ML20107H081
| ML20107H081 | |
| Person / Time | |
|---|---|
| Site: | Monticello, Prairie Island  |
| Issue date: | 04/16/1996 |
| From: | Richard Anderson NORTHERN STATES POWER CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| NUDOCS 9604240029 | |
| Download: ML20107H081 (1) | |
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5; Northem States Power Company 414 Nicollet Mall Minneapolis, Minnesota 55401 1927 Telephone (612) 330-5500 l
April 16, 1996 10 CFR 50.71(b) l U.
S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C.
20555 MONTICELLO NUCLEAR GENERATING PLANT Docket No. 50-263 License No. DPR-22 PRAIRIE ISLAND NUCLEAR GENERATING PLANT Docket No.
50-282 License No. DPR-40 50-306 DPR-60
~
Submittal of 1995 Annual Report Includino the Certified Financial Statements In accordance with 10 CFR 50.71(b) and Item No. 70 in Regulatory Guide 10.1, enclosed are ten (10) copies of our 1995 Annual Report, including the certified financial statements.
If you have any questions with regard to this information, please call Scott L. Weatherby at 612-330-7643 or Mel opstad at 612-295-1653.
Sincerely, f)hb Y, D (er Roger O.
Anderson
- Director, Licensing & Management Issues Enclosures c: w/ enclosure Regional Administrator-III, NRC Monticello NRR Project Manager, NRC Monticello Resident Inspector, NRC Prairie Island NRR Project Manager, NRC Prairie Island Resident Inspector, NRC l
c: w/o enclosure State of Minnesota, Attn Kris Sanda J E Silberg S L Weatherby 230048 Fde J )D0460mMON IILMhPEMOIC M96AN,,RP1 L TR 9604240029 960416 PDR ADOCK 05000263 pd Y y
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P FINANCIAL
SUMMARY
Return on Common Equity Earnings Per Share Common Stock Price Range 21 Years of Dividend Growth Percent Dollars Per Share Dollars Per Share Dollars Per Share 14 5.50 55 3.50 -
II 3.25 5.00 50 12
~
3.00
~
4.50 -
45.
~
11 2.75 10 4.00 40 1 50 9
3.50 35 23
~
8 22 3.00 30 7
1.75 2.50 25 l
6 1.50 5
2.00 20 1.25 4
1.50 15 1.00 _
1.00 10 2
.bo 1
.25 0
0 0
0 h !
b h !
h g Total g Total Year-End g Continuing Operstions N coatinuia0 operations Excluding Accounting Excluding Accounting Change and Discontmued Change and Discontinued Telephone Operations Telephone Operations Financial Highlights CONTENTS Year ended Det 31 1995 1994 % Change letter to Shareholders 2
karnings per share L3.91 S3.46 13.0 %
Dividends declared Operations Review 6
per share
$2.685
$2.625 2.3%
Directors and Officers 16 Utility operating revenues (millions)
$2,568.6
$2.486.5 3.3%
Management's Discussion and Analysis 18 Netincome (millions)
$275.8
$243.5 13.3 %
Consolidated Financial Statements 28
. Return on common equity 13.4 %
12.4 %
Notes to F.inancial Statements 34 Assets (millions)
$6,228.6
$5,949.7 4.6%
Customers (thousands) 1,821.4 1,786.4 2.0%
Reports of Management and Peak electric Independent Accountants 50 demand {rnegawatts) 7,519 7,101 5.9%
Financial Statistics 51 Retail electnc energy sales (millions of kilowatt hours) 34,500 33,096 4.2%
Operating Statistics 52 Benefit employees 6,829 7,032 (2.9%)
Shareholderinformation 55 i
Y i
1 Netincome Market Price and Book Value Div,dend Payout Ratio Average Cost of Dollars in Millions at year.End Percent of Earnings Long-Term Debt Dollars Par share Percent 32
~ ~
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2 m
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to - ~ ~
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300
~
110 40
~
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250 100
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100 70 8
mit ire p, io 2
50 b
60 h
0 0
50 0
b h
h b
i g Total g MarketPrice 1992 Payout Excluding Accounting Change g Continuingoperations g BookValue Excluding Accounting Change and Discontinued Telephone Operations COMPANY DESCRIPTION Northern States Power Company (NSP), headquar-Viking Gas Transmission Company, a wholly owned tered in Minneapolis, Minnesota, is a major U.S. utility subsidiary, owns and operates a 500-mile interstate with growing domestic and overseas non-regulated natural gas pipeline providing gas transportation ser-energy ventures. NSP and its wholly owned sub-vices to customers in the Upper Midwest from con-sidiary, Northern States Power Company-Wisconsin, nections with four major pipelines in the United operate generation, transmission and distribution States and Canada.
facilities providing electricity to about 1.4 million customers in Minnesota, Wisconsin, North Dakota, Cenergy, Inc., another wholly owned subsidiary, South Dakota and Michigan. The two companies became Cenerprise, Inc. on January 1,1996. The also distribute natural gas to more than :J0,000 cus-company markets natural gas, electricity and energy-tomers in Minnesota, Wisconsin, North Dakota and related services throughout the United States.
Michigan, and provide a variety of energy related services throughout their service areas.
i NRG Energy,Inc., a wholly owned subsidiary, oper-ates and has interests in independent, non-regulated
}
power and energy businesses in the United States and other countries, with major projects in Germany and Australia.
.. - -_- _.. - -.-. - -.~
i P
i a
9 LETTER TO SHAREHOLDERS
+
"ineteen ninety-Gvc was another good year for your company. Our Gnancial performance was strong, our subsidiaries continued to seek opportunities to grow and we took significant action to help ensure
)
success in the years ahead.
f i
d M
The single most important event in 1995 1
/
was our agreement to merge with Wiscon-
.)
sin Energy Corporation to form Primergy
)
l Corporation. We announced the plan on hiay 1, and shareholders of both companies gave their overwhelming approval in Sep-tember. Now we are pursuing approvals
)
from the Federal Energy Regulatory Com-
)
i mission, the Securities and Exchange Com-T Wh -
mission, the Department of Justice, the James J. Howard Federal Trade Commission, the Nuclear chairman of the Board, President and Chief Executive Officer Regulatory Commission and public service because our industry is at the crossroads of commissions 1 n hiinnesota, Wisconsin, change. Through industry restructuring at North Dakota and hiichigan. We remain the state and federallevels, competition will optimistic that the merger will be com-continue to increase and more open electric pleted by January 1,1997.
- markets will enable commercial, industrial and even residential customers to choose i
)
Wisconsin Energy is an electric and natural their energy suppliers. We want them to gas utility headquartered in hfilwaukee that choose Primergy. We believe the merger serves much of eastern Wisconsin and por-will help us succeed in the new marketplace j
tions of the Upper Peninsula of hiichigan.
and help your company continue to grow Like NSP, Wisconsin Energy has low and prosper. By ensuring continued com-l prices,is Gnancially sound, has commend-petitive prices, high-quality services and able operating records and is committed to commitment to customer satisfaction, l
environmental protection, safety and com-Primergy will help communities attract J
munity involvement. NSP and Wisconsin new business, add jobs and strengthen the Energy Gt well together.
economy in our combined service area.
I 3
j We are enthusiastic about the merger NSP and Wisconsin Energy h>ok forward to 4
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j i
t 2
I 5'
(.
a competition, and we intend to be ready for it ongoing operations, excluding non-recurring
- in all respects. We have the vision, the tech-transactions, were $3.69 per share, compared nologies and the expertise. We have employ-with $3.45 in 1994, a 7 percent increase. Net ecs who can exewte ' our plans in the income for the year ended December 31, empowered work environment we are cre-1995, was $275.8 million, compared with ating for them.
$243.5 million in 1994.
NSP and Wisconsin Energy are analyzing Higher electric and natural gas safes and l
carefully the best business and operating reduced operating and maintenance costs practices oflx>th companies and other indus-contributed to strong earnings in 1995.
i try leaders to help shape Primergy for a Total retail electric sales increased 4.2 per-dynamic future. The strong leadership and cent,in part due to a 1.3 percent increase in L
entrepreneurial spirit of our employees will customer accounts. Warmer-than-normal guide our new company. Primergy, to be summer weather also contributed to higher headquartered in Minneapolis, will be posi-demand for electricity. Total gas sales tioned to build long-term value for our increased 9.8 percent, and customer accounts shareholders, while enhancing customer increased 4.1 percent. Higher costs for depre-l service and system reliability, ciation, taxes and interest expenses partially ofTset the increases.
We ivill keep you informed as the merger continues to progress.
We are well-positioned to reach our objec-tive of long-term earnings growth of 5 I also am pleased to report that for the third percent per year, on average, from ongo.
consecutive year, your company's earnings ing operations, per share increased. Earnings per share in 1995 were $3.91, compared with $3.46 in in 1995, our non-regulated businesses, 1994, a 13 percent increase. Earnings from including: NRG Energy, Inc.; Cenergy, Inc.,
" "" I' Primorgy Service Territory 1996; and Eloigne Company continued to seek opportunities to grow. NSP's non-regu-y lated businesses contributed 50 cents per share in 1995, compared with 49 cents per j
K.
'~
share in 1994.
I For the 21st consecutive year, your dividend increased to an annual rate of $2.70 per l
B Area NSP win serve E gawgagEr.
4
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the year at W.m, up
]
common s oc co The new Primergy Corporation's electric and natural gas service area includes portions of Minnesota, from the 1994 close of $44.
l l
Wisconsin, Michigan's Upper Peninsula, North Dakota j
and South Dakota.
l 3
I;
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d i
In addition to strong financial performance, Our plan to temporarily store used fuel on business expansion and preparation for the or adjacent to Mescalero Apache land in future through our proposed merger, your New hiexico also moved forward in 1995.
company also made progress in other areas.
NSP and the Mescalcro Apache tribe are leading a group of more than 20 utilities j
. In 1995, NSP began storing used nuclear participating in the project.
fuel in reinforced steel containers at an cut-door facility adjacent to our Prairie Island In early 1996, the Mescalero project con-i nuclear power plant in Red sortium plans to select a site Wing, Minnesota. By the for the facility and deter-end of the year, three 122-mine the storage technol-ton loaded casks were moved ogy to be used. By the end
~
to the storage area.
~
of the year, the group plans 1.
to submit a project license l
In 1994, the Minnesota 1,eg-application to the Nuclear f'
Regulatory Commission. Our islature authorized NSP to phase in the use of 17 objective is to have the temp-I containers for temporary fuel orary storage facility operat-j storage ifour company meets in 1995, NSP began to store used ing by 2002.
several requirements. They nuclear fuelin reinforced steel con-include finding an alterna-tainers adjacent to the company's The federal government is Prairie Island plant. NSP continues tive storage site in Goodhue to work at the state and federal gov.
responsible for establishing a County, away from Prairie ernment levels to resolve the issue permanent nuclear waste Island, and the development n a permanent basis. Storage at repository. As chairman of the plant site is temporary.
or purchase of 425 mega-the Nuclear Energy Insti-watts of wind-generated and '
tute, I have encouraged 125 megawatts of biomass-generated nuclear utility companies and other groups electricity by 2002. We continue to make to work with government officials at the progress in all three areas.
state and federal levels to resolve the nuclear storage issue. A successful resolu-Members of the Prairie Island Indian tion is vital to our company, our industry Community requested that we provide and our country. Nuclear energy provides funding and land in exchange for their about 30 percent of the electricity our cus-support of new legislation ending the tomers use. They require a variety of reli-requirement for an alternative storage site.
able energy sources, including nuclear One legislative committee approved the power, to enhance economic and environ-proposal. However, it has not mental progress. As shareholders and citi-new advanced in a second committee. We will zens, you can be proud that your company continue to work with members of the has taken a leadership position on these Indian community and the Legislature to important issues.
resolve issues of mutual interest.
4
o 1
i Economic development is a priority for I believe being a good corporate citizen NSP's service area. In 1995, your company makes good business sense. Not only does the participated in 29 economic development effort help people in need,it also will help us projects in Minnesota that helped create or retain and attract customers in the much retain 3,900 jobs and are expected to gener-more competitive environment we face.
are an estimated $6.2 million in annual rev-enues for NSP. The projects include a new Our overall progress in 1995 was gratify-manufacturing facility Seagate Technology, ing. As we move ahead with the merger, Inc. is building in Bloomington, Minnesota, we will continue to focus on improving financial results, promoting In Eau Claire, Wisconsin,
~
{
profitable growth in our Hutchinson Technology Inc.
core electric and natural built a manufacturing plant
'l[
gas businesses and sub-in Gateway West Industrial sidiaries, and operating our j
Park, a partnership between power plants and other NSP and the city of Eau facilities safely, efficiently Claire. A second plant is and with respect for the i
scheduled to be built in 1996 environment. We will con-and operating in 1997. Total Hutchinson Technology Inc. makes tinue to serve our customers employment for the two suspension assemblies for computer well, and we will help our plants is estimated at 2,300.
disk drives and currently supplies employees adapt to changes about 70 percent of the market.
In South Dakota, NSP's in our industry. Our success comrnitment to economic today is a key to providing development in 1995 contributed more than energy for a bright tomorrow.
$2.2 million in revenue for NSP and an esti-mated 2,900 jobs in Sioux Falls alone. In On behalf of our Board of Directors, officer North Dakota, NSP helped attract First team and all of our employees,I thank you Bank, Cargill and Marvin Windows facili-sincerely for your confidence and support.
ties, and assisted the state campaign sup-We will continue to strive to earn it each and porting retention of two U.S. Air Force every day in the years ahead.
bases in Minot and Grand Forks.
Sincerely, We also are proud of our efforts to assist people in our communities. Our corporate contributions program, which primarily focuses on supporting disadvantaged peo-plc, provided $4.5 million in direct grants James J. Howard throughout our service area. Other efforts, Chairman of the Board, including nearly 15,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> of volunteer President and service and a successful United Way cam-Chief Executive Officer paign, also are significant.
February 19,1996 5
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ENERGY FOR A BRIGHT TOMORROW To ensure a bright tomorrow for our years of planning and development, we will shareholders, customers and employ-install a new customer service system (CSS) ces, NSP is meeting the challenges of a that employs the latest information technol-rapidly changing marketplace with aggres-ogy. CSS enables us to deal proactively and sive strategies for the future. Our proposal much more effectively with customer needs, to merge with Wisconsin Energy Cor-particularly the billing requirements oflarge poration to form Primergy customers. With the system's l
Coiporation was the most ease of use, we expect signif-significant of several far-t icant productivity gains as a
reaching decisions that will we provide customers with enhance our ability to grow 1'
faster and more meaningful 5-and thrive in a competitive y
information.
environment. In addition, we are actively pursuing
- . 4 s; improved customer service opportunities for pro 6 table
.y q ; j and productivity also were growth through our non-Odsd,.Nd
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important factors in upgrad-s regulated subsidiaries, and NSP's Chisago substation is one of ing aml redesigning NSP's are investing in new tech-several in the United States and control center, which began nologies to improve produc-Canada newly equipped with tech-operating in April 1995. The nologically advanced electrical tivity and customer service, devices as part of a project upgrad, center, featuring advanced ing NSP's 500-kilovolt transtnission information technology, con-line t canada.
Equally important is our solidates the management of reliance on the fundamental generation, transmission and good practices that continue to contribute to distribution operations in one h> cation.
our success: environmental protection, safety, cost control, workforce effectiveness, and Advances in transmission line technology I
community involvement.
contributed to the success of a three-year pro-ject to upgrade NSP's 500-kilovolt transmis-NSP recognizes that customers are driving sion line to Canada. The project increased the competitive changes occurring in the the capacity of the line by about 45 percent, electric industry. We support competition in eliminating the need to construct hundreds both the wholesale and retail electric markets of miles of new transmission lines while I.
because it allows customers to choose their enabling NSP to fulfill its electricity ex-energy supplier, lowers prices and increases change agreements with the Manitoba operating efficiency.
Hydro-Electric Iloa rd.
Our customers are key to our decision-mak-Technology allows us to achieve marked ing. In March 1996, after more than two improvements in customer service, but 1
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l there is no substitute for developing a per.
Workforce-effectiveness improvements ben-sonal relationship with customers. When efit customers and contribute to NSP's Seagate Technology,Inc., the world's largest bottom line. In 1995, NSP initiated a sig-volume manufacturer of magnetic record-nificant work process redesign for NSP ing heads, was evaluating locations for a Electric's distribution area that resulted in third wafer fabrication facility, NSP formed productivity improvements of 12 percent a consultative account team representing compared with 1994. At NSP's warehousing 4
several areas of the company to help attract operations in hiaple Grove, hiinnesota, Seagate's new facility.
workforce-effectiveness im-provements have reduced Seagate decided to locate the
~ - '
warehousing costs by 52 plant in Bloomington, hiin-4 percent smce 1993, while nesota, part of NSP's service increasing the amount of territory and adjacent to material handled per hour
]}
an existing Seagate facility.
by 47 percent.
Because electric reliability is essential to Seagate's opera-Those improvements demon-tions, NSP accelerated its strate employees' commit-scheduled upgrade of the Honeywell,Inc., one of NSP's largest ment to cost control and Nine hfile Creek substation.
electric customers, has received more customer service, but few than $1 million in rebates for energy-events showcased NSP em-efficiency improvements and the NSP also works closely with installation of a cool storage system.
playee dedication and deter-builders and developers, NSP key account executive AlbertJoe mination as dramatically as another group ofimportant (right) worked with Honeywell's Ben the 1995 heat storms. Two Cyr (left) on lighting improvements.
customers In 1995, NSP record-setting heat waves marked the first anniversary sent electric demand soaring ofits customer service guarantee program, to new highs of 7,439 megawatts on June 20 which guarantees builders and developers and 7,519 megawatts on July 13.
an installation date for electric and natural gas service, and ensures that NSP crews will High demand for sustained periods puts restore sites to their original condition fol-NSP's generation and distribution systems lowing an installation.
to the test and places enormous burdens on our workforce. Once again, however, NSP The program exceeded original expectations employees were equal to the challenge. Our and is receiving positive customer feedback.
line crews, power plant workers, control In addition, the guarantees have reduced center operators, engineers and customer NSP's own design and construction costs by representatives worked around the clock to improving workload management.
ensure an adequate electric supply and restore power when outages occurred.
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The heat also tested the eEcctiveness of NSP's strong. Prairie Island, which holds a No.1 energy management programs, including the rating from INPO as well, was identified as a Saver's Switch *, Peak-Control and Energy-top performer by the Nuclear Energy Insti-Control programs. Saver's Switch
- reduces tute. Both plants received high marks from peak load by cycling participants' central air the Nuclear Regulatory Commission in its conditioners on and off for 15-minute inter-most recent assessments.
vals. Peak-Control and Energy-Control pre-grams require participants to reduce their NSP's coal-fired and hydroelectric plants electric use when NSP is Snished 1995 with outstand-nearing its highest, or peak, ing operating records. Our level of electric demand in
'e, Sherburne County coal-6ted
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exchange for substantially plant once again achieved reduced energy bills. Usmg an availability rating higher the programs, NSP elimi-than 90 percent, compared nated 550 megawatts from its with the industry average peak load during those criti-of 82 percent. Our Allen S.
4 cal hot days.
F*
I King plant remains among the 50 lowest-cost coal-6 red NSP's electric generating Record setting heat waves in 1995 plants in the country.
plants performed admirably tested NSP employees and systems.
during the heat as well. The B th were equalto the challenge.
The company's l" Wisconsin company operated many of hydroelectric plants gener-its peaking units, those ated 968,065 megawatt hours, plants used during times of high energy a 16 percent increase over 1994. At the demand. The Angus Anson peaking plant, Chippewa Falls hydroelectric plant, crews which went into service in September 1994 completed an $8.8 million renovation, and uses two natural-gas-fired turbines, increasing the plant's turbine ef6ciency proved especially reliable and cost-effective.
from 76 percent to 92 percent, gaining addi-tional capacity and allowing it to operate Safe, efTicient, reliable operations also charac-another 40 years. The Chippewa Falls reno-terize the company's nuclear generating units, vation is consistent with the company's which include the Prairie Island and Monti-strategy to keep its existing assets viable and cello plants. In 1995, the Monticello plant maximize the use of a site for the long term.
received a top rating from the Institute of Nuclear Power Operations (INPO),indicat-Another important NSP focus is to secure ing the plant's overall operations were excel-avenues for profitable growth, which is i
lent. Monticello also achieved an availability the goal of our non-regulated operations.
record when it completed 375 days of contin-Once again, those businesses completed an
{
uous operation at year-end and was still going excellent year.
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1 Our wholly owned subsidiary NRG district heating systems in Pittsburgh and Energy, Inc. (NRG) and a partner own a San Francisco.
400-megawatt share of the 960-megawatt Schkopau coal-fired generating plant, located The NEO Corporation (NEO), an NRG near Leipzig, Germany. The first Schkopau subsidiary,is successfully operating 1i small i
unit began its startup process in November hydroelectric facilities across the United 1995 and was declared commercially opera-States and two generating plants that use tional in January 1996. Schkopau burns renewable landfill gas as fuel. NEO has brown coal, which comes exclusive rights to develop at from the nearby MIBRAG least 12 additional landfill 4~
industrial complex, also gas projects.
owned by NRG and part-ners. The second Schkopau Cenergy Inc., which became i
unit is expected to begin Cenerprise,Inc. on January 1, l
commercial operation in 1996, is another non-regu-1 June 1996.
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hockey, NSP Gas has discovered a tricity nationwide. In deliv-stone Power Station. NRG pr mising market for desiccant ering energy management 2
dehumidification systems for new made significant improve-and existing ice arenas. Fueled by services, the company devel-ments to environmental pro-natural gas, the system dehumidifies ops a five-to 10-year energy tection systems at the plant, ice arenas more efficiently than partnership with customers conventional methods.
which ran smoothly in its that typically includes analyz-second year of NRG opera-ing energy use, developing i
tion. In December 1995, NRG signed an and implementing efficiency improve-I agreement to operate and partially own the ments, helping to arrange financing for l
Collinsville Power Station, a 180-megawatt, capital improvements and guaranteeing coal-fired plant also located in Queensland.
projected savings.
4 NRG's domestic operations include the Min-NSP Gas added more new customers in 1995 neapolis Energy Center, which won several than ever before, signing up 16,708 by year-contracts in 1995, including cooling the new end. Many of them were in the Brainerd Federal Reserve Bank under construction in Lakes area, where in 1994 NSP Gas initiated j
Minneapolis, and heating Fairview Riverside its largest gas expansion ever. The utility also Hospital and Augsburg College. NRG also is aggressively pursuing a strategy to sign up acquired a 50 percent interest in Thermal customers on existing NSP gas lines.
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Like NSP's electric business, NSP Gas is rely-To improve customer service and increase ing on new technology to improve productiv-prmluctivity, we will invest in new technol-ity and customer service. NSP technicians ogy when it makes sense. We also will rely on who h>cate underground electric and natural workfi>rce-effectiveness measures to accom-gas lines at customers' request are using a plish those goals.
new computerized field operation system that incorporates radio communications tech-Our regulated and non-regulated operations nology to transmit data to and from the field.
will remain poised to take advantage of The system has increased opportunities for profitable productivity 5 percent and growth. We recognize that reduced dispatch and admin-our success depends on antic-istrative duties by 50 percent.
