ML20236M851
| ML20236M851 | |
| Person / Time | |
|---|---|
| Site: | Pilgrim |
| Issue date: | 12/31/1997 |
| From: | Desmond N, May T BOSTON EDISON CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| BECO-2.98.092, NUDOCS 9807140283 | |
| Download: ML20236M851 (117) | |
Text
___
O 10CFRi40.iS(b)(i) r sonean Edieon Pilgrim Nuclear Power Station i
Rocky Hill Road Plymouth, Massachusetts 02360-5599 l
l o Ltr. 2.98.092 Nancy L Desmond Regulatory Relations Group Manager July 6, 1998 U. S. Nuclear Regulatory Commission Attention: Document Control Desk i
Washington, DC 20555 Docket No. 50-293 l
License No. DPR-35 Annual Financial Statement for 1997 in accordance with 10 CFR50.71(b) and 10CFR140.15(b)(1), Boston Edison submits the enclosed 1997 Annual Report and the Securities and Exchange Commission (SEC) Form 10-K which corresponds to the 1997 Annual Report.
If you have any questions on this documentation, please contact Mr. Robert Cannon at (508) l 830-8321.
1 M
b Nancy L. Desmond j
Group Manager Regulatory Relations o
RLC/dcg/298092 L
l l.
I cc:
Mr. Alan B. Wang, Project Manager Project Directorate 1-3 Office of Nuclear Reactor Regulation l
Mail Stop: OWFN 14B2 U. S. Nuclear Regulatory Commission l
1 White Flint North
{i 11555 Rockville Pike Rockville, MD 20852 l
U.S. Nuclear Regulatory Commission Region 1 475 Allendale Road King of Prussia, PA 19406
,}7 g
4 Senior Resident inspector Q
Pilgrim Nuclear Power Station y
w/o 9907140283 971231 PDR ADOCK 05000293 l
I PM L_-_
,,,.,,,,3ll,',.,....;..L: ).,, ;h ;.'..' ' ',. ', '.. h,,,'.
1.. ::..u
. ~:. *;'.:
..... ' 1
- v. ' e. '. :,, :
1,,,,,, [
[..'
li.,. ' ' *
...:.'.L.
..,,.. :i
<.s
.. ~ :-
...,:..v-n..
-l'*.. ;.:. '.. :. '.. '.h, 15,
- . t.
.I y T.;.;,h.p'((':. ,', -.,,, ) "..(,-l :'
- c. 'l.., e.. [' - ',.., ',.j/ h :
.q'*. - 5;ll !.;/,<, f,'. I,'i[l[
. ) 3. ;. ?,' t [
.. ~
- 4'
<} l,:3..
f;. _ ;...
.e f,.'., ' ;.'.. h..? : ' ?:.'.,
.. - (,
., '.,.(,'. I ^.
, f;5
':, b.....'...,." '.;. i.
.3-
- c
,.V'".'
.,. *" % l;; '. l: :.
_,,',. '...........,.. n ll :/ ~,.(,.): ; ?; '. ;..' ',' b,,,
g_'- l: ','\\'.2.. 'g:' ' _; % ' l.'
4.,' 'p.:;':.
f ". '.,,.s
.,. - ?ll. ?_.,.,.;-;i'-*;l [ :. t ; ^ Q '
T((_.' [,. h1
- ' ::'i, ': 'l,, ^ f. V -
':%.. :',.] ;, s s..
e
- ,<,.x r., ;,
..r;..... : ': ;. l. ': ', ' ' G.: : : -7 :,3 _.., ; (,q(.V" :
W '.. d '.. L e';. Q: ' ). *:.
- <: '. ~ ; ~; * *,'.... r c.':
.4i. c.' :sVlL K',;-l'.:
...,,;,,, : 9[: ;,_...(
.. ;f 3.
..../
J~
- , (., y'._.
i. -; -
-, - c.
- 9.., ',;.,.
e g:._..... :l. ;t..,, y. *. 8.n c; :.~,. ' ' " _:
- '.. ;;,'e.. q :'. :..
~
n.,
y,,_
,.;,.... '., _,:...4..,',
s ',; ' L.,y,,,...%',
.a ; n'..
.l
?.
',; },, x,.... h '.x.;. '.. ' Q. ~.,,
3::,'
'. ;. 'p. A. '
't'
- . x._, >-
. _. ',..b
's
,9<.,. ;, :
.s...,,
[_
(
- h:k M. }:,%.'? f:.,: ' ~ :.. ? '~. ' '.,., , ji,. :. :' :,;.] ;& ;' _.'y'.[f.: lo f i_;'.i.:. ' :',', ' '...((
v -
s,
. ^ N 'l : ' d, l.$.....* ', > '. ' J. l
- ..j.L
- . ',. _ (.. D.. ; ' _;l: ' ;f', Q...., )f,:;j !; * ' ':
l '*.', ll." (!:<lc,i:.'. ? ' l L
.. ' ';l '.y',.,..';., _!' ';M:;....,.t1,,.;
'..zk :j.
,r' :.;. '. : '., i ^ : : ' s 1,[ 7..; '.,f.y..:
,,_.;.,? i.. '. : '".;; }. :.,,M:.L V ' "
':; D.. ;','-l '; ',...,'..,'Q..,.'.1;'*;:
6 ), + c,, ' l:.'l'.
.,,L
.Q l' y.;.
Ji -
,\\...",'> ' : '.... :,;.~.,: n f,,. r;+.ex;. <. q... :
z. w... :p,
- :,. s.... ;... : s... ~:.,.z : y 4 y
. v;
.. -v;:
,..,.,.,,..,, ^ '
.,i; *.['..f'? 'I,t i,'
l,...<.
.....,.,,.. '.- e '
I., ' ' I. ' h,. ?..;
s.
. ' Q. b..- "....:N'.,,.,.,.'!.l L l9...; } I ' :. '.Y 'L ', i i '...lll l l,'_ Q
-s
. ',. [' }, ' k ~., '...'
? _ c lP. st l.,, h ?
',4
- . ;[ .,f.';$' ;. ','. ?.'.,:o d $ ' _ v !
..' l. 'l',;*,. '.'z'. y, ; ??$ _ti,,,'; '.\\.'{!/.,..,- f' :S
- 7. l' ', ;.N I 2 ',:.,'*- 'L..;..[
~ h,..'). 3, :,:,",*. i.. 5,.4. $.. ; ; '. '. ' :'_' ',' ' _ ;):.; ;. '..'
' i: _ -
'.: \\. - )
f.! _ '.
=. ;,....' Ulg];., * < <.. '. :,'%. t.
'..'n,,
' }., l; : ' '..,T.,,
- ' *..,,',,' l, * \\. ',' e',( *
- (
T.,...,.., : ;.. j :., '
_. !L '.
,' _t; V '. :
- -'U
- ?
h...-
sj' lll.',.
n:,
_.>.)(. :.
- V:
l
^
F,
- 1, :_,p
_..,':' ' '... '; d' ? q.4
.b.
- -. :' ? ?; . "'..*;..
~
,'; ^.r.;;
- q...' '.'
._,..Q p.V.',:.,. y ' ~ 1,;
.'?.
-.;, ? ;;.h }l* i.'. ';,~.
i.'* s,J &
',;,: * '.fi *,., * '. '_G 4,..:.
- ,.'e } ll-
+ ' ' ;*;{., !":', ' y,4 *,,,..., <.::,,'.' !. :.',,;{ y '. '
.,__'._w,:r_'..,,
Q t,.1,'
,'r y' *',,,
- i. '
.e 1 <- '=- -
...*r +.
3:*- ;'; y -
,x.- ;-, ' l, _l'
.')
- i:.f'.
's e:5.:t..
D w<
, - ;f,,., ',, *,.
- g. f*:e. :,::
..,,'\\:
- . ' =..',:. *."
l.
Q;lb ", f,.l;
$....; _, : h, r. '- ' '- l;_ ' :" : j : "'. ;; Y. N ','[,
~. ':..,,:..... _ _ ' ;,', '..,. rlq,['s.
4 n',. t;g i
_ '.. ') \\,L,. 'i, 'O : --
'1 f.
. '.,',). i -._..;.* :,,'...;_ * : *:[' '. T. ' j., '.?.. ; ^ _
'L
? '. ': -,l L.i$% l L ;' :
- ;. e
- : ;. :...
o
.n
. s
. 7-.. ; ;, >.
~,,.;..- g.,s. ;.,. ;4..,. >... r
- W. * ' : ', j.
r.,...-
,,2,-l+.+:....,.,;g
,.;... c,
,e
$. -...,.,- -,...., ', 'i'.?," ,. -.
..,t...
' ' 9; ; ',.,'.. ' ' ', -.,L ',,, ',,', [ _.
.._.,e'.
p,, :..,;. h..,, ),.;'.. :
,8(' ;;'[_ ' ',
..,,.' [ _ ', : :[
- f.
'..j j, ',..
L 'U, - ' -
'e
\\ ;,,. % ' t,;, ',... ' ~.,',,! h: '.,
,,' ~
i..
3
.. ' '." ;. /.
2, :' * *,.;_ g s-_
.: e...,.,
f.
. h. ; '-^
- A,,g i., r ',
a. : '.
1
~- - '
.',,,,'.4,
..,A.'
" -,.,',..:,.. '...f', :..
, 7 J,
.:*f,. 7l'.
. :.=
5i
?' *^, '.,.*.. '..'.;) ; ' ' '. '?' ' ' $,.;., i ', - ~ 5.
,9* ' ' '. ',...,:,.;'..',,_',3...., 5,._, [ *.,*
' " f ',. * ;'. ' a **..;...,.'I
~ l Y,,Q_ '
- <.;,. ",;. ' f. _.. ', f&^ t
^k
.. '.h,0, ';
l.
- ll.,_.,. - Y.;,
- u..;9'4 )':**g.
,i
,., -...., ' -. '. : {.
s
. 1. :_,,
y,_,
.L,...
ys..'.c
..r'..
- .N ;'
. ~. -'. -...:,',
a-
_'....;...,,. : u'-.-.
l_,,,,
W... ' ' ' Q:,, ', :,,
- 1. '... -
I
_. y; ;,. ~, ' y --s'
-} _ - '._
. s' i., -
- '.. : (... - -
.p - >
_ _ ?.: e.
..s.
_,g o.
- .s.,
-,.st
,n,'
- ^
,a.. '. _
s'.
,-[*,,,;;'..'^.',,_-r -.&... *..e):.';,,,',..
.c
,,:',. : ;.,. ', v
.;.s...,...';..*
j 's., jn.,.~.~*':.%. '*,'.a.... - _ - -
4 q;..,
= * ,_,..._'n.-
..'.;,1.r,... ', '.-
i.
,....a.,.-
y ;..
T-w
-,% ? [,. *
,u__
',.....:\\L-
- -c,_
>.,.'s..,.
?:~,;,. -;,-' <.,..,.,,. _.,.,. '
.r,'-,,. ; * ;. ',;.
.- ' :* t ; ~
.. ; ? ;.,.,.,...;_
, ;,.pf ; ; <., ~ a _,-v 4
.,,**.s,.,
- e.'. '.,.^
1.
s
>. '...,1..
~ -
,l*.,,.';:.'._<,,. '.. '-l',
_.2 a--
-'Ql-'.,. ' '. ', * ' 'n'-
-r : i.; -'.
p....
.t
--s v
.u.
,x
.. r
.-*l '.f l, n.$., T ";,. '.. ; f
l
... - [ ',';, : ;,i. "7,. ' :. *,,
's.
- -.,., - '. 7
.s V.
'p'
, -?..,,
'.;i- - - '.,;;*.:,, v:V t : "
e.
',.9,,
' ' '.. p 'f ".5 '.,./ !l .
.q
','. l.)
y
(, i.,...
.g. ["
"[
l '
.J' !
- ....:,_,, [..: - -
e.
'. - {.,'s r-,. '. '
M. y:_,... ; ;.'3 ;. -
.._,,.t
.,...t,...,.
- ;;. f '. p. f,; *. ',
v..
. :' o '
. : v.., ;,
_a
..,,. ', '...,...,,e,'.'
,.,a ;':'i....., '.,,,,-,..
, =..
....,J
.,.7..e.
.,.....,..'..'..;: -, s'.;.g e.,.,
,,.'s'
'.. * ; N.'. ',,',:
,u., ",,,.,. -.
- j
.s '.,
.i r
e-
,; ::f,. y.
,,... ;! '...T.
g.,
1-. l ?-
N "_
. _ f. :..
. '... ~. '.
- Y:
'l_ k'l.....
e -r
' ' ; P.
.. '.:,, ' l },,[' *
,...'*:;j..'W_..'.'...'
ll.. ;,~.': '.;.'. ' :;..
- * *,E, ' ' '
,l..
e ' '. -,. -.
,._..,...').
' :'_:',.; ' e..: - ', :.
..:*.'.~.,:-
.,,'.g
. :.' _ _, _ '., 4 _ :. '.:',
'!.: l'
--. i:,*, -
. _.-'. : /.
. '. ',m.
f...'-
. * +
c.
ei '
'.l',.'.-,"7
.q '.,', ',, -, }
l :'.) " ' '. ' : *, =.. ? l '. ". ' ' ' '
- *, -..,j. 3.;
,..,.... *,.,y
- .'l, *1: *, '.,, _, '.
.!l.'
^
[ _' f.,;,' ' '.[
- l. 1 ",.. ', [ ' ' 7, ~.f,,,., ', ' ',
'l._'.,
' l ;. ), !.',.
_ ',
- b ' ' e.l l
,(.-
7'
- '.l.,f, : } "
.;?.' : '.]'l,'.
. f,/,
.[.'; ;, ;dl l ' '," ( ',', f., [ '. ' ' ",., N '.. j... :.,,,%,.
'J.
'),".
,...s
.1 l
~-
., '..t-.,
.,l,
,.f..-..
i,,- :
'g $.-.,
.g..,,
,,.. < * - ', y, f, c
.g J',-..
m,,#
+*
..:,",I..
', '., '. ' +, " *.. ',; +',. '. ' T ) l A ^gJ. * :
,4,.'..
, '., 's.
l ;,l
- .- - l ? !.
,._',.-}
. - l.
M4 '
l, :
- r
'- - -:., ', L:
,','v' t, ','.; ;',* I,
t, s
,:: '- ~
r.
{'_,...
_,, ; -l
. ;- Q, @g,n n;t.., V, r * ',..,,.
, 7 :..,..
. ll.) 9. - *.,
..a
-l ;-
',.,*,s,;.',;._....,,,.,,i
. ~. - -..
s.-
.,[.,......
l
.'q.
.m
..,3 "c=,:-- :., '...
'e
,' y :D'..e
, ',; ) ;
%,' l
?
.,,1._ -.';.' ' :-1.'
o_, '.
T' y.'_
~.w....',.
o,
,./
/$
h,','
- f
,..,i ls [,,
.i
- ' ' '[.,
.y 1 '"
. h 'lty,'.,,
)
f,,
,[
[,'...
^
- 3
- 4.,....d.; & y x@ n -
n*... ' "y t : +., 9.. '. ' :. '& r.. 3:~:.
-.. r-
- .w c.
- y.;'.
L
- .. ; r.u-
- A'k;w
<.. : 4. s..
...', ' ' _f l
- . m ; ' gf' '.,.
..g : a q,
'g. * ~ :. '.... f y,,., ' ls t
- *r',.
'.n,[, '
y
&*%5 *'.
g i
t.'. Q.
'l; . '., ' ' -
, )q,,
. = '.. '
', _..j ;..;j:l.,l'lf..
'f W' _,,
:?
l,' :s.,
w....
-,.. :,t -* *
- n
.;.O_l
- .,)
. f.,u.\\ :;f :".,'.j'f f,,.k.',;: l f. 4
/
. :o_
,_[J )'l l,j.k.< '
A
.. li....
.y...g
\\, s,
's X_. ;
ny
... y ' ~n,, :". y c
- p. s i %,.. : ; -
)y;' ',,
s.
.1 - '. A.'_
., y L.<. :
< y*
- v. )
4'..'
, ; l;
- g -....,
~r.,.
... I, :
m
..'.ol., '.[ %.A'.;.'o.}: ;... - % 'Q [ r l-l. '." *. q.., < 9[l,+ ;
'..'n:' Lif
'2,Q..,o.. e.Q.7,!* ?,3.
- p'. j' '..
l
.-*. 's p..
,1 J. }
- A,'
( !
- ,.',_y,'.,?.' ".
'- -)',1' 1
'e o
- ,.,f
_.y l
,'q..
" ',.' - '.f f' ' e [. 3-60
..)
' lqy l' _ ;
7,:. fevy y:n.. _J'_:.,;; } eQ'?_ A.c,b. F**
i l.'. Y
. !;' 'J..'; ::. ;,' - ': ; %
s
-^ l
_ }: _ ;,,
',Q., ;.i :.e.,:
- '?
., ' : f fl". *lR lhfIy
.Ay s,.
's.
'y
-.y,..
- 0 /.
..h
, *. ^
- i y.
'- C C ; *. E'A:
. m..
J*
/
h, f,. * ',
t*.
_ ~, _ ' g, ' ',.I; * ;
-t;~ *
.\\.. ' y,. }%::.% ? H. %. s..f'y'.
.- {..M. tM' q. : y. g &.
, T'8 ::x' V
.n n v.m
- ~ v.;lc.:
- 9.'.
.n
- m. _,L;: m :. : ;
.N W M,+c., p+ y/ji'y! n,., v, y j', '..,9 :-
.t:..'.',.
- 9,..;i.. m
- %. ;l,'
,J ; V x 7'
. '....' Jf 8' e 9'k 'g.*;;.f.
- R, L
. v:.;s n
- .x Q.
.y s:.
,- p 8.
.,,._ A; M
, +
+~
-[
I
....A,..'h 4.
. u. 'L'.:
- x. 1 7,;, *
- .6. 'y.' *- <
- . F e M)&' M i:. %,'f..: :.i : *,:,.. '.,.',. '
.l",.
q, p' !.". -:.. x ; s
..g,
'..I
. i 4
m.,
L:
..',,,)
Q
?_',
{f l.
. /.-:
I
<e
.. l%.
f'*^'.,._
. [..,Q '
.',"*.' ; 4.
' Y
- 4:.$. '; . x,_. : yy. ;,_
, - ~ -;. _.'s., f: *
- p
'l._
., e
.. :,:... ' f.
qp. T.
y.
% ' '. _e: ::::. _,;;.. l ;..
- ~ ' :. 7. ;p:.~ +h.;.;g. R_ t.O.. :.;.(^ q.
y'-
y _ ;v.
~ --
~:% ; -
. r -
v
. s.
w v..,
.s s.c j,
g,.
~q
'. s.,.
- g,.,? '..: ;\\,\\' y
'..'g.....,:.' '
.-l*_ ;..
~ ;#
,. _......,,{ * ? \\ V -l * :...
.e 9
,,v"_
'.'y'l'.,, -' '. '. ' '.~-
s.1. y,.R, $'3,
- s-
.a
]_.',,'.."_.
- i',., 4.'.S.'.'.-*
lt J..
- .1
. >I
- d
,'.(-.,-
.g~
l*
,c'
.sey t
\\
,r g.
.i e..
- u**
r
,.o-4
- a. : la,. '
.6,,
e.'a
+4 u,
.f
'l
. j. p ,.'.....
. if/
.,..,', Q. ' :.'a~.-
L. t -
2.""'
's.1 l8 ' *;..
'g g4*J.- 46, e* ~.
, / d, '--
, %.. s., k. [h.
't, ',-':y
. :-N _ :. '_ ' :
- j. A ?'.. ' '...
., -..; h,.. ' ll%.
_ ?^5Q )'..'.'. ( ".j,%.
,^
-.4
':~
)?
,,;.. > l-l?, 2 " '._,k ;.'. ;. : :
n'.-
a<
i.'". r. h.N,j '?,,d..h.Q
'{r W.ut
- *W.:: :'u~. 5.. '.,; g. ; f.. ;:7.Q d
C a
"?
- r,. s
..?-
,,;.e
- ~ -: :
n
~
3 t mm. & f;V" &'~ N;'.l*,Mff, - ' ' ' :
.. :1.'y <:
'., \\'.: ' '*(kv,. lQ:.);
f' t. ' -l
..
- i W.
C
~:l L
=,.
,Q ' '_J.!*L _ ;a 1 ;':
^ ' ', ~ ' -
,'q*&,.'-:...,,4
.' i'..
~.'%
%..',d..,...'1,,.:.
- .t
- 3
.T -i :
?
' h)q :*.
'.t.l:.1 y..,'n
- ,,, '; : q, e.p
- x
^ '. p\\ ; J' '.e.'q: s',f y -.'h'..
,,. g y, s. ;3.,,,,,, v.,.."*,;,.,..L.,*'.,.:,,
ot,,'.,,,..f..'L ;
'..r,.
Y J
'c,'
',b.S'.
s
- s f
3.,..
e_ _,j.;
V: %;.,,},.., 9,,..Q','___.-
p -.; u *, :, p.:
'.,.;-['.,
,)
_r
,.y _ f, q l, l.',. f: ",: *5 ' _ ;:.. :'.,, '. ;,'..*;'..
? - +.. '.. --
..._;,:. :* 1 V:
. f.
- %'..:.,.'.'..,'...,..:;:7
..'..., v:
- p;... ;. 3
- . : u r;,
e,.
' d ;,,. ;,. p,1.. '
.'t.,
_ ', '. -; q-..... * *
,'r,
- 7. : :..
n
... % ; : -.. y t ' _ ;;._'; L,
. ; *. s. -
.y.
' 2
^
v '. n. r
. ;.. ;%; 3..' ;. :....
- v".,,
v Y.,.;:e:. ' ; e 2. :i. :t,..., -
y.
~.:..?q. -
e. - v..
t
~........
'.... ~. -
u:
.. ;l....
q.,..
...i.,....
n.,.
5..., v.,.: :.
t; ;. '.. _y:s. e. :e. '
. ;,.'.'.'.t.
- 3 :
,..i
- 4. -.
~.....,,....
. 4 *4_.. v. : '.: ; ::...y,.. s :. ' ~
- c.*2'.,. -.:...;...........
a
. s....x....
n f.:... :.'L'..... -.,
- g %...
.c r,
., :.,... - -.... t:,.
~..-v.-
'... u:-
.1 w.:. :.,
-,,c?.=.8 v..
- s: '.
s -..
- .. ). (,
.o
..,f..
n ;:..,.3l:.
.,,',, ;..,n ;
a
.,e
-.,; i'..
.a.',
.....&f.7 s
n.
L.
"...l
.e...
... _ :. r,
>...(
. :.: __ >. :3 2.u.. q:,..'. '.; _,,,...,....
e-
. M;:. s
. :. % ; : '; ';,:., '. :s i..., 3. ; :-. _.r g ;:,,J: ' ; p'... -.::.'..y.._..y'.-
c
,f.
^3
. :: ' g 2, ',\\.,.'.y lh<.
4 r,
,e,
, ih
., ~. ;
.e. ~.g.
...;,..'.c,.j.,.-: (......., 1,
. c,,y;,,.
t.g
,.,.. (f ;..
'.,,,\\... 'q.. 3 3.. _..., s.
.y,
,,.7
-...l.' '.',V.'._l.,._.,..':.-
, ~.,
.'.o
,.y._,[.3,...
y;,:
4,. r.
-,...;....g 1
i. ;.
,,M
, 3. ' :. ~..
.o:
.: :'. 3 :q...,;......
- v.,.. ~,,[. ;,...:.
.a;..__
y:
.,~'.p.
^ _ 1
.f.,.
v#,
'. l : ;.i.
.,4
~
. ',.>.'.,i. > +. -
.. ' l:,v. - y..,,M ' ;.. ' A. ' ;.....\\;c.,'.:....... ', -. -+ f,.o;
.c.
- n
..t.
., y. ;
r m,:.,..,....
. ?; :,, :
s,.,
6
...u,3: 4..,' _.,.:: :, : ',,.,...J.. : ;:., i,..:,,-<~-
.s.
- .
- c.
e...eq...
g.y n-n
.f y
g,
- p....,..c y
6,.... *. ',.-
+.i..?.
.~
..g.
v.:.,
s...
'.r.. '.. :.lL '. ; 7.:4 ' J,,s..
- )..... !....' :. '.. -.
s
--..., - '.. ' '. ' ;,.T :.. j ',;.;.:"..v L. l.- ll. $ 3.* ' y '..,,., "' < n ;.' *.3_:,)
M.:
r.
.s c
,s r
t_.
.'...,.....{'..s.
_M. *., : -..,,..
- -..'l
'..,_,:%. :. *. ',l(.'.. :' -'84 k" "., '.( :.;[L'.. % :[ ) * :.'.,;
.'.'._.,l;,
', :. : :',',:... i ','..'.;,*.
'.f u.. g -..';u ( _ _. q,p...;... ;.. '.. s, y.
? :.'; '
).
r.-
...,.., s);1 -.
'7.,,_,,
- ... ;,,7 -
- ~,,. _, ;.
- : s,.'.;;g
,,;_e_..,
- c. v.
',: [.. _
_.,\\ > %.; -..y'.,_i,....-
s
.....,.y...,
,p*-
,._;..),.,.. ;:;..,s.,
l,.,....z,.:.*<.
. v...;,;.,...._.,.:;_:.,.,<,.
.i,,..'s.~,.n.....
j..r._,?,.._,...,*r,'.
, *..y c;n :.p'.t...*........?*,,.,.
J
,-._.... e' T.;.,..
,.. g.,.
__i.. i
..s
,'y.
t j,.,..,..
y
- .). :. :..a.
,,.,..s..,;,.,.....:.-..
.s.,.,e,-
- ^ ' p i...."i..., -..;._.,,
l ' ','q',,; ',j :,, ',,. f. ;., ?..' c'" y...,.. s
): (,,-..-
+.<.u.
' i' ':
..g,s.,r..,...
i s,
v*y
,.,y-
',.,- r.
j
,n;_. h..^l f ; '
,.)k,* " ' l ',':.,,u. ;,4, ' ;,, ' ; ;, h.' : ' " A l ' ]l?.% :.,
,.,,,':.,L,f,.*<~'~,.s
'.. Tr
..._.'..f,*..".:$,ro.
- 4 ', ; }
- ll ll; o y
.... ' d., ? 'y
~.. g ' '.l!
^
%. h
[, '.. J.U.. -., '. i,:d
,6-1 : '. i s
,i:__...,......,,f:h',',.,,,l.
[,
~
?...f,;
,.J.
__.,'.'.'."p,',.d,..%.,,'.,~.,.:."_'*
.,. i, 'w' :
V..
\\\\F'
,,' i,:,,
. U.s;';', %. '
- 9..
+.,.%,.'_.1..._
3-
-r
- 3.f '., :. o - Q. ;,',', -
.,;a;.., r ;
ii6,. '. '.
2,
-s,.
..g'/._r...,' ".;.'b..,'_'r.,
.- i-
.,- w,...'..,4-
- '^ ' -
.).
..-.e_' v
'*..f...
,. '!. fl., 4,, ' t."g..
- V,o.
.. *
- c; :*.6;l.,.. :.
- >._.4e
.+.......;'.'.j.......'..'.,..n.
,n r.
a.
......,.__.n,,.4.',..;
- v.
,; :, g... *,:.,.. :. a:..,s...'.-..,, ".s,:.
I
.).:<, x a.
,..._s.
.. y:.
.._Y.
^
- .1.. ;,. p *. J,. $. '. ;. ;,.. ;,.;,,. ;; -,-
-=...
._ \\.. (
-.:-.4....._.-
.q 9
i.,,
.__,;.,...,;..,'_,'},.
- e : <,..
g, e..
. s..
< a.
s :. p *..- '.... el..
. a :;. :.;< :..
.....i.,..w.
. J..
. 6.
c_-.,...
e
'.<..c:..
+
..l.)o.. F.,.....:.'k...,..< ~9 7:,f. c.a'. ; '. t' h *j:,' l4 + g "..: 9...; : : /. '..i. :.
b.
..'. q.,.. m,z '. :....i.?.V ~ y '9.,
,,Y, lr;:. '...
....V : ;.; :.,. ;.. *, "... -
.:..,,., r,?
..s z,
.., <. : i.,.,.
._ + Q y'? : *
...[,,.;,_..,.
.; >. ' :'.._ ;(.,
?..
y -..a i
. q '.,. ;_,_ - >.
.l.
- ... _ ')
,(.., _;;,.' _ k.;.
,'1*:'....
[,'. >:,. v,......,',: Q.
- ....,..,, r. ; r
.'",'.::i.,
", _ y !. ; y ',. ;;.
y -
.,.a
- _ _,,t.... ' - ~...
t...
...y
.~..;.... ~.
e......z ',. :.,
s*,
.~..s.., S. ; ;. _.s
, r p..._y, '; '
v-
.. :. p.
J.,.
. '. : ~.
Q, y;,, : ',.::i.,.' :.: ( ~,.9,,,a. m.
..,a. ;,;;.:
.;.o w...., h4... ;. e._
- v
,t,
- f f'
-' _. ?
'y.
..z. ;;.,L. :,
.- i. 9'....;.
n.
- .-., f,. :.wi.;y,?.
- 1. ;. y '..,., - ' ' ' _ :.
. ' _ ',, - '3:
1..'.....;
3.'...
.,',.s,,'
[,..;;'._..,},'_ _~'.,, ?[.},. [. Q. ' ' ',.y. _ '_ -
),,. fl-.
- ;;;. '. _[-
. r
<. ~
' Q:,.-
,w
- .,;; !.s.. '; _' -,,'
.- ' _ ^,,,
- y. :.. '. _l}t :a;,"':*
V,
. 'y ',.,.;,, f,iJ u
',_t-
'h..:.-_,;..,'..
lp...:
';. ".)
l.'. %.y_ y:,. ")f:.yQ,.,...
lr,
....n
-'.?
- g.;.,'_.'..',*
,(
, '.,.t..
l,'_Q L.,I:, ' ;. j,.* * '. '; :l: ; V's, k ', ; ',. r. ) );.) 'i.f.R '.T..;_ l:
.y
) '._:.,.l %. F.' ', f -",;;. s.:
- , ' i f. '.. '_,... h ',f.
- .. -
.r '[,'.,.. '? (.'..', -
',.L.'
'Q ;,. J.- jf r :.
.,. ** * '..l,:Q,_' l l f, { [...*:
.E s.',.
v
',;.. f.' : 4 V ^. Y. ;. :.,,..., :
- 3 '., ?. g. { ^
f.'I.f;. -(4.i:!
).,' f.. ' i' d
- T 2
b-, '-_.;' '. ;..- ; ; _,". ; :-
s -
~
- ,,.'.,,.f..t N '
t,',',S'
,*s g,..,.. ;t"...'...,.6,.v,.". '...j..'
'r
'i',
- i. i.;
.f,9 '.. ~..t...., o / e-...,.f-1.-
..: ].,.J... s.
.. '. ~. -..
.f.-.,*4
..,-.m,s.,.
o u
...i
....g....-
e
..n..
i:
.,)
,5
,., _,..p, ;g '
y._.
l_*.*,
.,...b,.- _,..'.;..',..
V, :;., _ "..
J,,.. ;*_
V.l l q.
.1.',.
,.y s
';!r
,. ;,.'..*p*, 'r
._ ). 's ;_.;,',,.. - '.. <- '_.,
..r j.,
.j
, l
.h.
'. q
,,L.'.
_.., k
'i,.. ?
,'y..[,..3 6.. ;. ".. ' '..,
-*,s.
- .,'i;,.-..
1,'.,.
- y,.
'...,.y+....W,}
y 'P 4*
u, e..-
r
..C
'p j. g,..
.,.- n.,:., -
-('
.. '.. c ; ; ;,..,'....-....: -,
r,.,._
.g.,
...7.',.*
'i
'f,,
.i/,
- M..
. w, ?.... '
s
Earnings Per Share Return On Equity 13 0%
52 75 52 71
$2.61 12.5%
12 4% 12 4%
52 52*
12 2%*
$2 50 12.1 %
$2 41 12 0% 119%
.1 52.28
~
$2.25 y.
k' i
V 11.0%
i 52 00 1993 1994 1995 1996 1997 1993 1994 1995 1996 1997
- 1995 amount excludes a
- 1995 percentage excludes a 50 44 restructuring charge.
50.44 restructuring charge.
FINANCIAL HIGHLIGHTS years ended December 31, 1997 1996 Operating revenues (000)
$ 1,776,233
$ 1,666.303 Eamings avadab!e for common (000)
$ 131,493 126,181 Weighted average common shares outstanding (000) 48,515 48.265 Common stock data:
Earnings per share 2.71 2.61 Drvidends declared per share 1.88 1.88 Payout ratio 69 %
72 %
j Book value per share 22.13 21.37 l
Return on average common equ:ty 12.4 %
12 4 %
Fixed charge coverage (SEC) 2.95 2.91 1
l l
l
"',.., '.. _l[;*
T'..
,,I
' l l','
.. ^'.
"i
_l,f... 0. }+
' - l. l l..l ',
!( -ly.
h, l ;'.
. [
J' ',,, -.'.
'.'_l.
3 '.}
,f
'.,j
- ..y -. ;I].( ;
- g...,
h,.1 '.
. y'
, _,;.,l,'
.n
- ..r. E~':
- [..;..,:, '
.\\ ".. -:.
. h,f g ',, ) -,,.f
,l ;
y.\\. h })g-
.'. g: f.,..,l... :.
3
,,[.h'.,... ". [ -.,.
f',
', -. ! ;.;, ',;., ';,i$,
,' Il
.l. h [. '.'.. '.
['
~.,,
,l," I..
.l l ', J.
i d' ', *:
,h-l
,'.4 fl([:
(' ; ' s.I,
' W._ll
). \\.,. l l.,
t
'Y.' l ' ' _.j;, j.
'l ' ^-
l, y i :.:
e, 'l.(' ', ' ;
N' U.:f ",
~ l^ ' ll.f Pf 'ej -.
, j,..
j ),f
- I, h *
,.y,.[
}; I. ;';,
O
,G ;;,~
.qlb l:'. T "
. '_ l1.,,
.1.r.. ;., '.;.
'..d-
'::..f
= g.,1-s*- F g : r....
g.-
. c,, '.. -;. :.. ;i.,.; ' J,..
'.y. w,,.. " 1 *.
r,i. ' - ',...p.f. ; ; '.
( l l.'of.. D '.:l' '.' &
[*!a.,
, ' '. -L'n,r'... ?
.,Y
. g. :i;.? ', r+ ', v
.,..'.3
, ? ll) a^ l.i..l; Q...;.N..\\..';lf: ' L ).ff, f f.
'q" a
- rv
. v.... p, - * :.
l.; -
+ l; \\ $, F,' 2 }p f..,L.
l.' l: f',.'.. b '. ?. _.]. :, %. 'f&. ;* y. ;;- [< b' I.1
', l,W. :.
,_, e s. ~ - *.
rc- ',-
~
f-l':. t,
4: -
- l~ {,_, ).
'J fl'._>s..";.'
.m g ~ K', " ' 'l llQ O '?' f.... % ?.' ' V:' ::
".e o
.", D ;, _.
.s.; -
?*
- ll l_..
i.
,p,
,f ',b'. :
- Y ',';.' ;l;'),'; i : ' _ : '
.. p.. %.
.~
^
,i ' "
y.Q;.
I ; i '
,.,y l __.-,
. i
- j:[l. f.
.g l. l ' } '
l f ',.' ;;I'~
$ 'I';{ < - l 'l ;., [,',l
.; _ \\
,. :.f }'l, [_'.f h. >...
- 1.,.. '..l /
-,',j'
'l5...'ll,.l:'
.O-
- o
- -l.
' _?:,;_'*
. A.j' ',
c-u %)..g '[c_,,
i }. f' l A[ ' '[, g.;g,'.... ;,;g ;' ',,,',.;;,z,. ';..*'
?,' '_ 'f. f,\\..l, gk
.y.,,
j,
- i
),[{,;;l }..-l' *
,. ;r m,,-
. :.. ' !.li l' :' k.'ll:.
'9-
{:'
.t
- L
.'\\,".__
'. ::,, - -,,. ll v,.
s, r,.,..
j
- A
- ..,'.; -
..'c y ',,4.., : - :
-,.....', l;l5 ( Y','_. :[
.e
.,f,.
y.
-} '.
1 l'
i
. l,,. {, ;,.s ',
y.:
.s *.,j. f:::-l
- l:,,. 1.>..-* :. :.
,y,...
v
-,}.
'. - - < ;.i, : ',,: ; e ' ;4.,., _' ' :
.v..
~
r.
c q,
. ', ~ _:.,.,';- -...,;..',m%,,,.'.,,,'y.....
- 3.'....... -..'
'>.:n.
. - s
< ' * - - ',.,.. 'u, :....,...
.. ;.+...,.......:.
-'-.:.',-::,.f.:,,'...'.',:
,..-*.. p:.
-.s :.,
- m.,5,,... g n..... :..
- e. / s.
1 f
.,...k ):..
_C _,.!L: : '>
r,..
'- ' ~
^
- y. *Je l': 4:\\ ', ', ~" :. '.,
r_'-,. _ _.
'yr,,,.
J,,.,./._,.-
.. ', \\; -lm..,
'.9' :. '..? j.
(..,.<..,3<,
. _..*..{,,
.,.sy p. 4; %,...;..
i
', -.. y, l_ ; 7..,. : 3';p",.. 't ' *,- -
'.. '. o ;' * ;.jp '
b' si. e 7'. '
s' g_
- :.;...' L. &. Ln_..s.'-, '. '. 7,,. < f, f,,4 o
.a
_I, Y,..
