ML20248K542
| ML20248K542 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 12/31/1997 |
| From: | Marshall D, Schwass G DQE |
| To: | |
| Shared Package | |
| ML20248K502 | List: |
| References | |
| NUDOCS 9806100160 | |
| Download: ML20248K542 (76) | |
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-On the Cover . .
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D O n'i 1 9 '1~. t _ > Electricity. Water. Telecommunicatiotts. Gai.. And much, much more. - ' O . :: e. 49 7 R e is u I: t s ; M.. DQE continues to pm.ition itself for increated competitkh in the energy services industry by devehiping market-dn'ven busin&se and - - .
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pannerstups that .pmvide a wide ranFe of energy soluthms for customers. ,#...~..
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f .. 'Our merger with Allegheny Energy will pmvide a largerv '.
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regiomt platform for expanded growth of these initi ives, as well as a ~ ' ' ' " '
'l . full range. of hen.cfits for existing customers sha 1ders and other . ,. ._;
important stakelmiders. Read on to learn how we are 7 Emerging as a ' . .
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.:. Total Energy Services Company."
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DOE Financial and Operating Highlightsi ; L1 ! T 1. . m .
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..H.. . ' David Marshgli pmvides' un overview of the comparty's major strategie .
i ; . t M :. ; .J .D.'.;- . f) A Jnigathen. The sweeping changes in the electne utihty industry. our ,, 7 - filagoed merger with Allegheny Energy. and the continued growtitof our
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. Enterging as a Total Energy Services Cdtnpany n< ..p..l .e i -
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.g The$lectne utility industry is undergoing 1godamental changg ~
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Our -lW7 annual report disensses!
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- the elements of Duquesne Light's regulatory restructuring. plan and
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the concept of electne generathm deregulation; .
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l i Please send a copy of the Allegheny Energy 1997 Annual Fleport to the i address below: e i I (Print or write legibly. This card will be used as your mailing label.) i i l 1 i I
,. Name ,
t i Address 1 l t City, State, Zip 1 1 4 i 1
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I g , ____. . . . . NO POSTAGE R OESSARY? MAILED IN THE UN'TED STATES BUSINESS REPLY MAIL - FIRST CLASS MAIL PERMIT NO. 388 HAGERSTOWN MO POSTAGE WILL BE PAfD BY ADDRESSEE sumumuurasmusumummme DIRECTOR CORPORATE COMMUNICATIONS ALLEGHENY ENERGY 10435 DOWNSVILLE PIKE HAGERSTOWN MD 21740-8772 1..l.l...lil...l.l..lll...l..l.l...II...l..l.l..I li O
TP A Special Message From Our Merger Partner At Alleghen" Energy, we are busily planning for the day our two companies become one. Both companies are working hard to get all the required regulatory approvals by the end of the second quarter of 1998. 40 Our employees are excited about the new oppor-tunities on the horizon and their role in creating America's best energy value. Our cus-tomers are supportive of the merger and look forward to the benefits it will bring to them and to the region. Our shareholders, who voted overwhelmingly in favor of the merger, see its potential for increasing the value of their investments. 43 Among the assets we bring to this union are a history of electric rates that have been among the lowest in the Northeast and in the country; a tradition of personal customer service that reflects the rural nature of the territory we serve; and a flexible management style that is receptive to progressive ideas that will help the Company grow. A0 We have found in
DQE a partner that shares our aspirations for the future and complements our traditional strengths. In other words, we have found a natural fit. AJ ) I have worked closely with g4 DQE President and CEO David Marshall during the past At Allegheny year to plan a new company that will be stronger than either Energy, we are f ur companies could be on a stand-alone basis. It has busily planning for the day our been a rewarding experience, characterized by agreement two companies become one. rather than controversy, by excitement, and by a spirit of II cooperation that can only lead to success. 4l.) A summary of the merger benefits and related information : ppears on the adjacent pages. More about the merger, restructuring, and other inteesting developments appears in the Allegheny Energy 1997 Annual Report. We'll be happy to send to you a free copy of our i report. A postage-paid card is attached for your convenience. Alan J. Noia Chairman, President, and CEO Allegheny Energy. Inc.
t I a ! DOE Highlights l Financial and Operating 9.".miHi,ons, e,c9,qt,per sha,re amounts) , , , , , , ,,1997 1996 Cha,nge , ,,, E.a..r.n..in.gs..pe..r. c.o.m. mon. s. har.e. ..... . . . $2.57. . $2.32 10.8 % Dividends paid per common share 6.3%
. . . . . . . . . . . . . . . . . . . . . . . . . . . . ...... . .. . . . $1.36. . . $1.28 .. . .. . .
Book value per common share at year end 7.2% )
.... . ... .. ..... .. . .... . .. .. ....... .. . . . . . . $19.30 . $.18.01
. . . . . . . ...... . .s N. .et.inco. .m. e.. .. . .. . .. ... . . . . . . . . . . .$.199 $179 11.2 %
D...O..E....r.etu..rn .o. n. a.ver.a..ge. c. o..mm. o. n .e.qu..ity 13.8 %
.. . . . . . . . . . . . 13.2.% . . . .... . ...
Electric utility return on average common equity 10.8% 10.8 % 1
...... ... . . ..... ...... .... . . . . . . . . . . . . . . . ... .. , . . . . . . . . . .. ... ..... .....J I
P.e..ak dem. a.nd..(.M. W..)..(.a.ll-t.im. e re. cord in.1997..).. 2..,671
- 2. .,.463 8.4% . . . .. .... . .
i E. lec.t.ri.c. .cu.s.t.omer..s. ...a.les..(.k.Wh.)... . . . . . . . 12..,545 12,426 1.0% O.perating revenues $1,219 $1,226 -0.6% Depreciation and amortization $243 9.0%
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. .. . $.223 Investment and other income $130 $73 78.1 %
Long-term investments $723 $519 39.3 % ..
. .l Market Price Per Share Five-Year Compound 1997 1996 1995 1994 1993 1992 Growth Rate High $35.13 $31.50 $30.75 $23.00 $24.67 $21.58 10.2 %
Low 8.5
- e. . . . . . . . . . . . . . . .... .......... .$26.88 . . . . . . $25.75. . . . ..... . . .$.19.63 .. $.18.42. .. .. $. 20.92 $17.92 . . . ..%. . . ..
Year-end
$35.13 $29.00
. . . . . . . . . . . . . . . . $.30.75 . . . . . . . . .$23.00
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It certainly has been an eventful year in your their interdependence from a strategic viewpoint. company's history...one that has exemplified the Fulfillment of our objectives regarding our dramatic change that is taking place in the electric customer choice restructuring plan, the proposed ff The changes tuility industry. I am pleased by our progress merger, and the growth of our market-driven throughout 1997, which is most effectively businesses will provide new opportunities to characterized by three primary initiatives further increase the value of your investment. navigated intended to preserve and enhance your investment. through over . Our efforts to achieve an equitable resolution We are aggressively preparing the past decade of Duquesne Light's restructuring plan for for competition transition to customer choice in Pennsylvania. The primary challenge facing us is to navigate have enhanced
. A proposed merger with Allegheny Energy, through Pennsylvania's landmark customer our ability creating the 10th largest investor-owned utility choice legislation. I am sure you have read with to capitalize based on total electric sales-with two million interest the many communications we have on new customers in five states, shared with you concerning our strategy to opportunities Continued growth of our market-driven successfully compete in this changing business busi iesses, which has contributed more signifi- environment. We are confident that as we work brought about cantly to the bottom line as part of the on- through the transition to customer choice, the by change. .
going transformation of our company into a many complex issues associated with the
)) total energy services provider. change from regulation of power generation to competition can be resolved equitably. We fully ,
support Gov. Ridge's vision of customer choice. a The end result should be an efficient market for
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1
* } We remain cautiously optimistic at this critical 3 juncture that we will have a reasonable opportunity to recover those generation-related
, investments made as part of our obligation to d provide a safe, adequate supply of electricity to customers in our franchised service area.
I reaffirm my personal commitment to you You will have an opportunity to review that I will do my utmost to see that the principles developments in each of these areas in more outlined in Pennsylvania's landmark customer detail in the following pages, yet I want to choice legislation are applied in a way that emphasize their importance and, to a degree, upholds shareholder interests. E
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,hg .a orvices Company Merger based on profitability, is an integral element of our restructuring plan for opportunity, efficiency, value and growth the transition to customer choice. The combination We have been aggressive in preparing for offers additional benefits resulting from cost increased competition. As we face perhaps the savings and increased efficiencies.
most monumental changes in the history of the While the merger provides additional options electric utility industry, we have taken another to meet the needs of numerous stakeholder in hold step. On April 7,1997, we gg our transition to customer choice. it announced the signing of a also enables expansion of our The earnings definitive merger agreement with market-driven businesses over a Allegheny Energy as the next gr wth of our larger customer base. The earnings strategic initiative to improve and market-driven growth of our market-driven grow and position us to win in a businesses has businesses has permitted the competitive electricity marketplace, permitted the significant accelerated depreciation Allegheny Energy and DQE are significant undertaken at Duquesne Light to committed to a merger based on reduce the risk and uncertainty accelerated profitability, opportunity, efficient "8 "" # depreciation #'#E" " " operations, customer value and electricity markets. growth. We believe our combination has a compelling strategic rationale Duquesne Light to Market-driven businesses due to: reduce the risk provide value-added energy
+ the geographical fit, which offers and uncertainty solutions a regional platform and critical brought on by The mission of our non-regulated, mass to better compete; deregulation of market-driven businesses has been to
+ a larger customer base to offer electricity markets. provide innovative, value-added, additional products and services; as well as )) integrated energy solutions. A. full customer choice approaches, we con-
+ the natural fit of our utility operations, tinue to des ekip and take to the market a diversified set I also see a atural fit of our management of consumer services arxl complementary pnxiucts teams. We are proud tojoin with a company known from our "tooltx1x" of investments. Our energy for its extraordinary customer service, low rates services, including energy facility operation and and low operating costs. Chairman Al Noia sets the maintenance, fuel management, and commercial tone at the top, with his clear vision of Allegheny encryy services, will augment and differentiate our Energy as " America's Best Energy Wlue " company fmm electric comnxxiity suppliers. Our The proposed merger with Allegheny Energy complementary products include alternative ER
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l l fuel products, telecommunications, home the history of our company. We now stand security, direct satellite TV, and gas. In many poised, because of our successes, to cor tinue our cases, we have developed joint ventures and evolution in the most profitable way for you, our strategic alliances to capitalize on opportunities shareholders. in an evolving energy services industry. These Our industry, along with the natural gas and alliances enhance the utilization and value of telecommunications industries, is at the cross-DQE's investments and capabilities. roe.ds of inevitable, radical change associated We have also added new dimensions to our with technological innovation and deregulation market-driven businesses. DQE at the national and international is now the largest collector and pro-
&& lesel. We will continue to see cessor of landfill gas in the country, The same discipline, convergenec and consolidation of and is the largest investor-owned these industries.
dn.ve and water utility in Texas. No one can clearly see the final
. . determination that end state of all these changes.
Our investment d.iscipl.me m each has helped DOE ilowever, the strategies and of these businesses has been con. sistent. Their design complements grow over the past investments we have continued to and augments our core businesses decade, despite put in place at DQE during the past and will continue to drive our strong year are devised to create value for many obstacles, w.d l financial performance. our customers and our shareholders Each of our strategic initiatives -
* "'I* "* P8'I # as we move to the next phase of the customer choice restructuring your new company, industry evolution. I expect this to plan, the proposed merger with Alleghony Energy. be the last annual report of DQE as a stand-alone company. But I asst.re Allegheny Energy, and the growth of our market-driven businesses-
)) you that the same discipline, drive was formulated to advance the interests of our and determination that has helped DQE grow stakeholder... shareholders, custoniers, employ- over the past decade, despite many obstacles, will ees and the communities that we serve. Their continue as part of your new company, Allegheny value will increase as we enter a new era in the Energy.
electric utility industry. On behalf of our board of directors,I sincerely thank you for your support and continued Poised to continue success investment in DQE. The char 4es we have navigated through over the past decade have enhanced our ability to , I k 48.iize on r.ew opportunities brought about by aange. The credit for your company's success goes to the en'.crprise and dedication that our David D. Marshall many talented employees have demonstrated President and Chief Executive Officer through some of the most challenging times in March 6,1998
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1 I 7 O November 3,1997,11 months to the day that Gov. Tom Ridge signed historic customer choice legislation into law, competitive electrons began flowing across Pennsylvania's utility transmission lines and into Prepari n g customers' homes. While it will take several years to fully implement customer for the New Energy Marketplace choice, the end result will be a competitive market for electric power generation. At DOE, we have been preparing for competition for more than a decade. We have been aggressively reducing our fixed generation costs, while growing earnings at an average rate of nearly 8% over the past 10 years. Duquesne Light's " mitigation" efforts will reduce the uncertainty brought on by deregulation of electricity markets. Read on to better understand Duquesne Light's competitive transition plan as customer choice evolves in Pennsylvania. How Customer Ch oice Will Work.. T When will customers 6 be able to choose 6 What choices will customers have? h What are some of the factors that could affect electricity suppliers? the price of electric power in a market-driven economy? g Once deregulation is implemented, customers g Each electric utility in the state submitted a will have the opportunity to select g The price of electric restructuring plan to the Pennsyl- a licensed electric generation generation will be vania Public Utility Commission supplier. The customer will be determined by the market based (PUC) last year. Experimental able to shop around for the best on supply and demand,just as pilot programs began in the fall of possible terms. During the current supply and demand determine 1997. The transition to customer pilot program, residential customers the prices of other commodities, choice is scheduled to begin on participating in Duquesne Light's such as gasoline and heating oil. January 1,1999, and will be service territory can choose from phased in over the following two eight licensed suppliers. Once the years. All customers will be able customer has purchased the power, to select an electric generation it is delivered over Duquesne supplier by January 1,2001. L.ight's transmission and distribution lines. . f- =
1 Customer Choice Promotes Cost Reduction Pennsylvania's customer choice Over the years, regulated utilities the PUC. The PUC approved law recognizes that in the process initiated long-term investments in Duquesne's decisions as prudent. of transforming the electric utility generation facilities to meet the The fact that tio remaining book . industry from a fully regulated to growing needs of their customers. vahie of these investments may a partially unregulated business, Utility investment in plants and not le recovemble in a deregulated [ y the Commonwealth must resolve equipment was driven by the market does not mean that l cenain transitional issues in a legal obligation to serve. All of recovery of these investments is , manner that, according to the law, these investments, which inappropriate.
"is fair to customers, electric currently are included in electric The customer choice law utilities, investors, employees of rates, were approved by the PUC includes provisions for utilities to 4 the electric utilities, kical after full prudence reviews. continue to recover these j communities, non-utility generators and other affected parties."
The obligation to serve meant that Duquesne 1.ight was required investments during the transition to competition.The PUC will
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The most controversial of these to forecast the expected demands detemdae the amount of transition 't issues is the recovery of of its customers on a long-term transition costs, also known basis and to have in place the costs that each utility will have the ) opportunity to recover. In as stranded costs. These costs, generation needed to serve these detemiining this amount, the law { [ which mainly relate to power demands. Each of DuouesnCs specifies that the PUC must generation, cturently are included investment decisions in consider the extent to which these ! , in customer rates as approved generation was based on this costs already have been reduced e i by the PUC, but may be obligation to serve and each will be reduced (mitigated) by the unrecoverable when generation investment was subjected to a full utility's own prudent practices and 4I
),
is deregulated. review in public hearings before cost-saving efforts. November 3,1997 November 1997
) /
Pilot pmgram begins Inten ening partiesfile testimony in restructuringfiling na* "M***"~ ^
. _ ; I -
N p ;b g
;p gggM December 1997 Duquesne Lightfiles rebuttal to '
;{,
inten enor testimony. including ( . y 22 . , V By May 29,1998 PUC deciaion on p By Jan m^1?2001 M Au:u'.t 1,1997 , ** restructuring and
/ *~+h)
Duquesne Lightfiles
- Y All cu. krs will merger plan 9 has ' ice egulawry restructuring and gy ?
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mergerplan with PUC February 27,1997 !- y S p* llf . Duquesne Lightfiles ' 3] i 4 y l pilot pmgram with PUC , 1 i WL c By January 1,2000 L S
~
f# \ps&,yh 66% ofcustomers will ma have choice
, By January 1,1939 c---
33% of customers will have choiu , of generation supplier
}n 3 #ce ..
7 January 1,1997 Pennsylvam,a Electricity g 4[ g] y . uga f Generation Customer
>Q; W',p*** pet y"J"~' Choice and Competition Q, , e Act goes into effect b wg _ m <
( { R' O~ [% < ' [, @$h , x a n 95 , ,' > z;[9.bE? yr ]p , U f 'y fh$ f .[ Recovering ,
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- ments are built into current customer bills, and the new M
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b3 law provides a rate cap for up to seven years, staning 4^[,#. [ 'W . . with 1999. All distribution customers, including those who choose another supplier,
+ will be responsible for paying
,[zJ g'n e wj a Competitive Transition Charge (CTC) for a period m y
' F MPYKJ . - e '[~ ' of time. This charge will be determined by the PUC based y on an examination of each utility's restructuring plan.
\ T. What 6 / costs need investment to be recovered? g All utilities have capital mvestment costs related to either their power plants or contracts to buy power from other Our Mitigation Strategy producers. Past investment As pan ofits strategic business repurchases, to sales of excess costs that were prudently plan, Duquesne Light has actively power in the wholesale market, neurred by utilities and engaged in mitigation - or cost- to efficiency initiatives to reduce approved by the PUC, and reduction - effons for more fuel costs and capital, operation are fully recoverable under than 10 years. and maintenance expenses. This the current regulated structure, In 1986, the PUC recognized emphasis on cost reduction is may not be recoverable in a what it described as Duquesne enabling the company to avoid competitive market. Under Light's "self-imposed austerity" $700 million in rate increases the new law, these costs may measures. This austerity began in and to reduce our potential be collected over several the mid-1980s and continues today stranded costs by $340 million years. However, each utility throughout all areas of the com- by January 1,1999. These cost is obligated to reduce or pany's operations. reductions will continue through mitigate" ti. se costs as a Duquesne Light's aggressive December 31,2005, to further condition for recovery. cost-reduction programs have reduce potential stranded costs resulted in cost savings of more by an additional 5690 million. than $1 billion. These reductions Duquesne's mitigation initiatives range from the closure, cancel- were further augmented in its lation and sale of certain customer choice restructuring generation facilities, to debt filing to the PUC on August 1. refinancing and stock
'Re g ula t o ry Re s t r u c t u rin g Pla n Maximizes Ef f ects of Competition Our restructuring plan builds on a history ofinnovation and maximizes plan, see the "Compet tion and the Customer Choice Act" section on "T"""{"]
j the benefits of competition and page 38. h 'RM*9[*h'%~Q% -Q !/ % cconomic development.He proposed merger with Allegheny is seithg generation by@. jM}j k m . Energyis ar> integral element of aur b i assets an option to G 1
@j filing and offers additional benefits avoid the need to recover y, Y T g) resulting fmm cost savings and stranded costs? 1 - 4 1d increased elliciencies.
{ m g Because of our pending merger Sales of electric generat- fjggew Mg y j] :rc with Allegheny Energy, we have filed ing plants are becoming Mg5 ajoint restructuring plan - our pmfened attemative-which pmvides increasingly common across the country as states move toward f@$(jM M $gngN 'g g' $j$4 Tk% 3) the most benefits for consumers. We customer choice. Some companies udhLhee also have filed a stand-alone phin in are using proceeds from these Some of the parties involved in the event the merger is not sales to reduce stranded costs. our restructuring case are recom-consummated. Other utilities planning mergers mending that we be required to Our filing details how we will are, in some cases, offering to sell generation assets as a way to stmeture our business in this partially divest generation assets determine their value. Since we new competitive environment. in response to regulatory are too small to compete in the it addresses a vaiiety ofissues concerns about market power - unregulated generation business, irquired by Pennsylvania's customer that is, too much generation in a we have agreed. in our stand-choice act, including the unbundling particular geographic region being alone filing, to auction our of mies to differentiate between concentrated in one company. generating units to establish a genemtion, tmnsmission and We believe a fundamental final valuation for those assets. distribution ser ices, as well as premise of the customer choice Ourjoint restructuring filing with tiratment of above-market cost; legislation was to let the market merger partner Allegheny Energy associated with utdity generation determine each utility's stranded proposes an auction of a portion asets. It includes a proposed costs after mitigation initiatives of the combined Company's nxiesign of mtes that encourages were taken into account, rather generation assets, to provide a economically eflicient consumption than relying on expert witnesses valid indkator of market price to by lowering mtes for customers using using computer models to forecast ensure that we would recover no more than their historic amounts. market prices and operating costs more than our stranded costs For more detailed infonnation 20 to 40 years into the future. through the CTC. A final PUC on our regulatory restructuring decision is pending. mwqmm-- mmm-wmmmm-- , mwn - m. mmwm y y .
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nergizing Our Utility Business A Special Tha n k You s Technology. Deregulation. Consolidation...In this era of rapid change, every year demands more than the previous year in order to deliver the positive results our shareholders and customers have grown to expect. Throughout 1997, employees at every level responded extremely professionally to the demands brought on by the dramatic changes taking place. It takes company-wide teamwork to prepare to merge and transition to competition simultaneously. These efforts would not be possible without the commitment and enthusiasm of our many talented employees. O.h q
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. Hagerstown Fairmont The natural geographicpt between our two companies helps to create an ideal strategicpt.
Transaction Merger at a GIance Overview As of December 31,1997
. combined company equity valued at $6.2 billion as of Allegheny Energy DOE closing prices (April 4,1997)
Combined
, gggg g Revenues 52 4 tulhon. 54.2 Nilum . pb billuin : shares of Allegheny Energy for Assets $6.7 billion $4.7 billion $11.4 billion each share of DQE common stock owned, which represents
% incawne , 52Ni millkm . SlW nIsilkm $4No millum a fair conversion ratio for both Earnings Per Share $2.30 companies
$2.57
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51.44 M . is tax-free Share Price $32.50 $35.13
- Transaction accounted for as
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t22 millum ',. 7A'enitum . Customers 1.4 million .6 million 2.0 million hiputanoo . 3 mamim i.5mmk. ~ cl Combined Total Sales Mix 4.5 manion As ofDecember 31,1997 Senice Territory 29.100 sq. miles 800 sq. miles 29,9(X) sq. miles Total Sales: 73.1 bilhon kWh Nsles G Hec l ul Cuni
- 4i;294 gWh 12.545 gWh 53,N39 gWh - (
Commercial Residential Total Generation Capacity Nuckw Cupa1ty 8,347 MW" None 2,670 MW 22MW I1,017 M W M2MW i ,
, d.
Peak Load 7,500 MW 2,671 MW 10,171 MW bnple,4 ees - 4.189 2 3,465 - H.357 ' i g pg
- Does n it include bulk power transactions. 30.6% Who s Tra,n,1c ons
" includes 276 MW of Ft. Martin No.1 owned by AYP f.nergy. Does not include 299 MW of other 3 non-utahry generation. 3 g g
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I D OE's E m e rgin g M a rket-D rive n B u sin es se s l
.,( 4 As we prepare for an p f
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; increasingly competitive
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/ ., j, on many fronts, it has been
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We have been successful
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f f l products and services and b)
. D, .. identifying niche investment opportunities related to our primary areas of expertise.
* ~1 This " toolbox" of marl <et-driven businesses will continue to contnbute more significantly to the bottom I
line as part of the ongoing transformation of our company into a total energy services provider.
l < Power quality remains an important bur,iness for DOE.. l Competitive electricity markets will Capitalizing on strategi: likely result in varying levels of power opportunities.. Market-Driven quality. Power quality products-DQE's market-driven businesses Businesses' including back-up power supply contributed 79 cents per share, or Contribution to EPS systems-will be increasingly in 30.7% of total earnings for 1997. demand to protect sensitive equipment This favorably compares to 43 from electricai variances. cents per share in 1996. During in May 1997 DQE 1997, these diversified, energy- 339
- acquired 10% owner-related businesses posted two ship in SatCon, a significant, non-recurring gains. O rublicly traded in the second quarter, we developer of energy comp!cted the sale of Chester storage systems.
Engineers, a water and waste- 39 , SetCon's flywheel-water services company, to US based energy storage Filter. Since acquiring Chester in systems are a competitive alternative 15 9 Q 1993, we worked closely with to the lead-acid batteries currently O management in restructuring the m used in traditional power quaiity company to focus on its strengths. systems. As part of this transaction, We ended our profitable Q : DQE received the exclusive right to association in May because 4% distribute SatCon's energy products Chester's refocused efforts on in our region. Based on SatCon's industrial wastewater contracts no O current market vaine, our investment longer fit into our total energy - has appreciated approximately 1007c.
