HomeMy WebLinkAboutAPA745HISTORIC!i
AND PROJECTED
OIL AND GAS
CONSUMPTION
JANUARY 1983 .
STATE OF
ALASKA
DEPARTMENT OF
NATURAL RESOURCES
DIVISION OF MINERALS
AND ENERGY MANAGEMENT
STATE OF ALASKA
HISTORICAL AND PROJECTED
OIL AND GAS CONSUMPTION
Bill Sheffield
Governor
Esther Wunnicke
Commissioner
Department of Natural Resources
January 1983
Prepared for the First Session,
Thirteenth Alaska Legislature
Contents
7
Execut lve &lmmary
Ll st of Tables
Ll st of Figures
1.0 Definitions
2.0 on and Gas Consumption
2 .I tleitlodol ogy
2.2 01 I Consumption
2.3 Gas Dl sposltlon and Consumption
I I I
v
I. I
2 .I
2 .I
2.5
2.14
2.4 01 I and Gas Consumption for Electricity Generation 2.21
3.0 Consumption Forcast 3.1
3.1 Transportation Liquid Fuels 3.7
3.2 SpaceHeating 3.13
3.3 utility Electricity Generation 3.15
3.4 lndustrl al Fuel Use 3.21
4.0 Feserve Estimates and fbya lty Share
4.1 Reserve Estimates
4.2 fbyalty Share
5.0 AnalysIs of Surp I us
5.1 Liquid Petroleum
5.2 Natural Gas
5.3 Projections Beyond Current Inventory
5.4 Sensitivity of Results
tppendl x A fbyalty 011 and Gas Data by Field
4 .I
4.1
4.4
5 .I
5 .I
5.3
5.3
5.5
A.l
,6ppend i x 8 Demand Projection M:dtlodology 8.1
8.1 Transportation Use of Liquid Petroleum 8.1
8.2 Electric Utility Use of Liquid Fuels and Natural Gas 8.4
8.3 Space Heating Use of Liquid Fuels and Natural Gas 8.10
8.4 Industrial Use of Liquid Fuels and Natural Gas 8.11
Append lx C Processing Plant, Transportation
Faci I ity and TAPS [l:)ta C.l
Append lx D Economic Growth Assumptions D. I
,6ppend i x E Con va-s ion Factors E.l
Appendix F Acknowledgements F. I
EXECUTIVE SU~1MARY
This report provides background on the in-state supply of, and demand for,
hydrocarbons. This report fulfills the requirements of Alaska Statute
38.05.183, which requires the Commissioner of the Department of Natural
Resources to submit an annual report to the Legislature, within 10 days of the
convening of the regular session, that shows the immediate and long-range
domestic and industrial needs for oil and gas in Alaska.
The statute requires that royalty oil and gas be used to satisfy present and
projected intrastate domestic and industrial needs before being sold for
export from the state or otherwise disposed of. The statute contains several
ambiguities in wording leading to a variety of possible definitions of
11 needs. 11 Therefore, in meeting the requirements of the statute, this report
first develops a number of definitions of consumption. The purpose of these
definitions is to provide a framework for identifying intrastate and
industrial needs.
Historical consumption by major use category is then presented. This section
updates the January 1982 report and provides estimated 1982 consumption for
the state and for three regions, Rail Belt, Rest-of-Alaska and Southeast.
Natural gas consumption in the Railbelt increased at about 3% per year over
the past decade, while petroleum fuels consumption has been increasing at
about 9% per year statewide.
Forecasts of oil and gas consumption are developed for the Rail Belt and the
remainder of the state (including Southeast) by major use category. These
forecasts show cumulative consumption of natural gas over the next 15 years of
3.9 trillion cubic feet. Cumulative refined product demand over the same
period is forecast to be 524 million barrels of crude oil equivalent (22,043
million gallons).
Low, medium, and high estimates of oil and gas reserves and the corresponding
state royalty share of these reserves are presented. The mid-level estimates
show that of the total crude oil reserves of 9.7 billion barrels, about 98%
are on the North Slope. Of these crude oil reserves, the state o\'ms about 1.2
billion royalty barrels; about 99% of the state's royalty share is located on
the North Slope. The middle case gas reserves of the state total about 39.0
trillion cubic feet (Tcf) with about 90% located on the North Slope. The
state • s royalty share is about 4. 6 trillion cubic feet, of which only 0.2 Tcf
are located in the Cook Inlet, the state's major demand center. The remaining
reserves lie on the North Slope, and the timing of this gas development can
have a significant impact upon the state's royalty surplus/deficit situation.
The cumulative 15-year demand for natural gas of approximately 4.0 trillion
cubic feet is slightly less than the state's royalty share. The cumulative
refined product demand of 524 million barrels of oil equivalent is
considerably less than the existing royalty oil inventory of 1.2 billion
barrels.
Major in-state denands for hydrocarbons are for transportation, electrical
generation and residential space heating. Transportation uses are forecast to
consume 402 million bbls of crude oil equivalent bet\'leen 1983 and 1997. The
use of natural gas for electrical generation in the Rail Belt is forecaste to
grow rapidly over the next 15 years. In the base case, demand grows from 32.9
Bcf in 1983 to 62.4 P.cf in 1997. Residential space heating consumption of
natural gas is forecast to grow from an annual rate of 18.2 billion cubic feet
(Bcf} in 1982 to 37.4 Bcf hy 1997. This increase is related to economic and
population growth in the Rail Belt area and to the expansion of gas delivery
systems into the f1atanuska Valley.
The supply and demand projections used in this report are by their very nature
probabilistic and should be viewed as likely outcomes only if the underlying
assumptions presented here are approximated by future events. For example,
in-state consumption will be influenced by economic and population growth
which will in. turn be fueled hy \'Jorld energy prices. In addition, the
development of the Susitna hydroelectric project would dramatically affect the
in-state demand for natural gas, particularly after the late 1990s. Finally,
the growth of a gas export market would affect in-state availability as well
as prices.
Even the supply side of the in-state balancing equation is probabilistic.
Only the mid-range estimates of oil and gas resources (9.7 million bbls, 39.0
Tcf} are reasonably certain. Estimates of undiscovered resources must be
treated as highly speculative and of minimal value for projection purposes.
Even if these resources exist {which they may not}, there is no guarantee that
they will be discovered in the appropriate time-frame {if ever} to assure
long-run supplies. Resources devoted to the discovery process by the major
oil firms will be largely determined by world market conditions, not surplus
or deficit conditions in the intrastate market.
In summary, under reasonable assumptions about in-state reserves and
consumption, the current inventory of hydrocarbon reserves is more than
adequate to meet the estimated demands of Alaskans for the next 15 years.
i i
L1 st of Tables
1.1 Base Year Consumption of AGAS Natural Gas In the
Resident! al Sectcr, 1970 to 1980 I .4
2.1 Utilities Reporting to the Alaska Fbwer
Administration 2.4
2.2 M:>tor Fue I Sa I es, 1982 2.8
2.3 Hlstcrlcal Motcr Fuel Sales: Rail Belt 2.9
2.4 HI storl ca 1 M:>tor Fue I Sales: Rest-of-State 2 .I 0
2.5 Hlstcrlcal Motcr Fuel Sales: Southeast 2.11
2.6 Historical M:>tor Fuel Sales: State 2.12
2.7 Gas Disposition and Sales, 1982 2.17
2.8 Historical Gas Disposition and Sales 2.19
2.9 Historical OJ I and Gas Consumption for
Electricity Generation 2.22
2.10 Historical Utility Electlclty Generated: Rail Belt 2.23
2.11 Historical Utility Electiclty Generated: Rest-of-State 2.24
2.12 Historical utility Electlclty Generated: Southeast 2.25
2.13 Historical Uti I ity Electlcity Generated: State 2.26
3.1 Projected Consumption of 011 and Gas 3.2
3.2 Projected Consumption of Vehicle Transport Fuel 3.8
3.3 Projected Consumption of 011 and Gas for Space Heat 3.14
3.4 Projected Consumption of Oil and Gas for Utility
Electrl city Generation 3.16
3.5 Projected Consumption of Oi I and Gas for Industry 3.22
4.1 Est I mated Recoverable 011 Reserves 4.2
4.2 Estimated Recoverable Gas Reserves 4.3
iii
4.3 Estimated fbyalty Share of Oi I 4.5
4.4 Est !mated Royalty Share of Gas 4.6
5.1 Surplus 011 Calculation 5.2
5.2 Surplus Gas Calculation 5.4
5.3 Sensitivity Analysis of Net Surplus 5.6
8.1 State Consumption of Motor Vehicle Diesel Fuel 8.3
8.2 Rail Belt Consumption of Electricity Net of
Space Heat! ng 8.5
8.3 Scheduled Southeast Alaska Hydroelectric Projects 8.8
D.l Population Projections 0.3
iv
Ll st of Fl gures
Page
2.A Study Regions 2.3
2.B Estimated 1982 Fuel Consumption 2.7
2.C Estimated 1982 Gas Dl sposltlon 2.15
2.0 Est I mated 1982 Gas Consumption 2.16
v
DEFINITIONS 1.0
AS 38.05.183 states that oil and gas taken in kind as the state's royalty
share of production may not be sold or otherwise disposed of for export from
the state until the Commissioner of Natural Resources determines that the
royalty-in-kind oil or gas is surplus to the present and projected intrastate
domestic and industrial needs for oil and gas. The statute also requires an
annual report to the state legislature showing the immediate and long-term
domestic and industrial needs of the state for oil and gas and an analysis of
how these needs are to be met.
The statute contains several key terms whose meaning must be resolved before
an estimate can be made of oil and gas surplus to the state's needs. These
key terms are: 1} "oil and gas," 2) 11 expm"t," 3) 11 present,"
4) 11 projected,11 5} "domestic," 6) "industrial," 7) "intrastate," and
8) "how these needs are' to be met." Each key term affects the size of the
estimated demand for oil and gas in Alaska and consequently, the size of the
projected surplus or deficit. The meaning of each term is discussed below.
Oi 1 and Gas
Crude oil and natural gas are fluids containing hydrocarbon compounds produced
from naturally occurring petroleum deposits. Typical crude oil contains
several hundred chemical compounds. The lightest of these are gases at normal
temperatures and pressure, described as "natural gas... These light fractions
of the crude oil stream include both hydrocarbon and non-hydrocarbon gases,
such as water, carbon dioxide, hydrogen sulfide, helium, or nitrogen. The
principal hydrocarbons are methane (CH4), ethane (C2H6), propane (C3H8),
butanes (C4Hl0), and pentanes (C5Hl2). The gaseous component is found most
often and in largest volumes, typically methane. Heavier factions of the
crude stream are usually liquids. If a given hydrocarbon fraction is gaseous
at reservoir temperatures and pressures, but is recoverable by condensation
(cooling and pressure reduction), absorption, or other means, it is classified
by the American Gas .Association (AGA) as a natural gas liquid (NGL) • ..!!
Natural gas liquids include ethane if ethane is recovered from the gas stream
as a liquid. A related term is liquified petroleum gas (LPG), composed of
hydrocarbons which liquify under moderate pressure under normal temperatures.
LPG usually refers to propane and butane. A second related term is
condensate, which refers to LPG plus heavier NGL component (natural
gasoline). The lightest hydrocarbon fraction is methane, which is almost
never recovered as a liquid, and which makes up the bulk of pipeline gas. If
a natural gas stream contains few hydrocarbons which are commercially
recoverable as liquids, it is considered 11 dry gas" or 11 lean gas ... The
distinction hetween 11 Wet 11 and "dry" is usually a legal one, which varies from
state to state. "Crude oil 11 usually means the non-gaseous portion of the
crude oil stream.
17 Definitions vary with processes.
1.1
Natural gas may occur in reservoirs which are predominately gas-bearing or in
reservoirs in which the gas is in contact with petroleum liquids.
Non-associated gas is natural gas from a reservoir where the gas is neither in
contact with nor dissolved in crude oil. Associated gas occurs in contact
with crude oil, but is not dissolved in it. A gas cap on a crude oil
reservoir is a typical example of associated gas. Dissolved gas is dissolved
in petroleum liquids and is produced along with them. Dissolved and
associated gases are usually good sources of NGL while non-associated gases
are often "dry."
The distinction between natural gas and its ~JGL components is important to a
study of the supply and demand of royalty oil and gas because natural gas
liquids have a multitude of uses when separated from the gas stream. For
example, propane is both produced in Alaska and sold in Alaska as bottled gas
for residential, commercial, and limited transportation uses, while butane is
used for blending in gasoline and military jet fuel and as a refinery fuel.
In addition, Marathon Oil uses LPG to enrich crude oil at its Trading Bay
facility. It ships the combined fluids to the Drift River terminal for
export.Y Potential uses for NGL also include the enriching ("spiking 11
) of
pipeline gas and crop drying. The Dow-Shell Petrochemical Group and Exxon
have also recently studied the feasibility of utilizing the NGL contained in
Prudhoe Bay natural gas as the basis for an Alaska petrochemicals industry.
Since the State has the option of considering t~GL separately from the gas
stream, two definitions of natural gas consumption and reserves are possible.
One of these would consider natural gas liquids as part of the gas stream.
The second definition would treat the markets for LPG and ethane separately
from those for gas. This requires a separate estimate of LPG consumption and
gas liquids reserves. In this report, demand for LPG and ethane is estimated
separately from that for gas; however, no separate estimate is made of gas
liquids reserves.
Export
Taken in context, this term appears to mean the direct physical sending of oil
and gas out of the state. However, when one considers the fact that much of
Alaska 1 s industrial use of oil and gas is processed directly for export
markets, the meaning of export versus 11 intrastate 11 is not so obvious. For
example, it appears that processing of gas into another product, e.g.,
anhydrous ammonia, would probably be an 11 industrial 11 use rather than 11export 11
of gas, even though the ammonia is mostly exported. Liquification to change
the phase of the gas is a less obvious case. The liquification of natural gas
will be considered a transportation process in this report. Still more
troublesome is the use of gas and oil for transportation related to export.
2/ Kramer, L., Williams, B., Erickson, G., In-State Use Stuqy for Propane and
Butane. Prepared for the Alaska Department of Natural Resources. Kramer
Associates, Juneau, October 1981.
1.2
Is the gas and oil consumed in TAPS pipeline pump stations, for example, an
''industrial .. use in state? Or is it really .. export" of that energy, since it
is consumed in the exporting process? There is no reason why the State may
not be approached in the furture to commit royalty oil and gas to quasi-export
uses. Indeed, a top dollar offer was made by the ALPETCO (later, Alaska Oil
Company) for royalty oil ultimately destined (as petrochemical products) for
out-of-state markets. Though the offer was made, payments in full were not
made. Also, the state once committed royalty gas to the El Paso gas pipeline
proposal for export of Prudhoe Bay gas, which involved liquefication. Neither
proposal was clearly for in-state industrial use. In this report, industrial
demand is treated with multiple definitions as outlined later in the chapter
to show how different definitions of "export" affect the estimate of total
consumption in Alaska.
Present
The problem here is that· the term "present" may mean "latest year"
consumption, "average recent year" consumption, 11 Weather-adjusted 11
consumption, or "worst case" consumption. In the residential and commercial
sector particularly, each definition gives a somewhat different answer because
of the variability of weather. Even the "worst case 11 scenario could be
interpreted in varying ways. Consider Alaska Gas and Service Company
residential gas consumption form 1970 to 1980. Base year present consumption
plausibly could be figured any of the ways shown in Table 1.1.
Obviously, based on even simple calculations like those in Table 1.1, the
"worst case" consumption calculation can result in considerably higher gas
consumption than the most recent year, if the most recent year happens to have
been a relatively warm one. While it is not correct forecasting procedure to
make long run forecast of intrastate residential consumption of natural gas
which assume worst case forecasts for every year, it may be prudent in
practice to reserve part of the the State's gas and oil supply for bad
weather. For forecasting, variability of weather makes the picking of a
starting value for consumption somewhat tricky. In this report, Rail Belt
consumption is based on average weather years. For the remainder of the
state, trended per capita consumption is used, which approximates average
weather conditions.
Projected
This is a very difficult concept, since many different projections of
consumption would be possible even if it were possible to agree on a single
concept defining consumption. Rates of economic development, population
growth, and re 1 ati ve energy prices -are key features of any consumption
forecast, but assumptions concerning any of these variables are necessarily
controversial. This report describes a range of possible consumption figures
under precisely articulated definitions of consumption and varying paces of
1.3
Base Year Consumptl on of AGN) Natura I Gas
In the Residencial ~ctor, 1970 to 1980
I. Actual Residential Consumption,
2. 1980 Tota I Based on Average O::msumpt ion
.3. 1980 Total Based on Weaiher-Mjusted
Average ConsumptIon Per OJstomer,
1970-1980
4. 1980 Total Based on HIghest Per Customer
Use, 1970-1980
5. 1980 Total Based on Most Recent Customer
Per Degree Day Use and Coldest Waather
Year 1970-1979 (21.4.3 cf/HDD/customer x
.35,482 customers x 12,016 H>D>.!!
