Annual Report (Form 10-K), fiscal year 1993





ITEM 3. LEGAL PROCEEDINGS
Williston Basin has been named as a defendant in a legal action primarily related to its transportation services. Such suit was filed by KN as described under "Pending Litigation". Williston Basin's assessment of this proceeding is included in the description of the litigation.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the fourth quarter of 1993. PART II
ITEM 5.

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
MDU Resources Group, Inc. common stock is listed on the New York Stock Exchange and uses the symbol "MDU". The price range of the Company's common stock as reported by the Wall Street Journal composite tape during 1993 and 1992 and dividends declared thereon were as follows:
Common Common Common Stock Stock Price Stock Price Dividends (High) (Low) Per Share
First Quarter . . . . . . . . $29 1/4 $25 7/8 $ .37 Second Quarter. . . . . . . . 32 1/2 29 .37 Third Quarter . . . . . . . . 32 29 3/4 .39 Fourth Quarter. . . . . . . . 33 1/8 30 1/2 .39 $1.52
First Quarter . . . . . . . . $25 3/4 $23 1/4 $ .36 Second Quarter. . . . . . . . 26 7/8 21 7/8 .36 Third Quarter . . . . . . . . 25 1/2 23 7/8 .37 Fourth Quarter. . . . . . . . 26 3/4 25 .37 $1.46
As of December 31, 1993, the Company's common stock was held by approximately 15,100 stockholders.
ITEM 6.

ITEM 6. SELECTED FINANCIAL DATA
Reference is made to selected Financial Data on pages 52 and 53 of the Company's Annual Report which is incorporated herein by reference.
ITEM 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
The following table (in millions of dollars) summarizes the contribution to consolidated earnings by each of the Company's businesses.
Years ended December 31, Business 1993 1992 1991 Utility -- Electric . . . . . . . . . . . . $12.6 $13.3 $15.3 Natural gas. . . . . . . . . . . 1.2 1.4 3.6 13.8 14.7 18.9 Natural gas transmission . . . . . 4.7 3.5 0.5 Mining and construction materials. . . . . . . . . . . . 12.4 10.7 9.8 Oil and natural gas production . . 7.1 5.7 8.0 Earnings on common stock . . . . . $38.0 $34.6 $37.2 Earnings per common share. . . . . $2.00 $1.82 $1.96 Return on average common equity. . 12.3% 11.6% 12.7%
Earnings information presented in this table and in the following discussion is before the $8.9 million ($5.5 million after-tax) cumulative effect of an accounting change. See Note 2 of Notes to Consolidated Financial Statements for a further discussion of this accounting change.
1993 compared to 1992
Consolidated earnings for 1993 are up $3.4 million when compared to 1992. The improvement is attributable to increased earnings from the natural gas transmission, mining and construction materials, and oil and natural gas production businesses, partially offset by a slight decrease in utility earnings. The reasons for such changes are described in the "1993 compared to 1992" discussions which follow.
1992 compared to 1991
Consolidated earnings for 1992 are down $2.6 million from the $37.2 million earned in 1991. The decline was the result of decreased earnings in the utility and oil and natural gas production businesses, partially offset by increased natural gas transmission and mining and construction materials earnings. The reasons for such changes are described in the "1992 compared to 1991" discussions which follow.
________________________________
Reference should be made to Items 1 and 2 -- "Business and Properties - - Interstate Natural Gas Transmission Operations and Property" and Notes 3, 4 and 5 of Notes to Consolidated Financial Statements for information pertinent to pending litigation, regulatory matters and revenues subject to refund and a natural gas repurchase commitment.
Financial and operating data
The following tables (in millions, where applicable) are key financial and operating statistics for each of the Company's business units. Certain reclassifications have been made in the following statistics for 1992 and 1991 to conform to the 1993 presentation. Such reclassifications had no effect on net income or common stockholders' investment as previously reported.
Montana-Dakota -- Electric Operations
Years ended December 31, 1993* 1992 1991
Operating revenues . . . . . . . . $131.1 $123.9 $128.7 Fuel and purchased power . . . . . 41.3 37.9 38.4 Operation and maintenance expenses . . . . . . . . . . . . 37.4 34.2 33.7 Operating income . . . . . . . . . 30.5 30.2 34.6
Retail sales (kWh) . . . . . . . . 1,893.7 1,829.9 1,877.6 Power deliveries to MAPP (kWh) . . 511.0 352.6 331.3
Cost of fuel and purchased power per kWh. . . . . . . . . . $ .016 $ .016 $ .016
Montana-Dakota -- Natural Gas Distribution Operations
Years ended December 31, 1993* 1992 1991 Operating revenues: Sales. . . . . . . . . . . . . . $151.7 $123.8 $134.4 Transportation & other . . . . . 4.3 4.4 4.2 Purchased natural gas sold . . . . 114.0 89.5 98.3 Operation and maintenance expenses . . . . . . . . . . . . 28.6 26.0 23.8 Operating income . . . . . . . . . 4.7 4.5 8.5
Volumes (dk): Sales. . . . . . . . . . . . . . 31.2 26.7 30.1 Transportation . . . . . . . . . 12.7 13.7 12.2 Total throughput . . . . . . . . . 43.9 40.4 42.3
Degree days (% of normal). . . . . 105.5% 87.1% 97.9% Cost of natural gas per dk . . . . $ 3.66 $ 3.35 $ 3.27
*See Note 2 of Notes to Consolidated Financial Statements for a discussion of an accounting change to reflect unbilled revenues.