'93 '94 '95 '96 '97 SatCon has been listed as one of the strategy. Over our four years of ownership, Chester provided a " Magic 25" stocks for 1998 solid annual return on investment. by IndividualInvestor magazine.o This transaction resulted in an Our marl <ct-driven businesses initial 9 cent gain in earnings continue to increase their . .
per share. percentace contribution to In the founh quarter, we sold earnings per 3 hare. Strategic alliances enhance our interest in Exide Electronics the value of DOE's investments Group, Inc. to BTR plc, a global The sales of Chester and Exide and capabilities.. engineering company. Exide is an Electronics are just two examples DQE's gnmth strategy to take to the integrated provider of non- of our ability to capitalize on market a divenified set of consumer-interruptible power quality strategic opponunities. We are oriented pnxiucts and senices t?so product;, systems and services accelerating our efforts in seeking includes partnerships with nationally domestically and internationally. additional growth opportunities recognized companies. Thmugh our This transaction contributed an in 1998 and beyond to continue strategic alliance with MCI, we are additional 8 cents to the bottom this positive trend. levemging DQE's fiber network to offer line in 1997. We are continuing to Following are profiles of some communications senices. In MCl, we explore additional investments in of the newest additions to our have a partner that is a recognized powcr quality beyond our existing " toolbox," which is illustrated on communications leader that aheady has investment in SatCon. pages 18-19. captured 20'7e of the long-distance telephone senice in our region.O El - - - - - - - - - -
4 barrels of oil, enough to provide energy to 75,000 households. Additionally, capturing gas from landfills results in significant environmental improvements by reducing greenhouse gases and volatile organic compounds, and providing odor control. l GSF is considered the premier l company in the landfill gas recovery business. Through GSF, DQE is gaining solid investment returns, as well as synergistic benefits, including introduction into a niche business in a growth industry, additional power genera-The GSF Energy Solution.. Since its inception in the early tion opportunities, and access to DQE acquired GSF Energy. Inc., 1970s, landfill gas recovery has new technologies with strong the largest collector and processor turned a source of air pollution and growth potential. of landfill pas in the United States, odors into a renewable energy An example of these synergistic late in 1996. GSF designs, permits, resource. A founder of landfill gas benefits is the 10-megawatt landfill builds. owns and operates landfill recovery technology,GSF Energy gas power generating facility we gas energy recovery facilities continues to be the leader in this have constructed in Monmouth across the nation,like the Olinda, industry. Today, GSF owns and County, New Jersey. After we California, facility pictured above. operates landfill gas recovery and confirmed the landfill's potential GSF is committed to providing pnxiuction facilities nationwide, with as a dependable gas supply, we systems that meet customers' a total processing capacity of more financed the project, provided needs for emission control of than 50 million cubic feet of land- project engineering oversight, landfill gas and make efficient use fill gas per day. The gas is turned cleared regulatory hurdles, and of a renewable energy resource. into a renewable energy resource negotiated a long-term agreement The energy recovered from -cither electricity, high-Btu pipe- for sale of the electricity.The processed landfill gas is used by line quality gas or industrial quality project is scheduled to go on-line residential, commercial and medium-Btu gas. This represents in the first quarter of 1998. O industrial customers. the annual equivalent of 1.5 million Product Bundhng Delivers Energy Savings to Local School District.. - 4 7 Weatherproof Bill
- g School District M natural gas F 3 \ OnDemand-
- energy monitonng roject electricity ] financing
- new equiprnent
- guaranteed shared savings 5
When faced with aging equipment equipment, delivered low-cost on gas and electricity. This bundling and rising energy bills, the energy, guaranteed the district's of our comprehensive product line Montour (Pa.) School District heating and cooling bills, and will provide a solid return over turned to DQE's market-driven provided 1009 of the equipment the next decade. Similar service companies for help in controlling financing. The district now enters offerings will differentiate us from costs. Utilizing our comprehensive each budget year with certainty electric commodity suppliers as product line, DQE installed new regarding how much will be spent competition increases. o E3 - - - -
Water: A unique aggregation strategy.. DQE subsidiary AquaSource, Inc., wastewater services to approxi-is a fast-growing water utility mately 900 customers. Because based in flouston, Texas. The of the natural beauty of this company's mission is to acquire environmentally conscious area, the E. Fuel offers a competitive and water systems in selected regions discharge of treated wastewater is . envir nmentally beneficial fuel of the country to expand and a highly sensitive topic. AquaSource alternative.. diversify its customer base. has been able to keep wastewater Early in 1997, DQE announced the AquaSource is enhancing DQE's treatment costs to a minimum by formation of a strategic alliance and profitability by achieving additional contracting with the 36-hole exclusive licensing arrangement with e , ,7 ,- - ,. ,~, % w ..
.. CQ Inc., a fuel technology company, g;g , j%%. ,~..Q Q { ,' *f :$/Wy t-to produce E-Fuel. This new, environ-W r
mentally sound synthetic fuel offers a
.... , reduced emission alternative to industrial coal. A DQE affiliate is
, building plants to produce this
*A pelletized fuel product, w hich combines coal and by-products from w < , . the recycling of paper and plastics, thus preserving valuable landfill space. E-Fuel will be used as an
. . ,.W . .- -
' ~
.,, alternative fuel in a variety of
. - J industries that use coal. With benefits
- d=F ,
n .
< g - _ including reductions in nitrogen
,%. oxide and sulfur dioxide of up to 25% we believe E-Fuel will be very efficiencies through increased size Woodcreek Golf Course to supply competitive in the marketplace.
and its expertise in the water and irrigation water. The first plant to produce E-Fuel wastewater business. Now the largest investor-owned is under construction in Tarentum, The Woodereek Resort Utility water utility in Texas, AquaSource Pennsylvania. Initial production of System, pictured above, was the plans to expand into other regions this environmentally friendly first acquisition by AquaSource. of the country. O pelletized fuel product is scheduled This system provides water and to begin in the first half of 1998. The Tarentum plant will be capable of producing up to 300,000 tons of International Activities..
- DQE's joint venture with E-Fuel per year. Ileinz USA's DQE continues to look beyond its Marathon Oil, ElectroGen Northside Pittsburgh food-processing traditional boundaries for business intemational, continues to actively complex will be a customer of opportunities. punue the development and E-Fuel from the Tarentum plant
- On January 26,1998, DQE acquisition of power projects. under a long-term energy services expanded its relationship with
- DQE has fonned a partnership contract. Five additional E-Fuel
- 11. J. Ileinz Company by with the Electricity Board and plants are under construction to providing opemtions, maintenance Power Corporation of the State provide a competitive advantage to and other energyclated senices of Kamataka, India, including a variety ofindustrial users. O at its framington, Ontario, facility a series of technical exchanges under a 15-year agreement.
Weatherwise'"'is actively over the next seveml years that gg~ will provide a platform for future pursuing emerging opportunities business opportunities. 3}' y"N in intemational markets to launch its platform of weatherclared We are pursuing independent power production opportunities 4 energy products and services. to participate in intemational A
- Ajoint venture with ITRON, Inc., generation markets by the EnSite Communications,is pur- operation of electric genemtion suing metercading opportun- equipment acquired through ities in India. leasehold investments.O
Transforming DOE's investments in Providing customers throughout our region and beyond it's about creating value every step of the g Utility Operations way, in everything we do. Growing certain rg DOE is merging with Allegheny Energy elements of our business, spinning off dividing its utility business into three others, while applying new technology.. Unregulated FERC-Regulated Generation Transmission Combined Integrated with transmis-low-cost 11,000 sion assets of surround-MW generation ing companies to form portfolio a regionalIndependent System Operator Developing " extensions" of our core business... 9 Marketing of Bundled Products Preparing for the opening of energy markets in Pennsylvania and neighboring states by offering bundled products through joint ventures Electricity
/
am yo un Leveraging Allegheny Energy's strong brand name
- L1 o i t iioi and innovative pricing to capture this emerging opportunity through the merged company N Natural Gas Taking advantage of the inherent convergence of electricity and natural gas through supply, '
transportation, storage and management Communications ( ,,, $h' Partnering to leverage DOE's fiber-optic network to offer communications services
. Direct Satellite TV Providing satellite television equipment "m m "* ' and programming N Weatherproof Bills" Introducing products that reduce weather-related financial risks for energy consumers and retailers iE"93Df9F N Electronic Commerce Providing advertiser-sponsored long-distance (g)Prefection 0se. telephone service Home Security Partnering to provide security equipment and monitoring
..We continue to pursue acquisitions that are y, synergistic with our core business, mindful of the gg importance of maintaining flexibility to repocition /
Distributed Generation and Power Quality or sell these busines::es if conditions change. These investing in the development of fuel cells, focused investments have yielded superior financial flywheel-based energy-storage sytems and oth results and provide the experience necessary to emerging energy technologies pursue new opportunities.. Exide Electronics (sold for a gain in 1997) E
the ' Emerging Energy Marketplace an expanding " Toolbox" of products and services
.. Recognizing customer needs are both diverse and simultaneous!y and changing, DOE is constantly expanding its components products and services to further differentiate State-Regulated its bundled offerings..
distribution ntegrated with Allegheny nergy distribution companies o maximize efficiencies and h ======, AgttaSource s eliability for 2 million ustomers Water Services P Aggregating, managing and introducing our } k g.- bundled products to domestic water and wastewater service operations j Water Utility Distribution
- Water Quality Testing
) Chester Engineers
} [QgW r A-(sold for a gain in 1997) Industrial and Commercial Energy Services Providing integrated energy management solutions through affiliations, licensing agreements and joint ventures
/
. Energy Facility Management and Generation Development (domestic and international)
EGI 9ma,*a Acquiring, developing, operating and j mainta,ning i central energy facilit,es i serving customer-specific sites
- Energy Management OnDemand" installing, monitoring and maintaining comprehensive energy management systems and services M
Energy Monitoring Services Providing automated metering and j energy consumption analysis services E.fygf"
. Fuel Technology introducing niche fuel technologies and providing fuel management services
. Gas Processing Developing new gas reserves for use
~
in energy service offerings Y
...While C011tillitilig tof0Cits oil tile "illits alid balls. "
Financial Services l Providing financial structures, customer While our business changes over time, l financing and esset management to the discipline, structure, and focus on expand DOE's energy product and service results that we apply in our investment offerings process continues. -
\ . Board of Directors Daniel Berg - - William H. KnoeH*
^ '
- 68. Term expires 2(XX)(1,6).
% 73. Term expires 2(XX)(3,4,6).
Institute Professor, Rensselaer Retired Chairman and Chief Polytechnic Institute. Chairman Executive Officer of Cyclops
~
# Industries, Inc. (basic and of the Academic Advisory Board of the National Academy of specialty steels and fabricated Engineering. Chairman of the steel products; industrial and board and director, Crystek Crystal commercial constmetion).
Corporation (manufacturer Directorships include Cabot Oil of high reliability crystals for and Gas Corporation and St. Clair microprocessors and oscillators). Memorial Hospital. Life trustee of Other directorships include Hy- Carnegie Mellon University. Tech Machine, Inc. (specialty pans), and Joachim Machinery Co., Inc. David D. Marshall (distributor of machine tools). 45. Term expires 1998 (3,5,6). President and Chief Executive Doreen E. Boyce . Officer of DQE; President and
- 63. Term expires 1998(2,5). Chief Executive Officer of President of the Buhl Foundation Duquesne Light. Directorships
~
include United Way of America. (supports educational and com munity programs). Directorships Trustee of Penn's Southwest include Microbac Laboratories, Association (economic Inc. and Dollar Bank, Federal development). Savings Bank. Trustee oi Thornas J. Murrin Franklin & Marshall Collyr
- 68. Term expires 2(XX)(3. 6).
- Dean, A.J. Palumbo School of
. Robert P. Bozzone" Business Adminstration,
- 64. Term expires 2000 ( l. 2). Duquesne University; former Vice Chairman of Allegheny Deputy Secretary of U.S. Dept.
' ~ ,
Teledyne, Inc. (specialty metals of Commerce; former President. production). Life member of Westinghouse Electric Corporation ASM International (engineering Enercy and Advanced Technology technical society). Directorships ~ Group. Directorships include include Allegheny Teledyne, lac. Motorola, Inc. (manufacturer Former Chairman, Pittsburgh of electric eq .ipment and branch of the Federal Reserve components) Member of the Bank of Clevei md. Trustee of Executive Cc mmittee of the U.S. Rensselaer Polytechmc Institute. Council on Compe:itiveness and Chairman of the Pittsburgh Tissue Sigo Falk Engineering Institute.
- 63. Term expires 1999(2,3,4).
Management of personal m Eric W. Springer
. investments. Chairman of Maurice 68. Term expires 1999 (1,4).
Falk Medic d Fund, the Leon Falk f*/. Partner of Horty, Springer and Family Trust, and the Chatham T Mattern, P.C. (attorneys-at-law). College Board of Trustees. - Trustee of the Maurice Falk Directorships include the Medical Fund and Trustee Emeritus Historical Society of Western of Presbyterian University Hospital Pennsylvania and the Allegheny and the University of Pittsburgh Land Trust. Medical Center. Past president of the Allegheny County Bar Association. DOE /Duquesne Light Committees:
- 1. Audit 3. Finance
- 2. Compensation .l. %minating Duquesne Light Committees:
S Employment and 6. Nuclear Review Community Relations
- Irad Director Ezir
, DOE Cfficoro David D. Marshall,45. President and Chief &ecutive 0]Jicer. Previously held senior executive positions in finance at Central Vermont Public Service. Joined the Company in 1985. Directorships included on page 20.
Gary L. Schwass,52. Secutive Vice President and Chief Financial Officer: Previously served in a variety of senior executive positions in finance and management with Consumers Power Company. Joined the Company in 1985. Directorships include Chair, Western Pennsylvania Development Credit Corporation (promotes small business through lending activities), a:. Vice President and Treasurer, Holy Family Foundation (supports families in crisis). Donald J. Clayton,43. lice President and Treasurrr Previously held senior financial positions with Duquesne Light, Montauk and Price Waterhouse. Joined the Company in 1985. Directorships melude Juvenile Diabetes Foundation. James D. Mitchell,46. Vice President. Previously held senior financial positions with Duquesne Light and U.S. West, Inc. Joined the Company in 1988. Directorships include Three Rivers Youth (helps troubled teen-agers). Morgan h. O'Brien,37. Vice President and Controller Previously held senior financial positions at DQE, Duquesne Light, PNC Bank and Deloitte & Touche. Joined the Company in 1991. Victor A. Roque,51. Vice President and General Coun3el. Formerly Vice President, General Counsel and Secretary for Orange and Rockland Utilities. Joined the Company in 1994. Directorships include the Pennsylvania Chamber of Business and Industry (economic development), Hill House Association (provider of social services), the Urban League of Pittsburgh and the United Way Good Neighbors Advisory Committee. Member, Salvation Army Greater Pittsburgh Advisory Board. Jack E. Saxer, Jr.,54. Vice Pn>sident. Previously held senior fm' ancial positions with Gulf Oil and Chevron. Joined the Company in 1989. Directorships include Point Venture (venture capital) and Pittsburgh Consumer j Health Coalition (healthcare advocacy for the disadvantaged). i Diane S. Eismont, 53 Deborrah E. Beck,40 Joan S. Senchyshyn,59
)
l Corporate Secretary Assistant Contndler Assistant Sectriarv Duquesne Light Company Officers David D. Marshall,45 Donald J. Clayton,43 Victor A. Roque,51 Fred R. Allison,48 i President and Chief Vice Firsident Vice Pn'sident and Assistant Contn>iler j Executive 01Ticer and Treasurer Genend Ci unsel yg7y S_9agay,3g Gary L. Schwass,52 William J. DeLeo,47 Diane S. I ismont,53 Assistant 7'rawirr i Senior Mce Firsident and Vice President, Corporat< Secretary and gllpam p, pigggg,47 ChiefFinacial Officer Marketing and Assistant Genend Counsel Assistant Treasurer \ James E. Cross,51 Corporate Perfonnance Jack E. Saxer, Jr.,54 President, Morgan K. O'Brien,37 Assistant Vice Ptrsident Joan S. Generation Group Vice President Senchyshyn,59 Administration Assistant Secretary Gary R. ontniller Sally K. Wade,44 Brandenberger, 60 James E. Wilson, 32 Assistant Vice President Assistant Contndler Vice President, Human Resources Custorner Operations
}
Duquesne Enterprises Of ficers Thomas A. Anthony J. Vi!!iotti,5/ H. Donald Morine,60 John L. Weinhold,61 Hurkmans,32 Vice President, I'reasurer President, Allegheny Vice President, President and Contndler Developrnent Corp. and Pn>perty Ventures, Ltd. Pnsperty Ventures, Ltd. Montauk Officers James D. Mitchell,46 William F. Fields,47 Frosina C. Cordisco,46 Lydia E. York,38 l President 17ce Firsident Vice President Vice President i and Treasurer DOE Energy Services Officers Alexis Tsaggaris,49 Deborrah E. Beck,40 President Trrasurer and Contndler l l DOEnergy Partners Officers John W. Welch,46 President l
1997 Financial Statements at a Glance . Detailed financial information can be found beginning on page 29. Selected Financial Data l [in millions, euept per share amounts) 1997 1996 1995 1994 Selected Income Statement items:
$1,133 $1,139 ' $1,134 Revenues from sales of electricity a ~237 232 244 Fuel and purchased power expenses
. # 896 907 890 Net electric revenues -
la 93 81 90-Other reveaues - i 989 988 '980 1 Net operating revenues
377 374 409
. operating and maintenance expenses 223 '203 166 Depreciation and amortizadon
. 86 89 ' 88 Taxes otlier than income taxes 686 666 663 Non-energy operating expenses .
- 303 322 317
. Operatingincome i 73 52 43 Investment and otherincome 110 107 110-Interest and other charges '
. 87~ 96 93 Income taxes
$ 179 $ 171 $ 157 Netincome .
Basic earningspershare $ 2.32 $ 2.20 $ 1.98 ' !
. Diluted earningspershare $ 2.29 $ 2.17 $ 1.96 .1
'2.69 2.73 2.57 Ratio ofearnings tofixed charges (pre-tax) .
Selected Balance Sheet items: Long-term investments $ 519 $ 441 $ 196
$2,817 $3,060 $3,140 Property, plant and equipment
$4,639 $4,459 $4,427 i Totalassets
$3,055 $2,801 $2,750 :l Total capitalization Capitalization Ratios:
~~m 3pggg~wyggg ~ 7 gymn rqqgg,q7
,[7.3%.1 . [2.5%j 53.5%;
j Preferred and prefenmoe stockj ,
. ~47.1 %' ; 50.0% - L 50.1% . .o.f Lag-tenn debt < , 3 pauhad.5:w.a:.Atk&d.d.r edeGna-i.arLa1%,,ug.L6hh. xMi , , s_& _, ,, gg ';g giw ,3 r.m. , g g _; &
Selected Common Stock information: Average shares outstanding 77.3 77.7 79.0 Shares outstanding at year-end 77.3 77.6 78.5 Market capitalization $2,241 $2.386 $1,550 l Dividends declared $ 101 $ 94 $ 89 Dividends declared per share $ 1.30 $ 1.21 $ 1.13 Book value per share at year-end $18.01 $17.13 $16.27 Dividend payout ratio 55.2 % 54.1 % 56.4 % Dividend yield at year-end 4.7% 4.2% 5.7% Return on average common equity 13.2 % 13.1 % 12.5 % Price-earnings ratio at year-end 12.5 14.0 9.9
1993 1992 1991 1990 1989 1988 1987 ~ ~
$$120 $1,116 : $1,1395 - $1,094 L $1,086 $1,039 ' $ 855
<238N .239 254 .229 '220 231 '228 882. '877- 885. 865 866 808 627-
. 63 " ' 37 '
38 31 :48 43 ' : 22 ' 1945 E 914 923 8% 914 851- 649-i4031 - 354 361:- 372 342 327 250 158 '132 123. '123: :123; 117- .82
' 71 -
.. 84 94 '80 . 93 - 81 . 67
- 632 : " - 570. ; 578 575. '558- '525 399
.313i -344L 1345c -321 356 "326' -250.
- 31> 42 :- 36 46 . :(3)L 30 29' 120 132-- 142 ~ 157 165' -175- 156-80 - '112L 105 88 - ' 75 - 62 (12) .:. !
s$-144- -$1142; $ - 134 - '$ 122.. .$ I13 $ .119 $ - 135
, $ .1.81 - - $ 1.78 $ 1.67 - $ 1.49... . $ 1.35 $ 1.24 - $ 1.23-
$ :1.79 - ' $ I.77 -
$ 1.65 - $ 1.48 $ 1.34 - . $ .1.24 . $ 1.23 2.29' 2.24. ' 2.10 .. l.90 : 1.78 ' . 1.72 ' l.58 -
a , , , s n. -
~
$ 126' $ - 59 $ 44l $' 18' -$ --
'$'- S' -
$3,168 i $3,037u $3,053 $3,(M8 $3,055 . ' $3,066 $3,098 '
. $4,550 $3,778 $3,851 $3,834 . $3,921 _ $3,881 : $4,152
- $2,781 - $2.716 $2,669. $2,770 $2,827 $2,866 53,169
"[4Ef35.IEf%E5I
' Ji;4.8% P f 4.9%f < f 5.2%>
%5ESIkT775E((]!5iI%[][!,I55Ik]W
> " 6.8%> ; 77.8%; '
18.5 % 48.2%S N m A52N f 53.2%Y n i$4.2M ' MM.Sfi 'M?54J%D
, !.58.052 d53.4%Ni *g e44&i.Juaw.415eW544 sa.114M4A Gm.Wmbusai%O nMd.a12ndbud.ALa'd Jt%4aiuaaksassr45A.whabbad.&%LieG.EdWdid$
79.5 L 79.4 80.1 81.6 ' 83.7 95.6 109.3 79.5 79.4 79.4 30.6 83.0 ' 86.7 105.1'
$1,829 . $1,708 $1,621 $1,337 $1.321 $1,084 $ 824'
$ 86' '$ 81 $ 78 $ 75 $ 73 $ 70 $ 8'
$ -1.08 $ 1.03' $ 0.97 $ 0.92 $ 0.87 $ 0.81 $ 0.E )
$15.47 $14.75 - $14.00 $13.38 $12.85 $12.34 - $11.5t, 58.8 % 56.9% 57.6 % 60.7 % 63.1 % 64.5 % 64.9%'
4.6% 5.0% 5.0% - 5.8% 5.7% 6.8%: 10.2 % 12.0% - 12.4 % -12.2% 11.3% 10.6 % 10.4 % 11.1 % 12.7 12.1 12.3 11.1 11.8 10.1' 6.4 E
Selecteri Operating Data 1997 1996 1995 1994 Sales of Electricity (kilowatt-hours): 6,362 6,474 6,170 Average annual residential use ' Electric energy sales billed (millions): 3,321 3,378 3,219 l
, Residential . 5,563 5,737 5,729 Commercial l
'n 3,285 3,237 3,256 Industr i
?
83 84 84-Miscelltu,eous 12,426 12,428- 12,122 7btalsa'es to customers ' 3,310 2,975 -3.212 Sales to oGrbulities 15,736 15,403 15,334 Totalsales , Percentage Change in Energy Sales: P.esidential (1.7) 4.9 (0.4) 1 0.1 3.0 1.3 Commercial 1.5 .- (0.6) 6.9 Industrial (1.2) 0.0 0.0 Miscellaneous
. 0.0 2.5 2.3 Totalsales to customen I1.3 (7.4) 13.9 Sales to other utilities .
Totalsales . 2.2 0.4 4.5 Energy Supply and Production Data: 7 5 5 Q M i s silii E N E M E Ars I 4 L
"~"T"[""7"V14
- 14,166) ML14,20lf,678 ?M"'?] ,
h ;hietgeneranon Purchased and net inten: hangedsystemplantsL. power , ::1,570
.1,202? 7656M 15,334 U 3 ifbestenerrysapply
===========--
15,736 L .. . . .15,403A_ _ _- _ . _ ' = = =. -1 =
.2 ,670l (2,834) 2,834 z :y
. pi L=Generating capability (megawatts)f ,
, ; Peak demand (megawatts) 2.463 :2,666i 12,5351 4 3
pst of fuelpermillion BTUf - t. , 130.21# { 6 131.375; 1137.23# h ng] { Average cost of generauon J per kilowatt-hour 7 12f; . , . ;2.22 ? ' . 2.23g1 i w . ^
.; wiswa.4L s Ja n u m, 2ar,+ 9+w,u24,w ww,: J. 4 kk,in. .uMadmub:.. ace.uG .8 Customer Data:
Telephone access: [
% of customers waiting less than 30 seconds
' U.[M 88 % 87 % 86 %
Customer Senice Guarantee Program enur rate Fg .007 % .007 % - Number of customers at year-end (thousands): ; Residential Okh I y]j 522.8 522.9 522.6 Commercial g $] 54.0 53.8 2.0 53.6 2.0 Industrial "g g @ 2.0 1.9 1.9 Other gfp ._ J q 1.9 7btalcustomers M)lMJNh > d 580.7 580.6 580.1
. -x .
Market-Driven Businesses:
% contribution to DQE earnings E5 " Ry d 19 % 15 % 10 %
Return on equity 15 % 13 % 10 % f j h; 3 2j9
$612 $470 $350 hg h( j Assets (millions)
Landfill gas reserves (Bcf) 171 - - Nama:awd g-
\
1993 1992 1991 1990 1989 1988 1987 6 ,201:... :5,901" 6,331 5,953- . ~.6,060- 6,168' . 6,019 1 3,231- :3,069 3,285 3,078 3,119- 3,065 3.156 . 5,490: 5,358 - : 5,450 . 5,236 5,145 :4,899 5,055 h 3,046 ? 3,059 3,042 ' 3,296 L 3221' 3302? ' 2,918' 84 . 83 - 84 . 84 84 91 98 - 11,851 11.569, 11,861 '11,694 11,569 11,604. 10,980. 2,821- '4,060 2,979 . -1,830 - 2,100 .2,716 2,426: ,
.14,672 '15,629 14,840 13,524-- 13,669 - .14,320 13,406 . aw . . , ,
53' (6.6)' 6.7 (1.3) (1.2) 3.0 3'7 . 2.5 .(1.7) 4.1 1.8 1.8 ' 3.2 - 3.7
. (0.4) 0.6 (7.7) 23 (2.5) 13.2 6.7 1.2 ' -(1.2) 0.0 0.0 (7.7) (7,1) (1.0) 2.4 (2.5) . 1.4 1.1 (03) 5.7 4.4 (30.5) 363 62.8 (12.9) . (22.7) 12.0 16.0 (6.1) - 53 9.7 (1.1) (4.5) 6.8 6.4
]pfyFM""~p""M"f{"T"{" ""?"7"77"9W""]'"~3?))"""]
* ?14A663 5 14,230 W '.13.266i ?13,455 (
M 9616$ y 115#74 :~
^ 12lC , *114,144;; @i
!!98 ??13,308b[i 4 4555s ' ' ' 2620t !258; _ SIE '
. 114 472; (15,629 n w % 14,tio). .. .. . .. . . . ":. -13,524_ . . _ 0. . . . . _ . .cl3469" . . .,.:14,320
. . _ . e. . . . . . . .<t3A06;-3 q
>Mj24 , f2,8Mg g f;2,8351 *
^ K2,835g 4 sc.p2,835y (2,836; 72,852s
, y2,372(.p; J2,280y ]y
# ~j2 W @ 12,308 1 $2A02( A2,379 , ~ J23ti;
's 1140.15dh*_ ; J153.70sy
;143,65#J z149.62#4 e143.87sj
- ll45.74(f q150.99tf g 4 f233W9, < 22.19t:% ' f2.44g ? .
02.51ff ;2.73 6 - J 2.fSe F - d2.33#J d m u m.-amaamaa.m.sh w e.x-mmam,a.aaw - m d 76% 41 % 26 % - - - - 5223 521.2 520.0 5183 516.8 513.8 510.8 52.9 52.8 52.6 523 52.0 51.5 50.9 2.0 - 2.0 2.0 2.0 2.0 2.0 2.0 1.9 : 1.8- 1.9 1.9 1.8 1.8 1.8 579.1 577.8 576.5 574.5 572.6 569.1 565.5 4% '1% 6% 2% 2% - - - -
$212 $106 $53 $31 $2 - -
. _w---_ _ - - - _ _ - - - - - . - _ _ _ -
4 1 Condenood Finencial Statomonto Condensed Statement of Consolidated income (inillions ofdollars, e.tcept per share arnounts) I Year Ended December 31, 1997 1996 Revenues from sales of electricity $1,113 $1,133
.%Me viility Als Wdh Fuel and purchased power expenses 33.3 237 )
increasa) .Indas\ria\
> ~- - - -
~~~~~1
~x-- Net electric revenues 890 896 3,gg gg Other revenues 106 93 9&, 989 New innstinenh re\o%Jl Net operating revenues -- -- - -- - - }-
+0 m rc h ,. sin ess
~ ~~ Operating and maintenance expenses 390 377 J
, Depreciation and amortization 243 223 kaAccokJ ,
recocy of Taxes other than income taxes 83 ,, , , 86 , ,,
/ ,, , , , , , , ,
liv e d < o s k ' Non-energy operating expenses 7l6 .. .. .. 6ss I 280 303 j gm.h
- Operatingincome 130 73
-- Investment and otherincome q
'"0'gygisco Interest and other charges 115 110 I pg.does3cs - / .. . . . . . . .
