20030418Reconsideration Vulcan Power.pdf

ULCAN POW8R COMPANY
1183 NW Wall Street, Suite G Bend, OR 97701 [phone]
By FedEx
April!7 2003
Commission Secretary
Idaho Public Utilities Commission
472 W. Washington
Boise, Idaho 83702
RE: GNR-O3-1 - Petition For Reconsideration
Dear Commission Secretary,
Enclosed please find an original and seven (7) copies of the Petition For Reconsideration
of Vulcan Power Company regarding Commission Order No. 29216 of Case No. GNR-03-
Thank you.
Steve Munson, CEO
cc: Mr. Peter Richardson, !EPI
c::: ~ -
.,'" -,-..
~R1r- ~ rr:;:::,c::. ;0 8 ~fil' ~:~ AJ ..c::
~~'
0) ~
'.1~ C. ;t:oa
'Z~:
U5,"P.CJ)(.0)f fa
Original
t\ECEIVEO FilED
2003 APR '8 AM 9: 39
STEVE MUNSON
VULCAN POWER COMPANY
1183 NW Wall Street, Suite G
Bend, OR 97701
Telephone: [phone]
Fax: [phone]
)Oi;n'U,U ,Vu v
UTiLiT iES COMMISSION
April17, 2003
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE PETITION
OF THE INDEPENDENT ENERGY
PRODUCERS OF IDAHO FOR AN
ORDER INCREASING THE SIZE AT
WHICH A QF IS ENTITILED TO
PUBLISHED AVOIDED COST RATES.
CASE No. GNR-03-
PETITION FOR RECONSIDERATION
OF VULCAN POWER COMPANY
Vulcan Power Company, hereinafter referred to as "Vulcan" or "the Company , Petitioner
herein, pursuant to RP 331 and Idaho Code 61-626, respectfully petitions the Commission for
reconsideration of Order No. 29216 upon the grounds that said Order is unreasonable and
inconsistent with the best interests of the state of Idaho. We do hereby request a formal
public proceeding to reconsider Order No. 29216 at the earliest possible convenience.
Vulcan requests that the Commission reconsider Order No. 29216 for the following reasons
and submits data and analysis herein for basis of such request.
Commission s decision to deny the Petition of the Independent Energy Producers of
Idaho ("IEPI") without holding a public proceeding to gather and consider information
from other Parties is unreasonable and inconsistent with the best interests of power
consumers and stakeholders of the state of Idaho.
Order No. 29216 states as its basis for denial that:
!EPI in its Petition presents no persuasive argument for revisiting
the QF eligibility capacity limit for published avoided cost rates.
(Order No. 29216 at p. 3).
VULCAN POWER COMPANY PETITION FOR RECONSIDERATION - PAGE 1
However, the Commission s Order does not dispute any of the facts put forth by !EPI in its
Petition supporting the benefits of their request to increase the QF size to 30 MW. The
Commission does not state that its goal of encouraging QF development has changed since
Order No. 29069. The Commission does not dispute the !EPI assertion that there would be no
negative impacts to the utilities from the increase in QF size, nor does the Commission
produce any of their own conclusions citing negative impacts. Given these facts, it is in the
best interest of the state of Idaho to grant, in part, the Petition of !EPI and hold a public
proceeding to further investigate the Petition of !EPL and to request the input of other Parties
and experts, including other potential qualifying OFs, so that the Commission could fully
evaluate the pros and cons (if any) of increasing the OF size to 30 MW
Traditional Utility Negotiations Not Productive
The Commission notes two points in denying the Petition of!EPI. The Commission states:
The Commission notes that QFs greater than 10 MW are not
precluded from contacting an electric utility and individually
negotiating power purchase agreement. That has long been the
contract procedure for large QFs. The starting point for such
negotiations under the Commission approved methodology is the
established posted rate. Should a utility fail to negotiate in good
faith with a qualified QF, a complaint can be filed with this
Commission." (Order No. 29216 at p. 3)
Vulcan does not dispute the legality of this contracting procedure, but does dispute the
practicality and actual results of such a process. Vulcan has shared the frustration of other
independent energy producers in attempting to conduct "good faith" contract negotiations
with electric utilities of Idaho. The results of such negotiations have been disappointing and
nonproductive. In fact, Vulcan believes the Commission was quite right when it stated:
Despite a QF history of industry reliability and an opportunity
presented to utilities to diversify their resource base by adding
renewables, utilities continue to regard PURPA QFs as interlopers.
(Order No. 29029 at p. 5)
VULCAN POWER COMPANY PETITION FOR RECONSIDERATION - PAGE 2
The perceived status of an "interloper" is not an enviable status when conducting contract
negotiations. The mere implication of that type of attitude from utilities denotes utility
hostility towards QFs and does not foster a healthy contract negotiating environment. This
process of contract negotiation will not facilitate additional QF project development.
QF Size - FERC and PURP A
The Commission also notes in denying the Petition of !EPI that:
FERC requires only that published rates be made available to QFs
with a design capacity of 100 kWor less." (Order No. 29216 at p. 3)
Although Vulcan agrees with this statement, we believe a statement more relevant to the
current issue would be that "FERC does not require, nor does it preclude facilities greater than
100 kW from being entitled to published avoided cost rates." The PURPA laws, however, do
implicitly address this issue by specifically placing an 80 MW cap on cogeneration facilities
while not placing size limitations on wind, geothermal or solar facilities. By specifically not
placing a cap on the renewable energy technologies, PURP A and FERC allow states to set the
limits on QF size to best accomplish the intent of the PURP A laws and the goals of the state.
Indeed it was this interpretation that allowed the Commission to originally increase the QF
size to 10 MW. That size was fairly arbitrary and was chosen to attempt to reach the
threshold of triggering additional QF development. It is no less arbitrary than 7 MW or 12
, or even 100 kW, in that none of these QF sizes will achieve sufficient economies of
scale to trigger the intended increase in QF development. The key factor that gives
significance to the actual MW size of QFs is whether or not the OF size leads to the actions
desired bv the goals of the Commission. The 10 MW size is insufficient to trigger such
actions. The 30 MW OF size now being suggested will be sufficient to trigger additional OF
development according to the very Parties that run the financial models and will eventually
finance and build the QF projects and meet the stated goals of the Commission.
VULCAN POWER COMPANY PETITION FOR RECONSIDERA nON - PAGE
Raise QF Size Now or Raise Avoided Costs Later
Vulcan believes the state and the region need OF development, and believes that
circumstances will eventually lead to such QF development. That time can either be now, by
raising the QF eligibility from 10 MW to 30 MW which will facilitate QF development
thereby helping keep avoided cost low, or the time can be later when Idaho s continued over-
reliance on seasonal hydro and fossil fuels will require raising the avoided cost rate and thus
opening the door for 10 MW QFs. Clearly the former would be more desirable for the people
and economy of Idaho.
Vulcan agrees with the Commission that
if the rates are no longer fair and accurate, the appropriate response
is to adjust the rates, not to limit the size of the QFs eligible for the
rates." (Order No. 29069 at p. 7)
Indeed, if sufficient steps are not taken by the Commission to encourage the diversification of
resources that QF development provides, then the Parties will likely be back in a proceeding
to increase the avoided cost rates.
As stated in the Petition of !EPI, the importance of diversifying energy resources has grown
even stronger than it was when the Commission increased the QF size to 10 MW. Hydro and
natural gas supply conditions have worsened for both the near-term and the long-term.
The Pacific Northwest is suffering from yet another below average water year. Reports have
shown that some regional snowpacks are 70% of normal. This disturbing trend of low water
years further underscores the fact that we cannot craft public policy for power assuming
normal" water years in the future. The future potential for hydro to even maintain its current
capacity is bleak, given the widespread opposition to new hydro construction, significant
regulation and costs of hydro relicensing, salmon migration issues, and the ever-increasing
demand for other uses of water. There is also, of course, the uncertainty to the future hydro
system that comes with the regional effects of global climate change. These problems with
hydro will not go away and point to the logical conclusion that diversification of the energy
system is the only logical hedge against future insufficient hydro power generation.
VULCAN POWER COMPANY PETITION FOR RECONSIDERATION - PAGE 4
Vulcan also believes that the outlook for future gas fuel supplies (and prices) is bleak and
agrees with the !EPI Petition that states
Natural gas has now moved from the supply status of a just-in-time
commodity to a commodity that is actually in deficit. It is projected to
remain in deficit status for the foreseeable future. As a result prices
have recently hovered near all time highs." (!EPI Petition at p. 9)
The Commission did not dispute these fmdings. Additional research and analysis conducted
by Vulcan and other gas experts further illuminate the ominous nature of the gas fuel supply
situation and is attached hereto.Data from Vulcan, Simmons & Company Int'l (Exhibit A),
the National Energy Board of Canada (Exhibit B), and Platts Research and Consulting
(Exhibit C) all indicate the high probability of gas fuel prices remaining at their high levels
and for price spikes and increases in the future.
The fact that the volatile gas fuel supply market has changed dramatically is likely
justification for readdressing the avoided cost rate in a new proceeding, but more relevant to
this Petition, it further demonstrates the importance of the Commission accomplishing the
admirable goals it set forth by initially raising the QF size to 10 MW, namely that:
Energy resource diversification is desirable.
Therefore QF development is desirable.
Therefore increasing the QF size to encourage QF development is desirable.
The passage of time has illuminated the reality that the Order of the Commission to raise the
QF size to 10 MW was the correct decision for Idaho, but it wasn t of sufficient magnitude to
achieve the desired effects of the Commission. Raising the OF size to 30 MW remains
consistent with the goals of the Commission and is in the best interests of the state of Idaho
VULCAN POWER COMPANY PETITION FOR RECONSIDERATION - PAGE 5
Respondent Energy Background
Mr. Steve Munson is an energy professional with thirty years participation in international
energy markets including: graduate thesis in the geopolitical impacts of declining oil supplies;
Wall Street energy investment banking; and correctly warning federal and state agencies and
electric utilities since 1995 of the recent power shortfalls and gas supply price impacts
throughout the West. He has warned power policy participants of impending electric power
price increases driven by North American mature gas basin depletion rates and future foreign
LNG supplies.
Mr. Munson is the CEO of Vulcan Power Company, a geothermal company that has
expended very large amounts of time and money in Idaho to advance clean, baseload
geothermal projects. It has been stymied along with others by the past 10 years of Idaho
Power and A vista opposition to geothermal power gaining a foothold in Idaho.
Vulcan Power Company and Mr. Munson were instrumental in the passage of a 20%
renewable portfolio standard in California, a 15 % renewable portfolio standard in Nevada
and a 10 % renewable portfolio standard rule in New Mexico. He is a founding member of
the Federal Geothermal Working Groups ofIdaho, New Mexico, and Oregon. He a member
of the Geothermal ResoUrces Council. Mr. Munson holds an MBA in Finance from the
Stanford Graduate School of Business and an MA in Political Science from Stanford
University.
Respectfully submitted this 17th day of April, 2003.
~~~
Steve Munson, CEO
Vulcan Power Company
VULCAN POWER COMPANY PETITION FOR RECONSIDERATION - PAGE 6
, '
Testimony of Vulcan Power Company
Exhibit A
Simmons & Company International: Natural Gas Research Reports
. ". '
3 . ,Simmons & Company Inte~ational, an inyestmerii banking firm based, in Houston: Texas,. has
been tracking natural gas production and price implications for years. The Simmons &
Company International natural gas research reports can be accessed on their web. site at
6 ." www.simmQnsco-intl.com.
Portions of the reports are copied which have influenced the Company opinion that the United
States in general and California in particular are faced with a significant risk of relative high
average annual prices for long term gas plant natural gas fuel. Also influencing this opinion
are domestic gas price increases since 1999, including changes in winter-summer seasonality
gas demand patterns.
In the opinion of the Company, the implication of the reports findings stated herein, are that
the natural gas fuel price for referent gas plant operations beginning in 2006 may average at
the high end range of the Platts CPUC workshop report of 3/4/03 which was $ 6.218 per mcf.
(See Platts report attached).
Simmons authorized Vulcan Power Company to quote from the referenced reports located on
their web site during the CPUC process. Simmons does not provide testimony. Their research
report data was used to form gas supply and price opinions. The work is subject to the
disclaimer at the bottom of the first page of the report section.
Interested parties are invited to review the referenced reports concerning the larger gas supply
and price picture to determine that such material is not out of context and to view the
III-
Testimony of Vulcan Power Company
disclaimer of Simmons & Company. The first report listed below is the latest Simmons report
available at 3/26/03.
Simmons Report: 3002 Natural Gas Production Update (at 11/25/02)
. ,
. 4
' "
~~The reported &ta (2002 '~ear to , c;tatiy hav ' shown a c~risi~tent ye~r/year" declin~ . !reIid of."-
. .
between 3% and 5% for the first three quarters of 2002, which is at the high' end of our 3% to .
6. 4% decline estimates in November 8, 2002 research report "North American Natural Gas~
. 7. . Improving Upon an Alrea~;Y Positiv~ qut!ook.
. .
It is interesting to note that the sequential change in actual gas production has' been essentially
flat during the last two quarters. mote:with the reference to "Positive Outlook" they mean
high gas prices.
