ML20151Z784
| ML20151Z784 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde  |
| Issue date: | 12/31/1997 |
| From: | Bohle C, Geoffrey Edwards, Haines J EL PASO ELECTRIC CO. |
| To: | |
| Shared Package | |
| ML17313A590 | List: |
| References | |
| NUDOCS 9809220118 | |
| Download: ML20151Z784 (99) | |
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El Paso Electric Company is a public utility engaged in the generation, f g ggg g;..Q']
transmission and distribution of electricity in an area of approximately 10,000 l
u f;
square miles in West Texas and Southern New Mexico. EPE has total assets
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n of approximately $ 1.8 billion and total revenues for the year ended December b
..EPE's mission is to provide M,
m e
,31,1997 were almost $600 million.
re/lable, competit/velypriced[
a electric service. We willkeep; -
EPE serves approximately 284,000 retail customers in Texas and New Mexico.
to the highlest standards"of -
7,4 In addition, it sells electricity to wholesale customers in New Mexico and y
e,o.
California and also has a contract for sales of power to the Comisi6n Federal lsafetsintegrity andexc,ellbncei
~
de Electricidad de Mexico (the national electric utility of Mexico). Principal
[ ' Jin allthat we do/and we willl industrial and.other large customers of EPE include steel production, copper f
abhieve financialhealth.'
y and oil refining, and garment manufacturing concerns as well as United E
E-t States military installations, including the United States Army Air Defense
[
.,w Center at Fort Bliss in Texas, White Sands Missile Range and Holloman Air b l7(pgg]pg E <? 4 Force Base in New Mexico.
U
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- Safety JElectricityis an EPE's principal offices are located at' Kayser Center,100 North Stanton, k
. v...
El Paso, Texas 79901. EPE was incorporated in Texas in 1901.
{
f /nherently hazardous product,i
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- yet it is essehtial'in ourN,
u
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modem socie' y,? Producing l t
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YY s.:.:,ww;MMa%mf.Mnmw$
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^ and distributing it' safely is :
s m.na.+.
- n. O :gwy,.m,
p essential to our success.'
in 1997, EPE made significant progress toward improving its financial e
p fundamentals. EPE continues to experience strong sales growth with increases a,
of 2.3% in retail energy sales and 1.7% customer growth, over 1996 levels.
e{
integn.ty1 Accountability,, "
c honesty, and reliabilit)hnust 1 EPE or.ce again successfully renewed a 200 MW power sales contract with Mexico for 1998. Operationally, the Palo Verde Nuclear Generating Station
)
' characterize allthat we dot achieved an 88% capacity factor and earned a 1.25 overall SALP score
\\
while operations and maintenance costs associated with the plant declined 6<.,;
)-
P 7.2% from the previous year. EPS for 1997 were $0.64, an increase of 25%,
' ExcellenceL We' measure e'
4,(
and EBITDA per share were $4.38. EPE also continued efforts to delever its
{
urpdtmance against the ? "
(
m
~
capital structure, with $83 million of long-term debt repurchases on the
. highest standards ~and expecta
- c open market, bringing total debt (net of available cash) to approximately h
fcontinuous improfementini g _
l 64% of capital at year-end.
all'that we do.
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" b Octobet IM
.}
Megawatt-hw Sab P'
Sales for Resale 3,897,085 179' 671 2,484,128 f 3 Oitober 1N:
-'o e<
4 Retail 47 5,652,907
< 16 902 SJ96p40 MN
~
Q (wned Generatin8 p
gg4 T ypy [
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-p %.
h,4tions aretenchW",' N M Total 5Y5fe'" ppa (MW)
- 442 I" 0 1,374 t,363 1,335 "l
T.
' e a nwnth45A g;, /,gpg,,i,9. - g dp.--niaatu'M' " ;
- p Number dCustomers 284,174 279,M6
~ 273'g3 26y,775 26L95g se
, ' g,gng,neering.Gchemistry,(61WW *d L.
Administrapon# M tk m g, g,,,,,n,n,.e, 3
S Number #"9W 1,076 1,082
'i i i,133 1*140 w gr} Traim6Jt.4 1
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. x Working smarter than ever before, EPE's dedicated employees added substantially to
' ')
?
a EPE's accomplishments over the past year.
~ '~~~"
'. f. -
In 1997, we paid down debt by $83 million through open market purchases. We also f
accumulated cash of $111 million. This cash is now available for additional open s - &
market purchases of debt or the retirement of debt and preferred stock as debt matures 4.iF and the preferred stock becomes callable. In addition, we renewed our power sale agreement with Mexico's national electric utility, the Comisi6n federal de Electricidad.
It is a valuable association which we will continue to cultivate and expand.
While retail sales increased 2.3% over 1996, we held O&M costs below 1996 levels -
7-a third straight year of O&M cost reductions. Earnings per share were 5.64 and free cash flow per share was $ 2.30. Standard and Poors improved our debt rating from BB-Leu mecce m c-mm
+
to BB+ with a positive outlook, and Moody's and Duff & Phelps improved our credit
.J.
f _,
g,,
f 9
ratings as well, to Ba2 and BB, respectively.
h~
s
< i s>
+
e
^y We are focused on winning the loyalty of our customers. From streamlining the process 4
i q
_ through which we plan and build facilities to connect new customers, and improving b
o' the reliability of our electric service, to providing value-added products and services b
+
4-through our Energy Services Business Unit, we are taking care of our customers in 7g
+
ways which benefit them and EPE. Notably, our ESBU began operation in July 1997
@ ['
and now has over $6.5 million in energy service proposals outstanding and $1.9 3
%gg--
g j
!"]
million of energy service projects in progress.
rw g'
Although our very strong cash flow and rapid deleveraging are indicative of bright y;, v +
P future prospects, our future is not entirely free of uncertainty. Three separate matters w
a:
Jand3/reCtorsI are cause for concern: our controversy with Las Cruces, New Mexico; the New Mexico
^
t Public Utility Commission's review of our New Mexico retail rates; and the potential
',- g s -
u' S~'q enactment in 1999 of laws introducing retail competition to the electric industry in 9
s ~ ' -
s Texas and New Mexico, y
6fERE ai% ', "S Our controversy with Las Cruces, which represents about 8% of our total revenue, is
<1 5
the most vexing. Las Cruces has created a municipal utility and is attempting to take s
. 'A 4
over, through acqu:sition or condemnation, our distribution facilities in Las Cruces.
m
,p
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Ai,hemgh Las C,uces ha,,efused,e,ene. ee,f,anchise which exp,,edim 19es,we
= Committed,to:
continue to provide Las Cruces with electric service pending the outcome of the 79 h municipalization effort. At the center of the controversy is the issue of fair compensation
^
aI 1
to E PE for costs we have incurred, primarily through our investment in the Palo Verde 4/DCreaS!Dg th'eY~
Nuclear cenerating station, to assure our ability to satisfy the present and p(
Q
'p' future energy needs of our customers, including those in Las Cruces.
P
. Vakte Oh0UT;
- ,s This issue is awaiting decision at the Federal Energy Regulatory Commission. The 4
FERC staff has calculated a range for the Las Cruces stranded costs from $8 million
~
s to $74 million, and made an initial recomrnendation that Las Cruces pay $30 million.
~
s Las Cruces contends the range should be from zero to $20 million. We believe fair IlDVe$tment,,,;g compensation would be $101 million. To acquire our system, Las Cruces would also q
'l have to pay us the value of our distribution facilities in Las Cruces, over and above
- [.
4
_v 4
the amount of stranded cost compensation. Barring agreement, that value would be determined through a condemnation proceeding in state court.
^
^
i%<n,'
4 a
We prefer a negotiated settlement with Las Cruces. However, we will not voluntarily 4
agrce to a solution which does not fairly compensate us for investments we have made to serve our Las Cruces customers. While we will continue to pursue a negotiated i
settlement, we do not predict a speedy resolution of this controversy.
?
The New Mexico Commission's review of our rates is a separate proceeding from the
%y 4
Las Cruces matter, and is a result of rate complaints filed by two residential customers.
4.w
,7 3
Although we are not seeking to increase our New Mexico rates, we have fik<l evidence Q
'9 4 4 4 ^
, ?,%
which shows that under existing interpretation of New Mexico law, our New Mexico
[
rates should be increased by approximately 8.5% Other parties to the case, however, n3 may file evidence which will argue that our rates should be reduced. Our goal is to j
5%
4 _ i#
find a basis upon which this case can be settled. We expect this case to be resolved
$ ~ 4 '/
by year-end 1998.
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Finally,'the Texas and New Mexico legislatures appear prepared to consider legislative proposals during their 1999 sessions which would introduce retail competition to the generation of electricity. EPE supports such a transition as long as all customers are treated fairly, the new competitive playing field is level (i.e. electric utilities are allowed y
h to compete on the same basis as other generators), and past investments by electnc utilities approved by utility commissions may be recovered.
We will continue our efforts to resolve these three concerns. Their successful resolution, however, will not in itself assure our success; at best, it will only set the stage. To further increase the value of EPE, we will pursue four principal objectives:
- Enhancing our transmission interconnection with the Comisidn federalde A
Electricidad to permit joint planning and development of mutually beneficial pm* Wa* ce= $===,,
generation projects and energy trading; p'
v V
- Maintaining above-average growth in retail sales, coupled with aggressive action to win the loyalty of our customers; e[ ~
g'ji m
Y
- Increasing revenue from our Energy Services Business Unit; and b~
e 1
N
= m y
a Controlling costs and rnaintaining our cash flow so that we can continue to "P
r delever and move toward investment-grade credit fundamentals.
~I r
The first two objectives require elaboration. The El Paso /Las Cruces/Judrez metroplex M.'
is a unique international community celebrating its 400th anniversary this year. The I
of ~
potential economic development of this area, driven by international trade, is almost
[
I unlimited. El Paso /Juarez is the busiest border point in the world. Approximately 20%
p
('~
of the U.S. land trade with Mexico moves through the El Paso area. One startling tG N
indicator of the substantial growth potential in this international community is the rise
[
~ ffggggg gg'i m electric energy consumption in judrez, from 1993 to 1997, electricity use in Judrez b
2 5
grew at an annual compound rate of more than 9% in 1997,48,000 new jobs were p
w#
~
created in Judrez, b
,3,
' ' WinntnO -e El Paso itself is poised for significant economic growth. While El Paso lost many
~
garment industry jobs in 1997, the Greater El Paso Chamber of Commerce reports that I
~ 'b M'<
El Paso gained more than 4,000 new jobs in 1997. The Chamber's goal for 1998 is D
s 1
6,000 jobs.
V. lt
/Op/f[
As for EPE's growth, our retail sales have increased at a compound annual rate of over D
3.5% for the last five years, a substantially higher rate than the industry average. The F
l ' [-.
number of our customers has grown at an average annual rate of 2% to 2.5% per year,
'JO O(f r.'
and more than 30% of our sales to large commercial and industrial customers are l
+
under long-term, competitively priced contracts.
[
We are pleased to report that at the end of the year Patricia Holland-Branch and James k
"ChSlOmCTSN Cicconi joined our Board. Both bring outstanding business and public affairs experience
['
T to an already strong and independent Board. All the officers and directors of EPE are committed to increa' sing the value of your investment by maintaining our strong cash
)f' flow, winning the loyalty of our customers through outstanding service, effectively meeting challenges in New Mexico, and seeking regional and international opportunities p
for growth,
'4 p
Thank you for your confidence.
t:
for the Board, h
' p p
?
p y
i r
M h
k h
N i
George W. Edwards, Jr.
Jam'es S. Haines, Jr.
[
s1 Chairman of the Board President and Chief Executive Officer T
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.LRITIf Al_ ARE AS OF BUSINESS-E
. i@
Change in the electric industry is occurring daily. Federal open access rules guiding transmission service related to wholesale competition are a reality, and retail competition is taking shape in several states. Texas and New Mexico will likely consider restructuring legislation during their 1999 legislative sessions. As part of our plan to succeed and achieve our principal objectives, we have identified critical areas of our business which
<P merit our concentrated focus:
Deleveraging and Cash Flow 7._
u t.u. w m, e. % c.,,u - W Competitive Service and Pricing
{ '""""*" ** **"*7 m ?
System Reliability f
7 Cr s_
Safety h,-
C
- Corporate Citizenship
~
" Reducing the amouht.
m.
x V
- ofdebt in the CapitalI, t
EPE sets specific yearly corporate goals relating to these areas of focus, and b
' Structure /S Crit /Cdif has established an all-employee cash bonus plan if goals are attained. Under
- n.
.'f the plan, no bonus is paid, irrespective of performance in other areas, if the h
' J to EPE'S abilitP tol ~
cash flow goal is not achieved. The cash flow goal must be achieved net
['
L.
C
,. ~
- achieve finanCla$
of any bonus paid.
V
[Y Ihealth Hbs4esier,l During 1997, the first full year of the plan, EPE met or exceeded most of the P
goals set, including the cash flow goal, resulting in a bonus pay out to all j,
~ <de/evefaginggoes; employees. EPE believes that this type of goal alignment between employees
[-
~
F
,~ -
~- '
and shareholders creates the culture necessary for success in today's changing g
- beyondSimply..
t i
utility landscape.
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7 Efficiencies which i mm,-gym m.ym y gm y-vny - m -
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reduce costs orl y$
o
'In 1997, EPE repurchased $83 million of first mortgage bonds in the open b ', ~/ncrease prod, uctivity market. At year-end, the debt component of the capital structure was
' improve CaSb [/ owe approximately 67% (including current maturities). Net of available cash, C
2.
W.
the debt ratio at year-end would have been approximately 64% By
( %,[pnd helpIdeiever EPE("' -
comparison, EPE emerged from bankruptcy protection in February 1996 17 with debt (net of cash) at approximately 74% of its capital structure.
[
~.
t l
This rapid deleveraging progress was cited by credit rating agencies as a t
.1 contributing factor to their decision to upgrade credit ratings for EPE in 1997
[
g and early 1998.
t I
Minimizing financial risk through the reduction of fixed obligations will 0
c, continue to be a primary focus. Currently, credit rating agencies define an b
{;
y investment grade capital structure as having a debt-to-capital ratio between
.50-55% Achieving an investment grade credit rating is a fundamental
[
t f
objective for EPE, which we believe is achievable in the relatively near term j[
b l
given EPE's strong free cash flow ($2.30 per share in'1997).
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v EPE to demonstrate
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~-a ty Npmk a
One factor in EPE's recent financial improvement has been its ability to reduce costs. The Rate Freeze Agreement currently in effect in EPE's Texas va/ue-addedservices,i,
[,
jurisdiction provides for EPE to maintain the benefit of cost reductions and L tofbe competitive anh.
o increases in productivity. In 1997, EPE was able to reduce its operations and maintenance costs by 1.79% from 1996 levels, marking the third year h;
' to be custoiner-locusek/."'
in a row of declining costs.
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Recognizing that revenue enhancement is equally vital to success, EPE I
created an Energy Services Business Unit during 1997. The ESBU was charged with developing energy efficient products and services that will build on EPE's core competencies in the electric utility business and should b
serve to differentiate EPE from potential competitors. Marketing plans have
- ~ p
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been developed and are being implemented. Customers are now being
'J offered pricing options, as well as value-added products and services that 4'
give them greater value for the kilowatt-hours purchased from EPE. These t
efforts are focused primarily on developing customer loyalty in addition to providing a base for incremental revenue growth in the future.
f t
-s.
During approximately six months of operat' ion, since its inception in 1997, y
the ESBU has contracted to provide energy services such as lighting retrofits,
~
mapping services, upgrading customer facilities and other energy-related g
services to customers which have resulted in over $6.5 million in energy service proposals outstanding as of year-end 1997, approximately $1.9
' "As retail competit/On;, -
million of which are currently in progress.
[
ap' proaches/one of thei l primary distinguishing; characteristics ofpot'ential]
}ystem ReliabilitYL f
Alectric service providers J
=
.a System reliability will-be a major issue in the transition to a competitive lis likely to'be quality) " "
- o/ serv' ice. One major -
market. Emphasizing that fact, the Public Utility Commission of Texas
~
~~
adopted rules during 1997 requiring all Texas utilities under its jurisdiction component o@uality of.
to file semi-annual reports on their service performances, based on several
~ service is reliability-the industry-accepted reliability indices. EPE also measures the performance measure ola utility's ab//ith' 4
of its New Mexico service area with the same reliability indices. Of 10 maintain continuou's a '
s 1
the 10 largest T.exas utilities fih.ng mitial reports m 1997, EPE ranked
~ hird-best in the category measuring frequency of outages.
service to its customers."
t T
EPE engages in an active ongoing program to upgrade facilities and enhance reliability. In 1997, EPE expended $47.7 million for capital improvements
(
on its facilities, of which approximately 33% was directly related to maintaining or improving system reliability. Capital improvement projects y
range from new construction and equipment installations to facility F
replacement and repair. EPE has and continues to expend significant capital for underground cable replacement, feeder reconductoring and voltage upgrades, protective device improvements, line rebuilds, substation upgrades r
and power plant improvements. The ultimate objective of all facility
/
improvements, replacements and repairs is to ensure operational integrity f
e and to maintain or enhance total system reliability.
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"Our commitment to safetyl ),
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/goes b~eyondprovidmg.
www x-n a,.au Continually str..iving to mimmve the number of work-related accidents (a safe environmenIfor :
and the amount of work time lost as a result of accidents is essential to Lemployees and customerd our success, given the inherently dangerous nature of our business. EPE
- .' : We want to change the L J has recently implemented various programs designed to make employees y y ? {ygy pggpfg gjgg gggjg C and the community more aware of the importance of safety when dealing c
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with electricity. As a' result of these programs during 1997, EPE reduced (I
. wor %a%%eQ.comes, \\
the number of overall on-the-job injuries by 44% from the previous year.
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. theirschools and their; In addition, EPE administered and organized important safety training
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and certification courses for hundreds of EPE employees. EPE believes h
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s that this safety message is also vital to the public and made more than k
4 120 safety presentations to schools, businesses, community groups and 5
government agencies.'
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The success of EPE relies upon the efforts of its employees. When they
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work safely and productively, EPE can achieve its goals and succeed in
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our changing industry.
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Being a good corporate citizen is a principal element of the working
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philosophy at EPE. A strong, giving presence in the communities we serve
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reinforces our relationship with our customers and develops pride and a
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'y sense of accomplishment in our employees. There is no better E
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way to show our customers how much we care than through our direct F !"dt EFE, we allshardaS % :
and active support of civic and charitable activities.
l' common vision l we ) i' f Responding to specific community needs during 1997, EPE's support eMat m$ng[ ' <
focused on programs which addressed issues such as youth education, our communities.,,' w f,
family and child crisis, abuse prevention and support for single land neighborhoods' parent families.
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In 1997, EPE's employees generously contributed to United Way, exceeding
~ which'fo //ve andj our corporate contribution goal. As a result, EPE was one of only five area F
work /S an important ?
businesses to be recognized with the prestigious Arco de Oro Award from
- part of ourjdb.'"
I the United Way of El Paso County given for substantial contribution.
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Another example of the spirit of giving evident in EPE employees,is the g
4 Volunteers in Action Program. EPE makes specific work hours available to employees who wish to particioate in civic and charitable activities..
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Since its inception, hundreds of employees have contributed thousands i
g of hours to make their communities better places in which to live. EPE employees tutor school children in various subjects; they coach Little
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a League; they volunteer in senior citizen centers; and they organize fund-
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raising events for their churches. Their commitment and dedication affirm
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EPE's belief that its employees are an essential part of our corporate k
s, Lu citizenship efforts.
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,l Operatind Revenues (in tNousands)y 1997 1996 m
,1995 <tn 1994'
? Bare Revenues
>. i Retaill',,
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s 146,412 141,719 128,295 129,869 rh 0.f Resid ntial
- Commercial and Indu;strial, Small,
,143,395 138,910 128,715 126,450
\\C6mmerblA.l and I,ndustrial, large ( /
45,581 43,483 40,870 39,754 64,328 65,534 59,613 59,811 h.,,,. c 5 ales to Pubhc Authorities ',
u-
- Total RetailJ
. =,
399,716 389,646 357,493 355,884
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+1 as s
s Who,lesale Sales for Resale.x,
59,263 71,254 74.557 75,750
- 'lotal Dase Revenues i.
458,979 460,900 432,050
~ 431,634
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1 Fuel Revenues and Economy Sales.
130,172 114,042' 68,823 101,076 4
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F ins 3,744 4,050 4,887 3,981
- Other C< >
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[ Total Operatirig Revenues 594.038
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578,923 504,617 536,760 Numbeh. 6f Cu'stomers (eMof hear)(
3
^ 'Residentiall 254,348 250,209 245,245 240,368 h4CommSrcial Md trUudri51, Small, 25,900 25,304 24,615 23,857 z.
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Commercial bd Jndustrial, targe, <;
115 102 89 80 3,811 3,711 3,674 3,470
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Other, - o s
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.'c i Total,
284.174 279,326 273.623 267,775 Erdrgy SuppNd, Net, kWh (in thousands)i
[Generat$d[
8,186,187 7,920,675 7,439,404 7,018,423 5
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Purchased and Interchanged "
M 617,651 711,791 584,853 1.051,251 l- >
- Total 2 8,803,838 8,632,466 8,024,257' 8,069,674
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. 7 H Energy Sales, LWh (in thousandsk.
- ' Retaib
- a Reddential 1,587,733 1,545,274 1,473,349 1,500,426
' Commercial and Industrial,' Small '
1,834,953 1,779,986 1,754,176 1,721,736
' Commercial and industriai, Large 1;271,449 1,216,941 1,121,329 1,092,028
{ Sales to Pubfic AuthoritiesY 1,090,312 1,110,706 1,068,048 1,081,850 5,784,447 5,652,907 5,416,902 5,396,040
- i. SVhoiesalei
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O>i Sales for Rnale 1,897,885 1,753,553 1,646,357 1,925,671
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Econo kSales 640,017 757,999 538,102 320,026 (Totai5 ales..
8,322,349 8,164,459 7,601,361 7,641,737 4'
'4 (Losses and Company Use.
481,489 468.007 422,896 427,937 W [T5tNI,
8,803,838 co 8.632,466 to 8,024,257(o 8.069,674 to
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P.ed load, kWl i
1,122,000 1,105,'000 1,088,000 1,093.000 C
f Ped, kW1 #
1,500,000 1,500,000 1,500,000 1,497,000 m y(Net Generating apacity or w "3, -
64.0 %
63.4 %
61.6 %
61.1 %
' " Loadf actor.s ^
a-
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' l Peak told, kW ;
p 1,442,000 1,387,000 1,374,000 1,365,000 s
.?N. et, Generating C. apa, city for Peak', kW..
1,500 000 1,500,000 1,500,000 1,497,000
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' toad factor -
3 640 %
64.2 %
62.0 %
63.7 %
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1993 1992 1991 1990 1989 1988 123,706 124,805 109,891 101,307 97,381 90,733 120,084 120,793 104,794 94,117 89,043 '
80,449 36,440 38,693 35,592 30,170 27,986 23,631 n
57,063 57,780 51,200 47,425 46,046 41,390 337,293 342,071 301,477 '
273,019 260,456 236,203 89,863 80,663 54,095 49,918 52,272 57,223' 427,156 422,734 355,572 322,937 312,728 293,426 112,005 98,451 103,810 119,525 118,305 104,499 4,433 3,575 3,023 2,847 2,437 3,945 543g 524,760 462,405 445,309 433,470 401,870 235,151 228,688 223,684 218,753 214,664 209,550 33,338 22,883 22,417 22,135 21,762 21,069 74 68 68 60 52 39 3,395 3,251 3,156 2,788 2,659 2,543 261,958 254.890 249,325 243,736 239,137 233,201
""I 6,635,162 7,330,004 6,128,171 5,277,127 4,753,236 4,904,854 1,416,172 589,288 1,273,440 1,726,525 1,794,492 2,079,665 8,041,334 7,919,292 7,401,611 7,003,652 6,547,728 6,984,519 1,424,935 1,395,387 1,342,830 1,318,471 1,299,768 1,246,081 1,616,434 1,555,047 1,511,550 1,484,207 1,450,817 1,397,913 872,477 911,750 864,025 784,177 763,650 697,758 1.034,231 997,483 956,691 954341 947,948 908,238 4,94&,077 4,859,667 4,675,096 4,541,296 4,462,183 f 4,249,990 2,484,128 2,361,204 1,717,850 1,442,799 1,411,162 1,271,366 164 559 264,654 637,425 640,399 348,429 1,109,872 s7,596,764 7,485,525 7,030,371 6,624,494 6,221,774 6,631,228 444,570 433,767 371,240 379,158 325,954 353,291 8,041,334 7,919,292 7,401,611 7,003,652 6,547,728 6,984,519 997,000
()74,000 929,000 920,000 916,000 840,000 1,497,000 1,497l000 '
1,497,000 1,497,000 1,497,000 1,497,000 62.1 %
62.3 %
62.6 %
61.6 %
61.0 %
63.0 %
i l
1,335,000 1.,302,000 1,142,000 1,098,000 1,076,000 1,002,000 1,497,000 1,497,000 1,497,000 1,497,000 1,497,000 1,497,000 f
66.4 %.
s 66.4 %
67.9 %
66 7 %
67.0 %
67.3 %'
Fmannaf data m thewd on tk combmed smules ftw the Predesenne Company que the pe ruxi lamsary 1 t9% to february 11,19% and the Eeorgamped Company hw the peru,d February 12,19% lo Det em a :=:m D, M(, yh;dhsskneM&y ;s#sNEd%& AC#M TNN y,,
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b N b $ $ b h M N k % M M % E 41$is s d / b M M B f W M IMM R D 4F DIR E C TO R S & O PF IC E,llS.
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President & Chief Executive Officer C
James S. Haines, Jr.
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Eduardo A. Rodriguez Senior Vice President-Customer &
f Corporate Services Y
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J. Frank Bates Vice President-Transmission &
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Form 10-K SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 (Mark One)
E ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31,1997 OR O TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commissio.3 file number 0-296 El Paso Electric Company (Exact name of registrant as specified in its charter)
Texas 74-0607870 (State or otherjurisd:ction ofincorporation or organization)
(1.R.S. Ernployer Identification No.)
Kayser Center,100 North Stanton, El Paso, Texas 79901 (Address of principal executive offices)
(Zip Code) ttegistrant's telephone number, including area code: (915) 543-5711 Szcurities Registered Pursuant to Section 12(b) of the Act:
Title ofeach class Nams_of each exchange on which reiristered 1
Common Stock, No Par Value American Stock Exchange j
Securities Registered Pursuant to Section 12(g) of the Act:
None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Sectior.13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for cach aborter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the - ast 90 days. YES X
N O __
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12,13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securitia under a p an confirmed by a court. YES _2L NO _
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in driinitive proxy or information statements incorporated by reference in Part III of this Form 10-K cr any amendment to this Form 10-K. [X]
As of March 13, 1998, the aggregate market value of the voting stock held by non-affiliates of the registrant was $399,107,460.
As of March 13,1998, there were outstanding 60,276,784 shares of common stock, no par value.
DOCUMENTS INCORPORATED BY REFERENCE Portions of the registrant's definitive Proxy Statement for the 1998 annual meeting of its chareholders are incorporated by reference into Part Ill of this report.
DEFINITIONS He following abbreviations, acronyms or defined terms used in this report are defined below:
Abbreviations, Acronyms or Defined Terms Terms l
i Agreed Order..
Agreed Order of the Texas Commission entered August 30, 1995 implementing certain previsions of the Rate Stipulation ANPP Participation Agreement...
Arizona Nuclear Power Project Participation Agreement dated August 23, 1973, as amended APS.,
Arizona Public Service Company Bankruptcy Case :
The case commencedJanuary 0,1992 by El Paso Electric Company in the United States Bankruptcy Coart for the Western District of Texas, Austin -
Division, as Case No. 921014%FM CFE; Comision Federal de Electricidad de Mexico, the national electric utility of Mexico
- Common Plant or Common Facilities..
Facilities at or related to Palo Verde that are common to all three Palo i
Verde Units Company..
El Paso Electric Company DOE...
United States Department of Energy Effective Date....
February 12,1996, the date the Reorganization became effective FERC..
Federal Energy Regulatory Ccmmission
)
Four Corners...
Four Corners Generating 5tation l
Freeze Period.
Ten-year period beginning August 2,1995, during which base rates for most Texas retail customers are expected to remain frozen pursuant to the Rate Stipulation IID.
Imperial Irrigation District, an irrigation district in Southern California KV......
Kilovolt (s) -
KW..
Kilowatt (s)
K W H..........
Kilowatt. hour (s)
)
MW=
Megawatt (s) i MWH.-
Megawatt hour (s)
Ww Mexico Commission...
New Mexico Public Utility Commission NRC..
Nuclear Regulatory Commission OPC..
Texas Office of Public Utility Counsel l
Palo Verde.
Palo Verde Nuclear Generating Station Palo Verde leases...
Leases and other documents entered into in connection with a series of sale -
and leaseback transactions in 1986 and 1987 invohing a portion of the Company's interest in Palo Verde Palo Verde Participants..
Those utilities who share in power and energy entitlements, and bear certain allocated costs, with respect to Palo Verde pursuant to the - ANPP Participation Agreement
- Plan...
The Company's Fourth Amended Plan of Reorganization dated November 7,1995, pursuant to which the Company emerged from bankruptcy on the EfTective Date
~ PNM......
Public Senice Company cf New Mexico Predecessor Company..
The Company prior to the Reorganization
. Rate Stipulation.....
Stipulation and Settlement Agreement dated as ofjuly 27,1995, between the Company, the City of El Paso, OPC and most other parties to the Company's rate proceedings before the Texas Commission providing for a ten-year rate freeze and other matters Reorganization and the emergence from bankruptcy by the Company
. Reorganization..
pursuant to the Plan Reorganized Company..
The Company following the Reorganization SFAS..
Statement of Financial Accounting Standards SPS..
Southwestern Public Senice Company Public Utility Commission of Texas Texas Commission......
TNP........
Texas-New Mexico Power Company (i).
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-w-r T.P r =*
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TABLE OF CONTENTS Item Description Page PART I l
1 Ilusiness....................................................................
1 2
Pro pe rt les..............................................
19 3
legal Proceed ings..................................................
19 4
Submission of Matters to a Vote of Security Holders.........
22 PART II
.5 Market for Registrant's Common Equity and Related Stockholder Matters....
23
- 6.. Selected 1inancial Data......................
25 7
Management's Discussion and Analysis of Financial Condition and Results of Operations....................................................
26 8
Financial Statements and Supplementary Data....
33 9
Changes in and Disagreements with Accountants on Accounting l
and Financial Disclosu re..............................................................
82 PART III 10 Directors and Executive Omcers of the Registrant.................................
82'
.I1 Isxec u tive Com pe n sa tion...................................................................
82 12 Security Ownership of Certain Ileneficial Owners and Management..............
82 13 Certain Relationships and Related Transactions......................................
82 PART IV 14 Exhibits, Financial Statement Schedules and Reports on Form 8-K...............
82 4
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(ii)
PART I Item 1.
Business General
-El Paso - Electric Company is a public utility engaged in the generation, transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas and southern New hiexico. The Company also serves wholesale customers in Texas, New hiexico, California and Alexico. The Company owns or has significant ownership interests in five electrical generating facilities providing it with a total capacity of approximately 1,500 h1W. For the twelve months ended December 31,1997, the Company's energy sources consisted of approximately 53% nuclear fuel,34% natural gas, 6% coal and 7% purchased power.
The Company serves approximately 284,000 residential, commercial, industrial and wholesale customers. The Company distributes electricity to retail customers principally in El Paso, Texas and the l
City oflas Cruces ("Las Cruces"), New hiexico (representing approximately 58% and 8%, respectively, of the Company's revenues for the twelve months ended December 31, 1997). In addition, the Company sells electricity to wholesale customers, including Texas-New hiexico Power Company, the Imperial irrigation District (a southern California electric power agency), and the Comision Federal de Electricidad de hiexico (the national electric utility of Mexico). Principal industrial and other large customers of the Company include steel production, copper and oil refining, garment manufacturing concerns and United States military installations, including the United States Army Air Defense Center at Fort Bliss in Texas and White Sands Missile Range and Holloman Air Force Base in New Mexico.
The Company's_ principal ollices are located at Kayser Center,100 North Stanton, El Paso, Texas 79901 (telephone 915-543-5711). The Company was incorporated in Texas in 1901. As of.
February 23,1998, the Company had approximatelv 1,100 employees, approximately 31% ofivhom are covered by a collective bargaining agreement that expires inJune 2000.
Facilities The Company currently has a net installed generating capacity of approximately 1,500 MW, consisting of an entitlement of 600 MW from Palo Verde Units 1,2 and 3,482 MW from its Newman Power Station,246 MW fiom its Rio Grande Power Station,104 MW from Four Corners Units 4 and 5, i
and 68 MW from its Copper Power Station.
Pcts Verde Station The Company owns a 15.8% interest in each of the three nuclear generating units and Common Plant at Palo Verde, located west of Phoenix, Arizona. The Palo Verde Participants include the i
Company-and six other utilities:
APS, Southern California Edison Company, PNM, Southern California Public Power Authority, Salt River Project Agricultural Improvement and Power District and
' the Los Angeles Department of Water and Power. APS serves as operating agent fcr Palo Verde.
The NRC'has granted facility operating licenses and full power operating licenses for all *hice units at Palo Verde for terms of forty years each. In addition, the Company is separately licensed by the NRC to own its proportionate share of Palo Verde.
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Pursuant to the ANPP Participation Agreement, the Palo Verde Participants share costs and generating entitlements in the same proportion as their percentage interests in the generating units and each Palo Verde Participant is required to fund its proportionate share of fuel, other operation, maintenance and capital costs. The Company's total monthly share of these costs was approximately S7.3 million in 1997. The ANPP Participation Agreement provides that, if a participant fails to meet its payment obligations, each non-defaulting participant shall pay its proportionate share of the payments J
owed by the defaulting participant.
Duommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company is i
required to fund its share of the estimated costs to decommission Palo Verde over the estimated service life of forty years. The Company's funding requirements are determined periodically based upon engineering cost estimates performed by outside engineers retained by the ANPP.
In December 1995, the Palo Verde Participants approved a decommissioning study performed by an outside engineering firm. The 1995 study determined that the Company will have to fund approximately S229 million (stated in 1995 dollars) to cover its share of decommissioning costs. The 1995 study assumed that (i) maintenance expense for spent fuel storage will be incurred for ten years after the shutdown of the last unit (estimated to be in 2024); (ii) a national interim spent fuel storage facility will be available; and (iii) as a result of such national spent fuel storage facility, the amount of spent fuel stored on-site will be reduced from all spent fuel assemblies to the final core plus fuel assemblies from approximately three refuelings. See " Spent Fuel Storage" below.
Cost estimates for decommissioning have increased with each study. The previous cost estimate from a 1993 study determined that the Company would have to fund approximately S221 million (stated in 1993 dollars). The 1993 estimate, however, reflected an 84% increase from the previous estimate made in 1989, primarily related to increases in estimated costs for low-level radioactive waste disposal.
Although the 1995 study was based on the latest available information, there can be no assurance i
that decommissioning cost estimates will not continue to increase in the future or that regulatory requirements will not change. In addition, until a new low-level radioactive waste repository opens and operates for a number of years, estimates of the cost to dispose oflow-level radioactive waste are subject to significant uncertainty. The decommissioning study is updated every three yeaa and a new study will be completed in 1998. See " Disposal of Low-Level Radioactive Waste" below.
The rate freeze under the Rate Stipulation would preclude the Company from seeking a rate increase in Texas during the Freeze Period to recover increases in decommissioning cost estimates.
Additional'y, there can be no assurance that the Company could increase its rates in any of its other jurisdictions to recover such increased costs. See Part II, Item 7, " Management's Discussion and j
Analysis of Financial Condition and Results of Operations - Operational Prospects and Challenges."
Steam Cenemtors. Palo Verde has experienced degradation in the steam generator tubes of each unit. The degradation includes axial tube cracking in the upper regions of the two steam generators in Unit 2 and. to a lesser degree,in Units 1 and 3. This form of steam generator tube degradation, while i
less common than other types, has also been seen at other United States nuclear generating stations. The units also have experienced circumferential cracking at the tube sheet, a more common type of tube cracking. The axial tube cracking was discovered (bilowing a steam generator tube rupture in Unit 2 in 2
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March 1993. Since that time, APS has undertaken an ongoing investigation and analysis and has
- performed corrective actions designed to mitigate further degradation. Corrective actions have included changes in operational procedures designed to lower the operating temperatures of the units, chemical cleaning and the implementation of other technical improvements. APS has stated that it believes its i
remedial actions have slowed the rate of tube degradation.
Steam generator tubes in each of the Palo Verde units have been inspected during regularly 1
scheduled refueling outages and mid-cycle inspection outages. If tube cracks are detected during an inspection, the affected tubes are taken out of service by plugging. This may impair the performance of a unit if suflicient numbers of steam generator tubes are affected.
The projected service lives of the units' steam generators are reassessed by APS periodically in conjunction with inspections made during outages of the Palo Verde units. APS has determined that it
- will be economically desirable to replace the Unit 2 steam generators, which have been the most affected by tube cracking. In 1997, the Palo Verde Participants unanimously approved the purchase ofone set of spare steam generators for delivery in May 2002. The Company's share of the cost is approximately S12.9 million. APS has indicated that in 1998 it will request that the participants approve installation of the spare generators in Unit 2 in 2003. The Company believes that such installation would require the unanimous approval of the Palo Verde Participants. The Company will continue to analyze the economic feasibility of steam generator replacement, or other options that may be available in connection with the operation of Unit 2. Also, the Company cannot predict whether the Palo Verde Participants will agree to replace the Unit 2 steam generators. The costs for the construction and shipping of the spare steam generators are expected to be incurred between 1998 and 2002. Installation costs,if they are approved, would be expected to be incurred between 1999 and 2003, with the bulk of the expenditures after 2000. The Company's portion of total costs associated with construction and potential installation of new steam generators in Unit 2, including replacement power costs and costs that would otherwise have been expended through the operation and maintenance budget, is currently estimated not to exceed S36 million. APS has also stated that, based on the latest available data, it estimates that the steam generators in Units 1 and 3 should operate for their designated lives of 40 years (to 2025 and 2027, respectively). APS will reassess the expected lives of these steam generators periodically.
The Rate Stipulation precludes the Company from seeking a rate increase in Texas during the Freeze Period to recover capital costs associated with such replacement of steam generators. Itis uncertain whether the costs associated with replacing the Unit 2 steam generators would be approved by the New Mexico Commission and included in the Company's rate base in New Mexico. See Part II, Item 7, " Management's Discussion and Analysis of Financial Condition and Results of Operations -
Operational Prospects and Challenges."
Disposal of Low-lael Radioactice IVaste. Congress has established requirements for the disposal of radioactive waste by each state generated within its borders. Arizona, California, North Dakota and South Dakota have entered into a compact (the " Southwestern Compact") for the disposal oflow-level radioactive waste. California will act as the first host state of the Southwestern Compact, and Arizona will serve as the second host state. The construction and opening of the California low-level radioactive waste disposal site in Ward Valley has been delayed due to extensive public hearings, disputes over environmental issues and review of technical issues related to the proposed site. Despite being licensed by the State of California, the Department of the Interior has not transferred the land to the state.
3 m
4 Followmg a report by the National Academy of Sciences, the Department of the Interior announced that, if certain environmental conditions were implemented prior to the transfer, it was prepared to convey the land. OnJanuary 16,1998, the Department of the Interior announced that fhrther scientific drilling had been approved for the Ward Valley site with testing to be performed by the federal government first, followed by testing by the State of California. No dates for the commencement of federal government testing have been established.
Although Palo Verde is projected to undergo decommissioning during the period in which Arizona will act as host for the Southwestern Compact, the opposition, delays, uncertainty and costs i
experienced in California demonstrate possible roadblocks that may be encountered when Arizona seeks l
to open its own waste repository.
Spent FuelStorage. The spent fuel storage facilities at Palo Verde have suflicient capacity to store all fuel expected to be discharged from normal operation of all three Palo Verde units through at least 1999. APS anticipates requesting approval from the NRC to use more of the space in the existing spent i
fuel storage facilities to extend the available storage capacity through 2001. Alternative on-site storage facilities are expected to be constructed by 2001 to supplement the existing facilities.
Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the " Waste Act"), the DOE is obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by all domestic power reactors. In accordance with the Waste Act, the DOE entered into a spent nuclear fuel contract with the Company and all other Palo Verde Participants.
In November 1989, the DOE reported that its spent nuclear fuel disposal facilities would not be in operation until 2010. Subsequentjudicial decisions required the DOE to start accepting spent nuclear fuel no later than January 31,1998. The DOE did not meet that deadline. As a result, under the DOE's current criteria for shipping allocation rights, it is estimated that Palo Verde could not ship spent fuel to the DOE's permanent disposal facility until approximately 2025. APS has indicated that alternative interim spent fuel storage methods will be available on-site or off-site for use by Palo Verde to allow its continued operation and to store spent fuel safely until shipments to the DOE's permanent disposal facility begin. APS's recommendation is to establish an on-site facility initially capable of storing approximately one-fourth of the total amount of spent fuel expected to be produced by Palo Verde, utilizing a dual purpose (storage and transport) dry storage system. The facility will be designed to be expandable in phases to accommodate additional amounts of spent fuel as needed. This facility is planned to be completed by May 2001. InJanuary 1997, the Texas Commission established a project to evaluate what, if any, action it should take with regard to payments made to the DOE for ftmding of the DOE's obligation 'to start accepting spent nuclear fuel by January 31,1998. After receiving initial
. comments, no further action has been taken in the project.
j Liabilip andInsurance Alatters. The Palo Verde Participants have public liability insurance against nuclear energy hazards up to the full limit of liability under federal law. The insurance consists of S200 million of primary liability insurance provided by commercial insurance carriers, with the balance being provided by an industry-wide retrospective assessment program, pursuant to which industry participants would be required to pay an assessment to cover any loss in excess of S200 million. The maximum assessment per reactor for each nuclear incident is approximately S79.2 million, subject to an annual limit of $10 million per incident. Based upon the Company's 15.8% interest in Palo Verde, the Company's maximum potential assessment per incident is approximately S37.6 million for all three units with an annual payment limitation of approximately S4.7 million.
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The Palo Verde Participants' maintain' "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of l
S2.7 billion, a substantial portion of which must first be applied to stabilization and decontamination.
J Finally, the Company has obtained insurance against a portion of any increased cost of generation or purchased power which may result from an accidental outage of any of the three Palo Verde units if the outage exceeds 23 weeks.
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Nzwman Power Station i
The Company's Newman Power Station, located in El Paso, Texas, consists of four generating units with an aggregate capacity of 482 h1W. The units operate primarily on natural gas, but can also operate on fuel oil.
Ria Grande Power Station The Company's Rio Grande Power Station, located in Sunland Park, New hiexico, adjacent to El Paso, Texas, consists of three steam-electric generating units with an aggregate capacity of 246 hlW.
The units operate primarily on natural gas, but can also operate on fuel oil.
Fc:r Corners Station-The Company owns an undivided 7% interest in Units 4 and 5 at Four Corners, located in northwestern New hiexico. The two coal fired generating units each have a generating capacity of 739 h1W. The Company shares power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) and the other participants.
Four Corners is located on land held under easements from the federal government and a lease from the Navajo Nation that expires in 2016. Certain of the facilities associated with Four Corners,
' including transmission lines and almost all of the contracted coal sources, are also located on Navajo j
land. Units 4 and 5 are located adjacent to a surface-mined supply of coal. See " Environmental hlatters
- Coal hiine Reclamation" below.
C:pper Power Station The Company's Copper Power Station, located in El Paso, Texas, consists of a 68 A1W
- combustion turbine used primarily to meet peak demands. The unit operates primarily on natural gas, but can also operate on fuel oil. The Company leases the combustion turbine and other generation equipment at the station under a lease that expires inJuly 2000, with renewal options for up to seven additional years.
Tr=smission and Distribution Lines and Agreements I
~ The. Company owns or has significant ownership interests in four major transmission lines and owns the distributionLnetwork within its retail service area. The Company is also a party to various transmission and power exchange agreements that, together with its owned transmission lines, enable the Company to obtain its energy entitlements from its remote generation at Palo Verde and Four Corners.
5 i
i 4
Springenille-Diablo Line. The Company owns a 310-mile,345 KV transmission line from Tucson Electric Power Company's ("TEP") Springerville Generating Plant near Springerville, Arizona, to the Luna Substation near. Deming, New hiexico, and to the Diablo Substation near Sunland Park, New hiexico, providing an interconnection with TEP for delivery of the Company's generation
- entitlements from Palo Verde and, if necessary, Four Corners.
Arrqvo-West Mesa Line. The_ Company owns a 202-mile, 345 KV transmission line from the Arroyo Substation located near Las Cruces, New hiexico, to PNhl's West Alesa Substation located near Aibuquerque, New hiexico. This is the delivery point for the Company's generation entitlement from Four Corners, which is transmitted to the West. Alesa Substation over approximately 150 miles of transmission lines owned by PNht. This transmission line also carries power from the region to the west and north of Four Corners, where the Company has a major interconnection with the other Four Corners participants.
Greenlee-Xnanan Line. The Company owns an undivided interest in a 196-mile, 345 KV transmission line from the Newman Power Station to TEI"s Greenlee Substation in Arizona. This line provides an interconnection with TEP for delivery of the Company's entitlements from Palo Verde and, if necessary, Four Corners.
l AMRAD-Ed@ County Line. The Company owns an undivided 66.7% interest in a 125-mile, 345 KV transmission line from the AMRAD Substation near Oro Grande, New hiexico, to the Company's and TNI"s high voltage direct cunent terminal at the Eddy County substation near Artesia, New hiexico. This terminal enables the Company to connect its transmission system to that of SPS,
}iroviding the Company with access to power markets to the east.
Issues Regarding Operation of Transmission Systern. As previously reported, the Company experienced four system-wide outars between September 1995 and hlarch 1996. As a result of remedial actions begun in November iv95, however, the Company has not experienced a system outage since hlarch 1996. The remedial actions included relay equipment replacements, transmission structure reconfigurations and implementation of load-shedding schemes designed to limit the extent of system instability under certain atypical conditions. The Company continues to import normal amounts of power over its transmission system and believes that it has identified and corrected the root causes of the
. outages to such a degree as to preclude, to the extent possible, similar future occurrences.
Environmental Matters The Company is subject to regulation. with respect to air, soil and water quality, solid waste disposal and other environmental matters by federal, state and local authorities. These authorities govern current facility operations and exercise continuing jurisdiction over facility modifications.
Environmental regulations can change rapidly and are diflicult to predict. Because construction of new
- facilities is subject to standards imposed by environmental regulation, substantial expenditures may be required to comply with such regulations. The Company analyzes the costs of its obligations arising from environmental matters on an ongoing basis, and management believes it has made adequate provision in its fmancial statements to meet such obligations. However, unforeseen expenses associated with compliance could have a material adverse effect on the future operations and financial condition of the Company.
6 1
4 l
e
O PCB Treatment, Inc. The Company received a request from the U.S. Environmental Protection Agency (" EPA") to participate in the remediation of polychlorinated biphenyls ("PCBs") at two facilities in Kansas and Missouri, which had bten operated by PCB Treatment, Inc. ("Irrl"). Presently, I'fl has discontinued operations and the EPA has determined that l'fl's abandoned facilities require remediation.
The Company and the PTI Steering Committee, which consists of the largest generators of the PCBs sent to l'fl, have executed a settlement agreement. In consideration for the payment of
' approximately S0.2 million, the settlement agreement excuses any further liability by the Company to the Steering Committee and indemnifies the Company for any liabilities to other patties as may be asserted in the future.
On September 16,1997, the EPA sent the Company a " general notice ofliability" wherein the agency formal!y notified the Company that it was considered a Potentially Responsible Party at the sites.
The Company believes any liability it may face at the sites is covered by the settlement agreement.
Accordingly, the Company immediately notified the Steering Committee and demanded it defend and indemnify the Company as provided in the settlement agreement. The Steering Committee informed the Company that i, intends to honor this indemnity obligation.
The Company may still face liability for possible deliveries of PCBs by I'FI to a third site which is also subject to remedial action by the federal authorities, except to the extent that those PCBs were transferred from the first site. The Company's records do not indicate any deliveries of PCBs to this third site. The Company believes it is unlikely to face substantial unindemnified liabilities associated with this third site.
CoalMine Reclamation. The Company has been informed by APS that the Company's estimated financial obligation for coal mine reclamation at Four Corners is not being fully reflected in the costs for which the Company is billed. APS, the operating agent for Four Corners, is performing an analysis to establish an appropriate revised cost estimate. Based on preliminary estimates from APS and the coal provider, the Company recorded a liability of approximately S12 million in 1996 which reflects the present value of the estimated future costs of reclamation for its share of the coal mine reclamation obligation.
7
Construction Program The Company has no current plans to construct any new generating facilities through at least 2004. Utility construction expenditures reflected in the table below consist primarily of expanding and updating the electric transmission and distribution systems and the cost ofimprovements and purchases j
of new steam generators at Palo Verde. The Company's estimated cash construction costs for 1998 through 2001 are approximately S220 million. Actual costs may vary from the construction program estimates set forth below. Such estimates are reviewed and updated periodically to reflect changed conditions.
i l
By Year (1)
By Function (In millit il (In millions) 1998..................
..S 51 Production (1)........
S 57 1999.......
57 Transmission.....
22 2 000............................
56 Distribution....................
105 2001..............
56 General...................
36 To tal................ S 220 Total............
.. S 220 (1)
Does not include acquisition costs for nuclear fuel. See " Energy Sources - Nuclear Fuel."
Energy Sources j
' General The following table summarizes the percentage contribution of nuclear fuel, natural gas, coal and purchased power to the total KWH energy mix of the Company:
Years Ended December 31.
Power Source '
1997 1996' 1995 N u c le a r Fu e l..........................................
53 %
53 %
53 %
Natural Gas...
34 32 30 Coal.....
6 7
9 Pu rchased Power...............................
7 8
8 Total............................................................
100 %
100 %
100 %
Fuel and purchased power costs are generally passed through directly to customers in Texas and New Mexico pursuant to currently applicable regulations. Historical fuel costs and revenues are reconciled periodically in proceedings before the appropriate commission to establish the applicable fuel rate to be charged customers and to determine whether a refund or surcharge based on such historical costs and revenues is necessary. See " Regulation - Texas Rate Matters - Fuel" and "- New Mexico Rate Matters - Fuel."
8
N clehrFest The Palo Verde Participants have contracts for uranium concentrate which should be suflicient to meet Palo Verde's operational requirements through at least 2000. The Company made spot purchases of uranium during 1997 to take advantage oflow market prices. Additional spot purchases may be made as appropriate. The Palo Verde Participants have contracted for up to 100% of conversion services required through 2000. The Palo Verde Participants have an enrichment se vices contract with the United States Enrichment Corporation ("USEC") which obligates USEC to furnish the enrichment services required for the operation of the three Palo Verde units through 2002, with an option for five additional years. A new contract provides fuel assembly fabrication services for each Palo Verde unit through 2016.
Nuclear Fuel Financing. Pursuant to the ANPP Participation Agreement, the Company owns an undivided interest in nuclear fuel purchased in connection with Palo Verde. The Company has available a $100 million credit facility that provides for working capital and up to $60 million for the financing of nuclear fuel. At December 31, P97, approximately S52.0 million had been drawn to finance nuclear fuel. This financing is effected hugh a trust that borrows under the facility to acquire
' and process the nuclear fuel. The Company is obligated to repay the trust's borrowings, and has secured this obligation with First Mortgage Collateral Series Bonds. In the Company's financial statements, the assets and liabilities of the trust are reported as assets and liabilities of the Company.
Nat ralGas In 1997, the Company's natural gas requirements at the Rio Grande Power Station were met solely with spot natural gas purchases from various suppliers. Interstate gas is delivered under a firm ten-year transportation agreement, which expires in 2001. Based on the current availability of economical and reliable spot natural gas, the Company anticipates it will continue to purchase spot natural gas for a portion of the fuel needs for the Rio Grande Power Station for the near term. To complement the spot purchases in 1998, the Company has entered into a one-year fixed-price gas supply contract. In addition, the Company has entered into a partial-year gas supply contract (April through October 1998).
For the long term, the Company will evaluate the availability of spot natural gas versus other supplies in obtaining a reliable and economical supply for the Rio Grande Power Station.
In 1997, natural gas for the Newman and Copper Power Stations was supplied pursuant to an intrastate natural gas contract which became effectiveJanuary 1,1997 and which expires December 31, 2001. To supplement this contract, the Company entered into a second natural gas supply agreement, which runs through 2001.'
C:al APS, as operating agent for Four Corners, purchases Four Corners' coal requirements from a supplier with a long-term lease of coal reserves owned by the Navajo Nation. The Company, based Jupon information from the operating agent, believes that Four Corners has suflicient reserves of coal to meet the plant's operational requirements for its useful life.
Phrchased Power To supplement its own generation and operating reserves, the Company has a firm power purchase agreement with SPS for amounts ranging from 50 MW to 110 MW for 1998.
9 i
't Operating Ste.tistica December 31.
1997 1996 (Al 1995 (B1 Operating revenues (In thousands):
, Base revenues:
Retail:
Re side n tial.......................................
S 146,412 S' 141,719 128,295-Commercial and industrial, small.......
143,395
-138,910 -
-128,715 l
Commercial and industrial, large..... '.....
45,581 43,483 40,870 Sales to public authorities..
64.328 65.534 59.613 Total retail.
399,716 389,646 357,493 Wholesale sales for resale...........
59.26,1 71.254 74.557 Total base revenues.
458,979 460,900 432,050
~ Fuel revenues and economy sales.....
130,172 114,042 68,823 Otlier;.................
4.887 3.981' 3.744' Total operating revenues.........
S 594.038 5 578.923 S 504.617 Number of customers (End of year):
Residential........................
254,348 250,209' 245,245-i
~ Commercial and industrial, small...........................
'25,900 25,304 24,615 Commercial and industrial, large.....................
I15
- 102, 89 Other.............
3.811 3.711 3.674 Total...
284.174 279.326 273.623
. Average annual KWH use per residential customer..
6.285 6.238 6.057-Energy supplied, net, KWH (In thousands):
'7,439,404 Generated.................
8,186,187 7,920,675 Purchased and interchanged............
617.651 711.791 584.853 Tot al...............
8.803.838 8.632.466 8.024.257 Energy sales, KWil (In. thousands):
Retail:
Residential.........
1,587,733 1,545,274 1,473,349 Commercial and industrial, small.......
1,834,953.
1,779,986 1,754,176 1
Commercial and industrial, large.........
1,271,449-1,216,941
,1,121,329 Sales to public authorities...
1.090.312 1.110.706 1.068.048-5,784,447 J 5,652,907 5,416,902 Wholesale:
i
' Sales for resale.....
1,897,885 1,753,553
'1,646,357 Economy sales.......
640.017 757.999 538.102
' Total sales.....
8,322,349 8,164,459
~ 7,601,361 Losses and company use.....
481.489.
468.007 422.896 Total......
8.803 838 8.632.466 8.024.257 Native system:
Peak load, KW............
1,122,000 1,105,000 1,088,000 Net generating capacity for peak, KW.,
1,500,000 -
1,500,000 1,500,000
- Load factor..........
64.0 %
63.4 %
61.6%
....4.
- Total system:
Pe ak load, KW..............................
1,442,000 1,387,000 1.374,000 Net generating capacity for peak, KW......
1,500,000 1,500,000 1,500,000 Load factor. '.
64.0 %
64.2 %
62.0 %
- (A) Financial data is based on the combined results for the Predecessor Company for the periodJanuary 1,1996 l-to February 11,1996 and the Reorganized Company for the period Februtuy 12,1996
[
(ll) Predecessor Company.
to December 31,1996.
