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Susitna Joint VentL're
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DOCUMENT CONTROL
FORECAST SUMMARY
by Stephen A. Smith and Mary H. Novak
WORLD OIL MARKETS:
A NERVOUS EQUILIBRIUM
(!)
Oil demands remain extremely weak.
Even after correction for record setting
wlntt.r weather mildness, year-over-year
demand declined again in the first quarter
of 1983---at a very much slower rate of
decline but, nonetheless, a decline.
(2)
The world inventory situati<;m remains
. clouded with uncertainty. AJ·though the
continuing world inventory draw which has
added to downward price pressure is
probably almost over, the poor quality of
inventory da ·~a and the potential for
further structural adjustments leave some
room for doubts.
(3)
Two o:f OPEC's members are essentially
bankrupt. Nigeria and Venezuela could
succumb to extreme financial pressures
and resort to discounting if volume does
not at least meet their quota levels or if
their quota levels cannot be increased
within the next year.
(4)
Two other members~ Iran and Libya,
cannot be relied upon for consistent
behavior for sustained periods of time--they too are not without considerable
iinancial pressures.
(5}
If the call upon OPEC fails to increase
From OPEC's perspective, the accumulated
evidence sin'2e the hlsforic marker price cut in
March might warrant the corx::lus1on: "so far, so
goodn. The positive signs include:
,
(l)
A downward price spiral did not develop.
This was a real possibility given the
vulnerability
and
panicky confusion
evidenced by OPEC from December
through Marchv
(2)
The call on OPEC production has
rebounded from February lows of 14 mmbd
to current levels of about 16 mmbd---not
a great recovery but a recovery
nonetheless.
(3)
The U.S. economic recovery appears to be
at least genuine and possibly shifting into
higher gear. Other developed economies 1
on balance, are demonstrating similar
movements.
(4)
Those members of oPgC most responsible
for OPEC's recent problems by their
discounting and lack of production
restraint in 1982 have demonstrated
surprising respect for
OPEC 1s new
agreement.
(5)
Key non-OPEC producers such as Mexico
and the U.K. have thus far been
cooperating with OPEC---Mexico by
constraining exports to 1.5 m· .1bd at a cost
of lost sales, and the U.I .. by BNOC's
prk2 cuts which stayed just short of
undercutting Nigeria.
above 15 to 16 mmbd for an extended
period, for example, one year, the marker
rice will almost certain!
ratchet
downward by another 3 to 4.
(6)
•r
Despite
this
recitation
of
favorable
occurrences, and the appearance of a nervous
equillbrium in most oil markets, OPEC is far
from "out of the woods", and the prospects for
further
downward
price
pressure
are
)considerable.
The most troublesome issues
~/include:
If the call on OPEC dof ~ increase to above
current ceiling levels by l~e end of 1983,
then the prospects for bickering over
dividing an expanding pie loom large. In a
sense, cooperation ls more difficult as
expectations improve than when a "siege"
mentaUty
frightens
members
into
reluctant cooperation.
Data Resources, Inc.
•
_,
.
1'
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'-""'-'"
..
(o~.
I
Forecast Summary
(7)
Whi.'f.! the odds are beginning to strongly
favor a sustained economic recovery,
concerns about interest rates and
international debt problems still linger.
Should the recovery abort in 1984, holding
the current oil price would be highly
unlikely.
(8)
Continued cooperation from non-OPEC
producers in terms of price and production
restraint is also de endent on a reasonabl
promp
mcrease
emana.
interest payments .for Mexico
effectively
financed
its
newfound
discipline in limiting oil exports---but
other financial needs will seriously test its
resolve as time passes with no increase in
oil revenues.
On balance, then, OPEC's new price and
production agreement has succeeded thus far
but many doubts remain. The key doubt is oil
demar.d---unless demands begin to show some
fairly early signs of ending their long decline, a
$25 or $26 price should be expected for 1984.
All factors considered, we believe the odds
slightly favor the $29 price holding through
1984---we would assign a 55% probability to
this case. The inventory draw is probably over
for the most part, the economic recovery
appears to be gathering momentum, and finally,
OPEC members appear to be sufficiently aware
of the disaster which awaits them if they fail to
observe the terms of OPEC's new agreement.
As described above, many things can go wrong
and some probably will. Given OPEC's recent
luck in encountering a statistically impossible
winter, they could well encounter another.
Blending this rather small risk with others listed
o.bove, we \\'ould assign 40% to 45% odds that
there would be at least one additional break in
the marker price in the 1983 to 1984 period.
Given there is a break, we would favor $3 to
$4. Odds of the marker rising above the current
$29 level any time t)1rough 1984 are remote--less than 5%. Price collapse scenarios over this
time frame---say less than $18---should be
viewed as equally remote.
Oil Prices
··~
The spectrum of OPEC and non-OPEC official
(/: ·) crude prices has become reasonably well aligned
· . . · and spot prices have stablized in a range within
2
fifty cents to one dollar be.low official crudes.
Nigeria's crudes are fifty cents per barrel
cheaper than other African and North Sea
crudes---a special concession to account for
their extreme financial problems. The extra
discount h~s been successful in pushing the
country's volumes temporarily to 1.6 mmbd in
May, which will force the Nigerians' to turn
away June sales to observe their 1.3 mmbd
quarterly quota.
Iran has been allowed to discount the $29
marker by a generous one dollar for its Iranian
light grade which is very close to marker
quality. Even at this price, volume is close to
but not over Iran's assigned 2.4 mmbd quota.
Iran did take a very tough line in recent
negotiations with Japan. In a complex barter
deal, the Iranians may have compromised on
price but only slightly---a considerably tougher
stance than they have exhibited in the past.
Mexico's prices have firmed relative to the
Saudi marker in the recent round of cuts. The
Isthmus grade is now at marker parity as
compared with a $1.50 discount from the $34
marker.
The heavier grade, Mayan, is now
discounted only $6 as contrasted with a prior
$9~ Even at these levels, the Mexicans' exports.
appear constrained by their decision to adhere
to their 1.5 mmbd quota. Even with the new,
relatively higher prices, they are reportedly
turning away sales. This reflects their recent
gentleman's agreement with OPEC. It is also
quite likely to be funded by some unpublicized
Saudi promise of finarcial assistance on debt
payments. The continuation of such "restraint"
is an important element in maintaining the
fragile order of the market---without it a
significant increase in exports could be
forthcoming.
The U.K. pricing move stopped just short of
inducing a Nigerian counter-response. By
lowering the price of all U.K. crudes except
Brent to $29.7 5 and Brent to $30, rough parity
was maintained but no money was left on the
table. Brent accounts for one third of U.K.
production.
U.S. prices have remained at leveL~ reached
prior to the OPEC cut---in a sense the U.S.
prices anticipated and effectively set OPEC's
prices, although many other factors ircluding
the Nigerian preemptive cut were involved.
West Texas Sour is generally priced at $29 and
Data Resources, Inc.
I
~ l
....
Forecast Summary
Probably two thirds of the "missing" 3 mmbd of
demand, or 2.0 mmbd, is due to record winter
mildness. The remaining 1.0 mrnbd must be
explained by further deterioration of the
industrial economy between summer 1982 and
winter 1983 and by a substantial inventory draw
at the secondary and tertiary inventory levels--which is observed as Hmissing" demand. The
massive secondary /tertiary stock draw appears
reasonable in view
of the widespread
expectations of collapsing oil prices which
prevailed for most of the first quarter. Tne
. incremental conservation effect, over a six
month period, was probably minimal.
delivered to Houston for $29.50. This is roughly
75 cents per barrel below parity with
comparable quality Saudi light---a considerably
softer discount than that which prevailed for
the $34 marker. Louisiana Sweet at $30.35
wellhead
shows a
similar
discount to
comparable foreign crudes.
Domestic spot
crude prices are about 20 to 50 cents above
contract except for Alaskan spot, which shows
over a $1 favorable gap.
U.S. spot and mainstream product prices have
rebounded far more strongly than crude--correcting a sharply oversold position in
February.
Net refinery margins may now
average a still-poor $1 to $2 as compared with
near-zero in February.
Refinery utilization
rates in the low seventies are slightly improved
from the low points, but hardly promise greatly
stronger returns on refining. Product stocks are
generally low, however, and firmer demands
induced by a growing economic recovery would
add slightly to existing margins.
Some indication of importance of the global
weather effects can be obtained simply by
considering U.S. degree d::;ys for winter 19821983 versus winter 1981-1982 (Exhibit 1) and
distillate
consumption
for
the
U.S.
corresponding two periods (Exhibit 2). It should
be noted that weather in Europe, Canada and
Japan
showed
comparable
degree-day
differences between the two winters. Secondly,
distillate is only one petroleum product whose
demand depends on winter weather. Residual
fuel is weather dependent for apartment
buildings
and
other
,large
commercial
establishments, and indirectly dependent as a
utility fuel for electric heat. Kerosene is also a
major heating fuel in Japan and other areas.
Oil Demands and "Winter" Weather
Free world oil demand for first quarter 1983
was probably no more than 4l+.2
mmbd,
virtually no higher than the 43.9 mmbd for third
quarter 1982. More tyoically, the first quarter
exceeds the prior th~rd by 3 to 4 mmbd.
'
'
"'
Exhibit h Average Heating Degree Days
(1982-1983 Versus 1981-1982)
Exhibit 2: Distillate Demand
(Million Barrels per Day)
1200
4.0.------------- - - - - - 3.8
1100
1981-1982
.
900
..
. ..
.
----------.---,.-----·-,..
. .·,
.
....
.
3.6 J.-_ _ _ _ _ _ _ _ _
:
..
1000
:"·. 1981-1982
....._..~,-~----
..
800
3-2
700
2.8
600
500
__________ ·------·
400
300
(1/)
200
-
,
1----+----J-- I
OCT
NOV
1982
DEC
-r---+-1~AN
FEB
MAR
2.0
~PR
ii-t-tt+t++i-t-l·lt·I+HtJ'i-lj+Ht-t-l-l·i ..l+l+f li"·l
SEP
1983
OCT
NDV
1982
Data Resources, Inc •
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'"~"'''""l'~ -;,;.;;;.-=~._,_,_,
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...,~.~--~-·~~~··.._,•-~···---~~·-~•"-~""·~-·»•'
DEC
~AN
fEB
MAR
APR
1983
MY
t
Forecast Summary
Exhibit 2 indicates that U.S. distillate fuel
dema~1d alone averaged 500 mmbd lower for
first quarter 1983 than first quarter 1982.
Given that U.S. distillate demand only accounts
for one third of total OECD demands, plus
allowing for some saving due to ,ncreases in
conservation, it is not unreasonable to assume
that distillate . fuel alone could explain 1.3
mmbd of first quarter free world weatherinduced oil variation from norm. An additional
0.7 mmbd saving due to weather can be
attributed to residual fuel, kerosene, and LPG.
In summary: w\1ile OPEC may have long-term
structural shifts from oil to explain much of the
post-1979 demand decline, first quarter 1983
was due to a much more straightforward
phenomenon---a statistically impossible winter.
U.S. Petroleum Product DemandsA Longer-Term Perspective
,.
While it is generally acknowledged that, among
petroleum products, gasoline demand is
relatively inelastic, and residual fuel demand is
relatively elastic, analysis of the relative
product demand responses to the 197 9-1980
price shock
would · sway
any
marginal
believers. Exhibit 3 compares demand indices
for gasoline, distillate, and residual fuel, with
thE: 1976 demand for each fuel set 1.0. The
first conclusion is that while demands for all
fuels shook off the effects of the 1973 price
Exhibit 3: U.S. Product Demand
Ratio of 1976 Demand
1. 1-y-----=-~=-----.::..~--~~---.-._------------,
' ·.
\
\
..... -----Gasoline
"-
\
·--.
-- .... .
\
\
\
·. •..
l)isti lla te
\
\
\
\
\
\
\
Residual \
\
\
1976
4
1977
1978
1979
1980
191:11
1982
shocks relatively easily and exhibited growth
along with an expanding economy in the 1976 to
1978 period, several more subtle factors were
at work. It took about fiv.::. years to retool for
more efficient cars---therefore there was a
response to the 1973-1974 price iocrease, but it
simply began to occur about the time of the
second shock. Its impacts were superimposed
on the behavioral impacts of the 1979 shc<:k
(lower speed, fewer miles, etc.). A second point
worth noting: while residual fuel demands
increased in 1976 to 1978, there were severe
. natural gas. shortages during this period for
which residual fuel served as a substitute.
Without this phenomena, an earlier decline
would have been expected.
{
.
The post-1978 period begins to show a new set
of patterns. Gasoline demand dec lines, after
the initial behavioral shock of 197 9-1980, have
eased to a very slow pace, now dependent on .a
slow bleed-in of more efficient cars slightly
offsetting greater miles. Distillate declines
have been more persistent, giving some credit
again to now adequate gas supplies and many
conversions to gas. The renewed drop in 1982
relates to a sharp cut in industrial use with a
seriously depressed heavy industrial sector.
In sharp contrast to gasoline and distillate
declines, the post-197 8 drop in residual fuel has
been near free-fall.
The magnitude of this
decline and remarkably similar declines for
other OECD countries has global implications
for OPEC's price of oil.
This theme is
considered briefly below and more fully in the
World Oil chapter of this Review.
r
t
\
Collapsing Residual Fuel DemandsImplications for OPEC Pricing
The demand decline fer U.S. residual fuel,
indicated in Exhibit 3, has nearly identical
counterparts for OECD Europe, Japan, Canada
and others. While total OECD oil consumption
has declined by 5 mmbd from 1976 to 1982,
residual fuel demand has declined from 10 to 6
mmbd.
In other words, the residual .fuel
decllnes account for 4 mmbd out of a total of 5
mmbd, or 8U% of the decline.
Given the near-vertical demand drop for
residual, important questions must be asked: (1)
how much of the residual fuel decline was due
Data Resources, Inc.
,.
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'
Forecast Summary
•
to the recession and how much is permanent?
(2) Can OPEC affor:d to price so as to lose the
entire residual fuel market?
the industrial activity impacts have been
superimposed and both were negative. As the
world economic recovery begins to induce an
industrial recovery, particularly for heavy
industries, the activity growth will become a
positive offset to continuing conservation.
Further, the fact that over 50% of the OPEC II
price increases have been rescinded will dampen
the rate of substitution considen=tbly.