TAaE 1.1
7.577 BCF
7.794 BCF
8.08.3 BCF
8.416 BCF
9.1.37 BCF
<.!!> cf =cubic feet; BCF = billion cubic feet, HOD= Heating degree
days.
1.4
economic, population, and fuel price growth. The economic and population
forecasts used in this report were done by the University of Alaska Institute
of Social and Economic Research in December, 1982. The assumptions used to
run their economic model are shown in Appendix D.
Domestic
Domestic consumption appears to mean Alaska residential consumption. As we
saw above under the subheading "present", it is not at all obvious which
definition of domestic consumption is the most appropriate, even when the
identity of the customer is not in dispute. Some multifamily residential use
may be described as "commercial,11 obscuring the definition of the customer and
causing forecasting problems for natural gas. The definition of 11 domestic 11
used in this report considers multifamily residential as 11 residential 11 and
11 domestic 11 use, rather than commercial.
Industrial
As described above, 11 industrial 11 energy use has a number of potential
definitions. Since one intent of giving in-state industrial needs priority
over export uses of royalty oil and gas seems to be to encourage in-state
economic activity, 3/ a day-to-day working definition of this priority is
that the royalty reserves be committed to the market, such as Alpetco, which
has the largest potential economic impact in Alaska. For forecasting
purposes, however, it is difficult to say which markets will prove to be of
the most economic benefit to the state. As a compromise, we will adopt four
alternative definitions of "industrial" in this study.
The four alternative definitions of industrial use of oil and gas used in this
report are outlined below, beginning with the most restrictive and moving to
the most liberal.
Definition 1: Industrial use consists of any consumption of natural gas,
petroleum, or their products in combustion (except that required to export
oil or gas); or the chemical transformation of natural gas, petroleum, or
their products into refined products for local markets. This definition
explicitly excludes the exported products from refineries, as well as uses
which merely change the phYsical form of the product (gas conditioning or
liquefaction) for export, or which move the product to an export market
(pipeline fuel, fuel used on lease, shrinkage, injection, vented and
flared gas).
Definition 2: Industrial use consists of any consumption of natural gas,
petroleum, or their products in combustion (except in oil and gas
production and transportation); or the chemical transformation of natural
3/ see however, the short discussion of legislative intent beginning on page
~of Kramer, Williams and Erickson, op. cit. That study raises many of the
issues regarding surplus gas and oil discussed in this report.
1.5
gas, petroleum, or their products into refined products. This definition
counts feedstocks for petrochemical plants and refineries as industrial
consumption. It also counts energy consumed by an LNG facility as
industrial consumption. It excludes the feedstocks of LNG plants and fuel
consumption by conditioning plants, pump stations, fuel used on lease,
shrinkage, injection and flared gas.
Definition 3: Industrial use consists of any consumption of natural gas,
crude oil, or their products in combustion {except in oil and gas
transport and extraction) or their chemical transformation into refined
products. This definition permits the feedstocks of refineries to be
counted as industrial consumption. It excludes fuels used in pump
stations, in conditioning plants, fuel used on lease, and gas shrinkage,
injection, or venting.
Definition 4: Industrial use consists of any use of natural gas, crude
oil, or their products in combustion, or their transformation into
chemically different products. This definition permits feedstocks of
refineries to be counted as industrial consumption, as well as energy
consumption in conditioning plants and pump stations. It excludes
injected gas, which is ultimately recoverable for other uses, and LNG,
which is considered an export. Definition of 4 will be used for the
purposes of this report.
None of the four definitions treats industrial use {including transportation)
to include gas injected to enhance oil recovery, since in theory this gas
remains part of the ultimately recoverable gas reserves of the state. Thus,
is not 11 Consumed.11
Intrastate
It is unclear what is meant by intrastate consumption. Some uses, such as
combustion of oil and gas products in fixed capital facilities in Alaska, are
reasonably easy to categorize as intrastate. There are several uses in
transportation which are not obviously within Alaska. These categories
include the fuel burned in marine vessels such as cargo vessels, ferries, and
fishing boats, and fuel burned in international and interstate air travel.
There are multiple ways to approach the definition of this consumption. The
first is a sales definition: the fuel used in transportation which is sold in
Alaska. The second approach is to base consumption on fuel used in Alaska or
related to Alaska•s economy and population, regardless of the point of sale.
This results in three logical definitions, described below:
Definition 1: Intrastate consumption in transportation includes all sales
of fuels to motor vehicles, airplanes, and vessels in Alaska, including
bonded fuels. It excludes fuel consumed by motor vessels which was
purchased in other states, and fuel consumed by airlines between Alaska
locations unless the fuel was sold in Alaska. It also excludes out of
state military fuel purchases.
1.6
Definition 2: Intrastate consumption includes fuel consumed by motor
vessels, airlines, and vehicles engaged in Alaskan economic activity. It
includes use of fuel by American fishing boats in Alaskan waters
regardless of where the fuel was purchased, use of fuel purchased in
Washington State by Alaska State ferries, and fuel consumed by ships and
aircraft involved in Alaska trade. It excludes sales to aircraft on
international flights (bonded and unbonded), but includes military out of
state purchases.
Definition 3: The final definition is a compromise between the first
two. It includes all fuel purchased within the state, plus military uses,
but excludes fuel purchased out of state except for military uses.
The basic definition in this report is the third definition. By excluding
bonded and exempt jet fuel, the report also approximates Definition 2. Lack
of data on out-state purchases by the military makes Definition 1 impractical.
How These Needs Are To Be t4et
Any analysis of how the oil and gas needs of intrastate domestic and
industrial sectors are to be met could include several sources of supply:
state royalty oil and gas, in-state oil and gas reserves under other
ownership, probable extensions of proven reserves, and imports of crude oil,
petroleum products, and (in theory) natural gas. Since some of the state's
needs are currently met with imported petroleum products, the state seems to
be allowed to export oil and gas as long as in-state needs are being met from
some source. This meets the intent of other parts of Alaska state law to
receive top dollar for the State's royalty oil and gas. Since it may be
cheaper to meet certain of Alaska's energy needs with imported products than
with instate refineries, AS 38.05.183 might all0\'1 the state to seek buyers for
its royalty oil who are willing to pay more than Alaska refiners and ship
petroleum products back to Alaska at competitive prices. The intent of the
law does not seem to be actual Alaska self-sufficiency in petroleum and gas
products; rather, it seems to be aimed at adequate overall supplies. It may
permit intrastate uses to be met from a variety of sources as long as they are
identified and discussed. Thus, it might be acceptable to say that
consumption can be met with imported product, even while exports are taking
place, so long as it benefits Alaskans. This is the position taken in this
report.
The only problems occur if the cost of imported product were significantly
above the cost of products which could be refined in Alaska, or if Alaska
users were suffering an absolute shortfall in petroleum products which could
be made up by product shipped from out of state. In such a circumstance, the
state might not be able to continue exporting.
1.7
OIL AND GAS CONSUf~PTION 2.0
METHODOLOGY 2.1
In this chapter the State of Alaska is divided into three regions: Rail Belt,
Rest-of-State and Southeast. Figure 2.A shows the three regions, Judical
Districts and pertinent Census Areas. Each region has distinctive energy
consumption patterns which reflect differing geography, economic activity and
mixes of available fuels.
Oil Consumption
All or nearly all oil consumed in Alaska is consumed as fuels. The Alaska
Department of Revenue's monthly Report of Motor Fuel Sold or Distributed in
Alaska for January through June were used for projecting 1982 fuel
consumption. During this period, data were reported by Judicial Districts
(JD). Fuel data for Judicial Districts were allocated to the three regions of
this chapter by computing:
Rail Belt= population share X (JO III+ JD IV)
Rest-of-State = JD I I + JD II I + JD IV -P.ai 1 Belt
Southeast = JD I
where: the Rail Belt population share of (JD III + JD IV) = 85%. The
population of Rail Belt as delineated on Figure 2.A included:
urban and rural population of:
within Rail Belt boundary,
urban and areal share of
rural population of:
Anchorage Borough
Fairbanks Northstar Borough
Prince William Sound census subarea
Kenai Peninsula Borough
Matanuska-Susitna Burough
Southeast Fairbanks census area
Valdez-Cordova Census Are~
Yukon-Koyukuk Census Area!!
These computations assume that the Rail Belt/Rest-of-State population ratio
within JD III and JD IV has not changed significantly since the 1980 census.
Natural Gas Disposition and Consumption
Estimated gas disposition figures for 1982 were derived from several sources.
Primary categories of gas use were comoiled from monthly Oil and Gas
Conservation Commission {OGCC) reports~ for January through July. The OGCC
categories are: Injection, Vented, Used (on Leases}, Shrinkage Other and sales.
l! U.S. Department of Commerce, Bureau of the Census, 1980 Census of
Population, Number of Inhabitants, Alaska, PC80-1-A3, November, 1981.
2/ Alaska Oil and Gas Conservation Commission, State of Alaska Report of
Gas Disposition, monthly publication.
2. 1
The 11 0ther 11 category applies only to North Cook Inlet and Prudhoe Bay fields
and tlas handled differently for the t\'40 fields. For tdorth Cook Inlet 11 0ther 11
was ignored because its volume was included in "Sold 11
• For Prudhoe Bay
11 0ther" \rJas merged with 11 Used 11 category because this volume is consumed by the
Central Compression Plant.
Gas 11 Sa 1 es 11 was subdivided by major purchaser·s. Data for these subdivisions
came from consumers themselves and from Dt1H1 royalty receipts. Specific data
sources are identified in footnotes to Tables 2.7 and 2.8.
Oil and Gas Consumption for Electricity Generation
H1storical data on fuels used to generate electr1city were compiled from
Alaska Power Authority (APA) publications.~ Each local utility reports
generation information to APA so allocation into the three regions is easily
done (See Table 2.1). The APA report for 1982, however will not be available
·until after this report is produced. While it was possible, using gas sales
data, to project the amount of gas used in 1982 for power generation, it was
not feasible to extrapolate the amount of oil used for generation of
electricity. Oil fired generations figures are therefore the product of
modeling described in Chapter 3.
3/ U.S. Department of Energy, ,n.laska Power Administration,
Alaska Electric Power Statistics, 1960-1981 , Seventh Edition, August, 1982
Alaska Electric Pm,ter Statistics, 1960-1~80, Sixth Edition, August, 1981
Alaska Electric Power Statistics, 1960-1976, Fifth Edition, July 1977
2.2
N 2
\.:.)
3
I
I
{ ,-...... ,-___ ,.._/
/
Fig. 2A Study Regions
CENSUS UN ITS
1 Anchorage Borough
2 Fairbanks Northstar Borough
3 Kenai Peninsula Borough
4 Matanuska Susitna Borough
5 Prince William Sound census subare
6 Southeast Fairbanks census area
7 Valdez-Cordova census area
8 Yuko~-Koyukuk census area
/
Judicial District
Boundaries
Railbelt
Boundary
Utilities Reporting to the Alaska Power Administration
Railbelt
Anchorage
Chistochi na
Dot Lake
Eng! ish Bay
Fa lrbanks
Glennallen
Homer
KenaI
Northway
Palmer
Paxson Lodge
Port Graham
Seldovia
Seward
Talkeetna
Tok
Valdez
Pest-of-state
Alakanuk
Pmb I er
Anaktuvak Pass
Aniak
Anvik
Atkasook
Barrow
Bathe I
Bettles
Chevak
Cold Bay
Cordova
Deadhorse
Di IIi ngham
AI eknag I k
Eek
El im
Emmonak
Ft. Yukon
Gambell
Goodnews Bay
Gray II ng
Holy Cross
1-boper fBay
Huslia
II iamna
Newha len
l'bnda I ten
Kaktovik
Ka I skag 1 Lower
Ka I skag, Upper
Kaltag
Kiana
Kiva! Ina
Kodiak & Pt. Lions
Kotzebue
Koyuk
Koyukag 1 Lower
Lake ~1inchumlna
Larsen Bay
Man ley Hot Sprl ngs
tvenokotak
Marsnal I
McGrath
Mekoryuk
Minto
Mt. Village
Naknek
Egegik
Napakiak
New Stuyahok
Nlkol skI
Noatak
Nome
Noorvik
!'til gsut
Nulato
Nunapitchuk
Kasigluk
01 d Harbor
Pi lot Station
Point Hope
Point Lay
Point Lions
Quinhagak
St. Mary's
Pltkas Point
Andreafsk i
St. Ml chael
Sand Point
Savoonga
Scammon BAy
Se I aw lk
Shageluk
Shaktool lk
Shi smaref
Shungnak
stebbins
Tanana
Teller
Togiak
Toksook Bay
Tununak
Unalakleet
Unalaska
Wainwrl ght
Wales
2.4
TABLE 2.1
S::>u thea s t
Angoon
Craig
Haines
1-bonah
Hydaburg
Juneau
Kake
Kasaan
Ketchikan
Klawock
Kl ukwan
~tlakatla
Pelican
Petersburg
51 tka
Skagway
Tenakee SprIngs
Wrangell
Yakutat
OIL CONSUMPTION 2.2
Estimated 1982 consumption of petroleum fuels is tabulated on Table 2.2. and
graphed on Fig. 28. All figures in the text below are estimates of 1982 fuel
consumption. Consumption figures for 1977-82 are listed on Tables 2.3 through
2.6.
It is important to recognize that data for 1981 and 1982 are not comparable
with each other nor with preceeding years. This is because, though the fuel
category names have remained the same during 1981 and 1982, several types of
fuel use have shifted from category to category during both years. Footnote 4
following Table 2.6 lists the current end-uses of fuel categories.
State Consumption
Aviation fuels accounted for 41.0% of state fuel consumption, most of this,
39.1%, being aviation jet fuel. Highway fuels accounted for about the same
percentage as aviation fuels, 39.9%, but this was apportioned between highway
diesel, 22.0% and highway gasoline, 17.9%. Off-highway diesel accounted for
13.1% of state consumption and marine fuels accounted for 6.0%, most of which
was diesel.
Regional Consumption
The Rail Belt, the most heavily populated and industrialized region, relies on
a mix of petroleum, natural gas, coal and nYdroelectricity for its energy
needs. This variety increases security of supply and stability of price for
consumers. The Rest-of-State region relies primarily on petroleum fuels,
though Barrow and Prudhoe Bay needs are supplemented by local natural gas
supplies. The Southeast region energy requirements are almost totally
supplied by petroleum (by tanker and barge) and hydroelectricity. The
Rest-of-State and Southeast are thus more vulnerable than the Rail Belt to
fluctuations in the world oil market.
The Rail Belt uses 70.9% of the petroleum fuels consumed in the state, whereas
Rest-of-State uses 21.0% and the Southeast uses 8.1%. Each region has a
distinctive fuel use pattern.
-Rail Belt. Aviation fuels account for 48.0% of the region's consumption
nearly all of which, 46.1%, is aviation jet fuel. Highway fuels account for
35.3% of regional use, divided between gasoline at 19.0% and diesel at 16.3%.
Off-highway diesel consumes 10.9% and marine fuels account for 5.8%, most of
which is diesel. Much of this marine fuel is consumed at Valdez by tankers
which transport Prudhoe Bay and Kuparuk River oil.
-Rest-of-State. Highway fuels are the dominent categories, totaling 56.8% of
regional use. Highway diesel is the largest single catagory, consuming
42.5%. This diesel is used in large volumes by pipeline companies for
electric generation and by construction companies for trucks hauling heavy
equipment. Aviation fuels total 30.4% and off-highway diesel accounts for
9.2% of regional use. Marine fuels, sold principally at Cordova, Kodiak and
Dutch Harbour and a few ports in southwest Alaska, account for 3.6%, most of
which is diesel.
2.5
-Southeast. The major regional use is off-highway diesel, at 42.5%. Highway
fuels consumed 36.9% of the local fuel budget, divided nearly equally between
diesel at 18.8% and gasoline at 18.1%. Marine fuels use, 13.3%, is
proportionally higher than in other regions. Aviation fuel use, at 7.3%,
however, is proportionally much lower than in Rail Belt or Rest-of-State.
2.6
Fig 2.8 ESTIMATED 1982 .FUEL CONSUMPTION
FUEL CONSUMPTION
STATEWIDE
100°/o OF STATE CONSUMPTION
1,080.202 MILLION GALLONS
FUEL CONSUMPTION
RAIL BELT
70.9°/o OF STATE CON.
765.554 MIL.GAL.
FUEL CONSUMPTION
REST-OF-STATE
21°/o OF STATE CON.
226.500 MIL.GAL.
MID
3.3%
7.408
MIG
0.3%
.640
FUEL CATEGORY
A/J-AVIATION JET
A/G-AVIATION GAS
A/B-AVIATION BONDED
H/G-HIGHWAY GAS
/
H/D-HIGHWAY DIESEL
OHD-OFF HIGHWAY DIESEL
M/G-MARINE GAS
H/G MID-MARINE DIESEL
19.0%:::;--___
144·482--__-----VOLUME PERCENTAGE WITHIN GRAPH
---_VOLUME IN MILLION GALLONS
?.7
FUEL CONSUMPTION
SOUTHEAST
8.1 °/o OF STATE CON.