., ;. 3y ;..
g ; ;;
.,, _.;,. ;y s, ~;..
l ;,;?
- , '... l
,. ' *, 3' -
,'.e:,j' E *
- l
'_ f...-,'
. G
__;.,,e'.,
y.
$ ; '., ' '.r :g,T h...,,. _ s!. ' '.h.'
..:,.[
f '* ',' ' !. ' ' '
- I' I
,.;^'.' - ' ', ;, ' *.
,' y '.
r-s e.:.,,
',, l 3,* ;,. _..
.p:
n.)...=.,
[$*
_, _ " ^ ', ' '.. ',y }; _ ',
+
l v
...Q ;R. ','.Q :,.,
y
. + -
s p
- I',.'".
('i..,.
,., ', ' f.,..Qt,.'. !e'.
a.; ^' *....,..y',_'., -^,
..,.,_._a,,c
.,n4
,, eq_.,,,._',.;
v a 3
%cf
-l,; _. :.
- ..
- 3
-,,_ '.,. ~,. ] ; y., <-'. ' '
~
~..,,.
},
_,[,
.,.y, 3.
,, h_ : j., j, - ~;, *... ' >. _.
..*'..'a...'I,*., -l,.. ( '
.?.' ',. :; ~
','..c
.....]. ' '_ n, Ws
}, '....'
.. ~. _
'. s).';.
e
._.,.s.2
,. ';* ',y._,:
' ; ',4 :. <
t T
, ~.
.s
" &',3;l
,e
....;, 4.,
. f j ;.; - -.....z.. ;. ' '... L
- b,>.
' '!. '. 4 r,.
7
,,g.
&., ' fQ'n :.f 'd. ~., f W ~.. - -
.,... ~.,.,,,....,..., _-.. -Q.
Q >:,
vg
,.,.,-.3, s..,; -.
f.
,9,*,'_'..'.'.
' ' '.,...... -,j,
ii,,g.
- . - i n...p. '. :.,'.
.Y ' ' ' ;
^~.%y
,..,.. '. ' j ' ;;,
L i.'& ; ? '..'
'...,'._'..s'~....... :f -A _.' ' /. :L ' - ]* 3, :', f
'....a L
- - ' i
- ',.. c.
-. :. : ;.' ;. )
s.,..-
e
.,;.n
.....',\\
3
- 3.,._ :,
..,:._,.., f. :x.,. Q. ; ~; -,,..
z.
,..,'. :. :g.,., -;..t t,,,.. %,
- ..s,
v,
.(,..
6,}_
2, 3
- . _ _'..,.j
,1,., s,. u. ;.......
v.[,'
..s
..'n
'.u-'
- ?
i e
y.>-.
- .. q..j.,~, (,, 4._
s.
.g.
._.r,;.-
t..
'T
.3,L -. ; e.,
[?. l,i
.A
' l :.I ' Y
h '..'.,
I L'.-
^
..c.
9.;;; :. i::'.;.n.,1_...
_c.
', Y',,,..
v.
L ' '[. '. ; 4. l :_...' ~
.. &;e,,..,,,p.
,.~
',a..
-:.a.
,,._"_f._
[,
y;-t
..l-
,_c.
..o.,.
y ;
..:$^-[*,
- ,.. '%? -,' _.. } [ ' '., _ _., -.
l
?
f '
- ; f....
,w l/'."
.,,.., i........
l.
I
.f:.e.'
. -'.,[,,,/..
,g ',., ',, j : k... ' -
.w.
.(J.,
i
'.J*'
E i.'
~f :.,'
.c g..-;,-.
3.; y
,g
' I..
', [
. ;,,; {a
.y&
- ;; 8
. y [: '.., ;'.j.k.
l;,y g;.
. 9.; 9:,, c
. :, h ' a i
r.
i - l:;
(:
~
[, [1 -
.?
3.,
L "Y,-'
....d,-:-.
,-aT..,..
..,.i., '
,-'.p.
.K',[..
'l ' l'_'
., j.: '_':.,
.' '._I 1 ; ;5,I ?.., '.f.f l l',
(
. ;.;', ' f s. '.
' ' ' : ' ;' f^t 6
l )
k fl - ' ;. ' i '
. A '-
dl I!-
L '.",..9 :, p NY )..l.l., -; /
li.
.' r ? '.... ', ^ '.
d
_d
.y, ;..;,
/:'
V4 : [
Q
- s. n.
~
l
_,[
'J
. l. l ~ _, ! _.. '. l [ '.l.
,(-'
... W' :.d'$'. ' : _4.!,,.
3 a
5 p.
- 4..' *,
M(,ha'Qg f,,, y
'.y-k -- -
1
_+v,.
- . :;;.r,=, a 7, -'...
S., 'N:,
._.: " yw s e3
'; _,,,.,.y'.**
- ..q
- , \\..,. ~.. '..
by ;,
( ;;.
h..,,7,,, _
- ', *?
-.~,.; _. y.
g.,
?
e ;
,..c...
z.,~.+
q_
r.
y
- ic.
_. w
- F.;,yl s,,
^9._ <;:n, $,
- ,.... '...,,...,,f.
,,, s. 3.,.,. c. ;;,y,.c....,
',y-q j ;- :..,,.c,.
y..:
ng i
.a
,t
,, 4
.,r-., ~., Q t' u.
,.>':: s +
.s 9;
i "u
- ', '. ;, t.
e.:, ' '
,L Y.n ((.,
~,.'.r.
' i...., :.. ' M p-'
'. L s,
- 7.. <
.r... ]. '
- y.. '.
t
+:
.y, L
'V._'*,.-
4 _. ' 4 -
m..c7,....... -,-..<., ~.. '.
-s.
s.
,... ' <': J.o....o.ky-;s...,y.
u
.t., :p ar,
' ': ~;p i,.
c.
7
'..a l-l.
~
l..
.g,
,~.
,,..[,
. ', -( J. f E',', ' ' [.'
(-
h, 'y (, ". M
.;.).It[,'-'.}
.,..,,"/
.. _, N.
,#'t '
S',,
'..,.h, ' kT '
h ek,.,,.,
g' I*
d'd
',.g.-
.2:
- N
'f l i (, ' ' ',' -
- N, ;. ' '
, _, \\.,' ' i. : l ,..l \\,.! l.'.
,._'A", d,,.
[,
I ' i-5,'.
. ;d,
- r...;...+
.JA V,
..y
?-
e,
- T - i. -f E.},.'. c. ".. j ;s,
. W:
.;,.':.'o.:"...,.,
N.
f.
- t.
v...l ' '. ; ..,.]..
. ',, ' ;,' ' '[,;,, K
- ,.'.[
y
'j; :, f '[; i c
,[..)
c '!
i,',
L
< 5
- :,.,..,.,'- ; ' - ' ' - '.,'EN h n. h _. ? :..:'.= %q i, ;.
t-s
.'.'.',~?
4
' < j ;...,
g.
., ' f. ' :,' b ':.., ',.,. ; l '.
f
.' fg
' 2:3
,)'. w:
.'s'
- e. :.
,' 1)','../
h..p
. c f; ; :. l;l,,
&j-] h.j[ ',5,of.+.ll'....g
,[
'*;, T 'c,
^
,..')..
.h'e-k[~-
.'.'...i' f.
N.
V'..
'.Q ;
,ll_llff.ll.lll5.,L.l_j.;;.,:
. je::
e..,
,7 4, z g..a-
.y,,,,,,
g
,_w-
- /[:
., y-
,,5.
. y )j... <...f*. g.
.. :,1;,
)-
..,i --
.'e.a.,'.,
J,.
,., ;, fg,.
- e_;.. ~, y.q.
v;..
- -cv.. y
".[:-
.m,,
-_m,
,, Y
, 7
.q
.',. :;. i y : i; ;l. :: a.
- ;,.. G.y
_-..~.;p. 's.
., :y.;
~ :.. $.
.,..',s.;.-.
s'ss..
n y
.. v. \\t c
.,d ay ;y 4 o
. t p,,.,
...py
- ,3.-
y
... E,. l'.,[- )',l:; ;' '
3l@l,,
'N
+
5
.,.,,i. 4. -.;..,.
.*A
".'.1['.'.[.
. l l.
1
- ..
- ~
.e
, ' N g"! Il. ',i '..- 2'l ' t n
'L f.
'..",,'5..
- / /.g ; f
., J q c,
'N f
si
^, ;.
.l.
..,' ',',. ; $,..'J; Q ' (.~.g * ;q,.:
..y. i ', *%
. l:,
s
",l [l; q y II I "' 8 '
J;. s l
,a s;;._ ? ;,.: v;,.,.. *.;..
.t
'.. ".... a J.._._,. _;.,... ( '..f., ;;,,_.g _
_L. ; *
..g r :, y..-
.l: >.7,
\\
. ',.j.;, i -
,.1
,..,_-;_'n.
,;...$. ',',# ', 9
,L f,.'.'h
. 'c v '.,. -
.;% : :.. j. 7;-
t _:
,4 ;
~ '.,;^'.. '.~:.;, ;...:Q
,._ '; ',;,.,Q, -,.,.j..}.
. ;,..; ;7.,.'.. :..., ( '. ?, 7.,*,,,
9.l..~.,. ;.<.'-. lj
,'r s'
...S
_f n :
ie ' '. :.
'!",a,'_,j. -
u....,., ".,.,...,,. p ;
W 41- -
,l.
,,,,.. c.,;,,;;;_...
n.
- .. ',l', 3.";
- ,.... ",
.', :, ' p -
- ,-. '.,r
.:*..l.'l l _. :t '
_\\
l
'.,v.
,:e -.,, _.....
- L
.,',. ;.'_ : :,,....1 [.Q,: ;[, -,
.e,'.,
,s*'-
. :," y:,,% ' ';,l.';
,n:.;
y w:,jf'. ?,
T a,
^.,,,.,
z..
v.
i
- r...
,~-%,'_.,y,,_._
1, :,[a,.;}. '.,
J.'",,.__
' ' '-,,, f, ;- (' _,.g,.
. :W
- .7
,_;';[ *, (, ~..; y.. ~
y,'.,',.>>_'...,...
v,,..
n'..,. 7l
...y<
y.
- g
-.,.. _. ; _ s
-.,5,,,' : '.. ;..
Cy'j[
...,<.s., ; ' 9 )...,' ?
,l,';,,
'.1
- 3., ; ;. ;... u
~ :'
.:.':\\'
r..,..;_
.l.
+ ; };"; - a... - '
'z ; _.;; -
m:
.... '. y.f, :; - '-.. c:.,,......... '.,..j,.. ' '
.,v _:.. -
6.f e,,. . -.'
4 '- +
'l-'_*.s..., ; -.:-..:,:, +
.... l,.;.f,
?~
s.. 3. } ' ;;; *.
l,,, ;. _
...3. ; ;;,,
'I.
\\.: : ". ^.
.~:,
4*,
- l'.".
',.,.T
.n
-' j; '.:
.:^
,s.'*
- 1. l V...., ' ' _ ' 'l; ;j ;,,. _... \\
ir,L,:: -
_., _., _;..l QK. ',.,,. _,l:.(, s,...
..L,
.,ll
...:......:'...',[:.n (... - f.,,...L.,,.... -.. '.,
,r-
.,~ " -. ...
.'a...3-,'g~':,,,..._,.,..,;,7..' :. ' " Q; : :,. ll
,......~,. ;,....y,,.........,.....a. ', 4,
^
v,'
o q,.....,
e.,
/
.: __, ' ' " ~_ ;- -.
. - '... ~...
l ',& - }. l ' _ -
.,a.
-.*..+y
- ...._;_ v
...,,y
...;,. - : ;,; ' y __ [. %.; J.,_,,_ :,.
.a;_.,.
s'
, -...*, '. "..., l (' :
,s'. *r:
s
\\
Q;
.,,,.. ' '. ~.. '. '
i -
.b,...
...4
.,,,.-...,.. ;..<..,.at-.
....~.,;,-,... _ -
.'.t
.,u.
' '. '. < /,.,;, y ; ; ;.,. '. -. i'. ;#
.c.
,...y,-
.Ls..._,.. _.. g-t..?*r p ',
t
.:-'.,it i T.
z,-
s S. -f'.
...', '...T
< +'
r';
s
_,:, i.
-( - 4. " c.. :
1.'
c.
,_;,_,.;.;; 3 I,
. f.x..
.3 : p;
- ' ;F..., '.O '
..I,Y '..s ?,. &
, ~ ?;.',': '.): ' '.
..,l v.1,.',..r.,; Q::..^ A; I,.'
i:-....
': +
l'(. %.6 ;,.l ', i ]:.O:. ' i',!'f:
- ;- -. >;.. : '.f,.x ',, '.. l 1,,.[... ?' *.. " > $..
.'.f :#.., ' ~'..,, *..':,,!::%.,. ' '.?, 4'
,d....e,.c.,'9.'; '..".?'.' * ( :.-- )... '.
1,", 's+
m '.. l' '. i,i j l+'. " ;,..,g
..,. i %,. b,. ; ;,5 3., s
.a.
8
?:
e.
-%,.9,.l.,#
e
'f,s...
- g
...,.t.
.i
,r 9-x y.
e a
..y,,
s
.f,
.t
< h, e.... -..,,.
., 3; -
,,,c c.- ",.-., _il. ': 'L : l lu '
...:.,* X
- C ; &,.,..
w.
'"..I f, $ a. *. '. ; ; ' : - L+~')
,/
'...'.'c
^
,'(.
.L*.
~ :.
- f.j. gf.; U.'[';,1
,..: - Y,..f. ;$,l
_h'f
..'L**:
N,. ;..;' '.i :,.. '
.a 'i '-
- z'-.. _ -.
- . 2 l
.b
.i., '. s - );,s' i, '. -
..l%
' 'c ';?,.,
a..*-
. f.,,
'i l.
~
f.
it....
4
,f,,_y;..'<,..
.. \\., ;;:,,' ' :., -..
N ,.'llf,
'?-
',g ' *: i'. ' ';g?v '. *
~c
-. / 4,s
,s;...... '
f
, ? ',. u.r
,k
'f. :
. f,?.
- . _,'
- '. ;Q., -..l,
- .,,\\
',p*
.;* ;...i,.. :'l. l G " '.,' y;;,..i;. e a
?_'._,...
..\\
s__
3
- g... _..;-.,, _
l-
_m
' J. \\ '. A*o n,.
- ;, ~ _,, ;..
. 'o 7:
o:.
1 '.
.'y
% x :(. - Q
..'l.
r.-
... ;... :. a. '.
,.?,,
..~
.g.. p.
m'.','.'c:
- MA _ ' s.'.'
L*: -
- %a.,it : -
,'c r., ',.. ....-..,.;,.'.'.-':y h
.:e.'%.,',,o.%.',
a
..t'
. i,:".. ' *.i ).g :%.' '
L" '; s...., l ': ;!:.:
.,4; ;
..".,c,*.
l t ';-.v; n,:.s's,.*
f 2,', ; _
,* ;, ; c 6. l.. g.,..,.'
e
. ;c-
,"...';,e... !.;
!:.%.,,;. : ~y;.. :.
,,c..',;..,, ;..,...,.
. h ; c q.Y.,. ;.;',,-...',: : y _ ' y, o.:.
o
- ;,,. )
,; t s.,2 mi,ykr;:
...n
.:; ;.t.
f
_'./[.
[ ' '.h [, q ;;*O.2 5 [.[ ' k,,., <.;.?)-
'y.
'O 3 ; %
',y.
t
.,. h., [')Y i,b,..
.,I :(*J
' ' - ". '.,S. ;1'j :, '.
.u.. f. ;.:, q,
. [
' ' ( '.. } '. h ) f.,J-U,'.,i f l h[c,
- f. !
g,{ @ <'. c;;.'yp i j'.;-,... ;,h; .. ['
.y
O
'l... _. ;.. ;....?
. ;, v_., ; r
,),l;i.f..f,.M If,
. h: '.lkl '
C 'i.' ' I' T. -
',.'[',.E., '";ll
- .,,. ~. 3.... ',.,; < %:.. p I.~.';^ 7.: :.,
.;\\. : y..,. ~ ::
s'
' ' '.l ', ',,: g i ;,y #.
. '..., v./
.,.<.Il_
v.
. e-
,;., j.3,g h. _,.~.hs...
[
- ' - l i* ; '..,.. ' ;.
o
., <..;.. p.,. ;, :>$......, p.s.,,.
p, - n.,1
's
<-. y
%_i..,;.,_',_,.'
e
.. - :o L,,..., ;[,".,.: "..,.. '_ j " /,:. ': ', x },, c.;.., v
. / * ; :'
s..
- w c. e.. +,.s:.,. p) j ',.u a
.rv
.,i1.9..__..;._.
r_..
=. '... :g ;..f,..",i:.'.'..,:.
.. i ;
, ' ;],',
..., _ _.. i t 1,,- ' [
a..
s,g d.. m y
,'...i...,,.i...-.......',/,.8,.
- ..a y -
g,.
- (.
. py *
- f.
y;
? ~':.'. '.
_ i _.
<,.p,.,.,'..-.....a.g.'...:.,.;.,.e.,..J,.....',.asi'.
._..,,.,'~,...,upcg'4c
' } j 9 :.'."...
- g g
.c..,..,'.:M,*",,,r,e..,
c,,:
',-.,.,..e.
.. ',.". r e r.
- 4. o' e,,..
s f.,j h
5, s..
.t e ;. ' -
' ^:
..c,
- . ' y~.lll,. '.f,
, R, -_ _,,. $,yj:,,.
o.-.
- g.. r.. :...
e;,
- , * \\
y.,.:.;.y lr,, ';*
.- ; ~, ;,.. % *._,,'l7
.,;r.:"..;*..
, - s; ;., u n
,L.
- ,_ -}y' y xv iun ;,,,
..'::s.._...,~.,,',
~*:
.y
,;, ;,..., *.. y a.,i.:. "., ;,sh, :.
.h g
.. r {.:.
., o,.. ;:
-e v
.t..._-
_,;...... ' ' ';;.T f,., [:; ;, ; ;-
9l, (, ' { (, [. _. -
.',.'e+; *.'
._..3v.-
.....,5..,,-.-;&.1:,e.._,
, g.y,....<..
3,
~ r.. ;,.q..;
p
- a. 3....
,n,..,_. ; _.
, A
. s, o.
_...,.,o.._,.._,..n,s....,.., _.. ;. :y 9.$;.,..,, ;.
- ,..-,,,,.s.
...,4., j _ _y;., _
'I,,,;-,,
- n
- ~;., 9....
.,,. ;,. ; ;; [;,,, 's.. '... 3 x.,,,,j,:,.,..;
.[~ _,
('r,
.c:.
3
.(.
'.;.. ;;__[ :-
p
_ _y;. yz _. 3. ;g, ;... '
__y
-l NNNINJN[N[\\[N; g
Earnings Per Share Return On Equity 13.0%
$2.75
$2.71
$2.61 12.5%
12.4% 12.4 %
$2.50 12.2%*
$2.41 4
12.0% 11.9%
[
$2.28
$2.25 11.5%
I i
A j
8 I
I I
11.0% -
i 1993 1994 1995 1996 1997
- 1995 amount excludes a
- 1995 percentage excludes a 50.44 restructuring charge.
50.44 restructuring charge.
i 1
A FINANCIAL HIGHLIGHTS years ended December 31, 4
1997 1996 Operating revenues (000)
$ 1,776,233
$ 1,666,303 Earnings available for common (000)
$ 131,493
$ 126,181 Weighted average common shares outstanding (000) 48,515 48,265 Common stock data:
Earnings per share 5
2.71 2.61 Dividends declared per share 1.88 1.88 4'
Payout ratio 69 %
72 %
Book value per share 22.13 21.37 Return on average cornmon equity 12.4 %
12.4 %
Fixed charge coverage (SEC) 2.95 2.91
CONTENTS Iztter to Shareholders 2
Commitment To Customers 4
11 hat Customers Can Expea From Electric Utility Deregulation 6
Strengthening The Economy and The Community -- Equally Important 7
The ArrivalofCompetition and Customer Choice 8
Exiting The Pouer Generation Business After 1iilears 10 New Afdiations.. New Directions 12 The Future 14 Financial Section 16 l
i J
l l
W%NA l
e L_________._____
I
N N \\I\\I\\ \\l DEAR SHAREHOLDER Dramatic and successful. Strong nords, but they accurately reflect the results of1997.
l i
For the past two y ears, in my annual letter to you, I have discussed changes expected in the industry and the company as a result of deregulation of energy supply. Now it has happened. Your company has emerged from the uncertainty of the past in a strong position for future success. But 1997 was more, much more, than the culmination of the anticipated changes in energy markets. It marked, as well, a significant change in our core business of generating electricity, with the decision to sell our oil and natural gas power plants.
Perhaps most importantly, as it relates to our future, our employees went the extra mile throughout the year for our customers and for you, our shareholders. The results speak for themselves:
Total shareholder return was 51 percent as the company's share price climbed 41 percent.
Earnings per share increased to 52.71.
Field operations were redesigned around customer expectations, resulting in significant productivity and service improvements.
Nearly a doien new customer services were introduced.
1 egislation passed that assures customers of energy savings and choice of energy suppliers, w hile providing for full recerery of stranded costs.
Sale of our oil and gas fired power plants attracted a 50 percent premium.
These results alone are impressive. However, by themselves they mask the fact that the sale of our power plants makes us a smaller company. While we have exited the electric generation business, we are in an excellent position to pursue new opportunities for growth. We have adopted an ambitious vision of the future. We see a company with two million customers in the year 2000, a three fold increase in three years. That growth will come from a combination of geographic expansion in electricity delisery, and possibly gas delivery, and from our joint sentures.
l l
l 2
-.-g 4
a J -
J
~
D
-y 4
O l
l Ours is a vision that capitali7es on the restructuring of energy markets, as well as their convergence with telecommunications markets. That sision, and steps already taken to achiese it, prompted McGraw-liill Publishing's Electricallibrid magazine to award your company the 1997 James 11.
l McGraw Award for Corporate Excellence. The award was presented because of "the company's visionary restructuring and diversification efforts"and"its groundbreaking corporate strategy." As the award notes, the strategy " continues to strengthen the company's commitment to the end user" This report is about that commitment and about the employees who make it real.
Thomas J. May t
l t
l Chairman, Prcsident and Chief Executive OfTicer Wl+N9N 3
COMMITMENT TO CUSTOMERS McGraw-lhil,in selecting the companyfor the 1997 James 11.
.ticGraw Awardfor Corporate Excellence, reagnized itfor its
" commitment to the end user." Ours is the last major industry to go through deregulation, after :he airlines, telecommunications, trucking and naturalgas. The public policy initiatives producing competition in the electric utihty industry are driven by a combination ofnew technologies, and customers who expect and want to have choices.
..i l,
9
- f/
1 yy v g /
..,.4 P
<f s-4
[,
- d.
}
A
+
4
N jsfNJNfNfNfjy--
s People and technology are coming together to change public policy and create competition in what had been a completely regulated monopoly industry. At Boston Edison, people and technology are also coming together - working together - to make a difference in delivering comfort, convenience and efDciency to customers. Boston Edison and the reliable delivery of electricity will be the core of the new holding company, BEC Energy.
In 1997, all aspects of the electric delivery business underwent transformation. Key business activities, such as electric system construction and services, asset management, metering and all aspects of customer care, were restructured around customer recluirements and the processes necessary to meet them.
The new business processes capture the best practices of workbclass companies, domestic and foreign.
This transformation is the result of a highly disciplined, customer-focused, strategic assessment of process, people and technological needs for a high performing " delivery" business.
To make the processes work, multi-disciplined teams are in place throughout Boston Edison. Separately, an asset management team focuses on investment planning and technology selection to ensure that the delisery network provides a high level of performance to achiese customer satisfaction and Gnancial return.
Meanwhile, new customer senice initiatives base been built around the principle of ease of doing business.These initiatives give customers options, and provide accurate and timely information and personalized service. New services intnxluced in 1997 included dired payment, Internet access to account information, appointment scheduling, and consolidated billing for customers uith multiple accounts. Also A new loolr introduced was a new storm response management and information system.This new system will shorten for the restoration time and provide customers with better information about restoration progress.
Boston As the changes described above were being implemented, major work continued to Edison upgrade the existing distribution system in and around the City of Boston. We also mtroduced a majorbili provides expansion of our automated meter reading system and further improvement in our remote monitoring customers and switching capabilities. Both significantly improve productivity and customer information, with more detailed infor-mation in an easier to read format.
5
N+N+NN WHAT CUSTOMERS CAN EXPECT FROM ELECTRIC UTILITY DEREGULATION Thefollowing is some basic information Bv. on Edison has been providmg its cunomers about deregulation, whic started March 1,1998.
Why was March I important?
Hat was when the production of electricity was officially" deregulated." That means that power pbnts will no longer be part of the regulated monopoly customers have known for decades. The electric utility, such as Boston Edison, will still deliver the electricity. But it will act more like Federal Express -- delivering the package of power you will purchase from among an array of producers. March I was also the date when electric utility rates -- the cent-per-kilowatt hour price -- went down 10 percent.
Does that mean the bill will go down 10%?
The price per kilowatt-hour will go down. Customers who use the same amount in March as during an earlier month, will see a 10 percent reduction. But consumption varies due to many factors, including weather, which affects the total bill. It is important to look at both the rate and the usage.
Will customers actually have to decide where to buy their electricity?
N, n t initially. They may choose to do nothing, to just continue getting power --
customers wiii production and delivery -- from the utility. The utility may not be producing it, but it will buy it for be able to choose the customers during the transition from monopoly to full competition.
company Afte ' -
h 1, who will customers call if the lights go out?
that produces Customers will continue to call their kul utilits that delivers their electricity. At will not change.
power.
Who will be responsible for ensuring a reliable supply of electricity?
Boston The electric utility -- the delivery company -- will continue to be responsible for a reliable Edison will transmission and distribution system. But making sure there is enough production capacity will be the continue to deliver that power.
result of market forces - supply and demand. Already,in anticipation of pending competition, power producers have announced new plants to meet anticipated demand for lower priced power.
6
STRENGTHENING THE ECONOMY AND THE COMMUNITY -- EQUALLY IMPORTANT Civic invoirement and emironmental stewardship remain an important aspect ofBoston Edison Companfs activities. The changes occurring in the electric utihty industry do not diminish the importance ofa nbrant economy, a clean ennronment and healthy communities to the well being of the company, its customers and its emplovces.
Over the years, the company has been active in programs to help the economy and the communities in which it does business. In 1997, the company continued to woil with state and local governments on quality oflife issues. For example, Chairman, President and CEOTom May chairs the Governor's Council on Economic Growth and Technology.The focus last year was on three issues -
/M,)
~
- 4..e p,-- [.
business support for quality education, continued g
progress on reducing the cost of doing business in yi Massachusetts, and initiatives to market
-:j.. M s.
Massachusetts to prospective employers. Internally,
( j ;,
g l
't w the company's economic development initiatives
$MP~'
continued to help attract employers such as Sun Microsystems to the service area.
4 h-On the environmental front, the congany worked closely with various interests to attract alternative fuel vehicle manufacturers 'e de prea l
and. to ecablish incentives for vehicle purchases. It helped attract federal funding for fleet operators to offset incremental costs of clean fuel technologies.
Finally, the company's philanthropic efforts were concentrated in the areas of education, the environment, health and human services, community development and the arts. It continued to help Boston MayorTom Menino implement the Kids Compute 2001 program, which is ahead of schedule as more and more companies step forward to participate.
1 1
4
)
7
l THE ARRIVAL OF COMPETITION AND j
CUSTOMER CHOICE
\\
l Tor the past half decade.pilowing passage of the National Energy Act of I 992, government, business, utihty industry, consumer, academic and environmentalleaders have been collaborating to restructure the electric utility nndustry.1he panies represented many interests and often opposing ricupoints.
Out of this process, a set ofprinciples emerged in 1995 and 1996 uhach Boston Edison has supported.
f e
1
.2
.g s
g' g
9 S
1 3
eV
. M.
t s
(
8
I NNslNisNsts I
in July 1997150ston Edison linalized its deregulation settlement agreement uith the Massachusetts Attorney General, the Massachusetts Disision of Energy Resources and various customer and environmental groups. Implementation of the settlement required state legislation and appnwal by the Massachusetts Department telecommunications and Energy (DTE). Iloth have been achiesed. The Massachusetts legislature passed, by overw helming majorities in both llouses, legislation that implements customer choice and competition for energy supply beginning in March 1998. " Landmark"may be an overused word to describe significant events. In this case,it seems appropriate.
The legislation is a well balanced approach to meeting the needs of customers, stm khohlers, communities hmting power plants and our employees. It assures all customers of a 10 percent rate reduction in 1998 followed by a further five percent reduction by September 1,1999. It prmides for full recovery of stranded costs w hile prmiding incentises for mitigating those costs. This is discussed more fully in the scetion on divestiture. Communities with power plant sites are protected against property tax losses as power plants are revalued. Additionally, the legislation maintains the state's commitment to those customers in need of assistance and to the deployment of energy conservation measures and the use of renewable energy.
The steps necessary to implement the legislation are now being taken. The company worked toward that end for much of 1997.113 year-end, sirtually all internal sy stems and infrastructure needed to implement customer choice were in place.
These inter nal changes were mming in concert with regulatory proceedings beli>re the DTE.
Employees worked The DTE considered specific filings from lloston Edison on the settlement and establishment of the through-holding company,13EC Energy. It also had to consider and act on new terms and conditions for
,,,3997 customers and for energy suppliers and registration requirements for suppliers and marketers. The DTE to pre.
[
has been able to keep to an aggressive schedule and meet the legislative requirements for competition P * ' '
electric and apprmal of settlements reathed by lloston Edison and other utilities.We are awaiting a decision from the DTE regarding our reorganization plan to form 11EC Energy-deregulation.
9
EXITING THE POWER GENERATION BUSINESS AFTER 111 YEARS An important requirement of the company's settlement agreement is the sale of oil and natural gas poner plants. In return,the company has been pronikJJull recovery ofstranded costs. It has been a Jofficult but necessary decision. No Jccision that requires a company to cut a major part of its business afier IiIjcars si cay. But the pubhc policy direction, as ucIl as the marketprces nere cIcar.
4 g
m
~ yi.
l 4
s 3 %(W
} lL
@ g.-
y
,a s.
W.39
-ca
,,,./-'
I.-
~
g,0,,i,4 gjit g :.,i..:
f* 0s u.
.}
.,/'t y
^
W e '
- v. - p +,.
.t D '
As a re'. ult, the company set an ambitious s(hedule in 1997 to sell its oil and natural gas pimer plants. This was based on the belief that plants soul early i.uuhl be the most attractise and would comm.uul the Sithe Energies best price, as potential bu ers jot keyed to gain a presence in this emerging market. We were correct.
tops the competi-lly spring, letters secking expressions of interest had been sent to 1,500 organi/atmn tive considered potential busers. lly summer, plant 5isits and meetings had begun as those interested ucre bidding being ualified. Siming in parallel with debate mer the restructuring legislation, the compam narrowed with an the list of bidders, uith bids due December 3,1997, just tuo uccks after the legislation was passal.
ggf,, 99 We had urged lau makers to act in 1997, arguing that it unuhl allon our customers to benefit 5657 mil-from the intense market interest. This woubl lead to a higher purchase price and redute rates charged to lion for five our customers, generating plants When the bids were opened and the winner announced on Det ember 10, the aggressise and a transitional pur-chase power contract.
strategics to push for House and Senate sotes in support of the legislation - - and to sell the oil and natural gas power plants - - ucre salidated.
Sithe Energies won the bidding, pasing a total of $657 million. Against a book salue of $450 million, Sithe's bid prosided 55 % milhon for the assets at fisc generating sites in and near lloston and s121 million for a transition purchase power contract.
Sithe cited competition and the recenth passed legidation as the reasons for its interest in I
hlassathusetts. Indicalise of how it sicu s the new market, Sithe also annouraed that it wouhl imest more than 51 billion at the sites to build 2,800 megawatts of new, highly eflicient generating capacity while keeping the 2,000 megan atts it purchased operating. This is testimont to our empimees and to the position $1 massachusetts has staked out in restructuring. It bodes ucIl for lloston Ldison since the 51assac husetts and New England economics shouhl benefit from the energy price impacts of competition.
The sale is expected to be completed by the middle of Stas.
Next to be addressed is the future of the Pilgrim Nuclear Pouer Station. In 1997, Pilgrim completed its shortest refueling outage in histon. The plant continued to perform utII, as it has throughout the 1990s. Under the settirment agreement which led to the salc of the oil and gas-fired plants, the company uill recmcr transition cost < associated uith Pilgrim,induding decommissioning costs.
Iloston i dison is required to desclop and file bs January 1,1999 with the Department of Telecommunications and Energy a plan for saluing Pilgrim. Among the options are creation of a regional or national alliance of nuclear plants or outright sale. In am case, the plant's physical condition is good, the plant is operating well and the staffis highh motisated.
I l
I I
kjsffsffjQ 11
NEW AFFILIATIONS... NEW DIRECTIONS j
I 1he company's ncn invohement in tcIccommunicarsons got yff to a strong start in i997. The telecommunicanonsjomt senture nith RCN attracicJ a lot ofnationalincJua interest - and many new cusomers.
RCN/11 massachusetts, m nhech Boston Edison is a 19 percent owner. is ncncJ as a nationalinodelfar vinIny entry into telecommunications markets. RCN is afacihtics-bascJ telecommunications company yffering bundicJ telephone, cable and Internet accesspr Jehrery over Juber optic netnorks.
m o, ~ -
s
[
d' ll ra i
sp,
,g
..s
'!v.
?
Au
. nu
\\
wag
_y,a
.nse
~
_dh u
(
l 11
NN+N%
RCN's overall customer count totaled approximately 20,000 by the end of 1997. It has attracted intense interest from communities throughout Greater lloston and around the state, especially regarding its cable television service. This is largely because for the first time established cable television companies are running into direct competition. An often-cited example is the City of Somenille, next to Iknton. In that city,Tme Warner chose not to impose a 10 percent rate increase last fall, simply because of the competition from RCN. Other cities and towns are taking notice, and RCN is signing video agreements with communities at the rate of one per month.
EnergyVision, an energy marketing joint venture withThe Williams Companies ofTulsa, Oklahoma, showed modest growth in 1997, primarily in the natural gas market. The electricity market in l
New England did not develop as quickly as anticipated. This is expected to change, howner, as states such j
l as Massachusetts open their markets, and independent generating companies such as Sithe Energies deselop new projects.
At another company afIlliate, Northwind Ikiston, construction began on its first district cooling plant krated atThe First Church of Christ, Scientist in Iloston. The plant uill be ready to sene customers in Boston's Back Bay District in June,1998. Northwind is 75 percent owned by Ikiston Edison and 25 percent owned by UnicomThermal of Chicago.
I Coneco, a wholiponned energy senices company, signed significant contraas in NewYork and l
Florida and several other states during the year. While it continued to grow, the pace slowed somewhat in late l
Customers have i
1997 due to energy conservation funding cutbacks for NewYork State schools.
I already begun to real-tre the bene-fits of competi-tion in the cable industry j
through our l
relationship with RCN.
l o
~
THE FUTURE our success in 1997 was built around reoric, processes and technologies working together to scrre customers. The company was featurcJ in publications such as TI.1tE magazine, the lIall Street purnal, the Newkrk Times and Torbes because ofitspcus on strategiesfor success under comyctition. The sision, and the strate-giesfor acccmpinhing it, are ss ell JcjincJ and bemg implemented.
ppm..
4p
- s..
m:=
l l, 2
- , y 23 V)-1 94
~
,4,p,4
/
4 14 l
l 1
l l
l l
There has neser been a more exciting time in the electric utility industry. And with the j
'"7'8 52 "
challenges of deregulation come opportunities for growth. In 1998, we expect to see the beginning of Edison dramatic changes in the structure of the utility indnstry in New England. Now that the rules of received competition and restructuring are becoming dear, consolidation appears inesitable. The company expects n, tion,i to be part of that consolidation as the territorial maps of utility sersice areas are redrawn. Geographic recogni-expansion is a major part of the company's strategy for growth.
from
~
The ycar 1998 will hase its challenges. The rate reduction of 10 percent, as well as the McGraw infrastructure necessary to achieve customer choice, will challenge our employees. The strict cost control Hili for l
l measures and productivity imprmements that have been imp!cmented in the recent past will continue.
Corporate Excellence.
Yet, the company is in a good position for grow th because of investments in technology, imprmements in operations and a highly skilled workforce.
The strong management team that produced the results of the last few years, especially the 1
results of 1997,is well positioned to lead lloston Edison. We will continue to balance the ongoing, I
day-to-day needs of the company while embracing each opportunity to grow and prosper.