Implications
According to Baker-Hughes the US gas-directed rig count has average 690 rigs through the
first three quarters of 2002. Even though this is significantly below the 2001 average activity
of 940 rigs, it is still above the pre 2000 record high of approximately 650 rigs in September
1997. With nearly 700 active rigs the continued production declines from the largest US gas
producers is further evidence of the relentlessness of the decline rate treadmill.
Moreover our assessment that US natural gas production will continue to decline into 2003
continues to be on track. We forecast 1.5% decline during 2003 with a 14 % increase in rig
count from 2002 levels." (See Natural Gas Supply Analysis - Simmons & Company, attached)
III - 22
Testimony ofVu\can Power Company
" '' ... '. :. '. '
Natura! Gas Supply Analysis
Simmons & C;ompal1y.IpteI11ational
2002 Energy Industry Research Reports
Nov. 8 , 2002
Feb. 15 , 2002
Simmons Comoanv International. 5000 Bank of America Houston. Texas 17002.
[phone] Fax [phone]
This report is based on information obtained from sources, which Simmons & Company International
believes to be reliable, but Simmons & Company International does not represent or warrant its accuracy.
The opinions, ratings and estimates contained in this report represent the views of Simmons & Company
as of the date of the report, and may be subject to change without prior notice. For detailed rating
information, go to http://sciwebO1/publicdisclosure.Simmons & Company International may seek
compensation for investment banking services from companies for which research coverage is provided.
The firm would expect to receive compensation for any such services. Research analyst compensation
is based upon (among other things) the firm s general investment banking revenues. Simmons &
Company International will not be responsible for the consequence of reliance upon any opinion or
statement contained in this report. This report is confidential and may not be reproduced in whole or in
part without the prior written permission of Simmons & Company International.
III - 23
, ., '
Testimony of Vulcan Power Company
North American Natural Gas, Improvin1! an Already Positive Outlook" (11/8/02)
As we near 2003 , our outlook on the natural gas markets continues to improve, as the
potential for tight supply and demand fundamentals has increased. The U.S. natural gas
production treadmill is more visible than ever and with a lethargic rig count that continues to
show no signs of recovery in the near-term, we believe that 2003 production will likely decline
6 1.5%. Moreover, the natural gas import situation has changed materially over the past few
~. years, as. C~nadian production. is ,at a' zenith~ .and imports from Canada' could decliri~ next,
- "
8 '' year ,while U,S. natural'ga~, 'exports to ' Mexico are on' a n increa$ing. traj.ectory.~Thus:' tne
burden to fncrease~U.S. gas"s~pply increasJrlgly ~~sts onJ~e untested should~rs of LNG! ' .
Electricity Generation (35% of total S. demand). Over 115.000 MW of new generating capacity
has come online since 1999 (when reserve margins hit a dangerously low 7%). Approximately 95% of
this new generating capacity is gas-f.red. Not surprisingly, we have recently witnessed sOlid demandgrowth fur natural gas to generate electricity. In 1999. 15% of electricity was generated using naturalgas; in 2001 , almost 17% of electricity was generated using natural gas.
.' .
Table=B.reakout,ot"r~taI And Gas.FJred
, ":"
Electrlclt Ge~ration' '
Natural Gas ,. Change-
1099
2099
3099
4Q99
FYe9
1000
2000
3QQO
4000
191
566
059
1.417
1558
1.352
700
129
1,505
13%
9,.
Total
Beolriciy
Generation% Change
706
846
11$7
636
1G.144
9~2
10.124
11..283
10.125
12%
16%
18%
15'11.
15%
14'1r.
17'1(,.
19'1r.
15,.
SOOI'Ofils: EIA and 81m moos & Company Intem;;l1ional.
The figures below graphicaUy illustrate the growth in natural gas-fired genera1ion. even thOugh total
power generation has experienced lethargiC growth over the past two years. This monthly electriCitydata further highlight the sigrificarrt seasonafity of natural gas-fired power generation demand during
the summer months when air oonditioning load peaks.
Gas-Flred Electric Generation
a.nnn
l"tII!!a D1OOO .:aM D200a.1
! 2,500
j 1.EOQ
11~
!i:(J
Jon
- -- ~
M.~ Aln Jul AIq II"" 0...... Noo Doc
Sources: EtA and Simmons & Company International.
Total Electricl Generation
16,Q1111
- 19911 C 2IJIJ . 2001 C :iIJO2
f 12,Q1111
. !U'.OO
! f!,.OOO
I Will
F,",,"" Ajr
"'"',
.I:If kq 6"!' Oct NIJI/ Doc
ill-
Testimony of Vulcan Power Company
In 2001 , total electricity generation was down 1 %. but demand for gas to generate electriCity was up
10%. Thus. even in a flat to declining overall electricity demand market, natural gas demand for
electricity grew through increased market share. We expect this trend to continue in 2002 and 2003.
With any electricity demand growth. natural gas will only gain incremental market share in the power
generation market as the vast majority of the incremental generation adds (Le., capacity ma-gin) is
natura! gas-fired.
. ;,. ., ,. -,' ,. -, ' ,
15%
' '
"TctaI~
10%
.,
i .
5"-
1.
~ . '
161t'1B . 2000 . ~ooo
~ ' '
. 4000 1001 2001'SQG1 C1' 1aG2 . .
:. .
10'!r0
8o1Jr~ EIA and Simmons & Company InlBrnatlonaL
In 2002. approximately 53.000 MW of new power plants are expected to come into service over the
course of the year. (please see our Odober 4. 2002 report, '"Evaluating The Near-tann And
Long..term OUUook of U.S. Electricity Fundamentals'. Year.to-date (through April), electricity demand
as reported by the U.S. Energy Information Acln'UnlstraUon was down 2%, but demand for gas to
generate elecb1clty was up 6% (or 0.bet/day). ThIs was In line with our expectations and is
particularly Impressive when considering that hydroelecb1c generation was up 16% year.over-year~
Further, with year-over;.year etootrIcity demand comparisons Dkely posWve during 20 to 4002, we
expect gas demand for electricity generation to continue its recent growth trend. Our estimate of a
3 bcf/day InC1'ea$6 In power generation demand for gas In 2002 looks very realistic. Utility demand
through the summer conftrms Improved eleotrlclty demand (as summer weather was approximately
15% warmer than normal).
In 2003, we expect approximately 45.000 MW of new power plants to come Into service. While these
new gas..fired power plants will displace- S()Ifne older, lesser effk:lent gas plants. we continue to believe
that powet" generation d4.tmand for gas will be up 1.0 bcflday In 2003 compared to 2002.
s. ElectriQlty Capa.c;lty AddltlQn$
Historic And Expected Capacity Additions (Gigawatts)
1900 1991 1992 1993- 1994 1~ 1996 19:97 1006 19r19 2000 2001 2OO2E 2OO3E 2.004E 2OO5E.
SOurce: RDI. Simmons & CompahY IntemBtionaL
III - 25
. ,.. .'" .. ,. .
. .
Testimony of Vulcan Power Company
' 1
For those nay.sayers I n the crowd who are fearful that no new power plants will come Into service In
2003 (as IPP players cancel plant construction), we note that this is not necessarily negative for gas
demand- With any electricity demand growth (and no new power plants), utlllzation of less efficient
peaking plants wi~ Increase. This would rotua!ly boost demand for gas compared to the expected
scenario where the planned combined cycle plants are completed.
Beyond 2003, y.e expect 15,000 MW of new pcM!er generation capadty to come Into selVic;:e during
2004. At this point. we estimate electricity reserve mar~ns will reach a comf9118t!1e 20% (compared
fp7%1r:l1?99J-
" '::;,. ..:.:: '-, ', . .' ,.. ,. ,' "..., . ' ' . ," -., - " ' ., ,
I U.S. Natural Gas,Suppty "
.. ~ "
S. ProdlJctJon (accounts for 84% ottota! U.S. gas supply). From 1995 through 1999, the gas rig
count averaged a rather consistent 450 to 550 rigs. Over this period, producUon per new gas well
completion was also: rather consistent averaging 1,O5l1)mcfd, In 2000, the gas rig count jumped to
72f'J rigs, and production per new completion declined to 0.60 mmcfd. In 2001 , the gas rig count
. ,
JU(nped fudher to average 937 rigs, I ~d new praduc:Uon per CornptetlQl'l dropP'ed. ,to Q..63 mmcfd.' We .
.. , - . ' . '
argue that'the rig actiVity levels and prodIctfon ~pOnse.ln 2000 and-2001 are tndJoatIVe Of.ttIErlaw Qf '. ,
. "
c;tlmln1$hlng mar~nal returns. .
, .' .' .~ . ' ": ' ' . '. .. ". .
The data from 1995 to 1999 argue that. with a base gas rig count of 500 rigs, produotlon per new
completion Is approximately 1.00 mmofd. looking at 2000 and 2001, we believe that Incremental rigs
above 500 and up to 750 were drti1llng prospects that average 0.35 mmctd of new production. Above
750 rigs, we believe the Increment~ rig drilled prospects that average 0.15 mmcfd of new production.
From this relationship, we continue to estImate that U.s. production will decline by 3 to 4% In
2002 (based on expectatfoo that the U.S. gas rig oount will average 700 In 2002). Through 1 HOO. U.
production was down 4.5%. With easier comparisons In 2HO2. we remain comfortable wtth our
analysis of U.S. produotlon trends.
70.1.200'
~ItF"i1i;os 60 PnM*odIon IJX)It
I!OO ~
800 i
400 I
5o.
!!04o.
130
:2&
200
NoIIIm4xxt5 I
!fJ fi $
, ~
Sources: EIA.. Saker Hughes and Simmoni'; & Company Inlerna!fonal.
In 2003, with expectations that the U.S. gas rig count will average 940 rigs, we expect U.S. gas
production to be Bat to down 1.5%.
III - 26
, Testimony of Vulcan Power Company
The reported natural gas production data from the U.S. EtA for 2HO1 and aU of 2002 are not useful due
to the ab$ence of Gulf of Mexico production oota. The Minerals Management S€fVice, the agency
responsible for aggregating and publishing GOM production data, has not posted any production data
since July 2001 due to a comQination of legal reasons and data oompilatlon problems. Thus, the EIA'
production estimates are made without the benefit of 25% of total lower 48 productlon...and are not
mearungful over the past several quarters.
In lieu of waiting on better production estimates fron'l the MMS and EIA, we track Texas natura! gas
: productIon data. ~ Texas' gas, wel! prOduc!:ron, :~Ich compOses 'all11ost 25% of tota( U.$-, gas well
, "
' . . proaI,Jction, $ows the,lmpaotof.r.educed drilling aC1lVltY-Oyerthe.past ($vq1.J~uters.A!thOl:l9h th!S,4atQ .
. " Is sut1jed to revision, we b~lleve Ifls a'oocent proxy fQr total' U.S. gasprodu~lon. T~xas gas
prOduction Started to decline In 4Q01 'as."85 continued as rig count continued to fall during 1 H02, . The
trends In Texas natural gas prodoction have been, SO far, dlrecUonally in-line with our estimates far
S. gas production decline of 3% to 4% In 2002.
, ." :' ', .
Texas Natural Gas Production
. .
NliIUtal Gas % a
.:~
Ri g COUnI '" ~-.getdtrl""
1098-13,:31 . 4D%o .360''B'$
2Q98
. .
13:34 319
.-:.
SQ98 13,00
. , ;' :/,,
9'!\,2B4 21'%
40911 13.16 1D%:225 -39%
FY9R 13.0.6%292 '5%
10W 12,-2.5%1B5 -49%
row 12.-4.17'9 -44%
JQW 12,"'.A-%221 14%4aw 13..oJI%:266 16%
FY99 12.2.JI%214 -21%
1000 13.1'JI.215 49')(,
2QOO 13,5'"2911 61"
3QOO 13.34 4.A'J\.363 55"
4000 13.43 2.6'!1-390 46')f,
FY1ID 13.ss 3.t1%-32If 114 %-
1001 13,1'JI...21 5:)'11
2001 13.53 1.2%..67 &7')(,
3001 13.33 (1%..n 33')(,
4001 13.25 1.3%394
FYD1 41-4';(,431 33%-
13.29 330"-22%
2QO2 13.19 -2..5%;3()6
3O'JTTD 13.2:%322 -32%
, .. ,. .' '
Scurce-&: TRRC, Simmons & Company International aoo Baker Hughea.
N,tura.t o.s'lmporl$ (itCCount for 16% ofkMl U.S. tJri.Ha1 (P$ ~Iy). S. natural gas imports
have two main sources: 1) Canada. and 2) Liquit'ied Natural Gas (LNG)mwhic;i1 are partially offset
natural gas exports to Mexico. We forecast total imports 10 the U.S. up 4% in 2003. driven by growth
in Canadian and LNG imports during 1 H03. Although believe: Canadian produdion could ~tNU
2003 (or even decline), we model a $tight ro-ease in 1H03 Canadian gas imports 10 the U.S. due tQ
high IeveI$ of Canadian storaGe and stignant industrial demand. We model 21-103 impOf1s flat. With
Canadian natural gas storage nearly full and the year-to-year comps for Canadian and LNG imports
reliativefy .due to low prices during 11-102. we model irn;;n:la~ imports during 1 HQ3. If this
impQft incr~ does not Jm1wrialize. the tight market we foreQIst for 2003 wil ce~nly become:
tighfe r.