10
Rtgulatisn Tces Rate Matters l
The rates and senices of the Company in Texas municipalities are regulated by those municipalities, and in unincorporated areas by the Texas Commission. The largest municipality in the j
Company's senice area is the City of El Paso. The Texas Commission has exclusive appellate jurisdiction to review municipal orders and ordinances regarding rates and senices in Texas and jurisdiction over certain other activities of the Company. The decisions of the Texas Commission are subject tojudicial review.
Rate Stipulation and Agreed Order. The Company's rates for its Texas customers are governed by a rate order entered by the Texas Commission in Docket 12700 adopting a Rate Stipulation and Agreed Order entered into by the Company, the Texas Commission stalT, the City of El Paso and virtually all other intervenors in the case. The Agreed Order implemented certain pmvisions of the Rate Stipulation and set rates consistent with the Rate Stipulation. Among other things, under the Rate Stipulation:
(i) the Company's base rates for most customers in Texas were fixed for the ten-year Freeze Period which began in August 1995; (ii) the City of El Paso granted the Company a new franchise that extends j
through the Freeze Period; (iii) the Company will retain 75% during the first five years of the Freeze Period and 50% during the remainder of the Freeze Period of (A) the net revenues generated by providing third-party transmission services and (B) profit margins from certain off-system power sales; (iv) the Company's reacquisition of the Palo Verde leased assets was deemed to be in the public interest; and (v) all appeals of Texas Commission orders concerning the Company and all outstanding Texas Commission dockets concerning the Company's rates were resolved.
i Neither the Rate Stipulation nor the Agreed Order deprives the Texas regulatory authorities of their jurisdiction over the Cornpany during the Freeze Period. However, the Texas Commission determined in the Agreed Order that the rate freeze is in the public interest and results in just and reasonable rates. Further, the signatories to the Rate Stipulation (other than the General Counsel, OPC
. and the State ofTexas) agreed not to seek to initiate an inquiry into the reasonableness of the Company's rates during the Freeze Period and to support the Company's entitlement to rates at the freeze level throughout the Freeze Period. The Company believes, but cannot assure, that its cost of service will support rates at or above the freeze level throughout the Freeze Period and, therefore, does not believe any attempt to reduce the Company's rates would be successful. Hmvever, during the Freeze Period, the Company is precluded from seeking rate increases in Texas, even in the event ofincreased operating or capital costs. In the event of a merger, the parties to the Rate Stipulation retain all rights provided in the Rate Stipulation, their rights to participate as a party in any proceeding related to the merger, and the right to pursue a reduction in rates below the freeze level to the extent of post-merger synergy savings.
Fuel. Pursuant to Texas Commission rules, the Company periodically must make a filing reconciling the revenues collected from Texas customers under its fixed fuel factor with the fuel and purchased power expenses actually incurred for the period covered by the reconciliation. A fuel and purchased power reconciliation must include not less than twelve months nor more than thirty-six months of reconcilable data. The Company has not filed a reconciliation for any period since June 1995. DilTerences between r-venues collected and expenses incur ed are subject to a refund to customers (in the case of an overrecevery of fuel costs) or surcharge (in the case of an underrecovery of fuel costs). The Texas Commission staff, local regulatory authorities such as the City of El Paso, and 11
customers are entitled to intervene in a fuel reconciliation proceeding and to challenge the recovery of fuel and purchased power expenses.
)
Higher than expected natural gas prices were experienced in December 1996, continued in the first quarter of 1997 and remained at higher levels through the remainder of 1997 compared to 1996.
These higher natural gas prices have increased the Company's underrecovered fuel costs, which will be reviewed in the next Texas fuel reconciliation.
A significant disallowance of fuel costs in this reconciliation could have an adverse effect on the Company's financial results. In January 1998, the Company filed a request with the Texas Commission to increase its Texas fixed fuel factor and implement a surcharge, subject to reconciliation, of its underrecovered fuel costs. The Company entered into a stipulation with all parties to the docket to implement the surcharge and a new fixed fuel factor. Both the fixed fuel factor and surcharge are expected to go into effect in April 1998.
Palo Verde Performance Standards. The Texas Commission has established performance standards for the operation of Palo Verde, pursuant to which each Palo Verde unit is evaluated annually to determine whether its three-year rolling average capacity factor entitles the Company to a reward or subjects it to a penalty. There are five performance bands based around a target capacity factor of 70%.
The capacity factor is calculated as the ratio of actual generation to maximum possible generation. If the capacity factor, as measured on a station-wide basis for any consecutive 24-month period, should fall below 35%, the Texas Commission could reconsider the rate treatment of Paio Verde, regardless of the provisions of the Rate Stipulation. The removal of Palo Verde from rate base could have a significanc negative impact on the Company's revenues and financial condition. For the three-year rolling average period ended December 31,1997, Palo Verde Units 1, 2 and 3 achieved capacity factors of 83.75%,
83.04% and 88.70%, respectively. These capacity factors result in the Company's entitlement to a combined reward of S2.8 million pursuant to the formula established by the Texas Commission for the Palo Verde units.
New Mexico Rate Matters The New Alexico Commission has jurisdiction over the Company's rates and services in New Alexico and over certain other activities of the Company, including prior approval of the issuance, assumption or guarantee of securities. The New Alexico Commission's decFions are subject tojudicial review. Current base rates in New Alexico were established in 1990 and have not increased since. The Company does not have an agreement with New Alexico regulatory authorities or parties to past New Alexico regulatory proceedings comparable to the Rate Stipulation. The largest city in the Company's New Alexico service territory is Las Cruces, which in 1997 accounted for 8% of the Company's total revenue. See item 3, " Legal Proceedings - Litigation with Las Cruces."
Pending l? ate Case. In October 1996, the New Alexico Commission issued an order in Case No. 2722, requiring the Company to answer certain ratepayer complaints and to file a rate filing package, including cost of service data and supporting testimony. On Alarch 3,1997, the Company filed with the New Alexico Commission all of the rate filing package data required by the Commission's order. Although the Company's filing demonstrates a revenue deficiency of approximately S8.6 million under current rates, the Company did not request a rate change to recover the deficiency. The New Alexico Commission could order a rate reduction or, alternatively, in response to economic factors and regulatom political and competitive pressures, the Company could agree to a rate reduction as part of an overall settlement of all issues in New Alexico. Prosecution of the rate case before the New Alexico 12
Commission is expected to be completed before the end of 1998. The Company is unable at this time to predict the outcome of this proceeding.
Fuel. The Company is required to make annual filings with the New Niexico Commission to reconcile the revenues collected under its fixed fuel factor with its fuel and purchased power expenses actually incurred, and to report the results of Palo Verde performance standards. These reports are due byJanuary 31 of each year for the preceding calendar year, and are filed along with the Company's request to revise its fixed fuel factor to reflect current projections of fuel and purchased power costs and to include the over or underrecovery reflected in the reconciliation report and the reward or penalty reflected in the performance standards report. On October 31,1997, the Company filed testimony and evidence supporting its continued use of the methodology and manner of collecting fuel and purchased power costs reflected in its tariffs. A hearing on this filing is scheduled forjuly 1998.
The Company's 1998 annual filing reflects a significant increase in the monthly fuel charge. This increase is necessary because of(i) significant increases in the spot price of natural gas and (ii) the delayed implementation of the 1997 change, effective with bills rendered on or after August 1,1997, which has caused the Company to underrecover its fuel costs in New hiexico by approximately S5.3 million for the year ended December 31,1997. The recovery of this amount, coupled with continued higher gas costs for 1998, results in an increase in the proposed 1998 fixed fuel factor of approximately 24% over the present factor. The Company believes it has fully justified its fuel and purchased power costs and recovery methodology. In Alarch 1998, the New hiexico Commission consolidated the 8 annual filing and the October 1997 filing for hearing inJuly 1998. There can be no assurance that the New hiexico Commission will accept the Company's proposed fixed fuel factor. As in Texas, interested parties are allowed to intervene and challenge the recoverability of fuel expenses. A significant disallowance of fuel costs could have an adverse effect on the Company's financial results.
Palo Verde Performance Standards. The New Alexico Commission has established performance standards for the operation of Palo Verde, pursuant to which the entire Palo Verde station is evaluated annually to determine ifits achieved capacity factor allows the Company to claim a reward or subjects it to a penalty. There are five performance bands based around a target capacity factor of 67.5%. Becaus Unit 3 is not included in the Company's New Alexico rate base, any penalty or reward calculated on a total station basis is limited to two-thirds of such penalty or reward. The capacity factor is calculated as the ratio of actual generation to maximum possible generation. If the annual capacity factor is 35% or less, the New Alexico Commission is required to initiate a proceeding to reconsider the rate base treatment of Palo Verde Units I and 2.
The removal of Palo Verde from rate base could have a significant negative impact on the Company's revenues and financial condition. For the year ended December 31,1997, the Palo Verde station capacity factor was 88.43%. This capacity factor results in the Company's entitlement to a reward of St.1 million, pursuant to the formula established by the New hiexico Commission fbr the Palo Verde units.
F:d:ral Regulatory Matters FederalEnergy Regulatop Commission. The Company is subject to regulation by the FERC in certain matters, including rates for wholesale power sales, transmission of electric power and the issuance of securities.
The Company has a long-term firm power sales agreement with IID providing for the sale of 100 AIW of firm capacity and 50 $1W of contingent capacity through April 2002. The agreement 13
generally provides for level sales prices over the life of the agreement. The Company also has a firm j
power sales agreement with TNP, providing for sales to TNP in the minimum amount of 25 MW
^
through 2002. Sales prices are essentially level for the remaining life of the agreement. Rate taritTs currently applicable to IID and TNP contain fuel and purchased power cost adjustment provisions designed to recover the Company's fuel and purchased power costs.
InJuly 1996, the Company filed its open access transmission tariffs (Docket No. OA96-200-000)
(the "Open Access Case"), in compliance with FERC Order No. 888, Promo.ing Wholesale Competition Through Open Access Non-Discriminatog Transmision Serrices by 1%blic Utilities; Recovery ofStranded Costs by Pu i
Utilities and Transmitting Utilities (" Order No. 888"), covering network and point-to-point transmission services and the six specifically required ancillary services. Several parties, including Las Cruces, other 4
utilities and several wholesale power marketers, intervened and filed protests to the Company's tariffs.
Issues raised by the intervenors included rates and the terms and conditions of the Company's tariffs, including the treatment of and costs related to, certain facilities making access to the CFE more available i
to parties other than the Company.
In February 1997, the Company entered into a stipulated
{
agreement among the various parties settling all rate issues related to the Open Access Case. Under the 4
i settlement, the Company will provide transmission senice, to the extent transmission capacity is available, to any party for firm or interruptible service to the CFE until the earlier of the end of 1998 or the date the FERC rules on the complaint filed by one of the wholesale power marketers that submitted a bid in 1996 to the CFE. See " Department of Energy" below.
Intervenors in the Open Access Case also raised certain issues relating to the criteria by which the Company will determine the amount of transmission capacity that is available for use by third parties desiring to use its transmission system. Hearings related to these issues were conducted before a FERC administrative law judge in January 1998. A final decision from the FERC on these issues is not expected until the fourth raarter of 1998. The Company does not expect a material financial impact to result from a FERC ruling.
InJuly 1996, Las Cruces exercised its right under Order No. 888 to request that the Company calculate Las Cruces'stcanded cost obligation should it leave the Company's system and operate its own municipal utility. For a discussion of this proceeding, see Item 3, " Legal Proceedings -- Litigation with
- Las Cruces."
Department ofEnergn The DOE regulates the Company's exports of power to the CFE in Mexico pursuant t. a license granted by the DOE and a presidential permit. In addition, the DOE is authorized to assess operators of nuclear generating facilities fbr a share of the costs of decom.missioning the DOE's uranium enrichment facilities a'nd for the ultimate costs of disposal of spent nuclear fuel. See " Facilities i
- Palo Verde Station - Spent Fuel Storage."
In September 1996, one of the wholesale power marketers that submitted a bid in 1996 to the CFE in connection with renewal of the interchange agreement for the supply of power during 1997 to CiudadJuarez, Mexico, filed a complaint against the Company with the FERC. The complaint sought emergency relief and requested the FERC to direct the Company to enter into an agreement to provide firm point to-point transmission senice to the CFE under the Company's open access transmission tariff.
In October.1996, the FERC issued 'an order requiring the Company to provide point-to-point transmission service over the Company's transmission system to substation facilities near the United States / Mexico border. The FERC, however, concurred with the Company's position that the
- FERC does not havejurisdiction to order transmission across the border, suggesting that the DOE has suchjurisdiction.-The DOE subsequently issued a Notice of Delegation and Assignment which delegated 14
to the FERC the DOE's authority to carry out its duties in this case. The FERC has docketed the Delegation and Assignment and the process is expected to continue throughout 1998.
Nuclear Regulatop Commission.
The -NRC has jurisdiction over the Company's licenses fbr Palo Verde and regulates the operation of nuclear generating stations to protect the health and safety of the public from radiation hazards and has authority to conduct environmental reviews pursuant to the National Environmental Policy Act.
Othrr Wholesale Customers The tenn of the Company's previous one-year 1997 sales agreement for finn capacity and associated energy to-the CFE terminated December 31, 1997. Pursuant to a bidding process, the Company was selected by the CFE to provide varying amounts of power during 1998 ranging from 90 to 200 MW. The price is stable throughout the twelve-month term of the agreement and includes charges for capacity and energy as well as transmission and any required ancillary senices. Under the new agreement, the Company's revenues in 1998 related to power sales to the CFE are expected to be similar to 1997 revenues. There can be no assurance that the CFE will remain a customer after 1998.
The agreement requires payment in United States dollars.
Rscent Changes in Utility Regulation General..The electric utility industry faces increasing pressure to become more competitive as legislative, regulatory, economic and technological changes occur.
Federal and state legislation, regulatory initiatives, and proposed initiatives in Texas and New Mexico encourage competition in the industry, and ultimately in the Company's senice area. Together with increasing customer demand for lower priced electricity and other energy senices, these measures have accelerated the industry's movement toward more competitive pricing and cost structures. Such competitive pressures could result in the loss ofcustomers and could diminish the ability of the Company to fully recover its investment in generation assets, as well as the cost of operating these assets. This issue is particularly important to the Company because its rates are significantly higher than national and regional averages. In the face of increased competition, there can be no assurance that the future operations, cash flows and financial condition of the Company will not be adversely affected, or that the Company will be able to sustain retail rates at the levels established by the Rate Stipulation during the Freeze Period.
Of particular importance to the Company is the issue of ultimate recoverability of " stranded costs," or costs previously found by regulatory authorities to be reasonable and prudent, but which at the same time are higher than would be recovered under immediate, full competition. There is substantial
' discussion and debate on this issue on both a national and state level and, at this time, there appears to be no clear solution.. At the federal level, the FERC has announced, through a formal rulemaking, its intention to' allow 100% recovery of all legitimate verifiable stranded costs attributable to FERC jurisdictional customers. Texas and New Mexico commissions and legislatures are engaged in various activities which are attempting to address the issue of stranded cost recovery from customers subject to theirjurisdictions.
FERC. In April 1996, the FERC issued its Order No. 888, requiring all public utilities owning, operating or controlling facilities used for transmitting electricity in interstate commerce to (i) file open access transmission tariffs containing minimum terms and conditions of non-discriminatory service and
-(ii) take transmissien senice (including ancillary services) for their own new wholesale sales and 15 s
.j
4 purchases of electric energy under the open access tariffs. Additionally, Order No. 888 permits public utilities to seek recovery oflegitimate, prudert and verifiable stranded costs and provides a mechanism for the recovery of such costs. Order No. 888 also prosides for recovery of costs associated with former power customers and new. municipally-owned entities becoming transmission-only customers as a result of providing open access transmission if the utility had a reasonable expectation of continuing to provide senice to the departing customer. Order No. 888 established criteria under which stranded costs will be evaluated for contracts entered into prior to July 11,1994, and for stranded costs resulting from the formation of any new municipal utilities. Recovery of stranded costs under contracts entered into after July 10,1994, will be governed by the terms of those contracts.
In April 1996, the FERC also issued Oider No. 889, Open Access Same-Time Infonnation @ stem (former[v Real-Time Information Networks) andStandards ofConduct (" Order No. 889"). Order No. 889 requires all public utilities owning, operating or controlling facilities used for transmitting electricity in interstate j
commerce to develop and maintain an Open Access Same-Time Information System that will give existing and potential transmission users access to transmission-related information on a basis consistent with that available to a utility's employees engaged in the buying and selling of power. Order No. 889 further requires public utilities to separate their transmission and generation marketing functions and adopt standards of conduct ensuring that all open access transmission customers are treated in a non-discriminatory manner.
Texas. During 1996, the Texas Commission conducted projects to evaluate the (i) scope of competition in the electric industry in Texas and (ii) potential stranded investment, procedures for allocating stranded costs, and acceptable methods of stranded cost recovery. The Texas Commission's report, which was issued inJanuary 1997, recommended a careful and deliberate approach to continued expansion of competition in the Texas electric market, ultimately leading to retail competition with certain safeguards, and recommended against any legislation that would introduce broad-based retail i
competition before 2000. The Texas Commission also quantified the potential retail " excess of cost over market" ("ECOM") under several scenarios. In February 1998, the Texas Commission requested all Texas utilities to revise the ECOM estimates based on certain updated assumptions. Using the Texas Commission's revised model inputs, the Company's revised ECOM estimates range from a high of S1.5 billion to a low of S843 million, with an expected value of S t.2 billion, assuming full retail access in 1999. Although several pieces oflegislation were oTered during the 1997 Texas legislative session, no significant deregulation legislation was passed.
In August 1997, the mutenant Governor appointed seven senators to sene on a special interim committee to study the various issues involved in a possible transition to a competitive electric market.
The committee is receiving testimony from various parties, including environmental advocates, consumer advocates, power marketers, public power entities, electric cooperatives and investor-owned utilities, as Ni as testimony and comments from the public at large, and is holding public hearings across the state on various aspects of the electric industry restructuring debate. The Association of
. Electric Companies of Texas (the "AECT") testified on behalf of all investor-owned utilities in Texas, including the Company. The AECT testified that it would support retail competition that provides benefits to all consumers, maintains electric system reliability, provides for equitable treatment of all competitors and provides for the preservation of prior regulatory commitments. The committee is expected to file a final report in late 1998. Recently, the Lieutenant Governor asked the Texas
. Comptroller of Public Accounts to initiate a study to review the impact of a deregulated electric market on state and local tax systems.
16
Xew Alexico. In 1995, the New hiexico Commission initiated a notice of inquiry regarding competition and the restructuring of regulation of the electric industry. The New hiexico Commission received comments from numerous parties representing various interests and conducted workshops in an attempt to arrive at a consensus with respect to the need for regulatory change, the nature of such I
change and the timing / transition of any changes. No consensus was reached by the participants. The New hiexico Commission also commenced a collaborative process with the assistance of facilitators in an attempt to reach consensus. Although that collaborative process failed to reach a consensus around which restructuring legislation could be drafted, the New hiexico investor-owned utilities, including the
)
~
Company, have agreed to support legislation that would permit retail competition provided: (i) all j
customers have the opportunity to benefit, (ii) reliability of electric service is maintained, (iii) all energy suppliers are subject to the same laws and regulations,(iv) the price of electric generating capacity and electric energy is determined solely by market forces, (v) unbundled transmission and distribution functions remain subject to regulation, and (vi) each electric utility must have a reasonable opportunity to recover its stranded costs. The 1998 legislative session concluded without the passage of any j
. significant deregulation legislation.
Reorganization Under Chapter 11 of the United States Bankruptcy Code On February 12,1996, the Company emerged from a bankruptcy proceeding which it instituted in January 1992. As a result of the Reorganization, the Company significantly reduced its debt and simplified its capital structure.. The Company's total obligations subject to compromise (including obligations related to the Palo Verde leases, which represented S700 million of allowed claims in the Bankruptcy Case) prior to its Reorganization was S2,007 million. Under the Plan, this debt and the Palo Verde Lease obligations were extinguished and the creditors received a combination of S212 million cash and newly issued debt and equity securities of the Reorganized Company consisting of
$1,189 million of long-term bonds and fmancing and capital lease obligations, S100 million of redeemable preferred stock and $255 million ofcemmon stock.
Under the Plan, all of the Predecessor Company's common and preferred stock was canceled and the holders of such securities received approximately S45 million (15%) of the Reorganized Company's common stock and the right to receive certain potentiallitigation recoveries which ultimately amounted to S20 millicn. In addition, on the Effective Date, the Palo Verde Irases were terminated and the Company reacquired such interests. See Part II, Item 8, " Financial Statements and Supplementary Data - Note H of Notes to Financial Statements."
.The Reorganized Company's fmancial statements for periods after February 12,1996 are not comparable to the Predecessor Company's financial statements for periods before February 12,1996. A vertical line is shown in the accompanying selected financial data and financial statements to separate the Reorganized Company from the Predecessor Company because the respective financialinformation has not been prepared on a consistent basis of accounting.
17
-~_ -.. _
Executive Officers of the Company Current Position and Name Age Business Experience l
James S. Haines........
51 Chief Executive Omcer, President and Director since May 1996; Executive Vice President and Chief Operating Omcer of Western Resources, Inc. from June 1995 to May 1996; Executive Vice President and Chief Administrative Omcer of Western Resources, Inc. from i
April 1992 tojune 1995.
4 Eduardo A. Rodriguez......
42 Senior Vice President - Customer and Corporate Services since August 1996; Senior Vice President sinceJanuary 1994; Vice President from April 1992 tojanuary 1994; General Counsel from 1988 to August 1996; Secretary fromjanuary 1989 tojanuary 1994.
J. Frank Bates..................
47 Vice President - Transmission and Distribution since 2
August 1996; Vice President - Operations from May 1994 to August 1996; Vice President - Customer i
Services Texas Division fromJune 1989 to May 1994.
Michael L. Blough..................... 42 Vice President - Administration since August 1996; Vice President since May 1995; Controller and Chief Accounting Omcer from November 1994 to August 1996; Assistant Vice President - Financial Planning from September 1990 to November 1994.
G ary R. H edrick...................... 4 3 Vice President, Chief Financial Omcer and Treasurer since August 1996; Treasurer since March 1996; Vice President - Financial Planning and Rate Administration from September 1990 to August 1996.
i John C. Horne............
49 Vice President - Power Generation since August 1996; Vice President - Power Supply from May 1994' to August 1996; Vice President - Transmission Systems 4
Division from August 1989 to May 1994.
Robert C. McNiel.....................
51 Vice President New Mexico Affairs since i
December 1997; Vice President - Public Affairs and i
Marketing from August 1996 to December 1997; Vice President - New Mexico Division from December 1989 to August 1996.
Terry Bassham........................... 37 General Counsel since August 1996; Shareholder with Clark, Thomas & Winters, P.C. from May 1993 to August 1996; Shareholder with Moreno, Fry & Bassham from February 1992 to May 1993.
Guillermo Silva,Jr...........
44 Secretary since Janeary 1994; Assistant Secretary from June 1989 tojanuary 1994.
The executive omcers of the Company are elected annually and serve at the discretion of the Board of Directors.
18 4:
1
It:m 2.
Properties The principal properties of the Company are described in Item 1, " Business," and such descriptions are incorporated herein by reference. Transmission lines are located either on private rights-of-way, casements or on streets or highways by public consent. See Part II, Item 8, " Financial Statements and Supplementary Data - Note F of Notes to Financial Statements" for information regarding encumbrances against the principal properties of the Company.
Item 3.
Legal Proceedings Litigation with Las Cruces Las Cruces is attempting to replace the Company as the electric service provider in Las Cruces by acquiring, through condemnation or a negotiated purchase, the distribution assets and other facilities used to provide electric service to customers in l2s Cruces. Sales to customers in Las Cruces represent approximately 8% of the Company's operating revenues.
In April 1995, Las Cruces filed a complaint against the Company in New hiexico state court, seeking a declaratoryjudgment that I2s Cruces has a right of eminent domain to condemn the electric distribution system and related facilities owned and operated by the Company within and adjacent to the city limits. In Alay 1995, the Company removed the case to federal district court in New hiexico.
Following a trial on the merits, the Federal hlagistrate granted the Company's motion to certify to the New hiexico Supreme Court the question of whether Las Cruces possesses the authority to condemn the Company's property for use as a municipal utility when that property is already devoted to public use.
Prior to a ruling by the New Niexico Supreme Court, the New hiexico legislature enacted a bill which purports to give Las Cruces the authority to condemn the Company's distribution system within its city limits and a territory extending five miles beyond the municipal boundary. On February 11,1998,the New hlexico Supreme Court ruled that the subsequent legislation rendered moot the certified question before the Supreme Court. On February 26,1998, the Company received notice from Las Cruces ofits intent to file a condemnation action in New hiexico district court. At this time the Company is unable to predict the outcome of this litigation.
If12s Cruces succeeds in its efibrts to condemn the Company's distribution system, the Company could lose its las Cruces customer base, although the Company would be entitled to receive "just compensation" as established by the court under New hlexico law. "Just compensation" is generally defined as the amount of money that would fairly compensate the party whose property is condemned.
It is the Company's opinion that this amount would be the difference between the value of the Company's entire system prior to the taking, as compared to the value of the entire system after the taking. See Item 1, " Business - Regulation - Federal Regulatory Alatters" for a full discussion of stranded costs.
I2s Cruces has taken several actions to position itself to acquire portions of the Company's distribution system and certain related facilities. In August 1991, SPS and Las Cruces entered into a fifteen-year contract granting SPS the right to provide all of the electric power and energy required by Las Cruces during the term of the contract. In addition, Las Cruces sold appro:.imately S73 million in revenue bonds in October 1995 to provide funding to finance the acquisitioi by condemnation or 19
negotiated purchase of the Company's electrical distribution assets within and adjacent to the Las Cruces city limits.
The Company has filed a lawsuit in the Dona Ana County District Court and is pursumg a complaint simultaneously before the New Mexico Commission challenging the legality of the sale of the revenue bonds. In addition, the New Mexico Commission is investigating the agreement between SPS q
and Las Cruces which, under certain circumstances, would g: ant Las Cruces an option to sell to SPS electric utility assets acquired through condemnation. In August 1996, the Dona Ana County District Court issued an opinion letter stating that Section 3-23-3 of the New Mexico Municipal Code is inapplicable to home rule municipalities and Las Cruces, thereibre, was not required to acquire the New Mexico Commission's approval before issuing revenue bonds to acquire utility property. However, the Court did agree with the Company that the revenue bonds, in this case backed by utility revenues, are subject to the same requirements as those imposed on other revenue bonds backed by gross receipts tax revenues. Therefore,if the Court's finding of the applicability of Las Cruces' home rule authority is overturned on appeal, the Company's position that the issuance of the bonds required prior approval could be upheld. The Company filed an appeal with the New Mexico Court of Appeals and Las Cruces requested an expedited ruling from the Court of Appeals. In August 1997, the New Mexico Court of Appeals certified to the New Mexico Supreme Court the issues related to Las Cruces' authority to issue the revenue bonds. Oral argument before the Supreme Court was held in November 1997.
InJuly 1996, Las Cruces exercised its right under Order No. 888 to request that the Company calculate Las Cruces' stranded cost obligation should it leave the Company's system and operate its own municipal utility. The Company's initial non-binding calculation was provided within the statutory period. Las Cruces subsequently filed a request at the FERC for a determination that Las Cruces would have no stranded cost obligation to the Company or, in the alternative, that the FERC convene a hearing to establish the amount of any stranded costs. In August 1997, the FERC issued an order denying Las Cruces' request Ibr a determination that Las Cruces would have no stranded cost obligation, and providing for evidentiary hearings on the following stranded costs issues: (i) whether the Company has met the " reasonable expectation" standard so as to justify recoven of stranded costs from Las Cruces; and (ii) if so, the amount of stranded costs that the Company may recover from Las Cruces. The Company filed testimony in support ofits recovery and calculation ofstranded costs, calculated pursuant to the FERC formula. After removal of all distribution and transmission related expenses, the Company's testimony reflects a generation stranded cost request of approximately S101 million. In November 1997, Las Cruces filed testimony which takes the position that the Company is entitled to stranded costs in the range of S0 to S19 million. On December 19,1997, the FERC stafTfiled testimony estimating the Company's stranded cost to be S29.4 million. Hearings of all issues were conducted at the FERC in February 1998. A final decision from the FERC is not expected before late 1998 or early 1999.
In April 1997, Las Cruces announced its plan to build a substation and distribution lines to serve a new customer in a city-owned industrial park. Las Cruces stated that SPS would construct, operate and maintain the new substation facility, and that the rates for this new customer would be significantly lower than the Company's current rates. Las Cruces has approved a contract with SPS to provide operation and maintenance senices for the proposed Las Cruces electric distribution system, substations and associated transmission facilities.
20
The Company continues to believe that it can provide lower cost electric service to customers in Las Cruces than can be achieved through a municipal takeover. Accordingly, the Company has stated its strong preference for a resolution ofits differences with Las Cruces through negotiation rather than litigation and condemnation. A negotiated settlement of the Company's pending rate case in New Mexico could include a reduction in rates and settlement of all issues in New Mexico, which would be likely to create increased political and economic pressure on the Company to reduce rates in Texas.
The Company is unable to predict the outcome of Las Cruces' efforts to replace the Company as its electric sersice provider or the efTects it may have on the Company's financial position, results of operations and cash flows. The Company does not believe it is probable that a loss has been incurred and, therefore, has made no provision in the accompanying financial statements related to these matters.
j Four Corners In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act and the Navajo Nation Pesticide Act (collectively, the " Acts"). In October 1995, the Four Corners participants requested that the United States Secretary of the Interior resolve their dispute with the Navajo Nation regarding whether the Acts apply to operation of Four Corners. The Four Corners participants subsequently filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, seeking, among other things, a declaratory judgment that (i) the Four Corners leases and federal easements preclude the application of the Acts to the operation of Four Corners; and (ii) the Navajo Nation and its agencies and courts lack adjudicatory jurisdiction to determine the enforceability of the Acts as applied to Four Corners. On October 18, 1995, the Navajo Nation and the Four Corners participants agreed to stay the proceedings indefinitely so the parties may attempt to resolve the dispute without litigation. This matter remains inactive and the j
Company is unable to predict the outcome of this case.
Water Cases SanJuan River Systern. The Four Corners participants are among the defendants in a suit filed by the State of New Mexico in 1975 in state district court in New Mexico against the United States of America, the City of Farmington, New Mexico, the Secretary of the Interior as Trustee for the Navajo Nation and other Indian tribes and certain other defendants (State ofNewMexico ex rel. S. E. Rgnolds, New Mexico State Engineer v. United States ofAmerica, et al., Eleventh Judicial District Court, County of San Juan, State of New Mexico, Cause No.75-184). The suit seeks adjudication of the water rights of the SanJuan River Stream System in New Mexico, which, among other things, supplies the water used at Four Corners. An agreement reached with the Navajo Nation in 1985 provides that if Four Corners loses a portion of its water rights in the adjudication, the tribe will provide sufIicient water from its allocation to offset the loss. The case has been inactive for many years and the Company is unable to predict the outcome of this case.
Gila River Systern. In connection with the construction and operation of Palo Verde, APS entered into contracts with certain municipalities granting APS the right to purchase efIluent for cooling purposes at Palo Verde. In 1986, a summons was served on APS that required all water claimants in the Iower Gila River Watershed in Arizona to assert any claims to water in an action pending in Maricopa County Superior Court, titled In re 7he General Adjudication ofAll Rights to Use Water in the Gila River System andSource. Palo Verde is located within the geographic area subject to the summons and the rights of the 21
_. -.~.
4 i-Palo Verde Participants to the use of groundwater and efiluent at Palo Verde is potentially at issue in this actionc _ APS, as operating agent, filed claims that dispute the Court's jurisdiction over the Palo Verde Participants' groundwater rights and their. contractual rights to efRuent relating to Palo Verde and, alternatively, seek confirmation of such' rights. In December 1992, the Arizona Supreme Court heard oral argument on certain issues in this matter that are pending on interlocutory appeal.. Issues important to the Palo Verde Participants' claims were remanded to the trial court for further action and the trial C
' court certified its decision for another interlocutory appeal to the Arizona Supreme Court The Arizona j
- Supreme Court will hear argument on these issues in October 1998 and subsequently render a decision.
j The Company is unable to predict the outcome of this case.
Other Legal Proceedings i
The Company is a party to various other claims, legal actions and complaints. In many of these matters, the Company has excess casualty liability insurance which is applicable.. Based upon a review
-of these claims ~and applicable insurance coverage, the Company believes that none of these claims will have a material adverse effect'on the operations, financial position or cash flows of the Company, b
' Item 4.
Submission of Matters to a Vote of Security Holders 4
i Not applicable.
e 1
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4 p
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l PART II Item 5.
Market for Registrant's Common Equity and Related Stockholder Matters The Company's common stock began trading on the American Stock Exchange on February 16, 1996 under the symbol "EE."
The high and low sales prices for the Company's common stock, as i
reported in the consolidated reporting system of the American Stock Exchange, for the periods indicated below, were as follows:
Sales Price l
High Low 1997 Fi rs t Qu a rte r...................................... S 715/isS 5%
Second Quarter...............
7%
5%
Thi rd Quarter..............................
7%s 5B/is Fourth Quarter.............
' 7%
5%
1996 February 16 - March 31......................... S 6%
S 4%
Second Quarter.........................
6%
5 Thi rd Quarte r.............................
6%
5%
Fo u rt h Qu a rt e r.....................................
6%
415/is At March 17,1998, there were 6,141 holders of record of the Company's common stock.
The Company's ability to pay dividends on the common stock for the next several years will be j
limited by; applicable law and by the fmancing arrangements entered into pursuant to the Reorganization. Pursuant to the resolutions creating the Company's Series A Preferred Stock, no dividends can be paid on the common stock if there are dividends in arrears on the Series A Preferred Stock. Pursuant to the First and Second Supplemental Indentures, so long as the Company's First hlortgage Bonds, are outstanding and the series with the longest maturity is not rated " investment grade"
.by either Standard & Poor's Rating Sersice or Moody's Investors Sersice, Inc., the Company may not declare any dividend on the common stock,~ other than in additional shares of common stock, or make any 'other distribution on, or acquire for value any shares of common stock (with certain limited exceptions) unless, after giving effect thereto, the aggregate of all such dividends, distributions and certain other payments made by the Company since February 12,1996 would be less than the sum of(i) 50% of the consolidated net income (as defined in the mortgage indenture) of the Company minus dividends paid in respect of the Series A Preferred Stock for the period from February 13,1996 to the most recently ended fiscal quarter fbr which quarterly financial statements are available (or, if such consolidated net income is a deficit, less 100% of such deficit), plus (ii) 100% of the aggregate net proceeds received by the Company from the issuance or sale since February 12,1996 of equity securities or debt securities that have been converted into equity securities, plus (iii) S10.0 million. Currently, the Company's First Mortgage Bonds are not rated investment grade.
. -Pursuant to the terms of the reimbursement agreements related to four letters of credit issued with respect to the four series of pollution control revenue bonds, so long as a drawing is available under any of the letters of credit, the same limitation contained in the First and Second Supplemental i
23
\\
Indentures on the declaration of dividends would apply to the Company. In addition to the restriction contained in the mortgage indenture, the credit agreement for the working capital and fuel financing facility limits to S15.0 million the aggregate amount of dividends that can be paid on the common stock during the three years aller its initial issuance on February 12,1996.
j l
i 24
Cm 6.
S2het,d Fin:ncirl D:ts
)
As of and for the following periods (In thousands except for share data):
Period from Period From Year February 12 January 1 Ended to to December 31, December 31, February 11, Years Emded December 31.
1997 1996 1996 1995,_
1994 1993
)perating revenues.
591,038 3 523,974 54,949 $
504,617 3
536,760 $
543,594
- )perating income..
161,667 144,491 1,639 49,874 54,997 57,035 acome (loss) before extraordinary items and cumulative effect of a change in accounting principle..
54,568 41,919 118,198 (33,319)-
(28,153)
(41,855) xtraordinary loss on repurchases of debt, net of federal income tax benefit.
(2,775) htraordinary gain on discharge of debt.
264,273 Jumulative effect of a change in accounting principle..
~-
(%,044) m l k'et income (loss) applicable to conunon stock..
38,649 31,431 382,471 (33,319)
(28,153)
(137,899) lasic earnings per common share:
Income (loss) before extraordinary items and cumulative effect of a change in accounting principle..
0.689 0.523
- 3.325 (0.937)
(0.792)
(1.178)
Extraordinary loss on repurchases of debt, net of federal income tax benefit (0.046)
Extraordinary gain on discharge of debt.
7.435 Cumulative effect of a change in accounting principle.
(2.702) m Net income (loss) 0.643 0.523 10.760 (0.937)
Neighted average number of common (0.792)
- (3.880) 4 shares outstanding 60,128,505 60,073,808 35,544,330 35,544,330 35,544,330 35,539,480
.)iluted earnings per common share:
j Income (loss) before extraordinary items and cumulative effect of a change in accounting principle z 0.685 0.523 3.325 (0.937)
(0.792)
(1.178)
Extraordinary loss on repurchases of debt, net of federalincome tax benefit..
(0 triQ
~
Extraordinary gain on discharge of debt..
7.435 Cumulative effect of a change in a.ccounting principle...
(2.702) m Net income (loss)..
0.639 0.523 10.760 (0.937)
(0.792)
(3.880)
Neighted average number of common shares and common share equivalents outstanding..-
60,437,632 60,116,709 35,544,330 35,544,330 35,544,330 35,539,480 Additions to utility plant..
75,431 53,346 8,176 87,937 59,976 57,806 fotal assets..
1,812,613 1,846,190 1,910,354 1,809,891 1,730,851 1,715,406 ang-term debt and financing and capital lease obligations....
966,810 1,046,173 1,164,328
- )cht and obligations subject to compromise..
1,608,091 1,537,303 1,495,315
> referred stock..
121,319 108,426 100,000 81,464 81,464 81,464 Jommon stock equity (deficit).,
369 640 31M57 300 000 (418.7631 (3R5 966)
(357_463)
(
) Reflects the change in accounting for income taxes due to the implementation of SFAS No.109, " Accounting fc r Income Taxes."
The selected financial data should be read in conjunction with Item 7, " Management's Discussion and Analysis of Financial Condition and Results of Operations," and Item 8, " Financial Statements and Supplementary Data."
25
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1 Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations Statements in this document, other than statements of historical information, are fonvard-looking statements that are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements, as well as other oral and written fonvard-looking statemenu made by or on behalf of the Company from time to time, including statements contained in the Company's filings with the Securities and Exchange Commission and its reports to stockholders, involve known and unknown risks and other factors which may cause the Company's actual results in future periods to differ materially from those expressed in any fonvard-looking statements. Any such
. statement is qualified by reference to the risks and factors discussed below under the headings
" Operational Prospects and Challenges" and " Liquidity and Capital Resources" and in the Company's filings with the Securities and Exchange Commission, which are available from the Securities and Exchange Commission or which may be obtained upon request from the Company. The Company cautions that the foregoing list ofimportant factors is not exclusive. The Company does not undertake to update any fonvard-looking statement that may be made from time to time by or on behalf of the Company.
i Operational Prospects and Challenges While the Company prepares for a new era of deregulation and competition in the electric utility industry, the Rate Stipulation provides a certain level of stability in the rates that the Company currently charges the majority ofits customers. During the Freeze Period, the Company's strategic goals include (i) serving the growing need for electricity within its retail senice territory; (ii) continuing to focus on its strategic location on the border with Mexico; (iii) enhancing long-term relationships with its largest retail customers; (iv) continuing to reduce operating costs; and (v) developing an energy-related services business The Company faces a number of challenges which could negatively impact its operations during the Freeze Period. The primary challenge is the risk ofincreased costs, including the risk of additional or unanticipated costs at Palo Verde resulting from (i) increases in operation and maintenance expenses; (ii) the possible replacement of steam generators; (iii) an extended outage of any of the Palo Verde units; (iv) increases in estimates of decommissioning costs; (v) the storage of radioactive materials; and (vi) compliance with the various requirements and regulations governing commercial nuclear generating stations. There can be no assurance that the Company's revenues will be suflicient to recover any increased costs incurred during the Freeze Period, including any such increased costs in connection with Palo Verde or increases in other costs of operation, whether as a result of higher than anticipated levels ofinflation, changes in tax laws or regulatory requirements, or other causes.
In December 1996 and the first quarter of 1997, rapid escalation in natural gas prices increased concern over price levels for energy, including electricity. The Company's recovery of fuel expense is subject to challenges regarding reasonableness and prudence through periodic fuel reconciliation proceedings. See Part I, Item 1, " Business - Regulation - Texas Rate Matters - Fuel" and "-
Regulation - New Mexico Rate Matters - Fuel."
Another risk to the Company's operations is the potential loss of customers. The Company's wholesale and large retail customers have, in varying degrees, additional alternate sources of economical 26
J Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations Statements in this document, other than statements of historical infonnation, are fonvard-looking statements that are made pursuant 'to the safe harbor provisions of the Private Securities Litigation Reform Act of1995. Such fonvard-looking statements, as well as other oral and written fonvard-looking statements made by or on behalf of the Company from time to time, including statements contained in the Company's filings with the Securities and Exchange Commission and its reports to stockholders, involve known and unknown risks and other factors which may cause the Company's actual results in future periods to differ materially from those expressed in any fonvard-looking statements. Any such statement is qualified by reference to the risks and factors discussed below under the headings
" Operational Prospects and Challenges" and " Liquidity and Capital Resources" and in the Company's filings with the Securities and Fxchange Commission, which are available from the Securities and Exchange Commission or which may be obtained upon request from the Company. The Company 2
cautions that the foregoing list ofimportant factors is not exclusive. The Company does not undertake to update any forward-looking statement that may be made from time to time by or on behalf of the Company.
'f Operational Prospects and Challenges While the Company prepares for a new era of deregulation and competition in the electric utility industry, the Rate Stipulation provides a certain level of stability in the rates that the Company currently 4
charges the majority ofits customers. During the Freeze Period, the Company's strategic goals include (i) serving the growing need for electricity within its retail service territory; (ii) continuing to focus on its strategic location on the border with Mexico; (iii) enhancing long-term relationships with its largest retail
]
customers; (iv) continuing to reduce operating costs; and (v) developing an energy-related services
- business.
1 The Company faces a number of challenges which could negatively impar its operations during the Freeze Period. The primary challenge is the risk ofincreased costs, includiry the risk of additional or unanticipated costs at Palo Verde resulting from (i) increases in operation.nd maintenance expenses; (ii) the possible replacement of steam generators;(iii) an extended outage of any of the Palo Verde units; (iv) increases in estimates of decommissioning costs; (v) the storage of radioactive materials; and (vi) compliance with the various requirements and regulations governing commercial nuclear generating stations. There can be no assurance that the Company's revenues will be suflicient to recover any increased costs incurred during the Freeze Period, including any such increased costs in connection with Palo Verde or increases in other costs of operation, whether as a result of higher than anticipated levels ofinflation, changes in tax laws or regulatory requirements, or other causes.
In December 1996 and the first quarter of 1997, rapid escalation in natural gas prices increased concern over price levels for energy, including electricity. The Company's recovery of fuel expense is subject to challenges regarding reasonableness and prudence through periodic fuel reconciliation proceedings. See Part I, item I, " Business - Regulation - Texas Rate Matters - Fuel" and "-
Regulation - New Mexico Rate Matters - Fuel."
Another risk to the Company's operations is the potential loss of customers. The Company's wholesale and large retail customers have, in varying degrees, additional alternate sources of economical 26
power, including co-generation of electric power. For example, a 504 MW combined-cycle generating 3
plant located in Samalayuca, Chihuahuai which is scheduled to be fully operational by the end of 1998,
.will give the CFE the current capacity to supply electricity to portions of northern Chihuahua, including the geographic area currently served by the Company. If the Company loses a significant portion ofits retail customer base or wholesale sales, the Company may not be able to replace such revenues through either the addition of new customers or an increase in rates to remaining customers. The New Mexico State legislature has passed legislation which gives Las Cruces the apparent legal authority to condemn the Company's distribution system and related assets located within its city limits, and the Company has received notice from Las Cruces of its intent to file an eminent domain proceeding. If Las Cruces succeeds in its efforts, the Company could lose its Las Cruces customer base, although the Company would receive "just compensation" as established by the court. See Part I, Item 3, " legal Proceedings -
litigation with Las Cruces."
.l In recent years, the United States has closed a large number of military bases and there can be no assurance that llolloman Air Force Base ("Ilolloman"), White Sands Missile Range (" White Sands")
or the. United States Army Air Defense Center at Fort Bliss ("Ft. Bliss") will not be closed in the future or that the Company will not lose all or some of ns military base sales. The Company's sales to the military
. bases represented approximately S19.6 million or 3% of operating revenues for the year ended December 31,1997. The Company signed a new contract with Ft. Bliss in August 1996, under which FtiBliss will take service from the Company through 1999, with the right thereafter to continue service
- on a year-to-year basis for an additional two years. :The Company has a contract to provide retail electric service to Holloman for a ten-year term which began in December 1995. In August 1996, the Army advised the Company White Sands would continue to purchase retail electric service from the Company pursuant to the existing retail service contract for an indefinite period. The Army will provide
. the Company written notice of termination of such contract not less than one year in advance of the
- termination date.
The Company does not currently have an agreement with New Mexico regulatory authorities or parties.to past New Mexico regulatory proceedings comparable to the Rate Stipulation. Pursuant to an order from the New Mexico Commission, the Company filed rate data with the Commission in March 1997. Although the Company's filing demonstrates a revenue deficiency of approximately S8.6 million under current rates, the Company did not request a rate change to recover the deficiency. The New Mexico' Commission could, after hearing, order a rate reduction or, alternatively, in response to regulatory, political and competitive pressures, the Company could agree to a rate reduction as part of an overall settlement of all issues in New Mexico, which would be likely to create increased political and economic pressure on the Company to' reduce rates in Texas. Prosecution of the case before the New Mexico Commission is expected to be completed in 1998. The Company is unable at this time to
. predict with certainty the outcome of this proceeding currently pending before the New Mexico Commission. See Part I, Item I, " Business - Regulation - New Mexico Rate Matters."
sThe Company faces the same concerns as most othec companies that use computers relating to the Year 2000 problem. The problem is that many computer applications do not correctly differentiate a one year difference betiveen the years $99 and 2000. Applications that are date sensitive may not prouerly calculate information or may not function.
The Company began working on the Year 2000 computer concern during the last quarter of 1996 and is attempting to either revise current computer systems to be Year 2000 compliant, or replace 27
i systems with new ones that are Year 2000 compliant by the end of 1998, to allow adequate time fbr additional testing and correction. Incremental costs of the project are anticipated to be immaterial as the Company is using internal resources to modify and test programs. The Company anticipates spending approximately $1.8 million on this project and is expensing such amount as incurred over the life of the project.
Because of the integrated nature of the Company's business with other utilities and its joint facilities operated by other utilities, the Company is inquiring about and reviewing the activities of the other utilities which comprise the integrated system. In addition, the Company is inquiring about and reviewing the activities of its financial institutions and major suppliers to determine their compliance with Year 2000 issues. Given the complex nature of this problem and the potential overlap with systems beyond the Company's control, the Company cannot assure that it will not experience some difficulty relating to the Year 2000 problem.
Finally, the electric utility industry in general is facing significant challenges and increased competition as a result of changes in federal provisions relating to third-party transmission services and independent power production, as well as potential changes in state regulatory provisions relating to wholesale and retail service.
Both the Texas and New Mexico Commissions have conducted proceedings related to industry restructuring and stranded cost recovery; however, restructuring legislation has yet to be passed in either state. See Part I, Item 1, " Business - Regulation - Recent i
Changes in Utility Regulation." The potential efTects of deregulation are particularly important to the Company because its rates are significantly higher than the national and regional averages. In the face ofincreased competition, there can be no assurance that such competition will not adversely affect the future operations, cash flow and financial condition of the Company.
Liquidity and Capital Resources The Company's principal liquidity requirements through the end of the decade are expected to consist of interest payments on the Company's indebtedness and capital expenditures related to the Company's generating facilities and transmission and distribution systems. The Company expects that cash flows from operations will be suflici nt for such purposes.
Iong-term capital requirements of the Company will consist primarily of construction of electric utility plant, payment of interest on and retirement of debt, and payment of dividends on and redemption of preferred stock. The Company has no current plans to construct any new generating capacity through at least 2004. Utility corutruction expenditures will consist primarily of expanding and updating the transmission and distribution systems and the cost of betterments and improvements to Palo Verde and other generating facihties.
The Company anticipates that internally generned funds will be sufTicient to meet its construction requirements, provide for the retirement of debt at maturity and enable the Company to meet other contingencies that may exist, such as compliance with. environmental regulation, pending litigation and any claims for indemnification. At December 31,1997, the Company had approximately Sl11.2 million in cash and cash equivalents. The Company also has a $100 million revolving credit facility, which provides up to S60 million for nuclear fuel purchases and up to S50 million (depending on the amount of borrowings outstanding for nuclear fuel purchases) for working capital needs. At 28
i December 31, 1997, approximately S52.0 million had been drawn for nuclear fuel purchases. No amounts have been drawn on this facility for working capital needs.
The Company has a high debt to capitalization ratio and significant debt service obligations. Due to the Rate Stipulation and competitive pressures, the Company does not expect to be able to raise its base rates in the event of increases in non-fuel costs or loss of revenues. Accordingly, soon after its emergence from bankruptcy, the Company established debt reduction as a high priority in order to gain additional financial flexibility to address the evolving competitive market.
The Company has significantly reduced its long-term debt following the Reorganization. From June 1,1996 through March 18,1998, the Company repurchased approximately S230.3 million of first mortgage bonds as part of an aggressive deleveraging program and has reduced its annual interest expense by approximately S17.9 million. Long-term indebtedness as a percentage of capitalization was reduced from 74% atjune 30,1996 to 66% at December 31,1997.
The Company continues to believe that the orderly reduction of debt with a goal of achieving a capital structure that is more typical in the electric utility industry and, ultimately, an investment grade rating, is a significant component oflong-term shareholder value creation. Accordingly, the Company will regularly evaluate market conditions and, when appropriate, use a portion ofits available cash to reduce its fixed obly tions through open market purchases of first mortgage bonds. However, the significant amount of debt reduction that the Company has achieved since the Reorganization, and the need for cash both to meet upcoming bond maturities and, if appropriate, to redeem early the Series A Preferred Stock, may result in a lower volume of repurchases in the future. Accordingly, the Company may experience a net increase in cash as it evaluates the comparative economic value of using excess cash for purposes other than open market purchases ofits first mortgagt bonds.
The degree to which the Company is leveraged could have important consequences on the Company's liquidity, including (i) the Company's ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate or other purposes could be limited in the future; (ii) a substantial portion of the Company's cash flow from operations will be dedicated to the payment of principal and inte.est on its indebtedness and, if appropriate, the early redemption of its Series A Preferred Stock; and (iii) the Company's substantial leverage may place the Company at a competitive disadvantage by limiting its financial flexibility to respond to the demands of the competitive market and make it more vulnerable to adverse economic or business changes.
Historical Results of Operations Fmancial comparisons herein for the years ended December 31,1997,1996 and 1995 are based on the results of operations of the Reorganized Company for the year ended December 31, 1997, combined results of the Reorganized Company for the period February 12,1996 to December 31,1996 and the Predecessor Company fbr the periodJanuary 1,1996 to February 11,1996, and results of the Predecessor Company for the year ended December 31,1995.
Net income applicale to common stock before extraordinary item in 1997 was approximately S41.4 million, or S0.69 per diluted common share, compared with combined net income applicable to common stock before reorganization items and extraordinary item of $27.4 million for the same period a 29 i
year ago, and net loss before reorganization items of $23.3 million, or S0.66 per diluted common share in 1995.
I Operating revenues net of energy expenses increased S4.7 million in 1997 compared to 1996, primarily due to increased KWH sales, partially ofTset by reduced revenue per KWH from the CFE.
Operating revenues net ofenergy expen; s increased S43.8 million in 1996 compared to 1995, primarily due to an increase in Texas base rates associated with the implementation of the Rate Stipulation and increased KWH sales.
Comparisons of KWH sales and operating revenues are shown below (In thousands):
Increase /(Decrease)
Years Ended December 31:
1997 1996 Amount Percent 4
Electric KWH Sales:
Retail Customers...
5,784,447 5,652,907 131,540 2.3%
l Other Utilities...............
1.897.885 1.753.553 144.332 8.2 i
Total......
7.682.332 7.406.460 275.87.2 3.7 i
Operating Revenues:
Retail Customers.................
S 497,838 S 471,824 S
26,044 5.5%
Other Utilities...........................
96.I70 107.099 0 0.929)
(l0.2)
To t al...............................
s 594.038 s 578.923 s
15.I15 2.6 Increase /(Decrease) 4 Years Ended December 31:
1996 1995 Amount Percent
- f Electric KWH Sales:
Retail Customers.........
5,G52,907 5,416,902 236,005 4.4%
Other Utilities.........................
1.753.553 1.646.357 107.196 6.5 To t al...................................
7.406.460 7.063.259 343.201 4.9 Operating Revenues:
f Retail Customers.........
S 471,824 S 405,316 S 66,508 16.4 %
Other Utilities................
107.099 99.301 7.798 7.9 To t al..............................
S 578.923 s 504.617 s 74.306 14.7 Other operations and maintenance expense decreased S12.0 million in 1997 compared to 1996, and S73.1 million in 1996 compared to 1995. The decreases were primarily the result of a reduction in
' Palo Verde costs of approximately S8.7 million and S67.3 million, respectively, due to the lease accruals
- by the Predecessor Company, with no corresponding accrual by the Reorganized Company as a result of the reacquisition of the leased portion of Palo Verde in the Reorganization.
Depreciation expense increased S2.4 million to S88.7 million in 1997 compared to S86.3 million in 1996. The efTect of an increase in depreciable plant following the reacquisition in the Reorganization of a portion'of Palo Verde and the depreciation of such amounts over the period of the Rate Stipulation 30
=
was partially offset by the decrease in the book value of depreciable plant from fresh-start reporting adjustments.
Combined depreciation expense increased S29.5 million to S86.3 million in 1996 compared to
$56.8 million in 1995. The effect of an increase in depreciable plant following the reacquistion in the Reorganization of a portion of Palo Verde was partially offset by the decrease in the book value of depreciable plant from fresh-start reporting adjustments. The effect of the implementation of fresh-start reporting and the accelerated depreciation of a portion of such amounts over the period of the Rate Stipulation resulted in increased depreciation expense of $37.2 million for the period February 12,1996 to December 31,1996, which was partially offset by decreased nuclear decommissioning amortization.
As part of the adoption of fresh-start reporting, the Company recognized the net present value of estimated future expenditures for nuclear decommissioning of approximately S84.9 million.
Taxes other than income taxes decreased $1.2 million in 1997 compared to 1996 and S9.0 million in 1996 compared to 1995, due to reduced Arizona property taxes. The decreases in Arizona property taxes resulted from a decrease in taxable nuclear plant based on plant reductions on the Company's regulatory books in 1997 and a new state property tax law which reduced the Company's property taxes by approximately S8.8 million in 1996.
Other income increased S3.8 million in 1997 compared to 1996 due to the favorable litigation settlement in 1997 of S7.5 million, net of legal fees and expenses, partially offset by a gain on sale of investment of S3.8 million and an additional S2.3 million due to favorable settlement of bankruptcy professional fees in 1996. There was no comparable activity in 1995. Also, in 1996, investment income was classified as Other Income, whereas investment income in 1995 was included in Reorganization Items (Expense) for the Predecessor Company. Investment income decreased S6.9 million in 1996 compared to 1995 due to reduced levels of cash resulting from repurchases of debt and the payment of bankruptcy-related claims.