. . .l l Income beforeincome taxes 295 266 lit'nEly' Twane ', Income taxes -
96 87 fiefeircJ Scuitics [7 widen) Requircen crk Netincome $ 199 $ 179
,- Earnings per share $ 2.57 $ 2.32 Coch.nocJ earn.ogs -
itnpDWrenk' n Depreciation and Amortization (milliams of dollars)
%2*'
gy3 The continued success of our snarket-
$203 driven busine.nes has enabled DQE O to gross earnings uhile increasing y
$158 g,,prechttion and arrusrtimtion cy>cnw O 10further reduce our utility operation's stranded cmts.
'93 '94 '95 '96 97
Condensed Consolidated Balance Sheet (millions ofdollars) As ofDecember 31, l Codinued 1997 1996 in ynOc$.c\'-)grue r'\ ven n * . . , . . . . bv. sines.scs y Current assets $ 569 $ 622
^
- Long-term investments 723 519 A2derokJ &cJ Property, plant and equipment 2.662 2,817 cod remey _./'~ Regulatory assets 681 637 Other non-current assets 44
. 59. . . .... .. .
Totalassets $4.694 $4,639 t l Current liabilities $ S 261 Deferred income 2.., 189 Non-current liabilities 1,084 1,134
, Laag-term debt 1.376 1,440
~ "' ' ' ~
,' Totalliabilities E,967' 3,05' z .. .. . . . . . . . . ...
Delf rub / Preferred and preference stock 228 3,j,, 223 Common shareholders' equity 1,499 1,392 Totalliabilities and equity $4.694 $4,639 I Long-Term investments tmdlions of dollarsI 5723 j i O Thrtmgh our market-driren businessex.fidurr capirings grou'th $99 will connefnnn nic he ins estments gy related to vs.r core business. Ncw i products and energy solutions are O being developed and implemented to transform our company into a $196
" Total Energ.s sers ices provider st:s Q O
'93 '94 '95 '96 '97 E - - -__ -
Condensed Statement of Consolidated Cash Flows , (Inillions ofdollars) l
)k'ar Ended December 31, 1997 1996 CodinocJ .shvng
/ Operating cash flows $ 470 $ 350 shbm (37) 3 Changes in working capital Other , ,, ,,
(6(0, , ,
, 30 , , , , ,
Cashfrom operating activities 367 383 , , , , , ,, , , IndvJes insedineds in 86 18 Disposition ofinvestments
$dCon, enerp f l casing, otTon.f bMe aciiity
' IAng-term investments (219) (101)
/ Capital expenditures (118) (101) housing, an) gas Sale of generating station -
169 remvery businesses Other (5) (2) Cashfrom inresting activities . ii50. . . . (iii. ' " ." ' . .' . . . CodinocJ JividenJ Common stock dividends (107) (101) grwih s__- Net change in long-term debt (66) 15 Common stock repurchases - (12) Net change in preferred and preference stock - 150 Change in notes payable - (29) Other 7 , , ,, ,(3) ,, , ,,, Cashframfinancing actirities , (166)
, 20 ,,,,, , , , , , ,
Net changein cash ,,
,j55,
, , ,,5,386 , , , , , , , , ,
Not Osmmung
- Cash Flow' tmiIli<ms <>fdottars)
O I"
$372 " "
O OoO l'ositis e cash flow allon s D(}E to rnect its operating and construction requirements, improve its capital structure and dcvelop its markcl-driven businesses.
'93 '94 '95 '96 '97
- Excludes working capital and other balance sheet changes L ____ _ _ - - - _ _ - _ _ _ _ _ _ _
1997 Financial In f o rma tio n Company Report on Financial Statements The Company is responsible for the financial information and representations contained in the financial statements and other sections of this annual report to shareholders. The Company believes that the consolidated financial statements have been - prepared in conformity with generally acceptedpzw11tinf principles that are appropriate in the circ 6thstances to reflect, in all material respects, the substance of events and transactions that should be included in the rtatements and that the other information in the annual report to shareholders is consistent with those statements. In preparing the financial statements, the Company makes informed judgments and estimates based on currently available information about the effects of certain events and transactions. The Company maintains a system of internal accounting control designed to provide reasonable assurance that the Company's assets are safeguarded and that transactions are executed and recorded in accordance with established procedures. There are limits inherent in any system or internal control and such limits are based on recognition that the cost of such a system should not exceed the benefits derived. The system of internal accounting control is supported by written policies and guidelines and is supplemented by a staff of internal auditors. The Company believes that the internal accounting control system provides reasonable assurance that its assets are safeguarded and the financial information is reliable. David D. Marshall President and Chief Executive Officer Gary L. Schwass Executive Vice President and Chief Financial Officer
4 Competitive Generation Credit Obligation to Serre Ghsury of Terms Under traditional regulation, the duty of a regulated The Company will provide a credit to a customer for the PUC-determined market price of electric utility to provide service to all customers in its service territory on a non-discriminatory basis. generation. Customers will experience savings to the extent that they can purchase power at a lower 7IP pnce from an alternative electne generation Gives all customers equal opportunity to access supplier than the amount of the credit. the transmission gnd. CTCor Competitive Dansition Charge p,,gy,,,,, During the electne utility restructuring from the Peak demand is the greatest amount of electricity I tradiuonal regulatory framework to customer demanded at any given time. I choice, electric utilities will have the opportunity to recover transition costs from customers through Pennsylvania Public Utility Commission (PCC) a surcharge, or competitive transition charge. The governmental body that regulates all utilities (electric, gas, telephone, water, etc.) that do Customer Choice business in Pennsylvama. The Pennsylvania Electricity Generation Customer Choice and Competition Act (see " Rate Rate Base { Matters" on page 38) will give consumers the The amount representing the value of assets right to contract for electricity at market pnces approved by a regulatory agency for inclusion in from PUC-approved electne generation supphers. rates charged to rate-regulated customers. j Decommissioning Costs Regulatory Assets Decommissioning costs are expenses to be Historic ratemaking practices granted exclusive incurred in connection with the entombment, geographic franchises in exchange for the decontamination, dismantling, removal and obligation to serve all customers. Under this disposal of structures, systems and components system, certain prudently incurred costs were of a power plant that has permanently ceased the approved by the PUC and the FERC for deferral production of electric energy. and future recovery with a return from customers. These deferred costs are capitalized as regulatory Deferred Energy Costs ssets by the regulated utility. in conjunction with the Energy Cost Rate Adjustment Clause, the Company records Restructuring Plan deferred energy costs to offset differences in contemplation of the merger with Allegheny between actual energy costs and the level of Energy being consummated, the Company has energy costs currently recovered from its rate- filed this plan incorporating the merger benefits regulated electric utility customers. into its restructuring and recovery of transition c sts under the Customer Choice Act. Distribution / Transmission Transmission is the flow of electricity from Stand-Alone Plan generating Mations over high voltage lines. In the event the merger with Allegheny Energy Distribution is the flow of electricity over lower is not consummated, the Company has filed this voltage facilities to the ultimate customer- plan for restructuring and recovery of transition usually businesses and homes. costs under the Customer Choice Act. Divestiture Tariff The selling of major assets (power plants, Public schedules that detail a utility's rates, rules, transmission equipment or distribution lines). service territory and terms of service that are filed for official approval with a regulatory agency. Energy Cost Rate Adjustment Clause (ECR) The Company recovers through the ECR, to the Transition or Stranded Costs extent that such amounts are not included in base Transition costs, also known as stranded costs, rates, the cost of nuclear fuel, fossil fuel and are the net present value of a utility's known or purchased power costs. measurable costs related to electric generation that are recoverable under the current regulatory Federal Energy Regulatory Commission (FERC) The FERC is an independent five-member framework,, but which may not be recoverable m commission within the United States Department a competitive generation market. They are costs which remam unrecovered following mitigation of Energy. Among its many responsibilities, the efforts taken by the utility. FERC sets rates and charges for the wholesale , transportation and sale of electricity. Unbundled Charges Separate charges for each of the generation, independent System Operator (ISO) transmission and distribution of electncity m An organization formed by, but independent of, ce rdance with the deregulation of generation transmission-owning utilities which is responsible under the Customer Choice Act. for ensuring nondiscriminatory open transmission access and the planning and security of the Watt combined bulk r "smission systems of utilities A watt is the rate at which electricity is generated within a given geographic region. or consumed. A kilowatt (KW)is equal to 1,000 y,73,f p3.er watts. A kilowatt-hour (KWH) is a measure of When one company owns a sufficiently large the quantity of electncity generated or consumed n ne hour by one kilowatt of powcr. A megawatt percentage of generation, transmission, or , (MW) is 1,000 kilowatts or one milhon watts. distribution capabilities in a region which allow it to set the market price of electricity. - - - - . _ _ . _ s________________________________________ _ _ _ _ _ _ , _ _ _ _ _D.
DOE 1907 Financici information Corporate DQE, Inc. (DQE) is an energy services holding company. Its subsidiaries are Duquesne Light Structure Company (Duquesne); Duquesne Enterprises, Inc. (DE); DQE Energy Services, Inc. (DES); DQEnergy Partners. Inc. (DQEnergy); and Montauk, Inc. (Montauk). DQE and its subsidiaries are collectively referred to as "the Company." Duquesne is an electric utility engaged in the generation, transmission, distribution and sale of electric energy and is the largest of DQE's subsidiaries. DE makes strategic investments beneficial to DQE's core energy business. These investments are intended to enhance DQE's capabilities as an energy provider, increase asset utilization. and act as a hedge against changing business conditions. DES is a diversified energy services company offering a wide range of energy solutions for industrial, utility and consumer markets worldwide. DES initiatives include energy facility development and operation, domestic and international independent power production, and the production and supply of innovative fuels. DQEnergy was fonned to align DQE with strategic partners to capitalize on opportunities in the energy services industry. These alliances are intended to enhance the utilization and value of DQE's strategic investments and capabilities while establishing DQE as a total energy provider. Montauk is a financial services company that makes long-term investments and provides financing for the Company's other market-driven businesses and their customers. Proposed Aterger On August 7,1997, the shareholders of the Company and Allegheny Energy, Inc. (AYE), approved a proposed tax-free, stock-for-stock merger. Upon consummation of the merger, DQE will be a wholly owned subsidiary of AYE. Immediately following the merger, Duquesne, DE, DES, DQEnergy and Montauk will remain wholly owned subsidiaries of DQE. The transaction is intended to be accounted for as a pooling ofinterests. Under the pooling ofinterests method of accounting for a business combination, the recorded assets, liabilities and equity of each of the combining companies are carried forward to the combined corporation at their recorded amounts. Accordingly, no goodwill, including the related future earnings impact of goodwill amortization, results from a transaction accounted for as a pooling of interests. In order to qualify for pooling treatment, many requirements must be met by each of the combining companies for a period of time before and after the combination occurs. Examples of the requirements prior to the merger include limitations on: dividends paid on common stock, stock repurchases, stock compensation plan activity and sales of significant assets. Management has focused and will continue to focus on meeting the pooling requirements as they relate to the Company prior to the merger. Under the terms of the transaction, the Company's shareholders will receive 1.12 shares of AYE common stock for each share of the Company's common stock and AYE's dividend in effect at the time of the closing of the merger. The transaction is expected to close in mid-1998, subject to approval of applicable regulatory agencies, including the public utility commissions in Pennsylvania and Maryland, the Securities and Exchange Commission (SEC), the Federal Energy Regulatory Commission (FERC) and the Nuclear Regulatory Commission (NRC). In September 1907, the City of Pittsburgh filed a federal antitrust suit seeking to prevent the merger and asking for monetary damages. Although the United States District Court for the District of Western Pennsylvania dismissed the suit in January 1998, the City of Pittsburgh filed an appeal and asked for expedited review. A hearing is currently scheduled for late March 1998. Unless otherwise indicated, all information presented in this Annual Report relates to the Company only and does not take into account the proposed merger between :he Company and AYE. The Company's Electric Service Territory The Company's electric utility operations provide service to customers in Allegheny County, includig the City of Pittsburgh; Beaver County; and Westmoreland County. (See " Rate Matters" on page 38.) This territory represents approximately 800 square miles in southwestern Pennsylvania, located within a 500-mile radius of one-half of the population of the United States and Canada. The population of the area served by the Company's electric utility operations, based on 1990 census data, is approximately 1,510,000, of whom 370,000 reside in the City of Pittsburgh. In addition to serving approximately 580,000 direct customers, the Company's utility operations also sell electricity to other utilities. Regulation The Company is subject to the accounting and reporting requirements of the SEC. In addition, l the Company's electric utility operations are subject to regulation by the Pennsylvania Public ) Utility Commission (PUC), including regulation under the Pennsylvania Electricity Generation 1 N
e Customer Choice and Competition Act (Cus'omer Choice Act), and the FERC under the Federal Power Act with respect to rates for interstate sales, transmission of electric power, accounting and other matters. (See " Rate Matters" on page 38.) The Company's electric utility operations are also subject to regulation by the NRC under the Atomic Energy Act of1954, as amended, with respect to the operation of its jointly owned / leased nuclear power plants, Beaver Valley Unit 1 (BV Unit 1), Beaver Valley Unit 2 (BV Unit 2) and Perry Unit 1. The Company's consolidated financial statements report regulatory assets and liabilities in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, Accountingfor the Egects of Certain Types ofRegidation (SFAS No. 71), and reDect the effects of the current ratemaking process. In accordance with SFAS No. 71, the Company's consolidated financial statements reflect regulatory assets and liabilities consistent with cost-based, pre-competition ratemaking regulations. The regulatory assets represent probable future revenue to the Company because provisions for these costs are currently included, or are expected to be included, in charges to electric utility customers through the ratemaking process. A company's electric utility operations, or a portion of such operations, could cease to meet the SFAS No. 71 criteria for various reasons, including a change in the FERC regulations or the competition-related changes in the PUC regulations. (See " Rate Matters" on page 38.)The Emerging Issues Task Force of the Financial Accounting Standards Board (EITF) has determined that once a transition plan has been approved. application of SFAS No. 71 to the generation portion of a utility must be discontinued and replaced by the application of SFAS No.101, Regulated Enterprises - Accountingfor the Discontinuation ofApplication of FASB Statement No. 71 (SFAS No. lol). The consensus reached by the EITF provides further guidance that the regulatory assets and liabilities of the generation portion of a utility to which SFAS No.101 is being applied should be determined on the basis of the source from which the regulated cash flows to realize such regulatory assets and settle such liabilities will be derived. Under the Customer Choice Act, the Company believes that its generation-related regulatory assets will be recovered through a competitive transition charge (CFC) collected in connection with providing transmission and distribution services, and the Company will continue to apply SFAS No. 71. Fixed assets related to the generation portion of a utility will be evaluated on the cash flows provided by the CFC, in accordance with SFAS No.121, Accountingfor the impairrrent of Long-Lived Assets andfor L<mg-Lived Assets to Be Disposed Of (SFAS No.121). The Company believes that all ofits regulatory assets continue to satisfy the SFAS No. 71 criteria in light of the transition to competitive generation under the Customer Choice Act and the ability to recover these regulatory assets through a CTC. Once any portion of the Company's electric utility operations is deemed to no longer meet the SFAS No. ?! criteria, or is not recove ed through a CTC, the Company will be required to write off assets (to the extent their net book value exceeds fair value), the recovery of which is uncertain, and any regulatory assets or liabilities for those operations that no longer meet these requirements. Any such write-off of assets could be materially adverse to the financial position, results of operations and cash flows of the Company. Results of The Company's future financial condition and its future operating results are substantially Operations dependent upon the effects of the Restructuring Plan or Stand-Alone Plan currently before the PUC. The Company expects to be given the opportunity to fully recover its transition costs. However, to the extent the Company does not ultimately recoser its transition costs, a charge against earnings would be recognized. Such charge could have a materially adverse effect on the Company's financial position, results of operations and cash flows. (See " Rate Matters" on page 38.) Earnings and Dividends The Company's earnings per share in 1997 were $2.57, versus 1996 earnings per share of $2.32, a $0.25 or 10.8 percent increase. Net income increased to $199.1 million in 1997 from $179.1 million in 1996, a $20.0 million or 11.2 percent increase. In 1997, Duquesne contributed $1.78 to earnings per share, a decrease from the prior year earnings per share contribution of $1.89. The decrease was the result of the incremental $25 million accelerated nuclear fixed asset recovery as detailed in Duquesne's 1996 PUC-approved mitigation plan. Despite mild 1997 temperatures as compared to 1996, the utility increased total sales to electric utility customers, primarily as a result of stronger industrial sales. The manket-driven subsidiaries contributed $0.79 or 30.7 percent of total earnings per share in 1997, up from $0.43 or 18.5 percent of total earnings per share in 1996. The sale of Chester Engineers (Chester)in the second quarter of 1997 and the sale of Exide Electronics Group, Inc (Exide) stock in the fourth quarter of 1997 together contributed 50.17 to earnings per share. The remaining increase is the result of earnings attributable to the increased level of long-term investments. 32
Earnings per share in 1996 were $2.32, an increase of $0.12 or 5.5 percent over 1995 earnings per share of $2.20. Net income of $179.1 million in 1996 was greater by $8.5 million or 5.0 percent from net income of $170.6 million in 1995. Duquesne contributed to earnings per share $1.89 in 1996 and $1.88 in 1995. The slight increase was the result of increased income from long-term investments made during late 1995 and 1996, offset by the $25 million accelerated nuclear fixed asset recovery as detailed in Duquesne's 1996 PUC-approved mitigation plan. In 1996, the market-driven subsidiaries added $0.43, a 34.4 percent increase over the 1995 contribution, due primarily to income from long-term investments made during late 1995 and 1996 and to increased income at Chester. I Once all dividends on DQE's Preferred Stock, Series A (Convertible), $100 liquidation preference per share (DQE Preferred Stock), have been paid, dividends may be paid on the Company's common ( stock to the extent permitted by law and as declared by the board of directors. However, payments of dividends on Duquesne's common stock may be restricted by Duquesne's obligations to holders l of preferred and preference stock pursuant to Duquesne's Restated Articles ofincorporation and by obligations of Duquesne's subsidiaries to holders of their preferred securities. No dividends or distributions may be made on Duquesne's common stock if Duquesne has not paid dividends or sinking fund obligations on its preferred or preference stock. Further, the aggregate amount of , Duquesne*s common stock dividend payments or distributions may not exceed certain percentages of net income if the ratio of total common shareholder's equity to total capitalization is less than specified percentages. As all of Duquesne's common stock is owned by the Company, to the extent that Duquesne cannot pay common dividends, the Company may not be able to pay dividends on its common stock or DQE Preferred Stock. The Company has continuously paid dividends on common stock since 1953. The Company's annualized dividends per share were $1.44, $1.36 and $1.28 at December 31,1997,1996 and 1995, respectively. During 1997, the Company paid a quarterly dividend of $0.34 per share on each of January 1, April 1 July I and October 1. The quarterly dividend declared in the fourth quarter of 1997 was increased from $0.34 to $0.36 per share payable January 1,1998. The Company expects that funds generated from operations will continue to be sufficient to pay dividends. The Company's need for and the availability of funds will be influenced by, among other things, new investment opportunities; the economic activity within the Company's utility service territory; competitive and environmental legislation; and regulatory matters experienced by the electric utility industry generally, more specifically the transition to competition and related issues pending in Pennsylvania. (See " Rate Matters" on page 38.) The Company's stock price was $35.13 at the end of 1997. The book value per share of common stock was $19.30 at December 31,1997, which represents a 7.2 percent increase in book value since December 31,1996. Revenues Total operating revenues in 1997 decreased $7.0 million or 0.6 percent as compared to 1996. Comparing 1996 and 1995 operating revenues, there was an increase of $6.0 million or 0.5 percent. Increase (Decrease) from Prior Year (Revenues in Millions ofDollars) 1997 l996 KWii Revenues KWH Revenues Residential (1.6)% $ 0.5 (1.7)% $ (8.9) Commercial (0.7)% 5.2 0.1 % (2.1) Industrial 6.5 % 8.0 1.5 % 0.0 Less: Provision for Doubtful Accounts 0.4 (2.8) Sales to Electric Utility Customers 1.0 % 13.3 0.0 % (8.2) Sales to Other Utilities (56.4)% (33.4) 11.3 % 2.3 Other Revenues 13.1 11.9 Total (11.1)% $ (7.0) 2.2 % $ 6.0 33
Sales to Electric Utility Customers Operating revenues are primarily derived from the Company's sales of electricity. Currently the PUC authorizes rates for electricity sales which are cost-based and are designed to recover the j l Company's operating expenses and investment in electric utility assets and to provide a return on the investment. Customer revenues fluctuate as a result of changes in sales volume and changes in j i fuel and other energy costs, as these costs are generally recoverable from customers through the l Energy Cost Rate Adjustment C!ause (ECR). Under current fuel cost recovery provisions, fuel revenues generally equal fuel expense, including the fuel component of purchased power, and do not affect net income. As required under the Customer Choice Act, the Company has filed with the PUC its plan addressing its proposed restructuring to operate in a competitive environment including unbundled charges for transmission, distribution, generation and a CTC. The Company cannot predict what rates the PUC will authorize in connection with these filings and the phase-in to competition. (See " Rate Matters" on page 38.) Sales to residential and commercial customers are influenced by weather conditions. Warmer summer and colder winter seasons lead to increased customer use of electricity for cooling cnd heating. Commercial sales are also affected by regional development. Sales to industrial customers are influenced by national and global economic conditions. 1997 Compared to 1996 In 199', net cvstomer revenues reflected on the statement of consolidated income increased $13.3 million or 1.2 percent from 1996. The variance can be attributed primarily to an increase in revenues to cover an increase in customer energy costs. The customer energy cost increase was $19.9 million. To a lesser extent, customer revenues were favorably impacted by an increase of 6.5 percent in industrial kilowatt hour (KWH) sales. Sales to a new customer, an industrial ! gas supplier, represent 64 percent of the increase, while the remaining increase is due to expansion of one of the Company's largest customers' manufacturing facilities. Residential and commercial f sales decreased 95,295 KWH when comparing 1997 and 1996 due to mild 1997 temperatures. Sales to the Company's 20 largest customers accounted for approximately 14 percent of customer j revenues in 1997,1996 and 1995. 1996 Compared to 1995: Net customer revenues decreased $8.2 million or 0.8 percent in 1996 l i compared to 1995. The variance can be attributed primarily to decreased residential customer KWH sales of 1.7 percent due to unseasonably warm summer temperatures in 1995, as compared to 1996, resulting in decreased revenues of $8.9 million. Industrial KWH sales volume in 1996 increased when compared to the prior year because of a self-generation outage experienced in 1996 by one of the Company's large industrial customers. Sales to Other Utilities Short-term sales to other utilities are regulated by the FERC and are made at market rates. Fluctuations in electricity sales to other utilities are related to the Company's customer energy requirements, the energy market and transmission conditions, and the availability of the Company's j generating stations. Future levels of short-term sales to other utilities will be affected by market rates. j J 1997 Compared to 1996: The Company's electricity sales to other utilities in 1997 were
$33.4 million or 57.4 percent less than in 1996. The reduction is due to reauced availability of generating capacity as a result of the sale of the Company's 50 percent interest in the Ft. Martin Power Station (Ft. Martin) in October 1996 and to a 9.1 percent increase in other generating stations' outage hours when compared to 1996. .
1996 Compared to 1995: In 1996, electricity sales to other utilities were $2.3 million or 4.2 percent ) greater than in 1995 due to the timing of generating station outages. Other Operating Revenues , Other operating revenues include the Company's non-KWH utility revenues and revenues from market-based operating activities. 1997 Compared to 1996: The other operating revenue increase of $13.1 million or 14.2 percent when comparing 1997 to 1996 is the result of $20.4 million in revenues from a landfill gas recovery j investment made in the fourth quarter of 1996 and growth in the market-driven businesses, partially ) offset by decreased revenues as a result of the sale of Chester in the second quarter of 1997. 1996 Compared to 1995: The increase of $11.9 million or 14.7 percent in other operating revenues in 1996 as compared to 1995 is primarily due to increased revenues at Chester, then a wholly 1 j owned subsidiary of DE, and revenues of a landfill gas recovery investment made in the fourth quarter of 1996. l
\
J h
- - _ . - _ _ _____-______________________a
Operating Expenses Fuel and Pim hased Power Dpeme Fluctuations in fuel and purchased power expense generally result from changes in the cost of fuel, the mix between coal and nuclear generation, the total KWils sold, and generating station availability. Because of tia ECR, changes in fuel and purchased power costs did not impact earnings in 1997,1996 and 1995. Under the Company's mitigation plan approved by the PUC in June 1996, ; the level of energy cost recovery is capped at 1.47 cents per KWH through May 2001. Pending the outcome of the Company's Restructuring Plan or Stand-Alone Plan filing, the Company may freeze the ECR and roll it into base rates. (See " Rate Matters" on page 38). 1997 Compared to 1996: Fuel and purchased power expense decreased $13.5 million or 5.7 percent in 1997, as compared to 1996, as a result of an 11.1 percent reduction in energy volume supplied. The $26.7 million decrease due to energy volume supplied was partially offset by increased energy costs of $13.2 million, primarily the result of purchased power prices. Reduced availability of generating stations due to a 9.1 percent increase in outage hours forced the Company to buy purchased power during high demand periods,resulting in increased costs. 1996 Compared to 1995: The increase of $5.0 million or 2.1 percent in 1996 as compared to 1995 was the result of a 33 percent increase in purchased power prices. This increase was partially offset by lower nuclear fuel costs. Other Operating & pense 1997 Compared to 199& The increase of $7.8 million or 2.6 percent in 1997 as compared to 1996 can be attributed to operating costs from a landfill gas recovery investment made in the fourth quarter of 1996 and growth in the market-driven businesses, partially oil' set by the reduced operating costs associated with Chester, which was sold during the second quarter of 1997. 1996 Compared to 1995 Other operating expense increased $6.0 million when comparing 1996 ; to 1995. The increase was the result of several factors, including a one-time lease charge, a full year j of expense for DES in 1996 and operating costs of a landfill gas secovery investment made in the ; fourth quarter of 1996. Maintenance Spense 1997 Comparrd to 1996: Maintenance exgnse increased $4.5 million or 5.7 percent. During 1997 there were approximately 21 percent more forced outage hours at nuclear stations than in 1996. 1996 Compared to 1995: Maintenance expense decreased 53.1 million or 3.8 percent in 1996 from 1995. The decrease was primarily due to lower maintenance outage costs as a result of fewer fossil station outages in 1996. Depreciation and Amortization & pense 1997 Compared to 1996: During 1997, depreciation and amortization expense increased
$19.9 million or 8.9 percent from 1996. The May 1,1996 increase in the Company's electric utility operations
- composite depreciation rate from 3.5 percent to 4.25 percent resulted in higher depreciation for the first four months of 1997; in addition, accelerated nuclear lease recovery, which began on May 1,1997, resulted in higher annualized amortization expense by $25 million.