Williston Basin Years ended December 31, 1993 1992 1991 Operating revenues: Sales for resale. . . . . . . . . $51.3* $63.5* $78.8* Transportation & other. . . . . . 40.0* 35.5* 37.2* Purchased natural gas sold . . . . 20.6 33.6 45.3 Operation and maintenance expenses . . . . . . . . . . . . 39.0** 33.0** 39.6** Operating income . . . . . . . . . 20.1 21.3 19.9
Volumes (dk): Sales for resale: Montana-Dakota. . . . . . . . . 13.0 16.5 19.3 Other . . . . . . . . . . . . . .2 .3 .3 Transportation: Montana-Dakota. . . . . . . . . 27.3 24.9 22.1 Other . . . . . . . . . . . . . 32.1 39.6 31.8 Total throughput . . . . . . . . . 72.6 81.3 73.5
Cost of natural gas per dk . . . . $1.78 $1.91 $2.07 _________________________________ * Includes recovery of deferred natural gas contract buy-out/buy-down costs. . . . . $13.0 $ 5.8 $ 6.5 ** Includes amortization of deferred natural gas contract buy-out/buy-down costs. . . . . $11.8 $ 6.2 $ 6.6
Knife River Years ended December 31, 1993 1992 1991 Operating revenues: Coal. . . . . . . . . . . . . . . $44.2 $43.8 $41.2 Construction materials. . . . . . 46.2 1.2 --- Operation and maintenance expenses . . . . . . . . . . . . 59.6 21.2 20.2 Reclamation expense. . . . . . . . 3.1 3.0 2.8 Severance taxes. . . . . . . . . . 4.4 4.3 4.2 Operating income . . . . . . . . . 17.0 11.5 9.7
Sales (000's): Coal (tons) . . . . . . . . . . . 5,066 4,913 4,731 Aggregates (tons) . . . . . . . . 2,391 263 --- Ready-mixed concrete (cubic yards) . . . . . . . . . 157 --- --- Asphalt (tons). . . . . . . . . . 141 --- ---
Fidelity Oil Years ended December 31, 1993 1992 1991
Operating revenues . . . . . . . . $39.1 $33.8 $33.9 Operation and maintenance expenses. . . . . . . . . . . . . 11.6 12.0 11.8 Depreciation, depletion and amortization. . . . . . . . . . . 12.0 8.8 6.0 Operating income . . . . . . . . . 11.8 9.5 12.6
Production (000's): Oil (barrels) . . . . . . . . . 1,497 1,531 1,491 Natural gas (Mcf). . . . . . . . 8,817 5,024 2,565
Average sales price: Oil (per barrel) . . . . . . . . $14.84 $16.74 $19.90 Natural gas (per Mcf). . . . . . 1.86 1.53 1.48
1993 compared to 1992
Montana-Dakota--Electric Operations
Operating income for the electric business increased due to an improvement in retail sales to residential and commercial markets, primarily the result of colder weather in the first quarter of 1993 and the addition of nearly 540 customers. Also, improving operating income was an increase in deliveries into the MAPP, the result of water conservation efforts by hydroelectric generators and the temporary shutdown of a nuclear generating station in Iowa. Increased fuel and purchased power costs, largely higher demand charges associated with the purchase of an additional five megawatts of firm capacity through a participation power contract partially offset the improvement in operating income. Higher operation and maintenance expenses also negatively affected operating income. Employee benefit-related costs increased operation expense while higher costs associated with repairs made at the Heskett, Big Stone and Coyote stations accounted for the increase in maintenance expense. Earnings from this business unit declined as a result of a decrease in Other Income--Net, reflecting the on-going effects of adopting SFAS No. 106, and increased federal income taxes. A decrease in interest expense due to lower interest rates stemming from long-term debt refinancing in 1992 and lower average short-term borrowings and interest rates, and the aforementioned operating income improvement, somewhat offset the earnings decline.
