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 March 31, 2004.
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 April 30, 2004
Common stock, $1.00 par value 32,416,379 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 2003 Annual Report on Form 10-K)
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*All periods presented reflect a net presentation of revenues at our gas marketing subsidiary and a gross presentation of revenues at our crude oil marketing subsidiary in accordance with EITF 02-3 and EITF 99-19.
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*crude in barrels, gas in MMBtu’s
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We are a diversified energy holding company operating principally in the United States with two major business groups – wholesale energy and retail services. We report for our business groups in the following financial segments:
Our wholesale energy group, Black Hills Energy, Inc., engages in the production of electric power through ownership of a diversified portfolio of generating plants and the sale of electric power and capacity primarily under long-term contracts, the production of coal, natural gas and crude oil primarily in the Rocky Mountain region, and the marketing and transportation of fuel products. Our retail services group consists of our electric utility and communications segments. Our electric utility, Black Hills Power, Inc., generates, transmits and distributes electricity to an average of approximately 61,000 customers in South Dakota, Wyoming and Montana. Our communications segment provides 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.
In 2003, we made the decision to divest of our non-strategic power generation assets located in the Northeastern United States. On September 30, 2003, we sold our seven hydroelectric power plants located in Upstate New York.
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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 2003 Annual Report on Form 10-K filed with the Securities and Exchange Commission.
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:
Discontinued operations in 2004 represent the operations of our 40 MW Pepperell power plant, our last power plant in the Eastern region, which is currently held for sale. Discontinued operations in 2003 represent the Pepperell plant as well as operations of the hydroelectric power plants located in upstate New York, which were sold on September 30, 2003.
Three Months Ended March 31, 2004 Compared to Three Months Ended March 31, 2003. Consolidated income from continuing operations for the three-month period ended March 31, 2004 was $10.0 million or $0.30 per share compared to $15.7 million or $0.58 per share in the same period of the prior year. Income from continuing operations for the three-month period ended March 31, 2004 includes a gain on the sale of certain assets that resulted in a net benefit of $0.02 per share after-tax. This gain on sale is included in our “Corporate” results.
Per share results in the first quarter of 2004 were also affected by an increase of 5.4 million weighted average shares outstanding, compared to the same period in 2003, due primarily to a 4.6 million share common stock offering in April 2003.
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Net income for the three months ended March 31, 2003, included a charge of $2.7 million or ($0.10) per share for change in accounting principles. The change in accounting principles 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.
Discussion of results from our operating groups and segments are included in the following pages.
The following is a summary of sales volumes of our coal, oil and natural gas production and power generation capacity:
Capacity in service includes 40 MW and 82 MW in 2004 and 2003, respectively, which are currently reported as "Discontinued operations."
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The following is a summary of average daily energy marketing volumes:
Discussion of results from our Wholesale Energy group’s operating segments are as follows:
Energy Marketing
Three Months Ended March 31, 2004 Compared to Three Months Ended March 31, 2003. The decrease in revenues is a result of a 13 percent decrease in crude oil volumes marketed, partially offset by a 4 percent increase in the average price per barrel marketed. Revenue decreases from crude oil marketing were offset by a similar decrease in the cost of crude oil sold.
Income from continuing operations decreased $0.3 million due to a decrease in gas marketing margins received and a $0.3 million unrealized mark-to-market loss for 2004, compared to a $2.4 million unrealized gain in 2003, resulting in a quarter-over-quarter pre-tax decrease of $2.7 million in unrealized mark-to-market adjustment at our gas marketing operations (See Note 15 for discussion of potential volatility in energy marketing earnings related to accounting treatment of certain hedging activities at our natural gas marketing operations). These items were partially offset by a 33 percent increase in natural gas volumes marketed and a $1.5 million increase in income from continuing operations at our crude oil marketing and transportation business resulting from an increase in contracted crude oil transportation and storage revenues.
