HomeMy WebLinkAboutAPA570IS
HD
9685
U6
R35
v.7
- »r»
Vl
"w »
O~~~
lJl Vlo0g_C
;0o()
_---IT'
lJl Vl
$rw...
OJ
;0
~
-<
ALASKA RE~OURCES J~~~ARY
U.S.DEPT.OF
Railbelt Electric Power
Alternatives Study:
Fossil Fuel Availability
and Price Forecasts
Volume VII
March 1982
Prepared for the Office of the Governor
State of Alaska
Division of Policy Development and Planning
and the Governor's Policy Review Committee
under Contrad 2311204417
Ba1teIIe
Pacific Northwest Laboratories
LEGAl OncE
This report was prepared by Battelle as an account of sponsored
research adivities.Neither Sponsor nor Battelle nor any person ading
on behalf of either:
MAKES ANY WARRANTY OR REPRESENTATION,EXPRESS OR
IMPLIED,with resped to the accuracy,completeness,or usefulness of
the information contained in this report,or that the use of any informa-
tion,apparatus,process,or composition disclosed in this report may not
infringe privately owned rights;or
Assumes any liabilities with resped to the use of,or for damages result-
ing from the use of,any information,apparatus,process,or composition
disclosed in this report.
t
Jc,!'l'np'~
ALASKA vpc;ounCES LIB~ARY
U.S.I)t~-~-l'r~(jli'Il~'rEIlIOR
!i\
;~:
I
Ir
-,
RAILBELT ELECTRIC POWER ALTERNATIVES STUDY:
FOSSIL FUEL AVAILABILITY AND PRICE
FORECASTS
Vo 1ume VII
T.J.Secrest
W.H.Swift
March 1982
For the Office of the Governor,
State of Alaska,
Division of Policy Development and
Planning,and the Governor's
Policy Review Committee
under Contract 2311204417
Battelle
Pacific Northwest Laboratories
Richland,Washington 99352
"t
.,
j
PROUX;UE
The State of Alaska commissioned Battelle to investigate potential
strategies for future electric power development in Alaska's Railbelt region.
The results of the study will be used by the Office of the Governor to
formulate recommendations for electric power development in the Railbelt.
The primary objective of the study is to develop and analyze several
alternative long-range plans for electric energy development in the Railbelt
region (see Volume I).Each plan is based on a general energy development
strategy representing one or more policies that Alaska may wish to pursue.
The analyses of the plans will produce forecasts of electric energy demand,
scheaules for aeveloping generation and conservation alternatives,estimates
of the cost of power,and discussions of the environmental and socioeconomic
characteristics for each plan.
This report (Volume VII of a series of seventeen reports listed below)
addresses the availability and price of fossil fuels over the forecast period
1980-2010 for the Railbelt region.Each of the chapters corresponds to
individual working papers for the respective fuels.The first of these was
completed in February of 1981 and the last was completed in November of 1981.
The costs and fuel prices in the working papers were adjusted to beginning of
year 1982 dollars for this final report using the GNP implicit price
deflator.
At the time the fuel price forecasts were assembled (1981 calendar year),
they reflected the main body of expert opinion concerning future world
petroleum prices,providing for real price escalation in the range of 1%to 3%
per year over the long term.Since that time,the market conditions for oil
have changed and there is no longer a strong consensus on the behavior of
future oil prices,although the predominant belief is for a lower level of
price escalation than existed even a year ago.Industry sources are now
forecasting annual real price increases for the 1980s ranging from minus 3.3%
to plus 2.8%,with low probability political crises possibly resulting iQ
higher rates of increase (Oil and Gas Journal 1982a).Two recent forecasts
(Standard Oil of California June 1982,Data Resources,Inc.Summer 1982)
predict a long-term real annual rate of increase in the range of 0%to 2%to
iii
Vol ume I
the end of the century.Although Alaska Department of Revenue's oil price
forecasts are clearly lower than a year ago,they also have been subject to
considerable uncertainty.The Department1s long-term annual real escalation
rates fell from about 2%in June of 1981 to negative 1%in March of 1982,but
then rose to negative .2%by June of 1982.The price forecasts for the other
fuel types were constructed with the recognition of the institutional as well
as market factors that would likely affect their behavior.
A number of events have taken place that may affect the availability and
prices of other fuels.The PacAlaska project has commitments for about two-
thirds of needed gas supplies (Oil and Gas Journal,1982b).The project
sponsors are optimistic about receiving a favorable ruling in late 1982 on the
LNG terminal to the located in California but expect an additional two-year
delay over environmental issues.The reported 1.6 Tcf of gas needed for this
project will have an impact upon the market for natural gas in the Cook Inlet
region.The ANGTS pipeline has been delayed until at least 1989,thus limiting
the availability of North Slope gas to the Interior.This delay also delays
the schedule for possible methanol production since the North Slope gas was to
be the feedstock for the methanol facility.
RAIL BEL T ELECTRIC POWER ALTERNATIVES STUDY
-Railbelt Electric Power Alternatives Study:Evaluation of
Railbelt Electric Energy Plans
Volume II -Selection of Electric Energy Generation Alternatives for
Consideration in Railbelt Electric Energy Plans
Volume III -Executive Summary -Candidate Electric Energy Technologies for
Future Application in the Railbelt Region of Alaska
Volume IV -Candidate Electric Energy Technologies for Future Application
in the Railbelt Region of Alaska
Volume V -Preliminary Railbelt Electric Energy Plans
Volume VI -Existing Generating Facilities and Planned Additions for the
Railbelt Region of Alaska
iv
Volume VII -Fossil Fuel Availability and Price Forecasts for the Railbelt
Region of Alaska
Volume VIII -Railbelt Electricity Demand (RED)Model Specifications
Volume VIII -Appendix -RED Model User's Manual
Volume IX -Alaska Economic Projections for Estimating Electricity
Requirements for the Railbelt
Volume X -Community Meeting Public Input for the Railbelt Electric Power
Alternatives Study
Volume XI -Over/Under (AREEP Version)Model User's Manual
Volume XII -Coal-Fired Steam-Electric Power Plant Alternatives for the
Railbelt Region of Alaska
Volume XIII -Natural Gas-Fired Combined-Cycle Power Plant Alternative for
the Railbelt Region of Alaska
Volume XIV -Chakachamna Hydroelectric Alternative for the Railbelt Region
of Alaska
Volume XV -Browne Hydroelectric Alternative for the Railbelt Region of
Alaska
Volume XVI -Wind Energy Alternative for the Railbelt Region of Alaska
Volume XVII -Coal-Gasification Combined-Cycle Power Plant Alternative for
the Railbelt Region of Alaska
November 1982
v
SUMMARY
This paper addresses the availability and price of fossil fuels over the
forecast period 1980-2010 for the Railbelt reQion.
The assessment of fuel availability considers only the in-state resource
base as the supply source for two reasons:either the available resource is
sufficient to supply Alaska's needs,or the cost of transporting fuels to
Alaska's markets is such that in-state substitutes will be available.The
Cook Inlet natural gas resource is the only fuel that may be inadequate to
supply the needs of the southern part of the Railbelt region over the time
horizon of the study,given no additional major finds.This gas could be
supplemented with high-cost liquefied natural gas (LNG)imports,but then
coal,oil,and North Slope gas become reasonable substitutes.
When a current price for a fuel is not available,the concept of
opportunity cost is used to develop the base price and forecast.This concept
provides that the resource price is equal to the price the resource will
command in an alternative market,less the appropriate transportation and
handling fees.Alaska is familiar with this net-back method of price
determination,which is currently used for valuation of their royalty gas and
oil resources.Table 1 and Figure 1 summarize fuel availability and prices
faced by the electric utilities for the forecast period.
COOK INLET NATURAL GAS
The supply and price of Cook Inlet natural gas is the most complex of all
the Railbelt fuels because contracts have established the quantity,current
price,and price escalation rate for various portions of the gas,and the
terms of these contracts differ.In addition,new or incremental supplies
used to meet demand in excess of the contracted supply are priced by their
opportunity value,which is the net-back from liquid natural gas (LNG)sales
to Japan.Determining price for Cook Inlet gas requires a forecast of both
price and quantity from each contractural source to develop the weighted
average gas price for the region.The result of this forecasting is a price
escalation that is not smooth over the forecast period.This uneven price
vii
TABLE 1.Fossil Fuel Availability and Price
Pricel106 Btu Annua 1 Real
Estimated (January 1982 Escalation
Fuel Type Reserves Availabil ity ~IS)Rate
Coal
Beluga/Cook Inlet 350x10 6 tons 1988 1.48 Mine 2.1%
240x10 6 Mouth
Healy/Interior tons Present 1.75 Deli vered 2.0%
Nenana
Natura 1 Gas
Cook Inlet(a)3,900 Bcf Present 0.86 City Gate 6.6%avg
North Slope/Interior 21,500 Bcf 1987 5.92 City Gate -4.3%avg
Liquids/Methanol 3,800 Bcf 1995
No.2 Heating Oil Adequate Present 6.90 Elelivered 2%
Peat N/A 1988 (b)1%
Refuse-Derived Fuel
Anchorage 1985
Fai rbanks 1988
(a)Volume weighted average price to Alaska Gas and Service and Chugach
Electrical Association.
(b)Estimates range from 1 to 3 times the price of coal.
escalation is evidenced in Figure 1 by the relatively constant price of gas
from 1980 to 1985,and the escalation over the rest of the period,with
stepped increases occurring in 1990 and 1995 when major contracts expire.
After 1995,the price and escalation rate of gas are determined by its
opportunity value because current purchase contracts will have expired.The
price of natural gas then is assumed to escalate at a rate approximately 2%
faster than inflation--the same real annual rate as for oil.Current
information about Cook Inlet natural gas reserves and total demand on those
reserves indicates that availabilty to the Alaskan market could become a major
problem as early as 19~0,and almost certainly after the year 2000.
viii
NO.Z FUEL OIL
(Z'"REAL ESCALATlONl
/B'"REAL ESCALATION)
'"'"'",,
""
--__- - - - ---II '"REAL ESCALATION)-----
,
,
,,"
---
14.00
lZ.00
10.00
::J-CD
:::E 8.00:::E
ilJ
Nco
~
6.00
4.00
Z.OO
1980 1990 ZOOO
YEAR
Z010
FIGURE 1.Projected Fuel Prices to Railbelt Utilities,
1982 ~/MMBtu,1980-2010
COAL
Two sources of coal are available to the Railbelt.The Usibelli mine
located at Healy is the only mine curently producing coal in significant
quantities.The cost of this coal is assumed to escalate in real terms at the
real historical rate of about 2%per year.A second potential source is the
Beluga coal field,which has been targeted as a source of supply for the
Anchorage area and as export to markets on the Pacific Rim.As discussed
below,this field may enter production about 1988.Beluga coal is expected to
escalate at the same rate as other coal supplies serving the Pacific Rim
export market at a real rate of about 2.1%annually.
Note that a great deal of uncertainty is involved in developing the
Beluga coal fields.These coal fields are now in the exploratory and
predevelopment phase.The coal has yet to be produced in any significant
quantity and thus,from an availability standpoint,must be considered
ix
prospective.Located in an area with very little to no infrastructure
development,these fields,while containing very large reserves,are not
likely to produce coal unless a firm market of five or more million tons per
year can be established.As a result,the establishment of an export market
is a necessary precursor to the availability of Beluga coal for in-state use.
PEAT
Alaska has substantial peat reserves,although these reserves have not
been comprehensively assessed.The peat resource is assumed not to be
developed before Beluga coal.Although information for peat development in
Alaska is lacking,a preliminary feasibility study (EKONO 1980)estimates a
range of likely prices from about 1 to 3 times the price of coal on a Btu
basis,depending upon the harvesting and processing method used.The only
real escalation likely to occur is that associated with transportation and
handling,set at less than a 1%real annual rate.
Based upon current resource information and existing steam-electric
generating technology,peat does not appear to be a competitive fuel for
electrical generation in the Railbelt.However,because of the extensive peat
resources available within the area,it appears to warrant further
investigation as technologies to use peat are further developed.
REFUSE-DERIVED FUEL
The refuse-derived fuel (RDF)resource is limited to the two
municipalities of Anchorage and Fairbanks.The resource has three problems:
1)limited availability,requiring RDF to be mixed with other fuels for
electricity generation,2)seasonality (more refuse is generated in the summer
than in the winter),and 3)limited storage life.However,it has two
offsetting factors:1)zero cost,since people place no value on refuse and
disposal costs already exist to refuse producers,and 2)the only real
escalation expected is in transportation and handling.A limited amount of
RDF generation appears feasible.
x
...
NATURAL GAS INTERIOR
The North Slope reserves of natural gas are sUfficient to supply the
Alaska Natural Gas Transportation System (ANGTS)to capacity (2 to 2.4 Bcf/day)
for the forecast period.This gas may begin flowing in 1986 or 1987.If only
Alaska's royalty share is diverted to serve the Fairbanks area,the supply of
gas would be about 100 Bcf/year.A current estimate of the delivered price of
gas to the "10wer 48"is about S10/MMBtu in 1982 dollars,with the January
1982 maximum wellhead price of S2.13/MMBtu.The net-back provides a first
year delivered city gate price to Fairbanks of about S5.92/MMBtu in 1982
dollars.This gas is not scheduled to decontrol under existing law and
desca1ates with the pipeline tariff.
NATURAL GAS LIQUIDS/METHANOL
The delivery of natural gas liquids (NGLs)to the Rai1be1t depends on the
construction schedule of the ANGTS and the real price of crude oil.Current
plans call for construction of an NGLs pipeline following the ANGTS,with a
real crude oil price in the range of S50 to S52/barrel.This schedule
provides for delivery of NGLs in the mid-to-1ate 1990s.
Methanol production is tied closely to the ANGTS because the natural gas
from that system would serve as the feedstock,but the timing of methanol
production appears to be tied to petrochemical production that may accompany
the NGL pipeline.Current methanol prices in the l'lower 48"have been in the
range of SO.90 to Sl.00/ga1.The net-back price at Alaska tidewater would
range from SO.85 to SO.95/ga1 or S13.29 to S14.86/MMBtu.This price must
incorporate Fairbanks'city gate price for the methane feedstock of
-S5.92/MMBtu,suggesting that the production and transportation costs from
Fairbanks to tidewater can be no greater than S7.34 to S8.9l/MMBtu.
Currently,methanol production is not cost competitive with other fuels in the
"10wer 48 11 and is not projected to become cost competitive until after the
year 2000.
xi
FUEL OILS
Refined petroleum products are the only fuels in which Alaska is
currently not self-sufficient.This is because of insufficient refinery
capacity for some products,rather than lack of resources.Alaska's royalty
share of crude oil production is sufficient to meet in-state consumption at
least through the year 2000,but some refined products are imported.The
supply of petroleum products is not believed to be a problem through the
forecast period,however.The current price of utility fuel oil of
-S6.90/MMBtu is a good indicator of its current opportunity value,especially
in view of the recent price decontrol on oil.This oil is expected to
escalate at a 2%annual real rate along with crude oil.Figure 1 also shows
the price of No.2 oil over the forecast period for real annual escalation
rates of 1%and 3%.
xii
CONTENTS
PROLOGUE
SUMMARY
1.0 INTRODUCTION
2.0 COOK INLET NATURAL GAS:AVAILABILITY AND PRICE FORECASTS
2.1 NEAR-TERM AVAILABILITY OF NATURAL GAS
2.1.1 Recoverable Reserves and Reserve Commitment Base
2.1.2 Potential for Release of Uncommitted Reserves
2.1.3 Natural Gas Utilization Scenarios
2.2 FORECASTING NEAR-TERM NATURAL GAS PRICE.
iii
vii
1.1
2.1
2.2
2.3
2.6
2.11
2.16
2.2.1 Factors in Price Formation for Indigenous Cook Inlet
Natural Gas.. . . . . . . .2.16
2.2.2 Interaction Between Natural Gas Contract Price Terms
and Likely Future Events . . . . . .2.18
2.2.3 Future Price Scenarios.• . . . . .2.23
3.0 ALASKA COAL
3.1 AVAILABILITY AND QUALITY .
3.2 COAL PRICE AND ESCALATION
3.2.1 Beluga/Chuitna Coal
3.2.2 Nenana Field Coal.
4.0 PEAT
4.1 AVAILABILITY
4.2 PRICE
5.0 REFUSE-DERIVED FUEL .
5.1 AVAILABILITY
3.1
3.3
3.5
3.8
3.16
4.1
4.1
4.2
5.1
5.1
xiii
r
5.2 PRICE
6.0 NORTH SLOPE NATURAL GAS .
6.1 AVAILABILITY
6.2 PRICE.
7.0 NATURAL GAS LIQUIDS/METHANOL .
7.1 AVAILABILITY
7.2 PRICE
8.0 FUEL OIL .
8.1 AVAILABILITY
8.2 PRICE
9.0 REFERENCES
APPENDIX A
xiv
.'
5.2
6.1
6.1
6.4
7.1
7.1
7.3
8.1
8.1
8.3
9.1
A.1
FIGURES
1 Projected Fuel Prices to Railbelt Utilities,1982 ~/MMBtu,
1980-2010.• • . • . . • • . . •ix
2.1 Principal Natural Gas Sales for Cook Inlet Region in 1979,Bcf .2.12
2.2 Weighted Average Natural Gas Acquisition Cost--Alaska Gas and
Service Company Without Pacific Alaska LNG . . . • .2.2~
2.3 Weighted Average Natural Gas Acquisition Cost--Chugach Electric
Association Without Pacific Alaska LNG Plant.. . . •2.27
3.1 Procedure for Estimating Steam Coal Price Escalation-Pacific
Rim Markets ....••..•.3.9
3.2 Composite Export Steam Coal Supply Function FOB Australia . .3.10
3.3 Composite Export Steam Coal Supply Function FOB South Africa .3.10
3.4 Composite Export Steam Coal Supply Function FOB Canada
(British Columbia).• . . . . . • . .3.11
3.5 Estimated Coal Prices FOB Port of Origin . • • • •3.13
xv
TABLES
1 Fossil Fuel Availability and Price.
2.1 Cook Inlet Natural Gas Status and Contracts -1980
vii i
2.4
2.2 Estimated Cook Inlet Natural Gas Reserve Commitment Status as of
January 1,1980,Bcf 2.5
2.3 Cumulative Natural Gas Reserves Potentially Available for In-State
Use--Bcf,January 1,1980 2.9
2.4 Cook Inlet Natural Gas Utilization Scenarios,Bcf/Year or Bcf
Cumulative 2.15
2.5 Summary of First Sale Natural Gas Contract Price Conditions.2.19
2.6 Time Table of Expected Significant Changes in Cook Inlet Natural
Gas Situation 2.22
2.7 Estimated Gas Price -Purchases by Alaska Gas and Service
Company Without Pacific Alaska LNG,1982 liS,0%Inflation
2.8 Estimated Natural Gas Acquisition Cost for Chugach Electric
Association Without Pacific Alaska LNG Plant,1982 liS,
0%Inflation
2.9 Estimated Gas Price -Purchases by Alaska Gas and Service
Company with Pacific LNG Gas,1982 liS,0%Inflation
2.24
2.26
2.28
2.10 Estimated Natural Gas Acquisition Cost -Chugach Electric
Association with Pacific Alaska LNG,1982 liS,0%Inflation.2.29
3.1 Preliminary Projections of Steam Coal Imports by Country and Year 3.7
3.2 Estimated Total Export Steam Coal Production for Non-U.S.
Countries Serving the Pacific Rim Markets
3.3 Market Share of Steam Coal Trade in the Pacific Rim
3.4 Steam Coal Prices Landed in Japan and Net-Back to Alaska
4.1 Cost Estimates of Peat-Based Fuels,1980 Dollars
6.1 Tariff by Segment of ANGTS
7.1 Crude Oil Price Sensitivity to Escalation Rate
3.12
3.14
3.15
4.3
6.5
7.3
8.1 Alaska Consumption of Imports and Exports of Refined Petroleum
Products in Barrels/Day,1979 .8.2
xvi
8.2 Fuel Oil Price in Fairbanks.1980-81
8.3 Expected Real Price Escalation Rates for Crude Oil
8.4 Oil Prices Over the Forecast Period.$/Bbl
xvii
8.4
8.5
8.6
1.0 INTRODUCTION
The Railbelt Electrical Power Alternatives Study is being conducted for
the Office of the Governor,State of Alaska,by Battelle,Pacific Northwest
Laboratories.Task 1 of the study addresses the future availability and
prices of various fuels.The fuels considered are those that are,or could
be,used in the generation of electric power or,at the consumer level,
proviae a substitute.These are coal,oil and natural gas.Two supplemental
fuels,peat and municipal waste,are also considered.
Location within the Railbelt region is also a determinant of the future
availability and price of the various fuels.Thus,in essentially all cases,
the analyses will consider the Cook Inlet and Fairbanks-Tenana Valley regions
separately.This is especially important for natural gas,as it is currently
available in only the Cook Inlet region and future availability of supply is
an area of concern.North Slope gas may be available in the Fairbanks area as
early as 1986,but there are no existing plans to pipe this gas to the Cook
Ihlet region.The price of gas in these two regions differs significantly
because Cook Inlet prices were initially established in a buyer's market with
long-term contracts and as these contracts expire over the next 10 to
15 years,prices will increase significantly.Natural gas prices in Fairbanks
are projected by netting back or deducting transmission costs from the
projected 1I1 0wer 48 11 market.