Montana-Dakota--Natural Gas Distribution Operations
Sales increases of 4.5 MMdk or $3.6 million, due to significantly colder weather than 1992 and the addition of over 3,500 residential and commercial customers, improved operating income for the natural gas distribution business. However, partially offsetting this improvement were the 1992 refinement of the estimated amount of delivered but unbilled natural gas volumes and increased operation and depreciation expenses. Employee benefit-related costs and distribution and sales expenses related to the system expansion into north-central South Dakota accounted for the majority of the operation expense increase. A Wyoming rate decrease effective in the second quarter of 1992 also reduced the operating income improvement. Gas distribution earnings decreased due to higher financing costs related to increased capital expenditures and carrying charges being accrued on natural gas costs refundable through rate adjustments, offset in part by interest savings resulting from 1992 long-term debt refinancing. The aforementioned operating income change and increased Other Income--Net, primarily due to the return being earned on deferred storage costs and increased interest income earned on natural gas costs recoverable through rate adjustments in Montana, reduced the earnings decline.
Williston Basin
Operating income declined at the natural gas transmission business as a result of decreased transportation volumes reflecting the effects of bypasses by two major transportation customers. Partially offsetting the effects of these bypasses were the increased movement of 3.4 MMdk of natural gas held under the repurchase commitment, due to favorable natural gas prices, and higher volumes transported on the November 1992 interconnection with NSP (1.8 MMdk), although at lower average rates than those replaced. Operating income was also negatively affected by the delay in the implementation of Order 636 until November 1, 1993. See Items 1 and 2 for Williston Basin for further discussions on the implementation of Order 636. Operation expenses increased slightly due to additional reserves related to the Koch settlement, increased transmission expenses and higher employee benefit-related costs. Largely offsetting the increased operation expenses are lower contract restructuring amortizations, an out-of-period adjustment to take-or-pay surcharge amortizations and a 1992 accrual for retroactive company production royalties. An adjustment to regulatory reserves reflected in operating revenues offset the effects of the additional reserves provided for the Koch settlement. Maintenance expenses increased as a result of compressor overhauls at several compressor station facilities. A weather-related sales improvement of 3.3 MMdk, or $2.8 million, combined with increased general rates implemented in November 1992, partially offset the operating income decline. Income from company production improved due to increased production, but at lower average prices. Earnings for this business unit increased due to reduced interest expense on long-term debt, the result of debt refinancing in mid-1993, and lower carrying costs associated with the natural gas repurchase commitment, primarily the result of both lower borrowings and decreased average rates, offset in part by the decline in operating income discussed above.
Knife River
Operating income increased due to sales from the newly acquired Alaskan and Oregon construction materials businesses and an improvement in coal tons sold at all mines, mainly the result of increased demand by electric generation customers. Lower selling prices at the Gascoyne Mine, effective June 1, 1992, following an amendment to the current coal supply agreement, partially offset the operating income increase. An increase in operating expenses resulting from the newly acquired construction materials businesses and a volume-related increase in coal operating expenses, combined with the accrual of SFAS No. 106 costs and increased stripping expense at the Beulah mine, due to higher overburden removal costs, also reduced operating income. Earnings increased due to the above-described operating income improvement, offset in part by reduced investment income (included in Other Income--Net), primarily resulting from lower investable funds due to the 1993 acquisitions and lower earned returns, and increased federal income taxes.
Fidelity Oil
Operating income for the oil and natural gas production business increased as a result of higher natural gas production and prices. In addition, decreased operation and maintenance expenses per equivalent barrel were somewhat offset by volume-related increases in such costs. Partially offsetting the operating income improvement was a decline in oil production and prices and increased depreciation, depletion and amortization, reflecting both increased production and higher rates. The aforementioned increase in operating income was further improved by the realization of certain investment gains resulting in the earnings improvement for this business. Increased interest expense, stemming from both higher average borrowings and rates, and increased federal income taxes, somewhat reduced earnings.
1992 compared to 1991
Montana-Dakota -- Electric Operations
The decline in operating income was due to reduced residential and commercial sales resulting primarily from warmer winter weather combined with a cooler summer than that experienced a year ago. An increase in deliveries into the MAPP, primarily in the fourth quarter, was more than offset by the decline in the average price. The fourth quarter increase in deliveries into the MAPP reflects water conservation efforts by hydroelectric generators. The discounting of sales prices necessitated by a weak wholesale market contributed to the price decline experienced for sales to the MAPP. Higher demand charges associated with the purchase of firm capacity through a participation power contract and an increase in operation expense, primarily payroll and benefit-related, also reduced operating income. The demand charge increase results from the additional purchase of 5 megawatts of firm capacity which began in May 1992 and the passthrough of costs associated with a periodic maintenance outage. Partially mitigating the operating income decline was an increase in large industrial sales, lower depreciation expense and a reduction in maintenance expense reflecting the impact of 1991 maintenance outages at the Heskett and Coyote stations. Earnings from this business unit decreased for the reasons discussed above, partially offset by reduced interest expense, the result of certain bond refinancings in the second and fourth quarter of 1991 and the second quarter of 1992 offset in part by increased average borrowings under lines of credit.