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Power Generation
Three Months Ended March 31, 2004 Compared to Three Months Ended March 31, 2003. Revenue decreased 12 percent in 2004 compared to 2003 primarily as a result of decreased energy sales at our plants not currently under long-term contract as there had been limited opportunities for economic dispatch due to the prevailing regional power market conditions. This includes a $5.8 million decrease in revenues at our Las Vegas facility, which has been selling power into the market, when economic to do so, since the September 2003 termination and buyout of the long-term contract at the Las Vegas II plant. A new long-term tolling arrangement for the capacity and energy of the Las Vegas II plant was entered into with Nevada Power Company and became effective April 1, 2004. These decreases were partially offset by additional revenue from a full quarter of capacity and energy payments at our 90 megawatt Wygen plant that became operational in February 2003.
Income from continuing operations decreased $5.5 million. Decreased earnings were the result of lower revenues, increased fuel cost primarily related to generating costs at our Las Vegas facility, higher depreciation costs primarily related to the Wygen plant, partially offset by lower interest expense from debt reduction from the proceeds of an asset sale and contract termination outweighed higher interest rates.
Oil and Gas
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Three Months Ended March 31, 2004 Compared to Three Months Ended March 31, 2003. Income from continuing operations increased $1.8 million. Volumes sold increased 60 percent, primarily related to a full quarter of production at the Mallon properties acquired in March 2003. Average gas and oil prices received in 2004 were $4.54/Mcf and $28.65/bbl, respectively, compared to $3.40/Mcf and $29.17/bbl in 2003. Total operating expenses increased 55 percent primarily related to the additional operations acquired in the Mallon transaction. In addition, 2004 lease operating expenses per Mcfe sold (LOE/MCFE) were flat with 2003.
The following is a summary of our internally estimated economically recoverable oil and gas reserves. These estimates are measured using constant product prices of $35.76 per barrel of oil and $5.93 per Mcf of natural gas as of March 31, 2004, and $31.04 per barrel of oil and $5.05 per Mcf of natural gas as of March 31, 2003. The increases in reserves are primarily the result of increased product prices. 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.
Coal Mining
Three Months Ended March 31, 2004 Compared to Three Months Ended March 31, 2003. Revenue from our mining segment increased 6 percent for the three-month period ended March 31, 2004, compared to the same period in 2003. The increase is attributable to a 5 percent increase in tons of coal sold. The increase in tons of coal sold was primarily attributable to sales to the Wygen Plant, which began commercial operation in February 2003, and additional sales through the train load-out facility.
Operating expenses increased 4 percent or approximately $0.2 million, primarily due to higher operating costs related to the increase in production and accruals for taxes.
Income from continuing operations increased 9 percent due to higher production volumes at higher average prices offset by higher taxes and production-related costs.
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Electric Utility
The following table provides certain operating statistics:
Three Months Ended March 31, 2004 Compared to Three Months Ended March 31, 2003. Electric utility revenues decreased 5 percent for the three-month period ended March 31, 2004, compared to the same period in the prior year. The decrease in revenue was primarily due to an 18 percent decrease in off-system electric MWh sales at a 6 percent decrease in average prices received. Decreased off-system megawatt-hour sales were impacted in part by plant availability resulting from scheduled maintenance outages during the three month period ended March 31, 2004. Firm residential, commercial, industrial and wholesale electricity revenues increased 3 percent, 1 percent, 5 percent and 2 percent, respectively. Residential and commercial customers increased 2 percent. Degree days, which is a measure of weather trends, were 7 percent below last year.
Electric operating expenses remained flat for the three-month period ended March 31, 2004, compared to the same period in the prior year. Purchased power increased $1.2 million due to a 21 percent increase in megawatt-hours purchased, partially offset by a 5 percent decrease in the average cost per megawatt-hour. Gas costs decreased 88 percent due to a 96 percent decrease in megawatt-hours generated with our gas turbines as prevailing prices made it more economical for us to purchase power for our peaking needs when it was available rather than generate energy from our gas turbines. The average cost per megawatt-hour of our gas generation was $40.57 for the three months ended March 31, 2003 compared to $35.02 per megawatt-hour for purchased power for the same time period. The decrease in fuel expense was offset by increased maintenance costs for scheduled plant outages, increased health insurance costs and an increase in allocated corporate costs.
Income from continuing operations decreased $1.7 million primarily due to the decrease in off-system electric revenue and increases in purchased power expense, maintenance expense, health insurance expense and allocated corporate costs, partially offset by an increase in firm system electric sales and a decrease in fuel expense.