" Boston Edison is being recognized forits ground breaking corporate strategy that was initiated wellin advance of state regulatory mandates and continues to strengthen the company's commitment to the end user" Mariel Leone Electrical World Editor-in-chief Commenting on Boston Edison's selection for McGraw Hill's l
Corporate Excellence Award N+NSNN is
'NbNstsNsN 1
FINANCIAL SECTION Dividends Paid Per Share Capital Expenditures (in millions)
$255 $247
$230-
$1.88 $1.88
$1.82
$205
$199
$1.76
$180
$1J5
$155
$145
$114
$105 1993 1994 1995 1996 1997 1993 1994 1995 1996 1997 Retail Customer Sales Mix OResident Commercial 60%
Industrial & Other 13%
16
M: nag:m:nt's Discussion end Analysis them will be derived. Net generating assets recoverable from the oroceeds of the fossil divestiture and through the non-bypassable Electric Utility Industry Restructuring transition charge of our distribution business which continues to The traditionally rate-regulated electric utility industry is rapidly be subject to rate-regulation, therefore, remain on our consolidat-changing in response to the continuing market pressures for ed balance sheet at December 31,1997. In addition, approxi-lower-priced electric energy. These pressures have resulted in mately 25% of the oper.-:. ions and capital costs, induding a regulatory and legislative proceedings at both federal and state wrurn on investment, of Pilgrim Nudear Power Station will con-levels designed to foster competition in the industry. On tinue to be collected under wholesale life of the unit contracts.
January 28,1998, the Massachusetts Department of These contracts continue to be regulated by the Federal Energy Telecommunications and Energy (DTE), formerly the Regulatory Commission (FERC) and are not impacted by our Department of Public Utilities (DPU), approved our restructur-settlement agreement.
ing settlement agreement that wa t ',ed in July 1997. The DTE D,vestiture of Fossil Generat.ing Assets i
found that the settlement agreer.m substanually complied or was consistent with key provisions of a Massachusetts law enact-Our restructuring settlement agreement includes a provision for ed in November 1997 establishing a comprehensive framework the divestiture of our fossil generating assets no later than six for the restructuring of our industry. Major provisions of our months after the retail access date. On December 10,1997,we settlement agreement include the ability for retail electric cus-entered into a purchase and sale agreement with Sithe Energies, tomers to choose their electricity supplier (referred to as retail Inc., a privately-held company headquanered in New York, to 1
access) as of March 1,1998 (the retail access date). Customers purchase our non-nuclear generating assets. The proceeds from who choose not to panicipate in retail access will have the the sale of these assets will be 5657 million. Fhe net book value option of continumg to buy power from our electric delivery of these assets at December 31,1997 is approximately 5450 mil-business at ' Standard Offer" prices. Upon the retail access date, lion. Included in the purchase price, Sithe Energies will pay customers that continue to buy electricity under the Standard 5121 million to us in connection with a six-month transitional Offer will realize an average 10% savings from the rates in effect power sales agreement under which we will buy power from the during 1997. Under the new legislation, Standard Ofter cus-generating plants. Sithe Energies will also be responsible for tomers will realize another 5% savings in electricity rates, after obligations resuking from the recently enacted utility restructur-1 an adjustment for inflation, by September 1,1999. We expect ing legislation for propeny tax payments to communities with to be able to meet this additional rate seduc: ion as a result of the now. nuclear power plants. Net proceeds from the divestiture divestiture of our fossil gen: rating assets which is discu sed will be used to reduce the distribution transitior, charge.
below. As part of our <ettlement agreement, the retail delivery Implementation of the divestiture plan is subject to cenain rates of our retained distribution business include a non-bypass-regulatory approvals including those of the DTE and the FERC.
able transition charp designed to recover certain costs incurred We anticip.cc finalization of the divestiture in mid-1998.
by our generation business under the traditional electric in July 1997, we reached an agreement with our field ser-ratemaking structure which cannot be otherwise recovered iu a vice union that requires the huyer of our fossil generating assets competitive environment. The rates of our distribution business to recognize and continue to honor the provisions of the union's will continue to be regulated by the DTE based on the cost of current collective bargaining agreement through the end ofits
)
providing distribution service.
term, May 2000. As pan of a package ofTered to employees In 1997 the Emerging Issues Task Force (EITF) reached con-affected by the fossil divestiture, all eligible fossil and designated sensus on specific issues raised related to the application of fossil support employees age 55 or older with at least to years of Statement of Financial Accounting Standards No. 71, Accounting service, or age 65 by July 1,1998, were offered unreduced for the Effects of Cenain Types of Regulation (SFAS 71). As part retirement cad transition benefits under a voluntary early retire-ofits consensus, the EITF determined that when deregulation ment program (VERP). Under this program,40 people elected legislation is passed and wgulatory actions have t> hen place pro-to retire. Retirement dates are expected to be the first of the viding suflicient detail for an enterprise to reasonably determine month follo,<ing the transfer of ownership of our fossil generat-how the transition plan will affect the separable ponion of hs ing assets. Severance programs were offered to management business being deregulated, the enterprise should stop applying and field service union employees affected by the fossil divesti.
SFAS 71 to that portion cfits business. As a wsuit of the recent.
ture that did not elect or were ineligible to retire under the ly passed Massachusetts electric industry restructuring legislation VERP, These severance benefits indude salary payments, edu-l and the DTE order regarding our related settlement agr.ement, cation / retraining allowances and outplacement services. It is we have determined that, as of December 31,1997, the pmvi.
anticipated that 48 employees will receive severance benefits sions of SFAS 71 no longer apply to the generation ponion of under these programs.
our business. The EITF funher determined that book values of The estimated costs associated with the VERP and sever-usets and liabilities originating in the separable pon;on of the ance programs is approximately 521 million including the business no longer su! at to rate-regulation should be evaluated effects on the retirement, life and dental plans. Severance and on the basis ofwhere the regulated cash flows to realize and settle employee retraining costs related to the divestiture are recover-17
able through the distribution transition charge under our settle-Company (WESCO), a subsidiary ofThe Williams Companies, ment agreement. Therefore, we have established an offsetting Inc. This LIC, EnergyVision, markets electricity, natural gas and regulatory asser for these obligations on our consolidated bal-energy-related services to retail customers in the six New England ance sheet at Decernber 31,1997.
states and began operations in February 1997. BETG and Nucl:ar Asset impairment Results of Operations As part of the riertlement agreement, we recover our net invest-
- ment in Pilgrim as of December 31,1995 (adjusted for deprecia-1997 versus 1996 l
tion through 1997) through the distribution transition arge.
Under the terms of the settlement agreement, we must perform Earnings per share of common stock were 52.71 in 1997 com-a nurket valuation of Pilgrim by 2002. Upon acceptance of the pared to $2.61 in 1996, a 3.8% increase as described below.
valuation by the DTE, the resulting dollar amount, net of pru.
Operating revenues dently incurred post-1995 investments in the plant, will reduce Oper2 ting revenues increased 6.6% over 1996 as follows:
amounts collectible through the transition charge. If the valua.
(in thousands) tion is not sufHcient to allow for the recovery of these invest-Retail electric revenues
$ 87,252 ments, we will seek their recovery through the transitiem charge.
Due to the market pressures facing us, the ultimate recovery of Demand side managemer't revenues 1,232 these assets is not certain. Therefore, we reduced our investment Wholesale revenues (765) in Pilgrim by the 513 million invested.n the plant since Short-term sales and other revenues 22,211 January 1,1996 as an impairment loss. An after tax charge of increase in operating revenues
$109,930 approximately 58 million due to this reduction was recorded to non-operating expense on our consolidated statement ofincome Retail base revenues, consistent with the 0.8% increase in in the fourth quarter of 1997. A similar uncertainty does not kilowatt-hour (kWh) sales in 1997, were relatively flat com-exist for the ultimate recovery of the fossil generating assets as pared to 1996. Increases due to warmer than normal tempera-the sale proceeds agreed to in the purchase and sale agreement rures in June and July, cooler temperatures in October and with Sithe Energies exceeds the net book value of these assets.
December and the stronger local economy were offset by milder than normal winter conditions during the first quarter of 1997 BEC Energy and lower industrial sales. Industrial sales continue to be We are currently awaiting a decision from the DTE regardm.g adversely affected by the dech.ne m manufactunng acovity m our reorganization plan to form a holding company structure. A our service territory. In addition, revenues in 1996 reflect one decismn from the Secun..nes and Exchange Comm..issmn is also more day of sales due to the leap year. Total retail electric rev-pending. Approval from the Nudcar Regulatory Comm..
ission enues increased $87.3 m.llion primarily due to the o.mmg effect i
was received on February 11,1998. Th.is plan was approved by
"# "" E"'
'# E * *' " " " ' * *'I' the FERC and ounhercholders in 1997. This new structure and purchased power clause revenues reflect the current recov-wd. l dearly separate our regulated and unregulated operations. It ery of prior year undercollecu.ons. These higher revenues are wdl provide us with greater orgai.Lational flexibih.ty allowing us offset by higher fuel and purchased peer expenses and, there-to take advantage of nonutility business opportunities in a more fore, have no net effect on earnings. Pugrim performance rev-umely manner. The holding company structure is a well-estab-enues, which vary annually based on the operating performance lished form of organization for companies conducu.ng muhiple of Pilgn.m Station, decreased due to a lower annual capacity fac-lines of business. In fact, all other.mvestor-owned Massachusetts tor effeco.ve November 1996 reflectmg the refueling and main-electnc utdities are current'y organized m. this manner. Thmugh renance outage in the first quarter of 1997.
our holding company, BEC Energy, we will seek ways to expand Short-term sales revenues m. creased approximately 516 m.l-i our customer base.
h.on. Th.. due to the continued reducu.on m avadable nudcar is is Joint Ventures energy supply in New England combined with a 42% increase in our fossil generation allowing for increased sales to the power We continue to conduct unregulated activities through our whol-exch nge. Revenues fr m short-term sales resuh in a corre-ly owned subsidiary, Boston Energy Tedmology Group (BETG).
sponding reduction to future fuel and purchased power billings During 1997, BETG entered into two joint venture agreen ents.
to retail customers and, therefore, have no net effect on earnings.
BETG has a joint venture agreement with RCN Telecom Services, Inc. (RCN). The final dosing on this joint venture Operating expenses occurred in June 1997. This limited liabi:;ty company (LIC)
Fuel and purchased power expenses m. creased 590.2 million.
irectly w. h local and long-distance telephone, video This ir crease reflects $57 milh.on related to the o.mmg effect of i
competes d.
u and Internet access companies for tdecommum. canons-reined E"Y***
E"*" " "'"#'E '" *
"' " *P""I services. BETG owns 49% of the LLC while RCN own 51%
fuel expense mcreased 550 million primarily due to the 42%
and maintains day-to-day management responsihih.ty. BETG also increase m foss.d generation. These increases were partially offset has an energy marketing venture with Williams Energy Serv.ices s8
by a 522 million decrease in power exchange purchases. Fuel 1996 vsrsus 1995 and purchased power expenses are substantially recoverable Earnings per share of common stock were 52.61 in 1996 com-through fuel and purchased power revenues.
pared to 52.08 in 1995. Earnings in 1995 reflect a nonrecurring Operations and maintenance expense decreased 52.6 mil-before tax charge of $34 million ($20.7 million after tax, or lion from 1996. The decrease is the result oflower spending 50.44 per share) associated with our corporate restructuring.
due to overall cost control effons and significam!y less overhaul The restructuring is discussed funher in Note F to the activity at our fossil generating units. These decreases were par-Consolidated Financial Statements. Excluding the nonrecurring tially offset by an approximately 55 million incremental impact restructuring charge, earnings per common share increased 3.6%
associated wah service restoration effons resulung from a severe over 1995 as described below.
snow storm in April 1997 that struck the greater Boston area.
The increase in depreciation and amonization expense is due Operating revenues to the net impact of two depreciation adjustments. We recorded Operating revenues increased 2.3% over 1995 as follows:
an 58.7 million nonrecurring charge to depreciation expense in (in thousands) the third quaner of 1997 to reflect the removal of specific Retail electric revenues
$48,649 nuclear-related intangible assets from our balance sheet. In 1996 Demand side management revenues (20,545) we recorded a 55.2 million adjustmeat to correct the accumulat-Wholesale revenues (2,072) ed depreciation balance of certain large computer equipment.
Short-term sales and other revenues 11,768 Income taxes increased as a result of higher net income off-set by a lower efTective tax rete. The effective tax rate for 1997 bcmase M operating revenues
$37,800 reflects the impact of the favorable outcome of an !mernal Revenue Service (IRS) appeal received in the third quaner relar.
Retail electric revenues increased 548.6 million. Fuel and ed to investment tax credits (lTC). This also resulted in an Purchased power clause revenues increased approximately $36 increase in unamonized ITC which will be reflected as a reduc.
million. These higher revenues are offset by higher fuel and tion to income tax expense over the life of the related assets.
purchased power expenses and, therefore, have no net effect on Refer to Note D to the Consolidated Financial Statements for earnings. Performance revenues increased $14.5 million as more information on income taxes.
Pilgrim Station operated at a higher capacity in 1996. Retail kWh sales increased 2.8% in 1996, primarily due to the posi-Oth r expense tive economic impacts on our commercial customers.
Other expense, net in 1997 reflects the charge of approximately Demand side maagement (DSM) revenues decreased pri-58 million, after tax, from the nuclear asser impairment which is marily due to a decline in current DSM program expenditures.
further discussed in Note C to the Consolidated Financial The primary reason for the decrease in wholesale revenues Smements in addition to BETG equity losses. These decreases is due to Pilgrim contract customer revenues. These revenues were panially offset by approximately 53 million, after tax, in decreased despite increased kWh sales due to lower operations interest income from the IRS appeal.
and maintenance expense related to Pilgrim Station. Pilgrim contract customers are billed for their proponionate share of the Intsr:st charges
,,;,, c,,,,,
Total interest charges on long. term debt decreased due to the Net short-term sales and other revenues increased $11.8 maturing of $100 million of 5.70% debentures in March 1997 million. Despite lower kWh sales, short-term sales revenues and the cessation of amonization of the associated redemption increased approximately $6 million due to higher fuel prices.
premiums. This was partially offset by the March 1997 issuance Revenues from short-term sales result in a corresponding reduc-of $100 million of 6.662% bank debt due in 1999. The tion to future fuel and purchased power billings to retail cus-decrease also reflects the maturity of $100 million of 51/8%
tomers and, therefore, have no net efTect on earnings. This debeutures in March 1996.
increase also reflects an increase in revenue < m non-electric Allowance for borrowed funds used during construction sources in 1996.
(AFUDC), which represents the financing costs of construction, decreased primarily due to a lower average construction work in Cperating expenses progress (CWIP) balance in 1997. The 1996 average CWIP bal.
Fuel and purchased power expenses increased $53.1 million.
ance included nuclear fuel purchased in anticipation of Pilgrim Fuel expense increased, despite a slight decrease in company gen-Station's scheduled refueling outage in the first quarter of 1997, eration, due to significantly higher oil and natural gas prices.
Purchased power expense reflects a higher volume of energy pur-(
Pr2f rred stock dividends chases and an overall increase in energy prices. These increases l
The decrease in preferred stock dividends is the result of the were panially offset by the timing effect of fuel and purchased redemption of 20,000 of mandatory and 20,000 ofoptional power cost recovery. Fuel and purchased power expenses are sub-shares of 7.27% series cumulative preferred stock in May 1997 stantially recoverable thmugh fuel and purchased power revenues.
and 400,000 shares of 8.25% series in June 1997. Refer to Note Operations and maintenance expense decreased $40.8 million I to the Consolidated Financial Statements.
primarily due to lower labor costs resulting from our 1995 restruc-19
\\
turing and the continuing cost control efforts of each of our busi-9% of our electde operating revenues. Total kWh sales increased ness units. In addition, the amortization of deferred nuclear out-3.1% as a result of the continued reduction in available nuclear age costs decreased 59 million. As discussed in Note B to the energy supply in New England. This reduction, combined with Consolidated Financial Statements, in the third quarter of 1995 an increase in our fossil generation allowed for increased sales to we made a retroactive change to the amortization period of these the power exchange.
deferred costs from five years to two years, consistent with the The 2.8% increase in 1996 retail kWh sales was primarily I
two-year cycle between refueling outages at Pilgrim Station.
due to the positive effect on commercial customers of the The 1995 operating expenses reflect a $34 million nonre-strong economy in our retail service territory. Residential sales curring charge related to our corporate restructuring. Refer to decreased slightly primarily due to overall milder than normal Note F to the Consolidated Financial Statements for additional weather conditions. Industrial sales remained relatively flat.
information regarding our 1995 restructuring.
Total kWh sales, including wholesale, increased 3.3% The Depreciation and amortization increased 532.2 million. The increase in wholesale sales was primarily due to higher sales to increase is primarily the result of a change in the estimated remain-our Pgrim contract customers as the plant was operating for ing economic lives of our Mystic 4,5 and 6 fossil generating units substantially all of 1996. In addition, sales to our municipal in the second quarter of 1996, retroactive to the beginning of the customers increased due to a reduction in available energy year, and an increase in the depreciable plant balance. The change supply in New England.
in estimated economic lives of hiystic 4,5 and 6 resulted in a $22 Electdc mnas million increase in depreciation expense for the year.
The decrease in DSM programs expense reflects the decline As discuss-d in the Electric Utility Industry Restructuring sec-in current DSM program expenditures.
tion, our delivery business will provide Standard Offer customers The increase in income taxes is due to higher ner income service at rates designed to give an average 10% savings upon the and a higher effective tax rate in 1996. The effective tax rate in retail access date. As part of the recently passed restructuring 1996 is 38.2% versus 37.1% in 1995.
legislation in Massachusetts, these customers are to realize an additin l 5% average savings, after an adjustment for inflation, intJrsst charges by g.. ober 1,1999. We expect to meet this additional rate Interest on long-term debt decreased due to the maturity of reduction as a result of the proceeds received from the divestiture
$100 million 8 7/8% debentures in December 1995 and $100 ofour fossil generating assets and potential securitization or reli-million 51/8% debentures in March 1996. These decreases nancing of our stranded costs. Under our settlement agreement, were partially offset by the issuance of $125 million 7.80%
the aggregate amount of our transition charge is reduced by the debentures in May 1995 which were outstanding for all of 1996.
net proceeds from fossil divestiture.
Other interest charges increased due :o an increase in interest on Under the settlement agreement, the annual performance short-term debt caused by the higher average short-term debt adjustment charge ceases and our cost recovery mechanism for level partially offset by a lower average short-term borrowing Pilgrim Station changes as of the retail access date. Approximately rate. The short-term debt balance increased as a result of the 25% of the operations and capital costs, including a return on debenture maturities and the redemption of 54 million of pre-investment, will continue to be collected under wholesale life of ferred stock in 1996. AFUDC decreased due to lower overall the unit contracts. The remaining output will be sold in the construction activity during 1996, shorter construction periods, competitive energy market. Through December 31,2000, we and lower short-term interest rates.
will share 25% of any profit or loss from the sale of Pilgrim's output with distribution customers through the transition Electric Sales and Revenues charge. In adu..itmn, we wdl obtain transition payments up to a Elsctric sales maximum of $23 million per year depending on the level of Retail kWh sales increased 0.8% in 1997. This was primarily
'". incurred for property taxes, insurance, regulatory fees and attributable to the commercial sector. The commercial increase
""'Y 9 "* #" *
Beginning up n the retail access date, the rates of our dis-reflects the impact of a continued strong economy in the Boston nibution business will remain unchanged through area and very warm temperatures in June and July and cooler December 31,2000, subject to a minimum and maximum than normal temperatures in the fourth quarter. Hotel occupan-n werage c mm n equity (ROE). We will be required rerum cy rates and non-manufacturing employment continued to to file witn the DTE a computation supporting the ROE of our increase in 1997. The commercial sector represents approxi-distribution business after each calendar year. The ROE is sub-mately 50% of our electric operating revenues. Residential rev-ject m a H or cf a.md a ceiling of 11.75% If the ROE is enues, which represent 27% of electric revenues, were also posi-below 6% we are authonzed to add a surcharge to distribution tively impacted by the weather. These positive impacts were off-rates in order to achieve the 6% floor. If the ROE is above set by milder winter weather in the first quarter of 1997 and 11% we are required to adjust distribution rates by an amount declines in manufacturing employment affecting the industrial necess ry to reduce the calculated ROE between 11% and sector. In addition, revenues in 1996 reflect one more day of 12.5% by 50% and a return above 12.5% by 100% No sales due to the leap year. The industrial sector represents only a
I adjustment is made if the ROE is between 6% and 11%. The expensed as incurred. In addition, we have made a decision to cost of providing transmission service to distribution cwomers use this opportunity to upgrade some of our less efficient cen-will be recovered on a fully reconciling basis.
tralized business systems. The full replacement costs associated with these systems will be capitalized and amortized over future Liqu,idity i
The total cost of the year 2000 project is expected to be We ordinarily meet most of our cash requirements for plant funded through internally generated funds. We anticipate com-expenditures with internally generated funds. These funds are pletWn of the year 2000 project in the third quaner of 1999.
cash flows from operating activities, adjusted to exclude changes in working capital and the payment of dividends. During 1997.
Other Matters 1996 and 1995 our internal generation of cash provided 211%,
Environmental 177% and 102% respectively of our plant expenditures. The capital spending level, excluding nuclear fuel, forecasted for We are subject to numerous federal, state and local star.dards with 1998 is $265 million which includes amounts for utility plant respect t waste disposal, air and water quahty and orher environ-and the capital requirements of our nonutility ventures. This mental considerations. These standards can require that we mod-
- f f
f "' #*ii"E *# h"*' ' *'"' "##**d "P*'** *E '"'
spending level also includes the 1998 portion of business system
- cunen y wn or operate approximately 30 properties replacements discussed below. The capital spending level over where o.d or hazardous materials were previously spilled or the next five years is forecasted to be approximately $940 mil-lion. In addition to capital expenditures, we have debt and pre-released. We also continue to face possible liability as a poten-ferred stock payment requirements of $103.6 million in 1998 nally resp nsible party m the cleanup f six multi-party haz-ardous waste snes m Massachusetts and other states where we and 1999, $168.6 million in 2000, $53.6 million in 2001 and are alleged to have generated, transported or disposed of haz-
$3.6 million in 2002.
ardous waste at the sites. Refer to Note L6. to the We supplement our internally generated funds as needed, Consolidated Fm.ancul Statements for more. forman.on regard-m primarily through the issuance of short-term commercial paper
- E
- 'd "' ** * *
- i*'" ** *
. h and bank borrowings. We have authority from the FERC to The Accountmg Standards Execun.ve Committee of the issue up to $350 milh.on of short-term debt. We also have a American Institute of Cern.fied Public Accountants issued
$200 milh.on revolving credit agreement and arrangements with Statement of Pos.. mon 96-1, Environmental Remed..ianon several banks to provide addinonal short-term credit on a com-Liabih..ues (SOP 96-1), effective m 1997. This statement con-mated as well as on an uncommitted and as available bas.is. At
"'**ive gmdance on specific accounting issues rdated December 31,1997, we had $137 million of shot t-term debt to the reccpan.on, measurement, display and disclosure of envi-outstandm.g none of which was m. curred under the revolving ronmental remed..ianon liabih..nes, it requires that an accrual for credit agreement. We have $220 million remaining under our environmental liabih..nes include estimates of the costs of com-approved long-term financing plan w. h the DTE which.
it is pensanon and benefits for those employees expected to devote a available through 1998. Proceeds from issuances under th.is sigmficant amount of time directly to that effort SOP 96-1 I
plan are to be used to refinance short and long-term securities had no material effect on our financial position or results of and to fund capaal expenditures. Refer to Notes I and J to the operations during 1997.
Casolidated F.mancial Statements f.or add..itmnal informatmn Uncertainties continue to exist with respect to the disposal relating to our financ.mg actmnes.
M fd M i bl di m in w m M At December 31,1997, BETG had $7.5 m.llion outstand-i resulu.ng from th< operation ofI,ilgn.m Stanon. The Um.ted mg under a revolving credit agreement. The purpose of th.
is States Department of Energy (DOE) is responsible for the ulti-k"*. ts fund as capital requirements above out $45 milhon mate disposal of spent nuclear fuel; however, uncertainties hmned investn.ent. This debt wdl be refmanced upon the for-regarding the DOE's schedule of acceptance of spent fuel for dis-marion of BEC Energy.
posal continue to exist. In 1995 we regained access to the 1.LW We anocipate usmg the sale proceeds from our pending disposal facility located in Barnwell, South Carolina. Refer to fossil divestiture m adjust our capital structure.
Note E to the Consolidated Financial Statements for funher dis-Y:ar 2000 Computer issue cussion regarding nuclear decommissioning and waste disposal.
The year 2000 computer issue is the result of programs written The 1990 Clean Air Act Amendments (CAAA) require a j
' using two digits instead of four to define an applicable year, significant reduction in nationwide emissions of sulfur dioxide Consequently, these programs will not properly recognize calen_
from fossil generating units. Other provisions of the CAAA dar dates beginning in the year 2000. This could cause comput, involve limitations on emissions of nitrogen oxides from existing ers to shut down or yield incorrect results.
gmerating units. As discussed in the Divestiture of Fossil We have developed a plan to address the year 2000 issue Generating Assets section, we have signed an agreement with l
that includes modification of certain applicadons and replace.
Sithe Energies for the sale of our fossil generating assets. If regu-ment of systems that are not year 2000 compliant. The cost latory approval is not obtained or is delayed, we could continue associated with modification of existing applications will be m operate these units subject to the provisions of these amend-21
ments. We currently meet the standards of the CAAA and, tutional. We are currently unable to determine the outcome of depending on the outcome of certain Massachusetts Department these proceedings or their impact on us.
of Environmental Protection air quality modeling studies, our Opponents of the electric industry restructuring legislation generating units could continue to operate through at least 1999 that was enacted in November 1997 have mounted a referen-before additional emission reductions would be required.
dum campaign to repeal that law. A coalition of business, Public concern continues regarding electromagnetic fields industry and public interest groups that supported the legisla-(EMF) associated with electric transmission and distribution tion, along with the electric utility industry, is opposed to the facilities and appliances and wiring in buildings and homes.
referendum and is prepared to mount an aggressive campaign to Such concerns have included the possibility of adverse heahh defeat it. We are currently unable to predict the eventual out-effects caused by EMF as well as perceived e& cts on property come of this referendum or its impact on us.
values. Some scientific reviews conducted to date have suggest-Safe harbor cautionary statement ed associations between EMF and potential health effects, while other studies have not substantiated such associations. The We occasionally make forward-looking statements such as fore-National Research Council previously reported that there is no casts and projections of expected future performance or state-conclusive evidence that exposure to EMF from power lines and ments ofour plans and objectives. These forward-looking state-appliances presents a health hazard. The panel of scientists, ments may be contained in fdings with the Securities and working with the National Academy of Sciences, report that Exchange Commission, press releases and oral statements. Actual more than 500 studies over the last several years have produced results could potentially differ materially from these statements.
no proof that EMF causes leukemia or other cancers or harms Therefore, no assurances can be given that the outcomes stated in human health in other ways. We continue to support research such forward-looking statements and estimates will be achieved.
into the subject and are participating in the funding ofindus-The preceding sections include certain forward-looking try-sponsored studies. We are aware that public concern regard-statements about the effects of the industry restructuring ing EMF in some cases has resulted in litigation, in opposition process and our related settlement agreement, the divestiture of to existing or proposed facilities in proceedings before regulators our fossil generating assets, operating results, year 2000 and or in requests for legislation or regulatory standards concerning environmental and legal issues.
EMF levels. We have addressed issues relative to EMF in vari-The e& cts of electric utility industry restructuring could ous legal and regulatory proceedings and in discussions with di&r from our expectations. This could occur as regulatory customers and other concerned persons: however, to date we decisions and negotiated settlements between utilities and inter-have not been significantly affected by these developments. We venors are finalized. In addition, the development of a comper-continue to monitor all aspects of the EMF issue, itive electric generation market, the impacts of actual electric supply and demand in New England and further legislative Litigrt. ion action may afTect the ultimate results of the. dustry restructur-m In October 1997, the DTE opened a proceeding to investigate ing and our settlement agreement.
our compliance with the 1993 order which permitted the forma-The divestiture plan could di&r from our expectations.
tion of BETG and authorized us to invest up to $45 million in This could occur if required regulatory approvals are delayed or unregulated activities. We are unable to determine the ultimate not obtained.
outcome of this proceeding or its impact on our operations.
The impacts of our continued cost control procedures on We were named as a party in lawsuits by Subaru of New our operating results could differ from our expectations. The England, Inc. and Subaru Distributors Corporation. The plain-effects of changes in economic conditions, tax rates, interest tiffs claimed certain automobiles stored on lots in South Boston rates, technology and the prices and availability of operating suffered pitting damage caused by emissions from our New supplies could materially a&ct our projected operating results.
Boston Station generating unit. In 1997 we settled both law-The timing and total costs related to our year 2000 plan suits. Neither settlement had a materialimpact on our consoli-could differ from our expectations. Factors that may cause such dated resuhs of operations or financial position.
di&rences include the ability to locate and correct all relevant Refer to Note L8. to the Consolidated Financial Statements for computer codes and the availability of personnel trained in this more information on other kpl matters in which we are involved, area. In addition, we cannot predict the nature or impact on operations of third party noncomplWce.
Industry restructuring legal proceedings / referendum Tk imcts of various envircrental and legal issues ctmpaign could di&r from our expectations. Nov regulations or changes The DTE order approving our settlement agreement has been to existing regulations could impose additional operating appealed by certain parties to the Massachusetts Supreme requirements or liabilities other than expected. The c& cts of Judicial Court. In addition, along with other Massachusetts changes in specific hazardous waste site conditions and cleanup investor owned utilities, we have been named as a defendant in a technology could affect our estimated cleanup liabilities. The class action suit seeking to declare certain provisions of the impacts of changes in available information and circumstances Massachusetts electric industry restructuring legislation unconsti-regarding legal issues could affect our estimated litigation costs.
)
22
_.___a
L Consolid:tsd Stat:msnts of Incoma years ended December 31, l
(in' thousands, except earnings per share) 1997 1996 1995 j
Operating revenues
$ 1,776,233
$ 1,666,303
$ 1,628,503 l-Operating expenses:
Fuel and purchased power 679,131 588,893 535,806 i
Operations and maintenance 414,779 417,372 458,196 Restructuring costs 0
0 34,000 Depreciation and amortization 188,687 185,494 153,339 l
Demand side management programs 29,790 30,825 45,125 Taxes-property and other 107,975 107,086 106,361 income taxes 95,021 88,703 68,276 Total operating expenses 1,515,383 1,418,373 1,401,103 Operating income 260,850 247,930 227,400 Other income (expense), net (10,498) 698 (575)
Operating and other income 250,352 248,628 226,825
{
interest charges:
Long-term debt 92,489 94,823 106,640 Other 14,410 14,551 12,642 Allowance for borrowed funds used during construction (1,189)
(2,292)
(4,767)
Total interest charges 105,710 107,082 114,515 Net income 144,642 141,546 112,310 Preferred stock dividends 13,149 15,365 15,571 Earnings available for common shareholders
$ 131,493
$ 126,181 5
96,739 Weighted average common shares outstanding 48,515 48,265 46,592 Earnings per share of common stock-basic and diluted 2.71 2.61 2.08 Consolidated Statements of Retained Earnings years ended December 31,
- (in thousands) 1997 1996 1995 Balance at the beginning of the year
$ 292,191
$ 257,749
$ 247,409 I
Net income 144,642 141,546 112,310 Subtotal 436,833 399,295 359,719 Dividends declared:
Preferred stock 13,149 15,365 15,571 Common stock 91,208 90,834 86,399 Subtotal -
104,357 106,199 101,970 Provision for preferred stock redemption and issuance costs (a) 3,674 905 0
Balance at the end of the year
$ 328,802
$ 292,191
$ 257,749 (a) Refer to Note B.7. to the Consolidated Financial Statements.
The accompanying notes are an integral part of the consolidated financial statements, i
O
C:ns:lidtt:d 8:l:nca Shuts December 31, (in thousands) 1997 1996 Assets Utility plant in service, at original cost
$ 4,457,868
$ 4,387,887 Less: accumulated depreciation 1,713,079
$ 2,744,789 1,550,317
$ 2,837,570 Nuclear fuel 351,722 351,453 Less: accumulated amortization 283,787 67,935 268,509 82,944 Construction work in progress 41,403 30,376-Net utility plant 2,854,127 2,950,890 Nuclear decommissioning trust 151,634 132,076 Equity investments 35,455 28,752 Other investments 7,107 7,630 Current assets:
Cash and cash equivalents 4,140 5,651 Accounts receivable 192,220 233,024
' Accrued unbilled revenues 30,048 34,922 Fuel, materials and supplies, at average cost 60,834 57,075 Prepaids and other 31,283 318,525 45,146 375,818 Deferred debits:
Regulatory assets 220,403 202,026 Other 35,096 32,099 Total assets
$ 3,622,347
$ 3,729,291 Capitalization and Liabilities Common stock equity
$ 1,073,454 5 1,036,424 Cumulative preferred stock 161,093 201,419 Long-term debt 1,057,076 1,058,644 Current liabilities:
Long-term debt / preferred stock due within one year 102,667
$ 102,667 Notes payable.
137,013 201,454 Accounts payable 87,015 134,083 Accrued interest 24,289 24,378 Dividends payable 24,748 25,343 Other 128,061 503,793 115,812 603,737
' Deferred credits:
Accumulated deferred income taxes 485,738 498,718 Accumulated deferred investment tax credits 60,736 58,899 Nuclear decommissioning liability 155,182 133,388 Power contracts 71,445 88,963 Other 53,830 49,099 Commitments and contingencies Total capitalization and liabilities
$ 3,622,347
$ 3,729,291 The accompanying notes are an integral part of the consolidated financial statements.
I 24
l Consolid:t:d Stat ments of Cash Flows years ended December 31,
-(in thousands) 1997 1996 1995 Operating activities:
N:t income
$ 144,642
$ 141,546
$ 112,310 Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 223,529 228,259 202,294 l
Deferred income taxes and investment tax credits (21,664)
(4,057)
(25,193)
Allowance for borrowed funds used during construction (1,189)
(2,292)
(4,767)
Nzt changes in:
Accounts receivable and accrued unbilled revenues 4 678 (11,719)
(34,626)
Fuel, materials and supplies (5,486)
(2,171) 7,202 Accounts payable (47,068) 609 2,978 Other current assets and liabilities 25,428 (44,514) 26,485 Other, net (4,640) 50,815 26,993 Net cash provided by operating activities 359,230 356,476 313,676 investing activities:
Plant expenditures (excluding AFUDC)
(114,110)
(145,347)
(180,822)
Nuclear fuel expenditures (4,089)
(52,967)
(13,621)
Investments in joint ventures (7,859)
(5,698) 0 Other investments (19,830)
(28,616)
(19,005)
Net cish used in investing activities (145,888)
(232,68)
(213,448)
Finincing activities:
Issuances:
Common stock 144 12,559 64,888 l
Long-term debt 100,000 0
125,000 R demptions:
Preferred stock (44,000)
(4,000)
(2,000)
Long-term debt (101,600)
(101,600)
(100,600)
Net change in notes payable (64,441) 75,013 (88,345) l Dividends paid (104,956)
(106,010)
(100,152) l Net cIsh used in financing activities (214,853)
(124,038)
(101,209) l Net d: crease in cash and cash equivalents (1,511)
(190)
(981) l Cash and cash equivalents at the beginning of the year 5,651 5,E 41 6,822 Cash and cash equivalents at the end of the year 4,140 5,651 5,841 l
Supplemental disclosures of cash flow information:
l i
C:sh paid during the year for-Interest, net of amounts capitalized
$ 100,795
$ 100,010
$ 104,011 income taxes 99,326 98,668 9'180 The accompanying notes are an integral part of the consolidated financial statements.
l l
25 l
Not:s to Consolidated Financial Statements Note A. Nature of Operations Boston Edison Company (the Company) is an investor-owned regulated public utility operating in the energy, energy services and telecommunications business. This includes the generation, purchase, transmission, distribution and sale of electric energy and the development and implementation of electric demand side management programs. A portion of our generation is produced by our wholly owncd nuclear generating unit, Pilgrim Nuclear Power Station. We supply electricity at retail to an area of 590 square miles, including the city of Boston and 39 surrounding cities and towns. We also supply electricity at wholesale for resale to other utilities and municipal electric depanments. Electric operating revenues were 88% retail and 12% wholesale in 1997. We also conduct unreg-ulated activities through our wholly owned subsidiary, Boston Energy Technology Group (BETG).
Through BETG and its subsidiaries, we are engaged in certain nonutility businesses, including energy utilization and conserva-tion, construction management and district energy. BETG has a joint venture with RCN Telecom Services, Inc. (RCN) that provides certain telecommunications-related services. The limited liability company (LLC) formed from this joint venture is owned 51% by RCN and 49% by BETG, with RCN having the day-to-day management responsibility. BETG also has a joint venture with Williams Energy Services Company (WESCO). This joint venture markets electricity, natural gas and energy-related services to retail customers in the six New England states. BETG and WESCO cach own 50% of this LLC, EnergyVision.
We are currently awaiting a decision from the Massacimsetts Department telecommunications and Energy (DTE), fonnerly the Department of Public Utilities, regarding our plan to form a holding company structure. This structure will clearly separate our regulated and unregulated lines of business. Through our holding company, BEC Energy, we will seek ways to expand our customer base. After the corporate reorganization, Boston Edison will be a wholly owned subsidiary of BEC Energy. BETG will cease being a subsidiary of Boston Edison and become a wholly owned subsidiary of BEC Energy. The common shareholders of Boston Edison will become shareholders of BEC Energy. The existing debt and preferred stock of Boston Edison will remain obligations of the regu-10ted utility business.