Montana-Dakota -- Gas Distribution Operations
A sales decline of 2.4 MMdk or $2.0 million, related to significantly warmer first quarter weather than in 1991, the refinement of the estimated amount of delivered but unbilled natural gas volumes and an increase in operation expenses, largely payroll and benefit-related costs, were the primary contributors to the operating income decline. The addition of over 2,400 residential and commercial customers mitigated in part the sales decline. Transportation volumes increased largely due to the addition of a large industrial customer in the second quarter of 1992, although at discounted rates, and the conversion of a principal customer from firm commercial sales to transportation. A North Dakota rate increase, which was placed into effect in the third quarter of 1991, partially mitigated the operating income decline. Gas distribution earnings decreased for the reasons discussed above offset in part by decreased interest expense related to carrying charges being accrued on natural gas costs refundable through rate adjustments and the effects of the bond refinancings discussed in Electric Operations above.
Williston Basin
Operating income improved as a result of increased transportation volumes reflecting the movement of 4.4 MMdk of natural gas held under the repurchase commitment, due to favorable natural gas prices. Reduced operation expenses resulting from December 1991 additions to reserves maintained for regulatory and market uncertainties and reduced litigation expenses and contract restructuring amortizations, offset in part by increased payroll and benefit-related costs and the accrual for retroactive company production royalties, also contributed to the increase in operating income. Partially offsetting the operating income increase were decreased weather-related sales of approximately 571 Mdk or $516,000, lower average realized rates on transportation services, due to a higher level of discounted transportation services being used, and decreased company production revenues, the result of both reduced volumes and lower prices. Earnings for this business unit increased as a result of the changes in operating income discussed above, decreased carrying costs associated with the natural gas repurchase commitment, largely due to lower interest rates, and reduced interest expense on revenues being reserved stemming from lower interest rates and lower carrying charges being accrued on natural gas costs refundable through rate adjustments. Decreased interest income related to recoverable natural gas contract litigation settlement costs and higher company-owned production refund accruals somewhat mitigated the earnings improvement.
Knife River
Increased coal sales at the Beulah mine, primarily due to outages experienced in 1991 by a major electric generation customer, were the primary factor improving operating income. Aggregate sales at the newly acquired construction materials business also added to operating revenues. Decreased coal sales at the Gascoyne and Savage mines due to reduced weather-related demand from electric generating station customers and increased operation and maintenance expenses partially offset the operating income improvement. The increase in operation and maintenance expenses resulted from a volume-related increase in coal operation expenses and first year expenses at the construction materials business offset in part by equipment efficiencies and lower stripping costs due to recovery of third seam coal at the Beulah mine. Mining and construction materials earnings increased for reasons discussed above offset in part by reduced investment income, largely due to lower returns resulting from declining interest rates, and increased corporate development-related costs (both included in Other Income--Net).
Fidelity Oil
An increase in oil and natural gas production was more than offset by lower average sales prices for oil producing the decline in operating income. A volume-related increase in operating costs related to working interests and increased depreciation, depletion and amortization also reduced operating income. Decreased operating costs associated with the net proceeds interests resulting from cost controls implemented by the operator, somewhat mitigated the operating income decline. Earnings for the oil and natural gas production business decreased as a result of the above changes in operating income and increased interest expense stemming from increased average borrowings.
Prospective Information
The operating results of the Company's utility and pipeline businesses are significantly influenced by the weather, the general economy of their respective service territories, and the ability to recover costs through the regulatory process.
Montana-Dakota is generally allowed to recover through general rates the costs of providing utility services which include fuel and purchased power costs and the cost of natural gas purchased. The electric business utilizes either fuel adjustment clauses or expedited rate filings to recover changes in fuel and purchased power costs in the interim periods. The natural gas business has similar mechanisms in place to pass through the changes in natural gas commodity, transportation and storage costs. Both recovery mechanisms reduce the effect the changes in these costs have on Montana-Dakota's results. See Items 1 and 2 for a further discussion of these items as they apply to Montana-Dakota's operations.
In July 1992, Montana-Dakota requested the NDPSC to implement a gas weather normalization adjustment mechanism in November 1992. In October 1992, the NDPSC disallowed the adjustment mechanism. Montana-Dakota requested reconsideration of this matter, which was granted by the NDPSC in December 1992. A continuance was granted until such time as a general natural gas rate case should be filed. Based on a settlement reached with the NDPSC in connection with a general natural gas rate case filed in July 1993, the implementation of the weather normalization adjustment mechanism was omitted from the settlement. See Items 1 and 2 under Montana- Dakota for a further discussion of the weather normalization adjustment mechanism as well as general rate increase applications filed and settlements reached with the NDPSC, SDPUC and WPSC, respectively.