Offsetting the increase by $8.5 million was the mid-1996 completion of the recovery of the investment in Perry Unit 2, the construction of which was abandoned by the Company in 1986. The remaining increase can be attributed to incremental depreciation for 1997 fixed asset additions and an increased level of nuclear decommissioning cost recognition. 1996 Compaird to 1995: Depreciation and amortization expense increased $20.4 million in 1996 when compared to 1995 primarily due to the increase in the Company's electric utility operations' composite depreciation rate from 3.5 percent to 4.25 percen effective May 1,1996. During the third quarter of 1996, the Company completed recovery of its investment in Perry Unit 2, the construction of which was abandoned by the Company in 1986. The resultant decrease in amonization expense was offset by the Company's increase in depreciation, as well as $9 million that was expensed related to the depreciation portion of deferred rate synchronization costs in conjunction v>ith the Company's 1996 PUC-approved mitigation plan. Taxes Other Than income Tues During 1997 and 1996, taxes other than income taxes decreased $3.4 million and $2.7 million, respectively, from the prior year, primarily due to the reduced West Virginia business and occupation taxes as a result of the sale of Ft. Martin in the fourth quarter of 1996. l l 2n L ----_ _ _ _ _ _ - - - - - - - - - - - - - - - - - - - -
I. ! i ! l Other income 1997 Compared to 1996: The Company increased other income significantly over 1996 levels. l A $56.0 million or 75.9 percent increase in other income resulted from long-tenn investment income, { j gains on the sale of Chester and Exide stock, and interest and dividend income from a higher level of short-tenn investments. The increase in long-term investment income of approximately $15 million ! was the result of investments made late in 1996 and throughout 1997. The Company invested approximately $180 million in lease investments in 1997. In the second quarter of 1997, Chester was sold for a pre-tax gain of approximately $12 million, net of estimated costs of the sale. In the fourth quarter of 1997, the Company's investment in Exide stock was sold for a pre-tax gain of approximately $11 million. 1996 Compared to 1995: The increase of $21.5 million in other income, when comparing 1996 and 1995, was primarily the result of income from long-tenn investments made during late 1995 and 1996. Interest and Other Charges 1997 Compared to 1996: Interest and other charges increased $5.4 million or 4.9 percent during 1997 as compared to 1996. The increase in 1997 was primarily the result of paying a full year of dividends in 1997 related to the Monthly Income Preferred Securities (MIPS) issued in May 1996. 1996 Compared to 1995t The increase in interest and other charges in 1996 from 1995 was
$2.7 million related to the MIPS issued in May 1996 and $2.5 million ofinterest on new term loans. The interest expense increase was offset by decreases from the retirement of long-term debt and preferred stock of subsidiaries during 1995.
Income 7 axes Income taxes were higher in 1997 as compared to 1996 by $8.4 million and lower in 1996 as compared to 1995 by $9.3 million. The 1997 variance was due to a higher level of taxable income primarily as a result of the gains recognized with the sale of Chester and Exide. In comparing 1996 and 1995, income taxes decreased primarily due to reduced taxable income. Liquidity and The Company's future liquidity and capital resources could be reduced as a result of the Ccpital Resources Restructuring Plan or Stand-Alone Plan currently before the PUC. The Company cannot predict the level of transition cost recovery that will be pennitted, the impact of any such recovery on the Company's capitalization and the continued compliance with the Company's debt covenants or whether internally generated cash will continue to meet or exceed the Company's capital requirements and dividend payments. (See " Rate Matters" on page 38.) Capital Expenditures The Company spent approximately $118.3 million in 1997, $101.2 million in 1996 and
$94.2 million in 1995 for cepital expenditures, of which $93.7 million in 1997, $88.5 million in 1996 and $78.7 million in 1995 was spent for electric utility construction. The remaining capital expenditures were related to the Company's market-driven businesses. The Company's capital expenditures for electric utility construction focus on improving and/or expanding electric utility generation, transmission and distribution systems. The Company cunently estimates that it will spend, excluding allowance for funds used during constmetion ( AFC) and nuclear fuel, approximately
$130 million during 1998 and $100 million in each of 1999 and 2000 for electric utility construction.
In 1997, the Company fonned a strategic alliance with CQ Inc. to pnxluce E-Fuel , a coal-based synthetic fuel. The Erst six plants to produce E-Fuel are under construction and are expected to be in operation by mid-1998. The Company estimates the cost of this construction to be approximately
$25 million in 1998.
Iamg-Term investments The Company has made long-term investments in the following areas: leases, affordable housing, gas reserves, energy solutions and water companies. Investing activities during 1997 included approximately $180 million in lease investments, $11 million in landfill gas reserve investments,
$16 million in affordable housing investments, and $12 million in the decommissioning trust fund and other investments. During 1997, the Company committed to approximately $5 million in equity funding obligations for lease investments. Investing activities during 1996 included approximately
$50 million in lease investments, $30 million in gas reserve investments, $15 million in affordable housing investments, and $6 million in energy solution and other investments. During 1996, the Company also committed to approximately $37 million in equity funding obligations for lease and affordable housing investments. The Company disposed of long-term leveraged lease assets totaling
$18 million during 1996. Investing activities of approximately $192 million during 1995 were balanced between investment types.
E
In 1997, the Company acquired 100 percent of the Class A Stock of AquaSource, Inc. (AquaSource), which was formed to acquire small and mid-sized water, wastewater and water services companies, with its initial focus in Texas. At December 31,1997, the Company had invested l approximately $7 million (of which approximately $1.5 million was in the form of DQE Preferred l Stock) to acquire the stock or assets of seven water, wastewater and water services companies. l In February 1998, the Company issued 159,732 shares of DQE Preferred Stock, representing an investment of approximately $16 million in a water company. The Company has committed approximately $24 million for additional investments in water, wastewater and water services l companies for the first quarter of 1998. In 1997, the Company entered into a partnership with MCI Communications Corporation. l The Company expects this partnership will lead to investment opportunities in the expanding telecommunications business. l The Company is also pursuing power project opportunities through several of its investments, including landfill gas investments and cenain leasehold investments, and its joint venture with Marathon Oil. I Financing The Company expects to meet its current obligations and debt maturities through the year 2002 with funds generated from operations and through new financings. At December 31,1997, the Company was in compliance with all of its debt covenants. Mortgage bonds in the amount of $35 million matured in February 1998 and were retired using available cash. In February 1998, the Company issued a notice of redemption of $100 million principal amount of its 8.75 percent mortgage bonds, originally due in May 2022. The redemption date is March 1998, and the redemption price is 106.5625 percent of the principal amount, plus interest accrued until redemption. The redemption is to be partially financed with the proceeds of the February 1998 issuance of $40 million principal amount of 6.45 percent mortgage bonds, due in Febnzary 2008. The Company anticipates additional financing of the redemption through the funher issuance of lower interest rate mortgage bonds. Mortgage bonds in the amount of $35 million and $5 million will mature in June and November 1998, respectively. The Company expects to retire these bonds with available cash or to refinance the bonds. The Company has $150 million in bank term loans outstanding at December 31,1997, with
$65 million maturing in 2000 and $85 million maturing in 2001.
In July 1997, the Company authorized and registered 1,000.000 shares of the DQE Preferred Stock, all with $100 liquidation preference, for use in connection with acquisitions by the Company of other businesses, assets or securities. (See "Long-Term Investments" discussion on page 36.) As of December 31,1997,15,480 shares of DQE Preferred Stock had been issued and were outstanding. An additional 159,732 shares of DQE Preferred Stock were issued in February 1998. In October 1997, a Duquesne subsidiary issued ten shares of preferred stock, par value $100,(XX) per share. The holders of such shares are entitled to a 6.5 percent annual dividend to be paid each September 30. In May 1996, Duquesne Capital LP. (Duquesne Capital), a special-purpose limited partnership of which Duquesne is the sole general partner, issued $150.0 million principal amount of 8% percent MIPS with a stated liquidation value of $25.00.The holders of MIPS are entitled to annual dividends of 8X percent, payable monthly. Such dividends are guaranteed by Duquesne. Short-Term Borrowings At December 31,1997, the Company had two extendible revolving credit arrangements, including a $125 million facility expiring in June 1998 and a $150 million facility expiring in October 1998. Interest rates can, in accordance with the option selected at the time of the borrowing, be based on prime, Eurodollar or certificate of deposit rates. Commitment fees are based on the unborrowed amount of the commitments. Both credit facilities contain two-year repayment periods for any amounts outstanding at the expiration of the revolving credit periods. At December 31,1997 and December 31,1996, there were no short-term borrowings outstanding. l Sale ofAccounts Receirable The Company and an unaffiliated corporation have an agreement that entitles the Company to [ sell, and the corporation to purchase, on an ongoing basis, up to $50 million of accounts receivable. I The Company had no receivables sold at December 31,1997 or December 31,1996. The accounts f receivable sales agreement, which expires in June 1998, is one of many sources of funds available to the Company. The Company may attempt to extend the agreement, replace it with a similar facility, or eliminate it upon expiration.
*R
1 Nuclear Fuel Leasing The Company finances its acquisitions of nuclear fuel through a leasing arrangement under which it may finance up to $75 million of nuclear fuel. As of December 31,1997, the amount of nuclear fuel financed by the Company under this arrangement totaled approximately $46.2 million. f The actual nuclear fuel costs to be financed will be influenced by such factors as changes in interest rates; lengths of the respective fuel cycles; reload cycle design; operations; and changes in nuclear material costs and services. the prices and availability of which are not known at this time. Such costs may also be innuenced by other events not presently foreseen. The Company plans to continue leasing nuclear fuel to fulfill its requirements at least through September 1998, the remaining term of the leasing arrangement. The Company may attempt to extend the arrangement, replace it with a similar facility, or climinate it upon expiration through the purchase of the balance of the nuclear fuel. R1ts Matters Competition and the Customer Choice Act The electric utility industry continues to undergo fundamental change in response to development of open transmission access and increased availability of energy alternatives. Under historical ratemaking practice, regulated electric utilities were granted exclusive geographic franchises to sell electricity in exchange for making investments and incurring obligations to serve customers under the then-existing regulatory framework. Through the raterraking process, those prudently incurred costs were recovered from customers along with a return on the investment. Additionally, certain operating costs were approved for deferral for future recovery from customers (regulatory assets). As a result of this historical ratemaking process, utilities have assets recorded on their balance sheets at above-market costs, thus creating transition or stranded costs. in Pennsylvania, the Customer Choice Act went into effect January 1,1997. The Customer Choice Act enables Pennsylvania's electric utility customers to purchase electricity at market prices from a variety of electric generation suppliers (customer choice). Although the Customer Choice Act will give customers their choice of electric eneration suppliers, delivery of the electricity from the generation supplier to the customer will remain the responsibility of the existing franchised utility. The Customer Choice Act also provides that the existing franchised utility may recover, through a CTC, an amount of transition or stranded costs that are determined by the PUC to be just and reasonable. Pennsylvania's electric utility restructuring is being accomplished through a two-stage process consisting of an initial customer choice pilot period (running through 1998) and a phase-in to competition period (beginning in 1999). For the Hrst stage, the Company filed a pilot program with the PUC on February 27,1997. For the second stage, the Company filed on August 1,1997 its restructuring and merger plan (the Restructuring Plan) and its stand-alone restructuring plan (the Stand-Alone Plan) with the PUC. (See the detailed discussion of these plans on pages 40 and 41.) Customer Choice Pilots The pilot period gives utilities an opportunity to examine a wide range of technical and administrative details related to competitive markets, including metering, billing, and cost and design of unbundled electric services.The Company pilot filing proposed unbundling transmission, distribution, generation and competitive transition charges and offered participating customers the same options that were to be available in a competitive generation market. The pilot was designed to comprise approximately 5 percent of the Company's residential, commercial and industrial demand. The 28,000 customers participating in the pilot may choose unbundled service, with their electricity provided by an alternative generation supplier, and will be subject to unbundled distribution and CTC charges approved by the PUC and unbundled transmission charges pursuant to the Company's FERC-approved tariff. On May 9,1997, the PUC issued a Preliminary Opinion and Order approving the Companyi filing in part, and requiring certain revisions. The Company and other utilities objected to several features of the PUC's Preliminary Opinion and Order. Hearings on several key issues were held in July. The PUC issued its final order on August 29,1997, approving a revised pilot program for the Company. On September 8,1997, the Company appealed the determination of the market price of generation set forth in this order to the Commonwealth Court of Pennsylvania. The Company expects a hearing to be scheduled for mid-1998. Although this appeal is pending, the Company complied with the PUC's order to implement the pilot program that began on November 3,1997. Financialimpact of Pilot Program Order it is anticipated that the net financial impact of the Company's customers' choosing alternative generation suppliers during the pilot period (through 1998) will be a reduction of operating revenues of approximately $1 million per month. (See " Forward-Looking Statements" discussion on page 42.) The Company is seeking in its Restructuring Plan and its Stand-Alone Plan to maintain current rates under Section 2804(4)(v) of the Customer Choice Act (Rate Cap Provision), which
.a
1 states that in certain circumstances an electric distribution utility may roll its energy cost rate into base rates without reducing its rates below the capped level if the PUC determines that excess earnings are to be used for mitigation of transition costs. The Company will reduce its accelerated nuclear lease amortization to offset the shortfall, if any, in operating revenues between the pilot program and the final approved rates. Phase-In to Competition The phase-in to competition begins on January 1,1999, when 33 percent of customers will have customer choice (including customers covered by the pilot program); 66 percent of customers will have customer choice no later than January 1,2000; and a!i customers will have customer choice no later than January 1,2001. However, in its sole order to date (the PECO Order), the PUC ordered the phase-in provisions of the Customer Choice Act to require the acceleration of the second and third phases to January 2,1999 and January 2,2000, respectively. As they ore phased-in, customers I that have chosen an electricity generation supplier other than the Company will pay that supplier l for generation charges, and will pay the Company a CTC (discussed below) and unbundled charges for transmission and distribution. Customers that continue to buy their generation from the Company will pay for their service at current regulated tariff rates divided into unbundled generation, transmission and distribution charges. The PECO Order concluded that under the Customer Choice Act, an electric distribution company, such as Duquesne is to remain a regulated utility and may only offer PUC-approved, tariffed rates (including unbundled generation rates). Delivery of electricity (including transmission. distribution and customer service) will continue to be regulated in substantially the same manner as under current regulation. Rate Cap and Transition Cost Recovery Before the phase-in to customer choice begins in 1999, the PUC expects utilities to take vigorous steps to mitigate transition costs as much as possible without increasing the rates they currently charge customers. The Company has mitigated in excess of $350 million of transition costs during the past three years through accelerated annual depreciation and a one-time write-down of nuclear generating station costs, accelerated recognition of nuclear lease costs, increased nuclear decommissioning funding, and amortization of various regulatory assets. This relative level of transition cost reduction, while holding rates constant, is unmatched within Pennsylvania. The PUC will determine what portion of a utility's transition or stranded costs that remain at January 1,1999 will be recoverable through a CTC from customers. The CTC recovery period could last through 2005, providing a utility a total of up to nine years beginning January 1,1997 to recover transition costs, unless this period is extended as part of a utility's PUC-approsed transition plan. An overall four-and-one-half-year rate cap from January 1,1997 will be imposed on the transmission and distribution charges of electric utility companies. Additionally, electric utility companies may not increase the generation price component of rates as long as transition costs are being recovered, with certain exceptions. Following is a summary of the Company's requested transition cost recovery, net of deferred taxes, as of January 1.1999; the related net balances as of December 31,1997; and the amounts mitigated during the past three years. Transition Costs Mitigation Balance CTC Recovery (Amounts in Millions of Dollars) 1/l/95 - 12/31/97 12/31/97 Requested 1/1/94 Nuclear generation plant (a) $232 $ 968 $ 877 Fossil generation plant (a) - 541 541 Generation-related regulatory assets (b) 103 382 357 Decommissioning costs (c) 18 133 124 Total $353 $2.024 $1,899 I (a) Nuclear and fossil generation plant represent a projection of the amount by w hich the net book value, including materials and supplies inventories, and fuel inventories, of the generating plants exceeds the market value for these plants. " Nuclear generation plant" also includes the present value of future above-market lease payments related to the sale / leaseback of BV Unit 2. (b) Generation-related regulatory assets represert costs which under the historical ratemaking process were deemed recoverable from customers through future rates. These regulatory assets include, among other items, amounts related to future federal income tax payments, premiums paid to reacquire debt, initial operating costs of BV Unit 2 and Perry Unit 1, and enerFy costs not recovered currently. (c) Decommissioning costs represent the estimated present value of unfunded fossil and nuclear generation plant [ decommissioning costs. C_________._._____.__
f l Financial Exposure to Transition Cost Recorcry Any estimate of the ultimate level of transition costs (including those set forth in the table on page 39) depends on, among other things, the extent to which such costs are deemed recoverable l by the PUC; the ongoing level of the Company's costs of operations; regional and national economic l conditions; and growth of the Company's sales. The Company believes that it is entitled to recover substantially all of its transition costs, but cannot predict the outcome of this regelatory process. (See " Forward-L(xiking Statements" discussion on page 42.) Indeed, the PECO Order provides for recus ery by PECO Energy Company (PECO) of 100 percent of transition costs determined to be just and reasonable by the PUC. Ilowes er, in determining transition costs, the PUC found the market value of PECO's generating units to be significantly higher than the estimate of market value sponsored by PECO. Thus, the total amount of transition costs requested by PECO was significantly more than that allowed by the PUC in the PECO Order, as the PUC-determined market value off-set a larger portion of the transition costs. The PUC-ordered recovery of PECO's transition costs through a CTC is permitted over an eight-and-one-half-year period beginning January 1,1999. Ilowever, PECO is only permitted to earn a return on the unamortized balance of transition costs at a rate equal ;o its long-term cost of debt. In the event that the PUC rules that any or all of the Company's transition costs cannot be recovered through a CTC mechanism, or the Company fails to satisfy the requirements of SFAS No. 71, these costs will be written off. (See " Regulation" discussion on page 31.) On January 26,1998, PECO announced that it was reducing its dividend by 44 percent, and also that it was reporting a net loss for 1997 of $1.5 billion. including an extra-ordinary charge of $3.1 billion (51.8 billion net of taxes)in the fourth quarter of 1997 to reflect the effects of the PECO Order. As the Company has substantial exposure to transition costs relative to its size, significant transition cost write-olTs could have a materially adverse effect on the Company's financial position, results of operations and cash flows. Various financial covenants and restrictions could be violated if substantial write-off of assets or recognition of liabilities occurs. Under such circumstances the Company may face constraints on its ability to pay dividends (See " Earnings and Dividends" discussion on page 32), issue new mortgage debt or maintain access to bank lines of credit, thus negatively impacting its operations. Timetablefor Restructuring Plan and Stand-Alone Plan Approval On August I,1997, the Company filed the Restructuring Plan and the Stand-Alone Plan with the PUC. Although the provisions of the Customer Choice Act require a PUC decision nine months from the filing date (which would be April 30,1998), the Pennsylvania Attorney General's Office requested an extension in order to conduct an investigation into certain competition issues relating to the Restructuring Plan. Pursuant to an arrangement among the Company, the PUC and the Attorney General, the Company anticipates a decision by the PUC (with respect to the Restructuring Plan if the merger is approved, or with respect to the Stand-Alone Plan if the merger is not approsed) on or before May 29,1998 or such later date as the parties may agree. Stand-Alone Plan in the event the merger with AYE is not consummated under the filed Restructuring Plan, the Company has sought approsal for restructuring and recosery of its ow n transition costs through a CTC under the Stand-Alone Plan. The Company proposed that any finding of market value for the Company's generating assets should be based on market evidence and not on an administrative determination of that salue based on price forecasts (the PECO Order determined the market value of PECO's generation based on the price forecast sponsored by the Pennglsania Office of Consumer Advocate). In addition, the Company proposed that such a final market valuation be j conducted in 2(X)3. and that an annual competitive market solicitation be used to set the CTC in the interim. The 2003 final market valuation w ould be performed by an independent panel of experts using the best available market evidence at that time. The Stand-Alone Plan filing also provided for certain triggers that would accelerate the date of this final market valuation. Prior to the final valuation, the Company w ould sell a substantial amount of power to the highest bidder in an annual i competitive sohcitation. The annual market price established by the solicitation would be used to set competitive generation credits and determine the CTC as a residual from the generation rate cap under the Rate Cap Provision. During the transition period, the Company committed b accelerate j amortization and depreciation of its generation-related assets and cap its return on equity through a return on equity spillover mechanism,in exchange for being allowed to charge existing rates under
)
the Rate Cap Provision. The Company committed to a minimum of 51.7 billion of amortization and depreciation of generation related assets by the end of 2005. Under the proposed return on equity spillover mechanism, additional amortization and depreciation in excess of this minimum
$1.7 billion commitment would be recorded in order to comply with the return on equity cap. The generation rate cap would apply to the sum of the CTC and the competitive generation credit
e determined in the annual competitive solicitation. The Stand-Alone Plan also proposed to redesign individual tariffs to encourage more efficient consumption and further mitigate transition costs during the transition period. Consistent with the Company's long standing commitment to economic development. the rate redesign provides for a significant reduction in the cost of electricity for inen mental consumption. Application of the rate redesign to the CTC would also have the potential to maximize mitigation of transition costs during the transition period. As an alternative to a market-based valuation in 2003, if the PUC finds that a determination of market value as of December 31,1998 is required by the Customer Choice Act, then the Company has agreed that the PUC may order an immediate auction of the Company's generation at that time. Restructuring Plan The Restructuring Plan incorporates the benefits of the merger with AYE, such as anti < qAd savings to the Company, on a nominal basis, of $365 million in generation-related costs over 20 years, ard $9 million in transmission-related costs and $173 million in distribution-related costs over 10 years. The Company plans to use the generation-related portion of its share of net operating synergy savings to shorten the transition cost recovery period. In addition, the anticipated cost savings are expected to permit the Company to increase its minimum depreciation and amortization commitment by $160 million, reduce distribution rates by $25 million in 2001, arid freeze distribution rates at this reduced level until 2005. The merger-related synergies are expected to enable the Company to reduce its transition costs in 2005 by $200 million. (See " Forward-Looking Statements" discussion on page 42.) The Restructuring Plan also incorporates the market-based approach to determining stranded costs proposed by the Company in its Stand-Alone Plan. The 2003 final market valuation will be performed by an independent panel of experts using the best available market evidence at that time, including a potential sale of a portion of the combined company's generating assets. Certain triggers will accelerate the date of this final market valuation if market prices rise significantly or the minimum amortization commitmeat is satisfied prior to 2003. %e annual market price established by the Company's solicitation wouM be used to set competitive generation credits and to determine the CTC as a residual from the generation rate cap under the Rate Cap Provision. The Company's minimum amortization commitment of $1.7 billion in the proposed Stand-Alone Plan has been increased under the Restructuring Plan. As in the Stand-Alone Plan, the determination of transition costs in 2003 will compare the book value of generating assets in 2005 (after netting the increased minimum commitment to depreciation and amortization and any return on equity spillover) with the market value of the - ' mets in 2005. The opposing parties beliese that there should be a one-time - .an of the gene ting assets performed at January 1,1999. Any merger-related syr:rgie- . mg u _ ~ ration auld then be used to reduce the Company's transition costs as of that d< P parties a. _ .aeve that the Company's proposed distribution rate decrease should be cil .ti Jary 1,1999, as well. AdditionalRestructuring
- m s nns *s ;
The Restructuring Plan . m er mber of commitments by the merged DQE/AYE entity. ! First, the merged entity wih m A mission system to all parties on a reciprocal non-discriminatory basis and elimi
~
< ate charges across the combined transmission system.
