JOINT LEGISLATIVE UTILITY
REVIEW COMMITTEE
REPORT TO THE
1997 GENERAL ASSEMBLY
OF NORTH CAROLII{A
I
I
5"*h @arulin a Weneral Sxxemblg
lJoinl p"egixla !fltilitg pebietu Osmmittee
State
pa
tihe ptililg plehietu Qlor
p"egiNlatibe puilning
big\ zznol,zsrs
SENATOR DAVIO W. HOYLE
CoCHAIRMAN
PO. Box 2494
GAsroNrA, N.C. 24053
STEVE J. ROSE, CoMMITTEE CoUNSEL
545 LEGTSLATIVE OFFICE BUILDTNG
3OO NoRTH SALTSBURY STREET
RALETcH, N.C. 27603-5925
TELEPHONE: (9 l9) 733-2574
FACStMILE: (9 I 9) 7 I 5-5460
REPRESENTATIVE W. W. 'DUB" DICKSON
COCHAI RM AN
7 I 8 AVON OALE ROAO
GASroNrA, N.C. 24054
PENNY N. WILLIAMS. COMMITTEE CLERK
TELEPHoNE: (9 | 9) 733-5734
FAcsrMrLE: (919) 733-31 l3
March 27, 1997
TO THE MEMBERS OF THE 1997 GENERAL ASSEMBLY:
Pursuant to Article 12.\ of Chapter 120 of the North Carolina General Statutes, and
Chapter 542 of the 1995 Session Laws, the Joint Legislative Utility Review Committee
herewith submits its report to the General Assembly.
Rep. W.W. "Dub" Dickson
House Cochairman
Senator David Wl
JOINT LEGISLATIVE UTILITY REVIEW COMMITTEE
MEMBERSHIP
President Pro Tempore Appointments
Sen. David W. Hoyle, Cochair
P.O. Box 2494
Gastonia, NC 28053
(704) 867-0822
Sen. R. L. Martin
P.O. Box 387
Bethel, NC 27812
(919) 82s-4361
Sen. David Parnell (until 12131196)
P.O. Box 100
Parkton, NC 28372
(9r0) 8s8-8326
Sen. Paul S. Smith (until 12131196)
P.O. Box 916
Salisbury, NC 28145-0916
(704) 633-9463
Sen. R.C. Soles
P.O. Box 6
Tabor City, NC 28463
(910) 6s3-20rs
Sen. Howard N. Lee (appointed 1/30/97)
109 Glenview Place
Chapel Hill, NC 27514
(91e) 942-6s28
Sen. Betsy L. Cochrane (appointed ll30l97)
122 Azalea Circle
Advance, NC 27006
(e10) 9e8-88e3
Staff:
Steven Rose
Research Division
(919) 733-2s78
Speaker's Appointments
Rep. W.W. "Dub" Dickson, Cochair
718 Avondale Road
Gastonia, NC 28054
(704)864-123r
Rep. Danny McComas
P.O.B,ox2274
Wilmington, NC 28442
(er0)343-8372
Rep. Richard T. Morgan
570 Pinehurst South
Pinehurst, NC 28374
(9r0)29s-4s7s
Rep. Dennis Reynolds
348 Holly Hill Lane
Burlington,NC 27215
(9r0) s38-060r
Rep. Tim Tallent
P.O. Box 1170
Kannapolis, NC 28082
(704) 938-4101
Clerk:
Penny Williams
(erg\ 733-5734
l-1
TABLE OF CONTENTS
Page
LETTEROF TRANSMITTAL ...........i
COMMITTEE MEMBERSHIP ...........ii
INTRODUCTION ...........1
AVOIDED COST - PAYMENTS TO SMALL HYDROELECTRIC
POWER PRODUCERS ... ......3
OTHER ACTIVITIES OF THE COMMITTEE ......7
APPENDICES
A. SUBPART B. PART XX, CHAPTER 542 OF THE 1995 SESSION
LAWS .......A-1
B. NORTH CAROLINA SMALL HYDRO (Clean Electricity from
Renewable Natural Resources ........B-l
C. STATEMENT TO THE JOINT LEGISLATIVE UTILITY REVIEW
COMMITTEE ON AVOIDED COSTS FOR HYDROELECTRIC
QUALIFYINGFACILITIES(CommissionerDuncan) .......C-l
D. STATEMENT TO THE JOINT LEGISLATIVE UTILITY REVIEW
COMMITTEE ON RECENT NATURAL GAS ACTIVITIES AT
THE UTILITIES COMMISSION (Commissioner Cobb) ....D-1
E. THE STATUS OF NATURAL GAS SERVICE IN NORTH
CAROLINA - FINANCIAL STRENGTH OF NORTH
CAROLINA LOCAL DISTRIBUTION COMPANIES
(Robert Gruber) .....E-1
INTRODUCTION
The Joint Legislative Utility Review Committee is a permanent committee of the
General Assembly, as provided in Article l2A of Chapter 120 of the General Statutes.
The Committee consists of ten members, five each from the Senate and the House of
Representatives. The House members are appointed by the Speaker of the House. The
Senate members are appointed by the President Pro Tempore of the Senate. Members
must be sitting members of the General Assembly. They serve at the pleasure of the
appointing officer. A Senate cochairman and a House cochairman are designated by the
respective appointing officer.
The general purpose of the Committee is to evaluate the actions of the State
Utilities Commission and the Public Staff, and to analyze the operations of the utility
companies operating in North Carolina. The Committee also stays abreast of regulatory
changes relating to utilities at the federal level, judicial decisions, and technical changes
affecting utilities. The Committee is authorized to make reports and recommendations to
the General Assembly, from time to time, on matters relating to the powers and duties of
the Committee (G.S. 120-70.3(7)).
The stated powers and purposes of the Committee include undertaking specific
studies as may be requested by the President Pro Tempore of the Senate, the Speaker of
the House of Representatives, the Legislative Research Commission, or either House of
the General Assembly (G.S. 120-70.3(8)).
The General Assembly specifically authorized the Committee to study issues
related to calculating avoided costs for small power producers, and authorized the
Committee to report any findings and recommendations to the 1997 General Assembly.
(Appendix A.)
This report of the Joint Legislative Utility Review Committee is made in response
to the specific authorization of the General Assembly, and as part of the Committee's
general and ongoing obligation to provide information and recommendations to the
General Assembly relating to public utilities. It covers the period of time from the
Committee's 1996 report, which ended with activities on Apri|26,1996, through January
14,1997.
AVOIDED COST - PAYMENTS TO SMALL HYROELECTRIC POWER
PRODUCERS
Recommendation of the Committee
The Joint Legislative Utility Review Committee makes no recontmendation to the
General Assembly. The Committee notes that there is currently a proceeding underway
before the North Carolina Utilities Commission to determine avoided cost payments to
small hydroelectric power producers for the next two years. The Committee Staff will
advise the Committee of the results of that proceeding when it is concluded.
Background
The Public Utilities Regulatory Policies Act of 1978 (PURPA) requires electric
utilities to purchase electricity from generators known as qualifying facilities. These are
cogeneration facilities and small power production facilities. G.S. 62-156 requires the
North Carolina Utilities Commission to determine the rates to be paid by electric utilities
for purchases of electricity from small power producers in North Carolina. Under North
Carolina law, small power producers are hydroelectric facilities of 80 megawatts or less.
The determination of these rates takes place in a biennial proceeding. The parties may
contract for a different rate than the rate determined by the Comission.
Under PURPA, and under G.S. 62-156, the amount paid by the electric utility to
the small hydroelectric facility may not exceed the avoided cost to the utility. Avoided
cost is the cost to the electric utility of the electric energy which, but for the purchase
from the small power producer, the utility would generate or purchase from another
source. While the rate paid by the electric utility may not exceed avoided cost, there are
differences in the methods which may be used to calculate avoided costs.
At its meeting on January 14, 7997, the Committee heard from all parties with an
interest in this issue. The representatives of the small hydroelectric generating facilities
testified that, based upon the payments being made to them pursuant to the Commission's
avoided cost order currently in effect, they could not make a profit. They suggested an
altemate method of calculating the rates paid to them. Their proposal would require the
utility to meter the power produced by the small power producer, with its value set at the
"retail" rate per kilowatt hour as approved by the Commission for the electric utility. The
utility would keep a specific portion of the money for itself, covering profit and overhead,
and the balance would be remitted to the small hydroelectric producer. A copy of the
proposal put forth by the small hydroelectric generators is found in Appendix B.