Interest charges decreased 58.9 million in 1997 compared to 1996, primarily due to a, uction in outstanding debt as a result of open market purchases of the Company's first mortgage bonas e t 'the extinguishment of certain debt in conjunction with the Reorganization. Interest charges int cased
$7.2 million in 1996 compared to 1995, primarily due to (i) increased interest on mortgage bonds due to a greater amount of bonds being outstanding subsequent to the Reorganization and (ii) accretion of the increased nuclear decommissioning liability as a result of implementing fresh-start reporting. This increase was partially oiTset by decreased interest charges due to the extinguishment of certain debt in conjunction with the Reorganization.
Income tax expense, excluding income tax benefits of S1.5 million related to the loss on repurchases of debt, increased SI1.5 million in 1997 compared to 1996, primarily due to changes in pre-tax income, including a favorable litigation settlement and certain permanent differences. Income tax expense, excluding the deferred income tax effects of fresh-start reporting, reorganization items and income taxes on interest income during bankruptcy, increased $39.1 million in 1996 compared to 1995, primarily due to changes in pre-tax income and certain differences in book and taxable income.
The reorganization items benefit recorded by the Predecessor Company upon the emergence from bankruptcy consisted of the effects of the Rate Stipulation and deferred income tax benefii related to the Reorganization. These. benefits were partially offset by (i) the adjustments of assets to their 31
reorganization value and liabilities to their fair market values; (ii) provisions for settlement of claims; and (iii) professional fees and other expenses. There were no comparable amounts in 1997.
l Extraordinary loss on repurchases of debt repn ents the payment of premiums on debt
- repurchased and the recognition of unamortized issuance c4penses on that debt of S2.8 million, net of federal income tax benefits of S t.5 million, with no comparable amounts in 1996.
Extraordinary gain on discharge of debt for the Predecessor Company fbr the periodJanuary 1, 1996 to February 11, 1996 consisted of forgiven indebtedness upon' the Reorganization, primarily related to the extinguishment of Palo Verde lease obligations with no comparable amounts in 1997.
For the last several years, inflation has been relatively low and, therefore, has had little impact on the Company's results of operations and financial condition.
In 1997, the Company implemented SFAS No.128, " Earnings Per Share," SFAS No.129, "I)isclosure of Information about Capital Structure," and SFAS No.130, " Reporting Comprehensive Income," none of which had a material effect on the Company's financial statements. See Item 8,
" Financial Statements and Supplementary Data - Note A of Notes to Financial Statements." There are no new accounting standards pending implementation by the Company which would have a material efTect on the Company's financial statements.
l
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32
Item 8.
Financial Statements and Supplementary Data INDEX TO FINANCIAL STATEMENTS Page In d e pen d e n t Au d i to rs' Re po rt....................................................................................
35 Balance Sheets at December 3 1, 1997 an d 1996.......................................................
36 Statements of Operations for the year ended December 31,1997, the period from February 12 to December 31,1996, the period fromJanuary 1 to February 11,1996 and the year ended December 3 1, 1 9 9 5.............................................
38 Statements of Comprehensive Operations for the year ended December 31,1997, the period from February 12 to December 31,1996, the period fromJanuary 1 to February 11,1996 and the year ended December 31,1995.................................................................
39 Statements of Changes in Common Stock Equity (Deficit) for the year ended December 31, 1995, the period from January 1 to February 11,1996, the period from February 12 to l
December 31,1996 and the year ended December 31,1997.......
40 Statements of Cash Ilows for the year ended December 31,1997, the period from February 12 to December 31,1996, the period fromJanuary 1 to February 11,1996 and the year ended December 31,1995...................................................................................................
41
' Notes to Financial S ta temen ts...........................................................
42 33
. ~...
s I
4 1
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t E
T This page left blank intentionally.
34
INDEPENDE.NT AUDITORS' REPORT The Shareholders and Board of Directors El Paso Electric Company We have audited the accompanying balance sheets of El Paso Electric Company (the " Company") as of l
December 31,1997 and 1996 and the related statements of operations, comprehensive operations, changes in common stock equity (deficit), and cash flows for the year ended December 31,1997, the l
period February 12,1996 to December 31,1996, the periodJanuary 1,1996 to February 11,1996,and the year ended December 31,1995. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence i
supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note A of Notes to Financial Statements, on February 12,1996, the Company emerged from bankruptcy. The financial statements of the reorganized Company reflect assets at reorganization value and liabilities at fair value under fresh-start reporting as of February 12, 1996. As a result, the financial statements of the reorganized Company are presented on a different basis than those prior to the reorganization and, therefore, are not comparable in all respects.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of El Paso Electric Company as of December 31,1997 and 1996, and the results cfits operations and its cash flows fbr the year ended December 31,1997, the period February 12,1996 to December 31, 1996, the period January 1, 1996 to February 11, 1996, and the year ended December 31,1995 in conformity with generally accepted accounting principles.
KPAIG Peat Alarwick LLP El Paso, Texas February 6,1998 35 1
l
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EL PASO ELECTRIC COMPANY BALANCE SHEETS ASSETS December 31.
(In thousands) 1997 1996 Utility plant (Notes A, B, C and F)
Electric plant in senice.
1,538,572 S 1,492,737 le cumulated depreciation and amortization.......
164.283 77.976 t plant in senice........
1,374,289 1,414,761 C,
action work in progress.
43,761 44,432 Nucicar fuel; includes fuelin process of $9,910 and
$5,084, respectively..
86,609 60,014 less accumulated amortization...
40.142 18.651 Net nuclear fuel......
46.467 41.363 Net utility plant...
1.464.517 1.500.556 Current ansets:
Cash and temporary investments...
I11,227 68,767 Accounts receivable, principally trade, net of allowance for doubtful accounts of $5,124 and S6,161, respectively...
58,960 57,587 Federal income tax receivable...
20,713 Inventories, at cost..
27,130 28,322 Net undercollection of fuel revenues............
13,870 1,925 Prepaymenis and other.......
6.930 8.727 Total current assets.
218.117 186.041 Long-term contract receivable (Note B)......
27.659 31.057 Deferred charges and other assets:
Accumulated deferred income taxes, net (Note G).
43,208 73,884 Decommissioning trust fund (Note C)..
38,438 33,054
. Oth e r..............
20.674 21.598 Total deferred charges and other assets..
102.320 128.536 Total assets...
S 1.812.613 s 1.846.190 See accompanying notes to financial statements.
l l
1 l
j 36 l
~
EL PASO ELECTRIC COMPANY BALANCE SHEETS (Contin :d)
CAPITALIZATION AND LIABILITIES December 31.
(In thousands except for share data) 1997 1996 C:pitalization (Notes D and E):
Common stock, stated value SI per share, 100,000,000 shares authorized, 60,060,034 and 59,999,981 shares issued and outstanding; and 196,404 and 180,000 restricted shares, respectively..
S 60,256 S 60,180 Capitalin excess ofstated value.......
241,222 240,768 Unearned compensation - restricted stock awards...
(1,138)
(758)
Accumulated earnings...
69,484 30,835 Accumulated other comprehensive income (loss) (unrealized gains (losses) on marketable securities)..
(184) 232 Common stock equity 369,640 331,257 Preferred stock, cumulative, no par value,2,000,000 shares authorized:
Redemption required - 1,213,188 and 1,084,264 shares issued and outstanding, respectively; at liquidation preference.......
121,319 108,426 long term debt (Note 19.........
938,562 1,021,749 Financing and capital lease obligations (Note F)........
28.248 24.424 Total capitalization..
1.457.769 1.485.856 Curr:nt liabilities:
Current maturities of financing and capitallease obligations (Note 19.....
28,463 28,333 Accounts payable, principally trade....
24,957 37,215 Taxes accrued other than federalincome taxes........
19,292 21,296 Interest accrued.................
21,172 L 23,150.
O th e r......................
17.439.
15.000 j
Total current liabilities..
I11.323 124.994 D:fgrred credits and other liabilities:
Decommissioning (Note C)..
94,917 89,544 Accrued postretirement benefit liability (NoteJ)..
75,531 71,313 Accrued pension liability (NoteJ)...
33,909 34,550 Other..
39.164 39.933 Total deferred credits and other liabilities....
243.521 235.340 C:mmitments and contingencies (Notes 11, C, H, I andJ)
Total capitalization and liabilities..
S 1.812.613 S 1.846.190 See accompanying notes to financial statements.
l i
I 37
l STATEMENTS OF OPERATIONS (la thmanduxcept f:r rhtre dzte)
Pzriod From Pzriod Frem Year February 12
, January 1 Year Ended to to Ended December 31, December 31, February 11, December D 1997 1996 1996 IM5 Opereting revenues:
1 Ilase revenues..-........
S 458,979 $
416,221 S
44,679 5 432,05$
Fuel revenues and economy sales.
130,172 104,193 9,849 68,82k Other.
4.887 3.569 421 3.74f 594.038 523.974 54.949 504.613 Estrgy expenses:
)
1 uel...............
113,457 92,899 10,125 76,00?
Purchased and interchanged power..
20.130 17.821 2.282 16.568 133.587 110.720 12.407 92.573 Operating revenues met of energy expenses.
460.451 413.254 42.542 412.0 4 Other operating expenses:
Other operations..
131,916 115,742 23,559 208,44R Maintenance........
34,782 34,702 4,743 43,41$
Depreciation and amortization..
88,735 79,772 6,577 56,76$
Taxes other than income taxes.,
43.351 38.547 6.024 53 3 298.784 268.763 40.903 362.170 Operrting income...
161.667 144.491 1.639 49.874 Othtr income (deductions):
Litigation settlement, net.
7,500
- l Investment income....
6,095 4,796
- l Gain on sale ofinvestment......
3,844
- )
Settlement of bankruptcy professional fees.
362 2,305
- i Other, net.
162 (681) 50 (91C 14.119 10.264 50 (91%
Ircrme before interest charges..
175.786 154.755 1.689 48.964 Ixt:rsst charges (credits):
In:erest on long. term debt..
86,117 85,633 Other interest..
6,200 5,722
- 1 Interest during reorganization,....
9,569 91,92i Interest capitalized and deferred..
(5.875)
(5.189)
(412)
(3.82C 86.442 86.166 9.157 88.103 Inc:me (loss) before income taxes.....
89,344 68,589 (7,468)
(39,131 Inc:me tax expense (benefit) (Note G)....
34.776 26.670 (3.415)
(15.7Sg Ire ime (loss) before reorganization items (zxpense) and extraordinary items..
54,568 41,919 (4,053)
(23,34 Reorganization items (expense), met ofincome tax benefit (expense)........
122.251 (9.970 Irc:me (loss) before extraordinary items..
54.568 41.919 118.198 (33.31]
Extrrerdinary items:
Extraordinary loss on repurchases of debt, net of federal income tax benefit.
(2,775)
Extraordinary gain on discharge of debt.
264.273 (2.775) 264.273 Net income (loss)..............
51,793 41,919 382,471 (33,315 Pr:ferred stock dividend requirements..
13.144 10.488 Nst ixcome (loss) applicable to common stock..
S 38 649 s 31.431 s
382.47I s (33.3 d
. Snic earnings per common share (Note A):
Income Ooss) bcfore extraordinary items.
.S 0.689 S 0.523 S
3.325 5 (0.931 Extraordinary loss on repurchases of debt, net of fedend income tax benefit.... _....
(0.046)
Extraordinary gain on discharge of debt.
7.435 Net incorne (loss)...
s 0.643 s o 523 s
10.760 s to.937 Diluted earnings per common share (Note A):
.S 0.685 3 0.523 S
3.325 S (0.931 Income (loss) before extraordinary items.
Extraordinary loss on repurchases of debt, net of federalincome tax benefit.
(0.046)
Extraordinary gain on discharge of debt.
7.435 Net income (loss)..
s o.639 s 0.523 s
10.700 s to 935 Wrighted average number of common shares
- outstanding...
60.128.505 60.073.808 35 M 33D 35.544.330 Wzighted average number of common share, and common share equivalents outstanding..
60.437.632 60.116.709 35.544.330 35.544.330 See accompanying notes to financial statements.
38
9 EL PASO ELECTRIC COMPANY STATEMENTS OF COMPREHENSIVE OPERATIONS (In thousands)
Period Fmm Pedod Fmm Year Febmary 12 January 1 Year Ended to to Ended December 31, December 31, February 11, December 31, l
1997 1996 1996 1995 ht i:ccm2 (lose)..
S 51,793 S 41,919 3
382,471 S (33,319)
Iticr c:mprehensive income (loss) (Note A):
Net unrealized gain (loss) on marketable securities,less applicable income tax benefit (expense) of S223,
$(125), S - and S(282), respectively.
(416) 232 522 Reclassification adjustment included in net income, net ofincome tax of 593.
(172) mpecheceive income (loss)..
51,377 42,151 582,299 (32,797) l rif rred ttock dividend requirements..
13.144 10.488 j
bmprehensiw income (loss) applicable to conunon stock..
S 38.233 s 31 663
?
3R2299 s
/32.7971 ee accompanying notes to financial statements.
39
I l
EL PASO ELECTRIC COMPANY t
l STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (DEFICIT) l (In thousands except for share data) l Unemmed Tenal c--
g-
! Comum Captalisa Reserksed Axmmih Odier hk Common Seud F=ws= of Sena Emmings G..p '
Shams Amount SennedVahne Awands (Ddcia.)
Inmme hen.)
(D dcs l Balances at December 31,1994..
35,544,330 $ 339,097 S
$ (724,713) $
(350) 5 (385,9(
l-Net loss -
(33,319)
(33,3 :
l-Other comprehensive income...
522 5;
Balancis at December 31,1995....
35,544,330 339,097 (758,032) 172 (418,7(
Net income.
382,471 382,4' Elimination of predecessor equity
- accounts..
(35,544,330)
(339,097) 339,097
[
Effects of fresh-start reporting acjustment to common stock equity..
36.464 (172) 3 6.21 Calances at February 11,1996.
Issuance ofcommon stock upon reorganization.........
59,999,981 60,000 240,000
- 300, Capitas stock expense.
(596)
(5 Grants of restricted common stock-180,000 180 768 (948)
Amortization of unearned compensation --
190 1
l Preferred stock dividends -
(10,488)
(10,4(
Net income..
41,919 41,@l Other comprehensive income..
232 2.
Cdancis at December 31,1996..
60,179,981 60,180 240,768 (758) 30,835 232 331$
Gr::nts of restricted common stock =
84,255 84 491 (575)
-)
Amortization of unearned compensation..
195 1;
Repurchase of unrestricted common stock..
(7,798)
(8)
(37)
(l Preferred stock dividends..
(13,144)
(13,1i Net income =.
51,793 51,7l Other comprehensive loss..
(416)
(4; C11=cis at December 31,1997..
60 956.438 5 60.25G $ 941 ??9 S (1 138) S 69 484 S IIR4) S 369 6 See accompanying notes to financial statements.
l i
1 40
~.
j i
EL PASO ELECTRIC COMPANY l
STATEMENTS OF CASH FLOWS
- (In thousands)
Period From Period From Year February 12 January 1 Year c Ended
.to to Ended December 31, December 31, February 11, December 31, 1997 1996 1M6 1995 C=h Hows From Operating Activities:
Net income (loss)..
S 51,793. S 41,919 382,471 S (33,319)
' Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization.,
111,622 99,355
'8,246 69,444 t
Deferred income taxes and investment tax credit, net.
32,394 41,341 (3,116)'
(26,744)
Other operating activities..
2,552 2,487 (805)
(6,795)
Extraordinary loss on repurchases of debt, net of federal income tax benefit...
'2,775 Gain on sale ofinvestment..
(3,844)
Reorganization items, net ofincome tax benefit...
(122,251)
Extraordinary gain on discharge of debt..
(264,273)
Change in:
r Accounts receivable..
(1,373) 3,513 5,429 (4,866)
Federal income tax receivable..
20,713' (20,713)
Inventories...
1,192
- (32) 90 1,590 Prepayments and other..
1,797 (1,974) 34 2,214
)
Long-term contract receivable..
3,398 2,333 293'
-(80) i (12,258)
(4,038)
(6,859) 11,885 Accounts payable..........
(1,978) 23,034 Interest accrued...
Net under/overcollection of fuel revenues...
(11,945)
(12,709) 417 16,581 Other current liabilities..
386 (1,242)
(152) 1,027 Deferred charges and credits..
5,520 (1,117) 1,994 21,187 i
Obligations subject to compromise..
9,430 71,839 Revenues subject to refund.
2.785 24.107 Net cash provided by operating activities...
206.588 168.313 13.733 148.070 C=h Flows From Investing Activities:
Adiitions to utility plant.,
(75,431).
(53,346)
(8,176)
(87,937).
Investment in decommissioning trust fund.
(6,023)
(5,960)
(553)
(5,159)
Proceeds from sale ofinvestment..
20.183 Net cash used for investing activities..
f81.454)
(39.123)
(8.729)
(93.096)
Car.h F12ws From Financing Activities:
Repurchases of and payments on long-term debt..
(86,771)
(117,528)
Net proceeds from financing obligations.'
5,369 3,320 43,309
-Redemption of capital lease obligations.
(1,272)
(364)
Capital stock expense...
(596)
Proceeds from issuance of preferred stock.
97,500 Proceeds from issuance oflong-term debt.
778,120 Redemption of obligations subject to compromise..
(1.131.695)
(1.05.1)
Net cash used for financing activities..
(82.674L (115.168)
/212.766)
(1.051)
Net incerase (decrease) in cash and temporary investments.
42,460 14,022 (207,762) 53,923 C= h and temporary investments at beginning of period.
68.767 54.745 2(a501 208.584 Cash and temporary investments at end of period..
S 111.227 S 68.767 S
54.745 S 262.507 See accompanying notes to financial statements.-
41 f
)
\\
' EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS
' A.
Summary of Signincant Accounting Policies Gennal. ' l Paso Electric Company (the " Company") is a public utility engaged in the generation, E
transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas' and southern New Mexico. The Company also serves wholesale customers in Texas, New Mexico, California and Mexico.
j The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of
. assets and liabilities and disclosure 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 those estimates.
Bankruptcy Reorganication. On February 12,1996 (the " Effective Date"), the Company emerged (the " Reorganization") fmm a bankruptcy proceeding which it instituted.in January 1992 (the
" Bankruptcy Case").' As a result of the Reorganization, the Company significantly reduced its debt and 4
- simplified its capital structure. The Company prior to the Reorganization (the " Predecessor Company")
had total obligations subject to compromise of S2,007 miHion (including obligations related to leases on i
portions of the Palo Verde Nuclear Generating Station ("Palo Verde") (the "Palo Verde Leases"), which represented S700 million of allowed claims in the Bankruptcy Case). Under the Company's Fourth Amended Plan of Reorganization ~(the " Plan"), this debt nnd the Palo Verde Irase obligations were extinguished and the creditors received a combination of S212 million cash and newly issued debt and
)
equity securities of the Company fbliowing the Reorganization _ (the " Reorganized Company") consisting i
. of'SI,189 million of long-term bonds and financing and capital lease obligations, $100 million of redeemable preferred stock and $255 million ofcommon stock.
Under the Plan, all of the Predecessor Company's common and preferred stock was canceled and the holders of such securities received approximately $45 million (15%) of the Reorganized Company's common stock and the right to receive certain potential litigation recoveries which ultimately amounted
- to S20 million. In addition, on the EfTective Date, the Palo Verde Leases were terminated and the Company reacquired such interests. See Note II.
Basis ofhesentation. The Company maintains its accounts in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (the "FERC"). The Company had determined that it does not meet the criteria for the application of Statement of Financial Accounting Standards ("SFAS") No. 71, " Accounting for the Effects of Certain Types of Regulation,"
and accordingly does not report the elTects of certain actions of regulators as' assets or liabilities unless
- such actions result in assets or liabilities under generally accepted accounting principles for commercial enterprises in' general.
The Company accounted for all transactions related to its Reorganization in accordance with Statement of Position 90-7, " Financial Reporting by Entities in Reorganization Under the Bankruptcy Code". (" SOP.90-7"). As of the Effective Date of the Reorganization, the Company applied " fresh-start" 42
EL PASO ELECTRIC COMPANY
~
NOTES TO FINANCIAL STATEMENTS reporting in accordance with SOP 90-7 resulting in the creation of a new reporting entity having no retained earnings or accumulated deficit. - In applying fresh-start reporting, the Company determined its reorganization ~ value, which was allocated to the Company's assets, and recorded its liabilities at fair value.. Reorganization value was determined as the value of the Company's capital structure, based on management's estimates of future operating results, less operational liabilities.
Because of the effects of fresh-start reporting, the Reorganized Company's financial statements i
for periods after February 12, 1996 are not comparable to the Predecessor Company's financial statements for periods before February 12,1996. A vertical line is shown in the accompanying financial,
statements to separate the Reorganized Company from the Predecessor Company because the respective fmancial statements have not been prepared on a consistent basis of accounting.
Comprehensire ' Income.
In 1997, the Company implemented SFAS No. 130, " Reporting Comprehensive Income." Under this standard, certain gains and losses that are not recognized currently in the statement of operations are reported as other comprehensive income.
. Utilip Plant.' Upon adoption of fresh-start reporting, the Company revalued its utility plant. As of February 12,1996, the value allocated to the assets used in the Company's generation, transmission and
_ distribution operations was based on the Company's estimate of the replacement cost less depreciation
("RCLD") and was derived from the value of the Company as a going concern rather than on an appraisal or other pmfessional valuation of its assets. The RCLD of generation assets was calculated based on estimates of the current cost of gas-fired combined-cycle and combustion turbine power plants, adjusted for certain economic factors. Additions to utility plant subsequent to February 12,1996 are reported at historical cost. Depreciation is provided on a straight-line basis over the estimated remaining lives of the assets (ranging from i1 years to 31 years), except for approximately S384 million of
" reorganization value allocated to net transmission, distribution and general plant in service. This amount is being depreciated over the ten-year period of a rate settlement (the " Rate Stipulation") dated
< July 27,'1995 among the Company and substantially all of the other parties to Docket No.12700.
The Company charges the cost of repairs and minor replacements to the appropriate operating expense accounts and capitalizes the cost of renewals and betterments. Gains or losses resuhing from retirements or other dispositions of operating property in the normal course of business are credited or charged to the accumulated provision for depreciation.
'The Company accrued a liability for the present value of the estimated decommissioning costs for the Company's interest in Palo Verde using an escalation rate of 3% and a discount rate of 6%.
Accretion of the decommissioning liability is charged to interest charges in the statements of operations.
o The cost of nuclear fuel is amortized to fuel expense on a unit-of-production basis. A provision for spent fuel disposal costs is charged to expense based on requirements of the Department of Energy (the." DOE") for disposal cost of approximately one-tenth of one cent on each kilowatt hour generated.
43
l
?
e EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Impainnent ofLong-Lized A3 sets. The Company evaluates impairment ofits long-lived assets and certain intangible assets whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. An asset is deemed impaired if the sum of the expected future cash flows is less than the carrying amount of the asset.
Capitalized Interest. The Company capitalizes, to construction work in progress, interest cost calculated in accordance with SFAS No. 34, " Capitalization ofInterest Cost."
Cash and Cash Equivalents. All temporary cash investments with an original maturity of three months or less are considered cash equivalents.
Investments. The Company's marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair market value and consist primarily of municipal bonds in trust ftmds established for decommissioning of its interest in Palo Verde which had a fair market value of approximately S38.4 million at December 31, 1997.
Such marketable securities are classified as "available-for-sale" securities and as such unrealized gains and losses are included in accumulated other comprehensive income as a separate componem of capitalization.
Inventories. Inventories, primarily parts, materials and supplies are stated at average cost not to exceed recoverable cost.
Operating Revenues. The Company accrues revenues for services rendered but unbilled.
The regulations of the Public Utility Commission of Texas (the " Texas Commission"), the New Mexico Public Utility Commission (the "New Mexico Commission") and the FERC and the agreements with individual customers generally provide for fuel and purchased and interchanged power expenser to be recovered from customers. Fuel revenues reflect the Company's estimate of recoverable i
fuel and purchased and interchanged power expenses net of a percentage of (i) profit margins from certain off-system sales and (ii) resenues from third-party transmission services, which are credited to customers. Economy sales relate to spot market sales and are included in fuel revenues. Base revenues refer to the Company's revenues from the sale ofelectricity, excluding such fuel revenues.
Federal Income Tmes. The Company accounts for federal income taxes under the asset and j
liability method of accounting for income taxes.
Under this method, deferred income taxes are i
recognized for the estimated future tax consequences of " temporary differences" by applying enacted statutory tax rates fbr each taxable jurisdiction applicable to future years to differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities. The Company records a valuation allowance to reduce its deferred tax assets to the extent it is more likely than not that such deferred tax assets will not be realized. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date.
Earnings per Share. The Company adopted the provisions of SFAS No.128, " Earnings per Share,"
which establishes standards for computing and presenting earnings per share, for the year ended 44 t
EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS December 31,1997. All per share amounts reported in prior periods presented have been restated to conform to the new standard. liasic carnings (loss) per common share is computed by dividing net income or loss, after deducting the preferred dividend requirements, by the weighted average number of common shares outstanding. Diluted earnings (loss) per common share is computed by dividing net income or loss, after deducting the preferred dividend requirements, by the weighted average number of common shares and dilutive common shares outstanding.
Beneft Plans. See NoteJ for accounting policies regarding the Company's retirement plans and postretirement benefits.
Stock Options and Restricted Stock. The Company has a long-term incentive plan which reserves shares of common stock fbr issuance to ofIicers, key employees and non-employee directors through the award or grant of stock options and restricted stock. The Company has adopted the disclosure-only provisions of SFAS No.123, " Accounting for Stock-Based Compensation" ("SFAS No.123").
Accordingly, compensation expense is recognized for the intrinsic value, if any, of option grants at measurement date ratably over the vesting period of the options. Compensation expense for the restricted stock awards is recognized for the fair value of the shares at the award date ratably over the restriction period. Uncarned compensation related to stock options and restricted stock awards is shown as a reduction of common stock equity.
Reclasspcations. Certain amounts in the financial statements for 1996 and 1995 have been reclassified to conform with the 1997 presentation.
45
l EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Supplemental Statements of Cash Flow Disclosures (In thousands)
Period From Period From Year February 12 January 1 Year Ended to to Ended December 31, December 31, February 11, December 31, 1997 1996 1996 1995 i
Cash (refunded) paid for-
)
Income taxes, net.
S (17,812)
S (2,504)
S S
12,950 Interest....
76,477 53,000 8,580 80,688 Reorganization items - professional fees and other..
3,264 8,910 2,279 15,207 Non-cash investing and financing activities:
Issuance of preferred stock for pay-in-kind dividends.....
12,893 8,426 Grants of restricted shares of common stock..
575 948 Property purchased through issuance of promissory note.......
964 I
Reorganized common stock exchanged for Predecessor co.nmon and preferred stock.
45,000
' Reorganized common stock exchanged for settlement of obligations subject to compromise.
255,000 long-term debt exchanged for settlement of obligations subject to compromise......
151,834
' Plant in senice reacquired through incurring obligation subject to compromise.
227,656 B.
Rate Matters 1
Texas Rate Matters The rates and services of the Company in Texas municipalities are regulated by those municipalities, and in unincorporated areas by the Texas Commission. The largest municipality in the l
Company's senice area is the City of El Paso. The Texas Commission has exclusive appellate jurisdiction to review municipal orders and ordinances regarding rates and senices in Texas and 46 i
1
(
-. ~-.
- ~. - - -
EL PASO ELECTRIC COMPANY l
NOTES TO FINANCIAL STATEMENTS jurisdiction over certain other activities of the Company. The decisions of the Texas Commission are subject tojudicial review.
Rate Stipulation and Agreed Order. The Company's rates for its Texas customers are governed by a rate order entered by the Texas Commission in Docket 12700 (the " Agreed Order") adopting a Rate l
Stipulation. The Agreed Order and Rate Stipulation were entered into by the Company, the Texas l
~ Commission staff, the City of El Paso and virtually all other intervenors in the case. The Agreed Order
. implemented certain provisions of the Rate Stipulation and set rates consistent with the Rate Stipulation.
u l
l Among other things, under the Rate. Stipulation: (i) the Company's base rates for most customers in Texas were fixed for ten years beginning in August 1995 (the " Freeze Period"); (ii) the City of El Paso granted the Company a new franchise that extends through the Freeze Period; (iii) the Company will retain 75% during the first live years of the Freeze Period and 50% during the remainder of the Freeze i
Period of(A) the net revenues generated by providing third-party transmission services and (B) profit margins from certain off-system power sales; (iv) the Company's reacquisition of the Palo Verde leased assets. was deemed to be in the public interest; and (v) all appeals of Texas Commission orders concerning the Company and all outstanding Texas Commission dockets concerning the Company's l
. rates were resolved.
Neither the Rate Stipulation nor the Agreed Order deprives the Texas regulatory authorities of j
l' their jurisdiction over the Company during the Freeze Period. However, the Texas Commission i
determined in the Agreed Order that the rate freeze is in.the public interest and results in just and reasonable rates. Further, the signatories to the Rate Stipulation (other than the General Counsel, the L
Texas Ollice of Public Utility Counsel and the State of Texas) agreed not to seek to initiate an inquiry into the reasonableness of the Company's rates during the Freeze Period and to support the Company's entitlement to rates at the freeze level throughout the Freeze Period. The Company believes, but cannot
. assure, that its cost of senice will support rates at or above the freeze level throughout the Freeze Period and, therefore, does not believe any attempt to reduce the Company's rates would be successful.
. However, during the Freeze Period, the Company is precluded from seeking rate increases in Texas,
, even in the event ofincreased operating or capital costs. In the event of a merger, the parties to the Rate Stipulation retain a!! rights provided in the Rate Stipulation, their rights to participate as a party in any proceeding related to the merger, and the right to pursue a reduction in rates below the freeze level to the extent of post-merger synergy savings.
Fuel. Pursuant to Texas Commission rules, the Company periodically must make a filing reconciling the revenues collected from Texas customers under its fixed fuel factor with the fuel and purchased power expenses actually incurred for the period covered by the reconciliation. A fuel and pu' chased power reconciliation must include not less than twelve months nor more than thirty-six r
- months of reconcilable data. The Company has not filed a reconciliation for any period since
' June 1995. Differences between revenues collected and expenses incurred are subject to a refund to customers (in the case of an overrecovery of fuel costs) or st rcharge (in the case of an underrecovery of fuel costs).- The Texas Commission. staff, local regulatory authorities such as the City of El Paso, and j
customers are entitled to intervene in a fuel reconciliation proceeding and to challenge the recovery of I
. fuel and purchased power expenses.
l l
47 l
~
EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS liigher than expected natural gas prices were experienced in December 1996, continued in the first quarter of 1997 and remained at higher levels through the remainder of 1997 compared to 1996.
These higher natural gas prices have increased the Company's underrecovered fuel costs, which will be reviewed in the next Texas fuel reconciliation.
A significant disallowance of fuel costs in this reconciliation could have an adverse elrect on the Company's financial results. In January 1998, the Company filed a request with the Texas Commission to increase its Texas fixed fuel factor and implement a surcharge, subject to reconciliation, of its underrecovered fuel costs. The Company l
entered into a stipulation with all parties to the docket to implement the surcharge and a new fixed fuel factor. Both the fixed fuel factor and surcharge are expected to go into effect in April 1998.
Palo I"erde Perfonnance Standards. The Texas Commission has established performance standards for the operation of Palo Verde, pursuant to which each Palo Verde unit is evaluated annually to l
determine whether its three-year rolling average capacity factor entitles the Company to a reward or subjects it to a penalty. There are five performance bands based around a target capacity factor of 70%.
.The capacity factor is calculated as the ratio of actual generation to maximum possible generation. If the capacity factor, as measured on a station-wide basis for any consecutive 24-month period, should fall below 35%, the Texas Commission could reconsider the rate treatment of Palo Verde, regardless of the j
- provisions of the Rate Stipulation. The removal of Palo Verde from rate base could have a significant negative impact on the Company's revenues and fmancial condition. For the three-year rolling average period ended December 31,1997, Palo Verde Units 1, 2 and 3 achieved capacity factors of 83.75%,
83.04% and 88.70%, respectively. These capacity factors result in the Company's entitlement to a combined reward of S2.8 million pursuant to the formula established by the Texas Commission for the Palo Verde units.-
New Mexico Rate Matters 1
The New Mexico Commission has jurisdiction over the Company's rates and services in New Mexico and over certain other activities of the Company, including prior approval of the issuance, i
assumption or guarantee of securities. The New Mexico Commission's decisions are subject to judicial review. Current base rates in New Mexico were established in'1990 and have not increased since. The Company does not have an agreement with New Mexico regulatory authorities or parties to past
-New Mexico regulatory proceedings comparable to the Rate Stipulation. The largest city in the Company's New Mexico service territory is Las Cruces, which in 1997 accounted for 8% of the Company's total revenue. See Note 1.
Pending Rate Case. In October 1996, the New Mexico Commission issued an order in Case No. 2722, requiring the Company to answer certain ratepayer complaints and to file a rate filing package, including cost of service data and supporting testimony. On March 3,1997, the Company filed with the New Mexico Commission all of the rate filing package data required by the Commission's
. order. Although the Company's filing demonstrates a revenue deficiency of approximately S8.6 million under current rates, the Company did not request a rate change to recover the deficiency. The New Mexico Commission could order a rate reduction or, alternatively, in response to economic factors 48
-4 l
EL PASO ELECTRIC COMPANY l
NOTES TO FINANCIAL STATEMENTS
. and regulatory, political and competitive pressures, the Company could agree to a rate reduction as part
_of an overall settlement of allissues in New Mexico. Prosecution of the rate case before the New Mexico L
Commission is' expected to be completed before the end of 1998. The Company is unable at this time to predict the outcome of this proceedmg.
Fuel. The Company is required to make annual filings with the New Mexico Commission to
. reconcile the revenues collected under its fixed fuel factor with its fuel and purchased power expenses
= actually incurred, and to report the results of Palo Verde performance standards. These reports are due J
byJanuary 31 of each year for the preceding calendar year, and are filed along with the Company's l
' request to revise its fixed fuel factor to reflect current projections of fuel and purchased power costs and to include the over or underrecovery reflected in the reconciliation report and the reward or penalty reflected in the performance standards report; On October 31,1997, the Company filed testimony and i
evidence supporting its continued use of the methodology and manner of collecting fuel and purchased power costs reflected in its tariffs. A hearing on this filing is scheduled forjuly 1998.
The Company's 1998 annual filing reflects a significant increase in the monthly fuel charge. This increase is necessary because of(i) significant increases in the spot price of natural gas and (ii) the delayed implementation of the 1997 change, effective with bills rendered on or after August 1,1997, which has baused the Company to underrecover its fuel costs in New Mexico by approximately S5.3 million for the year ended December 31,1997. The recovery of this amount, coupled with continued higher gas costs for 1998,'results in an increase in the proposed 1998 fixed fuel factor of approximately 24% over the
' present factor. The Company believes it has fully justified its fuel and purchased power costs and recovery methodology. In March 1998, the New Mexico Commission consolidated the 1998 annual filing and the October 1997 filing for hearing inJuly 1998. There can be no assurance that the New Mexico' Commission will accept the Company's proposed fixed fuel factor. As in Texas, interested parties are allowed.to intervene and challenge the recoverability of fuel expenses. A significant
- disallowance of fuel costs could have an adverse effect on the Company's financial results.
Palo Verde Perfonnance Standards. The New Mexico Commission has established perfbrmance standards fbr the operation of Palo Verde, pursuant to which the entire Palo Verde station is evaluated annually to determine ifits achieved capacity factor allows the Company to claim a reward or subjects it to a penalty. There are five performance bands based around a target capacity factor of 67.5%. Because LUnit 3 is not included in the Company's New Mexico rate base, any penalty or reward calculated on a total station basis is limited to two-thirds of such penalty or reward. The capacity factor is calculated as the ratio of actual generation to maximum possible generation. If the annual capacity factor is 35% or less, the New Mexico Commission is required to initiate a proceeding to reconsider the rate base treatment of Palo Verde Units 1 and 2.
The removal of Palo Verde from rate base could have a significant negative impact on the Company's revenues and financial condition. For the year ended
. December 31,1997, the Palo Verde station capacity factor was 88.43%. This capacity factor results in the Company's entitlement to a reward of St.l' million, pursuant to'the formula established by the New Mexico Commission for the Palo Verde units.
49
EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS 1
Federal Regulatory Matters FederalEnerp Replatory Commission. The Company is subject to regulation by the FERC in certain matters, including rates for wholesale power sales, transmission of electric power and the issuance of securities.
The Company has a long-term firm power sales agreement with Imperial Irrigation District
("IID") providing for the sale of 100 megawatts ("AIW") of firm capacity and 50 h1W of contingent capacity through April 2002. The agreement generally provides for level sales prices over the life of the agreement. The Company also has a firm power sales agreement with Texas-New hiexico Power
]
Company ("TNP"), providing for sales to TNP in the minimum amount of 25 AIW through 2002. Sales prices are essentially level for the remaining life of the agreement. Rate tariffs currently applicable to IID and TNP contain fuel and purchased power cost adjustment provisions designed to recover the Company's fuel and purchased power costs.
InJuly 1996, the Company filed its open access transmission tariffs (Docket No. OA96-200-000)
(the "Open Access Case"), in compliance with FERC Order No. 888, Promoting Molesale Competition lhrough Open Access Non-Discriminatory Transmission Serrices by 1%blic Utilities; Recorey ofStranded Costs by IMblic Utilities and Transmitting Utilities (" Order No. 888"), covering network and point-to-point transmission i
services and the six specifically required ancillary services. Several parties, including the City of Las Cruces, New hiexico ("Las Cruces"), other utilities and several wholesale power marketers, 1
intervened and filed protests to the Company's tariffs. Issues raised by the intervenors included rates and the terms and conditions of the Company's tariffs, including the treatment of and costs related to, certain facilities making access to the Comision Federal de Electricidad de hiexico ("CFE") more available to parties other than the Company. In February 1997, the Company entered into a stipulated agreement among the various parties settling all rate issues related to the Open Access Case. Under the settlement,
'the Company will provide transmission service, to the extent transmission capacity is available, to any party for firm or interruptible' service to the CFE until the earlier of the end of 1998 or the date the FERC rules on the complaint filed by one of the wholesale power marketers that submitted a bid in 1996 to the CFE. See " Department of Energy" below.
Intervenors in the Open Access Case also raised certain issues relating to the criteria by which the Company will determine the amount of transmission capacity that is available for use by third parties
' desiring to use its transmission system. Hearings related to these issues were conducted before a FERC administrative law judge in January 1998. A final decision from the FERC on these issues is not expected until the fourth quarter of 1998. The Company does not expect a material financial impact to result from a FERC ruling.
' InJuly 1996, Las Cruces exercised its right under Order No. 888 to request that the Company
. calculate Las Cruces' stranded cost obligation should it leave the Company's system and operate its own municipal utility. For a discussion of this proceeding, see Note I.
~ Department ofEnerp. The DOE regulates the Comp /'s exports of power to the CFE in h!cxico pursuant to a license granted by the DOE and a presidential permit. In addition, the DOE is authorized j
50
j EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS to assess operators of nuclear generating facilities for a share of the costs of decommissioning the DOE's uranium enrichment facilities and for the ultimate costs of disposal of spent nuclear fuel.
In September 1996, one of the wholesale power marketers that submitted a bid in 1996 to the CFE in connection with renewal of the interchange agreement for the supply of power during 1997 to CiudadJuarez, Mexico, filed a complaint against the Company with the FERC. The complaint sought emergency relief and requested the FERC to direct the Company to enter into an agreement to provide firm point-to-point transmission service to the CFE under the Company's open access transmission tariff.
In October 1996, the FERC issued an order requiring the Company to provide point-to-point transmission service over the Company's transmission system to substation facilities near the United States / Mexico border. The FERC, however, concurred with the Company's position that the FERC does not havejurisdiction to order transmission across the border, suggesting that the DOE has suchjurisdiction. The DOE subsequently issued a Notice of Delegation and Assignment which delegated to the FERC the DOE's authority to carry out its duties in this case. The FERC has docketed the Delegation and Assignment and the process is expected to continue throughout 1998.
l Kuclear Regulatory Commission. The Nuclear Regulatory Conunission (the "NRC") hasjurisdiction over the Company's licenses for Palo Verde and regulates the operation of nuclear generating stations to protect the health and safety of the public from radiation hazards and has authority to conduct environmental reviews pursuant to the National Environmental Policy Act.
Oth2r Wholesale Customers The term of the Company's previous one-year 1997 sales agreement for firm capacity and associated energy to the CFE terminated December 31, 1997. Pursuant to a bidding process, the Company was selected by the CFE to provide varying amounts of power during 1998 ranging from 90 to 200 MW. The price is stable throughout the twelve-month term of the agreement and includes charges for capacity and energy as well as transmission and any required ancillary services. Under the new agreement, the Company's revenues in 1998 : elated to power sales to the CFE are expected to be similar to 1997 revenues. There can be no assurance that the CFE will remain a customer after 1998.
The agreement requires payment in United States dollars.
R:crat Changes in Utility Regulation General. The electric utility industry faces increasing pressure to become more competitive as legislative, regulatory, economic and technological changes occur.
Federal and state legislation, regulatory initiatives, and proposed initiatives in Texas and New Mexico encourage competition in the industry, and ultimately in the Company's service area. Together with increasiag customer demand for lower priced electricity and other energy services, these measures have accelerated the industry's movement toward more competitive pricing and cost structures. Such competitive pressures could result in the loss of customers and could diminish the ability of the Company to fully recover its investment in generation assets, as well as the cost of operating these assets. This issue is particularly important to the Company because its rates are significantly higher than national and regional averages. In the face of 51
EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS increased competition, there can be no assurance that the future operations, cash flows and fmancial
)
condition of the Company will not be adversely affected, or that the Company will be able to sustain retail rates at the levels established by the Rate Stipulation durinb the Freeze Period.
Of particular importance to the Company is the issue of ultimate recoverability of " stranded costs," or costs previously found by regulatory authorities to be reasonable and prudent, but which at the same time are higher than would be recovered under immediate, full competition. There is substantial discussion and debate on this issue on both a national and state level and, at this time, there appears to be no clear solution. At the federal level, the FERC has announced, through a formal rulemaking, its intention to allow 100% recovery of all legitimate verifiable stranded costs attributable to FERC jurisdictional customers. Texas and New Mexico commissions and legislatures are engaged in various activities which are attempting to address the issue of stranded cost recovery from customers subject to theirjurisdictions.
FERC. In April 1996, the FERC issued its Order No. 888, requiring all public utilities owning, operating or controlling facilities used for transmitting electricity in interstate commerce to (i) file open access transmission tariffs containing minimum terms and conditions of non-discriminatory service and (ii) take transmission service (including ancillary services) for their own new wholesale sales and purchases of electric energy under the open access tariffs. Additionally, Order No. 888 permits public utilities to seek recovery oflegitimate, prudent and verifiable stranded cats and provides a mechanism for the recovery of such costs. Order No. 888 also provides for recovery of costs associated with former power customers and new municipally-owned entities becoming transmission-only customers as a result of providing open access transmission if the utility had a reasonable expectation of continuing to provide service to the departing customer. Order No. 888 established criteria under which stranded costs will be evaluated for contracts entered into prior to July 11,1994, and for stranded costs resulting from the forination of any~new municipal utilities. Recovery of stranded costs under contracts entered into after July 10,1994, will be governed by the terms of those contracts.
- In April 1996, the FERC also issued Order No. 889, Open Acass Same-Time Infonnation System t
(fonnerly Real-Time Infonnation Networks) and Standards of Conduct (" Order No. 889"). Order No. 889 requires all public utilities owning, operating or controlling facilities used for transmitting electricity in interstate commerce to develop and maintain an Open Access Same-Time Information System that will give existing and potential transmission users access to transmission-related information on a basis consistent with that available to a utility's employees engaged in the buying and selling of power. Order No. 889 further requires public utilities to separate their transmission and generation marketing functions and
- adopt standards of conduct ensuring that all open access transmission customers are treated in a non-discriminatory manner.
Texas. During 1996, the Texas Commission conducted projects to evaluate the (i) scope of competition in the electric industry in. Texas and (ii) potential stranded investment, procedures for allocating stranded costs, and acceptable methods of stranded cost recovery. The Texas Commission's report, which was issued inJanuary 1997, recommended a careful and deliberate approach to continued expansion of competition in the Texas electric market, ultimately leading to retail competition with 52
EL PASO ELECTRIC COMPANY d
NOTES TO FINANCIAL STATEMENTS certain safeguards, and recommended against any legislation that would introduce broad-based retail competition before 2000. The Texas Commission also quantified the potential retail " excess of cost over 1
market" ("ECOh!") under several scenarios. In February 1998, the Texas Commission requested all Texas utilities to revise the ECOAl estimates based on certain updated assumptions. Using the Texas Commission's revised model inputs, the Company's revised ECOM estimates range from a high of S t.5 billion to a low of S843 million, with an expected value of St.2 billion, assuming full retail access in 1999. Although several pieces oflegislation were ofTered during the 1997 Texas legislative session, no j
significant deregulation legislation was passed.
In August 1997, the Lieutenant Governor appointed seven senators to serve on a special mterim committee to study the various issues involved in a possible transition to a competitive electric market.
The committee is receiving testimony from various parties, including environmental advocates, consumer advocates, power marketers, public power entities, electric cooperatives and investor-owned utilities, as well as testimony and comments from the public at large, and is holding public hearings j
across the state on various aspects of the electric industry restructuring debate. The Association of Electric Companies of Texas (the "AECT") testified on behalf of all investor-owned utilities in Texas, including the Company. The AECT testified that it would support retail competition that provides benefits to all consumers, maintains electric system reliability, provides for equitable treatment of all competitors and provides for the preservation of prior regulatory commitments. The committee is expected to file a final report in late 1998. Recently, the Lieutenant Governor asked the Texas Comptroller of Public Accounts to initiate a study to review the impact of a deregulated electric market on state and local tax systems.
Sew Mexico. In 1995, the New Mexico Commission initiated a notice of inquiry regarding competition and the restructuring of regulation of the electric industry. The New Mexico Commission received comments from numerous parties representing various interests and conducted w ops in an attempt to arrive at a consensus with respect to the need for regulatory change. the natum of such change and the timing / transition of any changes. No consensus was reached by the participants. The New Mexico Commission also commenced a collaborative process with the assistance of facilitators in an attempt to reach consensus. Although that collaborative process failed to reach a consensus around which restructuring legislation could be drafted, the New Mexico investor-owned utilities, including the Company, have agreed to support legislation that would permit retail competition provided: (i) all customers have the opportunity to benefit, (ii) reliability of electric service is maintained, (iii) all energy suppliers are subject to the same laws and regulations,(iv) the price of electric generating capacity and electric energy is determined solely by market forces, (v) unbundled transmission and distribution functions remain subject to regulation, and (vi) each electric utility must have a reasonable opportunity to recover its stranded costs. The 1998 legislative session concluded without the passage of any significant deregulation legislation.
C.
Palo Verde and Otherjointly-Owned Utility Plant The Company has a 15.8% undivided interest in the three nuclear generating units at Palo Verde. The Palo Verde Participants include the Company, five other utilities and Arizona Public 53
r EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Service Company ("APS"), which serves as the operating agent for Palo Verde. "
operation of Palo Verde and the relationship among the Palo Verde Participants is governed by the Arizona Nuclear Power Project Participation Agreement (the "ANPP Participation Agreement").
Other jointly-owned utility plant includes a /% undivided interest in Units 4 and 5 of Four Corners Generating Station ("Four Corners") and certain other transmission facilities. A summary of the Company's investment in jointly-owned utility plant, excluding fuel, at December 31,1997 and 1996 is as follows (In thousands):
December 31,1997 December 31,1996 PhloVerde PaloVerde Station Other Station Other Electric plant in service.
......... S 573,218 S 180.815 S 568,957 S 180,366 Accumulated depreciation........
(46,589)
(27,078)
(22,162)
(12,747)
Construction work in progress...
12,545 2,249 8,545 985 Pursuant to the ANPP Participation Agreement, the Palo Verde Participants share costs and generating entitle nents in the same proportion as their percentage interests in the generating units and each Palo Verde Participant is required to fund its proportionate share of fuel, other operation, maintenance and capital costs, which, except capital costs, are included in the corresponding expense captions in the statements of operations. The Company's total monthly share of these costs was approximately S7.3 million in 1997. The ANPP Participation Agreement provides that if a participant fails to meet its payment obligations, each non-defaulting participant shall pay its proportionate share of the payments owed by the defaulting participant.
Duommissioning. Pursuant to the ANPP Participation Agreement and federallaw, the Company is required to fund its share of the estimated costs to decommission Palo Verde over the estimated service life of forty years. The Company's funding requirements are determined periodically based upon engineering cost estimates performed by outside engineers retained by the ANPP.
In December 1995, the Palo Verde Participants approved a decommissioning study performed by an outside engineering firm. The 1995 study determined that the Company will ha.e to fund approximately S229 million (stated in 1995 dollars) to cover its share of decemmissioning costs. The 1995 study assumed' that (i) maintenance expense for spent fuel storage will be incurred for ten years after the shutdown of the last unit (estimated to be in 2024); (ii) a national interim spent fuel storage facility will be available; and (iii) as a result of such national spent fuel storage facility, the amount of spent fuel stored on-site will be reduced from all spent fuel assemblies to the fmal core plus fuel assemblies from approximately three refuelings.
Cost estimates for decommissioning have increased with each study. The previous cost estimate from a 1993 study determined that the Company would have to ftmd approximately S221 million (stated 54
=
EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS in 1993 dollars). The 1993 estimate, however, reflected an 84% increase from the previous estimate made in 1989, primarily related to increases in estimated costs for low-level radioactive waste disposal.
Although the 1995 study was based on the latest available infbrmation, there can be no assurance that decommissioning cost estimates will not continue to increase in the future or that regulatory requirements will not change. In addition, until a new low-level radioactive waste repository opens and operates for a number of years, estimates of the cost to dispose oflow-level radioactive waste are subject to significant uncertainty. The decommissioning study is updated every three years and a new study will be completed in 1998.
The rate freeze under the Rate Stipulation would preclude the Company from seeking a rate increase in Texas during the Freeze Period to recover increases in decommissioning cost estimates.
Additionally, there can be no assurance that the Company could increase its rates in any of its other jurisdictions to recos er such increased costs.
1 The Company has established external trusts with independent trustees, which enable the Company to record a current deduction for federal income tax purposes of a portion of amounts funded.
As of December 31,1997, the aggregate balance of the trust funds was approximately S38.4 million, which is reflected in the Company's balance sheets in deferred charges and other assets.
Steam Generators. Palo Verde has experienced degradation in the steam generator tubes of each unit. The degradation includes axial tube cracking in the upper regions of the two steam generators in Unit 2 and, to a lesser degree, in Units 1 and 3. This form of steam generator tube degradation, while less common than other types, has also been seen at other United States nuclear generating stations. The 1
units also have experienced circumferential cracking at the tube sheet, a more common type of tube cracking. The axial tube cracking was discovered following a steam generator tube rupture in Unit 2 in March 1993. Since that time, APS has undertaken an ongoing investigation and analysis and has performed corrective actions designed to mitigate further degradation. Corrective actions have included changes in operational procedures designed to lower the operating temperatures of the units, chemical cleaning and the implementation of other technical improvements. APS has stated that it believes its remedial actions have slowed the rate of tube degradation.
Steam generator tubes in each of the Palo Verde units have been inspected during regularly scheduled refueling outages and mid-cycle inspection outages. If tube cracks are detected during an
)
inspection, the affected tubes are taken out of service by plugging. This may impair the performance of a unit ifsufficient numbers ofsteam generator tubes are affected.
The projected service lives of the units' steam generators are reassessed by APS periodically in conjunction with inspections made during outages of the Palo Verde units. APS has determined that it will be economically desirable to replace the Unit 2 steam generators, which have been the most affected by tube cracking. In 1997, the Palo Verde Participants unanimously approved the purchase of one set of spare steam generators for delivery in May 2002. The Company's share of the cost is approximately S12.9 million. APS has indicated that in 1998 it will request that the participants approve installation of 55
O EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS
- the spare generators in Unit 2 in 2003. The Company believes that such installation would require the unanimous approval of the Palo Verde Participants. The Company will continue to analyze the economic feasibility of steam generator replacement, or other options that may be available in connection with the operation of Unit 2. Also, the Company cannot predict whether the Palo Verde Participants will agree to replace the Unit 2 steam generators. The costs for the construction and shipping of the spare steam generators are expected to be incurre'd between 1998 and 2002. Installation costs,if they are approved, would be expected to be incurred between 1999 and 2003, with the bulk of the expenditures after 2000. The Company's portion of total costs associated with construction and potential installation of new steam generators in Unit 2, including replacement power costs and costs that would otherwise have been expended through 'the operation and maintenance budget, is currently estimated not to exceed S36 million. APS has also stated that,- based on the latest available data, it estimates'that the steam generators in Units I and 3 should operate for their designated lives of 40 years 1
' (to 2025 and 2027, respectively). APS will reassess the expected lives of these steam generators l
periodically.
1 The Rate Stipulation precludes the Company from seeking a rate increase in Texas during the Freeze Period to recover capital costs associated with such replacement of steam generators. Itis uncertain whether the costs associated with replacing the Unit 2 steam generators would be approved by the New Mexico Commission and included in the Company's rate base in New Mexico.
Liabilip andInsurance Matters. The Palo Verde Participants have public liability insurance against nuclear energy hazards _up to the full limit of liability under federal law. The insurance consists of S200 million of primary liability insurance provided by commercial insurance carriers, with the balance L
- being provided by an industry-wide retrospective assessment ' program, pursuant to which industry participants would be required to pay an assessment to cover any loss in excess of S200 million. The maximum assessment per reactor for each nuclear incident is approximately S79.2 million, subject to an annual limit of S10 million per incident. Based upon the Company's 15.8% interest in Palo Verde, the l
Company's maximum potential assessment per incident is approximately S37.6 million for all three units with an annual payment limitation of approximately S4.7 million.
The Palo Verde Participants maintain "all risk" (including nuclear hazards) insurance for
- property aamage to, and decontamination of, property at Palo Verde in the aggregate amount _of S2.7 billion, a substantial portion of which must first be applied to stabilization and decontamination.
Finally, the Company has obtaincd insurance against a portion of any increased cost of generation or
- purchased power which may result from an' accidental outage of any of the three Palo Verde units if the outage exceeds 23 weeks.
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s EL PASO ELECTRIC COMPANY l
NOTES TO FINANCIAL STATEMENTS D.
Common Stock Ov:rview The Company issued approximately 60 million shares of new common stock on February 12, 1996. The common stock has a stated value of SI per share, with no cumulative voting rights or preemptive rights. Holders of the common stock have the right to elect the Company's directors and to vote on other matters.
i Pursuant to the resolutions creating the Series A Preferred Stock, no dividends can be paid on the j
common stock if there are dividends in arrears on the Series A Preferred Stock. So long as the Company's First Mortgage Bonds are outstanding and the series with the longest maturity is not rated
' " investment grade" by either Standard & Poor's Rating Service or Moody's Investors Service, Inc., the
-Company may not declare any dividend on the common stock, other than in additional shares of common stock, or make any other distribution on, or acquire for value any shares of common stock (with certain limited exceptions) unless, after giving effect thereto, the aggregate of all such dividends, distributions and certain other payments made by the Company since February 12,1996 would be less than the sum of(i) 50% of the consolidated net income (as defined in the mortgage indenture) of the Company minus dividends paid in respect of the Series A Preferred Stock for the period from February 13,1996 to the most recently ended fiscal quarter for which quarterly financial statements are available (or, if such consolidated net income is a deficit, less 100% of such deficit), plus (ii) 100% of the aggregate net proceeds received by the Company from the issuance or sale since February 12,1996 of equity securities or debt securities that have been converted into equity securities, plus (iii) S10.0 million.
j Currently, the Company's First Mortgage Bonds are not rated investment grade.