Refer also to Note C to these Consolidated Financial Statements for changes in the nature of our operations as a result of the electric utility industry restructuring and our related settlement agreement.
Note B. Significant Accounting Policies
- 1. Basis of Consolidation and Accounting The consolidated financial statements include the activities of our wholly owned subsidiaries, Harbor Electric Energy Company (HEEC) and BETG. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to the prior year data to conform with the current presentation.
We follow accounting policies prescribed by the Federal Energy Regulatory Commission (FERC) and the DTE. We are also sub-ject to the accounting and reporting requirements of the Securities and Exchange Commission. The consolidated financial statements conform with generally accepted accounting principles (GAAP). As a rate-regulated company we have been subject to Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71), under GAAP. The application of SFAS 71 results in differences in the timing of recognition of certain expenses from that of other businesses and indus-tries. As a result of the recently passed Massachusetts electric industry restructuring legislation and the DTE order regarding our related settlement agreement, as of December 31,1997, we are no longer applying the provisions of SFAS 71 to our generation busi-ness. Our distribution business remains subject to rate-regulation and continues to meet the criteria for application of SFAS 71.
Refer to Note C to these Consolidated Financial Statements for more information on the accounting implications of the electric utili-ty industry restruc.uring.
The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
- 2. Revenues We record estimates of retail base revenues for electricity used by our customers but not yet billed at the end of each accounting period.
- 3. Forecasted Fuel and Purchased Power Rates The rate charged to retail customers for fuel and purchased power allows for fuel and purchased power costs which are not included in our base rates to be billed to customers using a forecasted rate. The difference between actual costs and the amounts bilkd to cus-tomers is recorded as an adjustment to fuel and purchased power expenses and is included in accounts receivable on the consolidated balance sheer until subsequent rates are adjusted.
i a6
- 4. Utility Plant Utility plant is stated at original cost of construction. The costs of replacements of property units are capitalized. Maintenance and repairs and replacements of minor items are expensed as incurred. The original cost of property retired, net of salvage value, and the related costs of removal are charged to accumulated depreciation.
- 5. D:preciation and Nuclear Fuel Amortization Depreciation of our utility plant is computed on a straight-line basis using composite rates based on the estimated useful lives of the various classes of property. Excluding the effect of the adjustment discussed below, the overall composite depreciation rates were l
3.30%,3.33% and 3.28% in 1997,1996 and 1995, respectively.
Upon the completion of a review of our electric generating units, we determined that our oldest and least ef6cient fossil units (Mystic 4,5 and 6) were unlikely to provide competitively-priced power beyond the year 2000. Therefore we revised the estimated remaining economic lives of these units to five years in 1996.
The cost of decomshioning Pilgrim Station is excluded from our depreciation rates. Refer to Note E to these Consolidated Financial Statements for a discussion of nudear decommissioning. The cost of nudear fuel is amortized based on the amount of energy Pilgrim Station produces. Nudear fuel expense also indudes an amount for the estimated costs of uhimately disposing of spent nuclear fuel and for assessments for the decontamination and decommissioning of United States Department of Energy nudear enrichment facilities. These costs are recovered from our customers through fuel rates.
- 6. Deferred Nuclear Outage Costs We defer the incremental costs associated with nuclear refueling outages when incurred and amortize them over Pilgrim Station's oper-ating cycle. In 1995 we changed the amortization period from five years to two years. The two-year amortization period is consistent with the two-year cycle between nuclear refueling outages at Pilgrim Station.
- 7. Costs Associated with issuance and Redemption of Debt and Preferred Stock Consistent with our recovery in electric rates, we defer discounts, redemption premiums and related costs associated with the redemp-tion and issuance oflong-term debt and preferred stock. The costs related to long. term debt are recognized as an addition to interest expense over the life of the original or replacement debt. Beginning in 1996, consistent with an accounting order received from the FERC, we reflect costs related to preferred stock r demptions and issuances as a direct reduction to retained earnings upcm redemption or over the average life of the replacement preferred stock series as applicable.
- 8. Allowance for Borrowed Funds Used During Construction (AFUDC)
AFUDC represents the estimated costs to finance utility plant constmcrion. In accordance with regulatory accounting, AFUDC is induded as a cost of utility plant and a reduction of current interest charges. Although AFUDC is not a current source of cash income, the costs are recovered from customers over the service life of the related plant in the form ofincreased revenues collected as a result of higher depreciation expense. Our AFUDC rates in 1997,1996 and 1995 were 6.04%,5.87% and 6.35%, respectivdy, and represented only the cost of short-term debt.
- 9. Cash and Cash Equivalents Cash and cash equivalents are comprised of highly liquid securities with maturities of 90 days or less when purchased. Outstanding checks are included in cash and accounts payable until they are presented for payment.
- 10. Allowance for Doubtful Accounts Our accounts receivable are substantially recoverable. This recovery occurs both from customer payments and from the portion of cus-tomer charges that provides for the recovery of bad debt expense. Accordingly, we do not maintain a significant allowance for doubtful accounts balance.
- 11. Regulatory Assets Regulatory assets represent costs incurred which are expected to be collected from customers through future charges in accordance with j
agreements with our regulators. These costs are expensed when the corresponding revenues are received in order to appropriately j
match revenues and expenses. The majority of these costs is currently being recovered from customers over varying time periods. Refer
]
to Note C to these Consolidated Financial Statements for information regarding the recovery of regulatory assets related to our genera-tion business.
)
n l
Regulatory assets consisted of the following:
December 31, l
1997 1996 Fossil divestiture
$ 21,248 5
0 71,445 88,963 Pow:r contracts income taxes, net 51,096 47,483 R:demption premiums 27,019 31,052 Postretirement benefits costs 22,441 15,009 Decont:mination and decommissioning 12,282 13,190 Nucl:ar outage costs 10,160 3,432 Other 4,712 2,897
$ 220,403
$ 202,026
- 12. Eirnings Per Share of Common Stock Basic earnings per share (EPS) of common stock is calculated by dividing net income, after the payment of preferred stock dividends, by the weighted average common shares outstanding during the year. Statement of Financial Accounting Standards No.128, Earnings per Share, requires the disclosure of diluted EPS effective for periods ending after December 15,1997.1)iluted EPS is similar to the computation of basic EPS except that the weighted average common shares is increased to include the number of dilutive potential common shares. Diluted EPS, which indudes the effect of deferred (nonvested) shares and stock options granted under the Stock Incentive Plan in the calculation of weighted average common shares, is the same as basic EPS displayed on the consolidated statement of income.
Note C. Electric Utility industry Restructuring
- 1. Accounting implications Under the traditional revenue requirements model, our electric rates have been based on the cost of providing electric service. As such, we have been subject to certain accounting standards that are not applicable to other businesses and industries in general. The applica-tion of SFAS 71 requires us to defer the recognition of certain costs when incurred if future rate recovery of these costs is expected.
Based on a consensus reached by the Emerging Issues Task Force (EITF) regarding specific issues raised related to the application of SFAS 71, we have determined that, as of December 31,1997, the provisions of SFAS 71 no longer apply to the generation portion of our busi-ness. In its consensus, the EITF determined that when deregulation legislation is passed and regulatory actions have taken place provid-ing sufficient detail for an enterprise to reasonably determine how the transition plan will affect the separable portion cfits business being deregulated, the enterprise should stop applying SFAS 71 to that portion ofits business. On January 28,1998, the DTE approved our restructuring settlement agreement that was filed in July 1997. The DTE found that the settlement agreement substantially com-plied or was consistent with key provisions of a Massachusetts law enacted in November 1997 establishing a comprehensive framework for the restructuring of our industry. The EITF further determined that book values of assets and liabilities originating in the separable portion of the business no longer subject to rate-regulation should be evaluated on the basis of where the regulated cash flows to realize and settle them will be derived. Net utility plant and other related assets on our consolidated balance sheet as of L)ecember 31.1997 include approximately $700 million related to nuclear generation and approximately $450 million related to fossil generation. As part of our settlement agreement, approximately 75% of these nuclear assets are fully recoverable through the non-bypassable transition charge of our distribution business which continues to be subject to rate-regulation. The remaining 25% will be collected under Pilgrim's wholesale life of the unit contracts. These contracts continue to be regulated by the FERC and are not impacted by our settlement agree-ment. These fossil assets will be recovered from the proceeds from their sale as discussed in part 2 below.
The implementation of our approved settlement agreement has certain accounting implications. The highlights of these include:
D:pr:clation The composite depreciation rate for distribution utility plant increases from 2.38% to 2.98% as of March 1,1998 (the retail access date).
G:noration related plant and regulatory assets Plant and regulatory assets related to our generation business, except for those related to Pilgrim's wholesale life of the unit contracts, will be recovered through the transition charge. This recovery, which includes a return, will occur over a twelve-year period, aR
}
Storm fund i
Under the settlement agreement, we are authorized to establish a storm contingency fund to use for the incremental costs of any major storm (in mess of $1 million). The settlement required that we initially establish the fund with $8 million of proceeds received from l
the sale of Clean Air Act emission allowances. As costs are charged against the fund, the balance will be restored to the original level from distribution charges up to a maximum of $3 million per year.
Fu:I and purchased power charge The fuel and purchased power charge ceases as of the retail access date. Net remaining over or under collection of fuel and purchased power cons will be reflected in future customer billings.
Stzndard offer charge l
Customers will have the option of continuing to buy power from our electric delivery business at " Standard Offer" prices as of the retail access date. The Standard Offer charge begins at 2.8 cents at retail access and increases to 5.1 cents by 2004. The cost of provid-ing Standard Offer service, which includes fuel and purchased power costs, will be recovered from Standard Ofrer customers on a fully 9
reconciling basis.
j Distribution and transmission charges l
Distribution rates will be subject to a minimum and maximum return on average common equity (ROE) through December 31,2000.
The ROE is subject to a floor of 6% and a ceiling of 11.75%. If the ROE is below 6%, we are authorized to add a surcharge to distri-i bution rates in order to achieve the 6% floor. If the ROE is above 11%, we are quired to adjwt distribution rates by an amount nec-cssary to reduce the calculated ROE between 11% and 12.5% by 50%, and a wmrn above 12.5% by 100%. No adjustment is made if I
the ROE is between 6% and 11%. In addition, distribution rates will be adjusted for any changes in tax laws or accounting principles that result in a change in our costs of more than $1 million. The cost of providing transmission service to distribution customers will be recovered on a fully reconciling basis.
NucI:ar generation Under the settlement agreement, the annual performance adjustment charge ceases and our cost recovery mechanism for Pilgrim Station changes as of the retail access date. Approximately 25% of the operations and capital costs, including a return on investment, will continue to be collected under wholesale life of the unit contracts. The remaining output will be sold in the competitive energy market. Through December 31,2000, we will share 25% of any profit or loss from the sale of Pilgrim's output with distribution customers through the transi-
)
tion charge. In addition, we will obtain transition payments up to a maximum of $23 million per year depending on the level of costs
{
incurred for property taxes, insurance, regulatory fees and security requirements.
J Nucl:ar decommissioning Approximately 25% of Pilgrim's decommissioning costs will continue to be collected under wholesale life of the unit contracts. The remaining portion will be recovered through the transition charge. Amounts collected for decommissioning will be adjusted as decom-missioning cost studies are updated. Refer to Note E to these Consolidated Financial Statements for more information on nuclear decommissioning costs.
j j
- 2. Divestiture of Fossil Generating Assets l
Included in our settlement agreement is a provision for the divestiture of our fossil generati. g assets. On December 10,1997,we entered into a purchase and sale agreement with Sithe Energies, Inc., a privately-held compa.y headquartered in New York, to purchase our non-nuclear generating assets. The proceeds from the sale of these assets will be $657 million. The net book value of these assets at December 31,1997 is approximately $450 million, included in the purchase price, Sithe Energies will pay $121 million to us in connection with a six-month transitional power sales agreement under which we will continue to buy power from the generating l
plants. Sithe Energies will aho be responsible for obligations resulting from the recently enacted utility restructuring legislation for property tax payments to communities with non-nuclear power plants.
In July 1997, we reached an agreement with our field service union that requires the buyer of our fossil generating assets to rec-l ognize and continue to honor the provisions of the union's current collective bargaining agreemem through the end ofits term May 2000. As part of a package offered to employees affected by the fossil divestiture, all eligible fossil and designated fossil support employees age 55 or older with at least 10 years of service, or age 65 by July 1,1998, were offered unreduced retirement and transi-tion benefits under a voluntary early retirement program (VERP). Under this program,40 people c!ected to retire. Retirement dates are expected to be the first of the month following the transfer of ownership of our fossil generating assets. Severance programs were offered to management and field service union employees afTected by the fossil divestiture that did not elect or were ineligible to retire under the VERP. These severance benefits include salary payments, education / retraining allowances and outplacement services. It is anticipated that 48 employees will receive severance benefits under these programs.
29
The estimated costs associated with the VERP and severance programs is approximately 521 million including the effects on the retirement, life and dental plans. Severance and employee retraining costs related to the divestiture are recoverable through the d bution transition charge under our settlement agreement. Therefore, we have established an offsetting regulatory asset for the ations on our consolidated balance sheet at December 31,1997.
- 3. Nuclear Asset Impairment As part of the settlement agreement, we recover our net investment in Pilgrim Station as of December 31,1995 (adjusted fo tion through 1997) through the distribution transition charge. Under the terms of the settlement agreement, we must perform a ma ket valuation of Pilgrim by 2002. Upon acceptance of the valuation by the DTE, the resulting dollar amount, net of prudently incurred post-1995 investments in the plant, will reduce amounts collectible through the transition charge. If the valuation is not s cient to allow for the recovery of these investments, we will seek their recovery through the transition charge. Due to the market pres-sures facing us, the ultimate recovery of these assets is not certain. Therefore, we reduced our investment in Pilgrim by the 513 m invested in the plant since January 1,1996 as an impairment loss under Statement of Financial Accounting Standards No.121, Accounting for the Impairment oflong-Lived Assets and for Long-Lived Assets to Be Disposed Of(SFAS 121). An after tax charge o approximately $8 million due to this reduction was recorded to non-operatirg expense on our consolidated statement ofincome in fourth quarter of 1997. A similar uncertainty does not exist for the ultimate recovery of the fossil generating assets as the sale proceed agreed to in the purchase and sale agreement with Sithe Energies exceeds the net book value of these assets.
Note D. Income Taxes Income taxes are accounted for in accordance with Statement of Financial Accounting Standards No.109, Accounting for Income Taxes (SFAS 109). SFAS 109 requires the recognition of deferred tax assets and liabilities for the future tax effects of temporary differ-ences between the carrying amounts and the tax basis of assets and liabilities. In accordance with SFAS 109 we recorded net regulatory i
assets of $51.1 million and $47.5 million and corresponding net increases in accumulated deferred income taxes as of December 31, 1997, and December 31,1996, respectively. The regulatory assets represent the additional future revenues to be collected from cus-tomers for deferred income taxes.
Accumulated deferred income taxes consisted of the following:
December 31, (in thousands) 1997 1996 Deferred tax liabilities:
Plant-related S 535,460
$ 532,390 Other 79,930 95,642 615,390 628,032 Deferred tax assets:
Plant-related 11,926 8,406 l
Investment tax ciedits 33,125 38,005 Other 84,601 82,903 129,652 129,314 Net accumulated deferred income taxes
$ 485,738
$ 498,718 No valuation allowances for deferred tax assets are deemed necessary.
Previously deferred investment tax credits are amortized over the estimated lives of the property giving rise to the credits.
30
Components ofincome tax expense were as follows:
years ended December 31, (in thousands) 1997 1996 1995 Current income tax expense
$ 116,685
$ 92,760
$ 93,469 Deferred income tax expense (14,104) 14 (21,115) investment tax credit amortization (7,560)
(4,071)
(4,078)
. income taxes charged to operations 95,021 88,703 68,276 Taxes on other income:
Current (12,566)
(721)
(1,729)
Total income tax expense 82,455
$ 87,982
$ 66,547 The effective income tax rates reflected in the consolidated financial statements and the reasons for their differences from the statutory federal income tax rate were as follows:
1997 1996 1995 Statutory tax rate 35.0%
35.0 %
35.0%
State income tax, net of federal income tax benefit 4.5 4.3 4.3 Investment tax credit amortization (3.3)
(1.8)
(2.3)
Other 0.1 0.7 0.1 Effective tax rate 36.3 %
38.2%
37.1 %
The 1997 effective tax rate declined by 0.8% as a result of the favorable outcome of an Internal Revenue Service appeal related to investment tax credits.
Note E. Nuclear Decommissioning and Nuclear Waste Disposal 1 Nuclear Decommissioning When Pilgrim Station's operating license expires in 2012 we will be required to decommission the plant. Decommissioning means to remove nuclear facilities from service safely and reduce residual radioactivity to a level that permits termination of the Nuclear Regulatory Commission (NRC) license and release of the property for unrestricted use. We record an estimate of decommissioning costs in depreciation expense on the consolidated statements ofincome over Pilgrim's expected service life. Decommissioning expense is approximately $14 million per year. The estimate used to determine our annual expense is based on a 1991 study that documents a cost of approximately $328 million to decommission the plant using the " green field" method, which provides for the plant site to be com-pletely restored to its original state. The cost estimate was incorporated in our 1992 retail settlement agreement. We receive recovery of the annual expense through charges to our retail customers and from other utility companies and municipalities which purchase a con-tracted amount of Pilgrim's electric generation. The funds we collect from decommissioning charges are deposited in an external trust and are restricted to use for decommissioning and related expenses. The net earnings on the trust funds, which are also restricted,
-increase the nuclear decommissioning trust balance, thus reducing the amount to be collected from customers.
l The 1991 decommissioning study was partially updated for internal planning purposes in order to evaluate the potential impae of long-term spent fuel storage options resulting from delays in the United States Department of Energy (DOEJ spent fuel removal pro-gram. Refer to part 2 for a discussion of spent fuel removal. The partial update indicated an estimated decommissioning cost of $400 million in 1991 dollars based upon a revised spent fuel removal schedule and utilization of dry spent fuel storage technology. We are in the process of updating this study. No final cost estimate is currently available; however, we continue to monitor DOE spent fuel removal schedules and developments in spent fuel storage technology along with their impact on the decommissioning estimate.
Cenain financial reporting considerations related to nuclear decommissioning costs have not been fully resolved. In 1996 the i.
Financial Accounting Standards Board (FASB) issued proposed new rules for accounting for liabilities related to closure and removal of long-lived assets, which include decommissioning of nuclear generating facilities. If these proposed rules are adopted we would be required to retroactively recognize the entire estimated liability for decommissioning costs on the balance sheet, offset by an addition to utility plant. The plant addition would be depreciated over Pilgrim's remaining expected service life. The liability would be mea-sured based on the prosent value of estimated future cash flows. The cumulative effect of adoption of these proposed rules could result 1 in the recognition of a regulatory asset to be recovered from customers to the extent that the present value difference in the liability between when the liability was incurred and when the rules are adopted exceeds the depreciation expense previously recognized for decommissioning. In addition, trust fund earnings would be eported on the income statement. The FASil recently resumed its delb
- erations on this project. No date has been set for the issuan c f either a final statement or revised proposed m!<
31
- 2. Spent Nucinr Fusi The verit fuel storage facility at Pilgrim Station is expected to provide storage capacity through approximately 2003. We have a license amendment from the N81C to modify the facility to provide suflicient room for spent nuc! car fuel generated through the end of Pilgrim's operating licere 'n 2012t however, any further modifications are subject to review by the DTE. We are actively exploring the feasibility of other spent a el storage facilities and technologies.
Delays in identifying a permanent storage site have continually postponed plans for the DOE's long-term storage and disposal I
site for spent nuclear fuel. The DOE's current estimate for an available site is 2010. In November 1997, the U.S. Court of Appeals for the District of Columbia Circuit ruled that the lack of an interim storage facility does not excuse the DOE from meeting its con-tract obligation to begin accepting spent nuclear fuel no later than January 31,1998. This decision was in response to petitions filed by us and other interested parties seeking declaratory rulings concerning enforcement and remedies for the DOE's failure to accept j
spent fuel in a timely manner. The court directed the plaintiffs to pursue relief under terms of their contracts with the DOE. Based on this ruling, the DOE may have to pay contract damages ifit does not take the spent nuclear fuel as scheduled. Under the Nuclear Waste Policy Act of 1982, it is the ultimate responsibility of the DOE to permanently dispose of spent nuclear fuel. We currently pay a fee of $1.00 per net megawarthour sold from Pilgrim Station generation under a nuclear fuel disposal contract with the DOE. The fee is collected from customers through fuel charges. We cannot predict at this time whether or on what schedule the DOE will eventually construct a spent fuel repository or what the effect will be of any delays in such construction.
The DOE recently denied our petition to suspend payments made to the Nuclear Waste Fund based on its interpretation of the U.S. Court of Appeal's decision made in November 1997. The DOE has, however, made an offer to consider amendments to exist-ing contracts to address the hardships the anticipated delay in accepting spent fuel may cause individual contract holders. We contin-ue to monitor this situation and consult with legal counsel as to our next course of action.
- 3. Low-Level Radioactive Waste We regained access to low-level radioactive waste (LLW) disposal facilities located in Barnwell, South Carolina, in 1995. This site is currently the only disposal facility available to us. legislation has been enacted in Massachusetts establishing a regulatory process for managing LLW, including the possible siting, licensing and construction of a disposal facility within the state, or, alternatively, an agree-ment with one or more other states. Pending the construction of a disposal facility within the state or the adoption by the state of some other LLW management procedure, we will continue to monitor the situation and investigate other anilable options.
Note E 1995 Corporate Restructuring in 1995 we streamlined the corporate organization and reorganized the company into separate business units in order to strengthen our competitiveness in the changing electric energy market. In conjunction with this reorganization we offered enhanced retirement pro-grams and implemented a special severance program to reduce employee staffmg levels. Under the enhanced retirement programs 330 employees elected to retire, and 149 employees whose positions were eliminated became eligible for benefits under the special severance program. These programs resulted in a $34 million pre-tax charge ($20.7 rnillion after tax) over the third and fourth quarters of 1995.
The charge consisted of $24 million for the retirement programs and $10 million for the severance program.
Note G. Pensions and Other Postretirement Benefits
- 1. P:nsions We have a defmed benefit funded retirement plan with certain contributory features that covers substantially all employees. Benefits are based upon an employee's years of service and highest eligible average compensation during the last ten years of credited employ-ment. Our funding policy is to contribute an amount each year that is not less than the minimum required contribution under federal law or greater than the maximum tax deductible a ount. The retirement plan assets consist of equities, bonds, money market funds, insurance contracts and real estate funds.
We also have an unfunded supplemental retirement plan for certain management employees. Benefits under this plan are based upon an employee's years of service and highest eligible average compensation during years of credited employment.
32
Net pension cost consisted of the following components:
years ended December 31, (in thousands) 1997 1996 1995 Current service cost - benefits earned 5 12,625 13,452
$ 11,339 Int: rest cost on projected benefit obligation 31,537 32,325 31,789 Actual return on plan assets (60,602)
(40,335)
(72,192)
Nst amortization and deferral 33,912 17,064 49,557
.Nat pension cost
$ 17,472 22,506
$ 20,493 In accordance with our 1992 retail rate settlement agreement we deferred the difference between the net pension cost of the retirement plan and its annual funding amount through 1995. Net pension cost recognized in 1995 was $28 million.
We experienced a high number of employee retirements from 1994 to 1996. A large number of these retirements were as a direct 3
I result of our 1995 corporate restructuring. In 1997, a review of the accounting for the pension expense related to the retirements revealed that an adjustment to the pension costs related to these employees was necessary. Therefore, we increased our pension regula-9 tory asset by $8.6 million in 1997 for the adjustment related to the period of our 1992 settlement agreement. The remaining adjust-ment did not have a material impact on our consolidated results of operations or financial position, j
We used the folicwing assumptions for calculating pension cost:
1997 1996 1995 Discount rate 7.75%
7.25%
8.25%
Expscted long-term rate of return on assets 10.00 %
10.00%
10.00 %
Compensation increase rate 3.90%
3.90%
3.90%
The plans' funded status were as follows:
December 31, (in thousands) 1997 1996 Supplemental Supplemental Retirement Retirement Retirement Retirement Plan Plan Plan Plan Acturrial present value of accumulated bennfit obligation:
Wsted
$ 361,484 8,571
$ 316,101 7,576 Non-vested 10,578 1,192 10,867 943 Total
$ 372,062 9,763
$ 326,968 8,519 Plin assets at fair value
$ 401,182 0
$ 331,299 0
Projected obligation for service rendered to date (446,360)
(11,076)
(400,561)
(9,199)
Projected benefit obligation in excess of plan assets (45,178)
(11,076)
(69,262)
(9,199)
Unrecognized prior service cost 9,385 9,736 11,238 9,436 Unrecognized net loss /(gain) 50,673 (27) 78,853 (1,141)
Unrecognized net obligation 5,704 0
7,130 0
Additional minimum liability (a) 0 (8,396) 0 (7,615)
Net pension prepayment /(liability)(b)
$ 20,584
$ (9,763) 27,959
$ (8,519) l (a) Statement of Financial Accounting Standards No. 87, Employers' Accounting for Pensions (SFAS 87), requires the recognition of an additional minimum liability for the excess of accumulated benefits over the fair value of plan assets and accrued pension costs. In accor-dance with SFAS 87 we recorded additional minimum liabilities and corresponding intangible assets of $8.4 million and $7.6 million on i
I our consolidated balance sheets at December 31,1997 and 1996, respectively.
(b) The prepaid pension aunount at December 31,1997 reflects the impact of $8 million related to the fossil workforce reduction as dis-cussed in Note C to these Consolidated Financial Statements.
33
We used the following assumptions for calculating the plans' year-end funded status:
1997 1996 7.25%
7.75 %
Discount rate 4.25%
3.90%
Compensation increase rate We also provide defined contribution 401(k) plans for substantially all of our employees. We match a portion of employees' vol-untary contributions to the plans. We made matching contributions of $8 million in 1997 and 1996 and $9 rnillion in 1995.
- 2. Oth r Postretirement Benefits In addition to pension benefits, we also provide health care and other benefits to our retired employees who meet certain age and years of service eligibility requirements. These postretirement benefits other than pensions (PBOPs) are accounted for in accordance with Statement of Financial Accounting Standards No.106, Employers' Accounting for Postretirement Benefits Other Than Pensions (SFAS 106). Our 1992 retail rate settlement agreement provided us with a phase-in to full expense of the PBOP costs incurred under SFAS 106. This settlement agreement allowed us to defer any costs in excess of the specified phase-in amounts to the extent that we funded an external trust. Our funding policy is to generally contribute 100% of PBOP costs to external trusts. Therefore, we recognized $23 mil-lion of PBOP costs in 1995 in accordance with the 1992 settlement agreement. Beginning in 1996 we recognized the full PBOP costs incurred under SFAS 106. The net deferred PBOP costs of $15 million resulting from the delayed phase-in are included in regulatory assets as thee costs will be recovered from customers in future periods.
Net postretirement benefits cost consisted of the following components:
years ended December 31, (in thousands) 1997 1996 1995 Current service cost - benefits earned 5
3,543 4,616 3,408 Interest cost on accumulated benefit obligation 17,006 16,815 13,521 Actual return on plan assets (18,852)
(9,584)
(7,151)
Amortization of transition obligation 9,151 9,151 9,151 Net other amortization and deferral 12.417 5,209 3,017 Net postretirement benefits cost
$ 23,265 26,207
$ 21,946 We used the following assumptions for calculating postretirement benefits cost:
1997 1996 1995 Discount rate 7.75%
7.25 %
8.25%
Expected long-term rate of return on assets 9.00 %
9.00 %
9.00%
Health care cost trend rate 6.00 %
7.00 %
7.00 %
The health care cost trend rate is assumed to decrease by 1% in 1998 and to remain at 5% in years thereafter. Changes in the heahh care cost trend rate will affect our cost and obligation amounts. A 1% increase in the assumed health care cost trend rate would increase the total service and interest cost components by 7.4% and would increase the accumulated benefit obligation at December 31,1997 by 6.6%.
i 34 l
l
l The PBOP program's funded status was as follows:
December 31, (in thousands) 1997 1996 Trust assets at fair value
$ 103,989
$ 72,702 Accumulated obligation foi service rendered to date from:
Retirees
$ (166,035)
$ (156,694)
Active employees eligible to retire (16,484)
(12,644)
Active employees not eligible to retire (55,097)
(237,616)
(61,567)
(230,905)
Accumulated benefit obligation in excess of trust assets (133,627)
(158,203)
Unrecognin.J prior service cost (14,128)
(16,274)
Unrecognized net loss 12,916 26,663 Unrecognized transition obligation 127,107 146,413 Net postretirement benefits liability (a)
$ (7,732)
$ (1,401)
(a) The postretirement benefits liability at December 31,1997 reflects an 58 million additional PBOP obligation related to the fossil l
workforce reduction as discussed in Note C to these Consolidated Financial Statements.
l l
The weighted average discount rates used to measure the program's year-end funded status were 7.25% in 1997 and 7.75% in 1996. The trust assets consist of equities, bonds and money market funds.
Note H. Stock-Based Compensation in 1997, we initiated a Stock Incentive Plan (the Plan) which was adopted by the Board of Directors and approved by our stockholders.
The Plan permits a variety of stock and stock-based awards, including stock options and deferred (nonvested) stock to be granted to cer-t2in key employees. The Plan limits the terms of awards to ten years. Subject to adjustment for stock-splits and similar events, the i
aggregate number of shares of common stock that may be delivered under the Plan is 2,000,000, including shares issued in lieu of or upon reinvestment of dividends arising from awards. During 1997, we granted 73,820 shares of deferred stock and 298,400 ten-year non-qualified stock options under the Plan. The weighted average grant date fair value of the deferred stock is $27.26. The options were granted at the full market price of the stock on the date of the grant. Both awards vest ratably over a three-year period.
We recognize compensation cost for our stock-based awards under the provisions ofAPB Opinion 25, which requires compensation cost to be measured by the quoted stock market price at the measurement date less the amount, if any, an employee is required to pay.
l l
35
The required fair value method disclosures related to our stock-based compensation are as follows (in thousands, except per share amounts) 1997 Nst income Actual 5 144,642 Pro forma
$ 144,572 Earnings per share Actual 2.71 Pro forma 2.71 Stock option activity of the Plan was as follows:
Options outstanding at January 1,1997 0
Options granted 298,400 Options forfeited (25,400)
Options outstanding at December 31,1997 273,000 Summarized information regarding stock options outstanding at December 31,1997:
Weighted Range of Average Remaining Weighted Average Exercise Prices Contractual Life (Years)
Exercise Price
$25.75-526.00 9.44
$25.84 No stock options were exercisable at December 31,1997.
The stock options were granted with a weighted average grant date fair value of $2.22. The fair value was estimated using the 131ack-Scholes option pricing model with the following weighted average assumptions:
Expected life (years) 4.0 Risk-free interest rate 6.44 %
Volatility 16%
Dividends 7.28%
Compensation cost recognized in income for our stock-based compensation awards in 1997 was $275,000.
1 36
Nota 1. Capital Stock December 31, (dollars in thousands, except per share amounts) 1997 1996 l
Ccmmon stock equity:
Common stock, par value $1 per share, 100,000,000 shares authorized; 48,514,973 and 48,509,537 shares issurd and outstanding:
48,515 48,510 Premium on common stock 696,137 695,723 Retsined earnings 328,802 292,191 Total common stock equity
$ 1,073,454
$ 1,036,424 l
l Dividends declared per share of common stock were $1.88 in 1997 and 1996 and $1.835 in 1995.
Cumulative preferred stock:
' Per value $100 per share,2,890,000 shares authorized; issued and outstanding:
Nonmandatory redeemable series:
Current Shares Redemption l
Series Outstanding Price / Share 4.25%
180,000
$103.625 18,000 18,000 l
4.78 %
250,000
$102.800 25,000 25,000 l
7.75 %
400,000 40,000 40,000 0
40,000 8.25 %
83,000 123,00T~
Less: redemption and issuance costs 0
(3,046)
Total nonmandatory redeemable series 83,000 119,954 Mandatory redeemable series:
Current Shares Redemption Series Outstanding Price / Share i
7.27 %
360,000
$102.420 36,000 40,000 8.00%
500,000 50,000 50,000 1
86,000 90,000 Less: redemption and issuance costs (5,907)
(6,535) due within one year (2,000)
(2,000)
Total mandatory redeemable series 78,093 81,465
- 1. Common Stock Common stock issuances in 1995 through 1997 were as follows:
Number Total Premium on l
(in thousands) of Shares Par Value Common Stock l
Bilance at December 31,1994 45,535 45,535
$ 622,803 1
- Dividend reinvestment plan 468 468 11,404 New issuances 2,000 2,000 49,479 Balance at December 31,1995 48,003 48,003 683,686 i
Dividend reinvestment plan 507 507 12,037 l
Balance at December 31,1996 48,510 48,510 695,723 Dividend reinvestment plan 5
5 414 Balance at December 31,1997 48,515 5
48,515
$ 696,137 37
- 2. Cumulative Mandatory Redeemable Freferred Stock The 360,000 shares of 7.27% sinking fund series cumulative preferred stock are currently redeemable at our option at $102.420. The redempoon price declines annually each hiay to par value in hiay 2002. The stock is subject to a mandatory sinking fund requirement of 20,000 shares each hiay at par plus accrued dividends. We also have the noncumulative option each hiay to redeem additional shares, not to exceed 20,000, through the sinking fund at 5100 per share plus accrued dividends. We redeemed, at par value,40,000 shares in 1997 and 1996 and 20,000 shares in 1995.
We are not able to redeem any part of the 500,000 shares of 8% series cumulative preferred stock prior to December 2001. The entire series is subject to mandatory redemption in December 2001 at 5100 per share plus accrued dividends.
Note J. Indebtedness December 31, (in thousands) 1997 1996 Long-term debt:
Debentures:
5.700%, due March 1997 0
$ 100,000 5.950%, due March 1998 100,000 100,000 6.800%, due February 2000 65,000 65,000 6.050%, due August 2000 100,000 100,000 6.800%, due March 2003 150,000 150,000 7.800%, due May 2010 125,000 125,000 9.875%, due June 2020 100,000 100,000 9.375%, due August 2021 115,000 115,000 8,250%, due September 2022 60,000 60,000 7.800%, due March 2023 200,000 200,000 Total debentm 1,015,000 1,115,000 Less: due within one year (100,000)
(100,000)
Net long-term debentures 915,000 1,015,000 Sewage facility revenue bonds 32,500 34,100 Less: due within one year (667)
(667)
Less: funds held by trustee (4,757)
(4,789)
Net long-term sewage facility revenue bonds 27,076 28,644 Massachusetts industrial Finance Agency bonds:
5.750%, due February 2014 15,000 15,000 6.662% bank loan, due 1999 100,000 0
Total long-term debt
$ 1,057,076
$ 1,058,644 Short-term debt:
Notes payable:
Bank loans 94,013 129,631 Commercial paper 43,000 71,823 Total notes payable
$ 137,013
$ 201,454 1
b
- 1. Long-tsrm Dsbt The 9 7/8% debentures due 2020 are first redeemable in June 2000 at a redemption price of 104.483%, the 9 3/8% series due 2021 are l
first redeemable in August 2001 at 104.612%, the 8.25% series due 2022 are first redeemable in September 2002 at 103.780% and the 7.80% series due 2023 are first redeemable in March 2003 at 103.730%. No other series are redeemable prior to maturity. There is no sinking fund requirement for any series of our debentures.
Sewage facility revenue bonds were issued by HEEC. The bonds are tax-exempt, subject to annual mandatory sinking fund redemption requirements and mature through 2015. In both May 1996 and 1997, we redeemed $1.6 million as scheduled. The weighted average interest rate of the bonds is 7.3%. A portion of the proceeds from the bonds is in reserve with the trustee. If HEEC should have insufficient funds to pay for extraordinary expenses, we would be required to make additional capital contributions or loans to the subsidiary up to a maximum of $1 million.
The 5.75% tax-exempt unsecured bonds due 2014 are redeemable beginning in February 2004 at a redemption price of 102%.
The redemption price decreases to 101% in February 2005 and to par in February 2006.
In March 1997, we obtained $100 million of 6.662% notes in the form of a bank loan. This note matures in 1999.
The aggregate principal amounts of our long-term debt (including HEEC sinking fund requirements) due through 2002 are 5101.6 million in 1998 and 1999, $166.6 million in 2000 and $1.6 million in 2001 and 2002.
- 2. Short-term Debt We have arrangements with certain banks to provide short-term credit on both a committed and an uncommitted and as available basis. We currently have regulatory aethority to issue up to $350 million of short-term debt.
We have a $200 million revolving credit agreement with a group of banks. This agreement is intended to provide a standby source of short-term borrowings. Under the terms of this agreement we are required to maintain a common equiry ratio of not less than 30% at all times. Commitment fees must be paid on the unused portion of the total agreement amount.
Information regarding our utility short-term borrowings, comprised of bank loans and commercial paper, is as follows:
(dollars in thousands) 1997 1996 1995 i
l Maximum short-term borrowings
$ 316,100
$ 272,500
$ 327,769 Weighted average amount outstanding
$ 212,663
$ 208,914
$ 165,720 Weighted average interest rates excluding commitment fees 5.85 %
5.65%
6.21 %
in addition, at December 31,1997, BETG had $7.5 million outstanding under a revolving credit agreement.
l Note K. Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of securities for which it is practicable to estimate the value:
i Nuclear decommissioning trust:
The cost of $151.6 million approximates fair value based on quoted market prices of securities held.
l Cash and cash equivalents:
The carrying amount of $4.1 million approximates fair value due to the short-term nature of these securities.
