United StatesSecurities and Exchange Commission Washington, D.C. 20549
Form 10-Q
QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2003.
OR
___ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES ACT OF 1934
For the transition period from _______________ to _______________.
Commission File Number 001-31303
Black Hills CorporationIncorporated in South Dakota IRS Identification Number 46-0458824
625 Ninth StreetRapid City, South Dakota 57701
Registrant’s telephone number (605) 721-1700
Former name, former address, and former fiscal year if changed since last report
NONE
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes X No___
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.
Class Outstanding at July 31, 2003
Common stock, $1.00 par value 32,107,619 shares
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TABLE OF CONTENTS
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The accompanying notes to condensed consolidated financial statements are an integral part of these condensed consolidated financial statements.
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BLACK HILLS CORPORATION
Notes to Condensed Consolidated Financial Statements(unaudited)(Reference is made to Notes to Consolidated Financial Statementsincluded in the Company's Annual Report on Form 10-K)
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December 31, 2002 balance for coal mine reclamation liability as previously accounted for under a cost-accumulation approach.
The Company incurred certain asset retirement obligations with its acquisition of Mallon Resources completed on March 10, 2003, as described in Note 15.
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As further described in Note 9, on April 30, 2003, the Company completed a public offering of 4.6 million shares of common stock. Accordingly, this transaction significantly affects the weighted average number of common shares outstanding used in earnings per share calculations for the current and for future periods.
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_____________________*crude in barrels, gas in MMBtu’s
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIALCONDITION AND RESULTS OF OPERATIONS
We are a diversified energy holding company operating principally in the United States. Our unregulated and regulated businesses have expanded significantly in recent years. Our integrated energy group, Black Hills Energy, Inc., produces and markets electric power and fuel. We produce and sell generating capacity and electricity in a number of markets, with a strong emphasis in the western United States. We also produce coal, natural gas and crude oil, primarily in the Rocky Mountain region, and transport crude oil in Texas. Our electric utility, Black Hills Power, Inc., serves an annual average of approximately 60,000 customers in South Dakota, Wyoming and Montana. Our communications group provides state-of-the-art broadband communications services to over 26,000 residential and business customers in Rapid City and the northern Black Hills region of South Dakota through Black Hills FiberCom, LLC.
The following discussion should be read in conjunction with Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations – included in our 2002 Annual Report on Form 10-K filed with the Securities and Exchange Commission.
Consolidated Results
Revenue and Income (loss) from continuing operations provided by each business group as a percentage of our total revenue and total income (loss) from continuing operations were as follows:
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Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002. Consolidated income from continuing operations for the three-month period ended June 30, 2003 was $16.7 million or $0.54 per share compared to $14.7 million or $0.54 per share in the same period of the prior year.
Income from continuing operations for the three-month period ended June 30, 2003 includes certain unusual items that resulted in a net charge of $0.04 per share. These items related to a $3.0 million charge or ($0.10) per share for a settlement reached with the Commodity Futures Trading Commission (CFTC) relating to its investigation of our marketing subsidiary, Enserco Energy Inc.‘s trade reporting practices to industry publications. (See Note 14 of the accompanying Notes to Condensed Consolidated Financial Statements), partially offset by a $0.06 benefit from unrealized gains from investments in certain energy funds.
The increase in income from continuing operations was driven by a 38 percent increase in earnings for the integrated energy business group. The strong operating results were attributed to higher oil and gas production and prices, an increase in power sales resulting from higher generating capacity in our power generation segment, increased earnings from power fund investments accounted for under the equity method of accounting, and improving performance in our communications business group, partially offset by a decrease in net income at the electric utility due to higher operating costs and interest expense, a decrease in net income in the mining segment due to higher operating costs, and a decrease in net income at the energy marketing segment, due to the CFTC settlement, lower margins received and a decrease in unrealized mark-to-market gains on derivative contracts.
During the second quarter of 2002, we decided to discontinue operations in our coal marketing business due primarily to challenges encountered in marketing our Wyodak coal from the Powder River Basin of Wyoming to midwestern and eastern coal markets. We sold the non-strategic assets effective August 1, 2002. Net loss from discontinued operations was $0.9 million or $(0.03) per share for the three months ended June 30, 2002. Prior year results of operations have been restated to reflect the discontinued operations.