There remains 6 mmbd of OECD residual fuel
demand---clearly OPEC cannot afford to Jose
this entire amount. (For any oil product,. a
barrel of lost demand is OPEC's barrel). To
show even a modest recovery in demand for
OPEC crude, the rate of residual fuel "demand
Joss" must be more than offset by other product
gains. The total world demand for gasoline is
already turning up and distillate demands are
poised to turn up. While much of the recent
Joss in residual fuel demand is structural, or
non-renewable,
a
significant
portion
is
traceable to the peculiar nature of the current
recession.
l
r
I
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f
ENERGY AND THE RECOVERY
I
Good economic news headlines the popular
press. The recovery seems to he well under
way, with positive signs from all sectors of the
economy.
The fluctuations that created
nagging doubts about the turnaround seemed to
have worked their way out of the sys~em.
Not only has the current recession been the
largest and deepest since the depression, it has
been particularly severe for heavy, energy
intensive industries.
This is understandable
given that it was an energy price shock which
was on of the prime factors underlying the
recession. Severe readjustments and permanent
dislocations are to be expected in the energy
area. However, permanent closure of a steel
mill in Gary is not necessarily lost oil and
energy demand---the plant may have only
moved to Korea.
While the total global
requirements
for
steel,
aluminum
and
chemicals, per dollar of world output, may shift
downward, they cannot change too radically.
l
I
Il
The most recent data for some of the primary
fuels and electricity sales is also beginning to
show some sign of recovery. While for many of
the primary "fuels the "positive signs" may be
only small~r negative percent changes when this
year's values are compared with last year's,
there may be better news over the next few
months.
Yet, although any upturn may be
considered "good news", the outlook continues
to be relatively pessimistic for the next few
years.
While the overall ec anomie indica tors are
showing some recovery, the impact on primary
fuel consumption is expected to Jag the upturn
in gross national product. This is projected for
two reasons: (1) inventory decumulation is
continuing, and (2) the recovery jn energy
intensive industrial sectors is expected to be
weak.
OPEC's current prices will cause a continued
Joss of worldwide res~1ual fuel markets---but at
a considerably slower rate. In the past few
years the conservation/substitution impact and
Exhibit 4: Key Macroeconomic Statistics
%CH
YEARS
--------------~-------------------------------------------------------------------------
1981
fl
•'"
1982
1983
1984
1985
1986
1990
1995
2000
2005
1,502.6 1,476.8 1,513.4 1,587.0 1,645.8 1,697.8 1,928.9 2,198.6 2,461.8 2,765.6
Real GNP
3.08
4.86
2.32
2.34
-1.72
2.47
3.71
2.55
1.94
3.16
%CH
2.07
2.17
2.27
4.33
2.38
2.51
3.15
1.96
7.51
Implicit Price Deflator
5.75
4.67
5.27
6.24
5.43
5.95
4.57
5.12
6.48
5.67
9.45
%CH
2.89
2.98
3.12
3.27
2.72
3.45
4.39
6.12
8.33
11.14
Consumer Price Index
3.04
4.63
4.97
6.85
6.19
5.94
5.54
6.73
10.31
6.15
%CH
1.51
1.39
1.42
1.53
1.61
1.68
1.98
3.09
FRB Production Index
2.33
2.66
'3.16
3.04
7.53
5.82
2.62
-8.12
2.31
3.84
3.78
2.96
%CH
0.70
0,74
0,79
0.78
0.70
0.77
0.82
0.82
0.79
FRB Cap3c1ty Index
0.79
0.03
0.83
5.65
4.09
1.48
0.44
-0.20
-0.19
-0.81 -10.99
%CH
10.04
9.13
8.59
8.29
9.71
6.97
6.96
7.62
6.90
6.62
Unemployment Rate
Data Resources, Inc.
%CH
,;cH
82 TO 82 TO 90 TO
2000
83
90
2.5
2.5
4.6
4.6
3.0
3.0
2.3
2.3
0.8
0.8
3".4
3.4
3.4
5.4
5.4
5.4
5.4
4.5
4.5
2.0
2.0
-4.1
2.5
2.5
6.2
6.2
6.6
6.6
3.0
3.0
-0.3
-0.3
0.0
5
.[I
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+
If<-.....
~~
.\
._.,.
...
.
I
Forecast Summary
Exhibit .5: Industrial Production Indices
1981:1
Real GNP
%CHYA
Implicit Price Deflator
%CHYA
FRS Production Index
%CHYA
1981:2
1981:4
1981:3
1982:1
1982:2
1982:4
1982:3
1983:2
1983:1
1983:3
1983:4
I
f
1,507.8 1,502.2 1,510.4 1,490.1 1,470.7 1,478.4 1,481.1 1,477.2 1,488.5 1,502.1 1,522.1 1,540.8
1.61
0.72
2.77
-0.87
1.21
-2.46
3.18
-1.58
-1.94
0.86
3.05
4.30
2.02
2.04
1.90
1.93
1.97
2.13
2.16
2.17
2.06
2.09
2.10
2.20
4.30
4.69
7.19
4.40
4.78
8.85
6.63
5.65
4.54
10.27
9.43
9.28
1.52
-0.57
1.52
5.56
1.53
7.54
1.46
-1.66
1.42
-6.59
1.39
-8.61
1.38
-9.71
1.35
-7.52
1.38
-2.68
1.40
0.74
1.43
3.65
1.46
7.78
Foods
%CHYA
1.52
1.99
1.52
2.11
1.51
1.45
1.52
0.77
1. 51
-0.70
1.50
-0.92
1.50
-0.77
}.52
-0.20
1.55
2.51
1.55
3.38
1. 56
3.98
1.57
3.19
Paper and Products
%CHYA
1.5.7
1.10
1.55
6.12
1.57
5.90
1.51
-2.63
1.50
·-4.19
1.48
-4.98
1.51
-3.49
1.54
1. 79
1.57
4.33
1.57
6.30
1.58
4. 77
1.61
4.72
Chemicals and Products
%CHYA
2.19
1.36
2.20
9.96
2.19
10.01
2.04
-4.43
1.99
-8.96
1.95
-11.14
1.95
-10.79
1. 94
-4.96
1.98
-0.97
2.01
3.08
2.06
5.44
2.10
8.28
Petroleum Products
%CHYA
1.32
-8.10
1.30
-2.26
1.29
1.81
1.28
-0.85
1.21
-7.80
1.22
-5.60
1.23
-5.02
1.21
-5.75
1.17
-3.24
1.21
-1.11
1.21
-1.41
1.22
0.62
Clay, Glass, and Stone
%CHYA
1.56
-3.67
1.51
6.87
1.48
6. 78
1.37
-8.30
1.32
-15.56
1.26
-16.74
1.29
-13.08
1.27
-7.30
1.31
-0.66
1.36
8.29
1.40
9.04
1.43
12.83
Primary Meta 1s
%CHYA
1.15
-0.87
1.10
11.79
1.10
26.96
0.96
-11.04
0.87
-23.9&
0.75
-31.98
0.73
-33.86
0.66
-31.82
0.76
-12.52
0.82
9.44
0.85
16.45
0.89
35.24
Source: U.S. Macroeconomic Forecast, May 1983
Exhibit 6: Industrial Production Indices
1979
Real GNP
%CHYA
Implicit Price Deflator
%CHYA
1981
1982
1984
1985
1,479.4 1,474.0 1,502.0' 1,476.8 1,513.4 1,587.0 1,645.8
3. 71
4.86
2.47
-1.72
2.84
-0.31
1..94
2.38
2.07
2.17
2.27
1.63
1. 79
1.96
5.12
5.95
4.57
4.67
8.68
9.33
9.45
1.47
-3.59
1.51
2.62
1.39
-8.12
1.42
2.31
1.53
7.53
1.61
5.82
Foods
%CHYA
1.47
3.29
1.50
1.48
1.52
1.58
1.51
--0.65
1.56
3.27
1.60
2.50
1.6-l
7..59
Paper and Products
%CHYA
1.51
4.26
1.51
0.01
1.55
2.54
1. 51
-2.75
1. 58
5.02
1.65
4.41
1. 70
3.05
Chemicals and Products
%CHYA
2.12
7.28
2.07
-2.20
2.15
4.02
1.96
-9.03
2.04
3.92
2.22
8.81
2.36
6.tl3
1.44
-0.78
1.33
-7,57
1.30
-2.52
1.22
-6,05
1.20
-1.29
1.24
3.12
1.26
1.41
Clay, Glass, and Stone
%CHYA
1.64
4.44
1.48
-9.90
1.48
0.14
1.28
-13.33
1.38
7.31
1.50
8.76
1.57
4.99
Primary Metals
%CHYA
1.21
0.87
1.02
-15.73
1.08
5.40
0.75
-30.29
0.83
10.41
0.96
15.58
1.04
8.68
Petroleum Products
%CHYA
Source: U.S. Mg.croeconomic Forecast, May 1983
'
6
1983
1.53
4.37
FRS Production Index
%CHYA
,.
1980
Data Resources, Inc.
l
J
l
.
.
.Jii.i·-~-;_c......;.;....,;.
_
;;-'
__]_'
·.··· ... ·~.~
,
'
..
_.;.~.......;.__.,.-i~L~~*,;:$ "!"~ ...,~..c~"
'
-
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.··
.·
...,..,..J/...o-->::.r-'----•~-,...~.---
.
.
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'......:<..... --- -·-·· ..-·__,....,,___.,--.~.. ,. .___-- ---··----·-··-·-----~·-...··--- -·~,.~·-·4 ·-<-<;~~- -~-~_,.,..,.._...._,.,
Forecast Summary
Exhibit 7: Change in Business Inventories
(Billions of 1972 Dollars)
1982:1 1982:2 1982:3 1982:4 1983:1
A11 Business
~1anufacturi ng
Merchant WHolesale Trade
Retail Trade
1983:2 1983:3 1983:4
-15.4
-4.4
3.4
-20.3
-12.4
-6.2
-0.7
2.8
-8.0
-7.2
2.8
1.2
-5.2
1.2
7.2
-14.4
-0.4
-5.2
-6.4
-6.0
0.8
-3.4
-2.8
1.3
0.3
-1.0
2.4
0.2
1.4
-3.2
-4.0
1.1
Source: U.S. Macroeconomic Forecast, May 1983
Key Economic Factors
The estimate of first quarter gross national
product showed real growth qf 3.1 %. Final
sales increased at a moderate rate, but
consumer
attitude
surveys are
showing
increasing gains. These indicators combined
with the most recent da.ta on personal income
growth should result in a sharp rise in consumer
spending over the next few months.
The·
forecast recovery is projected to be slow but
steady over the next few quarters, gaining
momentum in 1984.
Further, inflation is
projected to continue to be moderate over the
near term.
Exhibit 4 reports the key
macroeconomic variables on an annual basis.
macroeconomic outlook projects :ontinued
inventory correction through the second
quarter, although at a slower rate.
These
inventory corrections have played an important
part in delaying the recovery ln industrial
production. While the first quarter numbers
were large, they were insufficient to finish the
E.!!hibit 8: Selected Example of Industries Which Fail
to Regain Their Previous Production Peak by the End
of 1985 (Percent Change from 197 8-1981 Peak)
Percent Change From
1978-19&1 Peak to
1985:4 Level
On a quarterly basis, however, the lag between
the rise in GNP and the industrial production
indices provides a better indication of the
impact on industrial energy consumption. Total
industrial production, reported in Exhibit 4,
shows the projected overall annual increase of
2.3%, followed by significant increases in 1984
and 1985. Exhibits 5 and 6 report the quarterly
and annual production by SIC code. Production
in the automobile and housing sectors, which
have led the recovery so far, are projected to
continue to advance in 1983. Ultimately, this
will support production in supply industries.
However, production in some of the basic
manufacturing indu-stries will not begin to turn
around until the third quarter. This pattern
reflects the slow start of the recovery, tr.e
inventory decumulation process, and the
generally slower trend of this recovery.
Exhibit 7 reports the change in business
inventories for manufacturing and wholesale
trade.
As shown, inventory decumula tion
continued at a rapid rate through the first
quarter of 1983, following. a substantial decline
in the fourth quarter of 1982. The current
SIC 28:
Basic Chemicals
Paints
Agriculture Chemicals
-1.1
-10.0
-9.4
SIC 29:
Petroleum Products
-16.2
SIC 32:
Glass and Glass Products
Concrete and Misc. Clay Products
Cement and Structural Clay Products
-3.4
-5.5
-15.4
SIC 33:
Basic Steel and Mill Products
Iron and Steel Foundries
Nonferrous Metals
-22.1,\
-33.4
-11.4
SIC 35:
Engines and Turbines
Farm Equipment
-14.3
-39.9
SIC 37:
Automobiles
Motor Vehicle Parts
Trucks, Buses, and Trailers
Railroad Equipment
-16.1
-12.7
-22'.0
-55.0
SIC 39:
Miscellaneous Manufacturers
Source: Review of the U.S. Economy, May 1983
Data Resources Macroeconomic Service
'k·
Data Resources, Inc.
-4.1
J
7
II:
_ __ _ _ ,
I
Forecast Summary
demands. As shown in Exhibit 9, in 1981 direct
industrial consumption of primary fuel demands
was 16.6 quadrillion Btu, dropping from 18.1
quads in 1979. In 1982, consumption dropped all
the way to 14.2 quads.
Because of the
projected lag in production relative to the
recovery in the gross national product, and the
continuing drawdown of inventories through the
first half of 1983, there is no significant
increase projected in direct primary fuel
consumption in tr1e industrial sector in 1983.
total required correction. Thus, the need for
additional decumulation in the second quarter.
The current outlook projects that this will
realign the inventory to sales ratios, a.1d that
there will be some marginal stock building in
the third quarter.
Additionally, an important part of the
underlying macroeconomic forecast is the
projections of industrial activity by SIC code
through the near term., While the aggregate
industrial production index is projected to reach
1981 levels by late 1984, by mid-1985 it only
exceeds 1981 by 6.6%. Further, most of the
industries that are major consumers of primary
fuels do not reach 1978-1981 peak levels by the
fourth quarter of 1985. Exhibit 8 reports a
sampling of the industries projected to fail to
regain their peak production by 1985.
•
In 1984 and 1985., as industrial production begins
to experience some significant increases, direct
consumption of primary fuels begins to
increase.