Pursuant to the terms of the reimbursement agreements related to four letters of credit issued with respect to the four series of pollution control revenue bonds, so long as a drawing is available under any of the letters of credit, the same limitation on the declaration of dividends would apply to the Company. In addition to the restriction contained in the mortgage indenture, the credit agreement for the working capital and fuel financing facility limits to S15.0 million the aggregate amount of dividends that can be paid on the common stock during the three years after its initial issuance on February 12, 1996.
1996 Long-Term Incentive Plan The 1996 Long-Term Incentive Plan (the "1996 Plan") authorized the issuance of up to 3,500,000 shares of common stock for the benefit of officers, key employees and non-employee directors through the award or grant of non-statutory stock options, incentive stock options, stock appreciation rights, restricted stock, bonus stock and performance stock.
Stock Options. Stock' options have been granted at prices equal to or greater than the market value of the shares at the date of grant. The options expire ten years from the date of grant unless terminated 57
EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS carlier by the lloard of Directors. The following table summarizes the transactions of the Company's stock options for 1996 and 1997:
Weighted Average Number of Exercise Shares Price Unexercised options outstanding at February 12,1996..
S Options granted......
1,900,000 5.69 Options exercised..........
Options forfeited......
Unexercised options outstanding at December 31,1996...
1,900,000 5.69-Options granted......
55,000 6.56 Options exercised.............
Options forfeited..
(5.000) 6.56 Unexercised options outstanding at December 31,1997.
1.950.000 5.71 Certain stock options awarded vest ratably over a Ibur or five-year period. Stock options outstanding at December 31,1997 are as follows:
Exercise Number Remaining Number Price Outstanding Life. In Years Exercisable S
5.32 800,000 8.3 320,000 5.56 800,000 8.4 320,000 6.56 50,000 9.3 50,000 7.00 300.000 8.4 300.000 1.950.000 990.000 The Company has adopted the disclosure-only provisions of SFAS No.123. Accordingly,
.. because the stock option grants had no intrinsic value at the measurement date, no compensation cost has been recognized. Had compensation cost for the plan been determined based on the fair value at 58
,k EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS the grant date, consistent with the provisions of SFAS No.123, the Company's net earnings and earnings per share would have been reduced to the pro forma amounts presented below:
Period From February 12 to December 31, December 31, 1997 1996 Net income applicable to common stock (In thousands):
, As re po rte d..............................................S 38,649 S
31,43i Pro forma..........
38,093 30,337
. Basic earnings per share:
As repo rted.....................................
0.643 0.523 Pro forma...
0.634
.0.505 1
' Diluted earnings per share:
As reported.........
0.639 0.523 Pro forma...............
0.630 0.505 The fair value for these options was estimated at the grant date using the Black-Scholes option pricing model. Weighted average assumptions and grant-date fair value for 1997 and 1996 are presented below:
l 1997 1996 Risk-free interest rate 6.76 %
6.85 %
Expected life, in years 10 10 Expected volatility 10.86 %
4.24 %
Expected dividend yield Fair value S3.24 S2.60 RestrictedStock. The Company has awarded vested and unvested restricted stock awards under the 1996 Plan. Restrictions from resale generally lapse, and unvested awards vest, over periods of four to five years.. During 1997 and 1996, approximately S0.5 million and S0.2 million, respectively, relating to
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EL PASO ELECTRIC COMPANY
)
NOTES TO FINANCIAL STATEMENTS restricted stock awards were charged to expense. The following table summarizes the vested and unvested restricted stock awards for 1997 and 1996:
l Vested Unvested Total i
Restricted shares outstanding at February 12,1996..
Restricted stock awards.....
80,000 100,000 180,000 lapsed restrictions..
Restricted shares outstanding at December 31.1996...
80,000 100,000 180,000 Restricted stock awards..
47,440 36,815 84,255 lapsed restrictions and vesting.
(40.488)
(27.363)
(67.851)
Restricted shares outstanding at Decernber 31,1997...
86.952 109.452 196.404 The holder of a restricted stock award has rights as a shareholder of the Company, including the right to vote and,if applicable, receive cash dividends on restricted stock, except that certain restricted stock awards require any cash dividend on restricted stock to be delivered to the Company in exchange for additional shares of restricted stock of equivalent market value.
60
-)
1 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Ric:nciliation of Basic and Diluted Earnings Per Common Share The reconciliation of basic and diluted earnings per common share before extraordinary items is presented below:
For the Year Ended December 31.1997 Per Common Income Shares Share (In thousands)
Income before extraordinary items...
S 54,568 less: Preferred stock dividends..
13.144 Basic earnings per common share:
Income applicable to common stock.
41,424 60,128,505 S 0.689 Effect of dilutive securities:
' Unvested restricted stock.
16,041 Stock options..
293.086 Diluted earnings per common share:
Income applicable to common stock..
S 41.424
. 60.435.632 S 0.685 Period From February 12 to Decembr 31.1996 Per Common Inco:ne Shares Share (In thousands)
Income before extraordinary it "..
S 41,919 less: Preferred stock dividena....
10.488 l
Basic earnings per common share:
Income applicable to common stock..
31,431 60,073,808 $
Q323 EfTect of dilutive securities:
Unvested restricted stock...
3,912 Stock options...
38.989 Diluted earnings per common share:
Income applicable to common stock.
S 31.431 60.116.709 S 0.523 Options to purchase 300,000 shares of common stock at $7.00 per share were outstanding during 1997 and the second half of 1996 but were excluded from the computation of diluted earnings per common share for all periods except the first quarter of 1997 because the options' exercise price was greater than the average market price of the common shares for thoe periods. The options, which expire onJune 11,2006, were still outstanding at the end of 1997. Also excluded from the computation 61 Er
~
1 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS of diluted earnings per common share were options to purchase 525,000 shares of common stock at S7.50 per share, granted onJanuary 2,1998.
The reconciliation of basic and diluted earnings per common share for the Predecessor Company are noc presented herein as there were no reconciling items for periods prior to February 12,1996.
E.'
Preferred Stock i
The Company issued one million shares of new Series A Preferred Stock on February 12,1996.
The preferred stock has a liquidation preference of S100 per share, has no sinking fund requirements and must be redeemed by the Company in 2008. The preferred stock has an annual dividend rate of 11.40%, which is to be paid through the issuance of additional shares of preferred stock for the first three years and in cash thereafter. The Company issued a total of 213,188 additional shares between November 1,1996 and December 31,1997 to satisfy pay-in-kind dividends. Also, onJanuary 22,1998, the Company's Board of Directors declared a scheduled pay-in kind. dividend which was paid on February 1,1998, through the issuance of 34,559 additional shares to shareholders of record as of January 22,1993.
Following is a summary of the changes in the preferred stock of the Predecessor and Reorganized Company:
Redemption Required Redemption Not Required _
Shares Amount Shares Amount (In thousands)
(In thousands)
- Balance at December 31,1994 and 1995.
639,600 S 67,266 142,450 S 14,198 Redemption of Predecessor preferred stock.
(639,600)
(67,266)
(142,450)
(14,108)
Issuance of Reorganized preferred stock..
1,000,000 100,000 Issuance of dividends..
84.264 8.426 Balance at December 31,1996.
1,084,264 108,426 Issuance of dividends..
128.924 12.893 Balance at December 31,1997.
1.213 188 S 121.319 S
Optional Redanption. The Series A Preferred Stock is not redeemable at the Company's option prior to February 1,1999; provided, however, that upon the occurrence of a change of control on or prior to February 1,1999, the Company shall have the right to redeem the outstanding Series A Preferred Stock, in whole or in part, no earlier than 30 days nor later than 60. days from the date the change of control offer is mailed to the holders of Series A Preferred Stock, in cash, at a price per share.
equal to the sum of (i) 108% of the liquidation preference plus (ii) accrued and unpaid dividends
.(including an amount equal to a prorated dividend from the immediately preceding dividend accrual date), if any, to the redemption date. Thereafter, the outstanding Series A Preferred Stock may be redeemed, in whole or in part, at the option of the Company, in cash at the redemption prices set forth in the table below, plus all accrued and unpaid dividends (including an amount equal to a prorated 62
EL PASO EIECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS dividend from the immediately preceding dividend accrual date to the date of redemption), if any, if redeemed during the twelve-month period beginning on February 1 of the years indicated below:
Optional Redemption
-l Year Price l
1999.............................................
105.70 %
2000............................................
104.56 2001..........................................
103.42 2002................................................
102.28 2003'...........................................
101.14 2004 and thereafter...................
100.00 Mandator,y Redemption. On February 1,2008, the Company will be required to redeem (subject to the. legal availability of funds therefor) all outstanding shares of Series A Preferred Stock at a price m cash equal to the sum of(i) the liquidation preference thereof plus (ii) all accrued and unpaid dividends, if
.any, to the date of redemption.
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a EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS F.
Long-Term and Financing and Capital Lease Obligations Outstanding long-term and fmancing and capital lease obligations are as follows:
December 31.
1997 1996 long-Term Oblications:
First Mortgage Bonds (1):
7.25% Series A, issued 1996, due 1999.
S 66,261 S
78,266 7.75% Series B, issued 1996, due 2001.
62,698 78,771 8.25% Series C, issued 1996, due 2003..
I19,292 148,989 4
8.90% Series D, issued 1996, due 2006..
223,132 235,957 9.40% Series E, issued 1996, due 2011..
273,398 285,900
' Pollution Control Bonds (2):
Secured by First Mortgage Collateral Series Bonds:
Variable rate bonds, due 2014...
63,500 63,500 Variable rate refunding bonds, due 2013.......
33,300 33,300 Variable rate refunding bonds, due 2014.
37,100 37,100 Variable rate refunding bonds, due 2015.........
59,235 59,235 Promissoy note due 2007 (S84,000 due in 1998)(3)....
730 958 Total long-term obligations.
938.646 1.021.976 Financing and Canital Lease Oblications:
Turbine lease (S1,722,000 due in 1998)(4)..
4,628 5,900 Nuclear fuel (S26,657,000 due in 1998)(5)..
51.999
,__ 46.630 Total financing and capitallease obligations...
56.627 52.530 l
Total long-term and financing and capital lease obligations.
995,273 1,074,506 Current maturities (Amount due within one year).............
(28.463)
(28.333)
S 966.810 S 1.046.173 (1) First hlortgage Bonds Substantially all of the Company's utility plant is subject to liens under the First hlortgage Indenture.
The First Afortgage Indenture imposes certain limitations on the. ability of the Company to (i) declare or pay dividends on common stock; (ii) incur additional indebtedness or liens on mortgaged property; and (iii) enter into a consolidation, merger or sale dassets.
Series A, B, C and D Bonds may not be redeemed by the Company prior to maturity. Series E
- Bonds may be redeemed at the option of the Company, in whole or in part, on or after February 1, 2006.
64
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EL PASO ELECTRIC COMPANY l
NOTES TO FINANCIAL STATEMENTS The Company is not required to make mandatory redemption or sinking fund payments with respect to the bonds prior to maturity.
Repurchases of First Mortgage Bonds made during 1997 and 1996 are as follows (In thousands):
Period From February 12 Year Ended to December 31, December 31, 1997 1996 7.25% Series A............................
S 12,005 S
46,726 7.75% Series B................
16,073 71,217 8.25% Series C.......
29,697 8
8.90% Series D..................
I2,825 9.40% Series E..........,..........
I2.502 Total.....
S 83.102 S
117.951 (2) Pollution Control Bonds The Company has four series of tax exempt Pollution Control Bonds in an aggregate principal amount of approximately S193.1 million. Each of the tax exempt issues is enhanced by a letter of credit. The Company's obligation to the issuing banks pursuant to the letter of credit reimbursement agreements are secured by First Mortgage Collateral Series Bonds (the " Collateral Series Bonds")
. issued pursuant to the First Mortgage Indenture in the amount of the letters of credit. The efTective annualinterest rate on the bonds is calculated to be 5.65% at December 31,1997. The bonds may be required to be repurchased at the holder's option or are subject to mandatory redemption upon the occurrence of certain events, and are redeemable at the option of the Company under tertain circunctances.
(3) Promissory Note The note has an annualinterest rate of 5.5% and is secured by certain furniture and fixtures.
(4) Capitalized Lease Obligation, Copper Turbine The Company leases a turbine and certain other related equipment under a lease which expires in July 2000. with renewal options for up to seven additional years. Semiannual lease payments, including interest, are approximately S0.9 million through July 2000. The effective annual interest rate implicit in this lease is calculated to be 9.6%.
65
4 j
EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS 1
(5) Nuclear Fuel Financing The Company has available a S100 million credit facility that provides for working capital and up to S60 million for the financing of nuclear fuel. This financing is efTected through a trust that borrows under the facility to acquire ar.d process the nuclear fuel. The Company is obligated to repay the trust's borrowings, and has secured this obligation with Collateral Series Bonds. In the Company's financial statements, the assets and liabilities of the trust are reported as assets and liabilities of the Company.
The letter of credit reimbursement agreements which enhance the Company's Pollution Control Bonds and the $100 million credit facility require compliance with certain total debt and interest coverage ratios. The Company maintained the required compliance throughout 1997.
Scheduled maturities oflong-term and financing and capital lease obligations at December 31, 1997 are as follows (In thousands):
1998........
S 28,463 I 9 99..............................
93,412 2000...........................................
1,815 2001..........................................
62,797 2002........................................................
104 The table above does not reflect nuclear fuel purchase commitments and related obligations and
. maturities.
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f EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS i
l G.
Income Taxes The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31,1997 and 1996 are presented below (In thousands):
I December 31, December 31, 1997 1996 l.
Deferred tax assets:
Reorganization expenses financed with bonds.......
S 18,308 S 22,526 Capi tal leases...................................
2,633 2,873 l
Benefits of tax loss carryforwards........
222,764 256,510 Investment tax credit carryfonvard...................
20,410 20,410 Ahernative minimum tax credit carryfonvard........
I1,954 9,627 Other (including state deferred taxes)...
82.929 92.643 l
Total gross deferred tax assets.,
358.998 404.589 I
Less valuation allowance:
Fed e ral.....................................
I2,661 12,661 State.
17.149 17.941 l
Total valuation allowance......
29.810 30.602 1
Net deferred tax assets...............
329.188 373.987 Deferred tax liabilities:
Plant, principally due to difTerences in depreciation and basis difTerences.......
(275,531)
(288,416) i Other....
(l0.449)
(l1.687)
Total gross deferred tax liabilities................
(285.980)
(300.103)
Net accumulated deferred income taxes...
S 43.208 's 73.884
.The deferred tax asset valuation allowance decreased by approximately S0.8 million in 1997, S226.7 million in 1996 and S4.5 million in 1995. The decrease in 1997 was due to a reduction of I
unused state net operating loss ("NOL") carryfonvard benefits, which had valuation allowances recorded against them. The decrease in 1996 was primarily due to the Company's belief that, because of the Rate l
- Stipulation, Reorganization, and other factors, it is more likely than not that the Company will have L
suflicient taxable income in the future to utilize most of the tax NOL carryforward benefits that had j
valuation allowances recorded against them. The Company believes that the net deferred tax assets L would be fully realized at current levels of taxable income.
Prior to the effective date of the
! Reorganization, the Predecessor Company did not assume future taxable income for the utilization of NOL carryforwards. Approximately S27.1 million of the Compan/s valuation allowance at December 31,1997, if subsequently recognized as a tax benefit, would be credited directly to capital in E
excess ofstated value in accordance with SOP 90-7.
i 67 l
s EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The Company recognized income taxes as follows (In thousands):
Period From Period From February 12 January 1 Year Ended to to
. Year Ended t
December 31, December 31, February 11, December 31, 1997 1996 1996 1995 Income tax expense (benefit):
Federal:
Current..
S 2,382 S (17,203)
S S
13,757 Deferred..
28,087 38,828 (2,340) -
(21,703)
Investment tax credit amortization..
(325)
(2.828)
Subtotal current operations.
30,469 21,625 (2,665)
(10,774)
Deferred tax benefit on extraordinary loss..
(1,491)
Adjustment of assets to reorganization value and liabilities to fair value (elimination r
o accumulated deferred investment
.x credits)..
(77,950) l Deferred included in reorganization items.
(172,899)
(1,194)
Income tax expense on interest income during bankruptcy..
583 4.633 Total.
S 28.975 S 21 625 S
(252.9311 S (7.335)
State:
Current..
5 S
278 5
116 S 935 Deferred..
4.307 4.767 (866)
(5.9591 Subtotal current operations.
4,307 5,045 (750)
(5,024)
Deferred included in reorganization items.
(17.494)
Total.
S 4.307 S 5.045 S
(18.244) S
/5.024) 1
- The current federal income tax expense for 1997 results primarily frorn the accrual of alternative minimum tax ("Ah1T") for 1997. Deferred federal income tax includes an offsetting Ah1T benefit of approximately S2.4 million.
The current federal income tax benefit for 199f) resulted primarily from the carryback of 1996 AhlT NOL to the 1993,1994 and 1995 tax years and decreased by an expense for the reduction of investment tax credits ("ITC") utilized. Deferred federal income tax includes an olTsetting Ah1T deferred expense of approximately S24.0 million and a benefit for an increase in ITC carryforward of j
approximately S6.8 million.
The current federal income tax expense for 1995 results primarily from the accrual of Ah1T expense. The deferred federal income tax benefit recorded in 1995 includes ofIsetting Ah1T credits of approximately S18.3 million. ITC utilized of approximately S4.6 million was recorded as a reduction to current tax and included as a deferred tax expense.
68
+
EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Federal income tax provisions differ from amounts computed by applying the statutory rate of 35% to book income (loss) before federal income tax as follows (In thousands):
Period From Period Fmm February 12 January 1 Year Ended to to Year Ended December 31, December 31, February 11, December 31, 1997 1996 1996 1995 Federal income tax expense (benefit) computed on income (loss) at statutory rate..
S 28,269 S 22,240 S
45,339 S
(14,229)
Difference due to:
ITC amortization (net of deferred taxes).
(211)
(1,838)
Nondeductible bankruptcy costs.,
3,604 5,925 Federal valuation allowance.
(204,848)
(4,461)
Adjustment of assets to reorganization value and liabilities to fair value (elimination of accumulated deferred ITCs)..
(77,950)
Reorganization costs (including the nontaxable extraordinary gain on discharge of debt)..
(27,745)
Other.
706 (6151 8.880 7.268 Total federal income tax expense (benefit).
S 98 975 S 21.625 S (952.931) S (7.335)
Effective federal income tax rate..
35.9 %
34.0 %
/195 3 %
18.0 %
The Company had approximately S636.5 million of tax NOL carryfonvards, approximately S20.4 million ofITC carryfonvards and approximately S12.0 million of AMT credit cartyfonvards as of December 31,1997. If unused, the NOL carryfonvards would expire at the end of the year 2011, the ITC carryfonvards would expire in the years 2001 through 2005 and the AMT credit carryfonvards have an unlimited life.
The Reorganization and the associated implementation of fresh-start reporting gave rise to significant items ofincome and expense for fmancial reporting purposes that are not included in taxable income. These reorganization items resulted in an effective tax rate for the period fromJanuary I to February. 11,1996 that is significantly different than the current statutory rate of 35%.
H.
Commitments and Contingencies Sr13/ Leaseback Indemnification Obligations Pursuant to 'the Palo Verde sale / leaseback participatioh agreements and leases, if the lessors incur additional tax liability or other loss as a result of federal or state tax assessments related to the sale / leaseback transactions, the lessors may have claims against the Company for indemnification.
Pursuant to settlement agreements entered into under the Plan, certain of these indemnity obligations related to tax matters have continued after the EfTective Date.
. One of the lessors in the sale / leaseback transactions related to Unit 2 of Palo Verde has notified the Company that the Internal Revenue Service (" IRS") has raised issues, primarily related to ITC 69
e.
EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS claims by the lessor, regarding the income tax treatment of the sale / leaseback transactions. The Company estimates that the total amount of potential claims for indemnification from all lessors related to'the issues raised by the IRS could approximate S10.0 million, exclusive of any applicable interest, if the IRS prevails. Although the Company believes the lessor has meritorious defenses to the IRS' position, the Company cannot predict the outcome of the matter or the Company's liability for any resulting claim for indemnification. The Company does not believe it is probable that a loss has been incurred and, therefore, has made no provision in the accompanying financial statements related to this
~
matter.
Environmental Matters The Company is subject to regulation with respect to air, soil and water quality, solid waste disposal and other environmental matters by federal, state and local authorities. These authorities govern current facility operations and exercise continuing jurisdiction over facility modifications.
Environmental regulations can change rapidly and are difficult to predict. Because construction of new facilities is subject to standards imposed by environmental regulation, substantial expenditures may be
(
required to comply with such regulations. The Company analyzes the costs of its obligations arising from environmental matters on an ongoing basis, and management believes it has made adequate provision in its financial statements to meet such obligations. However, unforeseen expenses associated with compliance could have a material adverse effect on the future operations and financial condition of the Company.
..PCB Treatment, Inc. The Company received a request from the U.S. Environmental Protection Agency (" EPA") to participate in the remediation of polychlorinated biphenyls ("PCBs") at two facilities in Kansas and Missouri, which had been operated by PCB Treatment, Inc. ("PTI"). Presently, PTI has discontinued operations and the EPA has determined that FTPs abandoned facilities require remediation.
The Company and the FTI Steering Committee, which consists of the largest generators of the PCBs sent to FTI, have executed a settlement agreement. In consideration for the payment of approximately S0.2 million, the settlement agreement excuses any further liability by the Company to the Steering Committee and indemnifies the Company for any liabilities to other parties as may be asserted in the future.
On September 16,1997, the EPA sent the Company a " general notice ofliability" wherein the agency formally notified the Company that it was considered a Potentially Responsible Party at the sites.
l The Company believes any liability it may face at the sites is covered by the settlement agreement.
Accordingly, the Company immediately notified the Steering Committee and demanded it defend and indemnify the Company as provided in the settlement agreement. The Steering Committee informed j
the Company that it intends to honor this indemnity obligation.
The Company may still face liability for possible deliveries of PCBs by FTI to a third site which is also subject to remedial action by the federal authorities, except to the extent that those PCBs were 70
- ~. _ _ - - -..
EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS transferred from the first site. The Company's records do not indicate any deliveries of PCBs to this third site. The Company believes it is unlikely to face substantial unindemnified liabilities associated with this third site.
< CoalMine Redamation. The Company has been informed by APS that the Company's estimated financial obligation for coal mine reclamation at Four Corners is not being fully reflected in the costs for which the Company is billed. APS, the operating agent for Four Corners, is performing an analysis to establish an appropriate revised cost estimate. Based on preliminary estimates from APS and the coal provider, the Company recorded a liability of approximately S12 million in 1996 which reflects the present value of the estimated future costs of reclamation for its share of the coal mine reclamation obligation.
Ic Litigation Litigation with Las Cruces Las Cruces is attempting to replace the Company as the electric senice provider in 12s Cruces by acquiring, thmugh condemnation or a negotiated purchase, the distribution assets and other facilities used to provide electric senice to customers in Las Cruces. Sales to customers in Las Cruces represent approximately 8% of the Company's operating revenues.
In April 1995, Las Cruces filed a complaint against the Company in New hiexico state court, seeking'a declaratoryjudgment that Las Cruces has a right of eminent domain to condemn the electric distribution system and related facilities owned and operated by the Company within and adjacent to the city limits. In hiay 1995, the Company removed the case to federal district court in New Mexico.
Following a trial on the merits, the Federal Magistrate granted the Company's motion to certify to the New Mexico Supreme Court the question of whether Las Cruces possesses the authority to condemn the Company's property for use as a municipal utility when that property is already devoted to public use.
Prior to a ruling by the New Mexico Supreme Court, the New hiexico legislature enacted a bill which purports to give Las Cruces the authority to condemn the Company's distribution system within its city limits and a territory extending five miles beyond the municipal boundary. On February 11,1998,the New Mexico Supreme Court ruled that the subsequent legislation rendered moot the certified question before the Supreme Court. On February 26,1998, the Company received notice from 12s Cruces ofits intent to file a condemnation action in New Mexico district court. At this time the Company is unable to predict t) e. outcome of this litigation.
If Las Urum succeeds in its efforts to condemn the Company's distribution system, the Company could lose its Las Cruces customer base, although the Company would be entitled to receive "just ampensation" as established by the court under New Mexico law. "Just compensation" is generally defined as the amount ofmoney that would fairly compensate the party whose property is condemned. It is the Company's opinion that this amount would be the difference between the value of the Company's entire system prior to the taking, as compared to the value of the entire system after the taking. See Note 11 for a full discussion of stranded costs.
71
e 44 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Las Cruces has taken several actions to position itself to acquire portions of the Company's distribution system and certain related facilities. In August 1994, Southwestern Public Service Company
-("SPS") and las Cruces entered into a fifteen-year contract granting SPS the right to provide all of the electric power and energy required by Las Cruces during the term of the contract. In addition, Las Cruces sold approximately. S73 million in revenue bonds in October 1995 to provide funding to finance the acquisition by condemnation or negotiated purchase of the Company's electrical distribution assets within and adjacent to the Las Cruces city limits.
The Company has filed a lawsuit in the Dona Ana County District Court and is pursuing a complaint simultaneously before the New Mexico Commission challenging the legality of the sale of the revenue bonds. In addition, the New Mexico Commission is investigating the agreement between SPS and Las Cruces which, under certain circumstances, would grant Las Cruces an option to sell to SPS electric utility assets acquired through condemnation. In August 1996, the Dona Ana County District Court issued an opinion letter stating that Section 3-23-3 of the New Mexico Municipal Code is inapplicable to home rule municipalities and Las Cruces, therefore, was not required to acquire the New Mexico Commission's approval before issuing revenue bonds to acquire utility property. However, the Court did agree with the Company that the revenue bonds, in this case backed by utility revenues, are subject to the same requirements as those imposed on other revenue bonds backed by gross receipts tax revenues. Therefore,if the Court's finding of the applicability of Las Cruces' home rule authority is q
overturned on appeal, the Company's position that the issuance of the bonds required prior approval could be upheld. The Company filed an appeal with the New Mexico Court of Appeals and Las Cruces requested an expedited ruling from the Court of Appeals. In August 1997, the New Mexico Court of Appeals certiEed to the New Mexico Supreme Court the issues related to Las Cruces' authority to issue the revenue bonds. Oral argument before the Supreme Court was held in November 1997.
InJuly 1996, Las Cruces exercised its right under Order No. 888 to request that the Company calculate Las Cruces' stranded cost obligation should it leave the Company's system and operate its own municipal utility. The Company's initial non-binding calculation was provided within the statutory
. period. Las Cruces subsequently filed a request at the FERC for a determination that Las Cruces would have no stranded cost obligation to the Company or, in the alternative, that the FERC convene a hearing to establish the amount of any stranded costs. In August 1997, the FERC issued an order denying Las Cruces' request for a determination that Las Cruces would have no stranded cost obligation, i
and providing for evidentiary hearings on the following stranded costs issues: (i) whether the Company has met the " reasonable expectation" standard so as to justify recovery of stranded costs from l
Las Cruces; and (ii) if so, the amount of stranded costs that the Company may recover from Las Cruces.
The Company filed testimony in support ofits recovery and calculation of stranded costs, calculated pursuant to the FERC formula. After removal of all distribution and transmission related expenses, the -
Company's testimony reflects a generation stranded cost request of approximately S101 million. In November 1997, Las Cruces filed testimony which takes the position that the Company is entitled to stranded costs in the range of S0 to S19 million.,On December 19,1997, the FERC staff filed testimony estimating the Company's stranded cost to be S29.4 million. Hearings of all issues were conducted at the 72
- -~ - -._ -.-
EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS FERC in February 1998. A final decision from the FERC is not expected before late 1998 or early 1999.
In April 1997, Las Cruces announced its plan to build a substation and distribution lines to serve a new customer in a city-owned industrial park. Las Cruces stated that SPS would construct, operate and maintain the new substation facility, and that the ratee fbr this new customer would be significantly l
lower than the Company's current rates. Las Cruces has approved a contract with SPS to provide operation and maintenance services for the proposed Las Cruces electric distribution system, substations and associated transmission facilities.
The Company continues to believe that it can provide lower cost electric service to customers in Las Cruces than can be achieved through a municipal takeover. Accordingly, the Company has stated its strong preference for a resolution ofits differences with Las Cruces through negotiation rather than litigation and condemnation. A negotiated settlement of the Company's pending rate case in New Mexico could include a reduction in rates and settlement of all issues in New Mexico, which would be likely to create increased political and economic pressure on the Company to reduce rates in Texas.
The Company is unable to predict the outcome of Las Cruces' efforts to replace the Company as its electric service provider or the effects it may have on the Company's financial position, results of operations and cash flows. The Company does not believe it is probable that a loss has been incurred and, therefore, has made no provision in the accompanying financial statements related to these matters.
Fe:r Corners In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act and the Navajo Nation Pesticide Act (collectively, the " Acts"). In October 1995, the Four Corners participants requested that the United States Secretary of the Interior resolve their dispute with the Navajo Nation regarding whether the Acts apply to operation of Four Corners. The Four Corners participants subsequently filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, seeking, among other things, a declaratory judgment that (i) the Four Corners leases and federal casements preclude the application of the Acts to the operation of Four Corners; and (ii) the Navajo Nation and its agencies and courts lack adjudicatory
. jurisdiction to determine the enforceability of the Acts as applied to Four Corners. On October 18, 1995, the Navajo Nation and the Four Corners participants agreed to stay the proceedings indefinitely so the parties may attempt to resolve the dispute without litigation. This matter remains inactive and the Company is unable to predict the outcome of this case.
- Wct r Cases SanJuan River System. The Four Corners participants are among the defendants in a suit filed by the State of New Mexico in 1975 in state district court in New Mexico against the United States of America, the City of Farmington, New Mexico, the Secretary of the Interior as Trustee for the Navajo Nation and other Indian tribes and certain other defendants (State ofXewMexico ex rel. S. E. Reynolds, 73
EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS NewMexico State Engineer v. United States of Arnerica, et al., Eleventh Judicial District Court, County of Sanjuan, State of New Mexico, Cause No.75-184). The suit seeks adjudication of the water rights of the SanJuan River Stream System in New Mexico, which, among other things, supplies the water used at four Corners. An agreement reached with the Navajo Nation in 1985 provides that if Four Corners loses a portion of its water rights in the adjudication, the tribe will provide sumcient water from its allocation to offset the loss. The case has been inactive for many years and the Company is unable to predict the outcome of this case.
Gila River @ stern. In connection with the construction and operation of Palo Verde, APS entered into contracts with certain municipalities granting APS the right to purchase emuent for cooling purposes at Palo Verde. In 1986, a summons was served on APS that required all water claimants in the Lower Gila River Watershed in Arizona to assert any claims to water in an action pending in Maricopa l
County Superior Court, titled in re The General Adjudication ofAllRights to Use Water in the Gila River Systern andSource. Palo Verde is located within the geographic area subject to the summons and the rights of the Palo Verde Participants to the use of groundwater anci -muent at Palo Verde is potentially at issue in this action. APS, as operating agent, filed claims that dispua the Court'sjurisdiction over the Palo Verde Participants' groundwater rights and their contractual rigits to emuent relating to Palo Verde and, alternatively, seek confirmation of such rights. In December 1992, the Arizona Supreme Court heard oral argument on certain issues in this matter that are pending on interlocutory appeal. Issues important to the Palo Verde Participants' claims were remanded to the trial court for further action and the trial court certified its decision for another interlocutory appeal to the Arizona Supreme Court. The Arizona Supreme Court will hear argument on these issues in October 1998 and subsequently render a decision.
The Company is unable to predict the outcome of this case.
Other Legal Proceedings The Company is a party to various other claims, legal actions and complaints. In many of these matters, the Company has excess casualty liability insurance which is applicable. Based upon a review of these claims and applicable insurance coverage, the Company believes that none of these claims will have a material adverse effect on the operations, financial position or cash flows of the Company.
J.
Employee Benefits Pension Plan The Company's Retirement Income Plan (the " Retirement Plan") covers employaes who have completed one year of senice with the Company, are 21 years of age and work at least a mirdmum number of hours each year. The Retirement Plan is a qualified noncontributory defined benefit plan.
Upon retirement or death of a vested plan participant, assets of the Retirement Plan are used to pay benefit obligations under the Retirement Plan. Contributions from the Company are based on the minimum funding amounts required by the Department of Labor and IRS under provisions of the Retirement Plan, as actuarially calculated..The assets of the Retirement Plan are invested in equity L
74
1
.s EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS securities, fixed income instruments and cash equivalents and are managed by pmfessional investment managers appointed by the Company.
The Company's Non-Qualified Retirement Income Plan is a non-funded dermed benefit plan which covers certain former employees of the Company. The pension cost for the Non-Qualified Retirement Income Plan is based on substantially the same actuarial methods and economic assumptions as those used for the Retirement Plan.
During 1996, as part of the Reorganization, the Company tenninated the Non-Qualified Retirement Income Plan with respect to all active employees resulting in a curtailment gain of approximately S2.0 million. In conjunction therewith, the Company entered into retirement agreements with ten ofIicers who had been participants in the Non-Qualified Retirement Income Plan resulting in an increase in the accumulated benefit obligation of approximately S10.2 million. This increase in the accumulated benefit obligation and the curtailment gain were recognized as reorganization items by the Predecessor Company.
Net periodic pension cost for the Retirement Plan and the Non-Qualified Retirement Income Plan under SFAS No. 87, " Employers' Accounting for Pensions," is made up of the components listed below as determined using the projected unit credit actuarial cost method (In thousands):
Period From Period From 1
Year February 12
, January 1 Year Ended to to Ended December 31, December 31, February 11, December 31, 1997 1996 1996 1995 Service costs for benefits earned during the period..
S 2,402 S 2,148 '
S 354 S 2,011 Interest costs on projected benefit obligation.
6,737 5,774 749 5,157 Actual return on plan assets.
(12,469)
(5,019)
(570)
(9,267)
Net amortization and deferral..
7,375 842 113 6,008 Recognition of previously unrecognized items..
21.738 f
Net periodic pension cost recognized..
S 4 045 S 1745 S
22.384 s 3.909 1
The assumed annual discount rates used in determining the net periodic,ension cost were 7.50%,7.25% and 8.50% for 1997,1996 and 1995, respectively.
The pension cost includes amortization of unrecognized items. In the application of fresh-start reporting, the Company recorded the then existing unrecognized items as of February 11,1996 in the amount of approximately S21.7 million.
75
4 4
EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The funded status of the plans and amount recognized in the Company's balance sheets at December 31,1997 and 1996 are presented below (In thousands):
December 31.
1997 1996 Non-Non- -
Qualified Qualified Retimment Retirement Retimment Retirement Income Income Income Income Plan Plan Plan Plan Actuarial present value of benefit obligations-Vested benefit obligation.,
S (65.523) S I'19.324) s (57.366) S (18.171)
Accumulated benefit obligation..
8 (68.481) s (19.324) s (59.883) s (18.171)
Projected benefit obligation..
.S (83,812) S (19,324) S (72,951) S (18,171)
Plan assets at fair value.
74.114 61.460 Projected benefit obligation in excess of plan assets.
(9,698)
(19,324)
(11,491)
(18,171)
Unrecognized net (gain) loss from past experience..
(4,887) 162 (3,520)
(1,368)
Adjustment required to recognize minimum liability.
(162)
Accrued pension liability.
(14.585) S (19.321) S (15.011) s (19.539) e Actuarial assumptions used in determining the actuarial present value of projected benefit obligations are as follows:
1997 1996 Discount rate..
7.00%
7.50%
Rate ofincrease in compensation levels...
5.00%
5.00%
Expected long-term rate of return on plan assets..........
8.50*.
8.50%
. Other Postretirement Benefits
. The Company provides certain health care benefits for retired employees and their eligible dependents and life insurance benefits for retired employees only. Substantially all of the Company's employees may become eligible for those benefits if they reach retirement age while working for the Company. Those benefits are accounted for under SFAS No. 106, " Employers' Accounting for
~ Postretirement Benefits Other Than Pensions." Contributions from the Company are based on the funding amounts required by the Texas Commission in the Rate Stipulation. The assets of the Other Postretirement Benefits Plan are invested in fixed income instruments and cash equivalents and are managed by professional investment managers appointed by the Company.
76
o EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The benefit cost includes amortization of unrecognized items. In the application of fresh-start reporting, the Company recorded the then existing unrecognized items as of February 11,1996 in the amount of approximately S52.3 million.
Net periodic postretirement benefit ccat is made up of the components listed below (In thousands):
Period Period From From Year February 12 January 1 Year Ended to to Ended l
December 31, December 31, February 11, December 31, l
1997 1996 1996 1995 Service costs for benefits earned during the period...
S 2,538 S 2,209 S
279 S
1,603 Interest costs on accumulated postretirement benefit obligation.
5,254 4,723 607 4,046 Actual return on plan assets..
(250)
(146)
Amortization of transition obligations..
263 2,363 Amortization of(gain) loss..
(7) 60 (54)
Recognition of previously unrecognized items.
52.340 Net periodic postretirement benefit cost j
a recognized....
E 7.535 S 6.786 S
53.549 S
7.958
)
The funded status of the plan and amount recognized in the Company's balance sheets at December 31,1997 and 1996 are presented below (In thousands):
December 31.
1997 1996 j
Accumulated postretirement benefit obligation:
Retirees....
S (35,846) S (29,908)
Active participants:
Fully eligible.
(10,171)
(10,964)
)
Other...
(37.956)
(36.727)
(83,973)
(77,599)
Plan assets at fair value..
8.822 8.050 i
Accumulated postretirement benefit obligation in excess of plan assets..
(75,151)
(69,549)
Unrecognized net gain from past experience different from that assumed..
(380)
(1.764)
Accrued postretirement benefit liability.
S (75.531) S (71.313)
For measurement purposes, a 10.9% annual rate of increase in the per capita cost of covered health care benefits wa: assumed for 1998; the rate was assumed to decrease gradually to 6% for 2004 77
EL PASO ELECTRIC COMPANY j
NOTES TO FINANCIAL STATEMENTS and remain at that level thereafter. The health care cost trend rate assumption has a significant effect on the amounts reported. To illustrate, increasing the assumed health care cost trend rates by one percentage point in each year would increase the accumulated postretirement benefit obligation as of December 31,1997 by S10.5 million and the aggregate of the senice and interest cost components of net periodic postretirement benefit cost for the year ended December 31,1997 by S t.2 million.
Actuarial assumptions used in determining the actuarial present value of accumulated postretirement benefit obligations are as follows:
1997 1996 Discount rate........
7.00%
7.50%
)
Rate ofincrease in compensation levels...
5.00%
5.00%
Rate of return on plan assets.........
4.50%
4.50%
All Employee Cash Bonus Plan The All Employee Cash Bonus Plan (the " Bonus Plan"), introduced in early 1997, was i
established to reward employees for their contribution in helping the Company attain its corporate goals.
Eligible employees below officer level would receive a cash bonus if the Company attained established levels of safety, customer satisfaction and deleveraging (or cash flow) during 1997. The cash flow goal had to be met before any bonus amounts would be paid, and improvement in cash flmv must be greater than any bonus amounts paid. The Company was able to surpass the required minimum levels of improvement in two out of the three performance measures. As a result of the Company's success, the Company distributed approximately S2.3 million in cash bonuses to all eligible employees in early February 1998. The bonus was expensed in the fourth quarter of 1997. The Company has renewed the Bonus Plan in 1998 with similar goals.
j
)
K.
Franchises and Significant Customers City of El Paso Franchise The Company's major franchise is with the City of El Paso, Texas. The franchise agreement provides an arrangement for the Company's utilization of public rights of-way necessary to serve its retail customers within the City of El Paso. The franchise with the City of El Paso extends through August 1, 2005.
Las Cruces Franchise The Company's franchise with Las Cruces expired in March 1994.
The Company has continued to provide electric senice to customers within Las Cruces; however, las Cruces is attempting to replace the Company as the electric service provider in 12s Cruces. Recently, the New Mexico legislature has passed legislation which purports to give Las Cruces the authority to condemn the 78
W EL PASO ELECTRIC COMPANY l
l NOTES TO FINANCIAL STATEMENTS Company's distribution system and related assets. If Las Cruces succeeds in its efibrts to condemn the Company's distribution system, the Company could lose its Las Cruces customer base. See Note I.
Military Installations
- The Company currently serves Holloman Air Force Base ("Holloman"), White Sands Missile Range (" White Sands") and the United States Army Air I)efense Center at Fort Bliss ("Ft. Bliss"). The Company's sales to the military bases represented approximately S19.6 million or 3% of operating revenues in 1997. The Company signed a new contract with Ft. Bliss in August 1996, which provides that Ft. Bliss will take service from the Company through 1999, with the right thereafter to continue service on a year-to-year basis for an additional two years. The Company has a contract for service to i
l Holloman for a ten-year term which began in December 1995. In August 1996, the Army advised the Company that White Sands would continue to purchase retail electric service from the Company pursuant to the existing retail service contract for an indefinite period, until written termination of such j
contract by the Army not less than one year in advance of the termination date.
L.
FinancialInstruments SFAS No.107, " Disclosure about Fair Value of Financial Instruments," requires the Company to i
disclose estimated fair values for its financial instruments. The Company has determined that cash and temporary investments, accounts receivable, long-term contract receivable, accounts payable, customer deposits, decommissioning trust funds, long-term debt, and preferred stock meet the definition of
' financial instruments. The carrying amounts of cash and temporary investments, accounts receivable, accounts payable, and customer deposits approximate fair value because af the short maturity of these items.
Based on prevailing interest rates, the fair value of the long-term contract receivable approximates its carrying value. Decommissioning trust funds are carried at market value.
79
4
%~
J EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The fair values of the Company's long-term debt, including the current portion thereof, and preferred stock, are based on estimated market prices for similar issues at December 31,1997 and 1996 and are presented in the table below (In thousands):
1997 1996 Estimated Estimated Carrying Fair Carrying Fair Amount Value Amount Value First Mortgage llonds...
S 744,78i S 814,857 S 827,883 S 864,047 Pollution Control Bonds.
193,135 193,135 (2) 193,135 193,135 (2)
Nuclear Fuel Financing (l).
51.999 51.999(3) 46.630 46.630(3)
Total.
S 989.915 s 1.059.991 S1.067.648 s 1.103.812 Preferred Stock....
S 121.319 S 131.752 S 108.426 S 119.377 (1) Includes current maturities.
(2) The interest rate on the Company's pollution control bonds is reset weekly to reflect current market rates. Consequently, the carrying value approximates fair value.
(3). The interest rate on the Company's financing and capital lease obligations for nuclear fuel purchases l
is reset every quarter to reflect current market rates. Consequently, the carrying value approximates fair value.
~,
80
o b
EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS M.
Selected Quarterly Financial Data (Unaudited)
Numiben Ibix!Ihun li4 uary12 January 1 to 1997 O_uarters 1996 O_uarters March 31, iblauasy 11, 4thm 3rd
_ _.2nd_.
Ist 4th 3rd 2nd 1996 1996 (la thousands except for share data)
Operating twnues
$143,766 $170,140 $144,275 $135,857 $ 143,023 $ 166,656 $144,388 8 69,907 54,949 Opraringincome 31,210 59,179 40,015 31,233 29,958 57.964 40,730 15,839 1,639 lacorne (Icas)lrfore reorpnaation itenu aruimnw,4wyitems.
8,743 23,988 16,245 5,592 7,960 22,770 9.500 1,689 (4,053)
Reorganizationitems, net ofincome taabenefit 122,251 b:rrordinaryhason repudiasesof detA, '
ret of federalincome taxterr6t......
(35)
(69)
(427l (2,244)
Extramdustygaincndishargeddets..
264,273 (2)
Netincrmapg&alle tocxamman stock.
5,282 20,588 12,580 199 4,898 19,793 6,603 137 382,471 Basic camings per common share:
Income l:dn extraordinary itens..._.
0.089 0.343 0.216 0.040 0.082 0.329 0.110 0.002 3.325 Extrardinary kms on repudiases of debt, ret of federalirmne tax berrfit (0.001)
(0.001)
(0.007)
(0.037)
Extrardinary gain on disdurge of debt.
7.435 (2)
Net iimne.
0.088 0.342 0.209 0.003 0.082 0.329 0.110 0.002 10.760 Diluted camings percornmon share:
Income trfore extraordinaryitems...
0.088 0.',4 2 0.216 0.04 0 0.081 0.329 0.1 i0 0.002 3.325
> Emuw,&wylossonrepudusesof debt, net of federalincome tax benefit.-
(0.001)
(0.001)
(0.007)
(0.037)
Extraordinary gain on discharge of debr 7.435 (2)
Net income-0.087 0.341 0.209 0.003 0.081 0.329 0.110 0.002 10.760 (1) Includes an all employee cash bonus. See Note,J.
(2) Reflects the discharge of obligations subject to compromise for less than their recorded amounts.
81
It:m 9.
Ch:rg:2 in and Dizgrezments with Accrunt=ta em Acc = ting ecd Fimrcid '
Disclosure Not applicable.
PART III and PART IV The information set forth in Part III and Part IV has been omitted from this Annual Report to Shareholders.
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l 1
. A Profile cf Southem Calif rnia Edison Company i
i Southem Califomia Edison (SCE) is one of the nation's largest electric utilities. Headquartered in Rosemead, Califomia, SCE is a subsidiary of Edison Intemational, which is primarily an energy-services
- company, SCE, a 111-year-old investor-owned utility, serves 4.3 million customers in Central and Southem
. Califomia. More than 11 million people live in its 50,000-square-mile service territory.
i f
Contents 1-Selected Financial and Operating Data: 1993-1997 2
Management's Discussion and Analysis of Results of Operations and Financial Condition 15 Consohdated Financial Statements 19 Notes to Consolidated Financial Statements '
40 Quarterly Financial Data 41-Responsibility for Financial Reporting 42 Report of Independent Public Accountants 43 Board of Directors 43. Management Team b
I i
i-6 4
I l
\\
Selected Fin:ncial rnd Operating Datt: 1993-1997 Southern CaMomia Edison Company Dollars in millions 1997 1996 1995 1994 1993 Income statement data:
Operating revenue
$ 7,953
$ 7,583
$ 7,873
$ 7,799
$ 7,397 Operating expenses 6,893 6,450 6,724 6,705 6,232 Feel and purchased power expenses 3,735 3,336 3,197 3,403 3,290 Incune tax from operations 582 578 560 508 506 Allowance for funds used during construction 17 25 34 29 36 Interest expense - net 444 453 464 443 449 Net income 606 655 680 639 678 Eamings available for common stock 576 621 643 599 637 Ratio of eamings to fixed charges 3.49 3.54 3.52 3.43 3.39 ralance sheet data:
Assets
$18,059
$17,737
$18,155
$18,076
$18,098 Gross utility plant 21,483 21,134 20,717 20,127 19,441 Accumulated provision for depreciatica and decommissioning 10,544 9,431 8,569 7,710 7,138 Common shareholder's equity 3,958 5,045 5,144 5,039 4,932 Preferred stock:
Not subject to mandatory redemption 184 284 284 359 359 Subject to mandatory redemption 275 275 275 275 275 Long-term debt 6,145 4,779 5,215 4,988 5,234 Capitalstructure:
Common shareholder's equity 37.5%
48.6 %
47.1 %
47.3 %
45.7%
Preferred stock:
Not subject to mandatory redemption 1.7%
2.7%
2.6%
3.3%
3.3%
Subject to mandatory redemption 2.6%
2.7%
2.5%
2.6%
2.5%
Long-term debt 58.2 %
46.0 %
47.8 %
46.8%
48.5%
Operating data:
Peak demand in megawatts (MW) 19,118 18,207 17,548 18,044 16,475 Generation capacity at peak (MW) 21,511 21,602 21,603 20,615 20,606 Kilowatt-hour sales (kWh) (in millions) 77,234 75,572 74,296 77,986 73,308 Average annual kWh sales per residential customer 6,399 6,322 6,188 6,259 6,070 Total energy requirement (kWh) (in millions) 86,849 84,236 81,924 85,011 81,328 Energy mix:
Thermal 44.7 %
47.6%
51.6 %
59.5 %
53.8 %
Hydro 6.5%
6.9%
7.7%
3.9%
7.3%
Purchased power and other sources 48.8 %
45.5 %
40.7 %
36.6%
38.9 %
Customers (in millions) 4.25 4.22 4.18 4.15 4.12 Full-time employees
- 12,642 12,057 14,886 16,351 16,585
- 1993-1994 are based on twelve-month averages.
~
6O 1
4 Management's Discussion and Analysis of Results cf Operations and Financial Condition in the following Management's Discussion and Analysis of Results of Operations and Financial Condition and elsewhere in this annual report, the words estimates, expects, anticipates, believes, and other similar expressions are intended to identify forward-looking information that involves risks and uncertainties.
Actual results or outcomes could differ materially as a result of such important factors as further actions by state and federal regulatory bodies setting rates and implementing the restructuring of the electric utility industry; the effects of new laws and regulations relating to restructuring and other matters; the effects of increased competition in the electric utility business, including the beginning of direct customer access to retail energy suppliers and the unbundling of revenue cycle services such as metering and billing; changes in prices of electricity and fuel costs; changes in market interest rates; new or increased environmental liabilities; and other unforeseen events.
Hasults of Operations Eamings Southern Califomia Edison Company's (SCE) 1997 eamings were $576 million, compared with $621 million in 1996 and $643 million in 1995. SCE's eamings include special charges of $18 million in 1996 for workforce management costs and reserves, and $15 million in 1995 for workforce management expenses. Before special charges, eamings declined $63 million in 1997 from the prior year, mainly due to the extended outage and lower retum at the San Onofre Nuclear Generrung Station. The decline was partially offset by higher sales and lower non-nuclear operating expenses. The $19 million decrease in 1996 eamings from 1995 (excluding nonrecurring charges) is mainly attributable to a reduction in authorized rates of retum and authorized operating expenses, partially offset by improved operating performance.
Operating Revenue Operating revenue increased 5% over 1996, due to an increase in sales volume and customer refunds in 1996. There were no comparable refunds in 1997. The increase !n volume is mainly attrbutable to the overall increase in retail sales among residential and commercial customers. Operating revenue in 1996 decreased 4% from 1995, as increased sales volume was more than offset by lower average rates. The lower rates were attributable to the Califomia Public Utilities Commission's (CPUC) decision to lower SCE's 1996 authorized revenue by 4.4%. Additionally, during 1996, SCE's customers received a one-time bill credit totaling $237 million as part of a CPUC-erdered refund of energy cost balanc;ng account overcollections. In 1997, over 98% of SCE's operating revenue was from retail sales. Retail rates are regulated by the CPUC and wholesale rates are regulated by the Federal Energy Regulatory Commission (FERC).
Due to warm weather during the summer months, operating revenue during the third quarter of each year is significantly higher than the other quarters.
1 The changes in operating revenue resulted from-in mdhons Year ended December 31, 1997 1996 1995 Operating revenue -
Rate changes (including refunds) 3 173
$ (522)
$ 168 sales volume changes 193 206 (129)
Other 4
26 35
+
Total 8 370
$ (290) 74
+
Legislation enacted in September 1996 provir %I for, among other things, at least a 10% rate reduction 3
(financed through the issuance of rate reductian notes) for residential and small commercial customers in i
1998 and other rates to remain frozen at the June 10,1996, level (system average of 10.1c per kilowatt-t hour). See discussion in Competitive Environment.
2
s b
Southern CalifomkJ Edison Company Operating Expenses Fuel expense increased 40% in 1997. The increase is primarily due to a $174 million gas contract termination payment during the third quarter, combined with higher gas prices and the extended refueling outages at San Onofre. San Onofre Unit 2 was shut down during the entire first quarter of 1997, Unit 3 was shut down 80 days of the second quarter and both units had a combined outage time of 30 days during the third quarter, which resulted in an overall increase in gas-powered generation for the year.
There were no comparable outages in 1996. Fuel expense increased 11% in 1996, compared to 1995, due to higher gas prices and changes in the fuel mix.
Purchased-power expense increased slightly in 1997 and 1996, due to incraases in spot market purchases and increases in power purchased under federally mandated contracts. SCE is required under federal law to purchase power from certain nonutility generators even though energy prices under these contracts are generally higher than other sources. In 1997, SCE paid about $1.6 billion (including energy and capacity payments) more for these power purchases than the cost of power available from o;her sources. The CPUC has mandated the prices for these contracts.
Provisions for regulatory adjustment clauses decreased substantially in 1997, due to undercollections in the energy cost balancing account as actual energy costs (including the gas termination payments discussed above) exceeded CPUC-authorized fue! and purchased-power cost estimates. In addition, there were undercollections associated with SCE's direct access activities (see discussion in Competitive Environment - Direct Customer Access), research and development activities and San Onofre. These undercollections were offset by overcollections related to actual base-rate revenue from kilowatt-hour sales exceeding CPUC-authorized estimates and the final settlement of SCE's Canadian supply and transportation contracts (see discussion in Regulatory Matters). The,,rovisions for regulatory adjustment clauses also decreased in 1996 from 1995 due to lower than authorized base-rate revenue, undercollections related to the accelerated recovery of SCE's remaining investment in San Onofre Units 2 and 3, and the $237 million refund to ratepayers during 1996 for prior energy cost balancing account overcollections.
Maintenance expense increased 23% in 1997, due to increased maintenance costs for the schedulad refueling outages at the San Onofre units and SCE's transmission and distribution operating facilities.
Depreciation and decommissioning expense increased 17% in 1997. The increase is due to increases in plant assets and the accelerated recovery of the Palo Verde Nuclear Generating Station units effective January 1997. Depreciation and decommissioning expense increased 12% in 1996, compared to 1995, due to higher depreciation rates and the accelerated recovery of San Onofre Units 2 and 3 starting in April 1996.
Property and other taxes decreased 32% in 1997, due to a reclassification of payroll taxes to operation and maintenance expense.
Otherincome and Deductions The provision for rate phase-in plan reflects a CPUC-authorized,10-year rate phase-in plan, which deferred the collection of revenue during the first four years of operation for the Palo Verde units. The deferred revenue (including interest) was collected evenly over the final six years of each unit's plan. The plan ended in February 1996, September 1996 and January 1998 for Units 1,2 and 3, respectively. The provision is non-cash offset to the collection of deferred revenue.
Interest and dividend income increased 18% in 1997, due to increases in interest camed on SCE's balancing accounts and increases in dividend income from its equity investments.
3
J Manrgement's Discussi:n and An-lysis cf Results cf OperatMns and Financial Conditi;;n Other nonoperating income decreased substantially in 1997, due to additional accruals for regulatory matters associated with the restructuring of California's electric utility industry. Other nonoperating income also decreased in 1996, compared to 1995, due to regulatory accruals in 1996.
Interest & pense Interest on long-term debt chcreased 9% in 1997, due to the early retirement of $400 million of first and refunding mortgage bonds in July 1997, partially offset by additional interest expense associated with the issuance of approximately $2.5 billion in rate reduction notes in December 1997 (see discussion in Cash Flows from Financing Activities).
Other interest expense increased in 1997, due to higher levels of short-term debt used to retire first and refunding mortgage bonds, discussed above. Other interest expense decreased in 1996 from 1995, due to the lower levels of short-term debt and lower interest rates.
Financial Condition SCE's liquidity is primarily affected by debt maturities, dividend payments and capital expenditures.
Capital resources include cash from operations and extemal financings.
Edison International's Board of Directors has authorized the repurchase of up to $2.3 billion of its outstanding shares of common stock. Edison international has repurchased 76.9 million shares ($1.7 billion) cetween January 1995 and January 30,1998, funded by dividends from its subsidiaries and its lines of credit.