Consolidated revenues for the three-month period ended June 30, 2003 were $300.0 million compared to $260.7 million for the same period in 2002. Revenues increased in each of our three business groups. In the power generation segment, revenues increased 53 percent due to a substantial increase in its generating capacity. Oil and gas revenue increased 86 percent, due to a 53 percent increase in production resulting primarily from the March 2003 acquisition of Mallon Resources and a 37 percent increase in the average price received. Mining revenue increased 18 percent, due to a 34 percent increase in tons sold. Revenues from the electric utility group increased 2 percent, due to an 11 percent increase in off-system sales and a 10 percent increase in average prices received for non-firm sales offset by lower industrial revenues. The communications group revenue increased 43 percent as a result of the recording of revenue associated with the 2003-2004 Black Hills telephone directory and a 17 percent increase in its customer base.
Consolidated operating expenses for the three-month period increased from $229.9 million in 2002 to $262.0 million in 2003. The increase was primarily due to an increase in fuel costs and depreciation expense as a result of our increased investment in independent power generation and increased operating expenses related to the increase in production in each of our three business groups. Corporate costs increased $1.6 million primarily due to the result of a write-off of deferred debt issuance costs associated with the $35 million term loan paid off during the second quarter of 2003, higher general and administrative expenses and increased pension expenses.
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Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002. Consolidated income from continuing operations for the six-month period ended June 30, 2003 was $33.5 million or $1.14 per share compared to $29.6 million or $1.09 per share in the same period of the prior year. Income from continuing operations for the six-month period ended June 30, 2003 includes certain unusual items that resulted in a net charge of $0.04 per share. These items relate to a $3.0 million charge or ($0.10) per share for the CFTC Settlement, partially offset by a $0.06 benefit from unrealized gains from investments in certain energy funds. Consolidated income from continuing operations for the six months ended June 30, 2002 include a $0.07 per share benefit attributed to the collection of previously reserved amounts.
The increase in income from continuing operations was a result of higher oil and gas prices, an increase in power sales resulting from higher generation capacity in our power generation segment, increased earnings from power fund investments accounted for under the equity method of accounting and improving performance in our communications business group, partially offset by a decrease in income at the electric utility due to higher operating costs and interest expense, a decrease in income in the mining segment due to higher operating costs, and a decrease in income at the energy marketing segment, due to the CFTC Settlement and lower margins received.
Net income for the six months ended June 30, 2003, included a charge of $2.7 million or ($0.09) per share for changes in accounting principles compared to a $0.9 million benefit or $0.03 per share in 2002. The change in accounting principles in 2003 reflect a $2.9 million charge related to the adoption of EITF 02-3 and a $0.2 million benefit related to the adoption of SFAS 143. The change in accounting principle in 2002 reflects a $0.9 million benefit related to the adoption of SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142).
In addition, during the second quarter of 2002, we decided to discontinue operations in our coal marketing business due primarily to challenges encountered in marketing our Wyodak coal from the Powder River Basin of Wyoming to midwestern and eastern coal markets. We sold the non-strategic assets effective August 1, 2002. Net loss from discontinued operations was $2.6 million or $(0.09) per share for the six months ended June 30, 2002. Prior year results of operations have been restated to reflect the discontinued operations.
Consolidated revenues for the six-month period ended June 30, 2003 were $599.4 million compared to $431.3 million for the same period in 2002. Revenues increased in each of our three business groups due primarily to higher production volumes. In the power generation segment, revenues increased 53 percent due to a substantial increase in its generating capacity in service. Energy marketing revenues increased 45 percent, due primarily to a 16 percent increase in crude oil average daily volumes marketed at average prices 24 percent higher than the same period in 2002. Oil and gas revenue increased 68 percent, primarily due to a 33 percent increase in production. Mining revenue increased 8 percent, due to a 23 percent increase in coal production partially offset by lower average prices received. Revenues from the electric utility group increased 10 percent, due to a 29 percent increase in off-system megawatt-hour sales at a 23 percent increase in average prices received. The communications group revenue increased 30 percent as a result of the recording of revenue, associated with the 2003 – 2004 Black Hills telephone directory and a 17 percent increase in its customer base.
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Consolidated operating expenses for the six-month period increased to $522.5 million in 2003 from $369.7 million in 2002. The increase was due to an increase in fuel and depreciation expense as a result of our increased investment in independent power generation and increased operating expenses related to the increase in production in all business segments. Corporate costs increased $1.7 million primarily due to the result of a write-off of deferred debt issuance costs associated with the $35 million term loan paid off during the second quarter of 2003, higher general and administrative expenses and increased pension expenses.
The following business group and segment information does not include discontinued operations and intercompany eliminations.