Fuel prices are established in a variety of ways,depending upon the fuel
type and market prospects.For some fuels a current price is established,
either through market conditions or by contract.These fuels are coal from
the Healy Mine in Fairbanks,Cook Inlet natural gas and refined oil products.
Other fuels are identified for development primarily for export markets and
their prices are netted back to the Alaska market by subtracting the
appropriate transportation costs;these are North Slope natural gas to
Fairbanks,coal from the Beluga field in the Cook Inlet region,and natural
gas liquids and methanol.Two other fuels,peat and refuse-derived fuel,have
their prices developed from the best estimate of production costs.
1.1
Fuel escalation is examined from a slightly different perspective.The
oil,natural gas and natural gas liquids escalate,more or less,in unison
because of their transportability and substitutability.Coal price escalation
is tied more closely to production costs,although at some point oil price
escalation becomes important.The escalation rate of peat and refuse fuels is
tied closely to production costs.
This report devotes a chapter to each of the fuels analyzed.Each
chapter has been assembled from a corresponding working paper.As few changes
as possible were made in changing the working papers into chapters.Changes
that were made were done so on the basis of additional information gained
since the initial completion of the working paper.These changes resulted in
a slight price increase for coal and Cook Inlet natural gas and a price
decrease for peat and refuse-derived fuel.Those readers interested in the
draft working papers are referred to them as follows:
1.1 -Cook Inlet Natural Gas:Future Availability and Price Forecasts
1.2 -Alaska Coal Future Availability and Price Forecasts
1.3 -Peat Availability and Price Forecasts
1.4 -Municipal Refuse-Derived Fuel (RDF)
1.5 -North Slope Natural Gas Availability and Price Forecasts
1.6 -Natural Gas Liquids/Methanol Availability
1.7 -Fuel Oil Availability and Price Forecasts
1.2
2.0 COOK INLET NATURAL GAS:AVAILABILITY AND PRICE FORECASTS
In the 1950s and 1960s oil companies in search of crude oil,a readily
transportable commodity,encountered (to their probable distress)more natural
gas than oil.Since gas is not as easily transported to markets as oil,a
buyer's market occurred.As a result,the natural gas utility system was
created and such industries as the Collier Carbon and Chemical Company and the
Phillips/Marathon LNG export plant were attracted.Alaskan consumers in the
Cook Inlet region benefited greatly from their buyer's market position and
even today enjoy the lowest cost natural gas in the United States.As a
logical consequence,the region depends heavily on natural gas as a major
source of energy for electric power generation,home and commercial space
heating,and appliances--in fact,for most energy except for transportation
fuels.
It is unlikely that these conditions will continue much further into the
future,and significant shifts may occur in end use of energy and,hence,in
electric power generation costs as well as requirements.This chapter
examines the relationship between natural gas availability and prices in the
Cook Inlet region in conjunction with demand projected on an annual basis.It
should be noted that peak day gas supply limitations and the consequences are
not addressed.
An ideal objective would be to provide a supply curve (price versus
cumulative quality consumed).Unfortunately,as geologic data on
yet-to-be-discovered resources are not available,this study used existing
reserve information and long-term and probable future gas sales contract
conditions.As a consequence,a conservative forecasting stance is taken.
1.The possibility of significant new reserve disclosures and
developments is excluded and not credited as being available.
2.The most recent (and substantially lower than previous)estimates of
identified economically recoverable reserves published by the Alaska
Oil and Gas Conservation Commission are used vis-a-vis the generally
more optimistic reserve estimates prepared in the early 1970s by the
U.S.Bureau of Mines.
2.1
•
Once a reasonable estimate of remaining recoverable reserves is
developed,several scenarios of the likely depletion of these reserves are
provided.The intent is to identify likely dates (years)when gas
deliverability and prices might significantly change.These scenarios are
based on recent estimates of both natural gas utility sales and electrical
power production from natural gas.It is recognized that different natural
gas utilization scenarios could result in different estimates;however,it is
not expected that the end conclusions would be substantially changed.
2.1 NEAR-TERM AVAILABILITY OF NATURAL GAS
The future availability of Cook Inlet natural gas for in-state
consumption is clearly dependent on:1)the quantity of known remaining
recoverable reserves;2)the level of commitment of those reserves to in-state
consumption;3)the likelihood that uncommitted reserves might become
available for dedication to in-state uses;4)the possibility that certain
reserves now committed to the Pacific Alaska LNG (PALNG)project might be
released for in-state consumption;5)the expected rate of consumption;and
finally,6)the likelihood that new reserves will be identified and committed
for in-state consumption.
This section develops a number of natural gas availability scenarios that
appear logically supportable.Although most (67%in 197~)of the natural gas
sold in Cook Inlet is exported as LNG (to Tokyo Gas and Tokyo Electric)or
converted to ammonia and urea for export to Pacific Rim markets,the major
concern of this study is the gas available for in-state consumption either
directly by gas utility customers or by the electric utilities.Some gas is
also used in oil and gas production operations so is not available to the
utilities.Outlets to other markets,however,do have an influence on future
actions by lease holders with as yet uncommitted reserves.
The base year chosen for this portion of the study is 1979 for
consumption and 1980 for reserve base.These are the latest years for which
complete data were available at the time this section of the report was
initially completed.In those instances (e.g.,ammonia/urea production)where
preliminary 1980 data indicate that higher throughputs can be accommodated,
2.2
the 1979 data were adjusted for purposes of forecasting future consumption.
It is recognized that 1979 was not necessarily a representative "weather
year,"because temperatures in the Cook Inlet region since 1976 have been
warmer than the historical average.As a consequence,the scenarios developed
may underestimate future actual consumption.
2.1.1 Recoverable Reserves and Reserve Commitment Base
The estimated remaining recoverable reserves in the Cook Inlet region are
shown in Table 2.1.These are based on information supplied by the Alaska Oil
and Gas Conservation Commission (AOGCC).(a)Commitments of these reserves
are estimated and shown in Table 2.2.These are based on our review of all
major contracts for gas sales and adjusted for drawdown prior to January 1,
1980,using data provided by AOGCC(b)and data obtained by the Institute of
Social and Economic Research(c)from detailed records in AOGCC files.
Appendix A provides detail on a field-by-field basis.
The committed status of known recoverable reserves for Cook Inlet natural
gas as of January 1,1980,can be summarized as follows:
Billions of
Cubic Feet (Bcf)
Committed Resources
Alaska Gas and Service Company
Chugach Electric Association
Anchorage Mun.Light and Power(d)
Total for In-State Consumption
(other than oil and gas produc-
tion activities)
Pacific Alaska LNG Associates(e)
Export (LNG +NH3/Urea)
Total
Uncommitted Reserves
375
310
?
0B"5"
829+
730
2244+
1839
(a)
(b)
(c)
(d)
(e)
Alaska Oil and Gas Conservation Commission,Bulletin,July 1980 and
letter,Hoyle W.Hamilton to W.H.Swift,November 14,1980.
Letter,Hoyle W.Hamilton,AOGCC,to W.H.Swift,January 12,1981.
Letter,O.S.Goldsmith to W.H.Swift,January 13,1981.
Royalty gas.Commitment status uncertain due to recent transfer of State
land to the Cook Inlet Region Incorporated.
Based on DeGolyer and MacNaughten estimate filed with the FPC.If AOGCC
reserve estimates are used,this value is 740+.Values do not include
the Tyonek Field for which no reserve estimate is available.
2.3
TABLE 2.1.Cook Inlet Natural Gas Status and Contracts -1980
Peninsula SOCAL Shut State
Greenhouses,ARCO In Royalty 1979
_~_'!..ental UIIao %__~~_
0 0.00925 0.~/)3
7.99 I/).99 90.~6
0 0 0.1
N.A.N.A.N.A.
0 0 <fJ.1
0 0 0
N.A.N.A.N.A.
"'3.09 97.0 995.1
0 0 0
12.5 16.61 66.90
12.5 0 1.0/)
12.5 49.4 ~5fj.5
0 0 0.1
12.5 0 N.A.
2.7??0.0254 1.9/)1
N.A.N.A.N.A.
0 (120.3)(6)(1,173.7)(/)1
N.A.N.A.N.A.
0 N.A.N.A.
0.a220
Net Product Ion (~)
Cumulat lVP
to 11l/80
___B~__
0.7705o
X
X
X
X
Tokyo Gas,
Tokyo
Electric
Recoverab 1e Co 111 er PacificReserves
11l/80 Chugach City Carbon Alaska
__B~~_A!ask a Electric of and Lease LNG
~l1ne Co.Assoc '---AHP&L Ken~Chemica 1 Use Assoc.
Beaver Creek 240 ------..--X (5)
Beluqa River 747 --X ------X X
Birch Hill 11
Cannerv LOOp(3)N.A.
Falls Creek 13
Ivan River 26
Ka 1(hchabuna N.A.
Kenai l313 X --Royalty
Lf'.<is River gO ------------X
McArthur River 7B --------X X (5)
Nicolai Creek 17
North Cook In let 1074 Roya lty
Only
N North Fork 12.
N.Middle Ground+:0-N.A.
~terlinq 23
Stump Lake(3)N.A.
Swanson River 242(2)
Trall Ridgell)N.A.
Tvonek(l )N.A.
West Foreland N.A.
West Fork 7 X --------X
'iotes
1.Represents combioed total of fields.Also identified as Albert Kaloa and Moquaki.
2.Being injected for pressure.Maintenance with Rental Gas from the Kenai field.Original indigenous reserves estimated at 59.6 Bcf.Anticipated
recover v of injected 9aS estimated at 192 Bcf for total of 2~2 Bcf after conmencement of blowdown.
J.Potential discovery or heing drilled.
4.Alaska Oil and Gas Conservation COIl1I1ission.
5.Contracts reportedly being ne90tiated.
fl.Represents injection.
TABLE 2.2.Estimated Cook In let Natural Gas Reserve Co 11111 itme nt Status
as of January 1,1980,Bcf
Pacific
Alaska Chugach Collier Alaska Tokyo Gas SOCAL,
Recovera~lr Pipeline Electr ic Carbon &LNG Tokyo ARCO Uncollll1i tted
Reserves 6 Co.Assoc.AHP&L ~Assoc.E1ectoj£Rental Reserves.
Beaver Creek 240 --------------240
Be luga River 767 --310 ----"'624 ----Negative
Birch Hill 11 --------------n
Cannery Loop N.A.--_.----(1 )----N.A.
Falls Creek 13 -------- --
----13
I van Ri ver 26 --------106(4)----0
Kaldachahuna N.A.------ --
------N.A.
Kenai 1313 338 --(2)499 ----106 370
Lewis River 90 ------.-99(4)----0
McArthur River 78 --------------78
Mico hi Creek 17 --------------17
Morth Cook Inlet 1074 30(7)--------231(5)--813
Morth Fork 12 -- ------------12
N M.HiJdle Ground M.A.------ --------N.A..~ter li n9 23 23<J1 --------------
~tu~Lake M.A.--------(1)----N.A.
~wanson River 242 (3)--------------242
Trail Ridge M.A.-------- --
----N.A.
Tyonek M.A.--------All ----0
Wes t Fore hnd 20 --------------20
West Fork I I ------------0
Tota I cOllll1itted reserves =2350+
Total 3933 375 310 --499 829>231 106 1839
Motes
1.Participant in pxploration under way in 1980.
~.Uncertain royalty status.
3.8attelle estimate of gas available on blowdown.
4.Based on DeGolyer and H~cNaughten reserve estimate in 1975.
5.This figure assumes that T.G.and T.E.contracts will be met by gas from the Cook Inlet Field.In actuality,a
significant portion is supplied by the Kenai Field.
6.Alaska Oil and Gas Conservation Commission.
7.Royalty.
2.1.2 Potential for Release of Uncommitted Reserves
The potential for release (and commitment to contracts for in-state
consumption)can be addressed on a field-by-field basis taking into account
lease ownership,alternative commitment opportunities,field size and
location,availability of gas transmission pipelines,and future producibility.
Currently Producing Fields (1261 Bcf)
Of the currently producing
North Cook Inlet
Kenai
McArthur River
fields,the uncommitted reserves are:
813 Bcf
370
78
1261 Bcf
The North Cook Inlet Field leases to Phillips and Marathon,among others,
and is the principal supplier to the Tokyo Electric and Tokyo Gas contracts
for LNG.This is a very profitable contract for the lessees as the price
appears (see Appendix A)directly related to world oil prices and is free of
Federal price regulation.Although the existing contract expires in 1984,
there is an option to renew.We believe that this option will be taken up and
reserves will not be released for in-state consumption.Contract extension
will be under the jurisdiction of the Economic Regulatory Administration,U.S.
Department of Energy (DOE).In addition,production from the North Cook Inlet
Field is expected to decline at a rate of about 10%per year beginning in 1985.
The Kenai Field is leased "largely by Union and Marathon ana is the second
supplier (-30%)to the Phillips/Marathon LNG plant serving the Tokyo
contracts.The Kenai Field also provides the bulk of the feed stock to the
Collier Carbon and Chemical Company's ammonia/urea plant.Collier Carbon and
Chemical is a wholly owned subsidiary of Union Oil Company.Due to the
profitability of both the Phillips/Marathon and the Collier Carbon
arrangements,we expect that the remaining reserves will be retained for
future commitment to these operations.
The McArthur River Field (primarily an oil field)lease is owned
principally by Union Oil Company and is a supply source for Collier Carbon and
2.6
Chemical Company.Gas production started to decline at about 8%per year in
1971.For this reason and those already cited,we do not expect McArthur
River gas to enter the in-state consumption market.
The above reasoning suggests that the 1261 Bcf of uncommitted reserves in
producing fields (except Beluga River)should be deducted from the 1839 Bcf of
total uncommitted reserves,leaving 578 Bcf that might become available to
PALNG Associated.
The Pacific Alaska LNG (PALNG)currently has more than 829 Bcf in reserve
commitments.(a)These reserves are all under contracts that contain
"kick-out"provisions.If PALNG does not take delivery of gas or meet other
conditions specified in the contract prior to the "kick-outll date,the
commitments may be cancelled.It is our understanding that these dates have
been passed but that none of the suppliers have as yet exercised this
option.(b)
The likelihood that the PALNG project will go forward is clouded:
1.Pacific Gas and Electric Company,a major sponsor,has limited its
support for the projects.(c)
2.Natural gas requirements in California are declining or at least not
increasing as rapidly as previously expected.
3.A1ternative gas supplies to the California market are gaining
strength.
4.PALNG has not yet been able to establish the reserve commitments
necessary to satisfy Federal Energy Regulatory Commission (FERC)
licensing requirements.
5.Regulatory (FERC)proceedings regarding the LNG terminal at Point
Conception,California,are not scheduled to be completed until at
least mid-to-late 1982.At issue is the seismic safety of the site.
(a)As of July 1982 these commitments have increased to about 980 Bcf.Oil
and Journal,July 26,1982,p.106.---
(b)Letter,Len McLean,Pacific Alaska LNG Associates,to W.H.Swift,
January 5,1981.
(c)Another sponsor is needed to cover one-fourth to one-third of the projects
costs.Oil and Gas Journal,July 26,1982,p.106.
2.7
Reserves committed to PALNG are as follows:
Beluga River Field(a)-624 Bcf
Ivan River(b)106
Lewis River(c)99
Tyonek(d)all----
829+Bcf
Of the above fields,only the Beluga River Field is producing (supply to
Chugach Electric Association,CEA)but it is remote from existing pipelines.
Gas from both the Ivan River,Lewis River and Tyonek Fields is not committed
nor are these fields connected to a pipeline.The Ivan River and Lewis River
Fields are located near the Beluga River Field so do not have ready pipeline
access;the Tyonek Field is reasonably close to pipeline access.None of the
lessees of these fields appear to have direct or indirect connection to
out-of-state gas sales except via PALNG.
In the author's opinion,there is a better-than-even chance that the
reserves now committed to PALNG will be released,likely to the highest
bidder,and potentially will be available for in-state use.
Other Known Reserves--Not Producing or Committed (578 Bcf)
The remaining estimated reserves of natural gas in the Cook Inlet region
may be classified both by size and remoteness.These fields are as follows in
likely order of interest .
•Beaver Creek (240 Bcf):Not connected by pipelines but centrally
located in the Kenai Peninsula.Union/Marathon are the lessees.
This field appears to be the most attractive for next development.
(a)Based on contract terms for reserve commitments from Chevron USA and
Atlanta Richfield coupled with assumption that Shell Oil Company's
unstated commitments are comparable to those of the other lessees.
(b)Based on DeGolyer and MacNaughten estimates.The Alaska Oil and Gas
Conservation Commission carries a value of 26 Bcf.
(c)Contract commitment is for 99 Bcf;the AOGCC estimates 90 Bcf.
(d)No reserve estimates are available.
2.8
•Nicolai Creek (17 Bcf):Not connected but a pipeline runs through
the field.Texaco is the lessee.
•Birch Hill (11 Bcf):Not connected but pipeline to Nikiski is
nearby.Lessees are Chevron/Arco.
•Sterling (23 Bcf):Not connected but Alaska Pipeline is adjacent.
Lessees are Union and Marathon.
•West Foreland (20 Bcf):Not connected but reasonably near Trading
Bay production facilities.AMOCO is the operator.
•Swanson River (242 Bcf):Reserve estimates are debatable.Although
included in this listing,rental gas is committed for return to
Kenai Field proaucer and,if produced,will probably be devoted to
ammonia/urea production or LNG export to Tokyo Electric and Tokyo
Gas.
•Falls Creek (13 Bcf):Not connected and very remote.Chevron USA
is lessee.
•North Fork (12 Bcf):Not connected and very remote.Chevron USA is
lessee.
Depending on whether the reserves committed to PALNG Associates will be
released and committed to in-state contracts,the above data can be summarized
as shown in Table 2.3.
TABLE 2.3.Cumulative Natural Gas Reserves Potentially Available
for In-State Use--Bcf,January 1,1980
Committed Reserves
PALNG Reserves
Beaver Creek
Small/Near Fields
Small/Remote Fields
Small/Very Remote Fields
PALNG Reserves
Released
685
1514+
1754+
1805+
1825+
1850+
2.9
PALNG Project
Proceeds
685
685
925
976
996
1021
Implication of The Natural Gas Policy Act of 1978
The price of natural gas is controlled either by long-term contracts with
purchasers or,if uncommitted under contract,by the Natural Gas Policy Act of
1978 (NGPA).Although no applications for price determination under the NGPA
have been made for Cook Inlet natural gas,it appears the uncommitted reserves
will fall under Section 109(a)(3)of the NGPA.This sets the maximum lawful
price at $1.45/MMBtu for April 1977 with a quarterly inflation adjustment
factor determined by the GNP deflator,plus a 2.43%per year escalator.For
January 1980,the adjusted maximum lawful price was $1.786/MMBtu.Assuming
the NGPA remains in full effect,it appears that producers committing
additional reserves for intrastate consumption will seek a price as high as
they can obtain up to that ceiling.If the NGPA is repealed or modified to
effectively decontrol Cook Inlet natural gas,the producers may obtain a
higher price equivalent to the best alternative,i.e.,an "opportunity price."
At the present time the only gas that appears to be effectively
deregulated is the gas dedicated by Phillips/Marathon to the Tokyo Electric
and Tokyo Gas Companies.This gas had an effective wellhead price of
$2.07/Mcf in December 1980 and,based on monthly price behavior during 1980,
appears now to be reaching and tracking very closely world crude oil prices at
the Japan point of delivery.Presumably,the opportunity price for gas owned
by both Phillips and Marathon will track this situation.
In the case of Union Oil Company leases,the producer1s opportunity price
(for gas not sold to Tokyo Electric or Tokyo Gas)is difficult to determine
since their principal interest would probably be to maintain operation of the
Collier Carbon and Chemical Company ammonia/urea operation.The latter is a
wholly owned subsidiary of the Union Oil Company and,in effect,the price is
a transfer price that most likely would be a net-back from that received in
sales of the ammonia/urea products in the Pacific Rim markets.In this
instance,they compete with products produced from gas at either the world
price or at a somewhat lower average domestic price,but certainly not as low
as the current cost of gas to Collier Carbon and Chemical Company's Kenai
Plant ($0.61/Mcf marginal cost).
2.10
...
Understandably,all producers will be reluctant to commit reserves until
the question of the PALNG Associates project and the issue of natural gas
deregulation are resolved.The observation includes those producers without
direct access to LNG or ammonia/urea markets.
2.1.3 Natural Gas Utilization Scenarios
This section addresses the future drawdown of dedicated reserves and
potential reserves that might be committed to in-state use.
Figure 2.1 illustrates the ~atural gas flows from producing fields to
major consumers for 1979,the latest year for which complete data are
available.(a)Of greatest interest to this study are the gas flows shown in
the upper right hand corner of the figure because these are major in-state
consumers,i.e.,CEA,gas utility sales to end-use consumers,to the military
installations and to Anchorage Municipal Power and Light (AMP&L)for
electrical energy generation.Our scenarios regarding these consumers rest on
the following assumptions:
1.Sales to Cook Inlet military installations will remain constant at
about 5 Bcf/year.
2.Sales of natural gas for direct consumer use will increase at about
4%per year from the 1979 base year (Goldsmith and OIConnor 1980).
3.Sales of natural gas from a Beluga Field to CEA will increase at a
rate equal to the most recent medium growth forecast for Cook Inlet
area electricity sales as follows (Goldsmith and Huskey 1980).