However, direct primary energy
consumption does not keep pace with the
projections of industrial production. The latter
results from several factors. Production has
fallen to such low levels that many basic
industries have permanently closed plants. This
results in increased utilization of newer, more
efficient plants. And, as energy prices have
increased, price induced efficiencies have been
Irr.iustrial Energy Requirements
The above discussion highlights the factors
under lying the forecast of industrial energy
-~
f
l
i
!xhlblt 9: Summary of Industrial Fuel and Power Consumption
%CH
YEARS
1979
1980
1981
1982
1983
1984
1985
19&5
1990
2000
%CH
%CH
82 TO 82 TO 90 TO
83
90
2000
Key Macroeconomic Indicators (Annual Rate of Cnange)
Real GNP
FRB Industrial Production Index
Capacity Utilization (level)
2,84
4.37
0.86
-0.37
-3.59
0.79
1.94
2.62
0.78
-1.72
-8.12
0.70
2.47
2.31
0,70
4.86
7.53
0.74
0.79
3.08
3.78
0.82
2.32
2.96
0,7g
2.5
2.3
0.8
3.4
4.5
2.0
2.5
3.0
-0.3
5.16
5.19
3.01
19.15
7.59
7.81
4.63
25.52
18.19
18.84
10.49
48.85
-6.4
9.0
-0.4
7,g
6.4
9.2
9.2
8.1
g,1
g,2
8.5
6,7
1.4
3,16
3.71
5.82
3.114
0.77
Average Industrial Prices (Dollars per mmBtu}
Average Residual fuel
Hatyral Gas
Coal
neclricity
Coal
Steam
Other
Natural Gas
Boller and Process
Lease and !'lant
Petroleum
Boller and Proress
Other
Other
Total
Electnclty
4.33
4.23
Z.29
14.77
2.97
2.24
1.74
8.35
4.15
2.58
1. 98
10.09
5.17
3.12
2.27
11.80
1,683.5
1,g52.5
1,497.0
1,684.2
1,588.5
1,616.5
1,576,4
1,097.4
1,597.9
1,290.6
1,738.4
1,46B.B
1,879.7
1,577.7
2,010.7
1,600.7
2,464.8
1,645.2
3,429,7
I, 757.5
17.6
5,7
5.2
3.4
0.7
7,020.6
1,528.5
7,343.8
1,047.0
7,268.8
991.2
6,141.5
835.5
s,g83,7
805.7
6,164.4
78B.O
6,265.3
781.7
6,302.1
781.0
6,282.3
719.3
6,411.4
684.8
-2.6
-3.6
0.3
-1.9
0.2
-0.5
3,288.0
2,631.1
2,584.8
2,478.5
32.7
2,629,0
2,42B.1
33.0
2,259.1
2,2g5.7
33.0
2,33B,8
2,359,4
3.:i.4
2,617.8
2,413.8
34.4
2,787,4
2,434.1
35.9
2,B22.0
2,429.3
38.6
3,052.2
2,436.1
66.6
3,?03.7
2,565.9
136.6
3.5
2.8
4.J
3.8
0.7
9.2
0,5
0.5
7.5
18,138.2 16,668.0 16,555.1 14,238.5 i4~4io:5
is:;25:6
16,666.5 18,1B9,6
1.2
2.0
o.9
~.63
3.87
2.30
13.69
4.48
4.41
2.43
16.50
4.79
4.79
2.68
17.93
fuel and Power Consumption (Trillion Btu)
34.1
2,782.8
2,708.5
2,7zg.2
2,525.5
2,574.7
2,692,3
15,761.7 15,9B4.4
2,832.7
2,981.5
3,327.1
4,287.3
1.9
3,5
2.6
Boiler and Process foss1l fuel Oemand (Trillion Btu)
Ste6nt Coal
Gas
on
G~<.
and Ofl
Total
Co a1's Share of Co al/0 ii/Gas
Gas• Share of Oil/Gas
8
1,683.5
1,497.0
1,58B.5
1,576.4
1,597.9
1,73B.4
1,879.7
2,010.7
2,464.8
3,429.7
1.4
5.7
3.4
7,020,6
3,288.0
7,343,8
2,584.8
7,268,8
2,629.0
6,141.5
2,259.1
s,g83.7
2,338,8
6,164.4
2,617,8
6,265.3
2,787.4
5,302.1
2,822.0
6,2B2.3
3,052.Z
6,411.4
3,203.7
-2.6
J.S
0.3
3,8
0.2
0,5
10,308.6
g,92B.6
9,B97.8
B,400.6
B,322.4
8,782.2
9,052.7
9,124.1
g,J34.5
9,615.2
-O,g
1.3
0.3
11,425.6 11,486.3
9,977.0
9,920.4
10,520.6 1Q,g32,4 11,134.9 11,7,9,3 13,044.9
-0.6
2.1
1,0
0.16
0.73
0.16
0.72
0.26
0.67
1.g
-1.7
3.6
-1.0
2.3
-0.1
l1,g92.1
o. }11
0.68
0.13
0,74
0.14
0.73
0,17
0.70
Data Resources, Inc.
0.11
0.69
0.18
0.69
0.21
0.67
r
Forecast Summary
introduced.
Thus, as the economic picture
improves, the energy requirements necessary to
support a given level of output are projected to
decline. The net result is that direct primary
fuel demand in the industrial sector does not
reach 1981 levels until 1990, although the
aggregate industrial production index regains
1981 levels by early 1985.
U.S. ENERGY
MARKETS
PRICES
AND
Roughly a year ago, natural gas sales to the
industrial sector began to fall at double-digit
rate~.
Recession induced declines in energy
requ1rements coupled with unexpectedly soft
residual fuel prices swept the gas industry into
an entirely new environment. As each quarter
passed, sales continued their 20% year over
year declines, which contributed to paradoxical
gas price increases.
CURRENT
Oil
As oil prices stabilize, the refiners' average
acquisition price of crude oil is projected to
decEm: to $29.25/bbl in 1983 from $31.87 in
1982. Crude oil prices are expected to remain
low in the near term, before beginning rapid
escalation in the latter half of the 1980s. Price
increases average just above 6% annually in the
1980s, rising about 9.5% per year in the 1990s.
Key crude and petroleum product prices are
summarized in Exhibit 10.
Natural Gas
The natural gas industry at this point may even
be looking back on 1982 as a good year. While
last yea:- may have been bad, 1983 is likely to
be worse. As we near the halfway mark, the
results of early 1983 do not bode well for the
second half.
These increases were due to contractual
provisions that had become commonplace
following passage of the Natural Gas Policy
Act.
Post NGPA, stickier take-or-pay
provisions were included in most contracts,
while matching market-out provisions were
usually included only for the post January 1985
period.
Further exacerbating the pricing
problems were the very high prices paid for
natural gas deregulated in 1980, as shown in
Exhibit 11.
As gas sales declined in 1982 due to lower
energy requirements and increasing competition
from fuel oil, gas pipelines were forced to shutin supplies. Because of contractual obligations,
gas from contracts signed before enactment of
the NGPA was predominantly shut-in, resulting
in a shift in supplies towards more expensive
gas.
This problem fed upon itself as the
economy stagnated, and industrial price
increases near 25% resulted.
Exhlblt 10~ Summary of Key Crude and Petroleum Prices
(Nominal Dollars)
%CH
YEARS
%CH
%CH
~----------------------------------~------------------~-----~-------------··--
Refiner's Acquisition
Foreign Crude
Domestic Crude
Composite
82 TO 82 TO 90 TO
1980 1981 1982 1983 1984 1985 1986 1990 1995 2000
2005
83
90
2000
Cost
$/bbl 33.89 37.05 33.58 29.84 29.86 31.95 34.65 51.49 82.64
179.39 -] 1.1 5.5
9.4
S/hbl 24.23 34.33 31.21 29.07 28..90 30.69 33.25 50.82 81.94 126.98
9.5
$/bbl 28.07 35.24 31.87 29.25 29.21 31.10 33.72 51.06 82.21 126.43 178.59 -6.9 6.3
126.66 178.94 -8.2 6,1
9.5
Retail Residenti~l Prices
Average Gasoline
$/gal
Home Heating Oil
$/gal
,,
'
Wholesale Prices
Distillate Oil
Residua 1 Oil
Average Sulfur
0.0-0.3% Sulfur
0.31-1.0% Sulfur
Over 1.0% Sulfur
1.22
0.98
1.35
1.21
1.28
1.17
1.20
1.07
1,26
1.12
1.35
1.20
1.46
1.31
2.10
1.88
3.21
2.90
$/gal
0.80
0.99
0.93
0.82
0.85
0.92
1.01
1.51
2.39
$/bbl
$/bbl
$/bbl
$/bbl
26.09
31.13
27.59
22.11
32.50
39.31
33.69
28.57
29.09
36.34
30.71
25,82
27.22
30.80
28.86
24.72
4.72
4.31
3.63
28.15 30.09 32.43 47.72 75.119 114.36
31.95 34.22 36.e5 54,60 85.45 128.15
29.95 32.07 34.58 51.39 80.98 122.29
25.51' a.4o 29.59 44.45 71.01 108.51
Data Resources, Inc.
6.50
5.98
-5.9
-8.4
6.4
6.1
8.4
8.6
5.09 -12.7
6.2
9.2
161.06 -6.4
180.05 -15.3
172.16 -6.0
153.72 -4.3
6.4
5.2
6.6
7.0
9.1
8.9
9.1
9.3
I
'I
~
-,
_ij
,.
c,
i!
·a& .....:.-.....
(}_'
_...,
J
•:-
~..,.....--•.__..."'"'"""l"""'i.......:•,~---~""-;~-~.....~~...:....11~..::-.-. ,~
...
,"'!'4'
I
.,/
::;,.---~--,~-
Forecast Summary
Exhibit 11: Volumes and Prices of
Wellhead Purchases by NGPA Category
(End of QuartE:r Data Reported)
1981:1 1981:2 1981:3 1981:4
1982:1 1982:2 1982:3 1982:4 1983:1
SECTION 102
143
VOLUME
2.88
PRICE
166
2.90
174
3.03
182
3.08
i92
3.24
195
3.27
156
3.41
208
3.42
135
3.47
SECTION 103
55
VOLUME
2.60
PRICE
83
2.67
93
2.72
95
2.76
97
2.87
105
2.95
97
3.00
94
3.01
60
3.05
SECTION 104
389
VOLU~lE ·
1.22
PRICE
509
1.20
499
1.23
483
1.25
466
1.33
470
1.33
380
1.36
401
1.38
228
1.26
SECTION 105
4
VOLUME
2.47
PRICE
4
2.47
3
2.43
3
2.46
3
2.65
3
2.65
4
2.46
4
2.54
2
2.06
SECTlON 106
14
VOLUME
1.02
PRICE
21
0.98
22
1.01
24
1.01
25
1.04
25
1.07
23
1.09
25
1.09
13
0.99
SECTION 107
26
VOLUME
6.15
PRICE
33
5.83
39
7.04
43
7.32
47
7.37
56
7.41
59
7.33
76
7.20
60
6.89
SECTION 108
7
VOLUME
3.24
PRICE
15
3.32
16
3.35
16
3.50
18
3.57
18
3. 77
19
3.81
20
3.80
12
3.98
5
2.26
9
2.26
9
11
2.25
10
2.36
10
2.49
10
2.56
11
2.32
2.71
9
2.69
MISCELLANEOUS
VOLUME
0
0.00
PRICE
0
0.00
0
0.00
0
0.00
0
0.00
1
3.45
2
2.83
15
3.22
14
3.31
TOTAL GAS
VOLUME
PRICE
845
1.92
855
2.07
857
2.16
858
2.32
883
2.40
750
2.55
854
2.68
533
2.79
20
20
20
20
20
18
20
14
SECTION 109
VOLUME
~RICE
643
1.94
NUf.,BER OF C0!1PAN1 ES
14
REPORTlNG
~
SOURCE;NATURAL GAS MONTHLY OOE/ElA
PURCHASED GAS ADJUSTMENT FILINGS
20 MAJOR INTERSTATE PIPELiNE COMPANIES
I
f
I
fc
While gas sales declined in response, the gas
industry anxiously awaited the economic
recovery. If the promised recovery would have
begun last year, possibly some of the problems
may have been alleviated. As it was, sales
continued to dec11ne as more of the expensive
gas contracted for in boom times became
available.
The net result was phenomenal
escalation of the acquisition cost of natural gas.
As we entered
1983, the process of
renegotiation of contracts between producers
and pipelines was well under way. Pipeline
acquisition costs for natural gas were beginning
to show some moderation in their increases
10
even though very few were actually showing
declines, and the wholesale price indices were
beginning to show the effects of some
discounting.
However, the weather was
unusually mild, oil prices took a dive, and (as
discussed above) the demand for energy never
'
recovered.
f
I.
Late in the first quarter, serious discussion of
the natural gas problem began on Capitol Hill.
The
administration
proposed
a
rather
cumbersome bill, and several interesting
alternatives were also introduced. Despite this
increased attention, however, the problems of
the gas industry are escalating rather than
diminishing.
Data Resources, Inc.
I
··~
·Forecast Summary
,I
Gas pricing continues to become more and more
muddled. Facing significant loss of market, an
increasing numbers of pipelines have begun
abrogating contracts.
The abrogation of
contracts has undermined what unity there was
in the natural gas industry---although it will
moderate price increases. Unfortunately, it
will also extend the confusion in the industry.
First, even the moderate price increases of the
first quarter are not supportable in today's
market. The delivered price of natural gas is
all too often higher, by a substantial margin,
than oil. Second, primary fuel sales are not
increasing. Oil sales still remain below last
year, although the gap ls closing, coal has
stagtmted, and natural gas sales by distributors
to industrials are down 18% to 20% from yearearlier levels. Energy sales are not expected to
gain some momentum until mid-third quarter.
Natural gas pipelines and distributors can only
hope that the fourth quarter recovery will
significantly increase demand for primary fuels.
There are several pertinent facts that must be
. kept in mind when looking at the natural gas
situation: (1) the recovery has begun, but it
probably won't affect gas sales until mid-third
quarter, (2) the recovery is not a boom,
industrial oil and gas sales are not projected to
match 1981 levels in this decade, (3) to stay
competitive, the average welihead price for
natural gas probably cannot be greater than
$3imcf, (4) e\iefi at. that level, gas will be at
parity with oil and prices will have to remain
flexible to maintain gas 1s industrial market.