Integrated Energy Group
The following is a summary of sales volumes of our coal, oil and natural gas production and various measures of power generation:
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*includes a 90 MW plant under a lease arrangement
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The following is a summary of average daily energy marketing volumes:
Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002. Income from continuing operations for the integrated energy group for the three months ended June 30, 2003 was $14.3 million, compared to $10.3 million in the same period of the prior year. Income from continuing operations increased approximately $4.0 million primarily due to increased power generating capacity, increased oil and gas production and increased earnings from power fund investments accounted for under the equity method of accounting, partially offset by the $3.0 million CFTC Settlement. Income from continuing operations in our power generation segment increased $7.7 million due to increased generating capacity in service and increased earnings from power fund investments. The increased earnings from our power fund investments primarily relate to a $1.8 million after-tax benefit attributed to unrealized gains on investments accounted for under a fair-value method of accounting at our equity method power funds. Income from continuing operations at our oil and gas segment increased approximately $1.3 million due to higher prices received compared to 2002 and a 53 percent increase in production. Income from continuing operations at our energy marketing segment decreased $3.9 million due to the CFTC Settlement, a decrease in margins received and a decrease in unrealized mark-to-market gains on derivative contracts. Income from continuing operations for the mining segment decreased $1.2 million as higher production volumes were more than offset by lower average prices, higher operating costs and certain accruals for taxes and other items.
Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002. Income from continuing operations for the integrated energy group for the six months ended June 30, 2003 was $26.6 million, compared to $19.8 million in the same period of the prior year. In addition, 2002 income from continuing operations includes a $1.9 million benefit relating to the collection of previously reserved amounts for California operations in our power generation segment. Income from continuing operations increased approximately $6.7 million due to increased generating capacity, increased oil and gas production and increased earnings from power fund investments accounted for under the equity method of accounting partially offset by the $3.0 million CFTC settlement. Income from continuing operations in our power generation segment increased $7.5 million due to increased generating capacity in service and increased earnings from power fund investments. Income from continuing operations at our oil and gas segment increased approximately $2.3 million due to higher prices received compared to 2002 and a 33 percent increase in production. Income from continuing operations at our energy marketing segment decreased $1.1 million primarily due to the CFTC Settlement offset by the increased volumes marketed. Income from continuing operations for the mining segment decreased $1.9 million as higher production volumes were more than offset by lower average prices, higher operating costs and certain accruals for taxes and other items.
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Energy Marketing
Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002. The increase in revenues is a result of a 4 percent increase in crude oil volumes marketed at an average price 2 percent higher than the prior year and an increase in oil transportation and oil terminal revenues offset by a decrease in revenue from lower gas marketing margins. Revenue increases from crude oil marketing were offset by a similar increase in the cost of crude oil sold.
Operating expenses increased $12.9 million due to the $3.0 million settlement reached with the CFTC, a 2 percent increase in the cost of crude oil sold, an increase in general and administrative expenses and an increase in operations and maintenance expense associated with increased volumes of crude oil transportation.
Income from continuing operations decreased $3.9 million due to the CFTC Settlement, a decrease in oil and gas margins received and an increase in general and administrative expenses and operations and maintenance expense associated with increased volumes of crude oil transportation. As a result of changing commodity prices, net income was impacted by unrealized gains recognized through mark-to-market accounting treatment. Unrealized pre-tax mark-to-market gains for the three-month period ended June 30, 2003 were $0.3 million compared to $1.3 million in 2002 resulting in a quarter over quarter decrease of $1.0 million pre-tax.
Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002. Revenues increased 45 percent, due primarily to a 16 percent increase in crude oil volumes marketed at average prices 24 percent higher than the same period in the prior year. In addition, revenues from natural gas marketing margins and oil transportation and terminal operations increased over the prior year. Revenue increases from crude oil marketing were offset by similar increases in the cost of crude oil sold.
Operating expenses increased $110.0 million due to a $103.2 million increase in the cost of crude oil sold, the $3.0 million settlement reached with the CFTC and an increase in operations and maintenance expense associated with increased volumes of crude oil transportation.
Income from continuing operations decreased $1.1 million due to the $3.0 million CFTC Settlement partially offset by earnings from increased volumes marketed. Net income decreased $4.0 million primarily due to the CFTC Settlement and a change in accounting principle of $(2.9) million, net of tax, related to the adoption of EITF 02-3, partially offset by higher unrealized mark-to market gains and higher earnings from increased volumes marketed. As a result of changing commodity prices, net income was impacted by unrealized gains recognized through mark-to-market accounting treatment. Unrealized pre-tax mark-to-market gains for the six-month period ended June 30, 2003 were $1.9 million compared to $0.3 million in 2002 resulting in a period over period increase of $1.6 million pre-tax.