Qlnada. For U1e better part of the last 15 years, Canada has served as the marginal supplier of natural
gas 10 the U.S. market This story is coming to an end. With a rapidly accelerating base decline
curve (from 10% to12%, 10 years ago. to 20% to 22% today), lower production per new well (1.
mmcfd 10 yeafS ago to 0~5 mmcfd today), and (ie(;rused drilling activity (down 29% year-tQ-(Iate),
Canadian imports. are down 3% (or 0.bcff1;lay) year-to-datf;t through July (accoFding to the U.
DOE).
At best, we see Canadian deliverability tat in 2003. With anything approaCling a normal wIDter,
Canadian oom$tic gas demand will be up-resulting in a in expot15 10 the U.s. even with
flat deliverability. In this s~, we see U.$ imports of CMadian gas down in 2003. If Canadian
de!iverability is down and domestic demand is up, exports of gas 10 U1e U.s. could be down by as
much as 1.0 bdfday.
III - 27
Testimony of Vulcan Power Company
Dynamics of Electricity-Driven Natural Gas Demand" (2/15/02)
We estimate that natural gas demand for power was approximately 16 BCF/day in .2001. Depending
on overall demand for electricity, we believe that overall gas demand for power will increaseup to 2 BCF/day per year over the next two years despite the impact of improved utilization
rates of 10Wtllr marginal cost fuel sources, capacity creep from nuclear and coal..fired
generation. and gas on gas competition. Assuming 2"5% annual demand gro'Nth the follo\M:ng
grapll summarizes the relative impact of drivers to electricily..ooven gas demand over the next two
Years-
: ""~ ~ '~.
~~t(m~ E~~..o"~ft G86 D ~d (BCF.lDay
j " .:: . ., ' ,. .- .
2002-' :: .,'
o..a
Adl-...d
o..m..nd
, " , . . '.~
11!0.0 2..0
... ,
1&:0
PrIM v....rGatl EladrloltyDmnClnd o..m..nd
Goow.1b It
~~:
iinpnw instllikortion CI:o:p:Kiily
Cm.op
. ." .. ". -.. .
200s
::: "..
11.
1SJ) PdorY-- I!!~Gat. o....-.dDmn..nd GovMIt.&
go" PlItt
C:banQlltl
0..&0'"iiIJ
..........1I1utltl&albn Cm.op
Ad;..-d
Dema nd
&1..-: Eneqw Imom.tii:In Adminialnlliara. RDI -.d Simmo.. & CoinfIany llrlloomatiix'1-
NoIi!I: Aaaalmes. 2.5% ......111 a1eclriciIV den'i8tJd grcv.DL
. .
I Summary
We do not project a material dedlne in eleclridty-related gas demand dUit! to 1he effBds
ull\fz.ation rate manges" capacity Ct-eep and gas. ()t1 ga:& competition OVI!II' the next twn years.
unteaa. we hiM! a protta.cted ded81e in overall demand fot' efectrlcity- OVetaU demand for
electricity Is the targe&'tsmgtB factor Influencing etectriCity-driVen gas demand.
Mote than any .other fuel &DUlce, gas-fired -eklc:tricity prodtiction uxhlbitti a large d~ree r:rf
s.eascliii'lliity. FUfth.ermoM . eleCfrlclty-f'elated !)as. demand is heavily InIlUit!nced by Mgional
diarad:erlstlca. Almost 80% of electricity-driven gas demand Is centerad In 2 out of the 10
HERe region$ (ERCOT and WSCC).
UtiUmtion nrtEta for nudl!lat and coal-fa'ed capadly are im,prO\llng, and utiizalioo rates r:rf
hydroetedric capacity are 8t1Cpeded to irnpr-ove aftl!ll' ill severe drought In the Pacific Nort!hwest.
In fbtal.WB exJi'ld utiUzatton talBchanges to di&pfacB about 6O(J mmcftday of gas demand
each 'year over the next two years..
Capacity aeep In nuclear and coa~(jred capacity e1Clsts. ()yer the next: two years, we expect
capacity Cre&p could potentialty displace an additional 300 to 400 mmcf/day of gas
demand each year.
Gas on gas competition has a materia. effect an eteclricity-related gas dem.md. W& expect
eIectricfty..-etatBd gas demand to Increase despita gas on gas competition. That saki, gas
on gas competition will canniballm a total of 8 to 10 BCFJday of pot1!ntial gas demand
over the next two years.
Fuet switching from gas to oil can h.we a materia! effect on electriclty-reta1Bd gas dematJd.
VIlhan 10&1 switching from gas 10 oil occurs.. we estimate that eledricity-driven gas.
demand could decfme by 1 to 2 RCF/day.
III - 28
;. .
Testimony of Vulcan Power Company
I Overview
Theta is Ctlmmt1.,. B significant amoullt of debat~ surrotmdlng the magnitude of el.lectticl1y-drwen
hawtaJ gas demand. Thi$ report addtess.eEi :some of the key IBEioos $tJrtootidlrag this debate.
Supply and demand fundametitms are- hEavily k'lf1uenood by tB11iotiill dtaradmistics 1hat ate
compouf1ded by the state of the. tmns~ti syst:em, 'tNtiid1 CUttt'tl1lJy Inhibits the moverrteflt of power
between regiOtls.. Therefore, we apptiad if! gtoOUtid-up, ieglooa1 apprmJCh to our anatysis. A1thotlgh
mgionaJ an~ l$;-ml..Kfimore cumbBt'$oOm!! ttJatw loc:OOngl1t OIJarali chano~ ,1eel'lt it. abso:tut~ne~ary in order to capttJre the, intricacies :of the -fragmented U.S. power miliUt. Simple "back of
:' '
ihtt Eit\\tEIlope
" '
ca1culalioos' ibat lump the entire U.S. Into - OOe cak:ulation can ' tead1D. ermniMJuisas&tiniptioos and misleading tesuitS.
. ,
Our anaiysi& mly incUt~s estimates of electricify-related uB& demand over the next two
years. We have. not attemptedlD make projBcliofJs beyond 2003 becaU$4!l otli!K:ik of visibillty
suwiY and demand fundarrtefllals and petidino. envlrohmental legislation. FederalLy spon:scred
. I.IegtsJatioh, colleCtively referred to as NOt SIP Cail, calls for state impterrteflta1ioh' plal'lS (SI Pt.) ih
22' MidweStern and Eastern &tates aimed at (educing niUous oxide: emsmons. Oh trade: .(()r
imptemenlation so~me in 2004
, ~,
~eliiWe there Is a.&IrOngll~e1i~d that ~$8 plans wu. haV~ ah
. .
fmpiict on the'abili~.of many existing cOal-fired gBMrating plahtS to oper~& at Curtem utilization
' ..' .
rates. _I it; difficult to am;BS.$ tha l""act of fhMe Wiltiai:ives because tt is slid IWlilving and has' milhY
, '. .. ,
moving parts. Hawever, there is a very real potential that reduced coal utilization could lead to higher
utilization rates for gas-fired generation and materially impact eledricity-drtven gas dtlmand.
I Schools of Thought
The Optimist: The bull case for electricityarelated natural gas demand. Keeping in tune VJith the
boom in development of natural gu-fired generation over the past couple of years, approximately
000 MW of new gas.-fired capacity came online in 2001. Only counting projects already under
construction, roughly another 100 000 MW capacity should come online before the end of 2003.
Virtually all of this capacity is gas-fired. New plants are expected to achieve utilization rates upwards
of 65% for combined-cyde and 20% for simple-qrde, thereby inaBasing gas demand 4 to 5 BCFJday
each year over the next few years. Improving nudear and coal u1ilization will not have a huge impact
because these units are typically older plants that will increasingly need to undergo. maintenance and
retrofits in ortler to be abf& to operate at cummt utilization rates. Additionally, environmental
concerns should eventually force many of these ptantslc shut doYm.
The Pessimist The bear case for electricity-related natural gas demand. Gas-fired capacity has
come online at a record pace and will continue Ic come online through at least 2003, creating a
supply glut of electric generating capacity that is only getting worse because demand has faltered
with the economy- Nudear and coal-fired utilization rates are improving evecy year and hydroeledric
utilization is making a comeback after a severe drought in the Padfic Nor1l1Yiest. Existing nudear
and coaJ..fired units are also being retrofitted and re-rated, consistently improving their output
capacity. On a macginal cost basis, nuclear and coal-fired generation operates at a lower cost than
gas-fnd capacity. Therefore, utilization improvements and capacity creep will displace most
additional gas-fired production. New gas-fed capacity will run at lower utilization rates than Vtthat
developeR are planning and ..wI mostly compels on the margin with alder gas-fired capacity, creating
gas on gas competition. This will actually reduce overall demand for nalural gas needed to produce
electricity as newer, more efficient units use less gas to produce the same amount of electricity that
older units generate.
Our View: Improving utilization rates, capacity creep, and gas on gas competition eJCisl and
negatively impact electricity-driven gas demand. A great deal of gas-fired capacity has come online
over the past couple of years, and this will continue through at least 2003. As a result, there is a glut
of capacity in some regions. However, the fact that some regions still face a tight supply situation has
been masked by depressed electricity demand as a resuH of a fattering economy. Despite these
factors, we believe that eledricity-driven natural gas demand could grow up to 2 BCF/day each Y.!'Iar
overthe next two years and that there \WI not be a material decline in e~reJaled gas demand.
However, how much gas demand growth we experience Voill in a large part be determined by averaD
demand for electricity. While it is likely that electricity demand growth \WI return after the malaise in
the second half of 2001 , indications are that it wiD not occur until at least the secood half of 2002.
ill-
Testimony of Vulcan Power Company
J Regional Variations
Not surprisingly, electricity..driven gas demand is higher in regions where gas.-fired capacityrepresents a material portion of overall generating capacity. In our analysis, we found .18ctricity~
related gas demand to be hnvity concentrated in regions with a large concentration of
gas-flntd capacityt mainly Texas, California and New England. Electricity-related gas demand isalso affected by the relative concentration of lower margirlaJ cost generating capacity in each region.
As we have said, just because gas4ired capacity exists does not mean that it will run as developers
have planned. In regions v.mere enough generation from fow..cost sources af pmver like nudear and
coal-fired capacity exists to meet demand, gas-fired generating capacity does not run an appreciable
percentage of the time (Le. ECAR, MAIN, MAPP). This illustrates the diffiaJlty 1hat new gas.fired
capacity in those regions (especially baselaad capacity) could have in achieving utilization rates
required to make these investments economic "lMthout substantial electricity cremand growth.
Using our estimates for 2002, the folkming table illustrates regiOnal variation in gas demand for
production of electricily.
2002 Est Regional Gas Demand for Electricity
Production (BCFIDay)
NERC Region Gas Demand % of iotalECAR 0.
ERCOT 4A 2&%FReC 1.WAC 0.MroN O~ MAPP 0.NPCC 2.2 13%SERe 1.1 S~ 1~ WSCC 5.31%iotl1. 17.1 100%.sa~ E.I1eIW Il1d'oImatim AdminilitratioR, RDI and Sirnrno~ & Cotnp'anr lntf:mat!tJt'I81
Nob!!: AulJ'rIIM 2.5% dl!!millhd and he) from 1I'fI' to oJ..
I ConcllAion
Regional, seasonal and marginal cost considerations play large part in determining
electricity-related natural gas demand. Ignoring any of these factors can lead to erroneous
assumptions and therefore concfusions in estimating gas demand, Although growth of electricity-
driven gas demand is not likely to be the 4 to 5 BCF/day that some are predicting, the impact of
improving utilization rates and other factors negatively impacting gas demand are not likely to bring
about a material decline in gas demand siltier. Eledricity..driven gas demand is likely to grow over
the next couple of years, but the amount of growth is highly dependant on overaJl demand for
electricity. Due to Ia~ of visibility in supply conditions and pendin1) 6nWonrnentallegislation, it is
difficult to make projections of eJectricity-driwn gas demand much beyond 2003, and we are
inherently skeptical of the degree of accuracy in any IQn~-tenn assessments.
III - 30
Testimony of Vulcan Power Company
Exhibit B
.. ., '. '.
Natural Gas Supply Analysis
" ,, . ' .
" N atiorial Energy Board of CaJj.ada
2001 Annual Report
III-
, .. .
Testimony of Vulcan Power Company
III - 32
18000-
16(jO~
1400~
12000.: '
. J.O~oo.:,
8QOI)~
6O00~
400Q~
200Q~
Testimony of Vulcan Power Company
Number of Wells Drilled
Q":
200t
" ., '
Dt'J 'Other
. . '
Oil
.'
