBT
Long-term debt outstanding at December 31 iswas as follows (in thousands):
| 2009 | | | 2008 | |
First mortgage bonds: | | | | | |
8.06% due 2010 | $ | 30,000 | | | $ | 30,000 | |
9.49% due 2018 | | 2,520 | | | | 2,810 | |
9.35% due 2021 | | 19,980 | | | | 21,645 | |
7.23% due 2032 | | 75,000 | | | | 75,000 | |
6.125% due 2039 | | 180,000 | | | | - | |
Unamortized discount on 6.125% bonds | | (124 | ) | | | - | |
| | 307,376 | | | | 129,455 | |
Other long-term debt: | | | | | | | |
Pollution control revenue bonds at 4.8% due 2014 | | 6,450 | | | | 6,450 | |
Pollution control revenue bonds at 5.35% due 2024 | | 12,200 | | | | 12,200 | |
Other | | 3,043 | | | | 3,104 | |
| | 21,693 | | | | 21,754 | |
| | | | | | | |
Total long-term debt | | 329,069 | | | | 151,209 | |
Less current maturities | | (32,025 | ) | | | (2,016 | ) |
Net long-term debt | $ | 297,044 | | | $ | 149,193 | |
| | | | | | |
| December 31, 2010 | December 31, 2009 |
First mortgage bonds: | | |
8.06% due 2010 | $ | — | | $ | 30,000 | |
9.49% due 2018 | — | | 2,520 | |
9.35% due 2021 | — | | 19,980 | |
7.23% due 2032 | 75,000 | | 75,000 | |
6.125% due 2039 | 180,000 | | 180,000 | |
Unamortized discount on 6.125% bonds | (119 | ) | (124 | ) |
| 254,881 | | 307,376 | |
Other long-term debt: | | |
Pollution control revenue bonds at 4.8% due 2014 | 6,450 | | 6,450 | |
Pollution control revenue bonds at 5.35% due 2024 | 12,200 | | 12,200 | |
Other | 2,972 | | 3,043 | |
| 21,622 | | 21,693 | |
| | |
Total long-term debt | 276,503 | | 329,069 | |
Less current maturities | (81 | ) | (32,025 | ) |
Net long-term debt | $ | 276,422 | | $ | 297,044 | |
Bond Issuance
On October 27, 2009, we completed a $180 million first mortgage bond issuance. The bonds were priced at 99.931% of par and a reoffer yield of 6.13%. The bonds mature November 1, 2039 and carry an annual interest rate of 6.125%, which is scheduled to be paid semi-annually. We received proceeds net of underwriting fees of $178.3 million which were used to repay intercompany borrowings from BHC, primarily incurred to fund the construction of Wygen III.III, and to redeem the Series AC mortgage bonds. Deferred finance costs of approximately $2.2 million were capitalized and will beare being amortized over the term of the bonds. Amortization of deferred financing costs is included in Interest expense.
Substantially all of our property is subject to the lien of the indenture securing our first mortgage bonds. First mortgage bonds may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures.
Series AC Bonds
In February 2010, the Series 8.06% AC bonds matured. These were paid in full for $30.0 million of principal plus accrued interest of $1.2 million.
Series Y Bonds
In March 2010, we completed redemption of our Series Y 9.49% bonds in full. The bonds were originally due in 2018. A total of $2.7 million was paid on March 31, 2010, which includes the principal balance of $2.5 million plus accrued interest and an early redemption premium of 2.618%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Balance Sheet and is being amortized over the remaining term of the original bonds.
Series Z Bonds
In June 2010, we completed redemption of our Series Z 9.35% bonds in full. The bonds were originally due in 2021. A total of $21.8 million was paid on June 1, 2010, which included the principal balance of $20.0 million plus accrued interest and an early redemption premium of 4.675%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Balance Sheet and is being amortized over the remaining term of the original bonds.
Long-term Debt Maturities
Scheduled maturities of our outstanding long-term debt (excluding unamortized discounts) are approximately $32.0 million in 2010; $2.0 million a year for the years 2011, 2012 and 2013; $8.4 million in 2014; and $282.7 million thereafter.as follows (in thousands):
(6) | FAIR VALUE OF FINANCIAL INSTRUMENTS |
| | | |
2011 | $ | 81 | |
2012 | $ | 36 | |
2013 | $ | — | |
2014 | $ | 6,450 | |
2015 | $ | — | |
Thereafter | $ | 270,055 | |
(7) FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair values of our financial instruments at December 31 arewere as follows (in thousands):
| 2009 | | | 2008 | |
| Carrying Amount | | | Fair Value | | | Carrying Amount | | | Fair Value | |
| | | | | | | | | | | |
Cash and cash equivalents | $ | 1,709 | | | $ | 1,709 | | | $ | 4 | | | $ | 4 | |
Derivative financial instruments – accrued liabilities | $ | 5 | | | $ | 5 | | | $ | - | | | $ | - | |
Long-term debt, including current maturities | $ | 329,069 | | | $ | 344,942 | | | $ | 151,209 | | | $ | 144,107 | |
| | | | | | | | | | | | |
| December 31, 2010 | December 31, 2009 |
| Carrying Value | Fair Value | Carrying Value | Fair Value |
| | | | |
Cash and cash equivalents | $ | 2,045 | | $ | 2,045 | | $ | 1,709 | | $ | 1,709 | |
Derivative financial instruments - Accrued liabilities | $ | — | | $ | — | | $ | 5 | | $ | 5 | |
Long-term debt, including current maturities | $ | 276,503 | | $ | 301,964 | | $ | 329,069 | | $ | 344,942 | |
The following methods and assumptions were used to estimate the fair value of each class of our financial instruments.
Cash and Cash Equivalents
The carrying amount approximates fair value due to the short maturity of these instruments.
Derivative Financial Instruments
These instruments are carried at fair value. Descriptions of the instruments we use are included in Note 4.5.
Long-Term Debt
The fair value of our long-term debt is estimated based on quoted market rates for debt instruments having similar maturities and similar debt ratings. Our outstanding first mortgage bonds are either currently not callable or are subject to make-whole provisions which would eliminate any economic benefits for us to call and refinance the first mortgage bonds.
Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands):
| 2009 | | | 2008 | | | 2007 | |
| | | | | | | | |
Current | $ | (3,296 | ) | | $ | (6,521 | ) | | $ | 8,704 | |
Deferred | | 11,600 | | | | 16,072 | | | | 3,864 | |
Total income tax expense | $ | 8,304 | | | $ | 9,551 | | | $ | 12,568 | |
| | | | | | | | | |
| December 31, 2010 | December 31, 2009 | December 31, 2008 |
| | | |
Current | $ | (14,885 | ) | $ | (3,296 | ) | $ | (6,521 | ) |
Deferred | 25,626 | | 11,600 | | 16,072 | |
Total income tax expense | $ | 10,741 | | $ | 8,304 | | $ | 9,551 | |
The temporary differences which gave rise to the net deferred tax liability were as follows (in thousands):
Years ended December 31, | 2009 | | | 2008 | | |
| | | December 31, 2010 | December 31, 2009 |
| | | | | | |
Deferred tax assets, current: | | | | | | |
Asset valuation reserve | $ | 90 | | | $ | 129 | | $ | 217 | | $ | 90 | |
Employee benefits | | 946 | | | | 932 | | 803 | | 946 | |
Rate refund | | 428 | | — | |
Other | | 2 | | | | - | | — | | 2 | |
Total deferred tax assets, current | | 1,038 | | | | 1,061 | | 1,448 | | 1,038 | |
| | | | | | | | |
Deferred tax liabilities, current: | | | | | | | | |
Prepaid expenses | | 214 | | | | 213 | | (251 | ) | (214 | ) |
Deferred costs | | 2,677 | | | | 1,580 | | (2,056 | ) | (2,677 | ) |
Total deferred tax liabilities, current | | 2,891 | | | | 1,793 | | (2,307 | ) | (2,891 | ) |
| | | | | | | | |
Net deferred tax liability, current | $ | 1,853 | | | $ | 732 | | |
Net deferred tax assets (liabilities), current | | $ | (859 | ) | $ | (1,853 | ) |
| | | | | | | | |
Deferred tax assets, non-current: | | | | | | | | |
Plant related differences | $ | 1,151 | | | $ | 1,151 | | $ | 909 | | $ | 1,151 | |
Regulatory liabilities | | 7,847 | | | | 10,156 | | 10,074 | | 7,847 | |
Employee benefits | | 3,468 | | | | 3,528 | | 3,547 | | 3,468 | |
Net operating loss | | 9,147 | | — | |
Items of other comprehensive income | | 175 | | | | 227 | | 225 | | 175 | |
Research and development credit | | 1,038 | | | | - | | 1,613 | | 1,038 | |
Other | | 128 | | | | 128 | | — | | 128 | |
Total deferred tax assets, non-current | | 13,807 | | | | 15,190 | | 25,515 | | 13,807 | |
| | | | | | | | |
Deferred tax liabilities, non-current: | | | | | | | | |
Accelerated depreciation and other plant related differences | | 93,253 | | | | 83,112 | | (132,338 | ) | (93,253 | ) |
AFUDC | | 4,926 | | | | 3,247 | | (6,168 | ) | (4,926 | ) |
Regulatory assets | | 10,011 | | | | 11,270 | | (5,557 | ) | (10,011 | ) |
Employee benefits | | 1,052 | | | | 2,237 | | (2,983 | ) | (1,052 | ) |
Other | | 772 | | | | 828 | | (788 | ) | (772 | ) |
Total deferred tax liabilities, non-current | | 110,014 | | | | 100,694 | | (147,834 | ) | (110,014 | ) |
| | | | | | | | |
Net deferred tax liability, non-current | $ | 96,207 | | | $ | 85,504 | | |
Net deferred tax assets (liabilities), non-current | | $ | (122,319 | ) | $ | (96,207 | ) |
| | | | | | | | |
Net deferred tax liability | $ | 98,060 | | | $ | 86,236 | | |
Net deferred tax assets (liabilities) | | $ | (123,178 | ) | $ | (98,060 | ) |
The following table reconciles the change in the net deferred income tax liabilityassets (liabilities) from December 31, 2009 to December 31, 2010 and from December 31, 2008 to December 31, 2009 to the deferred income tax expense (benefit) (in thousands):
| 2009 | | | 2008 | |
| | | | | |