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Power Generation
Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002. Revenue increased 53 percent and operating income nearly doubled for the three-month period ended June 30, 2003 compared to the same period in 2002 and is primarily attributed to additional generating capacity. As of June 30, 2003, we had 1,046 megawatts of independent power capacity in service compared to 646 megawatts at June 30, 2002.
Net income for the power generation segment increased $7.7 million due to the additional generating capacity and increased earnings from power fund investments accounted for under the equity method of accounting. Increased earnings from our power fund investments primarily relate to a $1.8 million after-tax benefit attributed to unrealized gains on investments accounted for under a fair value method of accounting at the power funds.
Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002. Revenue and operating income increased 53 percent for the six-month period ended June 30, 2003 compared to the same period in 2002 and is attributed to additional generating capacity and increased earnings from additional ownership of an energy partnership. As of June 30, 2003 we had 1,046 megawatts of independent power capacity in service compared to 646 megawatts at June 30, 2002.
Net income for the power generation segment increased $6.6 million due to the additional generating capacity and increased earnings from power fund investments accounted for under the equity method of accounting. Increased earnings from our power fund investments primarily relate to $1.8 million after-tax benefit attributed to unrealized gains on investments accounted for under a fair value method of accounting at the power funds. Results from 2002 reflect a $1.9 million after-tax benefit related to the collection of previously reserved amounts for California operations and a $0.9 million after-tax benefit from a change in accounting principle related to the adoption of SFAS 142.
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Oil and Gas
The following is a summary of our internally estimated economically recoverable oil and gas reserves measured using constant product prices of $30.18 per barrel of oil and $5.33 per Mcf of natural gas as of June 30, 2003 and $26.25 per barrel of oil and $3.10 per Mcf of natural gas as of June 30, 2002. Significant increases in reserves are primarily the result of the March 2003 acquisition of Mallon Resources. Estimates of economically recoverable reserves for interim periods are based on independent year-end reserve studies updated for acquisitions, drilling activity, property sales and actual production during the interim period. These internally estimated reserves may differ from actual results.
Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002.Revenue from our oil and gas production business segment increased 86 percent for the three-month period ended June 30, 2003, compared to the same period in 2002, due to a 53 percent increase in production primarily resulting from the March 2003 acquisition of Mallon Resources, and a 37 percent increase in the average price received.
Operating expenses increased 67 percent primarily due to the increase in production.
Income from continuing operations more than doubled due to the higher prices received and the increase in production compared to 2002.
Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002. Revenue from our oil and gas production segment increased 68 percent for the six month period ended June 30, 2003, compared to the same period in 2002, due to a 33 percent increase in production primarily resulting from the March 2003 acquisition of Mallon Resources, and a 40 percent increase in the average price received.
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Operating expenses increased 47 percent primarily due to the increase in production.
Income from continuing operations more than doubled due to the higher prices received and the increase in production. Net income for 2003 also reflects a $0.1 million after-tax charge from the change in accounting principle related to the adoption of SFAS 143.
Mining
Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002. Revenue from our mining segment increased 18 percent for the three-month period ended June 30, 2003, compared to the same period in 2002. A 34 percent increase in tons of coal sold was partially offset by lower average prices received. The increase in tons of coal sold was primarily attributable to sales to the Wygen Plant which began commercial operation in February 2003 and sales of coal through the train load-out facility.
Operating expenses increased 55 percent or approximately $2.6 million primarily due to higher operating costs related to the increase in production, accruals for taxes and certain other items and an increase in general and administrative costs.
Income from continuing operations decreased 47 percent due to an increase in general and administrative and direct mining costs, partially offset by the increase in tons of coal sold in the second quarter of 2003.
Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002. Revenue from our mining segment increased 8 percent for the six-month period ended June 30, 2003, compared to the same period in 2002. A 23 percent increase in tons of coal sold was partially offset by lower average prices received. The increase in tons of coal sold was primarily attributable to sales to the Wygen Plant which began commercial operation in February 2003 and sales of coal through the train load-out facility.
Operating expenses increased 31 percent or approximately $3.3 million primarily due to higher operating costs related to the increase in production, accruals for taxes and certain other items and an increase in general and administrative costs.