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sidiary, Viking Gas Trans-k' mission Co. (Viking), plans Finally, we will not abandon a
are under way to expand the fundamentals that made Viking's existing service to NSP a strong company in the the hiinnesota communities NSP employee Barb Thomas (left) past and will contribute to its of Perham and Randall and became a good friend of Beverly competitiveness in the future industrial customer Ameri-(center) and Tammie Thornton after as we merge with Wisconsin participating in the Homeless To can Crystal Sugar, and begin Home project, which links homeless l'nergy to become Primergy, serving ProGold, LLC, a families to housing in the Minneapo-Those fundamentals include new industrial customer in lis St. Paul area. During 1995, NSP the recognition that our employees moved 12 families into a North Dakota. The com-place they could call home.
employees are instrumental pany will install 13.5 miles of to our success, and must be a
new pipeline as part of the skilled and empowered; the expansion, which is scheduled fi>r 1996.
belief that contributing to our communi-ties remains important in a competitive As NSP moves rapidly into a marketplace market; and our ongoing commitment to filled with greater uncertainties, our energy environmental protection, will remain fi>cused on customers and work-ing with them to identify and meet or exceed With those strategies in place and our will-their needs. We will look in particular fbr ingness to pursue them aggressively, we have opportunities that contribute to cupomers the energy fbr a bright tomorrow.
competitiveness and our own profitabil 15
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i.l ?. cw .n . m = 1 N BOARD OF DIRECTORS Back row,left to right G.M. Pieschel, Dr. Margaret R. Preska, H. Lyman Bretting, Dale L Haakenstad and Douglas W. Leatherdale Front row,left to right Richard M. Kovacevich, John E. Pearson,W. John Driscoll, James J. Howard, Allen F. Jacobson, A. Patricia Sampson and David A. Christensen 1 DIRECTORS OF THE MINNESOTA COMPANY H. Lyman (Tad) Bretting (59) 3,4 James J. Howard (60)* John E. Pearson (69) 2,3 neside,it and CEO Chainnan ofthe Ikard, Rethed Chainnan C.G.Bretting AlanufacturingCom;uny,Inc. Besident and CEO The NWNI Companies,Inc.and Stanufacturer of napkin and [uper towel Northern States Power Company Northwestern National Life Insurance Co. Ibkling machines (elected January 1987) (elected December 1983) (elected Afarch 1990) Allen F. Jacobson (69) 2,4 G.M. Pieschel(68) I,3 David A.Christensen(6l)2,4 Retired Chainruiriand CEO Chainnan ofthe lkurd l hrsident and CEO hiinnesota hiining Farmers and hierchants State Bank Raven Industries, Inc. and Stanufacturing Company (elected February 1978) hianufacturers of reinforcal plastics, sewn (elected January 1983) Dr. Margaret R. Preska (58) 2,4 P '" Richard M. Kovacevich (52) 3,4 DistingushedSenice hofessor 1 ct Ic r( 6 Chainnan, Mrsident and Cho Alinnesota State Unn ersities W. John Driscoll(67) 1,2 Norwest Corporation (elected January 1980) Retired Chainnan ofthe /kurd Hokling company fbr lunking institutions A. Patn.. Sampson (47) I,3 cia i and Mrsident (elected April 1990) "#"I'""' Rock Island Company Private investment firm Douglas W. Leatherdale (59) I,2 Dr.Sandersand Aswiates (elected November 1974) Chainnan fthe Board, omdentand CEO A inanagement and hersity The St. Paul Companies, Inc, consulting company Dale L Haakenstad (68) 1,4 Property and liability insurance (elected January l985) Retired nrsident and CEO organization Western States 1.ife Insurance Company (elected April 1991) 8 j (electal February 1978) Board Committees j
- l. Audit j
- 2. Corporate Alanagement j
- 3. Finance
- 4. Pow er Supply
) 4 Of alnes f. k-loWard ks an eX offi([o mentber of a!! committec% 16
PRINClfAL OFFICERS OF THE MINNESOTA COMPANY Douglas D. Antony (53) Gary R. Johnson (49) Roger D. Sandoen (50) ' President-NSF Genemtion l' ice President, General Counsel l' ice President, Contmiler and CIO N* Atland D. Brusven (63) _ Cynthia L Lesker (47) President-NSP Electnc Loren L Taylor (49) l'ia President-Finance Jackie A. Currier (44) Edward L Wetzt (56) l'ia President and Treasurer Edwatd J.McIntyre (45) l' ice Ponident-Nuclear Generation L' ice President and CFO . James J. Howard (60) Keith H.Wietecki(46) Chairman ofthe Board, President and CEO Thomas A.Micheletti(49) President-NSP Gas l' ice President-Public and Gosernment Affairs DIRECTORS OF THE WISCONSIN COMPANY - H. Lyman (Tad) Bretting (59)* Wayne E. Harrison (68) Larry G. Schnack (58)* President and CEO Dairy Farmer Chanalfor C. G. liretting Stanufacturing Company, Inc. - . elected August 1990) University of Wisconsin-Eau Claire ( i Alanufacturer ofnapkin and (#t##'#J Ni#I 1988) RWm6* ([ted President Loren L Taylor (49) 1 0 Wissota Sand and Gravel Company President-NSF Electric Philip M. Gelatt (45)* (elected November 1979) NSP-hfinnesota 4 Pinident
- I John A.Noor(49)
Northern Engravm.g Corporaton Chainnan. President and CEO ng ents eu lia ce thern States Power Company
- Audit Committee members and electrome controls mdustnes M
d ha 19Q (elected Alay 1990) ' PRINCIPAL. OFFICERS OF THE WISCONSIN COMPANY Michael N. Gregerson (48) David E. Ripka (47) Neal A. Siikarla (49) l' ice President-Customer Services Controller Treasurer John P. Moore, Jr. (49). Anthony G. Schuster (51) Patrick D.Watkins (55) Secretary and General Counsel l' ice President-Pourr Delivery and Generation l' ice President-Corporate Services l John A.Noor(49) Chairman, President and CEO DIRECTORS OF N RG EN ERGY, INC. Douglas D. Antony (53) Gary R. Johnson (49) David H. Peterson (54) President-NSP Generation l' ice President, General Counsel Chairman, President and CEO (elected February 1995) and Corparate Secretary NRG Energy, Inc. Northern States Pourr Company (electedJuly 1989) Jackie A. Currier (44) (elected February 1993) l'ia Pusident and Treasurer Northern States Pouer Company Edward J.McIntyre (45) (elatedJanuary 1993) iice Presidentand CFO Northern States Pou er Company (elected hIay 1992) - PRINCIPAL OFFICERS OF N RG ENERGY INC. David H. Peterson (54) Carl A.Carroca(59) Robert McClenachan (44) Chainnan ofthe Board, President and CEO l' ice President l' ice President- " "I*#"' James J. Bender (39) <Luistant GeneralCounsel Julie A.Jorgensen(33) Louise T.Routhe (39) and Corporate Secretary l' ice President and General Counsel l' ice President-Human Resouras Leonard A.Bluhm(50) Valorie A. Knudsen (39) l' ice President and CFO Contmiler Ronald J.WilI(55) l' ice President-Operations and Engineering Lee R. Carlson (56) Craig A.Mataczynski(35) Treasurer l' ice President-U.S. Business Detriorment 17
Northern States Power Company, a Minnesota corporation (the To increase dividends on a regular basis and maintain a long term Company), has two significant subsidiaries Northern States Power average paylut ratio in the r:nge of 65 t2 75 percent. The objective Company, a Wisconsin corporation (the Wisconsin Company), and payout ratio is based on long term earnings expectations. In June NRG Energy,Inc., a Delaware corporation (NRG). The Company also 1995, NSP's annualized common dividend rate was increased by 6 has several other subsidiaries, including Viking Gas Transmission cents per share, or 2.3 percent, from $2.64 to $2.70. The dividend pay-Company (Viking) and Cenergy, Inc. (Cenergy), which changed its out ratio was 69 percent in 1995, within the objective range. name to Cenerprise, Inc., effective Jan.1,1996. The Company and its subsidiaries collectively are referred to herein as NSP. To maintain continued financial strength with a double A bond rating. The Company's first mortgage bonds continued to be rated AA by S&P, j FINANCIAL RESULTS AND OBJECTIVES AA-by Duff & Phelps, Inc. and AA by Fitch Investors Service,Inc. Since ) May 1994, Moody's has rated NSP's first mortgage bonds Al based on 1995 FINANCIAL RESULTS 9 "9 NSP's 1995 earnings per share were $3.91, an increase of 45 cents, or 13.0 percent, over the $3.46 earned in 1994. The effects of sales
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growth in the core electric and gas etility businesses, favorable rable ratings. NSP's pret x interest coverage ratio, based on income weather, and reduced operating and maintenance costs more than "E offset higher costs for depreciation, tax and interest expenses. This ' uc c nsMng o% puunt cwnmon % at provided a regulated utility earnings increase of 44 cents,or 14.8 per-yea and N,.incWng WegWated and non-mgulaM @wadons, cent, from 1994. In.995, non-regulated businesses contributed earn- '"U ings of 50 cents, up 1 cent, or 2.0 percent, from W4 earnings. Investor returns also were enhanced in 1995 by an intresse in the To pih de @M MSP mi@m MG Mim common dividend rate, as discussed below. by the year 2000. NRG expects to meet this goal through growing "U NSP remained financially strong in 1995, as evidenced by continued nesses. Businesses owned or managed by NRG provided 12.4 per-high operating cash flows and interest coverage. NSP maintained cent of NSP's earnings in 1995 and 13.5 percent in 1994. Its first mortgage bond ratmgs with all rating agencies during 1995. NSP bonds are rated double A by all rating agencies except To maintain iong-term average annual earnings growth of 5 percent Moody's Investors Services (Moody's). Moody's downgraded NSP's from ongoing operations, as described below. Excluding the non-first mortgage bond ratings in May 1994 to Al based on its interpre-recurring items discussed later under Factors Affecting Results of tation of provisions of a Mmnesota law enacted in 1994 regarding Operations, NSP achieved earnings per share growth of 7.0 percent the used fuel storage project for the Praine Island nuclear generat-in 1995 over 1994 and an average annual growth of 10.5 percent ing plant. (See discussion of this legislation in Notes 14 and 15 to the gg3' Financial Statements.) In 1995, Moody's placed the Company's rat-i ings on credit review for possible upgrade based on anticipated 1994 1993 cost savings from the proposed merger with Wisconsin Energy Cor. Total earnings per share S3.46 S3.02 poration, which is discussed later. non-recurring items yM 0 01 ""0'
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ota e o investors is measured by dividends plus stock price appreciation. NSP's common dividend rate increased by more than 2 Total earnings per share increased 13.0 percent in 1995 over 1994. percent and its stock price increased by 11.6 percent in 1995. For the most recent 15,10 and five year periods, the total return on NSP BUSINESS STRATEGIES common stock averaged 18,1 percent,12.7 percent and 13.8 percent NSP's management is proactive in shaping the new business environ-per year, respectively. For the same periods, the total return for the ment in which it will be operating. In April 1995, the Company and Standard & Poor's (S&P) composite stock index for 500 industrial smnsin EnwMowahn M enW ine a Mnhe agme-companies averaged 14.8 percent,14.8 percent and 16.5 percent per men a n a sua u nus cwnNnahn in a % gen year, respectively. of-equals" transaction to operate as Primergy Corporation (Primergy), as discussed further under Factors Affectmg Results of Operations. FINANCIAL OBJECTIVES mpan anagmenMea s & Ws uansacen u cmad NSP's financial objectives are: mg a combined enterprise well positioned for an increasingly com-et r on co on e u or the three s d ng n as shareholders of both companies. In addition to this merger strategy, percent. Based on a three-year average, this return was below the g top one fourth of the industry, which was approximately 13.0 percent, but above the median three-year industry average of approximately Focusing on the core energy business. The electric utility industry is E""" becoming more complex as customers, as well as utilrties and federal and state regulators, promote competition. To remain successfulin 18
this more complex environment, NSP will maintain its focus on its mal summer weather in 1995 contributed to sales growth compared core energy related activities, with 1994, which had a cooler than-normal summer. Providing reliable, low-cost, environmentally responsible energy. On a weather-adjusted basis, sales to retail customers increased an Whether energy is produced or purchased through NSP's regulated estimated 2.4 percent in 1995 and 3 4 percent in 1994. Retail sales utility or its non regulated businesses, three general concepts pro-growth for 1996 is estimated to be 0.8 percent over 1995, or 1.9 per-vide a focus for its energy businesses: reliable energy, low-cost cent on a weather-adjusted basis. energy and environmentally responsible energy. Sales to other utilities increased 1.0 percent in 1995 after decreas-Responding to customer needs. Customers will have an increasing ing 21.6 percent in 1994. The 1994 decrease from 1993 largely was number of options for meeting their energy needs, and there will be due to unusually high demand in 1993 from utilities in flood-stricken competition among energy companies for the privilege of serving Midwestern states. those customers. NSP will work with its customers to develop inno-vative products and services that benefit both customers and NSP. The table below summarizes the principal reasons for the electric revenue changes during the past two years: Increasing non-regulated investments and earnings. Non-regulated businesses will be an important part of NSP's future. Deregulation in (Millions of dollars) m==m 1994 vs.1993 the utility industry is expected to provide new investment opportuni-Retail sales growth p q q ties in non-regulated businesses. Participation in these opportunities (excluding weather impacts) b tSWj $56 is expected to improve NSP's total profitability. Estimated impact of weather on h ? h[< (43 8 retail sales volume RESULTS OF OPERATIONS AND LIQUIDITY Sales to other utilities
- 1j (20)
{gG ~ p13 AND CAPITAL RESOURCES Wholesale sales 7 ' N 19 + 2 Conservation cost recovery The following discussion and analys. by management focuses on Fuel adjustment clause recovery 'M 23 is those factors that had a material effect on NSP's financial condition Other rate changes L 15 Energy management discounts an[: ther i (tel! and results of operations during 1995 and 1994. It should be read in o I conjunction with the accompanying Financial Statements and Notes Total revenue increase t 535 4 $92 thereto. Trends and contingencies of a material nature are discussed to the extent known and considered relevant. Material changes in NSP's electric rates are adjusted for changes in fuel and purchased balance sheet items are discussed below and in the accompanying g g Notes to Financial Statements. The discussion and analysis and the through fuel adjustment clauses in all jurisdictions, except as noted related financial statements do not reflect the impact of the Com-below for Wisconsin. While the lag in implementing these billing pany's proposed merger with WEC except for pro forma mformation adjustments is approximately 60 days, an estimate of the adjustments included in Note 18 to the Financial Statements. is recorded in unbilled revenue in the month in which costs are incurred. In Wisconsin, the biennial retail rate review process con-RESULTS OF OPERATIONS siders changes in electric fuel and purchased energy costs in lieu of 1995 Compared with 1994 and 1993 a fuel adjustment clause. NSP's 1995 earnings per share were $3.91, up 45 cents from the $3.46 earned in 1994 and up 89 cents from the $3.02 earned in 1993. Regu-In 1995, a new rate adjustment clause was approved. It accelerated lated utility businesses generated earnings per share of $3.41 in 1995, recovery of deferred electric conservation and energy management $2.97 in 1994 and $2.93 in 1993. Non-regulated businesses generated program costs in the Company's Minnesota jurisdiction. This adjust-earnings per share of 50 cents in 1995,49 cents in 1994 and 9 cents in ment clause helps reduce the need for filing a general rate increase 1993. The results of the regulated utihty businesses and the non reg-request for recovery of increases in conservation expenditures. The ulated businesses are discussed in more detaillater. In addition to the Company is required to request a new cost recovery level annually, in revenue and expense changes, earnings per share have been January 1996, a number of changes to the Company's regulatory affected by an increasing average number of common and equivalent deferral and amortization practices for Minnesota conservation pro. shares outstanding. Common and equivalent shares increased in 1995 gram expenditures were approved. These changes allow the Com-and 1994 due mainly to stock issuances for the Company's dividend pany to expense rather than amortize new conservation expenditures reinvestment and stock ownership plans. beginning in 1996 and to increase its recovery of electric margins lost due to conservation activity. In addition, the Company received approval for 19% and 1997 conservation expenditures at levels lower Utility Operating Results than 1995. On April 1,1996, the Company expects to file for annual Electric Revenues Sales to retail customers, which account for more changes to the Minnesota conservation rate adjustment clause with than 90 percent of NSP's electric revenue, increased 4.2 percent in an effective period of July 1,1996, through June 30,1997. Revenues in 1995 and 3.9 percent in 1994. Retail revenues were favorably affected 1996 are expected to increase by an estimated $17 million, compared by sales growth, weather and increased cost recovery for conserva-with 1995, due to the effects of the rate recovery changes for conser-tion expenditures. During 1995, NSP added 18,297 retail electric cus-vation programs in 1995 and 1996. These revenue increases will be tomers, a 1.3 percent increase. Total sales of electricity increased 2.9 largely offset by a corresponding increase in conservation expenses. percent in 1995 and decreased 0.2 percent in 1994. Warmer than-nor-19
Electric Prsductisn Expenses Fuel expense for electric generation The table below summarites the principal reasons for the gas revenue j increased $4.5 million, or 1.4 percent,in 1995 compared with an changes during the past two years. increase of $5.6 million, or 1.8 percent,in 1994. The 1995 increase was primarily attributable to an increase in output from NSP's generating (Millions of dollars) 1994 vs 1993 plants, resulting from increased sales and fewer scheduled plant Sales growth maintenance outages. Although output from NSP's generating plants (excluding weather impacts) $0 declined slightlyin 1994 because of more scheduled fossil plant main-Estimated impact of weather tenance outages, fuel expenses were higher in 1994 because of the on firm sales volume (8) I higher cost of nuclear fuel per megawatt-hour due to increased pay-Sales to off system customers 14 ments to the U.S. Department of Energy (DOE) for decommissioning Purchased gas adjustment Q[Q j and decontamination of the DOE's uranium enrichment facilities and clause recovery M (24) nuclear fuel disposal costs. In addition, the costs of fossil fuel were Rate changes and other [ j 4 higher in 1994 because of fewer coal purchases at the lowest con-Viking Gas (acquired in June 1993) jbn#U 5 tractual prices due to lower fossil plant output. Total revenue increase (decrease) 9.44 $(9) Purchased power costs decreased $5.2 million, or 2.1 percent,in 1995 NSP's retail gas rates are adjusted for changes in purchased gas costs after increasing $41.1 million, or 19.7 percent,in 1994. The decrease in from amounts currently included in approved base rates through pur. 1995 was primarily due to lower average market prices and less energy chased gas adjustment clauses in all jurisdictions. Effective November purchased. The level of purchases declined due to fewer scheduled 1995, a new rate adjustment clause was approved that accelerated l plant maintenance outages in 1995. The increase in 1994 primarily was recovery of deferred gas conservation and energy management pro-due to additional demand expenses of $21 million for the full-year impact gram costs in the Company's Mmnesota jurisdiction, similar to the retail of capacity charges from the power purchase agreements with the electric rate clause discussed previously. The Company estimates it Manitoba Hydro-Electric Board (MH), which went into effect in May will receive an additional $2.7 million in revenues from this new rate i 1993, as discussed in Note 15 to the Financial Statements. In addition to mechanism in 1996 compared with 1995. This increased recovery will dernand expenses, purchased power costs increased from 1993 due to resultin a corresponding increase in conservation expenses. higher average market prices and increased purchases because of more plant maintenance outages in 1994. Cost of Gas Purchased and Transported The cost of gas purchased and transported decreased $7.1 million, or 2.7 percent, in 1995 primarily Gas Revenues The majority of NSP's retail gas sales are categorized due to a 12.6 percent decline in the per unit cost of purchased gas, as firm (primarily space heating customers) and interruptible (com-partially offset by higher sendout volumes due to increased sales and mercial/ industrial customers with an alternate energy suoply). Firm off system deliteries. The lower cost of purchased gas reflects con-sales in 1995 increased 6.8 percent compared with 1994 sales, while tmuing favorable market pricing, while the higher gas sendout reflects firm sales in 1994 decreased 5.4 percent compared with 1993 sales. sales growth in 1995 and higher gas sales to off-system customers. The 1995 increase primarily is due to increased sales of natural gas The cost of gas associated with off-system sales was $14.3 million in resulting from 16,680 additional new firm gas customers, a 4.1 percent 1995 and $12.7 million in 1994. The cost of gas purchased and trans-increase, and slightly more favorable weather in 1995. The 1994 ported decreased $18.6 million, or 6.6 percent,in 1994. The decrease decrease was due largely to warm weather in the last quarter of 1994. reflects lower gas prices and cost recovery adjustments, partially off-set by higher sendout volumes primarily for gas sales to off-system On a weather adjusted basis, firm sales are estimated to have customers. The average cost per unit of NSP-owned gas sold in 1994 increased 4.6 percent in 1995 and decreased 0.7 percent in 1994. Firm was 8.4 percent lower than it was in 1993, mainly due to lower market gas sales in 1996 are estimated to increase by 2.6 percent relative to prices for gas. 1995, a 3 6 percent increase on a weather-adjusted basis. Other Operation, Maintenance and Administrative and General interruptible sales of gas increased 15.7 percent in 1995 and 4.4 per. These expenses,in total, decreased by $9.1 million, or 1.4 percent, in cent in 1994. The 1995 increase is the result of f avorable gas market 1995 compared with an increase of $26.0 million, or 4.0 percent,in prices that caused large interruptible customers with alternate fuel 1994. The 1995 decrease is largely due to fewer employees, fewer sources to use more natural gas. 0ther gas deliveries increased 46.1 scheduled plant maintenance outages, lower property insurance pre-percent in 1995 and 65.7 parcent in 1994 primanly due to additional miums and a one time charge in 1994 for postemployment benefits. gas sales to off system customers. Viking wholesale transmission Partially offsetting these decreases were higher employee benefit deliveries increased 1,1 percent in 1995. These wholesale deliveries costs, and higher electric line maintenance costs, mostly for tree trim-increased 74.3 percent in 1994 due to a full year of Viking activity. ming and heat-related repairs. The 1994 increase resulted primarily from higher postretirement health care costs, including amounts deferred from 1993, and higher postemployment costs as discussed in Note 2 to the Financial Statements. (See Note 12 to the Financial Statements for a summary of administrative and general expenses.) Conservation and Energy Management Expenses in 1995 were higher than in 1994 primarily due to higher amortization levels of deferred conservation program costs, consistent with cost recovery under new 20