Increase in deferred income tax liability from the preceding table | $ | 11,824 | | | $ | 16,457 | |
Deferred taxes related to regulatory assets and liabilities | | (1,323 | ) | | | (1,200 | ) |
Deferred taxes associated with other comprehensive income | | (73 | ) | | | 38 | |
Deferred taxes related to property basis differences | | 2,851 | | | | 767 | |
Deferred taxes related to AFUDC | | (1,679 | ) | | | - | |
Other | | - | | | | 10 | |
Deferred income tax expense for the period | $ | 11,600 | | | $ | 16,072 | |
| | | | | | |
| 2010 | 2009 |
| | |
Change in deferred income tax assets (liabilities) | $ | 25,118 | | $ | 11,824 | |
Deferred taxes related to regulatory assets and liabilities | 9,272 | | (1,323 | ) |
Deferred taxes associated with other comprehensive income | (2,141 | ) | (73 | ) |
Deferred taxes related to property basis differences | (4,713 | ) | 2,851 | |
Deferred taxes related to AFUDC | (1,910 | ) | (1,679 | ) |
Other | — | | — | |
Deferred income tax expense (benefit) for the period | $ | 25,626 | | $ | 11,600 | |
The effective tax rate differs from the federal statutory rate for the years ended, December 31, as follows:
| | 2009 | | | 2008 | | | 2007 | |
| | | | | | | | | |
Federal statutory rate | | | 35.0 | % | | | 35.0 | % | | | 35.0 | % |
Amortization of excess deferred and investment tax credits | | | (0.9 | ) | | | (0.7 | ) | | | (1.0 | ) |
Equity AFUDC | | | (6.2 | ) | | | (3.6 | ) | | | - | |
Other | | | (1.5 | ) | | | (1.1 | ) | | | (0.5 | ) |
| | | 26.4 | % | | | 29.6 | % | | | 33.5 | % |
| | | | | | |
| December 31, 2010 | December 31, 2009 | December 31, 2008 |
| | | |
Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % |
Amortization of excess deferred and investment tax credits | (0.6 | ) | (0.9 | ) | (0.7 | ) |
Equity AFUDC | (2.0 | ) | (6.2 | ) | (3.6 | ) |
Flow through adjustments * | (7.4 | ) | — | | — | |
Other | 0.6 | | (1.5 | ) | (1.1 | ) |
| 25.6 | % | 26.4 | % | 29.6 | % |
* The flow-through adjustments relate primarily to an accounting method change for tax purposes that was filed with the 2008 tax return and for which consent was received from the IRS in September 2009. The effect of the change allows us to take a current tax deduction for repair costs that were previously capitalized for tax purposes. These costs will continue to be capitalized for book purposes. We adoptedrecorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and we flowed the tax benefit through to our customers in the form of lower rates as a result of a rate case settlement that occurred during 2010. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. Due to this regulatory treatment, we recorded an income tax benefit that was attributable to the 2008 through 2010 tax years. For years prior to 2008, we did not record a regulatory asset for the repairs deduction as the tax benefit was not flowed through to customers.
The accounting standards for uncertain tax positions on January 1, 2007 which clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with accounting standards for income taxes. The accounting standards prescribe a recognition threshold and measurement attributes for the financial statement recognition and measurement of a tax position taken or expected to be taken. The impact of this implementation had no effect on our financial statements.
The following table reconciles the total amounts of unrecognized tax benefits at the beginning and end of the period (in thousands):
| 2009 | | | 2008 | |
| | | | | |
Unrecognized tax benefits at January 1 | $ | 767 | | | $ | - | |
Additions for prior year tax positions | | 3,110 | | | | - | |
Additions for current year tax positions | | - | | | | 767 | |
| | | | | | | |
Unrecognized tax benefits at December 31 | $ | 3,877 | | | $ | 767 | |
| | | | | | |
| 2010 | 2009 |
| | |
Unrecognized tax benefits at January 1 | $ | 3,877 | | $ | 767 | |
Additions for prior year tax positions | 130 | | 3,110 | |
Reductions for prior year tax positions | (913 | ) | — | |
| | |
Unrecognized tax benefits at December 31 | $ | 3,094 | | $ | 3,877 | |
The reduction for prior year tax positions relate to the reversal through otherwise allowed tax depreciation. The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $0.3$1.1 million.
It is our continuing practice to recognize interest and/or penalties related to income tax matters in income tax expense. During the year ended December 31, 2010 and 2009, the interest expense recognized related to income tax matters was not material to our financial results.
We fileThe Company files income tax returns in the United States federal jurisdiction. We dojurisdictionas a member of the BHC consolidated group. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of any audits or the expiration of statutes of limitations prior to December 31, 2010.2011.
At December 31, 2010, we have federal NOL carry forward of $26.1 million which will expire in 2030. Ultimate usage of this NOL depends upon our future taxable income.
(9) COMPREHENSIVE INCOME
The following tables display each component of Other Comprehensive Income (Loss), after-tax, and the related tax effects for the years ended December 31, (in thousands):
| 2009 | |
| | | | | | |
| Pre-tax Amount | | Tax (Expense) Benefit | | Net-of-tax Amount | |
| | | | | | | | | |
Pension liability adjustment | | $ | 150 | | | $ | (52 | ) | | $ | 98 | |
Reclassification adjustments of cash flow hedges settled and included in net income | | | 64 | | | | (24 | ) | | | 40 | |
Net change in fair value of derivatives designated as cash flow hedges | | | (5 | ) | | | 3 | | | | (2 | ) |
Other comprehensive income | | $ | 209 | | | $ | (73 | ) | | $ | 136 | |
| | | | | | | | | |
| December 31, 2010 |
| Pre-tax Amount | Tax (Expense) Benefit | Net-of-tax Amount |
| | | |
Minimum pension liability adjustment | $ | (145 | ) | $ | 51 | | $ | (94 | ) |
Reclassification adjustments of cash flow hedges settled and included in net income | 64 | | (23 | ) | 41 | |
Net change in fair value of derivatives designated as cash flow hedges | 6 | | (2 | ) | 4 | |
Other comprehensive loss | $ | (75 | ) | $ | 26 | | $ | (49 | ) |
| 2008 | |
| | | | | | |
| Pre-tax Amount | | Tax Benefit | | Net-of-tax Amount | |
| | | | | | | | | |
Pension liability adjustment | | $ | (4 | ) | | $ | 1 | | | $ | (3 | ) |
Reclassification adjustments of cash flow hedges settled and included in net income | | | (107 | ) | | | 38 | | | | (69 | ) |
Other comprehensive loss | | $ | (111 | ) | | $ | 39 | | | $ | (72 | ) |
| | | | | | | | | |
| December 31, 2009 |
| Pre-tax Amount | Tax (Expense) Benefit | Net-of-tax Amount |
| | | |
Minimum pension liability adjustment | $ | 150 | | $ | (52 | ) | $ | 98 | |
Reclassification adjustments of cash flow hedges settled and included in net income | 64 | | (24 | ) | 40 | |
Net change in fair value of derivatives designated as cash flow hedges | (5 | ) | 3 | | (2 | ) |
Other comprehensive income | $ | 209 | | $ | (73 | ) | $ | 136 | |
| 2007 | |
| | | | | | |
| Pre-tax Amount | | Tax (Expense) Benefit | | Net-of-tax Amount | |
| | | | | | | | | |
Pension liability adjustment | | $ | 115 | | | $ | (39 | ) | | $ | 76 | |
Reclassification adjustments of cash flow hedges settled and included in net income | | | 424 | | | | (148 | ) | | | 276 | |
Net change in fair value of derivatives designated as cash flow hedges | | | (1,069 | ) | | | 372 | | | | (697 | ) |
Other comprehensive loss | | $ | (530 | ) | | $ | 185 | | | $ | (345 | ) |
| | | | | | | | | |
| December 31, 2008 |
| Pre-tax Amount | Tax Benefit | Net-of-tax Amount |
| | | |
Minimum pension liability adjustment | $ | (4 | ) | $ | 1 | | $ | (3 | ) |
Reclassification adjustments of cash flow hedges settled and included in net income | (107 | ) | 38 | | (69 | ) |
Other comprehensive loss | $ | (111 | ) | $ | 39 | | $ | (72 | ) |
Balances by classification included within Accumulated other comprehensive loss on the accompanying Balance Sheets at December 31 arewere as follows (in thousands):
| 2009 | | | 2008 | |
| | | | | |
Derivatives designated as cash flow hedges | $ | (893 | ) | | $ | (932 | ) |
Employee benefit plans | | (320 | ) | | | (417 | ) |
Total accumulated other comprehensive loss | $ | (1,213 | ) | | $ | (1,349 | ) |
| | | | | | |
| December 31, 2010 | December 31, 2009 |
| | |
Derivatives designated as cash flow hedges | $ | (848 | ) | $ | (893 | ) |
Employee benefit plans | (414 | ) | (320 | ) |
Total accumulated other comprehensive loss | $ | (1,262 | ) | $ | (1,213 | ) |
(10) EMPLOYEE BENEFIT PLANS
(9) | EMPLOYEE BENEFIT PLANS |
Funded Status of Benefit Plans
The funded status of postretirement benefit plansplan is required to be recognized in the statement of financial position. The funded status for pension plansplan is measured as the difference between the projected benefit obligation and the fair value of plan assets. The funded status for all other benefit plans is measured as the difference between the accumulated benefit obligation and the fair value of plan assets. A liability is recorded for an amount by which the benefit obligation exceeds the fair value of plan assets or an asset is recorded for any amount by which the fair value of plan assets exceeds the benefit obligation.