88.148 MIL. GAL.
H/D
18.8%
16.602
H/G
18.1%
15.946
M/D
\HIL7%
\0.284
M/lj
1.6 Yo
1.434
A/J
5.60f,:,
4.936
Motor Fuel Sales, 1982 ]j' ~ (Million Gallons) TABLE 2.2
RAILBEL T REST-OF SOUTH STATE
-STATE -EAST
Aviation-Jet 352.666 65.128 4.936 422.730
Aviation-Gas 9.194 2.822 1.482 13.498
Aviation-Bonded 5.578 .984 .000 6.562
Highway-Gas 144.482 32.456 15.946 192.884
Highway-Diesel 125.088 96.320 16.600 238.008
Highway-Other .014 .006 .002 .022
Off-Highway Diesel 83.714 20.736 37.464 141.914
Marine-Gas 3.184 .640 1.434 5.258
Marine-Diesel 41.634 7.408 10.284 59.326
Subtotal 765.554 226.500 88.148
Total 1,080.202
2.8
Historical Motor Fuel Sales: RAILBELT 1f (Million Gallons) TABLE 2.3
1977 1978 1979 1980 1981 1982 !!I
Aviation -Jet
Taxable !J-555 _y.183 102.585 106.451 123.660 281.258
Exempt 189.785 163.754 129.194 71.408
Aviation -Gas
Taxable _i?-413 _i?-370 11.339 11.242 12.365 8.844
Exe~t .453 .345 .341 .350
Aviation Bonded y Exempt 37.189 67.986 95.229 80.754 5.578
Highway -Gas
Taxable 14.023 140.250 133.261 128.190 133.050 138.532
Exempt 5.094 8.290 7.527 8.162 7.032 5.950
Highway -Diesel
Taxable 118.999 101.598 56.597 64.791 69.606 118.792
Exempt 45.162 54.050 39.477 23.935 11.506 6.296
Highway -Other y y Taxable 91.562 116.897 47.425 .014
Off-Highway Diesel y y Exempt 81.483 97.004 47.438 83.714
Marine -Gas
Taxable 6.059 7.160 8.004 7.573 4.553 3.180
Exempt .384 .554 .292 .025 .026 .004
Marine -Diesel
Taxable 32.217 41.869 53.167 62.341 47.018 39.904
Exempt 6.396 10.116 6.325 5.370 4.149 1.730
Marine -Non-propulsion y y y y y Exempt 5.323
Marine -Other
Taxable .593 £79.228 y .258 y .020 y .002 y .ooo
Exe~t .998
Historical Motor Fuel Sales: REST-OF-STATE 1/ (Million Gallons) TABLE 2.4
1977 1978 1979 1980 1981 ~!:±/
Aviation -Jet
Taxable _i?-844 »-057 18.691 19.863 24.142 52.358
Exempt }0.977 26.750 22.917 12.770
Aviation -Gas
Taxable ij-984 ij-232 3.217 3.400 }.929 2.662
Exempt .075 .099 .122 .160
Aviation Bonded y y y y Exempt 14.251 .984
Highway -Gas
Taxable 11.994 1.?-688 26.675 26.675 29.294 }1.158
Exempt 1.146 1.316 1.418 1.298
Highway -Diesel
Taxable 11.512 17.878 23.462 39.833 74.455 91.322
Exempt 9.801 7.053 4.7}4 4.998
Highway -Other y y Taxable 12.619 16.366 8.370 .006
Off-Highway Diesel y y Exempt 14.635 19.307 16.102 20.736
Marine -Gas
Taxable i/.690 1}-144 1.316 1.375 1.316 .636
Exempt .053 .005 .006 .002
Marine -Diesel
Taxable l]-684 jJ-804 6.366 7.902 9.230 7.100
Exempt .830 .742 .733 .306
Marine -Non-propulsion y y y y y Exempt .883
Marine -Other
Taxable y .107 _?)-089 y .061 y .015 y .ooo y .ooo
Exempt
2. 10
-,
Historical Motor Fuel Sales: SOUTHEAST 1( (Million Gallons) TABLE 2.5
1977 1978 1979 1980 1981 1982!!!
Aviation -Jet
Taxable ~.765 "J]·l67 4.914 3.760 4.756 4.644
Exempt .226 .377 .503 .292
Aviation -Gas
Taxable g•852 g•543 1. 757 1.712 1.886 1.420
Exempt .023 .ll5 .lll .062
Aviation Bonded y y y y Exempt .ooo .ooo
Highway -Gas
».131 13.867 Taxable »·102 14.612 15.018 15.262
Exempt .590 .570 .634 .684
Highway -Diesel
"J}·731 6.578 Taxable '19•746 7.293 9.506 8.420
Exempt 5.660 6.144 6.584 8.180
Highway -Other y y Taxable .002 .003 .002 .002
Off-Highway Diesel y y Exempt 20.157 26.192 30.710 37.464
Marine -Gas
Taxable _g.135 _g.l28 2.075 1.739 1.646 1.430
Exempt .103 -.Oll .053 .004
Marine -Diesel
Taxable if·107 !)·713 9.888 10.569 10.881 9.892
Exempt .498 .lll .271 .392
Marine -Non-propulsion y y y y y Exempt .667
Marine -Other
Taxable y .131 y-139 y .134 y .045 y .002 y .ooo
Exempt
2. 11
Historical Motor Fuel Sales: STATE 1/ (Million Gallons) TABLE 2.6
1977 1978 1979 .J1!iQ. 1981 1982 !!/
Aviation -Jet
Taxable 103.163 113.006 126.190 130.074 152.558 338.262
Exempt 190.392 220.789 220.988 190.881 152.614 84.468
Aviation -Gas
Taxable 15.249 15.145 16.373 16.354 18.180 12.926
Exempt 1.521 .685 .552 .558 .574 .572
Aviation Bonded
Exempt 37.189 29.812 67.986 95.229 95.005 6.562
Highway -Gas
Taxable 181.119 179.069 173.802 169.191 177.362 184.952
Exempt 5.094 8.290 7.527 8.162 9.084 7.932
Highway -Diesel
101.598 Taxable 118.999 56.597 64.791 153.567 218.534
Exempt '45.162 54.050 39.477 23.935 22.824 19.474
Highway -Other y y Taxable 91.562 116.897 55.797 .022
Off-Highway Diesel y y Exempt 81.483 97.004 94.250 141.914
Marine -Gas
Taxable 6.059 7.160 8.004 7.573 7.517 5.248
Exempt .384 .554 .292 .025 .085 .010
Marine -Diesel
Taxable 32.217 41.869 53.167 62.341 67.129 56.896
Exempt 6.396 10.116 6.325 5.370 5.153 2.430
Marine -Non-propulsion y y y y y Exempt 5.323
Marine -Other
Taxable .593 .g9.228 y .258 y .020 y .002 y .ooo
Exempt .998
2. 12
1/ Alaska Department of Revenue, Report of Motor Fuel Sold or Distributed In
Alaska, monthly reports.
2/ Data not reported.
~ Data not reported by Judicial District
4/ Current (12/1982) major end-uses of fuel categories (Exempt fuels, except
for Aviation Jet Exempt, are sold to Federal, State and local governments
and to charitable institutions):
Aviation -Jet
Taxable
Exempt
A vi ati on -Gas
Aviation -Bonded
Highway -Gas
Highway -Diesel
Highway -Other
Off-Highway Diesel
Marine -Gas
Marine -Di ese 1
Ma ri ne -Other
Commercial and private: domestic flights
Commercial: foreign flights (this use continues
to shift from Aviation-Bonded to this category).
Commercial and private: domestic and foreign
flights
Jet fuel for commercial foreign flights (this
use continues to shift from this category to
Aviation Jet Exempt).
Highway vehicles and construction industry.
Highway vehicles and construction industry
(non-public utility turbine fuel shifted from
Highway-Other to this category).
Category closed July, 1982 (major use as non-
public utility turbine fuel shifted to Highway
Di ese 1).
Power generation and heating fuel (heating fuel
use has shifted to this catagory since mid 1981).
use in or on watercraft
Use in or on watercraft
Fuel additives
2. 13
GAS DISPOSITION AND CONSUMPTION 2.3
Estimated 1982 figures for natural gas disposition and consumption are shown
on Table 2. 7, with 1981 figures added for comparison. In the foll O\'li ng text,
all percentages are of estimated 1982 gas consumption. In principle, gas
which has been extracted then injected has not been consumed; most is
available for later extraction, though sor~e is 11 used 11 in maintaining oil field
reservoir pressure. For this reason, Fig. 2.C shows state and regional
disposition of all gas extracted in l!l82, \'lhereas Fig 2.0 shows the end use of
gas actually consumed. Gas disposition and consumption figures for 1971-1982
are shown on Table 2.8.
State Disposition and Consumption
Of the gas extracted in 1982, 74.5% was injected, 18.6% was sold and 6.9% was
consumed in field operations. Overall 1982 gas extraction increased by 9.6%
over 1981. Injection increased by 11.5% and field operations, including
venting, used on leases, shrinkage and other, increased by 12.6% over 1981
levels. These increases were primarily due to Kuparuk River field production
which began in December, 1981. Total state sales categories increased by 1.7%
over 1981 •
Regional Disposition and Consumption
All of Alaska•s gas is extracted in the Rail Belt, in and around Cook Inlet,
and in Rest-of-State at Barrow, Prudhoe Bay and Kuparuk River fields. The
extraction/consumption ratios of the two regions are quite different. ~·1ost of
the state•s gas is extracted in the Rest-of-State region but a great
proportion of that gas is injected and little is consumed. The Rail Belt,
however extracts less total volume of gas but more of that extracted gas is
consumed and less is injected than in Rest-of-State.
-Rail Belt. Of the gas extracted in this region in 1982, 66.2% was consumed,
59.2% in sales and 7.0% in field operations. The remaining third was injected.
Liquification of natural gas accounted for 31.2% of gas sales while the
manufacture of Ammonia -Urea consumed 27.4%. Other regional uses accounted
for about one-quarter of the regional consumption, power generation at 17.4%
and gas utilities at 8.7%.
-Rest-of-State. Virtually all of the region•s gas is extracted from Prudhoe
Bay and Kuparuk River fields. South Barrow field is locally important, but
produces only 0.07% of the region•s gas.
By far the largest part, 91.3%, of the extracted gas was injected, whereas
6.8% went to field operations and 1.9% was sold.
Of the gas consumed, 78.9% was used in field operations. t~st of the
remainder was sold to TAPS or used by Prudhoe Bay refineries. Non-industrial
sales at Barrow accounted for 1.4% of regional consumption, 0.8% for utilities
and 0.6% for power generation.
2. 14
Fig. 2.C ESTIMATED 1982. GAS DISPOSITI'ON
NATURAL GAS DISPOSITION
STATEWIDE
NATURAL GAS DISPOSITION
RAIL BELT
29.30Jo OF STATE EXTRACTION
305.043 BCF
71.470
DISPOSITION
IOO.Oo/o OF STATE EXTRACTION
1,039.747 BCF
NATURAL GAS DISPOSITION
REST-OF-STATE
· 70.7°/o OF STATE EXTRACTION
734.704 BCF
s
1.9%
13.500
F
6.8%
50.158
~ F-FIELD OPERATIONS U
-INJECTION
I
~ S-SALES
33·8 %----VOLUME PERCENTAGE WITHIN GRAPH 103·138 VOLUME IN BCF
2. 1 5
Fig. 2.0 ESTIMATED 1982 GAS CONSUMPTION
NATURAL GAS CONSUMPTION
STATEWIDE
100.0°/o OF STATE CONSUMPTIO~
265.563 BCF
22.045
NATURAL GAS CONSUMPTION
RAIL BELT
NATURAL GAS CONSUMPTION
REST-OF-STATE
76.0°/o OF STATE CONSUMPTION
201.905 BCF
24.0°/o OF STATE CONSUMPTION
63.658 BCF
0
4.7°/o
9.488
CONSUMPTION USE
F -FIELD OPERATIONS
L-LNG
A -AMMONIA-UREA
P-ELECTRIC POWER GENERATION
U -GAS UTILITIES
A 0-0THER SALES
27.4%----
55·319----------VOLUME PERCENTAGE WITHIN GRAPH
----VOLUME IN BCF
2. 1 G
12.557
Gas Disposition and Sales, 1982 (BCFl TABLE 2. 7
1981 1982 1/
STATE RAIL BELT REST-oF SOUTH STATE CHAI\GE,
-STATE EAST 1981-82
lnjectrortf 694.196 103.138 671.046 0 774.184 +II. 5$
Field Operations:
Vented, Used, 63.485 21.312 50.158 0 71.470 +12.6%
Shrinkage, Other.Y
SatesY 190.873 180.593 13.500 0 194.093 +I. 7$
L~ 68.823 62.903 0 0 62.903 -8.6%
Ammon I a Ure~ 53.707 55.319 0 0 55.319 +4.2$
Power Generatlo~ 33.631 35.216 .404 0 35.620 +4.9$
Civilian (29.072) (30.544) ( .404) 0 (30. 948)
Military (4.56) (4.672) 0 0 (4.672)
Gas Uti IItie~ 16.215 17.667 .539 0 18.206 +12.3%
Res I dentlal (8 .386) (9.215) (. 539) 0 (9.754)
Commercial (7 .829) (8.452) 0 (8.452)
Other Sales.¥ 18.497 9.488 12.557 0 22.045 +19.2
Producers (6.009) (9.488) (9.488)
RefIners (.414) (. 467) (. 467) +12.8%
TAPS (11.106) (11.942) (I I. 942 > + 7.5%
Ml sc. (. 968) (. 148) (.148)
Sub Totai.Y 305.043 734.704 0
TOTM3f 948.554 1,039.747 +9.6%
2. 17
l/
2/
3/
Estimated from part-year reports of sources cited below.
Alaska Oil and Gas Conservation Commission, State of Alaska Report
of Gas Disposition, monthly reports.
Alaska Division of Minerals and Energy Management royalty reports
from producers.
Alaska Public Utilities Commission, annual reports from vendors,
Alaska Oil and Gas Commission, op.cit. and personal communications
with Alaska Gas and Service, Kenai Service Utility and Barrow
Utilities and Electric Cooperative.
2.18
Historical Gas Disposition and Sale~ <BCFl TABLE 2.8
1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981' '. 1982.!.!
RAILE£LT
I nj ectlon 73.88 76.13 87.78 86.81 95.183 I I I .082 115.131 114.074 119.825 115.4 100.410 103.138
Fie I d Operations:
Vented, Used on Leases, 45.25 36.56 20.90 23.89 28.830 24.466 24.396 23.524 17.520 28.0 20.569 21 .312
Shrinkage
Sales
LN3~ 63.24 59.87 6.().99 61 .87 64.777 63.509 66.912 60.874 64.111 55.3 68.823 62.903
Ammonia Urerf! 19.49 20.58 20.64 2.10 23.888 24.257 28.620 48.879 51 .657 47.6 53.707 55.319
Power Gena-at!~ 10.31 13.16 15.48 17 .I I 19.619 22.188 23.590 24.591 28.155 28.7 29.072 30.544
N Mi I itary~ 6.549 6.473 6.069 5.684 5.842 5.424 5.100 5.126 4.986 4.8 4.560 4.672
1..0
Gas Uti I iti es7.! 8.243 8.952 9.653 9.816 I 2.044 12.552 12.683 I 3.454 14.045 15.5 16.215 17.667
Other Sales 0.97 1.08 1.59 1.16 2.371 I. 775 3.529 3.277 4.757 5. I 5. 732 9.488
REST -lf -STATE
Injection 68.080 271 .854 390.136 546.5 593.786 671 .046
Fie I d OperatIons:
Vented, Used on Leases, Other 2.808 3.856 24.444 29.231 33.763 39.6 42.916 50.158
Sales 1.037 2.053 3.347 7.802 9.512 12.0 12.764 13.500
STATE
Injection 694.196 774.184
Fie I d Operations:
Vented, Used on Leases, Other 63.485 71 .470
Sales 190.873 194.093
TOTAL 256.399 71 .162 375.832 602.687 738.485 898.554 948.554 I ,039. 747
1/ Estimated from part-year reports of sources cited below.
2/ All data, except where specifically cited, from Alaska Oil and Gas
Conservation (OGCC), State of Alaska Report of Gas Disposition, monthly
reports.
3/ For 1971-74: Stanford Research Institute (SRI), Natural Gas Demand and
Sup ly to the year 2000 in the Cook Inlet Basin of South Central Alaska,
Novem er : sum o pro uct1on rom Kena1 an Beaver ree
gas fields, reported in Alaska Oil and Gas Conservation Commission (OGCC),
Kenai Gas Sales and 2) sales from North Cook Inlet gas field reported in
OGCC, op.cit.; 1980: direct communication with Phillips Petroleum Company;
1981-82, Alaska Division of Minerals and Energy Management, royalty
reports from producer.
4/ For 1971-74: SRI, op.cit.; 1975-79: sum of 1) sales from Kenai and Beaver
Creek gas fields to Collier Chemical reported in OGCC, Kenai Gas Sales and
2) sales from McArthur River gas field reported in OGCC, op.cit.; 1980:
direct communcation with Union Oil Co.; 1981-82: Alaska Division of
Minerals and Energy Management royalty reports from producers.