electric and gas rate adjustment clauses in the Company's %nnesota Pref;rred Dividends Dividends on the Company's preferred stock jurisdiction effective May 1,1995, and Nov.1,1995, respectively. The decreased in 1994 primarily due to redemption of the $7.84 Series deferred costs being amortized are higher due to increased customer Cumulative Preferred Stock in October 1993. participation in NSP's conservation and energy management programs. NON-REGULATED BUSINESS RESULTS Depreciation and Amortization The increases in 1995 and 1994 reflect gp. non regulated operations include many diversified businesses, s higher levels of depreciable plant. such as independent power p uduction, gas marketing, industrial heating and cooling, and energy-related refuse-derived fuel (RDF) Property and General Taxes Property and general taxes increased in c n. abo has inenu in aMaW Mussg @cu 1995 and 1994 primarily due to property additions and higher property and severalincome producing properties.The following discusses NSP's diversified business results in the aggregate. Utility income Taxes The variations in income taxes primarily are Operating Revenues and Expenses The net results of non-regulated attributable to fluctuations in taxable income. (See Note 9 to the ' U " Financial Statements for a detailed reconciliation of the statutory tax 8 "*" rate to NSP's effective tax rate.) to the Financial Statements lists the. dividual components of this line in iteml Non regulated operating revenues increased $71.3 million, or 29 NON-OPERATING ITEMS RELATED TO UTILITY BUSINESSES percent, in 1995, and $151.3 million, or 167 percent,in 1994. The 1995 Allowance for Funds Used During Construction (AFC) The differ-increase was largely due to increased gas marketing sales by ences in AFC for the reported periods are attributable to varying lev-Cenergy. The 1994 increase was mainly due to the impact of Cenergy els of construction work in progress and changing AFC rates gas marketing and NRG industrial heating and cooling businesses associated with various levels of short term borrowings to fund acquired in 1993. Non-regulated operating expenses increased in 1995 construction. In addition, returns allowed on deferred costs for con-primarily due to higher gas costs associated with Cenergy gas sales servation and energy management programs increased AFC-equity and higher project development expenses by NRG on pending pro. by $2.6 million and $2.0 million in 1995 and 1994, respectively, and jects. Non-regulated operating expenses increased in 1994 consistent increased AFC-debt by the amounts of $1.5 million and $0.9 million in with revenue increases resulting from 1993 acquisitions. In addition, 1995 and 1994, respectively. such expenses increased in 1994 due to fewer project development costs being capitalized on pending projects in 1994 compared with Other income (Expense) Note 12 to the Financial Statements lists the 1993, and project write-downs. Non-regulated operating expenses components of Other income (Deductions)-Net reported on the Con-include charges of $5.0 million in 1995 and $5.0 million in 1994 for pre-solidated Statements of Income. 0ther than the operating revenues viously capitalized development and investment costs to reflect a and expensss of non regulated businesses, as discussed in the next decrease in the expected future cash flows of certain energy projects. section, non-operating income (net of expense items and associated income taxes) related to utility businesses increased $5.6 million in Equity in Operating Earnings NSP has a less-than-majority equity inter-1995 and decreased $2.4 million in 1994. The 1995 increase primarily is est in many non-regulated projects, as discussed in Note 3 to the due to higher expense levels in 1994 for environmental and regulatory Financial Statements. Consequently, a large portion of NSP's non-regu-contingencies, and public and governmental affairs costs related to lated earnings is reported as Equityin Earnings of Unconsolidated Affil-the Prairie Island fuel storage issue. These were partly offset by iates on the Consolidated Statements of income. The 1995 decrease in lower interest income associated with the Company's settlement of equity in project operating earnings is due to lower earnings from an federalincome tax disputes in 1995. The 1994 decrease primarily is NRG cogeneration project contract that was terminated in 1995 and due to higher expenses for environmental and regulatory contingen-other domestic projects, somewhat off set by higher earnings from NRG cies, and higher public and governmental aff airs expenses associ-international energy projects (one of which did not provide earnings ated with the Prairie Island fuel storage issue, partially offset by prior to the second quarter of 1994). The 1994 increase in equity in pro-interest income associated with the Company's settlement of federal ject operating earnings primarily is due to new international energy income tax disputes. projects in which NRG entered during 1994 (as discussed in Note 3 to the Financial Statements), and more profitable operations of other I;terest Charges (Before AFC) Interest costs recognized for NSP's energy projects in which NRG had been an investor for several years. utility businesses, including amounts capitalized to reflect the financ-ing costs of construction activities, were S123.4 million in 1995, $107.1 Equity in Gains From Contract Terminations In June 1995, after million in 1994 and $110.4 million in 1993. The 1995 increase is largely receiving final regulatory approvals, a power sales contract between due to long-term debt issues in 1995 and 1994 (net of retirements) and a California energy project,in which NRG is a 45 percent investor, and higher short-term interest rates, which affect commercial paper bor-an unaffiliated utility company was terminated. A pretax gain of rowings and variable rate long-term debt. The 1994 decrease reflects approximately $30 million was recognized by NRG for its share of the theimpactof refinancing severalhigher ratelong term debtissuesin termination settlement. In 1994, a Michigan cogeneration project,in 1993 and 1994. These interest savings were partially offset by interest which NRG was a 50 percent investor, received a payment from an on higher short term debt balances and Viking debt (issued late in unaffiliated utility company as compensation for the termination of an 1993). The average short-term debt balance was $208.7 million in energy purchase agreement. A pretax pain of $9.7 million was recog-1995, $204.5 million in 1994 and $77.0 million in 1993. nized by NRG for its share of the contra :t termination settlement, net of projectinvestment costs. 21 I
Other IIctm3 (Expense) Other than the operating revenues and the Company and the utility subsidiary of WEC. The business combi-expenses of non regulated businesses, as discussed above,non oper, nation is intended to be tax free for income tax purposes, and sting income (net of expense items) related to non regulated busi-occounted for as a " pooling of interests." On Sept. 13,1995, more nesses increased $4.7 million in 1995 and increased $0.8 million in 1994. than 95 percent of the respective shareholders of the Company and The 1995 increase primarily is due to a gain on the sale of Cenergy oil WEC voting approved the merger plan at their respective shareholder and gas properties, higher income from cash investments, and an meetings. Under the proposed business combination, shareholders of adjustment to the 1994 contract termination gain recorded by NRG. the Company would receive 1.626 shares of Primergy common stock for each share of the Company's common stock owned at the time of laterest Expense Interest charges on the Consolidated Statements of the merger. Income include interest and amortization expenses related to non-regulated businesses. The expenses were $9.9 million in 1995, $8.0 After the merger is completed, a transition to a new organization million in 1994 and $3.1 million in 1993. The increase in 1995 mainly is would begin. Anticipated cost savings of the new organization (com-due to the issuance of long term debt on new affordable housing pro-pared with the continued independent operation of NSP and WEC) jects by Eloigne Company, a wholly owned subsidiary of the Company. are estimated to be $2 billion over a 10-year period, net of transaction The increase in 1994 relates primarily to non-utility long-term debt costs (about $30 million) and costs to achievs the merger savings issued to finance the 1993 acquisitions of NRG's industrial heating (about $122 million). It is anticipated that the proposed merger will and cooling business (Minneapolis Energy Center), a gas marketing allow the companies to implement a modest reduction in electric business now operated by Cenergy, and 1994 investments in afford-retail rates and a four year rate freeze for electric retail customers. In able housing projects by Eloigne Company. In addition, during 1994 addition, the companies agreed to provide a four year freeze in and late 1993, United Power & Land and First Midwest Auto Park, wholesale rates. After the merger, the regulated businesses of NSP wholly owned subsidiaries of the Company, issued long term debt and WEC would continue to operate as utility subsidiaries of secured by non regulated properties and lowered NSP's equity Primergy, which would be registered under the Public Utility Holding investment in these subsidiaries. Company Act of 1935 (PUHCA), as amended, and some of the Com-pany's subsidiaries would be transferred to direct Primergy owner. Income Taxes The Consolidated Statements of income include ship. Except for ce-tain gas distribution properties transferred to the income tax expense related to non-regulated businesses of $6.1 mil-Company, the Wisconsin Company will become part of the regulated lion in 1995, $2.6 million in 1994 and $3.5 million in 1993. The increase business of WEC. Although NSP and WEC are working to avoid in 1995 mainly is due to a gain from an NRG energy contract termina-divestitures, the PUHCA may require the merged entity to divest cer-tion, as discussed previously, somewhat offset by higher income tax tain of its gas utility and/or non-regulated operations. Also, regulatory credits from Eloigne Company's affordable housing projects. The authorities may require the restructuring of transmission system decrease in 1994 mainly is due to higher income tax credits from operations or administration. NSP currently cannot determine if such affordable housing projects and energy tax credits related to an NRG divestitures or restructuring would be required. In addition, Wiscon-project, somewhat offset by higher taxes due to higher operating sin state law limits the total assets of non utility affiliates of Primergy, earnings, as discussed above. The effective tax rate in 1995 and 1994 This could affect the growth of non-regulated operations. is substantially less than the U.S. federal tax rate mainly due to the tax treatment of income from unconsolidated international affiliates, and The agreement to merge is subject to a number of conditions, including energy and affordable housing tax credits, as shown in Note 9 to the approval by applicable regulatory authorities. During 1995, NSP and Financial Statements. WEC received a ruling from the internal Revenue Service indicating that the proposed successive merger transactions would not prevent FACTORS AFFECTING RESULTS OF OPERATIONS treatment of the business combination as a tax free reorganization "PE "' I' "" " "" 9" NSP's results of operations during 1995,1994 and 1993 were primarily During 1995, NSP and WEC submitted filings to the Federal Energy Reg-dependent upon the operations of the Company's and Wisconsin ulatory Commission (FERC), applicable state regulatory commissions Company's utility businesses consisting of the generation, transmis-and other governmental authonties seeking approval of the proposed sion, distribution and sale of electricity and the distribution, trans-merger to form Primergy. The FERC has put the merger application on portation and sale of natural gas. NSP's utility revenues depend on an accelerated schedule, ordering the administrative law judge's initial customer usage, which varies with weather conditions, general buss-decision by Aug. 30,1996, and briefs on exception by Sept. 30,1996, ness conditions, the state of the economy and the cost of energy ser-which makes possible a FERC ruling on the merger application by the vices. Various regulatory agencies approve the prices for electric and end of 1996 Although the goal cf NSP and WEC is to receive approvals gas service within their respective jurisdictions. In addition, NSP's from all regulatory authonties by the end of 1996, some regulatory non regulated businesses are contributing significantly to NSP's authorities have not established a timetable for their decisions. There-earnings. The historical and future trends of NSP's operating results fore, the timing of the approvals necessary to complete the merger is have been and are expected to be affected by the following factors: not known at this time. The state filings included a request for deferred
- * " "9 " "" '"
Proposed Merger On April 28,1995, the Company and WEC entered into
- 0 an Agreement and Plan of Merger that provides for a business combi-
"#U nation of NSP and WEC in a ' merger of equals" transaction. As a Intangible and Other Assets. In February 1996, the appropriate commit-result of the mergers contemplated by the merger agreement, Primergy tees of the Minnesota Legislature passed legislation that would affect will become the holding company for the regulated operations of both 22
. _~ - -. - ~ - merger approval for electric utilities. This bill, if passed into law, would In March 1995, the FERC issued a Blotice of Proposed Rulemaking on provide for certain binding commitments regarding minimum levels of Open Access Non discriminatory Transmission Services and a Sup-staffing and investment for electric service, plemental Notice of Proposed Rulemaking on Stranded Investment (together called the Mega-NOPR). The Mega NOPR is intended to in addrtion to the regulatory and other governmental approvals of the create a vigorous wholesale electric market by requiring transmis-proposed merger, certain NSP financial and other agreements may sion providers to offer open access to their transmission systems. be construed to require that,in the case of a change in ownership The FERC is proposing to require utilities to unbundle power sales (such as the proposed merger), the other party to the agreement must from transmission. This "unbundled service
- requirement would consent to the change or waive the requirement. Agreements with apply only to new requirements contracts and new coordination trade such provisions at Dec. 31,1995, include $101.7 million of long-term contracts. The Mega NOPR would apply tc all utilities under the debt, operating lease agreements with annual payments of $1.3 mil-FERC's jurisdiction and would require each utility to file individual tar-lion in 1996 and a $10 million credit line agreement, under which there ilts. The FERC also seeks to require non jurisdictional transmission-were no borrowings at Dec. 31,1995 Although neither consents nor providing entities (such as municipals and cooperatives) to offer open waivers from the other partier have yet been obtained, NSP will seek access by including a reciprocity clause in their individual tariffs so to obtain them prior to the completion of the merger. (See further dis-that those who take service from a FERC jurisdictional utihty must cussion of the proposed business combination in Note 18 to the also offer open access. Concurrently with the Mega NOPR, the FERC Financial Statements.)
issued a proposal for a Real Time Information Network intended to facihtate open access by requiring all public utilities to create an Regulation NSP's utility rates are approved by the FERC, the Min-electronic bulletin board of information regarding their transmission nesota Public Utilities Commission (MPUC), the North Dakota Public system services, availability and rates. Also in the Mega NOPR, the Service Commission, the Public Service Commission of Wisconsin FERC proposed to consider cases involving stranded costs resulting (PSCW), the Michigan Public Service Commission and the South from open access (a) when a state regulatory commission does not Dakota Public Utilities Commission. Rates are designed to recover have authority under state law to address such costs at the time retail l plant investment and operating costs and an allowed return on wheeling (which is the transmission to retail customers of power gen-investment, using an annual period upon which rate case filings are erated by a third party n competition with supplies from the host util-based. NSP requests changes in rates for utility services as needed ity) takes place, and (to Mter a state commission has addressed such j through filings with the governing commissions. The rates charged to costs. In response to the FERC's proposals, NSP filed comments with retail customers in Wisconsin are reviewed and adjusted biennially. the FERC that supported the Mega NOPR's open access initiative and Because comprehensive rate changes are not requested annually in asserted NSP's intent that open access transmission tariffs filed in Minnesota, NSP's primary jurisdiction, changes in operating costs 1994 comply with the spirit of the Mega-NOPR. NSP expects the can affect NSP's earnings, shareholders' equity and other financial impact of any rulemaking such as the Mega NOPR to be consistent results. Except for Wisconsin electric operations, NSP's rate sched-with its efforts to be a competitively priced supplier of electricity and i ules provide for cost-of-energy and resource adjustments to billings an active participant in the competitive market for electricity. and revenues for changes in the cost of fuel for electric generation,. purchased energy, purchased gas, and conservation and energy With the development of electric industry competition, the Company management program costs. For 'Nisconsin electric operations, the has experienced an increase in requests for the use of its transmis-biennial tetail rate review process considers changes in electric fuel sion system. A large portion of these requests is due to the increase and purchased energy costs in lieu of a cost of energy adjustment in FERC approved power marketers. In 1995, the Company filed 23 clause. In addition to changes in operating costs, other factors affect-transmission service agreements for FERC approval, including 10 with j ing rate filings are sales growth, conservation and demand-side man-power marketers. While the annual transmission revenue in 1995 from agement efforts and the cost of capital. this activity was immaterial,it is expected that 1996 revenues will increase due to the growth of power marketing activity in this region. Competition The Energy Policy Act of 1992 (the Act) was a catalyst for comprehensive and significant changes in the operation of electric In response to the developing electric industry competition, Cenergy utikties, including increased competition. The Act's reform of the applied for and was granted permission by the FERC to market elec. PUHCA promotes creation of wholesale non utility power generators tricity (except electricity generated by NSP)in the United States, and authorizes the FERC to require utilities to provide wholesale trans-effective Dec.1,1994. Cenergy was one of the first affiliates of an mission services to third parties. The legislation allows utilities and electric utility to obtain this approval from the FERC. non regulated companies to build, own and operate power plants nationally and internationally without being subject to restrictions that Some states are considering proposals to increase competition in the previously applied to utilities under the PUHCA. Managernent believes supply of electricity. In response to a proposalin 1994 by its regulator this legislation will promote the continued trend of increased competi-in Wisconsin, NSP outlined the transitional steps necessary to create tion in the electric energy markets. NSP management plans to con-an open and fair competitive electric market. NSP's position is that all tinue its efforts to be a competitively priced supplier of electricity and customers should be able to choose their electric supplier by 2001, an active participant in the competitive market for electricity. The pro-and that generation also should be deregulated by 2001. NSP pro-posed merger with WEC is a key strategic initiative designed to facili-poses that ut:hties retain operational control of their transmission and tate NSP's effective competition in the future energy marketplace. distribution systems, and that utilities should be permitted to recover the cost of investments made under traditional regulation. Regulators 23
- _ - _ - - = .. - ~. -.. - - -~.. in Minnesota and Wisconsin are currently considering what actions vide their power supply. While the fullimpact of these changes is . they should take regarding electric industry competition. In Wiscon-unknown at this time, the following changes have been identified. sin, regulators developed a plan for a phased approach. They voted to adopt a restructuring plan, which includes a 32 step phase-in of retail in 1992, nine of the Company's municipal wholesale electric customers wheeling by the year 2001 A key component of the plan is to provide notified the Company of their intent to terminate their power supply the protections necessary to ensure that consumers are not harmed agreements with the Company, effective July 1995 or July 1996. The in an increasingly competitive environment. One component of the loss of seven of these customers in July 1995 resulted in a revenue plan is to have an independent system operator control transmission decrease of approximately $12 million from 1994 levels. The other two access. In Minnesota, regulators have develc, ped draft principles to customers, who are expected to terminate their power agreements in i provide a framework for electric industry restructuring. They have not July 1996, provided revenues of $3.6 million in 1995. These nine cus-established definitive timelines for industry restructuring or changes. tomers are expected to become wheeling customers providing esti-1 One of the principles supports an open transmission system and mated annual revenues of nearly $3 million. NSP's remaining 19 establishing a robust wholesale competitive market. NSP believes the municipal wholesale electric customers are under contracts with ) transition to a more competitive electric industry is inevitable and terms expiring in the years 1999 through 2008. beneficial for all consumers. NSP supports an orderly and efficient transition to an open, fair and competitive energy market for all cus-During 1993, the Company signed an electric power agreement to tomers and suppliers. The timing of regulatory actions and their provide Michigan's Upper Peninsula Power Company (UPPCO)with impact on NSP cannot be predicted and may be significant. up to 150 megawatts of baseload service, peaking service options and load regulatiorgservice options for 20 years from January 1998 During 1992 and 1993, the FERC issued a series of orders (together through December 2017. Load regulation service is designed to called Order 636) addressing interstate natural gas pipeline service change the level of power delivery during each hour to match restructuring. This restructuring "unbundled' each of the services UPPCO's load requirements. UPPC0 has nominated 50 megawatts of (sales, transportation, storage and ancillary services) traditionally baseload and five megawatts of winter season peaking power pur-provided by gas pipeline companies. Interstate pipelines have been chases from NSP beginning Jan.1,1998. The annual revenue for 1998 allowed to recover from their custcmers 100 percent of prudently is projected to be approximately $11 million to $14 million. The inter-incurred transition costs attributable to Order 636 restructuring. change agreement between UPPCO and NSP for this sale was Under service agreements that went into effect Nov.1,1993, NSP accepted by the FERC.The Michigan Public Utilities Commission also estimates that it will be responsible for less than $11 million of tran-must approve the transaction. sition costs over a five year period beginning on that date. To date, NSP's regulatory commissions have approved recovery of these Rate Changes As discussed previously under Utility Operating restructuring charges in retail gas rates through the purchased gas Results, filings for rate changes in 1995 had an immaterialimpact on adjustment. NSP does not believe Order 636 has materially affected financial results. No significant general rate filings in any of NSP's its cost of gas supply. NSP's acquisitions of Viking and Cenergy in utility jurisdictions are expected for 1996. However, the Company has 1993 have enhanced its abihty to participate in the more competitive proposed rate changes in connection with requested approvals of its gas transportation business. In implementing Order 636, Viking proposed business combination with WEC, as discussed previously. incurred no transition costs. Used Nuclear Fuel Storage and Disposalin 1994, NSP received leg-Customer Cogeneration Koch Refining Co. (Koch), the Compar/s islative authorization from the State of Minnesota for dry cask fuel stor-largest customer, which provides approximately $30 million in ansual agc facihties at the Company's Prairie Island nuclear generating i revenues to NSP, proposes to build a corneration plant to burn petro-f acihty. M : condition of this authorization, the Minnesota Legislature leum coke, a refinery byproduct, to produce between 180 and 250 established several resource commitments for the Company, including megawatts of electricity. This would be enoop supply for Koch's own wind and biomass generation sources, as well as other requirements. use plus an additional 80 to 150 megawatts to be sold on the wholesale In addition, the Company and other utilities filed a lawsuit against the market. Koch is requesting a legislative exemption from Mmnesota DOE in 1994 to compel the DOE to fulfillits statutory and contractual property tax for its plant. While NSP supports the reduction of taxes on obligations to store and dispose of used nuclear fuel as required by the generating facilities,it believes any reduction should be applied to all Nuclear Waste Policy Act of 1982. Also, the Company is leading a con-generating facilities so that there are no unfair tax advantages avail-sortium to establish a private facility forinterim storage of used nuclear able to sume generators. This project has severalimplications for NSP: fuel, the outcome of which is uncertain at this time. (See Notes 14 and
- 1) Koch could become a competitor as it seeks markets for its excess 15 to the Financial Statements for more information.)