While the policies adopted by many of the
pipelines may not be optimal, the reality of the
situation is that if oil prices are stable (or even
soft), then gas prices must stablize at end-use
parity.
The current outlook reflects that
assumption that gas pnc1ng will remain
competitive, but there will be some loss of sales
in 1983, and continued (but not disastrous) loss
·The
of market share over the forecast.
alternative energy prices are shown in Exhibit
12.
Finally, the complaint heard most often with
regard to natural gas is that the industry is
divided, there is no consensus of opinion.
Unfortunately, this is true, and it undermines
any effort to coordinate a legislative fix for the
natural gas dilemma. The latter problem is
perhaps the most serious.
Without a
coordinated effort of the industry, the
probability of natural gas legislation passing is
quite slim. In fact, without coordination, the
industry is probably better off without a
legislative fix as one likely initiative would
extend rather than lighten controls on gas
wellhead prices. In our outlook we explicitly
assume the NGPA remains in place, although
allowance is made for the very likely prospect
that either legislation may be passed or that
commissioners concur in requiring contract
carriage and allowing brokering of gas supplies.
l
}\
fi.
r
I
I'l
I
E.xhlbit 12: Industrial Energy Prices
(1982 Dollars per mmBtu)
--
20_,-------------- - -
18
_..;--
.-·-
16
_...,.- ELECTRICITY
.
I
12
I
-
10
,
DISTILLATE
2
J 975
1980
1985
1~90
1995
2000
.
'"
Data Resources, Jnc.
-
11
.
I
Forecast Summary
All coal consumption categories are projected
to increase at a healthier rate in 1984 as the
economy heats up. Production will begin to _
experience
some
strong
increases
as
accumulated stocks are finally realigned with
consumption.
.Coal
As the recession deepened last year, coal felt
some softening of its market, though not to the
same extent as oil and gas. In 1982, industrial
sales of coal fell roughly 17% while electric
utility sales feli only 0.5%. The net result was
a loss of less than 4% of 1981 sales.
In
particular, the industrial sales reflect the
precipitous decline in met coal---a drop of
nearly 30%.
II
I
Prices are expected to remain weak in 1983 as
the new contract price actually falls in real
terms, and the average delivered price
increases just slightly faster than inflation.
Real increases begin in 1984 as the slow-butsteady increase in coal consumption by both the
electric utility and industrial sectors takes hold.
The market softening in 1982 led to both a real
and nominal decline ln coal prices. Spot prices
played an important role in holding down both
new contract and average delivered prices.
This year suffers from continued lack of
demand.
Electric utility consumption is
projected to remain soft, reflecting weak
electricity growth and another banner year for
hydro. Industrial sales are also projected to be
faidy weak, with steam coal consumption
increa;:;ing only 1.4% in 1983.
Met coal
consumption, coming back from a much steeper
drop in 1982, increases at a healthier rate.
Electricity
Electricity sales, after declining last year, are
projected to increase 2.1% this year. While
sales for the first quarter were below yearearlier levels, sales moved above year-ago
Exhibit 13: Electric Utilities Demand
for Energy Used in the Generation of Electricity
(Trillion Btu)
,.,.,
~CH
~CH
~CH
YEARS
~-~-~~~---·-·---------~---·------·-------~---------------·--------~---------·-----------------~·------·-----1984
1979
1980
1983
1985
1986
1981
191l2
1990
2000
8~
83
TO 8Z 10 90 10
2000
90
1
j,
Generation .Mb
Coal
ll,26Z. 68
0.47
Nuclear
:C of total
2,714.85
0.11
2,671.87
0.11
Z,974,00
0.12
Hydropower
~ of total
3,107.11
0.13
3,074.29
0.13
Other
:C or total
89.25
o.oo
Oll and Gas
l of total
6,966.05
0.29
on
:C of Oil/Gas
Gas
:C cf 01 I/Gas
,.
Total
Electrtclty Demand
12
l3,18l,05 13,63Z.53 13,976.31 15,462.15 23,442.73
().51
0.51
0.51
0.50
0.61
12,151.10 12,583.00 12,526.00 1Z,124. 71
(1,51
0,50
0.51
0.52
of total
:C
7,094.30
2.7
-0.4
4,2
2.0
1.0
3,084.00
0.13
3, :i53.45
0.14
3,787.77
0.15
4,245.37
0,16
4,910.95
0.18
6,137.19
0.20
6,766.91
0.18
8.7
5.8
9.0
5.7
-t.z
3,033,00
0.12
3,541.00
0.15
3,58057
0.14
3,577.37
O.H
3,508.92
0.13
3,427.18
0.12
3,525.17
0.11
3,576.91
0.09
-1.6
1.1
-0.1
-3.0
0.1
-2.0
114.16
0.00
127.00
0.01
108.00
o.oo
193.72
0,01
Z47.08
0.01
311.88
0.01
343.42
0.01
584,47
627.20
o.oz
79.4
74.5
23.5
19.8
-1.5
6,461.09
0.26
5,966,35
0.24
4,904.69
0,20
4,980.89
0,20
4,806 51
0,<9
4,854.11
0,18
4,952.33
0.18
5,099.97
0.17
3,906.16
0.10
-1.2
-2.5
o.s
-2.6
-4.7
7.8
6.1
3.3
2.8
-1.0
-1.5
1.1
~1.5
-0,8
~.8
3.1
~.~
2.1
2,9
2.3
o.oz
2,654.33 2' 202.43 1,568.69 1,690.59 1,754.50 l, 79l •. 43 1,838.31 2,027.63 1,738.22
0.41
.37
0.34
0.44
0.37
0.37
0.37
0.32
0.40
3,806.77 3,763.92 3,336.00 3,290.30 3,052.01 3,060.67 3,Jl4,0Z 3,012,34 2,167.94
0.59 _,.. ____0,63
0.66
0.68,.
0.56
. ..,_ __ ""' ____
___ .,.....,_0.63
...... , __ ._ .........0.6(1
........0.63
_.... __ -.- . 0.63
..... .................
~- ...
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.......
24,J.s9,95 24,47;,>,51 24,683.35 24,163.69 Z4,83J.J5 25,599.78 25,55?.81 27,610.19 30,808.96 38,31!1.91
3,356,85
0.48
3,609.20
.... ._.. o.sz
.,...,. ... _
1.6
-1.2
-- -.--
7,?54,23
------ -
....
7,348.75
7,217,57
-~
1,s9o.:u
7,370,23
.. - -- -
7,876.68
Data Resources, Inc.
-
-
8,180.29
--
9,098,30 n.m.o1
1.6
~1.4
~2.9
0,7
~3.4
I
Forecast Summary
levels in May.
The forecast, based upon an
expectation of normal weather patterns for the
rest of the year, reflects the positive signs of
economic recovery: early ga· : in personal
income, and turnaround of the l.r·erall industrial
production index.
Most utilities should emerge from this period
only a little bruised, ushering in an era starting
in the late 1980s when there will be little or no
real electricity price increases. This results
from the increased utilization of these l..:>wvariable-cost plants coinciding with the
depreciation of these very expensive plants.
Thus, Exhibit 12 shows the real price bending in
the late 1980s before starting up again in the
late 1990s.
Significant gains are projected for 1984 and
1985 as industrial sales of electricity mirror the
economic recovery.
Total electricity sales
increase near 3% per year for the first few
years of the forecast, as industrial sales recover
19811evels by 1985. However, this sales growth
remains well below what was expected in the
mid-1970s.
THE LONG TERM OUTLOOK
Macroeconomic
The changing generation mix, shown in Exhibit
13, reflects the moderation of demand growth
and the shift in base generation toward coal and
nuclear plants. The electric utility industry is
paying a heavy price for these big, high-cost
nuclear and coal projects, which were begun in
the 1970s, when growth was expected to range
from 4% to 7% per year. Once these units are
in place, however, their l0wer fuel cost will
reduce
the
share
of
high-variable-cost
generation in the U.,S. electricity mix. In the
first three years of the forecast, nuclear
generation is expected to increase to 16% of
total generation.
This increase just about
exactly offsets any growth in demand for oll
and gas from their currently depressed levels,
and their composite share drops from 20% of
the market to 18% by 1985.
•
~'
The long-term macroeconomic forecast closely
tracks the path of potential output.
The
principal forecast concepts are summarized
below:
o
The long term outlook closely parallels the
rate of growth of potential output, defined
as the output which the economy could
produce at a reJati vely high but stable level
of utilization of its capital stock and labor
force. This measure is determined largely
by the size of the labor force. Labor force
increases and labor participation rates are
projected to slow over the forecast
interval.
lt
i
i
I
l
~
The
electricity
outlook
is
moderately
optimistic. Most of the now almost completed
plants are expected to make it, if not when
scheduled then within a year or two. It is
assumed that n ost plants will be immediately
allowed in the rate base upon compietion.
Moderate fuel cost expenditu:es are expected.
With decllning interest rates and most of the
short-term debt turned over, those utilities not
bringing on new nuclear generating units should
experience very mild prlce increases over the
next few years. With ample excess capacity,
the probability of brown-outs is near zero, and
with growing electricity demand induced by the
economic recovery, the capital-related, or fixed
elements of utility costs will be spread over a
broadening demand base. However, for those
utilities in the throes of finishing plants and
bringing them on-line, the next few years should
be unsettling, as the new higher (much higher)
rates hit consumers.
o
Real GNP is projected to increase at rates
above 3% through the Jate 1980s, slowing to
2.5% per year through the 1990s.
o
Inflation, as measured by the implicit price
deflator, 1ncreases steadlly through the
early 1990s, reaching a high of 6.5% in the
mid-1990s, before slowing to a 5.5% long
term.
o
Industrial production, after recovering to
1981 levels by 1985, slows to a long-term
rate roughly 0 .. 5% above the rate of growth
in real GNP.
o
Unemployment declines slowly, dropping
from 9.1% in 1984 to 7.0% by 1990, and
maintains that level through the end of the
forecast.
Total Energy Demand
Over the longer term, significant '>trldes are
projected in improving the energy tc.- real GNP
Data R'=sources, Inc. ·
,.,.,.
~
13
'
I
Forecast Sum mary
ratio, but the rate of change does not approach
the level experienced during the 1970s of 2.0%
per year. With a slow recovery and softer fuel
prices, the forecast reflects the diminished but
not
reversed
.incentives
for
energy
conservation. While 1984 represents a return to
significant annual reductions in energy
intensity, the average annual decrease in the
energy to GNP ratio of 3.4% experienced during
the 1979 to 1982 interval is never matched.
14
r·----f
This was to be expected, since the 1970s
experienced two major oil shocks, which had a
substantial impact on the overall energy price
level, and since easily attainable improvements
in conservation have already been made.
During the forecast period, the slowing
conservation is accompanied by increased use of
coal and nuclear energy, both of which are
expected to gain as a share of total energy
demand.
Data Resources, Inc.
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ENERGY POLICY UPDATE
by Margaret F-1. Rhodes
INTRODUCTION
Political caution is the phrase that best
describes Washington's attitude toward energy
legislation and regulation at the moment.
Proposals having potentially substantial energy
impacts are on the docket -or being discussed,
including natural gas pricing revision, new oil
taxes, and air pollution control revision.
Decisive action is probably not on the
immediate horizon, however, as regulators and
legislators, exhibiting a growing sensitivity to
the potential Voting Day consequences of their
actions, are taking care to measure the politics
of the more controversial issues.
OIL
New Oil Tax?
Talk of a new crude oil tax has been floating
around for more than a year now; the process of
assembling a federal budget inevitably i~
accompanied by threats to increase taxes to all
sectors, including the energy sector~ in order to
narrow a widerJng deficit. Last year the talk
was louder; a proposal to apply a $5 per barrel
import fee on crude oii imports garnered
support from a number of Congressional leaders
before those leaders concluded that the politics
were too controversial. The idea resurfaced
this year in the President's budget package, in
the shape of a standby tax for future, not
present, fiscal years in the event the deficit
reached a specified but not unlikely level.
Congress was not interested in the idea of a
standby tax for future years, but proposals were
floated for $5 or $10 taxes on imported or
imported plus domestic crudes.
"
To date, however, no major proposals have been
formally introduced or acted upon by any of the
influential committees in Congress, and the
important Congressional leaders are staying
relatively neutral on the question. The talk in
Congress is definitely quieter this year than
last. Congress is putting together a budget with
a hefty deficit and a substantial tax increase
component.
The latter, however, could
conceivably be achieved by increases in
non-energy taxes, and energy taxes indeed have
been receiving little public mention in the
latest rounds of budg~t actions.
President
Reagar has vowed to veto any tax increase
proposals, but that's what he said, originally,
last year, too. Any tax increase proposal will
face rough sledding in Congress, but oil taxes
usually face rougher sledding than others. Thuss
while an oil tax increase cannot be entirely
ruled out th1s year 1 given the si zc of the federal
budget deficit, its chances are not highly likely.
Windfall Profits Tax-Update
The Supreme Court is now considering the
constitutionality of the windfall profits tax and
may rule by this summer. The odds are in favor
of the tax ultimately surviving in some form. In
addition to legal challenge, windfall profits tax
revenues are facing a challenge from another
direction: a substantialiy different, i.e., lower,
oil price environment than existed three years
ago when the tax was enacted. Now that this
crude oil tax has passed its third birthday, it is
useful to pause and review some of its issues
and workings.
The revenue issue is of concern in Washington.
The
federal
government
has
become
accustomed to this relatively new but
substantial contributor to the revenue side of
the budget. This is a reason that proposals for
new oil taxes have been made: to supplement
falling levels of revenues from the windfall
profits tax. Revenues are falling for a number
of reasons, and the government itself believes it
may only realize half of originally projected
revenue levels by the time the tax phases out.
The tax is currently scheduled to begin to phase
out when net cumulative revenues reach $227
biJlion, but not before January 1988 or after
January 1991. "Net" means after accounting
for income tax deductions for the windfail
profits tax. To date, net revenues P~\'e been
Thn:>ugh
around 40-5096 of gross revenues.
June 1982, the last date for which definitive
data is available, cumulative gross revenues
Data Resources, Inc.
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.,
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Energy Policy Update
to 20% in share, and exempt volumes rose from
187 thousand barrels per day (mbd) to 412
mbd. Exhibit 1 Illustrates how these factors are
combining to produce lower revenues.