The Honorable Allyson K. Duncan, of the North Carolina Utilities Commission,
testified before the Committee and explained the methods the Commission has used to
calculate avoided cost. She pointed out that the Commission is in the midst of the
biennial proceeding to determine avoided cost rates for the next two-year period. The
Commission has specifically required the electric utilities to address issues relating to:
l. Encouraging hydrogeneration by calculating avoided cost rates based on higher
performance adj ustment factors;
2. Whether to consider the direct and indirect costs of air pollution, nuclear
decommissioning, and other costs that may be avoided because of hydrogeneration; and
3. Appropriate terms and conditions for offering long term avoided cost rates to
small hydroelectric producers.
Commissioner Duncan closed her remarks by pointing out that the discussion of
electric utility restructuring presently going on in Congress may well involve the repeal
or alteration of PURPA. Commissioner Duncan's remarks are found in Appendix C of
this report. ,
Mr. Robert Kaylor represented Duke Power Company and North Carolina Power
Company before the Committee. He pointed out that the Federal Energy Regulatory
Commission (FERC) has consistently ruled that states may not establish required
payments to qualifring facilities that would exceed a utility's avoided cost. It is the
position of Duke Power and North Carolina Power that the proposal of the hydroelectric
generators would result in payments above avoided cost. He also pointed out that the
rates paid to these facilities for electricity are reflected in the rates ultimately charged to
customers of the electric utility. Electric utilities did not encourage the small
hydroelectric developers to make investments in hydroelectric facilities. When Federal
law and state law first required the electric utilities to purchase power from the small
hydroelectric producers, the cost of electricity was high and, therefore, the payments to
small hydroelectric producers were high. However, the cost of electricity has gone down
due to lower fuel costs and lower inflation. This, in turn, has resulted in the avoided cost
being less. Mr. Kaylor pointed out that the question of whether or not special provisions
should be made to preserve the small hydroelectric facilities is a social issue. If society
believes it is beneficial to preserve these facilities, then society as a whole should provide
the compensation necessary to do so. The burden should not be placed on the electric
utilities and. ultimately. the customers of those utilities.
Mr. Len Anthony represented Carolina Power & Light Company before the
Committee. He pointed out that the method proposed for calculating the payments to the
small hydroelectric producers would be inappropriate because basing them on the retail
rate charged to the utility customers ignores other costs of doing business such as
distribution, metering, billing and collection, taxes, insurance, and so on. PURPA, and
the North Carolina law, requires the Utilities Commission to establish avoided cost rates
equal to the costs the utility can avoid by purchasing the electricity rather than generating
it. The method proposed by the hydroelectric generators would not be based upon that
methodology. Mr. Anthony pointed out that CP&L has not had a general rate increase
since 1988, and in real dollars, CP&L's residential rates are more than 670 lower than they
were in 1990.
Gizele Rankin, an attomey with the Public Staff, also reviewed some of the
history involved in the development of the small hydroelectric industry and the methods
of paying these power producers. One factor, in particular, that she believes the Utilities
Commission should alter in calculating avoided cost has to do with the performance
factor adjustment presently in effect. It requires the small hydroelectric operators to
operate 83% of the on-peak hours. Evidence in prior proceedings indicates that the
operations of the small hydroelectric generators in North Carolina are constrained by lack
of rainfall. This is a particular problem during the summer on-peak hours. A
performance adjustment factor that took this dependence on natural conditions into
account, would result in higher payments to the small hydroelectric generators, while
remaining within the bounds of the avoided cost formula.
It is expected that the Utilities Commission will issue its avoided cost order,
which will have considered the performance factor, as well as other issues, in April of
t997.
OTHER ACTIVITIES OF THE COMMITTEE
At its meeting on January 14,1997,the Committee officially received the biennial
gas expansion reports of the North Carolina Utilities Commission and the Public Staff.
These reports are required to be presented to the Committee pursuant to G.S. 62-364.
G.S. 62-364 requires the natural gas local distribution companies to file biennial reports
with the Utilities Commission detailing each company's plans for providing natural gas
service in areas of its franchise territory in which natural gas service is not available.
These reports are updated every two years. The Utilities Commission and the Public
Staff are required by that statute to independently provide analyses and summaries of
those reports, together with status reports of natural gas service in North Carolina, to the
Committee. Of interest is the fact that two amendments were added to G.S. 62-36Aby
the 1995 General Assembly. The first amendment requires the expansion of natural gas
service by each of the local distribution companies to all areas of their franchise
territories by July l, 1998 or within three years of the time the franchise territory is
awarded, whichever is later. Any company which the Commission determines is not
providing adequate service to at least some portion of each county within its territory by
that time, forfeits the exclusive franchise rights to that portion of the territory not being
served. The other amendment required the Commission to ensure that every county in
the State was franchised to a natural gas local distribution company not later than January
r,1997.
The reports of the Utilities Commission and the Public Staff were presented by
Commissioner Laurence A. Cobb, and Robert Gruber, Executive Director of the Public
Staff. To avoid a duplication of effort, Commissioner Cobb concentrated on the
assignment of the unfranchised areas of the State, which has been completed, and the
expansion activities of the natural gas local distribution companies. Mr. Gruber
concentrated on the financial strength of the natural gas local distribution companies as it
relates to the provision of service in their franchise territories. A copy of Commissioner
Cobb's statement is contained in Appendix D. A copy of Mr. Gruber's statement is
contained in Appendix E.
At the January 14, 1997 meeting the Committee received a report from Utilities
Commission Chairman Joanne Sanford regarding the Utilities Commission's ongoing
activities implementing local telecommunications competition pursuant to legislation
passed by the 1995 General Assembly (House Bill 161). The Committee also received a
brief report concerning the merger of MCI and British Telecommunications.
APPM{DIX A
Subpart B, Part K, CXrapter 542 of the 1995 Session laws
Subpart B. Utiliry Energy Cost (H.B. 931 - Allred)
Sec. 20.3. The Joint Legislative Utility Review Committee is authorized to
study the issues related to calculating avoided costs for small power producers and
ma'y recommend any needed changes to the General Assembly. Sec. 20.4. The Cominittee is authorized to report any findings and
recommendations under this subpart to the 1997 General Assemoly and may make an
interim report, including any recommended legislation, to th€ 1996 Regular Session
of the 1995 General Assembly.
A-1
APPN{DIX B
North Carolina
Small Hgdro
ffao. ,l
oD -@o
\ <\ s-
Ckan E[ectricittt from
Renewable Nataral tlesources
I * '*''
Beqlvlnin{.t tfti:;; !t(.litr" l'lrtr'lft (l.trt'r:lin.i':l;::;mall tt\rdroelecl:i'it: lJerltlrii-tor's
t.lill lts';ir::;terrnattr;all!t frri",:::gd (lut crf ht.t:;iner:i:.'; unlr:ss; E f.'ljr
ht n$ lrj {lr:rrll l.|l.rrnr;41'-r:r thr':r[ l'or lhr:it''-'1t",::: tricit!| is adopt.ed.
l.n the (t,rrl5r iil fJ"i tlte i.tueld(.l .ct ".rrrrrrirJcrd c0s;t'. ({.rr.:; dLr0ut"- f iue tc' 51)i
(::ent'-:-:; flr(.lr l<ilotr.lttt" l'lcr,l it: i."; rlcr.rn t0 jusl ()Qel''t..1 Ccflt:;, ab0ilt.
.'r 50e; ['r]tjur::licrn in thr:r i;lsimr.-,rl ':ot;t cf nli]kin{.1 glsttricity" If
;mall hUdr(.r ll'rtir:rr)l::L; ;-ii'r:r frli'i1 .":,r.i l:r:r itr:r:: ept'- fltltd f0ntracl'.S untJs:r l:htar
;.lucridcd ilrrr:it'.:ii::he:rtlrjr, l:ltL:(r trill tnlSr re';:eir.,rl.lltttt.tt half foI their
Dcrurlr rrh..lt'. 1;f1q1,r rlirl 1lii \rrj,ji'ij ,irtl(1. Cle,ilrly, lhr.tU ililflfl0l :;llrr/it-tt-.'i'lt.
thi::; ri-tt.('1.
ther a,.rr,ritJeri r.:(:r:;tt:if:hrjrrnr.-r r*rr:rrkr'; fur thr..: r.rt.ilit'.it:r::;, dnd it. i::.'lll tttirk
for trig l:herrni-il {,ltlflt:]r',:lt(:rrr:ti t\iilt:t {::iln t;,hocr:;li ttilt:tn ;'lnd hortr ilttch l:ti
r1n. Lt rrill n(tl trr:'r'k tor':;tnnll lrytlrrl. trle are inherentllt lirnil:-
efl in Si;,1:r,:r ;tnd r,lhett ;.ind hr:ru rilr.ti:'h fir{)trtt:ir tlril c.ln t|lake. lrltt cilnflcrll
1n{nipulate t'.hLl :ilf'e.rillflot^r t.0 tal<cr .ltlufint.aqcr of tttarketpl.l,:e irltren-t.
iue::; liktl t.hc: r:(lal nnrl gi:rii tlurner'::; can, 0r il0ke hlatet' ilFp('l.rr'
ulren it isn't: t-here.
flut, srnall htrclro is N0rth keieping. 0nue snrall hydro is finished
r^rith il:; fUel, |r(:ru cfin drink it! It:s n0t dAnger0il:;' dt)0Sn'tl hAver
tr: bcr hurierJ for a thousand !,rlgrs;, and, clcretn't Follute the "lir'
l,lc :;aue lu{lret t'.han -16,000 l:oni; lf c:r:rgl antl Preuent the emission of
lnore than 60,CI00 t'.0ns of pollt.tt'.irnt"- e.iuery ye0r.
