Chapter 10
AN ECONOMIC ANALYSIS OF NATURAL GAS
PRICE MOVEMENTS DURING THE CRISIS
Natural gas prices have a particular effect on electricity prices in California.
This chapter extensively analyzes both the relationship between electricity
and natural gas, and the prevailing market conditions in the natural gas
industry during the energy crisis in California. We present statistical
analyses that include daily natural gas price models for both Northern and
Southern California markets for the period January 1, 1999 through July 31,
2002. These analyses test various hypotheses to determine both what caused
movements in California’s spot natural gas prices and the relationship
between California prices and national prices.
It is undisputed that natural gas prices spiked during the electricity crisis
in California. The facts behind this price spike are widely known and
virtually undisputed. In October 2001, state analysts at the California
Energy Commission (CEC) issued a report entitled Natural Gas
Infrastructure Issues (CEC Report) that examines in detail the factors that
caused the price spike in natural gas prices experienced in California in late
2000 and early 2001. Our structural analysis supports virtually all the
CEC’s conclusions. We begin by summarizing basic facts.
The natural gas market in California experienced its own “perfect storm”
that reflects some of the same market-force factors that led to the electricity
crisis in California. First, it is important to understand the market
infrastructure. Five interstate pipelines deliver natural gas to California’s
border. These pipelines have a total delivery capacity of about 7 billion
cubic feet (Bcf) per day, and in-state production adds about 1 Bcf per day.1
The California intrastate delivery market has a Northern California market
that is served by the PG&E intrastate pipeline delivery system, and the
1
CEC Report, p. 44.
86
The California Electricity Crisis: What, Why, and What’s Next
Southern California market is served primarily by the SoCalGas intrastate
pipeline delivery system. The combined California intrastate pipeline
system has a total capacity of 6.7 Bcf per day connected to interstate
pipelines.2 About 15 percent of California’s natural gas is supplied from instate sources.3 The rest is sourced from Canada (28%), the Rockies (10%),
and the Southwest (46%).4 In the year 2000, total demand in California was
6.584 Bcf per day, or 98 percent of California’s daily intrastate delivery
capacity.5 While this shows a very tight statewide reserve margin, the actual
reserve margin was even worse in Southern California, which was faced
with severe supply shortages caused, in part, by demand exceeding capacity,
and exacerbated by an inadequate infrastructure that limits receipts and
constrains access to storage.
While market conditions were tight for natural gas delivery, these
markets remained reasonably workably competitive. Table 10-1 shows that
interstate deliveries, plus in-state production, had a Hirschman-Herfindahl
Index (HHI) of about 1897.
Table 10-1. Interstate Deliveries to California
Pipeline
Capacity
Percentage
HHI
PG&E Transmission Northwest (GTN)
1,930 mmcf/d
24.00%
576
El Paso (Topock)
2,080 mmcf/d
25.87%
669.2569
El Paso (Ehrenberg)
1,240 mmcf/d
15.42%
237.7764
Transwestern
1,090 mmcf/d
13.56%
183.8736
700 mmcf/d
8.71%
75.8641
In-State Production
1,000 mmcf/d
12.44%
154.7536
TOTAL
8,040 mmcf/d
100.00%
1,897.52
Kern River (Mojave)
Table 10-2 shows that intrastate deliveries had an HHI of about 1503.
HHIs of between 1000 and 1800 are generally deemed to be workably
competitive.
2
CEC Report, p. 49.
3
Ibid, p. 38.
4
California Energy Commission website report entitled “California Natural Gas Facts and
Figures” at www.energy.ca.gov/naturalgas/natural_gas_facts.html.
5
California Energy Commission website report entitled “2000 California Natural Gas
Consumption” at www.energy.ca.gov/naturalgas/consumption.html.