Second, the merged entity will ju .u, smposed Midwest Independent System Operator (150) or other then-existing ISO, or forr. ts < n ISO if no existing ISO offers acceptable rules. including marginal cost transmission rat .F cral utilities have applications pending before the FERC to form ISOs. Third, the merged em .y has committed to make a report,18 months after consummation of the merger, to the PLIC regarding its progress on the ISO commitment. The PUC may, at its option, require the merged entity to relinquish control of 300 MW of generating capacity to alleviate concerns over market power.The form of relinquishment would be at the option of the merged entity; possible forms of relinquishment include an energy swap, entering a power sale contract, divestiture of generating assets and a biddir,3 trust. The FederalFilings l In addition to the PUC filings of the Restructuring Plan and the Stand-Alone Plan, on August 1, i 1997, the Company and AYE filed their joint merger application with the FERC (the FERC Filing). Pursuant to the FERC Filing, the Company and AYE have committed to forming or joining an ISO that meets the entity's requirements, including marginal cost transmission pricing, following the merger. In addition, the Company and AYE have stated in the FERC Filing that following the merger the combined entity's market share will not violate th narket power conditions and requirements set by the FERC. On January 20,1998, the Compmy and AYE filed merger applications with the Antitrust Division of the Department of Justice and the Federal Trade Commission. These applications are currently pending. L______-__--_ _. N c
1 Forward-inoking Statements l The foregoing paragraphs contain forward-looking statements (within the meaning of the Private Securities Litigation Reform Act of1995) regarding the financial impact, consequences and benefits of the Customer Choice Act, the pilot program, the Stand-Alone Plan, the Restructuring Plan and the merger with AYE. Such forward-looking statements involve known and unknown risks and uncertainties that may cause the actual results and benefits to materially differ from those implied by such statements. Such risks and uncertainties include, but are not limited to, the substance of PUC approvals regarding the Starid-Alone Plan or the Restructuring Plan, general economic and business conditions, industry capacity, changes in technology, integration of the operations of AYE ! and the Company, regulatory conditions to the merger, the loss of any significant customers, and changes in business strategy or development plans, Proputy, Plant and investment in PP&E and Accumulated Depreciation Equipment (PP&E) The Company's total investment in property, plant and equipmetit and the related accumulated depreciation balances for major classes of property at December 31,1997 and 1996, are as follows: PP&E and Related Accumulated Depreciation at December 31 (Amounts in Thousands of Dollars) 1997 1996 . Accumulated Net Accumulated Net I investment Depreciation Investment Imestment Depreciation Investment Electric Production $2,494,476 $1J75,516 $1,318,960 $2.467,786 $1,092,928 $1,374,858 298,614 119,895 178,719 299,895 114,406 185,489 Electric Transmission Electric Distribution 1,206,546 390,103 816,443 1,176,738 374,180 802.558 334,565 192,439 142,126 324.366 168.470 155,896 Electric General Property IIeld for Future Use (a) 3,980 66 3,914 190.821 82,737 108,084 Property Held Under Capitalleases 113,662 50,725 62,937 99,608 47,670 51,938 Other 173,2H5 34,tn50 139,235 228.256 89.554 138.702 Total $4,625,128 $1,962,794 $2.662,334 $4,787,470 $1,%9,945 $2,817.525 (a) See " Property field for Future Use" discussion on page 43. Joint interests in Generating Units The Company has various contracts with subsidiaries of FirstEnergy Corporation (Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company (CEI) and The Toledo Edison Company), with respect to several jointly owned / leased generating units, that include provisions for coordinated maintenance responsibilities, limited and qualified mutual back-up in the event of outages, and certain capacity and energy transactions. In September 1995, the Company commenced arbitration against CEl, seeking damages, tennination of the Operating Agreement for Eastlake Unit 5 (Eastlake) and partition of the parties' interests in Eastlake through a sale and division of the proceeds. The arbitration demand alleged, among other things, the improper allocation by CEI of fuel and related costs; the mismanagement of the administration of the Saginaw coal contract in connection with the closing of the Saginaw ' mine, which historically supplied coal to Eastlake; and the concealment by CEI of material information. CEI also seeks monetary damages from the Company for alleged unpaid joint costs in connection with the operation of Eastlake. The Company removed the action to the United States District Coun for the Northern District of Ohio, Eastern Division, where it is now pending. Currently, the patties are engaged in settlement discussions. The Company anticipates that a trial will commence late m 1998. Joint Interests in Power Stations Nuclear Power Stations Heaver Valley Perry Unit 1 Unit 2 Unit 1 Duquesne
- 47.50%
- 13.74% (a) 13.74 %
FirstEnergy Corporation 52.50% 86.269
- 86.26 %
Fossil Power Stations Sammis Bruce Mansfield Eastlake Unit 7 Unit 1 Unit 2 Unit 3 Unit 5 Duquesne 31.20 % 29.30 % 8.00% 13.74 % 31.20 % FirstEnergy Corporation
- 68.80 %
- 70.70 %
- 92.00 %
- 86.26 %
- 68.80 %
- Denotes Operator (a) In 1987, the Company sold and leased back its 13.74 percent interest in BV Unit 2. The Company leased back its interest in the unit for a term of 29.5 years. The lease is accounted for as an operating lease. l l
l - i t Property Heldfor Future Use In 1986, the PUC approved the Company's request to remove Phillips Power Station (Phillips) I and a portion of Brunot Island (BI) from service. These assets were classified as property held for future use. In 1997, through its analysis of customer choice in the Restructuring Plan and Stand-Alone Plan, the Company determined that Phillips and a portion of B1 would not be cost-effective in the production of electricity in the face of a competitive marketplace. Based on this analysis, Phillips and a portion of BI have been reclassified on the balance sheet from property held for future use to a regulatory asset. In each of the filings, the Company is seeking recovery ofits investment and associated costs of Phillips and Bl through a CTC. (See " Rate Matters" on page 38.) Employees At December 31,1997, the Company had 3,465 employees, including 1,114 employees at the Company-operated Beaver Valley Power Station (BVPS). The Company is party to a labor contract expiring in September 2001 with the International Brotherhood of Electrical Workers, which represents approximately 2,000 of the Company's employees. The contract provides, among other things, employment security, income protection and 3 percent annual wage increases through September 2000. Electric Utility The Company's fossil plants operated at an equivalent availability factor of 78 percent in 1997 Operations and 76 percent in 1996. The Company's nuclear plants operated at an equivalent availability factor of 67 percent in 1997 and 76 percent in 1996. BV Unit I went off-line on September 27,1997, for a scheduled refueling outage, and returned to service on January 21,1998. Perry Unit I completed a refueling outage on October 23,1997. This outage lasted 40 days, a record for Perry Unit 1. The next refueling outage for BV Unit 1 is currently scheduled to begin in April 1999. The next refueling outages for BV Unit 2 and Perry Unit I are currently scheduled to begin in September 1998 and March 1999, respectively. The timing and duration of scheduled maintenance and refueling outages, as well as the duration of forced outages, affect the availability of power stations. The Company normally experiences its peak demand in the summer. De 1997 and all-time customer system peak demand of 2,671 MW occurred on July 15,1997. BV Unit I went off-line January 30,1998, due to an issue identified in a technical review recently completed by the Company. BV Unit 2 went off-line December 16,1997, to repair the emergency air supply system to the control room and has remained off-line due to other issues identified by a similar technical review of BV Unit 2. These technical reviews are in response to a 1997 commitment made by the Company to the NRC. The Company is one of many utilities faced with these technical issues, some of which date back to the original design of BVPS. Both BVPS units remain off-line for a revalidation of technical specification surveillance testing requirements of various plant systems. Based on the current status of the revalidation process, the Company currently anticipates that both BVPS units will remain off-line through March 1998. BVPS's two units are equipped with steam generators designed and built by Westinghouse Electric Corporation (Westinghouse). Similar to other Westinghouse nuclear plants, outside diameter stress corrosion cracking (ODSCC) has occurred in the steam generator tubes of both units. The units continue to operate at 100 percent reactor power, although approximately 17 percent of BV Unit 1 and 2 percent of BV Unit 2 steam generator tubes have been removed from service. Material acceleration in the rate of ODSCC could lead to a loss in plant efficiency and significant repairs or replacement of BV Unit I steam generators. The total replacement cost of the BV Unit I steam generators is estimated at $125 million, $59 million of which would be the Company's responsibility.The earliest that the BV Unit I steam generators could be replaced during a scheduled refueling outage is the fall of 2000. Fossil Fuel The Company believes that sufficient coal for its coal-fired generating units will be available frcm various sources to satisfy its requirements for the foreseeable future. During 1997, approximately 2.3 million tons of coal were consumed at the Company's two wholly owned coal-fired stations, Cheswick Power Station (Cheswick) and Elrama Power Station (Elrama). The Company owns Warwick Mine, an underground mine located in southwestern Pennsylvania. At December 31,1997, the Company's net investment in the mine was $10.7 million.The Company estimates that, at December 31,1997, its economically recoverable coal reserves at Warwick Mine were in excess of 1.5 million tons. An unaffiliated contract operator at Warwick Mine encountered adverse geologic conditions late in 1996 that resulted in a contract default. Commencing in 1997, a new unaffiliated operator began producing approximately 360,000 tons of coal per year, for exclusive use at Elrama. The Company purchases the remaining coal for use at Elrama on the open market. The current estimated liability for mine closing, including final site reclamation, mine water treatment and certain labor liabilities is $47.6 million, and the Company has recorded a liability on the consolidated balance sheet of approximately $27.5 million toward these costs. n
During 1997,34 percent of the Company's coal supplies were provided by contracts, including Warwick Mine, with the remainder satisGed through purchases on the spot market. The Company had three long-term contracts in effect at December 31,1997 that, in combination with spot market purchases, are expected to furnish an adequate future coal supply. The Company does not anticipate any difficulty in replacing or renewing these contracts as they expire from 2000 through 2005. At December 31,1997, the Company's wholly owned and jointly owned generating units had on hand an average coal supply of 41 days. Nuclear Fuel The cycle of production and utilization of nuclear f uel consists of (1) mining and milling of uranium ore and processing the ore into uranium concentrates, (2) converting uranium concentrates to uranium hexafluoride, (3) enriching the uranium hexauuoride, (4) fabricating fuel assemblies, (5) utilizing the nuclear fuel in the generating station reactor, and (6) storing and disposing of spent fuel. An adequate supply of uranium is under contract to meet the Company's requirements for its jointly owned / leased nuclear units through 2000. An adequate supply of conversion services through the year 2002 is also under contract. Enrichment serviccs for the Company's joint interests in BV Units I and 2 and Perry Unit I will be supplied through fiscal year 1999 under a United States Enrichment Corporation (USEC) Utility Services contract. The Company has terminated, at zero cost, all of its enrichment services requirements under this contract for the fiscal years 2000 through 2005 and is planning to secure required enrichment services during this period from other suppliers. The Company continues to review on an annual basis its alternatives for enrichment services for the years 2006 through 2014 under the USEC contract and may terminate these future years if it can arrange more cost-effective enrichment services. Fuel fabrication contracts are in place to supply reload requirements through 2002 and 2003 respectively, for BV Unit I and BV Unit 2 and the life of plant for Perry Unit 1. The Company will continue to make arrangements for future uranium supply and related services, as required. (See " Nuclear Fuel Leasing" discussion on page 38.) Nuclear The Company expects to decommission BV Unit 1, BV Unit 2 and Perry Unit I no earlier than Deosmmissioning the expiration of each plant's operating license in 2016,2027 and 2026. At the end of its operating life BV Unit I may be placed in safe storage until BV Unit 2 is ready to be decommissioned, at which time the units may be decommissioned together. Based on site-specific studies conducted in 1997 for BV Unit I and BV Unit 2, and a 1997 update of the 1994 study for Perry Urit 1, the Company's approximate share of the total estimated decommissioning costs, including removal and decontamination costs, is $170 million, $55 million and $90 million, respectively. The amount currently being used to determine the Company's cost of service related to decommissioning all three nuclear units is $224 million. The Company is seeking recovery of any potential shonfall in decommissioning funding as part of either its Restructuring Plan or its Stand-Alone Plan. (See " Rate Matters" on page 38.) With respect to the transition to a competitive generation market, the Customer Choice Act requires that utilities include a plan to mitigate any shortfall in decommissioning trust fund payments for the life of the facility with any future decommissioning filings. Consistent with this requirement, in 1997 the Company increased its annual contributions to the decommissioning trusts by $5 million to approximately $9 million. The Company has received approval from the Internal Revenue Senice (IRS) for qualification of 100 percent of additional nuclear decommissioning trust funding for BV Unit 2 and Perry Unit 1, and 79 percent for BV Unit 1. Funding for nuclear decommissioning costs is deposited in external, segregated trust accounts and invested in a portfolio of corporate common stock and debt securities, municipal bonds, cenificates of deposit and United States government securities. The market value of the aggregate trust fund balances at December 31,1997 totaled approximately $47.1 million. Nuclear insurance The Price-Anderwn Amendments to the Atemic Energy Act ofl954 limit public liability from a single incident at a nuclear plant to $8.9 billkm. The maximum available private primary insurance of $200 million has been purchased by the Company. Additional protection of $8.7 billion would be provided by an assessment of up to $79.3 million per incident on each nuclear unit in the United States. The Company's maximum total possible assessment, $59.4 million, which is based on its ownership or leasehold interests in three nuclear generating units, would be limited to a maximum of $7.5 million per incident per year. This assessment is subject to indexing for inDation and may be subject to state premium taxes. If assessments from the nuclear industry prove insulTicient to pay claims, the United States Congress could impose other revenue-raising measures on the industry. The Company's share ofinsurance coverage for property damage, decommissioning and decontamination liability is $1.2 billion. The Company would be responsible for its share of any damages in excess of insurance coverage. In addition, if the property damage reserves of Nuclear
l 1 Electric Insurance Limited (NEIL), an industry mutual insurance company that provides a ponion I of this coverage, are inadequate to cover claims arising from an incident at any United States nuclear site covered by that insurer, the Company could be assessed retrospective premiums totaling a maximum of $5.8 million. i In addition, the Company participates in a NEIL program that provides insurance for the increased ) cost of generation and/or purchased power resulting from an accidental outage of a nuclear unit.
- Subject to the policy deductible, terms and limit, the coverage provides for a weekly indemnity of l the estimated incremental costs during the three-year period starting 21 weeks after an accident, with no coverage thereafter. If NEIL's losses for this program ever exceed its reserves, the Company could be assessed retrospective premiums totaling a maximum of $3.4 million.
l Spent Nuclear The Nuclear %ste Policy Act of1982 established a federal policy for handling and disposing of l Fuel Disposal spent nuclear fuel and a policy requiring the establishment of a final repository to accept spent i nuclear fuel. Electric utility companies have entered into contracts with the United States Depanment of Energy (DOE) for the permanent disposal of spent nuclear fuel and high-level radioactive waste in compliance with this legislation. The DOE has indicated that its repository under these contracts will not be available for acceptance of spent nuclear fuel before 2010. The DOE has not yet established an interim or permanent storage facility, despite a ruling by the United States Court of Appeals for the District of Columbia Circuit that the DOE was legally obligated to begin acceptance of spent nuclear fuel for disposal by January 31,1998. Existing on-site spent nuclear fuel storage capacities at BV Unit 1 BV Unit 2 and Perry Unit I are expected to be sufficient until 2017,2011 and 2011, respectively. In early 1997, the Company joined 35 other electric utilities and 46 states, state agencies and regulatory commissions in filing suit in the United States Court of Appeals for the District of Columbia Circuit against the DOE. The panies requested the coun to suspend the utilities
- payments into the Nuclear Waste Fund and to place future payments into an escrow account until the DOE fulfills its obligation to accept spent nuclear fuel. The DOE had requested that the court delay litigation while it pursued alternative dispute resolution under the terms ofits contracts with the utilities. The court ruling, issued November 14,1997, was not entirely in favor of the DOE or the utilities. The court pennitted the DOE to pursue alternative dispute resolution, but prohibited it from using its lack of a spent fuel repository as a defense. The DOE has requested a rehearing on the matter, which has yet to be scheduled.
Uranium Nuclear reactor licensees in the United States are assessed annually for the decontamination and Enrichment decommissioning of DOE uranium enrichment facilities. Assessments are based on the amount of Obligations uranium a utility had processed for enrichment prior to enactment of the National Energy Policy Act of1992 (NEPA) and are to be paid by such utilities over a 15-year period. At December 31,1997, the Company's liability for contributions was approximately $7.2 million (subject to an inflation adjustment). (See " Rate Matters" on page 38.) Environmental Various federal and state authorities regulate the Company with respect to air and water quality M;tters and other environmental matters. The Company believes it is in current compliance with all material applicable environmental regulations. The Comprehensive Envimnmental Response, Compensation and Liability Act of1980 and the Superfimd Amendments and Reauthorization Act of1986 (Superfund) established a variety of informational and environmental action programs. The Environmental Protection Agency (EPA) previously informed the Company of its potential involvement in three hazardous waste sites. The Company reached agreements to make de minimis financial settlements related to these sites in order to resolve any associated liability. Through its acquisition of GSF Energy (GSF), the Company indirectly became involved in three additional hazardous waste sites. GSF was a minor contributor of materials to each site, and other solvent potentially responsible parties are involved. GSF believes that available defenses, along with its overall limited involvement, will limit any potential liability it may have for clean-up costs. Additionally, as part of the GSF acquisition the Company is indemnified for any costs that it may incur related to these sites by at least one financially responsible party. Accordingly, the Company believes that these matters will not have a material adverse effect on its financial position, results of operations or cash flows. As required by Title V of the Clean Air Act Amendments (Clean Air Act), the Company filed comprehensive air operating permit applications for Cheswick, Elrama, B1 and Phillips during the last half of 1995. Approval is still pending for these applications. The Company filed its Title IV Phase 11 Clean Air Act compliance plan with the PUC on December 27,1995. The Company also filed Title IV Phase 11 permit applications for oxides of nitrogen (NOx) emissions from Cheswick, Elrama and Phillips with the Allegheny County Health Department and the Pennsylvania Department of Environmental Protection (DEP) on December 23,1997. E
Although the Company believes it has satisfied all of the Phase 1 Acid Rain Program requirements of the Clean Air Act, the Phase II Acid Rain Program requires significant additional reductions of sulfur dioxide (S02) and NOx by the year 2(X)0. The Company currently has 662 MW of nuclear f capacity and 887 MW of coal capacity equipped with SO: emission-reducing equipment (excluding 300 MW of regulatory assets at Phillips). Through the year 2(XX), the Company is considering a combination of compliance methods that include fuel switching; increased use of, and improvements in, SO; emission-reducing equipment; low NOs burner technology; and the purchase of emission ailowances for those remaining stations not in compliance. The Company has developed, patented and installed low NOs burner technology for the Elrama boilers. These cost-effective NOx reduction systems installed on the Elrama roof-fired boilers were specified as the benchmark for the industry for this class of boilers in the EPA's final Group 11 rulemaking. The Company is also currently evaluating additional low-cost. developmental NOx reduction technologies at Cheswick. In 1997 the Ccmpany tested combustion-related NOx controls at Cheswick, with positive results, and expects to install low-cost modifications and a new flue gas conditioning system to maximize the effects of such controls. In addition to the Phase II Acid Rain Program requirements, the Company is responsible for additional NOx reduction requirements to meet the current Ozone Ambient Air Quality Standards under Title 1 of the Clean Air Act. Compliance with the current ozone standard is based on pre-1997 ozone data using a one-hour average value approach. Flue gas conditioning and post-combustion NOx reduction tecimologies may be employed to meet the one-hour standard if economically justified. Also, the Company is examining and developing innovative emissions technologies designed to reduce costs. The Company also continues to work with the operators of its jointly owned stations to implement cost-effective compliance strategies to meet these requirements. The Company is closely monitoring other future air quality programs and air emission control requirements that could result from more stringent ambient air quality and emission standards for 502 and NOx particulate and other by-products of coal combustion. In 1997 the DEP finalized a regulation to implement the additional NOx control requirements that were recommended by the Ozone Transport Commission. The estimated costs to comply with this program have been included in the Company's capital cost estimates through the year 2000. The Company currently estimates that additional capital costs to comply with Clean Air Act requirements through the year 20(X) will be approximately $20 million, in July 1997, the EPA announced new national ambient air quality standards for ozone and fine particulate matter. To allow each state time to determine what areas may not meet the standards and to adopt control strategies to achieve compliance, the ozone standards will not be implemented until 2004, and the fine particulate matter standards will not be implemented until 2007 or later. Because appropriate state ambient air monitoring and implementation plans have not been developed, the costs of compliance with these new standards cannot be determined by the Company at this time. In December 1997, more than 160 nations reached a preliminary agreement (Kyoto Protocol), under which, among other things, the United States would be required to reduce its greenhouse gas emissions during the years 2008 through 2012. However, as the Kyoto Protocol has yet to be either signed or ratified, and the related greenhouse gas reducti on programs remain undeveloped, the costs of compliance cannot be determined by the Company at this time. In 1992, the DEP issued Residual Waste Management Regulations governing the generation and management of non-hazardous residual waste, such as coal ash. The Company is assessing the sites it utilizes and has developed compliance strategies that are currently under review by the DEP. Capital costs of $2.8 million were incurred by the Company in 1997 to comply with these DEP regulations. Based on information currently available, approximately $8 million will be spent in 1998. The additional capital cost of compliance through the year 2000 is estimated, based on current information, to be approximately $16 million. This estimate is subject to the results of groundwater assessments and DEP final approval of compliance plans. The Company is involved in various other environmental matters. The Company believes that such matters, in total, will not have a materially adverse effect on its financial position, results of operations or cash flows. Other Customer Advanced Reliability System The Customer Advanced Reliability System (CARS) is a communications service that provides the Company with an electronic link to its customers, including the ability to read customer meters. In September 1997, the Company amended its service contract with Itron, Inc., with respect to CARS. The amendment extends by one year, into 1998, the period during which bron, Inc., will install and finalize the system. As of December 31,1997, more than 98 percent of customers' meters had been adapted for CARS, and more than 450,000 meters were being read automatically.
1 ear 2000 Many existing computer programs use only two digits to identify a year (for example, "98" is used to represent "1998"). Suen programs read "00" as the year 1900, and thus may not recognize dates beginning with the year 2000, or may otherwise produce erroneous results or cease processing when dates after 1999 are encountered. Such failures could cause disruptions in normal business operations. In 1994. the Company inventoried and assessed the critical information systems that impact operations and financial reporting (including systems with respect to the general ledger, supply chain, billing, payroll human resources, financial reporting and certain types of data for plant maintenance) in order to develop a strategy to address required computer software changes and upgrades relating to such operations. By 1995, a nian to test and, as necessary, replace, upgrade or repair these systems had been developed and implementation had begun, with an anticipated completion date in 1999. Although implementadon of the plan has been accelerated in certain respects by Year 2(XX) issues, the planned rep!acement, upgrade and repair of the systems is also generally required for business purposes unrelated to the Year 2000 issue. The Company currently believes that implementation of the plan will minimize its Year 2000 issues relating to these systems. Replacement, upgrade and repair projects that have been completed or are currently in progress include, without limitation, the replacement of an integrated plant maintenance system at BVPS tincluding related computer hardware), replacement of the supply chain (purchasing and inventory) system, and release upgrades of packaged software for the corporate financial recordkeeping system. The cost of all such projects is currently estimated to be $35 million, approximately one-half of
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which had been incurred ttuough 1997. Duquesne has been expensing or capitalizing such costs in accordance with appropriate accounting policies. The Company has assembled a team to inventory and assess the Year 2000 issues that impact it. The team is comprised of management representatives from all functional areas of the Company's businesses. In addition to monitoring the informMion systems plan described above, the goals of the team include an assessment of the Company's exposure to Year 2000-related problems in devices and equipment containing embedded microprocessors that may not correctly identify the year, as well as potential problems that may originate with third parties outside the Company's control. The Company also participates in the Electric Power Research Institute's project to share information about technical issues regarding the Year 2000 problem with other entities in the electric utility industry. Given the fact that the Company's assessment, as noted above,is currently in progress, the Company cannot currently estimate the exact extent of any outstanding Year 2000 systems and equipment issues, the specific time frame in which any required corrections would need to be made and the costs to the Company in correcting any possible related outstanding matters. Until the Company's assessment is comple:cd, it cannot determine whether Year 2000 issues and related costs will be material to the Company's operations, f'mancial condition and results of operations. Retirement Plan Measurement Assumptions The Company decreased the discount rate used to determine the projected benefit obligation on the Company's retirement plans at December 31,1997 to 7.0 percent. The assumed change in future compensation levels and assumed rate of return on plan assets were also decreased to reflect current market and economic conditions. The effects of these changes on the Company's retirement plan obligations are reflected in the amour.ts shown in " Employee Benefits," Note M to the consolidated financial statements, on page 70. The resulting change in related expenses for subsequent years is not expected to be material. Recent Accounting Prorwuncements SFAS No.130, Reporting Comprehensive Income (SFAS No. I30) and SFAS No.131, Di.; closures about Segments of an Enterprise and Related Information (SFAS No.131), have been issued and are eftective for fiscal years beginning after December 15,1997. SFAS No.130 defines comprehensive income and < olines certain reponing and disclosure requirements related to comprehensive income. SFAS No.1s. requires cenain disclosures about business segments of an enterprise,if applicable. The adoption of SFAS No.130 and SFAS No.131 is not expected to have a significant impact on the Company's financial statements or disclosures.
~ / 75tMf$EhEdihIdinfo5udiE5NaidlErcin[tiMtcNiictissedin5is Mndsport'arifdrwardlb$1d h % statements which involve risks and uncensinties including, but not limited to, ecsomic, competitive, govermnen ,
M and technological factors affecting the Company's operations, markets, pmducts, services and prices and other factors .' Ediscussed in. the Company's filings with the Securitier and Exchange. Commission. wama -a-aa- a w.a .. - . . , w . . . 5
Report cf To the Directors and Shareholders qf DQE, Inc.: Independent We have audited the accompanying consolidated balance sheet of DQE, Inc. and its subsidiaries Certified Public as of December 31,1997 and 1996, and the related consolidated statements of income, retained Acc:untants earnings, and cash flows for each of the three years in the period ended December 31,1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of DQE, Inc. and its subsidiaries as of December 31,1997 and 1996, and the
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results n their operations and their cash flows for each of the three years in the period ended December 31,1997 in conformity with generally accepted accounting principles. O N Deloitte & Touche LLP pittsburgh, pennsylvania January 27,1998 I l Report of the The Audit Commitiee, composed entirely of non-employee directors, meets regularly with the Audit Committee independent certified public accountants and the internal auditors to discuss results of their audit of the Board of work, their evaluation of the adequacy of the internal accounting controls and the quality of financial Directors of DGE reporting. In fulfilling its responsibilities in 1997, the Audit Committee recommended to the Board of Directors, subject to shareholder approval, the selection of the Company's independent certified ! public accountants.The Audit Committee reviewed the overa!! scope and details of the independent certified public accountants
- and internal auditors' respective audit plans and reviewed and approved the independent certified public accountants
- general audit fees and non-audit services.
Audit Committee meetings are designed to facilitate open communications with internal auditors and independent certified public accountants. To ensure auditor independence, both the independent certified public accountants and the internal auditors have full and free access to the Audit Committee. The Audit Committee of the Board of Directors of DQE
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Statomont of Consolidated Incomo (Thousands of Dollars, & cept Per Share Amouras) lear Ended December 31, 1997 1996 1995 Operating Sales of Electricity: R. venues j Residential $ 405,915 $ 405,392 $ 414,291 Commercial 494,834 489,646 491,789 Industrial 198,708 190,723 190,689
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Provision for doubtful accounts (11,000) (10,582) (13,430) Net customer revenues 1,088,457 1,075,179 1,083,339 Utilities 24,861 58,292 55,9u3 l Total Sales of Electricity 1,113,318 1,133,471 1,139,302 Other 105,856 92,724 80,860 ) Total Operating Rerenues 1,219,174 1,226,I95 1,220,162 Operating Fuel and purchased power 223,411 236,924 231,968 Expenses Other operating 306,747 298,977 292,997 Maintenance 82,869 78,386 81.516 Depreciation and amortization 242,843 222,928 202,558 Taxes other than income taxes 82,567 85,974 88,658 Total Operating Erpenses 938,437 923,189 897,697 Operating income Operating Income 280,737 303,006 322,465 Other income Long-term investment income 64,464 49,636 28,975 Gain on dispositions 34,364 5,119 9,129 Interest and other income 30,979 19.035 14,210 Total Other Income 129,807 73,790 52,314 Interest and Other Charges 115,638 110,270 107,555 Income Before Income Taxes 294,906 266,526 267,224 l Income Taxes 95,805 87,388 96,661 N;t income Net income $ 199,101 $ 179,138 $ 170,563 Average Number of Common Shares Outstanding (Thousands of Shares) 77,492 77,349 77,674
. Ecrnings Per Shate Basic Earnings Per Share of Common Stock $2.57 $2.32 $2.20 Diluted Earnings Per Share of Common Stock $2.54 $2.29 $2.17 Dividends Declared Dividends Declared Per Share of Common Stock $1.38 $1.30 $1.21 See notes to consolidatedpnancial statements.