Income from continuing operations decreased 40 percent due to an increase in general and administrative and direct mining costs, partially offset by the increase in tons of coal sold in the six-month period ended June 30, 2003. Net income for 2003 also reflects a $0.3 million after-tax benefit from the change in accounting principle related to the adoption of SFAS 143.
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Electric Utility Group
The following table provides certain operating statistics:
Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002. Electric utility revenues increased 2 percent for the three-month period ended June 30, 2003, compared to the same period in the prior year. The increase in revenue was primarily due to an 11 percent increase in off-system electric megawatt-hour sales, at a 10 percent increase in average prices received. Firm residential, commercial and industrial electricity revenues decreased 3 percent, 1 percent, and 7 percent, respectively. The decrease in industrial revenues was primarily due to the closing of Homestake Gold Mine and decreased electricity usage at the South Dakota Cement Plant.
Electric operating expenses increased 15 percent for the three month period ended June 30, 2003, compared to the same period in the prior year. The increase in operating expenses was primarily due to an increase in purchased power costs, additional costs incurred during a scheduled maintenance outage at our Osage plant, and an increase in depreciation, administrative and general costs. Purchased power and fuel costs increased $2.1 million due to the increase in electric sales and higher gas prices. Depreciation expense increased $0.4 million primarily due to the depreciation associated with the combustion turbines. Administrative and general expenses increased primarily due to a $0.5 million increase in pension expense.
Interest expense increased $1.0 million for the three month period, primarily due to interest associated with the $75 million first mortgage bonds issued in August 2002.
Net income decreased $2.1 million primarily due to the increase in purchased power expense, interest expense, depreciation expense and pension expense, partially offset by an increase in off-system electric sales and transmission revenues.
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Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002. Electric utility revenues increased 10 percent for the six-month period ended June 30, 2003, compared to the same period in the prior year. The increase in revenue was primarily due to a 29 percent increase in off-system electric megawatt-hour sales at a 23 percent increase in average prices received. Industrial revenues decreased 8 percent, primarily due to the closing of Homestake Gold Mine and Federal Beef Processors and decreased electricity usage at the South Dakota Cement Plant.
Electric operating expenses increased 23 percent for the six-month period ended June 30, 2003 compared to the same period in the prior year. The increase in operating expense was primarily due to a $6.2 million increase in purchased power costs, a $1.3 million increase in fuel expense, and increased depreciation and general and administrative expenses. Purchased power and fuel costs increased due to the increase in electric sales and higher gas prices. The average cost of fuel and purchased power increased 17 percent in 2003 compared to the same period in 2002. Depreciation expense increased due to additional expense related to combustion turbines. A $1.0 million increase in pension expense contributed to the increase in general and administrative expense.
Interest expense increased $2.1 million for the six-month period, primarily due to interest associated with the $75 million first mortgage bonds issued in August 2002.
Net income decreased $3.2 million, primarily due to the increase in fuel and purchased power expense, depreciation expense and pension expense, partially offset by an increase in off-system electric and transmission revenues.
Communications Group
In 2003, reported business customers were adjusted for the consolidation of multiple-location business customers, business orders and temporary business access lines.
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Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002. The communications business group’s net loss for the three-month period ended June 30, 2003 was $0.4 million, compared to $2.0 million in 2002. The performance improvement is due largely to a 43 percent increase in revenue as a result of a larger customer base and the recording of $2.4 million of revenue associated with the 2003 – 2004 Black Hills telephone directory partially offset by directory publishing costs, increased depreciation and tax expense.
The total number of customers exceeded 26,000 at the end of June 2003 – a 17 percent increase over the customer base at June 30, 2002 and a 3 and 6 percent increase compared to March 31 2003 and December 31, 2002, respectively.
Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002. The communications business group’s net loss for the six-month period ended June 30, 2003 was $2.2 million, compared to $4.3 million in 2002. The performance improvement is due to a larger customer base and the recording of $2.4 million of revenue associated with the 2003 – 2004 Black Hills telephone directory, partially offset by directory publishing costs, higher depreciation and tax expenses.
The total number of customers exceeded 26,000 at the end of June 2003 – a 17 percent increase compared to June 30, 2002 and a 3 and 6 percent increase compared to March 31, 2003 and December 31, 2002, respectively.
Earnings Guidance
Because of our commitment to a strong balance sheet and reflecting current prospects resulting from prevailing economic conditions, we recently revised our long-term average annual earnings per share growth target to approximately 8 percent.