5/ For 1971-74: SRI, op.cit.; 1975-80: sum of 1) sales reported by Anchorage
Natural Gas to Alaska Public Utilities Commission (APUC) and 2) deliveries
from Beluga River gas field to Chugach Electric, reported in OGCC,
op.cit.; 1981-82: APUC annual reports from vendors, personal
communications with Alaska Gas and Service and OGCC, op.cit.
6/ For 1971-80: Sales reported by Anchorage Natural Gas to APUC, op. cit.;
1981-82: personal communications with Alaska Gas and Service.
Zf For 1971 -1975 Gas Rate Schedule revision: internal records of Anchorage
Natural Gas; 1975-81: sales reported by Anchorage Gas and Service Co. and
Kenai Utility Service Corp. to APUC, op. cit.; 1982: personal
communication with Anchorage Gas and Service and Kenai Utility Service.
2.20
OIL AND NATURAL GAS CONSUMPTION FOR ELECTRICITY GENERATION
Table 2.9 lists the oil and gas consumed for electricity generation in the
three regions for the last eleven years. Following the surge of energy
consumption during the Alaska Pipeline construction years~ oil fired
generation has decreased in the Railbelt and Southeast.
2.4
-Rail Belt. In the Railbelt the diminishing oil share is being replaced by
an increasing gas share. Industry and population growth plus the
attractive pricing of natural gas have contributed to this increase.
-Rest-of-State. Gas used in Rest-of-State is primarily at Barrow. This use
is increasing though absolute quantities are small. Oil use is increasing
reflecting increased exploration and development activity for oil~ gas and
minerals.
-Southeast. The South~ast's population growth has leveled off. This
leveling off has resulted in tapering oi1 use with a very slight increase
in hydroelectricity.
Tables 2.10 through 2.13 show net generation by fuel for the three regions and
the state.
-Rail-Belt. Since 1976 the oil share has decreased while the gas share has
increased. Increases in oil prices versus more attractive gas prices
account for this. The coal share has also declined whereas the
hydroelectric share has remained relatively steady, varying seasonally with
1 oad needs.
-Rest-of-State. The Rest-of-State use is all oil and natural gas with gas
starting to make inroads by 1976. Oil and gas shares have not change
significantly. Absolute quantities are increasing, primarily due to
increased oil field activity.
-Southeast. Electric generation in the Southeast is presently split
approximately 4 to 1 by hYdroelectric and petroleum fuels.
2.21
Historical Oil and Gas Consumption for Electrl.clty Generation 1/ TABLE 2.9
RAIL BELT REST-OF-STATE SOUTHEAST
Oil Gas Oil Gas 5/ Oil Gas
(Mi Ilion Gallons) (BCFl (Million Gallons) (BCF> (Million Gallons) CBCF>
i971 9.903 9.980 4.859 .22 4.299 0
1972 9.882 12.780 7.345 .332/ 6.791 0
1973 8.579 15.683 8.603 .492/ 6.818 0
1974 7.050 17.117 9.357 .132/ 6.252 0
1975 13.921 19.619 11.332 .1093/ 7.289 0
7976 19.397 22.204 12.342 .162 5.174 0
19712/ 23.087 23.534 13.913 .183 5.076 0
197f!Y 20.265 24.557 15.167 .200 1. I 15 0
1972!/ 19.638 28.295.±! 16.003 .228 6.905 0
1980 19.664 28.763 16.105 .228 6.011 0
1981 13.359 29.071 16.483 .300 6.232 0
1982l_l 10.000 30.544 18.232 .404 6. 777 0
1/ U.S. Department of Energy, Alaska Power Administration, Alaska Electric Power Statistics
1960 -1980, Sixth Edition August, 1981 and Alaska Electric Power Statistics 1960 -1976,
Fifth Edition, July, 1977.
2/ Preliminary data from Alaska Power Administration.
3/ Estimated from: gas -Alaska 01 I and Gas Conservation Commission, State of Alaska
Report of Gas Disposition, monthly reports; ol I -modeling described In Chapter 3 of this
report.
4/ AGA Gas Facts
5/ Principally Barrow
2.22
Historical Utility Electricity Generated: RAIL BELT..!/ TABLE 2.10
Oil Gas Coal Hydro Total
Thousand
Thousand MWh Share (%) Thousand MWh Share ('~) Thousand MWh Share (r.) Thousand MWh Share (%) MWh
1971 48.0 4.4 612.6 56.0 262.1 24.0 170.6 15.6 1093.3
1912 59.1 4.7 748.2 59.8 281.2 22.5 162.6 13.0 1251.1
1973 66.4 4.6 973.1 67.0 278.5 19.2 134.4 9.3 1452.4
1974 66.1 4.2 1049.1 66.7 305.0 19.4 153.0 9.7 1573.2
1975 126.9 6.8 1246.3 66.7 328.5 11.6 16~.1 9.0 1869.8
1976 179.8 8.4 1473.8 68.5 318.3 14.8 179.8 8.4 2151.7
1977 182.0 7.8 1596.4 68.4 315.1 13.5 240.64 10. 3!!.1 2333. 9!:!1
1978 193.5 7.9 1719.6 70.2 313.5 12.8 221.84 9 .!!!I 2449 0 6!:!1
1979 191.0 7.5 1826.0 11.2 313.2 12.3 215.73 8 0 5!:!1 2546. 7!:!1
N . 1980 187.4 7.2 1857.9 11.6 296.3 11.4 254.0 9.8 2595.6 N
\N
1981 120.5 4.5 1900.2 11.6 354.3 13.3 280.4 10.6 2655.5
Historical Utility Electricity Generated: REST-OF-STATE.!/ TABLE 2.11
Oil Gas Coal Hydro Total
Thousand
Thousand MWh Share (~&) Thousand MWh Share U•> Thousand MWh Share (%) Thousand MWh Share <~•> MWh
1971 95.6 98.7 1.3 1.3 0 0 0 0 96.93
1972 100.2 100.0 0 0 0 0 0 0 100.2
1973 100.8 100.0 0 0 0 0 0 0 100.8
1974 102.4 100.0 0 0 0 0 0 0 102.4
1975 130.4 100.0 0 0 0 0 0 0 130.4
1976 142.5 94.5 8.3 5.5 0 0 0 0 150.8
1977 165.5 94.2 10.2 5.8 0 0 0 0 175. 7ll
N 1978 173.0 93.8 11.4 6.2 0 0 0 0 184.4ll .
N
191. 1ll ~ 1979 179.2 93.5 12.5 6.5 0 0 0 0
1980 184.7 93.2 13.4 6.8 0 0 0 0 198.1
1981 211.6 92.4 17.5 7.6 '0 0 0 0 229.0
Historical Utility Electricity Generated: SOUTHEAsTY TABLE 2.12
Oil Gas Coal Hydro Total
Thousand
Thousand MWh Share 010 Thousand MWh Share (?,;) Thousand MWh Share (%) Thousand MWh Share (?&) MWh
1971 51.5 21.1 0 0 0 0 192.4-Y 78.9 243.9
1972 85.3 31.7 0 0 0 0 183.4-Y 68.3 268.7
1973 83.3 35.5 0 0 0 0 151.61' 64.5 234.9
1974 78.9 31.4 0 0 0 0 172.6 68.6 251.5
1975 96.0 33.6 0 0 0 0 189.6 66.4 285.6
1976 61.8 23.4 0 0 0 0 202.8 76.6 264.6
1977 47.1 14.8 0 0 0 0 271.3sY 85.2 318.5
N
25o.zY N 1978 81.9 24.7 0 0 0 0 75.3 332.1
\Jl
243.27Y 1979 103.2 29.8 0 0 0 0 70.2 346.5
1980 75.4 20.6 0 0 0 0 289.9 79.4 365.3
1981 76.7 19.4 0 0 0 0 318.1 80.6 394.8
Historical Utility Electricity Generated: STATEY TABLE 2.13
Oil Gas Coal H}::dro 2 ~ ousand
Thousand MWh Share (%) Thousand MWh Share (~) Thousand HWh Share (%) Thousand HWh Share (~) HWh
1971 195.1 n.6 613.9 42.8 262.1 18.3 J6J.o.Y 25.J 14J4.1
1972 252.5 15.6 742.2 45.8 281.2 17.3 J46.o.Y 21.3 1621.9
197J 250.6 14.1 966.9 54.J 278.5 15.6 286.o.Y 16.0 1782.0
1974 246.5 12.8 1049.1 54.5 305.0 15.8 325.6 16.9 1926.2
1975 J52.8 15.4 1246.4 54.5 328.5 14.4 357.7 15.7 2285.4
1976 J84.2 15.0 1482.0 51.1 318.3 12.4 382.6 14.9 2567.1
N 1977 J59.2 12.7 16J4.6 57.8 J22.4 11.4 512.o.Y 18.1 2828.1 .
N 1978 436.0 14.7 1732.2 58.4 326.3 11.0 472.o.Y 15.9 2966.1 0"
1979 481.2 15.6 1823.2 59.1 320.8 10.4 459.o.Y 14.9 J084.9
1980 447.5 14.2 1871.3 59.2 296.J 9.4 54J.90 17.2 3159.0
1981 408.76 12.5 1917.70 58.5 J54.34 10.8 598.52 18.2 3279.J2
l/ U.S. Department of Energy, Alaska Power Administration, Alaska Electric
Power Statistics 1960-1981,
Seventh Edition, AUgust 1982. Alaska
Electric Power Statistics 1960-1980, Sixth Edition, August 1981 and
Alaska Electric Power Statistics 1960-1976, Fifth Edition, July 1977.
2/ U.S. Department of Energy, State Energy nata Report, September 1981. All
hydroelectric sources are found within Southeast and Railbelt regions.
Alaska total figures for 1971-1973 and 1977-1979 are split 53%-47% (1980
reported split) between the Southeast and Railbelt respectively.
3/ Includes industrial, utility production and net imports.
4/ Estimated
Note: 1977-1979 figures estimated for Oil, Gas, and Coal shares since data
were not available from sources cited.
2.27
CONSUMPTION FORECAST 3.0
Consumption of oil and gas in all major categories is forecast to increase in
future years.lf
Consumption of natural gas will grow from 211 billion cubic feet (bcf} in 1983
to 243 bcf in 1987 (annual growth of 2.9 percent}, 286 bcf in 1992
(3.1 percent annual growth}, and 309 bcf in 1997 (2.6 percent annual growth}.
Although industry currently consumes the majority of natural gas and is
forecast to continue to be the dominant user, growth of gas use for space
heating and electricity generation will outstrip growth in industrial use.
Over the next 15 years, use of gas for space heating will more than double,
from 18.9 bcf in 1983 to.37.4 bcf in 1997 (4.7 percent annual growth}. Use of
gas for electricity generation will grow from 32.9 bcf in 1983 to 62.4 bcf in
1997 (4.4 percent annual growth}.
Consumption of liquid petroleum will increase from 1,251 million gallons in
1983 (about 30 million barrels of crude oil equivalent} to 1,713 million
gallons in 1997 (41 million barrels). This represents a 2.1 percent annual
growth rate. The five-and ten-year growth rates are both 2.0 percent
annually. Space heating use of petroleum will grow most rapidly, at
2.5 percent annually, due to size increases in the building stock outside the
railbelt. Vehicle transportation use will increase 2.0 percent annually, a
modest rate of increase due to increases in motor vehicle fuel use
efficiencies. Electric utility use of fuel oil will decrease in the mid-1980s
as several hYdroelectric facilities replace high cost fuel oil generation, but
total consumption will subsequently increase and the 15-year growth rate will
be 2.2 percent annually. Industrial use of petroleum liquids will remain
constant.
17 See Appendix B for assumptions.
3.1
Projected Consumption of 01 I and Gas
(Liquids-Million Gallons)
(Ni!tural Gas-BCF>
Total
State
Vehicle Transportation
Liquids 938
Natural gas 0
Space Heat
Liquids 169
Natura I gas 18.2
Utllitr Electrlclt~
Generation
Liquids 35.1
Natural gas 30.9
Industry
Liquids 94.8
Natura I gas 154.4
Total
Liquids 1236.9
Natura I gas 203.5
For detal I, see following tables.
1982
Rai 1-
Belt
682
0
64
17.7
10
30.5
91.7
139.9
TABLE 3. I
1983
Non-Total Rai 1-Non-
Ra II belt State Belt Rallbelt
256 977 704 273
0 0 0 0
105 174 66 108
.5 18.9 18.4 .5
25.1 37.7 10 27.7
.4 32.9 32.5 .4
94.8
62.7 158.8 91.8 67
63.6 210.6 142.7 67.9
3.2
Projected Consumption of 01 I and Gas
(Liquids-Ml Ilion Gallons)
(Natura I Gas -BCF)
Total
State
Vehicle Transportation
Liquids 996
Natura I gas 0
Space Heat
Liquids 179
Natura I gas 20
Utlllt~ Electricity
Generation
Liquids 38.6
Natural gas 35. I
lndustr~
Liquids 94.8
Natura I gas 163.6
Total
Ll qui ds 1308.4
Natura I gas 218.7
For detail, see following tables.
1984
Rail-
Belt
720
0
68
19.4
10
34.6
91.8
145.8
TABLE 3.1 (cont.>
1985
tbn-Total Rail-tt>n-
Ra !!belt State Belt Ra II belt
277 I ,017 736 280
0 0 0 0
Ill 185 70 115
.6 20.8 20.2 .6
28.6 31.8 10 21.8
.5 37 36.5 .5
94.8
71.8 168.6 91.8 76.8
1328.6
72.9 226.4 148.5 77.9
3.3
Projected Consumption of 01 I and Gas
<Liquids-Million Gallons>
<Natura I Gas -BCF>
Total
State
Vehicle Transportation
Liquids I ,037
Natural gas 0
Seace Heat
7 Liquids 190
Natura I gas 22
ut I I l t:( E I ectr I c l t)::
Generation
Liquids 32.7
Natura I gas 38.4
Industry
Liquids 94.8
Natura I gas 174
Total
Liquids 1354.5
Natura I gas 234.4
For detail, see following tables.
1986
Rail-
Belt
754
0
72
21.4
10
37.9
91.8
151. I
TABLE 3.1 (cont.)
1987
tbn-Total Rai 1-tbn-
Ra II belt State Belt Rallbelt
283 1,056 770 286
0 0 0 0
118 195 74 121
.6 23.4 22.8 .6
22.7 33.5 10 23.5
.5 39.9 39.4 .5
94.8
82.2 179.7 91.8 87.9
1379.3
83.3 243 154 89.0
3.4
Projected Consumption of Oi I and Gas
(Liquids-Million Gallons)
(Natural Gas -BCF)
Total
State
Vehicle Transportation
Liquids 1,174
Natura I gas 0
Space Heat
Liquids 221
Natura I gas 30.3
utllltl Electricity
Generation
Liquids 40.6
Natura I gas 45.8
Industry
Ll qulds 94.8
Natura I gas 209.6
Total
Liquids 1530.4
Natura I gas 285.7
For detal I, see following tables.
1992
Rai 1-
Belt
869
0
82
29.7
10
45.2
91.8
166.7
TABLE 3.1 (cont.)
1997
Non-Total Rail-Non-
Ra It belt State Belt Rail belt
306 1,313 987 328
0 0 0 0
139 253 92 161
.6 37.4 36.8 .6
30.6 51.9 10 41.9
.6 62.4 61.6 .8
94.8
117.8 209.6 91.8 I 17.8
1712.7
119 309.4 190.2 I 19.2
3.5
Projected Consumption of 01 I and Gas
(Liquids -Million Gallons)
<Natural Gas -BCF)
1983-1997
Total Rail
State Belt
Vehicle Transportation
Ll qulds 16,882 12,418
Natural gas 0 0
Space Heat
Liquids 3,147 1,174
Natural gas 408.6 399.7
Utlllt~ Electricity
Generation
Liquids 590.8 150
Natural gas 668,1 659.4
Industry
Liquids i,423
Natural gas 2,866 1,377
Total
Ll qu Ids 22,042.8
Natural gas 3,942.7 2,436.1
For detail, see following tables.
TABLE 3. I (cont. )
Total
Non-
Rail belt
4,464
0
1,973
8.9
440.8
8.7
I ,489
1,506.6
3.6
TRANSPORTATION LIQUID FUELS 3. 1
Transportation fuel consumption will grow moderately with population growth in
future years, increasing from 938 million gallons in 1982 to 1,313 million
gallons in 1997 (Table 3.2). Growth will be relatively evenly divided among
the three types of fuels--jet fuel, diesel, and gasoline.
Fuel use efficiency will increase in all types of uses but will be most
evident in highway gasoline consumption which is projected to decline on a per
capita basis. In aviation, marine, and diesel highway uses, economic growth
will result in a continued increase in per capita consumption levels.
Total consumption projected over the 15-year period from 1983 to 1997 is
16,882 million gallons •. This is approximately equivalent to 402 million
barrels of crude oil.