We apply accounting standards for regulated operations, and accordingly, the unrecognized net periodic benefit cost that would have been reclassified to Accumulated other comprehensive income (loss) was alternatively recorded as a regulatory asset or regulatory liability, net of tax.
The measurement date of plans should be the date of our year-end balance sheet. We had used a September 30 measurement date. During 2008, we changed the measurement date to December 31. Therefore, $0.2$0.2 million, net of tax, was recognized as an adjustment to retained earnings.
Defined Benefit Pension Plan
We have a noncontributory defined benefit pension plan (Plan)("Pension Plan") covering the employees who meet certain eligibility requirements. The benefits are based on years of service and compensation levels during the highest five consecutive years of the last ten years of service. Our funding policy is in accordance with the federal government's funding requirements. The Pension Plan's assets are held in trust and consist primarily of equity and fixed income investments. We use a December 31 measurement date for the Pension Plan.
In July 2009, the Board of Directors approved a partial freeze to our Defined Benefitthe Pension Plan (withfor all participants with the exception of bargaining unit participants).participants. The freeze is effective January 1, 2010 and eliminateseliminated new non-bargaining unit employees from participation in the plan,Pension Plan and freezesfroze the benefits of current non-bargaining unit participants except for the following group: those non-bargaining unit participants who are both 1) are age 45 or older as of December 31, 2009 and have 10 years or more of credited service as of January 1, 2010; and 2) elect to continue to accrue additional benefits under the pension planPension Plan and consequently forego the additional age-age and points-based employer contribution under ourthe Company's 401(k) retirement savings plan. Plan assets and obligations were revalued July 31, 2009 in conjunction with the freeze, andAs a result of this action, we recognized a pre-tax curtailment expense of approximately $0.2 million in the third quarter of 2009.
In September of 2010, our bargaining unit employees voted to freeze participation in the Pension Plan and to freeze the benefits of current bargaining unit participants except for the following group: those bargaining unit participants who are both 1) age 45 or older as of December 31, 2010 and have 10 years or more of credited service as of January 1, 2011; and 2) elect to continue to accrue additional benefits under the Pension Plan and consequently forego the additional age and points-based employer contribution under the Company's 401(k) retirement savings plan. The change is effective January 1, 2011. As a result of this action, we recognized a pre-tax curtailment expense of less than $0.1 million that was recognized in the fourth quarter of 2010.
The Pension 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 Pension Plan portfolio. The expected long-term rate of return for each asset class is determined primarily from adjusted long-term historical returns for the asset class. It is anticipated that long-term future returns will not achieve historical results.
The expected long-term rate of return for equity investments was 9.5%9.25% and 9.50% for the 20092010 and 20082009 plan years.years, respectively. For determining the expected long-term rate of return for equity assets, we reviewed interest rate trends and annual 20-, 30-, 40-, and 50-year returns on the S&P 500 Index, which were, at December 31, 2009, 8.1%2010, 11.1%9.1%, 9.7%10.8%, 10.1% and 9.3%9.7%, respectively. Fund management fees were estimated to be 0.18% for S&P 500 Index assets and 0.45% for other assets. The expected long-term rate of return on fixed income investments was 6.0%5.75%; the return was based upon historical returns on 10-year treasury bonds of 6.9% from 1962 to 2009, and adjusted for recent declines in interest rates. The expected long-term rate of return on cash investments was estimated to be 1.0%, which was based upon current one-year LIBOR rates.
Pension Plan Assets
Percentage of fair value of Pension Plan assets at December 31:
| 2009 | 2008 |
| | |
Equity | 72% | 68% |
Fixed income | 25 | 28 |
Cash | 3 | 4 |
Total | 100% | 100% |
| | | | |
| 2010 | 2009 |
| | |
Equity | 68 | % | 72 | % |
Fixed income | 29 | | 25 | |
Cash | 3 | | 3 | |
Total | 100 | % | 100 | % |
The Investment Policy for the Pension Plans is to seek to achieve the following long-term objectives: 1) a rate of return in excess of the annualized inflation rate based on a five-year moving average; 2) a rate of return that meets or exceeds the assumed actuarial rate of return that meets or exceeds the assumed actuarial rate of return as stated in the Plan’sPlan's actuarial report; 3) a rate of return on investments, net of expenses, that is equal to or exceeds various benchmark rates on a moving three-year average, and 4) maintenance of sufficient income and liquidity to pay monthly retirement benefits. The policy strategy seeks to prudently invest in a diversified portfolio of predominately equity and fixed income assets.
The policy contains certain prohibitions on transactions in separately managed portfolios in which the Pension Plan may invest, including prohibitions on short sales.
Cash Flows
We made no contributions to the Plan in 2009 and expect no contributions to the Plan in 2010.
Supplemental Non-qualified Defined Benefit Retirement Plans
We have various supplemental retirement plans ("Supplemental Plans") for key executives. The Supplemental Plans are non-qualified defined benefit plans. We use a December 31 measurement date for the Supplemental Plans. Effective January 1, 2010, we eliminated a non-qualified pension plan in which some of our officers participated due to the partial freeze of our qualified pension plans.plan. We also amended the NQDC, which was adopted in 1999. The NQDC is a non-qualified deferred compensation plan that provides executives with an opportunity to elect to defer compensation and receive benefits without reference to the limitations on contributions in the Plan or those imposed by the IRS. The amended NQDC provides for non-elective non-qualified restoration benefits to certain officers who are not eligible to continue accruing benefits under the Defined Benefit Pension Plans and associated non-qualified pension restoration plans. All contributions to the non-qualified plans are subject to a graded vesting schedule of 20% per year over five years with vesting credit beginning with service in the Plan on and after January 1, 2010.
Supplemental Plan Assets
The Plan hasSupplemental Plans have no assets. We fund on a cash basis as benefits are paid.
The estimated employer contribution is expected to be $0.1 million in 2010. Contributions are expected to be made in the form of benefit payments.
Non-pension Defined Benefit Postretirement Plan
Employees who are participants in our Non-Pension Postretirement Healthcare Plan ("Healthcare Plan") and who retire on or after attaining age 55 after completing at least five years of service are entitled to postretirement healthcare benefits. These benefits are subject to premiums, deductibles, co-payment provisions and other limitations. We may amend or change the Healthcare Plan periodically. We are not pre-funding our retiree medical plan. We use a December 31measurement date for the Healthcare Plan. In July 2009, the Board of Directors approved a freezean amendment to the Healthcare Plan which changed the structure of the Healthcare Plan for non-union employees to a Retiree Medical Savings Account structure and expanded eligibility of Plan participants,RMSA structure. This change was effective January 1, 2010.
In September 2010, the bargaining unit employees voted to change the structure of their benefits to an RMSA. This change is effective January 1, 2011. It has been determined that the Healthcare Plan's post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy. The effect of the Medicare Part D subsidy on the accumulated postretirement benefit obligation for the fiscal year ending December 31, 2009, was an actuarial gain of approximately $0.9 million. The effect on 2009 net periodic postretirement benefit cost was a decrease of approximately $0.1 million.
Plan Assets
The Healthcare Plan has no assets. We fund on a cash basis as benefits are paid.
Plan Contributions and Estimated Cash Flows
The estimated employer contributions are expectedContributions made to be $0.4 million in 2010. Contributionsthe Supplemental Non-qualified Defined Benefit Retirement Plans and the Non-pension Defined Benefit Postretirement Plan are expected to be made in the form of benefit payments. Contributions to each of the plans were as follows (in thousands):
| | | | | | |
| 2010 | 2009 |
Defined Benefit Plans | | |
Defined Benefit Pension Plan | $ | 8,798 | | $ | — | |
Non-pension Defined Benefit Postretirement Healthcare Plan | $ | 657 | | $ | 578 | |
Supplemental Non-Qualified Defined Benefit Plan | $ | 108 | | $ | 89 | |
| | |
Defined Contribution Plans | | |
Company Retirement Contribution | $ | 171 | | $ | — | |
Matching contributions | $ | 1,029 | | $ | 712 | |
Contributions to our employee benefit plans to be made in 2011 are as follows (in thousands):
| | | |
| 2011 |
Defined Benefit Plans | |
Defined Benefit Pension Plan | $ | — | |
Non-Pension Defined Benefit Postretirement Healthcare Plan | $ | 503 | |
Supplemental Non-Qualified Defined Benefit Plan | $ | 108 | |
Fair Value Measurements
Accounting standards for fair value measurements provide a single definition of fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and also requires disclosures and establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The fair value hierarchy ranks the quality and reliability of the information used to determine fair values giving the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). The pension plan is able to classify fair value balances based on the observability of inputs.
Financial assets and liabilities carried at fair value are classified and disclosed in one of the following three categories:
Level 1 – - Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities.