Br:yon11 the f.lr:t'. l-hat the rrlt.r'crtlrilrJe eur:lution 0f the avoided c0$t
scheme t.hreatens to destroy u!, n0thing has changed uith respect
lrt the ualucr of *ltlan, hydr0crlcrr;lrit:: {J€rneration. l,le still need to
us;e 0ur clelane:;t Dour er f ir:;t, ltl ':onserve c'rulf0ssil 'fuels, to
reduce 0lt" depenrlenr:e of forcril,tn cril, and redilce the dn0iltlt 0f
pollutant:i expr:llecJ into the air anrl utater by large pouer tllants;.
By ignoring thr-i hirlrlen c0:rts att0ndanl t0 fo:;sil fuel dnd nuclear
0ernerati0n, ailong other uay$, the: ulilizes have ||lanaged tc reduce
the claimr:rJ avoidr':rl c0."it t0 a level $0 lcrt^r thal if small hydro i:;
forcetl tcr acr::eFt it our projects; cailnot $uruiue- If thei utjili-lies
gel their !tit5r, they ilatt sitUe :.;on1e Inqneyr but, for thatl
:;auing, Nort'.h Cirrolina's; only uiahle naturel resource energy re-s()[
rrce urill br: lo:;t"
1o Frersrrpve :.;ntall hyrJro, a difft:r'Lrnt, fsir method of payrnent for
its po$er i; rtrlerJt:rl. (ieneral Stal.ltIe 62-'1.56 seys:
11 FR0t10:;fil. l.rllt rrtlfl
:;t'|fi l. l. tl'itlRt.lt: l. [fi1tll C
Tft[.ftTnrNl rll'
r;: illI R fi 1t.lR s
a :-;rn..r I l t:rCrt{L:r prcrducer dnd ai'l t.r lcrt::tr it:
g1111' t.la I 11.r il{:lr(:?ti lti .-r';tlrtt r;.tr:1.. f rtr llht':r
1:0,,:{ tri' i{-:* for the crlerctrii: illf.'" - " .. ".
i^r'iqil it'rtr l'.hl r.tt. i I i lV t0 lll.lf'(.:tl,r:.';t': lh?
t'.(.1r'tlr:;; qr::it rllr I is.;hed in :;ul:segt ic'n (h J u f
(aj ln l.l'rr't r.r,.tenl tihirt
ut_ i I i l rr iir:Jtr JrL&tah l e lo
s.;.-.r lr,r r:r1 r'r leiltr it: it.y 0r
t.hr'r (,r:rrum isl; irtn ::;h,:r I I
lir:rhrrrr under rat';rls .:nd
lhi,: :;tri.:t'.i0n-
B-2
lir.ri.r,r,r.:t:1.irrn (bi irrurrl<rj',; (er:;r:;tlnt.iallvi lxtlRlif-I,
().1:,, fj7 lfjG CiCr(:l:; nrrl. r'eqttit"r: ..1 ,:.:(lfll.r','iil:l- tt.r
if ,jrn ,iLlt^tlralrlt('lrtl'i-:iit.lrt- ht't rcar::htirr:l ir 13t.l[t13l"l,
,,1r.'11 idr'rcl c:o:.;t. 1;,:rh(lril(1) il.lu(:rkL)tJ .
bri t.lilr.lcri' frll[111fi . t.ln ltt
011 ,]l t:hr: rl: (:rtI{1 Iit:: ,rt"ed
l:tr.tl:. ,tn(lrtttlcrr (rlii!, if a tltLlluilll!J <l{i''r:rr:;r[tlg .Jf'ri.!fltlefllLtilt. [.rrllrrlr-it:trl i-]
j;rll,arll l:rotilC:r'p't'(;rrlt.li]:r.:r.lnd.,lt Utilil-\r,::.11'l t.',,: hdtl r)t.ll-',,;'idr {.r1' l'rlJ[?lxt'|,
l'lt.rrt.h {'lar0 I iil,i l..rt{,ilreitd!r p(:rrrtl it.'; ll
l'll.rt" :;r.l(J{:lrl:i;licrn rlrlrt.rl0y::; Ihr.: r:;irttp,le. r']':.1ir:rtltLrfll: r.rf i-crll'l'tr;iitq l:fl(il
L-:t]|l||'Jlir,:a1:gdi'.r..luirjgrll::r]jt,:-.;i:ht-]ltIt}r.rit-it.r.l;irtl1:rlli,f.*ir:.;!l,',l.l.,llll't|}r.l',[.
r,rlrii:,h rttrgi'\Iorle, iitr:,lr.trlinq lhcr pttttlir:, illi:i\.r ttr.'iilfil
It. i12r.rq1l1rg'.; (lrr:rLlnrl r*rha1: ({(l *;rll "lltLrl-.::i[)rlr':::i{'ii.:" ,a{t::':.:q'j;:., f.r'r 1-ltt'r
nt*rk{:tltlll...tL':tr, Utiuplr,:r:i (,tith lepl'.Ain rl(:ri-t-[ri'rlli{'ui';'tlitln linrit.'ll ir]ll:l;
r:i(:l,l;i{nr.:r(l lr:r flrnl.cri::t'..u:}; anrl ther publitt frrint 1't.tl:ufr? pIotlletni; ;lri':;'
inl.t frr:rtt cotn[]lcl)i i^;lttr:r fiilinQ :;{:h(1rllr.ir:i, ,.ii'tt.i faif l]ri:lultltir[11]:i; 11"(l llnt:
uti I itie:; fr:r therr 0'rrtir:ipaticn.
thr.: ::;t:lrr;rili-rtl if: r)n fu I lor'r in'J pit{Jr.}
f r,., n t. 1.:; tt:;; I e ffi - Iut plan durrsn't
*0nl inile t0 Inetet"', cl i:;tribute,
rnernt:;, in ar fa:;hion siililar lo
ctrrnplex rate fixin{J schemc,. The
:,;r.rtlport i:; alrerild5r tn place.
:;j h o t{ :; t- ft{? tll ,al c: h.r it i t.: l:; r:r f' t: lt t-: {;: l'l f' -
r:,hern{:irl it. th': utiIititi::; trcruld
ll i I |, r::t:r I I t-:r;tl, .rrtd rl i ::;perr;ie pa! "
rJhirtj t'.he! do n(ltJ l.lncler the nt0re
ph5r:; ir:a I r:'{p.l iUt[ent .*nd lrL0 i::;l it:a I
Thg rltilifsr ttttLtlrl tllgtr.tr'(lllr prgdttr::l-iOi'l iittrl lhtl 1;,tlril 0'f Crlr?r::1'.i^ltl:-
ity rn thcr qrid. Iach ilonth thery r.rcrulrl e:illL:t.tl;:rt-t) hotr Intjt:h []0t(tPlr
lhe r:itltilll prujecl had cr)nlribiltcd t':ri thr': {)0o1, and lh0'lalue t:'f
it at'. the: rr, tatl rilt'.e pel kilouatt. af:rllt"tl'.tcrd tiy the [:onlnli:;::;ittn f0r
thrl receiuinU r.rtility. ihe r.rtility ucrr.lld ker':p fi ::;Fe*ifi*, p0r'-
t--ion 0f the ntcne5r for itself, and refiit'. the r*rll.rincler tlct thtr
s;tlrir I I po(iler producef'..