The
table, based on IRS data, compares third
quarter 1981 data, the first complete set of
data, with second quarter 1982 data, the most
recent compiete set of data. The data does not
include oil volumes from returns not itemizing
by category (a small percentage), nor does it
account for subsequent adjustments for under or
over withholding. It is useful, nevertheless, for
presenting a general overview of the trendso
from the tax totailed $45· billion. Revenues
dropped Jast year when oil prices dropped; for
fiscal year 1982, the government estimates that
$19 billion was grossed, as compared with $23
billion in FY81. Moreover, the government
expec-;:s annual revenues to continue to decrease
fn the next few years.
While falling oil prices are the principal reason
for falling revenues, there are other reasons.
Congressional amendments to the windfall
profit~ tax are gradually relaxing the tax bite in
some areas. For instance; the tax rate on
"newly discovered" (pm;t -1978) volumes dropped
in 1982 from 30% to 27 .5%, this year to 25%,
and is phasing down to a 15% rate by 1986.
Also, at the beginning of this year, stripper
production of independents dropped from a 30%
tax rate to exempt status.
As can be seen in the table, oil pdces (the
"removal price 11) dropped about $3 per barrel .in
the nine-month period, while the regulatory
base prices rose, on schedule, by over $1. These
changes, combined with revisions in tax rates
and other factors, led to reductions ln tax per
barrel ranging from $1.30 for the lightest-taxed
categories to $2.50 for the most heavily taxed
categories
(non-Alaskan
tier
one
and
non-independent tier two). ("1~he figure shown
for tax per barrel includes the regulatory state
severance tax adjustment, not shown in the
table for brevity's sake.)
Other factors include rising base prices and a
slight shift in oil volumes toward the less highly
taxed
categories.
For
instance,
the
highest-taxed category, tier one, declined from
70% of total volumes in second quarter 1981 to
67% a year later, in second quarter 1982, while
the most lightly taxed category rose from 16%
rl
Exhibit 1: Windfall Proiits Tax Breakdown: Comparison
of Third Quarter 1981 and Second Quarter 1982
(P~rcent Shdre of Volumes and Dollars per Barrel)
Removal Price
Tax
Base Price
1Q!!.
2082
1Q!!
2Q82
~
2Q82
19!!
2Q82
47
4
4.5
4
33.0~
34.18
30.17
31.15
14.80
15.18
15.71
16.07
12.17
8.95
9.69
7.09
17
Jess
18
than 1
22.79
21.49
18.69
29.02
14.86
14.80
15.93
1.5.34
4.73
2.85
1.58
6.55
Tier Two
60%
30%
8
5
8
5
33.29
33.49
30.06
30.70
17.90
17.76
19.10
19.70
8.78
4•.51
6.28
3.15
Tier Three
New (30%-1981, 27 •.5%-1982)
Incremental Tertiary (.30%)
Heavy (30%)
12
1
5
14
1
5
34.66
34.40
2.5.41
31.33
31.49
22.41
21.04
20.66
16.79
22•.53
22.47
18.20
3.84
3.89
2•.5.5
2.?.7
2•.57
31.19
28.01
16.12
17.40
8.5.5
6.01
Tier One, Ex. Sadlerochit
Taxed at 70%
Taxed at 50%
Tier One, Sadlerochit
70%
50%
l
I
J
Total Taxed
t
~
1.25
Note: These estimates exclude returns not itemizing by category,
;::re before adjustments for under- or overwithholding, and include
adjustment for state severance taxes, not shown in this table •
•
I
Source: IRS
'., ~
16
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c
Volumes(%)
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Energy Policy Update
NATURAL GAS
The stiff natural gas price increases over the
past year, when other energy prices were either
declining (oil) or slowing to a crawl, have
stirred up not only consumers at'id regulators,
but also pipeline companies, who .fear
permanent volume loss. Tl,e pipeline companies
are trying to pull down their gas purchase costs,
but the sticky nature of gas contracts means
that price moderation will be a gradual
process. Responding to a flood of consumer
complaints, the Administration and Congress
are seeing what they can- do to hasten the
process.
would be priced at this cap. (3) Currently
decontrolled high-cost gas would be frozen,
until 1986, at the higher of the market cap or
its price on the day of enactment, while tight.
sands gas would be frozen until 1986 at thE•
regulated ceiling in existence upon enactment.
Contract-Out: As of January 1985, either the
gas pipeline or the producer can cancel a
contract, after giving advance notice. This ls
meant to serve as an additional prod to
renegotiate new, presumably lower-priced
contracts.
The producer is afforded some
protection, in that the pipeline could still be
forced to transport those gas volumes, for a
fee, that are subsequently sold to someone else.
Administration Proposal
The Administration viewpoint, embodied in a
proposal drawn up by Energy Secretary Hodel
• 1d introduced by President Reagan, is that
complete price deregulation will ultimately lead
to lower prices than if present regulations
remained intact. In order to avoid shocking the
system, however--and in deference to the
difficult politics of gas decontrol--the bill
would phase in the price decontrol. In addit1on,
the Administration bill · addresses the principal
contractual issues that are thought to be
contributing to the industry's inflexibility in
responding to changing market conditions, i.e.,
its current inability to lower prices quickly.
Details of the Administration's proposal are as
follows:
Decontrol: (1) New and renegotiated contracts
can be priced at whatever level agreed upon by
both parties, effective immediately upon
enactment of the law. (2) "Old" gas volumes,
currently scheduled to remain prke-contro11ed 7
at low prices, forever, would be decontrolled at
the beginning of 1986 if not renegotiated
earlier. (3) All other gas volumes, not in new or
renegotiated
contracts,
would
also
be
decontrolled at that date, which means a
one-year delay for several "new" and intrastate
categories from their currently scheduled
decontrol date.
Price Ceilings: Prior to decontrol, the national
average price of all new or renegotiated
contracts would serve as an alternative gas
price ceiling. (1) All but Sec. 107 (high-cost)
gas categories would be priced at the lower of
their otherwise applicable ceiling or this
"market cap". (2) Durlng !985, the volumes
whose decon".. rol has been delayed by one year
Take-or-Pay:
An upper limit of 70% of
contract volumes is' set.
Cost Passthrough: Interstate pipelines can only
pass through, to their sale prices, as much of
their gas purchase cost increases as would
increase prices with the rate of inflation.
Increases above the rate of inflation could only
be permitted after a full-dress hearing at
FERC.
Price Escalators: Automatic price escalator
clauses in contracts could not act to increase
prices above the market cap.
Contract Carriage:
The government could
order pipelines to transport, for a fee, gas
volumes in deals negotiated directly between
producers and other purchasers.
House Democrats' Proposal
Numerous other bills have been introduced in
Congress, too many to be detailed.
The
Administration's
proposal
represents
the
greatest degree of decontrol that could
conceivably be approved by the current
Congress. To bracket this discussion, a proposal
by several dozen Democrats in the House of
Representatives will be detailed here. This bill
represents the greatest degree of increase in
control that could conceivably be approved by
Congress. This bill would delay the present
phased, partial decontrol schedule by two years
and lower all price ceilings. In addition, it is
more aggressive than the Administration
propos~!
at reducing or eliminating the
contruc:tual provisions that are thought to be
contri')uting to the gas industry's market
respor.se inflexibility. Details are as follows.
Data Resources, Inc.
17
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Energy Policy Update
fJ..-· toDecontrol:
(1) All volumes currently scheduled
be decontrolled in January 1985 and July
1987, including new categories and all but
low-priced intrastate volumes, would be
decontrol!ed two years later, in January 1987
and July 1989, instead. (2) Old volumes would
remain controlled forever,
as presently
regulated ..
Price Ceilings: (1) All but Sec. 107 gas would
be rolled back to and frozen at January 19&2
levels. (2) Those prices would then escalate
either at 75% of the rate of Inflation (PGNP) or
with the energy component of the consumer
price index, whichever rate is lower. (3) New
volumes of currently-decontrolled high-cost gas
would be priced at 150% of the Sec. 103 price
ceiling. (4) Tight sands gas would be capped at
that ceiling, or lower, at the discretion of
FERC.
(5} FERC could not establish new
high-cost categories. (6) Old and new import
volumes likewise would be capped at 150% of
the Sec. 103 price.
Market-Out: A pipeline can refuse delivery if
(1) the seller refuses, upon 30-day notice, to
renegotiate, or (2) if the pipeline determines
that it will be unable to sell the volumes due to
market conditions. (3) When refusing volumes,
a
pipeline would have to refuse the
highest-priced volumes first.. In addition, after
refusing volumes at a given price, a pipeline
could not then purchase gas elsewhere at a
similar or higher price. As a final protection
for the producer, the pipeline could be forced to
transport, for a fee, the refused gas that the
producer is able to sell to someone else.
Take~or-Pay:
An upper limit of 50% of
contract volumes would be set for take-or-pay
and minimum-bill clauses.
Price Escalators: No indefinite or automatic
es.:::alators, such as most-favored-nation, area
rate, oil-reference price, etc., would be
permitted.
Cost Passthrough:
Pipelines would have to
minimize cost in their gas purchasing; how they
should do this is not spelled out.
Contract Carriage:
Upon request of the
purchaser, FERC would be required to order a
pipeline to serve, for a fee, as a carrier in
producer /user direct deals.
Legislation: Progress and Outlook
While the two bills discussed above are not the
most extreme proposals possible, even they are
not given a very good chance of passage.
Decontrol of old gas, as in the Administration
bill, is unlikely. Extension of current price
controls is remotely possible, but would face
considerable challenge. Some people believe
that if only contract stickiness could be
eliminated, the natural gas market could
perform reasonably within the current price
ceiling system. For this reason, and because
pricing proposals are so highly controversial in
Congress, several members of Congress are
setting their sights on non-price contractual
provisiOns, such as take-or-pay, indefinite
escalators, market-out, etc.
r
I
Contract carriage is currently drawing a lot of
attention.
Easing the way for increased
industrial/producer direct purchases could lower
the industrials' costs, but. distributors are
worried about Joss of load, worsening load
factors, and higher prices for their remaining
(residential and other small) customers. For
this reason, the most popular contract carriage
proposals are fairly emasculated, requiring the
approval of states or the local distribution
companies themselves. Given the conflicting
points of view surrounding even this non-price
issue, passage of a contract carriage bill with
bite should not be given a very high probability.
In summary, the usual battle lines have been
drawn by the usual Congressional combatants on
both sides of the highly-charged price control
issue, probably barring significant revision in
the foreseeable future.
Non-price revision
stands a better chance, but is by no means
certain.
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Regulatory Revision
.I
The Federal Energy Regulatory Commission
(FE.RC) has little authority to revise prices on
'its own, but what authority it has, it is
exercising- The latest proposal would affect
relatively few volunoes, but is impo;:-tant as an
indicator of FERC's current attitude toward gas
pricing in general and incentive prices for
high-cost gas in particular. Specifically, FERC
is proposing a new, lower incentive price for
new volumes of administratively defined
high-cost gas categories (107(c)(5), currently
just tight sands gas). This price would be based
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Energy Policy Update
•
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relaxing clean air requirements, majority
support for an acid rain program significantly
tightening emission control requirements is not
yet evident. The relevant committees in the
House and Senate once again have Clean Air
Act revision legislation in their plans for this
session, but they are not moving very fast on
the proposals. As is the case with natural gas
pricing 1eglslation, the viewpoints on both sides
of the issue are so strong that Congress won't
even try to reconcile them as Iong as they have
more urgent legislation to act upon, such as the
budget.
on an equivalent oil price--FERC favors
average resld--and would float as the oll price
rises and falls. in the proposal, FERC would use
the price of residual fuel paid by electric
utilities,
then
back
out
an
imputed
transportation cost (over a dollar, gas basis),
resulting ln a price ceiling that would currently
be about two dollars less than the current tight
sands price ceiling. This proposal reveals two
facets of FER C's current pricing philosophy: (1)
that incentive prices for high-cost gas are
currently too high; and (2} that F'ERC has taken
the final step in the evolution of its philosophy
from strictly cost-based- pricing, through
several
interim
stages,
to
explicitly
commodity-value pricing, after years of taking
alternative fuel prices into account in some
manner or shape.
Surface Mining
Surface mining regulation is following trends
similar to recent trends in other environmental
policies.
On the one hand, Secretary Watt
finally released his extensive rewrite of the
surface
mining
regulations,
significantly
loosening them.
On the other hand,
environmentalists are already taking these
rules--many of them not yet implemented-to
court. Environmental groups believe the rules
leave too much regulatory discretion to the
states, whose enforcement record has been
mixed. They also believe some of the rules do
not
afford
sufficient
environmental
protection.
One of the most controversial
provisions in the new rules is an esoterically
phrased passage pertaining to mining on publlc
lands that is thought to have the potential of
permitting a significant amount of mining in
parks and other publicly-owned lands that would
otherwise be off-limits under the law. Another
controversial rule is one that limits the ability
of the public to petition to have specific land
areas declared unsuitable for mining. Thus, the
Watt vs. environmentalists battle over strip
mining regulations, a battle that has been
running throughout the current Administration,
is far from over. The outcome is not yet dear,
but the Administration's growing sensitivity to
environmental issues, combined with a recent
intensification of enforcement efforts by the
office of Surface Mining Reclamation and
Enforcement, suggest that the coal mining
industry should expect no more than a
middle-of-the-road regulatory attitude from
Washington.
COAL
Air Pollution Control
As President Reagan's time in office grows, it
becomes increasingly evident that the coal
sector 1s high hopes f~r relaxed coal-burning
regulations will go unfulfilled. The transfer of
leadership at the Environmental Protection
Agency from Gorsuch to Ruckelshaus is just the
latest
confirmation of that
probability.
Gorsuch's attempts to implement Reagan's
0riginal a1r pollution deregulatory policy had
been unsuccessful due to challenges by
environmentalists and others, and to her
Washington inexperience.
Ruckelshaus has
\V ashingtcn experience but is well known as
favoring a middle-of-the-road approach to air
pollution regulation.
The President thus is
signalHng that he is giving in to public (voter)
pressure and backing away from a strong
deregulatory stance.
The most important
impact could be on the one major coal-burning
issue left to be settled, and one in which the
EPA has some discretionary authority: new
source performance standards for industrial
boilers.
This rule revision is · still in the
development stage, where it has been for years.