SCE's cash flow coverage of dividends during 1997 decreased to 0.9 times from 2.2 times in 1996 and 3.5 times in 1995 e c rasult of a $1.2 billion special dividend SCE paid to Edison International from the rate reduction note proceeds received in December 1997.
Cash Flows from Operating Activities Net cash provided by operating activities totaled $1.7 billion in 1997, $1.8 billion in 1996 and $2.0 billion in 1995. Cash from operations exceeded capital requirements for all years presented.
Cash Flows from Financing Activities Short-term debt is used to finance fuel inventories, balancing account undercollections and general cash requirements. Long-term debt is used mainly to finance capital expenditures. External financings are influenced by market conditions and other factors, including limitations imposed by its articles of incorporation and trust indenture. As of December 31,1997, SCE cou!d issue approximately $10.4 billion of additional first and refunding mortgage bonds and $5.3 billion of preferred stock at current interest and dividend rates.
At December 31, 1997, SCE had available lines of credit of $1.8 billion, with $1.3 billion for general purposo short-term debt and $500 million for the long-term refinancing of its variable-rate pollution-control bonds. These unsecured lines of credit are at negotiated or bank index rates with various expiration dates; the majority have five-year terms.
Califomia law prohibits SCE from incurring or guaranteeing debt for its nonutility affiliates. Additionally, the CPUC regulates SCE's capital structure, limiting the dividends it may pay Edison International. At December 31,1997, SCE had the capacity to pay $1.4 billion in additional dividends and continue to maintain its authorized capital structure.
4
r b
Southern CaHfornb Edison Company in December 1997, SCE Funding LLC, a special purpose entity (SPE), of which SCE is the sole member, issued approximately $2.5 billion of rate reduction notes to Bankers Trust Company of Califomia, as certificate trustee for the California infrastructure and Economic Development Bank Special Purpose Trust SCE-1 (Trust), which is a special purpose entity establis!..? by the State of California. The terms of the rate reduction notes generally mirror the terms of the pass-through certificates issued by the Trust, which are known as rate reduction certificates. The proceeds of the rate reduction notes were used by the SPE to purchase from SCE an enforceable right known as transition property. Transition property is a current property right created pursuant to the restructuring legislation and a financing order of the CPUC and consists generally of the right to be paid a specified amount from a non-bypassable tariff levied on residential and small commercial customers. Notwithstanding the legal sale of the transition property by SCE to the SPE, the amounts reflected as assets on SCE's balance sheet have not been reduced by the amount of the transition property sold to the SPE, and the liabilities of the SPE for the rate reduction notes are for accounting purposes reflected as long-term liabilities on the consolidated balance sheet of SCE. SCE used the proceeds from the sale of the transition property to retire debt and equity securities.
The rate reduction notes have maturities ranging from one to 10 years, and bear interest at rates ranging from 5.98% to 6.42%. The rate reduction notes are secured solely by the transition property and certain other assets of the SPE, and there is no recourse to SCE or Edison international.
Although ine SPE is consolidated with SCE in the financial statements, as required by generally accepted accounting principles, the SPE is legally separate from SCE, the assets of the SPE are not available to creditors of SCE or Edison international, and the transition property is legally not an asset of SCE or Edison International.
Cash Flows from Investing Activities The primary uses of cash for investing activities are additions to property and plant and funding of nuclear decommissioning trusts. Decommissioning costs are accrued and recovered in rates over the term of each nuclear generating facility's operating license through charges to depreciation expense. SCE estimates that it will spend approximately $12.7 billion between 2013 - 2070 to decommission its nuclear facilities. This estimate is based on SCE's current-dollar decommissioning costs ($2.1 billion), escalated using a 6.65% annual rate. These costs are expected to be funded from independent decommissioning trusts which receive SCE contributions of approximately $100 million per year until decommissioning begins.
Market Risk Exposures SCE's primary market risk exposures arise from fluctuations in energy prices and interest rates. SCE's risk management policy allows the use of derivative financial instruments to manage its financial exposures, but prohibits the use of these instruments for speculative or trading purposes.
SCE has hedged a portion of its exposure to increases in natural gas prices. Increases in natural gas prices tend to increase the price of electricity purchased from the power exchange (PX). SCE's exposure l
is also limited by regulatory mechanisms that protect SCE from much of the risk arising from high clectricity prices.
A 10% increase in market interest rates would result in a $6 million increase in the fair value of SCE's interest rate hedge agreements. A 10% decrease in market interest rates would result in a $6 million decline in the fair market value of interest rate hedge agreements. A 10% increase in natural gas prices would result in a $26 million increase in the fair market value of gas call options. A 10% decrease in natural gas prices would result in a $17 million decline la the fair market value of gas call options. A 10%
change in market rates is expected to have an immaterial effect on SCE's other financial instruments.
5
T Managem:nt's Discussion cnd Analysis cf R;sults cf Operati:n2 and Financial Condition Projected CapitalRequirements SCE's projected construction expenditures for the next five years are: 1998 - $956 million; 1999 - $807 million; 2000 - $763 million; 2001 - $721 million; and 2002- $671 million.
Long-term debt maturities and sinking fund requirements for the next five years are: 1998 - $693 million; 1999 - $401 million; 2000 - $571 million; 2001 - $646 million; and 2002 - $446 million.
Preferred stock redemption requirements for the next five years are: 1998 through 2001 - zero and 2002 - $105 million.
Regulatory Matters Legislation enacted in September 1996 provided for, among other things, a 10% rate reduction for residential and small commercial customers in 1998 and other rates to remain frozen 61 the June 10,1996, level (system average of 10.1c per kilowatt-hour). See further discussion in Competitive Environment - Restructuring Legislation.
In 1998, revenue will be affected by various mechanisms depending on the utility operation. Revenue related to distribution operations will be determined through a performance-basad rate-making mechanism (PBR) (see discussion in Competitive Environment - PBR) and the distribution assets will have the opportunity to earn a CPUC-authorized 9.49% return. Until the independent system operator (ISO) begins operation, transmission revenue will be determined by the same mechanism as distribution operations. After that time, transmission revenue will be determined through FERC-authorized rates and transmission assets will earn a 9.43% retum. These rates are subject to refund. See discussions in the Corr,petitive Environment - Rate-setting and FERC Restructuring Decision sections.
Revenue from generation-related operations will be determined through the competition transition charge (CTC) mechanism, nuclear rate-making agreements and the competitive market. Revenue related to fossil and hydroelectric generation operations will be recovered from two sources. The portion that is made uneconomic by electric industry restructuring will be determined through the CTC mechanism. The portion that is economic will be recovered through the PX mechanism. In 1998, fossil and hydroelectric generation assets will earn a 7.22% retum. A more detailed discussion is in Competitive Environment -
CTC.
The CPUC has authorized revised rate-making plans for SCE's nuclear facilities, which call for the accelerated recovery of its nuclear investments in exchange for a lower authorized rate of retum. SCE's nuclear assets are eaming an annual rate of return of 7.35%. In addition, the San Onofre plan authorizes a fixed rate of approximately 4c per kilowatt-hour generated for operating costs including incremental capital costs, and nuclear fuel and nuclear fuel financing costs. The San Onofre plan commenced in April 1996, and ends in December 2001 for the accelerated recovery portion and in December 2003 for the incentive pricing portion. Palo Verde's operating costs, including incremental capital costs, and nuclear fuel and nuclear fuel financing costs, are subject to balancing account treatment. The Palo Verde plan commenced in January 1997 and ends in December 2001. Beginning January 1,1998, both the San Onofre and Palo Verde rate-making plans became part of the CTC mechanism.
The changes in revenue from the regulatory mechanisms discussed above, excluding the effects of other rate actions, is expected to have a minimal impact on 1998 eamings. However, the issuance of the rate reduction notes in December 1997, which enables the repurchase of debt and equity, will have a negative impact on 1998 eamings of approximately $97 million, j
in 1994, SCE filed its testimony in the non-Oualifying Facilities (OF) phase of the 1994 Energy Cost Adjustment Clause proceeding. In 1995, the CPUC's Office of Ratepayer Advocates (ORA) filed its report on the reasonableness of SCE's gas supply costs for both the 1993 and 1994 record periods. The 6
l
s Southern California Edison Company report recommends a disallowance of $13 million for excessive costs incurred from November 1993 through March 1994 associated with SCE's Canadian gas purchase and supply contracts. The report requested that the CPUC defer finding SCE's Canadian supply and transportation agreements reasonable for the duration of their terms and that the costs under these contracts be reviewed on a yearly basis. In 1996, the CRA issued its report for the 1995 record period recommending a $38 million disallowance for excessive costs incurred from April 1994 through March 1995. Both proposed disallowarm were later consolidated into one proceeding. On December 3,1997, the CPUC approved a settler.= ; greement between SCE and the ORA on this and any future issues, which will result in a
$61 mir
..<,cluding interest) refund to SCE's customers. The refund which is fully reflected in the financial s.atements will be made in first quarter 1998, in 1991, SCE filed its testimony in the QF phase of the 1991 Energy Cost Adjustment Clause proceeding.
In 1993, the ORA filed its report on the reasonableness of SCE's OF contracts and alleged that SCE hao imprudently renegotiated a OF contract with the Mojave Cogeneration Company.
The report i
recommended a disallowance of $32 million (1993 net present value) over the contract's 20-year life.
I Subsequently, SCE and the ORA reached a settlement where SCE agreed to a one-time reduction to its cnergy cost adjustment clause balancing account of $14 million plus interest, in October 1996, the CPUC approved the settlement agreement, subject to SCE and the ORA accepting certain conditions conceming the way the $14 million payment would be reflected in rates. After reviewing the decision, SCE declined to accept the condition proposed by the CPUC and in November 1996 filed an app'ication l
for rehearing. In February 1997, the CPUC denied SCE's application. Because SCE and the ORA were unable to finalize their settlement, hearings on the ORA's disallowance recommendations were held in i
June 1997. During the hearings, the ORA presented testimony to update its assessment of ratepayer harm, which it now estimates to be $45 million (1997 net present value) over the contract's life. In -
November 1997, a CPUC administrative law judge (ALJ) issued a proposed decision which would adopt the ORA's $45 million disallowance. In January 1998, the CPUC withdrew the ALJ's proposed decision pending oral arguments. Oral arguments were heard on February 4,1998, at which time SCE requested an attemate proposed decision be issued. SCE expects this matter to be returned to the CPUC's agenda in the near future and a final decision to be issued during second quarter 1998. SCE cannot predict the final outcome of this matter but does not believe it will materially affect its results of operations.
Competitive Environment SCE currently operates in a highly regulated environment in which it has an obligation to deliver electric service to customers in retum for an exclusive franchise within its service territory. This regulatory environment is changing. The generation sector has experienced competition from nonutility power producers and regulators are restructuring Caliiomia's electric utility industry.
Califomia Electric Utility Restructuring Restructuring Legislation - In September 1996, the State of California enacted legislation to provide a transition to a competitive market structure. The legislation substantially adopted the CPUC's December 1995 restructuring decision by addressing stranded-cost recovery for utilities and providing a certain cost-recovery time period for the transition costs associated with utility-owned generation-related assets.
Transition costs related to power-purchase contracts would be recovered through the terms of their contracts while most of the remaining transition costs would be recovered through 2001. The legislation also included provisions to f nance a portion of the stranded costs that residential and small commercial customers would have paid between 1993 and 2001, which would allow SCE to reduce rates by at least 10% to these customers, beginning January 1,1998. The financing would occur with securities issued by the Califomia Infrastructure and Economic Development Bank, or an entity approved by the Bank. The legislation included a rate freeze for all other customers, including large commercial and industrial customers, as well as provisions for continued funding for energy conservation, low-income programs and renewable resources. Despite the rate freeze, SCE expects to be able to recover its revenue requirement during the 1998-2001 transition period.
In addition, the legislation mandated the 7
J ManagemInt's Dir ussi:n and Analysis of Results of Op;rati:ns and Financial CC titi:n implementation of the CTC that provides utilities the opportunity to recover costs made uneconomic by electric utility restructuring. Finally, the legislatior' contained provisions for the recovery (through 2006) of reasonable employee-related transition costs, incurred and projected, for retraining, severance, early retirement, outplacement and related expenses.
Rate Reduction Notes-In May 1997, SCE filed an application with the CPUC requesting approval of the issuance of an aggregate amount of up to $3 billion of rate reduction notes in one or more series or classes and a 10% rate redJCtion for the period from January 1,1998, through March 31, 2002. At the same time, SCE filed an application with the Califomia infrastructure and Economic Developinent Bank for approval to issue the notes. Residential and small commercial customers will repay the notes over the expected 10-year term through non-bypassable charges based on electricity consumption. In December 1997, after receiving approval from both the CPUC and the infrastructure Bank, a limited liability company created by SCE issued approximately $2.5 billion of these notes. For further de* ails, see the discussion in Cash Flows from Financing Activities.
CPUC Restructuring Decision - The CPUC's December 1995 decision on restructuring California's electric utility industry started the transition to a new market structure, which is expected to provide competition and customer choice and is scheduled to begin March 31, 1998. Key elements of the CPUC's restructuring decision included: creation of the PX and ISO; availability of direct customer access and customer choice; PBR for those utility services not subject to competition; voluntary divestiture of at least 50% of utilities' gas-fueled generation, and implementation of the CTC.
Rate-setting - In December 1996, SCE filed a more comprehensive plan (elaborating on its July 1996
[
filing related to the conceptual aspects of separating costs as requested by CPUC and FERC directives) for the functional unbundling of its rates for electric service, beginning January 1,1998. In response to CPUC and FERC orders, as well as the new restructuring legislation, this filing addressed the implementation-level detail for the functional unbundling of rates into separate charges for energy, transmission, distribution, the CTC, public benefit programs and nuclear decommissioning.
The transmission component of this rate unbundling process was addressed at the FERC through a March 1997 filing. In December 1997, the FERC approved these rates, subject to refund, to be effective on the 1
l date the ISO begins operation. CPUC hearings on SCE's rate unbundling (also known as rate setting) plan wore concluded in April 1997. In August 1997, the CPUC issued a decision which adopted the methodology for determining CTC residually (see CTC discussion below) and adopted SCE's revenue requirement components for public benefit programs and nuclear decommissioning. The decision also adjusted SCE's proposed distribution revenue requirement by reallocating $76 million of it annually to other functions such as generation and transmission. Under the decision, SCE will be able to recover most of the reallocated amount through market revenue, other rate-making mechanisms after petitioning the CPUC to modify its prior decisions, or another review process later in its divestiture proceeding.
FX and ISO - In April 1996, SCE, Pacific Gas & Electric Company and San Diego Gas & Electric Company filed a proposal with the FERC regarding the creation of the PX and the ISO. In November 1996, the FERC conditionally accepted the proposal and directed the three utilities, the ISO, and the PX to file more specific information. The filing was made in March 1997, and included SCE's proposed transmission revenue requirement.
On October 29, 1997, the FERC gave conditional, interim l
l authorization for operation of the PX and ISO to begin on January 1,1998. The FERC stated it would closely monitor the PX and ISO, require further studies and make modifications, where necessary. A comprehensive review will be performed by the FERC after three years of operation of the PX and ISO.
On December 22,1997, the PX and ISO governing boards announced a delay in Me planned start-up of the PX and ISO due to insufficient testing of operational, settlement and bilkng 3ystems. The PX and ISO are now expected to begin operation by March 31,1998.
In July 1996, the three utilid.s jointly filed an application with the CPUC requesting approval to establish a restructuring trust which would obtain loans up to $250 million for the development of the ISO and PX 8
t Southern California Edison Company through January 1,1998. The loans are backed by utility guarantees; SCE's share was 45%, or $113 million, in August 1996, the CPUC issued an interim order establishing the restructuring trust and the funding level of $250 million, which has been used to build the hardware and software systems for the ISO and PX. The ISO and PX will repay the trust's loans and recover funds from future ISO and PX customers. In November 1997, the CPUC approved a petition jointly filed by the three utilities which requested an increase in the loan guarantees from $250 million to $300 million; SCE's share of this new total is $135 million. In December 1997, the CPUC approved a remaining item with respect to the petition which requested that the one-time restructuring implementation charge, to be paid to the PX by the utilities, be deemed a non-bypassable charge to be recovered from all retail customers. The amount of the PX charge is $85 million; SCE's share is 45%, or $38 million.
Direct Customer Access - In May 1997, the CPUC issued a decision describing how all California investor-owned-utility customers will be able to choose who will provide them with electric generation service beginning January 1,1998. On December 30,1997, the CPUC issued a decision delaying direct access until March 31,1998, due to operational delays in the start-up of the PX and ISO. On this date, customers will be able to choose to remain utility customers with bundled electric service from SCE (which will purchase its power through the PX), or choose direct access, which means the customer can contract directly with either independent power producers or retail electric service providers such as power brokers, marketers and aggregators. Additionally, all investor-owned-utility customers must pay the CTC whether or not they choose to buy power through SCE. Electric utilities will continue to p ovide the core distribution service of delivering energy through its distribution system regardless of a customer's choice of electricity supplier. The CPUC will continue to regulate the prices and service obligations related to distribution services. If the new competitive market cannot accommodate the volume of direct access transactions, the CPUC could implement a conUngency plan. However, the CPUC believes it is likely that interest in and migration to direct access will be gradual.
Revenue Cycle Services - A decision issued by the CPUC in May 1997, introduces customer choice to metering, billing and related services (referred to as revenue cycle services) that are now provided by Califomia's investor-owned utilities. Under this revenue cycle services unbundling decision, beginning in January 1998, direct access customers may choose to have either SCE or their electric generation service provider render consolidated (energy and distribution) bills, or they may choose to have separate billings from each service provider. However, not all electric generation service providers will necessarily offer each billing option. In addition, beginning in January 1998, customers with maximum demand above 20 kW (primarily industrial and large commercial) can choose SCE or any other supplier to provide their metering service. All other customers will have this cotion beginning in January 1999. In determining whether any credit should be provided by the utility to firms providing customers with revenue cycle services, and the amount of any such credit, the CPUC has indicated that it is appropriate to net the cost incurred by the utility and the cost avoided by the utility as a result of such services being provided by the other firm rather than by the utility. The unbundling of revenue cycle services will expose SCE to the possible loss of revenue, higher stranded costs and a reduction in revenue security.
PBR-in 1993, SCE filed for a PBR mechanism to determine most of its revenue (excluding fuel). The filing was subsequently divided between transmission and distribution (T&D) and power generation.
In September 1990, the CPUC adopted a non-generation or T&D PBR mechanism for SCE which began on January 1,1997. According to the CPUC, beginning in 1998 (coincident with the initiation of the competitive market), the transmission portion is to be separated from non-generation PBR and subject to ratemaking under the rules of the FERC. The distribution-only PBR will extend through December.1001, Key elements of the non-generation PBR include: T&D rates indexed for inflation based en the Consumer Price Index less a productivity factor; elimination of the kilowatt-hour sales adjustment; adjustments for cost changes that are not within SCE's control; a cost of capital trigger mechanism based on changes in a bond index; standards for service reliability and safety; and a net revenue-sharing mechanism that determines how customers and shareholders will share gains and losses from T&D operations.
9
Man gement's Discussi:n and Analysis of R:sults cf Operatisns and Fin nclil Conditi:n With the CPUC's 1995 restructuring decision and the passage of restructuring legislation in 1996, the j
majority of power generation ratemaking (primarily fossil-fueled and nuclear) was assigned to other mechanisms. In April 1997, a CPUC interim order determined that the proposed structure of the fossil-fueled plants' must-run contracts were under the FERC's jurisdiction. On October 31,1997, SCE filed must-run tariff schedules with the FERC covering its six ISO-designated must-run plants. In the meantime, SCE is pursuing the divestiture of these plants (see Divestiture discussion below) and might not ever itself provide service under these FERC tariff schedules.
In December 1997, the CPUC adopted a PBR-type rate-making mechanism for SCE's hydroelectric plants. The mechanism sets the hydroelectiic revenue requirement in 1998 and establishes a formula for extending it through the duration of the electric industry restructuring transition period, or until market valuation of the hydroelectric facilities, whichever occurs first. The mechanism provides that power sales revenue from hydroelectric facilities in excess of the hydroelectric revenue requirement be credited against the costs to transition to a competitive market (see CTC discussion below).
Divestiture - In November 1996, SCE filed an application with the CPUC to voluntarily divest, by auction, all 12 of its oil-and gas-fueled generation plants. This application builds on SCE's March 1996 plan which outlined huw SCE proposed to divest 50% of these assets. Under the new proposal, SCE would continue to operate and maintain the divested power plants for at least two years following their sale, as mandated by the restructuring legislation enacted in September 1996. In addition, SCE would offer workforce transition programs to those employees who may be impacted by divestiture-related job reductions. SCE's proposal is contingent on the overall electric industry restructuring implementation process continuing on a satisfactory path. In September 1997, the CPUC approved SCE's proposal to auction the 12 plants.
On December 1,1997, SCE filed a compliance filing with the CPUC stating that it had sold 10 plants. On December 16,1997, the CPUC approved the sale of the 10 plants. On February 6,1998, SCE filed a compliance filing with the CPUC for the sale of an 11th plant. CPUC approval of the sale is expected before March 31,1998. The total sales price of the 11 plants is $1.1 billion, or 2.16 times their combined book value of $531 million. Net proceeds of the sales will be used to reduce stranded costs, which otherwise were expected to be collected through the CTC mechanism. The transfer of ownership of the 11 plants is expected to occur shortly before the start of the new competitive market, which the PX and ISO expect to occur on March 31,1998. The sale and CPUC approval of the single remaining plant is expected to be completed in early 1998.
CTC - Recovery of costs to transition to a competitive market is being implemented through a non-bypassable CTC. This charge applies to all customers who were using or began using utility services on or after the CPUC's December 20,1995, decision date. In August 1996, in compliance with the CPUC's restructuring decision, SCE filed its application to estimate its 1998 transition costs. In October 1996, SCE amended its transition cost filing to reflect the effects of the legislation enacted in September 1996.
Under the rate freeze codified in the legislation, the CTC will be determined residually (i.e., after subtracting other cost components for the PX, T&D, nuclear decommissioning and public benefit programs). Nevertheless, the CPUC directed that the amended application provide estimates of SCE's potential transition costs from 1998 through 2030. SCE provided two estimates between approximately
$13.1 billion (1998 net present value) assuming the fossil plants have a market value equal to their net book value, and $13.8 billion (1998 net present value) assuming the fossil plants have no market value.
These estimates are based on incurred costs, forecasts of future costs and assumed market prices.
However, changes in the assumed market prices could materially affect these estimates. The potential transition costs are comprised of: $7.5 billion from SCE's qualifying facility contracts, which are the direct i
result of pr'or legislative and regulatory mandates; and $5.6 billion to $6.3 billion from costs pertaining to certain generating plants (successful completion of the sale of SCE's gas-fired generating plants would reduce this estimate of transition costs for SCF.-owned generation to less than $5 billion) and regulatory commitments consisting of costs incurred (inose recovery has been deferred by the CPUC) to provide 10
. ~.
Southern Californt] Edison Csmpany service to customers. Such commitments include the recovery of income tax benefits previously flowed through to customers, postretirement benefit transition costs, accelerated recovery of San Onofre Units 2 and 3 and the Palo Verde units (as discussed in Regulatory Matters), and certain other costs. In February 1997, SCE filed an update to the CTC filing to reflect approval by the CPUC of settlements regarding ratemaking for SCE's share of Palo Verde and the buyout of a power purchase agreement, as well as other minor data updates. No substantive changes in the total CTC estimates were included. This issue has been sep'trated into two phases; Phase 1 addresses the rate-making issues and Phase 2 the quantification issues.
A decision on Phase 1 was issued in June 1997, which, among other things, required the establishment of a transition cost balancing account and annual transition cost proceedings, set a market rate forecast for 1998 transition costs, and required that generation-related regulatory assets be amortized ratably over a 48-month period. Hearings on Phase 2 were held in May and June 1997 and a final decision was issued on November 19,1997. The Phase 2 decision established the calculation methodologies and procedures for SCE to collect its transition costs from 1998 through the end of the rate freeze. The Phase 2 decision also reduced SCE's authorized rate of return on certain assets eligible for transition cost recovery (primarily fossil-and hydroelectric-generation related assets) beginning July 1997, five months earlier than anticipated. The decision, excluding the effects of other rate actions, had a negative impact on 1997 earnings of approximately $14 million. SCE has filed an application for rehearing on the 1997 rate of retum issue.
Accounting /or Generation-Related Assets - If the CPUC's electric industry restructuring plan is implemented as outlined above, SCE would be allowed to recover its CTC through non-bypassable charges to its distribution customers (although its investment in certain generation assets would be subject to a lower authorized rate of retum).
As previously reported, from November 1996 to July 1997, SCE and the other major California electric utilities were engaged in discussions with the Securities and Exchange Commission staff regarding the proper application of regulatory accounting standards in light of the electric industry restructuring legislation enacted by the State of California in September 1996 and the CPUC's electric industry restructuring plan. This issue was placed on the agenda of the Financial Accounting Standards Board's Emerging issues Task Force (EITF) during April 1997 and a final consensus was reached at the July EITF meeting. During the third quarter of 1997, SCE implemented the EITF consensus and discontinued application of accounting principles for rate-regulated enterprises for its investment in generation facilities.
However, implementation of the EITF consensus did not require SCE to write off any of its generation-related assets, including regulatory assets of approximately $600 million at December 31,1997. SCE has retained these assets on its balance sheet because the legislation and restructuring plan referred to above make probable their recovery through a non-bypassable CTC to distribution customers. These regulatory assets relate primarily to the recovery of accelerated income tax benefits previously flowed through to customers, purchased power contract termination payments, unamortized losses on reacquired debt, and the recovery of amounts deferred under the Palo Verde rate phase-in plan. The consensus reached by the EITF also permits the recording of new generation-related regulatory assets during the transition period that are probable of recovery through the CTC mechanism.
If during the transition period events were to occur that made the recovery of those generation-related regulatory assets no longer probable, *7. would be required to write off the remaining balance of such assets as a one-time, non-cash charge, against eamings. If such a write-off were to be required, SCE believes that it should not affect the recovery of stranded costs provided for in the legislation and restructuring plan.
Although depreciation-related differences could result from applying a regulatory prescribed depreciation method (straight-line, remaining-life method) rather than a method that would have been applied absent the regulatory process, SCE believes that the depreciable lives of its generation-related assets would 11
ManagemInt's Discussi:n and Analysis cf Results cf Operati:ns cnd Fin ncial Conditi:n not vary significantly from that of an unregulated enterprise, as the CPUC bases depreciable lives on periodic studies that reflect the physical useful lives of the assets. SCE also believes that any depreciation-related differences would be recovered through the CTC.
If events occur during the restructuring process that result in all or a portion of the CTC being improbable of recovery, SCE could have additional write-offs associated with these costs if they are not recovered through another regulatory mechanism. At this time, SCE cannot predict what other revisions will ultimately be made during the restructuring process in subsequent proceedings or implementation phases, or the effect, after the transition period, that competition will have on its results of operations or financial position.
FERC Restructuring Decision in April 1996, the FERC issued its decision on stranded-cost recovery and open access transmission, effective July 1996. The decision, reaffirmed by the FERC in its March and November 1997 orders, requires all electic utilities subject to the FERC's jurisdiction to file transmission tariffs which provide competitors with increased access to transmission facilities for wholesale transactions and also establishes information requirements for the transmission utility. The decision also provides utilities with the opportunity to recover stranded costs associated with existing wholesale customers, retail-tumed-wholesale customers and retail wheeling when the state regulatory body does not have authority to address retail stranded costs. Even though the CPUC is currently addressing stranded-cost recovery through the CTC proceedings, the FERC has also asserted primary jurisdiction over the recovery of stranded costs associated with retail-turned-wholesale customers, such as a new municipal electric system or a municipal annexation. However, the FERC did clarify that it does not intend to prevent or interfere with a state's authority and that it has oiscretion to defer to a state stranded-cost-calculation method. In January 1997, the FERC accepted the open access transmission tariff SCE filed in compliance with the April 1996 decision. The rates included in the tariff are being collected subject to refund. In May G7, SCE filed a revised open access tariff to reflect the few revisions set forth in the March 1997 order. The open access transmission tariff will be terminated on the date the ISO begins operation.
Environmental Protection SCE is subject to numerous environmental laws and regulations, which require it to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment.
As further discussed in Note 10 to the Consolidated Financial Statements, SCE records its environmental liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. SCE reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site. Unless there is a probable amount, SCE records the lower end of this likely range of costs.
In connection with the issuance of the San Onofre Units 2 and 3 operating permits, SCE reached agreement with the California Coastal Commission in 1991 to restore certain marine mitigation sites. The restorations include two sites: designated wetlands and the construction of an artificial kelp reef off the California coast. After SCE requested certain modifications to the agreement, the Coastal Commission issued a final ruling in April 1997 to reduce the scope of remediations. SCE elected to pay for the costs of marine mitigation in lieu of placing the funds into a trust. Rate recovery of these cods is occurring through the San Onofre incentive pricing plan discussed in Note 1 to the Consolidated Financial Statements.
12
s Southern California Edison Company SCE's recorded estimated minimum liability to remediate its 50 identified sites is $178 million, which includes $75 million for the two sites discussed above. One of SCE's sites, a former pole-treating facility, is considered a federal Superfund site and represents 42% of its recorded liability. The ultimate costs to clean up SCE's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process. SCE believes that, due to these uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to $246 million. The upper limit of this range of costs was estimated using assumptions least favorable to SCE among a range of reasonably possibb outcomes.
The CPUC allows SCE to recover environmental-cleanup costs at 41 of its sites, representing $91 million of its recorded liability, through an incentive mechanism. Under this mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance carriers and other third parties. SCE has successfully settled insurance claims with all responsible carriers. Costs incurred at SCE's remaining sites are expected to be recovered through customer rates. SCE has recorded a regulatory asset of $153 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates. This amount includes $60 million of marine mitigation costs remaining to be recovered through the San Onofre incentive pricing plan.
SCE's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination, and the extent, if any, that SCE may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites.
SCE expects to clean up its identifie ' sites over a period of up to 30 years. Remediatbn costs in each of the next several years are expecte % range from $4 million to $10 million. Recorded costs for 1997 were $10 million.
Based on currently available infoi.
ion, SCE believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range and, based upon the CPUC's regulatory treatment of environmental cleanup costs, SCE believes that costs ultimately recorded will not materially affect its results of operations or financial position. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, wm.'ot require material revisions to such estimates.
The 1990 federal Clean Air Act reqaires power producers to have emissha allowances to emit sulfur dioxide. Power companies receive emissions allowances from the federal government and may bank or sell excess allowances. SCE expects to have excess allowances under Phase ll of the Clean Air Act (2000 and later). The act also calls for a study to determine if additional regulations are needed to reduce regional haze in the southwestem U.S. In addition, another study is in progress to determine the specific impact of air contaminant emissions from the Mohave Coal Generating Station on visibility in Grand Canyon National Park. The potential effect of these studies on sulfur dioxide emissions regulations for Mohave is unknown.
SCE's projected capital expenditures to protect the environment are $820 million for the 1998 - 2002 period, mainly for aesthetics treatment, including undergrounding certain transmission and distribution lines.
The possibility that exposure to electric and magnetic fields (EMF) emanating from power lines, household appliances and other electric sources may result in adverse health effects has been the subject of scientific research. After many years of research, scientists have not found that exposure to EMF causes disease in humans. Research on this topic is continuing. However, the CPUC has issued a decision which provides for a rate-recoverable research and public education program conducted by California electric utilities, and authorizes these utilities to take no-cost or low-cost steps to reduce EMF 13
Managem:nt's Discussi:n cnd Anilysl3 cf R.sults cf Operati:ns cnd Financlil Conditi:n in new electric facilities. SCE is unable to predict when or if the scientific community will be able to reach a consensus on any health effects of EMF, or the effect that such a consensus, if reached, could have on future els :tric operations.
San Onofre Steam Generator Tubes The San Onofre Units 2 and 3 steam generators have performed relatively well through the first 15 years of operation, with low rates of ongoing steam generator tube degradation. However, during the Unit 2 scheduled refueling and inspection outage, which was completed in Spring 1997, an increased rate of tube degradation was identified, which resulted in the removal of more tubes from service than had been expected. The steam generator design allows for the removal of up to 10% of the tubes before the rating capacity of the unit must be reduced. As a result of the increased degradation, a mid-cycle inspection outage wi!! be conducted in early 1998 for Unit 2.
During Unit 3's refueling outage, which was completed in July 1997, inspections of structural supports for steam generator tubes identified several areas where the thickness of the supports had been reduced, apparently by erosion during normal plant operation. As a result, a mid-cycle inspection outage is planned for early 1998. However, during Unit 2's Spring 1997 inspection outage, similar tube supports showed no sign of such erosion.
Proposed New Accounting Standard During 1996, the Financial Accounting Standards Board issued an exposure draft that would establish accounting standards for the recognition and measurement of closure and removal obligations. The exposure draft would require the estimated present value of an obligation to be recorded as a liability, along with a corresponding increase in the plant or regulatory asset accounts when the obligation is incurred. If the exposure draft is approved in its present form, it would affect SCE's accounting practices for the decommissioning of its nuclear power plants, obligations for coal mine reclamation costs and any other activities related to the closure or removal of long lived assets. SCE does not expect that the accounting changes proposed in the exposure draft would have an adverse effect on its results of operations even after deregulation due to its current and expected future ability to recover these costs through customer rates.
Year 2000 issue Many of SCE's existing computer systems identify a year by using only two digits instead of four. If not corrected, these programs could fail or create erroneous results when the new century begins. This situation has been referred to generally as the Year 2000 issue.
SCE has developed plans and is addressing the programming changes that it has determined are necessary in order for its computer systems to function properly beginning in 2000. Rernediation of SCE's key financial systems for the Year 2000 issue was completed in 1997. SCE's informational and operational systems have been assessed, and detailed plans have been developed to address modifications required to be completed, tested and operational by December 31,1999. Preliminary estimates of the costs to complete these modifications, including the cost of new hardware and software application modifications, range from $55 million to $80 million, about half of which are expected to be capital costs. Current rate levels for providing electric service should be sufficient to provide funding for these modifications. Remediation of existing critical systems is expected to be 75% complete by the end of 1998. SCE expects its Year 2000 date conversion project to be completed on a timely basis, with no material adverse impact to its results of operations or financial position.
SCE's Year 2000 date conversion project includes an assessment of critical interfaces with the computer systems of others and it does not expect a material adverse effect on its operating and business functions from the Year 2000 issue.
14
f' Consolidated Statements ef Income southem califomia Edison Company in thousands Year ended December 31, 1997 1996 1995 Operating revenue
$7,953,386
$7,583,382
$7,872,718 Fuel 881,471 630,512 614,954 i
Purchased power 2,854,002 2,705,880 2,581,878 Provisions for regulatory adjustment clauses - net (410,935)
(225,908) 229,744 Other operating expenses
't,212,468 1,178,316 1,226,534 Maintenance 405,545 329,371 356,693 Depreciation and decommissioning 1,239,878 1,063,505 954,141 4
Income taxes 582,031 578,329 559,694 Property and other taxes 129,038 190,284 200,236 Total operating expenses 6,893,498 6,450,289 6,723,874 Operating income 1,059,888 1,133,093 1,148,844 Provision for rate phase-in plan (48,486)
(84,288)
(122,233) i Allowance for equity funds used during construction 7,651 15,579 19,082
[
Interest and dividend income 44,636 37,855 37,644 Other nonoperating income (deductions) - net (23,036)
(3,623) 45,651 Total other income (deductions) - not (19,235)
(34,477)
(19,856)
Income before interest expense 1,040,653 1,098,616 1,128,988 i
Interest on long-term debt 345,592 380,812 385,187
' Other interest expense 101,078 73,914 80,130 Allowance for borrowed funds used during construction (9,213)
(9,794)
(14,489)
Capitalized interest (2,398)
(1,711)
(1,531)
Total interest expense-not 435,059 443,221 449,297 Not income 605,594 655,395 679,691 Dividends on preferred stock 29,488 34,395 36,764 Earnings available for common stock
$ 576,106
$ 621,000
$ 642,927 4
k i
Consolidated Statements of Retained Earnings d
l In thousands Year ended December 31, 1997 1996 1995 Balance at beginning of year
$2,665,612
$2,780,058
$2,683,568 l
Net income 605,594 655,395 679,691 Dividends declared on common stock (1,829,040)
(735,429)
(545,672)
Dividends declared one preferred stock (29,488)
(34,395)
(36,764)
Reacquired capital stock expense (4,844)
(17)
(765) i Balance at end of year
$1,407,834
$2,665,612
$2,780,058 The accompanying notes are integral part of these financial statements.
l 4
i
)
Consolidated Balance Sheets In thousands December 31, 1997 1996 ASSETS Transmission and distribution:
Utility plant, at original cost, subject to i
cost-based rate regulation
$11,213,352
$10,973,311 i-Accumulated provision for depreciation (5,573,742)
(5,128,652)
Construction work in progress 492,614 461,048 e
6,132,224 6,305,707 Generation:
3 l
Utility plant, at original cost, not subject to cost-based rate regulation 9,522,127 9,427,076 Accumulated provision for depreciation and decommissioning (4,970,137).
(4,302,419)
Construction workin progress 100,283 95,597 Nuclear fuel, at amcrtized cost 154,757 176.827 4,807,030 5,397,081 Total utility plant 10,939,254 11,702,788 i
Nonutility property -less accumulated provision for depreciation of $24,730 and $25,102 s
i at respective dates 67,869 63,931 Nuclear decommissioning trusts 1,831,460 1,485,525 i
Other investments 171,399 103,973 Total other property and investments 2,070,728 1,653.429 Cash and equivalents 962,272 319,942 Receivables, including unbilled revenue, less allowances of $26,453 and $26,079 for uncollectible accounts at respective dates 906,388 921,083 Fuelinventory 58,059 72,480 Materials and supplies, at average cost 132,980 154,2S6 Accumulated deferred income taxes - net 123,146 240,429 Regulatory balancing accounts-net 193,311 Prepayments and other current assets 93,098 105,137 Total current assets 2,469,254 1,813,337 Unamortized debt issuance arid reacquisition expense 359,304 346,834 Rate phase-in plan 3,777 50,703 Income tax-related deferred charges 1,543,380 '
1,741,091 Other deferred charges 673,601 428,370 Total deferred charges 2,580,062 2,566,998 Total assets
$18,059,298
$17,736,552 i
The accompanying notes are an integral part of these financial statements.
1 l
I 16
-..-.-~-.
Southem Califomia Edloon Company in thousands, except share amounts December 31, 1997 1996 CAPITALIZATION AND LIABILITIES Common shareholder's equity:
i Common stock (434,888,104 shares outstanding at each date)
$ 2,168,054
$ 2,168,054 Additional paid-in capital and other 382,054 210,857 Retained eamings 1,407,834 2.665,612 3,957,942 5,044,523 Preferred stock:
Not subject to mandatory redemption 183,755 283,755 Subject to mandatory redemption 275,000 275,000 j
Long-term debt 6,144,597 4,778,703 l
Total capitalization 10,561,294 10,381,981 e
l j
Other long-term liabilities 479,637 423,925 1
[
Current portion of long-term debt 692,875 501,470 Short-term debt 322,028 230,149 Accounts payable 406,704 392,779 Accrued taxes 509,270 484,688 Accrued interest 85,406 93,363 j
Dividends payable 95,146 108,563 Regulatory balancing accounts-net 181,488 Deferred unbilled revenue and other current liabilities 931,856 825,317 l
Totalcurrent liabilities 3,043,285 2,817,817 Accumulated deferred income taxes - net 2,939,471 3,170,696 Accumulated deferred investment tax credits 326,728 347,118 Customer advances and other deferred credits 708,745 595,015 Total deferred credits 3,974,944 4,112,829 Minority Interest 138 Commitments and contingencies (Notes 2,8,9 and 10)
Total capitalization and liabilities
$18,059,298
$ 17,736,552 The accompanying notes are an integral part of these financial statements.
17
southern CaHfornia Edloon Company Consolidated Statements cf Cash Firws In thousands Year ended December 31, 1997 1996 1995 Cash flows from operating activities:
1 Net income
$ 605,594
$ 655,395
$ 679,691 Adjustments for non-cash items:
Depreciation and decommissioning 1,239,878 1,063,505 954,141 Amortization 81,363 90,931 68,064 Rate phase-in plan 46,926 79,011 111,016 Deferred income taxes and investment tax credits 63,379 46,122 (208,671)
Other long-term liabilities 55,712 79,733 33,129 Other-net (208,624)
(153,034)
(261)
Changes in working capital:
Receivables 14,695 (9,120)
(9,873)
Regulatory balancing accounts (374,799)
(156,379) 282,157 Fuel inventory, materials and supplies 35,707 38,791 (19,499)
Prepayments and other current assets 12,039 9,152 (15,511)
Accrued interest and taxes 16,625 (58,827) 34,704 Accounts payable and other current liabilities 120,464 93,362 45,355 Net cash provided by operating activities 1,708,959 1,778,642 1,954,442 Cash flows from financing activities:
Long-term debt issued 396,309 393,829 Long-term debt repaid (916,145)
(403,957)
(422,503)
Rate reduction notes issued 2,449,289 Preferred stock redeemed (100,000)
(75,000)
Nuclear fuel financing - net (20,140) 41,803 31,134 Short-term debt financing-net 91,879 (129,359)
(316,006)
Capital transferred 153,000 Dividends paid (1,871,944)
(799,593)
(559,886)
Net cash used by financing activities (214,061)
(894,797)
(948,432)
Cash flows from investing activities:
Additions to property and plant (685,320)
(616,427)
(772,950)
' Funding of nuclear decommissioning trusts (153,756)
(148,158)
(150,595)
Unrealized gcin in equity investments - net 32,911 14,900 8,483 Other - net (46,403)
(75,985)
(21.273)
Net cash us ed by investing activities (852,568)
(825,670)
(936,335) l Net increase in cash and equivalents 642,330 58,175 69,675 Cash and equivalents, beginning of year 319,942 261,767 192,092 Cash and equivalents, end of year
$ 962,272
$ 319,942
$ 261,767 Cash payments for interest and taxes:
Interest - net of amounts capitalized S 342,137
$ 346,980
$ 381,267 Taxes 438,003 545,834 692,780 The accompanying notes are an integral part of these financial statements.
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Not:s t) Consolidated Fin ncial StatemintS Southem CaHfomia Edison Company Note 1.
Summary of Significant Accounting Policies Accounting Principles Southern California Edison Company's (SCE) accounting policies conform with generally accepted accounting principles (GAAP), including the accounting principles for rate-regulated enterprises which reflect the rate-making policies of the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC). As a result of industry restructuring legislation enacted by the State of California and a related change in the application of accounting principles for rate-regulated enterprises adopted recently by the Financial Accounting Standards Board's Emerging issues Task Force (EITF), during the third quarter of 1937, SCE began accounting for its investment in generation facilities in accordance with GAAP applicable to enterprises in general. Although this change did not result in any adjustment of the carrying value of such investment, it is shown separately on SCE's Balance Sheet under the caption: Generation utility plant, at original cost, not subject to cost-based rate regulation. The competitive market for electric generation in California is scheduled to begin March 31,1998.
Competition Transillon Charge (CTC)
Beginning January 1,1998, a non-bypassable charge is being billed to all customers, which provides SCE the opportunity to recover its costs to transition to a competitive market.
Consolidation Policy The consolidated financial statements include SCE and its subsidiaries. Intercompany transactions have been eliminated.
Estimates Financial statements prepared in compliance with GAAP require management to make estimates and assumptions that affect the amounts reported in the financial statements and disclosure of contingencies.
Actual results could differ from those estimates. Certain significant estimates related to electric utility restructuring, decommissioning and contingencies are further discussed in Notes 2, 9 and 10 to the Consolidated Financial Statements, respectively.
FuelInventory Fuel inventory is valued under the last-in, first-out method for fuel oil and natural gas, and under the first-in, first-out method for coal.
Nature of Operations SCE's outstanding common stock is owned entirely by its parent company, Edison International. SCE is
{
a public utility which produces and supplies electric energy for its 4.3 million customers in Central and Southern Califomia. SCE currently operates in a highly regulated environment in which it has an obligation to deliver electric service to customers in return for an exclusive franchise within its service l
territory. This regulatory environment is changing, as further discussed in Note 2 to the Consolidated l
Financial Statements.
Nuclear i
The CPUC authorized rate phase-in plans to defer the collection of $200 million in revenue for each unit 4
at the Palo Verde Nuclear Generating Station during the first four years of operation and recover the
)
deferred revenue (including interest) evenly over the following six years. The phase-in plans ended in i
February 1996, September 1996 and January 1998 for Units 1,2 and 3, respectively.
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Not2s to Consolidated Financist Statem2nts Under federal law, SCE is liable for its share of the estimated costs to decommission three federal nuclear enrichment facilities (based on purchases). These costs, which will be paid over 15 years, are recorded as a fuel cost and recovered through non-bypassable customer rates.
In 1992, SCE discontinued operation of San Onofre Nuclear Generating Station Unit 1, after the CPUC emroved a settlement agreement between SCE and the CPUC's Office of Ratepayer Advocates (ORA) to discontinue operation of Unit 1 because operation of the unit was no longer cost-effective. As part of the agreement, SCE recovered its remaining investment over a four-year period ending August 1996, eaming an 8.98% rate of return.
In 1994, the CPUC authorized accelerated recovery of SCE's nuclear plant investments by $75 million per year, with a corresponding deceleration in recovery of its transmission and distribution assets through revised depreciation estimates over their remaining useful lives.
In April 1996, the CPUC authorized a further acceleration of the recovery of SCE's remaining investment of $2.6 billion in San Onofre Units 2 and 3. The accelerated recovery will continue through December 2001, earning a 7.35% fixed rate of return. Operating costs, including nuclear fuel and nuclear fuel financing costs, and incremental capital expenditures at San Onofre Units 2 and 3 are recovered through an incentive pricing plan which allows SCE to receive about 4c per kilowatt-hour through 2003. Any differences between these costs and the incentive price will flow through to the shareholders. Beginning January 1,1998, the accelerated plant recovery and the incentive pricing plan became part of the CTC mechanism. Beginning in 2004, SCE will be required to share equally with ratepayers the net benefits received from operation of the units.
In January 1997, the CPUC authorized a further acceleration of the recovery of its remaining investment of $1.2 billion in Palo Verde Units 1,2 and 3. The accelerated recovery will continue through December 2001, earning a 7.35% fixed rate of return. The accelerated plant recovery, as well as operating costs, including nuclear fuel and nuclear fuel financing costs, and incremental capital expenditures, are subject to balancing account treatment through 2001. Beginning January 1,1998, the balancing account became part of the CTC mechanism. The existing nuclear unit incentive procedure will continue only for purposes of calculating a reward for performance of any unit above an 80% capacity factor for a fuel cycle.
Beginning in 2002, SCE will be required to share equally with ratepayers the net benefits received from operation of Palo Verde.
Reclassifications Certain prior-year amounts were reclassified to conform to the December 31,1997, financial statement presentation.
Regulatory Balancing Accounts Prior to January 1,1998, the differences between CPUC-authorized and actual base-rate revenue from kilowatt-hour sales and CPUC-authorized and actual energy costs were accumulated in balancing accounts until they were refunded to, or recovered from, utility customers through authorized rate adjustments (with interest). Beginning January 1,1998, the difference between generation related revenue and generation-related costs is being accumulated in a transition cost balancing account. These transition costs are being recovered from utility customers (with interest) through the CTC through 2001.
Income tax effects on all balancing account changes are deferred.
In January 1997, in compliance with the new restructuring legislation, overcollections in the kilowatt-hour sales and energy cost balancing accounts at December 31, 1996, were transferred to an interim l
balancing account and were credited to the transition cost balancing account beginning in January 1998.
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Southern California Edison Company Research, Development and Demonstration (RD&D)
SCE capitalizes RD&D costs that are expected to result in plant construction. If construction does not occur, these costs are charged to expense. RD&D expenses are recorded in a balancing account and, at the end of the rate-case cycle, any authorized but unspent RD&D funds are refunded to customers.
RD&D expenses were $39 million in 1997, $21 million in 1996 and $28 million in 1995.
Revenue Operating revenue includes amounts for services rendered but unbilled at the end of each year.
Utility Plant Plant additions, including replacements and betterments, are capitalized. Such costs include direct material and labor, construction overhead and an allowance for funds used during construction (AFUDC).
AFUDC represents the estimated cost of debt and equity funds that finance utility-plant construction.
AFUDC is capitalized during plant construction and reported in current earnings. AFUDC is recovered in rates through depreciation expense over the usefullife of the related asset. Depreciation of utility plant is computed on a straight-line, remaining-life basis, l
Replaced or retired property and removal costs less salvage are charged to the accumulated provision for depreciation. Depreciation expense stated as a percent of average original cost of depreciable utility plant was 5.2% for 1997,4.2% for 1996 and 3.6% for 1995.
During the third quarter of 1997, SCE discontinued accounting for its investment in generation facilities using accounting principles applicable to rate-regulated enterprises and began accounting for such investment using GAAP applicable to enterprises in general. The carrying value of such investment was unaffected by this change.
Note 2. Regulatory Matters California Electric Utility Industry Restructuring Restructuring Legislation -In September 1996, the State of Califomia enacted legislation to provide a transition to a competitive market structure. The legislation substantially adopted the CPUC's December 1995 restructuring decision by addressing stranded-cost recovery for utilities and providing a certain cost-recovery time period for the transition costs as' Ated with utility-owned generation-related assets.
Transition costs related to power-purchase contras would be recovered through the terms of their contracts while most of the remaining transition costs would be recovered through 2001. The legislation also included provisions to finance a portion of the stranded costs that residential and small commercial customers would have paid between 1998 and 2001, which would allow SCE to reduce rates by at least 10% to these customers, beginning January 1,1998. The financing would occur with securities issued by the California infrastructure and Economic Development Bank, or an entity approved by the Bank. The legislation included a rate freeze for all other customers, including large commercial and industrial customers, as well as provisions for continued funding for energy conservation, low-income programs and renewable resources. Despite the rate freeze, SCE expects to be able to recover its revenue requirement during the 1998 - 2001 transition period. In addition, the legislation mandated the implementation of the CTC that provides utilities the opportunity to recover costs made uneconomic by electric utility restructuring. Finally, the legislation contained provisions for the recovery (through 2006) of reasonable employee-related transition costs, incurred and projected, for retraining, severance, early retirement, outplacement and related expenses.
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Notes 12 Cons:lidated Fin:nci"l Statem:nts Rate Reduction Notes -In May 1997, SCE filad an s 1 with the CPUC requesting approval of the issuance of an aggregate amount of up to $3 billb
> reduction notes in one or more series or classes and a 10% rate reduction for the period froi
.ry 1,1998, through March 31,2002. At the same time, SCE filed an application with the Calfa..a.
1 structure and Economic Development Bank for approval to issue the notes. Residential and small commercial customers will repay the notes over the expected 10-year term through non-bypassable charges based on electricity consumption. In December 1997, after receiving approval from both the CPUC and the infrastructure Bank, a limited liability company created by SCE issued approxinztely $2.5 billion of these notes. For further details, see the discussion under Long-Term Debt in Note 3 to the Consolidated Financial Statements.
CPUC Restructuring Decision - The CPUC's December 1995 decision on restructuring California's electric utility industry started the transition to a new market structure, which is expected to provide competition and customer choice and is scheduled to begin March 31, 1998. Key elements of the CPUC's restructuring decision included.
creation of an independent power exchange (PX) and independent system operator (ISO); availability of direct customer access and customer choice; performance-based ratemaking (PBR) for those ut?ity services not subject to competition; voluntary divestiture of at least 50% of utilities' gas-fueled generation, and implementation of the CTC.
Rate-setting-In December 1996, SCE filed a more comprehensive plan (elaborating on its July 1996 filing related to the conceptual aspects of separating costs as requested by CPUC and FERC directives) for the functional unbundling of its rates for electric service, beginning January 1,1998. In response to CPUC and FERC orders, as well as the new restructuring legislation, this filing addressed the implementation-level detail for the functional unbundling of rates into separate charges for energy, transmission, distribution, the CTC, public benefit programs and nuclear decommissioning.
The transmission component o' this rate unbundling process was addressed at the FERC through a March 1997 filing. In December 1997, the FERC approved these rates, subject to refund, to be effective on the date the ISO begins operation. CPUC hearings on SCE's rate unbundling (also known as rate-setting) plan were concluded in April 1997. In August 1997, the CPUC issued a decision which adopted the methodology for determining CTC residually (see CTC discussion below) and adopted SCE's revenue requirement components for public benefit programs and nuclear decommissioning. The decision also adjusted SCE's proposed distribution revenue requirement by reallocating $76 million of the amount annually to other functions such as generation and transmission. Under the decision, SCE will be able to i
recover most of the reallocated amount through market revenue, other rate-making mechanisms after petitioning the CPUC to modify its prior decisions, or another review process later in its divestiture proceer/ing.
PX and ISO - In April 1996, SCE, Pacific Gas & Electric Company and San Diego Gas & Electric Company fikd a proposal with the FERC regarding the creation of the PX and the ISO. In November 1996, the FERC conditionally accepted the proposal and directed the three utilities, the ISO, and the PX to file more specific information. The filing was made in March 1997, and included SCE's proposed transmission revenue requirement.
On October 29, 1997, the FERC gave conditional, interim authorizetion for operation of the PX and ISO to begin on January 1,1998. The FERC stated it would closely monitor the PX and ISO, require further studies and make modifications, where necessary. A comprehensive review will be performed by the FERC after three years of operation of the PX and ISO.
On December 22,1997, the AX and ISO governing boards announced a delay in the planned start up of the PX and ISO due te insufficient testing of operational, settlement and billing systems. The PX and ISO are now expected to begin operation by March 31,1998.
In July 1996, the three utilities jointly filed an application with the CPUC requesting approval to establish a restructuring trust which would obtain loans up to $250 million for the development of the ISO and PX through January 1,1998. The loans are backed by utility guarantees; SCB Me was 45%, or $113 million. In August 1996, the CPUC issued an interim order establishing the restructuring trust and the funding level of $250 million, which has been used to build the hardware and software systems for the 22
Southern CaHfornia Edison Osmpany ISO and PX. The ISO and PX will repay the trust's loans and recover funds from future ISO and PX customers. In November 1997, the CPUC approved a petition jointly filed by the three utilities which requested an increase in the loan guarantees from $250 million to $300 million; SCE's share of this new l
totalis $135 million. In December 1997, the CPUC approved a remaining item with respect to the petition which requested that the one-time restructuring implementation charge, to be paid to the PX by the utilities, be deemed a non-bypassable charge to be recovered from all retail customers. The amount of the PX charge is $85 million; SCE% share is 45%, or $38 million.
Direct Customer Access - In May 1997, the CPUC issued a decision describing how all California investor-owned-utility customers wi!! be able to choose who will provide them with electric generation service beginning January 1,1998. On December 30,1997, the CPUC issued a decision delaying direct access until March 31,1998, due to the operational delays in the start-up of the PX and ISO. On this date, customers will be able to choose to remain utility customers with bundled electric service from SCE (which will purchase its power through the PX), or choose direct access, which means the customer can contract directly with either independent power producers or retail electric service providers such as power brokers, marketers and aggregators. Additionally, all investor-owned-utility customers must pay l
the CTC whether or not they choose to buy power through SCE. Electric utilities will continue to provide the core distribution service of delivering erergy through its distribution system regardless of a customer's choice of electricity supplier. The CPUC will continue to regulate the prices and service obligations related to distribution services. If the new competitive market cannot accommodate the volume of direct access transactions, the CPUC could implement a contingency plan. However, the CPUC believes it is likely that interest in and migration to direct access will be gradual.