1980 -1985 5.04%per year
1985 -1990 2.67%per year
1990 -1995 5.08%per year
(a)Some of the data used in preparation of Figure 2.1 were drawn from the
report "Historic and Projected Oil and Gas Consumption"dated January 1980
and prepared for the Royalty Oil and Gas Development Advisory Board and
the 11th Alaska State Legislature.It is understood that revisions to
this report are being made.Gas sales by Alaska Gas and Service Company
(AGAS)to CEA and AMP&L are from telephone discussion with Bill Hickman of
AGAS January 23,1981.
2.11
>,
LEGEND
~WORKING INTEREST
--.-ROYALTV .
TOKYO ELECTRIC,
TOKYO GAS
lPHILlIPS-MARATHON LNG)
BELUGA RIVER
__..;..16..;...9_1_.CHUGACH ELECTRiC.,
ASSOC IATt ON
13.76 \'b e,'b GAS UTILITY SALES
O.n ALASKA PI PELINE ~&MILITARY 14.991
WEST FORK ------1.,.148
"4 COMPANY ~ANCHORAGE MUNICIPALte,~/l\'Oi[N1\~_0 --~LIGHT AND POWER
----1--------
_ - --6,96 I ..CHEVRON/ARCO RENTAL
KENAI r (SWANSON RIVER FIELD INJECTION)
44.15 /
.tel'
'J>"/MCARTHUR RIVER r 6 91 COLLIER CARBON
AND CHEMICAL CO.
~/""./
NORTH COOK INLET __41";;".;..3-..
FIGURE 2,1.Principal Natural Gas Sales for Cook Inlet Region in 1979,Bcf
Total gas sales from the Beluga River Field under the existing
contract,however,have an upper limit of 21.9 Bcf/year under the
maximum "take"provision of the gas sales contracts to CEA,If CEA
desires additional take above 21.9 Bcf/year,it seems likely that a
separate contract would be negotiated (at a higher price).
4.If the Anchorage-Fairbanks electrical power interconnection is
installed in 1984,gas sales will increase by the following amounts
("Intertie Gas"):(a)
Bcf/year Bcf/year
1984 -2,48 1989 -3,36
1985 -2.98 1990 -3.24
1986 -3,07 1991 -3.10
1987 -3,27 1992 -3,03
1988 -3.32 1993 -2,79
(a)Based on estimated incremental generation of electrical energy and
converting estimated GWh/year using a heat rate of 12,000 Btu/kWh and
a heating value of 1,035 MMBtu/Mcf,GWh figures provided by Dave
Shafer,Commonwealth Associates,January 26,1981.
2.12
...------------------------------------------
...
5.Sales of natural gas by AGAS to AMP&L and to CEA will increase at a
rate of 90%of that shown in Assumption 3,reflecting improvements
in plant heat rates.
It seems unlikely that CEA would reopen its present contract (that
otherwise runs to 1997)with the Beluga Field producers and expose
itself to the potential for much higher prices (certainly as high as
Chugach would have to pay AGAS for gas from that source,and
possibly much higher).The last case could apply if the Beluga
producers were,for example,to sell gas to Phillips/Marathon (a
pipeline connection would be required to the North Cook Inlet Field
Platform).
If,as seems likely,Chugach does not choose to exceed its Beluga
maximum take provision,then the equivalent generation would be
shifted to gas supplied by AGAS to AMP&L or Chugach.
Alternatively,Chugach could seek a separate contract for
supplemental Beluga gas over and above the maximum take provision.
To the extent they are not bound by the commitments in the contract
with PALNG,the producers presumably would be willing to provide
such gas and at a price that recognizes the cost to Chugach of gas
from AGAS.This latter price would set a floor under the
supplemental Beluga gas price.
6.Generation capacity additions at least until 1988 are confined to
natural gas-(or oil-)fired combustion turbine and combined cycle
units.In 1988 the Bradley Lake hydroelectric project comes on-line
displacing about 3.3 Bcf/year of natural gas electric utility fuel.
Anticipating Susitna hydroelectric or other state-financed baseload
projects,the utilities will avoid capital-intensive plant additions
and opt for higher fuel cost alternatives in an attempt to minimize
additions to their rate base that may later become idle.Exemptions
from the provisions of the Power Plant and Industrial Fuels Use Act
may be necessary in the future;we believe that strong cases may be
made for such exemptions.
2.13
Based on these assumptions,two primary scenarios for natural gas
utilization are developed.Table 2.4 summarizes the consequences of these two
scenarios and runs them to the year 2000;after 1993 the scenarios are on a
best-guess basis for illustration only.
1.Business As Usual:No regulatory or contractual impediments occur.
Cook Inlet gas consumers,both electrical utilities and end-use
consumers,continue dependence on natural gas.
2.Constrained:Contractual impediments (Chugach with Beluga Field
producers)shift future gas demands to AGAS,and "future gas,"i.e.,
that might occur after 1985,is provided by AGAS either to AMP&L or
CEA.In addition,gas consumed to service the interconnection
between Cook Inlet and Fairbanks is provided by AGAS.
It is recognized that the assumptions used at this stage do not optimize
loadings of the various generation plants in a systems sense.Nevertheless,
for purposes of analyzing gas availability,they seem reasonable and lead to
the following conclusions:
Business as Usual Scenario
1.Gas sales to CEA reach the maximum delivery or take rate of
21.9 Bcf/year in 1985.
2.Cumulative AGAS sales to gas utility customers and the electric
utilities exhaust the currently dedicated reserves in 1990,and
alternative gas at a higher price must be supplied.
3.Beluga gas sales (unimpeded by maximum take contract provisions)
result in expenditures of committed reserves in 1993.
4.All gas currently committed for in-state use is expended in 1991.
Constrained Case
1.Alaska Gas &Service Company dedicated reserves are exhausted in
1989.
2.Beluga gas reserves dedicated to CEA become exhausted in 1995.
2.14
TABLE 2.4.Cook Inlet Natural Gas Utilization Scenarios,Bef/Year or Bef Cumulative
Constrainted Case
Beluga Field Ceiling at Maximum Take Alntertle Gas·
Supp lied by AGAS
Cumulative
Business as Usual -No Impediments Increase in
AG&S Cilmu Iat i ve Chugach Gas AG&S Revised
Gas Sales to Cumulative Beluga Cumulative AG&S Plus Cumulative Demand Sales to Revised Cumulative
Uti lity Electric AG&S to Beluga Beluga "Intertie""Intertie"Shift Electric Cumulative Beluga
Year 'iilitary ~Utili!L Sales Chugach Sales Sales Gas Gas to AG&S Utility AG&S Sales Sales
1980 5.00 14.60 1.11.75 31.35
11
7.7'
17.76 49.1l 31.35 17.76
81 15.19 j'12.28 63.82 18.66 36.42 100.24 63.82 36.42
82 15.79 12.84 97.45 19.60 56.02 153.47 97.45 56.02
83 16.42 13.42 132.29 ;'20.57 76.61 208.go 132.29 76.61........
84 17.08 ~14.03 168.40 ~21.63 98.24 266.64 2.48 2.48 2.48 170.88 98.24""~22.31(d)85 17.77 ';J,14.27 205.84 120.55 326.39 2.98 5.46 0.41 5.87 211.71 120.14
86 18.48 i 15.02 244.34 122 .91 143.46 387.80 3.07 8.53 1.01 9.95 254.29 142.04
87 19.21 1 15 •38 283.93 >,23.52 166.98 450.91 3.27 11.80 1.62 14.84 298.77 163.94......
19.98 ;'12.45 321.36 ""191.13 512.49 3.32 15.12 2.25 20.41 341.77 185.8488:;;24.15......
386.63(e)20.78 ...359.96 T24.79 215.92 575.88 3.36 18.48 2.89 26.66 207.74N89~12.83.1990 21.61 i 13.22 399.80(a)25.45 241.37 641.17 3.24 21.72 3.55 33.45 433.25 229.64......
U1 441.25 !26.74 268.11 709.36(c)3.10 24.82 41.39 483.63 251.5491..22 .48 113 •97 4.84
92 ~23.38 484.39 >,396.21 780.60 3.03 27.85 6.20 50.62 534.01 273.44..14.76 ;0 28.10
93 i;"24.31 >,529.29 ~29.53 325.74(b)855.03 2.79 30.64 7.63 61.04 590.33 295.34;0 15.59
94 25.29 ~16.45 576.03 j31.03 356.71 932.74 317.24
95 26.30 i 17 .36 624.69 32.61 389.38 1014.07 339.14(f)
96 27.35 118 •20 675.24 134 •09 423.47 1098.71 361.04
97 28.44 ..19.08 727.76 >,35.65 459.12 1186.88 382.94
98 29.58 >,782.34 ~p7.27 496.39 1278.73 404.84;0 20.00
99 30.76 :;20.96 839.06 ~38.97 535.36 1374.42 426.74
2000 31.99 ,21.95 898.00 I 40.75 576.11 1474.11 448.64
(a)Gas reserves currently dedicated to Alaska Gas and Service Co.exhausted in 1990.
(b)Beluga Field gas dedicated to Chugach Electric Association exhausted in 1993.
(c)Total gas currently dedicated to in-state use exhausted in 1991.
(d)Chugach Electric Association Contract with Beluga Field producers has maximum take provision of 21.9 Bcf/year.The greater take presumes Chug~ch would
be willing to renegotiate or enter a new contract.
(e)If Alaska Gas and,Service Co.sales to electric utilities assume demand shed from Beluga Field as a result of Chugach maximum take provision and also
pick up "Intertie Gas"demand,AGAS dedicated reserves are exhausted by 1989.
(f)Beluga Gas Reserves dedicated to Chugach Electric Association are exhausted in 1995.
The dates mentioned in these conclusions are not intended to indicate
that "all the gas is gone,"only that extreme changes in gas prices are likely
to occur as these dates approach and are passed.These price changes may
occur gradually as new gas purchases are rolled in (e.g.,supplies to AGAS)or
abruptly (e.g.,CEA from the Beluga Field).We also recognize that CEA is
engaged in exploratory drilling for gas and may find economically recoverable
reserves that could displace or supplement existing committed reserves.
Future natural gas prices are the subject of the next section.
2.2 FORECASTING NEAR-TERM NATURAL GAS PRICE
Natural gas prices were mentioned in the preceding section only to the
extent of noting that major price discontinuities are expected in the future
and noting the possible consequences of these discontinuities on future
seller/purchaser transactions.As in the analysis of gas availability,this
analysis leans heavily on review of existing long-term contracts ana the
likely (largely economic)motivations of both the producers and purchasers of
natural gas after these contracts expire.
This section attempts to develop reasonable scenarios for future natural
gas prices that would be paid either by the electrical utilities or by end-use
consumers.To the extent possible an effort is made to produce a schedule of
the likely gas price over time.The scenario approach is used because a
number of uncertainties now exist that could markedly affect prices.
2.2.1 Factors in Price Formation for Indigenous Cook Inlet Natural Gas
The prices or costs of natural gas seen by the purchasing electrical
utilities or the end-use consumers are dependent on a number of factors,some
of which are reasonably predictable and some of which are not.These factors
are presented in estimated order of importance.
1.Provisions in existing long-term contracts including:
a)Predictable price increase scheduled in advance.
b)Provisions that become operational if producers of a given
field make deliveries from that field to a third party under
contracts with different price conditions.
2.16
c)Provisions that link prices of future sales in the Cook Inlet
area to those in other fields.
d)Provisions that are linked to some measure of inflation.
e)Expiration dates and provisions for options to extend.
f)Contract provisions that establish a maximum take for a given
year.If the purchaser wishes to increase his take above that
maximum,he may expose himself to having to renegotiate less
favorable terms.
g)Minimum take (take or pay)provisions.The purchaser pays for
gas not taken and the effective gas cost is thus higher if he
does not achieve the minimum take.
h)Special provisiuns for compression,gathering and wheeling.
2.Whether the market conditions can be classified as a IIsellerlsll or
IIbuyer 1 s"market.In the initial years of Cook Inlet natural gas
production,the amount of gas available far exceeded demand,
resulting in a IIbuyer 1 s"market.Thus prices were depressed.As
long as the PALNG proposed plant remains pending and willing to
purchase gas at the maximum lawful price under the NGPA of 1978 (or
at possibly a higher price if deregulation occurs),the market is a
"seller's"market.If the PALNG project is cancelled ana another
major market outlet does not develop,the market will revert to
"buyer"conditions.The uncertainty regarding PALNG obviously
clouds the understanding of future prices.
3.Potential deregulation of natural gas or substantial revision to the
Natural Gas Policy Act of 1978 (NGPA).This would seem to be in
concert with the current federal administration's economic
policies.However,the political difficulties in implementing such
a change are great.The maximum lawful price for "new ll
(Section 103)gas under NGPA was ~2.158/MMBtu in January 1980 and
escalates at 2.43%per year in real terms.
2.17
_....._-------------------~
4.To the extent not constrained by price regulations,the opportunity
price the seller might be able to obtain in a sale to a third party;
a related case would be the transfer price to a wholly owned
subsidiary,e.g.,the Union Oil Company/Collier Carbon and Chemical
Company relationship.In this instance the sale might not be fully
at "arms length.11 Similarly,the sellers'perception of the buyers'
opportunity cost of natural gas from another source,and quite
conceivably,the cost of a replacement distillate combustion turbine
fuel,would be a factor.
5.License extension for existing natural gas facilities.The
Phillips/Marathon LNG export facility and sales contracts were
licensed by the old Federal Power Commission.The present contract
expires June 1,1984,and contains an option to renew for an
additional 5 years,but without a specification of price.In ~rder
to renew,approval of the export contract extension must be obtained
from DOE's Economic Regulatory Administration.From the standpoint
of Alaskan consumers,regulatory action here presumably would only
affect the price of royalty gas taken by AGAS if the latter1s
contract with the state were to be similarly extended.
6.Amount of state production (severance)tax,which is currently the
greater of 10%of first sale price or 6.4¢/Mcf.In the case of
wells nearing exhaustion,this tax may be adjusted downward by a
variable economic limit factor designed to maximize economic
recovery.
Table 2.5 summarizes the first sale price conditions for existing natural
gas contracts.These prices do not include the state production (severance)
taxes,which are applicable to working interest but not to royalty gas.
2.2.2 Interaction Between Natural Gas Contract Price Terms and Likely
Future Events
Adjustments in gas prices are based upon events that may reasonably take
place in the future.Based on the contract terms and the scenarios developed
above,we estimated key dates of expected significant events for Cook Inlet
2.18
N.
........
ID
TABLE 2.5.
Alaska
_-!J~IE___P~ne Co.
Be'uga River
I van Rive ..
Summary of First Sale Natural Gas Contract Price Conditions
Kenai lie 11 head SO.27/Hc f
1/1/80 -12/31/85
frlJll 111/86 -
12/31/92.the
greater of SO.27/
Hef or the average
prIce Union/
Marathon wtll
recei ve frlJll new
third party sales.
To above.add
de 11 verab Illty
charge of SO.29/
Hcf escalating
with producer
price index
(a 11 goods).
Alaska
___F~~__~l!!lne Co.
lpwis Riyer
MeAl-thur River
Chugach
Electric
TABLE 2.5.
Anchorage Collier
~~L Carbon &Chemical
Not Ayal lable
(contd)
Pac if Ic Alash
_lNG.Assoc_.__
SMle as Beluga
Field.If deregu-
lated,then aYerage
of 3 highest prIces
paid In Cook Inlet
by pIpeline con-
panles for resale.
Tokyo Gas Peninsula
~lectrlc Greenhouses
SOCAl/ARCO
Renta ,
N.
No
North Cook
Sterling
Tyonek
West Fork
Roya lty gas.
Wellhead price
same as pa Id
by Tokyo Gas
&Electric plus
SO.12/Mcf
(1/1/81);
gathering charge
to I ntrease 6_/
plus SO.10 con-
pression charge
to Increase 6_/
year.
Not ava llab Ie but
be It eyed to be
similar to Kenai
Field.
S.,r,e as for lewis
River Field.
lie 11 head prl ce
SZ.0649/1tIl tu
In 12/80.Future
price appears
linked to world
011 price.
SO.40/Hcf
natural gas (Table 2.6).As these dates are approached,prjce changes for
sales both to electric utilities and to gas utility direct customers will
change as natural gas from alternative sources is rolled (blended)in.In
general,most changes in average prices will be gradual because of the
rolled-in effects.One exception to this would be PALNG's entry into the
market and the effect on natural gas costs for CEA.Increased costs to
Chugach would show up in electrical energy costs to all consumers in the Cook
Inlet region other than those served by AMP&L.Marginal prices of new sources
of natural gas will,however,increase almost as step functions even though
diluted by transmission costs downstream from the wellheads.(a)
The principal conclusions to be drawn from the Table 2.6 "Time Line"are
as follows.
1.The question of whether to proceed with the PALNG project may be
resolved in late 1982,and the uncertainty hanging over future gas
prices for uncommitted gas should be resolved to some degree.
2.In the 1984-1986 period,problems of deliverability from the Kenai
and North Cook Inlet Fields will increase;Beluga Field gas sales to
CEA will reach the maximum take contract provision,and either a new
contract will have to be negotiated for supplemental gas or
additional gas purchased from AGAS.Regardless of specific
outcomes,prices should increase significantly,at least for the
electric utilities.
3.In the 1989-1~91 period,natural gas committed for in-state
consumption is exhausted and prices (in the extreme case)could rise
to near the cost of distillate fuel oil if natural gas prices are
deregulated.Although this might be the limit of the "opportunity
cost,"it is doubtful that the gas producers could obtain this
(a)The miscellaneous costs of gathering,compression,and transmission
between the wellheads and the consumers are expected to remain constant in
nominal dollars unless covered in contract terms.Declines in gas utility
rate bases will be offset by increasing operation and maintenance costs or
physical additions to improve deliverability,etc.
2.21
_Jtt._
~...
TABLE 2.6.Time Table of Expected Significant Changes in Cook Inlet Natural
Gas Situati on
-
Date
1981 1)Kenai Field gas to Alaska Pipeline Company.Price increase from 24¢/Mcf to
27 ¢/Mcf at we 11 head.
2)North Cook Inlet gas to Alaska Pipeline Cor~any.Expected to incur lO¢/Mcf
cOfT1)ression charge (escalates at 6%annually).
3}Decision on Pacific Alaska LNG.Go-no go expected.
1984 1}Phillips/Marathon contract with Tokyo Gas and Tokyo Electric expires.May
be renewed for additional 5 years by mutual a9reement.
2}State Royalty gas contract to Alaska Pipeline Company expires for North
Cook Inlet Field.
3}Beluga Field 9as sales to Chu9ach Electric reach maximum take provisions if
sales increase as expected.
1985 1}Earliest year for Pacific Alaska LNG start if project is to proceed.
2)If Pacific Alaska LNG starts,Beluga 9as costs to Chugach Electric Associa-
tion could increase from 21¢/Mef to 85¢/Mcf if Beluga 9as is taken.
3}Production from North Cook Inlet Field expected to start decline at 10%per
year rate.
4)Kenai Field deliveries to Alaska Pipeline Company may start to decline.
1986 1}Kenai 9as price to Alaska Pipeline Company could increase to average of new
sales to third parties.
1989 1)Swanson River Oil Field blowdown expected to start at maximum rate of about
18.2 Bcf/year.
2)If Chugach draws SUPPlemental gas from AGAS rather than exceed maximum take
from Beluga,AGAS reserves are exhausted.
1990 1)Gas reserves currently committed to AGAS are exhausted irrespective of
above Chug ach sh ift.
1991 1)All gas reserves counted for in-state consumption are exhausted.
2)Kenai Field gas cOlllllitted to Collier Carbon and Chemical COfT1)any exhausted.
1993 1)Kenai Field gas committed to Alaska Pipeline Company exhausted if take
remains steady at 1979 rate.
1995 1)Beluga Field gas committed to Chugach is exhausted if Chugach does not
exceed maximum take prOVisions.
2)Beluga Field gas committed to CEA exhausted if it does not shift
supplemental gas requirements to AGAS and increase as expected.
1998 1)Chugach Electric Association contract for Beluga River gas expires.
2)Beluga River gas cOlllllitted to Chugach is exhausted if take remains steady
at 1979 rate.
1999 1)Swanson River Field blowdown expected to end.
2.22
l
price.It thus appears that the major near-term turning points are
about 198~and 1990.Significant changes in prices should start to
occur even with continued natural gas price regulation at these
dates.
2.2.3 Future Price ScenarioS(a)
Pacific Alaska LNG Associates Project Does Not Proceed
This scenario is the one most favorable to Alaskan consumers because
adverse contract terms are not called into play and a "buyer's market"
prevails.Under this scenario,it is assumed that AGAS continues to take as
much gas as possible from the Kenai and West Fork Fields and about 4 Bcf per
year of royalty natural gas from the North Cook Inlet Field (highest cost).
Natural gas deliveries to the electric utilities are interruptible;but,AGAS
installs an LNG storage facility in about 1985,purchasing liquefaction
services from the existing Phillips/Marathon LNG plant at least to assure
deliverability to gas utility customers.Ultimately,this additional LNG
storage depends on the size and conditions of future gas contracts and the
disposition of the royalty gas.Electric utilities must increasingly shift to
distillate turbine fuels for periods of peak demand.