•
On the legislative front, little movement was
seen during the past three months. The same
add rain program proposals that were
introduced last year are currently pending, and
their chances are probably similar to what they
were .last year. \Vhlle there does not seem to be
sufficient support to pass a bill dramatically
i
Leasing
Also on the supply side, Secretary Watt's coal
leasing policies for federal lands also are
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Energy Policy Update
>\ coming under fire.
A recent report by the
• .../ General Accounting Office lent support to
complaints by members of·Congress a year ago
that the government sold leases too cheaply in
last year's Powder River B3:sin lease sale.
Meanwhile, members of Congress are discussing
the possibility of legislation to slow down the
pace of coal leasing.
Transportation
Coal producers and shippe: s, including electric
utilities, are concerned al:out a new set of rules
proposed
by
the
Interstate
Commerce
-Commission that define guidelines for setting
railroad rates ChargeJ for hauling coal in
captive markets (i.e., many utility markets).
Under the proposed guidelines, railroads which
are defined as "revenue-inadequate 11 (i.e., most
of them) could raise rates 15% per year on top
of the rate of inflation, up to a ceiling defined
by what would be the stand-alone cost of
providing that rail service. Opponents believe
that the guidelines would sharply raise
transportation rates and therefore the cost of
coal. The ICC will not issue final regulations
until later this year after holding hearings and
studying comments from the public.
Once again, as it has every year for the past
several years, legislation has been introduced in
Congress to give coal slurry pipelines the right
of eminent domain.
It is felt that such
legislation is necessary to launch the pipelines
as a significant coal transportation mode, and
coal purchasers are anxious to launch an
alternative transportation mode that can
compete with railroads and thereby help to hold
coal transportation costs down.
Several
committees in the House and Senate have
approved versi•ons of the legislation already, but
other committees also want to act on it.
Despite its apparent ease in progressing through
Congress so far, the existence of formidable
blocs of opponents, both railroad interests and
environmentalists, prevent the legislation from
being an automatic shoo-in.
ELECTRIC UTILITIES
Nuclear Plants and States' Rights
•
The Supreme Court made two decisions this
spring that affect the electric utility sector. In
one decision, the court upheld a California law
that gave the states the right to prohibit
20
construction of new nuclear plants as long as
nuclear waste disposal issues remain unsettled.
The federal government has sole authority over
safety factors regarding nuclear plants, but the
waste issue apparently was determined to
extend beyond just safety issues. The new
federal nuclear waste legislation should
presumably make such state laws irrelevant,
except there are so many uncertainties
surrounding actual implementation of the new
federal waste program that it probably will not
make them totally moot. This court decision,
.confirming ~tates' veto rights on other than
safety issues, seems to apply just to new
construction.
Cogeneration
In another decision, the court upheld the federal
government's cogeneration regulations issued
under the Public Utilities Regulatory Policy
Act.
In those regulations, utilities can be
required to interconnect with cogenerators and
purchase their power at "full avoided cost"
rates as defined by the government.
The
utilities had considered that cost structure too
high.
These regulations were considered
important to the establishment of cogeneration
as an energy source, so affirming the rules will
remove some of the uncertainty that may have
been holding potential cogenerators back.
CWIP
The Federal Energy Regulatory Commission has
stated a new policy on "construction work in
progress": it will allow (upon application to
FERC) 50% of the CWIP in a utility's rate
base. This will help ease the financial strain on
utilities that formerly could not recover a
return on costly new plants until they were in
operation.. The new rule officially affects just
the small portion of all electricity sales in the
nation that are under FERC jurisdiction, but it
is expected to influence decisions by state
public utility commissions.
Just how many
state commissions will be influenced is unclear,
since son 1e already permit CWIP in some form
and others seem to be opposed to it.
Opponents,
including
some members of
Congress, fear that CWIP would raise electric
rates too high. In answer to this issue, FERC is
phasing in the impact of the rule by only
permitting, in each of the initial years, the
CWIP component of a utility's rate increase to
increase rates 6% per year above what they
otherwise would be.
Data Resources, Inc.
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Notes and Technical Appendix
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·rab!e A-1: Data Resources Outlook of the
United States Energy Sector
(STUBLIST: RSUMMAR Y)
';CH
YEARS
----------------~-----~~-----------------------------
1982 1983 1984
?RIMARY ENERGY
Total
:,esioential
Colllllercial
Industria 1
l1anf~ort5{iyo
~ ec
1c 1 1ty
Energy to Ilea 1 :;NP
Electncity
CO~SUMPTION
1Q ~
21:
.)16.7
.8
2~:2 ~ta 2g:g
2U
47.8 47.2 46.0
45.3 44.7
CONSUt~PTJO!I
7.4
BY fUEl TYPE
7.6
7.9
32 TO 32 TO 90 TO
83
90
2000
~1.7
~u
1.3
0.3
2.8
1.6
-1.3
0.7
2.0
0.3
3.1
1.3
-1.2
2.2
1.0
0.4
;!.2
39.0 37.0 1!i.5
-1.4
-1.7
-:.z
1.2
-2.7
2.6
8.7
1.1
NC
78.2
0.9
-0.4
3.2
9.0
-0.1
22.7
0.3
-(1.2
:1.9
1.0
().1
1Cl.5
().8
2.1
2.9
:!.3
30.9
30.8
25.6
52.0
10.4
10.7
33.0
30,3
26.7
74.9
74.8
67.3
-8.2
-6.9
-6.4
-5.g
5.4
-0.2
12.0
9.6
9.0
6.9
6.7
7.9
6.1
6.3
6.4
6.4
8,7
9.2
8.9
9.2
6.6
6.6
8.1
9.7
'3.5
9.5
9.1
8.4
B.6
7.8
9.0
8.9
9.2
5.9
5.9
6.7
0.8
3.9
0.1
4.3
0.1
-2.1
-3.7
-5.2
2.5
NC
-1.9
-1.1
2.2
2.6
NC
-:l.4
-1).8
<!.9
(!.2
2('.6
)N 3R:s
~OUADRILLION
8.2
9.1
1.0
-3.3
-1.3
BTU}
30.1 30.5 31.0 31.3 31.5 32.4 33.5 33.4 34.1
18.4 17.9 17.8 17.9 18.0 17.8 17.4 17.6 17.3
15.4 15.8 115.6 17.3 17.8 l9.S 23.7 28.9 35,1
3.1 3.4 3.3 4.2 4.9 6.1 6.8 6.8 6.8
3.6 3.. E 3.6 3.5 3.5 3.6 3.6 3.6 3.7
0.0 0.0 0.0 0.0 0.0 0.1 0.2 0.3 0.5
0.1 0.2 0•.2 0.3 0.3 0,6 0.6 0.6 0.6
7.2
":~H
3Y SECiOR :ouAORILL!ON BTU)
70.7 71.4 73.0 74.6 75.0 30.4 35,7 91.2 98.1
6.4 6.2 6.2 6.1
6.1
5.8 5.4 5.1 5.0
3.7 3.7 3.7 3.7 3.7 3.9 4.3 4.9 5.6
17.0 17.2 18.1 18.7 19.0 20.0 21.2 22.2 23.5
TOTAL
Petrol Tum
.'latura Gas
Coal
Nuclear
Hydropower
Solar
Exotic
1985 1986 1990 1995 2000 :zoos
:cH
10.3 11.4 12.8
NC
PRICES-CURRENT DOLLARS PER MJLLIOK BlU
Crude Oil (Average)
Crude Oil {Domestic)
Res1dual fuel-Industrial
Gasoline
Coal-Average Delivered
Coal-new Contract
Natural Gas Rgsidential
Natural Gas Conmercial
Natural Gas Industrial
Electricity Residential
Electricity Commercial
Electricity Industrial
e.
5.5 5.0 5.0
5.4 5.0 5.0
4.6 4.3 4.5
10.2 9.6 10.1
1.6 1.7 1.8
1.7 1.7 1.9
4.9 5.5 5.8
4.7 5.1 5.4
3.9 4.2 4.4
18.8 20.1 21.9
18.8 20.0 21.9
13.7 14.8 16.5
5.4
5.3
4.B
lO.B
2.0
2.0
6.1
5.7
4.8
23.4
23.4
17.9
S.!l
5.7
5.2
11.7
2.2
2.4
6.6
6.2
5.2
24.8
24.7
19.1
8.B
8.8
7.6
16.8
3.2
3.5
10.0
9.3
7.8
31.4
31.3
25.5
14.2
14.1
12.0
25.6
5.0
5.1
15.9
14.8
12.7
41.6
41.5
35.4
21.8
21.8
18.2
37.7
7.3
7.5
23.5
21.7
18.8
55.7
55.7
48.8
FUEL CONSUMPTION BY SECTOR (QUADRILLION BTU)
Residentiai
Petroleum
Natural Gas
Coal
Electric\ ty
Solar
Cocrnerc i a1
Petroleum
Natural Gas
Coal
Electricity
Solar
Industrial
?etroleur.:
Natural Gas
Coal
Electricity
Solar
Exotic
Transportation
Petroleum
Gasoline
Natural Gas
Electricity
Electric Util1ty
?etroleum
Natural Gas
Coal
Nuclear
Hydropower
Solar
Exotic
o.l
1.5
4.8
2.5
0.0
1.5
4.7
0.1
2.6
0.0
1,5
4.7
0.1
2.7
0.0
1.0
2.6
0.1
2.1
0.0
1.0
2.5
0.1
2.2
0.0
1.0
2.6
0.1
2.2
0.0
7.3
7.0
2.7
2.5
J.O
0.0
7.5
6,8
2.9
2.6
0.0
7.9
7.0
3.2
2.7
0.0
0.0
1.4
1.4
4.6
0.1
2.8
0.0
1.3
4'.4
0.1
3.1
0.0
1.1
4.2
0.1
3,5
O.ti
0.9
l.Ci
1.0
2.a
0.1
2.6
o.s
3.7
0.2
3.2
0.2
0.8
4.3
0.2
3.6
0,2
2.6
-2.5
-5.7
1.9
NC
-0.1
0.6
1.8
2.6
IIC
-1.0
2.9
2.9
2.0
11.0
!1.8 10.3
7.1 1,1
5,2 5.9
4.3 4.9
li.1 0.1
0.0 0.0
2.6
-2.7
8.0
1,9
NC
NC
2,4
0,0
5.!'3.5
NC
NC
1.0
0.1
Z,4
2.6
12.7
10,9
18.7 1B.8 18.8 18.8 18.8 19.2 19.6 20.0 20.6
12.3 12.;! 12.0 11.9 ll.7 11,4 10.7 10.0 9.1
0.6 0.6 0.6 0.6 0.6 o.s 0.5 0.5 0.5
{LO
0.0 0.0 0,0 0.0 0.0 0.0 o.o o.o
0,3
-0.3
-1.9
0.3
-1.0
-1.6
1.6
0.4
-1.3
-0 •. 3
o.. 8
1.6 1' 7 1.8 1.8 1.8 2.0 1.9 i. 7 1.5
3.3 3.3 3.1 3.1 3.1 3.1 2.9 2.2 1.4
12.5 12.7 13.2 13.6 14.(1 15.4 18.8 23.4 28.9
3.1 3,4 3.8 4,2 4.9 6.1 6.8 6.8 5.8
3,5 3,6 3.6 3.5 3.4
3.5
3.5 3.6 3.7
o.o 0.0 0.0 0,0 0.0 0.0 0,0 0.0 o.o
0.1 0.2 0.2 0.3 0.3 0,5 0.6 0.6 0.6
7.8
-1.4
1.6
8.7
1.1
NC
78.2
o.o
4.6
0.1
2.7
0.0
1:0
2.6
0.1
2.3
0.0
8.2
7.0
3.5
2.8
o.o
0.0
2.6
0.1
2.3
0.0
J:l
0.9
3.2
0.1
2.9
0.1
8.3
7.1
3.6
3,0
0.0
0.0
s.8
7.0
4.1
3.3
0.0
1).0
9.8
6.6
4.7
3.8
0.1
0.0
4.1
0.1
3.9
0.0
0.0
3.3
-1,5
-1.0
-3,4
2.5
4,6
2.7
2.3
0.8
3.0
-4,3
1.6
3.4
5.4
3.0
4.5
2.0
5.4
7.5
5,8
2.5
6.2
2.2
3.0
-0.3
6.6
9.4
6.4
3.4
-4.1
o.o
2,7
4.3
9.0
'1.0
-0.1 • 0.1
NC
2.9
22.5
0.5
OTHER KEY MEASURES-AtltiUAl RATES OF CHANGE
••
Real GNP
-1.7 2.5
G~IP Defla-tor
5.9 4.6
Real D1sposable Jntome
1.1 2.7
FRB Production Index
-8.1 2.3
FRS Capacity Utilization -11.0 0,8
6,2 3.0
Consumer Price Index
WPI - fuel and Pnwer
-0.1 -4.3
2.0 1.6
Wholesale Price Index
4.9
4.7
4.8
7.5
5,6
4.6
2.3
5.3
3.7
5.1
3.8
5.8
4.1
3.2 3.1
2.6 2.3
5.3 6.2 6.5 5.7
3.1
2.3 2.3 2,1
3.8 3,8 3.2 3.0
1.5 0.4 -0 •.2 -0.?
s.o 5.5 6.7 6.8 6.2
6.0 12.7 12.1 9.9 7.6
6,1 6.9 7.3 6.7 5.4
5.9
6.5
4.8
9,7 10.0
9,1
8.6
6.9
Unempioyment Rate
8.3
7.0
6,6
7.0
2.3
5,4
2.2
3.0
o.o
-~.
21
Data Resources, Inc.
..
"'~·-··-·--···~-·-··---~-·--,--·-·· -·--·-··~----·---,·-~·----·"'""~--
___
•.,_.,,.,.._.
.,_,
___,,
''";.,--·~·····---·"""~-------"·-·-·"·---·-·-···
'-·~ ~.
'
Notes and Technical Appendix
I
f
.able A-2: National Energy Prices
......::urrent Dollars)
(STUBLIST: PRICENAT)
!!