[l:; .an r:xantnle:
iiav the retsil rate 0f thq: r't)':('riuinl utility i:;7-1.1r ';enFs
per kilor.r*tl: hour, lhr: 1993 [Jr.rke ['or,tr]r residenti.'il Iatct- 1'het
r.rtility r*roulrl deduct L/.Z fttl it'.:-': prof it., le:euin11 r0ughly
fi.2g cenls. Thtin lheg uor.rlrl rlerlLrr:l ancrther' l2?'; frttlt ti-2!l
[r.1t-lls;, lt]aving 5.53 centl. 1.t truulrJ he thi:.1 aln0llnt'.' 5.53
c(:rnLii pr:rr kil(itd.,1tt hr:rur', tirncr:; thrr nt.l[lh(:]f't:r1'kilohliilt. tlolir:.;
contrihuterl Lrg the srnall pcruer Pruclucrlr t.(r tht'r lltirLl, t.hdt'
the iltl i I il:U ur:rl ltl rern il: t() thr; :;ma I I pDtilflr' []rtltlut::tarl'.
1'his 1:;.r1:;tr.:rrl r,rc'r.rld have it ne0lir3ilrle rlcrnFltar5r effetrt crtl l:ll.t {::rln*
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APPH{DIX C
STATEMENT TO THE JOINT LEGISLATIVE UTILITY REVIEW COMMITTEE
ON AVOIDED COSTS FOR HYDROELECTRIC QUALIFYING FACILITIES
January 14,1997
Background
The Public Utilities Regulatory Policies Act of 1978 (PURPA) required each electric
utility to purchase electricity from qualifying f6cilities (QFs), which are defined in PURPA
as cogeneration and small power production facilities. Generally speaking, cogeneration
facilities are nonutility plants that simultaneously produce two forms of energy, such as
electric power and steam, while meeting certain thermal efficiency standards, including the
use of five percent of its energy for commercial or industrial processes. Cogeneration
facilities should use less fuel than would be required to produce electricity and steam
separately. Small power production facilities are plants which use biomass, waste, or
renewable resources like wind, water, and solar to produce electricity while meeting certain
size and ownership standards. Reliance on these renewable resources of energy serves
to reduce the use of scarce resources such as coal and oil. The hydroelectric facilities that
we are considering today are small power producers under PURPA.
The Federal Energy Regulatory Commission (FERC) was required by PURPA to
prescribe rules governing electric utility purchases from qualifying facilities. The FERC
regulations require electric utilities to purchase electricity from qualifying facilities at rates
that reflect the avoided costs of the respective utility. The FERC defined avoided costs
as the costs that the purchasing utility can avoid as a result of obtaining energy and
capacity from a given supplier rather than generating an equivalent amount of energy and
capacity itself or purchasing the energy and capacity from alternative suppliers.
lmplementation of the FERC rules was delegated to the State regulatory authorities.
The N.C. Utilities Commission has since established separate avoided cost rates for each
electric utility operating in North Carolina, and has revised such rates every two years.
The Commission reviews the avoided cost rates of each utility, including contractual
arrangements, interconnection charges, terms and conditions of service, and related
matters by holding biennial proceedings.
G.S. 62-156 provides that, beginning no later than March 1981 and continuing at
least every two years thereafter, the Utilities Commission shall determine the rates to be
paid by electric utilities for purchases of electricity from small power producers in North
Carolina. North Carolina law defines a small power producer as a hydroelectric facility of
80 megawatts or less capacity. The definition of small power producer under state law
is more restrictive than the PURPA definition in that it includes only hydroelectric facilities
of 80 megawatts or less capacity while excluding other types of renewable resources that
are included in the PURPA definition.
The Utilities Commission establishes rates pursuant to G.S. 62-156 in the same
biennial proceedings in which rates are established pursuant to PURPA. The rates
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established pursuant to G.S. 62-156 are based on the avoided costs of each utility, in the
same manner as the rates established pursuant to PURPA.
Avoided Cost Rates
The Commission establishes avoided cost rates utilizing methodologies that are
generally accepted and used throughout the electric utility industry. For example, CP&L
ind Duke have utilized the "peaker" methodology. The peaker methodology utilizes the
cost of a peaker-type generating facility, typically a 75 to 100 megawatt combustion turbine
unit, to determine avoided capacity costs. Avoided energy costs are calculated using a
cost simulation model to analyze marginal system running (fuel and operation and
maintenance) costs, in order to determine the degree to which these running costs change
if a block of power displaces some of the utility's generation. The sum of the avoided
capacity costs and the avoided energy costs is the utility's total avoided costs. Theory
underpinning the peaker method indicates that the avoided cost determined using the
peaker method will equal the avoided cost of a baseload unit. This is true because the
lower capital costs of the peaker or combustion turbine are offset by the fuel and other
operation and maintenance expenses included in the utility's system marginal running
costs, which are higher for a peaker than for a baseload unit. The peaker method was
developed by the National Economib Research Associates, Inc. (or NERA), when
sponsored by the NationalAssociation of Utility Regulatory Commissioners, among others.
N. C. Power has utilized the Differential Revenue Requirement (DRR) methodology in
each of the past several biennial proceedings. The DRR methodology involves a
comparison of the revenue requirements of a utility which result from two alternative
system expansion plans - one including a block of new power purchased from outside
suppliers and the other excluding purchase of such a block. The utility's generation costs
are calculated on a yearly basis for an extended period of time for each of these two
scenarios. The difference between these two scenarios is then computed for each year,
and the results converted into present value terms, thereby providing an estimate of the
present value of the total avoided cost of the assumed'block of the QF capacity.
Advocates of the use of the DRR method claim that the DRR methodology is fairly intuitive
and straightforward, i.e., it provides an easily understood picture of what costs are avoided
when QF power is acquired by the utility, and some other source of power is displaced or
avoided. The Commission heard extensive testimony and comment on the relative merits
of those methodologies versus others, and it determined that a common methodology
should not be mandated for all utilities to use. lt found that there are widely divergent
opinions even among those who are most expert in these matters as to what costs are
actually avoided and what methodologies will best identify those costs. lt concluded that
each utility should be allowed to generally pursue its own preferred method for calculating
avoided costs, subject to the ongoing review and discussion of details of each
methodology in the biennial proceedings.
A major issue in establishing avoided cost rates has been the determination of long-term
avoided cost rates applicable over the next five, ten, or fifteen years, versus avoided
cost rates that will be applicable over the two-year interval between biennial proceedings.
In general, the Commission has established long-term avoided cost rates for qualifying
c2
facilities under PURPA having five megawatts or less capacity, and for small power
producers under G.S.62-156, having 80 megawatts or less capacity.
A controversial issue in establishing avoided cost rates has been the determination
of avoided cost rates for capacity versus energy. In general, the Commission has
established capacity payments that are paid only for electricity supplied during the
purchasing utitity's on-peak hours, plus additional energy payments that are paid for all
electricity supplied during both on-peak and off-peak hours.
Another issue concerns the appropriate level of what is referred to as a
"performance adjustment factor'' used to calculate the capacity credits paid to QFs. The
Commission has found that a purpose of the performance adjustment factor is to allow a
QF to experience some level of outages and still receive the entire capacity credit payment
based on the utility's avoided capacity costs. Without a performance adjustment factor,
a QF would have to run 100 percent of the time during peak hours to receive its full
capacity credit payment. lt should be noted that the utility's own plants are not available
or used during all peak hours. The Commission has used a 1.2 performance adjustment
factor in establishing the utility's avoided cost capacity payments in each of the last several
proceedings. A performance adjustment factor ol 1.2 requires a QF to operate 83o/o of the
purchased utility's on-peak hours to earn the entire capacity credit based on the utility's
avoided cost.
In the last biennial proceeding, the issue was raised of whether small hydroelectric
facilities should be required to operate 83% of peak hours in order to receive the full
capacity payment. Hydro facilities are typically constrained by rainfall over which they
have no control, so they do not normally operate 83% of the on-peak hours. In the last
biennial proceeding, the Public Staff proposed that a different performance factor be
applied to hydros in order to address this problem. However, the Public Staffs proposal
in this regard was tendered in its proposed order which was submifted after the evidentiary
record was closed. While the Commission did not accept the Public Staff's recommended
performance adjustment factor, the Commission Order establishing the current biennial
proceeding, required parties to address the merits of encouraging hydro generation by
calculating avoided cost rates for hydros based on higher performance adjustment factors.
The issue will be addressed again in the current biennial proceeding.
Current Biennial Proceedinq
The Commission established the current biennial proceeding to determine avoided
cost rates in Docket No. E-100, Sub 79. The electric utilities were required to file their
proposed rates, standard contract forms and supporting work papers and comments for
purchases from qualifying facilities by November 4, 1996. All other parties filed their reply
comments and other proposals yesterday. The proceeding will also include another round
of comments, a public hearing for taking non-expert public witness testimony on February
4, 1997 , and proposed orders by March 4, 1997.