It is also assumed that AGAS arranges for supplemental gas supply over
and above 1985 supply estimates from either the Kenai or Beaver Creek Fields
at a hlgher price.This price is rolled into all final sale prices without
preference to any class of customers.This scenario ~lso assumes that gas
availability from the Kenai Field declines at about 10%per year starting in
1986.Alaska Gas and Services·weighted average wellhead price plus
applicable taxes and other charges therefore increase as shown in Table 2.7
and Figure 2.2.
Chugach Electric Association depends principally (82%in 1979)on a
currently favorable contract for Beluga River Field gas.The Beluga
generation plants are base and intermediate load suppliers and CEA1s other
combustion turbines,supplied by AGAS,are used primarily for peaking duty.
(a)For the purposes of these scenarios,an interconnection between the Cook
Inlet and Fairbanks load centers does not exist.If interconnection
occurs,drawdown of Cook Inlet gas reserves are accelerated and
supplemental gas is introduced slightly sooner.
2.23
TABLE 2.7.Estimated Gas Price -Purchases by Alaska Gas and Service Company
Without Pacific Alaska LNG,1982 $IS,0%Inflation
Non-Royalty
Kenai Plus Supplemental Gas Weighted Ave.
North Cook Royalty North Fork
$/Mcf(a)
Total AGAS Price fO AGAS
Year Bcf/Yr S/Mcf Bcf/Yr $/Mcf Bcf/Yr Bcf/Yr $/Mcf b)
1980 4.00 (2.68)(c)2.50 (1.18)27.35 (29.44)0.64 (0.58)0 --31.35 (32.12)1.13 (0.63)
1981 4.00 (1.03)2.56 (2.10)28.57 (30.85 )0.64 (0.63)0 --32.57 (31.88 1.11 (0.68)
1982 4.00 2.63 29.63 0.64 0 --33.63 1.12
1983 4.00 2.68 30.84 0.64 0 --34.84 1.10
1984 4.00 2.75 32.11 0.64 0 --36.11 1.11
1985 4.00 2.82 33.44 0.64 0 --37.44 1.12
1986 4.00 2.89 30.40 0.64 4.60 3.14 39.00 1.41
1987 4.00 2.96 27.64 0.64 7.95 3.22 39.59 1.63
1988 4.00 3.03 25.12 0.64 8.31 3.30 37.43 1.73
1989 4.00 3.12 22.84 0.64 11.76 3.39 38.60 1.95
N 1990 4.00 3.18 20.76 0.64 15.08 3.45 39.84 2.20.
N 41.45 3.56 41.45 3.80-Po 1991 0 --0 --
1992 0 --0 --43.14 3.65 43.14 3.89
1993 0 --0 --44.90 3.73 44.90 3.97
1994 0 --0 --46.74 3.82 46.74 4.06
1995 0 --0 --48.66 3.92 48.66 4.16
1996 0 --0 --50.55 4.01 50.55 4.25
1997 0 --0 --52.52 4.11 52.52 4.35
1998 0 --0 --54.58 4.23 54.58 4.47
1999 0 --0 --56.72 4.33 56.72 4.57
2000 0 --0 --58.94 4.46 58.94 4.70
(a)Price assumed comparable to North Cook Royalty gas plus production tax at wellhead and Pacific Rim gas
price set by world oil price CIF.
(b)Includes delivery charge to Anchorage for assuring delivery during cold weather.
(c)Items in parentheses are actual quantities and prices for 1980 and 1981.
1
5.00
4.00
3.00
....u
~--....2.UO
Nco
'".....
1.00
1980 82 84 86 B~90 92 94 96 9H 2000
FIGURE 2.2.Weighted Average Natural Gas Acquisition Cost--Alaska Gas
and Service Company Without Pacific Alaska LNG
For purposes of this analysis,it is assumed that CEA will continue to
draw h~avily on the Beluga River Field up to its contractual maximum take
provisions.At that time (1985)CEA will either negotiate a supplemental gas
supply contract with the Beluga producers or shift generation to capacity
supplied by AGAS,whichever price is lower.(a)In either event,the price
CEA most likely must pay would be the rolled-in price delivered by AGAS
(Table 2.7 plus a gas transmission charge of about $0.26 Mcf).With these
assumptions,the weighted average natural gas acquisition cost for CEA is
developed in Table 2.8 and plotted in Figure 2.3.
(a)Ignoring any differences in electrical transmission costs or plant heat
rates.
2.25
.~~:...~-:...~
1J.::.t [i1!:f1"J'"~JF i.l~i4i...J.cl.J.Or~
b
TABLE 2.8.Estimated Natural Gas Acquisition Cost for Chugach Electric
Association Without Pacific Alaska LNG Plant,1982 $I S ,
0%Inf1at i on
A1ask a Supplemental Gas Weighted
Beluga Gas and Servi ce
$/Mcf(a)
Average Gas
Year Bcf/Yr $/Mcf Bcf/Yr $/Mcf Bcf/Yr Bcf $/Mcf
1980 17.76 0.27 3.95 (3.98)(b)1.34 0.04 )21.71 0.46
1981 18.66 0.26 4.15 (4.65)1.32 (1.20)22.81 0.45
1982 19.60 0.27 4.35 1.33 23.95 0.46
1983 20.57 0.27 4.57 1.31 25.14 0.46
1984 21.63 0.27 4.80 1.32 26.43 0.46
1985 21.90 0.27 5.04 1.33 26.94 0.51
1986 21.90 0.28 5.17 1.62 0.41 1.62(a)27.48 0.54
1987 21.90 0.28 5.31 1.84 1.01 1.84(a)28.22 0.66
1988 21.90 0.30 5.45 1.95 1.62 1.95 (a)28.97 0.70
1989 21.90 0.30 5.60 2.16 2.25 2.16(a)29.7'5 0.78
1990 21.90 0.32 5.75 2.41 2.89 2.41(a)30.54 0.90
1991 21.90 0.32 6.04 4.01 4.84 4.01 32.78 1.53
1992 21.90 0.34 5.35 4.10 5.20 4.10 33.45 1.66
1993 21.90 0.34 6.67 4.18 7.63 4.18 36.20 1.87
1994 21.go 0.36 7.01 4.27 9.13 4.27 38.04 2.00
1995 21.90 0.36 7.36 4.37 10.71 4.37 39.97 2.17
1996 0 7.48 4.46 34.09 4.46 41.57 4.46
1997 0 7.58 4.56 35.65 4.56 43.23 4.56
1998 0 7.69 4.68 37.27 4.68 44.96 4.68
1999 0 7.79 4.79 38.97 4.78 46.76 4.78
2000 0 7.88 4.91 40.75 4.91 48.63 4.91
(a)The minimum price available from AGAS or Beluga Field producers,assumed to be about
equa 1.
(b)Items in parentheses are actual percent and quantities for 1980 and 1981.
2.26
5.00
4.00
.....3.00
~...........
Nco
'"....
1.0
1980 82 84 98 2000
FIGURE 2.3.Weighted Average Natural Gas Acquisition Cost--Chugach
Electric Association Without Pacific Alaska LNG Plant
Pacific Alaska LNG Associates or Similar Project Proceeds
The principal price change introduced by this scenario is to sharply
increase the cost of natural gas provided from the Beluga River Field to CEA
and from the Kenai Field to AGAS.Using the same assumptions as employed in
the previous scenario,the weighted average natural gas acquisition costs are
developed for AGAS (Table 2.9)and CEA (Table 2.10).In this scenario,
Chugach probably does not have the option of negotiating a contract for
supplemental gas from the Beluga River Field producers and must take
supplemental gas from sources such as AGAS or at least at comparable costs.
2.27
TABLE 2.9.Estimated Gas Price -Purchases by Alaska Gas and Service
Company with Pacific LNG Gas,1982 $IS,0%Inflation
Weighted
North Cook ROyalt~A11 Other Gas Total Average ( )
Year Bcf/Yr $/cf BcflVr S/Mcf Bcf/yr Price,$/Mcf a
1980 4.00 (2 .fi8 )(bl 2.50 (1 .•18)27.35 (29.44)0.64 (0.58 )31.35 (32.12)1.13 (0.63)
1981 4.00 (1.03)2.56 (2.10)28.57 (30.85)0.64 (0.63)32.57 (31.88)1.11 (0.68)
1982 4.00 2.63 29.63 0.64 33.63 1.12
1983 4.00 2.68 30.84 0.64 34.84 1.10
1984 4.00 2.75 32.11 0.64 36.11 1.11
1q85 4.00 2.82 34.44 0.64 37.44 1.12
1986 4.00 2.89 35.00 3.65 39.00 3.81
1q87 4.00 2.96 35.59 3.73 39.59 3.89
1988 4.00 3.03 33.43 3.82 37.43 3.97
1989 4.00 3.12 34.60 3.92 38.60 4.08
1990 4.00 3.18 35.84 4.01 39.84 4.17
1991 0 41.45 4.09 41.45 4.33
1992 0 43.14 4.18 43.14 4.42
1993 0 44.90 4.24 44.90 4.48
1994 0 46.74 4.33 46.74 4.57
1995 0 48.66 4.66 48.66 4.70
(a)Includes delivery charge to Anchorage for assuring delivery during cold
weather.
(b)Items in parentheses are actual quantities and prices for 1980 and 1981.
2.28
2.29
3.0 ALASKA COAL
In the context of electric power supplied from a central station utility,
coal-fired thermal generation presents a clear alternative to hydroelectric or
the natural gas/oil-fired generation systems in the Railbelt region.There
are several reasons for consiaering coal:
•Resources within the region are large and can or could be made
available at significantly lower costs (heating value basis)than
oil or natural gas,particularly over the long term.
•The nature of steam coal markets and resources is such that price
escalation over and above general inflation is not expected to be
any higher than for oil and lower than for natural gas.
•Long-term supply contracts can be entered into,thus establishing
relatively predictable future costs.
•National policy certainly encourages coal use in place of gas and
oil,if not outrightly mandating its substitution for these fuels in
large-scale operations.
Two major surface mineable coal reserves are located within the Railbelt
region:the currently producing Nenana Coal Field near Healy (and connected
to the Alaska Railroad),and the Beluga/Chuitna coal fields (not now
producing)remotely located on the west side of Cook Inlet.Other coal
reserves occur on the Kenai Peninsula and in the Matanuska Valley.The former
are in the form of thin,lenticular deposits not suitable for large-scale
mining,and the latter require more costly underground mining techniques.
Still other reserves occur in the lower Susitna Basin and in the Jarvis Creek
area.Little data exist for the reserves in these latter areas,and costs are
speculative.
The Nenana coal field is now being produced by Usibelli Coal Mine,Inc.
at a rate of about 700,000 tons per year (TPY).Coal is supplied by truck to
the near-mine-mouth 25-MW Healy generation plant of the Golden Valley Electric
Association.The Healy plant operates in a base load mode.Additional coal
is crushed and marketed via the Alaska Railroad to the Fairbanks Municipal
3.1
~·----_ii'lll4 _
Utilities System,the University of Alaska,and the military installations at
Clear AFB,Eielson AFB and Fort Wainwright.More recently,the export market
has been tested for the cement/lime industry in Korea via the Alaska Railroad
and the Port of Anchorage.
The Beluga/Chuitna coal fields are in the exploratory and predevelopment
phase.While containing large reserves,these fields are located in a region
with little or no infrastructure and are not likely to be developed unless a
firm market of 1.5-2 million TPY mine-mouth or 5 million TPY export,or some
combination can be established.On an electric power equivalent basis,
1.5-2 million annual tonnage amounts to about 400 MW to 600 MW of baseloaded
coal-fired power generation capacity,or just slightly less than equivalent to
the capacity of the proposed Watana Dam in the Susitna hydroelectric
project.
Should coal-fired power generation become a significant source of
electricity production in the Railbelt,generation capacity would probably be
added in increments ranging from 200 MW to 400 MW.This staging requirement
might or might not,in itself,support opening the Beluga/Chuitna coal fields
for local consumption.Nevertheless,the outlook for developing the
Beluga/Chuitna fields for export to Pacific Rim markets appears favorable.In
addition,Placer Amex Inc.and the Bass-Hunt-Wilson Group,the major
leaseholders in the Beluga/Chuitna region,are pursuing coal-to-methanol
conversion and a direct export mine,respectively.
While the current effort to develop the Beluga-Chuitna fields is mainly
oriented toward large-scale mining (beginning at 5 to 6 million tons per year)
for export,Battelle further explored the possibility of smaller mines with
some of the producers in the Beluga area.One group stated that previous
analysis done by themselves and others indicates that mines serving mine-mouth
power plants might be opened for as little as 0.5 million tons per year.
Furthermore,at 400 MW (about 1.4 million tons per year)a mine-mouth plant
would probably be competitive with other sources of power and a 2 million tons
year contract (600 MW)would be very attractive.These studies have not been
reevaluated in light of more recent knowledge or for generating plants smaller
than 400 MW.Another producer group states the situation a bit differently.
3.2
They agree that a coal mine with contracts for take-or-pay at 2 million tons
per year to a mine-mouth plant would be attractive,as would a 2 to 3 million
tons per year export mine with 2 to 3 million tons mine-mouth sales.There
are circumstances where three-quarters of a million tons per year (enough to
fire a single 200-MW plant)might be attractive enough to open the mine.It
would depend on what additional demand (export and mine mouth)might be
forthcoming,with what guarantees,and with what timing.A 200-~IW plant by
itself mayor may not provide sufficient demand to open a mine in the
Beluga-Chuitna fields.The producers appear divided on this point.
In the base case analyzed in Volume I of the study,200 MW of coal-fired
generation is planned for 1992 at Beluga in Anchorage-Cook Inlet and 200 MW in
Fairbanks-Tanana Valley at Nenana.Conceivably the Nenana plant could be
built at Beluga,if necessary.Even so,the two increments of 200 MW called
for in the base case might be spaced too far apart in time to open the mine in
the absence of an export market.The prospects would be worse at lower demand
in the absence of exports,since only one 200-MW plant might then be needed.
In the plan calling for increased use of coal,600 MW of coal-fired
generating capacity is planned for Beluga between 1997 and 2002,plus another
200 MW at Nenana.This would be enough demand to open a mine at Beluga if the
producers could secure a take-or-pay contract for 400 to 600 MW worth of
coal.The mine could be opened for the first 200 MW of demand if the
producers had ironclad assurances that total deliveries would reach 400 to
600 MW within two to three years.Otherwise,exports could be required.
In any case where exports are required to open the mine,the exports must
be sufficient to pay for shipping facilities.This level of exports is about
4 million to 6 million tons per year without mine-mouth demand for electric
generation.Even with mine-mouth demand,exports would have to total 2 to
4 million tons per year to pay for export facilities.
3.1 AVAILABILITY AND QUALITY
The Nenana field,located on the north slope of the Alaska Range,is
currently producing at a rate of about 700,000 TPY and is operated by the
3.3
Usibelli Coal Mine,Inc.Existing mlnlng capacity is about 2 million TPY and
the present bases could support expansion to 4 million TPY.At this higher
rate,mine life is expected to be about 60 years without significant
depletion.
The quality of the coal is as follows:
Heating Value (coverage)
Ash Content
Moisture
Hardgrove Grindability Index
Ash Softening Temperature
Ash Na 20 Content
Sulfur Content
Nitrogen Content
8000 Btu/lb
7-8%average
11%max.
25-30%
-34.as mined
2100°F
0.08%
<0.25%
0.60%
The surface mineable Chuitna Field (the reference field for the Beluga
region)is located about 12 miles from tidewater on the west side of Cook
Inlet.The mine area would also be about 12 miles (air)from CEA1s existing
Beluga Generation Station and from the point of connection to the existing
transmission corridor to the Cook Inlet load center.
A recent report by the Bechtel Corporation indicates that reserves of 350
million tons can be mined with a cumulative stripping ratio of 4.4 over a
30-year period (Bechtel Corporation 1980).Thus,a mining rate of
11.7 million TPY could be supported without significant depletion of the
reserves that have received the greatest attention.
In order for Chuitna coal to be available for in-state use at a
reasonable price,an export market might have to be established (see
Section 3.0).The outlook for this development appears excellent;however,it
is based primarily on the rapidly growing East Asian markets.In addition,
time is required for mine design,and environmental ana licensing activities.
Based on these considerations,Chuitna coal could be available as early as
1986,but with more certainty by 1988.A decision on proceeding with
development is expected in the early 1980s.
3.4
The run-of-mine quality of coal expected from the Chuitna Field is as
follows:
Heating Value
Ash Content
Moisture
Hardgrove Grindability Index
Ash Softening Temperature
Ash Na 20 Content
Su lfur Content
Nitrogen Content
3.2 COAL PRICE AND ESCALATION
7500-8200 Btu/lb
7-8%
20-28%
20-25
2350°F
0.95%
0.16-0.18%
N.A.
The general approach used to forecast steam coal prices in Alaska is
similar to that used for other fuels such as natural gas and petroleum-based
fuels.That is,future prices are based on recent actual or estimated prices
and then modified for the future based on the concept of an "opportunity
price."This price is that which the seller would receive in the open
market.This approach,therefore,necessitates some understanding of the
steam coal market and price formation factors at least for those coals which
have access to alternative non-Alaskan markets.In this case,these markets
are primarily in East Asia.
A recent study by Battelle-Northwest addressed the steam coal market
outlook on the Pacific Rim (East Asian and U.S.West Coast)in relation to the
potential development of the Beluga Coal Fields (Swift,Haskins,and Scott
1980).That report made several points relevant to this study:
1.Steam coal markets differ substantially from petroleum markets.
Long-term contracts are common in order to accommodate the financing
needs of the producers on one hand,and assure relatively firm
supplies and prices of known-quality coal to the purchasers on the
other.Quite frequently,purchasers seek an equity position in the
producing operation to assure stability.
3.5
2.Market prices are determined primarily by the costs of production
plus profit.This is in contrast to crude oil markets where prices
are established by national oil companies or the host governments in
producing countries.The coal markets are thus generally competi-
tive.High world oil prices provide the major stimulus for switch-
ing to coal but,because of the competitive nature of the market,do
not actually establish coal prices.
3.In turn,the costs of production are determined primarily by the
nature of the mining operation,e.g.,surface versus underground,
and the geologic conditions such as thickness of seams,depth of
overburden,and general terrain conditions.
4.For reasons of transportation costs,Alaska's coal market appears to
be decoupled from the western U.S.market and will more likely be
closely linked by international trade to East Asia,and specifically
to Korea,Japan and Taiwan.In these markets,Alaskan coal will
compete primarily with coals from Australia,South Africa,Canada,
The People's Republic of China,and Western Canada.Due to high
domestic rail transportation costs,western U.S.coals are not
believed to be major long-term competitors.
5.Steam coal trade on the Pacific Rim is in its infancy with no
well-established patterns as yet.Despite this,growth is expected
to be dramatic as illustrated in Table 3.1.This has been brought
about primarily by the high cost of the imported oil and liquefied
natural gas,both of which can be displaced by coal,given adequate
time for installation of new coal-fired plants.
6.Despite price disparities between different suppliers,coal
purchasers and governments,e.g.,Japanese electric power utilities
and the Ministry of International Trade and Industry,appear to have
taken the position that diversity in sources of supply is worth some
cost penalty.In fact,it now appears that despite significant
differences in coal costs,market shares for supplying countries
will be determined more by policy decisions and less by pure
economic considerations.
3.6
TABLE 3.1.Preliminary Projections of Stefm)coal Imports
by Country and Year (DOE 1981)a
Million Tons Per Year
197':1 1985 1990 2000-- ----
Japan 2.8 26.4 50.4 103.2-123.7
Korea 6.2 9.6 16.8 52.3
Taiwan 5.5 3.7 16.8 43.3
Hong Kong N/A 4.8 9.6 12.0--
Total 14.5 44.5 93.6 210.8-231.3
(a)Data adjusted to 11,500 Btu/lb coal by Battelle,Pacific
Northwest Laboratories.
7.If the major East Asian coal-importing country,i.e.,Japan,adheres to
its announced policy of source diversification and includes the U.S.as a
supplier,then Alaskan coal,particularly from the Cook Inlet region,
could capture a major percentage of the U.S.exports to the Pacific Rim.
This is because western U.S.coal fields have high overland
transportation costs.
In addition to the question of whether Alaskan coal will enter
international trade,the problem in forecasting future price lies in the
fact that there is little market precedent in the Pacific Rim.Steam
coal trade to date has been minuscule relative to its expected future
levels;prospective purchasers in East Asia have had little experience
with coal-fired plants;standards for contractual arrangements including
equity participation in producing operations and infrastructure have not
been worked out and tested.
Regardless of the above problems,it seems reasonable to expect that the
Pacific Rim market will eventually function in a manner similar to the U.S.
domestic market except that targets for diversified supplies will be set as a
matter of policy rather than simply economics.With that exception,it
appears that competitive market forces will prevail at least once an initial
base contract price is established.
3.7
Because of the joint necessity for long-term contracts (10 years)on the
part of both sellers and buyers,it seems likely that a contract for Alaskan
coal will start with a negotiated base price established largely on the cost
of production and delivery plus a reasonable rate of return.Clauses will be
included to cover production cost increases or decreases due to changing
mining conditions (e.g.,geology),regulatory and tax changes,and labor and
other cost factors.