Montana-Dakota is extending natural gas service to 11 north central South Dakota communities at an estimated cost of $9.0 million. This extension has the potential of adding approximately 1.6 MMdk to annual natural gas sales. Service to seven communities began in late 1993 with plans to provide service to the remaining four communities, as well as surveys to determine feasibility in neighboring communities, scheduled for 1994.
See Items 1 and 2 for both Montana-Dakota and Williston Basin for additional information related to the FERC's Order 636, which requires fundamental changes in the way natural gas pipelines do business. Williston Basin, based on a September 1993, FERC order, implemented Order 636 on November 1, 1993. Although no assurances can be provided, the Company believes that Order 636 will not have a significant effect on its financial position or results of operations.
See Items 1 and 2 for Williston Basin for a further discussion on Williston Basin's construction of a 49-mile pipeline in eastern North Dakota and Williston Basin's interconnection in northwestern North Dakota with a Canadian pipeline. Williston Basin continues to evaluate certain opportunities which may exist to increase transportation and storage services through system expansion or interconnections.
In late 1992 and early 1993 two major transportation customers, Koch and Amerada, bypassed Williston Basin's transportation system. As a result of these bypasses, Williston Basin received 11.3 MMdk less natural gas for transportation in 1993 than in 1992. See Items 1 and 2 under Williston Basin for a further discussion of these system bypasses.
On October 1, 1992, as a result of increases in natural gas prices, Williston Basin began to sell and transport a portion of the natural gas held under the repurchase commitment. Williston Basin will continue to aggressively market this natural gas as long as market conditions remain favorable. In addition, it will continue to seek long-term sales contracts. See Items 1 and 2 under Williston Basin for additional information on the natural gas held under this repurchase agreement.
Montana-Dakota and Williston Basin filed suit against Rockwell International Corporation to recover any costs which may be associated with the presence of polychlorinated biphenyls in portions of their natural gas distribution and transmission systems. See Items 1 and 2 under Montana-Dakota and Williston Basin for a discussion of this and other environmental matters.
In early 1993, Knife River, together with the Lignite Energy Council, supported the introduction of legislation in North Dakota which would provide severance tax relief for its Gascoyne Mine. Under the legislation, the state will forego its 50 percent share of severance taxes for coal shipped out of state after July 1, 1995, and local political subdivisions are given the option to forego their 35 percent of the tax. The legislation passed both House and Senate with strong support and was signed by the governor. This tax relief will help keep the price of Gascoyne coal competitive.
Knife River continues to seek out additional growth opportunities. These include not only identifying possibilities for alternate uses of lignite coal but also investigating the acquisition of other surface mining properties, particularly those relating to sand and gravel aggregates and related products such as ready-mixed concrete, asphalt and various finished aggregate products. In 1993, Knife River acquired two construction materials operations, one in Anchorage, Alaska, and the other with locations in Medford, Oregon and Stockton, California. See Items 1 and 2 under Knife River for a further discussion of these acquisitions.
Future cash flows and operating income from oil and natural gas production and reserves are influenced by fluctuations in sales prices as well as the cost of acquiring, finding and producing those reserves. Although Fidelity Oil continues to acquire, develop and explore for oil and natural gas reserves, no assurances can be made as to the future net cash flows from those operations.
On January 1, 1993, Montana-Dakota changed its revenue recognition method to include the accrual of estimated unbilled revenues. This change will provide for a better matching of revenues and expenses and is consistent with predominant industry practice. See Note 2 of Notes to Consolidated Financial Statements for a further discussion of this accounting change.
The FASB issued SFAS No. 109, "Accounting for Income Taxes" (SFAS No. 109) in February 1992, which changes the accounting method used to measure and recognize income tax effects in financial statements. SFAS No. 109, among other things, requires that existing deferred tax balances be revised to reflect any change in statutory rates. The Company adopted this new standard on January 1, 1993. Based on the provisions of SFAS No. 109, the effect on the Company's financial position or results of operations was not material. Any excess deferred income tax balances associated with rate-regulated activities at the time of implementation have been recorded as a regulatory liability and are expected to be reflected as a reduction in future rates charged customers in accordance with applicable regulatory procedures. See Notes 2 and 13 for a further discussion on the adoption of this standard.
In December 1990, the FASB issued SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other than Pensions" (SFAS No. 106). SFAS No. 106 establishes accounting standards for postretirement benefits whereby an employer must recognize in its financial statements on an ongoing basis the actuarially calculated obligation (accumulated postretirement benefit obligation) and related annual costs associated with providing such benefits to employees upon retirement. These benefits are recognized ratably over the employee's term of employment to such employee's eligible retirement date, as earned, rather than the previously used pay-as- you-go practice which recognized such costs when they were paid. The Company adopted this new standard on January 1, 1993. Based on the health care and life insurance benefits which are available to all eligible employees and their dependents upon the employees' retirement, the Company's annual cost based on the provisions of SFAS No. 106 for 1993 is approximately $7.5 million, including amortization of the initial accumulated postretirement benefit obligation of $49 million over 20 years. See Notes 2 and 15 of Notes to Consolidated Financial Statements for a further discussion on the adoption of this standard and the Company's efforts regarding regulatory recovery, including the NDPSC's January 19, 1994, order which requires the expensing, commencing January 1, 1994, of the ongoing SFAS No. 106 incremental expense estimated at $1.0 million annually.