3.7
Projected Consumption of Vehicle Transport Fuelsif
<Mill ion Gallons)
1982
State t-On-State
Total Rallbelt Ra i I belt Total
Gasoline
Total 212 157 55 236
Highway 193 144 48 206
~1ar I ne 5 3 2 39
Aviation 13 9 4 21
Diesel
Total 297 167 131 303
HIghway 238 125 113 243
Marine 59 42 18 60
Jet Fue I
Total 429 356 71 438
Civil ian Domestic 338 281 57 159
Mi lltary &
International 91 77 14 279
Grand Tot a I 938 662 256 977
Numbers may not sum to total due to rounding.
TABLE 3.2
1983
I-bn-
Rallbelt Rail belt
170 66
148 58
6 2
15 6
219 65
175 68
44 17
315 122
I 14 44
201 78
704 273
!! Includes Industrial, ml lltary, and government use. Excludes space
heating, uti I ity generation and pipeline fuel.
3.8
., Projected Consumption of Vehicle Transport Fuelslf
<Million Gallons)
1984
State flbn-State
Total Rallbelt Rallbelt Total
Gasol fne
Total 238 172 66 241
HIghway 208 150 58 210
Marine 9 6 2 9
Aviation 22 16 6 22
Diesel
Total 309 224 86 316
Highway 248 179 69 253
Marine 62 45 17 63
Jet Fuel
Total 449 324 125 460
Civilian Domestic 167 121 46 175
Military &
International 282 203 79 285
Grand Tota I 996 720 277 1,017
Numbers may not sum to total due to rounding.
TABLE 3.2 <cont. l
1985
flbn-
Rallbelt Rallbelt
175 65
153 58
6 2
16 6
229 86
183 69
46 17
332 128
127 48
205 80
736 280
<al Includes Industrial, military, and government use. Excludes space
heating, utility generation and pipeline fuel.
3.9
Projected Consumption of Vehicle Transport Fuels!!
(Mi II ion Gallons)
1986
State Non-State
Total Rai I belt Rallbelt Total
Gasoline
Total 244 178 66 245
Highway 212 155 58 214
Marl ne 9 7 3 9
Aviation 22 16 6 23
Diesel
Total 322 235 87 328
Highway 258 188 70 263
Marine 64 47 17 66
Jet Fuel
Total 471 341 130 483
Civilian Domestic 184 134 50 193
Mi lltary &
International 287 207 80 290
Grand Total 1,037 754 283 1,056
Numbers may not sum to total due to rounding.
TABLE 3.2 (cont.)
1987
N:Jn-
Rail belt Rail belt
179 66
157 57
7 3
17 6
240 88
192 71
48 18
351 132
141 52
209 81
770 286
1/ Includes Industrial, military, and government use. Excludes space
heating, utility generation and pipeline fuel.
3. 10
Projected Consumption of Vehicle Transport Fuels!/
<Mill I on Ga lions)
1992
State t-bn-State
Total Rail belt Rail belt Total
Gasoll ne
Total 260 194 66 275
Highway 225 168 57 236
Marine 10 8 3 II
Aviation 25 19 6 28
Diesel
Total 362 270 92 400
Highway 290 217 74 320
Marine 72 54 18 80
Jet Fuel
Total 552 405 148 638
Civilian Domestic 248 185 63 317
Military &
International 305 220 85 321
Grand Total 1,174 869 306 1,313
Numbers may not sum to total due to rounding.
TABLE 3,2 (cont.>
1997
t-t:ln-
Rail belt Rail belt
210 66
180 56
9 3
21 7
305 96
244 77
61 19
472 166
241 76
231 90
987 328
I( Includes Industrial, military, and government use, Excludes space
heating, utility generation and pipeline fuel.
3. 11
Projected Consumption of Vehicle Transport Fuels!/
<Ml Ilion Ga lions)
1983 -1997 Total
State f'j)n-
Total Ral I belt Rail belt
Gasoline
Total 3,806 2,816 990
Highway
Marl ne
Aviation
Diesel
Total 5,211 3,860 I ,351
Highway
Marine
Jet Fuel
Total 7,865 5,742 2,123
Civil lan Domestic
Ml lltary &
International
Grand Total 16,882 12,418 4,464
Numbers may not sum to total due to rounding.
TABLE 3.2 (cont.)
1/ Includes Industrial, military, and government use. Excludes space
heating, utility generation and pipeline fuel.
3. 12
SPACE HEATING 3.2
Space heating fuel consumption will increase moderately with population
and an increase in the size of the building stock relative to
population. Natural gas use will grow more rapidly than fuel oil, from
18.2 billion cubic feet in 1982 to 37.4 billion cubic feet in 1997 {Table
3.3).
The relatively more rapid growth of natural gas is attributable both to
the more rapid growth of population in the railbelt as well as the
extension of the natural gas market into the Matanuska Valley. The
expansion of the natural gas market is estimated to increase gas use by
about eight percent in the 1990 1 s. Barrow, on the North Slope, is the
only location outside of the railbelt presently served by natural gas.
The majority of fuel oil used for space heating is consumed outside the
railbelt although fuel oil is important where natural gas is not
available. Outside of the railbelt most space heating is done with fuel
oil. Fuel oil consumption for this use grows from 170 million gallons in
1982 to 253 million gallons in 1997.
3.13
Projected Consumption of Oil and Gas for Space Heat TABLE 3.3
1982 1983 1984 1985 1986 1987
Natural Gas <BCFl
Total 18.21 18.9 20.0 20.8 22.0 23.4
Rail belt 17.67 18.4 19.4 20.2 21.4 22.8
Current Market 17.67 18.4 19.4 20.2 21.0 22.0
Matanuska Valley 0 0 0 0 .4 .6
Non-Rail belt .54 .5 .6 .6 .6 .6
Fuel 011 (Million Gallons>
Total 169.9 174.3 179.2 184.7 189.5 194.4
Rallbelt 65 66.4 68 70 71.6 73
Non-Rail belt 104.9 107.9 I 11.2 114.7 117.9 121.4
1983-1997
1992 1997 Total
Natural Gas <BCFl
Total 30.3 37.4 408.6
Rai !belt 29.7 36.8 399.7
Current Market 27.4 33.9
Matanuska Valley 2.3 2.9
Non-Rallbelt .6 .6 8.9
Fuel Oi I (Million Gallons)
Total 221.5 253.2 3147.9
Rail belt 82.4 92.4 1174.6
Non-Rallbelt 139.1 160.8 1,973.1
3.14
UTILITY ELECTRICITY GENERATION 3.3
Natural gas use for utility electricity generation will exhibit strong
growth in the next 15 years as the majority of incremental electricity
demand growth in the railbelt is met with additions to natural gas-fired
generation. Natural gas use nearly doubles from 32.9 bcf in 1983 to
62.4 bcf in 1997 (Table 3.4). The percentage of electricity in the
railbelt provided by natural gas reaches a high of 81 percent by 1997
after temporarily falling below its current level of 77 percent when the
Bradley Lake hYdroelectric facility comes on line.~
Fuel oil use for utility electricity generation will grow at an average
annual rate of only 2.6 percent. This is due to the expected completion
of several hYdroelectric plants in locations currently dependent entirely
upon fuel oil for generation. Because of this, fuel oil use will actually
fall in the mid-1980s, but continued growth in electricity demand will
cause fuel oil use to r~sume its upward trend shortly thereafter.
2/ Susitna hYdro is considered in Chapter 5.
3.15
Projected Consumption of Of I and Gas for
Uti II ty El ectrl city Generation
1982
State
Total Railbelt Southeast
Electricity Production
(Thousand MWi) 3,625 2,971 415
Percent Natura I Gas 76 0
Percent Fuel 011 3 23
Natural Gas <BCF>
30.9 30.5 0
Fuel 011 CMi Ilion Gallons) 35.1 10 7.8
1983
State
Total Rai I belt &>utheast
Electricity Production 3, 786 3,102 431
<Thousand MWi)
Percent Natura I Gas 17 0
Percent Fue I Oil 3 26
Natural Gas <BCF) 32.9 32.5 0
Fue I Oil <Mi Ilion Gallons> 37.7 10 9.2
3. 16
T.ABLE 3.4
~st of
State
239
7
93
.4
17.3
Rest of
State
253
7
93
.4
18.5
Projected Consumption of Oi I and Gas for
ut Ill ty E I ectr I cIty Generation TABLE 3.4 (cont.>
1984
State lEist of
Total Ra II belt Southeast State
Electricity Production
(Thousand MW·O 3,962 3,244 448 270
Percent Natura I Gas 78 0 7
Percent Fuel Oil 2 24 93
Natural Gas (BCF) 35. I 34.6 0 .5
Fuel 011 <Million Gallons> 38.6 10 8.8 19.8
1985
State Rest of
Total Rallbe!t Southeast State
Electricity Production 4,122 3,375 463 284
<Thousand M\til
Percent Natural Gas 79 0 7
Percent Fue I 011 2 18 68
Natural Gas (BCFJ 37 36.5 0 .5
Fuel 011 <Million Gallons> 31.8 10 6.6 15.2
3.17
Projected Consumption of 01 I and Gas for
Uti llty Electricity Generation TPBLE 3.4 (cont. l
1986
state Pest of
Total Rallbelt Southeast State
Electricity Production
<Thousand Mv.tD 4,237 3,472 472 293
Percent Natural Gas 79 0 7
Percent Fuel Oil 2 18 68
Natural Gas <BCFl 38.4 37.9 0 .5
Fuel 01 I <Mi Ilion Ga II onsl 32.7 10 7.0 15.7
1987
State Rest of
Total Rallbelt !i:lutheast State
Electricity Production 4,352 3,569 481 302
<Thousand M\-1-ll
Percent Natura I Gas 80 0 7
Percent Fue I Oi I 2 19 68
Natural Gas CBCFl 39.9 39.4 0 .5
Fuel Oil (Mi Ilion Gallonsl 33.5 10 7.4 16.1
3. 18
Projected Consumption of 01 I and Gas for
Utility Electricity Generation TJIBLE 3.4 (cont.)
1992
State Fest of
Total Rail belt Southeast State
Electricity Production
(Thousand MIII-I) 5, i90 4,265 550 375
Percent Natura I Gas 75 0 7
Percent Fuel Oi I 2 24 68
Natural Gas CBCF> 45.8 45.2 0 .6
Fuel OJ I <Million Gallons> 40.6 10 10.6 20.0
1997
State Rest of
Total RaJ lbelt Southeast State
Electricity Production 6,518 5,370 651 497
<Thousand MIII-I)
Percent Natura I Gas 81 0 7
Percent Fue I OJ I I 29 68
Natural Gas CBCF> 62.4 61.6 0 .8
Fue I 01 I (Million Gallons) 51.9 10 15.3 26.6
3. 19
Projected Consumption of 01 l and Gas for
Utility Electricity Generation
State
TI>SLE 3.4 (cont.>
1983-1997 Total
Fest of
Total Ra libel t Southeast State
Electricity Production
<Thousand M\tD
Percent Natural Gas
Percent Fuel 01!
Natural Gas <BCF> 668.1 659.4 0 8.7
Fuel 01 I (MI Ilion Ga lions> 590.8 150 148.8 292
3.20
INDUSTRIAL FUEL USE 3.4
Increased use of natural gas in future years will be related to
petroleum production. This will be concentrated on the North Slope
where expanded petroleum activity will be concentrated. The other
large use of natural gas, the production of Ammonia-Urea, will
continue requiring constant amounts of natural gas.
The major industrial use of fuel oil (not including transportation)
is also in the petroleum industry. Pipeline fuel for the Alyeska
pipeline is the largest element of this use. In addition, a
significant amount of fuel is used for electricity generation. Both
of these uses are projected at constant levels.
3.21
Projected Consumption of Oil and Gas for
1982
Natural Gas (BCF>
Total Consumption 154.4
Petroleum Production Related 94.5
Pipe II ne Fue I
Rail belt
Rest of State
Other II
North Slope
Cook Inlet
Ammonia Urea
Mi lltary
Item: Inject ion
North Slope
Cook Inlet
01 I (Mi Ilion Barrels)
Total
Pipe I ine Fuel
Electrical Generation
12.9
I .0
II. 9
81.6
50.8
30.8
55.3
4.7
774.1
671.0
103,1
2.258
2.000
• 258
Industry
1983
158.8
98.8
13.7
I ,0
12.7
85.1
54.3
30.8
55.3
4.7
2.258
2.000
.258
1984
163.6
103.6
14.6
1.0
13.6
89.0
58.2
30.8
55.3
4.7
2.258
2.000
.258
1985
168.6
108.6
15.6
1.0
14.6
93.0
62.2
30.8
55.3
4.7
2.258
2.000
.258
TABLE 3. 5
1986 1987
174
114.0
16.6
I .o
15.6
97.4
66.6
30.8
55.3
4.7
2.258
2.000
.258
179.7
119.7
17.7
1.0
16.7
102.0
71 .2
30.8
55.3
4.7
2.258
2.000
,258
II Includes natural gas In field operations, sales to producers and refiners, and miscellaneous sales.
3.22
Projected Consumption of Oil and Gas for Industry TABLE 3.5 (cont.>
Natural Gas CBCF>
Total Consumption
Petroleum Production
Pipeline Fuel
Rat I belt
Rest of State
other I/
North Slope
Cook Inlet
Ammon I a Urea
Ml lltary
Item: Injection
North Slope
Cook Inlet
Oil (Million Barrels>
Total
Pipeline Fuel
Electrical Generation
Related
1992
209.6
149.6
18.9
1.0
17.9
130.7
99.9
30.8
55,3
4.7
2.258
2.000
.258
1997
209.6
149.6
18.9
1.0
17.9
130.7
99.9
30.8
55.3
4.7
2.258
2.000
.258
1983-1997
Total
2840.8
1966
264.2
15.0
249.2
1701.8
1239.8
462.0
70.5
829.5
33.870
30.000
3.870
1/ Includes natural gas In field operations, sales to producers
and refiners, and miscellaneous sales.
3.23
RESERVE ESTU1ATES AND ROYALTY SHARE 4.0
This section develops estimates of oil and gas reserves in the state and the
royalty share of these reserves. The reserve estimates are developed for low,
mid and high cases. The low and mid estimates are based upon proven and
probable reserves. The high estimates also contain undiscovered reserve
estimates. The royalty share is based upon existing contracts and best
estimates of future royalty contracts.
RESERVE F.STU1ATES 4.1
The estimated reserves for oil and gas are shown in Tables 4.1 and 4.2,
respectively. The estimates are developed separately for Cook Inlet, the
North Slope and 11 Undi scovered" as different sources of information were drawn
upon for each category. .
Cool< Inlet
Much information is available about the oil and gas reserves in the Cook Inlet
area, and major new discoveries are not considered likely at this time. The
reserves are assumed to remain constant for low, mid and high estimates. In
addition, Cook Inlet reserves account for about 2% and 9% of the state's low
and mid estimates of proven and probable oil and gas reserves, respectively.
The high estimate of reserves further reduces the Cook Inlet share of total
reserves to 1% and 6% respectively.
North Slope
Oil and gas reserve estimates for the North Slope are taken from a report to
the Governor.{lJ These estimates provide the low, mid and high proven and
probable oil reserves on currently leased state onshore lands. These
estimates were compiled from public information available to the author.
Current North Slope oil production is from the Sadlerochit reservoir in
Prudhoe Bay Unit and the Kuparuk River reservoir in l<uparuk River Unit. The
other fields and areas listed in the Van Dyke report are lumped together
because production is not expected to begin until the mid to late 1900s.
(l) Van Dyke, ~l., Proven and Probable Oil and Gas Reserves, North Slope,
Alaska, Division of tHnerals and Energy f4anagement, September 25, 1980, and
personal communication ll/10/82.
4. 1
Estimated Recoverable Oi I Reserves <Mfi!Bel...)
Location/Fie I d
Cook Inlet..!!
Beaver Creek
Granite Pol nt
McArthur R I ver
Ml dd I e Ground Shoa I
Sw anson R I ver
Tradl ng Bay
Subtotal
North Slq;J~
Prudhoe Bay, Sad I eroch it Reservoir
Kuparuk
Other North S I ope
Subtotal
UndIscovered "31
Total
II Alaska 011 and Gas Conservation Commission, 1981 Statistical Report.
2/ Van Dyke, W., Proven and Probable Oi I and Gas Reserves, North
Slq;Je, Alaska, September 25, 1980, and personal communication I 1/10/82.
3/ "NPC Sees Big U.S. Arctic Resources," Oi I and Gas Journal, November 23,
1981; and "Estimates of Undiscovered Recoverable Resources of Conventionally
Producible 011 and Gas In the United States, a Summary," U.S. Geological
Survey,Open-FIIe Report 81-192, 1981.
4.2
Est !mated Recoverab I e Gas Reserves <BCF> TABLE 4.2
Reserve Estimate
Locatlon/FI e I d Low Mid High
Cook Inlet J.!