Mandatory redeemable cumulative preferred stock, sewage facility revenue bonds and unsecuted debt:
The fair values of these securities are based upon the quoted market prices of similar issues. Carrying amounts and fair values as of December 31,1997, are as follows:
Carrying Fair (in thousands)
Amount Value Mandatory redeemable cumulative preferred stock 5
80,093 91,720 Sewage facility revenue bonds 32,500 35,084 Unsecured debt
$ 1,030,000
$ 1,073,982 39 i-
Nots L. Commitm nts and Conting:ncies
- 1. Contractual Commitments At December 31,1997, we had estimated contractual obligations for plant and equipment of approximately $18 million.
We have leases for certain facilities and equipment. Our estimated minimum rental commitments under both transmission agreements and noncancellable leases for the years after 1997 are as follows:
(in thousands) l l
1998 21,938 l
1999 18,958 l
2000 16,738 2001 12,356 2002 11,194 Yurs thereafter 91,874 Total
$ 173,058 Amounts above include $2.7 million which is expected to be assumed by Sithe Energies as part of our pending fossil divestiture discussed in Note C to these Consolidated Financial Statements.
The total of future minimum rental income to be received under noncancellable subleases related to the above leases is $300,921.
We will capitalize a portion of these lease rentals as part of plant expenditures in the future. The total expense for both lease rentals and transmission agreements was $27.5 million in 1997, $26.3 million in 1996 and $24.5 million in 1995, net of capitalized j
expenses of $1.2 million in 1997, $2.9 million in 1996 and $2.7 million in 1995.
l We previously entered into various take or pay and throughput agreements, primarily to supply our New Boston fossil generating l
st2 tion with natural gas. The fixed and determinable portions of the obligations associated with these agreements are $19.5 million in 1998 and 1999 and $14.6 million in 2000. As part of our fossil divestiture agreement, Sithe Energies has agreed to assume these obligations. The total expense under these agreements was $47.1 million in 1997, $49.5 million in 1996 and $13.9 million in 1995.
- 2. Electric Company investments We have an approximately 11% equity investment in two companies which own and operate transmission facilities to import electricity from the Hydro-Quebec system in Canada. As an equity participant we are required to guarantee, in addition to our own share, the total obligations of those participants who do not meet certain credit criteria. At December 31,1997, our portion of these guarantees was $16.6 million.
We have a 9.5% equity investment of approximately $2 million in Yankee Atomic Electric Company (Yankee Atomic). In 1992 the board of directors of Yankee Atomic decided to discontinue operations of the Yankee Atomic nuclear generating station perma-nently and decommission the facility.
l Yankee Atomic received approval from the FERC to continue to collect its investment and decommissioning costs through 2000, the period of the plant's operating license. The estimate of our share of Yankee Atomic's investment and costs of decommissioning is approximately $13 million as of December 31,1997. This estimate is recorded on our consolidated balance sheet as a power contract liability and an offsetting regulatory asset.
We also have a 9.5% equiry investment in Connecticut Yankee Atomic Power Company (CYAPC) of approximately $11 million.
In December 1996, the board of directors of CYAPC, which owns and operates the Connecticut Yankee nuclear electric generating unit (Connecticut Yankee), unanimously voted to retire the unit. The decision was based on an economic analysis of the costs of operating the unit through 2007, the period ofits operating license, compared to the costs of closing the unit and incurring replace-ment power costs for the same period.
The current estimate of the sum of future payments for the closing, decommissioning and recovery of the remaining investment in Connecticut Yankee is approximately $615 million. Our share of these remaining estimated costs is $58 million. This estimate is recorded on our consolidated balance sheet as a power contract liability and an offsetting regulatory asser similar to Yankee Atomic.
In early 1997, CYAPC filed a rate case at the FERC seeking to recover certain post-operating costs, including decommissioning.
The Connecticut Department of Public Utility Control (DPUC) has raised concerns to _the FERC regarding CYAPC's estimate of these costs and the plant operator's prudency prior to the shutdown decision. The FERC set CYAPC's request for hearing before an Administrative Law Judge. The DPUC subsequently filed testimony in the proceeding asserting the position that the FERC should deny recovery of substantial post-operating costs, including a significant amount related to decommissioning and the return on CYAPC's undepreciated investment. We are currently unable to determine the ultimate outcome of this proceeding or its impact.
4o
l 1 Nucinr Insurtnca The federal Price-Anderson Act currently provides $8.9 billion of financial protection for public liability claims and legal costs arising from a single nuclear-related accident. The first $200 million of nuclear liability is covered by commercial insurance. Additional nuclear liability insurance up to $8.7 billion is provided by a retrospective assessment of up to $79.3 million per incident levied on each of the 110 nuclear generating units currently licensed to operate in the United States, with a maximum assessment of $10 million per reactor per accident in any year.
We have purchased insurance from Nuclear Electric Insurance Limited (NEIL) to cover some of the costs to purchase replace-
)
ment power during a prolonged accidental outage and the cost of repair, replacement, decontamination or decommissioning of our utility property resulting from covered incidents at Pilgrim Station. Our maximum potential total assessment for losses which occur during current policy years is $10.4 million under both the replacement power and excess property damage, decontamination and decommissioning policies.
- 4. Hazardous Waste We are an owner or operator of approximately 30 propenies where oil or hazardous materials were spilled or released. As such, we are required to clean up these propenies in accordance with a timetable developed by the Massachusetts Depanment of Environmental Protection. We continue to evaluate the costs associated with site cleanup. There are uncenainties associated with these costs due to the comph.ities of cleanup technology, regulatory requirements and the particular characteristics of the different sites. We also contin-ue to face possible liability as a potentially responsible party in the cleanup of six multi-party hazardous waste sites in Massachusetts and other states where we are alleged to have generated, transported or disposed of hazardous waste at the sites. We are one of many potentially responsible panies and currently expect to have only a small percentage of the potential liability. Through December 31, 1997, we have accrued approximately $7 million related to our cleanup liabilities. We are unable to fully determine a range of reason-ably possible cleanup costs in excess of the accrued amount, although based on our assessments of the specific site circumstances, we do not believe that it is probable that any such additional costs will have a material impact on our financial condition. However, it is rea-sonably possible that additional provisions for cleanup costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term.
- 5. Generating Unit Performance Program Our recovery of the incremental purchased power costs resulting from outages at our generating units occurring through the retail access date is subject to review by the DTE. We are unable to fully determine a range of reasonably possible disallowance costs in excess of amounts accrued, although, based on the information currently available, we do not believe that it is probable that any such additional costs will have a material impact on our financial condition. However, it is reasonably possible that additional disallowance costs that may result from a change in estimates could have a material impact on the results of a reponing period in the near term.
- 6. Litigation In October 1997, the DTE operwd a proceeding to investigate our compliance with the 1993 order which permitted the formation of BETG and authorized us to invest up to $45 million in unregulated activities. We are unable to determine the ultimate outcome of this proceeding or its impact on our operations.
In the normal course of our business we are involved in certain other legal matters. We are unable to fully determine a range of reasonably possible litigation costs in excess of amounts accrued, although, based on the information currently available, we do not believe that it is probable that any such additional costs will have a material impact on our financial condition. However, it is reason-ably possible that additional litigation costs that may result from a change in estimates could have a material impact on the results of I
a reporting period in the near term.
- 7. Industry Restructuring Legal Proceedings / Referendum Campaign The DTE order approving our settlement agreement has been appealed by certain panies to the Massachusetts Supreme Judicial Court.
In addition, along with other Massachusetts investor owned utilities, we have been named as a defendant in a class action suit seeking to declare cenain provisions of the Massachusetts electric industry restructuring legislation unconstitutional. We are currently unable to determine the outcome of these proceedings or their impact on us.
j Opponents of the electric industry restructuring legislation that was enacted in November 1997 have mounted a referendum campaign to repeal that law. A coalition of business, industry and public interest groups that supported the legislation, along with the electric utility industry, is opposed to the referendum and is prepared to mount an aggressive campaign to defeat it. We are cur-rently unable to predict the eventual outcome of this referendum or its impact on us.
I 41
Nots M. Long-Tsrm Powar Contracts
- 1. Long-Term Contracts for the Purchase of Electricity We purchase electric power under several long-term contracts for which we pay a share of a generating unit's capital and fixed cperating costs through the contract expiration date. The total cost of these contracts is included in purchased power expense on our consolidated income statements. Information relating to these contracts as of December 31,1997, is as follows:
proportionate share (in thousands)
Units of Debt Contract Capacity Minimum Outstanding Expiration Purchased (a)
Debt Through Cont.
Annual Generating Unit Date MW 5ervice Exp. Date Cost Canal Unit 1 2002 25.0 141
$ 1,475 5 5,172
$ 28,997 Mass. Bay Transportation Authority - 1 2005 100.0 34 2,166 Ocean State Power - Unit 1 2010 23.5 72 4,256 17,962 21,778 Ocean State Power - Unit 2 2011 23.5 72 3,592 15,951 23,969 Northeast Energy Associates (b)
(b) 219 134,023
. L'Energia (c) 2013 73.0 63 21,902 MassPower 2013 44.3 117 11,227 70,660 54,215 p
Mass. Bay Transportation Authority - 2 2019 100.0 34 577
/
Total 752
$ 20,550
$109,745
$ 287,627 i!
L (a) The Northeast Energy Associates contract represents 6.5% of our total system generation capability. The remaining units listed above represent approximately 16% in total.
(b) We purchase 75.5% of the energy output of this unit under two contracts. One contract represents 135MW and expires in the year 2015. The other contract is for 84MW and expires in 2010. We pay for this energy based on a price per kWh actually received.
We do not pay a proportionate share of the unit's capital and fixed operating costs.
(c) We pay for this energy based on a price per kWh actually received.
f j
Our total fixed and variable costs associated with these contracts in 1997,1996 and 1995 were approximately $288 million, $281 j
million and $262 million, respectively. Our minimum fixed payments under these contracts for the years after 1997 are as follows:
i (in thousands) 1998 88,406 1999 88,501 2000 89,853 2001 90,365 2002 92,768 Years thereafter 959,981 Total
$ 1,409,874 Total present value
$ 783,975 Under our settlement agreement, by July 1998 we are required to file a plan with the DTE describing the actions we intend to take to sell, assign or otherwise dispose of our purchased power contracts.
42
l
- 2. Long-Tarm Powxr Silas Contracts
+
! In addition to other wholesale power sales, we sell a percentage of Pilgrim Station's output to other utilities and municipalities under long-term contracts. Information relating to these contracts is as follows:
Contract Expiration Units of Capacity Sold 3
Contract Customer Date MW Commonwealth Electric Company 2012 11.0 73.7 Montaup Electric Company 2012 11.0 73.7 Various municipalities 2000 (a) 3.7 25.0 Total 25.7 172.4 i.
(a) Subject to certain adjustments.
Under these contracts, the utilities and municipalities pay their proportionate share of the costs of operating Pilgrim Station and associated transmission facilities. These costs include operation and maintenance expenses, insurance, local taxes, depreciation, decom-i missioning and a return on investment.
h
. Rrport ofIndependent Accountants To the Stockholders and Directors of Boston Edison Company
. We have audited the accompanying consolidated balance sheets et Boston Edison Company and subsidiaries (the Company) as of l-
' December 31,1997 and 1996, and the related consolidated statements ofincome, retained 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 pen-form 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 l
assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial state-
- ment presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of
- the Company as of December 31,1997 and 1996, and the consolidated results ofits operations and its cash flows for each of the three years in the period ended December 31,1997, in conformity with nerally accepted accounting principles.
Boston, Massachusetts January 22,1998 l
i 43
Szlictsd Consolidated Qutrtarly Fin ncitl D:ta (Unauditad)
(in thousands, except earnings per share)
Earnings Available Earnings Operating Operating Net for Common Per Average Revenues Income income Shareholders Common Share (a)
T997 First quarter
$ 422,725
$ 47,589
$ 20,935
$ 17,118
$ 0.35 Second quarter 426,735 60,487 33,978 30,484 0.63 Third quarter 519,513 108,060 81,418 78,499 1.62 Fourth quarter 407,260 44,714 8,311 5,392 0.11
'1996 First quarter.
$ 387,849
$ 52,093
$ 25,203
$ 21,313
$ 0.44
- Second quarter 389,756 55,232 27,926 24,086 0.50 Third quarter 497,968 105,353 80,011 76,194 1.58 Fourth quarter 390,730 35,252 8,406 4,588 0.09 l
(a) Based on the weighted average number of common shares outstanding during each quarter.
l S11:cted Quarterly Common Stock Data (Unaudited)
The reported high and low market value per shart of our common stock as report d in the MllStnet/ournaland the dividends declared per share for each of the quarters in 1997 and 1996 was as follows:
l 1997 1996 I
l High Low Dividends High Low Dividends First quarter
$27 3/8 26
$0.470
$301/8
$261/4
$0.470 Second quarter 26 5/8 24 5/8 0.470 27 1/8 23 5/8 0.470 Third quarter 30 7/8 26 1/2 0.470 25 3/8 21 3/4 0.470 Fourth quarter 38 3/8 30 1/4 0.470 27 21 3/4 0.470 i
l l
1 1
u
S:l:cted Ccnsalidstzd Opsrating St:tistics (Unauditsd)
)
1997 1996 1995 1994 1993 Capacity - MW:
i Pilgrim Station 670 670 669 669 670 i
New Boston Station 760 730 760 760 760 Mystic Station 994 994 1,005 1,006 1,006 W.F. Wyman Unit 4 37 37 36 36 36 Jet turbines 276 278 284 287 283 Total (a) 2,737 2,709 2,754 2,758 2,755 Contract purchases 941 1,237 1,274 1,035 938 Contract sales (281)
(333)
(340)
(373)
(283)
Net capability at year-end 3,397 3,613 3,688 3,420 3,410 Net capability at peak - MW 3,444 3,385 3,466 2,484 3,663 Capability responsibility to NEPOOL at peak - MW 3,312 3,256 3,306 3,306 3,190 Company territory:
Hourly peak - MW 2,835 2,703 2,785 2,798 2,662 Load factor 61.0 %
63.4 %
60.0 %
58.9 %
60.5 %
Capability (net kW):
Fossil 85 %
86 %
85 %
84 %
84 %
Nuclear 15 %
14 %
15 %
16 %
16 %
Generation (system kWh excluding interchange):
Fossil 80 % '
69 %
73 %
75 %
68 %
Nuclear -
20 %
31 %
27 %
25 %
32 %
' Utility plant ($ in 000's):
l Expenditures
$ 114,110 '
$ 145,347
$ 180,822
$ 198,771
$ 246,774 Retirements 21,449 68,688 48,111 45,673 34,147
- Accumulated depreciation.
1,713,079 1,550,317 1,439,996 1,344,452 1,258,359 Depreciable plant 4,375,391 4,317,028 4,235,347 3,994,212 3,841,752 Number of utility employees at year-end 3,227 3,362 3,812 4,026 4,397 (a) Based upon winter capability audit results.
I 45
S:Isct:d Consolid:t:d S:I:s Statistics (Unaudit:d) 1997-1996 1995 1994 1993 Electric energy (kWh in thousands):
Sources (system output):
Generated 11,686,810 10,531,745 10,537,114 9,428,931 9,787,092 Purchased 6,014,208 5,680,194 5,446,542 5,920,065 5,326,224 New England Power Pool 887,250 1,842,732 1,513,467 1,535,335 1,575,310 Total 18,588,268 18,054,671 17,497,123 16,884,331 16,688,626 Disposition:
Commercial 7,991,349 7,821,371 7,454,684 7,478,631 7,263,358 Residential 3,566,405 3,549,899 3,563,626 3,534,372 3,477,870 Industrial 1,467,600 1,547,630 1,538,218 1,539,385 1,580,969 I
Other (a) 131,187 130,678 131,626 130,721 145,242 Total retail sales 13,156,541 13,049,578 12,688,154 12,683,109 12,467,439 I
Wholesale and contract sales (a) 2,674,283 3,127,087 2,805,777 2,367,589 2,272,669 New England Power Pool 1,610,860 741,390 884,336 725,439 877,978
' Total system 17,441,684 16,918,055 16,378,267 15,776,137 15,618,086 Miscellaneous usage 1,146,584 1,136,616 1,118,856 1,108,194 1,070,540 Total 18.588,268 18,054,671 17,497,123 16,884,331 16,688,626 Kilowatthour sales - annual growth:
Commercial 2.2 %
4.9 %
(0.3)%
3.0 %
1.2 %
Residential 0.5 (0.4) 0.8 1.6 1.9 Industrial (5.2) 0.6 (0.1)
(2.6)
(5.4)
Cther 0.4 (0.7) 0.7 (10.0)
(50.3)
Total retail sales (a) 0.8 2.8 1.7 (0.7)
Wholesale and contract sales (14.5) 11.5 18.5 4.2 (9.7)
New England Power Pool 117.3 (16.2) 21.9 (17.4)
(53.7)
Total system 3.1 %
3.3 %
3.8 %
1.0 %
(8.0)%
Electric operating revenues by class:
Commercial 51 %
50 %
50 %
50 %
49 %
Residential 27 %
27 %
28 %
28 %
28 %
Industrial 9%
9%
9%
9%
10 %
Other 1%
2%
2%
2%
1%
Wholesale and contiact 12 %
12 %
11 %
11 %
12 %
Average number of customers 662,354 657,487 653,757 655,707 651,141 (a) EfTective in both November 1995 and February 1993, a former retail customer became a wholesale customer as allowed under Massachusetts state law.
i 46
S&ct:d Cens: lid:t:d Fin:nci:I St:tistics (Un:udited) 1 1997 1996 1995 1994 1993 Operating revenues (000)
$ 1,776,233
$ 1,666,303
$ 1,628,503
$ 1,544,735
$ 1,482,159 l Earnings available for common (000) 131,493
$ 126,181 96,739 (a) 109,257 102,513 Per common share:
Earnings 2.71 2.61 2.08 (a) 2.41 2.28 Dividends declared 1.880 1.880 1.835 1.775 1.715 Dividends pcid 1.88 1.88 5
1.82 1.76 1.70 Book value 22.13 21.37 20.61 20.11 19.42 Payout ratio 69 %
72 %
88 %(a) 73 %
75 %
Return on average common equity 12.4 %
12.4 %
10.0 %(a) 12.1 %
11.9 %
Year-end dividend yield 5.0 %
7.0 %
6.4 %
7.6 %
5.9 %
Fixed charge coverage (SEC) 2.95 2.91 2.38 2.46 2.22 Capitalization:
Total debt 51 %
52 %
54 %
56 %
57 %
Preferred equity 7%
8%
8%
9%
9%
Common equity 42 %
40 %
38 %
35 %
34 %
Long-term debt (000)
$ 1,057,076
$ 1,058,644
$ 1,160,223
$ 1,136,617
$ 1,272,497 Mandatory redeemable preferred stock (000) 80,093 83,465 5
86,837 88,837 90,837 Total assets (000)
$ 3,622,347
$ 3,729,291
$ 3,637,170
$ 3,608,699
$ 3,468,724 Internal generation after dividends (000)
$ 240,362
$ 257,446
$ 184,492
$ 217,030 194,209 Plant expenditures (000) 114,110
$ 145,347
$ 180,822 198,771
$ 246,774 Internal generation 211 %
177 %
102 %
109 %
79 %
Commen shares outstanding:
Weighted average 48,514,958 48,264,734 46,591,662 45,337,661 44,959,050 Year-end 48,514,973 48,509,537 48,003,178 45,535,477 45,129,227 Stock price:
High 38 3/8 30 1/8 29 1/2 29 7/8 32 5/8 Low 24 5/8 21 3/4 23 1/8 21 1/2 26 3/8 Year-end 37 7/8 26 7/8 29 1/2 24 29 3/4 Year-end market value (000)
$ 1,R37,505
$ 1,303,694 5 1,416,094
$ 1,092,851
$ 1,342,595 Trading volume (shares) 37,732,900 41,105,700 23,078,900 25,095,100 18,729,400 Market / book ratio (year-end) 1.71 1.26 1.43 1.19 1.53 Price / earnings ratio (year-end) 14.0 10.3 14.2 (a) 10.0 13.0 (a) Amounts exduding $34 million pre-tax restructuring charge:
l Earnings available for common (000) 117,403 1
Earnings 2.52 Payout ratio 72 %
Return on average common equity 12.2 %
i Price / earnings ratio 11.7 %
Certain reclassifications and recalculations were made to the data reported in prior years to conform with the method of presentation used in 1997.
47
Offic:rs Dir:ctors I
Thomas J. May, Chairman of the Board, President and Chief a,d Gary L. Countryman, Chairman of the Board and Chief Executive OGcer Executive OGcer, Liberty Mutual Insurance Company Thomas G. Dignan, Jr., Partner, Ropes & Gray Ronald A. Ledgett, Executive Vice President a,e Alison Alden, Senior Vice President - Sales, Services and Human Resources d,e Richard J. Egan, Chairman of the Board, EMC Corporation (smrage-related computer system products)
L Carl Gustin, Senior Vice President - Corporate Relations b,c d Charles K. Gi%rd, Chairman and Chief Executive Douglas S. Horan, Sem.or Vice President - Strategy and Law OGcer, BankBoston Corporation and General Counsel (bank holding company) and BankBoston, N.A.
~
James J. Judge, Senior Vice President - Corporate Services and a,b Nelson S. Gihrd, Principal, Fleetwing Capital (venture investments)
William N. Dimoulas, Vice President - Information ve Vice Pres. dent, Teachers a,b,c Matma S. Horner, Execuu.
i Technology Insurance and Annuity Association and College Philippe A. Frangules, Vice President - Strategic Planning and Retirement Eqtiiries Fund Business Development a,c Thomas J. May, Chairman of the Board, President and Richard S. Hahn, Vice President - Technology Chief Executive O$cer, Boston Edison Company Leon J. Olivier, Vice President - Nuclear Operations and b,d Sherry H. Penney, Chancellor, University of Station Director Massachusetts at Boston David M. Samuel, Vice President - Customer Care h.e Herbert Rudi, Jr., Turm r Chairman of the Board and Chief Executive OGcer, LFE Corporation (tramc and Robert J. Weafer, Jr., Vice President - Finance, Controller and industrial process control systems)
Chief Accounting OGcer b,e Stephen J. Sweeney, Former Chairman of the Board, Theodora S. Convisser, Clerk of the Corporation President and Chief Executive Officer, Boston Edison Donald Anastasia, Assistant Trcasurer Company a
Member of Executive Committee b
Member ofAudit, Finance and Risk Management Committee Member of Pricing Committee c
d Member of Execuuve Personnel Committee Member of Nuclear Oversight Committee e
48
Important Shareholder Information Automatic Monthly investment Program Shareholder Inquiries Shareholders who are participams in the Dividend Reinvestment and Common Stock Purchase Plan may now if you have questions concerning your dividend payments, the Dividend Rein"estment and Common Stock Purchase PLm, direct rnake automatic monthly invegments of a speci6ed amount deposit service, transfer procedures or other stock account matters, (not less than 550 per nionth) through an Automated Clearing please contact our stock transfer agent at the following address:
Ilouse ("ACH") withdrawal from their savings or checking t
l Boston IhuiServe account. Once automatic monthly deductions are initiated.
Shareholder Services Division funds will be drawn from your designated bank account on the 25th of each month and will be invested in common stock on P.O. Box 8040 the neu investment date. For more information on the Boston, MA 02266-8040 Automatic Monthly Investment Pmgram, or an enrollment Toll Free Phone: 1-800-338-8446 form, wntact our stock transfer agent.
~ lecommunication Device for the Deaf fl vu; c
3 800 952-9245.
S fekeeping Program Dividend Payment Dates Shareholders who are participants in the Dividend Reinvestment and Common Stock Purchase Plan can transfer their common Common and Preferred stock certiGcates into their plan account for safekeeping.
1st of February, May, August and November Dividends on those shares will be reinvested automatically like Tax Status of 1997 D..dends any other shares heki in the plan. 'lo contmue recewmg cash ivi dividends, you must hold your shares in certi6cate form. Iur Generally, unless you are subject to certain exemptions, all divi-additional information, contact our stock transfer agent.
dends on our common or preferred stock are to be considered 100% taxable.
SEC Form 10-K Stock Symbol and Exchange Listings Stockhoklers may obtain a copy of our annual report to the Secun..nes and Exchange Comnu.ssmn on Form 10-K, by con-Tkker Symboh BSE tacting our Investor Relations Department.
New York (NYSE) and Boston stock exchanges Quarterly Report to Shareholders 1998 Annual Shareholders Meeting Bene 6ctal owners of our stock w hose shares are registered m.
All sharehokiers are invited to attend our Annual Meeting on names other than their own may obtain copies of our Quarterly Tuesday, May 5,1998, at 11:00 A.M. at the Boston Back Bay Reports to Shareholders by contacting our Investor Relations Hihon, Second Floor, Belvidere Ballroom,40 Dahon Street, Department. Note that the Annual Report will continue to be Boston, Massachusetts.
mailed to benefkial owners directly by their bank or broker.
Dividend Payments - Direct Deposit Service investor & Shareholder Contacts Shareholders receiving dividend checks can arrange for electron-Philip J. I embo direct deposit. Transfers are made on the dividend payment Director, investor Relations u :es and conGrmation statements are mailed to shareholders.
(617) 424-3562 To take advantage of this convenient program, contact our or stock transfer agent as noted above.
Jean M. Carella Dividend Reinvestment and Common Stock I"""" ' N'Ii""' S C'I'II*'
P Purchase Plan (617) 424-2658 Our Dividend Reinvestment and Common Smck Purchase Plan Email Address (the plan) is available to our common and preferred shareholders, irFbedison.com our residential electric customers and employees. Participants do not pay brokerage fees or wmmissions related to the purchase of Internet Address wes. Some important features of the plan are as follows www.bostonedison.com Optional cash payments invested monthly
- $50 per month minimum not to exceed $40,000 Company Contact per calendar year Theodora S. Convisser
- Safekeeping of common stock certi6 cates Clerk of the Co coration BeneGcial owners of our stock whose shares are registered in General Offices names other than their own (e.g., a broker or bank nominee) must arrange participation with the record holder. If for any 800 Boylston Street reason you are unable to arrange participation with your broker Boston, M A 02199-8003 or bank nominee, you must become a record holder by having (617) 424-2000 the shares transferred to your own name.
& Boston Edison 800 Boylston Street Boston, Massachusetts 02199-8003
- - - - - ~ _ _ _
Wcshingt:n, D.C. 20549 FORM 10-K j
S$)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
'1934 Fer the fiscal year ended December 31,1997 i
OR l
]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number 1-2301 BOSTON EDISON COMPANY (Exact name of registrant as specified in its charter)
Massachusetts 04-1278810 (State or otherjurisdiction of (1.R.S. Employer incorporation or organization)
Identification No.)
100 Boylston Street. Boston. Massachusetts 02199 (Address of principal executive offices)
(Zip Code) agistrant's telephone number, including area code: 617-424 2000 ocurities registered pursuant to Section 12(b) of the Act:
Name of each exchange
/
Title of each class on which registered Ccmmon stock, par value $1 per sharc New York Stock Exchange Boston Stock Exchange Cumulative preferred stock:
7.75% Series, par value $100 per share New York Stock Exchange (represented by depositary sharcs cach represents one-fourth interest in par value) curities registered pursuant to Section 12(g) of the Act: None 9cate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities 3hange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and D has been subject to such filing requirements for the past 90 days. YES X.' NO,_
dicate by check mark if disclosure of delinquent filers pursuant to item 405 of Regulation S-K is not contained herein, and will not 3 contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part 111 of this mn 10-K or any amendment to this Form 10-K. [X]
b r>ggregate market value of the voting stock held by non-affiliates of the registrant as of March 24,1998 computed as the average of the.
sh and low market price of the common stock as reported in the listing of composite transactions for New York Stock Exchange listed curities in the Wall Street Journal: $2,019,435,751.
dicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.
Class Outstanding at March 24.1998 Common Stock, $1 par value 48,514,973 shares DOCUMENTS INCORPORATED BY REFERENCE 111 Document El Portions of definitive proxy statement dated March 31,1998 for Annual Meeting of Stockholders to be held May 5,1998, i
Boston Edison Company Form 10-K Annual Report December 31, 1997 Part I Page Item 1.
Business 2
Item 2.
Properties and Power Supply 6
Item 3.
Legal Proceedings 8
Item 4.
Submission of Matters to a Vote of Security Holders 8
Part II i
Item 5.
Market for the Registrant's Common Stock and Related Stockholder Matters 11 Item 6.
Selected Financial Data 12 item 7.
Management's Discussion and Analysis 13 Item 8.
Financial Statements and Supplementary Financial Information 24 Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 51 Part III Item 10.
Directors and Executive Officers of the Registrant 52 Item 11.
Executive Compensation 52 Item 12.
Security ownership of Certain Beneficial owners and Management 53 Item 13.
Certain Relationships and Related Transactions 53 Part IV Item 14.
Exhibits, Financial Statement Schedules and Reports on Fo rm 8-K 54 1
l e
e Part I 1
Item 1.
Business (a) General Development of Business Boston Edison Company (the Company) is an investor-owned regulated public utility incorporated in 1886 under Massachusetts law.
The Company operates in the energy, energy services and telecommunications business, which includes the generation, purchase, transmission, distribution and sale of electric energy and the development and implementation of electric demand side l
management programs.
Refer to the Electric Utility Industry Restructuring section of Item 7 for information regarding the restructuring of the electric utility industry and its impact on the Company.
The Company also conducts unregulated activities through its wholly owned subsidiary, Boston Energy Technology Group (BETG). Through BETG and its subsidiaries, the Company is engaged in certain nonutility businesses, including energy utilization and conservation, construction management and district energy.
Refer to Note A to the Consolidated Financial Statements in Item 8 for more information regarding the Company's nonutility business ventures.
The Company is currently awaiting a decision from the Massachusetts Department of Telecommunications and Energy (DTE), formerly the Department of Public Utilities, and the Securities and Exchange Commission regarding its reorganization plan to form a holding company structure. This plan has been e
approved by the Federal Energy Regulatory Commission (FERC), the Nuclear Regulatory Commission (NRC) and the Company'4 shareholders.
Refer to Note A to the Consolidated Financial Statements in Item 8 for more information regarding the holding company structure.
(b) Financial Information about Industry Segments The Company operates primarily as a regulated electric public utility, therefore industry segment information is not applicable.
(c) Narrative Description of Business Principal Products and Services The Company supplies electricity at retail to an area of 590 square miles, including the city of Boston and 39 surrounding cities and towns.
The population of the area served with electricity at retail is approximately 1.5 million.
In 1997 the Company served an average of approximately 660,000 customers. The Company also supplies electricity at wholesale for resale to other utilities and municipal electric departments.
Electric operating revenues by class for the last three years consisted of the following:
1997 1996 1995 Retail electric revenues:
Commercial 51%
50%
50%
Residential 27%
27%
28%
Industrial 9%
9%
9%
Other 1%
24 24 Wholesale and contract revenues 124 124 114 l
l l
2
Sources and Availability of Fuel The Company currently owns two stations whose generating units have the ability to burn oil, natural gas or both, one nuclear power station and ten combustion turbine generators. As discussed in Item 2, tho Company entered into an agreement to sell its non-nuclear generating assets in 1997.
Finalization of the sale is expected in mid-1998.
The Company's generation by type of fuel and the cost of fuel for each of the last five years were as follows:
Percentage of Company Average Cost of Fuel Generation by Source (%)
($ per Million BTU) 1997 1996 1995 1994 1993 1997 1996 1995 1994 1993 Oil 32.0 16.1 17.5 27.8 31.3 2.22 3.04 2.66 2.35 2.38 Gas 31.1 33.3 39.9 31.6 24.3 3.23 3.11 2.17 2.28 2.67 Nuclear 36.9 50.6 42.6 40.6 44.4 0.46 0.41 0.43 0.50 0.51 The majority of the Company's residual oil purchases consists of imported oil acquired primarily from international suppliers. Through March 1997, the Company had a contract with a major oil company to supply most of its estimated requirements.
The Company has been purchasing oil on the spot narket since that contract expired.
A portion of the Company's natural gas is supplied on an interruptible basis by contract. These contracts permit interruptions in deliveries by the supplier when natural gas supplies or pipeline capacity is unavailable. The Company 3, currently required to fuel New Boston Station exclusively by natural gas, except in certain emergency circumstances, as part of a 1991 consent order with the Massachusetts Department of Environmental Protection.
The Company has arrangements for a firm supply of natural gas to run the station at a minimum level and has a least-cout plan for operating beyond this ndnimum level which principally utilizes interruptible gas supplies or short-term capacity purchases.
In order to obtain fuel for use at its nuclear generating unit, the Company must obtain supplies of uranium concentrates and secure contracts for these concentrates to go through the processes of conversion, enrichment and fabrication of nuclear fuel assemblies. The Company currently has contracts l
for supplies of uranium concentrates and the processes of conversion, enrichment and fabrication through 2002, 2000, 2004 and 2012, respectively.
Franchises l
l Through its charter, which is unlimited in time, the Company has the right to engage in the business of producing and selling electricity, steam and other forms of energy, has powers incidental thereto and is entitled to all the rights and privileges of and subject to the duties imposed upon electric l
companies under Massachusetts laws. The locations in public ways for the l
Company's electric transudssion and distribution lines are obtained from municipal and other state authorities which, in granting these locations, act l
as agents for the state.
In some cases the action of these authorities is subject to appeal to the DTE.
The rights to these locations are not limited in time, but are not vested and are subject to the action of these authorities and the legislature.
Pursuant to the Massachusetts electric utility industry restructuring legislation enacted in November 1997, the DTE has defined the service territory of the Company based on the territory actually served on July 1, 1997, and following, to the extent possible, municipal boundaries.
The legislation further provided that, until terminnted by effect of law or 3
otherwise, the Company shall hava the exclusive obligation to provide distribution service to all retail customers within such service territory.
No other entity shall provide distribution service within this territory without the written consent of the Company which consent must be filed with the DTE and the municipality so affected.
Seasonal Nature of Business The Company's kilowatt-hour (kWh) sales and revenues are typically higher in the winter and summer than in the spring and fall as sales tend to vary with weather conditions.
In addition, the Company bills higher base rates to commercial and industrial customers during the billing months of June through September as authorized by the DTE.
Accordingly, greater than half of the company's annual earnings typically occurs in the third quarter.
Refer to the Selected consolidated Quarterly Financial Data (Unaudited) in Item 8.
Competitive conditions Refer ~to the Electric Utility Industry Restructuring section of Item 7 for a discussion of the competitive conditions affecting the Company.
Environmental Matters
~The Company is subject to numerous federal, state and local standards with respect to the management of wastes, air and water quality and other environmental considerations. These standards could require modification of existing facilities or curtailment or termination of operations at these facilities. They could also potentially delay or discontinue construction of new facilities and increase capital and operating costs by substantial amounts. Noncompliance with certain standards can, in some cases, also result in the imposition of monetary civil penalties.
Environmental-related capital expenditures for the years 1997 and 1996 were
$1.4 million and $2.7 million, respectively.
These expenditures are forecasted to be approximately $2 million in each of the years 1998 and 1999.
The Company believes that its operating facilities are in substantial compliance with currently applicable statutory and regulatory environmental requirements. Additional expenditures could be required as changes in environmental requirements occur.
Refer to the Environmental section of Item 7 for more information.
Number of Employees As of March 21, 1998, the Company had 3,196 full-time and 33 part-time utility employees including 2,166 represented by two locals of the Utility Workers Union of America, AFL-CIO.- The locals' labor contracts are effective through May of the year 2000. Wholly owned subsidiary operations had 27 full-time employees.
Employee relations are considered satisfactory by the company.
Refer to the Divestiture of Fossil Generating Assets section of Item 7 for information regarding employees affected by the sale of these assets.
(d) Financial Information about Foreign and Domestic Operations and Export Sales Refer to Principal Products and Services of this item for infonnation regarding the geographical area served by the Company and revenues by class for the last three years.
4
i (e) Additional Information Regulation The Company and its whelly owned subsidiary, Harbor Electric Energy Company (HEEC), operate primarily under the authority of the DTE, whose jurisdiction includes supervision over retail rates for electricity and financing and investing activities.
In addition, the FERC has jurisdiction over various phases of the Company's business including rates for Fawer sold at wholesale i
for resale, facilities used for the transmission or sale of that power, certain issuances of short-term debt and regulation of the system of accounts.
The Company's subsidiary BETG and its subsidiaries are not subject to such regulation.
The NRC has broad jurisdiction over the siting, construction and operation of l
nuclear reactors with respect to public health and safety, environmental i
matters and antitrust considerations. A license granted by the NRC may be revoked, suspended or modified for failure to construct or operate a facility l
in accordance with its terms. The Company currently holds an operating license for Pilgrim Station which expires in 2012.
Continuing NRC review of-existing regulations and certain operating occurrences at other nuclear plants have periodically resulted in the imposition of additional requirements for all nuclear plants in the United States, including Pilgrim Station.
NRC inspections and investigations can result in the issuance of notices of violation. These notices can also be accompanied by orders directing that certain actions be taken or by the imposition of monetary civil penalties.