The FASB issued SFAS No. 112, "Employers' Accounting for Postemployment Benefits" (SFAS No. 112) in November 1992. SFAS No. 112 establishes accounting standards for postemployment benefits whereby an employer must recognize the benefits provided to former or inactive employees, their beneficiaries, and covered dependents after employment, but before retirement. SFAS No. 112 is effective for fiscal years beginning after December 15, 1993, and therefore, the Company will be required to adopt this new standard in 1994. The Company believes, based on an evaluation of the benefits it provides which are covered by the provisions of SFAS No. 112, that such amounts are not material to its financial position or results of operations.
Liquidity and Capital Commitments
The Company's construction costs and additional investments in non-regulated mining and construction materials, and oil and natural gas activities (in millions of dollars) for 1991 through 1993 and as anticipated for 1994 through 1996 are summarized in the following table, which also includes the Company's capital needs for the retirement of maturing long-term securities.
Estimated 1991 1992 1993 Company/Description 1994 1995 1996 Montana-Dakota: $ 11.7 $ 13.2 $ 16.2 Electric $16.9 $19.8 $ 19.4 5.8 6.5 15.0 Natural Gas Distribution 12.4 10.4 11.3 17.5 19.7 31.2 29.3 30.2 30.7 4.1 9.4 5.4 Williston Basin 19.5 14.6 24.3 .9 16.3 46.5 Knife River 4.5 5.6 7.6 22.3 25.8 24.9 Fidelity 30.0 30.0 30.0 --- --- 1.0 Prairielands .2 .2 --- 44.8 71.2 109.0 83.5 80.6 92.6
Retirement/Repurchase 94.1 140.3 18.4 of Securities 15.3 10.8 10.8 $138.9 $211.5 $127.4 Total $98.8 $91.4 $103.4
In 1993, both Montana-Dakota's and Williston Basin's internal sources provided all of the funds needed for construction purposes. The Company's capital needs to retire maturing long-term corporate securities were $300,000.
It is anticipated that Montana-Dakota will continue to provide all of the funds required for its construction requirements for the years 1994 through 1996 from internal sources, through the use of its $30 million revolving credit and term loan agreement, all of which is outstanding at December 31, 1993, and through the issuance of long-term debt, the amount and timing of which will depend upon the Company's needs, internal cash generation and market conditions.
Williston Basin expects to meet its construction requirements and financing needs with a combination of internally generated funds, a $35 million line of credit currently available, none of which is outstanding at December 31, 1993, and through the issuance of long-term debt, the amount and timing of which will depend upon the Company's needs, internal cash generation and market conditions.
As further described in Items 1 and 2 under Williston Basin, on August 11, 1993, Koch and Williston Basin reached a settlement that terminated the litigation with respect to all parties. The settlement provided that Williston Basin make an immediate cash payment to Koch of $40 million and to transfer to Koch certain natural gas gathering facilities owned by Williston Basin having a cost, net of accumulated depreciation, of approximately $10.4 million. The company believes that it is entitled to recover from ratepayers most of the costs that were incurred as a result of this settlement. Although the amount of the costs which can ultimately be recovered is subject to regulatory and market uncertainties, Williston Basin believes that financing arrangements currently in place are adequate to finance these costs. See Items 1 and 2 under Williston Basin for a further discussion of this settlement and Williston Basin's efforts regarding regulatory recovery.
In March and May 1993, Williston Basin was directed by the MMS to pay approximately $3.5 million, plus interest, in claimed royalty underpayments for the period December 1, 1978, through February 29, 1988. In December 1993, Williston Basin also received an assessment from the MDR claiming additional production taxes due of $3.7 million, plus interest, for 1988 through 1991 production. See Items 1 and 2 under Williston Basin for a further discussion of Williston Basin's appeal efforts in these matters.
Knife River's 1993 capital needs were met through funds on hand and funds generated from internal sources. It is anticipated that funds on hand and funds generated from internal sources will continue to meet the needs of this business unit for 1994 through 1996, excluding funds which may be required for future acquisitions.
Fidelity Oil's 1993 capital needs related to its oil and natural gas acquisition, development and exploration program were met through funds generated from internal sources and a $20 million secured line of credit. It is anticipated that Fidelity's 1994 through 1996 capital needs will be met from internal sources and its secured line of credit. There was $1.5 million outstanding at December 31, 1993, under the secured line of credit.