An Economic Analysis of Natural Gas Price Movements During the
Crisis
Table 10-2. California Interstate Pipeline System
Pipeline
Capacity
PG&E*
Redwoods
Baja Path
So Cal
Needles
Hector Road
Topock
Ehrenberg
Mojave**
Kern River
In-State Production
TOTAL
Percentage
HHI
1,905 mmcf/d
1,140 mmcf/d
24.76%
14.81%
613.0576
219.3361
750 mmcf/d
50 mmcf/d
540 mmcf/d
1,210mmcf/d
400 mmcf/d
700 mmcf/d
1,000 mmcf/d
9.75%
0.65%
7.02%
15.72%
5.20%
9.10%
13.00%
95.0625
0.4225
49.2804
247.1184
27.04
82.81
169
7,695 mmcf/d
100.00%
1,503.13
87
* Also includes Kern Mojave (300), Needles (400), and Topock (1,140).
**Also includes Needles (300) and Topock (400)
Winter receipts at Malin drop to 1,500-1,760 mmcf/d due to increased demand in the PNW region.
There is also about 1,000 mmcf/d in California production.
As with the crisis in California’s electricity market, weather was a key
market force affecting natural gas prices. Drought conditions in the Pacific
Northwest reduced the hydroelectric supply to historically low levels.6
California found itself with very little excess capacity during peak demand
periods.7 Recall that in California, natural gas-fired electric generators are
the marginal power plants. With the decreased hydroelectric supply, these
natural gas fired units had to be run more often to pick up the slack.8 This
fact, coupled with the fact that many of these units were older and less
efficient, contributed to a large increase in natural gas consumption. For
example, between May and September of 2000, natural gas consumption by
electric utilities in California consumed 22.4 percent more natural gas than
6
Hydropower from the Pacific Northwest declined from an hourly average of 20,805 MW in
1999 to 18,075 MW in 2000. California hydropower also declined from an hourly average
of 4,395 MW in 1999 to 2,616 MW in 2000. See Cato Institute Report California’s
Electricity Crisis: What’s Going on, Who’s to Blame, and What to Do, Jerry Taylor and
Peter VanDoren (July 3, 2001) (Cato Report) citing Edward Krapels, “Was Gas to Blame?
Exploring the Cause of California’s High Prices,” Public Utilities Fortnightly, January 1,
2000, p. 4. See also CEC Report, p. 74.
7
Cato Report, p. 7.
CEC Report, p. 74.
8
88
The California Electricity Crisis: What, Why, and What’s Next
during the corresponding months in 1999.9 In the West as a whole, electric
generator demand for natural gas increased by 62 percent during this
period.10 In California, electric generators’ natural gas consumption
increased from 23% of total state consumption in 1999 to 35.3% in 2000, a
53.4% increase.11 This demand was even more pronounced in Southern
California, where natural gas demand surged two to three times normal for
the winter months.12 Recall that the Southern California natural gas
intrastate pipeline and storage infrastructure was strained under normal
situations. This increased demand further stretched the system. This
tightening natural gas supply situation was exacerbated by an unseasonably
hot summer in 2000. This hot weather increased natural gas consumption:
between June 1999 and June 2000 by 7.3 percent in the Western Systems
Coordinating Council states (excluding California) and by 13.7 percent for
California. The CAISO’s average daily peak loads grew by 11 percent in
May 2000 and 13 percent in June 2000 over corresponding periods for
1999.13 This unusually hot summer was followed by an extremely dry and
cold winter throughout the West. This further taxed hydro conditions while
customers increased their natural gas consumption to heat their homes.14
To make matters worse, there was an explosion in August 2000 on the El
Paso Pipeline, which is one of the major pipelines delivering natural gas into
Southern California. The pipeline rupture was not immediately rectified,
and the El Paso Pipeline’s capacity into Southern California was still down
20 percent as late as October 2000.15 This had a dramatic effect on SoCal
Gas’ storage and deliveries. Consequently, SoCal Gas entered the winter of
2000 with dangerously low storage levels.16 Although not nearly as serious
as in Southern California, Northern California also experienced “slack”
conditions in 2000-2001. In Northern California, capacity and supply barely
9
Cato Report, p. 8.
10
Ibid. See also S.A. Van Vactor and F.H. Pickle, “Money, Power, and Trade: What You
Never Knew About the Western Energy Crisis,” Public Utilities Fortnightly, May 1, 2001,
p. 36.
