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, 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 April 30, 2003
Common stock, $1.00 par value 32,063,278 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)
MANAGEMENT'S STATEMENT
STOCK BASED COMPENSATION
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(3) RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS
SFAS 143
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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 14, the preliminary purchase price allocation for this acquisition did not include estimates to quantify the asset retirement obligations and will be adjusted in future periods when an analysis in accordance with SFAS 143 can be completed.
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EITF 02-3
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(4) RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
(5) RECLASSIFICATIONS
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(6) EARNINGS PER SHARE
As further described in Note 16, on April 30, 2003, the Company completed a public offering of 4.6 million shares of common stock. Accordingly, this transaction will significantly affect the weighted average number of common shares outstanding used in earnings per share calculations of future periods.
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(7) COMPREHENSIVE INCOME
The following table presents the components of the Company's comprehensive income:
(8) CHANGES IN COMMON STOCK
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(9) CHANGES IN LONG-TERM DEBT AND NOTES PAYABLE
(10) GUARANTEES
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(11) SUMMARY OF INFORMATION RELATING TO SEGMENTS OF THE COMPANY’S BUSINESS
*Operating revenues for Energy marketing are presented in accordance with EITF 02-3 as described in Note 3.
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(12) RISK MANAGEMENT ACTIVITIES
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Trading Activities
Natural Gas Marketing
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Non-trading Energy Activities
Crude Oil Marketing
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Oil and Gas Exploration and Production
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*crude in barrels, gas in MMBtu’s
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Financing Activities
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(13) LEGAL PROCEEDINGS
Fires
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Federal Energy Regulatory Commission (FERC) Investigation
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Commodity Futures Trading Commission Investigation
Ongoing Proceedings
(14) ACQUISITIONS
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(15) DISCONTINUED OPERATION
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(16) SUBSEQUENT EVENTS
Common Stock Offering
Treasury Lock Acquired
Senior Unsecured Notes Offering
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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 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 average of 60,000 customers in South Dakota, Wyoming and Montana. Our communications group offers state-of-the-art broadband communications services to over 25,000 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 March 31, 2003 Compared to Three Months Ended March 31, 2002. Consolidated income from continuing operations for the three-month period ended March 31, 2003 was $16.9 million or $0.62 per share compared to $14.9 million or $0.55 per share in the same period of the prior year.
The increase in income from continuing operations was a result of higher oil and gas prices and gas marketing volumes and margins, an increase in power sales resulting from higher generation capacity in our power generation segment 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.
Net income for the three months ended March 31, 2003, included a charge of $2.7 million or ($0.10) 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 $(1.7) million or $(0.06) per share for the three months ended March 31, 2002. Prior year results of operations have been restated to reflect the discontinued operations.
Consolidated revenues for the three-month period ended March 31, 2003 were $299.3 million compared to $170.6 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 contracted capacity. Energy marketing revenues increased 126 percent, due primarily to a 41 percent increase in natural gas average daily volumes marketed and a 32 percent increase in crude oil average daily volumes marketed. Oil and gas revenue increased 49 percent, primarily due to a 14 percent increase in production. Mining revenue increased slightly, due to a 14 percent increase in coal production partially offset by lower average prices received. Revenues from the electric utility group increased 18 percent, due to a 53 percent increase in off-system sales and a 43 percent increase in average prices received. The communications group revenue increased 15 percent as a result of a 26 percent increase in its customer base.
Consolidated operating expenses for the three-month period increased from $139.3 million in 2002 to $260.6 million in 2003. Approximately 78 percent of the increase resulted from our crude oil marketing activities where the cost of crude oil sales were substantially higher due to increased volumes sold at higher prices. The remaining 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.
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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:
*includes a 90 MW plant under a lease arrangement
The following is a summary of average daily energy marketing volumes:
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Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002. Income from continuing operations for the integrated energy group for the three months ended March 31, 2003 was $12.3 million, compared to $9.5 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 from our energy marketing segment increased approximately $2.7 million due to a 41 percent increase in average daily gas volumes marketed and increased margins received at our gas marketing operations. Income from continuing operations in our power generation segment declined $0.2 million. Excluding the $1.9 million benefit mentioned above, income from continuing operations from our power generation segment increased approximately $1.7 million due to increased generating capacity in service. Income from continuing operations at our oil and gas segment increased approximately $1.0 million due to higher prices received compared to 2002 and a 14 percent increase in production. Income from continuing operations for the mining segment decreased $0.8 million as higher production volumes were more than offset by lower average prices and higher operating costs.