The Commission has required the electric utilities to include statements in their
current filings discussing: (1) the merits of encouraging hydro generation by calculating
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avoided cost rates for hydro QFs based on higher performance adjustment factors; (2) the
direct and indirect costs of air potlution, nuctear decommissioning, and other costs that are
avoided because of hydro generation on the utilities' respective systems; and (3)
appropriate terms and conditions for offering long-term avoided cost rates
Federal Pre-emption
The question of whether the General Assembly may, by state statute, give hydro
projects a premium in the determination of avoided cost rates is not as simple as it may
seem at first. The FERC has held that a state may not set rates for qualifying facilities
subject to PURPA in excess of avoided costs. The FERC first made this decision in 1988
in the case of a program under state law in New York that set a minimum rate of 6f per
kWh for certain generating facilities and provided for utilities to pay this rate, even if it
exceeded avoided cost, in order to encourage alternative energy sources. In a more
recent case, FERC dealt with a Connecticut statute that required utilities to purchase
energy from a resources recovery facility owned by a municipality at the same rate that the
utility charged the municipality for electricity. FERC held that a state may not, even under
its own authority, exceed the full avoided cost allowed by federal law for purchases of
electricity from a qualifying facility. To the extent it does so, it is pre-empted by federal law.
However, the concept of avoided cost is flexible; there are many methods for
determining avoided cost and PURPA allows the states quite a bit of freedom in
determining the method they will each use. Thus, to the extent that the Commission might
adopt a methodology for determining avoided cost rates that yields a higher figure for
hydros, that would arguably not violate the federal law. This possibility has not been fully
explored in the Commission's prior avoided cost proceedings, but this is essentially what
the Public Staff is attempting to do in the comments that it has filed in the Commission's
current avoided cost proceeding. The Commission will be deciding soon whether it agrees
with the Public Staffs proposal.
The Future of PURPA
Lastly, I might add that PURPA may be repealed. In the last session of Congress,
at least one bill was introduced which would have restructured the electric utility industry
to promote competition and eliminated the utilities' obligation to purchase QF power once
competition was achieved. Some members of Congress have indicated that electric utility
restructuring is a high priority in the current session. Thus, it is certainly possible that
PURPA may not survive long, at least not in its current form.
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APPNDIX D
STATEMENT OF COMMISSIONER LAURENCE A. COBB
TO THE JOINT LEGISLATIVE UTILITY REVIEW COMMITTEE
ON RECENT NATUML GAS ACTIVITIES AT THE UTII-ITIES COMMISSION
January 14' 1997
I am here today to report to the Committee on two matters related to natural gas
service in the State. First, i will report on the Commission's assignment of previously
unfranchised areas of the State for natural gas service. Second, I will summarize the
reports that the natural gas utilities recently RteO witn the Commission dealing with their
plans for expanding service in their franchised territories.
Assionment of Unfranchised Areas of the State
On June 12, 1995, the North Carolina General Assembly enacted legislation
requiring the Utilities Commission to issue franchises by January 1, 1997, for all areas of
the State which had not previously been franchised for natural gas service. Shortly after
enactment, the Commission issued an Order opening a proceeding to implement the
statute. That Order first allowed time for anyone who wanted to file an application for a
certificate to provide natural gas service to any unfranchised area of the State. The Order
then provided that if there were areas for which no application was filed, the Commission
would assign these areas on a county-by-county basis to one of the existing natural gas
utilities in the State.
The Commission received two applications pursuant to that Order. In December
1995, North Carolina Gas Service filed an application for a certificate for all of Stokes
County not already franchised to it. (N C. Gas already had a franchise for the southeast
corner of Stokes.) On the same day, Piedmont Natural Gas Company filed an application
for a certificate to serve the southwest corner of Stokes County. Those two applications
were consolidated for hearing and hearings were held in May and June 1996. Recently,
the Commission issued two orders dealing with Stokes County. On October 25, 1996, the
Commission issued an Order granting the application filed by Piedmont and denying the
application of N.C. Gas. Since Piedmont had asked for only the southwest corner of
Stokes County in its application, the Commission's October 25 Order left a part of the
county still unfranchised. The Commission issued an Order on December 12 assigning
the remainder of Stokes County to Piedmont contingent on the October 25 Order
withstanding appeal. N.C. Gas has appealed the October 25 Order to the appellate courts.
In the meanwhile, in May 1996, the Commission issued an Order dealing with all
the other unfranchised areas of the State. The Commission made preliminary assignments
of these areas and provided that any company could file protests or comments as to the
preliminary assignments. No comments were filed, and the Commission issued a Final
Order on August 16, 1996, making final assignments and issuing certificates of public
convenience and necessity.
The map that has been provided to the Committee illustrates the assignments made
by the Commission. The unfranchised areas of the State that were assigned by the
Commission's August 16 Order are (1) the far western counties of Cherokee, Graham,
Swain, Jackson, Macon and Clay; (2) the western counties of Madison, Yancey, Mitchell
and Avery; (3) the northwestern counties of Ashe and Alleghany; (4) the northeastern
counties of Camden, Cunituck, Dare and Tyrrell; and (5) parts of Montgomery and Moore
Counties. For the most part, these counties were assigned based on their proximity to
existing natural gas facilities and existing territories of the natural gas utilities. .
For example, the Commission assigned the far western counties of Cherokee,
Graham, Swain, Jackson, Macon and Clay to Public Service Company. This assignment
was primarily made because these counties are contiguous to Public Service's existing
territory in western North Carolina. For the same reason, the Gommission assigned
Madison County to Public Service.
The Commission assigned Yancey, Mitchell and Avery Counties to Piedmont
Natural Gas Company. These counties were assigned to Piedmont because they are
close to Piedmont's existing territory and because Piedmont has an expansion fund with
a considerable balance available for expansion purposes.
The northwestem counties of Ashe and Alleghany were assigned to Frontier Utilities
of North Carolina. These counties are contiguous to territory previously franchised to
Frontier. The previous franchise granted to Frontier is of course subject to an appeal that
is pending before the North Carolina Supreme Court.
The northeastern counties of Camden, Currituck, Dare and Tyrrellwere assigned
to North Carolina Natural Gas Corporation because they are contiguous to NCNG's
existing territory. The previously unfranchised parts of Montgomery and Moore Counties
were assigned to NCNG because NCNG already had a franchise for parts of those
counties.
I should mention one other matter noted on the map. Warren County is now in the
franchise territory of Public Service, but there is no natural gas service in the county at
present. Frontier has recently filed an application for a franchise for Warren County. The
Commission has scheduled a hearing on Frontier's application and the Commission will
be deciding that matter soon.
The Commission is glad to see all of the State map finally'Tilled in" and I am sure
that you are as well. A few of the assignments may change as the pending matters that
I have mentioned are decided, but the assignment of franchises for all of the State is an
important milepost in getting natural gas service extended throughout the State, and I am
glad to be able to report this development to you.
D-2
Natural Gas Expansion Reports
Tuming to my next subject, G.S. 62-36A requires the natural gas local distribution
companies (or LDCs) to file biennial reports with the Commission on their plans for
providing natural gas service in unserved areas of North Carolina, and it requires the
Commission to report to this Committee on the status of natural gas service within the
State and on the reports filed by the LDCs. The LDCs filed their latest reports in October
1995, and the Commission filed its report with the Committee on May 1, 1996. I am here
to give you an oral summary of these reports today.
NCNG, in its report, identified three expansion projects planned for the 1996-1998
time frame. The first involves the construction of a new 71-mile pipeline that will provide
initial natural gas service to Duplin and Onslow Counties. This project was approved for
expansion funding and consists of the construction of a new transmission pipeline running
from Mount Olive'to Warsaw, and then turning southeast through Duplin County and on
to Jacksonville and Camp Lejeune. Limited distribution systems are also included in
Faison, Kenansville, Jacksonville, and at Camp Lejeune. The towns of Faison and
Kenansville and the City of Jacksonville, as well as Duplin and Onslow Counties, have
committed financial assistance in the form of five annual payments to NCNG's expansion
fund in amounts equaling loOo/o of the ad valorem tax revenues collected on the facilities
constructed as part of this project. The total cost of this extension, which will provide initial
gas service to Duplin and Onslow Counties, is estimated to be $18.8 million. NCNG's
shareholder investment in this project is estimated to be $6.4 million, with the expansion
fund providing $12.4 million, the negative NPV of the project. This project was approved
for use of expansion funds in August of 1995; however, there was a delay in determining
whether federal officials would require an environmental assessment before construction
across federal land, and therefore actual construction has not yet commenced. An
environmental assessment has been required, and the Commission has required NCNG
to report in March on the status of this project.