Level 2 – - Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means.
Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources.
As required by accounting standards for fair value measurements, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect their placement within the fair value hierarchy levels. The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis as of December 31 2009 and 2008 (in thousands):
| Defined Benefit Pension Plan | At Fair Value as of December 31, 2009 | | December 31, 2010 |
Recurring Fair Value Measures | Level 1 | | | Level 2 | | | Level 3 | | | Total | | Level 1 | Level 2 | Level 3 | Total Fair Value |
| | | | | | | | | | | | |
Registered Investment Companies | $ | 22,632 | | | $ | - | | | $ | - | | | $ | 22,632 | | $ | 28,042 | | $ | — | | $ | — | | $ | 28,042 | |
Common Collective Trust | | - | | | | 16,408 | | | | - | | | | 16,408 | | — | | 19,104 | | — | | 19,104 | |
Insurance contracts | | — | | 1,082 | | — | | 1,082 | |
Total investments measured at fair value | $ | 22,632 | | | $ | 16,408 | | | $ | - | | | $ | 39,040 | | $ | 28,042 | | $ | 20,186 | | $ | — | | $ | 48,228 | |
Defined Benefit Pension Plan | At Fair Value as of December 31, 2008 | |
Recurring Fair Value Measures | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | | | | | | | | | | |
Registered Investment Companies | $ | 17,976 | | | $ | - | | | $ | - | | | $ | 17,976 | |
Common Collective Trust | | - | | | | 14,124 | | | | - | | | | 14,124 | |
Total investments measured at fair value | $ | 17,976 | | | $ | 14,124 | | | $ | - | | | $ | 32,100 | |
| | | | | | | | | | | | |
Defined Benefit Pension Plan | December 31, 2009 |
Recurring Fair Value Measures | Level 1 | Level 2 | Level 3 | Total Fair Value |
| | | | |
Registered Investment Companies | $ | 22,632 | | $ | — | | $ | — | | $ | 22,632 | |
Common Collective Trust | — | | 16,408 | | — | | 16,408 | |
Total investments measured at fair value | $ | 22,632 | | $ | 16,408 | | $ | — | | $ | 39,040 | |
Plan Reconciliations
The following tables provide a reconciliation of the Employee Benefit Plan's obligations and fair value of assets, for 2009 and 2008, components of the net periodic expense for the years ended 2009, 2008 and 2007 and elements of regulatory assets and liabilities and AOCI for 2009 and 2008 (in thousands):
Benefit Obligations
| | Defined Benefit Pension Plans | | | Supplemental Nonqualified Defined Benefit Retirement Plans | | | Non-pension Defined Benefit Postretirement Plans | |
| | 2009 | | | 2008 | | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Change in benefit obligation: | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
Projected benefit obligation at beginning of year | | $ | 51,965 | | | $ | 48,937 | | | $ | 1,672 | | | $ | 1,958 | | | $ | 7,393 | | | $ | 6,649 | |
Service cost | | | 1,155 | | | | 1,396 | | | | - | | | | - | | | | 216 | | | | 264 | |
Interest cost | | | 3,143 | | | | 3,790 | | | | 100 | | | | 150 | | | | 444 | | | | 522 | |
Actuarial loss | | | 1,686 | | | | 2,712 | | | | 7 | | | | 65 | | | | 3,474 | | | | 506 | |
Amendments | | | 100 | | | | - | | | | - | | | | - | | | | (1,960 | ) | | | - | |
Discount rate change | | | 1,047 | | | | - | | | | - | | | | - | | | | - | | | | - | |
Benefits paid | | | (2,312 | ) | | | (2,838 | ) | | | (89 | ) | | | (142 | ) | | | (579 | ) | | | (830 | ) |
Asset transfer to affiliate | | | (121 | ) | | | (2,032 | ) | | | - | | | | (359 | ) | | | (23 | ) | | | (297 | ) |
Plan curtailment reduction | | | (1,048 | ) | | | - | | | | - | | | | - | | | | - | | | | - | |
Medicare Part D adjustment | | | - | | | | - | | | | - | | | | - | | | | 46 | | | | 71 | |
Plan participant's contributions | | | - | | | | - | | | | - | | | | - | | | | 421 | | | | 508 | |
Net increase (decrease) | | | 3,650 | | | | 3,028 | | | | 18 | | | | (286 | ) | | | 2,039 | | | | 744 | |
Projected benefit obligation at end of year | | $ | 55,615 | | | $ | 51,965 | | | $ | 1,690 | | | $ | 1,672 | | | $ | 9,432 | | | $ | 7,393 | |
| | | | | | | | | | | | | | | | | | |
| Defined Benefit Pension Plans | Supplemental Nonqualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Plans |
| 2010 | 2009 | 2010 | 2009 | 2010 | 2009 |
Change in benefit obligation: | | | | | | |
| | | | | | |
Projected benefit obligation at beginning of year | $ | 55,615 | | $ | 51,965 | | $ | 1,690 | | $ | 1,672 | | $ | 9,432 | | $ | 7,393 | |
Service cost | 1,215 | | 1,155 | | — | | — | | 340 | | 216 | |
Interest cost | 3,280 | | 3,143 | | 100 | | 100 | | 547 | | 444 | |
Actuarial loss (gain) | 4,129 | | 1,686 | | 54 | | 7 | | (88 | ) | 3,474 | |
Amendments | 260 | | 100 | | — | | — | | (2,270 | ) | (1,960 | ) |
Discount rate change | — | | 1,047 | | — | | — | | — | | — | |
Benefits paid | (2,472 | ) | (2,312 | ) | (109 | ) | (89 | ) | (658 | ) | (579 | ) |
Asset transfer (to) from affiliate | (3,300 | ) | (121 | ) | 417 | | — | | (328 | ) | (23 | ) |
Plan curtailment reduction | (974 | ) | (1,048 | ) | — | | — | | — | | — | |
Medicare Part D adjustment | — | | — | | — | | — | | 88 | | 46 | |
Plan participants' contributions | — | | — | | — | | — | | 454 | | 421 | |
Net increase (decrease) | 2,138 | | 3,650 | | 462 | | 18 | | (1,915 | ) | 2,039 | |
Projected benefit obligation at end of year | $ | 57,753 | | $ | 55,615 | | $ | 2,152 | | $ | 1,690 | | $ | 7,517 | | $ | 9,432 | |
A reconciliation of the fair value of Plan assets (as of the December 31 measurement date) is as follows (in thousands):
| | Defined Benefit Pension Plans | | | Supplemental Nonqualified Defined Benefit Retirement Plans | | | Non-pension Defined Benefit Postretirement Plans | |
| | 2009 | | | 2008 | | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
| | | | | | | | | | | | | | | | | | |
Beginning market value of plan assets | | $ | 32,100 | | | $ | 52,466 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
Investment income (loss) | | | 9,337 | | | | (8,771 | ) | | | - | | | | - | | | | - | | | | - | |
Benefits paid | | | (2,312 | ) | | | (2,249 | ) | | | - | | | | - | | | | - | | | | - | |
Asset transfer to affiliate | | | (85 | ) | | | - | | | | - | | | | - | | | | - | | | | - | |
Ending market value of plan assets | | $ | 39,040 | | | $ | 41,446 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| | | | | | | | | | | | | | | | | | |
| Defined Benefit Pension Plans | Supplemental Nonqualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Plans |
| 2010 | 2009 | 2010 | 2009 | 2010 | 2009 |
| | | | | | |
Beginning market value of plan assets | $ | 39,040 | | $ | 32,100 | | $ | — | | $ | — | | $ | — | | $ | — | |
Investment income | 5,361 | | 9,337 | | — | | — | | — | | — | |
Benefits paid | (2,472 | ) | (2,312 | ) | — | | — | | — | | — | |
Employer contributions | 8,798 | | — | | — | | — | | — | | — | |
Asset transfer to affiliate | (2,499 | ) | (85 | ) | — | | — | | — | | — | |
Ending market value of plan assets | $ | 48,228 | | $ | 39,040 | | $ | — | | $ | — | | $ | — | | $ | — | |
Amounts recognized in the statement of financial position consist of (in thousands):
| | Defined Benefit Pension Plans | | | Supplemental Nonqualified Defined Benefit Retirement Plans | | | Non-pension Defined Benefit Postretirement Plans | |
| | 2009 | | | 2008 | | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
| | | | | | | | | | | | | | | | | | |
Regulatory asset (liability) | | $ | 19,580 | | | $ | 26,256 | | | $ | - | | | $ | - | | | $ | 1,443 | | | $ | (11 | ) |
Current liability | | $ | - | | | $ | - | | | $ | 98 | | | $ | 109 | | | $ | 325 | | | $ | 223 | |
Non-current liability | | $ | (16,576 | ) | | $ | (19,864 | ) | | $ | (1,592 | ) | | $ | (1,564 | ) | | $ | (9,110 | ) | | $ | (7,169 | ) |
| | | | | | | | | | | | | | | | | | |
| Defined Benefit Pension Plans | Supplemental Nonqualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Plans |
| 2010 | 2009 | 2010 | 2009 | 2010 | 2009 |
| | | | | | |
Regulatory asset (liability) | $ | 18,049 | | $ | 19,580 | | $ | — | | $ | — | | $ | (1,050 | ) | $ | 1,443 | |
Current (liability) | $ | — | | $ | — | | $ | (141 | ) | $ | (98 | ) | $ | (428 | ) | $ | (325 | ) |
Non-current (liability) | $ | (9,525 | ) | $ | (16,576 | ) | $ | (2,011 | ) | $ | (1,592 | ) | $ | (7,096 | ) | $ | (9,110 | ) |
Accumulated Benefit Obligation