Gi!I$
Upstream Activity
A nx:01d 17983 total\\le'lt.s W1:11: ~iif~ed in year 2001
excW1h1g th1: previoUs trlgh of IvSO7\\~eI1$
: ,, '
established in Y~at 200g, (Bfgitre :~). This record Jever"
of drilling activity was in respOnse to.the high
natural gas and oUprices that prevailed in the eady
part of the year. The foCU$ of the drilling was on
natural gas, with the number of gas wcll completions
up by 16 percent in 2001 from 20"00, and making up
69 percent of aUw:ells completed. Oil well
cQmpletio:ns,~r~1 ~ere14perCentlo\"'ertbanthe ,
. "
199l J!;/98.. ,1999 ,2000
. -
previ6us y~r., with oil drilling (lroppi~ng Qff ~ftet the '
. "
. fi~'t quarter as oil ptic~ 'de~d, ,
Competition for land remained high in 2001 as
revenue from land sale bonuses collected by the four western Canadian provinces totalled more
than $1.6 billion or 10 percent higher than in 2000. While the average price, at ~292 per
hff.'tate, was down sUght1y from ~299 per hectare received in 20001 the total !and area involved
in sales wMUP 15 perc~ from 2000, to 505 mOtion hectares. In. the hontiet areas1 the majority
of land sale activity was concent~ted in Nova Scotia offShore where there i$ keen interest
surrounding the proposed natural gas development at Deep Panuke.
Seismic survey activity also remained strong in 2001. with
number of active crews up eight percent over the
previous year. This increase reflects a greater level of
activity in the first ha'lf of ZOOl, with second-half levels
similar to those of 2000. Seismic activity in Western
Canada was focused in the southeast. foothills, and
northwest regions of Alberta as well as in the northeast
region of British Columbia. Record expenditures of
$20 billion for exploration and development of Canadian
conventional and frontier areas (exclud,ing oil sands) were
made in ZOOl, up 10 percent from the previous year.Exploration spending continues to be about one-third of the total oil and gas exploration and
deve1opment expenditure in Canada.
. .
Production
Despite record gas well drilling and completions in Alberta and Saskatchewan in z001.
production increased only marginally. Canadian marketable natural gas production In 2001
totaled 180.7 billion cubic meU'eS,up about percent from 2000 level$. The main sources of new
production were the Sable Island offshore project 11'1 Nova Scotia and a new gasfietd at Ladyfern
in northeast Briti$h Columbia. These sources oflncrem~tal production have slightly shifted the
distribution of Canadian natural gas supply at the expense of Alberta and Saskatchewan~ Alberta
now a,counts for 79 petC~t of total Canadian production, down from 8tpercent in 2QOO, and
Saskatchewan accounts for 3 perc~t, down from 4 percent in 2000. British Columbia now
contributes almost 14 percent, Nova Scotia 3 percent, NorthwE!St TerritorleslYukon 1 percent and
Ontario, less than 0.5 percent of totil Canadian gas production.
III - 33
Testimony of Vulcan Power Company
Reserves
Th~ NRB's estim3te of r~maining established reserv~s of matkctable natural ~s as. at year-end
2000 is 1 622 billion cubic m~ttes. This indud~ reserves from the Ea$t Coast offshore and the
Liard Region of the Northwest Territories (Table 6). The volume of remaining ~stablished reserves
HflturtIl C(I$ bporU tmd lmpom
Alth('1I.1gh thete wet~ fiUmajOt pipelines
Q~'ttUcted 11'120011 incre-m. thtt)ughput Oftt~ A"~ and M&,NP :systems ~~blOOC~ian &1lS ~s and imports tt,) ~lI(:h
record highs. IIi 2001t Jwt. expt,:KtvofUlhe$ were 102.8 billiOn cubic m~~ an 1.ri~1lSe of
.3 pet~rtt from 200) and ",n iJicrwe of 26 ~eent -over the last fiv(t ~rs.
'fbe; expt:lI1mamet continues tt) grow 1lS net ~p/.'Jrt$ now ~nt for $7 pet(:efit of tout C~dJan
ptOductitm (F1gl;11\!; 7), Thi$ 1$ up fJ:t)m 56 ~certt I.ri 2(00 and SO percent fl~ ~. TheIncr~ 11'1 20tH is prim~ty d~ t() ~hat1(OO tt. new mark~ 1lS i!.result of the statt"Up.and
fir$t full .rJf operation ()f Attiance .and incr~~ V(IIumes from Sable: Islat1id pr~i on
MEcNP s~tem. Gro:ss exp'J$ in 2001 read1ed a. reoord 10&.7 billiOn ctib~ metn!'.S- 1n.patt to
record gas volume$ being ~1mportoo tl) ('An. As m1.1d1 as. 3()per:r.-ent of the gas tt!t)VOO
AtJiart(1,! i~ irtlported bad I.ritf~ $l.mthern Orttari(j via Vecwr S, pipeUne, Impot1$ 00 Vector
attounwd n-JI ftbout 4..2 biUi(m cubiC; me:tres,in 2tXJ11 Or 72 percent of the 5.8 bUliCm cubiC mefre$
of t(tW 1IfipQ1tS. Prior to this.. gas import V(.i1,1ID(.'S had .bf:en negJigib.t~
The diStribution of expOrt sat~ in 2001 re~iS the irue!l'5a1 ,'t)tumes ROwing to 1;h(tM14wm
and NortheiLtt On t~ pipclirlcs .and are now ii$ (ollow$:: 39: pcrc~t to the Mid~J 30 vereent
tt): th~ Northc~~1 It) pcrcr.mt t(t Cil1iR'l1"niar 14per(1,!nf to the: heitlt N()Tth~stt ~ndless than
1 pe:rt;gnt tt) meM(Juntain Regiorl (Figure 8).
' : '
TABLE 6
Es:tlmat~ of E$.~bUshtd Re$eaws of Marketable:
. NatutaJ Gas at J1 Deeember ltJOO
. (billloo~ fI'j~f~)
' ': .. , . -, .
InltW
liG1.!
4 f!6H
200.
. 4.0'
,21.
fl. t!2U
. Rermlrn1oi:J
2:3.0
121()J
7fj jj
11..6
14..4
3"U
. ,1 QZ..c
. .
B ri&lsh CdtJrJ bIa"
Albeita-
S.i5 kaldtewan-
Ontario-
NHr a ndI 'iOOini
~\lSG1lla~~~
TMBI : .
- .' ,
taJ 'Eriilt.~ ~(H(M9'i&: l.Ueui"iI!1NB-Q::Ii"\YM!I dnmse
(b) MtME~a:~Bam.....dm.~~
W ~Ktm!U:b3-1~.;;mo
'iIO
~~.
G4'~.I\'tdIii-
TABLE 1
NaWr~ Gas ~ervlUt Addit.kms and Production
(blilton aIhlc Wl6r~)
19% 1991 1m: 1'999 2000 T(ltal
MdItlof16"8 .50 no 119 1S2 1S1 .s.QC159 1~1 16i 17fj 171 m
fMal ~aI~
~.
1121 1~. 16S1 1629
(11 wtOJlt--.tiadl:lai n l!)9T siIIttd tlllb:tm
(Ji) ~~!t~.~
d~lJn(!d from l~J9J albeIt by 1~ thart (Jr'W
pcrt;gttt, as produet1on continue1.1 t() (J1.ltpat.~
. n;!S~f\'~.addlti()rus..
, Fr.(m'l1996,2C)I)j)t cum1,1!~ti\'t- addJtioIU (.d "
, ,
markWtble gas
.~~
f(!plat-M ooit73'pen:Mt
(',If tOt.a.i production. - Wit~)ut th~ NQ\'a Scoti41 .
and U~rd re:serv~ a4ditjrms... thi$ would only be
62 peIiX!nt. C()ntirtuoo .and $.tIt,mg O)J1c-en~!t1ic)n
byirt(luS1ry on gas explormiQt1 l4)sultedin ~ar
2000 a4ditic)~ being the hi&~~ 1nr4)tent .~(S,
- '
(fab~ 7), WhU~ ne1\' di$((J~~s I.ri tlw LOOyf~
area of IkltiSh Q:.IU,mbia are tii)t;fp.Uy reOe:ct~
1n the -additiOO$ U,)t ~ar-2000. furt;b~
. . , .
. 1,hilfirtg il) 2()O~ 'hM prtWl(1ed ~han(1,!d -
deJin~tiof1 of thelX)(H. New dikr~r1e$
f~wer downward r~siOr\$ to ~imat~
for exi.Sitirtg: gas 1X1I.':It$ r~u1ted in a r~~ment
of 153 tNllion cubiC metreSJ ()I 8Spercf:rtt (Jf
mttural ~s prod1.let10n durIng 2000. The fact
th& gas prod1.l(.'ti(ttl hii$ been wtStrlpplng
re:s~vtS addltior'l$ d(!spite ~ry high rat~ (II
drllUng is an indi(!ttiQrt that the WCSB
maturing as a producing basin. It wUlllkely be:
difl~11lt to ma,intairt incr-eases 11'1 ilrtnUal
wJ.tho1,1t Ongoing ckve1opm~ in the
northern and ~rn~:rt portJOIU of \vc.~ the ~ c~ offshc;net and the
Mackenzie Df:ha region,
' ". .. ., ...
III - 34
. '
Tlit;': pr()p(.rtiil:m (~f Canadian brag t1;q)Vrn:d und~r
~h(H"t-t~rm orders in(:r&..iJSOO $E!;ruf1CiUidy in12(J(H W
~ttllo.5-t ~.n~~~nt fr(Ht'l 73 p(;f('entitt 2(()il
jni:;:II.!:,a~~ in sh()IH~rm !Ur.j1n~m~nt$ $in(:~
N~Wl.ml~r 2.(X:w1) is d~.;iJg~J)t to inqC'~d
vc)ll1ItlC$ (U1 t~~ ..1JiiilfJ(:(! ilI1dM&NI? $j'itt)Etl$.
BJ;lth th~ \'(.huJie an~l ~\'~1Ig.e priee. f(1f ~XP')rt~
hi 2.((n wC't(!I,lP $1~ifi.c;ant1y unlit 2p9O.
- , -, '
ffigl1!ft
~ .
exp~)ft "'(Jl~m~ 1!nd h~~er 4lV1!f4tgc f;ri~.
: .
fOr (~nadi-ari ~as have: tr~E1$1atet1 into ittcr~
~uft frtm ~ii18A~ I.'tXpom~ In 2(1() t.h-c
I~$W~ fn;tm. Ca~i;mItl1fUr~ expQrt.S
by 25 percent t4).a rei.,"'t)r(l ,$26,0 biUi!?"J up U~1m
$2:0,7 billiOn.jn2i)(Hl G~'j;imp)~ ill$(. rose t4)41
I~ri1 (:If $J,4tNfIi(mt r~S\Jfti:rigin flftt ~pc.Ht
. Of $~,6. ~UU(1n.f()r t~
j'~'. ..
Testimony of Vulcan Power Company
fiGURE 1
Carwcian N$lnsli Ga$ ProdU(tI~n and Net Exports
(billloa athk M~ttM,
.t&1)
100":'
l.-tlit,:.
, "
12~'
1007
lID':
60-:-
4i)-:-
20-:-
" 0':
, ., ,, ;"
1997,
" "
998
, ,
1999',2000 ' 2001 .
II PftJdu dfun Net bp orb
FIGULlE 8
rttunl GM SUpply aut Dbp;uidon
~1I1oft milk: Mftm)
III - 35
AS
.
Na
t
u
r
a
l

G
a
s

L
i
q
u
i
d
s

S
u
p
p
l
y

a
n
d

D
i
s
p
o
s
i
t
i
o
n
(t
h
O
U
S
D
n
d

c
u
b
i
c

IM
t
f
'
e
j

pe
l
'

da
y
)
19
9
1
19
9
8
19
9
9
20
0
0
5\1
p
p
l
y
Ca
n
a
d
i
a
n

P
r
a
4
u
c
t
i
o
o
.
93
5
96
.
3
IO
U
99
,
Im
p
o
r
t
s
"
"
1.3
1.~
1.
6
To
t
a
l

S
u
p
p
l
y
-
94
.
97
,
10
2
.
6
10
1
A
Dl
5
p
Q
S
l
t
i
o
n
Do
m
e
s
~
(
.
63
.
3
62
.
71
.
4
68
.
Ex
p
o
r
U
"
"
31
.
1
)
37
.
34
,
35
.
To
t
a
l

D
l
s
p
o
5
i
t
f
o
o
.
94
3
10
0
.
10
M
10
3
.
1
(a
)
So
;
o
r
r
e
(

N
E
a
(b
)
So
;
o
r
r
e
(

N
E
a

F
'
a
m

1
4
5
(e
)
So
;
o
r
r
e
(

N
E
a

F
G
n
l
l
S

1
5
1

i
I
I
1
d

86
f
t
(I
I
)
Te
t
a
l

w
p
p
l
y

II
c
u
q
n
"
t
I
U

dil
p
o
s
i
t
i
o
n

d
U
l
!
I
D

i
w
e
I
U
o
r
r

dI
a
n
~
.
(0
)
f!
6
m
I
o
A6
.
Ge
o
p
h
y
s
i
c
a
l

A
c
t
J
v
l
t
y
(o
c
t
l
v
~

s
e
i
s
m
i
c

ue
w
s
)
.
,
.
,
,
:
F
e
s
t
i
m
o
n
y

o
f

V
u
l
c
a
n

P
o
w
e
r

C
o
m
p
a
n
y
,
.
.
,
.
A7
.