Bea-.er Creek 240 240 240
Beluga River 742 742 742
Birch Hill II II II
Falls Creek 13 13 13
Granite Point 26 26 26
Ivan River 26 26 26
Kenai I, 109 I, 109 I, 109
LewIs River 22 22 22
McArthur R lver 90 90 90
Middle Ground Shoal 14 14 14
Nicolai Creek 17 17 17
North Cook Inlet 951 951 951
7North Fork 12 12 12
sterll ng 23 23 23
Swanson R lver 259 259 259
TradIng Bay 13 13 13
West Fore I and 20 20 20
West Fork 6 6 6
Subtotal 3,594 3,594 3,594
North Slope 3.!
Prudhoe Bay, Sadlerochit Resevolr 29,000 29,000 29,000
other North Slope 4,500 4,500 4,500
Subtotal 33,500 35,400 37,800
Und lscovered ~ N/A N/A 000
Total 37,094 38,994 56,394
1/ Alaska 01 I and Gas Conservation Commission, 1981 Statistical Report.
2/ Van Dyke, W., Proven and Probable Oi I and Gas Reserves, North
Slcpe, Alaska, September 25, 1980.
3/ "WC sees Big u.s. Arctic Resources," Oil and Gas Journal, November 23,
1981; and U.S. Geological Survey, Estimates of Undiscovered Recoverable
Resources of Con..entlonally Producible Oil and Gas In the United States, A
Summary, Open-FIle Report 81-192, 1981.
4.3
No gas is currently exported from the North Slope. The Alaska Natural Gas
Transportation System for carrying gas to the Lower 48 is targeted for
completion in 1987 or 1988, but is problematic at this time. The pipeline
capacity will then permit exports in the range of 2.0 to 2.4 Bcf per day, with
an expected level of 2.0 Bcf per day.
Undiscovered (Resources)
Undiscovered oil and gas resources are taken as the simple average of the low
estimates recently developed by the U.S. Geological Survey and the National
P~troleum Council (NPC). The USGS estimates are for conventionally producible
reserves based upon information available to USGS. The low USGS estimates of
undiscovered oil and gas resources are 2.5 Billion barrels and 19.8 Tcf,
respectively at the 95% confidence level. The NPC resources estimates were
developed for yields on investment of 10% for oil and gas and 15% for oil.
These estimates are 17.8 BBbl of oil that will yield a 15% return on
investment and 10.1 Tcf of gas that will yield a 10% return on investment.
The average low estimate of undiscovered resources is entered as the high
estimate in this report in order to present a conservative estimate.
ROYALTY SHARE
The royalty share assigned to each field may vary according to field
ownership and the terms of the contract. The share used for the Cook Inlet
fields and the Prudhoe Bay Sadlerochit Reservoir are taken from the
4.2
"Oi sposition of the States Royalty Share of Its Oil and Gas," prepared by the
Division of Minerals and Energy f•1anagement (Appendix A). The share for the
other existing North Slope fields is set at 12.5% and at 0% for the
undiscovered resources, due to the fact that not enough information is
available to estimate what portion of undiscovered North Slope resources if
any m~ be on state lands.
The royalty share of oil and gas reserves based upon these shares are
presented in Tables 4.3 and 4.4, respectively. In the middle case the royalty
oil available from Cook Inlet Fields is less than 2% of the State total
reserves and about 5% for gas reserves.
4.4
Estimated Royalty Share of Oil <MM3U
Location/Field
Cook Inlet
Beaver Creek
Granite Point
McArthur R I ver
Middle Ground Shoal
Swanson River
Trading Bay
Subtota I
North Slope
Prudhoe Bay, Sadlerochl t Reservoir
Kuparuk
other North S I ope
Subtota I
UndIscovered
Total
4.5
T.ABLE 4 •. 3
Royalty Share Corresponding
to Feserve Estimate
Low Mid HIgh
4.4 4.4 4.4
I 1.2 It .2 I I .2
3.2 3.2 3.2
0.5 0.5 0.5
19.3 19.3 19.3
771 869 918
75 125 188
136 198 297
982 I, 192 I ,403
N/A N/A 0
1001.3 121 1.3 1422.3
Estimated Royalty Share of Gas <BCF)
Locat ld
Cook Inlet
Beaver Creek
Be I uga R I ver
Birch Hi I I
Falls Creek
Granite Point
Ivan River
Kenai
Lewis River
McArthur River
Mi dd I e Ground Shoa I
Nl col al Creek
North Cook Inlet
North Fork
Sterl lng
Swanson river
Tradl ng Bay
West Fore I and
West Fork
Subtota I
North Slope
Prudhoe Bay, Sadlerochit Reservo lr
other North Slope
Subtota I
Undiscovered
TOTAL
4.6
T/>SLE 4.4
Royalty Share Corresponding
to Raserve Estimate
Low Mid High
56.0 56.0 56.0
3.3 3.3 3.3
22.9 22.9 22.9
11.2 I I. 2 I 1.2
1.8 1.8 I .8
2.1 2.1 2.1
118.9 118.9 118.9
.4 .4 .4
I .6 1.6 1.6
218.2 218.2 218.2
3,625 3,625 3,625
563 800 ~
4,188 4,425 4,725
N/A N/A 0
4,406.2 4,643.2 4,943.2
ANALYSIS OF SURPLUS 5.0
Under reasonable assumptions about recoverable reserves and Alaskan
consumption, the current inventory of both oil and gas is more than
sufficient to meet the presently identifiable needs of Alaskans for
the next 15 years. The state royalty share is also sufficient.
LIQUID PETROLEUt·1 5.1
Table 5.1 shows that the cumulative 15-year Alaskan demand for liquid
petroleum is approximately 525 million barrels of crude oil
equivalent. This is equal to approximately half the reserves of
royalty oil and is 5 percent of total reserves. No attempt has been
made to compare petroleum products produced at Alaskan refineries
with petroleum products consumed in the state. Currently the
capacity of Alaskan refi.neries exceeds Alaskan consumption (about
81 thousand barrels per day), but the product mix which the
refineries can produce does not match the product mix demanded. The
resulting cross hauling of crude oil out of Alaska and refined
products into the state is a common feature of petroleum markets in
general and does not represent an inefficient distribution of
refining capacity or mismatch of supply and demand.
5. 1
Surplus 01 I Calculation <Mil lion Barrels) TABLE 5.1
Liquid Petroleum
Statewide North Slope Cook Inlet
State State State
Total Royalty Total Royalty Total Royalty
Recoverable Reserves II 9,705 I, 21 I 9,530 I, 192 175 19
Estimated Produc-
tlon for remainder
of 1982 2/ 117 15 92 12 25 3
Estimated Remain-
lng Recoverable
Reserves as of
Jan. I, 1983 9,588 I, I 92 9,438 I, 180 150 16
Item: Estimated
Alaskan Consumption
d ur I ng I 982 3/ 29
Estimated Cumula-
t lve AI askan
Consumption from
1983 to 1997
(15 years) 525
Net Surplus (Def tel t) 9,063 667
l( From Chapter 4. North Slope is as of I 1/1/82. Cook Inlet is as of
1/1/82.
2/ Author's estimates. State royalty share Is proportion of state
royalty of I In total.
3/ From Chapter 3.
5.2
NATURAL GAS 5.2
Table 5.2 shows that the cumulative 15-year Alaskan demand for
natural gas is 3.943 trillion cubic feet of gas. This is
approximately 85 percent of the state royalty share of gas in the
current inventory at Cook Inlet and on the North Slope combined.
Since the transportation of natural gas normally requires a
pipeline, particular markets for gas which are linked by pipeline to
supplies are relevant for the determination of excess supply.
Table 5.2 shows that there is a net surplus in both the Cook Inlet
and North Slope markets. The Alaskan royalty share of Cook Inlet
gas alone, however, is insufficient to meet the projected Cook Inlet
requirements over the next 15 years.
PROJECTIONS BEYOI~O CURRENT INVENTORY 5.3
We assume recoverable reserves represent a 15-year inventory of
petroleum in the ground based upon historical reserve to production
ratios. The idea of an inventory of reserves is based on the notion
that because a very sizable investment is required to develop a
petroleum reservoir into recoverable reserves, such developments
will occur at a pace consistent with the growth in demand.
Excessive reserves, like excessive inventories, result in excessive
carrying costs to the oil companies.
Consequently, a 15 year time horizon for demand is also used in the
analyses. As time passes, the growth in demand will stimulate the
search for reserves to replace those produced, and markets will work
to keep supply and demand in balance.
5.3
Surplus Gas Calculation CBCF> TABLE 5.2
Natural Gas
Statewide North Slope Cook Inlet
State State State
Total Royalty Total Royalty Total Royalty
Recoverable Reserves 1/ 39,994 4,643 35,400 4,425 3,594 218
Estimated Produc-
tlon for remainder
of 1982 2/ 213 13 II 202 12
Estimated Remain-
I ng Recoverable
Reserves as of
Jan. I' 1983 38,781 4,630 35,389 4,424 3,392 206
Item: Estimated
Alaskan Consumption
durl ng 1982 ~ 203 64 139
Estimated Cumula-
tlve AI askan
Consumption from
1983 to 1997
( 15 years) 3,943 I, 507 2,436
Net Surplus ( l:ef I cIt) 34,838 687 33,882 2,917 956 (2,230)
1! From Chapter 4. North Slope Is as of 11/1/82. Cook Inlet Is as of
1/1/82.
2/ Total gas disposition net of reinjection, from Chapter 2. State
royalty share Is proportion of state royalty gas In total.
3/ From Chapter 3.
5.4
SENSITIVITY OF RESULTS 5.4
The conclusions of this chapter are sensitive to several assumptions
made in the analysis which may turn out to be incorrect. These are
discussed in turn and shown in Table 5.3.
Reserve Estimates
Because the low reserve estimates are quite similar to the mid-range
estimates, the positive oil and gas surpluses are not significantly
affected by using lo\"1 reserve estimates.
Economic Growth
Faster population growth will accelerate the use of liquid fuels more
than natural gas because a larger portion of natural gas is used by
large industrial users •. Even so, the net surplus of petroleum liquids
would be reduced only marginally by growth of population-related
consumption at double the base case rate. Use of natural gas would
expand by a smaller proportion.
Export of Gas
To the extent natural gas is exported, it is unavailable for the local
market. Cumulative exports over the next 15 years from current
operations are projected to be 945 billion cubic feet. If the Pacific
Alaska LNG facility were built to currently proposed specifications,
it would annually export 160 billion cubic feet. With an assumed
first year of operation of 1990, cumulative exports to California
through 1997 would be 1 , 280 b i 11 ion cubic feet. Combined exports to
Japan and California would be 2,225 billion cubic feet, reducing
reserves for instate use, and the net surplus, to 30,713 billion cubic
feet. The net surplus in Cook Inlet under these assumptions becomes a
net deficit.
Susi tna Hydro
If Susitna nydro is built according to the current schedule, it would
begin to replace generation by natural gas and fuel oil in 1994. If
natural gas use were cut back 75 percent beginning in that year,
cumulative gas consumption would decline 182 billion cubic feet. Fuel
oil use could be eliminated at a savings of 40 million gallons (about
one million barrels).
5.5
Sensitivity Analysis of Net Surplus TAtU 5.3
Net Surplus
Liquid Petroleum Natura I Gas
(Million barrels) (BCF>
Base case 9,063 34,838
Low reserve estimates 7,393 32,938
50% increase in growth of
population-related consumption 8,997 34,538
Export of LNG NIC 30,713
Susltna hydro 9,062 35,020
Natural gas available In
Fairbanks 9,243 34,779
N/C = no change
s.6
Natural Gas Availability in Fairbanks
If, by some means, natural gas became available in Fairbanks, all
electricity generation and space heating might convert to gas. This
could increase annual gas consumption for electricity generation by
6.3 billion cubic feet as coal and fuel oil use are backed out.
Fuel oil use would fall by 10 million gallons annually.
Natural gas consumption for space heating would gradually replace
fuel oil and coal and could capture 75 percent of the market. If
gas became available in 1993 and captured this share of the market
by 1997, gas consumption for space heat could increase 20.7 billion
cubic feet and fuel oil consumption fall by 120 million gallons.
The net surplus of gas would fall very marginally because of this.
5.7
ROYALTY OIL AND GAS DATA BY FIELD APPENDIX A
Beluga River
Cook Inlet, onshore, west side
Chevron, ARCO, Shell
Chevron
FIELD
LOCATION
OWNER
OPERATOR
LEASES State ADL: 17592, 17599, 17658, 21126, 21127, 21128, 21129
Federal AO: 29656, 29657
OIL
BEGAN OPERATION 1/68
CUMULATIVE PRODUCTim!
AS OF 7/31 /82
AVERAGE t·10NTHL Y
PRODUCTION 1-7/82
ESTWATED RESERVES
AS OF 7/31/82
ESTH1ATED PERCENT OF
FIELD DEPLETED
AS OF 7/31/82
ROYALTY 12.5%, Effective rate: 7.555%
PURCHASER Chugach Electric
Current Status
BBL
BBL
BBL
%
BBL
GAS
CASHJGHEAD GA-s-GAS ~/Ell
t·~CF 135,481,681 r1CF
MCF 1, 539,061 t1CF
MCF 742 BCF
% 16%
~1CF RIV: $ 0.20 t1CF
Chugach Electric is the only current purchaser of this gas. It is understood that
Pacific Alaska LNG has contracted to purchase gas from this field in the future.
Enstar has recently purchased gas under contract from Shell and tentatively plans
to build a pipeline through the ~"at-Su Valley to Anchorage.
Chugach Electric uses this gas for power generation which is delivered to the
Anchorage market.
There is no gas pipeline currently available to deliver gas from this field to any
other market.
Other than Chugach, there is no current purchaser for the State•s royalty share.
Due to the existence of several Federal leases, the State•s effective royalty share
is 7.55%, which resulted from a reallocation of the royalty ownership. The
reallocation was due to changing the m·mership detennination from surface acreage
to reservoir percentage.
A. 1
Granite Point
Cook Inlet, offshore, west side
FIELD
LOCATION
miNER
OPERATOR
LEASES
ARCO, Chevron, Amoco, Getty, Phillips, Union, Superior, Texaco, t1obil
Amoco, Texaco, ARCO, Union
State ADL: 17586, 17587, 17597, 18742, 18761, 18776, 35431
BEGAN OPERATION 12/67
CUt1ULATIVE PRODUCTION
AS OF 7/31/82
AVERAGE ~10NTHL Y
PRODUCTION 1-7/82
ESTH1ATED RESERVES
AS OF 1/l/82
ESTH1ATED PERCENT OF
FIELD DEPLETED
AS OF 7/82
ROYALTY 12.5%
OIL
89,571 ,680 BBL
292,152 BBL
35 HMBBL
73%
PURCHASER Tesoro RIK: $28.66 BBL
Amoco Platform*
1\RCO*
Union*
GAS
CASINGHEAD GA~
79,384,772 t1CF
255,078 MCF
26 BCF
77%
GAS WELL
RIV: $ • MCF RIV: $ •
RIV: $0.10 MCF
RIV: $0.118 t1CF
RIV: $0 .l 0 ~1CF
*small amount of casinghead gas sold to Amoco for use on platform.
Current Status
MCF
MCF
BCF
MCF
All Royalty oil produced from this field is taken in kind and sold to Tesoro-Alaska
Petro 1 eum Company.
Gas produced from this field was formerly flared. DOGC Flaring Order Number 194
dated June 30, 1971, has prohibited flaring since July 1, 1972, and this gas is now
recovered and used locally.
A.2
Kenai
Cook Inlet, onshore, east side
Union, t·1arathon, ARCO, Chevron
Union
FIELD
LOCATION
OWNER
OPERATOR
LEASES State ADL: 00593, 00594, 00588, 02411, 024·97, 308223, 324598
Federal AO: 28047, 28055, 28056, 28103, 28140, 28142, 28143
OIL GAS
CASINGHEA.D GA-s-GAS ~JELL
BEGAN OPERATION l/62
CUr1ULATIVE PRODUCTION
AS OF 7/31/82 BBL P1CF l , 265, 649, 770 MCF
AVERAGE t·10NTHL Y
PRODUCTION l-7/82
ESTI~mTED RESERVES
AS OF l/l/82
ESTH1ATED PERCENT OF
FIELD DEPLETED
AS OF 7/82
BBL MCF
BBL BCF
%
ROYALTY
PURCHASER
12.5%, Effective rate: Kenai, 2.06879%; Kenai Deep,
City of Kenai $ • BBL $ • t1CF
Union Chemical Corp.
Marathon LNG
Alaska Pipeline
Rental gas {Swanson River oil field)
Chevron Refining
Union-Chevron exchange
Weighted average
* Natura 1 gas 1 i qui ds
Current Status
9,413,658 P1CF
1,109 BCF
55%
0.0%
RIV: $0.29 f1CF
$0.53
$2.02
$0.605
$0.18
$0.605
$0.605
$0.526
The Kenai Unit provides most of the gas sales in the Cook Inlet area. The
estimated quantity of Alaska State royalty gas sales amounts to approximately
195,000 MCF as of 1982. The State does not receive the full 12 l/2% royalty share
because of the predominance of Federal leases in the unit and the recent conveyance
of land to Cook Inlet Region Incorporated. The price the State received for its
royalty share results from prices paid under existing contracts bebteen the 1 essees
and their purchasers.