Energy Marketing
Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002. The increase in revenues is attributed to substantially higher crude oil sales as a result of a 32 percent increase in barrels marketed at average prices 81 percent higher than those received during 2002. Revenue increases from our crude oil marketing were offset by a similar increase in the cost of crude oil sold. Income from continuing operations increased $2.7 million due to a 41 percent increase in average daily natural gas volumes marketed with increased margins received. Net income decreased 9 percent due to a change in accounting principle of $(2.9) million, net of tax related to the adoption of EITF 02-3. 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 March 31, 2003 were $1.7 million compared to a $1.0 million loss for the three month period ended March 31, 2002, resulting in a quarter over quarter increase of $2.7 million pre-tax.
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Power Generation
Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002. Revenue and operating income increased 53 percent and 11 percent, respectively for the three-month period ended March 31, 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 March 31, 2003, we had 1,046 megawatts of independent power capacity in service compared to 646 megawatts at March 31, 2002.
Net income for the power generation segment decreased $1.1 million due to a $1.9 million after-tax benefit in 2002 related to the collection of previously reserved amounts for California operations and a $0.9 million after-tax benefit in 2002 from a change in accounting principle related to the adoption of SFAS 142. The net income decrease was partially offset by the earnings generated from the additional generating capacity.
Oil and Gas
The following is a summary of our internally estimated economically recoverable oil and gas reserves measured using constant product prices of $31.04 per barrel of oil and $5.05 per Mcf of natural gas as of March 31, 2003 and $26.31 per barrel of oil and $3.28 per Mcf of natural gas as of March 31, 2002. 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.
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Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002. Revenue from our oil and gas production business segment increased 49 percent for the three-month period ended March 31, 2003, compared to the same period in 2002, due to a 14 percent increase in production and a 30 percent increase in the average price received.
Operating expenses increased 33 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. 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 March 31, 2003 Compared to Three Months Ended March 31, 2002. Revenue from our mining segment was flat with 2002 and income before the change in accounting principle decreased 32 percent for the three-month period ended March 31, 2003, compared to the same period in 2002. A 14 percent increase in tons of coal sold was partially offset by lower average prices received.
Operating expenses increased 12 percent or approximately $0.7 million primarily due to higher operating costs related to the increase in production and an increase in general and administrative costs.
Income from continuing operations decreased due to an increase in direct mining costs and corporate allocations partially offset by the increase in tons of coal sold in the first quarter of 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 March 31, 2003 Compared to Three Months Ended March 31, 2002. Electric utility revenues increased 18 percent for the three-month period ended March 31, 2003, compared to the same period in the prior year. The increase in revenue was primarily due to a 53 percent increase in off-system electric megawatt-hour sales, and a 43 percent increase in average prices received. Firm residential and commercial electricity revenues increased 2 percent and 4 percent, respectively, but were offset by a 9 percent decline in industrial revenues primarily due to the closing of Homestake Gold Mine and Federal Beef Processors.
Electric operating expenses increased 32 percent for the three month period ended March 31, 2003, compared to the same period in the prior year. The increase in operating expenses was primarily due to an increase in fuel and purchased power costs and an increase in administrative and general costs. Fuel and purchased power costs increased $5.3 million due to the increase in off-system electric sales. Administrative and general expenses increased primarily due to a $0.5 million increase in pension expense and a $0.7 million increase in salaries.
Interest expense increased $1.3 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 $1.1 million primarily due to the increase in interest expense, pension expense and administrative and general salaries, partially offset by an increase in electricity sales margins and transmission revenues.
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Communications Group
In 2003, reported business customers were adjusted for the consolidation of multiple-location business customers, business orders and temporary business access lines.
Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002. The communications business group’s net loss for the three-month period ended March 31, 2003 was $1.8 million, compared to $2.2 million in 2002. The performance improvement is due largely to a 15 percent increase in revenue as a result of a larger customer base, partially offset by increased depreciation and administrative and general expenses.
The total number of customers exceeded 25,000 at the end of March 2003 – a 2 percent increase over the customer base at December 31, 2002 and a 26 percent increase compared to March 31, 2002.
Earnings Guidance
We recently reaffirmed our long-term earnings per share growth rate target of 8 percent to 10 percent per year. Due to the initial dilutive effect of our common stock offering completed April 30, 2003, we expect 2003 earnings per share from continuing operations to approximate 2002 results.
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 three-month period ended March 31, 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 continue to fund property and investment additions primarily related to construction of additional electric generation facilities for our integrated energy business group 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 decreased $2.9 million for the three-month period ended March 31, 2003 compared to the same period in the prior year primarily due to the decrease in cash provided by changes in working capital.