The second project identified is an extension of natural gas service to the
Whiteville/Columbus County Industrial Park. This extension consists of the construction
of 17 miles of 6" transmission pipeline from an interconnection with the Company's existing
12" line near Bladenboro in Bladen County to the Columbus County Industrial Park west
of the town of Whiteville. This project will increase the availability of natural gas in
Columbus County and will be the first natural gas servi'ce to the Whiteville area. The total
cost of the project is estimated to be $1.8 million and NCNG will be responsible for
approximately $500,000 of this total pursuant to its agreement with Columbus County.
This project was included in NCNG's previous biennial report, but construction, which was
originally scheduled for 1994, was delayed. NCNG indicates that this project is virtually
complete. No expansion funds were used in this project.
D-3
The third project consists of approximately 5 miles of 4" transmission line which will
be installed in Bladen County to serve a new industrial plant, Accent Dyeing & Finishing,
Inc., and will also make natural gas service available within Elizabethtown. This will be the
first natural gas service to the Elizabethtown area. Bladen County has committed to use
up to $54,4,000 of available Community Development Block Grant Funds to construct this
pipeline. NCNG has agreed to fund the remainder of the project cost which is estimated
not to exceed approximately $200,000. Construction of this project is anticipated to be
completed in March of this year.
NCNG also identified a potential project which is under consideration at this time.
This project would provide initial gas service to Bertie and Martin Counties and would be
constructed in two phases. Phase lwould include 15.5 miles of 12" steel transmission
pipeline from Transco's delivery point at Ahoskie to Lewiston in Bertie County. lt would
also include a 6" steel lateral running approximately 2.7 miles to serve industrial
customers. The estimated construction cost for Phase I of this project is approximately
$6.0 million. The NPV for this portion of the project is a negative $3,931,400. Phase ll of
this extension would run from Lewiston to Robersonville in Martin County. lt would include
approximately 22.4 miles of 12" steel transmission line and a 500 ft. 6" steel lateral to an
industrial customer. In addition, this project would include approximately 1.8 miles of 6"
plastic distribution lines inside the town of Robersonville. The total cost for Phase ll is
estimated to be about $8.5 million. The NPV for this phase is a negative $3,786,500.
NCNG estimates that the total construction cost for this new pipeline to serve portions of
Bertie and Martin Counties would be approximately $14.5 million. The NPV for the project
as a whole is negative $7,717,900. Neither the feasibility nor the timing of this project has
been determined at this point. NCNG states that it will be analyzing this project in more
depth in the months ahead. According to NCNG, a decision will then be made as to
whether to request approval to use expansion funds for partial funding for this project. lf
they are approved, construction would most likely occur toward the end of the 1996-1998
time period covered by NCNG's report.
In addition to the four major projects currently planned or under consideration as
noted above, NCNG has identified 19 projects, each of which will require expenditures in
excess of $100,000, during the next three-year period. The 19 projects have a total
budgeted cost of approximately $3.4 million.
With respect to N.C. Gas, the only incorporated town in the Company's service
territory that is not served by natural gas is Stoneville in Rockingham County. N.C. Gas
has evaluated the cost and economic feasibility of serving Stoneville. The Stoneville
project consists of 4.3 miles of high pressure pipeline and a distribution system to serve
the community of Stoneville and is estimated to cost approximately $1.8 million. N.C. Gas
has performed an NPV analysis for the Stoneville project and determined that it is not
economically feasible to extend service to that community. The NPV analysis included
with the Company's report shows that approximately $500,000 is needed to make this
D4
project feasible. N.C. Gas stated in its report that it intends to ask the Commission for
authority to utilize expansion funds for this project. The town of Stoneville has granted the
Company a franchise for a gas distribution system within the town limits. lf the
Commission approves the use of expansion funds, N.C. Gas indicates that it expects to
extend service to Stoneville within the next three years.
Since its last biennial report, N.C. Gas has undertaken two projects. Service has
been extended to Walnut Cove and Shady Grove using the Company's own funds. The
Company has invested over $2 million and added over 1,000 services and 33 miles of
transmission and distribution mains since the end of the 1993 fiscal year. The Walnut
Cove and Shady Grove projects represent approximately 460/o of this investment.
Piedmont's 1996 biennial report identified several projects for which management
has approved preliminary plans and budgets. The primary expansion project identified
was the extension of service into the four-county area of Surry, Watauga, Wilkes and
Yadkin counties. However, as you know, the franchise for these four counties was
subsequently granted to Frontier, and Piedmont has appealed this matter to the Supreme
Court. Other expansion projects identified by Piedmont include expansions into Catawba
and Caldwell Counties. The first project would provide service to the industrial section
east of Claremont in Catawba County. This expansion would provide service to 5
commercial and2 industrial customers at a cost of approximately $434,397. The second
project would extend service along Highway 18 from Lenoir to the town of Gamewell in
Caldwell County. The cost of this project is estimated to be $184,256 and would provide
service to a mixture of residential and commercial customers. The NPV of this project is
$6,747.
Piedmont's biennial report also identified eight potential expansion projects that it
said may be canied out depending on the resolution of each project's economic feasibility
issues. One of these was expansion into Stokes County, where Piedmont did not have a
franchise at the time the report was filed. Since then, as I stated earlier, Piedmont has
been granted a franchise for most of Stokes County and, as a part of that franchise
proceeding, Piedmont stated that it would not use expansion funds in connection with its
Stokes County project. Other potential projects identified in Piedmont's report involve
expansion within Alexander, Davidson, Guilford, Lincoln, Forsyth and Randolph counties.
Excluding the Stokes County project, these projects have a total estimated cost of $9.7
million and a negative NPV of $3.8 million.
ln Piedmont's 1994 biennial report, it identified 62 new projects which required
capital expenditures of $100,000 or more, 38 of which Piedmont reported as still in-process.
As of the date of its 1996 biennial report, 18 of these 38 projects were still in-process.
Since the 1994 filing, Piedmont has initiated 98 additional projects, each
requiring capital expenditures of $100,000 or more. Thirty-four of these projects have
been completed and 64 are still in-process. The cost to complete the 64 projects is
D-5
approximately $8 million.
Since its last biennial report, PSNC has initiated an expansion of natural gas
service into previously unserved McDowell County. This project includes approximately
20.5 miles ol 12" transmission pipeline beginning near Black Mountain in Buncombe
County and continuing to Old Fort and Marion in McDowell County. The proposed
expansion also includes a limited amount of distribution mains in the town of Old Fort and
City of Marion. The town of Old Fort, Cig of Marion and McDowell County have submitted
resolutions to provide PSNC five annual payments equal to 100% of the property taxes
collected on natural gas facilities constructed as part of the proposed McDowell County
project. These local government assistance payments will act as a direct contribution to
PSNC's expansion fund. The total cost of this extension, v/fiich provided initial gas service
to McDowell County, was approximately $14 million. PSNC has received $7.8 million from
its expansion fund and expects to receive $412,500 in contributions in the form of local
government assistance payments. This project was completed in December 1996.
PSNC also has budgeted for 26 new projects, each requiring expenditures of
$100,000 or more. Thirteen are located in Wake County,5 are in Cabanus County,3
each are in lredell and Buncombe Counties and 1 each will be located in Alamance and
Haywood Counties. Over $8.9 million is to be spent, with 38% of that amount going for
mains and the remaining 62% invested in services and other costs. Based upon the
assumptions utilized by PSNC in performing its feasibility analyses, these projects reflect
a combined NPV of $3.8 million.
PSNC's 1996 biennial report lists four major projects in addition to the McDowell
County project that are not economically feasible and therefore will require the use of
expansion funds. These projects are (1) the extension of gas in Haywood County to the
town of Waynesville, (2) eastward in Franklin County to Louisburg and eastward in Wake
County to Wendell and Zebulon, (3) Alexander County including Taylorsville and (4)
Warren County including Warrenton. Since filing its report, on December 30, 1996, the
Company filed an application for approval to use its expansion fund for the first of these
projects, the extension of service to western Haywood County, and to withdraw up to $5
million in expansion funds for this project. In this application, Public Service advised the
Commission that it currently plans to file an application to serye Alexander County,
including Taylorsville and Hiddenite, in 1998 and that it is considering a variety of options
to provide service to the seven new counties recently assigned to it.
It was the Commission's overall conclusion that each LDC's plan for expansion of
natural gas service within its franchise territory in North Carolina is reasonable.