In addition, the Company could undertake certain actions regarding Pilgrim
)
Station at the request or suggestion of its insurers or the Institute of Nuclear Power Operations,
- p. voluntary association of nuclear utilities dedicated to the promotion of safety and reliability in the operation of nuclear power plants. Nuclear power continues to be a subject of political controversy and public debate manifested from time to time in the form of requests Co; various kinds of federal, state and local legislative or regulators action, direct voter initiatives or referenda or litigation.
The Company evnnot predict the extent, cost or timing of any modifications to Pilgrim Station which could be necessary in the future as a result of additional regulatory or other requirements, nor can it determine the effect I
e t such futura requirements on the continued operation of Pilgrim Station.
The Company continuously evaluates the operation of the station from the standpoint of safety, reliability and econondes.
i 5
capital Expenditure and Financings The Company's most recent estimates of capital expenditures (excluding nuclear fuel), allowance for funds used during construction (AFUDC), long-term debt maturities and mandatory sinking fund requirements for the years 1998 through 2002 are as follows:
lin thousands) 1998 1999 2000 2001 2002 Capital expenditures (1) $265,000
$230,000
$185,000
$140,000
$120,000 AFUDC
$ 1,500
$ 1,500
$ 1,500 1,500 1,500 Long-term debt
$101,600
$101,600
$166,600 1,600 1,600 Preferred stock sinkino fund (2) $ 2,000 2,000 2,000
$ 52,000 2,000 (1)
Includes nonutility ventures.
(2)
Excludes option to redeem up to $2,000 of additional shares of 7.274 series cumulative preferred stock each May; the Company will redeem
$4,000 of this series on May 1, 1998.
The Company continuously reviews its capital expenditure and financing programs. These programs and, therefore, the estimates included in this Form 10-K are subject to revision due to changes in regulatory requirements, environmental standards, availability and cost of capital, interest rates and other assumptions.
Utility plant expenditures in 1997 were $114 million and consisted primarily of additions to the Company's transmission and distribution systems.
Refer to the Liquidity section of Item 7 for more information regarding the Company's capital resources.
Item 2.
Properties and Power Supply The Company's total electric generation capacity from Company-owned facilities consisted of the following:
Year Unit Location Capacity
- Type Installed Pilgrim Nuclear Plymouth, Mass.
670 Nuclear 1972 Power Station New Boston Station South Boston, Mass.
760 Fossil 1965-1967 Units 1 and 2 Mystic Station Everett, Mass.
Units 4-5-6 388 Fossil 1957-1961 Unit 7 592 Fossil 1975 Combustion turbine 14 Fossil 1969 generator Combustion turbine Various 276 Fossil 1966-1971 cenerators (nine)
(a)
In megawatts (Kd) based on winter capability audit results.
6
4 l
The Company also owns approximately 6% of W.F. Wyman Unit 4.
The 619 MW oil-fired unit located in Yarmouth, Maine, began operations in 1978 and is I
operated by Central Maine Power Company. Additional electric generation capacity is available to the Company through its contractual arrangements with other utilities and nonutilities and its participation in the New England Power Pool as further described in this item.
In December 1997, the Company entered into a purchase and sale agreement with Sithe Energies, Inc., a privately-held company headquartered in New York, to purchase its non-nuclear generating assets.
Refer to Note C to the Consolidated Financial Statements in Item 8 for more information regarding the company's fossil divestiture.
The Company's significant items of property consist of electric generating stations, substations and service centers, and are generally located on Compar y-owned land. The Company's high-tension transudssion lines are generally located on land either owned or subject to easements in its favor.
The company's low-tension distribution lines and fossil fuel pipelines are located principally on public property under permission granted by municipal and other state authorities.
As of December 31, 1997, the Company's transmission system consisted of 362 miles of overhead circuits operating at 115, 230 and 345 kilovolts (kV) and 156 ndles of underground circuits operating at 115 and 045 kV.
The substations supported by these lines are 45 transmission or combined transadasion and distribution substations with transformer capacity of 10,281 megavolt amperes (MVA), 61 4 kV distribution substations with transformer
/
capacity of 1,017 MVA and 18 primary network units with 88 MVA capacity.
In addition, high tension service was delivered to 242 customers' substations.
The overhead and underground distribution systems cover approximately 4,700 and 900 miles of streets, respectively.
HEEC, the Company's regulated subsidiary, has a distribution system that consists principally of a 4.1 mile 115 kV submarine distribution line and a substation which is located on Deer Island in Boston, Massachusetts.
HEEC provides the ongoing support required to distribute electric energy to its one customer, the Massachusetts Water Resources Authority, at this location.
The Massachusetts Energy Facilities Siting Board (EFSB) must approve Company plans for the construction of certain new generation or transmission facilities based upon findings that such facilities are consistent with state public health, environmental protection and resource use and development
- policies.
In December 1997, the Company received approval from the EFSB regarding proposed transudssion and station facilities in Hopkinton and Milford, Massachusetts.
This approval has been appealed to the Massachusetts Supreme Judicial Court.
Purchased Power Contracts
{
Information regarding long-term contracts for the purchase of electricity is included in Note M to the Consolidated Financial Statements in Item 8.
Under the Company's two long-term purchased power contracts with the Massachusetts Bay Transportation Authority (MBTA), the MBTA retains the right to utilize the combustion turbines for its own emergency use and for testing purposes while the Company retains New England Power Pool credit for their capacity and output.
7
Sales Contracts The Company has agreements with Commonwealth Electric Company and Montaup Electric Company under which each purchace 11% of the capacity and corresponding energy of Pilgrim Station and pay 11% of the unit's capital and operating costs including an annual return on investment.
The company has similar agreements with multiple municipal electric companies for a total of 3.7% of the capacity and corresponding energy of Pilgrim Station.
New England Power Pool The Company is a member of the New England Power Pool (NEPOOL), a voluntary association of electric utilities and other electricity suppliers in New England responsible for the coordination, monitoring and directing of the operations of the major generating and transmission facilities in the region.
To obtain naximum benefits of power pooling, the electric facilities of all member companies are directed by an Independent System Operator (ISO - New England) as if they were a single power system. This is accomplished through the use of a central dispatching system that uses the lowest cost generation and transmission equipment available at any given time. As a result of its participation in NEPOOL, the Company's operating revenues and costs are affected to some extent by the operations of the other members.
During 1997, the power pool was restructured with changes taking effect to the membs ship and governance provisions of the power pooling agreement along with the transferal of operating responsibility of the integrated transmission and generation system in New England to the above referenced Independent System e
operator.
Rules and procedures for bid-basa'i markets for unbundled energy se'rvices in lieu of the current cost-based pricing mechanism are under development. A spot market for installed capability is scheduled to be in effect on April 1, 1998 and the spot markets for other unbundled electric products are anticipated to be ready in the fourth quarter of 1998.
The Company's net capacity was 3,397 MW at year end 1997 and 3,444 MW at its summer peak.
Its corresponding NEPOOL capacity obligations were estimated to be 3,036 MW and 3,312 MW, respectively.
, Item 3.
Legal Proceedings
. Refer to Note L to the Consolidated Financial Statements in Item 8 for a discussion of legal matters affecting the Company.
Item 4.
Subndssion of Matters to a Vote of Security Holders There were no matters submitted to a vote of security holders during the fourth quarter of 1997.
8
4 l
Executive Officers of the Registrant The names, ages, positions and business experience during the past five years of all the executive officers of Boston Edison Company and its subsidiaries as of March 1, 1998 are listed below. There are no family relationships between any of the officers of the Company, nor any arrangement or understanding between any company officer and another person pursuant to which the position as officer is held.
Officers of the Company hold office until the first meeting of the directors following the next annual meeting of the stockholders and until their respective successors are chosen and qualified.
l Business Experience l
Name, Age and Position During Past Five Years Thomas J. May, 50 Chairman of the Board, President chairman of the Board, President and Chief Executive Officer (since and Chief Executive Officer 1995), Chairman of the Board and Chief Executive Officer (1994-1995), President end Chief Operating Officer (1993-1994) and Executive Vice President (1993);
Director (since 1991) 4 Chairman of the Board, President and Chief Executive Officer and Director, Boston Energy Technology Group, Inc.; Director, Harbor Electric Energy Company, Boston Edison Services, Inc., BecoCom, Inc., Northwind Boston, LLC and Coneco Corp.
Ronald A.
Ledgett, 59 Lxecutive Vice President (since Executive Vice President 1997), Senior Vice President -
Fossil, Field Service and Electric j
Delivery (1996-1997) and Senior i
Vice President - Power Delivery i
(1991-1995) l l
Alison Alden, 49 Senior Vice President - Sales, Senior Vice President - Sales, Services and Human Resources Services and Human Resources (since 1996) r.nd Vice President -
Sales & Service (1993-1996) l L. Carl Gustin, 54 Senior Vice President - Corporate Senior Vice President - Corporate Relations (since 1995) and Senior Relations Vice President - Marketing &
Corporate Relations (1989-1995) 9
Business Experience Name, Age and Position During Past Five Years Senior Vice President - Strategy Douglas S.
Horan, 48 and Law and General Counsel Senior Vice President - Strategy and Law and General Counsel (since 1995), Vice President and General Counsel (1994-1995) and Deputy General Counsel (1991-1994)
Senior Vice President, General l.
Counsel and Director, Harbor Electric Energy Company; Senior Vice President and Director, BecoCom, Inc.; Director, Boston Energy Technology Group, Inc.,
Boston Edison Services, Inc. and Coneco Corp.
James'J. Judge, 42 Senior Vice President - Corporate Senior Vice President - Corporate Services and Treasurer (since Services and Treasurer 1995), Assistant Treasurer (1989-1995) and Director - Corporate Planning (1993-1995)
Senior Vice President, Treasurer f
and Director, Harbor Electric Energy Company and Boston Energy Technology Group, Inc.; Senior Vice President and Director, Boston Edison Services, Inc. and BecoCom, Inc.; Director, Northwind Boston, LLC, Coneco Corp. and EnergyVision, LLC Robert J. Weafer, Jr.,
51 Vice President - Finance,
-Vice President - Finance, Controller and Chief Accounting Controller and Chief officer (since 1991)
Accounting Officer Assistant Treasurer, Harbor Electric Energy Company, Boston Energy Technology Group, Inc.,
Boston Edison Services, Inc. and Coneco Corp.
Theodora S.
Convisser, 50 Clerk of the Corporation (since Clerk of the Corporation 1986) and Assistant General Counsel (since 1984)
Clerk, Harbor Electric Energy Company, Boston Energy Technology Group, Inc., Boston Edison Services, Inc., BecoCom, Inc.,
Northwind Boston, LLC, Coneco Corp. and EnergyVision, LLC 10
4 Part II
]
Item 5.
Market for the Registrant's Common Stock and Related Stockholder Matters (a) Market Information The Company's common stock is listed on the New York and Boston Stock Exchanges.
The high and low market value per share of the Company's common stock as reported in the Wall Street Journal for each of the quarters in 1997 and 1996 was as follows:
1997 1996
)
High Low High Low First quarter
$27 3/8
$26
$30 1/8
$26 1/4 Second quarter
$26 5/8
$24 5/8
$27 1/8
$23 5/8 Third quarter
$30 7/8
$26 1/2
$25 3/8
$21.3/4 Fourth cuarter
$38 3/8
$30 1/4
$27
$21 3/4 i
(b) Holders As of March 24, 1998, the Company had 32,200 holders of record of its common stock.
J (c) Dividends Dividends declared per share of common stock for each of the quarters in 1997 and 1996 were as follows:
1997 1996 First quarter
$0.470
$0.470 Second quarter
$0.470
$0.470 Third quarter
$0.470
$0.470 Fourth auarter
$0.470
$0.470 (d) Other Information Ratio of earnings to fixed charges and ratio of earnings to fixed charges and preferred stock dividend requirements for the year ended December 31, 1997:
Ratio of earnings to fixed charges 2.95 Ratio of earnings to fixed charges and l
preferred stock dividend requirements 2.51 l
i l
l l-
\\
l 11 1
lL_:____-__________________-__-___-_____.
Item 6.
Selected Financial Data The following table summarizes five years of selected consolidated financial data of the company (in thousands, except per share data).
1997 1996 1995 1994 1993 l
Operating revenues
$1,776,233
$1,666,303
$1,628,503
$1,544,735
$1,482,159 Net income $ 144,642
$ 141,546
$ 112,310 125,022 118,218 Earnings per share of Common stock-basic and diluted S
2.71 2.61 2.08(a) $
2.41 2.28 Total assets
$3,622,347
$3,729,291
$3,637,170
$3,608,699
$3,468,724 Long-term debt
$1,057,076
$1,058,644
$1,160,223
$1,136,617
$1,272,497 Redeemable preferred
't stock
$ 163,093
$ 203,419
$ 206,514
$ 208,514
$ 210,514 cash dividends declared per common share 1.880 S
1.880 S
1.035 S
1.775 1.715 (a)
Ir.cludes $0.44 per share restructuring charge.
Excluding the restructuring charge, 1995 earnings per share were $2.52.
12
Item 7.
Management's Discussion and Analysis Electric Utility Industry Restructuring The traditionally rate-regulated electric utility industry is rapidly changing in response to the continuing market pressures for lower priced electric energy.
These pressures have resulted in regulatory and legislative proceedings at both federal and state levels designed to foster competition in the industry.
On January 28, 1998, the Massachusetts Department of Telecommunications and Energy (DTE), formerly the Department of Public Utilities (DPU), approved our restructuring sett3mnent agreement that was filed in July 1997. The DTE found that the settlement agreement substantially complied or was consistent with key provisions of a Massachusetts law enacted in November 1997 establishing a comprehensive framework for the restructuring of our industry. Major provisions of our settlement agreement include the ability for re, tail electric customers to choose their electricity supplier (referred to as retail access) as of March 1, 1998 (the retail access date).
Customers who choose not to participate in retail access will have the option of continuing to buy power from our electric delivery business at " Standard Offer" prices. Upon the retail access date, customers that continue to buy electricity under the Standard Offer will realize an average 10% savings from the rates in effect during 1997. Under the new legislation, Standard Offer customers will realize another 5% savings in electricity rates, after an adjustment for inflation, by September 1, 1999. We expect to be able to meet this additional rate reduction as a result of the divestiture of our fossil generating assets which is discussed below. Im part of our settlement aqreament, the retail delivery rates of our retained distribution business include a non-bypassable transition charge designed to recover certain costs incurred by our generation business under the traditional electric ratemaking structure which cannot be otherwise recovered in a competitive environment.
The rates of our distribution business will continue to be regulated by the DTE based on the cost of providing distribution service.
In 1997 the Emerging Issues Task Force (EITF) reached consensus on specific issues raised related to the application of Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (S FAS 71). As part of its consensus, the EITF determined that when deregulation legislation is passed and regulatory actions have taken place providing sufficient detail for an enterprise to reasonably determine how the transition plan will affect the separable portion of its business being deregulated, the enterprise should stop applying SFAS 71 to that portion of its business. As a result of the recently passed Massachusetts electric industry restructuring legislation and the DTE order regarding our related settlement agreement, we have determined that, as of Decenber 31, 1997, the provisions of SFAS 71 no longer apply to the generation portion of our business. The EITF further determined that book values of assets and liabilities originating in the separable portion of the business no longer subject to rate-regulation should be evaluated on the basis of where the regulated cash flows to realize and settle them will be derived.
Net generating assets recoverable from the proceeds of the fossil divestiture and through the non-bypassable transition charge of our distribution business which continues to be subject to rate-regulation, therefore, remain on our consolidated balance sheet at December 31, 1997.
In addition, approximately 25% of the operations and capital costs, including a return on investment, of Pilgrim Nuclear Power Station will continue to be collected under wholesale life of the unit contracts. These contracts continue to be regulated by the Federal Energy Regulatory Commission (FERC) and are not impacted by our settlement agreement.
13
4 Divestiture of Fasoil Gen:rsting Ascats our restructuring settlement agreement includes a provision for the divestiture of our fossil generating assets no later than six months after the retail access date.
On December 10, 1997, we entered into a purchase and sale agreement with Sithe Energies, Inc., a privately-held company headquartered in New York, to purchase our non-nuclear generating assets. The proceeds from the sale of these assets will be $657 million. The net book value of these assets at December 31, 1997 is approximately $450 ndllion.
Included in the purchase price, Sithe Energies will pay $121 ndllion to us in connection with a six-month transitional power sales agreement under which we will buy power from the generating plants.
Sithe Energies will also be responsible for obligations resulting from the recently enacted utility restructuring legislation for property tax payments to communities with non-nuclear power plants. Net proceeds from the divestiture will be used to reduce the distribution transition charge.
Implementation.of the divestiture plan is subject to certain regulatory approvals including those of the DTE and the FERC, We anticipate finalization of the divestiture in mid-1998.
In Jul'y 1997, we reached an agreement with our field service union that requires the buyer of our fossil generating assets to recognize and continue to honor the provisions of the union's current collective bargaining agreement through the end of its tenm, May 2000. As part of a package offered to employees affected by the fossil divestiture, all eligible fossil and designated fossil support employees age 55 or older with at least 10 years of f service, or age 65 by July 1, 1998, were offered unreduced retirement and transition benefits under a voluntary early retirement program (VERP). Under this program, 40 people elected to retire.
Retirement dates are expected to be the first of the month following the transfer of ownership of our fossil generating assets.
Severance programs were offered to management and field service union employees affected by the fossil divestiture that did not elect or were ineligible to retire under the VERP. These severance benefits include salary payments, education / retraining allowances and outplacement services.
It is anticipated that 48 employees will receive severance benefits under these programs.
The estimated costs associated with the VERP and severance programs is approximately $21 ndllion including the effects on the retirement, life and dental plans.
Severance and employee retraining costs related to the divestiture are recoverable through the distribution transition charge under our settlement agreement. Therefore, we have established an offsetting regulatory asset for these obligations on our consolidated balance sheet at December 31, 1997.
Nuclear Asset Impairment As part of the settlement agreement, we recover our net investment in Pilgrim as of December 31, 1995 (adjusted for depreciation through 1997) through the distribution transition charge. Under the terms of the settlement agreement, we must perform a market valuation of Pilgrim by 2002. Upon acceptance of the valuation by the DTE, the resulting dollar amount, net of prudently incurred post-1995 investments in the plant, will reduce amounts collectible through the transition charge.
If the valuation is not sufficient to allow for the recovery of these investments, we will seek their recovery through the transition charge.
Due to the market pressures facing us, the ultimate recovery of these assets is not certain.
Therefore, we reduced our investment in Pilgrim by the $13 ndllion invested in the plant since January 1, 1996 as 14
an impairment loss.
An after tax charge of approximately $8 million due to this reduction was recorded to non-operating expense on our consolidated statement of income in the fourth quarter of 1997. A similar uncertainty does not exist for the ultimate recovery of the fossil generating assets as the sale proceeds agreed to in the purchase and sale agreement with Sithe Energies exceeds the net book value of these assets.
BEC Energy We are currently awaiting a decision from the DTE regarding our reorganization plan to form a holding company structure. A decision from the Securities and Exchange Commission is also pending. Approval from the Nuclear Regulatory Commission was received on February 11, 1998. This plan was approved by the FERC and our shareholders in 1997. This new structure will clearly separate our regulated and unregulated operations.
It will provide us with greater organizational flexibility allowing us to take advantage of nonutility business opportunities in a more timely manner. The holding company structure is a well established form of organization for companies conducting multiple lines of business.
In fact, all other Anvestor-owned Massachusetts electric utilities are currently organized in this manner.
Through our holding company, BEC Energy, we will seek ways to expand our customer base.
Joint Ventures We continue to conduct unregulated activities through our wholly owned subsidiary, Boston Energy Technology Group (BETG).
During 1997, BETG entered into two joint venture agreements.
BETG has a joint venture agreement with 1
RCN Telecom Services, Inc. (RCN). The final closing on this joint venture occurred in June 1997. This limited liability company (LLC) competes directly l
with local and long-distance telephone, video and Internet access companies i
for telecommunications-related services.
BETG owns 49% of the LLC while RCN l
owns 51% and maintains day-to-day nanagement responsibility.
BETG also has an energy marketing venture with Williams Energy Services Company (WESCO), a subsidiary of The Williane Companies, Inc.
This LLC, EnergyVision, markets electricity, natural gas and energy-related services to retail customers in the six New England states and began operations in February 1997.
BETG and WESCO each own 50% of EnergyVision.
Results of Operations 1997 versus 1996 j
Earnings per share of common stock were $2.71 in 1997 compared to $2.61 in 1996, a 3.8% increase as described below.
Operating revenues Operating revenues increased 6.6% over 1996 as follows:
(in thousands)
Retail electric revenues S 87,252 Demand side management revenues 1,232 Wholesale revenues (765)
Short-term sales and other revenues 22,211 Increase in operatino revenues
$109,930 Retail base revenues, consistent with the 0.8% increase in kilowatt-hour (kWh) sales in 1997, were relatively flat compared to 1996.
Increases due to warmer than normal temperatures in June and July, cooler temperatures in October and 15 t---_________
December and the stronger local economy were effset by milder than normal winter conditions during the first quarter of 1997 and lower industrial sales.
Industrial sales continue to be adversely affected by the decline in manufacturing activity in our service territory.
In addition, revenues in 1996 reflect one more day of sales due to the leap year.
Total retail electric revenues increased $87.3 million primarily due to the timing effect of fuel and purchased power cost recovery.
The increase in fuel and purchased power clause revenues reflect the current recovery of prior year undercollections. These higher revenues are offset by higher fuel and purchased power expenses and, therefore, have no net effect-on earnings.
Pilgrim performance revenues, which vary annually based on the operating l
performance of Pilgrim Station, decreased due to a lower annual capacity factor effective November 1996 reflecting the refueling and maintenance outage in the first quarter of 1997.
l Short-term sales revenues increased approximately $16 million.
This is due to the continued reduction in available nuclear energy supply in New England conbined with A 42% increase in our fossil generation allowing for increased I
l sales to the power exchange.
Revenues from short-term sales result in a corresponding reduction to future fuel and purchased power billings to retail customers and, therefore, have no net effect on earnings.
1 l
Operating expenses i
Fuel and purchased power expenses increased $90.2 ndllion.
This increase reflects $57 million related to the timing effect of fuel and purchased power l
cost recovery.
In addition, company fuel expense increased $50 million y
prAmarily due to the 42% increase in fossil generation.
These increases were partially offset by a $22 ndllion decrease in power exchange purchases.
Fuel l
l l
and purchased power expenses are substantially recoverable through fuel and purchased power revenues.
operations and maintenance expense decreased $2.6 million from 1996.
The decrease is the result of lower spending due to overall cost control efforts I
and significantly less overhaul activity at our fossil generating units.
These decreases were partially offset by an approximately $5 million l
incremental impact associated with service restoration efforts resulting from a severe snow storm in April 1997 that struck the greater Boston area.
The increase in depreciation and amortization expense is due to the net impact of two depreciation adjustments. We recorded an $8.7 million nonrecurring charge to depreciation expense in the third quarter of 1997 to reflect the l
removal of specific nuclear-related intangible assets from our balance sheet.
l In 1996 we recorded a $5.2 ndllion adjustment to correct the accumulated L
depreciation balance of certain large computer equipment.
Income taxes increased as a result of higher net income offset by a lower effective tax rate.
The effective tax rate for 1997 reflects the impact of the favorable outcome of an Internal Revenue Service (IRS) appeal received in l
the third quarter related to investment tax credits (ITC).
This also resulted l
in an increase in unamortized ITC which will be reflected as a reduction to income tax expense over the life of the related assets.
Refer to Note D to the consolidated Financial Statements for more information on income taxes.
Other expense other expense, net in 1997 reflects the charge of approximately $8 million, after tax, from the nuclear asset impairment which is further discussed in Note C to the consolidated Financial Statements in addition to BETG equity j
I 16
)
1
4 losses.
These decreases were partially offset by approximately $3 million, after tax, in interest income from the IRS appeal.
Interest charges Total interest charges on long-term debt decreased due to the maturing of $100 million of 5.70% debentures in March 1997 and the cessation of amortization of the associated redemption premiums. This was partially offset by the March 1997 issuance of $100 million of 6.662% bank debt due in 1999.
The decrease also reflects the naturity of $100 ndllion of 51/8% debentures in March 1996.
Allowance for borrowed funds used during construction (AFUDC), which represents the financing costs of construction, decreased primarily due to a lower average construction work in progress (CWIP) balance in 1997.
The 1996 average CWIP balance included nuclear fuel purchased in anticipation of Pilgrim Station's scheduled refueling outage in the first quarter of 1997.
Preferred stock dividends The decrease in preferred stock dividends is the result of the redemption of 20,000 of mandatory and 20,000 of optional shares of 7.27% series cumulative preferred stock in May 1997 and 400,000 shares of 8.25% series in June 1997.
Refer to Note I to the Consolidated Financial Statements.
1996 versus 1995 s
Earnings per share of common sto k were $2.61 in 1996 compared to $2.08 in 1995.
Earnings in 1995 reflect.. nonrecurring before tax charge of $34 ndllion ($20.7 ndllion af ter tax, or $0.44 per share) associated with our corporate restructuring.
The restructuring is discussed further in Note F to the Consolidated Financial Statements.
Excluding the nonrecurring
]
restructuring charge, earnings per common share increased 3.6% over 1995 as described below.
Operating revenues Operating revenues increased 2.3% over 1995 as follows:
(in thousands)
Retail electric revenues
$48,649 Demand side management revenues (20,545)
Wholesale revenues (2,072)
Short-term sales and other revenues 11,768 l
l Increase in operatine revenues
$37,800 l
Retail electric revenues increased $48.6 million.
Fuel and purchased power clause revenues increased approximately $36 million.
These higher revenues are offset by higher fuel and purchased power expenses and, therefore, have no net effect on earnings.
Performance revenues increased $14.5 million as l
Pilgrim Station operated at a higher capacity in 1996.
Retail kWh sales I
increased 2.8% in 1996, primarily due to the positive economic impacts on our commercial customers.
Demand side management (DSM) revenues decreased primarily due to a decline in current DSM program expenditures.
The primary reason for the decrease in wholesale revenues is due to Pilgrim contract customer revenues. These revenues decreased despite increased kWh sales due to lower operations and maintenance expense related to Pilgrim 17
_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ~
Station.
Pilgrim contract customers are billed for their proportionate share of the unit's costs.
I Net short-term sales and other revenues increased $11.8 ndllion.
Despite i
lower kWh sales, short-term sales revenues increased approximately $6 ndllion due to higher fuel prices.
Revenues from short-term sales result in a corresponding reduction to future fuel and purchased power billings to retail customers and, therefore, have no net effect on earnings.
This increase also reflects an increase in revenue from non-electric sources in 1996.
l Operating expenses l
l Fuel and purchased power expenses increased $53.1 million.
Fuel expense increased, despite a slight decrease in ecmpany generation, due to significantly higher oil and natural gas prices.
Purchased power expense reflects a higher volume of energy purchases and an overall increase in energy l
prices. These increases were partially offset by the timing effect of fuel and purchased power cost recovery.
Fuel and purchased power expenses are substantially recoverable through fuel and purchased power revenues.
Operations and maintenance expense decreased $40.8 million primarily due to lower labor costs resulting from our 1995 restructuring and the continuing cost control efforts of each of our business units.
In addition, the amortization of deferred nuclear outage costs decreased $9 ndllion. As discussed in Note B to the Consolidated Financial Statements, in the third quarter of 1995 we nmde a retroactive change to the amortization period of these deferred costs from five years to two years, consistent with the f
two-year cycle between rafueling outages at Pilgrim Station.
The 1995 operating expenses reflect a $34 ndllion nonrecurring charge related to our corporate restructuring.
Refer to Note F to the Consolidated Financial Statements for additional information regarding our 1995 restructuring.
Depreciation and amortization increased $32.2 million.
The increase is primarily the result of a change in the estimated remaining econcmic lives of our Mystic 4, 5 and 6 fossil generating units in the second quarter of 1996, retroactive to the beginning of the year, and an increase in the depreciable plant balance.
The change in estimated economic lives of Mystic 4, 5 and 6 resulted in a $22 million increase in depreciation expense for the year.
The decrease in DSM prograns expense reflects the decline in current DSM program expenditures.
The increase in income taxes is due to higher net income and a higher effective tax rate in 1996. The effective tax rate in 1996 is 38.2% versus 37.1% in 1995.
Interest charges Interest on long-term debt decreased due to the maturity of $100 nullion 8 7/8% debentures in December 1995 and $100 million 5 1/8% debentures in March i
1996.
These decreases were partially offset by the issuance of $125 million l
7.80% debentures in May 1995 which were outstanding for all of 1996.
Other interest charges increased due to an increase in interest on short-term debt caused by the higher average short-term debt level partially offset by a lower average short-term borrowing rate.
The short-term debt balance increased as a f
result of the debenture maturities and the redemption of $4 million of preferred stock in 1996. AFUDC decreased due to lower overall construction 18
i j
1 activity during 1996, shorter construction periods, and lower short-term l
interest rates.
Electric Sales and Revenues i
Electric sales Retail kWh sales increased 0.8% in 1997.
This was primarily attributable to the commercial sector. The commercial increase reflects the impact of a continued strong economy in the Boston area and very warm temperatures in June and July and cooler than nornal temperatures in the fourth quarter. Hotel occupancy rates and non-manufacturing employment continued to increase in 1997. The commercial sector represents approximately 50% of our electric operating revenues.
Residential revenues, which represent 27% of electric revenues, were also positively impacted by the weather. These positive j
impacts were offset by milder winter weather in the first quarter of 1997 and J
declines in manufacturing enployment affecting the industrial sector.
In addition, revenues in 1996 reflect one more day of sales due to the leap year.
The industrial sector represents only 9% of our electric operating revenues.
Total kWh sales increased 3.1% as a result of the continued reduction in available nuclear energy supply in New England. This reduction, combined with an increase in our fossil generation allowed for increased sales to the power exchange.
The 2.8% increase in 1996 retail kWh sales was primarily due to the positive effect on commercial customers of the strong economy in our retail service y
territory.
Residential sales decreased slightly primarily due to overall milder than normal weather conditions.
Industrial s..les remained relatively flat.
Total kWh sales, including wholesale, increased 3.3%.
The increase in wholesale sales was primarily due to higher sales to our Pilgrim contract customers as the plant was operating for substantially all of 1996.
In addition, sales to our municipal customers increased due to a reduction in available energy supply in New England.
Electric zevenues As discussed in the Electric Utility Industry Restructuring section, our delivery business will provide Standard offer customers service at rates designed to give an average 10% savings upon the retail access date.
As part of the recently passed restructuring legislation in Massachusetts, these customers are to realize an additional 5% average savings, after an adjustment for inflation, by September 1, 1999. We expect to meet this additional rate reduction as a result of the proceeds received from the divestiture of our fossil generating assets and potential securitization or refinancing of our stranded costs. Under our settlement agreement, the aggregate amount of our transition charge is reduced by the net proceeds from fossil divestiture.
Under the settlement agreement, the annual performance adjustment charge ceases and our cost recovery mechanism for Pilgrim Station changes as of the retail access date.
Approximately 25% of the operations and capital costs, including a return on investment, will continue to be collected under wholesale life of the unit contracts. The remaining output will be sold in the competitive energy market. Through December 31, 2000, we will share 25%
of any profit. or loss from the sale of Pilgrim's output with distribution customers through the transition charge.
In addition, we will obtain transition payments up to a naximum of $23 ndllion per year depending on the level of costs incurred for property taxes, insurance, regulatory fees and security requirements.
I 19
Beginning upon the retail access date, the rates of our distribution business will remain unchanged through December 31, 2000, subject to a minimum and maximum return on average common equity (ROE). We will be required to file with the DTE a computation supporting the ROE of our distribution business after each calendar year. The ROE is subject to a floor of 6% and a ceiling of 11.75%.
If the ROE is below 6%, we are authorized to add a surcharge to distribution rates in order to achieve the 6% floor.
If the ROE is above 11%,
we are required to adjust distribution rates by an amount necessary to reduce the calculated ROE between 11% and 12.5% by 50%, and a return above 12.5% by l
100%. No adjustment is made if the ROE is between 6% and 11%.
The cost of providing transmission service to distribution customers will be recovered on a fully reconciling basis.
Liquidity We ordinarily meet most of our cash requirements for plant expenditures with internally generated funds. These funds are cash flows from operating activities, adjusted to exclude changes in working capital and the payment of dividends.
During 1997, 1996 and 1995 our internal generats.n of cash j
provided 211%, 177% and 102%, respectively of our plant expenditures.
The j
capital spending level, excluding nuclear fuel, forecasted for 1998 is $265 l
ndllion which includes amounts for utility plant and the capital requirements of our nonutility ventures. This spending level also includes the 1998 portion of business system replacements discussed below.
The capital spending level over the next five years is forecasted to be approximately $940 million.
In addition to capital expenditures, we have debt and preferred stock payment l
requirements of $103.6 million in 1998 and 1999, $168.6 million in 2000, $53.6 !
million in 2001 and $3.6 million in 2002.
We supplement our internally generated funds as needed, primarily through the issuance of short-term commercial paper and bank borrowings. We have authority from the FERC to issue up to $350 million of short-term debt.
We also have a $200 million revolving credit agreement and arrangements with several banks to provide additional short-term credit on a conadtted as well as on an uncommitted and as available basis. At December 31, 1997, we had
$137 ndllion of short-term debt outstanding, none of which was incurred under the revolving credit agreement. We have $220 million remaining under our approved long-term financing plan with the DTE which is available through 1998.
Proceeds from issuances under this plan are to be used to refinance short and long-term securities and to fund capital expenditures.
Refer to Notes I and J to the consolidated Financial Statements for additional information relating to our financing activities.
At December 31, 1997, BETG had $7.5 million outstanding under a revolving credit-a g reement. The purpose of this line is to fund its capital requirements above our $45 million limited investment. This debt will be refinanced upon the formation of BEC Energy.
We anticipate using the sale proceeds from our pending fossil divestiture to adjust our capital structure.
Year 2000 computer Issue The year 2000 computer issue is the result of programs written using two digits instead of four to define an applicable year.
Consequently, these programs will not properly recognize calendar dates beginning in the year 2000. This could cause conputers to shut down or yield incorrect results.
I l
i 20 l
Wa have developed a plan to address the year 2000 issue that includes modification of certain applications and replacement of systems that are not year 2000 compliant. The cost associated with modification of existing applications will be expensed as incurred.
In addition, we have made a decision to use this opportunity to upgrade some of our less efficient centralized business systene. The full replacement costs associated with these systens will be capitalized and amortized over future periods.
The total cost of the year 2000 project is expected to be funded through internally generated funds. We anticipate completion of the year 2000 project in the third quarter of 1999.
Other Matters Environmen tal l
We are subject to numerous federal, state and local standards with respect to waste disposal, air and water quality and other environmental considerations.
These standards can require that we modify our existing facilities or incur increased operating costs.
We currently own or operate approximately 30 properties where oil or hazardous materials were previously spilled or released. We also continue to face possible liability as a potentially responsible party in the cleanup of six multi-party hazardous waste sites in Massachusetts and other states where we are alleged to have generated, transported or disposed of hazardous waste at the sites.
Refer to Note L.6. to the Consolidated Financial Statements for more information regarding hazardous waste issues.
The Accounting Standards Executive Committee of the American Institute of l
Certified Public Accountants issued Statement of Position 96-1, Environmental Remediation Liabilities (SOP 96-1), effective in 1997. This statement contains authoritative guidance on specific accounting issues related to the recognition, measurement, display and disclosure of environmental remediation liabilities.
It requires that an accrual for environmental liabilities include estimates of the costs of compensation and benefits for those employees expected to devote a significant amount t" time directly to that effort.
SOP 96-1 had no material effect on our financial position or results of operations during 1997.
Uncertainties centinue to exist with respect to the disposal of both spent I
nuclear fuel and low-level radioactive waste (LLW) resulting from the operation of Pilgrim Station. The United States Department of Energy (DOE) is responsible for the ultimate disposal of spent nuclear fuel; however, uncertainties regarding the DOE's schedule of acceptance of spent fuel for disposal continue to exist.
In 1995 we regained access to the LLW disposal facility located in barnwell, South Carolina.
Refer to Note E to the Consolidated Financial Statements for further discussion regarding nuclear decommissioning and waste disposal.
The 1990 Clean Air Act Amendments (CAAA) require a significant reduction in nationwide emissions of sulfur dioxide from fossil generating units.
Other provisions of the CAAA involve limitations on emissions of nitrogen oxides from existing generating units. Am discussed in the Divestiture of Fossil Generating Assets section, we have signed an agreement with Sithe Energies for the sale of our fossil generating assets.
If regulatory approval is not obtained or is delayed, we could continue to operate these units subject to the provisions of these amendments. We currently meet the standards of the CAAA and, depending on the outcome of certain Massachusetts Department of Environmental Protection air quality modeling studies, our generating units 21 l
i E_.___________________________
could continue to operate through at least 1999 before additional emission reductions would be required.
Public concern continues regarding electromagnetic fields ( EMF) associated with electric transudssica and distribution f acilities and appliances and wiring in buildings and homes.
Such concerns have included the possibility of adverse health effects caused by EMF as well as perceived effects on property values.
Some scientific reviews conducted to date have suggested associations between EMF and potential health effects, while other studies have not substantiated such associations.
The National Research Council previously reported that there is no conclusive evidence that exposure to EMF from power lines and appliances presents a health hazard.