In addition,it seems reasonable that the producers (including the equity
participation by the purchaser)will require some marketplace clearing
mechanisms.That is,they will require contract provisions that link the
prices they receive for their coal to at least the changes in the landed cost
of coals supplied from other sources.(a)Such terms are comparable to those
currently applied to agreements for purchases of other energy commodities such
as LNG and LPG.
3.2.1 Beluga/Chuitna Coal
Based on the above information ana assumptions,the rationale for
forecasting future prices of Alaskan steam coals (particularly those strongly
tied to other markets)is shown diagrammatically in Figure 3.1.The process
starts with estimates of coal supply functions (prices as a function of
production rate)for steam coals for each of the sources of supply competing
with Alaskan coal.These estimates are shown in Figures 3.2,3.3,and 3.4 for
supplies FOB dock Australia,South Africa and Canada,respectively.All
prices are expressed in 1982 U.S.dollars and are based on composite supply
functions for each country as shown disaggregated in Swift et al.'s Beluga
Coal Market Study.A separate estimate for Wyoming coal (the steam coal from
the contiguous United States believed most likely to be part of large tonnage
contract exports)is not shown,as the nature of the reserves points to an
essentially flat supply function.However,in general,essentially all supply
(a)Linkage to absolute cost levels (the free market approach)appears unlikely
because of the policy decision to pre-establish target market shares.
3.8
ESTIMATE COAL SUPPLY
FUNCTIONS BY EXPORTING
COUNTRY(l)
~
ESTIMATE TOTAL ESTIMATED FOB C~ST OFPRODUCTIONBY..COAL BY COUNTRY 3COUNTRYOFORIGIN(2)
!
ESTIMATED COST OF ESTIMATED LANDEDTRANSPORTATIONBY..COST OF COAL IN PACI FICCOUNTRYOFORIGINRIMBYCOUNTRYOFORIGIN(3,4)
~ESTIMATED PACIFIC RIM ESTIMATED WEIGHTEDMARKETSHAREBY..AVERAGE LANDED COST (3)COUNTRY OF ORIGIN OF COAL IN PACIFIC RIM
~ESTIMATED COST OF ESTIMATED ESCALATIONTRANSPORTATION,ALASKA ..RATETOMARKET
(1)Price as function of production rate
(2)Production rate as function of time
(3)Price as function of time
(4)Japan used as proxy
FIGURE 3.1.Procedure for Estimating Steam Coal Price
Escalation -Pacific Rim Markets
3.9
:a :II
1.50
:3...I 1.00....-'"!
0.50
-'WI
o 50 100
MMTPY
150 200
FIGURE 3.2.Composite Export Steam Coal Supply Function FOB Australia
1.00
:3...a>0.80I....-'"~...
0.60
0 50 100
MHTPY
150 200
FIGURE 3.3.Composite Export Steam Coal Supply Function FOB South Africa
3.10
1.80
1.60
::::l
.j.J
a:l~
~1.40.........
-b<)-
Ncoen-
1.20
o 50
MMTPY
100
FIGURE 3.4.Composite Export Steam Coal Supply Function FOB Canada
(British Columbia)
curves show upward trendS as production rates increase.This comes about as
each new increment of production capacity encounters more costly mining
conditions,i.e.,the marginal cost of production rises in real terms.
Next,estimates of total steam coal (of a grade likely to be exported)
production rates over time are applied to the supply functions to estimate the
future cost of coal FOB the producing country.The production rate estimates,
shown in Table 3.2,are based on recent U.S.DOE forecasts that draw on a
large number of estimates from domestic and foreign sources.
The findings of this stage of analysis are depicted in Figure 3.5.The
range of future prices illustrates the uncertainty introduced by possible
bands of production rates.Australian coal prices,though starting at the
lowest level in 1985,increase more rapidly than others because of a
combination of marked increases in expected production rates,coupled with
moderate upward increases in costs of production.
3.11
•I Ie
TABLE 3.2.Estimated Total Export Steam Coal Production for
Non-U.S.Countries Serving the Pacific Rim Markets
(DOE 1981)
Million Ton Per Year
1985 1990 2000
Australia 15-20 35-40 75-120
South Africa 40-50 60-70 80-180
Canada 4 4-10 4-24
Market shares (for producing countries)are then entered to yield the
weighted average landed cost of steam coal delivered to Japan,which is a
proxy for the Pacific Rim market as a whole.Estimated market shares are
shown in Table 3.3 based on DOE studies.
Finally,the expected future costs of transportation to the Japan proxy
market from Alaska are backed out from the weighted average landed "cost from
other major competitors to provide a "net-back"price to Cook Inlet.Not all
potential suppliers are shown,primarily because of the absence of cost or
price data for mainland China or Russia.Nevertheless,the results should be
indicative and are given in Table 3.4.
These results show an initial price at mine-mouth of $1.29/MMBtu for
shipments beginning 1985,with a real escalation rate of 2.1%over the period
1985 to 2000.This compares to recent discussions with the Bass-Hunt Wilson
group,which indicate that the run-of-mine price of coal at mine-mouth is
expected to be about $1.17/MMBtu in January 1981 dollars or $1.28/MMBtu in
1982 dollars.It must be recognized that these estimates are based on
production costs and therefore represent a minimum estimate of price.
It is also useful to examine the actual prices of steam coal in the
Pacific Rim.A sampling of 1980 spot prices for steam coal CIF Taiwan from
Coal Week International yields a price of Sl.66/MMBtu ana early 1981 spot
prices CIF Taiwan were $2.41.This is a rather sharp increase in price and
may not be indicative of the long-term trend as steam coal suppliers are
better able to meet the growing demana for steam coal.The average price of
steam coal CIF to Japan was S2.18/MMBtu for 1980 assuming 12,000 Btu/lb and
about $2.15/MMBtu in early 1981.
3.12
2.10
2.00 Wyomi ng
1.80
Australia
_--------£South Af'rlca
~
1.00
0.80
1.60
~
~co
::E
I Canada
::E 1.40........
I-b"to
&'Ncoen.....
1.20
0.60
1980 1990
YEAR
2000
FIGURE 3.5.Estimated Coal Prices FOB Port of Origin
3.13
•11$a
TABLE 3.3.Market Share of Steam Coal Trade in the Pacific Rim
(DOE 1981)
Percent
South All
USA Australia Africa China Canada Others
Japan
1985 15 30 20 15 10 10
1990 15 30 20 15 10 10
2000 25 25 10 12 12 16
South Korea
1985 50 50
1990 50 50
2000 50 50
Taiwan
1985 20 60 20
1990 20 60 20
2000 20 60 20
Hong Kong
1985 25 25 25 25
1990 25 25 25 25
2000 25 25 25 25
These recent prices can be adjusted to Alaska using an approximate
shipping fee from Alaska to Taiwan of ~0.60/MMBtu and to Japan of ~0.50/MMBtu,
and an approximate cost of ~0.20/MMBtu from the Bechtel study to move the coal
from the mine to the post.This provides a net-back price from Taiwan of
about ~1.60/MMBtu and ~1.45/MMBtu from Japan.A simple average of these two
would peg the Beluga mine-mouth price at about $1.53/MMBtu in early 1Y81 or
about $1.66/MMBtu in January 1982 dollars.
The difference between the predicted production cost estimate
(51.29/MMBtu)and the estimated net-back price in the current market
($1.66/MMBtu)is about $0.37/MMBtu.This is a relatively small range given
that there are no coal exports at present and that both numbers are estimates
3.14
~.
l
1
I
I
I:
TABLE 3.4.Steam Coal Prices Landed in Japan and Net-Back
to Alaska (1982 S/MMBtu)(Swift~Haskins~and
Scott)(DOE 1981)
~
Country of Origin 19S5 1990 2000
Australia 1.30 1.46 1.83
Market Share %30 30 25
Canada 1.88 1.92 2.03
Market Share %10 10 12
South Africa 1.64 1.77 1.96
Market Share %20 20 10
U.S.(other than(A~aska)2.99 3.16 3.30
Market Share a 15 15 25
Weighted Average Landed 1.81 1.95 2.41
Less Transportation Cost
From Alaska 0.51 0.56 0.64
Net-Back 1.29 1.39 1.77
Escalation Rate %/Year 1.6%2.4%
(a)U.S.market share of Japan coal markets adjusted
to reflect only non-Alaskan coal~Wyoming source
assumed.
based upon different sets of information.This analysis will average the two
prices to arrive at a mean price of SI.48/MMBtu with the two estimates
representing the high and low prices.
The escalation rate of 2:1%for the period 198b to 2000 is felt to be a
reasonable estimate of the future behavior of steam coal prices.During the
1970s~steam coal prices to utilities in the "lower 48"escalated at slightly
over two percent.In addition~a number of organizations have forecasted real
increases in coal prices of around two percent.
3.10
•P4 .."n:auil
3.2.2 Nenana Field Coal
Unlike Beluga/Chuitna field coal,further consumption of Nenana field
coal for power generation is expected to occur not at mine-mouth but rather at
siting areas along the Alaska Railroad right-of-way.(a)Thus,delivered
costs of coal will include rail transportation costs.
Based on discussions with M.Joseph Usibelli of the Usibelli Coal Mine,
Inc.,the base price of coal (1st Qt 1980 dollars)should be 51.20/MMBtu FOB
rail cars at Healy or Sl.43jMMBtu in 1982 dollars.The real rate of price
escalation for this coal is pegged at an annual rate of two percent although
information from Usibelli indicates that the rate of price increase may be
lower.The real escalation of this coal,as measured by the producer price
index,was about two percent per year from 1965 to 1980 and at an annual rate
of 4.1%from 1974 to 1980.On the other hand,a more highly mechanized
dragline operation is in place and Usibelli has indicated that as equipment
utilization increases as a result of higher production rates,the price may
decrease about 8%at a production rate of two million TPY.The likelihood of
a low or even zero price escalation is confirmed somewhat by the terms and
conditions of the contracts for supply to the Golden Valley Electric
Association and the Fairbanks Municipal Utility System.These contracts
(which expire in 1988 and 1986,respectively)provide for cost increases
indexed to a Producer Price Index (Industrial Commodities).However,price
behavior at the end of this contract cannot be predicted and the 2 percent
real rate for the entire forecast period is felt to be a safe assumption.
The Alaska Railroad has advised that tentative rates for scheduled
unit-train movements of coal from Healy to various sites along the railroad
will be as follows based on railroad arrival cars:
(a)The existing 25-MW Golden Valley Electric Association Healy plant is
recognized.However,for purposes of conservative cost estimation,it is
assumed that further larger scale generation sites will be located so as
to avoid conflict with the Prevention of Significant Deterioration clauses
of the Clean Air Act as a result of proximity to Denali National Park.
3.16
..
Adjusted to
Location ~/ton (1980 basis)1982 ~
Nenana 4.25 5.05
Willow K 6.50 7.72
Matanuska 7~70 9.15
Anchorage 8.90 10.57
Seward 10.00 11.88
Future costs would be subject to escalation using the Association of
American Railroad's Cost Index.For purposes of this analysis it is assumed
that any real transportation cost increase will be associated with fuel costs
(expected to increase 2%per year),which amount to about 30%of rail haul
costs.Converting to ~/MMBtu,the above analysis results in the following
estimated delivery price for coal supplied in year y.
Location 1982 ~/MMBtu
Nenana 0.22 +0.09 (1.02)x
Willow 0.34 +0.14 (1.02)x
Matanuska 0.40 +0.17 (1.02)x
Anchorage 0.46 +0.20 (1.02)x
where x =y-1980
3.17
4.0 PEAT
Peat is defined as geologically young coal.It consists of partially
decomposed plant matter ~nd inorganic materials that,over time,have
accumulated in a water-saturated environment.Peat has been used as a fuel
resource in Northern Europe and the Soviet Union.Other countries,including
Canada,the United States,Sweden and West Germany,have active peat fuel
research programs.Primarily because of the availability of lower-cost fuels,
there has been little use of peat in the United States as a fuel resource.
There are a number of recent and current studies to assess the resource
potential and fuel availability of peat in several areas of the country,
including Alaska.A preliminary resource assessment of peat in the state,and
harvesting methods and costs for other locations are used to develop the
information for this chapter.
4.1 AVAILABILITY
A preliminary assessment (Northern Technical Services and EKONO 1980)
(EKONO 1980)of peat resources in the Railbelt identified bogs in the
Matanuska-Kisitna Valley as potential sources of peat fuel,although
comprehensive estimates of resources or reserves were not offered for these
bogs.Information obtained indicates a lack of continuous high-quality peat
resources with sulfur,nitrogen and ash content higher than Alaskan coals if
compared on an energy equivalency basis.The prevailing quality problem is
ash content;only 36%of the peat samples analyzed for ash had less than 25%
ash content,the limit for peat fuel as specified by the U.S.Department of
Energy.The study recommended further site-specific investigations in order
to assess the time-energy potential of peat resources in the Railbelt.
The report considered five sites for more detailed consideration.These
bogs met DOE criteria of a minimum five-foot depth,8,300 Btu/lb dry weight,
and access did not pose a significant problem.These bogs were identified as
Nancy Lake West,Rogers Creek,Mile 196 West,Nancy Lake East and Stephan
Lake.The information developed provides an indication of fuel quality and
bog depth,but relatively little information regarding bog size.Of the bogs
4.1
1
1
I
mentioned only about 1,000 acres of the Nancy Lake East bog were evaluated for
volume and fuel quality.The total area of the Nancy Lake East bog that
contains fuel-quality peat with some consistency is estimated at 3,500 acres.
The high cost of transporting peat is another factor limiting its use as
a fuel.Thus,peat-fired generation units are generally proposed for bog-site
operation.Given the above lack of knowledge about the resource base and
overall quality of the resource,the Nancy Lake East site appears to be one of
the more suitable.If the entire bog (3,500 acres)with an estimated average
depth of seven feet containea fuel-quality peat,it would provide fuel for a
30 MW cogeneration plant for about 15 years.Although this is based upon less
than complete information about the peat resource,it indicates that
large-scale (100 MW and up)generating facilities could probably not be
supported by the peat resource supplied from a single bog.
4.2 PRICE
Before a price for peat fuel is presented,it is useful to examine
briefly the harvesting and fuel preparation methods.Peat harvesting is
conventionally done by milling or sod methods,where only a five-to-eight-inch
thick layer is removed from the bog each year.This requires that a large
area be cleared and drained to provide an adequate volume of peat and a
sufficient drying area.Hydraulic harvesting is an alternative method;the
area to be harvested is cleared and the peat is removed by backhoe or some
other mechanical means.Bog waters have a higher acidity level than
surrounding lakes,rivers and streams and drainage of these waters could pose
an environmental problem to the surrounding waters.
Once harvested,the peat is processed to reduce the moisture content in
order to produce a suitable fuel.Current harvesting methods rely on solar
and convective drying to reduce the moisture content from a level of
approximately 80 to 90%in its natural state to 30 to 55%.The actual
combustion requires further reduction in the moisture content to 10 to 25%,
depending on the boiler configuration.This may be achieved by recirculated
flue gas or hot air for pulverized (fuel peat)peat used for direct combustion.
4.2
Harvested peat may also be processed to produce pellets or briquettes.
Preparation involves blending,crushing and screening of the peat prior to
drying and compaction.The pellets or briquettes are of a uniform size and
shape for combustion in grate-fired boilers,fluidized bed combustion systems
and peat gasification systems.Another peat fuel preparation process known as
wet carbonization is able to by-pass the air-drying stage and uses
hydraulically harvested peat to produce a pelletized fuel.
The cost of delivered peat is dependent on both the distance required to
transport the peat and the harvesting method employed.A breakdown of costs
of delivered peat for various harvesting-processing operations is shown in
Table 4.1.Peat,delivered over an economically short distance at 50%
moisture content to an Alaskan power plant,has been estimated to cost between
$1.60 and ~4.20/106 Btu (EKONO,1980).If the peat is processed into
pellets or briquettes,the cost is estimated to run between S3.40 and
6~5.20/10 Btu.
TABLE 4.1.Cost Estimates of Peat-Based Fuels,1980 Dollars
(EKONO 1980)
Process Method
Mi~led peat,400,000 tonla @ 50%moisture,
bog area requirement 5,000-6,800 acres
Sod peat,60,000 tonla @ 50%moisture,bog
area requirement 1,000-1,300 acres
Fuel peat,27,000 tonla @ 50%moisture,
hydrauliclmechanical harvesting
Peat pellets,30,000 tonla @ 10%moisture,
hydrauliclmechanical harvesting
Peat briquettes,30,000 tonla @ 10%moisture,
bog area requirement 800-1,100 acres
Peat fuel from wet carbonization 250,000 tonI
a @ 5%moisture,hydraulic harvesting
4.3
Energy
Cost
S/MMBtu
$1.60 -2.30
2.90 -4.20
1.95 -2.40
3.40 -4.80
4.20 -5.20
2.70 -4.20
.------II1II::II1II::•••••••••••_~~
Larger milled peat harvesting operations producing 1 to 6 million tons of
peat per year have been estimated to provide peat at $0.75 to $1.05/106 Btu.
Hydraulic harvesting of one million tons per year,with mechanical dewatering
and thermal drying to 50%moisture content,is estimated to cost about
$0.83/106 Btu (Punwani 1980).Such large operations woula be capable of
supplying fuel for 120 to 700 MW power plants.However,it should be noted
that preliminary information regarding the resource base does not indicate
bogs of sufficient area to sustain operations of this range in Alaska.
Because of the capital-intensive nature of harvesting ana fuel
preparation,escalation of peat-based fuels is expected to be connected
primarily with other fuel used in the production process.The result is a
relatively low escalation rate in peat fuel prices since other fuel inputs,
such as diesel fuel for operating harvesting equipment,is only one of three
general production inputs,i.e.,capital,labor and fuel.
4.4
5.0 REFUSE-DERIVED FUEL
The analysis of refuse-derived fuel (RDF)for the Railbelt region is
based upon two recent reports (Metcalf and Eddy/Engineers 1979)(Black and
Veatch 1980)and with discussions held with the staff of Solid Waste Divisions'
of the Municipality of Anchorage and the North Star Borough.Due to the high
cost of collection,consideration of RDF for electric power generation at a
significant scale is necessarily limited to metropolitan areas where the
sources of refuse are more concentrated.Thus consideration is given only to
the Anchorage and North Star Borough solid waste disposal areas.The
Anchorage area includes the Municipality,Fort Richardson,Elmendorf Air Force
Base,Eagle River-Chugiak,and Turnagain Arm.
5.1 AVAILABILITY
The quantities of municipal waste available in 1980 for the two
metropolitan areas were:
Anchorage
Fairbanks
161,000 tons per year
(136,000 after classification)
50,000 tons per year
(42,000 after classification)
Future quantities are expected to occur roughly in proportion to population in
each of the areas.
One significant problem with RDF is that it is not produced at an even
annual rate.For example,1980 data for Anchorage indicate that the ratio
between the peak (August)and the lowest (February)supply month is about
2:2.Since RDF cannot be stored for any considerable length of time,its use
very likely must be combined with a supplemental fuel.This appears to be the
concept involved in the Black &Veatch study for Fort Richardson.
The heat content of shredded and air classification RDF is typically
6,700 Btu/lb.Shredding and air classification is necessary to remove glass
and ferrous and nonferrous metals that would otherwise be deleterious to
furnace performance and operating reliability.
5.1
··*411#11#14
The quantities and heat content data can be placed in perspective by
estimating the amount of base load power generation the RDF streams could
support under annual average conditions.Based on a 80%base load plant
factor,a heat rate of 12,000 Btu/kwh (low heating value solid fuels result in
increased heat rates),and the above 1980 RDF quantities and heating values,
the following power plant capacities are calculated:
.,
Anchorage Area:
Fairbanks
21.7 MW
6.7 MW
Again,it is anticipated that a larger scale plant would be used and refuse
would be supplemented with another fuel.
From an environmental standpoint,it may be difficult to site an RDF
fired power plant within the metropolitan areas.This would impose an
additional cost to the use of RDF.Although no specific data are available,
RDF woulc be expected to contain greater percentages of sulfur and nitrogen
compounds than high-quality coal.
5.2 PRICE
RDF is not assigned a price in the typical sense because it is a negative
good and people are willing to pay to dispose of refuse.Disposal costs in
Anchorage in 1981 of $65.28/ton of refuse include the collection and disposal
at the existing shredder plant landfill.Shredcer processing and landfill
disposal account for about $IS/ton.As mentioned aboved,the existing
shredder facility would require modification in order to classify the refuse
so that the fuel would be free of glass and metal objects.The Metcalf and
Eddy report does not deal with the collection aspect of refuse disposal,but
does provide estimates for shredding and disposal.Estimated operating and
disposal costs for the current facility were stated at $19.90/ton 1980 dollars
and at $14.54/ton for the modified facility.Although there was an increase
in operating costs (labor,maintenance and electricity)of the modified facil-
ity,there was a greater decrease in the cost of residue removal and landfill
because of the smaller volume of refuse ultimately disposed of.This results
in an estimated reduction of about $5.36 in the disposal cost of refuse.
5.2
Before proceeding,the $19.90 shredding and disposal cost estimated in
the Metcalf and Eddy report exceeds the $15.00 cost provided by the City of
Anchorage.For purposes of estimation,it is assumed that the current $15.00
shredding and disposal cost would be reduced proportionately to the estimates
in the Metcalf and Eddy study,27 percent.The reduction of about $4.00 is
then interpreted as the reduction in overall cost of refuse disposal,given
that the produced RDF is used for firing a boiler and less waste material is
hauled to the landfill.It must also be noted that the cost reduction does
not include transporting the RDF to a boiler site.The estimated cost of
moving the RDF from the shredding facility to either the Fort Richardson
boiler or a new boiler located next to the Chugach Steam Generating Plant is
about $3.50/ton in 1981 dollars.Given the error of estimation this
approximately offsets the cost savings of disposal.