Ex
p
l
o
r
a
t
i
o
n

a
n
d

D
e
v
e
l
o
p
m
e
nt

E
x
p
e
n
d
i
t
u
r
e
~
:
(m
i
l
l
i
o
n

S,
,
"

20
0
1
.
19
9
7
19
9
8
19
9
9
20
0
0

,
1
0
0
1
-
EJ
p
I
o
r
A
t
T
(
I
R
92
2
Co
n
v
e
n
t
i
o
n
a
l

A
r
e
a
s
-
5;
2
2
9
8-4
0
87
3
93
2
6,5
3
0
Fr
o
n
t
i
e
1

A
r
m
"
"
13
9
21
4
51
3
63
9

'
7
0
5
To
t
a
l

C
a
n
a
d
a
5.
3
6
8
05
4
Mi
l
7,
2
3
5
93
.
De
w
l
o
p
m
e
n
t
.
.
Co
n
v
e
n
t
i
o
n
a
l

A
r
e
a
S
-
10
,
7
1
0

.
8,
0
7
6
,
6,8
4
2
10
,
5
5
7
.
11
,
62
5
66
.
Fr
o
n
t
i
e
r

A
r
N
i
-
,
'
1
0
0
'
1;8
6
.
5
34
7
49
2
'
64
0
To
t
a
l

C
a
n
a
d
a
11
/
61
0
94
1
18
9
12
,
.
0
4
?
;
1
3
)
6
5
94
.
9
To
t
a
l

E
x
p
e
n
I
I
t
t
n
l
16
,
9
7
8
14
,
9
9
5
13
,
5
7
5
18
.
6
2
0
20
,
50
0
,
'
ta
)
8r
i
I
i
t
!
I

C
W
r
l
i
o
,

io
m
i
l
t
b
o
l
.

0
n
1
a
r
i
c
(b
)
Nc
I
I
t
I
1
!
f
t
s
t
T
l
t
r
i
l
l
1
r
i
e
5
,

M
c
n
1
.
m
m
"
.
-
.
d
oI!
i
l
H
)
t
e
" ,
te
l
E!
I
i
N
I
o
'
,
So
o
I
a
'
.
Ca
n
d
i
n

A
m
c
:
i
a
r
i
o
n

c
t
P
o
t
l
o
l
t
t
G
l

AS
.
.
.

Sa
l
e
s

o
f

E
x
p
l
o
r
a
i
l
o
~

R
i
g
h
t
s

I
n

W
e
s
t
e
r
n

C
a
n
a
~
a

.
19
9
1
19
9
8
19
9
9
20
0
0
20
0
1
-
51
5
0
"
30
1
5
29
9
6
38
3
;
;
'
39
0
8
73
6
48
3
,
73
1
69
3
'
85
4
94
4
50
9
39
8
28
~
37
3
,.

~
,
68
8
0

.

'
..
0
1
1
41
2
9

'
4
8
1
2

'
:
,
51
5
7
15
3
,
59
7
59
3
14
2
08
6
.
?
1
6

"
17
6

'
2
4
8

'
44
0
13
0
:
,
6
1;
5
0
5
75
4
81
5

,
1
,
43
9
1,5
8
3
.
.
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
Ne
I

(
1
0
0
0

h
i
)
Ja
n
u
l
l
'
)
'
Alb
e
r
\
.
!
Fe
b
r
l
l
a
r
y
Br
i
t
i
$
h

C
o
l
u
m
b
i
a
Ml
l
t
w
S,
l
s
\
:
a
t
c
h
e
w
a
n
Ap
r
i
l
Ma
n
l
t
Q
b
a
Mil
)
'
To
t
a
l
Ju
n
e
(m
i
l
l
i
o
n

5
)
Ju
l
y
Au
g
u
$
l
Al
b
e
r
t
a
Br
i
t
i
$
h

C
o
I
t
m
b
i
a
Se
p
t
e
m
~
SJ
s
\
:
a
!
l
;
h
e
w
a
n
Oc
t
o
b
e
r
Mll
l
l
i
t
o
b
a
No
v
e
m
b
e
r
To
t
a
l
De
c
e
m
l
w
(0
)
So
o
J
n
:
o
o
.
Po
I
m
I
O
I
I
I
1

So
o
I
a
'
.
O8
1
r
0
;
1

B
l
A
I
e
6
o
il
l
-
Testimony of Vulcan Power Company
Exhibit C
Platts Research and Consulting
Research Reports:
The Value of Renewables as a Physical Hedge
Against Natural Gas Price Movements
April 2003
The Cost of New Gas-Fired Generation
March 28, 2003
III - 37
Platts Research & Consulting (PR&C)
3333 Walnut Street
Boulder, CO 80301
April 2003
The Value of Renewables as a
Physical Hedge Against Natural Gas'
Price Movements
CONTENTS
. .
A. Executive Summary
B. Key Findings
C. Gas Price Forecast
D. Securing Reliable Gas at Fixed Price
E. Putting the Pieces Together
Brandon Owens (brandon owens~/atts.com)
Brandon has extensive experience developing and leading original research for both public and
private sector research organizations. An expert witness and invited speaker at renewable
energy events, he s produced numerous reports and technical articles on renewable energy
technologies, markets, and policies, Before joining Platts, Brandon served as senior energy
analyst at the National Renewable Energy Laboratory in Golden, Colorado, and in Washington
C. Brandon holds an M.S, degree in Mineral Economics from the Colorado School of Mines
and bachelor degrees in Mathematics and Economics from the University of Colorado,
The Value of Renewables as a Physical Hedge
Against Natural Gas Price Movements
Brandon Owens
A. Executive Summary
Renewable energy technologies, which do not require fossil fuelto generate electricity, promote power price stability by
avoiding the risks associated with underlying natural gas price
escalation, volatility, and delivery. In this report, we estimate
the hedge-value of renewables by quantifying the costs faced by
gas-fired generators in order to secure reliable natural gas
supplies at a fixed price. We derive this cost by calculating the
direct expenses that must be paid by gas-fired power plants to:
(1) guarantee gas delivery, (2) eliminate price volatility, and
(3) remove gas price escalation.
Using the total of these expenses as a proxy for the hedge value,
we conclude that under our baseline gas pri~e scenario, the total
cost associated with meeting gas deliverability requirements
through the use of gas storage, and the 'cost associated with
fixing future gas prices using options under our baseline gas
price forecast, is $5.20/MWh. However, this value assumes perfect
foresight with respect to future fuel use requirements and
therefore represents a lower bound. This value also depends
critically upon the timing of the introduction of non-traditional
gas supply sources to offset incremental demand growth and may
rise substantially if these sources are delayed.
In practice, the hedge-value is plant-specific and a function of
geography, regional market dynamics, and future expectations.
Ultimately, project-specific modeling and scenario analysis are
required to arrive at an analytically defensible figure of merit
for an individual plant. Further, we note that the hedge-value is
only one component of the total renewable energy value. In the
end, a comprehensive valuation approach that considers the full
risks and rewards of both renewables and conventional generation
options is the only way to determine the appropriate role for
renewable energy technologies
markets that lie ahead.
the fully competi ti ve power
B. Key Findings
Where available, underground storage, with rapid inj ection and
withdrawal capabilities, is often the best and least-cost
method to provide guaranteed gas delivery. Although the costof storage varies considerably and is based on underlying
storage field economics, using FERC Form 2 data , we estimate
that average costs are $0, 45/mmBtu range. For a new combined-
cycle gas-fired generator with a heat rate of 7 100 Btu/kWh,
this translates into an incremental cost of $3. 20/MWh.
Subj ect to the costs of margin accounts and the transaction
costs of entering into and then closing out futures contracts,
power generators can dramatically reduce their exposure to
natural gas price volatility at a low cost through the use of
natural gas futures contracts. However because futures
traders .do not. have the ability to lock in a specific gas
price, but rather must purchase gas for future delivery at
prevailing contract prices futures cannot be used to
eliminate the risks associated with gas price escalation.
Instead, gas price escalation must be addressed through the
use of options, which allow buyers to specify a specific price
for future gas delivery. However, the use of options does not
protect buyers from basis risk and may entail transaction
costs such as the bid-ask spread.
An options trading strategy called a "collar" can be used to
lock in a fixed price of gas, thus removing both volatility
and escalation simultaneously. This can be done by buying a
call" option and selling a "put" option with the same
strike " price for every delivery month in the fuel supply
term. The long-term cost of this strategy can be estimated
using a relationship known as the "put-call parity" and is a
function of future natural gas prices. Using our baseline gas
price forecast, in which prices are expected to average
$3.54/mmBtu (2003 dollars) through 2020, we estimate that the
- ----
cost of a collar strategy to hold fuel costs constant over the
life of a gas-fired plant is $2. OO/MWh.
. Non-traditional gas supply sources, such as Artic gas, coal
bed methane, and liquefied natural gas (LNG) play an important
role in determining the hedge-value of renewables. In our
baseline gas price forecast, we assume that these sources
enter the market in 2006. However , if this assumption is
relaxed by 2 years, we expect natural gas prices to increase
significantly relative to our baseline forecast. The 30-year
cost of enacting a collar strategy to hold gas prices constant
under this delayed-supply scenario doubles from $2/MWh to
$4/MWh. Further, if the introduction of non-traditional
sources is delayed by more than two years, the hedge-value of
renewables increases dramatically.
In practice, the hedge-value is plant-specific and a function of
geography, regional market dynamics, and future expectations.
Ultimately, project-specific modeling and scenario analysis are
required to arrive at an analytically defensible figure of merit
for an individual plant. Further , we note that the hedge-value is
only one component of the total renewable energy value
proposition. In the' end, a comprehensive valuation approach that
considers the full risks and rewards of both renewables and
conventional generation options is the only way to determine the
appropriate role for renewable energy technologies in the fully
competitive power markets that lie ahead.
C. Gas Price Forecast
Our gas price forecasts are generated using the Gas Pipeline
Competition Model (GPCM), which is a combination software-
database linear optimization system that includes detailed
representation of gas production, transportation, storage,
marketing, and distribution. GPCM is the latest in a series of
systems and models built by Dr. Robert E. Brooks from the mid-
1970s through the present. Platts Research & Consulting is the
exclusive distributor of GPCMdat, a GPCM-compliant quarterly data
service that is essential for the operation of GPCM.
In our baseline gas forecast, we proj ect U, S. natural gas demand
to grow at an annual average growth rate of 1.4 percent with real
prices averaging $3. 54/mmBtu (2003 dollars) through 2020. We
expect increasing gas demand to be driven by a robust electric
sector annual growth rate of 5.percent, Traditionally, the
industrial, residential, and commepcial sectors are roughly twice
the size of the electric generation sector. However, our outlook
for new gas-fired generation has the electric sector surpassing
industrial consumption by 2010 and end-use demand by 2012.
In our baseline forecast, we expect production from traditional
gas-producing regions expected to be flat or declining over the
forecast period with the following non-traditional supply sources
stepping in to offset demand growth:
We expect Rocky Mountain coal bed methane supply
deliverability to grow at nearly 3.percent annually
throughout the forecast period. This prediction is bolstered
by the recent, favorable environmental assessment released by
the Bureau of Land Management (BLM) promoting coal bed methane
development.
We assume Ghat McKenzie Delta Artic gas will enter the lower-
48 market in January 2010. North &lope Artic gas is assumed to
come online in January 2012.
We believe that liquefied natural gas (LNG) deliverability
will reach a number similar to that of present day Gulf of
Mexico offshore production by 2015. Our current outlook calls
for all existing LNG terminals to be operational and expanded,
and two additional proposals to be constructed, with the first
one operational in 2006.
However, gi ven the high degree of uncertainty related to both
timing and magnitude of supply, we also acknowledge that our
baseline assumptions with regard to the introduction of non-
traditional sources may be aggressive. To demonstrate the
importance of these assumptions, we constructed "limited supply"
and "pessimistic supply scenarios to complement our baseline
price forecast. In the limited supply scenario, we assume that
the introduction of non-traditional supply sources is delayed by
2 years; and, in the pessimistic supply forecast , we assume tnat
demand is met only through traditional
2020.
supply sources through
We expect gas prices to increase substantially in both of these
supply scenarios. In the limited supply case, real prices average
$4.16/mmBtu from 2003 to 2020, versus $3,54/mmBtu in the baseline
forecast, More importantly, gas prices climbs to $4.39 /mmBtu
the middle of the forecast before converging toward the baseline
price at the end of the forecast horizon. The price impact is
even more dramatic in the pessimistic supply forecast. Near-term
real prices quickly exceed to $4.50, and approach $5. 50/mmBtu by
the end of the forecast period.
We stress that the baseline forecast represents our expected
price path for natural gas prices; however, the limited and
pessimistic supply scenarios are enlightening because they
highlight the tight balance between natural gas demand and supply
moving forward.