There have been no material changes in our critical accounting policies from those reported in our 2002 Annual Report on Form 10-K filed with the Securities Exchange Commission. For more information on our critical accounting policies, see Part II, Item 7 in our 2002 Annual Report on Form 10-K.
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Cash Flow Activities
During the six-month period ended June 30, 2003, we generated sufficient cash flow from operations to meet our operating needs, to pay dividends on common and preferred stock, to pay our long-term debt maturities and to fund a portion of our property additions. We plan to fund future property and investment additions primarily through a combination of operating cash flow, increased short-term debt, long-term debt and long-term non-recourse project financing.
Cash flows from operations increased $34.3 million for the six-month period ended June 30, 2003 compared to the same period in the prior year primarily due to the increase in cash provided by earnings from operations and changes in working capital.
During the six months ended June 30, 2003, we had cash outflows for investing activities of $53.7 million, which includes $47.0 million for property, plant and equipment additions and the acquisition of assets.
During the six months ended June 30, 2003, we had cash outflows from financing activities of $40.7 million, primarily due to the repayment of debt offset by the proceeds from a public offering of 4.6 million shares of common stock and the sale of $250 million ten-year notes.
On April 30, 2003, we completed a public offering of 4.6 million shares of common stock at $27 per share. Net proceeds were approximately $118 million after commissions and expenses. The proceeds were used to pay off a $50 million credit facility due in May 2003 and to repay $68 million under our 364-day revolving credit facility which expires on August 26, 2003.
On May 21, 2003, we issued $250 million 6.5 percent ten-year notes. Net proceeds from the note offering were approximately $247 million after the discount, commissions and expenses. The proceeds were used to repay our $35 million term loan due September 30, 2004, all of our short-term borrowings under our $195 million, 364-day revolving credit facility and all of our outstanding notes payable under our three-year revolving credit facility which expires on August 24, 2004.
Dividends
Dividends paid on our common stock totaled $0.30 per share in each of the first and second quarters of 2003. This reflects a 3.4 percent increase, as approved by our board of directors in January 2003, from the prior periods. The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our credit facilities and our future business prospects.
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Short-Term Liquidity and Financing Transactions
Our principal sources of short-term liquidity are our revolving bank facilities and cash provided by operations. As of June 30, 2003, we had approximately $79.5 million of cash unrestricted for operations and $395 million of credit through revolving bank facilities. Approximately $39.2 million of the cash balance at June 30, 2003 was restricted by subsidiary debt agreements that limit our subsidiaries’ ability to dividend cash to the parent company. The bank facilities consisted of a $195 million facility due August 26, 2003 and a $200 million facility due August 27, 2004. These bank facilities can be used to fund our working capital needs, for general corporate purposes and to provide liquidity for a commercial paper program if implemented. At June 30, 2003, we had no bank borrowings outstanding under these facilities. After inclusion of applicable letters of credit, the remaining borrowing capacity under the bank facilities was $348.4 million at June 30, 2003.
Our liquidity position was greatly enhanced during the second quarter due to the public offering of 4.6 million shares of common stock and $250 million of ten-year notes (See discussion above under cash flow activities). These two offerings provided net proceeds of approximately $365 million which were used to pay off the $50 million credit facility due in May 2003, the $35 million term loan due September 30, 2004, all of our borrowings under our 364-day revolving credit facility which expires on August 26, 2003, and all of our notes payable under our three-year revolving credit facility which expires on August 24, 2004.
We are currently in the process of negotiating a $200 million three-year revolving credit facility which we expect to complete in August 2003.
The above bank facilities include covenants that are common in such arrangements. Several of the facilities require that we maintain a consolidated net worth in an amount of not less than the sum of $425 million and 50 percent of the aggregate consolidated net income beginning April 1, 2002; a recourse leverage ratio not to exceed 0.65 to 1.00; and a fixed charge coverage ratio of not less than 1.5 to 1.0. In addition, the $195 million 364-day credit facility and the $200 million three-year credit facility contain a liquidity covenant that requires us to have $30 million of liquid assets as of the last day of each fiscal quarter. Liquid assets are defined as unrestricted cash and available unused capacity under our credit facilities. If these covenants are violated, it would be considered an event of default entitling the lender to terminate the remaining commitment and accelerate all principal and interest outstanding. In addition, certain of our interest rate swap agreements include cross-default provisions. These provisions would allow the counterparty the right to terminate the swap agreement and liquidate at a prevailing market rate, in the event of default. As of June 30, 2003, we were in compliance with the above covenants.