capacity; 2) Koch's capacity would also represent a potential power source for NSP; and 3) Koch's plan represents a potentialloss of a Environmental Matters NSP incurs several types of environmental large retail customer. The project's anticipated three year lead time will costs, including nuclear plant decommissioning, storage and ultimate allow NSP to respond appropriately. disposal of used nuclear fuel, disposal of hazardous materials and wastes, remadiation of contaminated sites and monitoring of dis-Wholesale Customers NSP had wholesale revenues from sales of charges into the environment. Because of the continuing trend toward electricity of approximately $44 million in 1995 and approximately $57 greater environmental awareness and increasingly stringent regula-million in 1994. The trend of increased competition, as previously dis-tion, NSP has been experiencing a trend toward increasing environ-cussed, has resulted in significant changes in the negotiation of con-mental costs. This trend has caused, and may continue to cause, tracts with wholesale customers. In the past several years, these slightly higher operating expenses and capital expenditures for envi-customers have begun to evaluate a variety of energy sources to pro-ronmental compliance. In addition to nuclear decommissioning and 24
used nuclear fuel disposal expenses (as discussed in Note 14 to the businesses in 1995 and 1994 may not necessarily be indicativo of Financial Statements), costs charged to NSP's operating expenses for future operating results. environmental monitoring and disposal of hazardous materials and wastes in 1995 were approximately $26 million and are expected to Accounting Changes The Financial Accounting Standards Board increase to an average annual amount of approximately $30 million for (FASB) has issued two new accounting standards that become effec-the five-year period 19962000. However, the precise timing and tive in 1996. Statement of Financial Accounting Standards (SFAS) No. ] amount of environmental costs, including those for site remediation 121, Accounting for the impairment of Long Lived Assets, establishes and disposal of hazardous materials, are currently unknown. In each standards for measuring and recognizing asset impairments. SFAS No. of the years 1995,1994 and 1993, the Company spent about $15 million 123, Accounting for Stock-Based Compensation, provides an optional for capital expenditures on environmentalimprovements at its utility accounting method for compensation from stock option and other stock f acihties. in 1996, the Company expects to incur approximately $20 mil-award programs that NSP does not intend to use. NSP does not expect lion in capital expenditures for compliance with environmental regula-the adoption of these new accounting standards to have a material tions and approximately $180 million for the five year period 1996-2000. impact on its results of operations or financial condition. However, the These capital expenditure amounts include the costs of constructing principles of SFAS No.121 will be followed to measure the effects of any used nuclear fuel storage casks. (See Notes 14 and 15 to the Financial stranded investments that could arise from the Act, the FERC's Mega-Statements for further discussion of these and other environmental NOPR proposal or other competitive business developments. contingencies that could affect NSP.) Weather NSP's earnings can be significantly affected by unusual into effect in 1997. The standards would require the full accrual of weather. In 1995, unusual weather, mainly a hot summer, increased nuclear plant decommissioning and certain other site exit obligations. earnings over a normal year by an estimated 21 cents per share. Mild Material adjustments to NSP's balance sheet could occur under the weather, mainly cool summers, reduced earnings from a normal year FASB's proposal. However, the effects of regulation are expected to min-by an estimated 13 cents per share in 1994 and 18 cents per share in imize or eliminate any impact on operating expenses and earnings from 1993. The effect of weather is considered part of NSP's ongoing busi-this future accounting change. (For further discussion of the expected ness operations. impact of this change, see Note 14 to the Financial Statements ) Acquisitions In 1994, NRG acquired ownership interests in three signif-Use of Derivatives Through its non regulated subsidiaries, NSP uses icant international energy projects (listed in Note 3 to the Financial derivative financialinstruments to hedge the risks of fluctuations in for-Statements). NSP also made three other strategically important busi-eign currencies and natural gas prices. Also,to hedge the interest rate ness ecquisitions in 1993, including an interstate natural gas pipeline risk associated with fixed rate debt in a declining interest rate environ-(Viking), an energy services marketing business (Cenergy) and a steam ment, NSP uses interest rate swap agreements to convert fixed rate debt heating and chilled water cooling system business (Minneapolis to variable rate debt. (See Notes l and 11 tu the Financial Statements for Energy Center, now an NRG subsidiary). NSP continues to evaluate further discussion of NSP's financialinstruments and derivatives.) opportunities to enhance its competitive position and shareholder returns through strategic business acquisitions. Non-recurring items NSP's earnings for 1995 include two significant unusual or infrequently occurring items. As discussed in the Non-reg-Impact of Non-regulated Investments NSP's net income includes ulated Business Results section, NRG recognized a pretax gain of after tax earnings of $33.6 million, or 50 cents per share, from all of its approximately $30 million (26 cents per share) from a power sales non regulated businesses in 1995 and $32.9 million, or 49 cents per contract termination settlement. Partially offsetting this gain was an share,in 1994. As discussed previously, NRG acquired equity interests asset impairment write down of $5 million before taxes (4 cents per in three significant energy projects in 1994. NSP expects to continue share) for a non-regulated domestic energy project. investing significant amounts in non-regulated projects, including domestic and international power production projects through NRG, NSP's 1994 earnings also included several significant unusual or as described under Future Financing Requirements. Depending on the infrequently occurring items. Although their net effect was an earn-success and timing of involvement in these projects NSP's goalis for ings increase of only I cent per share, individually significant non-NRG earnings to increase in the future to contribute at least 20 per-recurring items included a gain on termination of a non regulated cent of NSP's earnings by the year 2000. The non regulated projects in cogeneration contract, interest income from the settlement of a fed-which NRG has invested carry a higher level of risk than NSP's tradi-eralincome tax dispute, a charge for pre 1994 postemployment costs tional utility businesses. Current and future investments in non regu-associated with adopting SFAS No.112, and asset impairment write-lated projects are subject to uncertainties prior to finallegal closing, downs for certain non-regulated energy projects. and continuing operations are subject to foreign government actions, foreign economic and currency risks, partnership actions, competi-Inflation Historically, certain operating costs, mainly labor and prop- . tion, operating risks, dependence on certain suppliers and customers, erty taxes, have been affected by inflation. Also, inflation has tended domestic and foreign environmental and energy regulations, or all of to increase the replacement cost of operating facilities,which has these items. Most of NRG's current project investments consist of increased depreciation expense when replacement f acilities are con-minority interests, and a substantial portion of future investments may structed. However, several significant expense items, including fuel take the form of minority interests, which limits NRG's ability to control costs, income taxes and interest expense have been less sensitive to the development or operation of the projects. In addition, significant inflation. 0verall, inflation at the levels currently being experienced is expenses may be incurred for potential projects pursued by NRG that not expected to materially affect NSP's prices to customers or returns may never materialize.The operating results of NSP's non regulated to shareholders. 25
L10111DITY AND CAPITAL. RLSOURCES NSP's equity investments in non-regulated projects during 1995 were financed through internally generated funds. Project financing 1995 Firncing Regiirements NSP's need for capital funds is primar-requirements,in excess of equity contributions from investors, were ily related to the construction of plant and equipment to meet the satisfied with project debt. Project debt associated with many of needs of electric and gas utility customers and to fund equity commit-NSP's non regulated investments is not reflected in NSP's balance ments or other investments in non regulated businesses. Total NSP sheet because the equity method of accounting is used for such utility capital expenditures (including AFC) were $386 million in 1995-investments. (See Note 3 to the Financial Statements.) Of that amount, $318 million related to replacements and improve-rnents of NSP's electric system and nuclear fuel, and $37 million In January 1996, NRG issued $125 million of 7.625 percent unse-involved construction of natural gas distribution f acdities. NSP com-cured Senior Notes maturing in 2006 to support equity requirements panies invested $71 million in non regulated projects and property in for projects currently under way and in development. The Senior 1995. NRG primarily invested in existing projects. In 1995, Cenergy Notes were assigned ratings of BBB by S&P's Rating Group and became a majority investor (80 percent)in Energy Masters Corpora-Baa3 by Moody's. tion, a firm specializing in energy efficiency improvement services for commercial, industrial and institutional customers. The investment is Future Financing Requirements Utdity financing requirements for 1996-accounted Ior on a consolidated basis. Eloigne Company invested in 2000 may be affected in varying degrees by numerous f actors, including affordable housing projects, including wholly owned and limited part-load growth, changes in capital expenditure levels, rate changes nership ventures, allowed by regulatory agencies, new legislation, market entry of com-peting electric power generators, changes in environmental regulations 1995 Financing Activity During 1995, NSP's primary sources of capital and other regulatory requirements. NSP currently estimates that its util-included internally genuated funds,long term debt, short-term debt ity capital expenditures will be $410 million in 1996 and $1.9 billion for the and common stock issuances, as discussed below. The allocation of five-year period 1996-2000. Of the 1996 amount, approximately $345 mil-financing requirements between these capital options is based on the lion is scheduled for utility electric facilities and approximately $45 mil-relative cost of each option, regulatory restrictions and the con. lion for natural gas facilities,:ncluding Viking. In addition to utility capital straints of NSP's long range capital structure objectives. During 1995, expenditures, expected financing requirements for the 1996-2000 period NSP continued to meetits long-range regulated capital structure include approximately $480 million to retire long term debt and meet first objective of 45-50 percent common equity and 42-50 percent debt. m rtgage bcnd sinking fund requirements. Funds generated internally from operating cash flows in 1995 Through its subsidiaries. NSP expects to invest significant amounts in remained sufficient to meet working capital needs, debt service, divi, non-regulated projects in the future. Financing requirements for non-dend payout requirements and non regulated investment commit, regulated project investments may vary depending on the success, tim-ments, as well as fund a significant portion of construction ing and level of involvement in projects currently under consideration. expenditures. The pretax interest coverage ratio, excluding AFC,was NSP's potential capital requirements for non regulated projects and j 3.8 in 1995 and 3.9 in 1994. These ratios met NSP's objective range of property are estimated to be approximately $140 million in 1996 and 3.5 5.0 for interest coverage. Internally generated funds could have approximately $550 million for the five-year period 1996-2000. These provided financing for 85 percent of NSP's total capital expenditures amounts include commitments for NRG investments, as discussed in for 1995 and 72 percent of the $1.9 billion in capital expenditures Note 15 to the Financial Statements, and Eloigne Company investments incurred for the five year period 1991 1995. of up to $13 million annually in 1996-2000 for affordablo housing pro-jects. Eloigne Company expects to finance approximately 65 percent of NSP had approximately $216 million in short term borrowings out. these investments in affordable housing projects with equity and standing as of Dec. 31,1995. Throughout 1995, short-term borrowings approximately 35 percent with long-term debt. In addition to invest-were used to finance a portion of utility capital expenditures and pro, ments in non-regulated projects, NSP continues to evaluate opportuni-vide for other NSP cash needs. ties to enhance shareholder returns and achieve long term financial objectives through acquisitions of existing businesses. Long term in 1995, the Company issued $250 million of first mortgage bonds to financing may be required for such investments. refinance higher-cost debt issues and reduce short term debt levels. Eloigne Company also issued approximately $12.5 million oflong term The Company also will have future financing requirements for the debt to finance affordable housing project investments. portion of nuclear plant decommissioning costs not funded extemally. Based on the most recent decommissioning study, these amounts are During 1995,the Company issued new shares of common stock under anticipated to be approximately $363 million, and are expected to be various stock plans, including 536,360 new shares under the paid during the years 2010 to 2022. Employee Stock Ownership Plan (ESOP),527,671 new shares under the Dividend Reinvestment and Stock Purchase Plan (DRSPP), and Future Sources of Financing NSP expects to obtain external capital for 63,780 new shares under the Executive Long Term incentive Award future financing requirements by periodically issuing long term debt, Stock Plan. In addition, the Company issued common stock in con-short-term debt, common stock and preferred stock as needed to nection with a non regulated business acquisition. At Dec.31 1995, maintain desired capitalization ratios. 0ver the long term, NSP's equity the total number of common shares outstanding was 68,175,934. investments in non regulated projects are expected to be financed through internally generated funds or the Company's issuance of com-mon stock. Financing requirements for the non regulated projects, in 26
excess of equity contnbutions from investors, are expected to be ful-level of commercial paper borrowings. Commercial banhs presently filled through project or subsidiary debt. Decommissioning expenses provide credit lines of approximately $265 million to the Company and not funded by an external trust are expected to be financed through a an additional $17 million to subsidiaries of the Company. These credit combination of internally generated funds,long term debt and com-lines make short-term financing available in the form of bank loans. mon stock.The extent of externalfinancing to be required for nuclear decommissioning costs, as discussed above,is unknown at this time. The Company's Articles of Incorporation authorize the maximum amount of preferred stock that may be issued. Under these provisions, the Com-i NSP's ability to finance its utility construction program at a reasonable pany could have issued all $460 million of its remaining authorized, but j cost and to provide for other capital needs depends on its ability to unissued, preferred stock at Dec. 31,1995, and remained in compliance meet investors' return expectations. Financing flexibility is enhanced by with allinterest and dividend coverage requirements. providing working capital needs and a high percentage of total capital requirements from internal sources, and having the ability to issue long. The level of common stock authorized under the Company's Articles term securities and obtain short-term credit. NSP expects to maintain of incorporation is 160 million shares. In January 1996, the Company adequate access to securities markets in 1996. Access to securities filed a registration statement with the SEC to provide for the sale of up markets at a reasonable cost is determined in large part by credit qual-to 1.6 million additional shares of new common stock under the Com-i ity. The Company's first mortgage bonds are rated AA-by Standard & pany's Dividend Reinvestment and Stock Purchase Plan (DRSPP) and Poor's Corporation, Al by Moody's Investors Service, Inc. (Moody's), Executive Long Term lncentive Award Stock Plan. The Company may AA by Duff & Phelps,Inc., and AA by Fitch investors Service,Inc. Rat-issue new shares or purchase shares on the open market for its ings for the Wisconsin Company's first mortgage bonds are generally stock-based plans. (See Note 5 to the Financial Statements for dis-comparable. These ratings reflect the views of such organizations, and cussion of stock awards outstanding.)The Company plans to issue an explanation of the significance of these ratings may be obtained new shares for its DRSPP, ESOP and Executive Long Term incentive from each agency. In May 1994 Moody's downgraded the Company's Award Stock plans in 1996. While no general public stock offerings first mortgage bond ratings to Al based on its interpretation of provi-are currently anticipated in 19%, such offerings may be necessary to sions of a Minnesota law enacted in 1994 for used nuclear fuel storage fund significant equity investments in non regulated projects should at the Prairie Island generating plant (The other three rating agencies they occur. reaffirmed their ratings of the Company's bonds after considering the potentialimpact of the legislation on NSP.) As discussed in Notes 14 Internally generated funds from utility operations are expected to and 15 to the Financial Statements, the legislation requires the Com-equal approximately 90 percent of anticipated utility capital expendi-pany to increase its use of renewable energy sources such as wind and tures for 1996 and approximately 100 percent of tha $1.9 billion in biomass power. Moody's has indicated that it believes these sources of anticipated utility capital expenditures for the five-year period 1996-power are considerably more costly than the power currently gener-2000. Internally generated funds from all operations are expected to ated and that NSP's electric production costs willincrease materially equal approximately 75 percent and 90 percent, respectively, of the over current levels. NSP acknowledges that electric production costs anticipated total capital expenditure!, for 1996 and the five year may increase as a result of the Prairie Island legislation. In 1995, period 1996 2000. Because NSP intends to reinvest foreign cash flows Moody's placed the Company's ratings on credit review for possible in non-U.S. operations, the equity income from international invest-upgrade based on anticipated cost savings from the proposed merger ments currently does not provide operating cash available for U.S. with WEC, which was discussed previously. cash requirements such as payment of dividends, domestic capital expenditures and domestic debt service. Through NRG, NSP intends The Company's and the Wisconsin Company's first mortgage indentures to pursue a diverse portfolio of foreign energy projects with varying limit the amount of first mortgage bonds that may be issued. The MPUC levels of cash flows, income and foreign taxation to allow maximum and the PSCW have jurisdiction over securities issuance. At Dec. 31, flexibility of foreign cash flows. 1995, with en assumed interest rate of 7.0 percent, the Company could have issued about $2.5 billion of additional first mortgage bonds under The merger agreement, as previously discussed, provides for restric-its indenture, and the Wisconsin Company could have issued about $356 tions on certain transactions by both the Company and WEC, including million of additional first mortgage bonds under its indenture. the issuance of debt and equity securities. While the Company cur-rently does not plan to enter into transactions that would not comply The Company filed a shelf registration for first mortgage bonds with with these restrictions, circumstances may arise to make such trans-the Securities at.d Exchange Commission (SEC)in October 1995. actions necessary. Under such circumstances,the Company and WEC Depending on capital market conditions, the Company expects to would need to mutually agree to amend the merger agreement. issue the $300 million of registered, but unissued, bonds over the next several years to raise additional capital or redeem outstanding secu-rities. In addition, depending on market conditions, the Wisconsin Company may issue up to $65 million in first mortgage bonds to redeem outstandmg securities or raise additional capital. The Company's Board of Directors has approved short-term borrow-ing levels up to 10 percent of capitalization. The Company has received regulatory approval for up to $445 million in short term bor-rowing levels and plans to keep its credit lines at or above its average 27
Year Ended Dec. 31 (Thousands of dollars, exceptper share data) ( 1994 1993 Utility Operating Revences 1 Electric l $2 066 644 $1976916 Gas ] 419 903 429 076 Total 2 486 547 2 403 992 Utility Operating Expenses Electric production expenses - fuel and purchased power i 570 880 524 126 Cost of gas purchased and transported 263 905 282 036 316 479 310 585 Other operation 170 145 161 413 Maintenance Administrative and general i 187 996 176 617 31 231 29 358 Conservation and energy management __ I, 273 801 264 517 Depreciation and amortization I Property and general taxes 1 234 564 223 108 income taxes i 129 228 128 346 Total 2 178 229 2 100 106 Utility Operating income i 308 318 303 886 Other income (Expense) ~ Equityin earnings of unconsolidated affiliates: Earnings from operations 32 024 3 030 Gain from contract termination ~ 9 685 Allowance for funds used during construction - equity 4 548 7 328 Other income (deductions)- net (3 686) 7 982 Income taxes on non-regulated operations and non-operating items (199) (2 394) Total 42 372 15 946
- Income Before Interest Charges 350 690 319 832 Interest Charges Interest on utihty long term debt 89 553 101 677 Other utility interest and amortization 17 555 8 739 Non-regulated interest and amortization 7 975 3 146 Allowance for funds used during construction - debt (7 868)
(5 470) Total 107 215 108 092 Net income 243 475 211 740 Preferred Stock Dividends 12 364 14 580 Earnings Available for Common Stock $231111 $197160 Average Number of Common and Equivalent Shares Outstanding (000's) 66 845 65 211 Earnings Per Average Common Share $3.46 $3.02 Common Dividends Declared per Share $2.625 $2.565 See Notes to Financial Statements on pages 34 to 49 28
Year Ended Dec. 31 (Thousands of dollars) 1894 1993 Cash Fliws from Operating Activities: Net Income $243 475 $211740 Adjustments to reconcile net income to cash from operating activities: Depreciation and amortization 304 583 286 855 Nuclear fuel amortization 45 553 43 120 Deferred income taxes (6 101) 12 256 Deferred investment tax credits recognized (9 501) (9 223) Allowance for funds used during constrection - equity (4 548) (7 328) Undistributed equity in earnings of unconsolidated affiliate operations (23 588) (1 142) Undistributed equity in gain from non regulated contract termination settlements Cash provided by (used for) changes in certain working capitalitems (8 627) 33 259 Conservation program expenditures - net of amc tization (29 963) (21 185) Cash provided by (used for) changes in other a ssets and liabilities f (1 042) 12 340 Net Cash Provided by Operating Activities ~ k$@ 510 241 560 692 L ( [% Cash Flows from Investing Activities: Capital expenditures: Utility busineeses .P (387 026) (356 836) Non-regulated businesses (22 260) (4 859) Increase (decrease)in construction payables 11 668 2 598 Allowance for funds used during construction - equity 4 548 7 328 Sale (purchase) of short-term investments - net f (866) 62 Investment in external decommissioning fund (42 677) (32 578) Business acquisitions (159 385) Equity investments in non-regulated projects and other en (132 511) (25 957) Net Cash Used forInvesting Activities (569 124) (569 627) Cash Flows from Financing Activities: Change in short term debt - net issuances (repayments) 132 239 (40 361) Proceeds from issuance of long term debt 367 184 613 120 Loan to ESOP Repayment of long-term debt, including reacquisition premiums (272 097) (489 106) Proceeds from issuance of common stock 1 368 183 654 Redemption of preferred stock, including premium (36 092) Dividends paid (186 568) (180 220) Net Cash Provided by (Used for) Financing Activities 42 126 50 995 Net increase (Decrease)in Cash and Cash Equivalents (16 757) 42 060 Cash and Cash Equivalents at Beginning of Period 57 812 15 752 Cash and Cash Equivalents at End of Period $41055 $57 812 Cash Provided by (Used for) Changes in Certain Working Capital items: Customer accounts receivable and unbilled utility revenues $14 708 $(43 219) Materials and supplies inventories (13 462) 13 911 Payables and accrued liabilities (excluding construction payables) 32 550 54 247 Customer rate refunds (10 410) 12 235 Other (32 013) (3 915) Net $(8 627) $33 259 Supplemental Disclosures of Cash Flow Information: Cash paid during the year for: Interest (net of amount capitalized) $106 867 $107 037 Income taxes (net of refunds received) $170 474 $120 491 See Notes to FinancialStatements on pages 34 to 49 29
Dec. 31 iThousands of dollars) M 1994 y7]$ [gi Assets Utility PL:nt Electric - including construction work in progress: 1995, $137,662,1994, $117,235 h 3 $6 372 317 0as 79 677 233 Other 262 506 Total 4 wggyA 7 312 056 i i (3 116 811) Accumulated provision for depreciation Nuclear fuel-including amounts in process: 1995, $34,235; 1994, $12 505 g j 797 097 Accumulated provision for amortization (718 690) Net utility plant femyan 4 273 652 gh. t.(p;p; Current Assets c p 41 055 Cash and cash equivalents Short term investments ' jN/$ij 892 Customer accounts receivable -net of accumulated provision N a ?$ for uncollectible accounts: 1995, $4,338; 1993, $3,912 229 272 Unbilled utility revenues 4 6,: 98 651 Other receivables SM$l 80 444 Materials and supplies - at average cost @[ [. [ r (Ms Mi 56 960 Fuel Y 101 878 Other Prepayments and other NMh 56 075 Total current assets Erx6 665 227 Other Assets vu x, y Regulatory assets MI 357 576 .M 172 961 Non-regulated property-netof aecumulated depreciation:1995,$83.724;1994,$73,296 Equity investments in non regulated projects and other investments 197 490 External decommissioning fund investments M. 145 467 Long term receivables g 8M3, 68 735 Intangible and other assets MM 68 624 Total other assets If;tWW 1 010 853 Total (W3j $5 949 732 Liabilities and Equity g Capitalization (See pages 32 33) p$M, Common stockholders' equity $1896 967 Preferred stockholders' equity My 240 469 Long-term debt %M3 1 463 354 Total capitalization PM4 3 600 790 j9g,) Current Liabilities jM 16 106 Long term debt due within one year Other long-term debt potentially due within one year 596 % 141 600 Short-term debt-primarily commercial paper Q$$$ 238 439 Accounts payable M, 234 905 {M; ID j 178 119 Taxes accrued IN% 28 164 Interest accrued Dividends payable on common and preferred stocks h. WBjj 47 283 Accrued payroll, vacation and other MW 79 029 Total current liabilities MW Q 963 645 Other Liabilities G_ j Deferred income taxes N 0019 845 031 h1Sl913j 173 838 Deferred investment tax credits Regulatoryliabilities QWW3 200 517 Pension and other benefit obligations (M3 Ell 92 514 Other long-term obligations and deferred income f 5815d 73 397 e Total other liabilities [1WW ] 1 385 297 Commitments and Contingent Liabilities (See Notes 14 and 15) b d Total {WWWj $5 949 732 See Notes to FinancialStatements on pages 34 to 49 30
Cumulativa Currency 4 N:mber of Retained Shares Held Tra:slation (Dollar amounts in thousands) Shares iss*ed Par Valce Premium Earnings by ESOP Adicstments Balance at Dec.31,1992 62 598 360 $156 496 $370 819 $1099 896 $ (5113) Net income 211 740 Dividends declared: Cumulative preferred stock at required rates (14 580) Common stock (168 615) Issuances of common stock 4 281 217 10 703 176 296 Preferred stock redemption and stock issuance costs (3 345) (1 069) Loan to ESOP to purchase shares (15 000) Repaymentof ESOPloan 9 226 Balance at Dec.31,1993 66 879 577 $167199 $543 770 $1127 372 $(10 887) l Netincome 243 475 Dividends declared: Cumulative preferred stock at required rates (12 364) Common stock (175 292) issuances of common stock 42 567 106 1 342 1 Stock issuance costs (80) Tax benefit from stock options exercised 843 Repayment of ESOP loan 7 897 Currency translation adjustments $3 586 Balance at Dec.31,1994 66 922 144 $167 305 $545 875 $1183191 $ (2 990) $3 586 Net income 275 795 Dividends declared: Cumulative preferred stock at required rates (12 450) Common stock (180 510) Issuances of common stock 1 253 790 3 135 53 051 Stock issuance costs (1) Tax benefit from stock options exercised 169 Loan to ESOP to purchase shares (15 000) Repayment of ESOP loan 7 333 Currency translation adjustments (1 098) m:n, m. mrraimp,a - . 38133b4 a v 181N440 4 iBION8 i - St MS W -i
- $11057)-
i825d s See Notes to Financial Statements on pages 34 to 49 31
Dec. 31 (Thousands of dottarsl um 1994 Common Stockholders' Eq3ity Common stock - authorized 160,000,000 shares of $2.50 par value; issued shares: 1995,68,175,934; 1994,66,922,144 $ 167305 Premium on common stock L 545 875 jh[@' l 1 183 191 Retained earnings Leveraged common stock held by Employee Stock Ownership Plan (ESOP) /)%g - shares at cost: 1995,229,154; 1994,59,445 (2 990)
- W3 3 586 Currency translation adiustments - net Total common stockholders' equity J35BWq
$1896 967 (i Cumulative Preferred Stock - authorized 7,000,000 shares of $100 par value; h, 'g; M outstanding shares: 1995 and 1994,2,400,000 Minnesota Company h[, ' j g $3.60 series,275,000 shares MDWj $27 500 4.08 series,150,000 shares iSWd 15 000 4.10 series,175,000 shares y 317WV 17 500 4.11 series. 200,000 shares h NW 20 000 4.16 series,100,000 shares (f.!WWj 10 000 4.56 series,150,000 shares , ; 15Wj 15 000 6.80 series. 200,000 shares 4NWd 20 000 7.00 series,200,000 shares NINGj 20 000 Variable Rate series A,300,000 shares O WWS 30 000 i Variable Rate series B,650,000 shares @bSWh 65 000 Total n 35Wl 240 000 Premium on preferred stock NI@M 469 Total preferreu stockholders' equity L S :$f4Wj $ 240 469 j] '~ i Long Term Debt f Me,;g; First Mortgage Bunds Minnesota Company k4 Series due: March t, 1996,6.2 % [8]$% $ 8 800* Oct.1,1997,5X% ~ @W] 100 000 Feb.1,1999, SX% WWW4 200 000 Dec.1,2000,5X% $WM 100 000 Oct. I,2001,7X% CDWj 150 000 hWW] [$ WWS March 1,2002,7X% 50 000 Feb.1,2003,7X% 50 000 April 1,2003,64% MNW$ 80 000 Dec.1,2005,6X% eIWW] 70 000 0ec.1,1994 2006,6.60% " [M % 22 300 " March 1,2011, Variable Rate yWK 13 700* July 1,2019,9X% c,; 98 000 4[ Q[WW]h June 1,2020,9%% 70 000 July 1,2025,7X% ]($1pmj@M (13 700) Total $1012 800 Less redeemable bonds classified as current (see Note 7) Less current maturities F h(1814 (1 200) Net (St_WW J $ 997 900
- Pollution controlfinancing
- Resource recovery financing See Notes to FinancialStatements on pages 34 to 49 32
Dec. 31 (Thousands oldollars! 1994 Long Term Debt-continued i. First Mortgage Bonds Wisconsin Company (less reaequired bonds: 1995, $3,365,1994, $490) .. f .g Series due: L . SiM.g] $ 40 000 4 Oct.1,2003,5X% April 1,2021,9X% pd4DMS 48 010 March 1,2023. 7x% MMM 110 000 Total 19,85; 198 010 Less current maturities
- ~
(2 910) i Net IS'198W3 $ 195100 Guaranty Agreements-Minnesota Company Series due: ,g, Feb.1.1994-2003,5.41% SilM 5 900' May 1,1*J4 2003,5.69% hMW) 24 750' Feb.1,2003,7.40% F 1-39F 3 500* Total p?8Wj 34 150 Less current maturities i, i(IW( (700) Net 18 ? W1B d $ 33 450 Miscellaneous Long Term Debt Q:g, j City of Becker Pollution Control Revenue Bonds - Series due $;[ ] Dec.1,2005, 7.25% $$8Wl $ 9 000* April 1,2007,6.80%
- SWi 60 000*
March 1,2019, Variable Rate i (W 27 900* Sept.1,2019, Variable Rate J:1NWc 100 000* Anoka County Resource Recovery Bond - Series due '. [ [ - Dec.1,1994 2008,7.06% U [$$1N" 25 150** City of La Crosse, Resource Recovery Bond - Series due [.( k Nov.1,2011,7X% g $1BQ 18 600** Viking Gas Transmission Company Senior Notes - Series due is,_ J 0ct. 31,2008,6.4% ENWh 29 511 NRG Energy Center,Inc. (Minneapolis Energy Center) [T/.h Senior Secured Notes - Series due June 15,2013,7.31% $30% 81 498 United Power & Land Notes due " ' ' g _. March 31,2000,7.62% g AStuj 9 375 Various Affordable Housing Project Notes due 6 y_f 1994 2024,1.0 5 9.9 % >fj3 W 7 710 Employee Stock Ownership Plan Bank loan due 1y ,7 1994 2002, Variable Rate D L S$pt t 2 698 h U$NPN Other 10 736 Total {s@30W j g 382 178 Less variable rate Becker bonds classified as current (See Note 7) 2FM j (127 900) Less current maturities "dtimi (11 296) Net {$.31WB :i $ 242982 Unamortized discount on iong-term debt - net j!i 7 54i (6 078) Totallong-term debt F198 W 4 1 463 354 Total capitah2ation r5MB NS y $3 600 790
- Pollution controlfinancing
- Resource recovery financing See Notes to FinancialStatements on pages 34 to 49 l
33
- 1.