| Defined Benefit Pension Plans | | Supplemental Nonqualified Defined Benefit Retirement Plans | | Non-pension Defined Benefit Postretirement Plans | |
| 2009 | | 2008 | | 2009 | | 2008 | | 2009 | | 2008 | |
| | | | | | | | | | | | | | | | | | |
Accumulated benefit obligation | | $ | 47,745 | | | $ | 43,894 | | | $ | 1,645 | | | $ | 1,622 | | | $ | 9,432 | | | $ | 7,393 | |
| | | | | | | | | | | | | | | | | | |
| Defined Benefit Pension Plans | Supplemental Nonqualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Plans |
| 2010 | 2009 | 2010 | 2009 | 2010 | 2009 |
| | | | | | |
Accumulated benefit obligation | $ | 52,250 | | $ | 47,745 | | $ | 2,058 | | $ | 1,645 | | $ | 7,517 | | $ | 9,432 | |
Components of Net Periodic Expense
| | Defined Benefit Pension Plans | | | Supplemental Nonqualified Defined Benefit Retirement Plans | | | Non-pension Defined Benefit Postretirement Plans | |
| | 2009 | | | 2008 | | | 2007 | | | 2009 | | | 2008 | | | 2007 | | | 2009 | | | 2008 | | | 2007 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
Service cost | | $ | 1,155 | | | $ | 1,117 | | | $ | 1,137 | | | $ | - | | | $ | - | | | $ | - | | | $ | 216 | | | $ | 211 | | | $ | 211 | |
Interest cost | | | 3,143 | | | | 3,032 | | | | 2,923 | | | | 100 | | | | 120 | | | | 116 | | | | 444 | | | | 417 | | | | 398 | |
Expected return on assets | | | (2,780 | ) | | | (4,374 | ) | | | (3,885 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
Amortization of prior service cost | | | 87 | | | | 112 | | | | 103 | | | | - | | | | 1 | | | | 1 | | | | - | | | | - | | | | - | |
Amortization of transition obligation | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 51 | | | | 51 | | | | 51 | |
Recognized net actuarial loss (gain) | | | 1,586 | | | | - | | | | 408 | | | | 43 | | | | 44 | | | | 57 | | | | - | | | | (1 | ) | | | - | |
Curtailment expense | | | 189 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
Net periodic expense | | $ | 3,380 | | | $ | (113 | ) | | $ | 686 | | | $ | 143 | | | $ | 165 | | | $ | 174 | | | $ | 711 | | | $ | 678 | | | $ | 660 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Defined Benefit Pension Plans | Supplemental Nonqualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Plans |
| 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 |
| | | | | | | | | |
Service cost | $ | 1,214 | | $ | 1,155 | | $ | 1,117 | | $ | — | | $ | — | | $ | — | | $ | 340 | | $ | 216 | | $ | 211 | |
Interest cost | 3,280 | | 3,143 | | 3,032 | | 100 | | 100 | | 120 | | 547 | | 444 | | 417 | |
Expected return on assets | (3,008 | ) | (2,780 | ) | (4,374 | ) | — | | — | | — | | — | | — | | — | |
Amortization of prior service cost | 62 | | 87 | | 112 | | — | | — | | 1 | | (141 | ) | — | | — | |
Amortization of transition obligation | — | | — | | — | | — | | — | | — | | 171 | | 51 | | 51 | |
Recognized net actuarial loss (gain) | 1,378 | | 1,586 | | — | | 30 | | 43 | | 44 | | — | | — | | (1 | ) |
Curtailment expense | 57 | | 189 | | — | | — | | — | | — | | — | | — | | — | |
Net periodic expense | $ | 2,983 | | $ | 3,380 | | $ | (113 | ) | $ | 130 | | $ | 143 | | $ | 165 | | $ | 917 | | $ | 711 | | $ | 678 | |
47
Accumulated Other Comprehensive Income (Loss)
Amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 arewere as follows (in thousands):
| Defined Benefit Pension Plans | | Supplemental Nonqualified Defined Benefit Retirement Plans | | Non-pension Defined Benefit Postretirement Plans | |
| 2009 | | 2008 | | 2009 | | 2008 | | 2009 | | 2008 | |
| | |
Net loss | | $ | - | | | $ | - | | | $ | (324 | ) | | $ | (347 | ) | | $ | - | | | $ | - | |
Prior service cost | | | - | | | | - | | | | - | | | | (1 | ) | | | - | | | | - | |
Transition obligation | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
| | $ | - | | | $ | - | | | $ | (324 | ) | | $ | (348 | ) | | $ | - | | | $ | - | |
| | | | | | | | | | | | | | | | | | |
| Defined Benefit Pension Plans | Supplemental Nonqualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Plans |
| 2010 | 2009 | 2010 | 2009 | 2010 | 2009 |
| |
Net loss | $ | — | | $ | — | | $ | (418 | ) | $ | (324 | ) | $ | — | | $ | — | |
Prior service cost | — | | — | | — | | — | | — | | — | |
Transition obligation | — | | — | | — | | — | | — | | — | |
| $ | — | | $ | — | | $ | (418 | ) | $ | (324 | ) | $ | — | | $ | — | |
The amounts in AOCI, regulatory assets or regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2010 are2011 were as follows (in thousands):
| Defined Benefits Pension Plans | | | Supplemental Nonqualified Defined Benefit Retirement Plans | | | Non-pension Defined Benefit Postretirement Plans | |
| | | | | | | | |
Net loss | $ | 895 | | | $ | 20 | | | $ | 111 | |
Prior service cost | | 41 | | | | - | | | | (91 | ) |
Transition obligation | | - | | | | - | | | | - | |
Total net periodic benefit cost expected to be recognized during calendar year 2010 | $ | 936 | | | $ | 20 | | | $ | 20 | |
| | | | | | | | | |
| Defined Benefits Pension Plans | Supplemental Nonqualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Plans |
| | | |
Net loss | $ | 966 | | $ | 31 | | $ | 106 | |
Prior service cost | 40 | | — | | (204 | ) |
Transition obligation | — | | — | | — | |
Total net periodic benefit cost expected to be recognized during calendar year 2011 | $ | 1,006 | | $ | 31 | | $ | (98 | ) |
Assumptions
| | | | | | | | | | | | | | | | | | |
| Defined Benefit Pension Plans | Supplemental Nonqualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Plans |
| 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 |
Weighted-average assumptions used to determine benefit obligations: | | | | | | | | | |
Discount rate | 5.50 | % | 6.05 | % | 6.20 | % | 5.50 | % | 6.10 | % | 6.20 | % | 5.00 | % | 5.90 | % | 6.10 | % |
Rate of increase in compensation levels | 3.70 | % | 4.25 | % | 4.25 | % | 5.00 | % | 5.00 | % | 5.00 | % | N/A | N/A | N/A |
| | | | | | | | | |
Weighted-average assumptions used to determine net periodic benefit cost for plan year: | | | | | | | | | |
Discount rate | 6.05 | % | 6.25 | % | 6.35 | % | 6.10 | % | 6.20 | % | 6.35 | % | 5.90 | % | 6.10 | % | 6.35 | % |
Expected long-term rate of return on assets* | 8.00 | % | 8.50 | % | 8.50 | % | N/A | N/A | N/A | N/A | N/A | N/A |
Rate of increase in compensation levels | 4.25 | % | 4.25 | % | 4.34 | % | 5.00 | % | 5.00 | % | N/A | N/A | N/A | N/A |
_____________________________
* The expected rate of return on plan assets changed to 7.75% for the calculation of the 2011 net periodic pension cost.
Assumptions
| Defined Benefit Pension Plans | Supplemental Nonqualified Defined Benefit Retirement Plans | Non-pension Defined Benefit Postretirement Plans |
| | | |
Weighted-average assumptions used to determine benefit obligations: | 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | 2009 | 2008 | 2007 |
| | | | | | | | | |
Discount rate | 6.05% | 6.20% | 6.35% | 6.10% | 6.20% | 6.35% | 5.90% | 6.10% | 6.35% |
Rate of increase in compensation levels | 4.25% | 4.25% | 4.34% | 5.00% | 5.00% | 5.00% | N/A | N/A | N/A |
| | | | | | | | | |
Weighted-average assumptions used to determine net periodic benefit cost for plan year: | 2009 | 2008 | 2007 | 2009 | 2008 | 2007 | 2009 | 2008 | 2007 |
| | | | | | | | | |
Discount rate | 6.25% | 6.35% | 5.95% | 6.20% | 6.35% | 5.95% | 6.10% | 6.35% | 5.95% |
Expected long-term rate of return on assets* | 8.50% | 8.50% | 8.50% | N/A | N/A | N/A | N/A | N/A | N/A |
Rate of increase in compensation levels | 4.25% | 4.34% | 4.31% | 5.00% | N/A | 5.00% | N/A | N/A | N/A |
_____________________________
* | The expected rate of return on plan assets changed to 8.00% for the calculation of the 2010 net periodic pension cost. |
The healthcare costbenefit obligation was determined at December 31, 2010, using an initial healthcare trend rate assumption for 2009 fiscal year benefit obligation determination and 2010 fiscal year expense is a 10% increase for 2009of 9.5% grading down until ato an ultimate rate of 4.5% ultimatein 2027, and at December 31, 2009, using an initial healthcare trend rate is reachedof 10.0% trending down to an ultimate rate of 4.5% in fiscal year 2027. The healthcare cost trend rate assumption for the 2008 fiscal year benefit obligation determination and 2009 fiscal year expense was a 9% increase for 2009 grading down 1% per year until a 5% ultimate trend rate is reached in fiscal year 2013.