Our consolidated net worth was $678.4 million at June 30, 2003, which was approximately $214 million in excess of the net worth we are required to maintain under the debt covenant described above. The long-term debt component of our capital structure at June 30, 2003 was 54.9 percent, our total debt leverage (long-term debt and short-term debt) was 55.7 percent, and our recourse leverage ratio was approximately 49 percent.
In addition, Enserco Energy Inc., our gas marketing unit, has a $135 million uncommitted, discretionary line of credit to provide support for the purchase of natural gas. We provided no guarantee to the lender under this facility. This facility was extended during the second quarter to September 30, 2003. At June 30, 2003, there were outstanding letters of credit issued under the facility of $53.6 million with no borrowing balances outstanding on the facility.
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Similarly, Black Hills Energy Resources, Inc., our oil marketing unit, has a $40 million uncommitted, discretionary credit facility. This line of credit provided credit support for the purchases of crude oil by Black Hills Energy Resources. We provided no guarantee to the lender under this facility. At June 30, 2003, Black Hills Energy Resources had letters of credit outstanding of $4.5 million.
On May 13, 2003, our corporate credit rating was downgraded to “BBB-” by Standard and Poor’s Ratings Group. This credit rating downgrade had minimal effect on our interest rates under our credit agreements. Our issuer credit rating is “Baa3” by Moody’s Investors Service. These security ratings are subject to revision and/or withdrawal at any time by the respective rating organizations. None of our current credit agreements contain acceleration triggers. If our credit rating drops below investment grade, however, pricing under these agreements would be affected. Based upon borrowings outstanding at June 30, 2003, a further credit downgrade to BB+ would increase interest expense by an additional $1.5 million a year.
In July 2003, we entered into a definitive agreement to sell seven hydroelectric power plants in New York State for approximately $186 million. The transaction is expected to reduce project indebtedness by approximately $82 million and increase funds available for additional debt repayment or for capital deployment, should potential projects meet certain strict investment criteria. Based on historical earnings from these assets and reduced interest costs from an assumed debt reduction from proceeds, we anticipate that the sale could reduce annual earnings by approximately $0.07 per share. The asset sale is expected to close in the third quarter of 2003.
Our ability to obtain additional financing will depend upon a number of factors, including our future performance and financial results and capital market conditions. We can provide no assurance that we will be able to raise additional capital on reasonable terms or at all.
There have been no other material changes in our forecasted changes in liquidity and capital requirements from those reported in Item 7 of our 2002 Annual Report on Form 10-K filed with the Securities Exchange Commission.
Guarantees
During the first quarter of 2003, a $135 million completion guarantee for the expanded facilities under a construction loan for Black Hills Colorado expired. During the second quarter of 2003, a $50 million guarantee of the secured financing for the Las Vegas II project expired when the associated debt was paid off and $7.5 million of guarantees under certain energy marketing derivative, power and gas agreements expired or were terminated. In addition a new $2.5 million guarantee was issued during the second quarter related to payments under energy marketing derivative, power and gas agreements. At June 30, 2003, we had guarantees totaling $178.0 million in place.
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Capital Requirements
During the six months ended June 30, 2003, capital expenditures were approximately $47 million. We currently expect capital expenditures for the entire year 2003 to approximate $110 million, which is significantly less than forecasted earlier this year. Management continues active pursuit of appropriate investment opportunities, but presently, no significant asset acquisitions or other capital deployments for new or expanded projects are anticipated to close during the remainder of the year.
Results of an investigation into reporting of trading information could adversely affect our business.
In March 2003, we received a request for information from the Commodity Futures Trading Commission, or CFTC, calling for the production, among other things, of “all documents relating to natural gas and electricity trading” in connection with the CFTC’s industry wide investigation of trade and trade reporting practices of power and natural gas trading companies. We have cooperated fully with the CFTC producing documents and other materials in response to more specific requests relating to the reporting of natural gas trading information to energy industry publications, conducted our own internal investigation into the accuracy of information that former employees of Enserco Energy Inc., our gas marketing subsidiary, voluntarily reported to trade publications, and provided detailed reports of our investigation to the CFTC.
On July 31, 2003 we announced that a settlement was reached with the CFTC on this investigation, whereby we agreed to pay a civil monetary penalty of $3.0 million (see Note 14 of the accompanying Notes to Condensed Consolidated Financial Statements). Although we agreed to this civil monetary penalty with the CFTC we cannot guarantee that other legal proceedings, civil or criminal fines or penalties, or other regulatory action related to this issue will not occur which, in turn, could adversely affect our financial condition or results of operations.