SUMMARY
OF SmNIFICANT ACCOUNTING POLICIES Allowance f r Funds Used DuriIg Construction (AFC) AFC, a non- "O
- System of Acctros Northern States Power Company, a Minnesota senting the cost of capital used to finance utility construction cWporation (tha Company),.is predominantly a regulated public utility activities, to qualified Construction Work in Progress (CWIP). The AFC sarving custori ers in Minnesota, North Dakota and South Dakota.
rate was 6.0 percent in 1995,5.0 percent in 1994 ano 7.4 percent in Northern States Power Company, a Wisconsin corporation (the Wis-1993. The amount of AFC capitalized as a construction cost in CWIP is consin Company), a wholly owned subsidiary of the Company,is a credited to other income (for equity capital) and interest charges (for regulated public utility serving customers in Wisconsin and Michigan. debt capital). AFC amounts capitalized in CWIP are included in rate Anothei wholly owned subsidiary, Viking Gas Transmission Company base.u: establishing utility service rates. In addition to construction-(Viking), is a regulated natural gas transmission company that oper-related amounts, AFC is also recorded to reflect returns on capital ates a 500-mile interstate natural gas pipeline. Consequently, the used to finance conservation programs. Company, the Wisconsin Company and Vikmg maintain accounting records in accordance with either the uniform system of accounts Dwihb%dlW4mm@@s6N prescribed by the Federal Energy Regulatory Commission (FERC) or puted by applying the straight line method over the estimated useful those prescribed by state regulatory commissions, whose systems ives of various property classes. The Company files with the Min-are the same in all material respects. nesota Public Utilities Commission (MPUC) an annus' review of remain-ing lives for electric and gas production properties. The most recent Principles of Consolidation The consolidated financial statements studies, as approved by the MPUC, recomcderl s decrease of inclade all material companies in which NSP holds a controlling a roximately 30.2 million and an increasr. of approximately 30.5 million fint.cialinterest, including: the Wisconsin Company; NRG Energy, for the 1995 and 1994 annual depreciatir.n accruals. Nspectively. In n (WIG); Viking: Cenergy, Inc. (Cenergy), which changed its name to Cenerpnse,Inc. effective Jan.1,1996; and Eloigne Company. As Every five years, the Company also must file an average service life discussed in Note 3, NSP has investments in partnerships, joint ven. filing for transmission, distribution and general properties. The most tures and projects for which the equity method of accounting is recent filmgs approved by the MPUC were in 1994 for general plant applied. Earnings from equity in international investments are and in 1993 for all other facilities. Depreciation provisions, as a per-recorded net of foreign income taxes. All significant intercompany centage of the average balance of depreciable utility propertyin ser-transactions and balances have been eliminated in consolidation vice, were 3.64 percent in 1995,3.55 percent in 1994 and 3.47 percent except for intercompany and intersegment profits for sales among the in 1993. electric and gas utikty businesses of the Company, the Wisconsin Company and Viking, which are allowed in utility rates. The Company Decommissioning As discussed in Note 14, NSP currently is record-and its subsidianes collectively are referred to herein as NSP. i i i h hm's nuclear gen-erating plants through annual depreciation accruals. The provision Revenues Revenues are recognized based on products and services for the estimated decommissioning costs has been calculated using provided to customers each month. Because utility customer meters an annuity approach designed to provide for full expense accrual are read and billed on a cycle basis, unbilled revenues (and related g energy costs) are estimated and recorded for services provided1 om the monthly meter-readmg dates to month-end. .s nuclear plants.The Financial Accounting Standards Board a coundng Man h m M m go W The Company's rate schedules, applicable to substantially all of its util-effect in 1997. The standards would require the full accrual of nuclear ity customers, include cost of-energy adjustment clauses, under which rates are adjusted to reflect changes in average costs of fuels, pur-in 1997. (See Note 14 for more discussion of this proposed standard.) chased energy and gas purchased for resale. The Company's rate schedules in Minnesota also include a rate adjustment clause, which is Nuclear Fuel Expense The original cost of nuclear fuelis amortized to to be adjusted annually, to reflect changes in recovery of electric and fuel expense based on energy expended. Nuclear fuel expense also gas deferred conservation program costs. As ordered by its primary includes assessments from the U.S. Department of Energy (DOE) for i regulator, Wisconsin Company retail rate schedules include a cost of-costs of future fuel disposal and DOE f acility decommissioning, as energy adjustment clause for purchased gas but not for electric fuel discussed in Note 14. and purchased energy. The biennial retait rate review process for Wis-consin electric operations considers changes in electric fuel and pur-W MCehebsedmmm chased energy costs in lieu of a cost-of-energy adjustment. g gg amount of the liability can be reasonably estimated.When a single Utility Plant and Retirements Utility plant.is stated at original cost. estimate of the li rhy innot be determined, the low end of the esti-The cost of additions to utility plantincludes contracted work, direct mated range i; -, aed. Costs are charged to expense or deferred labor and materials, allocable overhead costs and allowance for as a regulatory asset based on expected recovery in future rates,it funds used during construction. The cost of units of property retired, they relate to the remediation of conditions caused by past opera-plus net removal cost,is charged to the accumulated provision for tions, or if they are not expected to mitigate or prevent contamination depreciation and amortization. Maintenance and replacement of from future operations. Where environmental expenditures relate to items determined to be less than units of property are charged t facilities currently in use, such as pollution control equipment, the operating expenses. costs may be capitalized and depreciated over the future service periods. Estimated remediation costs are recorded at undiscounted 34
I amounts, independent of any insurance or rate recovery, based on derivative arrangementis the use of natural gas futures contracts by l prior experience, assessments and current technology. Accrued Cenergy to manage the risk of gas price fluctuations.The cost or obligations are regularly adjusted as environmental assessments and benefit of natural gas futures contracts is recorded when related estimates are revised, and remediation efforts proceed. For sites sales commitments are fulfilled as a component of Cenergy's non-where NSP has been designated as one of several potentially respon-regulated operating expenses. NSP does not speculate in natural gas sible parties, the amount accrued represents NSP's estimated share futures. A third derivative instrument used by NSP is interest rate of the cost. NSP intends to treat any future costs incurred related to swaps that convert fixed rate debt to variable rate debt. The cost or decommissioning and restoration of its non-nuclear power plants and benefit of the interest rate swap agreements is recorded as a compo-substation sites, where operation may extend indefinitely, as a capi-nent of interest expense. None of these three derivative financial talized removal cost of retirement in utility plant. Depreciation instruments is reflected on NSP's balance sheet. j expense levels currently recovered in rates include a provision for an j estimate of removal costs (based on historical experience). Use of Estimates In recording transactions and balances resulting l from business operations, NSP uses estimates based on the best 12come Taxes NSP records income taxes in accordance with State-information available. Estimates are used for such items as plant ment of Financial Accounting Standards (SfAS) No.109-Accounting depreciable lives, tax provisions, uncollectible accounts, environ-for income Taxes. Under the liability method required by SFAS No. mentalloss contingencies, unbilled revenues and actuarially deter-109, income taxes are deferred for all temporary differences between mined benefit costs. As better information becomes available (or pretax financial and taxable income and between the book and tax actual amounts are determinable), the recorded estimates are bases of assets and liabilities. Deferred taxes are recorded using the revised. Consequently, operating results can be affected by revisions tax rates scheduled by law to be in effect when the temporary differ-to prior accounting estimates. Recent changes in interest rates have ences reverse. Due to the effects of regulation, current income tax resulted in changes to actuarial assumptions used in the benefit cost expense is provided for the reversal of some temporary differences calculations for postretirement benefits. Also,the depreciable lives of l previously accounted for by the flow-through method. Also, regula-certain plant assets are reviewed and,if appropriate, revised each i tion has created certain regulatory assets and liabilities related to year, as discussed previously. (See Notes 8,14 and 15 for more infor-income taxes, as summarized in Note 10. NSP's policy for income mation on the effects of these changes in estimates.) taxes related to international operations is discussed in Note 9. Cash Equivalents NSP considers investments in certain debt instru-Investment tax credits are deferred and amortized over the estimated ments (primarily commercial paper) with an original maturity to NSP of lives of the related property. three months or less at the time of purchase to be cash equivalents. Foreign Currency Translation The local currencies are generally the Regulatory Deferrels As regulated utilities, the Company,the Wiscon-l functional currency of NSP's foreign operations. Foreign currency sin Company and Viking account for certain income and expense i denominated assets and liabilities are translated at end of-period items under the provisions of SFAS No. 71 - Accounting for the rates of exchange. The resulting currency translation adjustments are Effects of Regulation. In doing so, certain costs that would otherwise accumulated and reported as a separate component of stockholders' be charged to expense are deferred as regulatory assets based on equity. Income, expense and cash flows are translated at weighted-expected recovery from customers in future rates. Likewise, certain average rates of exchange for the period. credits that otherwise would be reflected as income are deferred as regulatory liabilities based on expected flowback to customers in Exchange gains and losses that result from foreign currency transac. future rates. Management's expected recovery of deferred costs and tions (e g. converting cash distributions made in one currency to expected flowback of deferred credits are generally based on spe-another) are included in the results of operations as a component of cific ratemaking decisions or precedent for each item. Regulatory equity in earnings of unconsolidated affiliates. Through Dec. 31,1995, assets and liabilities are amortized consistent with ratemaking treat-NSP had not experienced any material translation gains or losses ment established by regulators. Note 10 describes the nature and from foreign currency transactions that have occurred since the amounts of these regulatory deferrals. respective foreign investment dates. Other Assets The purchase of various non-regulated entities from Derivative FinancialInstruments NSP's policy is to hedge foreign 19931995 at a price exceeding the underlying fair value of net assets currency denominated investments as they are made to preserve acquired resulted in recorded goodwill of $20.3 million ($19.0 million their U.S. dollar value, where appropriate hedging instruments are net of accumulated amortization) at Dec. 31,1995. This goodwill and available. NRG has entered into currency hedging transactions other intangible assets acquired are being amortized using the through the use of forward foreign currency exchange agreements. straight-line method over periods of 15 to 30 years. NSP periodically i Gains and losses on these agreements offset the effect of foreign evaluates the recovery of gmdwill based on an analysis of estimated currency exchange rate fluctuations on the valuation of the invest-undiscounted future cash i i ments underlying the hedges. Hedging gains and losses, net of income tax effects, are reported with other currency translation intangible and other assets also include deferred financing costs adjustments as a separate component of stockholders' equity. NRG is (net of amortization) of approximately $11.8 million at Dec.31,1995. not hedging currency translation adjustments related to future oper-These costs are being amortized over the remaining maturity period ating results. NSP does not speculate in foreign currencies. A second of the related debt. 35
R:cf assificatitns Certain reclassifications have been made to the Investments in the MIBRAG and Gladstone projects in 1994 resulted in 1994 and 1993 financial statements to conform with the 1995 presem an increase in the equity in earnings from unconsolidated affiliates of tation. These reclassifications had no effect 01 net income or earn-approximately $26 million in 1994. ings per share. Summarized Financiallnformation of Unconsolidated Affiliates
- 2. ACCOUNTING CHANGES Summarized financialinformation for these projects, including inter-ests owned by NSP and other parties, was as follows (as of and for Postemployment Benefits Effective Jan.1,1994, NSP adopted the the years ended Dec.31,1995 and 1994L provisions of SFAS No.112 - Employers' Accounting for Postemploy-ment Benefits.This standard required the accrual of certain postem-p;
,p ployment costs, such as injury compensation and severance, that are (Millions of dollars) um 1994 payable in the future. The Company's pre 1994 liability of approxi. g mately S9.4 million (8 cents per share) was expensed in 1994. Other Assets 1 98.9 1 593.8 Total Assets $ 93034 $2108.7 Postratirement Benefits As discussed in Note 8, NSP changed its Current Liabikties is 3E5 5 1596 accounting for postretirement medical and death benefits in 1993. Other liabikties T3 1 480.0 Due to rate recovery of the expense increases,the change had an Equity b 469.1 immaterial effect on net income. Of the 1993 cost increases due t Total Liabikties and Equity hWNLO f $2108.7 adoption of SFAS No.106, about $12 million was deferred to be amor-gp tired over rate recovery periods in 19941996. In 1994, administrative in Unconsolidatea Affiliates 3 $179.1 and general expenses increased by approximately $16 million due to IN full recognition of accrued SFAS No.106 costs, including amounts Results of Operations deferred from 1993. (Millions of dollars) um 1994 iMOLR) E"* "9
- 3. lNVESTMENTL ACCOUNTED FOR BY THE EQUITY METHOD Operating income
$128.8 4 Through its non-regulated subsidiaries, NSP has investments in vari. Net income i MW2) $117.0 ous international and domestic energy projects and domestic afford-able housing and real esta*.e projects. The equity method of
- 4. CUMULATIVE PREFERRED STOCK accounting is applied to suct mvestments in affiliates, which include The Company has two series of adjustable rate preferred stock. The joint ventures and partnerste ecause the ownership structure dividend rates are calculated quarterly and are based on prevaihng prevents NSP from exercisiig e : ntrolkng mfluence over operating rates of certain taxable government debt securities indices. At Dec.
and financial policies of the pu ets. Under this method, ecuity m the 31,1995, the annualized dividend rates were $5.50 for both series A pretax income or losses of domestic partnerships ant' in the net and series B. income or losses of international projects is reflectrJ as Equity in Earnings of Unconsolidated Atfiliates. A summary of NSP's significant At Dec. 31,1995, the various preferred stock series were callable at equity-method investments is as bliows: rices per share ranging from $102.00 to $103.75, plus accrued divi-dends. In 1993, the Company redeemed all 350,000 shares of its $7.84 s s Curndahn MM M a@H2 per sham Name Ar a In er st Se c Vanous Independent
- 5. COMMON STOCK AND INCENTIVE STOCK PLANS Power Production July 1991-Facilities U.S.A.
45W50% December 1994 The Company's Articles of Incorporation and First Mortgage Inden-Affordable Housing - Apnl 1993-ture provide for certain restrictions on the payment of cash dividends Limited Partnerships U.S.A. 20599% December 1995 on common stock. At Dec. 31,1995, the Company could have paid, Rosebud SynCoal without restrictions, additional cash dividends of more than $1 billion Partnership U.S.A. 50 % August 1993 on common stock. MIBRAG Mmmg and Power Generation Europe 33.3 % January 1994 NSP has an Executive Long Term Incentive Award Stock Plan that Gladstone Power permits granting non-qualified stock options. The options currently Station Australia 37.5 % March 1994 granted may be exercised one year from the date of grant and are Scudder Latin exercisable thereafter for up to nine years. The plan also allows cer. American Trust for tain employees to receive restricted stock and other performance Independent Power Latin awards. Performance awards are value% dollars, but paid in shares Energy Projects America 25 % June 1993 based on the market price at the time of payment. Transactions under Schkopau Power Under the various incentive stock programs, which may result in the Station Europe 20.6 % Construction Msuance of new shares,were as follows: 36
i Stock Awards The Company's First Mortgage Bonds Series due March 1,2011, and (Thousands o/ shares u,a 1994 1993 the City of Becker Pollution Control Revenue Bonds Series due March Outstanding Jan.1 537.1 5283 1,2019, and Sept.1,2019, have variable interest rates, which currently Options granted 304 0 196.9 change at various periods up to 270 days, based on prevaihng rates Other stock awards y .2 9.5 for certain commercial paper securities or similar issues The interest Options and awards eL _ (42.6) (174.3) rates applicable to these issues averaged 5.2 percent,3.7 percent Options and awards fc$l.% (16.1) (22.2l and 3.8 percent, respectively, at Dec. 31,1995. The 2011 series bonds Other -( % L2) (1.5) are redeemable upon seven days notice at the option of the bond-Outstanding at Dec.3P = MWj 782.4 537 1 holder. The Company also is potentially liable for repayment of the Option pnce ranges: .g y 2019 Series Becker Bonds when the bonds are tendered, which unexercised y,e
- .l occurs each time the variable interest rates change. The principal at Dec. 31 pamassem $33.25 S43.50 $33.25-$43.50 amount of all three series of these variable rate bonds outstanding Exercised during 5 d
represents potential short-term obligations and, therefore,is reported (WS4EW $33.25-$43.50 $33.25-$40.94 under current liabilities on the balance sheet. the year Using the treasury stock metho1 of accounting for outstanding stock Maturities and sinking-fund requirements on long-term debt are: 1996, options, the weighted average number of shares of common stock $25,760,000; 1997, $111,553.000; 1998, $14,457,000; 1999, $210,909,000, outstanding for the calculation of primary earnings per share includes and 2000, $115,982,000. any dilutive effects of stock options and other stock awards as com-mon stock equivalents. The differences between shares used for pri-
- 8. BENEFIT PLANS AND OTHER POSTRETIREMENT BENEFITS mary and fully diluted earnings per share were not material.
p appr ma percent are vesented W locallab unions
- 6. SHORT-TERM BORROWINGS under a collective-bargaining agreement, which expires Dec. 31,1996 NSP has approximately $282 million of commercial bank credit lines under commitment fee arrangements. These credit lines make short-Pension Benefits NSP has a non contributory, defined benefit pen-term financing available in the form of bank loans and support for com-sion plan that covers substantially all employees. Benefits are based mercial paper sales. There were no borrowings against these credit on a combination of years of service,the employee's highest average lines at Dec. 31,1995, and approximately $3.6 million of such borrow-pay for 48 consecutive months and Social Security benefits.
ings, with interest payable at 9.75 percent, at Dec. 31,1994. However, $9 6 million in letters of credit were outstanding, which reduced the it is the Company's policy to fully fund the actuarially determined pen-available credit lines at Dec. 31,1995. sion costs recognized for ratemaking purposes, subject to the limita-tions under epplicable employee benefit and tax laws. Plan assets At Dec. 31,1995 and 1994, the Company had $215.6 million and $234.8 principally consist of common stock of public companies, corporate i million, respectively, in short-term commercial paper borrowings out-bonds and U.S. government securities. The funded status of NSP's standing. The weighted average interest rates on all short-term bor-pension plan as of Dec.31 is as follows: rowings as of Dec. 31,1995, and Dec. 31,1994, were 5.7 percent and 6.1 percent, respectively. (Thousands of dollars) M 1994 Actuanal present value of benefit obligation:9 g 7.LONG TERM DEBT Vested 8 ~meJ $ 571254 Non-vested 191M i 120 420 The annual sinking-fund requirements of the Company's and the Accumulated benefit obligation A SMSd $ 691674 Wisconsin Company's First Mortgage Indentures are the amounts Projected benefit obligation 251W55 $ 836 957 necessary to ndeem 1 percent of the highest principal amount of Plan assets at fair value h15W 1 165 584 each series of fi st mortgage bonds at any time outstanding, exclud-Plan assets in excess of ing those serbs issued for pollution control and resource recovery , e rojected benefit obligation ff4M94 (328 627) Unrecognized prior service cost 6 :(WN! (21 538) financings, e ad excluding certain other series totaling $990 million. The Company may, and has, applied property additions in lieu of cash Unrecognized net actuarial gain $MWi 370 289 payments on all series, as permitted by its First Mortgage Indenture. Unrecognized net transitional asset b / S15 691 The Wisconsin rr mpany also may apply property additions in lieu of Net pension liability recorded !$ n15 W i $ 20 815 cash on all series as permitted by its First Mortgage Indenture. Except for minor exclusions, all real and personal property of the l For regulatory purposes, the Company's pension expense is deter-j Company and the Wisconsin Company is subject to the liens of the mined and recorded under the aggregate-cost method. As required j first mortgage indentures. 0ther debt securities are secured by a lien by SFAS No. 87 - Employers' Accounting for Pensions, the difference on the related real or personal property, as indicated on the Consoli-between the pension costs recorded for ratemaking purposes and dated Statements of Capitalization. the amounts determined under SFAS No. 87 is recorded as a regula-f tory liability on the balance sheet. Net annual periodic pension cost includes the following components: 37
(Thousands of dollars} nm 1994 1993 (IVillions of doIIers) "T1 1994 gg. _g 3 B0: Service cost-benefits earned ._q during the period @$ESI $27 536 $25015 Retirees /$lES' $132.2 Interest cost on projected (( Fully oligible plan participants %f35A] 21.5 benefit obligation A MRj 65 107 71 015 Other active plan participants '41188 % 79.4 Actual return on assets 1380 3 % (12 668) (152 019) Total APB0 y 373j 233.1 Net amortization and deferral (35 5 3 (82114) 66 299 Plan assets at fair value N11Al 8.0 Net periodic pension cost
- ,j APB0 in excess of plan assets y275Aq 225.1 determined under SFAS No. 87
!(191K (2 139) 10 370 Unrecognized net actuarial gain (loss) $ gal < 2.3 j Unrecognized transition obligation f110Bh (194.0) Additional costs recognized ,q due to actions of regulators ' ? tSW i 3 922 5 117 Net benefit obligation recorded 0 $ SlJ 0 $ 33.4 Net periodic pension cost pg,p q $ 1783 0 $ # 3161 $15 487 The assumed health care cost trend rates used in measuring the APB0 recognized for ratemaking at Dec. 31,1995 and 1994, respectively, were 10.4 and 11.0 percent for The weighted average discount rate used in determining the actuarial those under age 65, and 7.3 and 7.5 percent for those over age 65. The present value of the projected obligation was 7 percent in 1995 and 8 assumed cost trend rates are expected to decrease each year until they percent in 1994 The rate of increase in future compensation levels used reach 5.5 percent for both age groups in the year 2004, after which they in determinmg the actuarial present value of the projected obligation are assumed to remain constant. A 1 percent increase in the assumed was 5 percent in 1995 and 1994. The assumed long-term rate of return on health care cost tiend rate for each year would increase the APB0 by assets used for cost determinations under SFAS No. 87 was 9 percent approximately 15 percent as of Dec. 31,1995. Service and interest cost for 1995 and 8 percent for 1994 and 1993. Assumption changes components of the net periodic postretirement cost would increase by decreased 1995 pension costs (determined under SFAS No. 87) by approximately 17 percent with a similar 1 percent increase in the approximately $21.5 million. Assumption changes are expected to assumed health care cost trend rate. The assumed discount rate used increase 1996 pension costs (determined under SFAS No. 87) by approx-in determining the APB0 was 7 percent for Dec. 31,1995,8 percent for imately $13.6 million. Because the Company's pension expense is deter-Dec. 31,1994, and 7 percent for Dec. 31,1993, compounded annually. mined under the aggregate-cost method (not SFAS No. 87) for regulatory The assumed long-term rate of return on assets used for cost determi-and financial reporting purposes, the effects of regulation prevent the nations under SFAS No.106 was 8 percent for 1995 and 1994. Assump-majority of these assumption changes from affecting earnings. tion changes decreased 1994 costs by approximately $2.1 million and decreased 1995 costs by approximately $2.0 million. The effect of the Postretirement Health Care NSP has a contributory health and welfare changes in 1996 is expected to be a cost increase of approximately benefit plan that provides health care and death benefits to substantially $2.1 million. all employees after their retirement. The plan is intended to provide for sharing the costs of retiree health care between NSP and retirees. For The net annual periodic postretirement benefit cost recorded consists employees retiring after Jan.1,1994, a six-year cost-sharing strategy of the following components: was implemented with retirees paying 15 percent of the total cost of health care in 1994, increasing to a total of 40 percent in 1999. (Millions of dollars) u 1994 1993 Service cost benefits p._ _g Effective Jan.1,1993, NSP adopted the provisions of SFAS No.106 - earned during the year i ^ $ li.2 j $ 5.0 $ 4.4 Employers' Accounting for Postretirement Benefits Other Than Pen-Interest cost (on service cost and APBO) : 192 { 16.1 17.5 sions. SFAS No.106 requires the actuarially determined obligation for Actual return on assets ( (1.0) j L2) LI) ~ postretirement health care and death benefits to be fully accrued by Amortization of transition obligation [ ;10A j 10.8 10.8 the date employees attain full eligibility for such benefits, which is Net amortization and deferral - O.4 j L3) .1 generally when they reach retirement age. This is a significant Net penodic postretirement 6 y change from NSP's pre 1993 policy of racognizing benefit costs on a health care cost under SFAS No.106h ) 34.5 $ 31.4 32.7 cash basis after retirement. In conjunction with the adoption of SFAS Costs recognized (deferred) due to [ No.106, NSP elected to amortize on a straight-kne basis over 20 actions of regulators P.