Revenue Cycle Services - A decision issued by the CPUC in May 1997, introduces customer choice to metering, billing and related services (referred to as revenuo cycle services) that are now provided by California's investor-owned utilities. Under this revenue cycle services unbundling decision, beginning in January 1998, direct access customers may choose to have either SCE or their electric generation service provider render consolidated (energy and distribution) bills, or they may choose to have separate billings from each service provider. However, not all electric generation service providers will necessarily offer each billing option. In addition, beginning in January 1998, customers with maximum demand above 20 kW (primarily industrial and large commercial) can choose SCE or any other supplier to provide their metering service. All other customers will have this option beginning in J;nuary 1999. In determining 4
whether any credit should be provided by the utility to firms providing customers with revenue cycle i
services, and the amount of any such credit, the CPUC has indicated that it is appropriate to net the cost incurred by the utility and the cost avoided by the utility as a result of such services being providvd by the other firm rather than by the utility.
PBR -In 1993, SCE filed for a PBR mechanism to determine most of its revenue (excluding fuel). The filing was subsequently divided between transmission and distribution (T&D) and power generation. In September 1996, the CPUC adopted a non-generation or T&D PBR mechanism for SCE which began on January 1,1997. According to the CPUC, beginning in 1998 (coincident with the initiation of the ca opetitive market), the transmission portion is to be separated from non-generation PBR and subject to ratemaking under the rules of the FERC. The distribution-only PBR will extend through December 2001.
Key elements of the non-generation P8R include: T&D rates indexed for inflation based on the Consumer Price index less a productivity factor; elimination of the kilowatt-hour sales adjustment; adjustments for cost changes that me not within SCE's control; a cost of capital trigger mechanism based on changes in a bond index; standards for service reliability and safety; and a net revenue-sharing mechanism that determines how customers and shareholders will share gains and losses from T&9 operations.
With the CPUC's 1995 restructuring decision and the passage of restructuring legislation in 1996, the majority of power generation ratemaking (primarily fossil-fueled and nuclear) was assignad to other mechanisms. In April 1997, a CPUC interim order determined that the proposed structure of the fossil-fueled plants' must-run contracts were under the FERC's jurisdiction. On October 31,1997, SCE filed 23
Notes to Consolidated Fin ncial Statem;nts l
must-run tariff schedules with the FERC covering its six ISO-designated must-run plants. In the meantime, SCE is pursuing the divestiture of these plants (see Divestiture discussion below) and might not ever itself provide service under these FERC tariff schedules.
In December 1997, the CPUC adopted a PBR-type rate-making mechanism for SCE's hydroelectric plants. The mechanism sets the hydroelectric revenue requirement in 1998 and establishes a formula for extending it through the duratbn of the electric industry restructuring transition period, or until market valuation of the hydroelectric facilities, whichever occurs first. The mechanism provides that power sales revenue from hydroelectric facilities in excess of the hydroelectric revenue requirement be credited against the costs to transition to a competitive market (see CTC discussion below).
Divestiture - In November 1996, SCE filed an application with the CPUC to voluntarily divest, by auction, all 12 of its oil-and gas-fueled generation plants. This application builds on SCE's March 1996 plan which outlined how SCE proposed to divest 50% of these assets. Under the new proposal, SCE would continue to operate and maintain the divested power plants for at least two years following their sale, as mandated by the restructuring legislation enacted in September 1996. In addition, SCE would offer workforce transition programs to those employees who may be impacted by divestiture-related job reductions. SCE's proposal is contingent on the overall electric industry restructuring implementation process continuing on a satisfactory path. In September 1997, the CPUC approved SCE's proposal to auction the 12 plants.
On December 1,1997, SCE filed a compliance filing with the CPUC stating that it had sold 10 plants. On December 16,1997, the CPUC approved the sale of the 10 plants. On February 6,1998, SCE filed a compliance filing with the CPUC for the sale of an 11th plant. CPUC approval of the sale is expected before March 31,1998. The total sales price of the 11 plants is $1.1 billion, or 2.16 times their combined book value of $531 million. Net proceeds of the sales will be used to reduce stranded costs which otherwise were expected to be collected through a non-bypassable CTC. The transfer of ownership of the 11 plants is expected to occur shortly before the start of the new competitive market, which the PX and ISO currently expect to occur on March 31,1998. The sale and CPUC approval of the single remaining plant is expected to be completed in early 1998.
CTC-The CTC applies to all customers who were using or began using utility services on or after the CPUC's December 20,1995, decision date, in August 1996, in compliance with the CPUC's restructuring decision, SCE filed its application to estimate its 1998 transition costs. In October 1996, SCE amended its transition cost filing to reflect the effects of the legislation enacted in September 1996. Under the rate freeze codified in the legislation, the CTC will be determined residually (i.e., after subtracting other cost components for the PX, T&D, nuclear decommissioning and public benefit programs). Nevertheless, the CPUC directed that the amended application provide estimates of SCE's potential transition costs from 1998 through 2030. SCE provided two estimates between approximately $13.1 billion (1998 net present value) assuming the fossil plants have a market value equal to their net book value, and $13.8 billion (1998 net present value) assuming the fossil plants have no market value. These estimates are based on incurred costs, forecasts of future costs and assumed market prices. However, changes in the assumed market prices eauld materially affect these estimates. The potential transition costs are comprised of:
$7.5 billion from SCE's qualifying facilities (OF) contracts, which are the direct result of prior legislative and regulatory mandates; and $5.6 billion to $6.3 billion from costs pertaining to certain generating plants (successful completion of the sale of SCE's gas-fired gg iting plants would reduce this estimate of transition costs for SCE-owned generation to less than $5 billion) and regulatory commitments consisting of costs incurred (whose recovery has been deferred by the CPUC) to provide service a customers.
Such commitments irciude the recovery of income tax benefits previously flowed through to customers, postretirement benefit transition costs, accelerated recovery of San Onofre Units 2 and 3 and the Palo Verde units, (as discussed in Note 1 to the Consolidated Financial Statements) and certain other costs. In February 1997, SCE filed an update to the CTC filing to reflect approval by the CPUC of settlements regarding ratemaking for SCE's share of Palo Verde and the buyout of a power purchase agreement, as well as other minor data updates. No substantive changes in the total CTC estimates were included.
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Southern california Edison Company This issue has been separated into two phases: Phase 1 addresses the rate-making issues and Phase 2 the quantification issues.
A decision on Phase 1 was issued in June 1997, which, among other things, required the establishment of a transition cost balancing account and annual transition cost proceedings, set a market rate forecast for 1998 transition costs, and required that generation-related regulatory assets be amortized ratably over a 48-month period. Hearings on Phase 2 were held in May and June 1997 and a final decision was issued on November 19,1997. The Phase 2 decision established the calculation methodologies and procedures for SCE to collect its transition costs from 1998 through the end of the rate freeze. The Phase 2 decision also reduced SCE's authorized rate of retum on certain assets eligible for transition cost recovery (primarily fossil-and hydroelectric-generation related assets) beginning July 1997, five months earlier than anticipated. The decision, excluding the effects of other rate actions, had a negative impact on 1997 eamings of approximately $14 million. SCE has filed an application for rehearing on the 1997 rate of return issue.
Accounting for Generation-Related Assets - If the CPUC's electric industry restructuring plan is implemented as outlined above, SCE would be allowed to recover its CTC through non-bypassable charges to its distribution customers (although its investment in certain generation assets would be subject to a lower authorized rate of return).
As previously reported, from November 1996 to July 1997, SCE and the other major California electric utilities were engaged in discussions with the Securities and Exchange Commission staff regarding the proper application of regulatory accounting standards in light of the electric industry restructuring legislation enacted by the State of California in September 1996 and the CPUC's electric industry restructuring plan. This issue was placed on the agenda of the EITF during April 1997 and a final consensus was reached at the July EITF meeting. During the third quarter of 1997, SCE implemented the EITF consensus and discontinued application n' accounting principles for rate-regulated enterprises for its investment in generation facilities.
However, implementation of the EITF consensus did not require SCE to write off any of its generation-related assets, including regulatory assets of approximately $600 million at December 31,1997. SCE has retained these assets on its balance sheet because the legislation and restructuring plan referred to above make probable their recovery through a CTC to distribution customers. These regulatory assets r: late primarily to the recovery of accelerated income tax benefits previously flowed through to customers, purchased power contract termination payments, unamortized losses on reacquired debt, and the recovery of amounts deferred under the Palo Verde rate phase-in plan. The consensus reached by the EITF a:so permits the recording of new generation-related regulatory assets during the transition period that are probable of recovery through the CTC mechanism.
If during the transition period events were to occur that made the recovery of these generation-related regulatory assets no longer probable, SCE would be required to write off the remaining balance of such assets as a one-time, non-cash charge against earnings. If such a write-off were to be required, SCE believes that it should not affect the recovery of stranded costs provided for in the legislation and restructuring plan.
Although depreciation-related differences could result from applying a regulatory prescribed depreciation method (straight-line, remaining-life method) rather than a method that would have been appFed absent the regulatory process, SCE believes that the depreciable lives of its generation ~related assets would not vary significantly from that of an unregulated enterprise, as the CPUC bases depreciable lives on periodic studies that reflect the physical useful lives of the assets. SCE also believes that any depteciation-rtlated differences would be recovered through the CTC.
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Notes is Consolidated FinIncial Statemints If events occur during the restructuring process that result in all or a portion of the CTC being improbable of recovery, SCE could have additional write-offs associated with these costs if they are not recovered through another regulatory mechanism. At this time, SCE cannot predict what other revisions will ultimately be made during the restructuring process in subsequent proceedings or implementation phases, or the effect, after the transition period, that competition will have on its results of operations or financial position.
FERC Restructuring Decision in April 1996, the FERC issued its decision on stranded-cost recovery and open access transmission, effective July 1996. The decision, reaffirmed by the FERC in its March and November 1997 orders, requires all electric utilities subject to the FERC's jurisdiction to file transmission tariffs which provido competitors with increased access to transmission facilities for wholesale transactions and also establishes information requirements for the transmission utility. The decision also provides utilities with the opportunity to recover stranded costs associated with existing wholesale customers, retail-turned-wholesale customers and retail wheeling when the state regulatory body does not have authority to address retail stranded costs. Even though the CPUC is currently addressing stranded-cost recovery through the CTC proceedings, the FERC has also asserted primary jurisdiction over the recovery of stranded costs associated with retail-tumed-wholesale customers, such as a new municipal electric system or a municipal annexation. However, the FERC did clarify that it does not intend to prevent or interfere with a state's authority and that it has discretion to defer to a state stranded-cost-calculation method. In January 1997, the FERC accepted the open access transmission tariff SCE filed in compliance with the April 1996 decision. The rates included in the tariff are being collected subject to refund. In May 1997, SCE filed a revised open access tariff to reflect the few revisions set forth in the March 1997 order. The open access transmission tariff will be terminated on the date the ISO begins operation.
Canadian Gas Contracts in 1994, SCE filed its testimony in the non-OF phase of the 1994 Energy Cost Adjustment Clause proceeding. In 1995, the ORA filed its report on the reasonableness of SCE's gas supply costs for both the 1993 and 1994 record periods. The report recommended a disallowance of $13 million for excessive costs incurred from November 1993 through March 1994 associated with SCE's Canadian gas purchase and supply contracts. The report requested that the CPUC defer finding SCE's Canadian supply and transportation agreements reasonable for the duration of their terms and that the wti under these contracts be reviewed on a yearly basis. In 1996, the ORA issued its report for the 1995 record period recommending a $38 million disallowance for excessive costs incurred from April 1994 through March 1995.
Both proposed disallowances were later consolidated into one proceeding. On December 3,1997, the CPUC approved a settlement agreement between SCE and the ORA on this and any future issues which will result in a $61 million (including interest) refund to SCE's customers. This refund is fully reflected in the financial statements and will be made in first quarter 1998.
Mojave Cogeneration Contract in 1991, SCE filed its testimony in the OF phase of the 1991 Energy Cost Adjustment Clause proceeding.
In 1993, the ORA filed is report on the reasonableness of SCE's OF contracts and alleged that SCE had imprudently renegotiated a OF contract with the Mojave Cogeneration Company.
The report recommended a disallowance of $32 million (1993 net present value) over the contract's 20-year life.
Subsequently, SCE and the ORA reached a settlement where SCE agreed to a one-time reduction to its energy-cost adjustment clause balancing account of $14 million plus interest. In October 1996, the CPUC approved the settlement agreement, subject to SCE and the ORA accepting certain conditions conceming the way the $14 million payment would be reflected in rates. After reviewing the decision, SCE declined to accept the condition proposed by the CPUC and in November 1996 filed an application 26
aouthern Californb Edloon Company for rehearing. In February 1997, the CPUC denied SCE's application. Because SCE and the ORA were unable to finalize their settlement, hearings on the ORA's disallowance recommendations were held in June 1997. During the hearings, the ORA presented testimony to upda% its assessment of ratepayer harm, which it now estimates to be $45 million (1997 net present value) over the contract's life. In November 1997, a CPUC administrative law judge (ALJ) issued a proposed decision which would adopt the ORA's $45 million disallowance. In January 1998, the CPUC withdrew the ALJ's proposed decision pending oral arguments. Oral arguments were heard on February 4,1998, at which time SCE requested en alternate proposed decision be issued. SCE expects this matter to be retumed to the CPUC's agenda in the near futura and a final decision to be issued during second quarter 1998. SCE cannot predict the final outcome of this matter but does not believe it will materially affect its results of operations.
Note 3. FinancialInstruments Cash Equivalents Cash and equivalents include tax-exempt investments ($936 million at December 31,1997, and
$261 million at December 31,1996), and time deposits and other investments ($26 million at December 31,1997, and $59 million at December 31,1996) with maturities of three months or less.
Derivative FinancialInstruments SCE's risk management policy allows the use of derivative financial instruments to manage financial exposure on its investments and fluctuations in interest rates, but prohibits the use of these instruments for speculative or trading purposes.
SCE uses the hedge accounting method to record its derivative financialinstruments, except for gas call options. Hedge accounting requires an assessment that the transaction reduces risk, that the derivative be designated as a hedge at the inception of the derivative contract, and that the changes in the market value of a hedge move in an inverse direction to the item being hedged. Under hedge accounting, the derivative itself is not recorded on SCE's balance sheet. Mark-to-market accounting would be used if the hedge accounting cri'eria were not met. Interest rate differentials and amortization of premiums for interest rate caps are recorded as adjustments to interest expense. If the derivatives were terminated before the maturity of the corresponding debt issuance, the realized gain or loss on the transaction would be amortized over the remaining term of the debt.
SCE uses the mark-to-market accounting method for its gas call options. Gains and losses from monthly changes in market prices are recorded as income or expense. However, the costs of the options and the market price changes are recovered through the transition cost balancing account. As a result, the mark-to-market gains or losses have no effect on earnings.
Interest rate swaps and caps are used to reduce the potential impact of interest rate fluctuations on floating-rate long-term debt. At the balance sheet date of December 31,1996, SCE had an interest rate cap agreement which capped the interest rate at 6% for $30 million of debt due 2027; it expired July 1,1997. At the balance sheet dates of December 31,1997, and December 31,1996, SCE had an interest rate swap agreement which fixed the interest rate at 5.585% for $196 million of debt due 2008; it expires February 28,2008. The interest rate swap agreement requires the parties to pledge collateral according to bond rating and market interest rate changes. At December 31,1997, SCE had pledged
$19 million as collateral due to a decline in market interest rates. SCE is exposed to credit loss in the event of nonperformance by the counterparty to the agreement, but does not expect the counterparty to failto meet its obligations.
At December 31,1997, SCE had gas call options valued at $34 million. These options mitigate SCE's exposure to increases in natural gas prices. Increases in natural gas prices tend to increase the price of electricity purchased from the PX. The options cover various periods from 1998 through 2001.
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Notes ta Consolidated Financial Statements Fair Value of FinancialInstruments Fair values cf financialinstruments were:
In millions December 31, 1997 1996 Cost Fair Cost Fair Basis Value Basis Value Instrument Financial assets:
Decommissioning trusts
$1,371
$1,831
$1,217
$1,486 9
90 11 68 Equity investments 34 34 Gas calloptions Financialliabilities:
DOE decommissioning and decontamination fees 50 43 54 45 interest rate hedges 24 16 Long-term debt 6,145 6,456 4,779 5,001 Preferred stock subject to mandatory redemption 275 293 275 286 Financial assets are carried at their fair value based on quoted market prices for decommissioning trusts and equity investments, and on financial models for gas call options. Financial liabilities are recorded at cost. Financial liabilities' fair values are based on: termination costs for the interest rate swap; brokers' quotes for long-term debt, preferred stock and the cap; and discounted future cash flows for U.S.
Department of Energy (DOE) decommissioning and decontamination fees. Due to their short maturities, amounts reported for cash equivalents and short-term debt approximate fair value.
Gross unrealized holding gains on financial assets were:
In millions December 31, 1997 1996 Decommissioning trusts:
Municipal bonds
$131
$ 79 Stocks 190 138 U.S. government issues 91 39 Short-term and other 48 13 460 269 Gquity hvesnenis 81 57 Total
$541 "C320 There were no unrealized holding losses on financial assets for the years presented.
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Southern CaHfornla Edison Company Investments Net unrealized gains (losses) in equity investments are recorded as a separate component of shareholder's equity under the caption: Additional paid-in capital and other. Unrealized gains and losses on decommissioning trust funds are recorded in the accumulated provision for decommissioning.
A!! investments are classified as available-for-sale.
1 Long-Term Debt Califomia law prohibits SCE from incurring or guaran'eeing debt for its nonutility affiliates.
Almost all SCE properties are subject to a trust indentere lien.
SCE has pledged first and refunding mo'rtgage bondt as security for borrowed funds obtained from pollution-control bonds issued by government agencies.
SCE uses these proceeds to finance construction of pollution-control facilities. Bondholdem have limited discretion in redeeming certain oollution-control bonds, and SCE has arranged with securities dealers to remarket or purchase them if necessary.
Debt premium, discount and issuance expenses are arnortized over the life of each issue. Under CPUC rate-making procedures, debt reacquisition expenses are amortized over the remaining life of the reacquired debt or, if refinanced, the life of the new debt.
Long-term dcbt maturities and sinking fund requirements for the five years are: 1998 - $693 million; 1999 - $401 million; 2000- $571 million; 2001 - $646 million; and 2002 - $446 million.
In December 1997, SCE Funding LLC, a special purpose entity (SPE), of which SCE is the sole member, issued approximately $2.5 billion of rate reduction notes to Bankers Trust Company of Califomia, as certificate trustee for the California infrastructure and Economic Development Bank Special Purpose Trust SCE-1 (Trust), which is a special purpose entity established by the State of Califomia. The terms of the rate reduction notes generally mirror the terms of the pass-through certificates issued by the Trust, which are known as rate reduction certificates. The proceeds of the rate reduction notes were used by the SPE to purchase from SCE an enforceable right known as transition property. Transition property is a cu.*ent property right created pursuant to the restructuring legislation and a financing order of the l
CPUC and consists generally of the right to ho paid a specified amount from a non-bypassable tariff levied on residential and small commercial cuetnme*. Notwithstanding the legal sale of the transition property by SC5 to the SPE, the amounts reflected as usets on SCE's balance sheet have not been re Med by the amount of the transitica property sold to the SPE, and the liabilities of the SPE for the rate reduction notes are for accounting purposes reflected as long-term liabilities on the consolidated balance sheet of SCE. SCE used the proceeds from the sale of the transition property to retire debt and equity securities.
i The rate reduction notes have maturities ranging from one to 10 years, and bear interest at rates ranging from 5.98% to 6.42%. The rate reduction notes are secured solely by the transition property and certain oth~ assets of the SPE, and there is no recourse to SCE or Edison International.
snough the SPE is consolidated with SCE in the financial statements, as required by generally accepted accounting principles, the SPE is legally separate from SCE, the assets of the SPE are not available to creditors of SCE or Edison international, and the transition property is legally not an asset of SCE or Edison International.
29 j
Notes ta Consolidated Finan:lal Statements Long-term debt consisted of:
in millions December 31, 1997 1996 4
First and refunding mortgage bonds:
i 1998 2026 (5.45% to 8.375%)
$1,825
$2,725 Rate reduction notes:
1998 - 2007 (5.98% to 6.42%)
2,463 Pollution-control bonds:
1999-2027 (5.4% to 7.2% and variable) 1,202 1,204 Funds held by trustees.
(2)
(2)
Debentures and notes:
1998-2006 (5.6% to 8.25%)
1,195 1,195 l
Subordinated debentures:
100 100 2044 (8.375 %)
Commercial paper for nuclear fuel 92 112 l_ong-term debt due within one year (693)
(501)
Unamortized debt discount - net (37)
(54)
Total
$6,145
$4,779 i
On January 30,1998, SCE redeemed $125 million of 8.375% first and refunding mortgage bonds, due 2017. Also, on January 30,1998, a wholly owned financing subsidiary of SCE redeemed $200 million of 7.375% notes, due 2003.
Short Term Debt SCE has lines of credit it can use at negotiated or bank index rates. At December 31, t.s97, available lines totaled $1.8 billion, with $1.3 billion for short-term debt and $500 million available for the long-term refinancing of certain variable-rate pollution-control debt.
Short-term debt consisted of commercial paper used to finance fuel inventories, balancing account undercollections and general cash requirements. Commercial paper outstanding at December 31,1997, and 1996, was $415 million and $345 million, respectively. Commercial paper intended to finance nuclear fuel scheduled to be used more than one year after the balance sheet date is classified as long-term debt in connection with refinancing terms under five-year term lines of credit with commercial banks.
Weighted-average interest rates were 6.0% and 5.5% at December 31,1997, and 1996, respectively.
Note 4. Equity The CPUC regulates SCE's capital structure, limiting the dividends it may pay Edison International. At December 31,1997, SCE had the capacity to pay $1.4 billion in additional dividends and continue to maintain its authorized capital structure.
4 Authorized common stock is 560 million shares with no par value. Authorized shares of preferred and preference stock are: $25 cumulative preferred - 24 million; $100 cumulative preferred - 12 million; and preference - 50 millior.. All cumulative preferred stocks are redeemable.
Mandatority redeemeblo preferred stocks are subject to sinking-fund provisions. When preferred shares are redeemed, the ptemiums paid are charged to common equity.
Proferred stock redemption requirements for the next five years are: 1998 through 2001 - zero and 2002 - $105 million.
30
. - _. -... - -. - -. ~ ~. -. - - - _.... -. _ ~ ~ - _. -..
O o
Southem Califomia Edison Company 1
Cumulative preferred stock consisted of:
I 1
Dollars in millions, except per-share amounts December 31, 1997 1996 l
December 31.1997 Shares Redemption Outstandina Price Not subject to mandatory redemption:
$25 par value:
4.08% Series 1,000,000
$25.50
$ 25
$ 25
-4.24 1,200,000 25.80 30 30 4.32 1,653,429 28.75 41 41 4.78 1,296,769 25.80 33 33 4
5.80 2,200,000 25.25 55 55 7.36 100 Total
$184
$284 i
Subject to mandatory redemption:
$100 par value:
6.05% Series 750,000
$ 100.00
$ 75
$ 75 i
6.45 1,000,000 100.00 100 100 7.23 1,000,000 100.00 100 100 Total
$275
$275 In 1997,4 million shares of Series 7.36% preferred stock were redeemed. In 1995,750,000 shares of Series 7.58% preferred stock wers redeemod. There were no preferred stock issuances or redemptions in 1996.
Note 5. Income Taxes SCE and its subsidiaries will be included in Edison Intemational's consolidated federal income tax and combined state franchise tax retums.
Under income tax allocation agreements, each subsidiary calculates its own tax liability.
-Income tax expense includes the current tax liability from operations and the change in deferred income taxes during the year. Investment tax credits are amortized over the lives of the related properties.
1 a
1 i
l 31
Notes to Consolidated Financial Statements The components of the net accumulated deferred income tax liability were:
In milliens December 31, 1997 1996 Deferred tax assets:
$ 227 247 Property-related 2'73 201 Unrealized gains or losses 192 206 investment tax credits '
180 298 Regulatory balancing accounts 114 208 Decommissioning-related 335 135 Other
$ 1,321
$ 1,295 Total Deferred tax liabilities:
$ 3,272
$ 3,550 Property-related 127 122 Capitalized software costs 738 553 Other
$ 4,137
$ 4,225 Total Accumulated deferred income taxes - not 3 2,816
$ 2,930 Classification of accumulated deferred income taxes:
Included in deferred credits S 2,939
$ 3.170 123 240 included in currerr assets The current and deferred componerits of income tax expense were:
In millions Year ended December 31, 1997 1996 1995 Current:
Federal
$375
$386
$560 State 100 129 165 475 515 725 Deferred-federal and state:
Accrued charges (33)
(14) 1 Depreciation (47)
(14) 21 investrpent and energy tax credits - net (20)
(24)
(25)
Pension reserves (5) 45 (3)
Rate phase-in plan (19)
(32)
(46)
Regulatory balancing accounts 141 34 (118) 21 (12)
State tax-privilege year Other 28 (20)
(33) 45 (4)
(215)
Totalincome tax expense
$52tl
$511
$510 Classification of income taxes:
Included in operating income
$582
$578
$560 included in other income (62)
(67)
(50) ihe composite federal and state statutory income tax rate was 40.551% for 1997 and 41.045% for 1996 and 1995.
l-32 l
Southern Californsa Edison Company The federal statutory income tax rate is reconciled to the effective tax rate below:
Year ended December 31, 1997-1996 1995 Federal statutory rate 35.0 %
35.0%
35.0%
Capitalized software (0.9)
(0.8)
(0.8)
Depreciation and other 6.9 4.5 4.3 Investment and energy tax credits (1.8)
(2.0)
(2.2)
State tax - net of federal deduction 7.0 7.1 6.5 Effective tax rate 46.2 %
43.8 %
42.8 %
Note 6.
Employee Compensation and Benefit Plans Stock Option Plans Under its Long-Term Incentive Compensation Plan, SCE participates in the use of 8.2 million shares of parent company common stock reserved for potential issuance under various stock compensation programs to directors, officers and senior managers of Edison Intemational and its affiliates. Under these programs, options on 3.7 million shares of Edison In'ernational common stock are currently outstanding to officers and senior managers of SCE.
Each option may be exercised to purchase one share of Edison Intemational common stock, and is exercisable at a price equivalent to the fair market value of the underlying stock at the date of grant.
Edison international stock options include a dividend equivalent feature. Generally, for options issued before 1994, amounts equal to dividends accrue on the options at the same time and at the same rate as would be payable on the number of shares of Edison International common stock covered by the options.
The amounts accumu' ate without interest. For Edison Intemational stock options issued subsequent to 1993, dividend equivalents are subject to reduction unless certain shareholder return performance criteria are met.
- Edison Intemational stock options have a 10-year term with one-third of the total award vesting after each of the first three years of the award term. If an optionee retires, dies or is permanently and totally disabled during the threeyear vesting period, the unvested options will vest and be exercisable to the extent of 1/36 of the grant for each full month of service during the vesting period. Unvested options of any person who has served in the past on the Edison international or SCE Management Committee will vest and be exercisable upon the member's retirement, death or permanent and total disability. Upon retirement, death or permanent and total disability, the vested options may continue to be exercised within their original terms by the recipient or beneficiary. If an optionee is terminated other than by retirement, death or permanent and total disability, options which had vested as of the prior anniversary date of the grant are forfeited unless exercised within 180 days of the date of termination. All unvested options are forfeited on the date of termination.
SCE measures compensation expensa related to stock-based compensation by the intrinsic value method. Compensation expense recorded under the stock-compensation program was $5 million,
$8 million and $4 million for the years 1997,1996 and 1995, respectively.
Stock based compensation expense under the fair-value method of accounting would have resulted in pro forma earnings of $602 million, $653 million and $677 million for the years 1997,1996, and 1995, respectively.
The weighted-average fair value of options granted during 1997 and 1996 was $7.62 per share option and $6.27 per share option, respectively. The weighted-average remaining life of options outstanding as of December 31,1997, and 1996, was 7 years.
33
Notes is Consolidated Financial Statements The fair value for each option granted, reflecting the basis for the above pro forma disclosures, was determined on the date of grant.using the Black-Scholes option-pricing model.
The following assumptions were used in determining fair value through the model:
1997 1996 Expected life 7 years 7 years Risk freeinterest rate 6.3% - 6.8%
5.5%
17%
17%
Expected volatility The recognition of dividend equivalents results in no dividends assumed for purposes of fair-value determination. The application of fair-value accounting to calculate the pro forma disclosures above is not an indication of future income statemer.: effects. The pro forma disclosures do not reflect the effect of fair-value accounting on stock-based compensation awards granted prior to 1995.
Pension Plan SCE has a noncontributory, defined-benefit pension plan that covers employees meeting minimum service requirements. Benefits are based on years of accredited service and average base pay. SCE funds the plan on a level-premium actuarial method. These funds are accumulated in an independent trust. Annual contributions meet minimum legal funding requirements and do not exceed the maximum amounts deductible for income taxes. Prior service costs from pension plan amendments are funded over 30 years. Plan assets are primarily common stocks, corporate and government bonds, and short-term investments. In 1996, SCE recorded pension gains from a special voluntary early retirement program.
The plan's funded status was:
In millions December 31, 1977 1996 l
Actuarial present value of benefit obligations:
Vested benefits
$ 1,577
$ 1,670 Nonvested benefits 126 71 Accumulated benefit obligation 1,703 1,741 Value of projected future compensation levels 391 261
, Projected benefit obligation S 2,094
$ 2,002 Fair value of plan assats
$ 2,298
$ 2,165 Projected benefit obligation less than plan assets
$ (204)
(163)
Unrecognized net gain 304 300 Unrecognized prior service cost (184)
(199)
Unrecognized net obligation (17-year amortization)
(38)
(43)
Pension liability (asset)
$ (122)
$ (105)
Discount rate 7.0%
7.75%
Rate of increase in future compensation 5.0% -
5.0%
Expected long-term rate of retum on assets 8.0%
8.0%
34 l
Southern Californi) Edloon Company SCE recognizes pension expense calculated under the actuarial method used for ratemaking.
The components of pension expense were:
1 i
in millions Year ended December 31, 1997 1996 1995 i-Service cost for benefits eamed
$ 44
$ 49
$ 57 l
Interest cost on projected benefit obligation 138 178 156 Actual retum on plan assets (369)
(343)
(454)
^
Net amortization and deferral 222 145 268 i
Pension expense under accounting standards 35 29 27 Specialtermination benefits 3
i Regulatory adjustment -deferred 17 22 22
~
Net pension expense recognized 52 51 52 Settlement gain (121) 5 Total sxpense (gain)
$ 52
$ (70) $ 52 i
l Postratirement Benefits Other Than Pensions i
i-Employees retiring at or after age 55 with at least 10 years of service (or those eligible under the 1996 j
special voluntary early retirement program), are eligible for postratirement health and dental care, life l
Insurance and other benefits. Health and dental care benefits are subject to deductibles, copayment l
provisions and otherlimitations.
SCE is amortizing its obligation related to prior service over 20 years. SCE funds these benefits (by
)
}
contributions to independent trusts) up to tax-deductible limits, in accordance with rate-making practices.
f in 1996, SCE recorded special termination expenses due to a special voluntary early retirement program.
Any difference between recognized expense and amounts authorized for rate recovery is not expected to j
j be material (except for the impact of the early retirement program) and will be charged to earnings.
1 Trust assets are primarily common stocks, corporate and govemment bonds, and short-term investments.
4 l
The funded status of these benefits is reconciled to the recorded liability below; j
in millions December 31, 1997 1996 Actuarial present value of benefit obilgation:
Retirees
$1,000
$ 928 Employees eligible to retire 45 35 Other employees 488 386 Accumulated benefit obligation
$1,533
$1,349 Fait value of plan assets S 815
$ 617 Plan assets less than accumulated benefit obligation
$ 718
$ 732 Unrecognized transition obligation (403)
(430)
Unrecognized net gain (loss) -
(244)
(231)
Recorded liability
$ 71
$ 71 Discount rate 7.0%
7.75 %
Expected long-term rate of retum on assets 8.0%
8.5%
35 l
J
Not:s to Consolidated Financial Statem:nts The components of postretirement benefits other than pensions expense were:
In millions Year ended December 31, 1997 1996 1995 Service cost for benefits eamed
$ 30
$ 31
$ 35 99 90 77 Interest cost on benefit obligation Actual retum on plan assets (50)
(43)
(28) 4 6
1 Amortization of loss 27 27 27 Amortization of transition obligation 110 111 112 Not expense 72 Specialtermination expense
$110
$183
$112 Total expense The assumed rate of future increases in the per-capita cost of health care benefits is 8.5% for 1998, gradually decreasing to 5.25% for 2004 and beyond. Increasing the health care cost trend rate by one percentage point would increase the accumulated obligation as of December 31,1997, by $255 million annual aggregate service and interest costs by $28 million.
Employee Savings Plan SCE has a 401(k) defined contribution savings plan designed to supplement employees' retirement income. The plan received employer contributions of $15 million in 1997, $24 million in 1996 and
$19 million in 1995.
Note 7. Jointly Owned Utility Projects SCE owns interests in several generating stations and transmission systems for which each participant provides its own financing. SCE's share of expenses for each project is included in the consolidated statements of income.
The investment in each project, as ;ncluded in the consolidated balance sheet as of December 31,1997, was:
Plant in Accumulated Under Ownership In millions Service Depreciation Construction Interest Transmission systems:
Eldorado 28 9
3 60 %
Pacific Intertie 241 75 1
50 Generating stations:
Four Corners Units 4 and 5 (coal) 459 247 3
48 Mohave (coal) 307 146 5
56 Palo Verdo (nuclear) 1,601 665 9
16 San Onofre (nuclear) 4,212 2.210 38 75 Total
$6,848
$3,352
$ 59 I
36
Southern CalifoC 4 Edlaon Company Note 8. Leases j
SCE has operating leases, primarily for vehicles, with varying terms, provisions and expiration dates.
Estimated remaining commitments for noncancellable leases at December 31,1997, were:
Yrar ended December 31,
!n millions 1998
$15 1999 12 2000 10 2001 6
2002 3
Thereafter 5
Total
~
$31 Note 9. Commitments NuclearDecommissioning SCE plans to decommission its nuclear generat!ng facilities at the end of each facility's operating license by a prompt removai inethod authorized by the Nuclear Regulatory Coramission. Decommissioning is cstimated to cost $2.1 billion in current year dollars, based on site-specific studies performed in 1993 for j
San Onofre and 1992 for Palo Verde. Changes in the estimated costs, timing of decommissioning, or the
)
assumptions underlying these estimates could cause material revisions to the estimated total cost to decommission in the near term. Decommissioning is scheduled to begin in 2013 at San Onofre and 2024 at Palo Verde. San Onofre Unit 1, which shut down in 1992, is expected to be secured until decommissioning begins at the other San Onofre units.
Decommissioning costs, which are accrued and recovered through non-bypassable customer rates over the term of each nuclear facility's operating license, are recorded as a component of depreciation expense. Decommissioning expense was $154 million in 1997, $148 million in 1996 and $151 million in 1995. The accumulated provision for decommissioning was $1.1 billion at December 31,1997, and
$949 million at December 31, 1906. The estimated costs to decommission San Onofre Unit 1
($280 million) are recorded as a liability.
Decommissioning funds collected in rates are placed in independent trusts, which, together with accumulated eamings, will be utilized solely for decommissioning.
Trust investments include:
Maturity December 31.
In millions Dates 1997 1996 Municipalbonds 1998-2026
$ 459
$ 400 Stocks 392 549 U.S. government issues 1998-2027 357 212 Short-term and e.her 2002-2003 163 56 Total
$1,371
$1,217 37 l
s Notes t3 Consolidated Fintncial StatemInta Trust fund earnings (based on specific identification) increase the trust fund balance and the accumulated provision for decommissioning. Net earnings were $54 million, $49 million and $51 million for the years ended 1997,1996 and 1995, respectively. Proceeds from sales of securities (which are reinvested) were
$595 million for 1997, and $1.0 bilhon for 1996 and 1995. Approximately 89% of the trust fund contributions were tax-deductible.
The Financial Accounting Standards Board has issued an exposure draft related to accounting practices for removal costs, including decommissioning of nuclear power plants. The exposure draft would require SCE to report its estimated decommissioning costs as a liability, rather than recognizing these costs over th3 term of each facility's operating license (current industry practice). SCE does not believe that the changes proposed in the exposure draft would have an adverse effect on its results of operations even after deregulation due to its current and expected future ability to recover these costs through customer rates.
Other Commitments SCE has fuel supply contracts which require payment only if the fuel is made available for purchase.
SCE has power-purchase contracts with certain QCs (cogenerators and small power producers) and other utilities. The OF contracts provide for capacity payments if a facility meets certain performance obligations and energy payments based on actual power supplied to SCE. There are no requirements to make debt service payments.
SCE has unconditional purchase obligations for part of a power plant's generating output, as well as firm transmission service from another utility. Minimum payments are based, in part, on the debt-service requirements of the provider, whether or not the plant or transmission line is operable. The purchased-power contract is not expected to provide more than 5% of current or estimated future operating capacity.
SCE's minimum commitment under both contracts is approximately $193 million through 2017.
Certain commitments for the years 1998 through 2002 are estimated below:
1 in millions 1998 1999 2000 2001 2002 Projected construction expenditures
$956
$807
$763
$721
$671 Fuel supply contracts 228 146 167 154 163 Purchased-power capacity payments 686 711 714 716 714 Unconditional purchase obligations 9
9 10 9
10 1
i Note 10. Contingencies In addition to the matters disc losed in these notes, SCE is involved in legal, tax and regulatory proceedings before various courts and govemmental agencies regarding matters arising in the ordinary course of business. SCE believes the outcome of these proceedings will not materially affect its results of opeations or liquidity.
I EnvironmentalProtection l
SCE is subject to numerous environmental laws and regulations, which requ!re it to incur substantial l
costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment.
l l
38
p e
Southern California Edison Company l
SCE records its environmental liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. SCE reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently i
available information, including existing technology, presently enacted laws and regulations, experience cained at similar sites, and the probable level of involvement and financial condition of other potentially rcsponsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, SCE records the lower cnd of this reasonably likely range of costs (classified as other long-term liabilities at undiscounted amounts). While SCE has numerous insurance policies that it believes may provide coverage for some of these liabilities, it does not recognize recoveries in its financial statements until they are realized.
In connection with the issuance of the San Onofre Units 2 and 3 operating permits, SCE reached an agreement with the Califomia Coastal Commission in 1991 to restore certain marine mitigation sites. The i
restorations include two sites: designated wetlands and the construction of an artificial kelp reef off the Califomia coast. After SCE requested certain modifications to the agreement, the Coastal Commission issued a final ruling in April 1997 to reduce the scope of remediations. SCE elected to pay for the costs 1
of marine mitigation in lieu of placing the funds into a trust. Rate recovery of these costs is occurring j
through the San Onofre incentive pricing plan discussed in Note 1 to the Consolidated Financial i
Statements.
j SCE's recorded estimated minimum liability to remediate its 50 identified sites is $178 million, which i
includes $75 million for the two sites discussed above. The ultimate costs to clean up SCE's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation
]
process, such as: the extent and nature of contamination, the scarcity of reliable data for identified sites; tha varying costs of attemative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and the time periods over which site remediation is expected to occur. SCE believes that, due to these uncertainties, it is ceasonably possible that cleanup costs could exceed its recorded liability by up to $246 million. The upper limit of this range of costs was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes.
Tho CPUC allows SCE to recover environmente.! cleanup costs at 41 of its sites, representing $91 milhon of its recorded liability, through an incentive mechanism (SCE may request to include additional sites).
Under this mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders i
fund the remaining 10%, with the opportunity to recover these costs from insurance carriers and other l
third parties. SCE has successfully settled insurance claims with all responsible carriers. Costs incurred at SCE's remaining sites are expected to be recovered through customer rates. SCE has recorded a regulatory asset of $153 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates. This amount includes $60 million of marine mitigation costs remaining to be recovered through the San Onofre incentive pricing plan.
I SCE's identified sites include several sites for which there is a lack of currently available informat on, j
including the nature and magnitude of contamination, and the extent, if any, that SCE may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable cstimate of cleanup costs can now be made for these sites.
j l
SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of i
Qe next several years are expected to range from $4 million to $10 million. Recorded costs for 1997 were $10 million, i
Based on currently available information, SCE believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range and, based upon the CPUC's regulatory treatment of environmental-cleanup costs, SCE believes that costs ultimately recorded will not materially affect its results of operations or financial position.
There can be no assurance, however, that future 39
1%tts to Consolid:ted Financitt StatIments developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates.
NuclearInsurance Federallaw limits public liability claims from a nuclear incident to $8.9 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available
($200 million). The balance is covered by the industry's retrospective rating plan that uses deferred premium charges to every reactor licensee if a nuclear incident at any licensed reactor in the U.S. results in claims and'or costs which exceed the primary insurance at that plant site. Federal regulations require this secondary isvel of financial protection. The Nuclear Regulatory Commission exempted San Onofre Unit i from this se,ondary level, effective June 1994. The maximum deferred premium for each nuclear incident is $79 million per reactor, but not more than $10 million per reactor may be charged in any one year for each incident. Based on its ownership interests, SCE could be required to pay a maximum of
$158 million per nuclear incident. However, it would have to pay no more than $20 million per incident in any one year. Such amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and are subject to adjustment for inflation. If the public liability limit above is insufficient, federal regulations may impose further revenue-raising measures to pay claims, including a possible j
additional assessment on all licensed reactor operators.
Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary
$500 million also has been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage.
These policies are issued primarily by mutual insurance companies owned by utilities with nuclear facilities. If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to
$28 million per year, insurance premiums are charged to operating expense.
Quarterly Financial Data 1997 1996 In millions Total Fourth Third Second First Total Fourth Third Second First Operating revenue
$7,953
$1,980 $2.434 $1,844
$1,695 $7,583 $1,866 $2,346
$1,611
$1,760 Operating income 1,060 248 349 229 234 1,133 231 382 257 263 Netincome 606 123 233 129 121 655 121 256 131 147 Eamings available for common stock 576 116 226 122 112 621 113 247 123 138 Common dividends declared 1.829 1.266 217 171 175 735 196 178 180 181 40
R:sponsibility far Financial Reporting The management.of Southern California Edison Company (SCE) is responsible for the integrity and objectivity of the accompanying financial statements. The statements have been prepared in accordance with generally accepted accounting principles applied on a consistent basis and are based, in part, on management estimates and judgrnent.
SCE maintains systems of intemai control to provide reasonable, but not absolute, assurance that assets are safeguarded, transactions are executed in accordance with management's authorization and the accountity records may be relied upon for the preparation of the financial statements. There are limits inherent in al: systems of internal control, the design of which involves management's judgment and the recognition that the costs of such systems should not exceed the benefits to be derived. SCE believes its systems of internal control achieve this appropriate balanca. These systems are augmented by internal audit programs through which the adequacy and effectiveness of internal controls and policies and procedures are monitored, evaluated and reported to management. Actions are taken to correct deficiencies as they are identified.
SCE's independent public accountant::, Arthur Andersen LLP, are engaged to audit the financial statements in accordance with generally accepted auditing standards and to express an informed opinion on the faimess, in all material respects, of SCE's reported results of operations, cash flows and financial position.
As a further measure to assure the ongoing objectivity of financialinformation, the audit committee of the board of directors, which is composed of outside directors, meets periodica!!y, both jointly and separately, with management, the independent public accountants and internal auditors, who have restricted access to the committee. The committee recommends annually to the board of directors the appointment of a firm of independent public accountants to conduct audits of its financial statements; considers the independence of such firm and the overall adequacy of the audit scope and SCE's systems of internal control; reviews financial reporting issues; and is advised of management's actions regarding financial reporting and internal control matters.
SCE maintains high standards in selecting, training and developing personnel to assure that its operations are conducted in conformity with applicable laws and is committed to maintaining the highest standards of personal and corporate conduct. Management maintains programs tc, encourage and assess compliance with these standards.
f
(
Richard K Bushey John E. Bryson Vice President Chairman of the Board and Controller and Chief Executive Officer January 30,1998 41
a.
O southern camornia Edison company Report cf Independent Public Acc:untants To the Shareholders and the Board of Directors, Southern California Edison Company:
We have audited the accompanying consolidated balance sheets of Southern California Edison Company (SCE, a Califomia corporation) and its subsidiaries as of December 31,1997, and 1996, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1997.
These financial statements are the respcnsibility of SCE's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conductW our audits :n accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall fir,ancial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of SCE and its subsidiaries as of December 31,1997, and 1996, and the results of their operations and their cash flows for each of the three years in the period ended Decemoer 31,1997, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP l
Los Angeles, California January 30,1998 l
l l
l l
s 42 l
e Board cf Direct:rS Southern California EdlSon Company John E. Bryson Carl F. Huntainger E. L Shannon, Jr.
Chairrnan of the Board and CEO, General Partner, Retired Chairman of the Board, Edison internadonaland SCE DAE Urn 6ted Partnership Ltd.,
Santa Fe intomational Corporation, Ojal, Canfomia Alharnbra, CaNfomia Winston H. Chen Chairrnen of the Par mitas Foundation Charles D. Miller.
Robert H. Smith and Chairman of Pr amitas Chairman of the Board and CEO, Managing Director, Irwestment Corpora 6on, Avery DerrJson Corporation.
Smith and Crowley incorporated, Santa Clara, Califorma Pasadena, Canfomia Pasadena. CallLmia Warren Chrtetopher Luis G. Nogales Thomas C. Sutton Senior Partner, Pissident, Chairman of the Board and CEO.
O'Melveny & Myers, Nogales Partners, Pacific Ufo insurance Company, Los Angeles, Cantornia Los Angeles, California Newport Beach, Califomia Stephen E. Frank Ronald L Olson Daniel M. Tellop President and Chief Operating Senior Partner, Retired Chairman of the Board, Officer, SCE Munger Tolles and Olson, Lockheed Martin Corporation, Los Angeles, Cakfomia Bethesda, Maryland Camlila C. Froot*
Trustee, Chandler Trusts, J. J. Pinole
- James D.Watkine Director and Secretary-Treasurer, Retired Chairman of the Admiral USN, Retired i
Chandis Secunues Company, Board and CEO, President, Joint Oceanographic Los Angeles, CaNfornia First interstate Bancorp, institutions,Inc and President, Los Angeles, Cahfornia Consortum for Oceanographic Joan C. Henley Research and Education General Partner, James M. Roseer Washington, D.C.
Mramonte Vineyards, President, Rancho Palos Verdes, Califomia California State University, Los Angeles, Edward Zapants, M.D, Los Angeles, California Physician a o Neurosurgeon,
- Rodring on Aprg 16,1998 Torrance, Califomia Management Team John E Bryson Robwt G. Foster Lawrence D. Hamlin Chairman of the Board and CEO Senior h President, h President, Power Production Public Affairs j
Stephen E. Frank Thomas J. Higgine President and Chief Operating Officer Richard M. Rosenblum h President, Senior Vice President, Corporate Communications Bryant C. Denner T&D Wires Business Unit Executive Vice President and R. W. Kriegw General Counsel Emiko Banfleid h President, Nuclear Generation h President, Shared Services Alan J. Fohrer J. Michael Mendez Execuuve h President and Pamela A. Base Vice President, Labor Relations Chief Financial Officer Vice President, Customer Solutions Business Unit Dwight E. Nunn Harold B. Ray h President, Nuclear Engineering ExeevWye h President, Richard K. Bushey and Technical Services i
Generation Business Unit h President and Controuer Frank J. Quevedo Theodore F. Crevw, Jr.
Bruce C. Footw h President, Equal Opportunity Senior h President and Treasurer b President, San Francisco Regulatory Affairs Mahvash Yardi John R. Fleider h President and Chief Senior b President, Lillian R. Gorman information Officer Regulatory Polley and Affairs
% President, Human Resources Bevwly P. Ryder Corporate Secretary 43
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=. 5 e ,4> ' ~ g j ' W,, c e s-, ,t s r.- e y $ q h 9 fl6 e, ~ '., 1; ; f o, p Y = h. & - o h*., 9 k{:" 11 t ' h n r 4 e i Sh:;rcholdar Information Annual Meeting of Shareholders Thursday, April 16,1998 10:00 a.m. The industry Hills Sheraton Resort and Conference Center One Industry Hills Parkway City of Industry, California Stock Listing and Trading Information SCP. Preferred Stock The American and Pacific stock exchanges use the ticker symbol SCE. Previous day's closing prices, when traded, are listed in the daily newspapers in the American Stock Exchange table under the symbol SoCalEd. The 6.05%, 6.45% and 7.23% series are not listed. Where to Buy and Seil Stock The listed preferred stocks may be purchased through any brokerage firm. Fi ms handling unlisted series can be located through your broker. Transfer Agent and Registrar Southern Califomia Edison Company maintains shareholder records and is transfer agent and registrar for SCE preferred stock. Shareholders may call Shareholder Services, (800) 347-8625, between 8:00 a.m. and 4:00 p.m. (Pacific time) every business day, regarding: stock transfer and name-change requirements; e address changes, including dividend addresses; e electronic deposit of dividends; e taxpayer identification number submission or changes; e duplicate 1)99 forms and W-9 forms; e notices of and replacement of lost or destroyed stock certificates; e dividend checks; e requests to eliminate multiple annual report mailings; and e request access to online account information via Edison Intemational's internet Home Page, e www.edisonx.com The address of Shareholder Ser/ ices is: P.O. Box 400, Rosemead, Califomia 91770-0400 FAX: (626) 302-4815 ~ s SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 /ORM 10-K /X/ Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 1997 Cormiasion File Number 1-2313 SOUTHERN CALIFORNIA EDISON COMPANY (Exact neee of registrant as specifferf in its charter) california 95-1240335 (state or other jurisdiction of (I.it.S. Employer incorporation or orsanization) Identification No.) 2244 Walnut Grove Avenue (626) 302-1212 Rosemead, California 91770 (nesistrant's telephone number, (Address of principal executive offices) (Zip code) including aree code) Securities registered pursuant to Section 12(b) of the Act: Name of each exchange Title of each class an d.fch registered Capita" stock L'umulative Preferred $100 cumulative Preferred American and Pacific 4.081 teries 4.781 series 6.05% series 4.24% teries 5.80% series 6.45% series
- .32%.leries 7.23% series 14curities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes (I) No [ ]
Indicette by check man if disclosure of delinquent filers pursuant to Item 405 cd Regulation S-K is not contained herein, and will not be contained, to tt o best of registrant's knowledge, in definitive proxy or information statelsents incorporated by reference in Part III of this Form 10-K or any amanusent to this Form 10-K. [ ] As of March 23, 1998 there were 434,888,104 shares of Common Stock outstanding, all of which are held by the registrant's parent holding company. The aggregate market value of registrant's voting stock held by non-affiliates was approximately $426,452,116 on or about March 23, 1998 based upon prices reported by the American Stock Exchange. The market values. of the various classes of voting stock held by non-affiliates were as follows: CUMULATIVE PREFERRED STOCK $151,452,116; $100 CUMULATIVE PREFERRED STOCK $275,000,000. DOCUMENTS INCORPORATED BY REFERENCE Portions of the following documents listed below have been incorporated by reference into the parts of this report so indicated. (1) Designated portions of the Annual Report to Shareholders for the year ended December 31, 1997 Parts I, II and IV (2) Designated portions of the Joint Proxy Statement relating to registrant's 1998 Annual Meeting of Shareholders Part III / TABLE OF CONTENTS Item Pays Part I 1. Business 1 1 Competitive Environment 7 Regulation 9 Rate Matters Fuel Supply and Purchased Power Costs 13 Environmental Matters 14 Year 2000 Issue 17 17 2. Properties Existing Generating Facilities 17 Construction Program and Capital Expenditures 19 Nuclear Power Matters 19 22 3.- Legal Proceedings Qualifying Facilities Litigation 22 Wind Generators' Litigation 23 Geothermal Generators' Litigation 24 Electric and Magnetic Fields (EMF) Litigation 25 San Onofre Personal Injury Litigation 26 i Oil Pipeline Litigation 28 False Claims Act Litigation 28 Mohave Generating Station Environmental Litigation 28 4. Submission of Matters to a Vote of Security Holders 29 Executive Officers of the Registrant 29 Part II 5. Market for Registrant's Common Equity and Related 31 Stockholder Matters 6. Selected Financial Data 31 7. Management's Discussion and Analysis of Results of 31 Operations and Financial Condition 8. Financial Statements and Supplementary Data 31 9. Changes in and Disagreements with Accountants on 31 Accounting and Financial Disclosure Part III 10. Directors and Executive Officers of the Registrant 31 31 11. Executive Compensation 12. Security ownership of Certain Beneficial 32 owners and Managemsnt 13. Certain Relationships and Related Transactions 32 Part IV 14. Exhibits, Financial Statement Schedules, and 32 Reports on Form 8-K Report of Independent Public Accountants on 33 Supplemental Schedules 34 Supplemental Schedules 37 Signatures 38 Exhibit Index ( s PART I In this form 10-K, Southern California Edison Company (SCE) uses the words estimates, expects, anticipates, believes, and other similar expressions that are intended to identify forward-looking information that involves risks and uncertainties. Actual recults or outcomes could differ materially as a result of such important factors as further actions by state and federal regulatory bodies setting rates and implementing the restructuring of the electric utility industry; the effects of new laws and regulations relating to restructuring and other matters; the effects of increased competition in the electric utility business, including the beginning of direct customer access to retail energy suppliers and the unbundling of revenue cycle services such as metering and billing; changes in prices of electricity and fuel costs; changes in market interest rates; new or increased environmental liabilities; and other unforeseen events. Item 1. Business SCE was incorporated under California law in 1909. SCE is a public utility primarily engaged in the business of supplying electric energy to a 50,000 square-mile area of Central and Southern California, excluding the City of Los Angeles and certain other cities. This area includes some 800 cities and communities and a population of more than 11 million people. SCZ had 12,642 full-time employees at year-end 1997. During 1997, 38% of SCE's total operating revenue was derived from residential customers, 38% from commercial customers, 12% from industrial customers, 7% from public authorities, 4% from agricultural and other customers and 1% from resale customers. SCE comprises the major portion of the assets and revenue of Edison International, its parent holding company. Competitive Environment SCE currently operates in a highly regulated environment in which it has an obligation to deliver electric service to customers in return for an exclusive franchise within its' service territory. This regulatory environment is changing. The generation sector has experienced competition from nonutility power producers and regulators are restructuring California 's electric utility industry. California Electric Utility Restructuring Restructuring Decision - The California Public Utilities Commission's (CPUC) December 1995 decision on restructuring California's electric utility industry started the transition to a new market structure, which is expected to provide competition and customer choice and is scheduled to begin March 31, 1998. Key elements of the CPUC's restructuring decision included: creation of,an independent power exchange (PX) and independent system operator (Iso); availability of direct customer access and customer choice; performance-based ratemaking (PBR) for those utility services not subject to competition; voluntary divestiture of at least 50% of utilities' gas-fueled generation, and implementation of the competition transition charge (CTC). Restructuring Legislation - In September 1996, the State of California enacted legislation to provide a transition to a competitive market structure. The legislation substantially adopted the CPUC December 1995 restructuring decision by addressing stranded-cost recovery for utilities and providing a certain cost-recovery time period for the transition costs associated with utility-owned generation-related assets. Transition costs related to power-purchase contracts would be recovered through the terms of their contracts while most of the remaining transition costs would be recovered through 2001. The legislation also included provisions to finance a portion of the stranded costs that residential and small commercial customers would have paid between 1998 and 2001, which would allow SCE to reduce rates by at least 10% to these customers, beginning January 1, 1998. The financing would occur with securities issued by the 1 s e California Infrastructure and Economic Development Bank (Bank), or an entity approved by the Bank. The legislation included a rate freeze for all other customers, including large commercial and industrial customers, as well as nrovisions for continued funding for energy conservation, low-income pJograms and renewable resources. Despite the rate freeze, SCE expects to be able to recover its revenue requirement during the 1998-20C1 transition period. In
- addition, the legislation mandated ti.e implementation of the CTC that provides utilities the opportunity to recover costs made uneconomic by electric utility restructuring. Finally, the legislation contained provisions for the recovery (through 2006) of reasonable employee-related transition costs, incurred and projected, for retraining, severance, early retirement, outplacement and related expenses.