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Communications
Three Months Ended March 31, 2004 Compared to Three Months Ended March 31, 2003. The communications business group’s net loss was $1.8 million for the three-month periods ended March 31, 2004 and 2003, respectively. Revenues decreased as a result of $0.8 million in sales incentive costs related to a marketing campaign responding to a local competitor’s aggressive pricing pressure, primarily in the fourth quarter of 2003. These sales incentives included six months of service at discounted prices, of which many will become full price service during the second quarter of 2004. Revenue reductions from sales incentives were partially offset by increased customers, compared to 2003. In addition, reduced property tax accruals and a decrease in operations and maintenance expense were partially offset by increased corporate cost allocations.
Based on lower-than-expected results in the first quarter of 2004 and management’s current evaluation of capital deployment prospects for the remainder of 2004, the Company expects 2004 income from continuing operations to approximate $2.00 to $2.15 per share. The narrowing of guidance takes into consideration possible additional delay in the deployment of excess cash balances for anticipated capital investments in retail and wholesale energy operations, further debt reduction, stock repurchase or other corporate purposes, which, until deployed should result in lower returns from short-term investments instead of higher returns from alternative uses, and a revised expectation that any new development capital deployment likely would not have an accretive effect in 2004 due to the timing of such deployment. The Company continues to expect strong financial performance in 2004 from the oil and gas production business segment, due to expected continued increases in production and an advantageous price environment, and from the energy marketing business segment, due to expected increases in daily volumes marketed.
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There have been no material changes in our critical accounting policies from those reported in our 2003 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 2003 Annual Report on Form 10-K.
During the three-month period ended March 31, 2004, 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 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 $52.9 million for the three-month period ended March 31, 2004 compared to the same period in the prior year primarily due to an $18.8 million federal income tax refund and changes in working capital.
During the three months ended March 31, 2004, we had cash outflows from investing activities of $12.0 million, which was primarily related to property, plant and equipment additions in the normal course of business.
During the three months ended March 31, 2004, we had cash outflows from financing activities of $55.4 million, primarily due to the repayment of debt and payment of quarterly cash dividends on stock. On January 30, 2004, we repaid $45 million of the project-level debt outstanding on the Fountain Valley project.
Dividends paid on our common stock totaled $0.31 per share in the first quarter of 2004. This reflects a 3.3 percent increase, as approved by our board of directors in January 2004, from the 2003 quarterly dividend level. 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.
Our principal sources of short-term liquidity are revolving bank facilities and cash provided by operations. Our liquidity position remained strong during the first quarter of 2004. As of March 31, 2004, we had approximately $191.5 million of cash unrestricted for operations and $425 million of credit through revolving bank facilities. Approximately $55.5 million of the cash balance at March 31, 2004 was restricted by subsidiary debt agreements that limit our subsidiaries’ ability to dividend cash to the parent company. The bank facilities consisted of a $225 million facility due August 20, 2006 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 March 31, 2004, 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 $374.4 million at March 31, 2004.
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The above bank facilities include the following covenants that are common in such arrangements:
a consolidated net worth in an amount of not less than the sum of $475 million and 50 percent of the aggregate consolidated net income beginning April 1, 2003;
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.
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. As of March 31, 2004, we were in compliance with the above covenants.
Our consolidated net worth was $710.7 million at March 31, 2004, which was approximately $207.3 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 March 31, 2004 was 53.6 percent, our total debt leverage (long-term debt and short-term debt) was 54.1 percent, and our recourse leverage ratio was approximately 49.5 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. As of March 31, 2004, we had a $3.0 million guarantee to the lender under this facility. At March 31, 2004, there were outstanding letters of credit issued under the facility of $92.2 million, with no borrowing balances outstanding on the facility.
Similarly, Black Hills Energy Resources, Inc. (BHER), our oil marketing unit, has a $25 million uncommitted, discretionary credit facility. The facility allows BHER to elect up to $40 million of available credit via notification to the bank at the beginning of each calendar quarter. This line of credit provides credit support for the purchases of crude oil by BHER. We provided no guarantee to the lender under this facility. At March 31, 2004, BHER had letters of credit outstanding of $6.1 million.