- 4A i 4.1 (12.1) years the unrecognized accumulated postretirement benefit obliga-Net periodic postretirement health j
tion (APBO) of $215 6 million for current and future retirees. This care cost recognized for ratemaking * ' 535.6 4 $35.5 $20 6 obligation considered 1994 plan design changes, including Medicare integration, increased retiree cost sharing and managed indemnity Regulators for NSP's retail and wholesale customers in Minnesota, measures not in effect in 1993. Wisconsin and North Dakota have allowed full recovery of increased benefit costs under SFAS No.106, effective in 1993. Increased 1993 Before 1993, NSP funded payments for retiree benefits internally. accrual costs for Minnesota retail customers are being amortized While NSP generally prefers to continue using internal funding of over the years 1994 through 1996, consistent with approved rate benefits paid and accrued, significant levels of external funding, recovery. External funding was required by Minnesota and Wisconsin including the use of tax-advantaged trusts, have been required by retail regulators to the extent it is tax advantaged, funding began for NSP's regulators, as discussed below. Plan assets held in such trusts Wisconsin in 1993 and must begin by the next general rate filing for as of Dec. 31,1995, consisted of investments in equity mutual funds Minnesota. For wholesale ratemaking, the FERC has required external and cash equivalents.The funded status of NSP's health care plan as fundmg for all benefits paid and accrued under SFAS No.106. of Dec.31 is as follows: 38
ESOP NSP has a leveraged Employee Stock Ownership Plan (ESOP) and 5.4 million shares of the Company's common stock as of Dec. 31, that covers substantialiy all employees. Employer contributions to this 1995 and 1994, respectively. An average of 221,066 and 111,845 non-contributory, defined contribution plan are generally made to the uncommitted leveraged ESOP shares were excluded from earnings-extent NSP realizes a tax savings on its income statement from divi-per-share calculations in 1995 and 1994, respectively. The fair value of dends paid on certain shares held by the ESOP. Contributions to the NSP's leveraged ESOP shares approximated cost at Dec. 31,1995. ESOP in 1995,1994 and 1993, which represent compensation expense, were $5,059,000, $5,695,000 and $6,281,000, respectively. ESOP contri-401(k) NSP has a contributory, defined contribution Retirement Sav-butions have no material effect on NSP earnings because the contri-ings Plan, which complies with section 401(k) of the internal Revenue butions (net of tax) are essentially offset by the tax savings provided Code and covers substantially all employees. Since 1994, NSP has by the dividends paid on ESOP shares. Leveraged shares held by the been matching specified amounts of employee contributions to this ESOP are allocated to participants when dividends on stock held by plan. NSP's matching contributions were $3.7 million in 1995 and $2.6 the plan are used to repay ES0r loans. NSP's ESOP held 5.7 million million in 1994.
- 9. INCOME TAXES Totalincome tax expense from opvations differs from the amount computed by applying the statutory federalincome tax rate to income before income tax expense. The reasons for the difference are as follows:
La 1994 1993 Federal statutory rate gEA%j 35.0 % 35.0 % [(5J %) ( Increases (decreases)in tax from: 5.9 % 6.1 % State income taxes, net of federalincome tax benefit Tax credits recognized 09.4)%i (3.5)% (2.8)% 1 Equity income from unconsolidated international affiliates { W.51%l (2.5)% 0.0 % Regulatory differences - utility plant items 4 L1,0 % } 0.5 % 1.3 % Other - net b J SA %1 (0.7)% (1.4)% {fMA%! W3 34.7 % 38.2 % Effective income tax rate p g (Thousands oldollars) { 1 Income taxes are compnsed of the following expense (benefit) items: ,j ., y Included in utility operating expenses: Current federal tax expense l$1NM1 l $108 652 $92 099 NDNB3l Current state tax expense 34 823 25 787 (((120ft) (3 450) 15 010 Deferred lederal tax expense Deferred state tax expense y 93Nij (1 606) 4 431 Deferred investment tax credits V IBNF){ (9 191) (8 981) Total h-14714 e 129 228 128 346 Included in other income (expense): } Current federal tax expense ( L 551 $ 3 959 7 853 Current state tax expense L 1829j 923 2 289 Current foreign tax expense ? 23B? 219 h $2N) (3 548) (321) Current federal tax credits f}i ' 2048 ] Deferred federal tax expense (835) (6 736) F 083j (209) (449) Deferred state tax expense g Deferred investment tax credits b l(310)} (310) (242) Total p 5Wr 199 2 394 Totalincome tax expense 5 $15225 o $129 427 $130 740 income before income taxes includes net foreign equity income of $32 3 and $25.9 million in 1995 and 1994, respectively. NSP's management intends to reinvest the earnings of foreign operations indefinitely. Accordingly, U.S. income taxes and foreign withholding taxes have not been provided on the earnings of foreign subsidiary companies. The cumulative amount of undistributed earnhas of foreign subsidiaries upon which no U.S. income taxes or foreign withholding taxes have been provided is approximately $61.6 million at Dec. 31,1995. The additional U.S. income tax and freign wrthholding tax on the unremitted foreign earnings,if repatriated, would be offset in whole or in part by foreign tax credits. Thus,it is impracticable to estimate the amount of tax that might be payable. 39
The components of NSP's net deferred tax liability (current and non-
- 11. FINANCIAL INSTRUMENTS current portions) at Dec. 31 were:
Fair Values The estimated Dec. 31 fair values of NSP's recorded financialinstruments are as follows: (Thousands of do#ars) mm 1994 Deterred tax habikties: p> M (Thousands o/do#ars) m 1994 Difference between book and A s tax bases of property $"W3[ $ 843872 w Amenus, @M alue{b * "9 Amount Value Regulatory assets Kmme 120 329 76 775 9" * *"N @; ? tN; b.,.. (SWB Tax benefit transfer leases and short-term E ONBl 7 854 _4 Other h""h Total deferred tax liabihties f81mM1 I"*** *"'8 4 $1048 830 ,r H hs N "9 Deferred tax assets: p$ NW$ $ 80 383 c essoning p 9 98 Regulatory liabilities bE 4 investments .SW853c M', 85 $145467 $145 467 Deferred investment tax credits u : 01 Min 65 812 Deferred compensation, vacation Ih d v "9 and other accrued liabikties I ", "U j,,,, $1621060 $1540 595 h 257383 50 572 not currently deductible Other 6kIIWl 18 110 cas cash equNalents and sMmm innstments, be caWng Total deferred tax assets !$ W713i $ 214 877 Net deferred tax liabikty !$ WW4 $ 833 953 t approximates fay.r value because of the short maturity of amo those instruments. The fair values of the Company's long-term invest. rnen s n an enemal nuckar &commissbning fund am es&nad
- 10. REGULATORY ASSETS AND LIABILITIES based on quoted market prices for those or similar investments. The The following summarizes the individual components of unamortized fair value of NSP's long-term debt is estimated based on the quoted regulatory assets and liabilities shown on the Consolidated Balance market prices for the same or similar issues, or the current rates Sheets at Dec. 31:
offered to NSP for debt of the same remaining maturities. Amortization Derivatives NRG has entered into six forward foreign currency (Thousands o/do#ars) Period 21 1994 exchange contracts with counterparties to hedge exposure to cur-AFC recorded in plant gy. rency fluctuations to the extent permissible by hedge accounting e on a net-of tax basis
- Plant Lives lMSW $155102 requirements. Pursuant to these contracts, transactions have been Conservation and energy g* M executed that are designed to protect the economic value in U.S. dol-management programs
- Up to 10 Years 9530j 76 902 lars of NRG's equity investments and retained earnings, denominated Losses on dh in Australian dollars and German deutsche marks (DM). NRG's for-reacquired debt Term of New Debt NE3M! 52514 ward foreign currency exchange contracts, in the notional amount of Environmental costs Up to 15 Years
[ ~ S MS, 47 779 $119 million, hedge approximately $123 million of foreign currency Deferred postretirement denominated assets, and in the notional amount of $47 million, hedge h.EWj benefit costs 3-15 Years 9 930 approximately $64 millior' of foreign currency denominated retained Unrecovered purchased earnings at Dec.31,1995. Because the effects of both currency trans-gas costs 12 Years pJ$9Bij 7 601 lation adjustments to foreign investments and currency hedge instru-State commission ff 3 ment gains and losses are recorded on a net basis in stockholders' S (7Eth 5544 equity (not earnings), the impact of significant changes in currency accounting adjustments
- Plant Lives Other Various LIWtl 2 204 exchange rates on these items would have an immaterial effect on Total regulatory assets i$3M212 4 $357 576 NSP's financial condition and results of operations.The contracts Excess deferred income taxes
};. q required cash collateral balances of $5.9 million at Dec. 31,1995, collected from customers $ SMSj $ 75277 which are reflected as other current assets on NSP's balance sheet. Investment tax credit deferrals $1M371j 110831 The contracts terminate in 1998 through 2005 and require foreign cur-Unrealized gams from ,d rency interest payments by either party during each year of the con-decommissioning investments 15 3141 1 412 tract. If the contracts had been terminated at Dec. 31,1995, $5.2 Pension costs ( 21 W} 11054 million would have been payable by NRG for currency exchange rate Fuel costs and other b 74N! 1 943 changes to date. Management believes NRG's exposure to credit risk Totai regulatory habilities (8887574 $200 517 due to non-peiformance by the counterparties to its forward
- Earns a return on investmentin the raremaking process.
exchange contracts is not significant, based on the investment grade rating of the counterparties. 40 F
i Cenergy has entered into natural gas futures contracts in the notional
- 12. DETAIL OF CERTAIN INCOME AND EXPENSE ITEMS amount of $11.3 million at Dec. 31,1995. The original contract terms Administrative and general (A&G) expense for utility operations consists range from one month to three years. The contracts are intended to oMe Mowsg:
mitigate risk from fluctuations in the price of natural gas that will be required to satisfy sales commitments for future deliveries to cus-tomers in excess of Cenergy's natural gas reserves. Cenergy's futures salanes and wages S 49 726 $ ME contracts hedge $115.91 ion in anticipated natural gas sales in 1996-stretirement medical and j.' 1997. Margin balar' as of $2.3 million at Dec. 31,1995, were main-injury compensation benefits g n(g 41 901 14 995 tained on deposit mth brokers and recorded as cash and cash er n s-equivalents on N?/'s balance sheet. The counterparties to the aH u y en$oyees 38 M2 MM futures contracts are the New York Mercantile Exchange and major nahn technology, faches, gd gas pipeline ope:ators. Management believes that the risk of non-and administrative support g% 29 751 30 504 performance by these counterparties is not significant. If the con-lnswance anHam JS M ME tracts had been terminated at Dec. 31,1995, $0.6 million would have been payable to Cenergy for natural gas price fluctuations to date. I NSP has three interest rate swap agreements with notional amounts Other income (deductions)- net consist of the following: totalling $320 million. These swaps were entered into in conjunction with first mortgage bonds. As summarized below,these agreements effectively convert the interest costs of these debt issues from fixed Non-regulated operations-gp 7 to variable rates based on six-month London Interbank Offered Rates perating revenues and sales R $241827 $90 531 (LIBOR), with the rates changing semiannually. Operating expenses WWT 241480* 81 480 ax operaong income" JM ' 30 9OM National Amount Term of Net Effective interest and investment income ]HW 10839 4 522 (millions Swap Interest Cost at i Series ofdollars) Agreem:nt Dec. 31,1995 p M M2) an a con d sons Environmental and g% M .4 3, g W M reg awyc n ngene s Oct.1,1997 $100 Maturity 5.94 %
- " "9 "* ""#
5A% Series due ah net Mcome hense) M% $ 0680 $ M82 Feb.1,1999 $200 Maturity 5.36 % 7W% Series due nclu e niegulated energy project write-downs of $5.0 million March 1,2023 $20 March 1,1998 8.03 % 1 in 1995 and $50 million in 1994.
- "E Market risks associated with these agreements result from short-
- # "E###"
"##E" # I term interest rate fluctuations. Credit risk related to non-performance of the counterparties is not deemed significant, but would result in p NSP terminating the swap transaction and recognizing a gain or loss, depending on the fair market value of the swap. The interest rate The Company is a participant in a jointly owned 855-megawatt coal-fired swaps serve to hedge the interest rate risk associated with fixed rate electric generating unit, Sherburne County generating station unit No. 3 ( debt in a declining interest rate environment. This hedge is produced (Sherco 3), which began commercial operation Nov.1,1987. Undivided by the tendency for changes in the fair market value of the swap to be interests in Sherco 3 have been financed and are owned by the Com-offset by changes in the present value of the liability attributable to pany (59 percent) and Southern Minnesota Municipal Power Agency the fixed rate debt issued in conjunction with the interest rate swaps. (41 percent). The Company is the operating agent under the joint owner-f If the interest rate swaps had been discontinued on Dec. 31,1995, the ship agreement.The Company's share of related expenses for Sherco 3 present value benefit to NSP would have been $2.8 million, which is since commercial operations began are included in Utility Operating i 9artWly offset by an increase in the present value of the related debt Expenses. The Company's share of the gross cost recorded in Utility of $0.9 million above carrying value. Plant at Dec. 31,1995 and 1994, was $585,625,000 and $585,783,000, respectively. The corresponding accumulated provisions for deprecia-Letters of Credit NSP uses letters of credit to provide financial guaran-tion were $150,022,000 and $132,092,000. tees for certain operating obligations, including NSP workers' com-pensation benefits and ash disposal site costs, and Cenergy natural
- 14. NUCLEAR OBLIGATIONS gas purchases. At Dec. 31,1995, letters of credit of $46.7 million were Fuel Disposal NSP is responsible for the temporary storage of used outstanding. Generally,the letters of credit have terms of one year and nuclear fuel from the Company's nuclear generating pfants. Under a are automatically renewed, unless prior written notice of cancellation contract with the Company, the 00E is obligated to assume the is provided to NSP and the beneficiary by the issuing bank. The con-responsibility for permanent storage or disposal of NSP's used tract amounts of these letters of credit approximate their fair value nuclear fuel. The Company has been funding its portion of the DOE's and are subject to fees competitively determined in the marketplace.
l permanont d;sposal program since 1981. Funding took place through an internal sinking fund until 1983, when the DOE began assessing fuel disposal fees under the Nuclear Waste Policy Act of 1982 based 41
on a charge of 0.1 cent per kilowatt hour sold to customers from working with the Mescalero Apache Tribe to establish a private f acil-nuclear generation. The cumulative amount of such assessments ity for interim storage of used nuclear fuel on the Tribe's reservation from the DOE to NSP through Dec. 31,1995,is $230.8 million. Currently, in New Mexico. A core group of more than 20 United States nuclear it is not determinable if the amount and method of the DOE's assess-utilities has agreed to support the construction and operation of the ments to all utilities will be sufficient to fully fund the DOE's perma-Mescalero interim storage site. Work on the project is under way in nent storage or disposal f acihty. several areas, including environmental assessment, f acility design and drafting the detailed contracts that will govern the construction The DOE has stated in statute and by contract that a permanent stor-and operation of the site. An architect engineering firm and an envi-age or disposal facility would be ready to accept used nuclear fuel by ronmental contractor have been retained to perform the environmen-1998. Accordingly, NSP has been providing, with regulatory and leg-tal and licensing activities. The consortium is currently scheduled to islative approval,its own temporary on-site storage f acilities at its submit a license application for the facility to the Nuclear Regulatory Monticello and Prairie Island nuclear plants, with a capacity suffi-Commission (NRC)in December 1996. The spent fuel storage facility is cient for used fuel from the plants until at least that date. Recent indi-expected to be operational and able to accept the first shipment of cations from the DOE are that a permanent federal facility will not be used nuclear fuel by mid-2002. However, due to pending regulatory ready to accept used fuel from utilities until approximately 2010. In and governmental approval uncertainty, it is possible that this interim 1994, the Company and 13 other major utilities filed a lawsuit against storage may be delayed or not available. the DOE in an attempt to clarify the DOE's obligation to accept spent nuclear fuel beginning in 1998. The primary purpose of the lawsuit is Fuel expense includes DOE fuel disposal assessments of $12.3 million, to insure the Company and its customers receive timely storage of $10.6 million and $8.7 million for 1995,1994 and 1993, respectively. Dis-used nuclear fuel. The lawsuit was argued before the United States posal expenses reflect reductions of $0.7 million in 1994 and $2.6 mil-Circuit Court of Appeals for the District of Columbia on Jan.17,19%, lion in 1993 due to a change in the DOE's basis of charging customers, and a decision is expected in three to six months from the tima of retroactive to 1983. Nuclear fuel expenses in 1995,1994 and 1993 also argument. In 1995, the DOE published its " Final interpretationt of include about $5 milhon, $5 million and $1 million, respectively, for Nuclear Waste Acceptance issues"in the Federal Register. In this payments to the DOE for the decommissioning and decontamination j notice, the DOE concluded that it has neither an unconditional obliga-of the DOE's uranium enrichment facihties. The DOE's initial assess-tion to accept spent nuclear fuel by 1998 nor any authority to provide ment of $46 million to the Company was recorded in 1993. This j interim storage Because of the DOE's inadequate progress to provide assessment will be payable in annualinstallments from 1993-2008 and a permanent repository and its disavowal of its obligation, the Min-each installment is being amortized to expense on a monthly basis in nesota Department of Public Service is investigating whether contin-the 12 months following each payment. The most recent installment ued payments to fund the DOE's permanent disposal program is paid in 1995 was $3.7 million; future installments are subject to infla-prudent use of ratepayer money.The outcome of this investigation is tion adjustments under DOE rules. The Company is obtaining rate unknown at this time. In the meantime, NSP is investigating all of its recovery of these DOE assessments through the cost-of energy alternatives for used fuel storage until a DOE facility is available. adjustment clause as the assessments are amortizeo. Accordingly, When on-site temporary storage at NSP's nuclear plants reaches the unamortized assessment of $44 million at Dec. 31,1995, has been i approved capacity,the Company could seek interim storage at a con-deferred as a regulatory asset and is reported under the caption Envi-tracted private f acihty. The Company received Minnesota legislative ronmental Costs in Note 10. approval in 1994 for additional on-site storage f acihties at its Prairie Island plant, provided the Company satisfies certain requirements. Plant Decommissioning Decommissioning of all Company nuclear Seventeen dry cask containers, each of which can store approxi-f acilities is planned for the years 2010-2022, using the prompt disman-mately one half year's used fuel, can become available as follows: tiement method The Company is currently following industry practice five immediately in 1994; four more in 1996 if at.pphcation for an by ratably accruing the costs for decommissioning over the approved alternative storage site is filed, an effort to locate such a site is made cost recovery period and including the accruals in Utikty Plant - i and 100 megawatts of wind generation is available or contracted for Accumulated Depreciation, as discussed in Note 1. Consequently,the construction; and the final eight in 1999, unless the specified alterna-total decommissioning cost obligation and corresponding asset cur- ) tive site is not operational or under construction, certain resource rently are not recorded in NSP's financial statements. The FASB has commitments are not met, or the Minnesota Legislature revokes its proposed new accountmg standards which,if approved as expected approval. (See additional discussion of legislative commitments in in 19%, would require the full accrual of nuclear plant decommission-Note 15.) NSP has loaded used fuelinto three of the dry cask contain-ing and certain other site exit obligations beginning in 1997. If NSP ers as of Dec. 31,1995. With the dry cask storage facilities approved were to adopt the proposed accounting, beginning in 1997 an esti-in 1994 for the Prairie Island nuclear generating plant, the Company mated total discounted decommissioning obligation of $610 million believes it has adequate storage capacity to continue operation of its would be recorded as a liabikty,with the corresponding costs capital-nuclear plants until at least 2002 and 2003 for Prairie Island Units 1 ized as a plant asset and depreciated over the operating life of the and 2, respectively. The Monticello nuclear plant has storage capac-plant.The obligation calculation methodology proposed by the FASB ity to cont.nue operations until 2010. Storage availability to permit is slightly different from the ratemaking methodology that derives the operation beyond these dates is not assured at this time. decommissioning accruals currently being recovered in rates (as dis-cussed below). The Company has not yet determined the potential Two alternatives to on-site storage of used fuel are currently under impact of the FASB's proposed changes in the accounting for site exit consideration. As discussed in Note 15, the Company is investigating obligations other than nuclear decommissioning (such as costs of alternative sites in Goodhue County, Minnesota, for interim used removal). However, the ultimate decommissioning and site exit costs nuclear fuel storage. Also, the Company is leadmg a consortium to be accrued are the same under both methods and, accordingly,the 42
i. a.' ' piu y. ' u neso a am u>saianes effects of regulation cre expected to minimize or eliminate any impact At Dec. 31,1995, the Company has recorded and recovered in rates on operating expenses and results of operations from this future cumulative decommissioning accruals of $381 million;$177 million has accounting change. been deposited into external trust funds for such accruals. The Com-pany believes future decommissioning cost accruals will continue to Consistent with cost recovery in utility customer rates, the Company be recovered in customer rates. Decommissioning and interest records annual decommissioning accruals based on periodic site-accruals are included with the accumulated provision for deprecia-specific cost studies and a presumed ievel of dedicated funding. Cost tion on the balance sheet. Interest costs and trust earnings associ-studies quantify decommissioning costs in current dollars. Since the ated with externally funded obligations are reported in Other income costs are expected to be paid in 2010-2022, funding presumes that and Expense on the income statement. current costs will escalate in the future at a rate of 4.5 percent per year. The total estimated decommissioning costs that will ultimately A revision to NSP's 1993 nuclear decommissioning study and nuclear be paid, net of income earned by external trust funds,is currently plant depreciation capital recovery request was filed with the MPUC being accrued using an annuity approach over the approved plant and approved in 1994. Although management expects to operate the recovery period. This annuity approach uses the assumed rate of Prairie Island units through the end of their licensed lives, the return on funding, which is currently 6 percent (net of tax) for external approved capital recovery would allow for the plant to be fully depre-funding and approximately 8 percent (net of tax) for internal funding. ciated, including the accrual and recovery of decommissioning costs in 2008, about six years earlier than the end of its licensed life. The The total obligation for decommissioning currently is expected to be approved recovery period for Prairie Island has been reduced funded approximately 82 percent by external funds and 18 percent by because of the uncertainty regarding used fuel storage.The updated internal funds, as approved by the MPUC. Rate recovery of internal nuclear decommissioning study resulted in a decrease in annual cost funding began in 1971 through depreciation rates for removal accruals for decommissioning due to a reduction in decommissioning expense, and was changed to a sinking fund recovery in 1981. Contri-cost estimates as well as the shortened recovery period. The com-butions to the external fund started in 1990 and are expected to con-bined impact of the request as approved, including the shorter depre-tinue until plant decommissioning begins. Costs not funded by ciation p3riod and lower decommissioning costs, was a net decrease external trust contributions and related earnings will be funded of about $800,000 in ar.nual depreciation and decommissioning through internally generated funds and issuance of Company debt or expenses, beginning in 1994. stock. The assets held in trusts as of Dec. 31,1995, primarily consisted of investments in tax-exempt municipal bonds, eommon stock of pub-
- 15. COMMITMENTS AND CONTINGENT LIABILITIES lic companies and U.S. government securities.