The healthcare cost trend rate assumption has a significant effect on the amounts reported. A 1% increase or 1% decrease in the healthcare cost trend assumptionassumptions would increaseaffect the service and interest cost $0.1 million or 22%costs and the accumulated periodic postretirement benefit obligation $1.3 million or 14%. A 1% decrease would reduce the service and interest cost by $0.1 million or 17% and the accumulated periodic postretirement benefit obligation $1.0 million or 11%.as follows (dollars in thousands):
| | | | | | | | | | |
| Service and Interest Costs | Accumulated Periodic Postretirement Benefit Obligation |
| Dollars | Percent | Dollars | Percent |
1% increase | $ | 147 | | 17 | % | $ | 426 | | 6 | % |
1% (decrease) | $ | (114 | ) | (13 | )% | $ | (375 | ) | (5 | )% |
The following benefit payments, which reflect future service, are expected to be paid (in thousands):
| | | | | | | Non-pension Defined Benefit Postretirement Plans | |
| Defined Benefit Pension Plans | | | Supplemental Nonqualified Defined Benefit Retirement Plan | | | Expected Gross Benefit Payments | | | Expected Medicare Part D Drug Benefit Subsidy | | | Expected Net Benefit Payments | |
| | | | | | | | | | | | | | |
2010 | $ | 2,584 | | | $ | 98 | | | $ | 405 | | | $ | (80 | ) | | $ | 325 | |
2011 | | 2,743 | | | | 112 | | | | 486 | | | | (86 | ) | | | 400 | |
2012 | | 2,833 | | | | 94 | | | | 544 | | | | (94 | ) | | | 450 | |
2013 | | 2,975 | | | | 77 | | | | 585 | | | | (101 | ) | | | 484 | |
2014 | | 3,152 | | | | 93 | | | | 628 | | | | (107 | ) | | | 521 | |
2015-2019 | | 18,086 | | | | 557 | | | | 3,683 | | | | (624 | ) | | | 3,059 | |
| | | | | | | | | | | | | | | |
| | | Non-pension Defined Benefit Postretirement Plans |
| Defined Benefit Pension Plans | Supplemental Nonqualified Defined Benefit Retirement Plan | Expected Gross Benefit Payments | Expected Medicare Part D Drug Benefit Subsidy | Expected Net Benefit Payments |
| | | | | |
2011 | $ | 2,817 | | $ | 141 | | $ | 503 | | $ | (75 | ) | $ | 428 | |
2012 | $ | 2,907 | | $ | 122 | | $ | 600 | | $ | (82 | ) | $ | 518 | |
2013 | $ | 3,016 | | $ | 102 | | $ | 652 | | $ | (87 | ) | $ | 565 | |
2014 | $ | 3,148 | | $ | 103 | | $ | 699 | | $ | (91 | ) | $ | 608 | |
2015 | $ | 3,224 | | $ | 91 | | $ | 723 | | $ | (95 | ) | $ | 628 | |
2016-2020 | $ | 18,167 | | $ | 583 | | $ | 4,266 | | $ | (500 | ) | $ | 3,766 | |
Defined Contribution Plan
The Parent sponsors a 401(k) retirement savings plan in which employees may participate. Participants may elect to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis, up to a maximum amount established by the Internal Revenue Service. We provide aThe plan provides for company matching contribution of 100% of the employee's annual contribution up to a maximum of 3% of eligible compensation. Matchingcontributions and company retirement contributions. Employer contributions vest at 20% per year and are fully vested when the participant has 5 years of service. Our matching contributions were $0.7 million for 2009, $0.7 million for 2008 and $0.6 million for 2007.
(11) RELATED-PARTY TRANSACTIONS
Effective January 1, 2010 in conjunction with the partial freeze of our defined benefit pension plan, we amended our 401(k) Retirement Savings Plan. This freeze covers all employees with the exception of the bargaining unit employees and certain other employees grandfathered under a prior defined benefit plan election. The amendment provides for a matching contribution of 100% of the eligible employee's annual contribution up to a maximum of 6% of eligible compensation. The amendment also provides certain eligible participants an age and service-based employer contribution.
(10) | RELATED-PARTY TRANSACTIONS |
Receivables and Payables
We have accounts receivable balances related to transactions with other BHC subsidiaries. The balances were $4.1 million and $12.6 million as of December 31, 2009 and 2008, respectively. We also have accounts payable balances related to transactions with other BHC subsidiaries. TheThese balances were $10.0 million and $10.4 million as of December 31, 2009 and 2008, respectively.were as follows (in thousands):
| | | | | | |
| 2010 | 2009 |
Related party receivables | $ | 6,891 | | $ | 4,146 | |
Related party payables | $ | 12,562 | | $ | 10,030 | |
Money Pool Notes Receivable and Notes Payable
We have a Utility Money Pool Agreement with the Parent, Cheyenne Light and Black Hills Utility Holdings. Under the agreement, we may borrow from the Parent. The Agreement restricts us from loaning funds to the Parent or to any of the Parent's non-utility subsidiaries; the Agreement does not restrict us from making dividends to the Parent. Borrowings under the agreement bear interest at 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 LIBOR rate plus 100 basis points.
Through the Utility Money Pool, we have a net note receivable balance to the Parent of $57.7 million as of December 31, 2009 and a net note payable balance of $70.2 million as of December 31, 2008. Advances under this note bear interest at 0.70%2.75% above the daily LIBOR rate (0.93%(3.01% at December 31, 2009)2010). Net interest expenseWe had the following balances with the Utility Money Pool as of $1.1 million and $0.9 million was recorded for the years ended December 31 2009 and 2008, respectively. During 2007, we had a note receivable of $10.3 million for which we received $0.9 million of interest income.(in thousands):
| | | | | | | | | |
| 2010 | 2009 | 2008 |
| | | |
Notes receivable (payable) with Utility Money Pool, net | $ | 39,862 | | $ | 57,737 | | $ | (70,184 | ) |
| | | |
Net interest revenue (expense) | $ | 467 | | $ | (1,123 | ) | $ | (865 | ) |
Other Balances and Transactions
We received revenues of approximately $0.9 million, $1.2 million and $1.9 millionhad the following related party transactions for the years ended December 31, 2009, 20082010 and 2007, respectively, from Black Hills Wyoming, Inc. for the transmission of electricity.
We received revenues of approximately $1.8 million and $2.8 million for the years ended December 31, 2009 and 2008, respectively, from Cheyenne Light for the sale of electricity and dispatch services.
We recorded revenues of $0.2 million and $1.4 million for the years ending December 31, 2008 and 2007, respectively, relating to payments received pursuant to a natural gas swap entered into with Enserco.
We purchase coal from WRDC. The amount purchased during the years ended December 31, 2009, 2008 and 2007 was $16.3 million, $15.5 million and $12.6 million, respectively. These amounts are included in Fuel and purchased power onthe corresponding captions in the accompanying Statements of Income.Income:
| |
• | We received revenues from Black Hills Wyoming, Inc. for the transmission of electricity. |
| |
• | We received revenues from Cheyenne Light for the sale of electricity and dispatch services. |
| |
• | We recorded revenues relating to payments received pursuant to a natural gas swap entered into with Enserco. |
| |
• | We purchase coal from WRDC. These amounts are included in Fuel and purchased power on the accompanying Statements of Income. |
| |
• | We purchase excess power generated by Cheyenne Light. |
| |
• | In order to fuel our combustion turbine, we purchase natural gas from Enserco. These amounts are included in Fuel and purchased power on the accompanying Statements of Income. |
| |
• | In addition, we also pay the Parent for allocated corporate support service costs incurred on our behalf. |
| |
• | We have two contracts with Cheyenne Light under which Cheyenne Light sells up to 40 MW of wind-generated, renewable energy to us. |
We purchase excess power generated by Cheyenne Light. The amount purchased during the years ended December 31, 2009 and 2008 was $8.6 million and $6.4 million, respectively. | | | | | | | | | |
| 2010 | 2009 | 2008 |
| (in thousands) |
Revenues: | | | |
Black Hills Wyoming for transmission of electricity | $ | 1,378 | | $ | 873 | | $ | 1,245 | |
Cheyenne Light for electricity and dispatch services | $ | 1,200 | | $ | 1,823 | | $ | 2,778 | |
Natural gas swaps from Enserco | $ | — | | $ | — | | $ | 200 | |
| | | |
Purchases: | | | |
Coal purchases from WRDC | $ | 13,569 | | $ | 16,284 | | $ | 15,469 | |
Excess power purchased from Cheyenne Light | $ | 8,664 | | $ | 8,580 | | $ | 6,387 | |
Natural gas from Enserco | $ | 1,652 | | $ | 2,250 | | $ | 8,049 | |
Corporate support services from Parent | $ | 17,145 | | $ | 15,014 | | $ | 12,391 | |
Renewable wind energy from Cheyenne Light | $ | 4,538 | | $ | 2,791 | | $ | 628 | |
In order to fuel our combustion turbine, we purchase natural gas from Enserco. The amount purchased during the years ended December 31, 2009, 2008 and 2007 was approximately $2.3 million, $8.0 million and $4.5 million, respectively. These amounts are included in Fuel and purchased power on the accompanying Statements of Income.
In addition, we also pay the Parent for allocated corporate support service cost incurred on our behalf. Corporate costs allocated from the Parent were $15.0 million, $12.4 million and $11.3 million for the years ended December 31, 2009, 2008 and 2007, respectively.