D-6
/< okt . (-r' r+- t { r t,!,4!i"l
APPENDIX E
THE STATUS OF NATURAL GAS SERVICE IN NORTH CAROLINA
FINANCIAL STRENGTH OF NORTH CAROLINA
LOCAL DISTRIBUTION COMPANIES
North Carolina Natural Gas Corporation (NCNG) is a publicly-held, natural gas local
distribution company listed on the New York Stock Exchange (ticker symbol is NCG). At
December 31, 1995, NCNG employed 532 persons'and provided natural gas service to over
140,600 customers in south central and eastern North Carolina through a system comprised of
almost 3,600 miles of gas mains, five compressor stations, and a Liquified Natural Gas (LNG)
storage facility. NCNG, which is the only North Carolina LDC physically connected to two
interstate pipelines, has an interconnection with both Transco's and Columbia's interstate pipeline
systems.
NCNG's franchise territory, which consists of 47 eastern and south central North
Carolina counties, which covers over half the area of the State. The 47 counties include the four
counties recently assigned to NCNG. The population of the franchise area is 2.4 million and the
population density is 100 persons per square mile, considerably below the 147 persons per square
mile average for the State. NCNG's customer mix consists of 87 % residential , 12% commercial,
and less than 1% industrial customers. Industrial customers, although a very small portion of
total customers, use approximately 70% of NCNG's gas deliveries. At September 30, 1995,
NCNG's total capitalization was over $150 million and consisted of approximately 60% cornmon
equity and 40% debt. Its net income has ranged between $11 million and $12 million for each
of the last three fiscal years.
NCNG provides service to customers in 29 of the 47 counties in its franchise area.
Within these 29 counties, 63 cities and towns, as well as four municipal gas systems, are served.
E-1
NCNG serves approximately 17 % of the households in the counties in which service is currently
provided, as compared to approximately 12% in 1989.
The eighteen totally unserved counties in NCNG's franchised area are: Bertie, Camden,
Carteret, Chowan, Currifuck, Dare, Duplin, Gates, Hyde, Jones, Martin, Onslow, Pamlico,-
Pasquotank, Pender, Perquimans, Tyrell, and Washington. Montgomery and Moore Counties
are only partially served.
Public Service Company of North Carolina (PSNC) is a publicly-held, natural gas local
distribution company listed on the New York Stock Exchange (ticker symbol is PGS). PSNC
employs 1,130 persons and provides natural gas service to approximately 294,000 customers.
PSNC was founded in 1937, and as the result of several mergers and acquisitions, its
territory is composed of the following three noncontiguous areas: (1) the eastern section, which
includes the Research Triangle, seven surrounding counties, and a small portion of Alamance
County; (2) the piedmont section, which includes lredell, Cabarrus, and Alexander Counties, a
portion of Rowan County and the northeastern tip of Mecklenburg County; and (3) the western
section, which now includes all counties between Gaston County and Cherokee County. Prior
to the assignment to it of seven additional western counties, the population of its service territory
was 2.l million and its population density was 203 persons per square mile. This compared to
147 persons per square mile for the rest of the State. The overall density will be lower now.
At December 31, 1995 , PSNC's total capitalization was over $350 million, and consisted
of approximately 50% common equity and 50% debt. Its net income was between $21 and $22
million for each of the last two years.
PSNC provides service in 23 out of the 33 counties comprising its franchise area. Within
E-2
its service area, it serves 87 communities. PSNC serves approximately 33% of the households
in the counties where natural gas service is generally available, compared to a rate of 26% in
1988.
Prior to being assigned seven new counties in August, 1996, the three totally unserved
counties in PSNC's franchised area were Alexander, McDowell, and Warren. In addition, gas
service is being provided to only a very small portion of two other counties, Franklin and
Haywood. In December, 1996 PSNC's expansion project to McDowell County was completed.
PSNC also has developed preliminary plans to extend service into the center of Haywood County
and introduce service to its portion of Alexander County. PSNC currently has no plans to serve
the seven new western counties recently assigned to it. Frontier has applied to serve Warren
County, and PSNC has indicated that it will not oppose its application.
Piedmont Natural Gas Company is a publicly-traded natural gas local distribution
company that is listed on the New York Stock Exchange (ticker symbol is PNY). Piedmont
employs approximately 2,000 persons and provides natural gas service to over 510,000
residential, commercial, and industrial customers in the piedmont region of North and South
Carolina and in the Nashville, Tennessee area. In North Carolina, Piedmont provides natural
gas service to approximately 310,000 customers through a system comprised of approximately
400 miles of transmission lines, one liquified natural gas (LNG) plant, and 6,743 miles of
distribution line. Piedmont has access to gas supplies through its physical connections with the
Transco interstate pipeline.
Before Piedmont was assigned additional counties, its franchise territory consisted of all
or parts of 14 counties in the piedmont region of the state, and covered 5,&9 square miles. The
E-3
population of the area is approximately 2 million and its average population density is 356
persons per square mile, which is considerably higher than the 147 persons per square mile
average for the State. The Commission has recently assigned Avery, Yancy and Mitchell
Counties and the majority of Stokes County to Piedmont. This will lower the average population
density of its territory considerably.
Piedmont's customer mix consists of 86% residential, 14% commercial, and less than 1%
industrial customers. Gas deliveries to North Carolina customers for the year ended October 31,
1995, consisted of 28% residential, 17% commercial, and 55% industrial. At October 31, 1995,
Piedmont's total capitalization, including short-term debt and current maturities, was over $736
million which consisted of approximately 48% common equity and 52% debt. Its net income
has ranged between $36 million and $40 million, over the last three fiscal years.
North Carolina's LDCs have had a high demand for their services, and this demand is
requiring them to make considerable investment in capacity, transmission and distribution plant.
During the 1991-1995 period, NCNG invested $98.4 million in new plant, an increase
of over 40 percent. This new construction facilitated the addition of 28,300 new customers. The
customer growth rate during this period averaged 5.4% per year.
During the 1991-1995 period, Public Service invested $214.2 million in new plant which
facilitated the addition of 47,221 new customers. The customer growth during this period
averaged 4.7% per year.
During the same period, Piedmont invested $208 million in new plant. This facilitated
the addition of 62,518 new customers. The customer growth rate averaged 5.8% per year.
Attached to this speech are three pie charts which show where the construction budgets
s-4
f
of the three LDCs weie allocated. Generally, most of their budgets are spent in expanding
service within cities and towns where construction costs are lower and potential returns are
greater.
The LDCs' finance expansion projects through the use of traditional financing and/or
expansion funds. Traditional financing includes the company's internal generation of funds and
the acquisition of funds external to the company in the capital markets. Internally generated
funds are essentially the LDCs' retained earnings that are not paid to shareholders as dividends.
LDCs raise funds externally through the sale of debt securities, preferred stock and common
stock. By utilizing a combination of traditional financing and expansion funds, LDCs can extend
gas service to unserved counties that would otherwise not be economically feasible to seive. The
amount of expansion funds which can be used for a project is the amount required to make it
profitable (zero net present value) over the long run. The LDC must raise the remaining capital
for expansion projects from the traditional sources that it utilizes for its profitable projects.
Expansion projects must compete with profitable projects for the LDCs' limited resources.
Because gas expansion using traditional financing sources increases an LDC's rate base
(the amount of investment on which it is allowed to earn a profit), an LDC has the incentive to
extend service to new areas whenever the investment is profitable. The amount of new
investment is limited, however, by the amount of capital that an LDC can raise internally and
externally. The profitability of the new investment and the profitability of the LDC as a whole
could be adversely affected if the LDC attempts to finance new investment out of proportion to
its size or financing capability. Two measures commonly used to evaluate the financing
capability of an LDC to finance expansion are the following:
E-5
(1) the amount of internally generated funds that are not paid to shareholders as
dividends. An LDC with a low internal generation is experiencing a large amount
of new investment relative to the profits from its ongoing operations.
(2) capital expenditures as a percent of total capitalization - the amount of new
investment divided by the total debt and equity capital of.an LDC. An LDC with
a high ratio is considered to have a relatively large constnrction program.
An overly aggressive gas expansion program could cause an LDC to be viewed as having
greater risk by the financial community. The financial markets may place limits on the amount
of external financing that an LDC can raise by increasing its cost to borrow funds or decreasing
the market price of its stock. An LDC faced with more profitable investrnent options than
available reasonably-priced capital is forced to allocate its resources among competinb expansion
projects in the most profitable nanner possible. If an LDC affempts too much expansion, it runs
the risk of raising its cost of capital for all projects which could have a negative impact on
profitable and unprofitable expansion efforts. This could also put upward pressure on rates.