A. 3
Kuparuk River
North Slope, onshore
FIELD
LOCATION
OWNER
OPERATOR
LEASES
ARCO, BP, Chevron, Mobil, Phillips, Sohio, Union
ARCO
State ADL: See following page.
BEGAN OPERATION 12/81
CUMULATIVE PRODUCTION
AS OF 7/31/82
AVERAGE MONTHLY
PRODUCTION 1-7/82
ESTIMATED RESERVES
AS OF 1/1/82
ESTIMATED PERCENT OF
FIELD DEPLETED
AS OF 7/82
OIL
19,766,184 BBL
2,666,960 BBL
1, 000 MMBBL *
2%
GAS
CASINGHEAD GA~
3,984,797 MCF
481,137 MCF
206 BCF
1%
GAS WELL
ROYALTY 12.5%
PURCHASER NONE RIV: $17.015 BBL RIV: $2.71 MCF RIV: $ •
*source: William Van Dyke, personal comunication, 1982.
A.4
MCF
MCF
BCF
MCF
Field
Leases
Kuparuk River
State ADL:
25512, 25513, 25519, 25520, 25521, 25522, 25523, 25531, 25547, 25548, 25569, 25570,
25571, 25585, 25586, 25587, 25588, 25589, 25590, 25603, 25604, 25605, 25628, 25629,
25630, 25631, 25632, 25633, 25634, 25635, 25636, 25637, 25638, 25639, 25640, 25641,
25642, 25643, 25644, 25645, 25646, 25647, 25648, 25649, 25650, 25651, 25652, 25653,
25654, 25655, 25656, 25657, 25658, 25659, 25660, 25661, 25664, 25665, 25666, 25667,
25668
A.5
r~cArthur River
Cook Inlet, offshore, west side
Union, ARCO,
Union
FIELD
LOCATIOtJ
OWNER
OPERATOR
LEASES State ADL: 17519, 17594, 17602, 18716, 18729, 18730, 18758, 18772
18777, 21068
BEGAN OPERATION 12/69
CUMULATIVE PRODUCTION
AS OF 7/31/82
AVERAGE MONTHLY
PRODUCTION 1-7/82
ESTH1ATED RESERVES
AS OF l/l/82
ESTIMATED PERCENT OF
FIELD DEPLETED
AS OF 7/82
ROYALTY 12.5%
PURCHASER Tesoro
Current Status
OIL GAS
CASINGHEAD GAs;--
466,923,271 BBL 147,029,282 MCF
1,297,273 BBL 522,646 MCF
90 MMBBL 27 BCF
85% 86%
GAS WELL
87,071,920 MCF
724,152 MCF
63 BCF
60%
RIK: $28.04 BBL RIV: $ • MCF RIV: $ • MCF
All Royalty oil produced from this field is taken in kind and sold to Tesoro-Alaska
Petroleum Company.
Gas Produced from this field is casinghead gas and was formerly flared. DOGC
Flaring Order Number 104 dated June 30, 1971 has prohibited flaring since July l,
1972, and this gas is now recovered and used locally.
A.6
FIELD
LOCATION
OWNER
OPERATOR
LEASES
Middle Ground Shoals
Cook Inlet, offshore, east side
Amoco, ARCO, Chevron, Getty, Phillips, Shell
Shell, Amoco
State ADL: 17595, 18744, 18746, 18754, 18756
OIL GAS
CASINGHEAD GAs--GAS WELL
BESAN OPERATION 9/67
CUMULATIVE PRODUCTION
AS OF 7/31/82 135,887,301 BBL 66,666,495 MCF 34,812 MCF
AVERAGE MONTHLY
PRODUCTION 1-7/82
ESTIMATED RESERVES
AS OF 1 /l /82
ESTIMATED PERCENT OF
FIELD DEPLETED
AS OF 7/82
ROYALTY 12.5%
PURCHASER Tesoro
Current Status
303,298 BBL 188,355 MCF MCF
26 f~MBBL 14 BCF BCF
85% 84% %
RIK: $28.17 BBL RIV: $. MCF RIV: $ . MCF
All Royalty oil produced from this field is taken in kind and sold to Tesoro-Alaska
Petroleum Company.
Gas produced for this field is casinghead gas and was formerly flared. DOGC
Flaring Order Number 104 dated June 30, 1971, has prohibited flaring since July 1,
1972, and this gas is now recovered and used locally.
Recent increases in gas prices may encourage a reevaluation of this gas.
A.7
Nicolai Creek FIELD
LOCATION
OWNER
OPERATOR
LEASES
Cook Inlet, onshore -offshore, west side
Texaco, Superior
Texaco
State ADL: 17585, 17598, 63279
Federal AO: 34161
BEGAN OPERATION 10/68
CUf4ULATIVE PRODUCTION
AS OF 7/31/82
AVERAGE MONTHLY
PRODUCTION 1-7/82
ESTIMATED RESERVES
AS OF l/1 /82
ESTIMATED PERCENT OF
FIELD DEPLETED
AS OF 7/82
OIL
BBL
BBL
BBL
GAS
CASINGHEAD GAs--
MCF
MCF
BCF
GAS WELL
1,062,055 MCF
MCF
17 BCF
6%
ROYALTY 12.5%
PURCHASER Amoco $ • BBL $ • MCF RIV: $0.15 MCF
Current Status
Gas from this small field, when produced, is used only to provide fuel for platfonn
and shore facilities supporting petroleum production in this area. However, at the
present time, there is no production. At this time, there is no prospective
purchaser for the State's royalty share.
A.8
FIELD North Cook Inlet
LOCATION Cook Inlet, offshore, mid-channel
OWNER Phillips
OPERATOR Phillips
LEASES State ADL: 17589, 17590, 18740, 18741, 37831
OIL GAS
CASINGHEAD GA~ GAS WELL
BEGAN OPERATION 3/69
CUMULATIVE PRODUCTION
AS OF 7/31/82 BBL MCF 572,856,539 MCF
AVERAGE MONTHLY
PRODUCTION 1-7/82 BBL MCF 3,403,286 MCF
ESTIMATED RESERVES
AS OF 1/1/82 BBL BCF 951 BCF
ESTif~ATED PERCENT OF
FIELD DEPLETED
AS OF 7/82 % 38%
ROYALTY 12.5%
PURCHASER Alaska Pipeline $ . BBL $ • MCF RIK: $3.033 ~1CF
Phillips $ . BBL $ . MCF RIV: $0.4165725
t•1CF
Current Status
Gas from this offshore field is primarily delivered to the Phillips LNG plant and
subsequently sold in Japan. However, in 1977, the State entered into agreements
with Phillips and Alaska Pipeline Company to sell the royalty share to Alaska
Pipeline Company for delivery to the Alaska market. Royalty gas not purchased by
Alaska Pipeline Company is taken by Phillips.
A.9
Prudhoe Bay
North Slope, onshore
FIELD
LOCATION
OWNER Amerada-Hess, ARGO, BP, Chevron, Exxon, Getty LL&E, Marathon,
t1obi 1 , Phi 11 i ps
ARCO, Sohi o OPERJHOR
LEASES See following page.
BEGAN OPERATION 10/69
CUMULATIVE PRODUCTION
AS OF 7/31 /82
AVERAGE f.1Q~JTHL Y
PRODUCTION 1-7/82
ESTit~TED RESERVES
AS OF 7/3/82
ESTIMATED PERCENT OF
FIELD DEPLETED
AS OF 7/82
ROYAL TV 12.5%
OIL GAS
CASINGHEAD GAs--
2,418 ~1t1BBL 255, 760,0n8 t4CF
46,462,764 BBL 4,788,212 MCF
6,950* MMBBL 28,778 BCF
26% 1%
GAS WELL
PURCHASER Tesoro RIK: $28.04 BBL RIV: $ • t~CF RIV: $ •
*William Van Dyke, personal communication, 1982
Current Status
MCF
MCF
BCF
MCF
Small quantities of casinghead gas are presently being sold to the owners of the
Trans-Alaska Pipeline. The State is receiving royalty in value with the gas price
being set by the owners of the gas cap. There presently is no other market. The
State's share of sales is 12 1/2%.
The State's royalty share of the oil produced is 12 1/2% with 14.9% of this share
presently being taken in kind and sold to North Pole Refinery, and Golden Valley
Electric Assn. The State requested that an additional 35.5178% of the State's
share be taken in kind, which goes to Tesoro Alaska Petroleum Company. The
remainder is taken in value.
A. 10
Field: Prudhoe Bay
Leases: State ADL:
28238, 28239, 28240, 28241, 28241, 28244, 28245, 28246, 28257, 28257, 28258, 28260,
28261, 28262, 28262, 28263, 28263, 28264, 28265, 28277, 28278, 28279, 28280, 28281,
28282, 28283, 28284, 28285, 28286, 28287, 28288, 28289, 28289, 28290, 28299, 28300,
28301, 28302, 28303, 28304, 28305, 28306, 28307, 28308, 28309, 28310, 28311, 28312,
28313, 28314, 28315, 28316, 28316, 28320, 28321, 28322, 28323, 28324, 28325, 28326,
28327, 28328, 28329, 28330, 28331, 28332, 28333, 28334, 28334, 28335, 28339, 28343,
28344, 28345, 28346, 28349, 34628, 34629, 34630, 34631, 34632, 47446, 47447, 47448,
47449, 47450, 47451, 47452, 47453, 47454, 47469, 47471, 47472, 47475, 47476
A.ll
Sterling FIELD
LOCATION
OWNER
OPERATOR
LEASES
Cook Inlet, onshore, east side
Union, Marathon
Union
State ADL: 02497, 320912, 324599
OIL
BEGAN OPERATION 5/62
CUt4ULATIVE PRODUCTION
AS OF 7/31/82 BBL
AVERAGE 140NTHL Y
PRODUCTION 1-7/82 BBL
ESTIMATED RESERVES
AS OF 1/l/82 BBL
ESTIMATED PERCENT OF
FIELD DEPLETED
AS OF 7/82 %
ROYALTY 12.5%, Effective rate,l.55461%
PURCHASER Sport Lake $ . BBL
Greenhouse
STERLING
GAS
CASINGHEAD GAS
MCF
MCF
BCF
$ • MCF
Statistics relating to this field are shown on the attached table.
Current Status
GAS WELL
2, 024,290 t4CF
1,986 MCF
23 BCF
8%
$0.40 MCF
Since Federal and Cook Inlet Region Inc. leases are involved, the state•s royalty
share is approximately 1.6%. The only gas sold from this field is consumed
locally. There is no gas pipeline currently available to deliver this gas from
this field to any other market. Because of limited reserves, there is no current
prospect of additional markets.
A. 12
Trading Bay FIELD
LOCATION
OWNER
OPERATOR
LEASES
Cook Inlet, offshore, west side
Marathon, Union
Union
State ADL: 18731
BEGAN OPERATION 12/67
CUMULATIVE PRODUCTION
AS OF 7/31 /82
AVERAGE MONTHLY
PRODUCTION 1-7/82
ESTIMATED RESERVES
AS OF l/l/82
ESTIMATED PERCENT OF
FIELD DEPLETED
AS OF 7/82
ROYALTY 12.5%
OIL
83,352,631 BBL
120,092 BBL
4 MMBBL
96%
GAS
CASINGHEAD GAs--
53,929,018 MCF
98,359 MCF
3 BCF
96%
GAS WELL
469,236 MCF
24,770 MCF
10 BCF
5%
PURCHASER Tesoro RIK: $26.43 BBL* RIV: $ • MCF RIV: $ • MCF
*weighted average.
Current Status
All Royalty oil produced from this field is taken in kind and sold to Tesoro-Alaska
Petroleum Company.
Gas produced for this field is casinghead gas and was formerly flared. DOGC
Flaring Order Number 104 dated June 30, 1971, has prohibited flaring since July 1,
1972, and this gas is now recovered and used locally.
A. 13
DEMAND PRQJECTIOM METHODOLOGY APPENDIX B
DEMAND PROJECTION METHODOLOGY APPENDIX B
Demand for oil and gas is best calculated if divided into use
categories because of similarity in the factors affecting the level
and growth rate of demand by use. In addition, oil and gas often
compete with one another in a market for a particular use, such as
space heating or electricity generation. The use categories in this
study are transportation, electricity, space heat, and industrial.
The factors most important in projecting future demand will vary by
use catego~. In general, the most important are population
(households) and relative fuel prices. The household is the basic
consuming unit for the residential sectors and is a good proxy for
demand in the commercial sector. In the industrial sector, relative
fuel prices is the primary demand determinate; while in the
residential and commercial sectors, fuel prices are more important
in determining the type 'of fuel used.
TRANSPORTATION USE OF LIQUID PETROLEUt~ B. 1
The method of projecting transportation fuel use is with consumption
per capita coefficients.
Gasoline
a. Highway use (taxable & exempt) is the largest category of
gasoline consumption in Alaska. Historically, demand is related
to population, personal income, and the fuel efficiency of the
automobile stock. In Alaska, growth in the first two factors
will tend to offset the effect of increased fuel efficiency in
future years resulting in aggregate growth in use of this fuel.
Nationally, per capita consumption of gasoline has fallen in
recent years. We assume a continuation of this per capita trend
for Alaska. Demand is projected using a per capita coefficient
which declines one percent annually from the previous year.
1981 consumption was 444 gallons per capita.
b. Aviation gasoline (taxable and exempt) use has, in the past
decade, been roughly 10 percent as large as highway gasoline
use. The sharp decline in 1982 is probably a reporting error.
We assume that a strong income elasticity of demand for general
aviation will result in a maintenance of the current per capita
use coefficient in future years. 1981 consumption was 44.7
gallons per capita.
B. 1
c. Marine gasoline (taxable and exempt) use has, in the past
decade, been roughly 50 percent of the aviation gasoline
consumption level with an apparently slightly slower growth
rate. We assume a strong income elasticity of demand will
result in maintenance of the current per capita use coefficient
in future years. 1981 consumption was 18 gallons per capita.
Jet Fuel
Jet fuel consumption consists of domestic commercial operations,
international commercial operations, and military operations.
Domestic commercial operations is a function of the Alaskan
population and economy and as such has grown rapidly in per capita
terms historically (taxable). International commercial operations
are a function of world economic and political conditions as well as
aviation technology. Military operations are broadly a function,
albeit a different one, of the same factors. These two later
categories, accounting 'for about 2/3 of jet fuel consumption, cannot
be separately identified in the historical data, but their combined
total has shown relatively modest, although cyclical, growth since
the early 1970s.
Using 1981 as a base (since that is the last year for which domestic
commercial jet fuel consumption can be separately identified in the
data), we project domestic commercial consumption separately from
international commercial and military. The coefficient relating
consumption to population for domestic commercial aviation has
increased from 161 to 316 gallons per capita since 1971.
We assume future growth will exceed population but at a slower rate
because of increased efficiency of the capital stock. The
coefficient grows by three percent annually.
Variation in international commercial and military consumption is
difficult to project. Growth during the preceding decade
approximated one percent per annum. We use this figure to project
future growth.
Diesel
The categories used to report diesel fuel sales in Department of
Revenue tax records have changed at least twice since 1979, making
use of this source of data for projecting highway diesel consumption
(or any type of consumption) difficult. The difficulties are that
"exempt highway fuel 11 includes some nontransport fuel use and "off
highway fuel .. includes an unknown portion of electrical utility fuel
use and space heating use (see Table B.l).
B.2
State Consumption of
Motor Vehicle Diesel Fuel 1/ (Mill. Jon Gallons) TABLE B. I
Ott Other
Highway Highway Taxable
Year Total Taxable Exempt Exempt HIghway
1971 107 35 72
1972 84 29 55
1973 114 25 89
1974 166 66 100
1975 204 133 71
1976 205 140 65
1977 144 99 45
1978 156 102 54
1979 269 57 69 81 92
1980 302 65 24 97 117
1981 336 36 22 103 75
1982 380 19 19 142 0
l( Department of Revenue, Tax Records
B.3
We assume 1982 highway sales (taxable and exempt) represent all
highway transport use of diesel and no nontransport use. Future
growth in consumption is projected at the current per capita use
rate of 512.9 gallons. 11 0ff highway fuel 11 use and "other taxable
hi ghway 11 as reported by the Department of Revenue are components of
utility and space heat fuel use. Projections of these uses of
diesel fuel are separately calculated (see below).
Marine diesel use is roughly one quarter that of highway diesel.
Its use displayed very rapid growth in the mid 1970s and now appears
to be stabilizing. We assume a constant per capita level of
consumption of 127.8 gallons.
Regional Allocation
Regional allocations of transportation fuels are made on the same
basis as the allocations of historical consumption in Chapter 2.
ELECTRIC UTILITY USE OF LIQUID FUELS AND NATURAL GAS B.2
Electric utility use of oil and gas is a derived demand based upon
the demand for electricity and the methods used to generate it. We
project this use of liquid fuels and natural gas by first estimating
electricity demand for space heating and nonspace heating uses, then
determining the proportion generated by fuel oil and natural gas
and, finally, determining demand based upon the efficiency of
generation (heat rate}. Since the electricity generation
alternatives vary by region in Alaska, we project fuel use by three
major regions of the state.