The panel of scientists, working with the National Academy of Sciences, report that more than 500 studies over the last several years have produced no proof that EMF causes leukemia or other cancers or harms human health in other ways.
We continue to support r. search into the subject and are participating in the funding of industry-sponsored studies. We are aware that public concern regarding EMF in some cases has*resulted in litigation, in opposition to existing or proposed
)
facilities in proceedings before regulators or in requests for legislation or j
regulatory standards concerning EMF levels. We have addressed issues relative to EMF in various legal and regulatory proceedings and in discussions with j
customers and other concerned persons; however, to date we have not been l
significantly affected by these developments. We continue to monitor all aspects of the EMF issue.
Litigation In October 1997, the DTE opened a proceeding to investigate our compliance with the 1993 order which permitted the fonmation of BETG and authorized us to invest up to $45 million in unregulated activities. We are unable to determine the ultimate outcome of this proceeding or its impact on our operations.
We were named as a party in lawsuits by Subaru of New England, Inc. and Subaru Distributors Corporation.
The plaintiffs claimed certain automobiles stored j
on lots in South Boston suffered pitting damage caused by emissions from our l
New Boston Station generating unit.
In 1997 we settled both lawsuits.
Neither settlement had a material impact on our consolidated results of operations or financial position.
Refer to Note L.B. to the Consolidated Financial Statements for more information on other legal matters in which we are involved.
Industry restructuring legal proceedings / referendum campaign The DTE order approving our settlement agreement has been appealed by certain parties to the Massachusetts Supreme Judicial Court.
In addition, along with other Massachusetts investor-owned utilities, we have been named as a defendant in a class action suit seeking to declare certain provisions of the Massachusetts electric industry restructuring legislation unconstitutional.
We are currently unable to determine the outcome of these proceedings or their impact on us.
Opponents of the electric industry restructuring legislation that was enacted in November 1997 have mounted a referendum campaign to repeal that law.
A coalition of business, industry and public interest groups that supported the legislation, along with the electric utility industry, is opposed to the referendum and is prepared to mount an aggressive campaign to defeat it.
We 22
are currently unable to predict the eventual outcome of this referendum or its impact on us.
Safe harbor cautionary statement We occasionally nake forward-looking statements such as f oreca&ts and projections of expected future performance or statements of our plans and objectives. These forward-looking statements may be contained in filings with the Securities and Exchange Commission, press releases and oral statements.
Actual results could potentially differ materially from these statements.
Therefore, no assurances can be given that the outeemes stated in such forward-looking statements and estimates will be achieved.
The preceding sections include certain forward-looking statements about the effects of the industry restructuring process and our related settlement agreement, the divestiture of our fossil generating assete, operating results, f
year 2000 and environmental and legal issuer.
The effects of electric utility industry restructuring could differ from our expectations.
This could occur as regulatory decisions and negotiated I
settlements between utilities and interveners are finalized.
In addition, the development of a competitive electric generation market, the impacts of actual electric supply and demand in New England and further legislative action may affect the ultimate results of the industry restructuring and our settlement agreement.
I t
The divestiture plan could differ from our expectations. This could occur if required regulatory approvals are delayed or not obtained.
The impacts of our continued cost control procedures on our operating results could differ from our expectations. The effects of changes in economic conditions, tax rates, interest rates, technology and the prices and availability of operating supplies could materially affect our projected operating results.
The timing and total costs related to our year 2000 plan could differ from our expectations.
Factors that may cause such differences include the ability to i
-locate and correct all relevant computer codes and the availability of personnel trained in this area.
In addition, we cannot predict the nature or impact on operations of third party noncompliance.
The impacts of various environmental and legal issues could differ from our o
expectations. New regulations or changes to existing regulations could impose additional operating requirements or liabilities other than' expected.
The l
effects of changes in specific hazaraous waste site conditions and cleanup technology could affect our estinated cleanup liabilities. The impacts of changes in available information and circumstances regarding legal issues could affect our estimated litigation costs.
I 23
Item 8.
Financial Statements and Supplementary Financial Information Consolidated Statements of Income years ended December 31, (in thousands, except earnings per share) 1997 1996 1995 l
Operating revenues S1,776,233 S1,666,303 S1,628,503 Operating expenses:
Fuel and purchased power 679,131 588,893 535,806 Operations and maintenance 414,779 417,372 458,196 Restructuring costs 0
0 34,000 Depreciation and amortization 188,687 185,494 153,339 Demand side management programs 29,790 30,825 45,125 Taxes-property and other 107,975 107,086 106,361 Income taxes 95,021 88,703 68,276 Tota) operating expenses 1,515,383 1,418,373 1,401,103 Operating income 260,850 247,930 227,400 Other incoma (expense), net (10,498) 698 (575) operating and other income 250,352 248,628 226,825 Interest charges:
Long-term debt 92,489 94,823 106,640 Other 14,410 14,551 12,642 Allowance for borrowed funds used during : instruction (1,189)
(2,292)
(4,767)
/
Total interest charges 105,710 107,082 114,515 Net income 144,642 141,546 112,310 Preferred stock dividends 13,149 15,365 15,571 Earnings available for common shareholders S 131,493 $ 126,181 96,739 Weighted average common shares outstanding 48,515 48,265 46,592 Earnings per share of common stock-basic and diluted S
2.71 2.61 S
2.08 Consolidated Statements of Retained Earnings years ended December 31, (in thousands) 1997 1996 1995 Balance at the beginning of the year
$ 292,191 $ 257,749 $ 247,409 Net income 144,642 141,546 112,310 subtotal 436,833 399,295 359,719 Dividends declared:
Preferred stock 13,149 15,365 15,571 Common stock 91,208 90,834 86,399 Subtotal 104,357 106,199 101,970 Provision for preferred stock redemption and issuance costs (a) 3,674 905 0
Balance at the end of the year S
3?B,802 292,191 257,749 (a)
Refer to Note B.7. to the Consolidated Financial Statements.
The accompanying notes are an integral part of the consolidated financial statements.
24
l Consolidated Balance Sheets Decenber 31, (in thousands) 1997 1996 Assets-Utility plant in service, at original cost
$4,457,868
$4,387,887 Less: accumulated depreciation 1,713,079 $2,744,789 1,550,317 $2,837,570 i
Nuclear fuel 351,722 351,453
{
Less: accumulated amortization 283,787 67,935 268,509 82,944 Construction work in progress 41,403 30,376 Net utility plant 2,854,127 2,950,890 l
Nuclear decommissioning trust 151,634 132,076 l
Equity investments 35,455 28,752 other investments 7,107 7,630 Current assets:
Cash and cash equivalents 4,140 5,651 l
l Accounts receivable 192,220 233,024 l
Accrued unbilled revenues 30,048 34,922 Fuel, materials and supplies, at average cost 60,834 57,075 Prepaids and other 31,283 318,525 45,146 375,818 Deferred debits:
j Regulatory assets 220,403 202,026 Other 35,096 32,099 i
Total assets
$3,622,347
$3,729,291 I
l l
Capitalization and Liabilities
-Common stock equity
$1,073,454
$1,036,424
(
Cumulative preferred stock 161,093 201,419 i
Long-term debt 1,057,076 1,058,644 Current liabilities:
Long-term debt / preferred stock due within one year
$ 102,667
$ 102,667 Notes payable 137,013 201,454 Accounts payable-87,015 134,083 l
Accrued interest 24,289 24,378 Dividends payable 24,748 25,343 Other 128,061 503,793 115,812 603,737 Deferred credits:
Accumulated deferred income taxes 485,738 498,718 Accumulated deferred investment I
tax credits 60,736 58,899 Nuclear decommissioning liability 155,182 133,388 l
Power contracts 71,445 88,963 i
other 53,830 49,099
. Commitments and contingencies j
l Total capitalization and liabilities
$3,622,347
$3,729,291 The accompanying notes are an integral part of the consolidated financial statements.
25
Consolidated Statements of Cash Flows years ended December 31, (in thousands) 1997 1996 1995 Operating activities:
Net income
$144,642 $141,546 $112,310 Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 223,529 228,259 202,294 Deferred income taxes and investment tax credits (21,664)
(4,057)
(25,193)
Allowance for borrowed funds used during construction (1,189)
(2,292)
(4,767)
Het changes in:
Accounts receivable and accrued unbilled revenues 45,678 (11,719)
(34,626)
Fuel, materials and supplies (5,486)
(2,171) 7,202 Accounts payable (47,068) 609 2,978 other current assets and liabilities 25,428 (44,514) 26,485 other, net (4,640) 50,815 26,993 Net cash provided by operating activities 359,230 356,426 313,696 Investing activities:
Plant expenditures (excluding AFUDC)
(114,110) (145,347) (180,822)
Nuclear fuel expenditures (4,089)
(52,967)
(13,621)
Investments in joint ventures (7,859)
(5,698) 0 Other investments (19,830)
(28,616)
(19,005)
Net cash used in investing activities (145,888) (232,628) (213,448) i Financing activities:
Issuances:
Common stock 144 12,559 64,888 Long-term debt 100,000 0
125,000 Redemptions:
Preferred stock (44,000)
(4,000)
(2,000)
Long-term debt (101,600) (101,600) (100,600)
Net change in notes payable (64,441) 75,013 (88,345)
Dividends paid (104,956) (106,010) (100,152)
Net cash used in financing activities (214,853) (124,038) (101,209)
Het decrease in cash and cash equivalents (1,511)
(190)
(981)
Cash and cash equivalents at the beginning of the year 5,651 5,841 6,822 Cash and cash couivalents at the end of the year $
4,140 $
5,65) 5,841 Supplemental disclosures of cash flow information:
-Cash paid during the year for:
Interest, net of amounts capitalized
$100,795 $100,810 $104,011 Income taxes S 99,326 S 98,668 $ 96,180 The accompanying notes are an integral part of the consolidated financial statements.
26
Notes to Consolidated Financial Statements Note A.
Nature of Operations Boston Edison Company (the company) is an investor-owned regulated public utility operating in the inergy, energy services and telecommunications business. This includes tne generation, purchase, t ranand s sion, distribution and sale of electric energy and the development and implementation of electric demand side management prograns. A portion of our generation is produced by our wholly owned nuclear generating unit, Pilgrim Nuclear Power Station. We supply electricity at retail to.an area of 590 square ndles, including the city of Boston and 39 surrounding cities and towns. We also supply electricity at wholesale for resale to other utilities and municipal electric departments.
Electric operating revenues were 88% retail and 12% wholesale in 1997.
We also conduct unregulated activities through our wholly owned subsidiary, Boston Energy Technology Group (BETG).
Through BETG and its subsidiaries, we are engaged in certain nonutility businesses, including energy utilization and conservation, construction management and district energy.
BETG has a joint venture with RCN Telecom Services, Inc. (RCN) that provides certain telecommunications-related services.
The limited liability company (LLC) formed from this joint venture is owned 51% by RCN and 49E by BETG, with RCN having the day-to-day management responsibility.
BETG also has a joint venture with Willians Energy Services l
Company (WESCO).
This joint venture markets electricity, natural gas and energy-related services to retail customers in the six New England states.
BETG and WESCO each own 50% of this LLC, EnergyVision.
We are current..y awaiting a decision from the Massachusetts Department of Telecommunications and Energy (DTE), formerly the Department of Public Utilities, regarding our plan to form a holding company structure. This structure will clearly separate our regulated and unregulated lines of business. Through our holding company, BEC Energy, we will seek ways to expand our customer base. After the corporate reorganization, Boston Edison will be a wholly owned subsidiary of BEC Energy.
BETG will cease being a subsidiary of Boston Edison and become a wholly owned subsidiary f BEC Energy.
The common shareholders of Boston Edison will become s5ss,
!ders of BEC Energy. The existing debt and preferred stock of Boston Edt*L 11 remain obligations of the regulated utility business.
Refer also to Note C to these Consolidated Financial Statements fc: changes in the nature of our operations as a result of the electric utility industry i
I restructuring and our related settlement agreement.
Note B.
Significant Accounting Policies 1.
Basis of Consolidation and Accountingr The consolidated financial statements include the activities of our wholly owned subsidiaries, Harbor Electric Energy Company (HEEC) and BETG. All significant intercompany transactions have been eliminated.
Certain reclassifications have been made to the prior year data to conform with the current presentation.
We follow accounting policies prescribed by the Federal Energy Regulatory Conads sion (FERC) and the DTE.
We are also subject to the accounting and reporting requirements of the Securities and Exchange Commission. The consolidated financial statements conform with generally accepted accounting principles (GAAP). As a rate-regulated company we have been subject to 27
4 Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (SEAS 71), under GAAP.
The application of SFAS 71 results in differences in the timing of recognition of certain expenses from that of other businesses and industries. As a result of the recently passed Massachusetts electric industry restructuring legislation and the DTE order regarding our related settlement agreement, as of December 31, 1997, we are no longer applying the provisions of SFAS 71 to our generation business.
Our distribution business remains subject to rate-regulation and continues to I
meet the criteria for application of SFAS 71.
Refer to Note C to these Consolidated Financial Statements for_more information on the accounting 1
implications of the electric utility industry restructuring.
The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of-assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses j
during the reporting period. Actual results could differ from these i
estimates.
2.
Revenues We record estimates of retail base revenues for electricity used by our customers but not yet billed at the end of each accounting period.
3.
Forecasted Buel and Purchased Power Rates The rate charged to retail customers for fuel and purchased power allows for fuel and purchased power costs which are not included in our base rates to be billed to customers using a forecasted rate.
The difference between actual costs and the amounts billed to customers is recorded as an adjustment to fuel and purchased power expenses and is included in accounts receivable on the consolidated balance sheet until subsequent rates are adjusted.
4.
Utility Pinnt Utility plant is stated at original cost of construction.
The costs of replacements of property units are capitalized. Maintenance and repairs and replacements of ndner items are expensed as incurred. The original cost of property retired, net of salvage value, and the related costs of removal are charged to accumulated depreciation.
S.
Depreciation and Nuclear fuel Amortization l
Depreciation of our utility plant is computed on a straight-line basis using composite rates based on the estimated useful lives of the various classes of property.
Excluding the effect of the adjustment discussed below, the overall composite depreciation rates were 3.30%, 3.33% and 3.28% in 1997, 1996 and 1995, respectively.
Upon the completion of a review of our electric generating units, we determined that our oldest and least efficient fossil units (Mystic 4, 5 and
- 6) were unlikely to provide competitively-priced power beyond the year 2000.
Therefore we revised the estimated remaining economic lives of these units to five years in 1996.
The cost of decommissioning Pilgrim Station is excluded from our depreciation rates.
Refer to Note E to these Consolidated Financial Statements for a j
discussion of nuclear decommissioning. The cost of nuclear fuel is amortized based on the amount of energy Pilgrim Station produces. Nuclear fuel expense 28
also includes an amount for the estimated costs of ultinately disposing of spent nuclear fuel and for assessments for the decontamination and decommissioning of United States Department of Energy nuclear enrichment facilities. These costs are recovered from our customers through fuel rates.
6.
Deferred Nuclear Outnge Costs We defer the incremental costs associated with nuclear refueling outages when
{
incurred and amortize them over Pilgrim Station's operating cycle.
In 1995 we changed the amortization period from five years to two years.
The two year amortization period is consistent with the two-year cycle between nuclear refueling outages at Pilgrim Station.
7.
Costs Associated with Zusuance and Bedemption of Debt and Preferred Stock Consistent with our recovery in electric rates, we defer discounts, redemption premiums and related costs associated with the redemption and issuance of long-term debt'and preferred stock.
The costs related to long-term debt are recognized as an addition to interest expense over the life of the original or replacement debt.
Beginning in 1996, consistent with an accounting order received from the FERC, we reflect costs related to preferred stock redemptions and issuances as a direct reduction to retained earnings upon redemption or over the average life of the replacement preferred stock series as applicable.
B.
Allowance for Borrowed Funds Used During Construction (ATODC)
AFUDC represents the estimated cost-to finance utility plant construction.
In accordance with regulatory accounting, AFUDC is included as a cost of utility plant and a reduction of current interest charges. Although AFUDC is not a current source of cash income, the costs are recovered from customers over the service life of the related plant in the form of increased revenues collected as a result of higher depreciation expense.
Our AFUDC rates in 1997, 1996 and 1995 were 6.04%, 5.87% and 6.35%, respectively, and represented only the cost of short-term debt.
9.
Cash and Cash Equivalents Cash and cash equivalents are comprised of highly liquid securities with maturities of 90 days or less when purchased.
Outstanding checks are included in cash and accounts payable until they are presented for payment.
10.
Allowance for Doubtful Accounts our accounts receivable are substantially recoverable.
This recovery occurs both from customer payments and from the portion of customer charges that provides for the recovery of bad debt expense. Accordingly, we do not maintain a significant allowance for doubtful accounts balance.
11.
Regulatozy Assets Regulatory assets represent costs incurred which are expected to be collected from customers through future charges in accordance with agreements with our regulators.
These costs are expensed when the corresponding revenues are received in order to appropriately match revenues and expenses.
The majority of these costs is currently being recovered from customers over varying time periods.
Refer to Note C to these Consolidated Financial Statements for information regarding the recovery of regulatory assets related to our generation business.
29
Regulatory assets consisted of the following:
December 31, 1997 1996 Fossil divestiture
$ 21,248 S
0 Power contracts 71,445 08,963 Income taxes, net 51,096 47,483 Redemption premiums 27,019 31,052 Postretirement benefits costs 22,441 15,009 Decontamination and decommissioning 12,282 13,190 Nuclear outage costs 10,160 3,432 Other 4,712 2,897
$220,403
$202,026 22.
Earnkags Per Shaze of Casanon Stock 4
Basic earnings per share (EPS) of common stock is calculated by dividing net income, after the payment of preferred stock dividends, by the weighted average common shares outstanding during the year.
Statement of Financial Accounting Standards No. 128, Earnings per Share, requires the disclosure of diluted EPS effective for periods ending after December 15, 1997.
Diluted EPS is similar to the computation of basic EPS except that the weighted average common shares is increased to include the number of dilutive potential common shares.
Diluted EPS, which includes the effect of deferred (nonvested) shares and stock options granted under the Stock Incentive Plan in the calculation of weighted average common shares, is the same as basic EPS displayed on the consolidated statement of income.
Note C. Electric Utility Industry Restructuring 1.
Accounting Zap].Lastions Under the traditional revenue requirements model, our electric rates have been based on the cost of providing electric service. As such, we have been subject to certain accounting standards that are not applicable to other businesses and industries in general. The application of SEAS 71 requires us to defer the recognition of certain costs when incurred if future rate recovery of these costs is expected. Based on a consensus reached by the Emerging Issues Task Force (EITF) regarding specific issues raised related to the application of SEAS 71, we have determined that, as of December 31, 1997, the provisions of SEAS 71 no. longer apply to the generation portion of our business. In its consensus, the EITF determined that when deregulation legislation is passed and regulatory actions have taken place providing sufficient detail for an enterprise to reasonably determine how the transition plan will affect the separable portion of its business being deregulated, the enterprise should stop applying SEAS 71 to that portion of its business.
On January 28, 1998, the DTE approved our restructuring settlement agreement that was filed in July 1997. The DTE found that the settlement agreement substantially complied or was consistent with key provisions of a Massachusetts law enacted in November 1997 establishing a comprehensive framework for the restructuring of our industry. The EITF further determined that book values of assets and liabilities originating in the separable portion of the business no longer subject to rate-regulation should be evaluated on the basis of where the regulated cash flows to realize and settle them will be' derived. Net utility plant and other related assets on our consolidated balance sheet as of December 31, 1997 include approximately $700 adllion related to nuclear generation and approximately $450 ndllion related to fossil generation. As part of our settlement agreement, approximately 75%
of these nuclear assets are fully recoverable through the non-bypassable 30
. transition charge of our distribution business which continues to be subject to rate-regulation. The remaining 25% will be collected under Pilgrim's wholesale life of the unit contracts. These contracts continue to be l
regulated by the FERC and are not impacted by our settlement agreement.
These fossil assets will be recovered from the proceeds from their sale as discussed in part 2 below.
i The implementation of our approved settlement agreement has certain accounting implications. The highlights of these include:
Deprecia tion The composite depreciation rate for distribution utility plant increases from 2.38% to 2.98% as of March 1, 1998 (the retail access date).
Generation related plant and requistoxy assets Plant and regulatory assets related to our generation business, except for those related to Pilgrim's wholesale life of the unit contracts, will be recovered through the transition charge. This recovery, which includes a return, will occur over a twelve-year period.
Storm fund Under the settlement agreement, we are authorized to establish a storm contingency fund to use for the incremental costs of any major storm (in excess of $1 million). The settlement required that we initially establish the fund with $8 udllion of proceeds received from the a le of Clean Air Act emission allowances. As costs are charged against the fund, the balance will be restored to the original level from distribution charges up to a maximum of
$3 ndllion per year.
Tuel and purchased power charge The fuel and purchased power charge ceases as of the retail access date.
Net remaining over or under collection of fuel and purchased power costs will be retlected in future customer billings.
Standard offer chntge Customers will have the option of continuing to buy power from our electric j
delivery business at " Standard Offer" prices as of the retail access dats.
The Standard offes charge begins at 2.8 cents at retail access and increases l
to 5.1 cents by 2004.
The cost of providing Standard Offer service, which includes fuel and purchased power costs, will be recovered from Standard Offer customers on a fully reconciling basis.
1 Distribution and tz=n==4ssion shazgos Distribution rates will be subject to a ndnimum and naximum return on average common equity (ROE) through December 31, 2000. The ROE is subject to a floor of 6% and a ceiling of 11.75%.
If the ROE is below 6%, we are authorized to add a surcharge to distribution rates in order to achieve the 6% floor.
If the ROE is above 11%, we are required to adjust distribution rates by an amount necessary to reduce the calculated ROE between 11% and 12.5% by 50%,
and a return above 12.5% by 100%. No adjustment is made if the ROE is between 6% and 11%.
In addition, distribution rates will be adjusted for any changes in tax laws or accounting principles that result in a change in our costs of 31
more than $1 ndllion.
The cost of providing transmission service to distribution customers will be recovered on a fully reconciling basis.
Nuclear generation Under the settlement agreement, the annual performance adjustment charge ceases and our cost recovery mechanism for Pilgrim Station changes as of the retail access date.
Approximately 25% of the operations and capital costs, including a return on investment, will continue to be collected under wholesale life of the unit contracts.
The remaining output will be sold in the competitive energy market. Through December 31, 2000, we will share 25%
of any profit or loss from the sale of Pilgrim's output with distribution customers through the transition charge.
In addition, we will obtain
. transition payments up to a maximum of $23 million per year depending on the level of costs incurred for property taxes, insurance, regulatory fees and security require.ments.
Nuclear deconan'issioningr Approximately 25% of Pilgrim's decommissioning costs will continue to be collected under wholesale life of the unit contracts. The remaining portion will be recovered through the transition charge. Amounts collected for decommissioning will be adjusted as decommissioning cost studies are updated.
Refer to Note E to these consolidated Financial Statements for more information on nuclear decommissioning costs.
i 2.
Divestiture of Tossil Generating' Assets Included in our settlement agreement is a provision for the divestiture of our fossil generating assets.
On December 10, 1997, we entered into a purchase and sale agreement with Sithe Energies, Inc., a privately-held company headquartered in New York, to purchase our non-nuclear generating assets. The proceeds from the sale of these assets will be $657 million.
The net book value of these assets at December 31, 1997 is approximately $450 ndllion.
Included in the purchase price, Sithe Energies will pay $121 million to us in connection with a six-month transitional power sales agreement under which we will continue to buy power from the generating plants.
Sithe Energies will also be responsible for obligations resulting from the recently enacted utility restructuring legislation for property tax payments to communities with non-nuclear power plants.
In July 1997, we reached an agreement with our field service union that requires the buyer of our fossil generating assets to recognize and continue to honor the provisions of the union's current collective bargaining agreement through the end of its term, May 2000. As part of a package offered to employees affected by the fossil divestiture, all eligible fossil and designated fossil support employees age 55 or older with at least 10 years of service, or age 65 by July 1, 1998, were offered unreduced retirement and transition benefits under a voluntary early retirement program (VERP).
Under this program, 40 people elected to retire.
Retirement dates are expected to be the first of the month following the transfer of ownership of our fossil generating assets.
Severance programs were offered to management and field service union employees affected by the fossil divestiture that did not elect or were ineligible to retire under the VERP.
These severance benefits include salary payments, education / retraining allowances and outplacement services.
It is anticipated that 48 employees will receive severance benefits under these programs.
1 32
)
The estimated costs associated with the VERP and severance programs is approximately $21 ndllion including the ef fects on the retirement, life and dental plans.
Severance and employee retraining costs related to the divestiture are recoverable through the distribution transition charge under our settlement agreement.
Therefore, we have established an offsetting regulatory asset for these obligations on our consolidated balance sheet at December 31, 1997.
3.
Nuclear Asset Zapsizment As part of the settlement agreement, we recover our net investment in Pilgrim Station as of December 31, 1995 (adjusted for depreciation through 1997; through the distribution transition charge. Under the terms of the settlement agreement, we must perform a market valuation of Pilgrim by 2002. Upon acceptance of the valuation by the DTE, the resulting dollar amount, net of prudently incurred post-1995 investments in the plant, will reduce amounts collectible through the transition charge.
If the valuation is not sufficient to allow for the recovery of these investments, we will seek their recovery through the transition charge.
Due to the market pressures facing us, the ultimate recovery of these assets is not certain. Therefore, we reduced our investment in Pilgrim by the $13 million invested in the plant since Jcnuary 1, 1996 as an impairment loss under Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of (SEAS 121). An after tax charge of approximately $8 million due to this reduction was recorded to non-operating expense on our consolidated statement of income in the fourth quarter of 1997.
A similar uncertainty does not exist for the ultimate recovery of the fossil generating assets as the sale proceeds agreed to in the purchase and sale agreement with Sithe Energies exceeds the net book value of these assets.
Note D.
Income Tas,s 4
Income taxes are accounted for in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (S EAS 109 ).
SEAS 109 requires the recognition of deferred tax assets and liabilities for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities.
In accordance with SEAS 109 we recorded net regulatory assets of $51.1 million and $47.5 million and corresponding net increases in accumulated deferred income taxes as of December 31, 1997, and December 31, 1996, respectively. The regulatory assets represent the additional future revenues to be collected from customers for deferred income taxes.
Accumulated deferred income taxes consisted of the following:
December 31, (in thousands) 1997 1996 l
Deferred tax liabilities:
1 l-Plant-related
$535,460
$532,390 Other 79,930 95,642 615,390 628,032 l
Deferred tax assets:
Plant-related 11,926 8,406 l
Investment tax credits 33,125 38,005 Other 84,601 82,903 129,652 129,314 l
Net accumulated deferred income taxes
$485.738
$498,718 1
33
)
l l
o______________.________________._____.___
.________________....__________________._______._____.____o
No valuation allowances for deferred tax assets are deemed necessary.
Previously deferred investment tax credits are amortized over the estimated lives of the property giving rise to the credits.
Components of income tax expense were as follows:
years ended December 31, (in thousands) 1997 1996 1995 Current income tax expense
$116,685
$92,760
$93,469 Deferred income tax expense (14,104) 14 (21,115)
Investment tax credit amortization (7,560)
(4,071)
(4,078)
Income taxes charged to operations 95,021 68,703 68,276 Taxes on other income Current (12,566)
(721)
(1,729)
Total income tax expense S 82,455
$87,982
$66,547 The effective income tax rates reflected in the consolidated financial statements and the reasons for their differences from the statutory federal income tax rate were as follows:
1997 1996 1995 Statutory tax rate 35.0t 35.0%
35.0%
State income tax, net of federal income tax benefit 4.5 4.3 4.3 Investment tax credit amortization (3.3)
(1.8)
(2.3)
Other 0.1 0.7 0.1 Effective tax rate 36.3%
38.2%
37.1% >
The 1997 effective tax rate declined by 0.8% as a result of the favorable outcome of an Internal Revenue Service appeal related to investment tax credits.
Note E. Nuclear Decommissioning and Nuclear Waste Disposal 2.
Nuclear Decommissioning When Pilgrim Station's operating license expires in 2012 we will be required to decommission the plant.
Decommissioning means to remove nuclear facilities from service safely and reduce residual radioactivity to a level that permits termination of the Nuclear Regulatory Commission (NRC) license and release of the property for unrestricted use.
We record an estimate of decommissioning costs in depreciation expense on the consolidated statements of income over Pilgrim's expected service life.
Decommissioning expense is approximately $14 million~per year. The estimate used to determine our annual expense is basai on a 1991 study that documents a cost of approximately $328 million to decommission the plant using the " green field" method, which provides for the plant site to be completely restored to its original state.
The cost estimate was incorporated in our 1992 retail settlement agreement. We receive recovery of the annual expense through charges to our retail customers and from other utility companies and municipalities which purchase a contracted amount of Pilgrim's electric generation. The funds we collect from deconadssioning charges are deposited in an external trust and are restricted to use for decomndssioning and related expenses. The net earnings on the trust funds, which are also restricted, increase the nuclear decommissioning trust balance, thus reducing the amount to be collected from customers.
The 1991 decommissioning study was partially updated for internal planning purposes in order to evaluate the potential impact of Irng-term spent fuel storage options resulting from delays in the United States Department of 34
b 4
Energy (DOE) spent fuel removal program.
Refer to part 2 for a discussion of spent fuel removal. The partial update indicated an estinated decommissioning cost of $400 millien in 1991 dollars based upon a revised spent fuel removal schedule and utilization of dry spent fuel storage technology.
We are in the process of updating this study. No final cost estimate is currently available; however, we continue to monitor DOE spent fuel removal schedules
]
and developments in spent fuel storage technology along with their impact on the decommissioning estimate.
Certain financial reporting considerations related to nuclear decommissioning costs have not been fully resolved.
In 1996 the Financial Accounting Standards Board (EASB) issued proposed new rules for accounting for liabilities related to closure and removal of long-lived assets, which include decommissioning of nuclear generating facilities.
If these proposed rules are adopted we would be required to retroactively recognize the entire estimated liability for decommissioning costs on the balance sheet, offset by an addition to utility plant. The plant addition would be depreciated over Pilgrim's remaining expected service life. The liability would be measured based on the present value of estimated future cash flows. The cumulative effect of adoption of these prcposed rules could result in the recognition of a regulatory asset to be recovered from Oustomers to the extent that the present value difference in the liabildcy between when the liability was incurred and when the rules are adoptod exceeds the depreciation expense previously recognized for decommissioning.
In addition, trust fund earnings would be reported on the income sta'ement.
The EASB recently resumed its deliberations on this project. No date has been set for the issuance of either a final statement or revised proposed rules.
l l
2.
Spent Nuclear Duel l
The spent fuel storage facility at Pilgrim Station is expected to provide storage capacity through approximately 2003. We have a license amendment from the NRC to modify the facility to provide sufficient room for spent nuclear fuel generated through the end of Pilgrim's operating license in 2012; however, any fur ther modifications are subject to review by the DTE.
We are actively exploring the feasibility of other spent fuel storage facilities and technologies.
Delays in identifying a permanent storage site have continually postponed plans for the DOE's long-term storage and disposal site for spent nuclear fuel.
The DOE's current estimate for an available site is 2010.
In November 1997, the U.S.
Court of Appeals for the District of Columbia Circuit ruled that the lack of an interim storage facility does not excuse the DOE from j
meeting its contract obligation to begin accepting spent nuclear fuel no later than January 31, 1998. This decision was in response to petitions filed by us and other interested parties seeking declaratory rulings concerning enforcement and remedies for the DOE's f ailure to accept spent fuel in a timely manner. The court directed the plaintiffs to pursue relief under terms of their contracts with the DOE.
Based on this ruling, the DOE may ha ve to pay contract damages if it does not take the spent nuclear fuel as scheduled.
l l
Under the Nuclear Waste Policy Act of 1982, it is the ultimate responsibility of the DOE to permanently dispose of spent nuclear fuel.
We currently pay a i
fee of $1.00 per net megawatthour sold from Pilgrim Station generation under a nuclear fuel disposal contract with the DOE.
The fee is collected from customers through fuel charges. We cannot predict at this time whether or on what schedule the DOE will eventually construct a spent fuel repository or what the effect will be of any delays in such construction.
35
4 The DOE recently denied our petition to auspend payments made to the Nuclear Waste Fund based on its interpretation of the U.S. Court of Appeal's decision made in November 1997. The DOE has, however, made an offer to consider amendments to existing contracts to address the hardships the anticipated delay in accepting spent fuel may cause individual contract holders. We continue to monitor this situation and consult with legal counsel as to our next course of action.
3.
Low-Level Radioactive Waste We regained access to low-level radioactive waste (LLW) disposal facilities located in Barnwell, South Carolina, in 1995. This site is currently the only disposal facility available to us.
Legislation has been enacted in Massachusetts establishing a regulatory process for managing LLW, including the possible siting, licensing and construction of a disposal facility within the state, or, alternatively, an agreement with one or more other states.
Pending the construction of a disposal facility within the state or the adoption by th'e state of some other LLW management procedure, we will continue to monitor the situation and investigate other available options.
Note F.
1995 Corporate Restructuring In 1995 we streamlined the corporate organization and reorganized the company into separate business units in order to strengthen our competitiveness in the changing electric energy market. In conjunction with this reorganization we offered enhanced retirement programs and implemented a special severance program to reduce employee staffing levels. Under the enhanced retirement programs 330 employees elected to retire, and 149 employeea whose rosi* ions were eliminated became eligible for benefita under the speciar severance program. These programs resulted in a $34 ndllion pre-tax chat:9 ($20.7 million after tax) over the third and fourth quarters of 1995. The charge consisted of $24 million for the retirement programs and $10 ndllion for the severance program.
Note G.' Pensions and other Postratirement Benefits 2.
Pensions We have a defined benefit funded retirement plan with certain contributory features that covers substantially all employees.
Benefits are based upon an employee's years of service and highest eligible average compensation during the last ten years of credited employment. Our funding policy is to contribute an amount each year that is not less than the minimum required contribution under federal law or greater than the maximum tax deductible amount. The retirement plan assets consist of equities, bonds, money market funds, insurance contrhets and real estate funds.
We also have an unfunded supplemental retirement plan for certain management employees.
Benefits under this plan are based upon an employee's years of service and highest eligible average compensation during years of credited employment.
36
l l
Ilet pension cost consisted of the following components:
l I
years ended December 31, (in thousands) 1997 1996 1995 Current service cost - benefits earned
$12,625
$13,452
$11,339 Interest cost on projected benefit obligation 31,537 32,325 31,789 Actual return on plan assets (60,602)
(40,335)
(72,192) l tiet amortization and deferral 33,912 17,064 49,557 l
11e t r>ension cost
$17,472
$22,506
$20,493 In accordance with our 1992 retail rate settlement agreement we deferred the difference between the net pension cost of the retirement plan and its annual funding amount through 1995.
! Jet pension cost recognized in 1995 was $28 million.
We experienced a high number of employee retirements from 1994 to 1996. A large number of these retirements were as a direct result of our 1995 corporate restructuring.
In 1997, a review of the accounting for the pension expense related to the retirements revealed that an adjustment to the pension costs related to these employees was necessary.
Therefore, we increased our pension regulatory asset by $8.6 million in 1997 for the adjustment related to the period of our 1992 settlement agreement. The remaining adjustment did not have a material impact on our consolidated results of operations or financial pcsition.
We used the following assumptions for calculating pension cost:
1997 1996 1995 Discount rate 7.75%
7.25t 8.25%
Expected long-term rate of return on assets 10.00%
10.00%
10.00t compensation increase rate 3.90%
3.904 3.90%
l 1
l l
l 1
1 I
I i
i l
37
The plans' funded status were as follows:
December 31, (in thousands) 1997 1996 Supplemental Supplemental Retirement Retirement Retirement Retirement Plan Plan Plan Plan Actuarial present value of accumulated benefit obligation:
Vested
$361,484
$ 8,571
$316,101
$ 7,576 Non-vested 10,578 1,192 10,867 943 Total
$372,062 9,763
$326,968 8,519 Plan assets at fair value
$401,182 0
$331,299 0
Projected obligation for service rendered to date (446,360)
(11,076)
(400,561)
(9,199)
Projected benefit obligation in excess of plan assets (45,178)
(11,076)
(69,262)
(9,199)
Unrecognized prior service cost 9,385 9,736 11,238 9,436 Unrecognized net loss /(gain) 50,673 (27) 78,853 (1,141)
Unrecognized net obligation 5,704 0
7,130 0
Additional minimum liability (a) 0 (8,396) 0 (7,615)
Net pension prepayment /
(Idability) (b)
$ 20,584
$ (9,763)
$ 27,959
$ (8,519)
(a)
Statement of Financial Accounting Standards No. 87, Employers' Accounting for Pensions (SEAS 87), requires the recognition of an additional minimum liability for the excess of accumulated benefits over the fair value of plan assets and accrued pension costs.
In accordance with SEAS 87 we recorded additional minimum liabilities and corresponding intangible assets of $8.4 million and $7.6 million on our consolidated balance sheets at December 31, 1997 and 1996, respectively.
1 (b)
The prepaid pension amount at December 31, 1997 reflects the impact of
$8 million related to the fossil workforce reduction as discussed in Note C to these Consolidated Financial Statements.
We used the following assumptions for calculating the plans' year-end funded status:
1997 1996 Discount rate 7.25s 7.75%
compensation increase rate 4.25%
3.90E We also provide defined contribution 401(k) plans for substantially all of our employees. We match a portion of employees' voluntary contributions to the plans. We made matching contributions of $8 million in 1997 and 1996 and $9 million in 1995.