Rate Reduction Notes - In May 1997, SCE filed an application with the CPUC requesting approval of the issuance of an aggregate amount of up to $3 billion of rate reduction notes in one or more series or classes and a 10% rate reduction for the period from January 1, 1998, through March 31, 2002. At the same time, SCE filed an application with the Esnk for approval to issue the notes. Residential and small commercial customers will repay the notes over the expected 10 year term through non-bypassable charges based on electr h y consumption. In December 1997, after receiving approval from both the CPUC and the Bank, a limited liability company created by SCE issued approximately 02.5 billion of these notes. Rate-setting - In December 1996, SCE filed a more comprehensive plan (elaborating on its July 1996 filing related to the conceptual aspects of l separating costs as requested by CPUC and Federal Energy Regulatory Commission (FERC) directives) for the functional unbundling of its rates for electric service, beginning January 1, 1998. In response to CPUC and FERC orders, as well as the new restructuring legislation, this filing addressed the implementation-level detail for the functional unbundling of rates into separate charges for energy, transmission, distribution, the
- CTC, public benefit programs and nuclear decommissioning.
The transmission component of this rate unbundling process was addressed at the FERC through t March 1997 filing. In December 1997, the FERC approved these rates, subject to refund, to be effective on the date the ISO begins operation. (See " Transmission owners Tariff and Wholesale Distribution Access Tarif f" below for fur' her discussion. ) CPUC hearings on SCE's rate c unbundling (also known as rate-setting) plan were concluded in April 1997. In Argust 1997, the CPUC issued a decision which adopted the methodology for. tet.ermining CTC residually (see "CTC" discussion) and adopted SCE's revi nua requirement components for public benefit programs and nuclear decommissioning. The decision also adjusted SCE's proposed distribution revsnue requirement by reallocating $76 million of it annually to other functions such as generation and transmission. Under the decision, OCE will be able to recover most of the reallocated amount through market revenue, other rate-making mechanisms after petitioning the CPUC to modify its prior decisions, or another review process later in its divestiture proceeding. PX and ISO - In April 1996, SCE, Pacific Gas and Electric Company (PG&E) and San Diego Gas & Electric Company (SDG&E) filed a propcccl with the FERC regarding the creation of the FX and the ISO. In Novembe* 1996, the FERC conditionally accepted the proposal and directed the three atilities, the ISO, and the PX to file more specific information. The filing was made in March 1997, and included 3CE's proposed transmission revenue requirement. On October 29, 1997, the FERC gave cond'.tional, interim authorization for operation of the PX and ISO, which are new independent non profit California corporations, to begin on January 1,1998. Prior to the start of the ISO and PX, the chief executive officers of the PX, ISO and the three utilities cre required to certify that all the conditions were in place to ensure rel.atle electiic power operations. In addition, the FERC stated it would closely monitor the PX and ISO, require further 2 ~ s-studies and make modifications, where necessary. A comprehensive review will be performed by the FERC after three years of operation of the PX and ISO. On December 22, 1997, the PX and ISO governing boards announced a delay in the planned start-up of the PX and ISO due to insufficient j testing of operational, settlement and billing systems. The PX and ISO are now expected to begin operation by March 31, 1998. I j In July 1996, the three utilities jointly filed an application with the j CPUC requesting approval to establish a restructuring trust which would j obtain loans up to $250 million for the development of the ISO and PX j through January 1, 1998. The-loans are backed by utility guarantees; i SCE's share was 45%, or $113 million. In August 1996, the CPUC issued an interim order establishing the restructuring trust and the funding level of $250 million, which has been used to build the hardware and softwara i systems for the ISO and PX. The ISO and PX will repay the trust's loe, and recover funds from futurp ISO and PX customers. In November 1997, i the CPUC approved a petition jointly filed by the three utilities which requested an increase in the loan guarantees from $250 million to $300 million; SCE's share of this new total is $135 million. In December 1997, the CPUC approved a~ remaining issue with respect to the petition which requested that the one-time restructuring implementation charge, to be paid to the PX by the utilities, be deemed a non-bypassable charge to be recovered from all retail customers. The amount of the PX charge is approximately $101 million, plus interest; SCE's share is 45%, or $45.5 million. Direct Customer Access In May 1997, the CPUC issued a decision describing how all California investor-owned-utility customers will be able to choose who will provide them with electric generation service beginning January 1, 1998. On December 30, 1997, the CPUC issued a decision delaying direct access until March 31, 1998, due to operational delays in the startup of the PX and ISO. When the PX and ISO become operational, customers will be able to choose to remain utility customers with bundled electric service from SCE (which will purchase its power through the PX), or choose direct access, which means the customer can contract directly with either independent porer producers or retail electric-service providers such as power brokers, marketers and aggregaters. Additionally, all investor-owned utility customers must pay l l the CTC whether or not they choose to buy power through SCE. Electric utilities will continue to provide the core distribution service of delivering energy through their distribution systems regardless of a customer's choice of electricity supplier. The CPUC will continue to regulate the prices and service obligations related to distribution services. If the new competitive market cannot accommodate the volume of direct access transactions, the CPUC could inplement a contingency plan. However, the CPUC indicated that it believes it is likely that interest in and migration to direct access will be gradual. Revenue cycle Services - A decision issued by the CPUC in May 1997, introduces customer ' choice to metering, billing and related services (revenue cycle services) that are now provided by California's investor-owned utilities. Under this revenue cycle services unbundline decision, beginning in January 1998, direct access customers may choc.,Je to have either SCE or their electric generation service provider render consolidated (energy and distribution) bills, or they may choose to have separate billings from each service provider. However, not all electric generation service providers will necessarily offer each billing option. In addition, beginning in January 1998, customers with maximum demand above 20 kW (primarily industrial and large commercial) can choose SCE or any other supplier to provide their metering service. All other customers will have this option beginning in January 1999. Since direct access was delayed, options described in the CPUC decision as becoming available January 1, 1998, will not be available until the PX and ISO become operational. In determining whether any credit should be provided by the utility to firms providing customers with revenue cycle services, and 'the amount of any such credit, the CPUC has indicated that it.is 3 e appropriate to net the cost incurred by the utility and the cost avoided by the utility as a result of such services being provided by the other firm rather than by the utility. The unbundling of revenue cycle services will expose SCE to the possible loss of revenue, higher stranded costs and a reduction in revenue security. PBR - In 1993, SCE filed for a PBR mechanism to determine most of its revenue (excluding fuel). The filing was subsequently divided between transmission and distribution (T&D) and power generation. In September 1996, the CPUC adopted a non-generation or T&D PBR mechanism for SCE which began on January 1, 1997. According to the CPUC, beginning in 1998 (coincident with the initiation of the competitive m'-ket), the transmission portion is to be separated from non-generatton PBR and 4 subject to ratemaking under the rules of the FERC. The distc ' S nion-only PBR will extend through December 2001. Key elements of the non-generation PBR include: T&D rates indexed for inflation based on the Consumer Price Index less a productivity factor; elimination of the kilowatt-hour sales adjustment; adjustments for cost changes that are not within SCE's control; a cost of capital trigger mechanism based on changes in a bond index; standards for service reliability and safety; and a net revenue-sharing mechanism that determines how customers and shareholders will share gains and losses from T&D operations. With the CPUC's 1995 restructuring decision and the passage of restructuring legislation in 1996, the majority of power generation was assigned to other ratemaking (primarily fossil-fueled and nuclear) mechanisms. In April 1997, a CPUC interim order determined that the proposed structure of the fossil-fueled plants' must-run contracts were under the FERC's jurisdiction. On October 31, 1997, SCE filsd must-run tariff schedules with the FERC covering its six ISO-designatad must-run plants. In the meantime, SCE is pursuing the divestiture of these plants (see " Divestiture" discussion) and might not ever itself provide service under these FERC tariff schedules. In December 1997, the CPUC adopted a PBR-type rate-making mechanism for SCE 's hydroelectric plants. The mechanism sets the hydroelectric revenue requirement in 1998 and establirhas a formula for extending it through the duration of the electric industry restructuring transition period, or until market valuation of the hydroelectric facilities, whichever occurs first. The mechanism provides that power sales revenue fro:n hydroelectric facilities in excess of the hydroelectric revenue requirement be credited against the costs to transition to a competitive market (see "CTC" discussion). The CPUC has announced its intention to unbundle SCE's cost of capital by rajor utility function and has dirceted SCE to file an application by May 8, 1998. This proceeding could result in a change in latn 1998 or early 1999 to the cost of capital included within the PBR cost of capital trigger mechanism. Divestiture - In November 1996, SCE filed an application with the CPUC to voluntarily divest, by auction, all 12 of its oil-and gas-fueled generating plants. This application built upon SCE's March 1996 plan which outlined how SCE proposed to divest 50% of these assets. SCE would continue to operate and maintain the divested plants for at least two years following their sale, as mandated by the restructuring legislation enacted in September 1996. In addition, SCE would offer workforce transition programs to those employees who may be' impacted by divestiture-related job reductions. In September 1997, the CPUC approved SCE's propesal to auction the 12 plants. On December 1, 1997, SCE filed a compliance' filing with the CPUC stating that it agreed to sell ten plants. On December 16, 1997, the CPUC approved the sale of the ten plants. On February 6, 1998, SCE filed a 4 t-- compliance filing with the CPUC for the sale of an eleventh plant. CPUC approval of the sale is expected before March 31, 1998. The total sales price of the eleven plants is $1.1 billion er 2.16 times their combined book value of $531 million. Net proceeds of the sales will be used to reduce stranded costs, which otherwise were expected to be collected through the CTC mechanism. The transfer of ownership of the eleven plants is expected to occur concurrently with the start of the new competitive market, which the PX and ISO expect to occur on March 31, 1998. The process of selling the single remaining plant is still underway. CTC - Recovery of costs to transition to a competitive market is being implemented through a non-bypassable CTC. This charge applies to all customers who were using or began using utility services on or after the CPUC's December 20, 1995, decision date. In August 1996, in compliance with the CV1C's restructuring decision, SCE filed its application to estimate its 1998 transition costs. In October 1996, SCE amended its transition cost filing to reflect the effects of the legislation enacted in September 1996. Under the rate freeze codified in the legislation, the CTC will be deterrined residually (i.e., after subtracting other cost components for the energiy from PX, TLD, nuclsar decommissioning and public bonefit programs). Nevertheless, the CPUC directed that the amended application provide estimates of SCE's potential transition costs from 1998 through 2030. SCE provided two estimates between approximately $13.1 billion (1998 not present value) assuming the fousil plants have a market value equ-l to their not book value, and $13.8 billion (1998 not present value) asm tming the fossil plants have no market value. These estimates are based on incurred costs, forecasts of future coste and assumed market prices. However, changes in the assumed market prices could materially i affect these estimates. The potential transition costs are composed of $7.5 billion from SCE's qualifying facility (QF) contracts, which are the direct result of prior legislative and regulatory mandates; and $5.6 billion to $6.3 billion from costs pertaining to certain generating plants (successful completion of the sale of SCE's gas-fired generating plants would reduce this estimate of transition costs for SCE-owned generation to less than SS billion) and regulatory commitments consisting of costs incurred (whose recovery has been deferred by the CPUC) to provide service to customers. Such commitments include the recovery of income tax benefits previously flowed through to customers, postratirement benefit transition costs, accelerated recovery of San Onofre Nuclear Generating Station Units 2 and 3 and the Palo Verde Nuclear Generating Station units, and certain other costs. In February 1997, SCE filed an update to the CTC filing to reflect approval by the CPUC of settlements regarding ratomaking for SCE's share of Palo Verde and the buyout of a power purchase agreement, as well as other minor data updates. No substantive changes in the total CTC estimates were included. This issue has been separated into i two phases; Phase 1 addresses the rate-making issues and Phase 2 the quantification issues. A decision on Phase 1 was issued in June 1997, which, among other things, required the establishment of a transition cost balancing aeount and annual transition cost proceedings, set a market rate forecast for 1998 i transition costs, and required that generation-related regulatory assets l be amortized ratably over a 48-month period. Hearings on Phase 2 were held in May and June 1997.and a final decision was issued on November 19, 1997. The Phase 2 decision established the calculation methodologies and procedures for SCE to collect its transition costs from 1998 through the end of the rate freeze. The Phase 2 decision also reduced SCE's authorized rate of return on certain assets eligible for transition cost recovery (primarily fossil-and hydroelectric-generation related assets) beginning July 1997, five months earlier than anticipated. The decision, excluding the effects of other rate actions, had a negative impact on 1997 earnings of approximately $14 million. SCE has filed an application for rehearing on the 1997 rate of return issue. 5 s 9 Utility Rate Reduction and Reform Act Initiative - On November 24, 1997, individuals representing The Utility Reform Network (TURN), Public Media Center and the Coalition Against Utility Taxes filed a voter initiative with the California Attorney General. The proposed initiative, which was amended by the proponents on December 9, 1997, seeks among other things to: (i) impose an additional 10 percent rate reduction; (ii) block stranded cost recovery of nuclear investments; (iii) restrict stranded cost recovery of non-nuclear investments unless the CPUC finds that the utility would be deprived of the opportunity to earn a fair rate of return; and (iv) prohibit the collection of any charges pursuant to a financing order for the purpose of making payments on rate reduction notes, or if the financing order is found anforceable by a court, require the utility to offset such charges with an equal credit to customers. On Februa ry 11, 1998, the California Secretary of State circulated a copy of the title and summary prepared for the proposed initiative by the California Attorney General's Office, which included a summary of estimate of the fiscal impacts on etete and local governments if the initiative were to pass. That estits concluded that the net impact on state government revenue would be annual revenue reductions of approximately $100 million per fiscal year from 1998-2002. The estimate also referred to potential state liability for debt service on the rate reduction notes. The earliest that the initiative could be placed on a statewide ballot is November 3, 1998. SCE is unable to predict the outcome of this matter, but if the initiative were to qualify for the ballot, be voted into law and upheld by courts, it could have a material effect on its results of operations. Accounting for Generation-Related Assets - If the CPUC's electric industry restructuring plan is implemented as outlined above, SCE would be allowed to recover its CTC through non-bypassable charges to its distribution customers (although its invest.aent in certain generation assets would be subject to a lower authorized rate of return). From November 1996 to July 1997, SCE and the other major California electric utilities were engaged in discussions with the Securities and Exchange Commission (SEC) staff regarding the proper application of regulatory accounting standar3s in light of the electric industry restructuring legislation enacted by the State of California in September 1996 and the CPUC's electric industry restructuring plan. This issue was placed on the agenda of the Financial Accounting Standards Board's Emerging Issues Task Force (EITF) during April 1997 and a final consensus was reached at the July EITF meeting. During the third quarter of 1997, SCE implemented the EITF consensus and discontinued application of accounting principles for rate-regulated enterprises for its investment in generation facilities. However, implementation of the EITF consensus did not require SCE to write off any of its generation-related assets, including regulatory assets of approximately $600 million at December 31, 1997. SCE has retained these assets on its balance sheet because the legislation and restructuring plan referred to above make probable their recovery through a non-bypassable CTC to distribution customers. These regulatory assets relate primarily to the recovery of accelerated income tax benefits previously flowed through to customers, purchased power contract termination payments, unamortized losses on reacquired debt, and the recovery of amounts deferred under the Palo Verde rate phase-in plan. The consensus reached l by the EITF also permits the recording of new generation-related regulatory arsets during the transition period that are probable of recovery through the CTC mechanism. If during the transition period events were to occur that made the recovery of these generation-related regulatory assets no longer probable, SCE would be required to write off the remaining balance of such assets as a one-time, non-cash charge against earnings. If such a write-of f were to be required, SCE believes that it should not affect the recovery of scranded costs provided for in the legislation and restructuring plan. 6 Although depreciation-related differences could result from applying a regulatory prescribed depreciation method (straight-line, remaining-life method) rather than a method that would have been applied absent the regulatory. process, SCE believes that the depreciable lives of its generation-related assets would not vary significantly from that of an 1 unregulated enterprise, as the CPUC bases depreciable lives on periodic studies that reflect the physical useful lives of the assets. SCE also believes that any depreciation-related differences would be recovered through the CTC. If events occur during the restructuring process that result in all or a portion of the CTC being improbable of recovery, SCE could have additional write-offs associated with these costs if they are not recovered through another regulatory mechanism. At this time, SCE cannot predict what other revisions will ultirately be made during the restructuring process in subsequent proceedings or implementation phases, or the effect, after the transitien period, that competition will have on its results of operations or financial position. Transmission Owners Tariff and Wholesale Distribution Access Tariff - On March 31, 1997, SCE, PGGE and SDC&E jointly filed with the FERC a pro forma Transmission Owners Tarif f (T.O. Tarif f). The pro forma T.O. Tarif f was filed in conjunction with the ISO and PX tariffs, also filed on that date. Together, these tariffs set forth the rate design and terms and conditions for transmission service provided over SCE's facilities over which the ISO will have operational control. Additionally, on March 31,
- 1997, SCE filed an individual T.O.
- Tariff, its proposed revenue requirement for the facilities being turned over to the operational control of the ISO, and a Wholesale Distribution Access Tariff (WDAT).
i The SCE T.O. Tariff, excluding appendices, is identical to the pro forma l T.O. Tariff, and also contains appendices setting forth SCE's proposed Transmission Access Charges. FERC accepted the SCE T.O. Tariff rates and WDAT for filing, subject to refund, on December 17, 1997. TERC Restructuring Decision - In April 1996, the FERC issued its decision on stranded-cost recovery and open access transmission, effective July 1996. The decision, reaffirmed by the FERC in its March and November 1997 orders, requires all electric utilities subject to the FEF.C's jurisdiction to file transmission tariffs which provide competitors with increased access to transmission facilities for wholesale transactions and also establishes information requirements for the transmission utility. The decision also pro 5 tdes utilition with the opportunity to recover stranded costs associated with existing wholesale customers, retail-turned-wholesale customers and retail wheeling when the state regulatory body does not have authority to address retail stranded costs. Even though the CPUC is currently addressing stranded-cost recovery through the CTC proceedings, the FERC has also asserted primary jurisdiction over the recovery of stranded costs associated with retial-turned-wholesale customers, such as a new municipal electric system or a municipal annexation. However, FERC did clarify that it does not intend to prevent or interfere with a state's authority and that it has discretion to defer to a state stranded-cost-calculation method. In January 1997, the PERC accepted the open access transmission tariff SCE filed in compliance wit.h 3 the April 1996 decision. The rates included in the tariff are being i collected subject to refund. In May 1997, SCE filed a revised open access tariff to reflect the few revisions set forth in the March 1997 order. The open access transmission tariff will be terminated on the date the ISO begins operation. Regulation SCE's retail operations are subject to regulation by tne CPUC. The CPUC has the authority to regulate, among other things, retail rates, issuances of securities and accounting practices. SCE's wholesale operations are subject to regulation by the FERC. The FERC has the authority to regulate 1 7 J J wholesale rates as well as otl.er matters, including transmission service pricing, accounting practices and licensing of hydroelectric projects. SCE is wubject to the jurisdiction of the Nuclear Regulatory Commission (NRC) with respect to its nuclear power plants. NRC regulations govern the granting of licenses for the construction and operation of nuclear power plants and subject those power plants to continuing review and regulation. The construction, planning and siting of SCE's power plants within California are subject to the jurisdiction of the California Energy Commission and the CPUC. SCE is subject to rules and regulations of the California Air Resources Board and local air pollution control districts with respect to the emission of pollutants into the atmosphere, the regulatory requirements of the California State Water Resources Control Board and regional boards with respect to the disenarge of pollutants into waters of the state and the requirements of the California Department of Toxic Substances control with respect to handling and disposal of hazardous materials and wastes. SCE is also subject to regulation by the EPA, which administers certain federal statutes relating to environmental matters. Other federal, state and local laws and regulations relating to environmental protection, land use and water rights also affect SCE. The California Coastal Commission has continuing jurisdiction over the coastal permit for San onofre Units 2 and 3. Although the units are operating, the permit's mitigation requirements have not yet been fulfilled. California Coastal Commission jurisdiction may continue for several years due to implementation and oversight of permit mitigation conditions, including restoration of wetlands and construction of an artificial reef for kelp. The Department of Energy (DOE) has regulatory authority over certain aspcets of SCE's operations and business relating to energy conservation, solar energy development, power plant fuel use and disposal, coal conversion, electric sales for export, public utility regulatory policy and natural gas pricing. On December 16, 1997, the CPUC adopted a decision which established new rules governing the relationship between California's natural gas local distribution companies, electric utilities and certain of their affiliates. While SCE and its affiliates have been subject to affiliate transaction rules since the establishment of its holding company structure in 1988, these new rules are more detailed and restrictive. On December 31, 1997, SCE filed a preliminary Compliance Plan which set forth SCE's implementation of the new affiliate transaction rules. This preliminary Compliance Plan was supplemented by an additional filing made on January 30, 1998. A CPUC resolution is expected on SCE's Complianco Plan during the second quarter of 1998. For purposes of an electric utility, such as SCE, these new rules apply to all utility tra,e Mtions with affiliates engaging in the provision of a product that user slectricity or the provision of services that relate to the use of elactricity. Edison International is not subject to these new affiliate transaction rules and will continue to be subject to the prior rules. The new af filiate transaction rules are structured to address what the CPUC perceives market power and cross subsidization concerns arising out of the new competitive electricity market in California. These new i rules are categorized into nondiscrimination standards, disclosure and information standards, and separation standards. In addition, the new rules set forth requirements and restrictions on tha utility's of fering of certain products and services. SCE believes that the implementation of these new af filiate transaction rules will not materially affect its results of operation or financial position. 8 i L 9 Rat 2 Mattors CPUC Retail Ratemaking i The CPUC regulates the charges for services provided by SCE to its retail customers. As discussed in the section on Competitive Environment, the nature in which the CPUC regulates SCE is changing. The CPUC has issued final decisions regarding direct access, transition cost recovery and rate unbunaling in the restructuring of the electric industry. These decisions 4 I impact cost recovery and rate regulation beginning in January 1998, and implement new ratema' Lng mechanisms replacing the Electric Revenue Adjustment Mechanism, Energy Cost Adjustment Clause (ECAC) and base rates mechanism (collectively, the " pre-restructuring ratemaking mechanisms") described in prior annual and quarterly reports filed with the SEC. Total rate,s for all customers are frozen at June 10, 1996, levels, although residential and small commercial customers received a lot reduction from their June 10, 1996, rate levels beginning January 1,1998. These rate levels will remain in effect for the remainder of the transition period. Under these frozen rates, individual rate components (distribution, transmission, nuclear decommissioning and public purpose programs) are determined according to CPUC or FERC authorized mechanioms, with the generation rate determined residually by subtracting these other components from the total rate. Distribution Rates Distribution cost recovery is through a distribution PBR mechanism currently authorized through December 2001. Key elements of the distribution PBR includes distribution rates indexed for inflation based on the Consumer Price Index less a productivity factor; adjustments for cost changes that are not within SCE 's control; a cost of capital trigger mechanism based on changes in a bond index; standards for service i rolla'bility and safety; and a not revenue-sharing mechanism that i determines how customers and shareholders will share gains and losses from distribution operations. (see " California Electric Utility Restructuring- -PBR" section for additional discussion.) Transmission Rates Upon the commencement of the ISO and PX, transmission cost recovery will be under FERC authority. Until commencement of the ISO and PX, transmission cost recovery will be combined with distribution cost recovery through a T&D PBR. (See "Califotnia Electric Utility 4 } Restructuring--Rate-setting" and 'FERC Restructuring Decision" above for j additional discussion.) i Nuclear Decommissioning and Public Purpose Program Rates ) Recovery of SCE's nuclear decommissioning costs and legislatively mandated j public purpose program funding is through rates set to recover 100% of I these costs. Public purpose programs include cost effective energy efficiency, research, renewable technology development, and low income j programs. Generation Rates-1 l Effective with the commencement of ISO and PX operations, generation costs will be subject to recovery through the market price and the CTC. Revenue available to recover the uneconomic generation costs subject to . recovery through the CTC will be determined residually by subtracting the other rate components from total rates. This residual revenue will be first allocated to recovery of FERC-authcJized ISO charges for transmission-support and for purchases from the PX, and then to recovery of transition costs. Transition costs associated with QF and interutility contracts and the acceleration of sunk cost recovery will be subject to annual reasonableness review by the CPUC. 9 i i i x Transition cost recovery for most utility generation assets will terminate j by March 31, 2002, or when these costs are fully collected. (See "CTC" l above for additional discussion.) 1991 Anarpl ECAC Application 4 j In 1991, SCE issued its QF reasonableness testimony for the period April i 1, 1990, through M. arch 31, 1991. The Office of Ratepayer Advocates' (ORA) j report on QF reasonableness issues was issued in 1993. In its report, the ORA recommended that the CPUC disallow $1.5 millica in power purchase l expenses incurred as a result of purchases during the record period under a QF contract with Mojave Cogeneration Company, a nonutility generator. j The ORA further alleged that ratepayers may be harmed in the amount of i l $31.6 million (1993 not present value) over the contract's 20-year life. i SCE filed its rebuttal testimony on the contract in 1994. SCE and the ORA subsequently reached a settlement where SCE agreed to a one-time reduction to its ECAC balancing account of $14 million plus interest from January 1, 1 1996, to resolve the unreasonable acticn allegations by the ORA for 1991 4 and all subsequent record periods through the contract's 20-year life. On October 30, 1996, the.CPUC issued a decision which would approve the settlement, subject to SCE and the ORA accepting certain conditions concerning the manner in which the $14 million payment would be reflected in rates. After reviewing the decision, SCE declined to accept the condition proposed by the CPUC. Hearings on the ORA's disallowance recommendations regarding the Mojave cogeneration contract were held in June 1997. During the hearings, the ORA presented testimony to update its assessment of ratepayer harm, which it now assesses to be $45 million (1997 not present value) over the contract's life. On November 26, 1997, the assigned Administrative Law Judge (ALJ) issued a proposed decision (which is not binding on the CPUC) which would adopt the ORA's imprudence allegations. On January 13, 1998, the assigned ALJ issued an order setting aside the proposed decision in order to accommodate SCE's request for an oral argument to a quorum of the Commissioners. Oral arguments were heard on February 4, 1998, at which time ScE requested an alternate proposed decision be issurd, on March 11, 1998, the Assigned Commissioner issued an alternate proposed decision which recommerd.s a disallowance of $46,000 for the record period and expected dicall'c ances of $16.3 million over the life of the Mojave Cogeneration contract. The matter is currently scheduled for consideration at the CPUC
- r4 M?rch 26, 1998 meeting.
1992 Annual ECAC Application SCE filed its QF reasonableness testimony in September 1992. In January 1996, the ORA released its report on QF reasonableness for the 1992 record period as well as for that portion of the 1991 record period concerning capacity truncation and energy deliveries at forecast rates. On February 17, 1998, the %A submitted surrebuttal testimony. Hearings on the matter began on March 9 and concluded March 17, 1998 subject to SCE's right to recall certain witnesses in rebuttal to ORA's witnesses. If SCE elects to recall such witnesses, the hearing will resume on Aprtl 1, 1998. An adverse decision for SCE on either or both issues could, under certain circumstances, have a material impact on SCE's financial position if the decision were extended to subsequent record periods. 'Ihe ORA's surrabuttal testimony recommends a disallowance of $17.5.nillion associated with firm capacity truncation, $17.4 million for forecasted energy payments at forecast rates, and $43,000 for as-available capacity paymsnts at forecast rates. These amounts encompass the 1991 and 1992 periods, and exclude certain projects which have been deferred in this proceeding. 1993 Annual ECAC Application l SCE filed its QF reasonableness testimony on September 1, 1993. On March 2, 1998, the ORA filed a combined report covering the QF reasonableness phases of SCE's ECAC applications for 1993-1995. In the report, the ORA 10 recommends a disallowance of- $5.6 million related to SCE's administration i of.a contract with the Arbutus wind project. No other reasonableness 1 issues were _dentified in the report. SCE's rebuttal testimony is due on June 4, 1998, and hearings are scheduled for early August 1998. l 1994 Annual ECAC Application SCE filed its QF reasor' ableness testimony and non-QF Reasonableness of Operations. Report on May 27, 1994. The QF testimony reflects the reasonableness of execution of two new QF contracts and the reasonableness l of SCE's administration of 393 QF contracts. The non-QF report addresses I pow ar purchases and exchanges, and the operation of hydroelectric, coal, gas and nuclear resources for the period April 1, 1993, through March 31, 1994. The 1993, 1994 and 1995 QF issues will be joined for hearing. The non-QF issues were bifurcated with the gas procurement issues being separated from the other non-QF issues. On August 2, 1996, the CPUC l issued a decision finding that SCE's non-QF, non-gas procurement activities were reasonable. The ORA recommended a $13.3 million disallowance for costs incurred from Novembe-1993 through March 1994 associated with SCE's Canadian gas supply and tra.,)rtation contracts. On October 17, 1996, the ALJ granted the ORA's motion to consolidat's the 1994 and 1995 record periods for the limited purpose of addressing the gas reasonableness issues. Hearings on these issues began January 21, 1997, j and were concluded on February 20, 1997. l However, briefing was suspended by the ALJ at the request of the parties to facilitate settlement discussions. On July 11, 1997, the ORA and SCE executed a Settlement Agreement. The basic elements of the settlement includes (1) a $39 million disallowance for Canadian gas costs incurred through December 31, 1996; (2) a disallowance of $257,000 per month, per contract, for each of SCE's four supply contracts for Canadian gas costs beginning after January 1, 1997, and continuing u-til each of the commodity contracts are terminated '(one supply agreement was terminated on May 1, 1997, and the remaining three supply agreements were terminated on July 1, 1997); (3) a cost sharing mechanism in lieu of reasonableness review, whereby shareholders would absorb at lost 20% of the 'ormination or restructuring costs associated with the unadian supply and transportation contracts and at least 5% of the termination or restructuring custs associated with the El Paso transportation contract which the CPUC has already found reasonable (a portion of these termination or restructuring costs associeted with the cost sharing mechanisms would be flowed through to ratepayers through the Energy Deferred Refund Account);..nd (4) agreement that all other costs incurred under these contracts, including the termination, buy-down and/or buy-out costs are reasonable and should be determined to be reasonable by the CPUC. On December 3, 1997, the CPUC issued a decision approving the Settlement betecen SCE and the ORA. On March 12, 1998, the CPUC issued a decision ordering SCE to refund $65 million. The Settler 1nt has been fully reflected in SCE's financial statements. A discussion of the ORA's report in the QF reasonableness phase of this ECAC is set forth above in the discussions of the 1993 4CAC Application. 11 + i l f 1995 Annual ECAC Application ) a SCE filed its reasonableness of operations testimony on May 26, 1996. The QF reasonableness testimony reflects the reasonableness of settlement l agreements with six QFs, the reasonableness of the Biogen Power I termination agreement, and the reasonableness of the SCE's administration of 414 QF contracts for the period April 1, 1994, through March 31, 1995. i The 199J, 1994 and 1995 QF issues will be joined for hearing. 4 The non-QF report addresses power purchases and exchanges, aid the j operation of hydroelectric, coal, gas and nuclear resources fsr the pasriod l April 1, 1994, through March 31, 1995. In May 1996, the ORA issued its l reasonableness report on several non-QF reasonableness issues. The report i recommended a $6.6 million disallowance for replacement fuel expenses associated with 64 outage days due to the Palo Verde Unit 2 steam ? generator tube rupture in 1993, and that the issue of $5.2 million of l nuclear fuel expenses associated with the NUEXCO Trading Corp. bankruptcy j be held open for review. In written response to data requests, the ORA indicated it has withdrawn its concerns over the nuclear fuel expenses, j Additionally, SCE and the ORA executed a stipulation on December 18, 1997, resolving the Palo Verde issue by agreeing to a disallowance of $318,540 plus interest which is the replacement fuel expense associated with six outage days. A motion requesting approval of the SCE/ ORA stipulation was filed with the CPUC in December 1997. The CPUC issued its decision j approving the stipulation on February 19, 1998. On October 4, 1996, the ORA issued its report on SCE's Canadian gas i procurement contracts discussed above. The report recommended a $37.6 million disallowance for the period April 1994 through March 1995. On i October 17, 1996, the ALJ consolidated the gas reasonableness issues inte t the 1994 ECAC proceeding. The reasonableness of the Canadian gas procurement and transportation costs for the record period was resolved by the ORA /SCE settlement discussed above in the 1994 Annual ECAC 1 Application. The Settlement has been fully reflected in SCE's financial statements. A discussion of the ORA's report in the QF reasonabieness phase of this 'I ECAC is set forth above in the discussion of the 1993 ECAC Application. i } 1996 Annual ECAC Application l SCE filed its testimony on May 3,1996, requesting a finding that its fuel I and purchased power costs, including purchases from QFs recorded during I the period April 1,1995, through March 31, 1996, were reasonable. The QF 1 reasonableness testimony supports the reasonableness of SCE's administration of 396 QF contracts, including the restructuring or buyout j of certain contracts. The non-QF testimony supports the reasonableness of other power purchases and exchanges, and the operation of hydroelectric, l coal, gas'and nuclear resources. SCE requested and obtained an expedited finding of reasonableness by the CPUC for an agreement it signed with Portland General Electric (PGE), terminating a long-term power purchase contract. On December 9,1996, the CPUC issued a decision finding the termination of the agreement reasonable. Additionally, as the final part in the approval process, PGE and SCE filed notices of cancellation of the agreement with the FERC to be effective December 31, 1996. The FERC has accepted the notices of cancellation. Review by the ORA of the non-QF operations has been consolidated with its review in the 1997 Annual ECAC Application. The ORA's report was issued on August 18, 1997. (See "1997 Annual ECAC Application.") No date has been scheduled for the ORA's report on QF reasonableness. 12 -_.- - m 1997 Annual ECAC Application on May 30, 1997, SCE filed its annual reasonableness report requesting that the CPUC find reasonable its fuel and purchased-power :osts, including purchases from QFs recorded during the period of April.1,1996, through March 31, 1997. The QF testimony supports the reasonableness of the SCE's administration of ite QF contracts, including two QF j settlements. The non-QF testimony supports the reasonableness of other power purchases and exchanges, fuel costs and the operation of hydroelectric, coal, gas and nuclear resources. The ORA's review of the non-QF operations and costs has been consolidated with its review 'of the non-QF operations and costs in the 1996 ECAC e I Application. The ORA filed its report on August 18, 1997. In its report, the ORA recommended, among other things. (1) a disallowance of $360,000 associated with an outage at the coal-fired Four Corners Generating Station and (2) a $200,000 adjustment to the costs recorded in SCE's Catastrophic Events Memorandum Account. Hearings took place in January 1998. A CPUC decision is expected by July 1998. No date has been scheduled for the ORA's report on QF reasonableness. Palo Verde In January 1997, the CPUC authorized a further acceleration of the recovery of its remaining inveetment of $1.2 billion in Palo Verde Units 1, 2 and 3. The accelerated recovery will continue through December 2001, earning a 7.35% fixed rate of return. The accelerated plant recovery, as well as future operating costs, including nuclear fuel and nuclear fuel financing costs, end incremental capital expenditures, are subject to balancing account treatment through 2001. Beginning Jsnuary 1, 1998, the balancing account became part of the CTc mechanism. 'ine existing nuclear unit incentive procedure will continue only for purposes of calculating a reward for performance of any unit above an 80% capacity' factor for a fuel cycle. Beginning in 2002, SCE will be required to share equally with ratepayers the not benefits received from operation of Palo Verde. Proposed New Accounting Standard During 1996, the Financial Accounting Standards Board issued an exposure draft, that would establish accounting standards for the recognition and measurement of closure and removal obligations. The exposure draft would require the estimated present value of an obligation to be recorded as a liability, along with a corresponding increase in the plant or regulatory asset accounts when the obligation is incurred. If the exposure draft is l approved in its present form, it would affect SCE's accounting practices for decommissioning of its nuclear power plants, obligations for coal mine reclamation costs, and any other activities related to the closure or removal of long-lived assets. SCE does not expect that the accounting changes proposed in the exposure draf t, even after deregulation, would 1 have an adverse effect on its results of operations due to its current and expected future ability to recover these costs through customer rates. Fuel Supply and Purchased Power Costs Fuel and purchased-power costs were approximately $3.7 billion in 1997, an 11.9% increase over 1996. SCE's sources of energy during 1997 were purchased power 49t; natural gas 16t; nuclear 17t; coal 12t; and hydro 64. Average fuel costs, expressed in cents per kilowatt-hour, for the year ended December 31, 1997, were: oil, 8.53 cents; natural gas, 3.39 cents; nuclear, 0.48 cents; and coal, 1.32 cents. ) 13 a - - ~... -. -. - - -. - -. - - -. -.. - - -...... _, -. - - t hatural Gas supply As a resulti of the sale of 11 of its 12 gas-fired generating stations, SCE has terminated four long-term natural gas supply and three long-term gas transportation contracts which had been used to import gas from Canada. In ' addition, - SCE has exercised the option under its 15-year gas tranoportation commitment with El Paso Natural Gas Company to reduce Ats . capacity obligation from 200 million to 130 million cubic feet per day. Nuclear Fuel supply SCE has contractual arrangements covering 100% of the projected nuclear fuel requirements for San onofre through the years indicated below: Units 2&3 Uranium concentrates (1) 2003 Conversion..........'.......... 2003 Enrichment 2003 Fabrication 2005 2006/2006 Spent fuel storage (2) (1) Assumes the San Onofre participants meet their supply obligations in a timely manner. (2) Assumes full utilization of expanded on-site storage capacity and normal operation of the units, including interpool transfers and maintaining full-core reserve. The Nuclear Waste Policy Act of 1982 requires that the DOE provide for the disposal of utility spent nuclear fuel beginning January 31, 1998. The DOE defaulted on its obligation to begin acceptance of spent nuclear fuel from San Onofre. Dry cask storage either on-site or at another location will be required to permit continued operations beyond the date indicated above. Participants at Palo Verde have contractual agreements for uranium concentrates to meet projected requirements through 2000. Independent of arrangements made by other' participants, SCE will furnish its share of uranium concentrates requirement through at least' 1998 from existing i contracts. Contracts cover requirements to provide conversion through 2000, enrichment through 2002, and fabrication through 2016. Palo Verde on-site spent fuel storage capacity will accommodate needs through 2002 for Units 1 and 2, and through 2003 for Unit 3. Environmental Matters l Legislative and regulatory activities in the areas of air and water pollution, waste management, hazardous chemical use, noise abatement, land use, aesthetics and nuclear control continue to result in the imposition of numerous restrictions on SCE's operation of existing facilities, on the timing, cost, location, design, constructior-and operation by SCE of new f acilities, and on the cost of mitigating the effect of past operations on the environment. These activities substantially affect future planning and will continue to require modifications of SCE's existing facilities and operating procedures. *SCE is unable to predict.the extent to which additional regulations may affect its operations and capital expenditure requirements. The Clean' Air Act (CAA) provides the statutory framework to implement a program for achieving national ambient air quality standards in areas e.rceeding such standards and provides for maintenance of air quality in areas already meeting such standards. I 14 6 The CAA as amended in 1990, and as implemented within the South Coast Air Quality Management District (SCAQMD) and other districts within California required SCE to reduce emissions of oxides of nitrogen from its generating stations. SCE is selling all of its oil-and gas-fueled generating stations within the SCAQMD, the Mohave Desert Air Quality Management District, Ventura County Air Pollution Control District, and the Santa Barbara County Air Pollution Control District, with an expected sale closure date for 11 of the 12 generating stations being sold by March 31, 1998 (the twelfth plant is expected to be sold in 1998). It is expected that after the generating stations' sale closure dates, under operations and maintenance contracts with the individual owners, SCE will operate those f acilities that are kept in operation as active generating stations. SCE operations of the stations it gains contracts for, will be under the direction and expense of the new owners. SCE will be responsible for maintaining the environmental permits of the plants. However, che new owners, not SCE, will be responsible for the purchase and installation of emissions control equipment, and sufficient trading credits required for the plants under the Regional Clean Air Incentives Market within the SCAQMD. The CAA does not require any significant additional emissions control expenditures that are identifiable at this time. The Environmental Protection Agency (EPA) plans to issue its final rulemaking regarding regional haze regulations in late 1998. Also, the EPA and SCE will conclude a cooperative tracer study of sulfur dioxide emissions from the Mohave Generating Station in mid-to late-1998. The study is evaluating potential impact from Mohave emissions on haze within the Grand Canyon National Park. The extent to which these two activities may require sulfur dioxide or particulate emissions reductions at the Mohave plant is not known. The acid rain provisions of the amended CAA also put an annual limit on sulfur dioxide emissions allowed from power plants. SCE has received more sulfur dioxide allowances than it requires for its projected operations. Until more definite information on tracer study results are available, SCE expects to meet all the present regulations through improved operations at the plant. On February 19, 1998, the Sierra Club and the Grand Canyon Trust filed suit against SCE and the other co-owners of Mohave in the U.S. District Court cf Nevada alleging violations over the last five years of the CAA, the Nevada State Implementation Plan, and applicable air quality permits relating to opacity and sulfur dioxide emission limits. SCE, on behalf of the co-owners, will provide a timely response in defense of the suit. The CAA also requires the EPA to carry out a three year study of risk to public health from the emissior, of toxic air contaminants from electric utility steam generating plants, and to regulate such emissions only if required. The study has not been finalized by the EPA to date. Regulations under the clean Water Act require permits for the discharge of certain pollutants into waters of the U.S. Under this act, the EPA issues effluent limitation guidelines, pretreatment standards and new source performance standards for the control of certain pollutants. Individual states may impose even more stringent limitations. In order to comply with guidelines and standards applicable to steam electric power plants, SCE incurs additional expenses and capital expenditures. SCE presently has discharge permits for all applicable facilities. The Safe Drinking Water and Toxic Enforcement Act prohibits the exposure to individuals of chemicals known to the State of California to cause cancer or reproductive harm and the discharge of such listed chemicals into potential sources of drinking her. Additional chemicals are continuously being put on the state's ; ~ requiring constant monitoring. 15 l The Resource Conservation and Recovery Act (RCRA) provides the statutory authority for the EPA to implement a regulatory program for the safe treatment, recycling, storage and disposal of solid and hazardous wastes. There is an unresolved issue regarding the degree to which coal wastes should be regulated under the RCRA. Increased regulation may result in an increase in expenses related to the operation of Mohave. The Toxic Substances Control Act and accompanying regulations govern the manufacturing, processing, distribution in commerce, use and disposal of polychlorinated biphenyls, a toxic substance used in certain electrical equipment (PCB waste). Currant costs for disposal of PCB waste are immaturial. SCE records its environmental liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. SCE reviews its sites 'and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, SCE records the lower end of this reasonably likely range of costs (classified as other long-term liabilities at discounted amounts). While SCE has numerous insurance policies that it believes may provide coverage for some of these liabilities, it does not recognize recoveries in its financial statements until they are realized. In connection with the issuance of the San onofre Units 2 and 3 operating permits, SCE reached an agreement with the California Coastal Commission in 1991 to restore certain marine mitigation sites. The rastorations include two sites: designated wetlands and the construction of an artificial reef for kelp off the California coast. After SCE requested certain modifications to the agreement, the Californla Coastal Commission issued a final ruling in April 1997 to reduce the scope of remediations. SCE elected to pay for the costs of marine mitigation in lieu of placing the funds into a trust. Recovery of these costs is occurring through the San Onofre incentive pricing plan. SCE's recorded estimated minimum liability to remediate its 50 identified sites is $178 million, which includes $75 million for the two sites discussed above. The ultimate costs to clean up SCE's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as the extent and nature of contamination; the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and the time periods over which site remediation is expe:ted to occur. SCE believes that, due to these uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to $246 million. The upper limit of this range of costs was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes. The CPUC allows SCE to recover environmental-cleanup costs at 41 of its sites, representing 591 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recoven these costs from insurance carriers and other third parties. SCE has successfully sottled insurance claims with all responsible carriers. Costs incurred at SCE's remaining sites are expected to be recovered through customer rates. SCE has recorded a regulatory asset of $153 16 _ ~. t l million for its estimated minimum environmental-cleanup costs expected to 4 be recovered through customer rates. This amount includes $60 million of marine mitigation costs remaining to be recovered through the San Onofre incentive pricing plan. SCE's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of I contamination, and the extent, if any, that SCE may be held responsible j for contributing to any costs incurred for remediating these sites. Thus, 7 no reasonable est! mate of cleanup costs can now be made for these sites. 4 SCE expects to clau; up its identified sites over a period of up to 30 i years. Remediation costs in each of the next several years are expected to range from $4 million. to $10 =. illion. Recorded costs for 1997 were $10 I million. ~ Based on currently available information, SCE believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range and, based upon the CPUC's regulatory treatment of environmental-cleanup 4 costs, SCE believes that costs ultimately recorded will not materially affect its results of operations or financial position. There can be no j assurance,
- however, that future developments, including additional i
information about existing sites or the identification of new sites, will not require material revisions to such estimates. j SCE's projected capital expenditur*g to protect the environment are $820 ( million for the 1998-2002-perioy mainly for aesthetics treatment, including undergrounding certain tra.4 mission and distribution lines. Year 2000 Issue Many of SCE's existing computer systems identify a year by using only two digits instead of four. If not corrected, these programs could fail or create erroneous results when encountering dates in 2000 or later. This situation has been referred to generally as the Year 2000 Issue. SCE has developed plans and is addressing the progra:nming changes that it has determined are necessary in order for its computer systems to function properly beginning in 2000. Remediation of SCE's key financial systems for the Year 2000 Issue was completed in 1997. SCE's informational and operational systems have been assessed, and detailed plans have been developed to address modifications required to be completed, tested and operational by December 31, 1999. Preliminary estimates of the costs to complete these modifications, including the cost of new hardware and software application codifications, range from $55 million to $80 million, about half of which are expected to be capital costs. Current rate levels for providing electric service should be sufficient to provide funding for these modifications. Remediation of existing critical systems is expected to be 75% complete by the end of 1998. SCE expects its Year 2000 date conversion project to be completed on a timely basis, with no material adverse Lepact to its results of operations or financial position. SCE's Year 2000 date conversion project includes an assessment of critical ) interfaces with the computer systems of others and it does not expect a material adverse effect on its operating and business functions from the Year 2000 Issue. Item 2. Properties Existing Generating Facilities SCE owns and operates 12 oil-and gas-fueled electric generating plants, one - diesel-fueled generating plant, 38 hydroelectric ~ plants and an undivided 75.05% interest (1,614 MW not) in Units 2 and 3 at San onofre. 17 e SCE has signed agreements to sell 11 of its 12 oil-and gas-fueled generating plants, and expects those sales to close by March 31, 1998. SCE is also seeking to sell the twelfth plant. Any of the sold plants which remain in operation will continue to be operated by SCE for at least two years following the sale. These plants are located in Central and Southern California. Palo Verde (15.8% SCE-owned, 579 MW net) is located near Phoenix, Arizona. SCE owns a 48% undivided interest (754 MW) in Units 4 and 5 at Four Corners, a coal-fueled steam electric generating plant in New Mexico. Palo Verde and Four Corners are operated by other utilities. SCE operates and owns a 56% undivided interest (885 MW) in Mohave, which consists of two coal-fueled steam electric generating units in Clark County, Nevada. At year-end 1997, the existing SCE-owned generating capacity (summer effective rating) was comprised of approximately 65% gas,15% nuclear,11% coal, 8% hydroelectric and 1% oil. San Onofre, Fcur Corners, certain of SCE's substations and portions of its transmission, distribution and communication systems are located on lands of the United States or others under (with minor exceptions) licenser, permits, easements or leases or on public streets or highways pursuant to franchises. Certain of such documents obligate SCE, under specified circumstances and at its expense, to relocate transmission, distribution and communication facilities located on lande owned or controlled by federal, state or local governments. With certain exceptions, major and certain minor hydroelectric projects with related reservoirs, currently having an eff.ective operating capacity of 1,156 MW and located in whole or in part on lands of the U.S., are owned and operated by SCE under governmental licenses which expire at various times between 1997 and 2026. Such licenses impose numerous restrictions and obligations in SCE, including the right of the United States to acquire the project upon payment of specified compensation. i 1 When existing licenses expir 2 FERC has the authority to issue new ly if their license application is licenses to third parties, or ( superior to SCE's and then onic ri.: payment of specified compensation to SCE. Any new licenses issued ts JCE are expected to be issued under terms and conditions less favorable than those of the expired licenses. SCE's applications for the relicensing of certain hydroelectric projects referred to above with an aggregate ef fective operating capacity of 59.1 MW are pending. Annual licenses issued for all SCE projects, whose licenses have expired and are undergoing relicensing, will be renewed until the new licenses are issued. l In 1997, SCE's peak demand was 19,118 MW, set on September 4, 1997. Total area system operating capacity of 21,511 MW was available to SCE at the I time of the 1997 peak. Substantially all of SCE's properties are subject to the lien of a trust indenture securing First and Refunding Mortgage Bonds (Trust Indenture), of which approxicately $2.8 billion principal amount was outstanding at December 31, 1997. Such lien and SCE's title to its properties are subject to the terms of f ranchises, licenses, casements, leases, permits, contracts and other instruments under which properties are held or operated, certain statutes and governmental regulations, liens for taxes and assessments, and liens of the trustees under the Trust Indenture. In l addition, such lien and SCE's title to its properties are subject to l certain other liens, prior rights and other encumbrances, none of which, with minor or unsubstantial exceptions, affects SCE'm right to use such properties in its business, unless the matters with respect to SCE's interest in Four Corners and the related easement and lease referred to below may be so considered. 18 SCE's rights in the Four Corners Project, which is located on land of The Navajo Nation of Indians under an easement from the United States and a lease from The Navajo Nation, may be subject to possible defects. These defects include possible conflicting grants or encumbrances not 4 ascertainable because of the absence of, or inadequacies in, the applicable recording law and the record systems of the Bureau of Indian Aff airs and The Navajo Nation, the possible inability of SCE to resort to legal process to enforce its rights against The Navajo Nation without Congressional consent, possible impairment or termination under certain circumstances of the easement and lease by The Navajo Nation, Congress or the Secretary of the Interior and the possible invalidity of the Trust Indenture lien against SCE's interest in the easement, lease and improvements on the Four Corners Project. Construction Program and Capital Expenditures Cash required by SCE for its capital expenditures totaled $685 million in 1997, $616 million in 1996 and $773 million in 1995. Construction expenditures for the 1998-2002 perlod are forecasted at $3.9 billion. ~ In addition lo cash required for construction expenditures for the next five years as discussed above, $2.8 billion is needed to meet requirements for long-term debt maturities and sinking fund redemption requirements. SCE's estimates of cash available for operations for the five years through 2002 assume, among other things, the receipt of adequate and timely rate relief and the realization of its assumptions regarding cost increases, including the cost of capital. SCE's estimates and underlying assumptions are subject to continuous review and periodic revision. j The timing, type and amount of all additional long-term financing are also influenced by market conditions, rate relief and other factors, including limitations imposed-by SCE's Articles of Incorporation and Trust j Indenture, Nuclear Power Matters SCE's nuclear facilities have been reliable sources of inexpensive, non-polluting power for SCE's customers for more than a decade. Throughout the operating life of these f acilities, SCE's customers have supported the revenue requirements of SCE's capital investment in these facilities and for their incremental costs through traditional cost-of-service ratemaking. On January 10, 1996, the CPUC's decision for SCE's Test Year 1995 General Rate Case (GRC) rejected a settlement agreement proposed by SCE, SDGGE and the ORA in its original form, but proposed modifications to certain terms related and granted SCE the opportunity to accept the portion of the settlement agreement related to San Onofre Unite 2 and 3 with the proposed modifications. The CPUC gsve SCE 25 days to prepare a detailed proposal consistent with the policy adopted in SCE's 1995 GRC dacision. On February 5, 1996, SCE filed a revised San Onofre Unit 2 and 3 proposal in which it accepted the modifications to certain settlement agreement terms as. proposed by the CPUC. The CPUC adopted the revised proposal on April 10, 1996. Under this proposal, SCE would have recovered its remaining investment in San onofre Units 2 and 3 at a reduced rate of return of 7.35%, but on an accelerated basis during the eight-year period from the effective date in 1996 through December 31, 2003. Under Assembly i Bill 1890, however, the recovery of the San onofre remaining investment must be completed by December 31, 2001. In addition, the traditional cost-of-service ratomaking for San Onofre Units 2 and 3 was superseded by an incentive pricing plan, in which SCE's customers would pay a preset price for each kilowatt-hour of energy generated at San Onofre during the eight-year period. Assembly Bill 1890 allowed continuation of the incentive pricing plan through December 31,
- 2003, the end of the 19
= l eight-year period. SCE was compensated for the incremental costs required l for the continued operation of San Onofre Units 2 and 3 only with revenue earned through the incentive pricing plan. However, SCE also retained the ability to request recovery of the cost of fuel consumed for generation of replacement energy for periods in which San onofre is r.ot generating power through future ECAC filings. SCE-would also continue to collect funds for decommissioning expenses through traditional ratemaking treatment. On July 16, 1997, the CPUC approved SCE's request to transfer the recorded i i not investment in San onofre Units 2 and 3 step-up transformers to San onofre Unite 2 and 3 sunk costs for recovery by December 31, 2001, at a j reduced rate of return of 7.35%. On August 21, 1997,'the CPUC approved SDGGE and SCE's Joint Petition to i Modify, requesting continued recovery of certain cceporate administrative and general costs allocable to San onofre Units 2 and 3, at rates of 0.280 e } and 0.21C per kWh, respectively, for the period January 1, 1998, through j December 31, 2003. In.the restructuring decision, the CPUC ordered SCE to file an application 'by March'29, 1996, requesting a new rate mechanism for its share of the l Palo Verde units to be effective January 1, 1997. On February 29, 1996, 1 .ECE ff. led its Palo Verde Proposal Application requesting adoption of a new l rate mechanism for Palo Verde consistent with the San onofre Unite 2 and 3 rate mechanism. On November 15, 1996, SCE,. ORA and TURN, entered into a settlemant agreement regarding SCE's Palo Verde Proposal Application. j The settlement retained SCE's proposal to recover its' remaining investment in the Palo Verde units by Decerber 31, 2001, at a reduced rate of return of 7.35% consistent with AB 1890, but modified SCE's proposed Palo Verde rate mechanism. Instead of receiving a preset price for each kilowatt-f hour of energy generated during that period, as proposed, the settling parties agreed that SCE would recover its share of Palo Verde incremental I operating costs, except if those-costs exceed 95% of the levels forecast by SCE in its application by more than 30% in any given year. In that l' case, SCE must demonstrate that the aggregate amount of the costs exceeding the forecast in that year are reasonable. In addition, if the annual Palo Verde site Gross Capacity Factor (GCF) is less than 55% in a calendar year, SCE will tear the burden of proof to demonstrate that the site's operations causing the GCF to fall below 55% were reasonable in that year. Ir operations are determined to be unreasonable by the CPUC, SCE's replacement power purchases associated with that period of P21o Verde operations below 55% GCF may be disallowed. The CPUC approved the settlement agreement on December 20, 1996. Beginning in 2002, power from Palo Verde Unita 1, 2 and 3 will be sold at the then-current market prices with 50% of the benefits of such operation given to customers. Likewise, beginning in 2004, power from San onofre Units 2 and 3 will be sold at the then-current market prices with 50% of the benefits of such operation given to customers. saa onofre Nuclear Generating Station In 1992, the CPUC approved a settlement agreement between SCE and the ORA to discontinue operation of Unit 1 at the end of its then-current fuel cycle. In November 1992, SCE discontinued operation of Unit 1. As part of the agreement, SCE recovered its remaining investment over a four-year period ending August 1996. The Units 2 and 3 steam generators have performed relatively well through the first 15 years of operation, with low rates of ongoing tube degradation. However, during the Unit 2 scheduled refueling and inspection outage, which was completed in Spring 1997, an increased rate of degradation was identified, which resulted in the removal of more tubes from service than.had been expected. The steam generator design allows for the removal of up to 10% of the tubes before the rating capacity 20 4 4 of the unit must be reduced. As a result of the increased degradation, a mid-cycle outage was conducted in February 1998 for Unit 2. The results of that outage are still being evaluated. 1 During Unit 3's refueling outage, which was completed in July 1997, inspections of structural supports for steam generator tubes identified several areas where the thickness of the supports had been reduced, apparently by erosion during normal plant operation. As a result, a mid-cycle outage is planned for early 1998. However, during Unit 2's Spring i 1997 outage and the February 1998 mid-cycle outage, similar tube supports showed no signs of such erosion. Palo Verde Nuclear Generating Station on March 14, 1993, Arizona Public Service Company (APS), the operating agent for-Palo Verde, manually shut down Unit 2 as a result of a steam generator tube leak. Unit 2 remained shut down and began its scheduled refueling outage.on March 19, 1993. l APS performed an extensive inspection of the Unit 2 steam generators prior to the unit's return to service on September 1,1993. APS determined that intergranular attack /intergranular stress corrosion cracking was a major 1 contributor to the tube leak.. Subsequent inspections have revealed similar, though less severe, corrosion in the Unit 1 and Unit 3 steam generators. APS has taken, and indicates it will continue to take, remedial-actions that it believes-have slowed the rate.of steam generator j tube degradation in all three units. Based on latest available data, APS estimates that the Unit 1 and Unit 3 i steam generators should operate for the 40 year licensed operating life of those units, although APS continuas to monitor the situation. APS has disclosed that it^ believes it will be economically desirable to replace the Unit 2 steam generators, which have been most affected by tube cracking, in five to ten years. APS has indicated to'the participants that it believes that replacement of the Unit 2 steam generators would cost between $100 million and $150 million. SCE estimates that this cost - could be higher, such that its share of this cost would be between $16 million and $30 million plus replacement power costs. Unanimous approval of the Palo Verde participants is required for capital improvements, including steam generator replacement. In December 1997, the Palo Verde i participants unanimously agreed to purchase two spare steam generators at a cost of.approximately $82 million; however, SCE has not yet decided whether it suppo;ts replacement of the Unit 2 steam generators. Nuclear Facility Decommissimaing With the exception of San onofre Unit 1, SCE plans to deconunission its nuclear generating facilities at the end of each facility's operating license-by a prompt removal nethod authorised by the NRC. Currently, San onofre Unit 1,'which shut down in 1992, is expected to be stored until i decommissionirig begins at the other San onofre units. Decommissioning is i estimated to.ost $2.1 billion in current-year dollars based on site-specific studies performed in 1993 for San onofre and 1992 for Palo Verde. This estimate considers the total cost of decommissioning and diemantling the plant, including labor, material, burial and other costs. The site specific studies are updated approximately every three years. Changes in the estimated costs, timing of decommissioning, or the assumptions underlying these actimates could cause material revisions to the estimated 9-total cost to decommission in the near term. Decommissioning is scheduled to begin in 2013 at San onofre and 2024 at Palo Verde. Decossaissioning costs,.uhich are accrued and recovered through non-i byp&ssable customer rates over the terms of each nuclear facility's operating license, are recorded as a component of depreciation expense. l, Decosuaissioning,axpense was $154 million in 1997, $148 million in 1996 and $151 mill. ion in 1995. The accumulated provision for decommissioning was i 4 21 i 1: ,,. ~... -. ~. .--n 7_. $1.1 billion at December 31, 1997, and $949 million at December 31, 1996. The estimated costs to decommission San Onof re Unit 1 ($280 million in 1993 dollars) are recorded as a liability. Decommissioning funds collected in rates are placed in independent trusts which, together with accumulated earnings, will be utilized solely for decommissioning. Nuclear Insurance Federal law limits public liability claims from a nuclear incident to $8.9 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available ($200 million). The balance is covered by the industry's retrospective rating plan that uses deferred premium charges to every reactor licensee if a nuclear incident at any licensed reactor in the U.S. results in claims and/or costs which exceed the primary insurance at that plant site. Federal regulations require this secondary level of financial protection. The NRC exempted San Onofre Unit 1 from this secondary level, effective June 1994. The maximum deferred premium for each nuclear incident is $79 million per reactor, but not more than $10 million per reactor may be charged in any one year for each incident. Based on its ownership interests, SCE could be required to pay a maximum of $158 million per nuclear incident. However, it would have to pay no more than $20 million per incident in any one year. Such premium amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and are subject to periodic adjustment for inflation. If the public liability limit above is insufficient, federal regulations may impose further revenue-raising measures to pay claims, including a possible additional assessment on all licensed reactor operators. Property damage insurance covers losses up to $500 million, including decontamination coats, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 million has also bein purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage. These policies are issued primarily by mutual insurance ecmpanies owned by utilities with nuclear f acilities. If losses at any nuclear f acility covered by these arrangements were to exceed the accumulated funds for these insurance programs, SCt could be assessed retrospective premium adjustments of up to S28 million per year. Insurance premiums are charged to operating expense. Item 3. Legal Proceedings Qualifying Facilities Litigation on May 20, 1993, four geothermal QFs filed a lawsuit against SCE ir. Los Angeles County Superior Court, claiming that SCE underpaid, and continues to underpay, the plaintif f s for energy. SCE denied the allegations in its response to the complaint. The action was brought on behalf of Vulcan /BN Geothermal Power Company, Elmore L.P., Del Ranch L.P. and Leathers L.P., each of which was partially owned by a subsidiary of Edison Mission Energy (EME) (a subsidiary of Edison International) at the time of filing. In April 1996, EME's 50% share in these projects was sold to CalEnergy. In October 1994, plaintiffs submitted an amended complaint to the court to add causes of action for unfair cornpetition and restraint of trade. In July 1995, after several motions to strike had been heard by the court, the plaintiffs served a fourth amended complaint, which omitted the previous claims based on alleged restraint of trade. The plaintiffs allege in the fourth amended complaint that past underpayments have totaled at least $21 million. In other court filings, plaintiffs contend that additional contract payments owing from the beginning of the alleged underpayments through the end of the contract term could total approximately S60 million. Plaintiffs also seek unspecified punitive damages and an injunction to enjoin SCE from " future" unf air competition. 22 l 4 Af ter SCE's motion to strike portions of the fourth amended complaint was denied, SCE filed an answer to the fourth amended complaint which denies its material allegations. On May 1, 1996, the parties entered into an agreement for a cettlement of all claims in dispute. Pursuant to the agreement, the specific terms of which are confidential, a settlement amount has been paid and the parties have entered into mutual general releases, with respect to the period before January 1, 1996. SCE intends to seek recovery of this payment through rates. SCE has also agreed, subject to CPUC approva), to increase payments to plaintiffs for specified levels of energy deliveries for the period after December 31, 1995. Plaintif fs have reserved the right to continue the litigation with respect to the period after December 31, 1995, if CPUC approval is not obtained. On August 8,1996, SCE filed its application with the CPUC for approval of the settlement as it pertains to the period after 1995. On December 20, 1996, the ORA filed a protest to the application. In its protest, the ORA requests that the CPUC not grant the application or, in the alternative, that the CPUC conduct hearings on the application. On January 17, 1997, SCE filed a reply to the ORA's request. On February 27, 1997, a prehearing conference was held, at which time SCE's application was set for hearing to start on April 23, 1997. This hearing date was subsequently vacated by the assigned administrative law judge due to ongoing discussions to resolve issues raised by the ORA's protest. As a result of those discussions, SCE and the ORA entered into a stipulation and agreement (Stipulation) effective July 11, 1997. In the Stipulation, the ORA agrees to withdraw its protest and support SCE's application in return for SCE's agreement that the cost recovery issues presented in the application may be transferred for a decision in SCE's 1992 ECAC proceeding, where related issues are currently pending. The Stipulation further provides for SCE and the ORA to file a joint motion for approval of the stipulation. The motion was filed on September 25, 1997. In light of the Stipulation, plaintiffs and SCE have entered into two amendments to the May 1, 1996, settlement agreement. The first amendment provides for the post-1995 portion of the settlement to become ef fective through 1997 upon CPUC approval consistent with the Stipulation. The second amendment resulted in plaintiffs dismissing the lawsuit without prejudice pending final CPUC resolution of the issues raised by SCE's application. On December 16, 1997, the CPUC issued a decision which approves the application subject to che ter7 of the Stipulation. In light of this decision, SCE has supplemented testimony in the 1992 ECAC proceeding to support its request to recos its costs of settlement. Hearings in the 1992 ECAC began on March 9, 1.