Leg. lative Resource Comm.tments in 1994, the Minnesota Leg. la-is i is n aW smal enugpuwce and h cemenW The following table summarizes the funded status of the decommis-8" sioning obligation at Dec. 31,1995, under the method currently in use. age facility approval, as discussed in Note 14. The additional 'U"' (Millions of dollars) M f man genuadon) conW, can h sununaM as Mowr Decommissioning cost estimate }o o, e4 s from most recent study (1993 dollars) ($. M S w e gawans ha@ne Effect of escalating costs to payment N date (at 4.5% per year) NSEM "'O Wnd 23 Kumda M M9M Estimated future decommissioning costs (undiscounted) ! $10MA! nau na0 WM Ttimated decommissioning cost obligation q Wind 200 (Additional) 12/31/02 escalated to current dollars S :StRai nian M m ona0 W O2 External trust fund assets at fair value M WM Wind 400 (2) (Additional) 12/31/02 Decommissioning obligation in ,_,j excess of assets currently held in external trust j $,Sgt.3: (l)in addition to 25 megawatts of wind generation Decommissioning expenses recognized include the following compo-e ea c anning anknome $anning nents: (3) Power purchase contract awarded to Zond Systems, Inc. (MiHions of dollars) M 1994 1993 Annual decommissioning cost accrualg (;j re rted as depreciation expense ne w nrn n wen gawans of tM pa@ internally funded +M d{h " 9 '""" " " "" Y' (including interest casts) 1.1 14.5 r ec a@onal hgawans of snd enugdo be unk p Intuest cost on externally funded "#8"Y " *" * * " 9' decommissioning obligation 'i a 3.5 3.7 t """#8 " "**"I* Earnings from external trust funds - r1stM[ (3.5) (3.7) selected Zond Systems,Inc.to supply the wind energy. The Company Current year decommissioning j Ehke munn wsecu g s he de km an unsucunful Mu, accruals - net $34.3 $42.9 which has indicated it will not voluntarily transfer the wind rights. The 43
Company has commenced litigation to expedite resolution of the wind interest in O'Brien; (ii) a $7.5 million investment by NRG for all of rights dispute. Siting and design activities are proceeding while wind O'Brien's interest in certain biogas projects; and (iii) a $45 million rights acquisition efforts continue. An independent evaluator also unsecured loan from NRG to O'Brien. NRG currently is negotiating reviewed proposals from bidders regarding 50 megawatts of fao with an unaffiliated lender to refinance O'Brien's Newark Boxboard grown closed-loop biomass generation and made a recommendation project in the amount of $56 million, of which approximately $26 mil-to the Company in January 1996, with a final decision to be made in lion would be applied for distribution to O'Brien's creditors in reduc-early 1996. On Jan. 22,1996, the Company notified the MPUC that due tion of NRG's approximately $107 mil' ion obligation. If this financing is to the price of the various bids and other factors, the Company not obtained concurrently with the closing of the O'Brien transaction, intended to reject each of the bids. Since legislation may be proposed NRG would be obligated to make a $26 million loan to O'Brien after its to change various elements of the biomass mandate,the Company reorganization. proposed to delay its report detailing the Company's decision and its proposal to meet the statutory mandate untillater in 1996. Leases Rentals under operating leases were approximately $26.9 mil-lion, $24.0 million and $27.5 million for 1995,1994 and 1993, respec-Other commitments established by the Legislature include applying tively. Future commitments under these leases generally decline from for, locating and licensing an alternative used fuel storage site, a low-c arrent levels, income discount for electric customers, additional required conser-vation improvement expenditures and various study and reporting Fuel Contracts NSP has contracts providing for the purchase and requirements to a legislative electric energy task force formed in delivery of a significant portion of its current coal, nuclear fuel and 1994. In January 1995, the MPUC approved the Company's low-natural gas requirements. These contracts, which expire in various income discount programs in accordance with the statute. In July years between 1996 and 2013, require minimum contractual purchases 1995, the Company filed documents with the MEQB outlining two and deliveries of fuel, and additional payments for the rights to pur-alternative Goodhue County sites to be considered for the develop-chase coalin the future. in total, NSP is committed to the minimum J ment of an interim used nuclear fuel storage f acihty, as the Minnesota purchase of approximately $529 million of coal,$26 million of nuclear Legislature required. The MEQB has begun a 12-to 18-month public fuel and $512 million of natural gas and related transportation, or to process to examine these sites and any others that may be proposed. make payments in lieu thereof, under these contracts. In addition, NSP The Company has implemented programs to begin meeting the other is required to pay additional amounts depending on actual quantities legislative commitments. The Company's capital commitments dis-shipped under these agreements. As a result of FERC Order 636, NSP closed below include the known effects of the 1994 Prairie Island leg-has been very active in developing a mix of gas supply, transportation islation. The impact of the legislation on power purchase and storage contracts designed to meet its needs for retail gas sales. commitments and other operating expenses is not yet determinable. The contracts are with several suppliers and for various periods of time. Because NSP has other 7urces of fuel available and suppliers i 1 Capital Commitments NSP estimates utility capital expenditures, are expected to continue to provide reliable fuel supplies, risk of loss i including acquisitions of nuclear fuel, will be $410 million in 1996 and from non-performance under these contracts is not considered signif. $1.9 billion for 1996-2000. There also are contractual commitments for icant. In addition, NSP's risk of loss (in the form of increased costs) 1 the disposal of used nuclear fuel. (See Note 14.) from market price changes in fuelis mitigated through the cost of-energy adjustment provision of the ratemaking process, which pro. NRG is contractually committed to additional equity investments in an vides for recovery of nearly all fuel costs. existing German energy project. Such commitments are for approxi-mately DM 33 million in 1996. The 1996 commitment would be approx. Power Agreements The Company has exet uted several agreements imatef $23 million, based on exchange rates in effect at Dec. 31, with the Manitoba Hydro-Electric Boaro (MH) for hydroelectricity. A 1995. In addition, NRG is contractually committed to additional equity summary of the agreements is as follows: investments of $17 million in the Scudder Latin American Trust for Independent Power Energy Projects, as of Dec. 31,1995. Years Megawatts Participation Power Purchase 1996 2005 500 NRG is in the final stages of purchasing a 42 percent interest in Seasonal Participation Power Purchase 1996 250 0'Brien Environmental Energy, Inc. (O'Brien) from bankruptcy. In con-Seasonal Peaking Power Purchase 1996 200 nection with its bid for O'Brien, on Jan. 3,1996 NRG obtained a $100 Seasonal Diversity Exchanges: million letter of credit from a bank, whbh is secured by a pledge of Summer exchanges from MH 1996 2014 150 various NRG assets. NRG delivered the letter of creditto O'Brien on 1997-2016 200 Jan.18,1996, to secure its obligation to complete its proposed invest. Winter exchanges to MH 1996-2014 150 ment in O'Brien. In January 1996, the United States Bankruptcy Court 1996-2015 200 for the District of New Jersey confirmed the Chapter 11 Plan of Reor-2015-2017 400 genization for O'Brien proposed by NRG and other interested parties. 2018 200 0'Brien has interests in eight domestic operating power generation f acilities with aggregate capacity of approximately 230 megawatts, The cost of the 500 megawatt participation power purchase commit-and in one 150-megawatt facilityin the contract stage of develop-ment is based on 80 percent of the costs of owning and operating the ment. As a result of the purchase, approximately $107 million would Company's Sherco 3 generating plant (adjusted to 1993 dollars). The be made available to O'Brien's creditors by NRG. At least $81 million total estimated future annual capacity costs for all MH agreements is of the total made available to the creditors would be provided by NRG projected to be approximately $65 million. However, the Company and as follows:(i) a $28 million equity investment by NRG for its 42 percent MH have consented to arbitration to finalize interpretations of specific 44
contractual factors relating to the SU-megawatt participation agree-maximum assessments of approximately $4.9 million (five times the ment. These commitments to MH, which represen' about 22 percent amount of its annual premium) and $36.8 million (generally 7.5 times of MH's output capability in 1996, account for approximately 13 per-the amount of its annual premium)if losses exceed accumulated cent of NSP's 1996 electric system capability. The risk of loss from reserve funds under the business interruption and property damage non-performance by MH is not considered significant, and the risk of coverages, respectively. loss from market price changes is mitigated through cost of-energy rate adjustments. Environmental Contingencies Other long-term liabikties include an accrual of $42 million, and other current liabikties indude an The Company has an agreement with Minnkota Power Cooperative accrual of $6 million at Dec. 31,1995, for estimated costs associ-(MPC) for the purchase of summer season capacity and energy. From ated with environmental remediation. Approximately $37 million of 199S through 2001, the Co.npany will buy 150 megawatts of summer the long-term liability and $4 million of the current liabihty relate to a season capacity for $12.4 million annually. From 2002 through 2015, 00E assessment for decommissioning of a federal uranium enrich-the Company will purchase 100 megawatts of capacity for $10.0 mil-ment facihty, as discussed in Note 14. Other estimates have been lion annually. Under the agreement, energy will be priced against the recorded for expected environmental costs associated with manu-cost of fuel consumed per megawatt-hour at the Coyote Genercting f actured gas plant sites formerly used by the Company and other Station in North Dakota. The Company also has three seasonal (sum-waste disposal sites, as discussed below. mer) purchase power agreements with MPC, Minnesota Power and Mid American Energy Company for the purchase of 388 megawatts in These environmentalliabilities do not include accruals recorded (and 1996, including reserves. The annual cost of this capacity will be collected from customers in rates) for future nuclear fuel disposal approximately $4 million. costs or decommissioning costs related to the Company's nuclear generating plants. (See Note 14 for further discussion.) The Company has agreements with several non-regulated power producers to purchase electric capacity and associated energy The The Environmental Protection Agency (EPA) or state environmental 1996 cost of these commitments for non-regulated installed capacity agencies have designated the Company as a "potentially responsible is approximately $20 million for 115 megawatts. This annual cost will party" (PRP) for 12 waste disposal sites to which the Company increase to approximately $37 million $44 million for 1997 2018 and allegedly sent hazardous materials. Under applicable law, the Com-then decrease to approximately $25 million-$29 million for 2019-2027 pany, along with each PRP, could be held jointly and severally liable due to the expiration of existing agreements and an additional agree-for the total remediation costs of all 12 sites, which are currently esti-ment for the purchase of 245 to 262 megawatts. mated between $123 million and $126 million. If additional remediation is necessary or unexpected costs are incurred, the amount could be Nuclear Insurance The Company's public liabihty for claims resulting in excess of $126 million. The Company is not aware of the other par-from any nuclear incident is limited to $8.9 billion under the 1988 ties' inability to pay, nor does it know if responsibility for any of the Price Anderson amandment to the Atomic Energy Act of 1954. The sites is disputed by any party. The Company's share of the costs asso-l Company has secured $200 million of coverage for its public liability ciated with these 12 sites is approximately $2.5 million. Of this exposure with a pool of insurance companies. The remaining $8.7 bil-amount, about $1.5 million already has been paid in connection with hon of exposure is funded by the Secondary Financial Protection Pro-eight of the 12 sites for which the Company has settled with the EPA gram, available from assessments by the federal government in case and other PRPs. For the remaining four sites, neither the amount of of a nuclear accident.The Company is subject to assessments of up remediation costs nor the final method of their allocation among all to $79.3 million for each of its three licensed reactors to be applied for designated PRPs has been determined. However, the Company has public liability arising from a nuclear incident at any licensed nuclear recorded an estimate of approximately $1 million for future costs for facility in the United States. The maximum fundmg requirement is $10 all four sites, with the estimated payment dates not determinable at million per reactor during any one year. this time. While it is not feasible to determine the outcome of these matters, amounts accrued represent the best current estimate of the The Company purchases insurance for property damage and site Company's future liability for the remediation costs of these sites. It is decontamination cleariup costs with coverage limits of $2.0 billion for the Company's practice to vigorously pursue and,if necessary,;itigate each of the Company's two nuclear plant sites. The coverage consists with insurers to recover incurred remediation costs whenever possi-of $500 million from Nuclear Mutual Limited (NML) and $1.5 billion ble. Through litigation, the Company has recovered from other PRPs a from Nuclear Electric insurance Limited (NEIL). portion of the remediation costs paid to date. Management believes costs incurred in connection with the sites, which are not recovered NEll also provides business interruption insurance coverage,includ-from insurance carriers or other parties, should be allowed recovery ing the cost of replacement power obtained during certain prolonged in future ratemaking. Until the Company is identified as a PRP,it is not accidental outages of nuclear generating units. Premiums billed to possible for the Company to predict the timing or amount of any costs NSP from NML and NEIL are expensed over the policy term. All com-associated with cleanup sites other than those discussed above. panies insured with NML and NEIL are subject to retrospective pre-mium adjustments if losses exceed accumulated reserve funds. The Wisconsin Company potentially may be involved in the cleanup Capital has been accumulated in the reserve funds of NML and NEIL and remediation at three sites. One site is a solid and hazardous waste to the extent that the Company would have no exposure for retro-landfill site in Eau Claire, Wis. The Wisconsin Company contends that spective premium assesaments in case of a single incident under the it did not dispose of hazardous wastes in the subject landfill during the business interruption and the property damage insurance coverages. time period in question. Because neither the amount of cleanup costs However,in each calendar year, the Company could be subject to nor the final method of their allocation among all designated PRPs has 45
been determined,it is not feasible to predict the outcome of this mat-this complax legislation have been finalized. No additional capital ter at this time. The second site, in Ashland, Wis., contains cre-expenditures are anticipated to comply with the sulfur dioxide emis-osote/ coal tar contamination. A portion of the Ashland site was sion limits of the Clean Air Act. NSP has expended significant contaminated by a gas manufacturing plant formerly operated by the amounts over the years to reduce sulfur dioxide emissions at its Wisconsin Company. Cleanup at this portion of the site has begun and plants. Based on revisions to the sulfur dioxide portion of the pro-will be completed in 1996. The Wisconsin Company has paid approxi-gram, NSP's emission allowance allocations for the years 1995-1999 mately $400,000 and has accrued its estimated liability of $900,000 for were dramatically reduced. The Company's capital expenditures the remainder of the cleanup. The Wisconsin Company is discussing include some costs for ensuring compliance with the Clean Air Act's its potentialinvolvement in a second portion of the Ashland site with other emission requirements; other expenditures may be necessary the Wisconsin Department of Natural Resources. Investigations are upon EPA's finalization of remaining rules. Because NSP is only under way to determine the Wisconsin Company's responsibility as beginning to implement some provisions of the Clean Air Act,its over-well as that of predecessor companies contributing to the contamina-all financialimpact is unknown at this time. Capital expenditures for tion existing at the second portion of the Ashland site. The investiga-opacity compliance, which began in 1995 at certain f acilities, are tion also should determine the extent and source of the considered in the capital expenditure commitments disclosed previ-contamination and potential methods for remediation. An estimate of cusly. NSP plans to seek recovery of these expenditures in future cleanup and remediation costs at the Eau Claire site and the second rate proceedings. portion of the Ashland site and the extent of the Wisconsin Com-pany's responsibility,if any, for sharing such costs are not known at Several of NSP's operating facihties have asbestos-containing mater-this time. The third site is a landfill site in Hudson, Wis., which is one ial, which represents a potential health hazard to people who come in of the 12 waste disposal sites discussed previously. contact with it. Governmental regulations specify the required timing and nature of disposal of asbestos-containing materials. Under such The Company also is continuing to investigate 15 properties, either requirements, asbestos not readsy accessible to the environment presently or previously owned by the Company, which were at one need not be removed until th facilities containing the material are time sites of gas manufacturing, gas storage plants or gas pipelines. demolished. NSP estimatet its future asbestos removal costs will The purpose of this investigation is to determine i; waste materials approximate $43 million. Most cf these costs will not need to be are present,if such materials constitute an environ nental or health incurred until current operating fa%ies are demolished, and will be risk,if the Company has any responsibility for remedial action and if included in the costs of removal for the facilities. recovery under the Company's insurance policies can contribute to any remediation costs. Of the 15 gas sites under investigation, the Environmentalliabilities are subject to considerable uncertainties Company already has remediated one site and is actively taking that affect NSP's ability to estimate its share of the ultimate costs of remedial action at four of the sites. In addition, the Company has been remediation and pollution control efforts. Such uncertainties involve notified that two other sites eventually will require remediation, and a the nature and extent of site contamination, the extent of required study will be initiated in 1996 to determine the cost and method of cleanup efforts, varying costs of alternative cleanup methods and ) cleanup. Cleanup is expected to begin in 1997. The Company has paid pollution control technologies, changes in environmental remediation $6.7 million to date on these seven active sites. The one remediated and pollution control requirements, the potential effect of technologi-site continues to be monitored. The Company has recorded an esti-calimprovements, the number and financial strength of other poten-mated liability for future costs at the other six active sites of approxi-tially responsible parties at multi-party sites and the identification of mately $6.1 mi!! ion, with payment expected over the next 10 years. new environmental cleanup sites. NSP has recorded and/or dis-This estimate is based on prior experience and includes investigation, closed its best estimate of expected future environmental costs and remediation and litigation costs. As for the eight inactive sites, no lia-obligations, as discussed previously. bility has been recorded for remediation or investigation because the present land use at each of these sites does not warrant a response i.egal Claims in the normal course of business, NSP is a party to rou-action.While it is not feasible to determine the precise outcome of all tine claims and litigation arising from prior and current operations. NSP of these matters, the accruals recorded represent the current best is actively defending these matters and has recorded an estimate of estimate of the costs of any required cleanup or remedial actions at the probable cost of settlement or other disposition. In July 1993, a nat-these former gas operating sites. Management also believes that ural gas explosion occurred on the Company's distribution system in St. incurred costs, which are not recovered from insurance carriers or Paul, Minn. Total damages are estimated to exceed $1 million. The other parties, should be allowed recovery in future ratemaking. Dur-Company has a self-insured retention deductible of $1 million, with ing 1994, the Company's gas utility received approval for deferred generalliability coverage of $150 million, which includes coverage for accounting ioc certain gas remediation costs incurred at four active allinjuries and damages. Seventeen lawsuits have been filed, including sites, with final raw treatment of such costs to be determined in one suit with multiple plaintiffs. In April 1995, the National Transporta-future general gas rate cases. tion Safety Board found little,if any, fault with the Company's actions or conduct. A trial to decide civilliability and the parties responsible for The Clean Air Act, including the Amendments of 1990(the Clean Air the explosion has been scheduled for February 1997, with the damages Act), calls for reductions in emissions of sulfur dioxide and nitrogen portion of the trial scheduled for six months thereafter. The ultimate oxides from electric generating plants. These reductions, which will costs to the Company are unknown at this time. be phased in, began in 1995. The majority of the rules implementing 46
- 16. SEGMENT INFORMATION year Ended Dec. 31 (Thousands oldollars) 1994 1993 Utility operating income before income taxes Electric
$ 399185 $ 393 758 Gas 38 361 38 474 Total operating income before income taxes 4 $ 437 546 $ 432 232 Utility depreciation and amortization w Electric 4 $ 252 322 $ 245 200 Gas 21 479 19 317 Total depreciation and amortization bemec $ 273 801 $ 264 517 Utility capital expenditures h@ ] Electric utility $ 303 896 $ 284 239 Gas utility /;V ) 60 183 36 312 Common utiliry l 22 947 36 285 Total utility capital expenditures ff; M J $ 387 026 $ 356 836 l Identifiable assets pM:s Electric utility pk $4 634 511 $4 543 266 i Gas utility IM$ 556 975 521 595 Totalidentifiable assets yWWj $5191486 $5 064 881 Dther corporate assets
- TMM 758 246 522 837 Total assets
$5W54 $5 949 732 $5 587 718
- Includes equity investments of $185 million in 1995 and $134 million in 1994 in non-regulated energy projects outside of the United States.
- 17. SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarter Ended Utility operating revenues V $@p1R)ngi M Jt,.0f Wh 'ML,1NWM@< gW,, a s,KW, \\ ViS % Wi Utility operating income s 0 iM6 hS " U SW I I Net income < s ')kS N k[d h'h M j'y (( k dMN1h $p GSM 2 ' Earnings available for common stock j d &Wk "I' (dlj$W(s fM[gxNd:%j[, % t"h@% [f82l Earnings per average common share Y I' $$$lh M ' % Dividends declared per common share IW5P* 'lW%fJ j%1l Stock prices - high a ,y -low /0E5 3 4 EW5E. Ni1lW Q ' ' 1 W 5i Quarter Ended f Thousands of dollars) March 31,1994 June 30,1994 Sept. 30,1994 Dec. 31,1994 Utility operating revenues $683 462 $581963 $612 328 $608 794 Utility operating income 85 795 65 526 88 932 68 065* Netincome 65 794 52 808 76 065 48 808* Earnings available for common stock 62 737 49 751 72 968 45 655* Earnings per average common share $.94 S.74 $1.09 $.68* Dividends declared per common share $645 S.660 $.660 $.660 Stock prices - high $43% M3% $43% $47 -low $40% $38X $40W $41M
- An expense of $8.7 million ($5.1 million net of tax), or 8 cents per share, was recognized to write off the unamortized deferred costs associated with adopting SFAS No. I12 (See Note 2) Such costs had initially been deferred based on a preliminary decision to request amortization through rates over future periods.
47
II. MERGER AGREEMENT WITH WISCONSIN ENERGY CORPORATION SUMMARIZED PRO FORMA FINANCIAL INFORMATION (UNAUDITED) As previously reported in the Company's Current Report on Form 8-K, The following summary of unaudited pro forma financialinformation dated April 28,1995, and filed on May 3,1995, and Quarterly Reports reflects the adjustment of the historical consolidated balance sheets on Form l0-Q, the Company and Wisconsin Energy Corporation (WEC) and statements of income of NSP and WEC to give effect to the have entered into an Agreement and Plan of Merger (Merger Agree-Transaction to form Primergy and a new subsidiary structure. The ment), which provides for a strategic business combination involving unaudited pro forma balance sheet information gives effect to the the Company and WEC in a " merger of equals" transaction (the Transaction as if it had occurred on Dec. 31,1995. The unaudited pro i Transaction). See further discussion of the transaction in the Man-forma income statement information gives effect to the Transaction agement's Discussion and Analysic. Factors Affecting Results of as if it had occurred on Jan.1,1995. This pro forma information was Operations - Proposed Merger section. prepared from the historical consohdated financial statements of NSP and WEC on the basis of accounting for the Transaction as a pooling Primergy Corporation (Primergy), which will be registered under the of interests and should be read in conjunction with such historical Public Utility Holding Company Act of 1935, as amended, will be the consolidated financial statements and related notes thereto of NSP parent company of both the Company (which, for regulatory reasons, and WEC. The following information is not necessarily indicative of will reincorporate in Wisconsin) and WEC's current principal utility the financial position or operating results that would have occurred subsidiary, Wisconsin Electric Power Company, which will be had the Transaction been consummated on the dates for which the renamed " Wisconsin Energy Company? It is anticipated that, follow-Transaction is being given effect, nor is it necessarily indicative of ing the Transactien, except for certain gas distribution properties future Primergy operating results or financial position. transferred to the Company, the Wisconsin Company will be merged into Wisconsin Energy Company and that some of the Company's Primorgy information The following summarized Primergy pro forma other subsidiaries will become direct Primergy subsidiaries. financialinformation reflects the combination of the historical finan-cial statements of NSP and WEC after giving effect to the Transaction As noted above, pursuant to the Transaction, NSP will reincorporate in to form Primergy. A $141 million pro forma adjustment has been made Wisconsin. This reincorporation will be accomplished by the merger of to conform the presentations of noncurrent deferred income taxes in the Company into a new company, Northern Power Wisconsin Corpo-the summarized pro forma combined balance sheet information as a ration (New NSP), with New NSP being the surviving corporation and - net liability. The pro forma combined earnings per common share succeeding to the business of the Company as an operating public util-reflect pro forma adjustments to average common shares outstand-ity. Following such merger, a new WEC subsidiary, WEC Sub Corpora-ing in accordance with the stock conversion provisions of the Merger tion (WEC Sub), will be merged with and into New NSP, with New NSP Agreement. being the survivir g corporation and becoming a subsidiary of Primergy. Both New NSP and WEC Sub were created to effect the Transaction and will not have any significant operations, assets or liabilities prior to such mergers. After the Transaction is completed, current common stockholders of the Company will own shares of Primergy common stock, and current bondholders and preferred stockholders of the Com-pany will become investors in New NSP. 48
l Pro Forma Primergy Pro Forma FicanciciinfIrmation NSP WEC Combined i (Millions of dollars, except per share amounts) l As of Dec.31,1995, 1 Utihty Plant-Net $4 310 $2 911 $ 7 221 Current Assets 705 531 1 236 Other Assets 1 214 1 119 2 192 Total Assets $6 229 $4 561 $10 649 Commo_n Stockholders' Equity $2 028 $1871 $ 3 899 Preferred Stockholders' Equity 240 30 270 i Long Term Debt 1 542 1 368 2 910 Total Capitalization 3 810 3 269 7 079 1 Current Liabilities 992 436 1428 Other liabilities 1 427 856 2 142 4 Total Equity and Liabilities $6 229 $4 561 $10 649 For the Year Ended Dec.31,1995: l Utility Operating Revenues $2 569 ' $1770 $4 339 i Utikty Operating income $346 $329 $675 Net income, after Preferred Dividend Requirements $263 $234 $497 Earnings per Common Share: As reported $3.91 $2.13 Using NSP Equivalent Shares * $3.69 Using Primergy Shares $2.27 i
- Rertesents the pro forma equivalent of one share of NSP Common Stock calculated by multiplying the pro forma information by the conversion ratio of 1.626 shares of Primergy Common Stock for each share of NSP Common Stock.