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%CH
YEARS
----------------------------------------------------------------~-----------
1982
1983
1984
1985
1986
1990
1995
2000
2005
%CH
%CH
I
82 TO 82 TO 9(), TO
2000
90
83
U.S. PRICES INDICES
{I
3.0
1.6
4.6
5.4
5.8
5.4
6.6
6.4
6.2
126.98
126.43
126.66
179.39 -11.1
178.59 -6.9
178.94 -8.2
5.5
6.3
6.1
9.4
9.5
9.5
114.36
152.48
160.11
471.98
161.06 -6.4
213.89 -12.7
224.58 -11.7
650.42 -5.9
6.4
6.'l
6.3
6.4
9.1
9.2
9.2"
8.4
9.9
12.0
9.6
9.0
10.5
9.2
8.9
9.2
9.9
9.0
8.9
9.2
3.27
3.40
2.38
3.45
3.64
2.51
4.39
4.69
3.15
6.12
6.60
4.33
8.33
8.72
5.75
31.95
30.69
31.10
34,65
33.25
33.72
51..49
5o.at
51.05
82.64
81.94
82.21
29.09 27.22 28.15 30.09 32.43 47.72
39.24 311.24 35.64 38.57 42.3S 63.37
40.70 35.96 37.42 40.50 44.51 66.54
128.10 120.49 126.47 135.20 146.31 210.03
75.49
100,25
105.26
320.79
2.89
2.99
2.07
2.98
3.04
2.17
3.12
3.20
2.27
33.58
31.21
31.87
29.84
29.07
29.25
29.86
28.90
29.21
Consumer Price Index (1}
Wholes3le Price Index (1)
GNP Deflator (2)
11.14
11.15
7.51
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OIL PRICES
Imported Crude Oil {3)
Domestic Crude nil (3)
Crude Oil (Refiner Acquisition) (3)
(3l
Residual Fuel
Distillate Fuel 3)
Jet Fuel - Kerosine (3}
Gasoline (4)
I
NATURAL GAS PRICES
Average
Average
Average
Average
287.03 315.53 331.05 351.33 395.30 638.74 1,079.26 1,643.85 2,367.25
329.50
235.08
159.38
49.38 55.30 57.80 61.13 66.18 99.67
302.71
216.82
147.66
46.88 51.37 53.67 56.83 61.51 92.57
266.74
188.44
126.55
38.75 42.25 44.12 41.90 51:95 78.08
Acquisition (5)
Residential (6)
Commercial (6)
Industrial (6)
BITUMINOUS COAL PRICES
35.77
1.65
New Contract (7)
Average Elec. Util.(9)
Wholesale Index (1)
c
9.76
35.92
1.73
10.35
39.30
1.85
10.99
42.97
1.99
11.79
49.51
2.18
12.90
73.53
3.21
18.76
103.93
5.04
28.97
150.49
7.32
41.49
215.08
10.36
58.55
0.4
5.4
6.0
9.4
8.7
8.5
7.4
8.6
8.3
!
Il
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1
{
t.
~·
r
l
t
ELECTRICITY PRICES
5.77
6.41
6.41
4.67
Weighted U.S. Average (B)
Residential (8)
Com:nercial (8)
Industrial (8)
LEGEND
(1) - Index, 1967=1
~2~ - Index, 1972=1
3 - Dollars/Barrel
~4~ - Cents/Gallon
9 - Dollars/P~BTU
l
{5)
(6)
(7}
(8)
-
6.18
6.85
6.83
5.0~
6.79
7.47
7.48
5.63
7.28
8.00
8.00
6.12
7. 72
8.47
8.44
6.53
9.92
10.71
10.67
8.71
13.33
14.20
14.14
12.06
18.04
19.00
19.01
]6.67
24.45
25.55
25.54
22.96
7.1
6.9
6.7
7.9
7.0
6.6
6.6
8.1
6.2
5.9
5.9
6.7
Cents/MCF
Cents/Therm
Dollars/Ton
Cents/Kilowatt Hour
1'
22
Data Resources, Inc.
('
---
Notes and Technical Appendix
••
Table A-3: National Energy Prices
(1982
Dollars)
' '
(STUBLIST: RPRICENAT)
f,,
.
%CH
YEARS
--------------------------------------·-------------------------------1982
1983
1984
1985
1986
1990
1995
2000
2005
U.S. PRIC(5 INDICES
Consumer Price Index (1)
Wholesale Price Index (1}
GNP Deflator (1)
1.00
1.00
1.00
1.03
1.02
1.05
1.08
1.07
1.09
1.13
1.14
1.15
1.19
1.21
1.21
1.52
1.57
1.52
2.12
2.20
2.09
2.88
2.91
2.78
33.58
31.21
31.87
28.53
27.80
27.97
27.28
26.41
26.68
27 .7?
26.68
27.03
28.61
27.45
27.84
33.85
33.40
33.56
39.58
39.24
39.37
45.71
45.51
45.59
3.85
3.72
3.63
%CH
%CH
82 TO 82 TO 90 TO
83
2000
90
3.0
1.6
4.6
5.8
5.4
6.6
6.4
6.2
49.47 -15.0
49.25 -10.9
49.35 -12.2
0.1
0.9
0.7
3.0
3.1
3.1
5.~
OIL PRICES
Imported Crude Oil (2)
Domestic Crude Oil (2)
Crude Oil (Refiner Acquisition) (2)
~
Residual Fuel (2)
Distillate Fuel (2)
Jet Fuel - Kerosine (2)
Gasoline (3)
I
I
I
0-
29.09 26.03 25.72 26.15 26.78 31.37 36.15 41.16 44.42
39.24 32.75 32.56 33.52 35.00 41.65 48.01 54.89 58.99
40.70 34.38 34.19 35.20 36.75 43.74 50.41 57.63 61.94
128.10 115.22 115.54 117.50 120.80 138.06 153.62 169.89 179.38
-10.5
-16.5
-15.5
-10.1
0.9
0.7
0.9
0.9
2.8
2.8
2.8
2.1
287.03 301.73 302.45 314.04 326.37 419.87 516.84 591.70 652.86
49.38 52.88 52.81 53.13 54.64 65.52 76.32 84.62 90.87
46.88 49.13 49.04 49.39 50.78 60.85 70.71
78.04 83.48
38.75 40.40 40.31 41.63 42.89 51.32 60.60 67.83 73.56
5.1
7.1
4.8
4.3
4.9
3.6
3.3
3.6
3.5
2.6
?.5
NATURAL GAS PRICES
Average
Average
Average
Average
Acquisition (4)
Residential (5)
Commercial (5)
Industrial (5)
BITU~INOUS
2.8
COAL PRICES
New Contract (5f
Average £lee. U il. (6)
Wholesale Index (1)
35.77
1.65
35.90
1.69
1.13
37.35
1.73
1.21
40.88
1.80
1.32
48.33
}.0(1
34.35
1.66
1.06
5.77
6.41
6.41
4.67
5.91
6.55
6.53
4.82
6.20
6.83
6.83
5.14
6.33
6.95
6.95
5.32
6.37
6.99
6.97
5.39
6.52
7.04
7.01
5.72
2.11
1.92
49.77
2.42
2.97
54.17
2.64
4.25
59.32
2.86
6.00
-4.0
0.8
6.0
3.8
3.2
8.5
1.1
2.2
8.3
6.38
6.80
6.49
6.84
6.84
6.00
6.74
7.05
7.04
6.33
2.4
2.2
2.0
3.1
1.5
1.2
1.1
2.6
0.0
-0.3
-0.2
0.5
ELECTRICITY PRICES
Weighted U.S. Average (7)
Residentifl(~)>
Commerc1a
Industrial (7)
tEGEND
{1) - Index, 1982=1
~2j
Dollars/Barrel
3 ~ Cents/Gallon
(4) - Cents/MCF
-
(5)
(6)
(7)
{8)
-
6.77
5.78
Cents/Therm
Dollars/Ton
Cents/Kilowatt Hour
Dollars/MMBTU
Data Resources, lnt:.
J
23
•
l
I
Notes and Technical Appendix
j
I
~
.\ble A-4: National Energy Prices
· , . . 982 Dollars per Million Btu)
(STUBLIST: RPRICECOMP)
J
l
1
I
%CH
iCH
YEARS
-------~----------~-----------~----------------~-------------
%CH
82 TO 82 TO 90 TO
83
90
2000
1982
1983
1984
1985
1986
1990
1995
2000
2005
5.79
5.38
5.49
4.92
4.79
4.82
4.70
4.55
4.60
4.79
4.60
4.66
4.93
4.73
4.80
5.84
5.76
5.79
6.82
6.77
6.79
7.88
7.85
7.86
8.53 -15.0
8.49 -10.9
8.51 -12.2
4.63
6.74
7.18
10.24
4.14
5.62
6.06
9.21
<1.09
5.59
6.03
9.24
4.16
5.76
6.21
9.39
4.26 4.99 5.75 6.55 7.06
6.01
7.15 8.24 9.42 10.13
6.48 7.71 8.89 10.16 10.92
9.66 11.04 12.28 13.58 14.34
2.81
4.94
4.69
3.87
2.96
5.29
4.91
4.04
2.97
5.28
4.90
4.03
3.08
5.31
4.94
4.16
3.20
5.46
5.08
4.29
4.12
6.55
6.09
5.13
5.07
7.63
7.07
6.65
5.80
8.46
7.80
6.78
1.70
1.65
1.62
1.66
1.70
1.69
1.77
1. 73
1.95
1.80
2.33
2.11
2.44
2.42
16.91 17.32 18.17
18.78 19.19 20.01
18. 7B 1g.15 20.03
13.69 14.12 15.08
I8.55
20.37
20.38
15.58
18.67
20.50
20.43
15.81
19.11
20.64
20.55
16.78
18.71
19.94
1g.85
16.93
OIL PRICES
Jmported Crude Oil
Domestic Crude Oii
Crude Oil (Refiner Acquisition)
.
Res i tiuci 1 fue 1
Oistil1ate fuel
Jet Fuel - Kerosine
Gaso 1ine
0.1
0.9
0.7
3.0
3.1
3.1
-10.5
-16.5
-15.5
-10.1
0.9
0.7
0.9
0.9
2.8
2.8
2.8
2.1
6.40
9.09
8.35
7.36
5.1
7.1
4.8
4.3
4.9
3.6
3.3
3.6
3.5
2.6
2.70
2.64
2.95
2.86
-4.6
0.8
4.0
3.2
1.5
2.2
19.03
20.04
20.05
17.58
19.76
20.65
20.64
18.56
2.4
2.2
2.0
3.1
1.5
1.2
1.1
2.6
0.0
-0.3
-0.2
0.5
•
t
!
t
I
NATURAL GAS PRICES
Average
Average
Average
Average
Acquisition
Residential
Commercial
Industrial
2.5-
2.8
BITUMINOUS COAL PRICES
New Contract
Average Elec. Util.
ELECTRICITY PRICES
U.S. Average
Average Residential
Average Commercial
Average Industrial
~eighted
0
i
l
j
I
••
24
Data Resources, Inc.
\!
Notes and Technical Appendix
•
Table A-5: Crude Oil and Products Balance
{Million Barrels per Day)
(STUBLIST: OILBALANCE)
%CH
~CH
YEARS
1982
1983
1984
1985
1986
1990
1995
2000
2005
82 TO
83
1.54
6.54
1.01
0.13
2.67
1. ill
1.67
1.56
6.52
1.02
0.13
2.73
1.75
1.71
1.59
6.42
1.06
0.13
2.79
1.89
1.76
1.61
6.34
1.09
0.14
2.83
1.98
1.8D
1.62
6.26
1.11
0.14
2.87
2.02
1.83
1.67
6.05
1.20
0,14
3.03
2.20
1.98
1.70
5.71
1.32
0.14
3.29
2.43
2.16
1. 73
5.32
1.44
0.14
3.60
2.18
2.31
1.75
4.86
1.57
0.14
4.02
2.14
2.51
1.2
-0.2
1.7
2.2
2.1
3.3
2.3
1.0
-1.0
2.3
1.0
1.6
3.3
2.2
0.3
-1.3
1.8
-0.2
1.7
-0.1
1.5
15.24 15.42 15.64 15.79 15.85 16.27 16.74 16.72 17.00
1.1
0.8
0.3
----------------------------------·~--------------------------
PRODUCTS SUPPLIED
----------------LPG
GASOLINE
JET FUEL
KEROSENE
DISTILLATE FUEL
RESIDUAL FUEl..
OTHER
TOTAL PRODUCTS (DOMESTIC)
%CH
-----
82 TO 90 TO
2000
90
SUPPLY SOURCES
-------------DOMESTIC:
DOMESTIC CRUDE PRODUCTION
NATURAL GAS LIQUIDS
TOTAL DOMESTIC SUPPLY
FOREIGN:
IMPORTED CRUDE
EXPORTED CRUDE
8.54
1.53
8.42
1.30
8.25
1.14
8.01
0.91
7.73
0.74
-0.3
0.2
-0.4
-2.1
-0.5
-3.4
10.21 10.19 10.16 10.11 10.07
9.72
9.39
8.92
8.46
-0.2
-0.6
-0.9
8.65
1.54
8.61
1.54
8.57
1.54
3.29
0.24
3.77
0.23
4.01
0.23
4.16
0.23
4.24
0.23
4.78
0.23
5. 31
0.22
5.61
0.21
6.10
0.20
14.6
-3.3
4.8
-0.5
1.6
-1.0
3.05
·3.54
3.78
3.93
4.01
4.55
5.09
5.40
5.91
16.0
5.1
1.7
IMPORTED PRODUCTS
EXPORTED PRODUCTS
1.53
0.58
1.69
0.59
1.80
0.62
1.87
0.64
1.91
0.66
2.15
0.68
2.39
0.68
2.74
0.68
10.4
1.7
4.3
2.0
1.6
0.0
NET PRODUCT 111PORTS
0.95
1.10
1.18
1.23
1.25
1.47
----1. 71
2.52
0,68
1.84
2.06
15.7
5.5
2.3
TOTAL FOREIGN SUPPLY
4.00
4.64
4.96
5.15
5.26
6.01
6.80
7.24
7.97
16.0
5.2
1.9
14.21 14.83 15.12 15.27 15.32 15.73 16.19 16.16 16.43
4.3
1.3
0.3
0.55 -12.1
0.1
0.00 -58.1 -100.0
0.01 -94.2 -29.3
0.3
NC
0.3
NET CRUDE HlPORTS
0
8.67
1.54
TOTAL LIQUIDS
l
OTHER
REFINING PROCESS GAINS
INVENTORY DRAWDOWtl
STAT. DISCREPANCY
TOTAL SUPPLlES
0.52
0.29
0.23
0.46
0.12
0.01
0.51
0.00
0.01
0.51
o.oo
0.01
0.51
0.00
0.01
0.53
0.00
0,01
0.54
0.00
0.01
0.55
0.00
0.01
15.24 15.42 15.64 15.79 15.85 16.27 16.74 16.72 17.00
1.1
0.8
f
I
I
0.3
I·
Il
l
I
I
!
l
r
I
I
f
•
Data Resources, Inc.