Statement of Consolidated Retained Earnings (Thousands ofDollars) As ofDecember 31, 1997 1996 1995 Balance at beginning of year $ 777,607 $ 698,986 $ 622.072 Net income 199,101 179,138 170,s63 Dividends declared (106,959) (100,517) (93,649) Balance at end of year $ 869,749 $ 777,607 5 698,986 See notes to consolidatedpnancialstatements. 9 ___
I - Concolidatod Balanco Shoot (Tiwusands of Dollars) As of December 31, 1997 1996 A: sets Current Assets: Cash and temporary cash investments
$ 356,412 5 410,978 Receivables:
90,149 92,475 Electric customer accounts receivable 23,106 22,402 Other utility receivables 33,472 33,936 Other receivables (15,016) (18.688) less: Allowance for uncollectible accounts 131,711 130,125 Total Receivables - Net Materials and supplies (at average cost): 20,418 19,097 Coal 53,088 52,669 Operating and construction Total Afaterials and Supplies 73,506 7I,766 7,727 9,359 Other current assets 569,356 622,228 Total Current Assets Long-Term investments: 349,129 134,133 Leveraged leases Affordable housing 137,860 150,270 92,645 79,916 Gas reserves 69,329 85,893 Other leases Other 73,823 68.477 Total Long-Term Investments 722,786 5l8.689 Property, Plant and Equipment: Electric plant in service 4,335,149 4,275,110 Construction work in progress 56,471 45,059 Property held under capital leases 113,662 99,608 3,980 190,821 Property held for future use Other 115,866 176,872 Gross property, plant and equipment 4,625,128 4,787,470 Less: Accumulated depreciation and amortization (I,962,794) (1,969,945) Total Property, Plant and Equipment - Nel 2/>62,334 2,8I7.525 Other Non-Current Assets: Regulatory assets 680,885 636,816 Other 59,041 43,734 lotal Other Non-Current Assets 739,926 680.550 7btalAssets $4,694,402 M,638,992 See notes to consolidatedfinancial statements.
e (Thousands ofDollars) As of December 31, 1997 1996 Liabilities and Current Liabilities: Capitalization ' Notes payable $ - 5 749 Current maturities and sinking fund requirements 97,844 72,831 Accounts payable 85,085 96,230 Accrued liabilities 54,386 58,044 Dividends declared 30,312 28,633 Other 14,339 4,075 T>tal Current Liabilities 281,966 260,562 Non-Current Liabilities: Deferred income taxes - net 693,215 759,089 Deferred income 225,107 189,293 Deferred investment tax credits 97,782 106,201 Capital lease obligations 37,540 28,407 Other 255,467 240,763 Total Non-Current Liabilities 1,309,1l1 1.323,753 Commitments and Contingencies (Notes 11 through M) Capitalization: Long-Term Debt 1,376,121 1,439,746 Preferred and Preference Stock of Subsidiaries: Non-redeemable preferred stock 216,156 213,608 Non-redeemable preference stock 28,295 28,997 Total preferred and preference stock before deferred employee stock ownership plan (ESOP) benefit 244,451 242,605 Deferred ESOP benefit (16,400) (19,533) Total Preferred and Preference Stock of Subsidiaries 228,051 223,072 Common Shareholders' Equity: Common stock - no par value (authorized - 187.500,(XX) shares; issued - 109,679,154 shares) 1,001,225 990,502 Retained earnings 869,749 777,607 Treasury stock (at cost)(31,998,723 and 32,406,135 shares) (371,821) (376,250) Total Common Shareholders' Equity 1,499,153 1.391,859
- Total Capitali
- .ation 3,103,325 3,054,677 l Total Liabilities and Capitali:.ation $4,694,402 $4,638,992 t
See notes to consohdatedfinancial statements. 51
Statement of Consolidated Coch Flowe j (Thousandr of Dollars) l Year Ended December 31, 1997 1996 1995 ' l
$199,101 5179,138 $170,563 '
C1h Flows Net income fr:m Operating Principal non-cash charges (credits) to net income: 242,843 222,928 202,558 Activities Depreciation and amortization 67,671 53,166 38,847 Capital lease, nuclear fuel and investment amortization 60,811 (43,170) (10,921) Deferred income taxes and investment tax credits - net (34,364) (5,119) (9,129) Gain on disposition of investments t 66,246) (57,429) (31,054) Investment income (37,229) 2,915 34,875 Changes in working capital other than cash (25,318) (3,948) 11,652 (Increase) decrease in ECR (40,038) 34,445 48,731 Other 367,131 382,926 456,122 Net Cash Providedfrom Operating Activities (219,122) (77,147) (191,719) C:sh Flows from Long-term investments Investing Activities Capital expenditures (118,338) (101,150) (94.164) 86,300 18,100 1,929 Proceeds from disposition of investments
- 169,100 -
Sale of generating station Payment for purchase of GSF Energy, net of cash acquired
- (24,234) -
(4,938) (1,898) (3,854) Other Net Cash Used in Inresting Actirities t 256,098) (17,229) (287,808) t 106,959) (100,517) (93,649) Ca:h Ficws from Dividends on common stock Financing Activities Reducticas of long-term obligations: (52,100) (50,812) (56,114) Long-term debt (13,551) (19,326) (26,373) Capital leases Preferred and preference stock - - (29,732) (30) (11,717) (21,271) Repurchase of common stock Issuance of preferred stock - 150,000 -
- 85,(XX) 65,(X)0 Issuance of long-term debt Decrease in notes payable - (28,637) (20,236)
Other 6,941 (3,477) (l1,230) Net Cash (Used in) Prorsdedfrotn Financing Activities (l65,699) 20,514 (l93,605) Net (decrease) increase in cash and temporary cash invements tS4,566) 386,21! (25,291) Cash and teniporar! . ash investments at beginning of year 410,978 24,767 50,058 Cash and temporary cash investments at end of year $356,412 5410,978 $ 24,767 Supplemental Cash Flow information Crh Paid During Interest (net of amount capitalized) $ 95,413 5 95,702 5 99,954 tha Year income taxes $ 66,703 5 91,641 5 82,884 Non-Cash investing Capital lease obligations recorded $ 27,514 $ 13,050 $ 14.961 cnd Financing Equity funding obligations recorded $ 5,441 $ 36.716 $ 21,827 Activities Equity funding obligations cancelled $ 9,107 $ - Preferred stock issued in conjunction with long term investments $ 2,548 $ - $ 3,000 On May 1,1997. DQE exchanged its shares in Chester Engineers for shares of common stock of the purchaser of Chester Engineers, which were subsequently sold at various dates through June 5,1997. See notes to consolidatedfinancial statements. 5
Noton to Consolidated Financial Statements A. Summary of Consolidation and Proposed Merger Significant DQE, Inc. (DQE) is an energy services holding company. Its subsidiaries are Duquesne Light Accounting Company (Duquesne): Duquesne Enterprises, Inc. (DE); DQE Energy Services, Inc. (DES); Policies DQEnergy Partners, Inc. (DQEnergy); and Montauk, Inc. (Montauk). DQE and its subsidiaries are collectively referred to as "the Company." Duquesne is an electric utility engaged in the generation, transmission, distribution and sale of electric energy and is the largest of DQE's subsidiaries. DE makes strategic investments beneficial to DQE's core energy business. These investments are intended to enhance DQE's capabilities as an energy provider, increase asset utilization, and act as a hedge against changing business conditions. j DES is a diversified energy services company of fering a wide range of energy solutions for industrial, j utility and consumer markets worldwide. DES initiatives include energy facility development and operation, domestic and international independent power production, and the production and supply of innovative fuels. DQEnergy was formed to align DQE with strategic partners to capitalize on opportunities in the energy services industry.These alliances are intended to enhance the utilization and value of DQE's strategic investments and capabilities while establishing DQE as a total energy provider. Montauk is a financial services company that makes long-term investments and provides i financing for the Company's other market-driven businesses and their customers. All material intercompany balances and transactions have been eliminated in the preparation of the consolidated financial statements. On August 7,1997, the shareholders of the Company and Allegheny Energy, Inc. (AYE), approved a proposed tax-fme, stock-for-stock merger. Upon consummation of the merger, DQE will be a wholly owned subsidiary of AYE. Immediately following the merger, Duquesne, DE, DES, DQEnergy and Montauk will remain wholly owned subsidiaries of DQE.The transaction is intended to be accounted for as a pooling of interests. Under the pooling of interests method of accounting for a business combination, the recorded assets, liabilities and equity of each of the combining companies are carried forward to the combined corporation at their recorded amounts. Accordingly, no goodwill, including the related future earnings impact of goodwill amortization, results from a transaction accounted for as a pooling of interests. In order to qualify for pooling treatment, many requirements must be met by each of the combining companies for a period of time before and after the combination occurs. Examples of the requirements prior to the merger include limitations on: dividends paid on common stock, stock repurchases, stock compensation plan activity and sales of significant assets. Managen ent has focused and will continue to focus on meeting the pooling requirements as they relate to the Company prior to the merger. Under the terms of the transaction, the Company's shareholders will receive 1.12 shares of AYE common stock for each share of the Company's common stock and AYE's dividend in effect at the time of the closing of the merger.The transaction is expected to close in mid-1998, subject to approval of applicable regulatory agencies, including the public utility commissions in Pennsylvania and Maryland, the Securities and Exchange Commission (SEC), the Federal Energy Regulatory Commission (FERC) and the Nuclear Regulatory Commission (NRC). In September 1997, the City of Pittsburgh filed a federal antitrust suit seeking to prevent the merger and asking for monetary damages. Although the United States District Court for the District of Western Pennsylvania dismissed the suit in January 1998, the City of Pittsburgh filed an appeal and asked for expedited review. A hearing is currently scheduled for late March 1998. Unless otherwise indicated, all information presented in this Annual Report relates to the Company only and does not take into account the proposed merger between the Company and AYE. Basis ofAccounting The Company is subject to the accounting and reporting requirements of the SEC. In addition, the Company's electric utility operations are subject to regulation by the Pennsylvania Pubiic Utility Commission (PUC), including regulation under the Pennsylvania Electricity Generation Customer Choice and Competition Act (Customer Choice Act), and the FERC under the Federal Power Act with respect to rates for interstate sales, transmission of electric power, accounting and other matters. The Company's consolidated financial statements report regulatory assets and liabilities in accordance with Statement of Financial Accounting Standants (SFAS) No. 71, Accountingfor the Efects of Certain 7) pes ofRegulation (SFAS No. 71), and reflect the effects of the current ratemaking process. In accordance with SFAS No. 71, the Company's consolidated financial statements reflect regulatory assets and liabilities consistent with cost-based, pre-competition ratemaking regulations. t (See " Rate Matters Note E, on page 58.) as L__.____.__________________.___ _ _ . _ _ _ _ _ _ . _. _ . . _ _ . _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . __ __ _ _ _ _ _ _ _ _ _ _ . _ _ _ _ _ . .
The preparation of financial statements in conformity with generally accepted accounting principles i requires management to make estimates and assumptions that affect the reported amounts of assets l and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements. The reported amounts of revenues and expenses during the reporting period may also be affected by the estimates and assumptions management is required to make. Actual results could differ from those estimates. Revenuesfrom Sales of Electricity The Company's electric utility operations provide service to customers in Allegheny County, including the City of Pittsburgh; Beaver County; and Westmoreland County. (See " Rate Matters," Note E, on page 58.) This territory represents approximately 800 square miles in southwestern Pennsylvania, located within a 500-mile radius of one-half of the population of the United Smt:s and Canada. The population of the area served by the Company's electric utility operations, based on 1990 census data, is approximately 1,510,000, of whom 370,000 reside in the City of Pittsburgh. In addition to serving approximately 580,000 direct customers, the Company's utility operations also sell electricity to other utilities. Meters are read monthly and electric utility customers are billed on the same basis. Revenues are recorded in the accounting periods for which they are billed, with the exception of energy ccst recovery revenues. (See " Energy Cost Rate Adjustment Clause (ECR)" discussion below.) Energy Cost Rate Adjustment Clause (ECR) Through the ECR, the Company recovers (to the extent that such amounts are not included in base rates) nuclear fuel, fossil fuel and purchased power expenses and, also through the ECR, passes to its customers the profits from short-term power sales to other utilities (collectively, ECR energy costs). Under the Company's mitigation plan approved by the PUC in June 1996, the level of energy cost recovery is capped at 1.47 cents per kilowatt-hour (KWH) through May 2001. The rate currently being recovered is 1.28 cents per KWH, based upon estimated 1996 costs. To the extent that current fuel and purchased power costs, in combination with previously deferred fuel and purchased power costs, are not projected to be recoverable through this pncing mechanism, these costs would become transition costs subject to recovery through a competitive transition charge (CTC). (See " Rate Matters," Note E, on page 58.) Nuclear fuel expense is recorded on the basis of the quantity of electric energy generated and includes such costs as the fee imposed by the United States Department of Energy (DOE) for future disposal and ultimate storage and disposition of spent nuclear fuel. Fossil fuel expense includes the costs of coal, natural gas and fuel oil used in the generation of electricity. On the Company's statement of consolidated income, these ECR revenues are included as a component of operating revenues. For ECR purposes, the Company defers fuel and other energy expenses for recovery, or refunding, in subsequent years. The deferrals reDect the difference between the amount that the Company is currently collecting from customers and its actual ECR energy costs. The PUC annually reviews the Company's ECR energy costs for the fiscal year April through March, compares them to previously projected ECR energy costs, and adjusts the ECR for over- or under-recoveries and for two PUC-established coal cost standards. This adjustment was not made during 1997, despite a projected increase of 0.13 cents per KWH, pending the outcome of the Company's Restructuring Plan or Stand-Alone Plan (as defined in " Rate Matters," Note E, on page 58). Over- or under-recoveries from customers have been recorded in the consolidated balance sheet as payable to, or receivable from, customers. Based on Duquesne's Restructuring Plan and Stand-Alone Plan, the 1997 under-recoveries were reclassified as a regulatory asset and may be recovered through a CTC. At December 31,1997, $23.5 million was receivable from customers. At December 31,1996, $1.8 million was payable to customers and shown as other current liabilities. Maintenance Incremental maintenance costs incurred for refueling outages at the Company's nuclear units are deferred for amortization over the period between refueling outages (generally 18 months). The Company accrues, over the periods between outages, anticipated costs for scheduled major fossil generating station outages. Mainten mce costs incurred for non-major scheduled outages and for forced outages are charged to expense as such costs are incurred. Depreciation and Amortization Depreciation of property, plant and equipment, including plant-related intangibles, is recorded on a straight-line basis over the estimated remaining useful lives of properties. Amortization of other intangibles is recorded on a straight-line basis over a Hve-year peri ( 4. Amortization of limited partnership interests ir. gas reserve investments and depreciation of related property are on a units 1l1_
of production method over the total estimated gas reserves. Amortization of interests in affordable housing partnerships is based upon a mahod that approximates the equity method and amortization of certain other leases is on the basis of benefits recorded over the lives of the investments. Depreciation and amortization of other properties are calculated on various bases. In 1987, the Company sold its 13.74 percent interest in Beaver Valley Unit 2 and leased it back. The lease is accounted for as an operating lease, in May 1997, the Company accelerated the recognition of expense related to the lease. The accelerated expense recognition accounted for
$16.1 million of total amortization expense for 1997. Due to the above-market price of the lease, the Company has proposed in its Restructuring Plan 'md Stand-Alone Plan (as defined in " Rate Matters," Note E, on page 58) to recover the remaining above-market lease costs through a CTC, The Company records nuclear decommissioning costs under the category of depreciation and amortization expense and accrues a liability, equal to that amaunt, for nuclear decommissioning expense. On the Company's consolidated balance sheet, the dec immissioning trusts have been reflected in other long-tern investments, and the related liability has been recorded as other non-current liabilities. Trust fund earnings increase the fund balance and the recorded liability.
(See " Nuclear Decommissioning" discussion Note I, on page 64.) The Company's electric utility operations' composite depreciation rate increased from 3.5 percent to 4.25 percent effective May 1,1996. Also in 1996, the Company expensed $9 million related to the depreciation portion of deferred rate synchronization costs in conjunction with the Company's 1996 PUC-approved mitigation plan. Income *Iaxes The Company uses the liability method in computing deferred taxes on all differences between book and tax bases of assets These book / tax differences occur whe: events and transactions recognized for financial reporting purposes are not recognized in the same period for tax purposes. The deferred tax liability or asset is also adjusted in the period of enactment for the effect of changes in tax laws or rates. For its electric utility operations, the Company recognizes a regulatory asset for the deferred tax liabilities that are expected to be recovered from customers through rates. (See " Rate Matters," Note E, and " Income Taxes," Note G, on pages 58 and 62.) The Company reflects the amortization of the regulatory tax receivable resulting from reversals of deferred taxes as depreciation and amortization expense. Reversals of accumulated deferred income taxes are included in income tax expense. When applied to reduce the Company's income tax liability, investment tax credits related to electric utility property generally are deferred. Such credits are subsequently reflected, over the lives of the relate" assets, as reductions to income tax expense. Other Operating Revenues and Other income Other operating revenues include the Company's non-KWH utility revenues and revenues from market-based operating activities. Other income primarily is made up of inume from long-term investments entered into by the market-driven businesses. The income is separated from other revenues as the investment income does not result from operating activities. Property. Plant and Equipment The asset values of the Company's electric utility properties are stated at original construction cost, which includes related payroll taxes, pensions and other fringe benefits, as well as administrative and general costs. Also included in original construction, cost is an allowance for funds used during construction (AFC), which represents the estimated cost of debt and equity funds used to finance construction. Additions to, and replacements of, property units are charged to plant accounts. Maintenance, repairs and replacement of minor items of property are recorded as expenses when they are incurred. The costs of electric utility proper'ies that are retired (plus removal costs and less any salvace value) are charged to accumulated depreciation and amortization. l Substantially t.ll of the Company's electric utility properties are subject to a first mortgage lien. Temporary Cash investments Temporary cash investments are short-term, highly liquid investments with original maturities of three or fewei months. They are stated at market, which approximates cost. The Company considers temporary cash investments to be cash equivalents. 6$
Earnings Per Share SEAS No.128 Earningt Per Share (SFAS No.128). establishes standards for computing and presenting carnings per share and makes the standards comparable to international earnings per share standards. It replaces the presentation of primary earnings per share, as found in Accounting Principles Board (APB) Opinion No.15. Earnings per Share, with a presentation of basic earnings per share. It also requires dual presentation of basic and diluted earnings per share on the statement of consolidated income for all critities with complex capital structures. Basic earnings per share is computed by dividing income available to common stockholders by the weighted-average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that then shared in the eernings of the entity. The statement is effective for financial statements issued for periods ending after December 15,1997. The preference stock of the ESOP, as described in Note M," Employee lienefits," was the primary cause for the dilution of earnings per share for the years ended December 31,1997,1996 and 1995 as shown on the statement of consolidated income. Each share of the preference stock is exchangeable for one and one-half shares of DQE common stock. Assuming conversion at the beginning of each year, the number of DQE shares was added to the denominator (weighted-average number of common shares outstanding). Partially offsetting the dilutive effect of the additional shares, the preference stock has an annual dividend sate of $2.80 per share, which was added back to the numerator (income available to common stockholders). The result of calculating both basic and dilutive earnings per share for the three years presented was a $0.03 dilutive effect in each year. Stock-Based Compensation The Company accounts for stock-based compensation using the intrinsic value method prescribed in APB Opinion No. 25, Accountingfor Stock issued to Employees, and related interpretations. Accordingly, compensation cost for stock options is measured as the excess, if any, of the quoted market price of the Company's stoch at the date of the grant over the amount any employee must pay to acquire the stock. Compensation cost for stock appreciation rights is recorded annually based on the quoted market price of the Company's stock at the end of the period. Reclassification The 1996 and 1995 consolidated financial statements have been reclassified to conform with accotmting presentations adopted during 1997. Recent Accounting Pronouncements SFAS No.130, Reporting Comprehensive income (SFAS No. l30) and SEXS No.131, Disclosures about Segments of an Enterprise and Related Information (SFAS No.131), have been issued and are effective for fiscal years beginning after December 15,1997. SFAS No.130 defines comprehensive income and outlines certain reporting and disclosure requirements related to comprehensive income. SFAS No.131 requires certain disclosures about business segments of an enterprise, if applicable. The adoption of SFAS No.130 and SFAS No.131 is not expected to have a significant impact on the Company's financial statements or disclosures. B. Changes in Changes in Working Capital Other than Cash Working Capital (Net of1997 Chester Disposition and 1996 GSF Energy Acquisition) Other than Cash 1997 1996 1995 (Amounts in Thousands of Dollars)
$(14,947) $ (l,946) $ 34,341 Receivables (I,740) 1.286 9,994 Materials and supplies (519) (948) 3,126 Other current assets (4,993) 4.691 7,087 Accounts payable (15,030) (l68) (19,673)
Other current liabilities Total
$(37,229) $ 2.915 $ 34.875 C. Property, Plant in addition to its wholly owned generating units, the Company, together with FirstEnergy and Equipment Corporation, has an ownership or leasehold interest in certain jointly owned units. The Company is required to pay its share of the construction and operating costs of the units. The Company's share l
of the operating expenses of the units is included in the statement of consolidated income. 58 _-
l e i Generating Units at December 31,1997 Generating Net Utility Fuel l Unit Capability Plant Source (Afegawatts) (Afillions of Dollars) Cheswick 570 $ 120.4 Coal l Elrama (a) 487 96.5 Coal Eastlake Unit 5 . 186 35.6 Coal
- Sammis Unit 7 187 46.7 Coal l Bruce Mansfield Unit 1 (a) 228 62.5 Coal l Bruce Mansfield Unit 2 (a) 62 18.2 Coal l Bruce Mansfield Unit 3 (a) 110 47.9 Coal Beaver Valley Unit I (b) 385 195.9 Nuclear Beaver Valley Unit 2 (c)(d) I13 14.0 Nuclear Beaver Valley Common Facilities 149.5 Perry Unit 1 (e) 164 387.1 Nuclear Brunot Island Units 2a and 2b 178 21.9 Fuel Oil 7btal Generating Units 2.670 $ l. l96.2 (a) 'Ihe unit is equipped with flue gas desulfurization equipment.
tb) The Nuclear Regulatory Commission INRC) has granted a license to operate through January 2016. (c) In 1987, the Company sold and leased back its 13.74 percent interest in Beaser Wiley tJnit 2. The lease is accounted for as an operating lease. Amounts shown represent facilities not sold and subsequent leasehold improvements. (d) The NRC has granted a license to operate through May 2027. (e) The NRC has granted a license to operate through March 2026. D. Long-Term The Company makes equity investments in affordable housing and gas reserve partnerships as a investrnents limited partner. At December 31,1997, the Company had investments in 27 affordable housing funds and eight gas reserve partnerships. The Company is the lessor in nine leveraged lease l arrangements involving mining equipment, rail equipment, fossil generating stations, a waste-to-energy facility, high speed service ferries and natural gas processing equipment. These leases expire in various years beginning in 20N :hrough 2033. The recorded residual value of the equipment at the end of the lease terms is estimated to be approximately 2 percent of the original cost. The Company's aggregate investment represents 20 percent of the aggregate original cost of the property and is either leased to a creditworthy lessee or is secured by guarantees of the lessee's parent or affiliate. The remaining 80 percent was financed by non-recourse debt provided by lenders who have
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been granted, as their sole remedy in the event of default by the lessees, an assignment of rentals due under the leases and a security interest in the leased property. This debt amounted to $950 million and $553 million at December 31,1997 and 1996. Net Leveraged Lease Investments at December 31 1997 1996 (Amounts in l'housands of Dollars) Rentals receivable (net of non-recourse debt) $638,030 $215,358 Estimated residual value of leased assets 22,029 22,029 Less: Uneamed income (310,930) (103,254) Leveraged lease investments 349,129 134,133 Less: Deferred taxes arising from leveraged leases (115,383) (59,781) Net Lereraged Lease Inressments $233,746 $ 74,352 The Company's other leases include investments in fossil generating stations, a waste-to-energy facility, computers, vehicles and equipment. The Company's other investments are primarily in assets of nuclear decommissioning trusts and marketable securities. In accordance with SFAS No. 115, Accountingfor Certain investments in Debt and Equity Securities (SFAS No. I15), these investments are classified as available-for-sale and are stated at market value. The amount of I unrealized holding gains related to marketable securities was $8.1 rnillion ($4.7 million net of tax) at December 31,1997. The amount of unrealized holding losses related to marketable securities was
$4.4 million ($2.6 million net of tax) at December 31,1996. Deferred income primarily relates to the Company's other lease investments and certain gas reserve investments. Deferred amounts will be recognized as income over the lives of the underlying investments for periods generally not exceeding seven years.
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in 1997, the Company acquired 100 percent of the Class A Stock on AquaSource,Inc. (AquaSource), which was formed to acquire small and mid-sized water, wastewater and water services companies, with its initial focus in Texas. The Company created the Preferred Stock, Series A (Convenible), $100 liquidation preference per share (DQE Prcferred Stock), to issue as consideration in lieu of cash in connection with acquisitions by the Company of other businesses, assets or securities. (See "Prefbrred and Preference Stock," Note K, on page 68.) At Decerrber 31, 1997, the Company had invested approximately $7 million (of which approximvely $1.5 million was in the form of DQE Preferred Stock) to acquire the stock or assels of seven water, wastewater and water services companies. In Febnnry 1998, the Company issued 159,732 shares of DQE Preferred Stock, representing an investment of approximately $16 million i. a water company. The Company has committed approximately $24 millicn for additional investments in water, wastewater and water services companies for the first quarter of 1998. E. Rate Matters Competition and the Customer Choice ,1et The electric utility industry continues to undergo fundamental change in response to development of open transmission access and increased availability of energy alternatives. Under historical ratemaking practice, regulated electric utilities were graated exclusive geographic franchises to sell electricity in exchange for making investments and incurring obligations to serve customers under the then. existing regulatory framework. Through the ratemaking process, those pruintly incurred costs were recovered from customers along with a return on the investment. Additionally, certain operating costs were approved for deferral for future recovery from customers (regulatory assets). As a result of this historical ratemaking process, utilities have assets recorded on their balance sheets at above-market costs, thus creating transition or stranded costs, in Pennsylvania, the Customer Choice Act wcat into effect January 1,1997. The Customer Choice Act enables Pennsylvania's electric utility customers to purchase electricity at market prices from a variety of electric generation suppiiers (customer choice). Although the Customer Choice Act will give customers their choice of electric generation suppliers, delivery of the electricity from the generation supplier to the customer will remain the responsibility of the existing franchised utility. The Customer Choice Act also provides that the existing franchised utility may recover, through a CTC, an amount of transition or stranded costs that are determined by the PUC to be just and reasonable. Pennsylvania's electric utility restructuring is being accomplished through a two-stage process consisting of an initial customer choice pilot period (running through 1998) and a phase-in to competition period (beginning in 1999). For the first stage, the Company filed a pilot program with the PUC on February 27,1997. For the second stage, the Company filed on August 1,1997 its restructuring and merger plan (the Restructuring Plan) and its stand-alone restructuring plan (the Stand-Alone Plan) with the PUC, (See the detailed discussion of these plans on pages 59 and 60.) Customer Choice Pilots The pilot period gives utilities an opportunity to examine a wide range of technical and administrative details related to competitive markets, including metering, billing, and cost and design of unburidled electric services. The Company pilot filing proposed unbundling transmission, distribution, generation and competitive transition charges and offered participating customers the same options that were to be available in a competitive generation market. The pilot was designed to comprise approximately 5 percent of the Company's residential, commercial and industrial demand. The 28.000 customers participating in the pilot may choose unbundled service, with their electricity provided by an alternative generation supplier, and will be subject to unbundled distribution and CTC charges approved by the PUC and unbundled transmission charges pursuant to the Company's FERC-approved tarifL On May 9,1997, the PUC issued a Preliminary Opinion and Order approving the Company's filing in part, and requiring certain revisions. The Company and other utilities objected to several features of the PUC's Preliminary Opinion and Order. Hearings on several key issues were held in July. The PUC issued its final order on August 29,1997, approving a revised pilot program for the Company. On September 8,1997, the Company appealed the determination of the market price of generation set forth in this order to the Commonwealth Court of Pennsylvania. The Company expects a hearing to be scheduled for mid-1998. Although this appeal is pending, the Company complied with the PUC's order to implement the pilot program that began on November 3,1997. Phase-In to Competition The phase-in to competition begins on January 1,1999, when 33 percent of customers will have customer choice (including customers covered by the pilot program); 66 percent of customers will have customer choice no later than January 1,2000; and all customers will have customer choice no later than January 1,2001. However, in its sole order to date (the PECO Order), the PUC ordered the phase-in provisions of the Customer Choice Act to require the acceleration of the second and third phases to January 2,1999 and January 2,2000, respectively. As they are phased-in, E
customers that have chosen an electricity generation supplier other than the Company will pay that supplier for generation charges, and will pay the Company a CTC (discussed below) and unbundled charges for transmission and distribution. Customers that continue to buy their generation from the Company will pay for their sersice at current regulated tariff rates divided into unbundled generation, transmission and distribution charges. The PECO Order concluded that under the Customer Choice Act, an electric distribution company, such as Duquesne is to remain a regulated utility and may only offer PUC-approved, tariffed rates (including unbundled generation rates). Delivery of electricity (including transmission, distribution and customer service) will continue to be regulated in l substantially the same manner as under current regulation. 1 Rate Cap and Transition Cost Recovery Before the phase-in to customer choice begins in 1999, the PUC expects utilities to take vigorous steps to mitigate transition costs as much as possible without increasing the rates they currently charge customers. The Company has mitigated in excess of $350 million of trans uon costs during the past three years through accelerated annual depreciation and a one-time write-down of nuclear generating station costs, accelerated recognition of nuclear lease costs, increased nuclear decom-missioning funding, and amortization of various regulatory assets. This relative level of transition cost reduction, while holding rates constant, is unmatched within Pennsylvania. The PUC will determine what portion of a utility's transition or stranded costs that remain at January 1,1999 will be recoverable through a CTC from customers. The CTC recovery period could last through 2005, providing a utility a total of up to nine years beginning January 1,1997 to recover transition costs, unless this period is extended as part of a utility's PUC-approved transition plan. An overall four-and-one-half-year rate cap from January 1,1997 will be imposed on the transmission and distribution charges of electric utility companies. Additionally, electric utility companies may not increase the generation price component of rates as long as transition costs are being recovered, with certain exceptions. The Company has requested recovery of transition costs of approximately $2 billion, net of deferred taxes, beginning January 1,1999. Of this amount,
$0.5 billion represents regulatory assets and $1.5 billion represents potentially uneconomic plant and plant decommissioning costs. Any estimate of the ultimate level of transition costs for the Company depends on, among other things, the extent to which such costs are deemed recoverable by the PUC, the ongoing level of the cost of Duquesne's operations, regional and national economic conditions, and growth of the Company's sales. (See " Financial Exposure to Transition Cost Recovery" discussion on page 40 and " Regulatory Assets and Emerging Issues Task Force" discussion on page 61).