Ongoing regulatory industry-wide investigations into energy marketing trading activity and anomalous bidding behavior could adversely affect our business.
FERC and other regulatory agencies continue their industry-wide investigations into inappropriate energy marketing trading activity. FERC recently issued an order commencing an investigation into “anomalous bidding behavior and practices” in the Western markets. FERC Staff will investigate entities that submitted bids for short-term power sales in excess of $250 per megawatt in the markets operated by the CAISO and CAPX during the period May 1, 2000, to October 2, 2000. The Company cannot predict the outcome of these investigations and the effect they could have on our business.
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Ongoing changes in the United States utility industry, such as state and federal regulatory changes, a potential increase in the number of our competitors or the imposition of price limitations to address market volatility, could adversely affect our profitability.
The United States electric utility industry is currently experiencing increasing competitive pressures as a result of:
FERC has implemented and continues to propose regulatory changes to increase access to the nationwide transmission grid by utility and non-utility purchasers and sellers of electricity. In addition, a number of states have implemented or are considering or currently implementing methods to introduce and promote retail competition. Industry deregulation in some states has led to the disaggregation of some vertically integrated utilities into separate generation, transmission and distribution businesses, and deregulation initiatives in a number of states may encourage further disaggregation. As a result, significant additional and better capitalized competitors could become active in the generation, transmission and distribution segments of our industry, which could negatively affect our ability to expand our asset base.
In addition, the independent system operators who oversee most of the wholesale power markets have in the past imposed, and may in the future continue to impose, price limitations and other mechanisms to address some of the volatility in these markets. These types of price limitations and other mechanisms may adversely affect the profitability of those generating facilities that sell energy into the wholesale power markets. Given the extreme volatility and lack of meaningful long-term price history in some of these markets and the imposition of price limitations by independent system operators, we may not be able to operate profitably in all wholesale power markets.
Several bills, including the Energy Policy Act of 2003, have been introduced in Congress that would amend or repeal portions of PURPA, including the mandatory purchase requirements under which utilities are currently required to enter into contracts to purchase power from qualifying facilities. The proposed legislation would not affect our existing contracts. If the Energy Policy Act of 2003 or similar legislation is enacted, however, utilities would no longer be required to enter into new contracts with qualifying facilities if the FERC determines that the qualifying facility has access to a competitive wholesale market for the sale of electric energy. Any such legislation, if enacted, could adversely affect the value or profitability of our qualifying facilities.
There have been no other material changes in our risk factors from those reported in Items 1 and 2 of our 2002 Annual Report on Form 10-K filed with the Securities and Exchange Commission.
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Other than the new pronouncements reported in our 2002 Annual Report on Form 10-K filed with the Securities Exchange Commission and those discussed in Note 4 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements issued that when implemented would require us to either retroactively restate prior period financial statements or record a cumulative catch-up adjustment.
Forward Looking Statements
Some of the statements in this Form 10-Q include “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-Q that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions, which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including:
New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events, or otherwise.
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The following table provides a reconciliation of the activity in energy trading contracts marked to market during the six month period ended June 30, 2003 (in thousands):
On January 1, 2003, the Company adopted EITF Issue No. 02-3. As described in Notes 3 and 13 of the Notes to Condensed Consolidated Financial Statements in this Form 10-Q, the adoption of EITF 02-3 resulted in certain energy trading activities no longer being accounted for at fair value, therefore, the above reconciliation does not present a complete picture of our overall portfolio of trading activities and our expected cash flows from those operations. The cumulative effect of the adoption of EITF 02-3 is included in the above reconciliation of fair value of energy trading contracts from December 31, 2002 to June 30, 2003.
At June 30, 2003, we had a mark to fair value unrealized loss of $0.6 million for our natural gas marketing activities with substantially all of this amount current. The source of fair value measurements were as follows (in thousands):
There have been no material changes in market risk faced by us from those reported in our 2002 Annual Report on Form 10-K filed with the Securities Exchange Commission. For more information on market risk, see Part II, Item 7 in our 2002 Annual Report on Form 10-K, and Note 13 of our Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
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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 June 30, 2003. Based on their evaluation, they have concluded that our disclosure controls and procedures are adequate and effective to ensure that material information relating to us that is included in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the required time periods.
Changes in internal control over financial reporting
During the period covered by this Quarterly Report on Form 10-Q, 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.
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Part II - Other Information
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Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
Dated: August 13, 2003
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EXHIBIT INDEX
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