D. Securing Reliable Gas Supplies at a Fixed Price
Meeting Deliverability Requirements Through Underground Storage
Large gas consumers, such as power generators, can mitigate the
costs associated with adverse gas price movements through
physical or financial hedging. As already mentioned, renewable
energy technologies represent one physical option for eliminating
fuel price risk. Financial hedging instruments such as natural
futures and options contracts represent another option. In order
to understand the hedge-value of renewables, we must examine thecosts associated eliminating gas price uncertainty using
financial instruments. However, the use of financial instruments
does not occur in a vacuum. Power generators must enact
strategies to procure, transport, and store gas supplies even in
the presence of a financial hedging strategy. Thus, to properly
estimate the hedge-value of renewables, we must examine the gas
supply strategies of power generators to determine if they entail
costs that are above the expected market price of gas. These
costs must be quantified and included in our estimate of the
hedge-value of renewables.
Supply, In a gas supply contract, buyers and sellers must agree
upon the volume of gas to be delivered, the type of service (firm
or interruptible), the length of the contract, and the contract
price. Contract terms vary widely depending upon the purchaser
overall supply strategy, Natural gas contract prices are
typically pegged to publicly available gas price indices,
Contract prices include an additional premium or discount to
account for the difference in gas prices between Henry Hub andthe delivery location, This "basis differential" premium or
discount varies over time systematically with seasonal
variations, or secularly with broader fundamentals, Two
publications, Platts' monthly Inside FERC and Gas Market Daily,
both published by The McGraw-Hill Company, are widely used for
pricing information in the natural gas industry.
The fact that supply contract prices are typically tied to cashor futures market indices is very important for our purposes
because this means that often the price that power companies pay
for gas will ultimately reflect the prevailing long-run spot
market price. Thus, the price paid by gas purchasers in supply
contracts is unlikely to be above and beyond the expected marketprice. Supply contract prices must therefore be excluded from
our estimate of the hedge-value of renewables.
Transportation. Because the basis differential is an inherent
amalgamation of firm and interruptible costs in primary and
secondary markets between two trading hubs, it can be used as a
proxy for the transportation costs associated with moving gas
supplies from Henry Hub to the plant. Again here, as with gas
supply contract prices, the basis differential does not represent
a premium to secure reliable gas, but rather the embedded market
costs associated with acquiring gas supplies. As such, basis
differential estimates do not mitigate fossil fuel price risk for
gas-fired generators,
Storage. Where available, underground storage, with rapid injection
and withdrawal capabilities, is often the best and least-cost
method to provide guaranteed gas delivery. Thus, procuring the
services of underground gas storage facilities is often the final
step the gas generators take to ensure that reliable gas supplies
are available to meet the demands of gas-fired generato~.
Indeed, variations in generation load requirements are frequently
addressed through the use of underground gas storage facilities,
which can be used to provide the high level of deliverability and
pressure required for the operation of new combined-cycle power
plants. The ability to store gas ensures reliability during
periods of heavy demand by supplementing pipeline capacity.
Storage also enables greater system efficiency by allowing more
level production and transmission flows. End-use customers gain
from this increased efficiency with reduced overall costs of
service.
The use of gas storage is particularly important for new gas-
fired power plants, which have higher pressure requirements and
place more demands on the gas transportation systems than older
gas-fired boilers, Underground storage located near the plant .
often the best and cheapest method of meeting surge requirements.
Storage can also be used to reduce the amount of firm pipeline
capacity required to provide natural gas service to some
generating units.
Storage . rates vary from facility to facility, depend heavily on
the usage profile, and are often based on negotiated contractsthat are not publicly available. However, in FERC Form 2,
pipelines file revenue and volume information by rate class for
storage services provided to others. According to FERC Form 2, in
2001 , 2.6 quads of gas were moved through storage with an average
revenue of $0. 45/mmBtu (Platts GASDat database). This agrees well
with published estimates of storage facility costs. For a new
combined-cycle gas-fired generator with a heat rate of 7,100
Btu/kWh, this translates into an incremental cost of $3. 20/MWh.
Unlike supply and transportation contract prices, the costs
associated with natural gas storage do indeed represent an above
market premium that generation asset owners must pay to guarantee
gas delivery. In practice, this cost is optional, and many gas-
fired generation assets owners do not use gas storage for all or
portion of their supplies. However, the goal here is
quantify the costs that must be borne by gas-fired generators to
guarantee gas delivery; and in the absence of prohibitively
expensive firm transportation contracts for peaking generation
needs, storage is the least -cost method of guaranteeing gas
delivery, Thus, we use $3. 20jMWh as a proxy for costs associated
with guaranteeing fuel delivery for a gas-fired plant.
Using Derivatives to Eliminate Price Volatility and Escalation
Futures, In order to lock in future gas prices, power companies
must turn to the financial markets and make use of natural gas
derivatives, " financial instruments derived from a cash market
commodity such as natural gas, Derivatives are important in the
context of determining the hedge-value of renewables because they
provide a means by which gas-fired generators can eliminate the
risks associated with unfavorable natural gas price movements,
which is one of the major components of the renewable energy
hedge-value.
Natural gas futures contracts are one form of derivatives they
were first offered by the New York Mercantile Exchange (NYMEX) on
April 3, 1990. A futures contract is a legally binding agreement
between a buyer and a seller, whereby the buyer is obligated to
take delivery and the seller is obligated to provide future
delivery of a fixed amount of natural gas at a pred~termined
price at a specified location. The quantity of ~atural gas
covered by futures contract, the delivery period, the
specifications and the location for delivery, and the timing and
method of payment are all standardized.
The cost of futures trading. The use of futures contracts requires
payment both on an initial margin, a minimum deposit per contract
required when a futures position is opened, and a maintenance
margin , a sum which must be maintained on deposit at all time.
The level of the maintenance margin is determined by the credit
rating of the trader and can be very high for companies with less
than superior credit ratings. In light of the U. S. energy sector
credit crisis, in which S&P downgraded 135 utility-holding
companies and their subsidiaries in 2002 alone, fewer and fewer
power companies have favorable credit ratings, This can represent
substantial barrier to the use of derivatives to hedge gas
price volatility.
Some analysts
purchas ing gas
cite an additional premium associated within advance with futures and other derivatives,
such as forwards and swaps, For example, Mark Bolinger et aI,
(2002) compare the price of a 10-year natural gas swap to a 10-
year natural gas price forecast developed by the U. S, Energy
Information Administration (EIA), which they assume reflects what
the market is expecting spot natural gas prices to be over the
next 10 years" 1 They find thd.t over the past ~wo years natural
gas users have had to pay a premium as high as $0" 76/mmBtu over
expected spot prices to lock in natural gas prices for the next10 years. Based on thi finding, they conc I ude tha t the
incremental cost to hedge gas price risk exposure is potentially
large enough to tip the scales away from new investments in
variable-price, natural gas-fired generation and in favor of
fixed-price investments in renewable energy.
However, at this stage, it is our position that the findings .
Bolinger et aI, must be viewed tentatively for two important
reasons. First, even if a positive differential presently exists
between financial derivative contract prices (as represented by
Enron swap prices in Bolinger et al.) and gas price forecasts (as
represented by EIA's gas price forecast in Bolinger et al.,) we
can neither conclude .that the premium will persist, nor can we
state authoritatively that this value represents ,the premium that
gas buyers must bear 'in order "to reduce gas ' price risk. Among
other explanations, the posi ti ve differential may simply reflect
the difficulties associated with forecasting gas prices that are
in line with market expectations. Indeed, one could argue that in
the 1990s, as gas prices declined, forecasters systematically
overestimated future gas prices , and that today as gas prices
increase forecasters are systematically underestimating future
gas prices (i. e . they are chasing a moving target). Second, the
basic premise of Bolinger at al. cannot be validated empirically;
instead, one must identify underlying theoretical support for the
assertion that the contract price for future gas delivery is
Mark Bolinger, Ryan Wiser, Devra Bachrach, and William Golove,
Quantifying the value that energy efficiency and renewable
energy provide as a hedge against volatile natural gas prices,
Report LBNL-50272 (May, 2002), Lawrence Berkeley National
Laboratory (LBNL), 1 Cyclotron Road, MS 90-4000, Berkeley, CA
94720,
different than "market expectations," which is an aggregation of
producer and consumer sentiment, Thus far , theoretical evidence
(which has centered upon the use of the Capital Asset Pricing
Model (CAPM) to detect systematic risk in gas prices that would
explain the existence of a premium) has been inconclusive.
In the absence of conclusive theoretical evidence,we. believe
that it is prudent to adopt the most conservative posture and
assume that there is no premium associated with the purchase of
natural gas futures contracts. Thus, at the present time, we
conduct that large gas users can dramatically reduce their
exposure to natural gas price volatility at little cost, subjectto the costs of margin accounts and the transaction costs of
entering into and then closing out futures contracts. We willrevisit this conclusion as additional information becomes
available.
The limits of futures trading. It is important to note that while futures
contracts provide traders with the ability to lock in a gas
price , they do not lock in a specific price. Rather, market
participants must pay the prevailing futures contract price.
Further, because futures contracts are less liquid beyond
months gas consumers are unlikely to . lock in the prevailing price
beyond one year. To understand why this is important, consider a
gas-fired combined cycle plant that was built on the assumption
that cash market gas prices would average $4. OO/mmBtu for a
period long enough to enable full debt repayment and adequate
returns to equity investors. One year after plant completion-and
every year thereafter-purchasing additional futures contracts
doesn help minimize the risks gas price escalation. Market
price expectations have already risen, and the plant owner now
faces the prospect of paying a higher price for natural gas than
initially anticipated. This is why even though futures contracts
likely provide a low-cost hedge against volatility, but are not
useful in addressing natural gas price escalation. For this, we
must turn to options,
Options. second type of natural gas derivative traded on the
NYMEX are options, which work like an insurance policy. The buyer
of a natural gas option pays a premium to acquire the right, but
not the obligation , to buy gas at a specified "strike " price. If
the price of gas exceeds the market price on the delivery date,
then the option buyer pays the strike price and takes delivery of
the gas. On the other hand, if the price of gas is lower than the
~arket price, then the buyer lets the op~ion expire and purchases
gas on the spot market. The option buyer of the contract receives
the right, but not the obligation, to take delivery, and the
seller is obligated to provide future delivery of a fixed amount
of natural gas at a predetermined price at a specified location.
There are two types of options: "puts" and "calls." A call givesthe holder of the contract the right to buy the underlying
futures contract at a predetermined price and g1 ves the seller
the obligation to sell the underlying futures contract at the
same price if called upon to do so. A put option gives the holderthe right to sell the underlying futures contract at a
predetermined price, and gives the seller the obligation to buy
the underlying futures contract at the same price if called upon
to do so,
The cost of lC?cking Qas prices using options. Unlike natural gas f~tures,
which only lock in expected spot prices, options can provide
protection from both gas price volatility and gas price
escalation. The risk manager for a gas-fired generator can
purchase gas for future delivery at any specific price by
purchasing a call option. With a call option the buyer is
protected from upward gas price movements but can still profit
from downward price movements.
Remember, however , that in order to quantify the renewable energy
hedge-value, we must estimate the expenses required to mimic the
fuel risk profile of renewables. Renewables, once installed, do
not provide such options to profit from downward fuel price
movements. If we only include costs associated with purchasing
call options then we would be overestimating the value of
renewables as a hedge against gas price increases. Fortunately,
we can combine two options contracts into what is called a
collar" to duplicate the fuel certainty profile provided by
renewable energy technologies. To create a collar, traders
purchase a call option and sell a put option simultaneously.
Collars allow the reduction or elimination of the options premium
by trading off participation in a favorable price move beyond a
certain level.
Like the futures market, liquidity in the natural gas options
market declines substantially beyond ,one year. On the surface
then using market-based data, ii appears that we cannot
calculate the cost of a collar strategy for the life of a gas-
fired power plant. Fortunately, for our purposes the net cost of
purchasing a call and selling a put with the same strike price
and delivery date is defined by the following theoretical
relationship, known as the Uput-call parity
-rt
p=
where c is the call option premium , p is the put option premium,
and is the spot market price of natural gas at the time of
purchase, X is the strike price that is locked in, r is the risk-
free discount rate (usually represented by the interest rate of
90-day U.S. Treasury bills), and t is the time to maturity. This
relationship states that the difference between a call and a put
option with the same strike price and exercise date is equal to
the expected spot market price less the strike price di~counted
by the time value of money for a risk-free investment. The put-
call parity is a theoretical relationship driven by the presence
of arbitrageurs in the market, however, in well-formed markets,it describes actual pricing of options very well. We can,
therefore, use the put-call parity to estimate the long-term cost
of enacting a collar strategy to fix gas prices.