New NSP information The following summarized New NSP pro forma financialinformation reflects the adjustment of the historical financial state-ments of NSP to give effect to the Transaction, including the merger of the Wisconsin Company into Wisconsin Energy Company and the transfer of ownership of all of the other current NSP subsidiaries to Primergy.The transfer of certain Wisconsin Company gas distribution properties to New NSP, which is anticipated as part of the merger, has not been reflected in the pro forma amounts due to immateriality. Merger i Divestitures, Pro Forma New NSP Pro Forma Financial Information NSP Net New NSP IMollions of dollars) j As of Dec.31,1995: Utihty Plant - Net $4 310 $ (692) $3 618 Current Assets 705 (170) 535 i Other Assets 1 214 (531) 683 Total Assets $6 229 $(1393) $4 836 Common Stockholders' Equity $2 028 $ (706) $1322 Preferred Stockholders' Equity 240 240 Long-Term Debt 1542 (356) 1186 Total Capitalization 3 810 (1 062) 2 748 Current Liabilities 992 (139) 853 Other Liabihties 1 427 (192) 1235 Total Equity and Liabilities $6 229 $(1393) $4 836 a For the Year Ended Dec.31,1995: Utility 0perating Revenues $2 569 $(213) $2 356 Utility Operating Income $346 $(62) $284 Net income, after Preferred Dividend Requirements $263 $(73) $190 j 49
j REPORT OF MANAGEMENT REPORT OF INDEPENDENT ACCOUNTANTS l l Management is responsible for the preparation and integrity of NSP's To the Sharehold:rs of NIrthern Stat:s Power Compiny In our opin-i financial statements. The 'inancial statements have been prepared in ion, the accompanying consolidated balance sheet and statement of j l accordance with generally accepted accounting principles and nec-capitalization and the related consolidated statements of income, of essarily include some amounts that are based on management's esti-common stockholders' equity and of cash flows present fairly,in all mates and judgment. material respects, the financial position of Northern States Power Company, a Minnesota corporation, and its subsidiaries at Dec.31, To fulfillits responsibility, management maintains a strong internal 1995, and the results of their operations and their cash flows for the control structure, supported by formal policies and procedures that year in conformity with generally accepted accounting principles, are communicated throughout NSP. Management also maintains a These financial statements are the responsibility of the Company's staff of internal auditors who evaluate the adequacy of and investi-management; our responsibility is to express an opinion on these j gate the adherence to these controls, policies and procedures. financial statements based on our audit. We conducted our audit of these statements in accordance with generally accepted auditing Our independent public accountants have audited the financial stato-standards which require that we plan and perform the audit to obtain ments and have rendered an opinion as to the statements' fairness of reasonable assurance about whether the financial statements are presentation,in all material respects,in conformity with generally free of material misstatement. An auditincludes examining, on a test accepted accounting principles. During the audit, they obtained an basis, evidence supporting the amounts and disclosures in the finan-understanding of NSP's internal control structure, and performed cial statements, assessing the accounting principles used and signif-tests and other procedures to the extent required by generally icant estimates made by management, and evaluating the overall accepted auditing standards. financial statement presentation. We believe that our audit provides a reasonable basis for the opinion expressed above. The consolidated The Board of Directors pursues its oversight role with respect to NSP's financial statements of the Company and its subsidiaries for the years financial statements through the Audit Committee,which is comprised ended Dec. 31,1994 and 1993 were audited by other independent ] solely of non-management directors.The Committee meets periodically accountants whose report dated Feb. 8,1995 expressed an unquali-with the independent public accountants, internal auditors and man-fied opinion on those statements and included an explanatory para-agement to assure that all are properly discharging their responsibili-graph related to a change in method of accounting for postretirement ties. The Committee approves the scope of the annual audit and health care costs in 1993. reviews the recommendations the independent public accountants have for improving the internal control structure. The Board of Direc-tors, on the recommendation of the Audd Committee, engages the inde-pendent public accountants, subject to shareholder approval. M g l Both the independent public accountants and the internal auditors PRICE WATERHOUSE LLP l have unrestricted access to the Audit Committee. Minneapolis, Minnesota February 5,1996 j James J. Howard Chairman of the Board, President and Chief Executive Officer Edward J. McIntyre Vice President and Chief l Financial Officer NORTHERN STATES POWER COMPANY Minneapolis, Minnesota February 5,1996 50
Selected Financial Data (Mllions ol dollars, except per share datal GaE 1994 1993 1992 1991 1985 Utihty operating revenues $2 486.5 $2 404.0 $2159.5 $2 201.1 $1778.3 Utihty operating expenses $2178.2 $2100.1 $1003.5 $1895.6 $1531.6 income from continuing operations before accounting change (4) $243.5 $211.7 $160.9 $207.0 $195.8 Netincome $243.5 $211.7 $206.4 $224.1 $197.7 Earnings available for common stock $231.1 $197.2 $190.3 $206.1 $184.7 Average number of common and equivalent shares outstanding (000's) 66 845 65 211 62 641 62 566 62 274 Earnings per average common share: Continuing operations before accounting change (4) $3.46 $3.02 $2.31 $3.02 $2.94 Total ( $3.46 $3.02 $3.04 $3 29 $2.97 Dividends declared per share f. $2.625 $2.565 $2.495 $2.395 $1.725 Total assets d $5 949.7 $5 587.7 $5142.5 $4 918.8 $4 047.6 Long-term debt j d $1463.4 $1291.9 $1299.9 $1233.9 $1252.5 %f Ratio of earnings (from contmuing operations before accounting changes, including AFC)to hxed charges J 40 4.0 3.2 3.9 4.7 Financial Statistics us1 1994 1993 1992 1991 1985 Return on average common equity ,;777a Continuing operations before accounting change (4) ([ 12.4 % 11.4 % 9.1% 12.2 % 15.4 % Total earnings ava;lable for common stock ( 12.4 % 11.4 % 11.9 % 13.3 % 15.6 % Dividends as percent of earnings (2) 75.8 % 85.5 % 107.8 % 72.7 % 58.2 % 1,6 Dividends as percent of book value 9.7% 10.0 % 10.0 % 9.9% 9.6% 'yl. Five-year growth rate in earnings per share (1): Continuing operations before accounting change (4) / l 1.0% (2.9%) (4.1%) (0.6%) 13.4 % Total earnings available for common stock y((. 2.6% 0.1% 0.2% 0.5% 13.4 % [g Capital expenditures, excluding business acquisitions (millions) $409.3 $361.7 $427.8 $349.9 $513.7 Percent of capital expenditures that could be financed by internally generated Q j% %[ W funds (excludmg AFC and after dividends) 69.3 % 98.5 % 49.4 % 57.7 % 60.5 % Cash dividend coverage (2) 3.0 3.1 2.8 3.4 44 AFC as percent of earnings per share (2) $$$1E 5.4% 6.5% 10.5 % 5.6% 22.6 % Effective tax rate j$ 34.7 % 38.2 % 34.9 % 35 9 % 44 5 % Of y(SSk Capitalization (3) Common equity 47.5 % 49.4 % 47.5 % 49 6 % 44 5 % Preferred equity hj$$ti 60% 6.5% 8.0% 9.4% 7.9% Debt 4 484 46.5 % 44 1 % 44.5 % 41.0 % 47.6 % Total Mj 100.0 % 100.0 % 100.0 % 100.0 % 100.0 % 9? Average cost of long-term debt [8 6 7.34 % 6.96 % 7.87 % 8.15% 8.08 % Average utility plant investment per dollar of revenue fM $3.19 $3.15 $3.32 $3.11 $2.71 Accumulated depreciation as a percent of Rjf] depreciable plant {G35) 43.3 % 42.1 % 40.4 % 39.6 % 33.9 % Depreciation expense as a percent of average depreciable utikty plant M8805; 3.55 % 3.47 % 3.36 % 3.35 % 3.63 % Benefit employees (at Dec.31) $$M 7 032 7 362 7 522 7 414 7 414 AFC-Allowance for Funds Used During Construction (1) least squares method (2) Excludes the cumulative effect of unbilled revenue accounting change in 1992 earnings (3) Includes short-term notes payable, current portion oflong-term debt andpreferred stocks with mandato. y redemption (4) Income and earnings from continuing operations exclude discontinued telephone operations (in 1991 and prior years) and an accounting change (in 1992). They include non. recurring items in 1994 and 1995, as discussed on page 25. l l 51
1994 1993 1992 1991 1985 R gulat:d El;ctric Op* ratio 1s Revenues (thousands) Residential j With space heatmg $ 66 962 $ 68 222 $ 63 376 $ 67 878 $ 58 309 Without space heating 616 821 583 371 534 676 568 672 425 652 Small commercial and industrial 351287 327 888 312 581 315 946 236 915 Medium commercial and industrial Large commercial and industrial 824 195 780 444 718 712 713 177 515 794 Streetlighting and other 28 936 29 214 29 764 30 720 30 734 Total ratail 1 888 201 1 789 139 1 659 109 1 696 393 1 267 404 Sales for resale 146 239 159 498 137 962 145 008 94 605 Miscellaneous 32 204 26 279 26 245 21 837 14 103 Total $ 2 066 644 $ 1974 916 $1823 316 $1863 238 $1376112 Sales (millions of kilowatt-hours) Residential With space heating 1 076 1 094 1 041 1 141 1 066 Without space heating 8 227 7 998 7 640 8 226 6 900 Small commercial and industrial 5 585 5 307 5 224 5 330 4 326 Medium commercial and industrial Large commercial and industrial 17 874 17 117 16 365 16 286 12 569 Streetlighting and other 334 344 372 386 500 Totai retail 33 096 31 860 30 642 31 369 25 361 Sales for resale 6 733 8 044 6 530 6 083 4 211 Total 39 829 39 904 37 172 37 452 29 572 Customer accounts (at Dec. 31) Residential With space heating 76 050 75 644 74 939 74 646 66 668 Without space heating 1 146 578 1 131 928 1 119 354 1 104 772 1 010 194 Small commercial and industrial 142 858 141 446 140 768 139 266 125 992 l Medium commercial and industrial Large commercial and industrial 8 172 8 114 7 904 7 758 6 049 Streetlighting and other 4 836 4 813 4 627 7 662 5245 Totai retail 1 378 494 1 361 945 1 347 592 1 334 104 1 214 148 Residential with space heating Annual kwh per customer 14 224 14 531 13 950 15 272 16 522 Annuai revenue per customer $885.19 $906.18 $849 08 $908.47 $903.72 Average revenue per kwh 6.22e 6.24e 6.09e 5.95e 5.47e Residential without space heating Annual kwh per customer 7 230 7 106 6 879 7 505 6 887 Annual revenue per customer $542.04 $518.34 $481.45 $518.83 $424.86 Ave age revenue per kwh 7.50c 7.29e 7.00e 6.91e 6.17e Kilowatt-hour output (millions) Thermal 32 710 33 130 30 467 31 335 24 095 Hydro 922 1 001 1 024 1 153 1 200 Purchased and interchange 9 054 8 541 8 187 7 019 6 317 Total ' 42 686 42 672 39 678 39 507 31 612 Capability at time of maximum demand (megawatt Company owned 6 859 6 816 6 798 6 823 6 057 Maximum demand (megawatts) 7 101 6 990 6 128 7 080 5 205 Date of maximum demand June 14 Aug. 25 June 12 July 16 July 9
- Beginnmg on 1995, the commercialand industrialcusi
-s been segmented into small(less than 100 kw in demand per year), medium (100 kw up to 1,000 kw) and large (I,000 kw o tedium group, which is an estimate, was reported as large prior to 1295. 52
1994 1993 1992 1991 1985 R:gulated Gas Oporations Revenues (thousands) Residential With space heating $204 668 $220 828 $178164 $179161 $195 248 Without space heating 2 838 2 715 2 523 2 614 3 838 Commercial and industrial Firm 120 912 131 431 105 829 105 703 118 760 Interruptible 49 384 52 216 41 612 40 768 81 501 Interstate transmission (Viking)* 14 075 9 019 Miscellaneous ** 28 026 12 867 8 078 9 674 2 853 Total $419 903 $429 076 $336 206 $337 920 $402 200 Sales (thousands of mct) Residential With space heating 38 427 40 946 35 136 37 493 32 850 Without space heating 323 331 323 359 464 Commercial and industrial Firm 27 342 28 622 24 273 25 429 22 042 Interruptible 19 373 18 559 15 823 15 813 19 986 8 5 other gas delivered (thousands of mci) Interstate transmission (Viking)* 131 074 75 188 ~~ 54 Customer accounts Iat oec. Ji/ Residential With space heating 351 773 337 868 326 439 314 843 255 154 Without space heating 18 961 19 408 19 841 20 294 24 420 Commercial and industrial 37 140 36 185 35 458 34 663 28 414 Total 407 874 393 461 381 738 369 800 307 988 Residential with space heating Annualmcf per customer 112 124 110 122 131 Annuai revenue per customer $595.30 $667.28 $557.83 $581.61 $779.75 Average revenue per mcf $5.33 $5.39 $5 07 $4.78 $5.94 Gas purchased for resale to utility customers Total cost (thousandsl'" $245 939 $275 313 $216 743 $209 326 $300375 Cost recognized per mcl sold"* $2.85 $3.11 $2.86 $2.64 $3.98 Maximum sendout (mcf) 686 130 642 684 611 380 612 522 610 914 ' Date of maximum sendout Jan.17 Dec. 27 Dec. 23 Feb.14 Jan.19
- Excludes intercompany sales revenues of $2.4 million (20.44I thousands of mcf)in 1995 and $2.2 million (16,845 thousands of mcf) in I994
" Includes NSP revenues for agency and transportation services and off system sales
- " Excludes cost and volumes for other gas delivered 53
(Thousands of dottars, except tver share data) 1994 1993 Operating Results ~ l Operating Revenues $241827 $90 531 Operating Expenses (1) (241 480) (81 480) Equity in earnings of unconsolidated affiliates: Earnings from operations (2) 31 595 2 695 Gains from contract terminations 9 685 Other income (deductions)- net 1843 1 040 Interest expense (7 975) (3 146) income taxes (2) (2 591) (3 548) Net income $32 90/ $6 092 Contribution of Non-regulated Businesses to NSP Earnings per Share '~ J $0.44 $0.04 NRG Energy,Inc. Eloigne Company g } 0.02 0.00 Cenergy, Inc. (Cenerprise, Inc., effective Jan.1,1996) 0.00 0 00 h-( 0.03 0.05 Other (3) Total W lil $0.49 $0.09 (Thousands of dollars) M 1994 Equity Investment by Non-regulated Businesses in Unconsolidated Projects at Dec. 31 RF" (including undistributed earnings and capitalized development costs) WD Australian projects $75108 German projects F l 55 337 Other international projects t 4 013 Affordable housing projects (U.S.) 7 148 g Other U.S. projects i 36 152 Total Equity investment in Unconsolidated Non-regulated Projects $177 758 61 As ji.3) Additional Equity Invested in Consolidated Non-regulated Businesses ( 104 011 Total Net Assets of Non-regulated Businesses $281769 SIGNIFICANT UNCONSOLIDATED NON-REGULATED PROJECTS AT DEC.31,1995 Total NRG Mw-Generation Projects Operating Location Mw Ownership Equity Operator Gladstone Power Station Australia 1680 37.5 % 630 NRG MIBRAG mbh Germany 200 33.3 % 67 JointVenture MIBRAG(NRG/ Power-Gen plc/Morrison Knudsen Corp.) San Joaquin Valley Energy Partners California, USA 55 45.0 % 25 Joint Venture-NRCNolkar Coombs Jackson Valley Energy Partners California, USA 16 50.0 % 8 Joint Venture-NRCNolkar Coombs Scudder Latin American Power Projects Latin America 254 7.7 %-10 3 % 23 Stewart & Stevenson/Wartsila Sunnyside Cogeneration Associates Utah, USA 58 50.0 % 29 Joint Venture-NRG/ Babcock & Wilcox Energy Center Kladno Czech Republic 28 18.3 % 5 Energy Center Kladno Total NRG Mw-Generation Projects Under Construction Location Mw Ownership Equity Operator Schkopau Power Station Germany 960 20.6 % 200 Veba Kraftwerke Ruhr A.G. Total NRG Mw-Generation Projects Under Development (4) Location Mw Ownership Equity Operator O'Bnen Environmental Energy, Inc. New Jersey, USA 203 42% 85 Stewart & Stevenson Capitol District Energy Center Cogeneration Associates Connecticut, USA 56 50 % 28 Coastal Collinsville Australia 189 50 % 95 NRG (I) Includes project wate-downi of SS 0 million in 1995 and $5.0 million in 1994. (2) Equity in operating earnings a presented net of foreign income taxes of $8.3 million in 1995 and $18 million in 1994. (3) Includes NSP-owned refuse-c erived fuel c.perations managed by NRG. (4) Projects under development ma or may not be completed. 54
1994 1993 1992 1991 1985* Common stock shareholders at yeer-end 85 263 86 404 72 525 72 704 82 234 Book value at year end $28.35 $27.32 $25.91 $25.21 $19.72 Market prices High $47 $47 % $45 % $44 $27 X Low $38 X $40% $38 X $30 $20% Year-end closing $44 $43X $43 X $43 $26 M Dividends dec:ared per share t $2.625 $2.565 $2.495 $2.395 $1.725 Earnings per share f $3.46 $3.02 $3.04 $3.29 $2.97
- Adjusted for June 1986 twodor-one stock split HEADQUARTERS:
STOCK EXCHANGE LISTINGS AND TICKER SYMBOL: 414 Nicollet Mall, Minneapolis, MN 55401 Common stock is traded on New York, Chicago, and Pacific Exchanges. NYSE lists some preferred stock. Ticker symbol: NSP. Newspaper stock STOCK INFORMATION: tables list NSP as NoStPw, NoStPwr or NSPw. NSP's home page on the Contact the Shareholders Department at NSP's headquarters. Call toll-Internet is located at http://www.nspco.com free (800) 527-4677, Monday through Friday,8 a.m. to 5 p.m. CST. From the Minneapolis St. Paul area, call (612) 330-5560. ANNUAL MEETING: 1 Wed., April 24,1996,10 a.m. at the Minneapolis Convention Center, INVESTOR RELATIONS INFORMATION: Minneapolis, MN. Contact Richard J. Kolkmann, investor Relations, at NSP's headquarters. J Call (612) 330-6622. FORM 10-K (THE ANNUAL REPORT TO THE SECURITIES AND EXCHANGE COMMISSION): DIRECT DIVIDEND DEPOSIT: Contact the Financial Accounting, Budgets and Reports Department at NSP offers direct deposit of dividends to shareholders' checking or NSP headquarters. A statistical supplement to the annual report is also savings accounts. To sign up for this free service, contact the Share-available. Call (612) 330-7772. holders Department for information and authorization forms. STREET-NAME SHAREHOLDERS AND BENEFICIAL OWNERS: SCHEDULE OF ANTICIPATED DIVIDEND RECORD DATES AND PAYMENT If you would like to receive NSP's quarterly report, contact the Financial I DATES FOR 1996: Accounting, Budgets and Reports Department at NSP headquarters. Call (612)330-7772. Preferred Stock Common Stock Record Dates Payment Dates Record Dates Payment Dates DUPLICATE MAILINGS: Dec. 29,1995 Jan.15,1996 Jan.2,1996 Jan. 20,19% If there are two or more shareholders at your address, you may have March 29,19% April 15,1996 April 10,1996 April 20,1933 received duplicate shareholder mailings. To eliminate duplicate mailings, June 28,19% July 15,1996 July 11,1996 July 20,1996 write or call the Shareholders Department at NSP headquarters. Call Sept. 30,1996 Oct.15,1996 Oct.1,1996 Oct. 20,1996 toll-free (800) 527 4677, Monday through Friday,8 a.m. to 5 p.m. CST. Dec. 31,1996 Jan.15,1997 From the Minneapolis-St. Paul area, call 330 5560. DIVIDEND REINVESTMFNT AND STOCK PURCHASE PLAN: The Company's Dividend Reinvestment and Stock Purchase Plan offered by Prospectus is a convenient way to purchase shares of the Company's common stock without payment of any brokerage commission or service charge. Those eligible to participate in the plan are: . Shareholders of NSP + Shareholders who hold stock in " street name" through investment firms, provided the firm has established procedures permitting participation
- Employees of NSP and its subsidiaries
- Non shareholders of legal age who live in Minnesota, North Dakota, South Dakota, Wisconsin and Michigan (Non-shareholders must make an initialinvestment of at least $100)
Once enrolled in the plan, participants may:
- Automatically reinvest all or a portion of their quar;erly dividends
- Make additional cash investments. The minimum single paymentis
$25 and the maximum quarterly payment is $10,000. Contact the Shareholders Department for a Prospectus and authoriza-tion form. 55 J
NORTHERN STATES POWER COMPANY NORTHERN STATES POWER COMPANY l (MINNESOTA) (WISCONSIN) Transfer Agent, Common and Preferred Stocks Trustee-Bonds Northern States Power Company Firstar Trust Company 777 E. Wisconsin Ave. Registrar, Common and Preferred Stocks Milwaukee,WI 53202 Norwest Bank Minnesota, N.A. Sixth St. and Marquette Ave. Coupon-Paying Agents-Bonds Minneapolis, MN 55479-0059 Firstar Trust Company Milwaukee i Dividend Distribution Northern States Power Company First Bank, N.A. 201 West Wisconsin Ave. Forwarding Agent Milwaukee, Wl 53259 i Norwest Bank international 3 New York Plaza,15th Floor New York, NY 10004 k Trustee-Bonds Harris Trust and Savings Bank 111 West Monroe St. Chicago,IL 60690 i First Trust Company, Inc. 332 Minnesota St. ~ St. Paul, MN 55101 Norwest Bank Minnesota, N.A. Minneapolis Coupon-Paying Agents Bonds Harris Trust and Savings Bank Chicago i Chemical Bank of New York 277 Park Ave. New York, NY 10172 j First Trust Company,Inc. St. Paul l 1 i i r I Y f r ss
ABOUT THE COVERS .; e o o in addition to being home to NSP's corporate headquar-ters, the city of Minneapolis (front cover) provides a promising market for the company's Local Government Energy Conservation Program. As part of that effort, NSP ~ offers local governments partial funding for engineering . audits and design services, and provides no interest financing to promote comprehensive energy retrofits. Projects under way in Minneapolis include energy audit-ing and lighting retrofitting in as many as 65 city buildings. NSP also is working with the Minneapolis Water Works Department to test a new, energy efficient method of treating water, and plans to finance $2 million to $3 million ofimprovements in 1996. In St. Paul (back cover), where the program began in 1993, NSP has financed $1.4 million of energy improvements, saving the city almost $200,000 in annual energy costs. The city installed new equipment in 48 city buildings, and has audited and retrofitted more than 120 other electric services, such as pump stations. The program continues to find new conservation opportu-nities. The St. Paul Public Works / Traffic Department has installed $100,000 in new light-emitting diode (LED) traffic signal lighting, improving energy savings by up to 90 per-cent. The St. Paul Public Water Department will use the program to fund an estimated $300,000 of their new dewa-tering process. The Local Government Energy Conservation Program is part of NSP's ongoing effort to help customers conserve energy and manage its use. NSP's overall goal is to reduce system wide peak electric demand by 1,700 megawatts by the year 2000. That not only enables cus-tomers to save energy and money, but allows NSP to post-pone building large power plants. In 1995, the company and its customers achieved their greatest savings to date, reducing demand by 202 megawatts for a cumulative reduction of 1,224 megawatts, l h Printed on paper containing 10 percent recycled fibers and a minimum of 10 percent post-consumer waste. Please recycle.
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