We have funds on deposit from Black Hills Wyoming for transmission system reserve in the amount of $2.0 million and $1.9 million at December 31, 2009 and 2008, respectively, which isare included in Deferred credits and otherOther, non-current liabilities Other on the accompanying Balance Sheets. We have transmission system reserve balances as follows as of December 31 (in thousands):
| | | | | | |
| 2010 | 2009 |
Deferred credits and other liabilities | $ | 2,044 | | $ | 1,978 | |
Interest on the transmission system reserve deposit accrues quarterly at an average prime rate (3.25% at December 31, 2009)2010). We paid interest expense of $0.1 million for each of the years ended December 31 2009, 2008 and 2007, respectively.as follows (in thousands):
We have two contracts with Cheyenne Light under which Cheyenne Light sells up to 40 MW of wind-generated, renewable energy to us. Purchases from these agreements during 2009 were $2.8 million and $0.6 million in 2008.
| | | | | | | | | |
| 2010 | 2009 | 2008 |
Interest expense | $ | 65 | | $ | 70 | | $ | 114 | |
(12) SUPPLEMENTAL CASH FLOW INFORMATION
| | | | | | | | | |
Years ended December 31, | 2010 | 2009 | 2008 |
| (in thousands) |
Non-cash investing activities - | | | |
Property, plant and equipment financed with accrued liabilities | $ | 7,188 | | $ | 10,191 | | $ | 13,294 | |
Money pool activity - net repayment of funds loaned | $ | — | | $ | 25,000 | | $ | — | |
Non-cash financing activities - | | | |
Money pool activity - net repayment of funds borrowed | $ | — | | $ | (25,000 | ) | $ | — | |
| | | |
Supplemental disclosure of cash flow information: | | | |
Cash (paid) refunded during the period for - | | | |
Interest (net of amounts capitalized) | $ | (19,554 | ) | $ | (14,252 | ) | $ | (11,578 | ) |
Income taxes | $ | 15,805 | | $ | 3,700 | | $ | 5,877 | |
(13) COMMITMENTS AND CONTINGENCIES
(11) | SUPPLEMENTAL CASH FLOWS INFORMATION |
Years ended December 31, | 2009 | | | 2008 | | | 2007 | |
| (in thousands) | |
Non-cash investing and financing activities - | | | | | | | | |
Property, plant and equipment financed with accrued liabilities | $ | 10,191 | | | $ | 13,294 | | | $ | 1,323 | |
Distribution to Parent | $ | 225,000 | | | $ | - | | | $ | - | |
Borrowing from Parent | $ | 200,000 | | | $ | - | | | $ | - | |
| | | | | | | | | | | |
Supplemental disclosure of cash flow information: | | | | | | | | | | | |
Cash paid during the period for - | | | | | | | | | | | |
Interest (net of amounts capitalized) | $ | 14,252 | | | $ | 11,578 | | | $ | 11,782 | |
Income taxes (refunded) paid | $ | (3,700 | ) | | $ | (5,877 | ) | | $ | 17,284 | |
(12) | COMMITMENTS AND CONTINGENCIES |
Partial Sale of Wygen III to MDU
On April 9, 2009, we sold to MDU a 25% ownership interest in our Wygen III generation facility currently under construction.facility. At closing, MDU made a payment to us for its 25% share of the costs to date on the ongoing construction of the facility. Proceeds of $32.8 million were received of which $30.2 million was used to pay down a portion of the Acquisition Facility. MDU will continuecontinued to reimburse us for its 25% of the total costs paid to complete the project. The Wygen III generation facility began commercial operations on April 1, 2010. In conjunction with the sales transaction, we also modified a 2004 PPA between us and MDU.
On July 14, 2010, we sold a 23% ownership interest in Wygen III to the City of Gillette for $62.0 million. The purchase terminates the current PPA with the City of Gillette, and the Wygen III Participation Agreement has been amended to include the City of Gillette. The Participation Agreement provides that the City of Gillette will pay us for administrative services and share in the costs of operating the plant for the life of the facility. The estimated amount of net fixed assets sold totaled $55.8 million. We recognized a gain on the sale of $6.2 million.
Power Purchase and Transmission Services Agreements
We have the following power purchase power and transmission agreements as of December 31, 2009:2010:
| · |
• | A PPA with PacifiCorp expiring in 2023, which provides for the purchase by us of 50 MW of electric capacity and energy. 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 $11.8 million in 2009, $11.6 million in 2008 and $10.9 million in 2007.plants; |
| · |
• | A firm point-to-point transmission access agreement to deliver up to 50 MW of power on PacifiCorp's transmission system to wholesale customers in the western region through 2023. Costs incurred under this agreement were $1.2 million in each of the years ended 2009, 2008 and 2007, respectively.2023; |
| · |
• | Cheyenne Light entered into a 20-year PPA with Happy Jack for 29.4 MW of energy. Under a separate inter-company agreement expiring in 2028, Cheyenne Light has agreed to sell 20 MW50% of energythe facility output from Happy Jack to us; |
| · |
• | Cheyenne Light entered into a 20-year PPA with Silver Sage for 30 MW of energy. Commercial operations commenced on October 1, 2009. Under a separate inter-company agreement expiring in 2029, Cheyenne Light has agreed to sell 20 MW of energy from Silver Sage to us; and |
| · |
• | A Generation Dispatch Agreement with Cheyenne Light that requires us to purchase all of Cheyenne Light's excess energy. |
Costs incurred under these agreements were as follows for the years ended December 31 (in thousands):
| | | | | | | | | | | |
Contract | Contract Type | Expiring | 2010 | 2009 | 2008 |
| | | | | |
PacifiCorp | Electric capacity and energy | 2023 | $ | 12,936 | | $ | 11,862 | | $ | 11,571 | |
PacifiCorp | Transmission access | 2023 | $ | 1,215 | | $ | 1,215 | | $ | 1,215 | |
Cheyenne Light | Happy Jack Wind Farm | 2028 | $ | 2,815 | | $ | 2,078 | | $ | 628 | |
Cheyenne Light | Silver Sage Wind Farm | 2029 | $ | 1,723 | | $ | 713 | | $ | — | |
Long-Term Power Sales Agreements
We have the following power sales agreements as of December 31, 2009:2010:
| · |
• | A contractIn March 2010, we entered into a seven-year PPA and Purchase Option Agreement with the City of Gillette Wyoming, expiringeffective April 2010 that replaces a previous agreement. This PPA provided the City of Gillette, with an option to purchase a 23% ownership interest in 2012,our Wygen III facility which commenced commercial operations on April 1, 2010. The City of Gillette exercised its option to purchase the 23% ownership interest in Wygen III and the transaction closed in July 2010. The PPA terminated upon the closing of the transaction. We retain responsibility for operations of the facility with a life-of-plant lease and agreement for operations and coal supply. We entered into a five year agreement with the City of Gillette to dispatch the City of Gillette's first 23% of net generating capacity. MWs from the Wygen III unit are deemed to supply a portion of the City of Gillette's capacity and energy annually. During periods of reduced production at Wygen III, or during periods when Wygen III is off-line, we will provide the city'sCity of Gillette with its first 23 MW23% from our other generating facilities or from system purchases with reimbursement of capacity and energy. Thecosts by the City of Gillette. Under this agreement, renews automatically and requires a seven-year noticewe will also provide the City of termination. This contract is integrated into our control area and is treated as partGillette their operating component of our firm native load. As of December 31, 2009, neither party to the agreement had given notice of termination;spinning reserves; |
| · |
• | An agreement under which wewith MDU to provide 25% of Wygen III's net generating capacity for the life of the plant. In conjunction with MDU's April 2009 purchase of 25% ownership interest in Wygen III, an agreement to supply up to 74 MW of capacity and energy to MDU for the Sheridan, Wyoming electric service territory through the end of 2016.2016 was modified. The sales to MDU have been integrated into our control area and are considered part of our firm native load. In accordance with the terms of the agreement, MDU exercised its option to participate in the ownership ofMWs from the Wygen III plant that is currently being constructed. Under an agreement entered into in April 2009, MDU purchasedunit are deemed to supply a 25% undivided interest in the Wygen III plant. We retain responsibility for operationsportion of the facility with a life-of-plant lease and agreements with MDU for operations and coal supply. In conjunction with the sales transaction, we also modified the 2004 PPA under which we supplied MDU withrequired 74 MW of capacity and energy through 2016. The PPA with MDU will be supplied from its ownership interest in Wygen III.MW. During periods of reduced production at Wygen III, or during periods when Wygen III is offline, weoff-line, MDU will provide MDUbe provided with its first 25 MW from our other generation facilities or from system purchases; andpurchases with reimbursement of costs by MDU; |
| · |
• | An agreement under which we supply 20 MW of energy and capacity to MEAN under a contract that expires in 2023. This contract is unit-contingent based on the availability of our Neil Simpson II and Wygen III plants, with capacity purchase decreasing to 15 MW in 2018, 12 MW in 2020 and 10 MW in 2022. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows: |
| |
2010-2017 | 20 MW - 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II |
2018-2019 | 15 MW - 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II |
2020-2021 | 12 MW - 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II |
2022-2023 | 10 MW - 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II; and |
| · |
• | A five-year PPA with MEAN which commences the month following the onset of commercial operations of Wygen III.commenced on April 1, 2010. Under this contract, MEAN will purchasepurchases 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III. |
Legal Proceedings
Ongoing Litigation
We are subject to various 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 our financial position, results of operations or cash flows.