Our staff compared the performance of our LDCs with respect to these two key reasons
to two comparison groups: (1) a group of 28 LDCs covered by the Edward D. Jones Brokerage
firm and (2) a select group of 14 LDCs which experienced above average annual growth.
Attached is a comparison of key ratios chart shows that during the five year period 1991-
lgg5, the three LDCs experienced a higher customer growth rate than the LDC comparison
group (fast growing) and the 28 LDCs covered by Edward D. Jones. The three LDCs were able
to internally generate funds at a level comparable to the comparison group. The comparison
shows that all three had lower levels of expenditures per additional customers than the
E4
comparison groups. Finally, the comparisons show that all three had greater expenditures
relative to their size than the comparison groups. These comparisons lead us to conclude that
although our LDC's have relatively large construction programs due to a high rate of growth,
they have been able to maintain internal generation of funds at levels comparable to other LDCs.
Some further indication of the financial strength of the three companies is reflected in
their Standard &Poor's debt ratings. Piedmont's debt is rated A and Public is rated A-. There
is no S&P rating available for NCNG because their debt was placed privately. Value line rates
all three as B* * *, which is a superior relative financial strength. Thus we conclude that our
LDCs have to date managed their high growth rates very well, and that they are financially
healthy.
Finally, I want to point out that the LDCs, the Commission, and the legislature need to
balance the LDCs growth and expansion in a way to keep rates affordable. Historically, natural
gas has been relatively inexpensive compared to other energy sources. However, colder than
normal weather in November has caused this winter's cost of gas to increase dramatically. This
has caused natural gas rates this winter to be 20-25% higher than last year's rates. Hopefully,
the cost of producer gas will return to lower levels, but this current spike in rates is a warning
that we cannot take low gas rates for granted.
E4
North Carolina Natural Gas Company
Regional Gonstruction Expenditures
For Fiscal Years Ending September 30, 1994 and 1995
Goldsboro / Kinston
28o/o
I
Oo Fayetteville
19Yo
Farmville / Washington
9o/o
fndian Trall I
Albemarle
11%
Laurinburg /
Rockingham
60/o
Smithfield I Selma
1Oolo
Other
10%
Wilmington
7%
Piedmont Natural Gas Company, Inc.
Regional Gonstruction Expenditures
For Fiscal Years Ending October 31, 1994 and 1995
Hickory
Salisbury r1%
3% Charlotte
37%
Burlington
13%
High Point
8%
Winston Salem
17%
Greensboro
10o/o
Public Seruice Company of North Carolina, Inc. Regional
Construction Expenditu res
For Fiscal Years Ending September 30, 1994 and 1995
Raleigh
23%
IP
Concord / Kannapolis
9o/o
Hendersonville
Ghapel Hill / Durham
12%
Gastonia
14o/o
Other
13%
Mooresville / 5o/o
Statesville
5o/o
North Carolina LDG's
January 1997
NCNG NUI Corp.
Not Rated [1] BBB
Piedmont
A
B++
2
Public
Service
S&PDebtRating A-Value
Line:
Financial Strength [2]
Safety [3]
B++
3
B+
3
B++
2
Notes:
[1] Alldebt has been privately placed.
[2] Financial Strength range from highest to lowest: A++, A*, A, B++. B+, B, C++, C++, C
[3] Safety range from highest to lowest: 1,2.3,4, 5
1t13t97
E-11
Comparison of Key Ratios
Five-Year Averages
As of the 1995 Fiscal Year
Item
Major North Carolina LDCs Comparison Groups
NCNG PSNC Piedmont
14 High
Growth LDCs
28 Edward D.
Jones LDCs
Customer GroMh Rate 5.40o/o 4.701o 5.807o 1 4.00o/o 2.40o/o
Internal Generation of Funds 60% 55% 52o/o 55o/o 59o/o
Construction Expenditures per
Added Customer Ratio $3,434 93,747 $3.4s7 94,661 $6,SOs 2
Oonstruction Expenditures to Total
Capitalization Ratio 160/o 15% 14Yo 13o/o 12o/o
IF
N)
1 Piedmont's customer growth rates are 6.60/o for North Carolina and 5.8olo for its total
system, which includes territories in North Carolina, South Carolina and Tennessee.
2 Due to the skewed distribution of the E.D. Jones LDCs, a median value is presented for
the Construction Expenditures per Added Customer ratio.
RATIOS.XLS Prepared by Public Staff 1113t97
VALUE LINE MEASURES
FINANCIAL STRENGTH
A relative measure of financial strength of the companies reviewed by Value Line.
The relative ratings range from A++ (strongest) down to C (weakest), in nine
steps.
A++
A+
A
B++
B+
B
C++
C+
c
Supreme relative fi nancial strength
Excellent financial position relative to other companies
High-grade relative financial strength
Superior financial health on a relative basis
Very good relative financial structure
Good overall relative financial position
Satisfactory finances relative to other companies
Below-average relative financial position
Poorest financial strength relative to other major companies
SAFETY
A measurement of potential risk associated with individual common stocks. The
Safety Rank is computed by averaging two other Value Line indexes the Price
Stability Index and the Financial strength Rating. (The Price Stability Index is a
measure of the stability of a stock's price. lt includes sensitivity to the market (see
BETA) as well as the stock's inherent volatility. Price Stability ratings range from
100 (highest) to 5 (lowest)). Safety Ranks range from 1 (Highest) to 5 (Lowest).
Conservative investors should try to limit their purchases to equities ranked 1
(Highest) and 2 (Above Average) for Safety.
E-13
DESCRIPTION
NORTH
CAROLINA
NATURAL GAS
(3rDT)
TABLE 4
PIEDMONT
MTURAL GAS ' (3ror)
PUBLIC
SERVTCE CO.
It,DT)
COMPARISON OF NORTH CAROLINA GAS UTILITIES'AVERAGE
UNIT RATES AND AVERAGE COST OF PURCHASED GAS
YEAR
ENDING
DEC.31
N. C. GAS
SERVICE
($,DT}
1989
1 990
1 991
1 992
1 993
1 994
1 995
1 996
$2.8743
6.1460
5.1550
3.3436
3.0380
5.8406
4.7051
3.4800
2.7140
5.5604
4.4516
3.0941
2.7077
5.6075
4.3105
3.1 405
3.02U
6.5385
5.4792
3.7015
2.8750
6.550e
5.0736
3 4982
2.4892
5.9594
4 4097
3 1847
3.4284
6.6992
5.3155
3.7330
0.6749
3.7000
4.3749
8.2518
6.4635
4.3595
t2.5611
6.2465
5.2786
4.0187
2.9360
5.6981
4.5434
3.2990
2.7903
5.9261
4.6688
3.277',|
I z.z'tol
6.0750
4.8369
3.3748
2.9569
6.5528
5.4680
3.3296
3.2286
6.81 02
5.6941
3.7796
3.0559
6.4551
5.3528
3.4370
3.6195
6.6791
5.7718
4.1521
0.8601
3.7200
4.5801
8.9527
7A934
5.2642
32.8358
6.7007
4.8673
3.5317
2.6946
6.3935
4.11461
3.3280
2.4053
6.4140
4.2271
3.1985
2.6969
6.8036
4.6541
3.3712
3.0636
7.1605
5.2030
3.7970
3.1047
7.5771
5.5E04
3.9626
3.0325
7.5858
5.2821
4.1 559
3.4419
7.2505
5.6341
3.8605
0.8943
3.3000
4.1943
9.2918
6.8232
5.5188
$3.2400
6.0034
5.1809
2.9448
3.3200
5.6554
4.7134
3.9350
2.9800
5.9116
4.9845
3.1510
3.2500
5.9962
4.8659
3.2589
2.8656
6.0408
4.9679
3.2047
3.2271
6.5937
5.4358
3.3989
3.0400
6.4542
5.2169
3.8917
Cost of Gas
Residential Rates
Commercial Rates
Industrial Rates
Cost of Gas
Residential Rates
Commercial Rates
lndustrial Rates
Cost of Gas
Residential Rates
Commercial Rates
lndustrial Rates
Cost of Gas
Residential Rates
Commercial Rates
Industrial Rates
Cost of Gas
Residential Rates
Commercial Rates
Industrial Rates
Cost of Gas
Residential Rates
Commercial Rates
lndustrial Rates
Cost of Gas
Residential Rates .
Commercial Rates
lndustrial Rates
Cost of Gas
Residential Rates
Commercial Rates
lndustrial Rates
Cost of Gas
Fixed
Commodity
Combined
Residential Rates
Commercial Rates
Industrial Rates
1t1t97
E-1_4