E. Putting the Pieces Together
In this report, we delineated the direct costs faced by owners of
gas-fired assets in order to secure reliable gas supplies as a
fixed price. We conclude that the expenses related to underground
gas storage and the net costs associated with purchasing options
that lock in future gas prices are the only true costs that
should be included as expenses. We not turn to the valuation ofthe impact of these expenses on the annualized cost-of-
electricity for a state-of-the-art combined-cycle gas-fired power
plant,
ve already estimated the costs of mitigating deliverability
risk through the use of underground storage to be $3, 20/MWh based
on a 7,100 Btu/kWh heat rate. Now , by combining the put-call
parity relationship with our baseline gas price forecasts, we can
compute the net costs of using financial derivatives to lock
. future gas. prices. To estimate the options cost, we ass~me that
. the generation owner employs a strategy whereby options are
purchased annually in l-year blocks to lock gas prices at
$4. OO/mmBtu. We use $4, OO/mmBtu, because this is our forecast the
approximate starting price of gas when the plant is assumed to
begin in 2005, We assume a 5 percent risk-free rate throughout
the plant life,
Using this methodology, we find that under our baseline gas price
scenario the annualized cost of electricity for a state-of-the-art combined-cycle gas-fired generator increases by $2. OO/MWh
when the costs of purchasing financial options to remove price
volatility and lock in gas prices are included. Thus, the directcost associated with procuring reliable gas supplies while
protecting against gas price escalation is approximately
$5.20/MWh. However , if we assume that non-traditional gas supply
sources are delayed by 2 year~ and use our limited supply
forecast in place of our baseline gas price forecast, then gas
prices increase and the cost of purchasing options to protect
against gas price escalation rises to $4/MWh, and the total cost
associated with procuring reliable gas supplies while protecting
against gas price escalation rises to $7. 20/MWh.
It is important to remark that these values are likely to
underestimate the costs associated with procuring gas supplies
while protecting against gas price escalation. In practice,
plant owners will be unable to accurately predict future fuel use
requirements. This means that they may purchase either too many
or too few options. If too many options are purchased, they will
either go unused and the options costs will be wasted, or they
will be sold at the prevailing subj ecting the hold to option
price risk. If too few options are purchased, additional gas
supplies will have to be acquired in the cash market, subjecting
the plant owner to uncertain gas market prices. These costs are
not quantified in this analysis.
Te
s
t
i
m
o
n
y

o
f

V
u
l
c
a
n

P
o
w
e
r

C
o
m
p
a
n
y
Sa
j
,
J~
/
~
,
P,
.
M~
r
-
~
e
f
'
tf
c
,
~j
W
b
f
k
~
;
Ho
'
"
:
)
;~
~
~
J
h
;
~
~
j
;
ti
~
v
l
~
;
i8
N
:
"

"
l~
i
~
1
r
~
~
I
1
(
J
;R
b

om
E
j
5
'
a
5
t
v
~

d
R
i
e
s
s
?;
"

ve
l
'
l
u
e
r
s
a

n

'
#
r
a

n
c
i
S
C

0
"
"
f!
!
r
t
!
!
p
a
r
e
d
~
;
Y
:
3
f'
i
i
t
~
i
~
i
~
~
~
:
~
:S
b
l
i
l
d
e
r
,
Cd
8
n
a
O
,
1
:"
;
;
,
,,:
:
,
,;
,
,:
,
:,i
:
:
,
-~
,
i"

",;
'
"
::'
.'.
,
,
-
Ph
f
a
r
e
d
F

,.
.
::
"
"
"
,
V
t
J
l
p
a

h

F
c
:
J
w
e
r

Co
m

p

a

n
y
-t
A
1
3
3
N
V
y
V
V
$
I
I
S
t
r
e
e
t

i
s
u

it
e
G
EI
~
6
d
OR
9
7
,

f
(
)

:1
,
II
I

-

3
8
G)
,DJ
'
::
J
Rf
"
"'
"
:.
.
.
1
:
0
~j
?
~
J:
"C)
~
'
.-
:
.
:
r
.
.
.
.
.
,
:~
,
Q
;
;
' "

rr
.
P
,
:
J
;;
:
:
:
-
'
'~
.
.~
'
Te
s
t
i
m
o
n
y

o
f

V
u
l
c
a
n

P
o
w
e
r

C
o
m
p
a
n
y
$9
,
$;
)
:t
.
a
:~
~
,
~E
~
C
'
I
$
s
Ue
S
!~
r
$
;
;
.
I
;
$g

-
:;'-$
2
"
-:
$
1
,
,

..

.
D:
a
t
E
(
:
..
~
:
"

,
'
,
::
:
~
~,

K"

""
,
~j
.
J
U
t
~
~
;
;
~
(
3
A
$
d
~
r
,
(1
1
P
8
)
'
'
.
,
' ,
/:

"
",

'
,/,
.
.

,
:'"

"
,
i
l
l
-
T~
s
t
i
m
o
n
y

,
of

V
u
l
c
a
n

P
o
w
e
r

C
o
m
p
a
n
y
fi
~
l
j
~
t
'
1
=
~
~
i
~
~
~
i
:
r
!
\
t
9
J
i
J
U

i~
~
l
.
~r

~~
"
.
~J
~
~

.
~;
i
f
1
~
r
e
a
$
e
de
'
tr
f
a
.
nd
$
J
v
i
l
l
'
en
'
$tr

re

at
.
t~
a
~
t
;
;$
C
i

p
j
J
~
y
~
d
e
t
n
a
n
:
a
.
Ci3
J

ah
d
e
'
~.

be
t
w
g
e
n
e
h
a
~
'
t.I
s
e
s

\t
i
i
l
l

l
i
h
1
i
t
,
de
l
1
1
a
h
d
-
s
i
d
e
f
l
e
xi
b

i
l

i
t
y
.
~~
?
~
~
81
1
t
.
T.
~
l
~
f
j
n
,
g.
l
g
.
'
q~
,
j
r
o
P
J
9
.
v
~
J
l
1
-
.l
1
l
S
j
;
"
wh
i
p
h
.
a
J
J
q
w
p
r
(
)
d
y
.
qt
a
r
~
,
tQ
_
..
.
.
ra
i

n
~1
1
'
~
1
L
:
1
'
I
~
A
I
'
~
I
~
'
i
~
f
i
~
~
t
B
~
~
~
I
~
~
~

-
~W
i

~
g
?

i"
;
,
;~
;
,
.
(
'
;'C
i
/
"
~
"
"
:
,
bu
r
c
e
:
P
J
a
t
t
s
:
H
;
e
s
e
.
a

r
c
l
f
,
&
C

o
n
s
u
l
t
i
n

9
II
I

-

4
0
::
J
..
.
.
,
1:
0
"~
"
(I
)
i:
:
,
a
.
;
(!
)
1i
j
:/
C
)
(J
)
$2
0
'
$1
5
$1
(
1
,$
S
,
Te
s
t
i
m
o
n
y

o
f

V
u
l
c
a
n

P
o
w
e
r

C
o
m
p
a
n
y
N~
W
L
.
N
P
U
t
r
m

i
n
(
1
L
~
a
p
a
c
i
t
y
Ha
t
k
b
'
~
t
r
Y
!
1-
A
,
(7
6
0

M
M
c
f
d
)
El
a
j
a
L
Q
J
\
(
1
(
2
Q
U
f
\
r
1
M
c
f
q
)

,
(r
r
a
B
d
'
'
h

am

~

~
.
:
(

8
.
3
2
'

.
M
M
c

f
a
)
.
Gl
J
l
f
(
3
l
t
f
~
,
hQ
t
B

i
I-
A
(2

;
U
O
P
'
M.
.
M

C
f
d
)
0"

Al
"
t
l
c
:
e
x
n
'
an

sio

Mc
'
K~
n
i
r
e
'
b
e
r
t
~
(
,
.8

C
f
d
)
T:
c
J
?
L
A
f
~
'
~H
a
\
(
t
,
bB
C
f
d
)

"
,
$4
:
8
8
i
m
r
r
i
B
t
u
,
A
v
e
r
a
g
e
1$
6
,
."

'
'
,
',

'
"
'
"
in
~
fe
M
ta
r
t
t
~
.
ri
.
.
t
r
a
,
(
f
l
~
l
o
n
al
~
S
'
pl
y
A
d
(
t
i
t
io
h
s
"
'
1~
;
~.
'
~1
1
:
~
~
'
1:
;
m
'
.
"
1
~
1
~
~

"
l~
~
"
1~
?
" "
~~

17
~
~
'
1~
1
~
:
'
~~
~
~
"
'1
~
r
y
:
~
:
'
1~
1
~
17
1
~
"
:1
:
1
~

:1
~
'
~
"
19
f
r
1
~
1
~
'
l~
1
1
3
.
1~
2
0
;~
9
,
~r
~
~
:
e!
~
~
,
~;
,
fl
~
'
~~
f
r
~
,
~8
P
~
~
H
J
1
'
p
g

"
~
~
t
!
;
:
,
:
rN
Q
t
~
s
;
:
;
;
M
b

d
l
f
i
e
'
d;
b
~
$
el
i

r
l
~
f
&
r
e
~
~
$
t
/
~
i
g
$
Q
m
'
a$
'
i
t
i
c
f
:
m
a
j
o
Y
:
p
l
p
~
l
i
o
~
;
i

h
t
e
r
t
1
J
p
t
l
o
h
s

,
an
d

'
fr
o

r
r
o

~
1
(
h
V
d
t
o

'
cC
t
n

d
i
t
i

b

F
r
s
,
,/
:
"
."
"
,
"
"
":"
"
"
"
"..
""
"
.
.
,,
'
"
""
'
~~
"
"
"
""
"
...
o,;
,
.
.
.
.
:"
"
,
;
.
'
"
,
..
"
":
"
x
.
.
.
.
'
/:
,
"
""
"
,"
"
""
'
II
I

-

4
1
..
.
.
,
'.
.
.
.
.
.
.
.

'
;:
:
..
.
.
.
(J
'
J
Te
s
t
i
m
o
n
y

o
f

V
u
l
c
a
n

P
o
w
e
r

C
o
m
p
a
n
y
lf
i
~
t
:

gT
l
!
j
:

9:
/!&
~
~
j
~
~
t
~
G
:
;
?

$Z
r
J
--
-
-
-
-
-
-
-
.
.
-
-
-
-
-
-
.
-
,
.
.
.
.
.
.
-
-
-
-
-
,
.
.
.
-
-
-
.
.
.
.
"
,
.
.
.
.
"
.
"
'
.
.
.
.
.
.
.
"
.
"
"
...
.
.
.
'
"

,
'
"
,
'
.
.
'$
1
$
:
,
','
,
' "

"
"
"
"
"
"
.
"
"
.
,

"
"
,
' "
"
"
"
,
--
-
-
_
.
_
-
~
_
.
""
"
"

"'"
-~
"
-
,
,
-
,
-_
.
.
.
_
_
.
.
.
.
.
.
.
.
,
..,
,
.
M
~
.
.
_
.
.
.
.

,

-
,
.
w
.
'
..
.
.
.
.
'
,.
.
.
.
.
.
.
",
.
.
.
.
.
.
.
.
,
..
.

,
.

.
.
,.
.
..
-
-
-
.
.
.
.
.
..
.

.
.
.
.
.
"
""
"
"
"
"
"
"
"
..
.
.
.
.
.
.
.
_
_
.
.
~
.
.
-
-
_
.
.
,
.
,
.
.
.
.
_
.
.
.
.
..
.
.
.
.
.
.
.
.
.
,
.
.
.
.
.
"
"
"
.
"
$~
Q
'
$6
.

2
8
/
m
m
B
t
u
Av
e
r
a
g
e
..
.
.
.
.
'
..
,
'
...
.
.
~~
g
~
.
:j
~
~
1
'
,
;
1
;
~
'
/1
f
~
;
:
"
1~
?
1
~
~
;
1
;
6
~
r
1
+
0
?

1J
p
$
"
1
~
~
'

1~
~
~
n
'
ll
1
:)
1
~
1
~
1
~
'~

1
~
1
J
'
~~
1
S

,
t~
W

1.
.
'f
1
1
-
~1
-
t9

"
D:
i
j
.
t
'
E
:
t
:
~
P

u
f
q
~
:
"
'
PI
.

~t
t
$
'
H
e
s
~

f
f
i
r
C
J
1
~
,
&/
q
q
h
$
t
J
l
t
i

l
i
t

"
,
..,
,
"
'
"
0
""
"
"

.
.
.
,
",

"
II
I

-

Te
s
t
i
m
o
n
y

o
f

V
u
l
c
a
n

P
o
w
e
r

C
o
m
p
a
n
y
I~
Q
f
)
~
O
l
Q
QY
;
;
'
~a
~
.
F
j
r
e
d

Cp
m
b
i
n

e

d
.
.
cl

e
on
~
L
i
o
e
'
YJ
!
ar

;
20
0
5
a~
(
(
~
I
?
~

50
0

M
W
Pl
a
:
n
t
,
l~
;
i
f
e

'
30
"
Ye
a
r
s
e:
~
g
~
iJ
.
p
J
f
S
!
;
!
a~
~
g
t
~
r
(
~
t
~
~
'
l
;

.
,

7.
7
.
5
O
k
~;
~
p
;
i
l
~
I
'
~g
;
~
~
J
1
I
(
$
1
~
.
I)
W
'

$5
,
5
0
1
k
\
N
e.
a
t
.
Ra
t
e
~
0
((
B
f
l
J
7
k
:
V
i
h
)

7
'
0
,
Bt
a
/
k
W
h
'
P:
J
~
g
,
1~
'
~M
:
;
:
;
':
$
~
R
W
:
l~
:
.