- i. and are scheduled to conclude on approximately March 20, 1998.
Wind Generators' Litigation Between January 1994 and October 1994, SCE was named as a defendant in a series of eight lawsuits brought by independent power producers of wind generation. Seven of the lawsuits were filed in Los Angeles County Superior Court and one was filed in Kern County Superior Court. The lawsuits allege SCE incorrectly interpreted contracts with the plaintif fs by limiting fixed energy payments to a single 10-year period rather than beginning a new 10-year period of fixed energy payments for each stage of development. In its responses to the complaints, SCE denied the platntiffs' allegations. In each of the lawsuits, the plaintiffs seek declaratory relief regarding the proper interpretation of the contracts. Plaintiffs allege a combined total of approximately $189 million in damages, which includes consequential damages claimed in seven of the eight lawsuits. On March 1, 1995, the court in the lead Los Angeles Superior court case granted the plaintiffs' motion seeking summary adjudication that the contract language in question is not reasonably i susceptible to SCE's position that there is only a single, 10-year period 23 4 i of fixed payments. Following the March 1 ruling, a ninth lawsuit was filed in the Los Angeles Superior Court raising claims similar to those alleged in the first eight. SCE subsequently responded to the complaint in the new lawsuit by denying its material allegations. On April 5,1995, SCE filed a petition for Writ of Mandate, Prohibition or other Appropriate Relief, requesting that the Court of Appeal of the State of California, Second Appellate District issue a writ directing the Los Angeles Superior Court to vacate its March 1 order granting summary adjudication. In a decision filed August 9,1995, the Court of Appeal issued a writ directing that the order be overturned, and a new order be entered denying the motion. In light of the Court of Appeal decision in the lead Los Angeles case, a summary adjudication motion in the Kern County case was withdrawn. On March 25, 1996, pursuant to a court-approved stipulation, all but one of the cases were consolidated for trial in Los Angeles Superior Court. Shortly thereafter, on April 3, 1996, pursuant to stipulation of the parties, the Kern County case was ordered to be coordinated with the Los Angeles cases so that it too will be tried in Los Angeles. Trial of the consolidated cases, beginning with the lead case, commenced on March 10, 1997. The consolidated cases are to be tried one after another in bifurcated fashion with the liability phase of each and all of the cases to be tried before commencement of the damages phase, if applicable. T n timony and arguments in the liability phase of the lead case concluded 1 on May 20, 1997. On July 7, 1997, the court issued a tentative decision which effectively would resolve all liability issues in the lead case in SCE's favor. A proposed Statement of Decision consistent with the i conclusions in the tentative decision was submitted by SCE and argument on i the same took place at a hearing on October 31, 1997. The hearing was not concluded at that time s.1 further argument took place on November 17, 1997. On December 22, 1997, the judge ruled on the objections raised at the two hearings and ordered SCE to prepare a proposed Statement of Decision incorporating her ruling. SCE submitted this document to the court on January 13, 1998. At a hearing on February 4, 1998, the court, af ter considering additional objections to parts of the proposed order, directed SCE to prepare a further, revised order which would not materially change the court's previous, tentative rulings. This final statement of decision was filed on February 6, 1998. In addition, on February 20, 1998, the court entered a judgment against the lead Plaintiff. The court also scheduled another status and trial setting conference for April 2, 1998. Geothermal Generators' Litigation On June 9, 1997, SCE filed a complaint in Los Angeles Superior Court against another independent power producer of geothermal generation and five of its affiliated entities (collectively the " Defendants"). SCE alleges that in order to avoid power production plant shutdowns caused by excessive noncondensable gas in the geothermal field brine, the Defendants routinely vented highly toxic hydrogen sulfide gas from unmonitored release points beginning in 1990 and continuing through at least 1994, in violation of applicable federal, state and local environmental law. According to SCE, these violations cons'tituted material breaches by the Defendants of their obligations under their contracts and applicable law. The complaint seeks termination of the contracts and damages for excess power purchase payments made to the Defendants. The Defendants' motion to f transfer venue to Inyo County Superior Court was granted on August 31, 1997. On December 19, 1997, SCE filed a second amended complaint in resporce to which the Defendants filed a motion to strike, which was argued and taken under submission by the court on March 13, 1998. The Defendants also filed a motion for summary judgment, set for hearing on March 19, 1998, asserting that SCE's claims are timo-barred or were released in connection l with the settlement of prior litigation among some of the Defendants and two of SCE's affiliates, Mission Power Engineering Company, and The Mission Group (the Mission Parties). SCE asserts that the earlier j settlement does not bar the claims it is prosecuting in this matter and 24 b that these claims are not time-barred. SCE has filed its opposition to the motion for summary judgment and will shortly file a supplemental opposition to address certain additional matters raised by the Defendants. SCE has also filed a cross motion for summary adjudication with respect to =- the issues raised in Defendants' summary judgment motion. No hearing date has been scheduled for SCE's motion for summary adjudication. In addition, the Defendants have filed a motion to stay SCE's case pending resolution of certain technical issues by the Great Basin Air Quality Management District under the doctrine of primary jurisdiction. The motion was heard for hearing on March 13, 1998, and the matter was taken under submission at that time. The Defendants have also asserted various clabms against SCE and the Mission Parties in a cross-coniplaint filed in the action commenced by SCE as well as in a separate action filed against SCE by three of the Defendants in Inyo County Superior Court. Following a hearing on November 20, 1997, the court consolidated these actions for all purposes and ordered the Defendants to file a second amended cross-complaint. The second amended cross-complaint asserts nineteen causes of action against SCE, three of which are also asserted against the Mission Parties. Included are clai.ns for declaratory relief; breach of the implied covenant of good faith and fair dealing; inducing breach of employee agreements; breach of centract; disparagement, and slander per se; injunctive relief and restitution for unf air business practices; anticipatory breach of contract; violation of Public Utilities Code Sections 453, 707 and 2106,r i and negligent and intentional misrepresentation. Several of these claims ~ are premised on the theory that SCE has incorrectly interpreted the cross-complainants' contracts as providing for only a single " fixed price" period in view of the fact that the cross-complainants developed their projects in phases.m This theory has also been asserted by other independent power producers in litigation pending in Los Angeles Superior Court. (See, " Wind Generation Litigation" above.) SCE filed a demurrer to, and a motion to strike, in response te the second amended cross-a complaint, both of which were argued on March 13, 1998, and taken under submission by the court. ' Based on the common issues asserted in the Wind Generation Litigation and the Defendants' second amended cross-complaint, SCE filed a petition to coordinate the consolidated actions pending in Inyo County Superior Court with the Wind Generation Litigation pending in Los Angeles Superior Court. In connection with the petition to coordinate, SCE has also applied for a stay of all proceedings in Inyo County. Both the petition to coordinate "s and the application for stay will be decided by the judge presiding in the Wind Generation Litigation. A hetring has been scheduled with respect to both SCE's petit.8.on to coordinate and the application for stay on March 30, 1998. Discovery is' at a very preliminary stage, and it is reasonable to anticipate that there will be further amendments to the pleadings. The materiality of net final judgments against SCE in these actions would be largely dependent on the extent to which any damages or additional payments which might result therefrom are recoverable through rates. = Electric and Magnetic Fields (EMF) Litigation SCE is involved in three lawsuits alleging that various plaintiffs developed cancer as a result of exposure to EMF from CCE facilities. SCE denied the material allegations in its responses to each of these lawsuits. The first lawsuit was filed in Orange County Superior Court and served on SCE in June 1994. There are five named plaintiffs and six named defendants, including SCE. Three of the five plaintif fs are presently or were formerly employed by Grubb & Ellis, a real estate brokerage firm with offices located in a commercial building known as the Koll Center in 25 i 1 K \\ Newport Beach. Two.of the named plaintiffs are spouses of the cther plaintiffs. Grubb & Ellis and the owners and developers of tha Koll Center are also named as defendants in the lawsuit. This lawsuit alleges, among other things, that the three plaintiffs employed by Grubb & Ellis developed various forms of cancer as a result of exposure to EMF from electrical facilities owned by SCE and/or the other defendants located on Koll Center property. No specific damage amounts are alleged in the c>mplaint, but supplemental documentation prepared by the plaintiffs indicates that plaintif fs allege compensatory damages of approximately $8 million, plus unspecified punitive damages. In December 1995, the court granted SCE's motion for summary judgment and dismissed the case. Plaintiffs have filed a Netice of Appeal. Briefs have been submitted but no dats for oral argument has been set. A second lawsuit was filed in Orange County Superior Court and served on SCE in January 1995. This lawsuit arises out of the same fact situation as the June 1994 lawsuit dsacribed above and involves the same defendants. There are four named plaintiffs, two of whom were formerly employed by Grubb & Ellis and now allegedly have various forms of cancer. The other two plaintif f s are the spouses of those two individuals. No specific damage amounts are alleged in the complaint, but supplemental documentation prepared by the plaintiffs indicates that plaintif fs will allege compensatory damages of approximately $13.5 million, plus unspecified punitive damages. In April 1995, Grubb & Ellis filed a cross-complaint against the other co-defendants, requesting indemnification and declaratory relief concerning the rights and responsibilities of the parties. Although stayed for a time pending appellate review of sanctions imposed against plaintiffs' attorneys by the trial court, the case has been remanded back to thu trial court following the court of Appeal's decision modifying the sanctions order. To date, no further proceedings have been scheduled. A third case was filed in Orange County Superior Court and served on SCE in March 1995. The plaintiff alleges, among cther things, that he developed cancer as a result of EMF emitted from SCE distribution lines which he alleges were not constructed in accordance with CPUC standards. No specific damage amounts are alleged in the complaint but supplemental documentation prepared by the plaintiff indicates that plaintiff will allege compensatory damages of approximately $5.5
- million, plus unspecified punitive damages.
No trial date has been set in this case. San Onofre Personal Injury Litigation An SCE engineer employed at San Onofre died in 1991 from cancer of the aboomen. On February 6, 1995, his children sued SCE and SDG&E, as well as Combustion Engineering, the manufacturer of the fuel rods for the plant, in the U.S. District Court for the Southern District of California. Plaintiffs alleged that the former employee's illness resulted from, and was aggravated by, exposure to radiation at San Onofre, including contset with radioactive fuel particles released from failed fuel rods. Plaintif f s sought unspecified compensatory and punitive damages. On April 3, 1995, the court granted the defendants' motion to dismiss 14 of the plaintiffs' 15 claims. SCE's April 20, 1995, answer to the complaint denied all material allegations. On October 10, 1995, the court granted plaintiffs' motion to include the Institute of Nuclear Power Operations (an organization dedicated to achieving excellence ir nuclear power operations) as a defendant in the suit. On December 7. 1995, the court granted SCE's motion for summary judgment on the sole outstanding claim against it, basing the ruling on the worker's compensation system being the exclusive remedy for the claim. Plaintiffs have appealed this ruling to the Ninth Circuit Court of Appeals. Oral argument on the appeal took plage on December 4, 1997, and the matter iW now under submission. All trial court proceedings have been stayed pending the ruling of the Court of Appeals. The impact on SCE, if any, from further proceedings in this case against the remaining defendants cannot be determined at this time. 26 ~ = On July 5, 1995, a former SCE reactor operator and his wife sued SCE and SDGEE in the U.S. District Court for the Southern District of California. Plaintif fs also named Combustion Engineering, the manuf acturer of the fuel rods for the plant, and the Institute of Nuclear Power Operations as defendants. The former employee died of leukemia shortly after the complaint was filed. Plaintif f s allege that the former operator's illness resulted from, and was aggravated by, exposure to radiation at San Onofre, including contact with radioactive fuel particles released from failed fuel rods. Plaintif f s seek unspecified compensatory and punitive damages. On November 22, 1995, the complaint was amended to allege wrongful death and added the former employee's two children as plaintiffs. On December 22, 1995, SCE filed a motion to dismiss r, in the alternative, for summary judgment based on worker's compensat an exclusivity. On March 25, 1996, the court granted SCE's motion for i 4mmary judgment. Plaintiffs have appealed this ruling to the Ninth Circuit Court of Appeals. Oral argument on the appeal took place on December 4, 1997, and the matter is now under submission. All trial court proceedings have been stayed pending the ruling of the Court of Appeals in this case and in the case described in the above paragraph. The impact on SCE, if any, from further proceedings in this case against the remaining defendants cannot be determined at this time. On August 31, 1995, the wife and daughter of a former San Onofre security supervisor sued SCE and SDGCE in the U.S. District Court for the Southern District of California. Plaintif f s also named Combustion Engineering, the 4 manufacturer of fuel rods for the plant, and the Institute of Nuclear Power Operations as defendants. The security officer worked for a contractor in 1982, worked for SCE as a temporary employee (1982-1984), and later worked as an SCE security supervisor (1984-1994). The officer died of leukemia in 1994. Plaintiffs allege that the former officer's illness resulted from, and was aggravated by, his exposure to radiation at San Onofre, including contact with radioactive fuel particles released from failed fuel rods. Plaintiffs seek unspecified compensatory and punitive damages. SCE's November 13, 1995, answer to the complaint denied all material allegations. All trial court proceedings have been stayed pending the rulings of the Court of Appeals in the cases described in the above two paragraphs. On November 17, 1995, an SCE employee and his wife sued SCE in the U.S. District Court for the Southern District of California. Plaintiffs also named Combustion Engineering, the manufacturer of the fuel rods for the San Onofre plant. The employee worked for SCE et San Onofre from 1981 to 1990. Plaintiffs alleged that the employee transported radioactive byproducts on his person, clothing and/or tools to his home where his wife was then exposed to radiation that caused her leukemia. Plaintiffs seek unspecified compensatory and punitive damages. SCE's December 19, 1995, partial answer to the complaint denied all material non-employment related allegations. SCE's motion to dismiss the employee's employment related allegations based on worker's compensation exclusivity was granted on March 19, 1996. The employee's wife died on August 15, 1996. On September 20, 1996, the complaint was amended to allege wrongful death and to add the employee's two children as plaintiffs. SCE's motion for summary judgment was denied on April 9,1997. The trial in this case took place over approximately 22 days between January and March 1998 and resulted in a jury verdict for both defendants. It is not known whether plaintiffs will move for a new trial and/or appeal. On November 28, 1995, a former contract worker at San Onofre, her husband, and her son, sued SCE in the U.S. District court for the Southern District of California. Plaintiffs also named Combustion Engineering, the manuf acturer of the fuel rods for the San Onofre plant. Plaintiffs allege that the former contract worker transported radioactive byproducts on her person and clothing to her home where her son was then exposed to radiation that caused his leukemia. Plaintiffs seek unspecified compensatory and punitive damages. SCE'u January 2, 19J6, answer denied all material allegations. On August 12, 1996, the Court dismissed the 27 _ _ _ _ _ _ _ _ " - - ~ ' ' - - - - - - - _ _ _ _ This ence is claims of ths formar workar end her husband with projudles. expected to go to trial in mid-1998, after completion of ths trici court proceedings in the case described in the preceding paragraph. 1997, a former contract worker at San onofre and his wife On November 20, The sued SCE in the Superior Court of California, County of San Diego. contract worker was an ironworker at San Onofre during a portion of 1995. alleges that SCE allowed dangerous conditions to exist at San The suit His wife causing him to sustain unspecified personal injuries.
- Onofre, The case has been alleges loss of consortium and other general damages.
removed to the U.S. District Court for the Southern District of California. SCE filed a motion on January 6, 1998, asking that the case be converted to a Price-Anderson cause of action. Oil Pipeline Litigation On November 1, 1996, plaintiff, a crude oil pipeline company, filed a lawsuit against SCE and the City of Los Angeles (the City) in the United States District Court for the Central District of California claiming that SCE and the city had interfered with its attempt to construct a proposed 132-mile oil pipeline (Pacific Pipeline) designed to transport oil fror. the San Joaquin Valley and Santa Barbara to the Los Angeles refineries. Plaintiff alleges, among other things, that SCE and the City wrongfully initiated administrative and other legal proceedings in an attempt to Plaintiff derail and obetruct the construction of the Pacific Pipeline. alleges that these acts constitute unfair competition, tortious interference with economic advantage and violate state and federal antitrust laws. Plaintiff further claims that because of the alleged it could suffer losses in excess of $300 million. Additionally,
- delayw, plaintiff seeks treble and punitive damages.
On June 30, 1997, SCE filed an answer to the complaint denying the Plaintiff and substantive allegations and rai. sing appropriate defenses. SCE reached a settlement of this dispute for nonmonetary compensation. An agreement to dismiss the lawsuit was filed with the court on February 8, 1998. False Claims Act Litigation In September 1997, SCE became aware of a complaint filed in the Southern District of the U.S. District Court of California by a San Onofre employee, acting at his own initiative on behalf of the United States against SCE and SDG&E. The complaint alleges under the False Claime Act, that SCE and SDG&E have submitted fraudulent claims to the United States the State of California and their customers resulting in $491 government, The million in overpayments (S383 million of which is attributed to SCE). employee alleges that SCE and SDG&E provided the CPUC with data which inflated projected costs at San Onofre while minimizing projected revenue, The amount sought in this resulting in the CPUC setting inflated rates. complaint is subject to trebling, plus civil penalties of $10,000 per false claim submitted for payment (for an unspecified number of claims). SCE and SDG&E filed separate motions to dismiss this lawsuit on November 1997. The employee responded to both motions on December 20, SCE and SDG&E replied to the employee's response on January 13, 1998. 6, 1997. 1998, and Oral argument on the motion to dismiss was heard on January 20, the court has the matter under submission. Mohave Generating Station Env# 3 ental Litigation l On February 19, 1998, the Sierra Club a a Grind Canyon Trust filed suit against SCE. Mohave is operated bc and SCE is one of several co-owners. The lawsuit alleges that Mohave has been violating various the Nevada stnte implementation plan, provisions of the Clean Air Act, permits relating to opacity and sulfur dioxide and applicable pollution i f 28 .~. s emi 31cn limito ever th3 lect fiva yacro. Th2 plaintiffs seek declaratory and injunctive relief as well as civil penalties. Under the clean Air Act, the maximum civil penalty obtaini.ble is $25,000 per day of violation. j Item 4. Submission of Matters to a Vote of Security Holders Inapplicable. Pursuant to Form 10-K's General Instruction (" General Instruction") G(3), the following information is included as an additional item in Part Is m Executive Officers of the Registrant Age at December Effective Executlw Officer
- 31. 1997 rdmaryPosition Date John E. Bryson 54 Chairman of the Board, October 1, 1990 Chief Executive Officer and Director Stephen E. Frank 56 President, Chief Operating June 19, 1995 Officer and Director Bryant C. Danner 60 Executive Vice President June 1, 1995 and General Counsel l
A!an J. Fahrer 47 Executive Vice President and September 1, 1996 l j l Chief Financial Officer i Harold B. Ray 57 Executive Vice President, June 1, 1995 l Generation Business Unit Theodore F. Craver, Jr. 46 Senior Vice President and Treasurer February 18, 1998 John R. Fletder 52 Senior Vice President, Regulatory February 18, 1998 Policy and Affairs l Robert G. Foster 50 Senior Vice President, Novenber 21, 1996 l Public Affairs Richard M. Rosenblue 47 Senior Vice President, February 18, 1998 T&D Wires Business Unit i Pamela A. Bass 50 Vice President, Customer June 1, 1996 Solutions Business Unit Richard K. Bushey 57 vice President and Controller January 1, 1984 l Bruce C. Foster 45 Vice President, San Francisco January 1, 1995 Regulatory Affairs l Thomas J. Higgins 52 Vice President, Corporate April 1, 1995 l Connunications Beverty P. Ryder 47 Corporate Secretary January 1, 1996 (1) Executive Officers are defined by Rule 3b-7 of the General Rules and Regulations under the Securities Exchange Act of 1934, as amended. Executive Officers, Bryson, Dinner, Fohrer, Craver, Robert Foster, Bushey, Higgins, and Ryder hold the same positions with Edison International. Edison International is the parent holding company of SCE. 4 29 Nono of SCM'o cxscutivo offic3rc aro roltted to occh othsr by blood or marriage. As set forth in Article IV of SCE's Bylaws, the of ficers of SCE are chosen annually by and serve at the pleasure of SCE's Board of Directors and hold their respective offices until their resignation, removal, other disqualification from service, or until their respective successors are elected. All of the executive officers have been actively engaged in the business of SCE for more than five years except for Stephen i E. Frank, Theodore F. Craver, Jr., Bruce C. Foster, Thomas J. Higgins, and Beverly P. Ryder. Those officers who have not held their present position for the past five years had the following business experiences Stephen E. Frank President and Chief Operating Officer, August 1990 to January 1995 Florida Power and Light Company"' Bryant C. Denner Senior Vice President and July 1992 to May 1995 General Couns(L of Edison International and SCE Alan J. Fohrer Executive Vice Pred dent, Chief February 1996 to August 1996 Financial Officer and Treasurer of SCE Executive Vice President and May 1995 to January 1996 Chief Financial Officer of SCE Executive Vice President, Chief May 1995 to August 1996 Financial Officer and Treasurer of Edison International Senior Vice President, Chief January 1993 to April 1995 Financial Officer and Treasurer of Edison International Senior Vice President and Chief January 1993 to April 1995 Financial Officer of SCE Vice Presidont, Chief Financiat April 1991 to January 1993 officer and Treasurer of Edison International and SCE Harold B. Ray Senior Vice President, Power Systems June 1990 to May 1995 Theodore F. Craver, Jr. Vice President and Treasurer, SCE September 1996 to February 1998 Executive Vice President and Corporate September 1990 to August 1996 Treasurer, First Interstate Bancorp"' John R. Fletder Vice President, Regulatory Policy Februarv 1992 to January 1998 and Public Affairs Robert G.' Foster Vice President, Public Affairs November 1993 to January 1996 Regional Vice President, Sacramento January 1988 to October 1993 Office Richard M. Rosenblue Vice President, Distribution January 1996 to January 1998 Business Unit Vice President, Nuclear Engineering June 1993 to December 1995 and Technical Services Manager of Nuclear Regulatory Affairs June 1989 to May 1993 Bruce C. Foster Regional Vice President, San Francisco January 1992 to December 1994 office Thomas J. Higgins Vice President, Corporate Comununications April 1995 to January 1996 President, The Laurel Company""" January 1994 to December 1994 Senior Vice Prealdent of Blue October 1990 to December 1993 Cross / Blue Shield of Maryland'" Beverly P. Ryder Special Assistant to the Chairman May 1995 to December 1995 of Edison International and SCE Director, Strategic ALLlances, October 1993 to April 1995 EnvestSCE" General Manager, customer Solutions Jme 1992 to September 1993 (1) This entity is not a parent, subsidiary or other affiliate of SCE. 30 (2) A3 Procid:nt of Th3 L2urol Company, ThomSo J. Higgina provid:d cdvies on planning and financing for mergers and acquisitions for clients in the managed health care business. (3) This entity is a division of SCE. PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters Certain information responding to Item 5 with respect to frequency and amount of cash dividen<is is included in SCE's Annual Report to Shareholders for the year ended December 31, 1997, (" Annual Report") under " Quarterly Financial Data" on page 40 and is incorporated by reference pursuant to General Instruction G(2). As a result of the formation of a holding company described above in Item 1, all of the issued and outstanding common stock of SCE is owned by Edison International and there is no market for sue tock. Item 6. selected Financial Data Information responding to Item 6 is included in the Annual Report under " Selected Financial and Operating Data: 1993-1997" on page 1 and is incorporated herein by reference pursuant to General Instruction G(2). Item 7. Management's Dircussion and Analysis of Results of Operations and Financial Condition Information responding to Item 7 is included in the Annual Report under " Management's Discussion and Analysis of Results of Operations and Financial Condition" on pages 2 through 14 and is incorporated herein by reference pursuant to General Instruction G(2). Item 8. Financial Statements and Supplementary Data - Certain information responding to Item 8 is set forth after Item 14 in Part IV. Other information responding to Item 8 is included in the Annual Report on pages 15 through 40, and is incorporated herein by reference pursuant to General Instruction G(2). Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. 4 PART III Item 10. Directors and Executive Officers of the Registrant Information concerning executive officers of Edison International is set forth in Part I in accordance with General Instruction G(3), pursuant to Instruction 3 to Item 401(b) of Regulation S-K. Other information responding to Item 10 is included in the Joint Proxy Statement (" Proxy Statement") filed with the Commission in connection with SCE's Annual Meeting to be held on April 16, 1998, under the heading, " Election of Directors of Edison International and SCE" on pages 3 through 6 and "Section 16(a) Beneficial Ownership Reporting Compliance" on page 22, and is incorporated herein by reference pursuant to General Instruction G(3). Item 11. Executive Compensation Information responding to Item 11 is included in the Proxy Statement beginning with the section under the heading " Executive Compensation Table - Edison International and SCE" on pages 9 through 20, and is incorporated herein by reference pursuant to General Instruction G(3). 31 Item 12. S curity owntr hip cf Cartain Be = ficini Own:rs cad Maurg sett Information responding to Item 12 is includrd in tho Proxy Otctement under the headings " Stock Ownership of Directors and Executive Officers of Edison International and SCE" on pages 7 through 10 and ' Stock Ownership of certain Shareholders" on page 31, and is incorporated herein by reference pursuant to General Instruction G(3). Item 13. Certain Relationships and Related Transactions Information responding to Item'13 is included in the Proxy Statement under the heading "Certain Relationships and Transactions of Nominees and Executive Of ficers" on pages 22 through 25, and is incorpor2ted herein by reference pursuant to General Instruction G(3). PART IV Item 14. Exhibits, Financial Statement Schedules, and Re;vecs on Forn 8-K (a)(1) Financial Statements The following items contained in the 1997 Annual Report to Shareholderr are incorporated by reference in this report. Management's Discussion and Analysis of Results of Operations and Financial Condition consolidated Statements of Income -- Years Ended December 31, 1997, 1996 and 1995 Consolidated Statements of Retained Earnings -- Years Ended December 31, 1997, 1996 and 1995 Consolidated Balance Sheets -- December 31, 1997, and 1996 Years Ended December 31, Consolidated Statements of Cash Flows 1997, 1996 and 1995 Notes to Consolidated Financial Statements Responsibility for Financial Reporting Report of Independent Public Accountants (2) Report of Independent Public Accountants and Schedules Supplementing Financial Statements The following documents may be found in this report at the indicated page numbers. Page Report of Independent Public Accountants on Supplemental 33 Schedules Schedule II--Valuation and Qualifying Accounts for the Years 34 Ended December 31, 1997, 1996 and 1995 Schedules I through V, except those referred to above, are omitted as not required or not applicable. (3) Exhibits See Exhibit Index on page 38 of this report. (b) Reports on Form 8-K December 8, 1997 Item 5: Other Events: Sale of Southern California Edison Company's 10 Gas-fired Generating Plants December 17, 1997 Item 5: Other Events: Rate Reduction Bonds Sold February 13, 1998 Sale of Southern California Edison Company's Item 5: Other Events: Long Beach Gas-Fired Generating Plant l 32 .-~ REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SUPPLEMENTAL SCHEDULES To Southern California Edison Company: We have audited in accordance with generally accepted auditing standards, the consolidated financial statements included in the 1997 Annual Report to Shareholders of Southern California Edison Company (SCE) incorporated by reference in this Form 10-K, and have issued our report thereon dated i January 30, 1998. Our audits of the consolidated financial statements were made for the purpose of forming an opinion on tlise basic consolidated financial statements taken as a whole. The supplemental schedules listed in Part IV of this Fcra lO-K, which are the responsibility of SCE's management, are presented for purposes of complying with the Securities and Exchange Commission's rules and t regulations, and are not part of the basic consolidated financial statements. These supplemental schedules have been subjected to the auditing procedures applied in the audits of the basic consolidated financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole. ARTHUR ANDERSEN LLP Los Angeles, California January 30, 1998 l l l 4 4 33 l SOUTHERN CALIFORNIA EDISON CONPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS For the Year Ended December 31, 1997 Additions Balance at Charged to Charged to Balance Begiming of Costs and Other at End Description Period Expenses Accomts Deductions of Period (In thousands) Group A Uncollectible accounts -. S 20,742 5 24,245 Customers $ 24,390 $ 20,597 5 661 2,208 All other 1,689 1,180 S 21,403(a) $ 26,453 Total $ 26,079 $ 21,777 33333335 E3333335 55353333 33353555 E333333E Group B: DOE Decontamination $ 1,089(b) $ 5,542(c) $ 44,336 and Decomissioning $ 48,789 5 67,320(d) 29,380(e) 145,640 Purchased-power settle.nents 107,700 Pension and benefits 180,927 102,193 17,624(f) 89,544(g) 211,200 Insurance, casualty erud 65,797(h) 78,461 other 86,509 57,749 Total $423,925 5159,942 5 86,033 $190,263 $479,637 ===..... ==..... (a) Accounts written off, net. (b) Represents revision to estimate based on actual billings. c (c) Represents amounts paid. (d) Represents the present value of payments to be made under an agreement to terminate a purchased-power contract. (e) Represents the amortization of the liability established for purchased-power contract settlement agreements. (f) Primarily represents transfers from the accrued paid absence allowance account for required additions to the comprehensive disability plan accounts. (g) Includes pension payments to retired employees, amounts paid to active employees during periods of illness and the funding of certain pension benefits. (h) Amounts charged to operations that were not covered by insurance. c 34 I i + l SOUTHERN CALIFORNIA EDISON COMPANY l SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS l For the Year Ended December 31, 1996 l Addltions Balance at Charged to Diarged to Balance Begirviing of Costs and Other at End Deserfption Period. Expenses Accounts DedJetions of Period (In thousands) Group As uncollectible accounts -- Customers S 22,126 $ 21,831 s $ 19,567 $ 24,390 All other 2,013 376 700 1,689 Total s 24,139 s 22,207 8 $ 20,267(a) $ 26,079 Group B: DOE decontamination and decomunissioning S 52,742 5 s 1,468(b) $ 5,421(c) $ 48,789 Purchased-power settlement 107,700(d) 107,700 Pension and benefits 196,662 8,547 21,869(e) 46,151(f) 180,927 Insurance, casuelty and other 94,788 59,123 67,402(g) 86,509 Total $344,192. S67,670 $131,037 $118,974 S423,925 (a) Accounts written off, net. (b) Represents revision to estimate based on actual billings. j (c) Represents amounts paid. (d) Represents payments to be made under an agreement to terminate a purchased-power contract. i (e) Primarily represents transform from the accrued paid absence allowance account for required additions to the comprehensive disability plan accounts. (f) Includes pension payments to retired employees, amounts paid to active employees during periods of illness and the funding of certain pension benefits. I l i (g) Amounts chargec' to operations that were not covered by insurance. J l l r i I l J l 35 i l l 1 l SOUTHERN CALIFORNIA EDISON CONPANY SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS For the Year Ended December 31, 1995 Additions satance at Charsed to Charsed to Balance Begiming of Costs and other at End Description Period Expenses Accomts Deductions of Period (In thousands) Group A Uncollectible accounts -- s 21,000 s 22,179 s S 21,053 S 22,126 1,594 2,013 Customers All other 2,806 801 $ 22,647(a) S 24,139 Total S 23,806 S'22,980 Group B: DOE Decontamination $ 1,531(b) S 5,274(c) $ 52,742 and Decommissioning 5 56,485 s Pension and benefits 174,851 42,805 23,676(d) 44,670(e) 196,662 Insurance, casualty and 59,690(f) 94,788 79,727 74,751 other Total $311,063 $117,556 S25,207 $109,634 $344,192 (a) Accounts written off, net. (b) Represents revision to estimate based on actual billings. (c) Represents amounts paid. Primarily represents transfers from the accrued paid absence allowance (d) for required additions to the comprehensive disability plan account accounts. Includes pension payments to retired employees, amounts paid to active (e) employees during periods of illness and the funding of certain pension benefits. Amounts charged to operations that were not covered by insurance. (f) 36 o SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. SOUTHERN CALIFORNIA EDISON COMPANY By Kennetle S. Stewart Kenneth S. Stewart Assistant General Counsel 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 registrent and in the capacities and on the dates indicated. signature Title Date Principal Executive Officer: John E. Bryson* Chairman of the Board, March 24,1998 Chief Executive Officer and Director Principal Financial Officer: Alan J. Fohrer* Executive Vice President March 24,1998 and Chief Financial Officer controller or Principal Accounting Officers Richard K. Bushey* Vice President and March 24,1998 Controller Board of Directors Winston H. Chen* Director March 24,1998 Warren Christopher
- Director March 24,1998 Stephen E. Frank
- Director March 24,1998 Camilla C.
Frost
- Director March 24,1998 Joan C. Hanley*
Director March 24,1998 Carl F. Huntsinger* Director March 24,1998 Charles D. Miller
- Director March 24,1998 Luis G. Nogales*
Director March 24,1998 Ronald L. Olson* Director March 24,1998 J. J. Pinola* Director March 24,1998 James M. Rosser* Director March 24,1998 E. L. Shannon, Jr.* Director March 24,1993 Robert H. Smith
- Director March 24,1998 Thomas C.
Sutton* Director March 24,1998 Daniel M. Tellep* Director March 24,1998 James D. Watkins* Director March 24,1998 Edward Zapanta* Director March 24,1998
- By Kenneth S. Stewart Kenneth S. Stewart l
Assistant General Counsel l t 37 l l T e EZHIB3T INDEZ Exhibit Number Description 3.1 Restated Articles of Incorporation as amended through January 1996 (File No. 1-2313)* 1998 3.2 Bylaws as adopted by the Board of Directors on January 1, 4.1 Trust Indenture, dated as of October 1, 1923 (Registration No. 2-1369)* 4.2 Supplemental Indenture, dated as of March 1, 1927 (Registration No. 2-1369)* 4.3 Second Supplemental Indenture, dated as of April 25, 1935 (Registration No. 2-1472)* 4.4 Third Supplemental Indenture, dated as of June 24, 1935 (Registration No. 2-1602)* 4.5 Fourth Supplemental Indenture, dated as of September 1, 1935 (Registration No. 2-4522)* 4.6 Fifth Supplemental Indenture, dated as of August 15, 1939 (Registration No. 2-4522)* 4.7 Sixth Supplemental Indenture, dated as of September 1, 1940 (Registration No. 2-4522)* 4.8 Seventh Supplemental Indenture, dated as of January 15, 1948 (Registration No. 2-7369)* 4.9 Eighth Supplemental Indenture, dated as of August 15, 1948 (Registration No. 2-7610)* 4.10 Ninth Supplemental Indenture, dated as of February 15, 1951 (Registration No. 2-8781)* 4.11 Tenth Supplemental Indenture, dated as of August 15, 1951 (Registration No. 2-7966)* 4.12 Eleventh Supplemental Indenture, dated as of August 15, 1953 (Registration No. 2-10396)* 4.13 Twelfth Supplemental Indenture, dated as of August 15, 1954 (Registration No. 2-11049)* 4.14 Thirteenth Supplemental Indenture, dated as of April 15, 1956 (Registration No. 2-12341)* 4.15 Fourteenth Supplemental Indenture, dated as of February 15, 1957 (Registration No. 2-13030)* 4.16 Fifteenth Supplemental Indenture, dated as of July 1, 1957 (Registration No. 2-13418)* 4.17 Sixteenth Supplemental Indenture, dated as of August 15, 1957 (Registration No. 2-13516)* 4.18 Seventeenth Supplemental Indenture, dated as of August 15, 1958 (Registration No. 2-14285)* 4.19 Eighteenth Supplemental Indenture, dated as of January 15, 1960 (Registration No. 2-15906)* 4.20 Nineteenth Supplemental Indenture, dated as of August 15, 1960 (Registration No. 2-16820)* 4.21 Twentieth Supplemental Indenture, dated as of April 1, 1961 (Registration No. 2-17668)* 4.22 Twenty-First Supplemental Indenture, dated as of May 1, 1962 (Registration No. 2-20221)* 4.23 Twenty-Second Supplemental Indenture, dated as of October 15, 1962 (Registration No. 2-20791)* dated as of May 15, 1963 4.24 Twenty-Third Supplemental Indenture, (Registration No. 2-21346)* 4.25 Twenty-Fourth Supplemental Indenture, dated as of February 15, 1964 (Registration No. 2-22056)* 38 21HIIIT INDEI Exhibit Number Description 4.26 Twenty-Fif th Supplemental Indenture, dated as of February 1,1965 (Registration No. 2-23082)* 4.27 Twenty-Sixth Supplemental Indenture, dated as of May 1, 1966 (Registration No. 2-24835)* 4.28 Twenty-Seventh Supplemental Indenture, dated as of August 15, 1966 (Registration No. 2-25314)* 4.29 Twenty-Eighth Supplemental indenture, dated as of May 1, 1967 (Registration No. 2-26323)* 4.30 Twenty-Ninth Supplemental Indenture, dated as of February 1,1968 (Registration No. 2-28000)* 4.31 Thirtieth Supplemental Indenture, dated as of January 15, 1969 (Registration No. 2-31044)* 4.32 Thirty-First Supplemental Indenture, dated as of 3ctober 1,1969 (Registration No. 2-34839)* 4.33 Thirty-Second Supplemental Indenture, dated as of December 1, 1970 (Registration No. 2-38713)* 4.34 Thirty-Third Supplemental Indenture, dated as of September 15, 1971 (Registration No. 2-41527)* 4.35 Thirty-Fourth Supplemental-Indenture, dated as of August 15, 1972 (Registration No. 2-45046)* 4.36 Thirty-Fifth Supplemental Indenture, dated as of February 1,1974 (Registration No. 2-50039)* 4.37 Thirty-Sixth Supplemental Indenture, dated as of July 1, 1974 (Registration No. 2-59199)* 4.38 Thirty-seventh Supplemental Indenture, dated as of November 1, 1974 (Registration No. 2-52160)* 4.39 Thirty-Eighth Supplemental Indenture, dated as of March 1, 1975 (Registration No. 2-52776)* 4.40 Thirty-Ninth Supplemental Indenture, dated as of March 15, 1976 (Registration No. 2-55463)* 4.41 Fortieth Supplemental Indenture, dated as of July 1, 1977 (Registration No. 2-59199)* 4.42 Forty-First Supplemental Indenture, dated as of November 1, 1978 (Registration No. 2-62609)* 4.43 Forty-Second Supplemental Indenture, dated as of June 15, 1979 (File No. 1-2313)* 4.44 Forty-Third Supplemental Indenture, dated as of September 15, 1979 (File No. 1-2313)* 4.45 Forty-Fourth Supplemental Indenture, dated as of Octob' 1,1979 (Registration No. 2-65493)* 4.46 Forty-Fifth Supplemental Indenture, dated as of April 1, 1980 (Registration No. 2-66896)* 4.47 Forty-Sixth Supplemental Indenture, dated as of November 15, 1980 (Registration No. 2-69609)* 4.48 Forty-Seventh Supplemental Indenture, dated as of May 15, 1981 (Registration No. 2-71948)* 4.49 Forty-Eighth Supplemental Indenture, dated as of August 1, 1981 (File No. 1-2313)* 4.50 Forty-Ninth Supplemental Indenture, dated as of December 1,1981 (Registration No. 2-74339)* l 4.51 Fiftieth Supplemental Indenture, dated as of January 16, 1982 i (File No. 1-2313)* l 4.52 Fifty-First Supplemental Indenture, dated as of April 15, 1982 l (Registration No. 2-76626)* 39 s EIHIDIT INDEI Exhibit Description Number Fifty-Second Supplemental Indenture, dated as of November 1,1982 4.53 (Registration No. 2-79672)* Fif ty-Third supplemental Indenture, dated as of November 1,1982 4.54 (File No. 1-2313)* Fif ty-Fourth supplemental Indenture, dated as of January 1,1983 4.55-(File No. 1-2313)* Fif ty-Fif th Supplemental Indenture, dated as of May 1,1983 (File 4.56 No. 1-2313)* Fif ty-Sixth Supplemental Ind3nture, dated as of December 1,1984 4.57 (Registration No. 2-94512)* 4.58 Fifty-Seventh Supplemental Indenture, dated as of March 15, 1985 (Registration No. 2-96181)* Fifty-Eighth Supplemental Indenture, dated as of October 1,1985 4.59 ,(File No. 1-2313)* 15, 1985 4.60 Fifty-Ninth Supplemental Indenture, dated as of October (File No. 1-2313)* Sixtieth Supplemental Indenture, dated as of March 1,1986 (File 4.61 No. 1-2313)* 4.62 Sixty-First Supplemental Indenture, dated as of March 15, 1986 (File No. 1-2313)* 1986 Sixty-second Supplemental Indenture, dated as of April 15, 4.63 (File No. 1-2313)* dated as of April 15, 1986 4.64 Sixty-Third Supplemental Indenture, (File No. 1-2313)* dated as of July 1, 1986 4.65 Sixty-Fourth Supplemental Indenture, (File No. 1-2313)* l Sixty-Fif th Supplemental Indenture, dated as of September 1,1986 l 4.66 (File No. 1-2313)* Sixty-Sixth Supplemental Indenture, dated as of September 1,1986 4.67 l (File No. 1-2313)* 4.68 Sixty-Seventh Supplemental Indenture, dated as of December 1, 1986 (File No. 1-2313)* 4.69 Sixty-Eighth Supplemental Indenture, dated as of July 1, 1987 (Registration No. 33-19541)* 25, 1987 4.70 Sixty-Ninth Supplemental Indenture, dated as of October (Registration No. 33-19541)* 4.71 Seventieth Supplemental Ir. denture, dated as of November 1, 1987 (File No. 1-2313)* dated as of February 15, 4.72 Seventy-First Supplemental Indenture, 1988 (File No. 1-2313)* 15, 1988 Seventy-second Supplemental Indenture, dated as of April 4.73 (File No. 1-2313)* dated as of July 1, 1988 4.74 Seventy-Third Supplemental Indenture, (File No. 1-2313)* dated as of August 15, 4.75 Seventy-Fourth Supplemental Indenture, 1988 (File No. 1-2313)* Seventy-Fifth Supplemental Indenture, dated as of September 15, 4.76 1988 (File No. 1-2313)* 4.77 Seventy-Sixth Supplemental Indenture, dated as of January 15, 1989 (File No. 1-2313)* Seventy-Seventh supplemental Indenture, dated as of May 1, 1990 4.78 (File No. 1-2313)* 1990 Seventy-Eighth supplemental Indenture, dated as of June 15, '4.79 (File No. 1-2313)* 15, 1990 Seventy-Ninth Supplemental Indenture, dated as of August 4.80 (File No. 1-2313)* dated as of December 1, 1990 4.81 Eightieth Supplemental Indenture, (File No. 1-2313)* I 40 e-6 EERIOIT IND32 Exhibit Number Description 4.82 Eighty-First Supplemental Indenture, dated as of April 1, 1991 (File No. 1-2313)* 4.83 Eighty-second Supplemental-Indenture, dated as of May 1, 1991 (File No. 1-2313)* 4.84 Eighty-Third Supplemental Indenture, dated as of June 1, 1991 (File No. 1-2313)* 4.85 Eighty-Fourth Supplemental Indenture, dated as of December 1, 1991 (File No. 1-2313)* 4.86 Eighty-Fifth Supplemental Indenture, dated as of February 1,1992 (File No. 1-2313)* 4.87 Eighty-Sixth Supplemental Indenture, dated as of April 1, 1992 (File No. 1-2313)* 4.88 Eighty-Seventh Supplemental Indenture, dated as of July 1, 1992 (File No. 1-2313)*- 4.89 Eighty-Eighth Supplemental Indenture, dated as of July 15 1992 (File No. 1-2313)* 4.90 Eighty-Ninth Supplemental Indenture, dated as of December 1,1992 -(File No. 1-2313)* 4.91 Ninetieth Supplemental Indenture, dated as of January 15, 1993 (File No. 1-2313)* 4.92 Ninety-First Supplemental Indenture, dated as of March 1, 1993 (File No. 1-2313)* 4.93 Ninety-Second Supplemental Indenture, dated as of June 1,1993* 4.94 Ninety-Third Supplemental Indenture, dated as of June 15, 1993 (File No. 1-2313)* 4.95 Ninety-Fourth Supplemental Indenture, dated as of July 15, 1993 (File No. 1-2313)* 4.96 Ninety-Fifth Supplemental Indenture, dated as of September 1, 191' (File No. 1-2313)* 4.97 Nines f-sixth supplemental Indenture, dated as of October 1,1993 (File No. 1-2313)* 41 4 EIBIGIT INDEI Exhibit Number Description 10.1 1981 Deferred Compensation Agreement (File No. 1-2313)* 10.2 1985 Deferred Compensation Agreement for Executives (File No. 1-2313)* 10.3 1985 Deferred Compensation Agreement for Directors (File No. 1-2313)* 10.4 Director Deferred Compensation Plan (File No. 1-9936)* 10.5 Director Grantor Trust Agreement (File No. 1-9936)* 10.6 Executive Deferred Compensation Plan (File No. 1-9936)* 10.7 Executive Grantor Trust Agreement (File No. 1-9936)* 10.8 Executive Supplemental Benefit Program (File No. 1-2313)* 10.9 Executive Retirement Plan (File No. 1-2313)* 10.10 Employment Agreement with Howard P. Allen (File No. 1-2313)* 10.11 1996 Executive Incentive Compensation Plan (File No. 1-9936)* 10.12 Executive Incentive Compensation Plan 10.13 Executive Disability and Survivor Benefit Program (File No. 1-9936)* 10.14 Retirement Plan for Directors 10.15 Director Incentive Compensation Plan (File No. 1-2313)* 10.16 Officer Long-Term Incentive Compensation Plan 10.16.1 Form of Agreement for 1989-1995 Awards under the officer Long-Term Incentive Compensation Plan (File No. 1-9936)* 10.16.2 Form of Agreement for 1996 Awards under the officer Long-Term Incentive Compensation Plan (File No. 1-2313)* 10.16.3 Form of Agreement for 1997 Awards under the Officer and Management Long-Term Incentive Compensation Plans 10.17 Estate and Financial Planning Program (File No. 1-9936)* 10.18 Consulting Arrangement with Howard P. Allen 10.19 Employment Agreement with Bryant C. Danner (File No. 1-9936)* 10.20 Employment Agreement with Stephen E. Frank (File No. 1-9936)* 10.21 Election terms for Warren Christopher Computation of Ration of Earnings to Fixed Charges 12. 1997 Annual Report to shareholders for year ended December 31, 13. Consent of Independent Public Accountants - Arthur Andersen LLP 23. Power of Attorney 24.1 Certified copy of Resolution of Board of Directors Authorizing 24.2 Signature 27 Financial Data Schedule Incorporated by reference pursuant to Rule 12b-32. 42 O 6 (THIS PAGE INTENTIONALLY LEFT BLANK) g.-. 8 4 (THIS PAGE INTENTIONALLY LEFT BLANK) l l l