25
Notes and Technical Appendix
.Table A-6: Natural
Ga~ Balance
(STUBLIST: NGBALANCE)
iCH
YEARS
--------------~-------------------------------------------------------------------------
1982
1983
1985
1986
1990
Quantities - BCf per Year
1984
1995
2000
2005
iCH
%CH
82 TO 82 TO 90 TO
83
90
2000
'
i l
{ I
• l
Domestic Production
I~terstate Production
Intrastate Production
Alaskan Production
Canadian Imports
Mexican Imports
liquified Natural Gas
Synthetic Natural Gas
17,623.0 17,428.6 17,045.5 16,909.4 16,894.3 15,559.0 14,645.0 13.612.6 13,390.8 -1.1
10,598.1 10,531.5 10,508.9 10,268.4 10,215.5 9,617.9 9,840.6 9,445.5 9,555.1 -0.6
7,024.9 6,897.1 6,536.6 6, 641.0 6,678.7 5, 941.1 4,804.3 4,167.1 3,835.7 -1.8
0.0
0.0
0.0
0.0
0.0
0.0
0.0 1,200.0 1,200.0
NC
850.0
900.0 1,200.0 1,200.0 1,200.0 1,200.0 -23.1
779.8
600.0
700.0
105.0
55.0
75.0
100.0
100.0
500,0
800.0
800.0
800.0 -47.6
36.8
36.8
136.4
144.8
154.6
524.6
0.0
562.6
562.6
562.6
123.9
105.1
105.3
185.9
288.9
406.4
170.5
406.4
406.4 -15.0
-------- -------- -------- -------- -------- -------- -------- -------- --------
Total Natural Gas Supply 18,668.5 18,225.7 18,062.2 18,174,7 18,234.8 18,072.5 17,614.0 17,781.6 17,559.8
less:
Exports
55.0
53.0
53.0
53.0
53.0
53.0
53.0
53.0
53.0
Unaccounted for losses
677 .B
654.2
648.3
652.4
654.5
648.7
630.2
632.2
638.2
---~----
Net Gas Available
17,935.~
-------- -------- -------- -------- -------- -------- -------- --------
17,518.5 17,360.9 17,469.4 17,527.3 17,370.8 16,928.8 17,090.4 16,876.6
-1.5
-1.2
-2.1
NC
5.5
21.5
39.4
11.2
-0.2
-3.5
NC
0.0
4.8
0.7
3.5
-2.4
-0.4
-0.2
-3.6
-3.5
-O.:i
-0.5
0.0
-0.2
-2.3
-0.4
-0.2
0
..
\
'
Residential
Conmercial
Industria 1
fuel and Power
lease and Plant
Transportation
Electric Utility
Total
Consur.~ption
-2.3
-0.4
-il. 2
4,617.9
2,604.3
7,083.1
6,302.1
781.0
580.8
3,114.0
3,927.8
4,330.9
7,138.7
6,464.2
674.5
509.7
1,425.0
-3.7
-2.5
-2.7
-2.6
-3.6
-1.9
-1.4
-1.1
0.6
0.0
0.3
-1.9
-1.6
-1.0
-0.8
2.9
0.1
0.2
-0.5
-0.3
-3.4
18,420.0 17,930.1 17,821.6 17,920.5 18,000.3 17,818.3 17,367.6 17,551.4 17,332.1
-2.7
-0.4
-0.2
4,670.6
2,532.3
6,789.4
5,983.7
805.7
597.5
3,290.3
4,654.8
2,579.2
6,952.4
6,164.4
788.0
583.3
3,052.0
4,642.3
2,589.9
7,047.0
6,265.3
781.7
580.6
3,060.7
4,426.6
2,783.7
7,001.5
6,282.3
719.3
534.0
3,072.3
-------- -------- -------- -------- -------- --------
!
l
I
l<
.,
:I
l
1'
~
•I
:I
~
il '
~
l
lj
I
1'
.I
18,420.0 17,991.5 17,829.6 17,941.0 18,000.5 17,839.8 17,385.9 17,551.9 17,332.3
4,849.1
2,648.9
6,977.0
6,141.5
835.5
609.0
3,336.0
l
~ il
Natural Gas Consumption by Sector
(Trillion Btu)
Net Gas Available
'1
-1.3
4,217..5
3,177.4
6,578.6
5,901.5
677 .o
495.3
__2,898.9
.,.. _____
4,064.9
3,703.4
7,096.2
6,411.4
684.8
519.0
2,167.9
-------- --------
,I
il
d
!i
~i
:I"
'll
l
•l
Jl
1j
~;
II
"d
jf,
·~
rr
I
L
j
!
i
j
l
'
(
I!
l
i
I
•
26
Data Resources, Inc.
-
I'
Notes and Technical Appendix
•
Table A-7: Electric Energy Summary
(Physical Data)
(STUBLIST: ELCSUMPHYSICAL)
YEARS
----------------------------------------------------------------------------------·-----1986
1982
1983
1984
1985
1990
1995
2000
2005
%CH
%CH
%CH
83
90
90 TO
2000
----- ----- ----82 TO 82 TO
ELECTRICITY DEMAND (BILLION KWH)
Residential
Corrrnercial
Industrial
Transportation
Interdepartmental
Total
742.6
622.2
740.2
4.1
6.1
761.5
633.9
754.6
4.1
5.0
779.3
645.9
789.1
4.2
6.1
. 824.3
688.4
873.8
4,4
6.6
802.4
665.2
830.2
4.3
6.• 4
914.6
764.6
975.1
4.7
7.6
1,030.9
847.9
1,113.4
4.9
8.5
1,133.3
934.7
1,256.5
5.1
9.2
1,251.2
1,047.3
1,443.d
5.3
10.0
2.5
1.9
1.9
0.(1
-2.
2.6
2.6
3.5
1.6
2.6
2.2
2.0
2.6
0.8
2.0
3,338.8
3,757.6
2.1
2.9
2.3
4.7
0.4
94.3
76.1
18.2
120.2
359.4
167.7
4.7
0.4
94.3
76.1
18.2
120.2
431.4
127.6
4.7
0.4
94.3
76.1
i8.2
120.2
531.2
109.6
22.3
0.0
2.2
1.7
4.6
5.4
3.2
-0.7
16.8
53.3
1.8
1.3
4.1
8.6
2.7
-0.7
0.5
2.9
0.1
0.1
0.3
0.6
3.4
-4.1
-------- -----e-• -------- -------- -------- -------- -------- -------- -------- ---- ---- ---2,115.3 2,160.1 2,224.6 2,308.5 2,397.5 2,666.6 3,005.5
NET DEPENDABLE GENERATING CAPACITY (GIGAWATTS)
Exotic
Solar
Total Hydro •
Conventional
Pumped Storage
Nuclear
Coal
Oil and Gas
Total
1.3
0.0
80.9
68,0
12.8
58.6
247.9
205.0
1.6
0.0
82.6
69.2
13.4
61.8
256.0
203.6
2.0
0.0
83.6
70.2
13.5
79.9
265.6
203.0
2.5
0.0
87.2
72.2
14.9
87.2
272.8
200.8
2.8.
o.o
88.7
73.2
15.5
94.8
278..5
198.6
4.4
0.3
92.9
75.3
17.7
113.0
307.5
193.4
------------------------------------------------------------------------593.7
605.5
634.2
650.4
653.3
711.7
746.7
778.6
860.4
2.0
0.9
2.3
GENERATION (BILLION KWH)
0
Solar and Exotic
Net Hydroelectric
Nuclear
Coal
Natural Gas
Oil
Total
Generation/Demand
5.5
309.5
282.8
1,192.5
305.3
146.4
9.0
312,9
307.4
1,212.4
299.3
159.6
11.4
312.7
347.2
1,254.8
278.1
168.7
14.4
306.7
389.2
1,297.8
278.6
171.5
15.9
299.5
450.2
1,330.8
282.9
175.2
27.1
308.1
562.6
1,471.0
277.5
199.7
29.0
309.2
620.4
1,789.9
261.1
190.4
29.0
312.6
620.4
2,232.8
194.7
170.3
29.0
321.4
620.4
2,758.4
127.8
146.1
62.1
1.1
8.7
1.7
-2.0
9.0
21.9
-0.1
9.0
2.7
-1.2
4.0
0.7
0.1
1.0
4.3
-3.5
-1.6
1.06
1.07
1.07
1.06
1.07
1.07
1.06
1.07
1.07
0.5
0.1
o. ().
0.0
0.4
--------------- -------- -------- -------- -------- -------- -------- -------- ---------2,242.0 2,300.7 2,372.9 2,458.2 2,554.5 2,846.0 3,200.0 3,559.8 4,003.1
2.6
3.0
2.3
CAPACITY UTILIZATION (PERCENT)
Solar and Exotic
Hydroelectric
Nuclear
Coal
Oil and Gas
Average
Reserve Margin
Load factor
.
o.c
49.0
43.7
55.1
54.9
25.2
65.0
43.2
56.8
54.1
25.7
65.0
42.7
49.6
53.9
25.1
65.0
40.2
51.0
54.3
25.6
65.0
38.6
54.2
54.5
26.3
65.0
37.8
56.8
54.6
28.2
65.0
37.4
58.9
56.8
30.7
65.0
37.8
58.9
59.1
32.7
65.0
38.9
58.9
59.3
28.5
...
53.1
32,8
-1.0
3.2
-1.5
2.3
3.6
-1.8
0,4
-0.1
1.4
0.41
0 .• 61
0.41
0.61
0.44
0.61
0.43
0.62
0.41
0.62
0.38
0.63
0.31
0.64
0.26
0.66
0.24
0.66
-0.9
0.3
-1.2
0.4
-3.6
0.5
108.0
192.5
245.9
577.4
309.4
341.0
547.0
577.4
577.4
0.0
1.2
1.2
2.5
2.5
37.5
49.8
49.8
49.8
3,541.0 3,580.6 3,577.4 3,508.9 3,427.2 3,525.2 3,538.2 3,576.9 3,677.7
3,084.0 3,353.5 3,787.8 4,245.4 4,911.0 6,137.2 6,766.9 6,766.9 6,766.9
12,526.0 12,724.7 13,181.0 13,632.5 13,976.3 15,462.1 18,799.9 23,442.7 28,946.0
3,336.0 3,290.3 3,052.0 3,060.7 3,114,0 3,072.3 2,898.9 2,167.9 1,425.0
1,568.7 1,690.6 1,754.5 1,793.4 1,838.3 2,027.6 1,948.6 1,738.2 1,459.8
78.2
NC
1.1
8.7
1.6
22.5
NC
-0.1
9.0
2.7
-1.0
3.3
0.5
2.9
0.1
1.0
4.2
-3.4
-1.5
...
2.2
o.s
1.5
--------------- -------- -------- ---- --- ---- ---- -------------------------------43.1
43.4
48.9
42.7
43.1
44.0
45.7
52.2
0.6
0.7
1.3
FUEL DE"lAtlDS (TRILLION BTU)
Exotic
Solar
Hydroelectric
Nuclea •
Coal
Natural Gas
Oil
Total
-------24,163.7
----~---
24,833.4
----~---
25,599.8
-------- -------- -------- -----·-26,552.8 27,610.2 30,809.0 34,579.7
-----~---
38,319.9
nl,4
7.8
---------------2,8
3.1
42,902.6
•
Data Resources, Inc.
4
$
27
()
Notes and Technical Appendix
•
28
r-~------
Data Resources, Inc.
- - - - - - - - - - - - - - - - --l
I
Notes and Technical Appendix
e
'
Table A-9: Energy Demand by Sector - 1990
(Trillion Btu)
(STUBLIST: DISPLAY)
Household &
Industrial
Corrrnercial
Electric
Transportation Utilities
Total
FUEL AND POWER
[
Anthracite Coal
Bituminous Coal
Natural Gas
Petroleum
Gasoline
Jet Fuel
Distillate Fue1
Residual fuel
Liquefied Gases
Kerosine
Still Gas
Petroleum Coke
Aviation Gasoline
Nuclear Power
Hydropower
Solar
Exotic
Total. (Fuel & Power)
0
47.5
159.1
35.5
4,074.6
7,210.4
2,324.1
98.8
7,001.5
5,488.4
149.8
1,326.1
386,6
363.2
149.4
1,185.1
1,402.4
882.6
138.6
1,227.2
502.5
107.1
24.1
15,438.0 19,671.7
534.0
19,053.4
11,355.8 •
2,460.7
3,853.7
1,318.1
10.3
54.8
34.4
24.2
7.9
65,8
------9,806.8
-------
-------16,666.5
l
__, ______
!
j
l
3,072.3 17,818.3
2,027.6 28,893.5
11,604.4
10.0 2,470.7
81.4 6,446.3
1,930.9 5,038.0
1,256.1
288.0
1,227.2
507.9
5.4
54.8
6,137.2 6,137.2
3,525.2 3,559.6
127.5
37.5
554.9
547.0
1
l
I
I
~~~
-------- --------------- --------
19,587.4
--------
------.--
30,809.0 76,869.7
3,334.7
'J63.1
241.1
81.5
147.3
2,272.6
-371.0
157.6
3,492.3
963.1
398.7
81.5
147.3
2,272.6
--------
--------
3,334.7
157.6
RAw MATERIALS
Petro1eum
Asphalt & Road Oil
Lubes &Waxes
Petroleum Coke
Special Naphthas
Petrochemicals
Other Products
------Total (Raw Materials)
157.6
-------
- ... ------
---- -·--
Total Demand for Fuelr.
9,806.8
20,001.2
____
19,745.0
Demand for Electricity
5,729.4
3,327.1
16.0
-------
_.,_..,.
.....
--~-----
Data Resources, Inc.
-----·... --
-371~0
____
""' ___
3,492.3
__ .., ____ ,..
--------------- --------
30,809.0 80,362.0
25.8
9,098.3
29
I