Rail belt
a. Consumption
The space heating and nonspace heating components of electricity
consumption per capita in the railbelt are based upon the
Railbelt Electricity Demand Model (Table B.2) updated to
estimated 1982 electricity consumption levels.
8.4
Rail Belt Consumption of Electricity
Net of Space Heating
Consumption J! Population
(MWH)
1980 1498 284,392
1985 2059 341,169
1990 2355 370,445
1995 3091 421,983
2000 3866 472,551
TABLE 8.2
Consumption per Capita
<KWH>
5265
6035
6350
7325
8180
J! Total consumption In medium case minus twice the residential
space heating consumption, Electric Power Consumption for the
Rallbelt; Goldsmith and Huskey, tSER 1980.
6.5
Non-space heating railbelt electricity consumption per capita is
projected to grow according to the growth in Table B.2.
Electricity consumption for space heating depends upon population
growth· but also upon two other factors: )1) the extension of the gas
utility into the Matanuska Valley. and (2) the completion of the
electric intertie between Anchorage and Fairbanks. The former will
result in a portion of existing structures utilizing natural gas
rather than electricity for space heating. This will slow the
growth rate of electricity use but increase the use of utility gas.
The second factor may alter the relative price of electricity in
both Anchorage and Fairbanks relative to natural gas and fuel oil.
We assume the gas utility will extend their market into the
Matanuska Valley and aggressively market their gas for space
heating. Market penetration begins in 1985. and during the next
five years the electric space heating market in the Matanuska Valley
falls to half its current share. Subsequent to that, it resumes the
growth rate of per capita space heating consumption.
We assume the completion of the Anchorage-Fairbanks intertie does
not significantly alter the price of electricity faced by consumers
in either location. In particular, there is no shift towards
electric space heating in Fairbanks as a result of the tie~in to the
inexpensive gas-fired electricity from Anchorage.
b. Mode Split: Future additions to capacity within the projection
period are all gas-fired turbines. Incremental generation in
Anchorage is entirely natural gas. Incremental generation in
Fairbanks \'lill depend upon the cheaper of the cost of purchased
electricity from Anchorage generated by natural gas and the
marginal cost of locally produced electricity generated by fuel
oil. We assume electricity moves in both directions in the line
at different times. Fairbanks excess capacity provides reserves
to Anchorage and cheap Anchorage generation provides off peak
electricity to Fairbanks. Incremental generation in Fairbanks
comes from Anchorage produced electricity. The following
exceptions modify these rules:
1. Coal-fired generation in Fairbanks remains constant at
354 thousand r~WH annually.
2. Bradley Lake comes on line in 1988 and produces 300
thousand ~1WH annually. This backs out 4.5 billion
cubic feet of natural gas annually.
3. Solomon Gulch comes on line in 1982 with a firm annual
energy of 55 thousand MWH. This backs out 3 million
gallons of fuel oil annually.
Heat rates are projected to remain at current levels.
B.6
Southeast
a. Consumption
The growth rate in consumption per capita in Southeast is
assumed to be the same rate as in the railbelt. The advent of
less expensive electricity provided by hydroelectric power may
cause electric space heating demand to grow and accelerate that
growth rate. We assume this effect is insignificant.
b. Mode Split
As hydroelectric projects, now in the planning stage or under
construction, are brought on line, they will back out the use of
fuel oil in electricity generation in those locations linked to
the hydro power. The schedule of hydroelectric projects assumed
is as shown in Table 8.3.
8.7
Scheduled Southeast Alaska Hydroelectric Projects TABLE B.3 -
Scheduled Annual
Name Location Completion Capacity Energy
<MWl <MWHl
Swan Lake Ketchikan 1984 22 103
Tyee Lake Wrange 11/Petersburg 1985 20 133
B.8
Rest-of -State
The rest of the state, with the exception of Barrow, currently
relies on fuel oil for electricity generation. This dependence is
projected to continue into the future with the exception of Kodiak,
which will have some hydropower available in 1985 when the Terror
Lake project is completed. This will provide 132 thousand MWH of
firm annual energy.
Growth in per capita electricity demand is assumed to occur at twice
the rate projected for the railbelt.
B.9
SPACE HEATING USE l/ OF LIQUID FUELS AND NATURAL GAS 8.3
In the Anchorage area, natural gas is the most economical fuel for
space heating. Elsewhere fuel oil is least expensive except where
electricity generated by natural gas is available. In projecting
future demands, we use different procedures for gas and fuel oil.
Natural gas is based upon a projection of the current level of
consumption. Fuel oil demand is estimated based upon the proportion
of the population assumed to heat with fuel oil. This is
necessitated because there is no reliable direct estimate of current
fuel oil consumption for space heating.
Rail belt
Natural gas for space heating (and a small amount of related uses
for gas purchased from utilities) is projected to grow as a function
of population. Growth historically has occurred at a rate in excess
of population due to gas retrofiting and expansion of the
commmercial sector. This trend will moderate in the future, and
growth is projected to exceed population by two percent annually.
In addition, a new market will open in the Matanuska Valley in
1985. We estimate that by 1990, one-half of the building stock in
the Matanuska Valley will utilize natural gas for space heating.
The resulting demand level is estimated on a per capita basis.
Currently total natural gas consumption (residential plus
commercial) per capita for the gas using population is 113 mcf. The
proportion of railbelt population heating with gas is 47 percent.
This factor forms the basis for estimating the growth of space
heating demand for natural gas in the Matanuska Valley.
Fuel oil use for space heating is generally preferred only where gas
or gas-fired electricity is not available. Growth in its use will
depend upon the location of new structures in the railbelt. We
assume consumption grows at one percent in excess of the rate of
population increase. The base, from which this growth is projected,
is the per capita gas consumption figure converted to fuel oil on
the basis of BTU equivalency. The proportion of railbelt population
dependent upon fuel oil for space heating is estimate9 to be
12 percent.
17 Includes water heating, cooking, and other minor uses.
B. 10
Nonrai 1 belt
Outside the railbelt, space heating is almost entirely provided by
fuel oil, with the exception of Barrow. Growth in consumption is
assumed to occur two percent faster than population due to a
continuation in the decline of average household size and upgrading
of the average size and number of structures relative to
population. The same growth rate is applied to gas use in Barrow.
The base from which growth is projected is the same per capita
coefficient of fuel oil use for space heating used for the railbelt
population. This estimate is consistent with surveys and small
region studies of fuel oil use in rural Alaska. This estimate
entails compensating errors. On the one hand, the heating degree
days are greater in most parts of the state which rely on fuel oil
relative to Anchorage. On the other hand, the stock of structures
is smaller outside AnchQrage.
INDUSTRIAL USE OF liQUID FUELS AND NATURAl GAS B.4
Industrial consumption is not a function of population, but rather
of the availability of supplies and market opportunities. Since the
major industrial users of petroleum fuels are small in number, they
are best projected on a case by case basis.
Ammonia Urea Production
Ammonia Urea production using natural gas is assumed to continue at
a constant level.
Petroleum Production Related Use
a. Gas Use in Production
Natural gas is utilized in petroleum production in Cook Inlet
and on the North Slope for a variety of purposes, including
space heating, electricity generation, pump fuel, etc. The
level of consumption is difficult to project because of its many
uses, but is primarily dependent upon petroleum production
levels and petroleum employment levels. We assume the level
remains constant in Cook Inlet. On the North Slope it grows
seven percent annually for ten years and is constant thereafter.
b. Oil Use in Production
A small quantity of fuel oil is used in oil production. This is
included in the miscellaneous industrial category.
c. Gas Use in Transportation
Included in gas use in production.
B. 11
d. Transportation-Oil
Fuel oil fuels the pumps for most of the Alyeska pipeline.
Annual consumption is estimated to be two million barrels of
oil. This level is projected to remain constant.
e. Oil-Miscellaneous
Some fuel oil is used in electricity generation for industrial
self-supplied power. This amount~ taken from Alaska Power
Administration, is projected to remain constant.
f. Military
The milita~ uses natural gas for electricity generation and
space heating in the Anchorage area and fuel oil elsewhere.
Milita~ transportation use of fuel oil is counted in the
transportation sector. Military natural gas use is projected to
remain constant. Lack of data prevents the calculation of
military fuel ·oil consumption for space heating.
Injection
Gas is injected into petroleum reservoirs to enhance oil recovery.
Because this is only a temporary use of gas~ it is not counted a
part of final consumption.
8.12
PROCESSING PLANT, TRANSPORTATION FACILITY AND TAPS DATA APPD!DIX C
n
REFINERY
NIKISKI
Chevron Refinery
Tesoro Refinery
Union Chemical
Division
INTERIOR ALASKA
PLANT
CAPACITY
18,000 BPD,
North Slope
Crude
45,500 BPD
Ammonia
1,100,000
tons/yr
Urea 1,000,000
tons/yr
DATE
PLANT IN
OPERATION
1962
1969
(17 ,500 BPD)
1969
North Pole Refinery 46,600 BPD 1977
Phillips-Marathon
LNG
Pacific Alaska LNG
230,000
MCF/Day
1969
200,000 Planned 1986
MCF/Day
initial
400,000
MCF/Day (2nd yr)
PROCESSING PLANTS
DATE
EXPANSION
1974,1975,1977
1980 (7500 BPD
Hydro cracker
Unit.)
1977
Fall 1980
PLANT
PROOUCT
JP4, Furnace Oil, Diesels,
Fuel Oil, Asphalt, Unfinished
Gasoline.
Propane, Unleaded, Regular, and
Premium Gasoline, Jet A, Diesel
Fuel, No. 2 Diesel, JP 4 and
No. 6 Fuel Oil.
Anhydrous Ammonia, Urea Prills
and Granules.
Military Jet Fuel (JP4), 3000-
4000 BPD; Commercial Jet Fuel,
5000-6500 BPD; Diesel/Heating
Fuel No. l, 1000-1500 BPD;
Diesel/Heating Fuel No. 2,
1800-2500 BPD, Diesel Fuel
Type No. 4, 600-1800 BPD.
TRASPORTATION FACILITIES
Liquified Natural Gas.
Liquified Natural Gas.
DESTINATION
JP4, JASO, Furnace Oil, Diesels,
and Asphalt for Alaska;
Unfinished Gasoline, High Sulfur
Fuels to Lower-48 states.
Alaska except No. 6 Fuel Oil to
Lower-48 states.
West Coast and export by tanker
and bulk freighter.
Fairbanks area, Nenana and
river villages, Eilson AFB.
Japan, by tanker, 2 tankers
capacity 71,500 cubic meters
each, avg. one ship every 10 days.
Southern California one ship
every 13 days.
Trans-Alaska Pipeline statist! cs 1/
Closing
F\Jmp sta. I Valdex IF Ship Ship
1982 Throughput Sta-age Ships Cargo Ll ftlngs
January 50,385,826 6,130,687 61 81 I ,669 49,51 I ,820
February 45,548,631 5,242,503 53 852,308 45,172,305
March 50,379,849 2,919,529 65 800,744 52,048,334
Apri I 48,431 ,614 1,721,105 64 765,986 49,023,096
May 50,583,201 4,519,692 56 840,479 47,066,819
June 4 7,693,327 3,679, 775 56 855,928 4 7,931, 968
July 50,739,029 3,499,471 60 836,602 50,196,146
August 50,191,592 3,365,599 58 854,876 49,582,797
Sept. 48,998,195 6,790,667 52 863,280 44,890,561
October 50,404,233 5,832,173 61 829,994 50,629,644
November 48,082,928 4,061,822 61 806,667 49,206,687
December 49,703,120 4, 785,900 59 804,102 47,441,992
TOTAL 591,141,545 706 583,370,439
Average
f.bnth 49,261,795 59 826,886 48,614,203
1/ Personal communication with Alyeska Pipel lne Service.
C.2
ECmJOrU C GRO\fTH ASSUt4PTIONS APPENOIX n
ECONOMIC GROWTH ASSUMPTIONS APPENDIX D
Economic projections for estimating future petroleum demands are
particularly difficult to develop this year because of the unsettled
nature of both the world oil market and the national economy. The
former makes it difficult to project activity in the petroleum
industry, the most important basic sector industry in the economy,
and activity generated by state government spending, which is
primarily a function of the availability of petroleum revenues. The
latter affects the short and medium term level of economic activity
in the state as the recession in the Lower 48 states makes the
in-migration of people and money to Alaska more attractive.
This phenomenon during the last two years, amplified by the dramatic
growth in state spending fueled by the increase in oil prices, has
generated an increase in. population from 400 thousand in 1980 to
464 thousand in 1982 (Alaska Department of Labor). This two-year
increase in population matches the magnitude of the growth which
7ccurred between 1974 and 1976 during the peak construction years
for the oil pipeline (approximately 67 thousand), and was
unanticipated by all forecasts. This annual growth rate of
7.7 percent during the past two years contrasts sharply with an
average annual growth rate of 2.9 percent in population between 1960
and 1980. The fact that population change can display such a wide
variation in growth in only two years demonstrates the difficulty in
accurately projecting longer range population trends for Alaska,
particularly within the context of a temporary boom generated by
state spending.
The base case economic projection assumes a population growth rate
of 2 percent annually with an employment growth rate of
1.8 percent. These growth rates are down from those observed over
the first two decades of statehood, but are considerably above
projections of growth of the national economy. The U.S. Department
of Commerce has recently projected population growth for the nation
to the year 2000 at .8 percentage annually, and employment growth at
1.2 percent annually {Survey of Current Business, November 1980}.
These rates of growth are obviously consistent with many possible
sets of assumptions about future basic sector activity and public
sector spending. For future basic sector activity the particular
11 SCenario" employed to generate the population numbers for this
projection was similar to that used in the moderate case scenario
presented in last year•s study {Historical and Projected Oil and Gas
Consumptions, Division of Minerals and Energy Management, January
1982}, with the following exceptions:
D. 1
1. Pacific Alaska LNG-deleted
2. Petroleum Refinery -deleted
3. u.s. Borax ~1o lybdenum -added
4. Alaska Natural Gas Pipeline -two-year delay
Public sector spending is constrained by the flow of petroleum
revenues. This projection of employment is consistent with a growth
in state spending consistent with the current spending limit until
1988 at which time the revenue constraint supersedes the expenditure
limit ceiling. Non-essential programs are eliminated (transfers and
subsidies), taxes are reinstituted and tax schedules raised, and the
growth in the capital and operating budgets stops. State government
employment remains c~nstant after 1987.
The regional distribution of economic activity, employment, and
population continues to shift in favor of the railbelt as the
economic center of the state.
The population projections and distribution used in the demand
calculations are shown in Table D.l.
0.2
Population Projections TMLE D. I
state Southeast lbst-of-
Year Total Rallbelt 1/ AI aska State
1982 464,04 7 333,009 59,201 71,837
1983 4 73,328 341,001 59,812 72,515
1984 482,795 349,185 60,392 73,218
1985 492,450 357,566 60,968 73,916
1986 502,299 366,14 7 61,541 74,611
1987 512,345 374,935 62,109 75,301
1992 565,670 422,139 64,876 78,655
1997 624,546 4 75,286 67,466 81,794
J! Rallbelt Includes the followlrg Census Divisions: Anchorage,
Kana I Penlnsul a, M:Jtanuska-9Js ltna, Fa Jrbanks, Southeast Fa lrbanks,
and Valdez Cordova net of the Cordova census subarea.
0.3
CONVERSION FACTORS APPENOIX E
Conversion Factors
1 gallon diesel = 0.0239 barrel crude oil equivalent
1 gallon gasoline = 0.0215 barrel crude oil equivalent
1 gallon jet fuel = 0.023 barrel crude oil equivalent
1 gallon crude oil = 0.1387 million BTU
1 r1CF natura 1 gas = 1.000 mill ion BTU
1 barrel diesel = 5.825 million BTU
1 barrel gasoline = 5.248 million BTU
1 barrel jet fuel = 5.604 rni 11 1 on BTU
E.1
ACKNOWLEDGEMENTS APPENDIX F
ACKNOWLEDGEMENTS
This document was prepared by:
The Di vision of ~1i nera 1 s and Energy ~1anagement:
Kay Brown, Director
Jim Eason, Deputy Director
Bill Van Dyke, Petroleum Manager
Donna Wood, Royalty ~1anager
Ed Phillips, Petroleum Economist
Sam Murray, Petroleum Economist
Kris o•connor, Chief, Envr./Soc. Unit
Ed Park, Mgr., Net Profit Share
Nancy Grant, Accountant
Dick Beasley, Geologist
Wayne Hanson, Cartographer
Cathy Wilkie, Clerk Typist
Helena Bellin, Clerk Typist
Kathlene Gibson, Clerk
Diane Kochendorfer, Accounting Clerk
Sharon Thomas, Clerk Typist
The Institute of Social and Economic P~search:
Oliver Goldsmith, Associate Professor of Economics
Karen White, Research Associate
and:
Gregg Erickson and Associates, ,Juneau
F. 1