Timetablefor Restructuring Plan and Stand,11onr Plan Approval On August 1,1997, the Company filed the Restructuring Plan and the Stand-Alone Plan with the PUC. Although the provisions of the Customer Choice Act require a PUC decision nine months from the filing date (which would be April 30,1998), the Pennsylvania Attorney General's Office requested an extension in order to conduct an investigation into certain competition issues relating to the Restructuring Plan. Pursuant to an arrangement among the Company, the PUC and the Attorney General, the Company anticipates a decision by the PUC (with respect to the Restructuring Plan if the merger is approved, or with respect to the Stand-Alone Plan if the merger is not approvedi on or before May 29,1998 or such later date as the parties may agree. Stand-Alone Plan In the event the merger with AYE is not consummated under the filed Restructuring Plan, the Company has sought approval for restructuring and recovery of its own transition costs through a CTC under the Stand-Alone Plan. 'Ihe Company proposed that any finding of market value for the Company's generating assets snauld be based on market evidence and not on an administrative determination of that value based on price forecasts (the PECO Order determined the market value of PECO Energy Company's generation based on the price forecast sponsored by the Pennsylvania Office of Consumer Advocate). In addition. the Company proposed that such a final market valuation be conducted in 2003, and that an annual competitive market solicitation be used to set the CTC in the interim. The 2003 final market valuation would be performed by an independent panel of experts using the best available market evidence at that time. The Stand-Alone Plan filing also provided for certain triggers that would accelerate the date of this final market valuation. Prior to the final valuation, the Company would sell a substantial amount of power to the highest bidder ia an annual competitive solicitation. The annual market price established by the solicitation woulo be used to set competitive generation credits and determine the CTC as a residual from the generation rate cap under the Rate Cap Provision. (See " Financial Impact of Pilot Program Order" discussion on page 38.) During the transition period, the Company committed to accelerate amortization and depreciation of its generation-related assets and cap its retum on equity through a return on equity M
spillover mechanism, in exchange for being allowed to charge existing rates under the Rate Cap Provision. The Company committed to a minimum d 31.7 billion of amortization and depreciation of generation-related assets by the end of 2005. Under the proposed return on equity spillover mechanism additional amortization and depreciation in excess of this minimum $1.7 billion l commitment would be recorded in order to comply with the return on equity cap. The generation l rate cap would apply to the sum of the CTC and the competitive generation credit determined in I the annual competitive solicitation. The Stand-Alone Plan also proposed to redesign indisidual tariffs to encourage more efficient consumption and further mitigate transition costs during the transition period. Consistent with the Company's long-standing commitment to economic development, the rate redesign provides for a significant reduction in the cost of electricity for incremental consumption. Application of the rate redesign to the CTC would also have the potential to maximize mitigation of transition costs during the transition period. As an alternative to a market-based valuation in 2003, if the PUC finds that a determination of market value as of December 31,1998 is required by the Customer Choice Act, then the Company has agreed that the PUC may order an immediate auction of the Company's generation at that time. Restructuring Plan The Restructuring Plan incorporates the benefits of the merger with AYE, such as anticipated savings to the Company, on a nominal basis, of $365 million in generation-related costs over 20 years, and $9 million in transmission-related costs and $173 million in distribution-related costs over 10 years. The Company plans to use the generation-related portion of its share of net operating synergy savings to shorten the transition cost recovery period. The Restructuring Plan also incorporates the market-based approach to determining transition costs proposed by the Company in its Stand- Alone ) Plan. The 2003 final market valuation will be performed by an independent panel of experts using the best available market evidence at that time, including a potential sale of a portion of the combined company's generating assets. Certain triggers will accelerate the date of this final market valuation if market prices rise significantly or the minimum amortization commitment is satisfied prior to 2003. The annual market price established by the Company's solicitation would be used to set competitive generation credits and to determine the CTC as a residual from the generation rate cap under the Rate Cap Provision. The Company's minimum amortization commitment of $1.7 billion in the proposed Stand-Alone Plan has been increased under the Restructuring Plan. As in the Stand-Alone Plan, the detennination of transition costs in 2003 will compare the book value of generating assets in 2005 (after netting the increased minimum commitment to depreciation and amortization and any return on equity spillover) with the market value of the generating assets in 2005. The opposing parties believe that there should be a one-time valuation of the generating assets performed at January 1,1999. Any merger-related synergies relating to generation would then be used to reduce the Company's transition costs as of that date. These parties also believe that the Company's proposed distribution rate decrease should be effective January 1,1999, as well. Additional Restructuring Plan Commitments The Restructuring Plan also contains a number of commitments by the merged DQE/AYE entity. First, the merged entity will open up its transmission system to all parties on a reciprocal non-discriminatory basis and eliminate multiple rate charges across the combined transmission system. Second, the merged entity will join a recently proposed Midwest independent System Operator (ISO) or other then-existing ISO, or form its own ISO if no existing ISO offers acceptable rules, including marginal cost transmission rates. Several utilities have applications pending before the FERC to form ISOs. Third, the merged entity has committed to make a report,18 months after j consummation of the merger, to the PUC regarding its progress on the ISO commitment. The PUC J may, at its option, require the merged entity to relinquish control of 300 MW of generating capacity l to alleviate concerns over market power. The form of relinquishment would be at the option of the merged entity; possible forms of relinquishment include an energy swap, entering a power sale contract, divestiture of generating assets and a bidding trust. The Federal Filings in addition to tb PUC filings of the Restructuring Plan and the Stand-Alone Plan, on August 1, 1997, the Company and AYE filed their joint merger application with the FERC (the FERC Filing). Pursuant to the FERC Filing, the Company and AYE have committed to forming orjoining an ISO that meets the entity's requirements, including marginal cost transmission pricing, following the merger, in addition, the Company ar.d AYE have stated in the FERC Filing that following the merger the combined entity's market share will not violate the market power conditions and requirements ; set by the FERC. On January 20,1998, the Company and AYE filed merger applications with j the Antitrust Division of the Department of.Iustice and the Federal Trade Commission. These j applications are currently pending. ! 1
Regulatory Assets and Emerging issues Task Force As a result of the application of SFAS No. 71, the Company records regulatory assets on its consolidated balance sheet. The regulatory assets represent probable future revenue to the Company because provisions for these costs are currently included, or are expected to be included, in charges to electric utility customers through the ratemaking process. A company's electric utility operations, or a portion of such operations, could cease to meet the SFAS No. 71 criteria for various reasons, including a change in the FERC regulations or the competition-related changes in the PUC regulations. (See " Competition and the Customer Choice Act," Note E, on page 58.) The Emerging Issues Task Force of the Financial Accounting Standards Board (EITF) has detennined that once a transition plan has been approved, application of SFAS No. 71 to the generation portion of a utility must be discontinued and replaced by the application of SFAS No.101, Regulated Enterprises - Accountingfor the Discontinuation of Application of FASB Statement No. 71 (SFAS No.101). The consensus reached by the EITF provides further guidance that the regulatory assets and liabilities of the generation portion of a utility to which SFAS No.101 is being applied should be determined on the basis of the source from which the regulated cash flows to realize such regulatory assets and settle such liabilities will be derived. Under the Customer Choice Act, the Company believes that its genration-related regulatory assets will be recovered through a CTC collected in connection with providing transmission and distribution services, and the Company will continue to apply SFAS No. 71. Fixed assets related to the generation portion of a utility will be evaluated on the cash flows provided by the CTC, in accordance with SFAS No.121, Accountingfor the Impairment of Limg-Lived Assets andfor limg-Uved Assets to Be Disposed Of(SFAS No.121). The Company believes that all of its regulatory assets continue to satisfy the SFAS No. 71 criteria in light of the transition to competitive generation under the Customer Choice Act and the ability to recover these regulatory assets through a CTC. Once any portion of the Company's electric utility operations is deemed tn no longer meet the SFAS No. 71 criteria, or is not recovered through a CTC, the Company will be required to write off assets (to the extent their net book value exceeds fair value), the recovery of which is uncenain, and any regulatory assets or liabilities for those operations that no longer meet these requirements. Any such write-off
)
of assets could be materially adverse to the financial position, results of operations and cash Dows of the Company. The Company's regulatory assets related to generation, transmission and distribution as of December 31,1997 were $561.9 million, $33.2 million and $85.8 million, respectively. At December 31,1996, the Company's regulatory assets related to generation, transmission and distribution were $492.6 million, $41.4 million and $102.8 million, respectively. The components of all regulatory assets far the periods presented are as follows: Regulatory Assets at December 31 k 1997 1996 (Amounts in Thousands of Dollars) l Regulatory tax receivable (Note A) $301,664 $394,131 I Brunot Island and Phillips cold reserve units (a) 105,693 - Unamortized debt costs (b) 87,915 93.299 Deferred rate synchronization costs (c) 37,231 41,446 Beaver Valley Unit 2 sale / leaseback premium (Note 11) 28,554 30,059 Deferred employee costs (d) 25,130 29,589 Deferred energy costs (Note A) 23,514 - Deferred nuclear maintenance outage costs (Note A) 17,013 13,462 l Deferred coal costs (c) 19,711 12,191 DOE decontamination and decommissioning receivable (Note 1) 8,847 9,779 Other (f) 29,613 12,860 Total Regulatory Assets $680,885 5636.816 (a) Through its analysis of customer choice in the Restructuring Plan and Stand-Alone Plan. the Company determined that Phillips and a portion of Brunot Island would not be cost-effective in the production of electricity in the face of a competitive marketplace. (b) The premiums paid to reacquire debt prior to scheduled maturity dates are defened for amortization over the life of l the debt issued to finance the reacquisitions. ( (c) Initial operating costs of Beaver Valley Unit 2 and Perry Unit I were deferred and are currently bemg recovered over a 10-year period. (d) includes amounts for recovery of accrued compensated absences and accrued claims for workers' compensation. 1 (c) The PUC has directed the Company to defer recovery of the delivered cost of coal to the extent that such cost exceeds f Fenerally prevailing market prices for similar coal, as detennined by the PUC. (f) 1997 amounts include $6.8 million related to Statement of Position 96-I. Enrimnmental Remediation Liabilities for l the ongoing monitoriaF of certain of the Company's sites and 56.8 miP. ion of one-time costs for the 1997 early retirement plan recorGed in accordance with SIAS No. 88, Employers'Accountingfor Settlements and Curtailments of Defined Benefit Pension Plans andfor Termination Benefits and SIAS No.106. Employers ' Accountingfor Postretirement Benefits Osher Than Pensions. tSee ' Employee Benefits," Note M, on page 70.) , 1 3 i
F. Short Term At December 31,1997, the Company had two extendible revolving credit arrangements, including BorrowinD and a $125 million facility expiring in June 1998 and a $150 million facility expiring in October 1998. Revolving Credit Interest rates can, in accordance with the option selected at the time of the borrowing, be based on Arrangements prime, Eurodollar or certificate of deposit rates. Commitment fees are based on the unborrowed amount of the commitments. Both credit facilities contain two-year sepayment periods for any amounts outstanding at the expiration of the revolving credit periods. At December 31,1997 and December 31,1996, there were no short-term borrowings outstanding. G. Income Taxes The annual federal corporate income tax returns have been audited by the Interr al Revenue Service (f RS) for the tax years through 1992. The IRS is reviewing the Company's 1993 and 1994 returns, and the tax years 1995 and 1996 remain subject to IRS review The Company does not believe that final settlement of the federal income tax returns for the years 1990 through 1996 will have a materially adverse effect on its financial position, results of operations or cash flows. Deferred Tax Assets (Liabilities) at December 31 1997 1996 (Amounts in Thousands of Dollars)
$ 210,394 $ 175,427 Tax benefit - long-term investments 58,137 61,131 Gain on sale / leaseback of BV Unit 2 40,573 44,067 Investment tax credits unamortized 19,637 19,222 Unbilled revenue 65,210 50.648 Other 393,951 350,49T Def aed tax assets (712,247) (783,851)
Property depreciation (125,171) (150,346) Regulatory assets (115,383) (59,781) Leveraged leases (31,360) (33,3? 1) Loss on reacquired debt unamortized (15,910) (5,054) Deferred coal and energy costs (87,095) (77,221) Other (1,087,166) (1,109,584) Deferred tax liabilities 5 (693,215) $ (759,089) Net Deferred Tax Liabilities income laxes 1997 1996 1995 (Amounts in Thousands of Dollars) Federal $ 3,911 $ 85,976 $ 77,667 Currently payable: State 31,083 44,582 29,915 Federal 69.324 (18,737) 2,550 Deferred - net: State (93) (14,874) (5,640) (8,420) (9,559) (7,831) Investment tax credits deferred - net
$ 95,805 $ 87,388 $ 96,661 Income Taxes Total income taxes differ from the amount computed by applying the statutory federal income tax rate to income before income taxes.
Income Tax Expense Reconciliation 1997 1996 1995 (Amounts in 7housands ofDollars)
$103,217 $ 93,284 $ 93,528 Computed federalincome tax at statutory rate Increase (decrease) in taxes resulting from:
State income taxes, net of federal income tax benefits 20,143 19,310 15,779 (17,831) (15,116) (5,478) investment tax benefits - net (8,420) (9,559) (7,831) Amortization of deferred investment tax credits (1,304) (531) 663 Other TotalIncome Tax Expense $ 95,805 $ 87.388 $ 96,661
H. Leases The Company leases nuclear fuel, a portion of a nuclear generating plant, cenain office buildings, computer equipment, and other property and equipment. CapitelLeases at December 31 1997 1996 (Amounts in Thousands of Dollars) Nuclear fuel $ 92,901 5 79,103 Electric plant 20,761 20,505 Total 113,662 99.608 Less: Accumulated amortization (50,725) (47,670) Property Held Under Capital Leases - Net (a) $62,937 $ $l,938 (a) Includes $2.874 in 1997 and $2.618 in 1996 of capital leases with associated obligations retired. In 1987, the Company sold and leased back its 13.74 percent interest in BV Unit 2; the sale was exclusive of transmission and common facilities. The Company subsequently leased back its interest in the unit for a term of 29.5 years. The lease provides for semi-annual payments and is accounted for as an operating lease. The Company is responsible under the tenns of the lease for all costs related to its interest in the unit. In December 1992, the Company participated in the refinancing of collateralized lease bonds to take advantage of lower interest rates and reduce the annual lease payments. The bonds were originally issued in 1987 for the purpose of partially financing the lease of BV Unit 2. In accordance with the BV Unit 2 lease agreement, the Company paid the premiums of approximately $36.4 million as a supplemental rent payment to the lessors. This amount was deferred r.nd is being amortized over the remaining lease term. At December 31,1997, the deferred balance was approximately $28.6 million. Leased nuclear fuel is amortized as the fuel is burned and charged to f url and purchased power expense on the statement of consolidated income The amortization of all other leased property is based on rental payments made (except the BV Unit 2 lease, see " Depreciation and Amortization" discussion on page 54). These lease-related expenses are charged to operating expenses on the statement of consolidated income. Summary of Renta! Payments 1997 1996 1995 (Amounts in Thousands of Dollars) Operating leases $60,684 $59,503 $57,617 Amortization of capital leases 16,847 19,378 26,705 Interest on capital leases 3,435 1,703 4,332 Total RentalPayments $80,966 $82,584 $88,654 Future Minimum Lease Payments Operating Leases Capital Leases Year Ended December 3l, (Amounts in Thousands of Dollars) 1998 $ 54,326 $ 26,401 1999 54,319 16,417 2000 54,280 10,446 2001 54,195 4,717 2002 55,746 3,342 2003 and thereafter 810,097 16,649 Total Afinimum Lease Payments $1,082,963 $ 77,792 Less: Amoen 7 presenting interest (17,729) Present value of minimum lease payments for capital leases (a) $ 60,063 (a) Includes current obligations of $22.5 million at December 31,1997.
1 l Future minimum lease payments for capital leases are related principally to the estimated use of nuclear f uel financed through leasing arrangements and building leases. Future minimum lease payments for operating leases are related principally to BV Unit 2 and certain corporate offices. Future payments due to the Company, as of December 31,1997, under subleases of certain l corporate office 3 pace ate approximately $5.9 million in 1998,56.0 million in 1999 and $27.6 million thereafter.
- l. Commitments Construction and Investments cnd , ,
The Company estimates that it will spend, excluding AFC and nuclear fuel, approximately Contmgencies $130 million during 1998 and $100 million in each of 1999 and 2000 for electric utility construction. In 1997, the Company formed a strategic alliance with CQ inc. to produce E-Fuel *, a coal-based synthetic fuel. The first six plants to produce E-Fuel are under construction, and are expected to be in operation by mid-1998. The Company estimates the cost of this construction to be approximately
$25 million in 1998.
In February 1998, the Company issued 159,732 shares of DQE Preferred Stock, representing an investment of approximately $16 million in a water company. The Company has committed approximately $24 million for additional investments in water, wastewater and water services companies for the first quarter of 1998. In 1997, the Company entered into a partnership with MCI Communications Corporation. The Company expects this partnership will lead to investment opportunities in the expanding telecommunications business. Nuclear-Related Matters The Company has an ownership interest in three nuclear units, two of which it operates. The operation of a nuclear facility involves special risks, potential liabilities, and specific regulatory and safety requirements. Specific information about risk management and potential liabilities is discussed below. Nuclear Decommissioning. The Company expects to decommission BV Unit 1, BV Unit 2 and Perry Unit I no earlier than the expiration of each plant's operating license in 2016,2027 and 2026. At the end ofits operating life, BV Unit I may be placed in safe storage until BV Unit 2 is ready to be decommissioned, at which time the units may be decommissioned together. Based on site-specific studies conducted in 1997 for BV l'ait I and BV Unit 2, and a 1997 update of the 1994 study for Perry Unit 1, the Compann pproximate share of the total estimated decommissioning costs, including removal and decontamination costs, is $170 million, $55 million and $90 million, respectively. The amount currently being used to determine the Company's cost of sersice related to decommissioning all three nuclear units is $224 million.The Company is seeking recovery of any potential shortfall in decomm;ssioning funding as part of either its Restructuring Plan or its Stand-Alone Plan. (See " Rate Matters," Note E, on page 58.) With resnect to the transition to a competitive reneration ma;ket, the Customer Choice Act requires that utilities include a plan to mitigate any shortfall in decommissioning trust fund payments for the life of the facility with any future decommissioning filings. Consistent with this requirement, in 1997 the Company increased its annual contributions to the decommissioning trusts by $5 million to approximately $9 million. The Company has received approval from the IRS for qualification of 100 percent of additional nuclear decommissioning trust funding for BV Unit 2 and Perry Unit 1, and 79 percent for BV Unit 1. Funding for nuclear decommissioning costs is deposited in external, segregated trust accounts and invested in a portfolio of corporate common stock and debt securities, municipal bonds, certi6 cates of deposit and United States government securities. The market value of the aggregate trust fund balances at December 31,1997 and 1996, totaled approximately $47.1 million and
$33.7 million, respectively.
Nuclear insurance. The Price-Anderson Amendments to the Atomic Energy Act of1954 limit public liability from a single incident at a nuclear plant to $8.9 billion. The maximum available > private primary insurance of $200 million has been purchased by the Company. Additional protection of $8.7 billion would be provided by an assessment of up to $79.3 million per incident on each nuclear unit in the United States. The Company's n aximum total possible assessment,
$59.4 million, which is based on its ownership or leasehold interests in three nuclear generating units, would be limited to a maximum of $7.5 million per incident per year. This assessment is subject to indexing for innation and may be subject to state premium taxes. If assessments from the nuclear industry prove insufficient to pay claims, the United States Congress could impose other revenue-raising measures on the industry.