During the three months ended March 31, 2003, we had cash outflows for investing activities of $31.0 million, which includes $30.3 million for property, plant and equipment additions and the acquisition of assets. Net cash outflows from financing activities totaled $15.7 million, primarily due to dividend payments and debt repayments.
Dividends
Dividends paid on our common stock totaled $0.30 per share in the first quarter of 2003. This reflects a 3.5 percent increase from the first quarter of 2002, 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.
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 March 31, 2003, we had approximately $68 million of cash unrestricted for operations and $395 million of credit through revolving bank facilities. Approximately $37 million of the cash balance at March 31, 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 March 31, 2003, we had $286.5 million of bank borrowings outstanding under these facilities. After inclusion of applicable letters of credit, the remaining borrowing capacity under the bank facilities was $51.2 million at March 31, 2003.
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A significant cash event occurred subsequent to the first quarter. On April 30, 2003, we completed a stock offering providing approximately $118 million in net proceeds. The proceeds were used to pay off a $50 million credit facility due in May 2003 and the remaining $68 million reduced the amount drawn on our 364-day revolving credit facility due August 26, 2003. After giving effect to this transaction on April 30, 2003, we had $213.5 million of bank borrowings outstanding under our corporate credit facilities with $124.2 million of remaining borrowing capacity available after the inclusion of applicable letters of credit.
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 March 31, 2003, we were in compliance with the above covenants.
Our consolidated net worth was $555.7 million at March 31, 2003, which was approximately $100 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, 2003 was 52.6 percent and our total debt leverage (long-term debt and short-term debt) was 63.8 percent. After giving effect to the common stock offering completed in April 2003 and the application of the net proceeds of the offering, our pro forma total debt leverage ratio as of March 31, 2003 was 56.1 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. At March 31, 2003, there were outstanding letters of credit issued under the facility of $69.9 million with no borrowing balances outstanding on the facility.
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 March 31, 2003, Black Hills Energy Resources had letters of credit outstanding of $8.7 million.
Subsequent to the end of the quarter, on May 13, 2003, our corporate credit rating was downgraded to “BBB-” by Standard and Poor’s Ratings Group.
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.
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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. No new guarantees were issued during the three months ended March 31, 2003. At March 31, 2003, we had guarantees totaling $229.5 million in place.
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 CFTC’s industry wide investigation of trade and trade reporting practices of power and natural gas trading companies. Since that time, we have produced documents and other materials in response to more specific requests relating to the reporting of natural gas trading information to energy industry publications. We are also conducting an internal investigation into the accuracy of information that former employees of Enserco Energy Inc., our gas marketing subsidiary, voluntarily reported to trade publications. As a part of our internal investigation and in response to CFTC’s document request, we provided documents and materials to the CFTC, including information identifying instances in which it appears that former employees at Enserco provided inaccurate reports of natural gas transactions to one or more industry trade publications. We intend to continue our policy of cooperation with the CFTC. However, both our internal and CFTC’s investigations are continuing, and we cannot predict their outcome or whether they will lead to legal proceedings against us, civil or criminal fines or penalties, or other regulatory action which, in turn, could adversely affect our financial condition or results of operations.
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:
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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.
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.
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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:
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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 three month period ended March 31, 2003 (in thousands):
On January 1, 2003, the Company adopted EITF Issue No. 02-3. As described in Notes 3 and 12 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 March 31, 2003.
At March 31, 2003, we had a mark to fair value unrealized loss of $0.7 million for our natural gas marketing activities. Of this amount, $0.9 million was current and $(1.6) million was non-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 12 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
Within 90 days prior to the filing date of the 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-14(c) and 15d-14(c) of the Securities Exchange Act of 1934 (Exchange Act). 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 controls
Our Chief Executive Officer and Chief Financial Officer have concluded that there were no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of their most recent evaluation of such controls, and that there were no significant deficiencies or material weaknesses in our internal controls.
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Part II — Other Information
Item 1. Legal Proceedings
Item 2. Changes in Securities and Use of Proceeds
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Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits —
Agreement and Plan of Merger among Black Hills Corporation, Black Hills Acquisition Corp., and Mallon Resources Corporation, dated as of October 1, 2002 (filed as Annex A to the Proxy Statement/Prospectus included in the Registration Statement of Form S-4 No. 333-101576).
Consent of Petroleum Engineer and Geologist.
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(b) Reports on Form 8-K
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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 15, 2003
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I, Daniel P. Landguth, certify that:
I have reviewed this quarterly report on Form 10-Q of Black Hills Corporation;
Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
Evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and
Presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and
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The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: May 15, 2003
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I, Mark T. Thies, certify that:
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EXHIBIT INDEX
Description
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