There were no changes in our corporate credit ratings during the first quarter of 2004.
Our ability to obtain additional financing, if necessary, 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 requirements from those reported in Item 7 of our 2003 Annual Report on Form 10-K filed with the Securities Exchange Commission.
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During the first quarter of 2004, a $5.0 million performance guarantee for Black Hills Wyoming, under a power sales agreement on the Wygen Plant expired. In addition a new $0.5 million guarantee was issued related to payments under various transactions with Idaho Power Company. At March 31, 2004, we had guarantees totaling $187.2 million in place.
During the three months ended March 31, 2004, capital expenditures were approximately $13 million. We currently expect capital expenditures for the entire year 2004 to approximate $312 million, as detailed in Item 7 of our 2003 Annual Report on Form 10-K filed with the Securities and Exchange Commission.
There have been no material changes in our risk factors from those reported in Items 1 and 2 of our 2003 Annual Report on Form 10-K filed with the Securities and Exchange Commission.
Other than the new pronouncements reported in our 2003 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.
This Quarterly Report on Form 10-Q includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-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 the risk factors described above, in Item 1 of our 2003 Annual Report on Form 10-K filed with the SEC, and the following:
The amount and timing of capital deployment in new investment opportunities;
General economic and political conditions, including tax rates or policies and inflation rates;
Our use of derivative financial instruments to hedge commodity and interest rate risks;
The creditworthiness of counterparties to trading and other transactions, and defaults on amounts due from counterparties;
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The amount of collateral required to be posted from time to time in our transactions;
Changes in or compliance with laws and regulations, particularly those relating to taxation, safety and protection of the environment;
The timing and extent of changes in energy-related and commodity prices, interest rates, energy and commodity supply or volume, the cost of transportation of commodities, and demand for our services, all of which can affect our earnings, liquidity position and the underlying value of our assets;
Weather and other natural phenomena;
The timing of production from oil and gas development facilities, which may be dependent upon issuance by federal, state, and tribal governments, or agencies thereof, of building, environmental and other permits, and the availability of specialized contractors, work force, equipment, and prices of and demand for our products;
The extent of success in connecting natural gas supplies to gathering and processing systems;
Industry and market changes, including the impact of consolidations and changes in competition;
The effect of accounting policies issued periodically by accounting standard-setting bodies;
The cost and effects on our business, including insurance, resulting from terrorist actions or responses to such actions;
Capital market conditions, including price risk due to marketable securities held as investments in benefit plans; and
Other factors discussed from time to time in our filings with the SEC.
New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events, or otherwise.
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The following table is a required disclosure and provides a reconciliation of the activity in energy trading contracts that meet the definition of a derivative under SFAS 133 and that were marked-to-market during the three months ended March 31, 2004 (in thousands):
On January 1, 2003, the Company adopted EITF Issue No. 02-3. 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. EITF 98-10 was superseded by EITF 02-3 and allowed a broad interpretation of what constituted “trading activity” and hence what would be marked-to-market. EITF 02-3 took a much narrower view of what “trading activity” should be marked-to-market, limiting mark-to-market treatment primarily to only those contracts that meet the definition of a derivative under SFAS 133. At our natural gas marketing operations, we often employ strategies that include derivative contracts along with inventory, storage and transportation positions to accomplish the objectives of our producer services, end-use origination and wholesale marketing groups. Except in very limited circumstances when we are able to designate transportation, storage or inventory positions as part of a fair value hedge, SFAS 133 generally does not allow us to mark our inventory, transportation or storage positions to market. The result is that while a significant majority of our natural gas marketing positions are fully economically hedged, we are required to mark some parts of our overall strategies (the derivatives), but are generally precluded from marking the rest of our economic hedges (transportation, inventory or storage) to market. Volatility in reported earnings and derivative positions should be expected given these accounting requirements.
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At March 31, 2004, we had a mark to fair value unrealized gain of $0.6 million for our derivative contracts related to our natural gas marketing activities, with $0.5 million of this amount current. The sources 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 2003 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 2003 Annual Report on Form 10-K, and Note 15 of our Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.
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 March 31, 2004. 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 required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the required time periods.
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: May 10, 2004
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EXHIBIT INDEX
Exhibit Number Description
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