V y
9 e The Company's share of insurance coverage for property damage, decommissioning and decon-tamination liability is $1.2 billion. The Company would be responsible for its share of any damages in excess of insurance coverage. In addition, if the property damage reserves of Nuclear Electric Insurance Limited (NEIL), an industry mutual insurance company that provides a portion of this coverage, are inadequate to cover claims arising from an incident at any United States nuclear site covered by that insurer, the Company could be assessed retrospective premiums totaling a maximum of $5.8 million. In addition, the Company participates in a NEIL program that provides insurance for the increased cost of generation and/or purchased power resulting from an accidental outage of a nuclear unit. Subject to the policy deductible, terms and limit, the coverage provides for a weekly indemnity of the estimated incremental costs during the three-year period starting 21 weeks after an accident, with no coverage thereafter. If NEIL's losses for this program ever exceed its reserves, the Company could be assessed retrospective premiums totaling a maximum of $3.4 million. Beaver Valley Power Station (BVPS) Steam Generators. BVPS's two units are equipped with steam generators designed and built by Westinghouse Electric Corporation (Westinghouse). Similar to other Westinghouse nuclear plants, outside diameter stress corrc .an cracking (ODSCC) has occurred in the steam generator tubes of both units. BV Unit 1, which was placed in service in 1976, has removed approximately 17 percent of its steam generator tubes from service through a process called " plugging." 110 wever, BV Unit I continues to operate at 100 percent reactor power and has the ability to return tubes to service by repairing them through a process called " sleeving." No tubes at either BV Unit 1 or BV Unit 2 have been sleeved to date. BV Unit 2, which was placed in service 11 years after BV Unit 1, has not yet exhibited the degree of ODSCC experienced at BV Unit 1. Approximately 2 percent of BV Unit 2's tubes are plugged; however,it is too early in the life of the unit to determine the extent to which ODSCC may become a problem at that unit. The Company has undertaken certain measures, such as increased inspections, water chemistry control and tube plugging, to minimize the operational impact of and to reduce susceptibility to ODSCC. Although the Company has taken these steps to allay the effects of ODSCC, the inherent potential for future ODSCC in steam generator tubes of the Westinghouse design still exists. Material acceleration in the rate of ODSCC could lead to a loss of plant efficiency, significant repairs or the possible replacement of the BV Unit I steam generators. The total replacement cost of the BV Unit I steam generators is currently estimated at $125 million. The Company would be responsible for $59 million of this total, which includes the cost of equipment removal and replacement steam generators but excludes replacement power costs. The earliest that the BV Unit I steam generators could be replaced during a scheduled refueling outage is the fall of 2000. The Company continues to explore all viable means of managing ODSCC, including new repair technologies, and plans to continue to perform 100 percent tube inspections during future refueling outages. The next refueling outage for BV Unit 1 is scheduled to begin in April 1999, and the next refueling outage for BV Unit 2 is currently scheduled to begin in September 1998. Both outages will include inspection of 100 percent of each unit's steam generator tubes. The Company will continue to monitor and evaluate the condition of the BVPS steam generators. BV Unit I went off-line on September 27,1997, for a scheduled refueling outage, and returned to service on January 21,1998. Perry Unit I completed a refueling outage on October 23,1997. This outage lasted 40 days, a record for Perry Unit 1. The next refueling outage for Perry Unit 1 is currently scheduled to begin in March 1999. BV Unit I went off-line January 30,1998, due to an issue identified in a technical review recently completed by the Company. BV Unit 2 went off-line December 16,1997, to repair the emergency air supply system to the control room and has remained off-line due to other issues identified by a similar technical review of BV Unit 2. These technical reviews are in response to a 1997 commitment made by the Company to the NRC. The Company is one of many utilities faced with these technical issues, some of which date back to the original design of BVPS. Both BVPS units remain off-line for a revalidation of technical specification surveillance testing requirements of various plant systems. Based on the current status of the revalidation process, the Company currently anticipates that both BVPS units will remain off-line through March 1998. Spent Nuclear Fuel Disposal. The Nuclear Waste Policy Act of1982 established a federal policy for handling and disposing of spent nuclear fuel and a policy requiring the establishment of a final repository to accept spent nuclear fuel. Electric utility companies have entered into con-tracts with the DOE for the permanent disposal of spent nuclear fuel and high-level radioactive waste in compliance with this legislation. The DOE has indicated that its repository under these contracts will not be available for acceptance of spent nuclear fuel before J10. The DOE has not ( yet established an interim or permanent storage facility, despite a ruling by the United States AtB
Os Court of Appeals for the District of Columbia Circuit that the DOE was legally obligated to begin j acceptance of spent nuclear fuel for disposal by January 31,1998. Existing on-site spent nuclear fuel storage capacities at BV Unit 1, BV Unit 2 and Perry Unit I are expected to be sufficient until 2017,2011 and 2011, respectively. In early 1997, the Company joined 35 other electric utilities and 46 states, state agencies and regulatory commissions in filing suit in the United States Court of Appeals for the District of Columbia Circuit against the DOE. The parties requested the court to suspend the utilities' payments into the Nuclear Waste Fund and to place future payments into an escrow account until the DOE l fulfills its obligation to accept spent nuclear fuel. The DOE had requested that the coun delay l litigation while it pursued alternative dispute resolution under the terms ofits contracts with the utilities. The court ruling, issued November 14,1997, was not entirely in favor of the DOE or the utilities. The court permitted the DOE to pursue alternative dispute resolution, but prohibited it from using its lack of a spent fuel repository as a defense. The DOE has requested a rehearing on the matter, which has yet to be scheduled. Uranium Enrichment Obligations. Nuclear reactor licensees in the United States are assessed annually for the decontamination and decommissioning of DOE uranium enrichment facilities. Assessments are based on the amount of uranium a utility had processed for enrichment prior to enactment of the National Energy Policy Act of1992 (NEPA) and are to be paid by such utilities over a 15-year period. At December 31,1997 and 1996, the Company's liability for contributions was approximately $7.2 million and $8.1 million, respectively (subject to an inflation adjustment). (See " Rate Matters " Note E, on page 58.) FossilDecommissioning In Pennsylvania, current ratemaking does not allow utilities to recover future decommissioning costs through depreciation charges during the operating life of fossil-fired generating stations. Based on studies conducted in 1997, this amount for fossil decommissioning is currently estimated to be $130 million for the Company's interest in 17 units at six sites. Each unit is expected to be decommissioned upon the cessation of the final unit's operations.The Company has submitted these estimates to the PUC, and is seeking to recover these costs as part of either its Restructuring Plan or its Stand-Alone Plan. (See " Rate Matters," Note E, on page 58.) Guarantees The Company and the other owners of Bruce Mansfield Power Station (Bruce Mansfield) have guaranteed certain debt and lease obligations related to a coal supply contract for Bruce Mansfield. At December 31,1997, the Company's share of these guarantees was $15.1 million. The prices paid for the coal by the companies under this contract are expected to be sufficient to meet debt and lease obligations to be satisfied in the year 2000. The minimt.m future payments to be made by the Company solely in relation to these obligations are $6.2 million in 1998, $5.8 million in 1999, and $4.6 million in 2000. The Company's total payments for coal purchased under the contract were $38.3 million in 1997, $26.9 million in 1996, and $28.9 million in 1995. As part of the Company's investment portfolio in affordable housing, the Company has received fees in exchange for guaranteeing a minimum defined yield to third-party investors. A portion of the fees received has been deferred to absorb any required payments with respect to these transactions. Based on an evaluation of the underlying housing projects, the Company believes that such deferrals are ample for this purpose. Residual Waste Management Regulations In 1992, the Pennsylvania Department of Environmental Protection (DEP) issued Residual Waste Management Regulations governing the generation and management of non-hazardous residual waste, such as coal ash. The Company is assessing the sites it utilizes and has developed compliance strategies that are currently under review by the DEP. Capital costs of $2.8 million and $2.5 million were incurred by the Company in 1997 and 1996, respectively, to comply with these DEP regulations. The additional capital cost of compliance through the year 2000 is estimated, based on current information, to be $16 million. This estimate is subject to the results of groundwater assessments and DEP final approval of compliance plans. l
o e o Employees The Company is party to a labor contract expiring in September 2001 with the International Brotherhood of Electrical Workers (IBEW), which represents approximately 2,000 of the Company's employees. The contract provides, among other things, employment security, income protection and 3 percent annual wage increases through September 2(XX). Other The Company is involved in various other legal proceedings and environmental matters. The Company belieses that such proceedings and matters,in total, will not have a materially adverse effect on its financial position, results of operations or cash Hows. J. Long-Term Debt The pollution control notes arise from the sale of bonds by public authorities for the purposes of financing construction of pollution control facilities at the Company's plants or refunding previously issued bonds. The Company is obligated to pay the principal and interest on these bonds. For certain of the pollution control notes, there is an annual commitment fee for an irrevocable letter of credit. Under certain circumstances, the letter of credit is available for the payment of interest on, or redemption of, all or a ponion of the notes. limg-Term Debt at December 31 Principal Outstanding interest IAmounts in Ihousands of Dollars) Rate Maturity 1997 1996 First mortgage bonds 5.85 %-8.75 % 1998-2025 $ 778,000 (a) $ 853,000 (b) Pollution control notes (c) 2009-2030 417,985 417,985 Sinking fund debentures 5% 2010 2.791 4.891 Term loans 6.4707.47% 2000-2001 150,000 150,000 Miscellaneous 31,017 17,785 Less: Unamortized debt discount and premium - net (3,672) (3.915) Total Long. Term Debt $1,376,121 $1,439,746 (a) Excludes $75.0 million related to current maturities during 1998. (b) Excludes $50.0 million related to a current maturity during 1997. (c) The pollution control notes have adjustable interest rates. The interest rates at year-end averaged 3.9 percent in 1997 and 3.7 percent in 1996. At December 31,1997, sinking fund requirements and maturities of long-term debt outstanding for the next five years were $75.3 million in 1998, $80.6 million in 1999, $165.2 million in 2000,
$85.2 million in 2001, and $0.3 million in 2002.
Total interest and other charges were $115.6 million in 1997, $110.3 million in 1996, and
$107.6 million in 1995. Interest costs attributable to long-term debt and other interest were
$101.2 million, $99.4 million and $102.4 million in 1997,1996 and 1995, respectively. Of these amounts, $2.3 million in 1997, $1.2 million in 1996, and $0.7 million in 1995 were capitalized as AFC. Debt discount or premium and related issuance expenses are amortized over the lives of the applicable issues.
During 1994, the Company's BV Unit 2 lease arrangement was amended to reflect an increase in federal income tax rates. At the same time, the associated letter of credit securing the lessor's equity interest in the unit was increased from $188 million to $194 million and the term of the letter of credit was extended to 1999. If certain specified events occur, the letter of credit could be drawn down by the owners, the leases could terminate, and collateralized lease bonds ($381.5 million at December 31,1997) would become direct obligations of the Company. At December 31,1997, the fair value of the Company's long-term debt, including current maturities and sinking fund requirements, estimated on the basis of quoted market prices for the same or similar issues or current rates offered to the Company for debt of the same remaining maturities, was $1,474.6 million. The principal amount included in the Company's consolidated balance sheet is $1,455.1 million. At December 31,1997 and 1996, the Company was in compliance with all of its debt covenants. l
K. Preferred and l' referred and l' reference Stock at December 31 Prefcrence (Shares and Ammmts in 1htmsands) Stock 1997 1996 Call Pn.ce Per Share Shares Amount Shares Amount Preferred Stock of DQE: 4.3% Series A Preferred Stock (a)(b) - 12 $1,172 - - 4.2% Series A Preferred Stock (a)(b) - 4 376 - - Preferred Stock Series of Subsidiaries: 551.00 148 7,407 148 $ 7,407 3.759 (c)(d)(e) 51.50 550 27,486 550 27,486 4.00% (c) (d) (e) 51.75 120 6,012 120 6.012 4.10% (c) (d) (c) 51.73 132 6,643 132 6.643 4.15% (c)(d)(c) 51.71 100 5,021 100 5,021 4.20% (c) (d) (e) 51.84 159 8,039 159 8,039
$2.10 (c)(d)(e)
- 3,000 -- 3,000 9.00% (f) -
6,000 150,000 6,000 150,000 8.375% (g) - 6.5% (h) - - 1,000 - - 7,225 216,156 7,209 213,608 Total Preferred Stock Preference Stock Series of Subsidiaries: (i) Plan Series A(e)(j) 36.90 799 28,295 817 28,997 799 28,295 817 28,997 Total Preference Stock Deferred ESOP benefit (16,400) (19,533)
$228,051 $223,072 Total Preferred and Preference Stock (a) Preferred Stock: 4.000.000 authorized shares; (g) Cumulative Monthly Income Preferred Securities, no par value Series A (MIPS): 6.0(X),(XX) authorized shares; (b) Convertible; $100 liquidation prefesence per share $25 involuntary liquidation value (c) Preferred stock: 4,000,000 authorized shares; (h) 1,500 authorized shares; 10 issued, $100.000 par
$50 par value; cumulative 5 alue; $100,(XX) involuntary liquidation value (d) $50 per share involuntary liquidation value (i) Preference stock: 8.(XK),(XX) authorized shares; (c) Non-redeemable $1 par value; cumulative (0 500 authorized shares; 10 issued $300.000 par (j) $35.50 per share involuntary liquidation value value; involuntary liquidation value $300.000 per share; mandatory redemption beginning August 2000 On July 30,1997, the Company authorized and registered 1,000,000 shares of DQE Preferred Stock. As of December 31,1997,15,480 shares of DQE Preferred Stock had been issued and were outstanding. An additional 159,732 shares of DQE Preferred Stock were issued on February 19,1998.
The DQE Preferred Stock ranks senior to the Company's common stock as to the payment of dividends and as to the distribution of assets on liquidations, dissolution or winding.up of the Company.The holders of DQE Preferred Stock are entitled to vote on all matters submitted to a sote of the holders of DQE comtron stock, voting together with the holders of common stock as a single class. Each share of DQE Preferred Stock is entitled to three votes. Each share of DQE Preferred Stock is convertible at the Company's option into the number of shares of DQE common stock computed by dividing the DQE Preferred Stock's $100 liquidation value by the five-day average closing sales price of DQE common stock for the five trading days immediately prior to the conversion date. Each unredeemed share of DQE Preferred Stock will automatically be converted on the first day of the firs; ..ionth commencing after the sixth anniversary of its issuance. If the proposed merger with AYE occurs prior to any conversion, each share of DQE Preferred Stock will be convertible into AYE common stock, using the same methodology to calculate the number of shares. Dividends on DQE Preferred Stock are paid quarterly on each January 1, April 1, July I and October 1. I1,720 shares of DQE Preferred Stock are entitled to an annual dividend of 4.3 percent, and in the fourth quarter of 1997 the Company declared an initial quarterly dividend of $1.075 per share, payable January 1,1998. 3.760 shares of DQE Preferred Stock me entitled to an annual dividend of 4.2 percent, and in the first quarter of 1998 the Company declared a dividend for the period of December 16,1997 through March 31,1998 of $1.237 per share, payable April 1,1998. The recently issued 159,732 shares are entitled to a 4.0 percent annual dividend, and in the first quarter of 1998 the Company declared a dividend for the period February 19,1998 through March 31,1998 of $0.444 per share, payable April 1,1998.
e
+
e in October 1997, a Duquesne subsidiary issued 10 shares of preferred stock, par value $1(X).0(X) per share. The holders of such shares are entitled to a 6.5 percent annual dividend to be paid each September 30. In 1995, another Duquesne subsidiary issued 10 shares of preferred stock, par value $300,000 per share. The holders of such shares are entitled to a 9.0 percent annual dividend paid quarterly. In May 1996, Duquesne Capital L.P. (Duquesne Capital), a special-purpose limited partnership of which Duquesne is the sole general partner, issued $150.0 million principal amount of 8X percent Monthly income Preferred Securities (MIPS), Series A, with a stated liquidation value of $25.00. The holders of MIPS are entitled to annual dividends of 8X percent, payable monthly. The sole assets of Duquesne Capital are Duquesne's 8X percent ddentures, with a principal amount of
$151.5 million. These debt securities may be redeemed at Duquesne's option on or after May 31, 2001. Duquesne has guaranteed the payment of distributions on, and rederuption price and liquidation amount in respect of the MIPS to the extent that Duquesne Capital has funds available for such payment from the debt securities. Upon maturity or prior redemption of such debt securities, the MIPS will be mandatorily redeemed. The Company's consolidated balance sheet reflects only the
$150.0 million of MIPS.
Holders of Duquesne's preferred stock are entitled to cumulative quarterly dividends. If four quarterly dividends on any series of preferred stock are in arrears, holders of the preferred stock are entitled to elect a majority of Duquesne's board of directors until all dividends have been paid. Holders of Duquesne's preference stock are entitled to receive cumulative quarterly dividends if dividends on all series of preferred stock are paid. If six quarterly dividends on any series of preference stock are in arrears, holders of the preference stock are entitled to elect two of Duquesne's directors until all dividends have been paid. At December 31,1997, Duquesne had made all dividend payments. Preferred and preference dividends of subsidiaries included in interest and other charges were $16.7 million. $12.1 million and $5.9 million in 1997,1996 and 1995. Total preferred and preference stock had involuntary liquidation values of $244.4 million and $242.5 million, which exceeded par by $27.6 million and $28.2 million at December 31,1997 and 1996. In December 1991, the Company established an Employee Stock Ownership Plan (ESOP) to provide matching contributions for a 401(k) Retirement Savings Plan for Management Employees. (See " Employee Benefits " Note M, on page 70.) The Company issued and sold 845,070 shares of preference stock, plan series A to the trustee of the ESOP, As consideration for the stock, the Company received a note valued at $30 million from the trustee. The preference stock has an annual dividend rate of $2.80 per share, and each share of the preference stock is exchangeable for one and one-half shares of DQE common stock At December 31,1997, $16.4 million of preference stock issued in connection with the establishment of the ESOP had been offset, for financial statement purposes, by the recognition of a deferred ESOP benefit. Dividends on the preference stock and cash contributions from the Company are used to repay the ESOP note. The Company made cash contributions of approximately $1.1 million for 1997, $1.4 million for 1996, and $1.6 million for 1995. These cash contributions were the difference between the ESOP debt service and the amount of dividends on ESOP shares ($2.3 million in 1997,1996 and 1995). As shares of preference stock are allocated to the accounts of participants in the ESOP, the Company recognizes compensation expense, and the amount of the deferred compensation benefit is amortized. The Company recognized compensation expense related to the 401(k) plans of $3.2 million in 1997 and $2.3 million in 1996 and 1995. Although outstanding preferred stock is generally callable on notice of not less than 30 days, at stated prices plus accrued dividends, the outstanding MIPS and preference stock are not currently callable. None of the remaining Duquesne preferred or preference stock issues has mandatory purchase requirements. L - Common Stock Changes in the Number ofShares ofDQE Common Stock Outstanding 1997 1996 1995 (Amounts in Thousands ofShares) Outstanding as of January I 77,273 77,556 78,459 Reissuance from treasury stock 408 157 83 l Repurchase of common stock (1) (440) (986) Outstanding as ofDecember 31 77,6N0 77,273 77.556 l ma E__ _ _ _ _ _ . _ _ . _ _ . _ _ _ _ _ _ _ _ _ _ _ - - - _ . _ - - - - - - - - - - < ^ - - - "
O The Company has continuously paid dividends on common stock since 1953. The Company's annualized dividends per share were $1.44, $1.36 and $1.28 at December 31,1997,1996 and 1995. During 1997, the Company paid a quanctly dividend of $0.34 per share on each of January 1.
. April 1, July I and October 1. The quanerly dividend dectattd in the founh quarter of 1997 was increased from $0.34 to $0.36 per share payable January 1,1998.
Once all dividends on the DQE Preferred Stock have been paid, dividends may be paid on the Company's common stock to the extent permitted by law and as declared by the board of directors. flowever, payments of dividends on Duquesne's common stock may be restricted by Duquesne's obligations to holders of preferred and preference stock pursuant to Duquesne's Restated Articles of incorporation and by obligations of Duquesne's subsidiaries to holders of their preferred securities. No dividends or distributions may be made on Duquesne's common stack if Duquesne has not paid dividends or sinking fund obligations on its preferred or preference stock. Further, the aggregate amount of Duquesne's common stock dividend payments or distributions may not exceed certain percentages of net income if the ratio of total common shareholder's equity to total capitalization is less than specified percentages. As all of Duquesne's common stock is owned by the Company, to the extent that Duquesne cannot pay common dividends, the Company may not be able to pay dividends on its common stock or DQE Preferred Stock. No part of the retained earnings of the Company was restricted at December 31,1997. M. Empioyee Retirement Plans Benefits The Company maintains retirement plans to provide pensions for all eligible employees. Upon retirement, an employee receives a monthly pension based on his or her length of service and compensation. The cost of funding the pension plan is determined by the unit credit actuarial cost method. The Company's policy is to record this cost as an expense and to fund the pension plans by an amount that is at least equal to the minimum funding requirements of the Employee Retirrment In ome Security Act of1974 (ERISA) but that does not exceed the maximum tax-deductible amount for the year. Pension costs charged to expense or construction were $12.7 million for 1997,
$11.9 million for 1996, and $6.1 million for 1995.
In 1997, the Company offered an early retirement plan to its bargaining unit employees meeting certain age and service criteria. In accordance with SFAS No. 88, Employers
- Accounting for Settlements and Curtailments of Defined Benefit Pension Plans andfor Termination Benefits and SFAS No.106, Employers' Accountingfar Postretirement Benefits Other Than Pensions, the Company recorded $6.8 million of one-time costs as a regulatory asset and other non-current liability on the consolidated balance sheet.
Funded Status of the Retirement Plans and Amounts Recognized on the Consolidated Balance Sheet at December 31 1997 1996 (Amounts in Thousands ofDollars) Actuarial present value of benefits rendered to date: Vested benefits $460,483 $413,109 Non-vested benefits 25,080 22,551 Accumulated benefits obligations based on compensation to date 485,563 435,660 Additional benefits based on estimated future salary levels 68,739 61.438 IEjected benefits obligation 554,302 497,098 Fair market valu.: of plan assets 605,457 525,871 Projected benefits obligation under plan assets $ 51,155 $ 28,773 Unrecognized net gain $153,682 $128,382 Unrecognized prior service cost (39,800) (43,790) Unrecognized net transition liability (12,030) (13.853) Net pension liability per consolidated balance sheet (50,6E8) (41,966) Total $ 51,155 $ 28,773 4 Assumed rate of return on plan assets 8.0M 8.25 % d Discount rate used to determine projected benefits obligation 7.00 % 7.50 % Assumed change in compensation levels 4,75 % 5.25 % Pension assets consist primarily of common stocks, United States obligations and corporate debt securities. N
e Components ofNet Pension Cost 1997 1996 1995 (Amounts in Thousands of Dollars} Service cost (benefits earned during the year) $ 12,340 $ 12,209 $ 9,953 Interest on projected benefits obligation 36,570 32,597 30.063 Return on plan assets (95,444) (58,173) (99,246) Net amortization and deferrals 65,801 25,312 65,316 Net Pension Cost $ 19.267 $ 11,945 $ 6,086 Retirement Savings Plan and Other Benefit Options The Company sponsors separate 401(k) retirement plans for its management and bargaining unit employees. The 401(k) Retirement Savings Plan for Management Employees provides that the Company will match employee contributions to a 401(k) account up to a maximum of 6 percent of an employee's eligible salary. The Company match consists of a $0.25 base match per eligible contribution dollar and an additional $0.25 incentive match per eligible contribution dollar, if Board-approved targets are achieved. The 1997 incentive target for management was accomplished. The Company is funding its matching contributions to the 401(k) Retirement Savings Plan for Management Employees with payments to an ESOP established in December 1991. (See " Preferred and Preference Stock," Note K, on page 68.) The 40!(k) Retirement Savings Plan for IBEW Represented Employees provides that, beginning in 1995, the Company will match employee contributions to a 401(k) account up to a maximum of 4 percent of an employee's eligible salary. The Company match consists of a $0.25 base match per eligible contribution dollar and an additional $0.25 incentive match per eligible contribution dollar, if certain targets are met. In 1997, the incentive target was accomplished. The Company's shareholders have approved a long-term incentive plan through which the Company may grant management employees options to purchase, during the years 1987 through 2006, up to a total of 7.5 million shares of the Company's common stock at prices equal to the fair market value of such stock on the dates the options were granted. At December 31,1997, approximately two million of these shares were available for future grants. As of December 31,1997,1996 and 1995, active grants totaled 1,084,041; 1,698,000; and 2,159,000 shares. Exercise prices of these options ranged from $15.8334 to $33.7813 at Decemt tt 31, 1997; from $8.2084 to $30.875 at December 31,1996; and from $8.2084 to $27.625 at December 31, 1995. Expiration dates of these grants ranged from 2000 to 2007 at December 31,1997; from 1997 to 2006 at December 31,1996; and from 1997 to 2005 at December 31,1995. As of December 31, 1997,1996 and 1995, stock appreciation rights (SARs) had been granted in connection with 635,995; 984,000; and 1,202,000 of the options outstanding. During 1997,694,984 SARs were exercised; 638,494 options were exercised at prices ranging from $8.2084 to $30.75; and no options were cancelled. During 1996,715,000 SARs were exercised; 267,000 options were exercised at prices ranging from $8.2084 to $20.3334; and 150 options were cancelled. During 1995,367,000 SARs were exercised; 133,000 options were exercised at prices ranging from $8.2084 to $21.6667; and 28,000 options were cancelled. Of the active grants at December 31,1997,1996 and 1995, 402,816; 668,000; and 929,000 were not exercisable. Other Postretirement Benefits in addition to pension benefits, the Company provides certain health care benefits and life insurance for some retired employees. Participating retirees make contributions, which may be adjusted annually, to the health care plan. The life insurance plan is non-contributory. Company-provided health care benefits terminate when covered individuals become eligible for Medicare l l benefits or reach age 65, whichever comes first. The Company funds actual expenditures for I obligations under the plans on a " pay-as-you-go" basis. The Company has the right to modify or j terminate the plans. The Company accrues the actuarially determined costs of the aforementioned postretirement benefits over the period from the date of hire until the date the employee becomes fully eligible for benefits. The Company has elected to amorti7e the transition liability over 20 years. I l E _ _-- -_- - - _ - - M
*e Components of Postretirement Cost 1997 1996 (Amounts in Thousands ofDollars}
Service cost ' benefits earned during the period) $1,603 $1,182 Interest cost on accumulated benefit obligation 3,048 2,046 Amortization of the transttion obligation over 20 years 1,686 1,700 Other 218 (812)
$6,555 $4,116 Total Postretirement Cost The accumulated postretirement benefit obligation comprises the present value of the estimated future benefits payable to current retirees and a pro rata portion of estimated benefits payable to active employees after retirement.
Funded Status of Postretirement Plan at December 31 1997 1996 (Amounts in Thousands ofDollars) Actuarial present value of benefits: Retirees $ 8,150 $ 8.840 5,966 3,829 Fully eligible actise plan participants Other active plan participants 32,214 26,352 Accumulated postretirement benefit obligation 46,330 39,021 Fair market value of plan assets - Accumulated benefit obligation in excess of plan assets $(46,330) $(39,021) Unrecognized net actuarial (loss) gains $ (1,208) $ 2,874 Unrecognized net transition liability (25,294) (27,198) Postretirement liability per consolidated balance sheet (19,828) (14.697) Total $(46,330) $(39.021) Discount rate used to determine projected benefit obligation 7.00 % 7.509 Health care cost trend rates: For year beginning January 1 6.58 % 6.96 % Ultimate rate in the year 2001 5.50 % 6.00 % Effect of a one percent increase in health care cost trend rates: On accumulated projected benefit obligation $ 5,234 $ 2,920 On aggregate of annual service and interest costs $ 581 $ 391 N. Guarterly Summary of Selected Quarterly Financial Data (Thousands of Dollars, Except Per Share Amounts) h"*" *,';, IThe quarterly data reflect seasonal weather variations in the utility's service territory.] 1997 First Quarter Second Quarter Third Quarter Fourth Quarter (Unaudited) $285,861 $331,203 $298,526 Operating Revenues (a) $303,584 76,817 56,392 % ,448 51,080 Operating income (a) 45,097 46,778 58,665 48,561 Net income Basic Earnings Per Share 0.58 0.61 0.75 0.63 Diluted Earnings Per Share 0.57 0.60 0.75 0.62 Stock Price: High 29 % 29 33 % 35 % Low 27 % 26 % 31 % 30W 1996 First Quarter Second Quarter Third Quarter Fourth Quarter
$300.5I8 $293,357 $335,430 $296,890 Operating Revenues (a) 71,316 67,385 104,891 59,414 l- Operating income (a) 42,305 38,972 57,412 40,449 Net income Pasic Earnings Per Share 0.55 0.50 0.74 0.53 Diluted Earnings Per Share 0.54 0.49 0.74 0.52 Stock Price:
High 31% 28% 28% 30% Low 27% 25 % 27 27 (a) Restated to conform with presentations adopted during 1997, 72 .__
l l ll I S,hdroholder Referenco Guide - Common Stock Trading Symbol: DQE { Stock Exchanges Listed and Traded: } New York, Philadelphia, Chicago l Number of Common Shareholders of Record at Year-End: 72,557 DOE Internet Home Page A variety of shareholder, customer service and economic development information is available on DQE's home page on the World Wide Web. You also can interact with us via electronic mail. Our address is http://www.dge.com. i 1 Shareholder Direct Shareholders and potential investors are invited to call 1-888-247-0401 for the latest information on earnings and dividends. Shareholder Services / Assistance By telephone, representatives are available from 7:30 a.m. to 4 p.m, (Eastern time) to assist you with the following services: Direct purchase of initial shares Direct deposit of dividends Automatic cash contributions Dividend reinvestment Stock transfer requirements Dividend payment inquiries Change of address Lost stock certificate Please feel free to call at other times. Our Message Center is available 24 hours a day. You can record a message, and our staff will follow up on the next business day. g Financial Community Inquiries Analysts, investment managers and brokers should direct their inquiries to 1-412-3934133; Fax: 1-412-393-6571. Written inquiries should be sent to the Investor Relations Department at Box 68, Pittsburgh, PA 15230-0068. Dividend Tax Status The Company estimates that all common stock dividends paid in 1997 are taxable as dividend income. This estimate is subject to audit by the Internal Revenue Service. DOE and its affiliated companies are Equal Opportunity Employers. The DOE logo is a registered trademark of DQE, The following trademarks and service marks of other companies also appear in this report: ALLEGHENY ENERGY, ALLEGHENY ENERGY SOLUTIONS = (Allegheny Energy, Inc.); BROADPOINT COMMUNICATIONS (Broadpoint Communications, incJ; DSTV (DSTV Holdings, Inc.); E-FUE L (CQ. Inc.); H POWER (H Power Corp.);ITRON Utron, Inc.); ONDEMAND ENERGY SOLUTIONS (OnDemand Energy, Inc.); PROTECTION ONE (Protection One Alarm MorJtoring. Inc3: RECRA ENVIRONMENTAL (Recra Fnvimamer.tal, Inc.); SATCON (SatCon Technology Corporation); WEATHERWISE, WEATHERPROOF BILL (WeatheFNise USA LLC).
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