(14) QUARTERLY HISTORICAL DATA (Unaudited)
(13) | QUARTERLY HISTORICAL DATA (Unaudited) |
We operate on a calendar year basis. The following table sets forth selected unaudited historical operating results data for each quarter of 2009 and 2008 (in thousands):
| First Quarter | | | Second Quarter | | | Third Quarter | | | Fourth Quarter | |
2009: | | | | | | | | | | | |
Operating revenues | $ | 54,458 | | | $ | 46,836 | | | $ | 53,086 | | | $ | 52,699 | |
Operating income | | 10,705 | | | | 5,006 | | | | 8,920 | | | | 10,174 | |
Net income | | 6,964 | | | | 3,105 | | | | 7,166 | | | | 5,904 | |
| | | | | | | | | | | | | | | |
2008: | | | | | | | | | | | | | | | |
Operating revenues | $ | 57,632 | | | $ | 57,978 | | | $ | 59,358 | | | $ | 57,706 | |
Operating income | | 10,591 | | | | 9,270 | | | | 10,228 | | | | 8,547 | |
Net income | | 5,576 | | | | 5,251 | | | | 6,371 | | | | 5,561 | |
| | | | | | | | | | | | |
| First Quarter | Second Quarter | Third Quarter | Fourth Quarter |
2010 | | | | |
Operating revenues | $ | 54,489 | | $ | 56,438 | | $ | 59,051 | | $ | 59,785 | |
Operating income | $ | 9,361 | | $ | 10,510 | | $ | 21,092 | | $ | 14,305 | |
Net income | $ | 5,934 | | $ | 4,102 | | $ | 14,078 | | $ | 7,154 | |
| | | | |
2009 | | | | |
Operating revenues | $ | 54,458 | | $ | 46,836 | | $ | 53,086 | | $ | 52,699 | |
Operating income | $ | 10,705 | | $ | 5,006 | | $ | 8,920 | | $ | 10,174 | |
Net income | $ | 6,964 | | $ | 3,105 | | $ | 7,166 | | $ | 5,904 | |
In February 2010, we provided notice to the bondholders of our intent to call the BHP Series Y bonds in full. These bonds were originally due in 2018. The balance of $2.5 million plus an early redemption premium of 2.6% will be paid on March 31, 2010.
57ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
ITEM 9A. | 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, 2009.2010. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.
Internal control over financial reporting
Management's Report on Internal Control over Financial Reporting is presented on Page 26 |
Management's Report on Internal Control over Financial Reporting is presented on Page 24 of this Annual Report on Form 10-K. |
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. | ITEM 9B. OTHER INFORMATION |
None.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The following table sets forth the aggregate fees for services provided to us for the fiscal years ended December 31, 2010 and 2009 by our independent registered public accounting firm, Deloitte & Touche LLP (in thousands):
| | | | | | |
Deloitte & Touche LLP | 2010 | 2009 |
Audit Fees | $ | 335 | | $ | 552 | |
Tax Fees | 157 | | 116 | |
Audit-related fees | 48 | | 190 | |
Total | $ | 540 | | $ | 858 | |
Audit Fees. Fees for professional services rendered for the audits of our financial statements, review of the interim financial statements included in quarterly reports and services that generally only the independent auditor can reasonably provide, such as comfort letters, statutory audits, consents and assistance with and review of documents filed with the Securities and Exchange Commission.
Tax Fees. Fees for services related to tax compliance, and tax planning and advice including tax assistance with tax audits. These services include assistance regarding federal and state tax compliance and advice, review of tax returns, and federal and state tax planning.
Audit-Related Fees. Fees for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements and are not reported under "Audit Fees." These may services include internal control reviews; attest services that are not required by statute or regulation; employee benefit plan audits; due diligence, consultations and audits related to mergers and acquisitions; and consultations concerning financial accounting and reporting standards.
The services performed by Deloitte & Touche LLP were pre-approved in accordance with the Black Hills Corporation Audit Committee's pre-approval policy whereby the Audit Committee pre-approves all audit and permissible non-audit services provided by the independent registered public accountants. The Audit Committee annually reviews the services expected to be provided by the independent auditors and establish pre-approval fee levels for each category of services to be provided, including audit, audit-related, tax and other services. Any service that is not included in the approved list of services must be separately pre-approved by the Audit Committee.
| |
ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
| | |
(a) | 1. | Financial Statements |
| | |
| | Financial statements required by Item 15 are listed in the index included in Item 8 of Part II. |
| | |
| 2. | Schedules |
Valuation and Qualifying Accounts for the years ended December 31, 2010, 2009 and 2008
| | |
| | Valuation and Qualifying Accounts for the years ended December 31, 2009, 2008 and 2007. |
| | |
| | All other schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included elsewhere in the financial statements incorporated by reference in this Form 10-K. |
BLACK HILLS POWER, INC. VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31, 2009, 2008 AND 2007 | |
| |
Additions | | |
| |
Description | Balance at beginning of year | | Charged to costs and expenses | | Deductions | | Balance at end of year | |
| (in thousands) | | | |
Allowance for doubtful accounts: | | | | | | | | | | | | |
2009 | | $ | 370 | | | $ | 316 | | | $ | (427) | | | $ | 259 | |
2008 | | $ | 388 | | | $ | 637 | | | $ | (655) | | | $ | 370 | |
2007 | | $ | 250 | | | $ | 320 | | | $ | (182) | | | $ | 388 | |
| | | | | | | | | | | | |
BLACK HILLS POWER, INC. VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008 |
|
Description | Balance at beginning of year | Additions Charged to costs and expenses | Deductions | Balance at end of year |
| (in thousands) |
Allowance for doubtful accounts: | | | | |
2010 | $ | 259 | | $ | 499 | | $ | (528 | ) | $ | 230 | |
2009 | $ | 370 | | $ | 316 | | $ | (427 | ) | $ | 259 | |
2008 | $ | 388 | | $ | 637 | | $ | (655 | ) | $ | 370 | |
3. Exhibits
Exhibit Number | Description |
| |
3.1* | Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant's Form 8-K dated June 7, 1994 (No. 1-7978)). |
| |
3.2* | Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant's Form 10-K for 2000). |
| |
3.3* | Bylaws of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form S-8 dated July 13, 1999). |
| |
4.1* | Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registration Statement on Form S-3 (No. 333-150669-01)). |
| |
10.1* | Restated and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit 10.1 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). |
| |
10.2* | Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10.2 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). |
| |
10.3* | Reserve Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10.3 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). |
| |
23 | Independent Auditors' Consent |
| |
31.1 | Certification of Chief Executive Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| |
31.2 | Certification of Chief Financial Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| |
32.1 | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
| |
32.2 | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
_________________________
* Previously filed as part of the filing indicated and incorporated by reference herein.
| __________________________ |
| * | Previously filed as part of the filing indicated and incorporated by reference herein. |
| (b)(a) | See (a) 3. Exhibits above. |
| (c) |
(b) | See (a) 2. Schedules above. |
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.
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.
| | | |
| | BLACK HILLS POWER, INC. |
| | |
| | By | /s/ DAVID R. EMERY |
| | David R. Emery, Chairman and |
| | Chief Executive Officer |
| | |
Dated: | March 10, 20107, 2011 | |
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.
| | |
/s/ DAVID R. EMERY | Director and | March 10, 20107, 2011 |
David R. Emery, Chairman and | Principal Executive Officer | |
Chief Executive Officer | | |
| | |
/s/ ANTHONY S. CLEBERG | Principal Financial and | March 10, 20107, 2011 |
Anthony S. Cleberg, Executive Vice President | Accounting Officer | |
and Chief Financial Officer | | |
| | |
/s/ DAVID C. EBERTZ | Director | March 10, 20107, 2011 |
David C. Ebertz | | |
| | |
/s/ JACK W. EUGSTER | Director | March 10, 20107, 2011 |
Jack W. Eugster | | |
| | |
/s/ JOHN R. HOWARD | Director | March 10, 20107, 2011 |
John R. Howard | | |
| | |
/s/ KAY S. JORGENSEN | Director | March 10, 20107, 2011 |
Kay S. Jorgensen | | |
| | |
/s/ STEPHEN D. NEWLIN | Director | March 10, 20107, 2011 |
Stephen D. Newlin | | |
| | |
/s/ GARY L. PECHOTA | Director | March 10, 20107, 2011 |
Gary L. Pechota | | |
| | |
/s/ WARREN L. ROBINSON | Director | March 10, 20107, 2011 |
Warren L. Robinson | | |
| | |
/s/ JOHN B. VERING | Director | March 10, 20107, 2011 |
John B. Vering | | |
| | |
/s/ THOMAS J. ZELLER | Director | March 10, 20107, 2011 |
Thomas J. Zeller | | |
INDEX TO EXHIBITS
| |
Exhibit Number | Description |
| |
3.1* | Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant's Form 8-K dated June 7, 1994 (No. 1-7978)). |
| |
3.2* | Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant's Form 10-K for 2000). |
| |
3.3* | Bylaws of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form S-8 dated July 13, 1999). |
| |
4.1* | Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registration Statement on Form S-3 (No. 333-150669-01)). |
| |
10.1* | Restated and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit 10.1 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). |
| |
10.2* | Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10.2 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). |
| |
10.3* | Reserve Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10.3 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). |
| |
23 | Independent Auditors’Auditors' Consent |
| |
31.1 | Certification of Chief Executive Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| |
31.2 | Certification of Chief Financial Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| |
32.1 | Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
| |
32.2 | Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
___________________________________________________
* | Previously filed as part of the filing indicated and incorporated by reference herein. |
* Previously filed as part of the filing indicated and incorporated by reference herein.