$
,
;1
:
:
5/
k
W
'
Va
f
i
a
f
j
'
le
;
'.
(
G
J
J
&
r
v
1
'
f
;
~1
N
I
W
I
1
1
~

$
g
t
:
r
v
n
l
\
l
h

Ai
r
~
G
o
i
1
l
r
n
g
;
ip
!
et
f
o
r
f
m
a
n
;
ce
'
Up
/
ft
a
l
f
'
;(
.
9
A
i
'
of
;
QU
t
;
uf
)
*
*
"

,
.'
'
Iw
~
i
i
~
i
i

i
'
il
i
t
i
!
i
i
~
i
i
~
~
~
i
t
;
1i
~
i
~
~
l
~
~

~
t
;
~

'
,

,
;!
;

%
J~
~
~
'
ep
n
:
~
'
g:
,
G)
~
~
M
g
'
~~
t
;
~I
$
1
.
~
I
)
~
"

,
,
:$
.
y/
'
~D
o
e
s
\
h
t
i
t
;
i
n
c
l

ud
i
f
t
h
e
:
t
o
S
t
s

(J
f
:
:
e
ri
t
i
$
s
i
o
n
s
'
o
f
f
s
e
t
$

'
:J
t
J
~
,
~~
f
l
l
l
~
.
:~
~
~
r
y
~:
l
r
S
I
O
f
1
'

"
' '
,;'
"

'
o',
rn

-

4
3
E)
,
.e
b
t
l
E
:
q
.
.
U
:
i
l
y
r
Ra
.
t
'
:I
;
b
:
""
J
'
R
,
"
.~
,
~I
:
"
;"

'
"
"
Ji
l
r
,
~i
r
~
,
.~

\
;
Yr
J
'
"
, ,
.u
e
,
' "
Ja
r
m

\
,
'
:
ea
r
:
,
:
P
e
,
",

l
'
l
t
e
r
e
:
s
J
;
Ra
t
,
.~
:
CY
o
l
y
.
,
rJ
.
Jt
f
:
t
;
I!
I
:
;
~.
O
O
"
Jl
:
~.
~
'
:'

" "
Ef
f
~
Q
'
t
l
~
,
~;
I
.O
i
:
c;
'
g:
r
n
,
.e
.
,
, ,
1"
:
:
C
1
.
~
,
Ra
t
~
~
;
;
,
(;
o
/
f
i
l
y
r
)
:
'
, "
.:,
,
,

Y'

':
'
;

"
"C
'
"
'
;,

'
t"

,
'
,
:
"
"
,
:/"
"
:
,
,
.
'
,
'
:
:;

,
;:
"

,
,
,

:
:
,
:
;
x
~
,
e,

"
,
n"

a
l
e
,
"
,
e,

,
;
,
0
,
y
r
:,
,
'"

;
"
:"
'
"
"
,
"
rn
.

r
n
~
,
..

,
sc
a
B

Io
n

"
"
BL
e
,
Sf
i
u
r
c
e
:
P:
I
~
t
l
s
R
~

s
e
a

rc
'
t
f
~
&
"

Go
n
s
u
l
t
i
h

g
il
l
-
,
.
.
,
"

,
,
,
.
Te
s
t
i
m
~
n
y

o
f

V
u
l
c
a
n

P
o
w
e
r

C
o
m
p
a
n
y
60
:
:
4
0
"
15
0
/
0
:q
"
Y~
a
r
s
,
7.

I
J

00
1
0

40
.
j,
:
5
.
0
k
'1
:
-
0
0
1
,
~
:f
'
?
?
O
,.
.
.
.
.
.
;.
c
'
: "
,:
2
c'
-
.-

w
'.:
~)
:
~:
:
~Q
:
$4
0
$~
d
$?
g
~
~
,
~p

U
r
q
~
;

:

PJ
~
t
t
g
J
~
a
s
~
~

Y
t
D?
&
.
E
P
Q
t
1
s

ul
t

i
h
g
,
,
",

,

:
"

'
""
,
'"

'
"
,
;
,
"~
.
'
~
, ,
. ,
.
'
"
J.
.
.
:
,

',
,
:
,
:':
"
"
"
~;
2
0
,
$1
Q
!N
~
'
:~
'
..

,
$$
8
;
3
.
..
.
;
.

It
t
'!
.
i
~
II
I

-

Te
s
t
i
m
o
n
y

o
f

V
u
l
c
a
n

P
o
w
e
r

C
o
m
p
a
n
y
64
~
9
.
,
.
.
.
.
.
.
.
;A
~
i
i
$
i
d
e
"
ie

'
"
"
"
YU
l
~

"
'
"

"
am
a
t
e
SS
:
2
B
l
r
n
f
r
f
B
t
u

. ,
A"
t
g
'
pa
s
:
2
0
.
()
~
;
'
:
2
0
2
0
..

Te
s
t
i
m
o
n
y

o
f

V
u
l
c
a
n

P
o
w
e
r

C
o
m
p
a
n
y
p:
.

t
g
:
~
g
-
g:
,
:
r
~

'
rt
9
2
'
eJ
i
W
9

t'
~
.
,
;
g
:
,
M
~
"
~\
'

1
0
:

tb

:~
,

gJ

I
p
W
i
'

11
;

g'

m

~1
1
"

1
1

er
:
,
"
"
;
o
:,
'

'

'

;
.
l~
"
~!
:
g
9
::
~
~
k
p
j
y
'
,
cq
q
t
~
~
F
t
'
~l
1
y
e
Y
~
~n
~
'
"
"
,
, ,
te
l
er
s
,r
t
J
:
~
s
t
:
a

g
~
,
Wp
'
,
ht
l
;
i
e
:
vd
f
u

t
t
i
~
;
"
of
:
'
g$
s
tt
J
,
b
e
d
e
i
I
Y
~
f
e

~
~
'
ih
~
j
y
p
e
d
f
~

e

Ni

c~
-
:
(
f
r
r
r
r
i
b

r
~~
~
I
f
~
~
~
~
~
~
~
m
~
~
)
)
e

W
~
~
~
~
f
f
~
l
~
~
~
a
w
wi
c
r
e
l
y
)
:~
$

pe
n

c
u
h
g
:
l.
J
p
O
b
'
tt
j

e
p
(
j
r
c
b
a
~
e
r
,
,
' "
'
'
,,
'
:,'

"
"
"
'
,

'
' ,
,
"
,
,
"
ov
e
r
a
;s
u
' 1
"
"
1
\I
s
r

,'
"
:
"

.."
,
o
","
"'J
,
,.
.

"
I':
!
.
,
.)
'
,
,,
.
.)
'
.
,
(j
t
n
r
t
r
e
s
'
l.
J

S

ua
n
y
t
f
~
h

sf
e
r
t
h
e
h
s
k

o
f

ga
s
~i
~
i
~
e
:
;
U6
~
~
f
~
a
!
:
t
J
f
Y
J
.
~
g
.
~(
J
g

~
9
,

fn
e
,
r
s
q
s
!

n
g
,

g
a
s
~d
J
q
~
t
f
r
"
i
e
h
t
.
c
f
a
~

~
,
~s
(
G
A
G
'
S)

,
ah
d
:
p'
b
~
e

r
qJ
l
j
s
f
t
T
f
e
h
b
c
l
~
L
i
$
e
S
(
P
A
B
S
1
,
"
"
GA
,
p$
a
n
d
p
f
i
.
p
s
'
pr
o
v
i
d
e
a

m
e
a
n
S
'
t
o
~g
J
9
$
t
:
40
q
t
~
;
;
~P
J
X
e
t
r
)
(9
t
e
J
:
g
~
,
~e
S
"
9n
q
,

t
f
l
'
P.
t
Q
~
i
:
~
~
$

\
"
~h
(
)
-
q
~
"
9b
s
o
r
b
~
r
tt
1
9
t
$
r
n

p
a
t
h
s

"
,
"
.'
t
h
~
f
p
j
:
~
~
k
s
:
~
h
q
f

y
a
i
1
e
Y
5
(
6
f
:v
o
l
a
h
l
~

'
t1
a
t
u
r
a
l
,,
'

,
."

'
"
-
'
"
,

,
"
"
,
"
,

"
,
'
,
,
,
"
"
~f
?
$
'
::
~
'
dd
.
'
Wh
q

f
g
:
~
'
~I
.
~
"
..
P

o
w
~
ma
'
rk
e
t
s
be
f
o
r
e
~~
~
s
~~
~
~
/
~
r
~
'
li
a
'
ss
e

d
~
:O
n
'
tD
e
'
l
e
'
Gt
r
i
,
c

,
(:
3
-n
t
t
a
rl
b
e
:#
T
it
a
"I
I
"

;
.,
:
,
t
o
:
..

,~
,

"
)(
R
f
J
9
"
~i
~
~
i
JI
~
~
I
:
\
i
I
B
!
~
f
!
i
~
~
~
t
~
pr
e
v
a
l
l
l

h
m
:
$

P
'
Q
t
~
,

ma
'
(
J
~

e
:
~

:
p

t
i

b

'
e
~
'
"
1/
(
,
,\
;
,
"
;i
-
\
,
bu
r
c
e
:
:
P
'
!
'
~t
l
s
'
:
:
R
~

s
e
,
ar
c
'
b.
;
c
e
n
s

u
l
t
r
n
g
.
'
II
I

-

4
6
.
,
.
'
.
'
re
~
t
i
m
o
n
y

o
f

V
u
l
c
a
n

P
o
w
e
r

C
o
m
p
a
n
y
.
,

'

,
~
.

'
-I
f
)
R
'
e
t
J
,
~~
~
I
~
S
~
i
B
~
f
i
j
p
~
;
;
,
~~
g
r
f

~t
i
~
g

,
$t
a
~
i
n
i
f
'

~
9
f
.
a
!
/
Q

i
a

II
)

~\
t
f
l
~
:

d
$
~
$
,
"
,
i
.
,
~~
:
(
:
)
J
~
i
~
t
e
~
"
;w
j
t
b
:
I
.
J
I
'
1
:
(
r
e
r
l
~
i
-
'
f
1
9

r
t
~
t
'
yr
a
t
~
g~
s

p
r
i
q~
;
;
:
:
e
s
c
a
l
~
t
i
(
)
n
.
,
'\
l
P
:
I
~
t
i
li
t
y
,
~n
d
;
a
~
l
i
V
~
.
ry
~
'
"
'
"
"
'
.
.

,
.
.
,
'
~,

I
n
~
t
'
P
~
c
e
n
f
:r
e
~
6
r
t
w;
e
~
:
e
$
t
l
m
a
f
e
d
,
:t
b
e

h

e
d
g
'
e;
v
a
l
.
Ue
b
y
b
y
.

ca
l
C
L
i
l
a
.
t
i

n
g
-r;
"

i
t
~
~
~r
t
~
~
~
'
'
~~
~
r
~
~
~
~
;

~
~
!
(
:
~g
'
~l
f
~
~
~
~
~
i

~
'
~~
~
~
~
f
~
;
~
d

e
~
W
~

?p
l
~

n
t

$

to
:
~r
~
i
~
\
i
~
1
i
t
I
"
~~
1
1
~
~
?
1
:
.
~!

i

i
j
t

ii
j
~
t
~

,
rI
~
~

91

~
t
i
l
j
t
y
,

~
r
t
(;
3

)
,
.
..
)

'1
A
J
~
~
C
Q
n
~
J
!
i
.
~
e
(
f
i
t
h
~
j
f
i
e

\
f
Q
t
a
J
E
~
Q
s
t
'
a
~
~
9

ci

aU
i
d
Y
f
i
t
h
m
e
e

t
i
~
~
:
g
a
s

.~
.
.
nv
~
.

r
,
,
:
~i
J

i
!
r
:
:
~q
p
~
;
~m
,
.
nt
.
$/
:
!
~
,
rq
~
.
g
"
'
.
:
:
'
lh
~
.
Y$
~
;

~
!
g
l
J
~
,
~t
~
.

r
,
-
~
,
~
.
an
~
.
,
..
:
t

h
e
~l
l
i
~
"
"
1
d
l
l
r
~
t
~
'
_
W
'
I
W
~
~

,'
~
~
.

p
f
l

C
"
~
~
,
~~
r
4

9
r
i
~
t
L
i

f~
l
l
~
s
'
,
'
'
:
,
,
:

"
"
:
:
,
,
:/
'
,:
:
:
.
:
:
S'
(
m
r
c
e
:
PJ
a
t
l
s
:
Re

s
e
a

r
c
J
)
:
&
-

G

o
n
s

u
l
t
H
i

g
.
"
il
l
-
.
,