See Note 13 of Notes to the Consolidated Financial Statements for a discussion of deficiency notices received from the IRS proposing substantial additional income taxes. The level of funds which could be required as a result of the proposed deficiencies could be significant if the IRS position were upheld.
Prairielands' 1993 capital needs were met through funds generated internally. It is anticipated that Prairielands' 1994 and 1995 capital needs will be met through funds generated from internal sources and a $5 million line of credit, $2.0 million of which is outstanding at December 31, 1993.
The Company utilizes its $40 million lines of credit and its $30 million revolving credit and term loan agreement to meet its short-term financing needs and to take advantage of market conditions when timing the placement of long-term or permanent financing. There was $7.5 million outstanding at December 31, 1993, under the lines of credit.
The Company's issuance of first mortgage debt is subject to certain restrictions imposed under the terms and conditions of its Indenture of Mortgage. Generally, those restrictions require the Company to pledge $1.43 of unfunded property to the Trustee for each dollar of indebtedness incurred under the Indenture and that annual earnings (pretax and before interest charges) as defined in the Indenture, equal at least two times its annualized first mortgage bond interest costs. Under the more restrictive of the two tests, as of December 31, 1993, the Company could have issued approximately $153 million of additional first mortgage bonds.
The Company's coverage of fixed charges including preferred dividends was 3.0 and 2.4 times for 1993 and 1992, respectively. Additionally, the Company's first mortgage bond interest coverage was 3.4 times in 1993 compared to 3.3 times in 1992. Stockholders' equity as a percent of total capitalization was 56% and 53% at December 31, 1993 and 1992, respectively.
Effects of Inflation
The Company's consolidated financial statements reflect historical costs, thus combining the impact of dollars spent at various times. Such dollars have been affected by inflation, which generally erodes the purchasing power of monetary assets and increases operating costs. During times of chronic inflation, the loss of purchasing power and increased operating costs could potentially result in inadequate returns to stockholders primarily because of the lag in rate relief granted by regulatory agencies. Further, because the ratemaking process restricts the amount of depreciation expense to historical costs, cash flows from the recovery of such depreciation are inadequate to replace utility plant.
ITEM 8.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Reference is made to Pages 27 through 51 of the Annual Report.
ITEM 9.

ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.



ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Reference is made to Pages 3 through 6 and 13 and 14 of the Company's Proxy Statement dated March 7, 1994 (Proxy Statement) which is incorporated herein by reference.
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION
Reference is made to Pages 7 through 13 of the Proxy Statement.
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Reference is made to Page 14 of the Proxy Statement.
ITEM 13.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None. PART IV
ITEM 14.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Financial Statements, Financial Statement Schedules and Exhibits.
Index to Financial Statements and Financial Statement Schedules.
1. Financial Statements:
Report of Independent Public Accountants. . . . . * Consolidated Statements of Income for each of the three years in the period ended December 31, 1993 . . . . . . . . . . . . . . . * Consolidated Balance Sheets at December 31, 1993, 1992 and 1991 . . . . . . . . . . . . . . * Consolidated Statements of Capitalization at December 31, 1993, 1992 and 1991. . . . . . . . * Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 1993 . . . . . . . . . . . . . . . * Notes to Consolidated Financial Statements. . . . *
2. Financial Statement Schedules:
Report of Independent Public Accountants on Schedules . . . . . . . . . . . . . . . . . ** Schedule V -- Property, Plant and Equipment for the three years ended December 31, 1993 Schedule VI -- Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment for the three years ended December 31, 1993 . . . . . . . . . . . . ** Schedule IX -- Short-Term Borrowings for each of the three years in the period ended December 31, 1993 . . . . . . . . . . . . . . . ** Schedule X -- Supplementary Income Statement Information for each of the three years in the period ended December 31, 1993 . . . . . **
Schedules other than those listed above are omitted because of the absence of the conditions under which they are required, or because the information required is included in the Company's Consolidated Financial Statements and Notes thereto. ____________________
* The Consolidated Financial Statements listed in the above index which are included in the Company's Annual Report to Stockholders for 1993 are hereby incorporated by reference. With the exception of the pages referred to in Items 6 and 8, the Company's Annual Report to Stockholders for 1993 is not to be deemed filed as part of this report. **Filed herewith. 3. Exhibits:
3(a) Composite Certificate of Incorporation of MDU Resources Group, Inc., as amended to date, filed as Exhibit 4(a) in Registration No. 33-13092 . . . . . . . . . * 3(b) By-laws of MDU Resources Group, Inc., as amended to date. . . . . . . . . . . . . ** 4(a) Indenture of Mortgage, dated as of May 1, 1939, as restated in the Forty-Fifth Supplemental Indenture, dated as of April 21, 1992, and the Forty-Sixth through Forty-Eighth Supplements thereto between the Company and the New York Trust Company (The Bank of New York, successor Corporate Trustee) and A. C. Downing (W. T. Cunningham, successor Co-Trustee), filed as Exhibit 4(a) in Registration No. 33-66682; and Exhibits 4(e), 4(f) and 4(g) in Registration No. 33-53896 . . . * + 10(a) Management Incentive Compensation Plan, filed as Exhibit 10(a) in Registration No. 33-66682. . . . . . . . . . . . . . . . * + 10(b) 1992 Key Employee Stock Option Plan, filed as Exhibit 10(f) in Registration No. 33-66682. . . . . . . . . . . . . . . . * + 10(c) Restricted Stock Bonus Plan, filed as Exhibit 10(b) in Registration No. 33-66682. . . . . . . . . . . . . . . . * + 10(d) Supplemental Income Security Plan, filed as Exhibit 10(c) in Registration No. 33-66682. . . . . . . . . . . . . . . . * + 10(e) Directors' Compensation Policy, filed as Exhibit 10(d) in Registration No. 33-66682. . . . . . . . . . . . . . . . * + 10(f) Deferred Compensation Plan for Directors, filed as Exhibit 10(e) in Registration No. 33-66682. . . . . . . . . . . . . . . . * 13 Financial statements and supplementary data as contained in the Annual Report to Stockholders for 1993 . . . . . . . . . . . ** 21 Subsidiaries of MDU Resources Group, Inc. . ** 23(a) Consent of Independent Public Accountants . ** 23(b) Consent of Engineer . . . . . . . . . . . . ** 23(c) Consent of Engineer . . . . . . . . . . . . **
(b) Reports on Form 8-K.
None. ____________________
* Incorporated herein by reference as indicated. ** Filed herewith. + Management contract, compensatory plan or arrangement required to be filed as an exhibit to this form pursuant to Item 14(c) of this report.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULES
To MDU Resources Group, Inc:
We have audited, in accordance with generally accepted auditing standards, the consolidated financial statements included in the MDU Resources Group, Inc. Annual Report to Stockholders incorporated by reference in this Form 10-K, and have issued our report thereon dated January 25, 1994. Our audits of the consolidated financial statements were made for the purpose of forming an opinion on those statements taken as a whole. The schedules are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
/s/ ARTHUR ANDERSEN & CO. ARTHUR ANDERSEN & CO.
Minneapolis, Minnesota, January 25, 1994
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*Reclassification between plant accounts.
Plant is depreciated on a straight-line basis as follows:
Electric . . . . . . . . . . . . . . . . . . . .3.2% Natural Gas Distribution. . . . . . . . . . . . .4.3% Natural Gas Transmission. . . . . . . . . . . . .3.5% Mining and Construction Materials . . . . . . . .3.3 to 33.3%
Depletion of natural gas, coal and oil production properties is provided on a unit-of-production method based on estimated proved recoverable reserves.
____________________
*Reclassification between plant accounts.
Plant is depreciated on a straight-line basis as follows:
Electric . . . . . . . . . . . . . . . . . . . .3.2% Natural Gas Distribution. . . . . . . . . . . . .4.3% Natural Gas Transmission. . . . . . . . . . . . .3.1% Mining and Construction Materials . . . . . . . .3.3 to 33.3%
Depletion of natural gas, coal and oil production properties is provided on a unit-of-production method based on estimated proved recoverable reserves.
____________________
*Reclassification between plant accounts.
Plant is depreciated on a straight-line basis as follows:
Electric . . . . . . . . . . . . . . . . . . . .3.3% Natural Gas Distribution. . . . . . . . . . . . .4.3% Natural Gas Transmission. . . . . . . . . . . . .3.0% Mining and Construction Materials . . . . . . . .3.3 to 33.3%
Depletion of natural gas, coal and oil production properties is provided on a unit-of-production method based on estimated proved recoverable reserves.
____________________
(a) Includes depreciation on transportation and other equipment that is charged to construction, operations, maintenance and merchandising accounts.
____________________
(a) Includes depreciation on transportation and other equipment that is charged to construction, operations, maintenance and merchandising accounts.
____________________
(a) Includes depreciation on transportation and other equipment that is charged to construction, operations, maintenance and merchandising accounts.
The Company and its subsidiaries had unsecured lines of credit from several banks totalling $86 million at December 31, 1993, $80 million at December 31, 1992, and $73 million at December 31, 1991. These line of credit agreements provide for bank borrowings against the lines and/or support for commercial paper issues. The agreements provide for commitment fees at varying rates. The unused portions of the lines of credit are subject to withdrawal based on the occurrence of certain events.
The weighted average interest rate is calculated by dividing interest expense for the year by the amount of average daily borrowings outstanding.
Note: Depreciation and amortization of intangible assets, preoperating costs and similar deferrals, royalties and advertising costs are omitted as they are each less than 1% of operating revenues.