In net,the total cost of refuse collection and disposal would decrease
from $65.00 to about $61.00/ton in 1981 dollars.These estimates provide a
range of values for the produced RDF.The high end of the range is derived by
assuming that the current collection and disposal fee of $65.00/ton is
maintained.In this case,refuse producers would be indifferent to landfill
disposal or the production of RDF.Thus the S4.00 cost reduction could be
paid to the user of the RDF to provide an incentive to use the refuse as
fuel.Although,as noted above,this amount would probably be sufficient to
cover transportation of the RDF to the likely site for combustion.This then
sets the minimum value of RDF at zero.The other extreme would be to assume
that the RDF user would pay the full cost of collection and preparation or
about $61.00/ton.This amounts to about $4.55/MMBtu.This is higher than the
price of either natural gas or coal delivered to the Anchorage area.
The maximum amount a user of RDF would be willing to pay may be obtained
by comparing the cost of generated electricity from another fuel and backing
out the additional capital,operating and maintenance costs of a RDF-fired
facility.This information is not available,but an estimate is available for
conversion of the Fort Richardson boiler facility to handle RDF.Including
RDF transport from the shredding facility to Fort Richardson,the cost of
conversion was about S19.82/ton in 1981 dollars or about $1.50/MMBtu.This is
5.3
~.
.." $4ii$:M 2i2
interpreted as a penalty for refuse fuel so that its value is about
~1.50/MMBtu less than the price of competing fuels.This penalty may be less
or greater,depending upon the cost of modifying other facilities (new or
existing)to handle RDF.
The marginal cost of natural gas in the Anchorage area is about
~2.00/MMBtu and about ~1.70/MMBtu for coal,both in 1982 dollars.Correcting
the $1.50 penalty for RDF to 1982 dollars provides a penalty of about
$1.65/MMBtu.Given the accuracy of the estimates,the value of RDF delivered
to purchasers equals zero since the boiler modification cost equals the cost
of the least-cost alternate fuel.The uncertainty of firing generators with
RDF may even attach a negative value to it,meaning that RDF users would
accept it only if they were compensated.Provided that the same cost
structure for power plant conversions for RDF utilization exist in the
Fairbanks area,RDF would compete with coal which is priced at about
$1.40/MMBtu in 1980 dollars.Again,given the accuracy of the estimates RDF
would have a value near zero.
Although no mention of the value of RDF was made in the Metcalf and Eddy
study,several other conclusions of RDF utilization were noted.
1.The most practical and economical alternative is to convert the Fort
Richardson boilers to co-firing of coal and RDF.The RDF would be
produced at the municipality's shredding facility,as modified.
2.Military participation in this alternative,i.e.,hauling their
refuse to the municipality shredding facility,could result in
slightly higher overall costs to the military bases.
3.At present,the only materials that could be profitably recovered
from Anchorage area refuse are aluminum and computer tab cards.
Most scrap iron,steel,copper,and lead in the Anchorage area is
already being recycled by scrap metal brokers.The markets for
other materials are too uncertain to make their recovery feasible.
Battelle's conclusions are similar but with the following additions and
observations:
5.4
1.The motivation to use RDF would appear to derive principally from
costs and land use problems associated with sanitary landfill
disposal rather than from power generation considerations.
2.If environmental (air quality)requirements can be met for the
Anchorage Air Quality Control District,conversion of the existing
Fort Richardson boilers to RDF firing may be attractive,although
some derating could be experienced.We note that the Fort
Richardson boilers were installed in the very early 1950s and are
now approaching the end of normal useful life from an electrical
utility standpoint.
3.The Fort Richardson plants are cogenerators with a major function
being the supply of steam space heating to the base.Electric power
for civil use (off base)is incidental.Consequently,their
contribution to civilian power requirements in the Railbelt would be
negligible.
4.The quantity of RDF potentially available in the Fairbanks region
appears inadequate to support a significant scale civil operation.
Applications in the coal-fired plants (20 MW)at Fort Wainwright are
a possibility but at a higher expected fuel cost.
5.5
6.0 NORTH SLOPE NATURAL GAS
This chapter examines the quantity and price of North Slope natural gas
that would be available to the interior of Alaska (Fairbanks load center)via
the Alaska Natural Gas Transportation System (ANGTS).Recoverable natural gas
reserves in the Prudhoe Bay region are currently estimated at about 29 trillion
cubic ft (Tcf),most of which lie in the Sadlerochit formation.These
const itute about 11%of tota 1 U.S.recoverab le reserves in comparison to the
3.8 Tcf of recoverable reserves in the Cook Inlet region.Production from
Prudhoe Bay is targeted to be in the range of 2 to 2.4 Bcf/day,and the ANGTS
has been designed to handle these rates of flow.
Delivery of North Slope gas to the Alaskan interior depends on the market
for the gas in the contiguous United States and the completion of the ANGTS.
Three important,interdependent issues will greatly influence investors'
decisions to participate in the project:
•the status of gas deregulation
•the pipeline tariff structure and price of delivered gas
•the waiver package recently passed by Congress.
All three issues affect the competitiveness of North Slope gas delivered to the
IIl ower 48".
Given,that the System is completed on schedule,natural gas would begin
flowing in 1986 or 1987.The interior could then expect supplies equal to at
least the state1s 12.5%royalty share of gas.This would amount to 91 to 114
Bcf/yr of North Slope gas available for in-state consumption.
6.1 AVAILABILITY
The availability of North Slope natural gas to the interior and the
Fairbanks load center depends,first,on whether the ANGTS will be constructed
and,second,on the timing of gas deliveries from the constructed system.
Portions of the gas pipeline from Prudhoe Bay to the "lower 48"are
already under construction.The ANGTS is composed of five separate pieces,at
6.1
~..
least for reference purposes.These are the conditioning plant,the Alaskan
segment,the Canadian segment,the Eastern leg,and the Western leg.Portions
of the Canadian,Eastern and Western segments have been completed or are under
construction.These segments are being completed with the intention that they
will carry Canadian and other gas regardless of whether the entire system is
completed.
The Alaskan segment and the conditioning plant are in question because of
the cost of these portions of the line.Several estimates of the cost are
available.One recent estimate shows the conditioning plant and the Alaskan
segment will account for about 63%of the system's total cost of $23 billion in
1980 dollars.excluding interest and inflation (Office of the Federal Inspector
1981).The backers of the pipeline are having some difficulty raising
sufficient financing to complete this portion of the project.
Prospective investors are uncertain whether North Slope gas is'saleable in
the "1 ower 48."This uncertainty is due primarily to the expected price of
de 1i vered gas and the 1eve 1 of gas pri ces in the II 1ower 48.11 The current
estimate of delivered gas in 1987 is about $16/MMBtu in nominal dollars or
$9/MMBtu in 1980 dollars (Office of the Federal Inspector 1981).Although
rolled-in pricing is currently permitted for this gas,which makes it more
attractive,it is unlikely that rolling in will be an attractive option in 1987
because of changes in gas price regulation.The current gas decontrol formula
is criticized because it will result in a sharp increase in gas prices in 1985,
as the decontrol formula is based on oil prices of about $16/bbl.Under the
eXisting decontrol scheme,which is.in effect,partial decontrol,it is
estimated that decontrolled wellhead prices would be about twice their
controlled level--in the range of $7/MMBtu in 1985 dollars (Chemical Week
July 1981)or about $5/MMBtu in 1980 dollars assuming a 7%inflation rate.
The alternative complete decontrol scheme being pursued by the Reagan
Administration is predicted to result in a market clearing price of
about $4.50/MMBtu in 1980 dollars (Oil and Gas 1981;Stuart 1981,Platts
Oilgram News 1981).Both of these prices are far below that seen for the
North Slope gas.An article in Fortune (Stuart 1981)reports that there is
6.2
plenty of drilling activity for deep decontrolled gas,some of which is selling
at over $9/MMBtu.At the same time exploration for controlled gas is lagging,
thus suggesting that there is plenty of gas to be found at prices nearer $4.50
to $5.00/MMBtu.
Backers of the ANGTS are concerned that the pipeline might not proceed
under the total decontrol scenario.Given the level of prices predicted for
partial or total decontrol,it is difficult to imagine that the project would
proceed in either case.However,backers of the pipeline continue to seek
support in order to complete the project.Several issues may give them reason
for hope.The first is that the decontrol question is not settled;Congress
may extend controls on gas to avoid the sharp price increases that would likely
occur in 1985.This would permit the high cost North Slope gas to be rolled-in
with other lower-eost supplies.
A second reason for hope is the waiver package recently passed by
Congress.This package has several important provisions that could affect the
willingness of investors to participate in the project.One provides for
including the conditioning plant in the pipeline tariff,which would guarantee
that the investment would receive the same rate of return as the rest of the
pipeline and would not be subject to negotiation along with the wellhead price
of gas.Another provision allows North Slope gas producers a position of joint
ownership in the project.The third provision allows advance billing of "l ower
48"customers for completed portions of the pipeline.This would reduce the
future level of the pipeline tariff and the price of delivered gas.
The third issue centers on the pipeline tariff structure,which will have
the strongest influence on delivered gas prices.The tariff could be
structured such that it would be set at a low level and be allowed to increase
over time rather than use a decreasing or constant schedule.However,
investors might hesitate to participate under such an arrangement,because they
would not realize their return in the initial years of operation and so might
opt for other investment opportunities open to them.
Whether the pipeline will proceed given the eXisting situation is
uncertain.If the pipeline does proceed,it would be capable of transporting 2
6.3
,..akAw iili"An.
to 2.4 Bcf/day,and current permits set capacity at 2 Bcf/day.The state1s
12.5%royalty share of gas would provide up to 250 MMcf/day of gas to the
interior,which is viewed as sufficient to serve expected needs in the region.
If the current schedule is maintained,such deliveries would begin in 1986 or
1987.
6.2 PRICE
The first year delivered price of North Slope gas to the "lower 48"is
projected to be about $16/MMBtu in 1987 nominal dollars or about $9/MMBtu in
1980 dollars,including conditioning and the maximum wellhead value.Using the
implied escalation rate of 8.6%,this works out to about $10.60/MMBtu in 1982
dollars.Conversations with FERC indicate two options to pricing this gas for
the Alaskan market.The first is that Alaskan customers pay the full cost in
service or the same price as "lower 48"customers.The second and !'lore likely
option is that the price be netted back to the Alaskan market,and Alaskan
customers therefore pay less than the "lower 48"customers.This analysis
assumes that the second option will be implemented and develops the net-back
price and the escalation rate that would exist.
The net-back procedure first allocates the delivery fee to each segment of
the line,with the gas conditioning plant at Prudhoe Bay treated as one
segment.Then a mileage ratio for the Alaskan segment would be used to
allocate the Alaskan portion of the tariff.Finally,the delivered price would
be the sum of the wellhead price,the conditioning share of the tariff,and the
mileage-based share of the tariff apportioned to the Alaskan segment.
The figures for apportioning the tariff among the five segments are listed
in Table 6.1.The $10.60/MMBtu delivered price in 1982 dollars shown above
includes transmission costs and the maximum wellhead value of the gas,which is
$2.13/MMBtu in January of 1982;the net provides the conditioning and
transmission fee of about $8.47/MMBtu.The first calculation is to assign 16%
of the conditioning and transmission charge ($1.36/MMBtu)to all customers to
cover the conditioning segment--the rationale being that the gas must be
6.4
conditioned regardless of the point of consumption.The second calculation is
to assign 47%of the total transmission charge ($3.98/M~~tu)to the Alaskan
market as the Alaskan segment comprises 47%of the total ANGTS cost.This
amount is then fractioned on a mileage basis to the point of delivery in-
state.This analysis assumes that the point of delivery is Fairbanks,which is
about 450 miles down the approximate 740 miles of the Alaskan segment.This
mileage fraction,61%,provdes for the in-state transmission fee of about
$2.43/MMBTU.
TABLE 6.1 Tariff by Segment of ANGTS
Segment
Conditioning Plant
Alaskan Segment
Canadi an Segment
Eastern Leg
Western Leg
Estimated Cost )
(Billion 1980 $)(a
3.6
10.8
5.8
1.9
0.9
23.0
Share of
Total cost
16%
47%
25%
8%
4%
100%
(a)Excluding interest and inflation
The total of the conditioning share and in-state transmission fee
provides a minimum first-year price of about $3.79/MMBtu to the Fairbanks area
at a zero wellhead price,and a maximum price of $5.92/MMBtu at the maximum
allowable wellhead price of 2.13/MMBtu.Local transmission and distribution
would further increase this price.
The wellhead price of the gas is negotiable,but cannot exceed the
maximum price established under the 1978 Natural Gas Policy Act.Under the
Act,the North Slope gas price is not decontrolled in 1985 and remains constant
in real terms as only escalation due to inflation is permitted.
6.5
The behavior of the price over time is dependent upon the tariff
structure.For this analysis,the tariff is assumed to decline at a constant
rate such that the twenty-year average tariff using this constant decay rate is
equal to the twenty-year price stated in the Cost of Service analysis.A
constant annual decay rate of 13.5%may then be applied to the first-year
tariff ($3.79 in 1982 dollars for deliveries beginning in 1988)and the
wellhead value is then added back in to obtain the delivered price.This
provides for a delivered price in 2000 of $2.96 in 1982 dollars.
It should be noted that the constant decay factor tends to overstate the
tariff in early years and understate it in later years.This is because
typical gas pipeline tariffs decrease more rapidly in early years due to
accelerated depreciation of the fixed investment.However,the constant factor
used approximates the likely behavior of the price series and the inaccuracy
noted is of less consequence than the uncertainty regarding the act~al level of
the delivered price.
6.6
7.0 NATURAL GAS LIQUIDS/fvfTHANOL
The use of natural gas liquids (NGLs)from the North Slope has been the
subject of two recent major studies,done by the Dow-Shell Group and Exxon.
This chapter essentially summarizes the findings of the Dow-Shell study,which
have been confirmed by public statements from Exxon in regard to its unreleased
findings.The chapter first discusses the availability of NGLs and then
presents the pricing scenarios that would lead to their development.The Dow-
Shell study evaluates the use of NGLs with the unseparated liquefied petroleum
gas (butane,propane,pentane,and other components)exported to the Gulf
Coast,and the ethane component both exported and used for an in-state
petrochemical industry.
7.1 AVAILABILITY
Recoverable reserves of NGLs from North Slope fields are currently
estimated at about 400 million barrels and natural gas reserves at about 29
Tcf.The Dow-Shell study outlined plans for extracting natural gas at 2.7
Bcf/day,of which 210,000 barrels of liquid would be available for shipment in
an NGL pipeline.ANGTS has a planned capacity of 2 to 2.4 Bcf/day.
The production of NGLs is outlined in two phases.In the first phase
total NGL production would be 165,000 Bbl/day,with the production of ethane
increasing from 45,000 to 90,000 Bbl/day in the second phase to bring
production up to 210,000 Bbl/day.The remaining quantities of LPG gas,are
61,000,34,000,and 28,000 Bbl/day for propane,butanes and pentanes,
respectively,with no change in the in-production level from phase one to phase
two.The ethane component of the NGLs is the most important to Alaska for a
petrochemical industry and would be used to produce ethylene,an important
chemical feedstock.It is estimated that by the late 1980s demand in the
Pacific Rim markets will be sufficient to absorb the additional supply of NGLs.
Plans outlined in the Dow-Shell study contain three basic options.The
first is to extract and export all the NGLs to outside markets for further
processing.The second is to establish a petrochemical industry in Alaska that
7.1
!(
f~
p------------------------I
would produce low capital-intensive and high-ethane-content based products such
as polyethlene and alpha olefins.The third would be to establish a
petrochemical industry that would produce relatively high capital-intensive and
low-ethane-content based products such as ethylene glycol,ethylene dichloride
and ethylbenzene.The LPG components would not be processed in Alaska in
either of the petrochemical scenarios;rather,they would be exported to the
Gulf Coast market.The Dow-Shell study concludes that the second option is best
suited for Alaska.
The timing of all three options is tied to the price of crude oil and the
development of the ANGTS.The impact of the price of oil on the feasibility of
utilizing NGLs from the North Slope will be addre~sed in the next section;
however,a real increase in world crude oil prices is necessary for the
utilization of gas liquids.Potential participants in an NGL venture feel that
the infrastructure in Alaska could not support the construction of both the
ANGTS and NGL system at the same time.In addition,the likely cost increase
that would occur in both projects due to resource acquisition problems would
render them financially unfeasible if both were undertaken at the same time.
Given this information and the tentative current construction schedule for the
ANGTS,which is due to be completed in the late 1980s,the NGL system would not
be completed until the mid-to-late 1990s.
Production of methanol was also considered in the Dow-Shell study by Alaska
Interior Resources,Inc.The timing of a methanol facility depends on the
ANGTS;since methane from the North Slope would serve as the feedstock,
methanol production would begin in the late 1980s with the projected completion
of the ANGTS.The feasibility study concluded that methanol produced from
methane would be more economical than that produced from coal.The 5,000
metric ton per day facility would require about 175 MMcf of methane per
day.(a)This amount is less than the state's royalty share of North Slope
gas of 250 MMcf/day at a flow rate of 2 Bcf per day.
(a)Based on a personal communication with Mr.Bob Dempsey of Alaska Interior
Resources,Inc.that indicated 1 short ton of methanol contains about 19.5
to 20 MMBtu and the conversion efficiency,i.e.,Btu feedstock input to
methanol Btu content,is in the range of 60 to 65%.
7.2
TABLE 7.1 Crude Oil Price Sensitivity to Escalation Rate
Real Escalation Rate
Year 1%2X 3~
1980 $36.00 $36.00 $36.00
1985 $37.84 $39.75 $41.73
1990 $39.77 $43.88 $48.38
1995 $41.79 $48.45 $56.09
2000 $43.93 $53.49 $65.02
7.2 PRICE
The financial feasibility of extracting and marketing NGLs separately from
the gas stream depends primarily on the price received for the LPG components
and would require only slight increases in the price of crude oil.The
feasibility of further separating the ethane component for use in a
petrochemical venture would require a more substantial increase in the price
of oil.
The Dow-Shell study reports that the NGL venture would be viable with a
rise in crude oil prices to about $40/bbl or greater in real terms (1981
dollars),in absence of completion of the ANGTS.Given the current level of
oil prices,about $36/Bbl,the project1s feasibility would be dependent upon
,the real escalation of crude oil prices as shown in Table 7.1.
1
I
I
Without ANGTS the production of NGLs appears to be feasible as early as the
mid-1980s with a 2%to 3%real annual escalation rate.If ANGTS is
constructed,the study states that the real price of crude oil would have to
exceed $52/bbl,which would delay the NGL system into the mid-to-late 1990s
with a 2%to 3%real escalation rate.A 1%real escalation in oil prices
delays the feasibility of an NGL system beyond the year 2000.
The Dow-Shell study provided the following estimates of the Alaska
tidewater value of ethane and the LPG components corresponding to two world oil
prices:
7.3
Crude Oil Price,1981 $/Bbl
,.,
LPG,$/lb
Ethane,$j"lb
37.50
.081
.052
55.00--
.139
.111
Interpolating provides an estimate of the tidewater value of the product cor-
responding to the two feasibility scenarios outlined above,i.e.,LPG without
ANGTS at $40/Bbl and LPG with ANGTS at $52/Bbl in 1981 dollars.
LPG,$/lb
Ethane,~/lb
Without ANGTS
(Crude $40/Bbl)
.089
.060
With ANGTS
(Crude $52/Bb 1)
.129
.101
These prices represent the estimated tidewater value of these products as
outlined in the feasibility study with and without the ANGTS.
Methanol production costs and methanol prices were not mentioned in the
Dow-Shell feasibility study,nor was this information directly obtainable from
the stUdy's participants.However,it was indicated that the methanol produced
would be competitive on the West Coast markets with the methane feedstock
priced at its maximum legal value.(a)Recent methanol prices quoted in
Chemical Weekly have been in the range of $.90 to $1.00 per gallon,or about
$14.06 to U5.63 per t+1Btu.(b)This provides a net-back price to tidewater
Alaska of about $13.29 to $14.86 per MMBtu with a $2.00 per Bbl transportation
cost to the West Coast--compared to the projected cost of methane input at
Fairbanks of about $5.92 per MMBtu.This suggests that production and
transportation costs to tidewater are no greater than about $7.34 to $8.91 per
MMBtu.
(a)Personal communication with Mr.Bob Dempsey of Alaska Interior Resources,
Inc.
(b)Based on 64,000 Btu/gal.
7.4
8.0 FUEL OIL
The use of fuel oil for electricity generation is generally regarded as a
last-choice alternative because of its high cost.Generally,oil is used only
for peaking capacity.The Railbelt region conforms to this usage pattern,
although the northern portion of the Railbelt and remote sections of Alaska
depend heavily upon fuel oil for their electricity needs.
Given the current outlook for future oil prices,as determined by OPEC,it
is unlikely that oil will continue to figure heavily as baseload generating
fuel in the electricity generating plans for the Railbelt.This is aided by
the availability of lower cost natural gas and abundant supplies of coal
and hydroelectric sites,all of which promise relatively low-cost electricity
production.