2.
Other Postretirement Benefits In addition to pension benefits, we also provide health care and other benefits to our retired employees who meet certain age and years of service eligibility requirements. These postretirement benefits other than pensions (PBOPs) are accounted for in accordance with Statement of Financial Accounting 38
Standards No. 106, Employers' Accounting for Postretirement Benefits Other Than' Pensions (SEAS 106).
Our 1992 retail rate settlement agreement provided L
us with a phase-in to full expense of the PBOP costs incurred under SEAS 106.
This~ settlement agreement allowed us to defer any costs in excess of the specified phase-in amounts to the extent that we funded an external trust.
Our funding policy is to generally contribute 100% of PBOP costs to external trusts. Therefore, we recognized $23 adllion of PBOP costs in 1995 in accordance with the 1992 settlement agreement.
Beginning in 1996 we recognized the full PBOP costs incurred under SEAS 106.
The net deferred PBOP costs of S15 million resulting from the delayed phase-in are included in regulatory assets as these costs will be recovered from customers in future periods.
Net postretirement benefits cost consisted of the following components:
years ended December 31, (in thousands) 1997 1996 1995 Current service cost - benefits earned S 3,543
$ 4,616
$ 3,408 Interest cost on accumulated benefit obligation 17,006 16,815 13,521 Actual return on plan assets (18,852)
(9,584)
(7,151)
Amortization of transition obligation 9,151 9,151 9,151 Net other amortization and deferral 12,417 5,209 3,017 Net postretirement benefits cost
$23,265
$26,207
$21,946 We used the following assumptions for calculating postretirement benefits cost y
1997 1996 1995 Discount rate 7.75V 7.254 8.25%
Expected long-term rate of return on assets 9.00%
9.00e 9.00%
Health care cost trend rate 6.00%
7.001 7.00%
The health care cost trend rate is assumed to decrease by 1% in 1998 and to remain at 5% in years thereafter.
Changes in the health care cost trend rate will affect our cost and obligation amounts. A 1% increase in the assumed health care cost trend rate would increase the total service and interest cost components by 7.4% and would increase the accumulated benefit obligation at December 31, 1997 by 6.6%.
l 39
The PBOP program's funded statua was as follows:
December 31, (in thousands) 1997 1996 Trust assets at fair value S 103,989
$ 72,702 Accumulated obligation for service rendered to date from:
Retirees S(166,035)
$(156,694)
Active employees eligible to retire (16,484)
(12,644)
Active employees not eligible to retire (55,097)
(237,616) (61,567) (230,905)
Accumulated benefit obligation in excess of trust assets (133,627)
(158,203)
Unrecognized prior service cost (14,128)
(16,274) j Unrecognized net loss 12,916 26,663 I
Unrecognized transition obligation 127,107 146,413 Net postretirement benefits j
liability Fa )
S (7,732)
(1,401)
(a)
The postretirement benefits liability at December 31, 1997 reflects an S8 ndllion additional PBOP obligation related to the f ossil workforce -
reduction as discussed in Note C to these consolidated Financial l
Statements.
The keighted ave _ age discount rates used to measure the program's year-end funded status were 7.25% in 1997 and 7.75% in 1996. The trust assets consist of equities, bonds and money market funds.
Note E.
Stock-Based Compensation i
In 1997, we initiated a Stock Incentive Plan (the Plan) which was adopted by the Board of Directors and approved by our stockholders.
The Plan permits a variety of stock and stock-based awards, including stock options and deferred (nonvested) stock to be granted to certain key employees.
The Plan limits the terns of awards to ten years. Subject to adjustment for stock-splits and similar events, the aggregate number of shares of common stock that may be delivered under the Plan is 2,000,000, including shares issued in lieu of or upon reinvestment of dividends arising from awards.
During 1997, we granted 73,820 shares of deferred. stock and 298,400 ten-year non-qualified stock options under the Plan. The weighted average grant date fair value of the deferred stock is $27.26.
The optiore were granted at the full market price of the stock on the date of the grant.
Both awards vest ratably over a three-year period.
We recognize compensation cost for our stock-based awards under the provisions of APB Opinion 25, which requires compensation cost to be measured by the quoted stock market price at the measurement date less the amount, if any, an employee is required to pay. The required fair value method disclosures related to our stock-based compensation are as follows:
'(in thousands, except per share amounts) 1997 Net income Actual
$144,642 Pro forma
$144,572 Earnings per share
-Actual
$2.71 Pro forma
$2.71 40
Stock option activity of the Plan was as follows:
Options outstanding at January 1, 1997 0
options granted 298,400 Options forfeited (25,400)
Options outstanding at December 31, 1997 273,000 Summarized information regarding stock options outstanding at December 31, 1997:
Weighted Range of Average Remaining Weighted Average Exercise Prices Contractual Life (Years)
Exercise Price i
1 l
$25.75-$26.00 9.44
$25.84 l
No stock options were exercisable at December 31, 1997.
l The stock options were granted with a weighted average grant date fair value of $2.22.
The fair value was estimated using the Black-Scholes option pricing model with the following weighted average assumptions:
Expected life (years) 4.0 Risk-free interest rate 6.44b Volatility 16%
Dividends 7.28%
Compensation cost recognized in income for our stock-based compensation awards in 1997 was $275,000.
1 41 1
s.
Note I. Capital Stcis December 31, (dollars in thousands, except per share amounts) 1997 1996 Correnon stock equity:
Common stock, par value $1 per share, 100,000,000 shares authorized; 48,514,973 and 48,509,537 shares issued and outstanding:
48,515 $
48,510 Premium on common stock 696,137 695,723 Retained earnings 328,802 292,191 Total common stock couity
$1,073,454
$1,036,424 Dividends declared per share of common stock were $1.88 in 1997 and 1996 and
$1.835 in 1995.
Cumulative preferred stock:
Par value $100 per share, 2,890,000 shares authorized; issued and outstanding:
Nonmandatory redeemable series:
Current Shares Redemption Series Outstanding Price / Share 4.25b 180,000
$103.625 18,000 S 18,000 4.78%
250,000
$102.800 25,000 25,000 40,000 40,000 7.75%
400,000 0
40,000 8.25%
83,000 123,000 Less redemption and issuance costs 0
(3,046)
Total nonmandatory redeemable s e ri e s 83,000 119,954 Mandatory redeemable seriest Current Shares Redemption Series Outstanding Price / Share 7.27%
360,000
$102.420 36,000 $
40,000 8.00%
500,000 50,000 50,000 86,000 90,000 Less redemption and issuance costs (5,907)
(6,535) due within one year (2,000)
(2,000)
Total mandatory redeemable series S
78,093 81,465 1.
Ccaimon Stock l
Common stock issuances in 1995 through 1997 were as follows:
Number Total Premium on (in thousands) of Shares Par Value Common Stock Balance at December 31, 1994 45,535
$45,535
$622,803 Dividend reinvestment plan 468 468 11,404 New issuances 2,000 2,000 49,479 Balance at December 31, 1995 48,003 48,003 683,686 Dividend reinvestment plan 507 007 12,037 Balance at December 31, 1996 48,510 48,510 695,723 Dividend reinvestment plan 5
5 414 Balance at December 31, 1997 48,515 S48,515
$696,137 42
2.
Cuanslative Handatozy Redeemable Preferred Stock The'360,000 shares of 7.27% sinking fund series cumulative preferred stock are i
currently redeemable at our option at $102.420. The redemption price declines I
annually each May to par value in May 2002. The stock is subject to a mandatory sinking fund requirement of 20,000 shares each May at par plus accrued dividends. We also have the noncumulative option each May to redeem i
additional shares, not to exceed 20,000, through the sinking fund at $100 per l
share plus accrued dividends. We redeemed, at par value, 40,000 shares in 1997 and 1996 and 20,000 shares in 1995.
We are not able to redeem any part of the 500,000 shares of 84 series cumulative preferred stock prior to December 2001. The entire series is subject to mandatory redemption in December 2001 at $100 per share plus accrued dividends.
Note J.
Indebtedness I
December 31, (in thousands) 1997 1996 i
Long-term debt:
Debentures:
5.700%, due March 1997 0
S 100,000 5.950%, due March 1998 100,000 100,000 6.800%, due February 2000 65,000 65,000 6.050%, due August 2000 100,000 100,000 6.800%, due March 2003 150,000 150,000 7.800%, due May 2010 125,000 125,000 9.875%, due June 2020 100,000 100,000 9.375%, due August 2021 115,000 115,000 8.250%, due September 2022 60,000 60,000 7.800%, due March 2023 200,000 200,000 Total debentures 1,015,000 1,115,000 Less:
due within one year (200,000)
(100,000)
Net long-term debentures 915,000 1,015,000 Sewage facility revenue bonds 32,500 34,100 Less: due within one year (667)
(667)
Less: funds held by trustee (4,757)
(4,789)
Net long-term sewage facility revenue bonds 27,076 28,644 Massachusetts Industrial Finance Agency bonds:
5.750%, due February 2014 15,000 15,000
)
6.662% bank loan, due 1999 100,000 0
j Total lono-term debt
$3,057,076 S3,058,644 Short-term debt:
Notes payable:
Bank loar.s S
94,013
$ 129,631 Commercial paper 43,000 71,823 Total notes payable S
137,013 201,454 l
43
2.
Longr-tem Debt The 9 7/8% debentures due 2020 are first redeemable in June 2000 at a redemption price of. 104.483%, the 9 3/8% series due 2021 are first redeemable in August 2001 at 104.612%, the 8.25% series due 2022 are first redeemable in-Septenber 2002 at 103.780% and the 7.80% series due 2023 are first redeemable in March 2003 at 103.730%. No other series are redeemable prior to maturity.
There is no sinking fund requirement for any series of our debentures.
Sewage facility revenue bonds were issued by HEEC.
The bonds are tax-exempt, subject to annual mandatory sinking fund redemption requirements and mature through 2015.
In both May 1996 and 1997, we redeemed $1.6 million as scheduled.
The weighted average interest rate of the bonds is 7.3%.
A portion of the proceeds from the bonds is in reserve with the trustee.
If HEEC should have insufficient funds to pay for extraordinary expenses, we would be required to make additional capital contributions or loans to the subsidiary up to a maximum of $1 ndllion.
The 5.75% tax-exempt unsecured bonds due 2014 are redeemable beginning in February 2004 at a redemption price of 102%.
The redemption price decreases to 101% in February 2005 and to par in February 2006.
In March 1997, we obtained $100 million of 6.662% notes in the form of a bank loan. This note matures in 1999.
The aggregate principal amounts of our long-term debt (including HEEC sinking fund requirements) due through 2002 are $101.6 million in 1998 and 1999,
$166.6 million in 2000 and $1.6 million in 2001 and 2002.
2.
Short-tem Debt We have. arrangements with certain banks to provide short-term credit on both a committed and an uncommitted and as available basis.
We currently have
. regulatory authority to issue up to $350 million of short-term debt.
We have a $200 million revolving credit agreement with a group of banks. This agreement is intended to provide a standby source of short-term borrowings.
Under the terms of this agreement we are required to maintain a common equity ratio of not less than 30% at all times.
Commitment fees must be paid on the unused portion of the total agreement amount.
Information regarding our utility short-term borrewings, comprised of bank leans and commercial paper, is as follows:
(dollars in thousands) 1997 1996 1995 Maximum short-term borrowings
$316,100 $272,500 $327,769 Weighted average amount outstanding
$212,663 $208,914 $165,720 Weighted average interest rates excluding commitment fees 5.85%
5.65%
6.21%
In addition, at. December 31, 1997, BETG had $7.5 ndllion outstanding under a revolving credit agreement.
44
Note K. Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each class of securities for which it is practicable to estinate the value:
Nuclear decommissioning trust:
The cost of $151.6 million approximates f air value based on quoted narket prices of securities held.
Cash and cash equivalents:
The carrying amount of $4.1 million approximates fair value due to the short-tarm nature of these securities.
Mandatory redeemable cumulative preferred stock, sewage facility revenue bonds and unsecured debt:
The fair values of these securities are based upon the quoted market prices of similar issues.
Carrying amounts and fair values as of December 31, 1997, are as follows:
Carrying Fair (in thousands)
Amount Value Mandatory redeemable cumulative preferred stock 80,093 $
91,720 Sewage facility revenue bonds S
32,500 $
35,084 Unsecured debt
$1,030,000 $1,073,982 Note L. Commitments and Contingencies 1.
Contractual Comunitments At December 31, 1997, we had estimated contractual obligations for plant and equipment of approximately $18 million.
We have leases for certain_ facilities and equipment.
Our estimated minimum rental commitments under both transmission agreements and noncancellable leases for the years after 1997 are as follows:
(in thousands) 1998
$ 21,938 1999 18,958
'2000 16,738 2001 12,356 2002 11,194 I
Years thereafter 91,874 1
Total
$173,058 j
Amounts above include $2.7 million which is expected to be assumed by Sithe Energies as part of our pending fossil divestiture discussed in Note C to these Consolidated Financial Statements.
The total of future minimum rental income to be received under noncancellable subleases.related to the above leases is $300,921.
We will capitalize a portion of these lease rentals as part of plant I-expenditures in tne. future. The total expense for both lease rentals and transmission agreements was $27.5 million in 1997, $26.3 million in 1996 and 1
l' 45
$24.5 million in 1995, net of capitalized expenses of $1.2 million in 1997,
$2.9 ndllion in 1996 and $2.7 ndllion in 1995.
We previously entered into various take or pay and throughput agreements, primarily to supply our New Boston fossil generating station with natural gas.
The fixed and determinable portions of the obligations associated with these agreements are $19.5 million in 1998 and 1999 and $14.6 million in 2000. As part of our fossil divestiture agreement, Sithe Energies has agreed to assume these obligations. The total expense under these agreements was $47.1 million
{
in 1997, $49.5 million in 1996 and $13.9 million in 1995.
2.
Electric Conpany Investments We have an approximately 11% equity investment in two companies which own and operate transmission f acilities to import electricity f rom the Hydro-Quebec system in Canada. As an equity participant we are required to guarantee, in addition to our own share, the total obligations of those participants who do not meet certain credit criteria. At December 31, 1997, our portion of these guarantees was $16.6 million.
We have a 9.5% equity investment of approximately $2 million in Yankee Atomic Electric Company (Yankee Atomic).
In 1992 the board of directors of Yankee Atomic decided to discontinue operations of the Yankee Atomic nuclear generating station permanently and deconadssion the f acility.
Yankee Atomic received approval from the FERC to continue to collect its investment and decommissioning costs through 2000, the period of the plant's operating license. The estimate of our share of Yankee Atomic's investment and costs of deconadssioning is approximately $13 million as of December 31, 1997.
This estimate is recorded on our consolidated balance sheet as a power contract liability and an offsetting regulatory asset.
We also have a 9.5% equity investment in Connecticut Yankee Atomic Power Company (CYAPC) of approximately $11 million.
In December 1996, the board of directors of CYAPC, which owns and cperates the Connecticut Yankee nuclear electric generating unit (Connecticut Yankee), unanimously voted to retire the unit.
The decision was based on an economic analysis of the costs of operating the unit through 2007, the period of its operating license, compared to the costs of closing the unit and incurring replacement power costs for the same period.
The current estimate of the sum of future payments for the closing, decommissioning and recovery of the remaining investment in Connecticut Yankee is approximately $615 million.
Our share of these remaining estimated costs is $58 million.
This estimate is recorded on our consolidated balance sheet as a power contract liability and an offsetting regulatory asset similar to Yankee Atomic.
In early 1997, CYAPC filed a rate case at the FERC seeking to recover certain post-operating costs, including decommissioning. The Connecticut Department of Public Utility Control (DPUC) has raised concerns to the FERC regarding CYAPC's estimate of these costs and the plant operator's prudency prior to the shutdown decision. The FERC set CYAPC's request for hearing before an Administrative Law Judge. The DPUC subsequently filed testimony in the proceeding asserting the position that the FERC should deny recovery of substantial post-operating costs, including a significant amount related to decommissioning and the return on CYAPC's undepreciated investment. We are currently unable to determine the ultimate outcome of this proceeding or its impact.
46
i
.o J.
Nuclear Insurance The federal Price-Anderson Act currently provides $8.9 billion of financial protection for public liability clains and legal costs arising from a single nuclear-related accident.
The first $200 million of nuclear liability is covered by commercial insurance. Additional nuclear liability insurance up to
$8.7 billion is provided by a retrospective assessment of up to $79.3 million per incident levied on each of the 110 nuclear generating units currently licensed to operate in the United States, with a maximum assessment of $10 million per' reactor per accident in any year.
- We have purchased insurance from Nuclear Electric Insurance Limited (NEIL) to cover some of the costs to purchase replacement power during a prolonged accidental outage and the cost of repair, replacement, decontamination or decenudssioning of our utility property resulting from covered incidents at Pilgrim Station.
Our maximum potential total assessment for losses which occur during current policy years is $10.4 ndllion under both the replacement power and excess property damage, decontamination and decommissioning policies.
4.
Hazardous Wasta We are an owner or operator of approximately 30 properties where oil or hazardous materials were spilled or released. As such, we are required to clean up these properties in accordance with a timetable developed by the Massachusetts Department of Environmental Protection. We continue to evaluate the costs associated with site cleanup. There are uncertainties associated with these costs due to the complexities of cleanup technology, regulatory requirements and the particular characteristics of the different sites. We also continue to face possible liability as a potentially responsible party in the cleanup of six multi-party hazardous waste sites in Massachusetts and other states where we are alleged to have generated, transported or disposed of hazardous waste at the. sites. We are one of many potentially responsible parties and currently expect to have only a small percentage of the potential liability. Through December 31, 1997, we have accrued approximately $7 million related to our cleanup liabilities. We are unable to fully determine a range of reasonably possible cleanup costs in excess of the accrued amount, although based on our assessments of the specific site circumstances, we do l
not believe that it is probable that any such additional costs will have a material impact on our financial condition.
However, it is reasonably possible that additional provisions for cleanup costs that nay result from a change in estimates could have a material impact on the results of a reporting period in the near term.
5.
Generating Unit Perfo2xnance Program our recovery of the incremental purchased power costs resulting from outages at our generating units occurring through the retail access date is subject to review by the DTE.
We are unable to fully determine a range of reasonably possible disallowance costs in excess of amounts accrued, although, based on the information currently available, we do not believe that it is probable that any such additional costs will have a material impact on our financial condition.
However, it is reasonably possible that additional disallowance costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term.
I l
47 I
o.
6.
Litigation In October 1997, the DTE opened a proceeding to investigate our compliance with the 1993 order which permitted the formation of BETG and authorized us to invest up to $45 ndllion in unregulated activities.
We are unable to determine the ultimate outcome of this proceeding or its impact on our operations.
In the normal course of our business we are involved in certain other legal matters.
We are unable to fully determine a range of reasonably possible litigation costs in excess of amounts accrued, although, based on the information currently available, we do not believe that it is probable that any such additional costs will have a material impact on our financial condition.
However, it is reasonably possible that additional litigation costs that may result from a change in estimates could have a material impact on the results of a reporting period in the near term.
1.
Industzy Restructuring Legal Proceedings / Referendum Campaign The DTE order approving our settlement agreement has been appealed by certain parties to the Massachusetts Supreme Judicial Court.
In addition, along with other Massachusetts investor-owned utilities, we have been named as a defendant in a class action suit seeking to declare certain provisions of the Massachusetts electric industry restructuring legislation unconstitutional.
We are currently unable to determine the outcome of these proceedings er their impact on us.
Opponents of the electric industry restructuring leg.slation that was enacted d
in November 1997 have mounted a referendum campaign to repeal that law.
A coalition of business, industry and public interest groups that supported the legislation, along with the electric utility industry, is opposed to the referendum and is prepared to mount an aggressive campaign to defeat it.
We are currently unable to predict the eventual outcome of this referendum or its impact on us.
l 48
Note M.
Long-Term Power Contracts 1.
Long-Term Contracts for the Purchase of Electricity I
We purchase electric power under several long-term contracts for which we pay share of a generating unit's capital and fixed operating costs through the a
contract expiration date.
The total cost of these contracts is included in purchased power expense on our consolidated income statements.
Information relating to these contracts as of December 31, 1997, is as follows:
proportionate share (in thousands)
Units of Debt Contract Capacity Minimum Outstanding
)
Expiration Purchased Debt Through Cont.
Annual i
Generating Unit Date t
MW Service Exp. Date Cost Canal Unit 1 2002 25.0 141 $ 1,475 5 5,172 S 28,997 Mass. Bay Trans-portation Authority - 1 2005 100.0 34 2,166 Ocean State Power -
Unit 1 2010 23.5 72 4,256 17,962 21,778 Ocean State Power -
Unit 2 2011 23.5 72 3,592 15,951 23,969 Northeast Energy I
Associates (b)
(b) 219 134,023 L' Energia (c) 2013 73.0 63 21,902 MassPower 2013 44.3 117 11,227 70,560 54,215 Mass. Bay Trans-portation l
Authority - 2 2019 100.0 34 577 Total 752 $20,550
$109,745
$287,627 (a)
The Northeast Energy Associates contract represents 6.54 of our total system generation capability. The remaining units listed above represent approximately 16% in total.
(b)
We purchase 75.5% of the energy output of this unit under two contracts.
One contract represents 135MW and expires in the year 2015.
The other contract is for 84MW and expires in 2010.
We pay for this energy based 1
on a price per kWh actually received. We do not pay a proportionate share of the unit's capital and fixed operating costs.
(c)
We pay for this energy based on a price per kWh actually received.
Our total fixed and variable costs associated with these contracts in 1997, 1996 and 1995 were approximately $288 ndllion, $281 ndllion and $262 ndllion, respectively.
Our ndnimum fixed payments under these contracts for the years after 1997 are as follows:
(in thousands) 1998 88,406 1999 88,501 2000 89,853 2001 90,365 2002 92,768 Years thereafter 959,981 i
Total
$1,409,874 Total present value S
783,975 49 L______
Under our settlement agreemant, by July 1998 we are required to file a plan with the DTE describing the actions we intend to take to sell, assign or otherwise dispose of our purchased power contracts.
2.
Long-Tenn Power Sales Contracts In addition to other wholesale power sales, we sell a percentage of Pilgrim Station's output to other utilities and municipalities under long-term contracts.
Information relating to these contracts is as f ollc ws :
Contract Expiration Units of Capacity Sold Contract Customer Date V
Mvi-Commonwealth Electric Company 2012 11.0 73.7 Montaup Electric Company 2012 11.0 73.7 Various municipalities 2000(a) 3.7 25.0 Total 25.7 172.4 (a)
Subject to certain adjustments.
Under these contracts, the utilities and municipalities pay their proportionate share of the costs of operating Pilgrim Station and associated transmission facilities.
These costs include operation and maintenance expenses, insurance, local taxes, depreciation, decommissioning and a return on investment.
50
+
j I
selected consolidated Quarterly Financial Data (Unaudited)
(in thousands, except earnings per share)
Earnings Available Earnings Opersting Operating Net for Common Per Average Revenues Income Income Shareholders common Share"'
1997 First quarter
$422,725
$ 47,589
$20,935
$17,118
$0.35 Second quarter 426,735 60,487 33,978 30,484 0.63 7hird quarter 519,513 108,060 81,418 78,499 1.62 Fourth quarter 407,260 44,714 8,311 5,392 0.11 1996 First quartsr * $387,849
$ 52,093
$25,203
$21,313
$0.44 Second quartst 389,756 55,232 27,926 24,086 0.50 Third quarter 497,968 105,353 80,011 76,194 1.58 Fourth quarter 390,730 35,252 8,406 4,588 0.09 (a) Based on the weighted average number of common shares outstanding during each quarter.
Trem 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclos are Not applicable.
1 l
51
4 Part III Item 10.
Directors and Executive Officers of the Registrant (a)
Iden' ification of Directors See " Election of Directors - Information about Nominees and Incumbent Directors" on pages 1 through 4 of the definitive proxy statement dated March 31, 1998, incorporated herein by 4.eference.
(b)
Identification of Executive Officers The information required by this' item is included at the end >f Part I of this Form 10-K under the caption Executive Officers of the Registrant.
(c)
Identification of Certain Significant Employees Not applicable.
(d)
Fa$mily Relationships Not applicable.
(e)
Business Experience l
e For information relating to the business experience curing the past five years and other directorships (of companies subject to certain SEC requirements) held by each person nominated to be a director, see " Election of Directors -
.Information about Nominees and Incumbent Directors" on pages 1 through 4 of the definitive proxy statement dated March 31, 1998, incorporated herein by reference.
)
I For information relating to the business experience during the past five years of each person who is an executive officer, see Executive Officers of the
-Registrant in this Form 20-K.
l if)
Involvement in certain Legal Proceedings l
l Not applicable.
{
(g)
Promoters and Control Persons Not applicable.
Item 11.
Executive Compensation See " Executive Compensation" on pages 5 through 12 of the definitive proxy statement dated March 31, 1998, incorporated herein by reference.
52
Item 12.
Security Ownership of Certain Beneficial Owners and Management (a)
Security Ownership of Certain Beneficial Owners To the knowledge of management, no person owns beneficially more than five percent of the outstanding voting securities of the Company.
(b)
Security ownership of Management See " Stock Ownership by Directors and Executive Officers" on pages 4 through 5 of the definitive proxy statement dated March 31, 1998, incorporated herein by reference.
(c)
Changes in control Not applicable.'
Item 13.
Certain Relationships and Related Transactions l
l Not applicable.
l l
l l
1 53
Part IV Item 14.
Exhibits, Financial Statement Schedules and Reports on Form 8-K (a) The following documents are filed as part of this Form 10-K:
1.
Financial Statements:
Page Consolidated Statements of Income for the years ended December 31, 1997, 1996 and 1995 24 Consolidated Statements of Retained Earnings for the years ended December 31, 1997, 1996 and 1995 24
(
I Consolidated Balance Sheets as of December 31, 1997 and 1996 25 consolidated Statements of Cash Flows for the years l
l ended December 31, 1997, 1996 and 1995 26 l
Notes to Consolidated Financial Statements 27 Selected Consolidated Quarterly Financial Data (Unaudited) 51 Report of Independent Accountants 65 2.
Financial Statement Schedules:
1 No financial statement schedules are included as they are either not required l
or not applicable.
l 3.
Exhibits:
Eefer to the exhibits listing beginning on the following page.
l
)
i (b) Reports on Form 8-K:
l l
l A Fonn 8-K dated November 25, 1997, was filed during the fourth quarter of l
1997 disclosing that a Massachusetts electric utility industry restructuring l
l bill was signed into law in November 1997.
In addition, the 8-K announced I
that Sithe Energies, Inc. won the bid to purchase the Company's non-nuclear generating assets.
l l
54
t i
l Exhibit SEC Docket ExhibitJ_
Articles of Incorporation and By-Laws l
Incorporated herein by reference:
3.1 Restated Articles of Organization 3.1 1-2301 Form 10-Q
)
for the quarter ended June 30, 1994 3.2 Boston Edison Company Bylaws 3.1 1-2301 April 19, 1977, as amended Form 10-Q January 22, 1987, January 28, 1988, for the May 24, 1988 and November 22, 1989 quarter ended June 30, 1990 Exhibit 4 Instruments Defining the Rights of Security Holders, Including Indentures Incorporated herein by reference:
4.1 Medium-Team Notes Series A - Indenture 4.1 1-2201 dated September 1, 1988, between Forla 10-Q Boston Edison Company and Bank of for the Montreal Trust Company quarter ended September 30, 1988 4.1.1 First Supplemental Indenture 4.1 1-2301 dated June 1, 1990 to Form 8-K Indenture dated September 1, 1988 dated with Bank of Montreal Trust Company -
June 28, 1990 9 7/8% debentures due June 1, 2020 4.1.2 Indenture of Trust and Agreement among 4.1.26 1-2301 the City of Boston, Massachusetts Form 10-K (acting by and through its Industrial for the Development Financing Authority) and year ended Harbor Electric Energy Company and December 31, Shawmut Bank, N.A.,
as Trustee, dated 1991 November 1, 1991 4.1.3 Votes of the Pricing Committee of the 4.1.27 1-2301 Board of Directors of Boston Edison Form 10-X Company taken August 5, 1991 re for the 9 3/8% debentures due August 15, 2021 year ended December 31, 1991 l
55
o.
1 Exhibit SEC Docket 4.1.4 Revolving Credit Agreement dated 4.1.24 1-2301 February 12, 1993 Form 10-K for the year ended Decenber 31, 1992 4.1.4.1 First Amendment to Revolving Credit 4.1.10 1-2301 Agreement dated May 19, 1995 Form 10-K for the year ended Decenber 31, 1995 4.1.5 Votes of the Pricing Committee of the 4.1.25 1-2301 Board of Directors of Boston Edison Form 10-K Company taken September 10, 1992 re for the 8 1/4% debentures due September 15, 2022 year ended December 31, 1992 4.1.6 Votes of the Pricing Committee of the 4.1.26 1-2301 Board of Directors of Boston Edison Form 10-K Company taken January 27, 1993 re for the 6.80% debentures due February 1, 2000 year ended Decenber 31, 1992 4.1.7 Votes of the Pricing Committee of the 4.1.27 1-2301 Board of Directors of Boston Edison Form 10-K Company taken March 5,1993 re for the 6.80% debentures due March 15, 2003, year ended 7.80% debentures due March 15, 2023 December 31, 1992 4.1.8 Votes of the Pricing Committee of the 4.1.28 1-2301 Board of Directors of Boston Edison Form 10-K Company taken August 18, 1993 re for the 6.05% debentures due August 15, 2000 year ended Decenber 31, 1993 4.1.9 Votes of the Pricing Committee of the 4.1.9 1-2301 Board of Directors of Boston Edison Form 10-K Company taken May 10, 1995 re for the 7.80% debentures due May 15, 2010 year ended December 31, 1995 l
t 56
=
.s Exhibit SEC Docket Filed herewith:
4.1.4.2 Second Amendment to Revolving Credit Agreement dated July 1, 1997 The Company agrees to furnish to the Securities and Exchange Commission, upon request, a copy of any agreements or instruments defining the rights of holders of any long-term debt whose authorization does not exceed 10% of the Company's total assets.
I l
Exhibit SEC Docket Exhibit 10 Material Contracts Incorporated herein by reference:
10.1 Key Executive Benefit Plan 10.3.1 1-2301 Standard Form of Agreement, May Form 10-K 1986, with modifications for the year ended i
December 31, 1991 10.2 Executive Annual Incentive 10.5 1-2301 Compensat.on Plan Form 10-K i
for the y+4r ended December 31, 1986 l
10.2.1 Supplemental Executive Retirement 10.1 1-2301 l
Plan Form 10-Q for the i
quarter ended i
l June 30, 1997 l
10.2.2 1997 Stock Incentive Plan 10.2 1-2301 Form 10-Q for the quarter ended June 30, 1997 10.3 1991 Director Stock Plan 10.1 1-2301 Form 10-Q for the quarter ended March 31, 1991 l
l 57 l
Exhibit SEC Docket 10.4 Directors Retirement Benefit 10.8.1 1-2301 1
(1993 Plan)
Form 10-K for the year ended Decenber 31, 1993 10.5 Boston Edison Company Deferred 10.11 1-2301 Fee Plan dated January 14, 1993 Form 10-K for the year ended December 31, 1992 10.6 Deferred Compensation Trust J0.10 1-2301 between Boston Edison Company Form 10-K and State Street Bank and for the Trust Company dated year ended February 2, 1993 December 31, 1992 10.6.1 Amendment No. 1 to Deferred 10.5.1 1-2301 Compensation Trust dated Form 10-K March 31, 1994 for the year ended Decenber 31, 1994 10.7 Boston Edison Company Deferred 10.9 1-2301 Compensation Plan, Amendment and Form 10-K Restatement dated January 31, 1995 for the year ended December 31, 1994 10.8 Employment Agreement applicable to 10.10 1-2301 Ronald A. Ledgett dated April 30, 1987 Form 10-K for the year ended December 31, 1994 10.9 Retention Agreement applicable to 10.1 1-2301 Ronald A. Ledgett dated May 15, 1996 Form 10-Q for the quarter ended June 30, 1996 58
s Exhibit SEC Docket 10.9.1 Retention Agreement applicable to 10.13 1-2301 Douglas S.
Horan dated May 15, 1996 Form 10-K for the year ended December 31, 1996 10.10 Change in Control Agreement applicable 10.2 1-2301 to Thomas J.
May dated July 8, 1996 Form 10-Q for the quarter ended June 30, 1996 10.11 Form of Change in Control Agreement 10.3 1-2301 applicable to Ronald A. Ledgett, Form 10-Q L. Carl Gustin, Douglas S. Horan, for the James J.
Judge and certain other quarter ended officers dated July 8, 1996 June 30, 1996 Filed herewith:
10.9.2 Retention Agreement applicr*1e to James J. Judge dated May 15, 1996 l
10.12 Boston Edison Company Restructuring Settlement Agreement dated July 1997 59
g.
Enhibit SEC Docket l
Exhibit 12 Statement re Computation of Ratios l
I Filed herewith:
12.1 Computation of Ratio of Earnings 1
l to Fixed Charges for the Year Ended December 31, 1997 12.2 Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements for the Year Ended December 31, 1997 Exhibit 21 Subsidiaries of the Registrant 21.1 Harbor Electric Energy Company (incorporated in Massachusetts, a wholly owned subsidiary of Boston Edison Company 21.2 Boston Energy Technology Sroup, Inc.
(ine:rporated in Massachusetts),
a wholly owned subsidiary of Boston Edison Company 60
f, --
Exhibit SEC Docket l:
Exhibit 23 Consent of Independent Accountants l
Filed herewith:
23.1 Consent lof Independent Accountants to incorporate by reference their opinion included with this Form 10-K in the Form S-3 Registration Statements filed by the company on February 3, 1993 (File No. 33-57840),
1-May 31, 1995 (File No. 33-59693) and in the Form S-8 Registration Statements filed by the Company on October 10, 1985 (File No. 33-00810), July 28, 1986
{ File No. 33-7558), December 31, 1990 (File No. 33-38434), June 5, 1992 (33-48424 and 33-48425), March 17, 9
1993 (33-59662 and 33-59682) and April 6, 1995 (33-58457) and in the Form S-4 Registration Statement filed by Boston Edison Holdings, currently known as BEC Energy, on March 17, 1997 (File No.
333-23439)
Exhibit 27 Financial Data Schedule Filed herewith:
27.1 Schedule UT Exhibit 99' Additional Exhibits Incorporated herein by reference:
99.1 Settlement Agreement between Boston 28.1 1-2301 Edison Company and Commonwealth Form B-K Electric Company, Montaup Electric dated Company and the Municipal December 21, Light Department.of the Town of 1989 Reading, Massachusetts, datee;
-January 5, 1990 99.2' Settlement Agreement Letween Boston 28.2 1-2301
' Edison Company and City of Holyoke Form 10-Q Gas and Electric Department et. al.,
for the dated April 26, 1990 quarter ended March 31, 1990 1
i i
1 61
Exhibit SEC Docket 99.3 Information required by SEC Form 1-2301 11-K for certain Company employee Form 10-K/A benefit plans for the years ended Amendments to December 31, 1996, 1995 and 1994 Form 10-K for the years ended December 31, 1996, 1995 and l
1994 dated June 26,1997, June 27, 1996 and June 29,
- 1995, respectively 62
O SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Ar:t of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
BOSTON EDISON COMPANY By:
/s/ James J. Judge James J.
Judge Senior Vice President and Treasurer (Principal Financial Officer)
Date: March 24, 1998 Pursuant to the requirements of the Securities Exchange Act of 1934 this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 24th day of March 1998.
/s/ Thomas J. May Chairman of the Board, President Thomas J. May and Chief Executive Officer
/s/ Robert J.
Weafer, Jr.
Vice President - Finance, Robert J.
Weafer, Jr.
Controller and Chief Accounting l
Officer
/s/ Gary L.
Countryman Director Gary L.
Countryman
/s/ Thomas G.
Dignan, Jr.
Director Thones G.
Dignan, Jr.
/s/ Richard J.
Egan Director Richard J.
Egan
/s/ Charles K. Gifford Director Charles K.
Gifford
/s/ Nelson S.
Gifford Director Nelson S.
Gifford
/s/ Matina S.
Horner Director Matina S.
Horner 63
l p.
/s/ Sherry H.
Penney Director Sherry H.
Penney
/s/ Herbert Roth, Jr.
Director Herbert Roth, Jr.
/s/ Stephen J.
Sweeney Director Stephen J.
Sweeney 64
l
[
9
~
Report of Independent Accountants To the Stockholders and Directors of Boston Edison Company:
l I
l We have audited the consolidated financial statements of Boston Edison Company.
l and subsidiaries (the Company) listed in Item 14(a) of this Form 10-K.
These consolidated 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 i:
material misstatement.
An' audit-includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit l
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 L
for.our opinion.
In-our opinion,.the consolidated financial statements referred to above present fairly, in all naterial respects, the consolidated financial position l'
of the company as of December 31, 1997 and 1990, and the consolidated results I
of.its operations ~and its cash flows for each of the three years in the period I'
ended December 31, 1997, in conformity with generally accepted accounting principles.
COOPERS & LYBRAND L.L.P.
Boston, Massachusetts January 22, 199B' l:
1 f:
}
65
_.-_---______-_____-_-_-___ _-__ -_-_ -