8.1 AVAILABILITY
Although Alaska is currently not self-sufficient in refined petroleum
products,the availability of refined products over the forecast period appears
to present little problem.Recoverable reserves are estimated at about 8
billion barrels as of January 1981,with about 993 million barrels of this
being state royalty oil.This quantity of royalty oil is sufficient to cover
projected cumulative consumption of about 929 million barrels (Goldsmith and
O'Connor 1980)through the year 2000.Beyond this period,consumption can
likely be supplied by one or more of the following:an increase in the
quantity of recoverable reserves and royalty oil;diversion/purchase of
nonroyalty oil for in-state use;and out-of-state purchases from either foreign
or 1I1 ower 48 11 producers.
An estimate of Alaska's 1979 import dependence by petroleum product is
shown in Table 8.1 .•This information indicates that imports accounted for
about 37%of in-state consumption in that year.This dependence varies by
product from about 30%for motor gasoline to 100%for aviation gasoline.Given
no increase in in-state refinery capacity,this dependence on imports will
grow.
8.1
~----------------
~
H~
~
TABLE 8.1 Alaska Consumption of Imports and Exports of
Refined Petroleum Products in Barrels/Day,1979
T
I
Product
Motor Gasoline
Aviation Gasoline
Jet Fuel
LP Gas
Medium Distillates
Residual Fuel
TOTAL
Consumption
12,360
1,102
27,007
334
33,978
o
74,781
Exports
18,874
18,874
Imports
3,810
1,102
10,102
o
12,860
o
27,874
SOURCE:Department of Commerce and Economic Development.April 1981
(Draft).State of Alaska Long-Term Energy Plan.
Department of Commerce and Development,Division of Energy
and Power Development,Anchorage,Alaska.
The Alaska Department of Natural Resources (1982a;1982b)has solicited
proposals for the purchase of royalty oil for in-state processing or supply of
petroleum products.Three contracts have been submitted to the state
legislature for final approval.One is with Tesoro for about 46,000 barrel per
day (b/d)over a 12-year period.Current plans for refining this oil are to
use existing capacity and Tesoro will continue to evaluate expanding its in-
state refinery capacity.This contract has received legislature approval and
deliveries to Tesoro are to begin in January of 1983.
The other two contracts are with Doyon.The first of these contracts is
for about 19,000 bid for a 12-year term contingent upon the construction of a
refinery in Fairbanks oy December of 1983.This contract has also received
legislative approval on the condition that Doyon submit a financial plan for
the proposed refinery by October 1,1982.The second contract for about
17,000 bid for a 12-year term is no longer in effect.This contract was
contingent upon Doyon acquiring a controlling interest in the Mapco refinery by
May 1,1982 and this condition was not met.
Three other contracts are in some stage of consideration.The first is
based on an offer by the State to Chevron for about 38,000 bid of royalty oil,
8.2
with about 18,000 bid to be processed in state at Chevron's Nikiski refinery
and the remainder to be processed by Chevron in California and returned to
Alaska in finished products.The second is with Alaska for up to 15,000 bid
for 10 years in exchange for petroleum coke to blend with coal exports from the
Usibelli mine to Korea.The third is with Provident for up to 50,000 bid for
20 years to be exported and refined for sale in Arizona.
8.2 PRICE
This section develops the prices for fuel oil in Fairbanks and Anchorage
areas.These prices are developed separately because of the differences in
location and demand requirements,both of which affect the price of the oil
purchased.Oil price escalation is handled separately because of its
importance with regard to future prices.
Anchorage Municipal Power and Light purchases No.2 oil for winter peaking
purposes.The last purchase of oil was in December 1980 at a price of
$.959/gal or about $6.92/MMBtu.The price of this oil is not expected to have
changed significantly over the last year in view of the stability of world oil
prices during the last year and the prices of this and similar products in the
Fairbanks area.
Three grades of fuel oil and their respective heat content are identified
for electricity generation and space heating in the Fairbanks area.
No.1 and No.2 heating/diesel fuel
No.6 heavy turbine fuel
5,825 MBtu/bb 1
5,922 MBtu/bbl
Delivery and prices of these fuels have been set by contract between the North
Pole Refinery and its utility customers,the City of Fairbanks and the Golden
Valley Electric Association (GVEA).
The contract with GVEA was effective on May 1,1980,and runs for 7 years.
This contract contains a provision for price escalation at the world rate and
establishes a formula for computing the price of the turbine fuel.No.1 and 2
fuel oil prices are set equivalent to the lowest price given to other
customers,so the prices paid by GVEA are linked to those paid by the City of
Fairbanks.
8.3
JI
Table 8.2 shows the prices for each of the fuels to each of the buyers.
The prices to Fairbanks are those stated in the contract.The price of turbine
fuel to GVEA is the price being paid in November 1981.There is not a great
deal of difference in these prices because there has been virtually no change
in the world oil price over this period.The price of No.1 and 2 oil to GVEA
is assumed to be equal to that for the City of Fairbanks.
TABLE 8.2 Fuel Oil Price in Fairbanks,1980-81
No.
No.
No.
Fuel Type
1 Diesel Fuel
2 Heating/Diesel Fuel
6 Heavy Turbine Fuel
City of Fairbanks
$/Gal
.946
.893
.863
(Nov.1980)
$/MMBtu
6.82
6.44
6.12
GVEA (Nov.1981)
$/Gal $/MMBtu
NA NA
NA NA
.82 5.92
The market price of Alaska North Slope and other domestic crude oils is
now directly tied to world oil prices adjusted for transportation costs,as
these represent the marginal cost of supply.What future world oil prices will
be is highly speculative given the influence of the Organization of Petroleum
Exporting Countries (OPEC).
The approach taken in this analysis of future crude oil price behavior is
to examine the recent literature on the subject and draw a consensus forecast.
Table 8.3 summarizes the real price escalation rates for crude oil from a
variety of sources.These sources and others indicate a range of real price
escalation from 0%to 3%,with a 1%to 3%range for the longer term.Some
sources and recent experience indicate that a negative escalation over the
short term is also a possibility.Also,it is reported that OPEC is seeking to
maintain a 3%real rate of price increase.All of the sources,including OPEC
and others,think it unlikely that price increases will exhibit a smooth rate,
but rather a series of sharp jolts as experienced in the past.
This analysis selects a 2%real long-term rate of increase for the base
case with a high and low of 3%and 1%,respectively,for the range.In
addition to the consensus from the above sources,there are a number of other
reasons for this selection.Real price increases of greater than 3%are
8.4
unlikely because past increases have dramatically changed the relative price of
fuels.This has led to energy conservation measures and the substitution of
other fuels for oil products.These measures have helped to restrain recent
price increases contemplated by OPEC.The change in relative prices also
increases the development and commercialization of alternative energy-producing
technologies and oil recovery methods.OPEC is mindful that their product may
be displaced from the market if too large and too rapid a shift in relative
energy prices takes place.On the other hand,OPEC appears able to prevent a
decline in real prices over the long term.
TABLE 8.3.Expected Real Price Escalation Rates for Crude Oil
Time Period
1980-1990
1980-2000
1980-2000
1980-1985
Rea 1 Annua 1
3%
3%
1-2%
0-1%
Source
Patrick J.Keenen,Vice President,
Energy Economi cs,Chase Manhattan
Bank,Platts Oilgram News,Oct.14,
1981.
Standard Oil of California,Platts
Oilgram News,August 4,1981.
Texaco,Oil and Gas Journal,Sept.
28,1981.
Bankers Trust,Oil and Gas
Journal,Sept.28,1981.
~\1<-""
Given the current crude price of about $36/bbl,the real and nominal
prices of oil over the forecast period are listed in Table 8.4.The effect of
just the real escalation rate on oil price in constant dollars is rather
dramatic,giving a range of $47 to $82/bb1 by the end of the forecast period
for the 1 and 3%real escalation rates,respectively.This effect is more
startling when the oil prices are viewed in nominal dollars where both
inflation and real escalation are reflected in the price.
8.5
TABLE 8.4.Oil Prices Over the Forecast Period,$/Bbl
Nomi na 1 Do 11 ars,
1982 Do 11 ars 7%Inflation Rate
Year 1%2%3%1%2%3%
1982 36.00 36.00 36.00 36.00 36.00 36.00
1990 38.98 42.18 45.60 66.98 72 .47 78.36
2000 43.06 51.42 61.29 145.54 173.79 207.15
2010 47.57 62.68 82.37 316.26 416.73 547.63
8.6
.....
9.0 REFERENCES
Alaska Department of Natural Resources.1982a.Review of Alaska Royalty Oil
Policy and Findings For Proposed Disposition of Royalty Oil.Alaska
Department of Natural Resources,Pouch "W I
,Juneau,Alaska.
Alaska Department of Natura 1 Resources.1982b."Summary of Proposed
Disposition of Royalty Oil."Alaska Department of Natural Resources,
Commissioner's office,Juneau,Alaska.
Bechtel Corporation.April 1980.Excutive Summary,Preliminary Feasibility
Study Coal Export Program,Bass-Hunt Wilson Coal Leases,Chuitna River Field,
Alaska.Bechtel Corporation,San Francisco,California.
Black and Veatch.1980.Modifications of Four Existing Stoker-Fed Boilers
for Utilization of Refuse Derived Fuel,Fort Richardson,Alaska.Final
Conceptual Design Report,Volume I,Black and Veatch,Consulting Engineers,
Kansas City,Missouri.
Chemical Week.July 1,1981."DOE's Plan for Gas-Price Decontrol."
Data Resources,Inc.Summer 1982.U.S.Long-Term Review,Lexington,
Massachusetts.
Department of Energy.1981.Interim Report of the Interagency Coal Export
Task Force.Washington,D.C.
EKONO,Inc.November 1980.Peat Resource Estimation in Alaska -Final
Report.Volume II,prepared for the U.S.Department of Energy by EKONO,
Inc.,Bellevue,Washington.
Goldsmith,S.and L.Huskey.1980.Electric Power Consumption for the
Railbelt:A Projection of Requirements.Prepared for the State of Alaska,
House Power Alternatives Study Committee and Alaska Power Authority by the
Institute of Social and Economic Research,University of Alaska,Anchorage,
Alaska.
Goldsmith,S.and K.O'Connor.1980.Historic and Projected Oil and Gas
Consumption.Prepared for the Alaska Royalty Oil and Gas Development
Advisory Board by the Institute of Social and Economic Research,University
of Alaska,Anchorages and the Division of Minerals and Energy Management,
Department of Natural Resources,State of Alaska.
Metcalf and Eddy/Engineers.August 1979.Feasibility of Resource Recovery
from Solid Waste - A Report to the Municipality of Anchorage,Alaska.
Prepared for the Municipality of Anchorage,Alaska,by Metcalf and
Eddy/Engineers,Boston/New York/Palo Alto/Chicago.
9.1
.........._-------------------_-._---~•
r
Northern Technical Services and EKONO,Inc.August 1980.Peat Resource
Estimation in Alaska -Final Report.Volume I,prepared for the U.S.
Department of Energy,by Northern Technical Service,Anchorage,Alaska and
EKONO,Inc.,Bellevue,Washington.
Office of the Federal Inspector.October 19,1981.Cost of Service for the
Alaska Natural Gas Transportation System.Federal Energy Regulatory
Commission,Washington,D.C.
Oil and Gas Journal.1981.IINGPA Seen No Answer to U.S.Gas Supply Woes,"
February 16,1981.
Oil and Gas Journal.1982a."0il Price Rise Slowdown Seen for Next 10
Years.II May 17,1982.
Oil and Gas Journal.1982b."PacAlaska Project Lining Up Gas Supply.1I
Ju 1y 26,1982.
Platts Oilgram News.1981."Decontrolled Gas Price Would Be $4.50/MCF--
SOIND Economist,II October 15.1981,p.5.
Punwani,D.V.1980.Synthetic Fuels From Peat:State of the Art Review.
Paper presented at 7th Energy Technology Conference and Exposition,March
1980,Washington,D.C.
Standard Oil Company of California.June 1982.World Energy Outlook.
Standand Oil Company of California,Economics Department -Room 119,P.O.
Box 7137,San Francisco,California 94120.
Stuart,A.1981.liThe Blazing Battle to Free Natural Gas.1I Fortune,
October 19,1981.
Swift,W.H.,J.P.Haskins,and M.J.Scott.1980.Beluga Coal Market Study
Final Report.Prepared for the Division of Policy Development and Planning,
Office of the Governor,State of Alaska.Battelle,Pacific Northwest
Laboratories,Richland,Washington.
9.2
_".-------------------------~
"..
S013I~S~8 l~~nl~N 131NI ~OOJ NO ~l~a A~~WWnS
~XlaN3dd~
DISCOVERY DATE:2/10/67 FIELD OR UNIT:Beaver Creek
I~ITIAL PRODUCTION:1/73 LOCATION:Kenai Peninsula
WELLS FLOWING:SHUT IN:a STATE ROYALTY:0%
PRODUCTION 1979:Net.00925 Ecr.CU~lIJLATIVE PRODUCTION 1/l/80:Net 0.463 BCE
OPERATOR:Marathon Oi 1 Co.OTHER PARTICIPANTS:Union Oil Co.
ESTIMATED REMAINING RESERVES:
DEDICATED R8~AINING RESERVES:
B.U.Y.E.R
UNCDr1r·1!HED RE1'1AI NING RESERVES;
240
240
acr
BCF,DATE:
BCE,DATE:
1/1/80
MIE
1/1/80
""""
REHARKS;
1.No gas pipeline connection
2.One injection well
CONTRACT PROVISIONS:
Expired contract with Pacific Alaska LNG Associates reported for commitment
of 111 BCF.May be being renegotiated.
A.l
DISCOVERY DATE:
I~ITIAL PRODUCTION:
12/18/62
1/64
FIELD OR UNIT:Beluga River
LOCATION:W.Side Cook Inlet (Onshore)
r
WELLS FLOWING:6 SHUT IN:0 STATE ROYALTY:7.99%in value
PRODUCTION 1979:___]~6~9~9 ~B~CF CUMULATIVE PRODUCTION 1/1/80:9~O~.~4U'6 ~BC<LF
OPERATOR:Chevron USA,Inc.OTHER PARTICIPANTS:Shell Oil Co.(33%)
Atlantic Richfield (33%)
ESTIMATED REMAINING RESERVES:
DEDICATED REMAINING RESERVES:
B.L!.Y..ER
Chugach Electric Assoc.
Chugach Electric Assoc.
Pacific Alaska LNG Assoc.
767 BCF,DATE:
B.C.E
373(1)310
624
1/1/80
DAIE
Original Contract
1/1/80
11/5/75 (2)
UNCOi':I·llTTED REi'lAIiHNG RESERVES:Negati ve BCF,DATE:1/1/80
REi'lARKS:
1.Estimated by deducting cumulative sales to 1/1/80 from original contract
commi tment.
2.DeGolyer and MacNaughton estimate date 12/10/75.Estimate of reserves
committed to others (Chugach)given as 352 BCF as of 11/5/75.
CONTRACT PROVISIONS:
Chugach Electric Association
Original Commitment:373 BDF or until 1/1/98 which ever occurs first.
Delivery Obligations MMcf/day:
1973
1974
1975
1976
Maximum Take
30
30
30
35
A.2
Minimum Take
9
18
18
30
BELUGA FIELD (continued)
CONTRACT PROVISIONS:
~laximum Take Minimum Take
1977 50 30
1978 50 40
1979 60 40
1980 60 50
1981 60 50
1982 on 60 55
Price:
Without Pacific Wi th Paci fi c
Alaska LNG Alaska LNG
Purchases ¢/Mcf Purchases ¢/Mcf
1977 17.64
1978 18.64
1979 19.20
1980 19.62
1981 19.62
1982 20.03
1983 20.62
1984 21.03
1985 21.03 84.78
1986 21.45 86.45
)987 21.45 91.22
Pacific Alaska LNG Associates
Estimated Reserves
Execution Dates:Chevron
She 11
ARCO
7/15/77
7/11/77
6/30/77
220.8 Bcf
na
220.4 Bcf
--olIlIl
Terms:.Commi ts all gas in excess of commi tments to Chugach El ectri c
Association,20 years.
Price:$1.48/Mcf as of 1/1/78,l¢/quarter escalation
A.3
r
FIELD OR UN IT :--=.B.:...;ir~c::.:.;h~H '.:-"l~l _
STATE ROYALTY:0_%_
Atlantic Richfield
LOCATION:Kenai Peninsula
BCEO.1
OTHER PARTICIPANTS:
_______~BC~F CUMULATIVE PRODUCTION 1/1/80:
DISCOVERY DATE:6/9/65
I~ITIAL PRODUCTION:na
WELLS FLOWING:0 SHUT IN:
PRODUCTION 1979:0
OPERATOR:Chevron USA
ESTIMATED REMAINING RESERVES:11 BCF,DATE:1/1/80
DEDICATED REMAINING RESERVES:
uNcor'1r·1!TTED RH1A INING RESERVES:11 BCF,DATE:1/1/80
REf1ARKS:
1.Semi-remote field four miles north of Swanson River Field.
2.Closest pipeline is 16"line from N.Cook Inlet gas field to Nikiski.
CONTRACT PROVISIONS:
None
A.4
DISCOVERY DATE:na FIELD OR UNIT:Cannery Loop
I~ITIAL PRODUCTION:na LOCATIO~:3 mi East of Kenai
WELLS FLOWING:na SHUT IN:na STATE ROYALTY:na
PRODUCTI ON 1979:na BCF CU~1UL.ATIVE PRODUCTION 111/80:na ill
OPERATOR:Union Oil Co.OTHER PARTICIPANTS:---,-"Ma=r,-"a~tc.:..!.h::::..:on..:....-.._
Pacific Lighting
ESTIMATED REMAINING RESERVES:
DEDICATED REMAINING RESERVES:
B.U.YER
UNCOMMITTED RE~~I~ING RESERVES:
REf'1ARKS:
na
B..C.E
BCE,DATE:
MIE
BCE,DATE:
1.Potential discovery.one well.Confidentiality release date is
July 24.1981.
CONTRACT PROVISIONS:
None
A.5
,d ~
a
Falls Creek
LOCATION:E.Side Cook Inlet (On &Offshore)
FIELD OR UNIT:
STATE ROYALTY:
OTHER PARTICIPANTS:
_______-l.I.Bl.<LCF CUl11ULATIVE PRODUCTION 111/80:<0.1 RCF
DISCOVERY DATE:6/25/61
I~ITIAL PRODUCTION:na
WELLS FLOWING:a SHUT IN:
PRODUCTION 1979:a
OPERATOR:Chevron USA,Inc.
ESTIMATED REMAINING RESERVES:13 BCF,DATE:1/1/80
DEDICATED REI~A[NING RESERVES:
BUYER B..C..E
UNCOMMITTED REMAINING RESERVES:13 BCF,DATE:1/1/80
REi-lARKS:
1.Remote field
CONTRACT PROVISIONS:
None
A.6
o BCE CUMULATIVE PRODUCTION 1/1/80:
Pacific Alaska LNG Assoc.
~I,
iltr
B..C.Eo
MIE
11/1/75
lili80
12.5%
Ivan Ri ver
OTHER PARTICIPANTS:Atlantic Richfield (37.5%)
Pacific Lighting (12.5%)
LOCATIOi'l:W.Side Cook Inlet (onshore)
FIELD OR UNIT:
STATE ROYALTY:
BCF,DATE:
ill
105.9
26
SHUT IN:
n.a.
o
10LJU66
Chevron USA,Inc.
WELLS FLOWlNG:
OPERATOR:
I~rTIAL PRODUCTION:
BUYER
ESTIMATED REMAINING RESERVES:
PRODUCTION 1979:
DISCOVERY DATE:
DEDICATED REMAINING RESERVES:
U~COMMITTED REMAIi~ING RESERVES:o BCE,DATE:
REr~RKS:
1.DeGolyer &MacNaughton estimated recoverable reserves at 105.9 BCF
as of November 1,1975.
2.No pipeline connection.Located approximately 9 miles NE of Beluqa
gas field.
CONTRACT PROVISIONS:
Executed:
ARCO:June 30,1977
Pacific Lighting:August 30,1977
Chevron USA:July 15,1977
Term:20 years
Price:$1.46/Mcf July 1,1977,escalated l¢/quarter.If deregulated
escalate by producer price index (from 195.2 as of May,1977)
A.7
d _~
DISCOVERY DATE:na FIELD OR UNIT:Ka]dachabuna
I~ITIAL PRODUCTION:na LOCATION:W.Side Cook Inlet (Onshore)
WELLS FLOWING:na SHUT IN:na STATE ROYALTY:na
PRODUCTI ON 1979:___n:..:..:a::......-..J.LBC\<LE CLI~'ULATIVE PRODUCTION 111/80:na BCE
OPERATOR:Simasko Production Co.OTHER PARTICIPANTS:Union Oil Co.
ESTIMATED REMAINING RESERVES:
DEDICATED REMAINING RESERVES:
UNco~mI TTED RE~'AI iH NG RESERVES:
na BCE,DATE:
BCE,DATE:
REi1ARKS:
1.Wildcat drilling in progress (Oi]and Gas Journal,12/8/80)
2.One mile north of Granite Point Field (TllN-RllW)
CONTRACT PROVISIONS:
A.8
DISCOVERY DATE:10/11/59 FIELD OR UNIT:Kenai
I~ITIAL PRODUCTION:1962 LOCATION:Kenai Peninsula
WELLS FLOW ING :37 SHUT IN:STATE ROYALTY:'V 3.09 (l )
PRODUCTION 1979:97.0 BCE CU~lUI.ATIVE PRODUCTION 1/1/80:995.1 BCF
OPERATOR:Union Oil Co.OTHER PARTI CI PANTS:Marathon
ARCO -0.39%
Chevron -0.39%
ESTIMATED REMAINING RESERVES:1313 BCF,DATE:1/1/80
DEDICATED RE}lAININ6 RESERVES:
D8I.E
12/5/77 (12/31/80 2)
1/1/66
1/1/80(3)
1/1/80(3)
B..C.E
up to 585
312
400
499
106
~
Collier Carbon &Chemical
Alaska Pipeline Co.
Standard Oil Co.of
California/ARCO
Collier Carbon &Chemical
Standard Oil of California/ARCO
UNCOMMITTED REMAINING RESERVES:370(3)BCF,DATE:1/1/80
REf1ARKS:
1.Prior to transfer of portion to C.I.R.I.in 1980,current status
unknown.
2.Letter Bill B.Hickman,Alaska Gas and Service Co.to W.H.Swift,
January 13,1981.
3.Battelle estimate based on AOGCC raw data.
CONTRACT PROVISIONS:
Collier Carbon and Chemical Company
Original contract dated 8/7/68,subsequently amended 11/1/77.Maximum
delivery requirement -130,000 Mcf/day (47.45 Bcf/year).Price (1/1/80)
61.0¢/Mcf,to be renegotiated by 1/1/81.Term -20 years.Commitment
subject to prior contractual agreements (i.e.,subordinant to all other
present contracts).
A.9
KENAI FIELD (continued)
CONTRACT PROVISIONS:
Alaska Pipeline Corporation
Original contract executed 5/13/60;subsequent amendments occurred 5/1/67
10/1/67,1/1/72,and 1/1/75.The last two modifications cancelled all
prior amendments.
Commitment:550 Bcf on date of execution,may substitute from other sources.
Remaining reserves as of 12/1/80,312 Bcf.
~~inimull1 take of 72,000 Mcf/day (26.28 Bcf/year)until 12/31/85.After that
date,minimum take is the lesser of 72,000 Bcf or 75%of seller's delivery
capacity.Maximum take is 160,000 Mcf/day until 12/31/85.
Price:1/1/76 to 12/31/80
1/1/81 to 12/31/92
1/1/86 to 12/31/92
$0.24/Mcf
$0.27/Mcf
the greater of 27¢or the average price of
gas sales in the Cook Inlet area and received
by sellers for new sales to third parties.
De1iverabi1ity Charge:$0.29/Mcf on 1/1/80 escalating by producer price index.
Standard Oil Company of California and Atlantic Richfield (Rental Gas)
Executed:1/1/66
Maximum take:
r~i ni mum take:
400 Bcf total
1st 5 years
2nd 5 years
3rd 5 years
4th 5 years
21st year to
150 Bcf
45 Bcf /year
27 Bcf/year
16 Bcf/year
12 Bcf /year
b1owdown --8 Bcf/year
1/1/66-12/31/70
Price (Rental Charge):ranges from 8.1 to 8.9¢/Mcf depending on delivery
pressure.For royalty purposes,price is taken
as 16¢/Mcf.
A.10
--
KENAI FIELD (continued)
CONTRACT PROVISIONS:
Return after Commencement of Blowdown:
Anticipated to occur about 1989 at an average minimum rate of 18.2 Bcf
18.2 Bcf/year over 10 year period (182 Bcf cumulative).Maximum
return delivery rate.
City of Kenai
Contract executed 5/17/66 for term of 20 years.Apparently the
contract has never been envoked.
Anchorage Municpal Light and Power
State royalty gas contract executed 5/5/80 for all royalty gas over
20 year period.
Price:Equal to royalty payments state would have received if it had
take its royalty in-value plus additional transportation costs.Proforma
(1979)prices would be $0.8213/Mcf to A Gas,$0.6631/Mcf to AML&P.
Wheeling cost $0.24/Mcf.
This contract is yet to be exercised due to (1)Pricing dispute and (2)transfer
of some of the state lands in the lease area to Cook Inlet Region,Inc.
Tokyo Gas and Tokyo Electric
Some of the gas contracted for with Phillips/Marathon LNG is supplied
from the Kenai Field (18.77 Bcf in 1979).See data sheets on North
Cook Inlet Field.
A.11
----------------------------"""'""'lIIl....-
ESTIMATED REMAINING RESERVES:90 BCF,DATE:1/1/80
DED ICATED RE~IA INING RESE RVES :
aL!lli B..C.E D.8I.E
Pacific Alaska LNG Assoc.44 or 100%1/1/80
UNCOi\1r·1l TTED REf'1A INING RESERVES:o BCF,DATE:1/1/80
REi'1A RKS :
1.Remaining gas reserves estimated by DeGolyer and MacNaughton
at 21.78 Bcf as of 11/1/75.
2.No pipeline connections.Located NW of Ivan River Field.
CONTRACT PROVISIONS:
Pacific Alaska LNG Associates/Cities Service
Effective Date:July 1,1982 or date of initial delivery of gas
Term:20 years,22 Bcf
Price:$1.48/Mcf as of January 1,1978,escalating l¢/quarter.
If deregulate,then average of 3 highest prices then being
paid in Cook Inlet to pipeline companies for resale.
A.12
LEWIS RIVER (continued)
CONTRACT PROVISIONS:(continued)
Pacific Alaska LNG Associates/Pacific Lighting Gas Development
Essentially same as Cities Service contract except that if deregulated,
the price is the higher of (a)price paid to an Alaskan producer under
contract executed after 1/1/77,or (b)weighted average ~aid by Southern
California Gas Company and PG&E for gas less transportation costs.Price
is also escalated by the producer price index (PPI =195.2 -May 1977).
A.13
DISCOVERY DATE:12/2/68------'-------
IiHTIAL PRODUCTION:1/_6_9 _
FIELD OR UNIT:~1cArthur River
LOCATION:W.Side Cook Inlet (Offshore)
12.5%in ValueSTATEROYI\LTY:oSHUTIN:5
____7_.7_6__---lJ.'BCI<LF CU~1ULATIVE PRODUCTION 1/1/80:66.90 BCE
OTHER PI\RTICIPI\NTS:Atlantic Richfield (5%?)OPERATOR:Un;on 0;1 Co.
WELLS FLOWING:
PRODUCTION 1979:
ESTIMATED REMAINING RESERVES:
DEDICATED REMAINING RESERVES:
B.UYER
78 BCE,DATE:1/1/80
UNCOMMITTED REMAINING RESERVES:
REi'1ARKS:
1.Lease use.
78 BCE,DATE:1/1/80
CONTRACT PROVISIONS:
A.14
DISCOVERY DATE:5/1/66---'--...:.....-:....-_---
IiHTIAL PRODUCTION:10/68-_...:....-_---
FIELD OR UNIT:Nicolai Creek
LOCATION:W.Side Cook Inlet (On,Offshore)
1 .06 BCF
12.5%STATE ROYALTY:4oSHUTIN:
____~O B~CF CUMULATIVE PRODUCTION 1/1/80:
OTHER PARTICIPANTS:
WELLS FLOWING:
PRODUCTI ON 1979:
OPERATOR:_T~ex,-,-a-..:cc...::.o _
ESTIMATED REMAINING RESERVES:
DEDICATED REMAINING RESERVES:
illmffi
17
B.CE
BCF,DATE:1/1/80
DAIE
UNCOMMITTED REMAINING RESERVES:
REj1ARKS:
1.Lease use
17 BCF,DATE:1/1/80
CONTRACT PROVISIONS:
A.15
DISCOVERY DATE:9/1 /62 FIELD OR UNIT:North Cook Inlet
lilITlAL PRODUCTION:3/69 LOCATION:North Cook Inlet (Offshore)
WE LLS FLOW ING :11 SHUT IN:_1_STATE ROYALTY:12.5%
PRODUCTION 1979:49.4 RCF CU~'lILATlVE PRODUCTION 111/80:456.5 BCF
OPERATOR:Phillips Petroleum Co.OTHER PARTICIPANTS:Marathon--------
Chevron
AMOCO
CABOT
ESTIMATED REMAINING RESERVES:
DEDICATED REMAINING RESERVES:
6lJYER
Tokyo Gas and Electric
Alaska Pipeline Co.
1074 BCF,DATE:
acE
""191
""26.8 (Royalty)
1/1/80
DAIE.
1/1/81
1/1/81
UNcor'1r·lITTED RE!'1AINING RESERVES:",,806
REi'1ARKS:
BCF,DATE:1/1/81
The 1979 average production rate can be sustained until 1985 after which
the volumes will decline at about 10%per year.(Letter,John Horn,
Phillips Petroleum,Co.to D.G.Wold,Royalty Oil and Gas Development
Advisory Board,March 3,1977).
Alaska Pipeline Co.does not expect a full take of the royalty share
but rather 15 to 20 Bcf over the remaining term of thetr contract or
about 5 Bcf/year.
CONTRACT PROVISIONS:
Tokyo Gas and Tokyo Electric Co.
These contracts (dated March 6,1967)call for LNG delivery in Japan of
",,48.6 Bcf/year.The term is from June 1,1969 to June 1,1984 and may
be extended by mutual agreement an additional five years.
Price provisions are negotiable but apparently are tied to prices the
buyers may negotiate with other sellers of LNG and hence are related
to world oil prices.The formula used for calculating the well head
price (WHP)is:
WHP =(CIF Price in Japan)(0.36)-$0.055 =$/MMBtu
A.16
CONTRACT PROVISIONS:
Tokyo Gas and Tokyo Electric Co.
The 0.36 factor corrects for liquefaction and transportation costs,
$0.055/MMBtu covers pipeline costs from the North Cook platform to the
Kenai LNG Plant.(a)Wellhead price behavior during 1980 was as follows:
Weighted Average
LNG elF Price World Oil Price Wellhead Price
Month $/MMBtu $/~1MBtu $/r~I'1Btu
1 3.36 4.92 1.1541
2 3.36 -1.1541
3 3.36 -1.1541
4 4.97 -1.7337
5 5.25 -1.8345
6 5.40 5.43 1.8885
7 5.46 -1.9101
8 5.555 -1.9425
9 5.72 -2.0037
10 5.85 -2.0505
11 5.79 -2.0289
12 5.89 5.74 2.0649
Alaska Pipeline Co.(State Royalty)
This contract was entered into April 11,1977 and runs to June 1,1984.
Quantity is on a best effort basis with the intent not to take less
than 3 Bcf per year.Pricing provisions and market conditions are such
that Alaska Pipeline Company (APC)pays the same wellhead price as is
payed by Marathon and Phillips for that royalty gas taken in value (see
contract noted above).The cost of the gas to APC over and above the
wellhead price includes:(1)a gathering charge of $O.lO/Mcf with such
charge escalating at 6%per year from April 1977 ($0.119/Mcf in mid-1980)
and (2)a compression charge of $O.lO/Mcf increasing at a rate of 6%per
year from date of installation of compression facilities.Alaska Gas and
Service Co.advises that the compressors have been installed but not yet
used.They expect that this could occur at any time.
(a)Letter from John Horn,Phillips Petroleum Co.to Robert E.LeResche,
May 29,1980.
A.17
DISCOVERY DATE:12/20/65 FIELD OR U~HT:North Fork----------
I~ITIAL PRODUCTION:na LOCATION:Kenai Peninsula near Homer
WELLS FWd ING:o SHUT IN:STATE ROYAI_TY:o
PRODUCTI ON 1979:____O ......B:.u....CF CUJ~1ULATIVE PRODUCTION 1/1/80:0.1 BCF
OPERATOR:Chevron USA OTHER PARTICIPANTS:
ESTIMATED REMAINING RESERVES:
DEDICATED REMAINING RESERVES:
UNCOr1rlI TTED RU1AI iH NG RESERVES:
REi'lARKS:
12
12
BCF,DATE:
BCF,DATE:
1/1/80
1/1/80
A.18
1.Remote from existing pipelines
CONTRACT PROVISIONS:
I
I
I_______________L
DISCO'/ERY DATE:
1~ITIAL PRODUCTION:
11/15/64
na
FIELD OR UNIT:N.Middle Ground Shoal
LOCATIOii:Cook Inl et -Offshore
illna
12.5STATEROYALTY:
OTHER PARTICIPANTS:Shell (?)
o SHUT HI:
_____O__---Io£B""'-CF CU~1ULATIVE PRODUCTION 1/1/80:
Amoco Production Co.
WELLS FLOWING:
PRODUCTION 1979:
OPERATOR:
ESTIMATED REMAINING RESERVES:_n~a~__BCF,DATE:1/1/80
DED ICATED REfilA IN[NG RESERVES:
ill1YER B.C.E MIT
UNCOMMITTED REMAINING RESERVES:
REf'1ARKS:
BCF,DATE:
CONTRACT PROvrSIONS:
A.19
DISCOVERY DATE:8/4/61 FIELD OR UNIT:Sterling
I~ITIAL PRODUCTION:5/62 LOCATIO:I:Kenai Peninsula
WELLS FLOW [NG:SHUT IN:STATE ROYALTY:2.72237 in Value
PRODUCT ION 1979:0.02543 BCE CUMULATIVE PRODUCTION 1/1/80:1 .961 BCE
OPERATOR:110;00 Oil Co OTHER PARTICIPANTS:t1arathon -50%(7)
ESTIMATED REt1AI 1'1 ING RESERVES:
DEDICATED REMAINING RESERVES:
UNC0I-1rlI TTED RU1A Ii~I NG RESERVES:
REi-lARKS:
23
23
BCE,DATE:
BCE,DATE:
1/1/80
1/1/80
CONTRACT PROVISIONS:
Original to Sport Lake Greenhouses (11/1/73),assigned to Peninsula Greenhouses
(2/16/76).Quantity "...as may be produced and available from time to time
but not to exceed 300 Mcf/day and not more than 50,000 Mcf in anyone year.II
May be terminated by either party on 30 days notice.Price not available.
A.20
LOCATIOi~:ltJ.Side Cook Inlet (Onshore)
DISCOVERY DATE:
I~ITIAL PRODUCTION:
na
na
FIELD OR UNIT:Stump Lake
~~i
!:'li'~
UiH
ti
t:::;
~:-!
H
WELLS FLOWING:na SHUT IN:na STATE ROYALTY:na
PRODUCT!ON 1979:na BCF CUMULATIVE PRODUCTION 1/1/80:na E.C.E
OPERATOR:Chevron,USA OTHER PARTICIPANTS:Pacific Lighting
ESTIMATED RE~AINING RESERVES:
DEDICATED REMAINING RESERVES:
B.UYER
UNC01':I·'ITTED REi'1A Ii~ING RESERVES:
REi'lARK~:
na
au:
BCF,DATE:
DAlE
BCF,DATE:
1.Near Ivan River Field
2.Potential discovery -indefinite confidentiality date
CONTRACT PROVISIO~S:
A.21
DISCOVERY DATE:
I~ITIAL PRODUCTION:
WELLS FLOW II~G:
8/24/57
na
SHUT IN:5
FIELD OR UNIT:
LOCATIOi~:
STATE ROYALTY:
Swanson River
Kena i Peni nsul a
'V 3.09%
1
I
,
j
PRODUCTION 1979:120.3 I nj ec t ion BCF CUi·1ULATI VE PRODUCTI ON 111/80:1,173.7 I nj ~EEt ion
OPERATOR:Chevron USA OTHER PARTICIPANTS:Atlantic Richfield
Union Oil Co.-1.51%
Marathon Oil Co.-1.51%
ESTIMATED REI~AIN ING RESERVES:See Rema rks
DEDICATED REMAINING RESERVES:
UNCOMMITTED REMAINING RESERVES:__2__4__2 _
BCF,DATE:
BCE,DATE:1/1/80
REf1ARKS:
1.Primarily an oil field.Rental gas from Kenai Field being injected for
pressure maintenance.Blowdown expected to commence 1/89.
2.Original indigenous reserves estimated at 59.6 Bcf.Anticipated recovery
of injected gas on blowdown estimated at 182 Bcf for a total of about
242 Bcf.
CONTRACT PROVISIONS:
A.22
:_________________1_
DISCOVERY DATE:
IiHTIAL PRODUCTION:
6/1/65
12/68
FIELD OR UNIT:Trading Bay
LOCATION:Cook Inlet (Offshore)
WELLS FLOWING:n~a __SHUT IN:na STATE ROYALTY:12.5%
PRODUCTI ON 1979:0.7705 BCF CU~lULATIVE PRODUCTION 1/1/80:0.822 BCE
OPERATOR:Union Oil Co.OTHER PARTICIPANTS:Atlantic Richfield
Texaco,Inc.
ESTIMATED REMAINING RESERVES:
DEDICATED REMAINING RESERVES:
B.lJYER
UNCOMMITTED REr~IN[NG RESERVES:
REi'~RKS :
na
B.C.E
BCF,DATE:
DAIE
BCF,DATE:
1.Casing head gas,lease use
CONTRACT PROVISIONS:
A.23
j
---------------------------"1
DISCOVERY DATE:na FIELD OR UNIT:Trail Ridge
LOCATIOi'!:55 m NW of Anchorage
120N -RIOw
I~ITIAL PRODUCTION:
WELLS FLOWING:o
na
SHUT IN:o STATE ROYALTY:na
PRODUCTION 1979:____---->"-0__---I.!B;.LCF CU~'U LA TI VE PRODU CTI ON 1/1/80:o BCE
OPERATOR:Union Oil Co.OTHER PARTICIPANTS:
ESTIMATED REMAINING RESERVES:
DEDICATED REMAINING RESERVES:
UNCOMMITTED REMAINING RESERVES:
na
B..C.E
BCE,DATE:
BCE,DATE:
REf1ARKS:
1.Wildcat well drilling below 13,100 feet (Oil and Gas Journal,12/8/80)
CONTRACT PROVrSIONS:
A.24
!-------....1-.
DISCOVERY DATE:11 /28/65 FIELD OR UNIT:Tyonek -
I~ITIAL PRODUCTION:na LOCATION:W.Side Cook Inl et (Onshore)
WELLS FLOWING:0 SHUT HI:3 STATE ROYALTY:0%(C.I.R.I.)
PRODUCTION 1979:.0 .B..C.E CUMULATIVE PRODUCTION 1/1/80:na .B..C.E--
OPERATOR:Pacific Lighting,SIMPCO OTHER PARTICIPANTS:
ESTIMATED REMAINING RESERVES:
DEDICATED REMAINING RESERVES:
na BCF,DATE:
B.U.Y£R
Pacific Alaska LNG Assoc.
UNCOv~1ITTED REMAINING RESERVES:
B.C.E
100%
BCF,DATE:
D.AIE
REf1ARKS:
1.Also identified as Albert Kaloa and Moquawki Fields.
CONTRACT PROvrSIONS:
Pacific Alaska LNG Associates executed 8/17/77.
Estimated reserves to be determined by DeGolyer
as of January 1,1978 escalating at l¢/quarter.
for Lewis River Field contract.
A.25
Take or pay starting 7/1/81.
and MacNaughton.Price:$1.48/Mcf
On deregulation,pay same as
DISCOVERY DATE:3/29/62 FIELD OR UNIT:West Foreland
I~ITIAL PRODUCTION:na LOCATI01l:W.Side Cook Inlet
WELLS FLOWING:o SHUT IN:STATE ROYALTY:o
PRODUCTI ON 1979:_____O .....B.l<J....CF CU~1UL.ATIVE PRODUCTION 1/1/30:o BCF
OPERATOR:Amoco Product jon Co.OTHER PARTICIPANTS:
ESTIMATED REMAINING RESERVES:
DEDICATED REMAINING RESERVES:
UNCDr'lr·ll HED RE1'1A IiH NG RESERVES:
REi'1ARKS:
20
20
BCF,DATE:
BCF,DATE:
1/1/80
1/1/80
1.Semi-remote field -could be connected to existing submarine pipeline to
Nikiski.
CONTRACT PROVISIONS:
A.26
DISCOVERY DATE:9/26/60 FIELD OR UNIT:West Fork
I~ITIAL PRODUCTION:10/78 LOCATIO~:Kena i Peni nsu1 a
~ELLS FLOW [NG:SHUT IN:o STATE ROYALTY:0%
PRODUCTION 1979:0.7705 BCF CU~lULATIVE PRODUCTION 111/30:0.8220 BCE
OPERATOR:Hal boutv Alaska OTHER PARTICIPANTS:
ESTIMATED REMAINING RESERVES:
DEDICATED REMAINING RESERVES:
B..U.'f..ER
Alaska Pipeline Co.
UNCDr'1rlITTED REi'1AI iHNG RESERVES:
REi'1ARKS:
7
BIT
?
BCE,DATE:
BCE,DATE:
1/1/80
M.IE.
1.Alaska
source
da ily.
Alaska
Gas Jnd Service Co.indicates that this field is not a
of supply,a single well field that produces less than
Operating problems may result in shut in (letter Bill
Gas and Service Co.to W.H.Swift,January 13,1981).
significant
2,000 Mcf
B.Hickman,
CONTRACT PROVISIONS:
Alaska Pipeline Co.
A.27
~