11
See California Energy Commission reports “California Natural Gas Facts and Figures,”
www.energy.ca.gov/naturalgas/natural_gas_facts.html; “2000 California Natural Gas
Consumption,” www.energy.ca.gov/naturalgas/consumption.html.
12
Between November 2000 and March 2001, SoCalGas’ winter electric generation natural
gas demand ranged between .4 Bcf/d (November 2000) and 1.4 Bcf/d (January 2001)
higher than the five year average. CEC Report Figure 5.4, p. 56.
13
Cato Report, pp. 7-8. See also Van Vactor and Pickle, p. 36.
14
CEC Report, p. 7.
15
Ibid., p. 69.
16
Ibid., p. 52.
An Economic Analysis of Natural Gas Price Movements During the
Crisis
89
exceeded demand.17 In contrast, the Southern California natural gas
infrastructure was simply swamped by market forces.18
To meet this demand, SoCalGas was forced to withdraw from its
dwindling supply sources more than 1 Bcf/d to meet demand in January and
February 2001.19
The notion of “slack capacity” is important when examining changes in
natural gas prices. When there is excess capacity, competition will keep
prices in line with the major North American trading centers, such as Henry
Hub. When there is no excess capacity and regional demand outstrips
capacity, prices will increase sharply in California and depart from Henry
Hub. This concept can be readily observed. Since Northern and Southern
California are served from different supply sources, price differentials can
develop between Northern and Southern California due to differences in
available pipeline capacity.
In December 2000, both regional markets were tight due to the weather
and a surge in worldwide oil prices. These two factors were continental in
scope. Natural gas prices increased in Northern California to $14.58 per
MMBtu.20 Southern California prices rose a bit higher, to $15.14 per
MMBtu.21 During succeeding months, the regional price differential grew to
as much as $5 per MMBtu22 due to a lack of pipeline supply in Southern
California. The El Paso Pipeline explosion and a shortfall in natural gas
storage contributed to this price gap.
In 2002, however, demand, due to weakening economic conditions,
dropped to levels substantially below demand in 2001. Consequently,
natural gas supply and pipeline capacity again exceeded demand in both
markets and price differentials all but disappeared.23 Supply and demand
affects natural gas prices as they do all commodities. When transportation is
unconstrained or supply exceeds demand, North American natural gas
markets become highly interdependent and, in effect, move in lock step.
Therefore, prices are highly correlated, and differences in price levels reflect
transportation costs from Henry Hub back to producing areas and outward
from producing areas that sell to more distant or more localized markets
(e.g., intra-Alberta or in California).
17
CEC Report, pp. 55-56.
According to the CEC Report, SoCal Gas operated at 101 percent of capacity in December
2000 and at 103 percent from January to March 2001 (pp. 55-56).
19
CEC Report, Figure 5.3 (p. 55).
18
20
Ibid, p. 71.
21
Ibid.
22
Ibid.
23
Ibid.
90
The California Electricity Crisis: What, Why, and What’s Next
Just as the FERC recognized for electricity markets, there can be
localized (fairly large, in fact) constrained markets for natural gas. Behind
the constraints, market swings in prices are likely to be more volatile
because these constrained natural gas markets respond to both worldwide
petroleum conditions and localized swings in demand and supply. Some
facts seem very important. These include the West Coast’s unique conditions
during this period, including severe climate in late 2000 that combined
drought and a cold late fall/early winter, insufficient summer storage fills,
constrained pipeline capacity within the state (usage in excess of 100 percent
utilization), and a phenomenal surge in electric system demand for natural
gas. Nationwide, natural gas prices jumped dramatically from about $2.00
per MMBTU in 1999 to more than $10.00 per MMBTU at Henry Hub in
2000.24 These California-specific factors seem to have combined to
compound or amplify the surge in prices. Southern California spot prices
surged more than Northern California prices.
In the ongoing Refund Case, the FERC recognized these facts by
requiring a separate natural gas price for Northern and Southern California
generation units, recognizing explicitly that there were two separate,
independently operating natural gas markets in California. While both
markets were severely affected by market forces that drove up natural gas
prices in the state, Southern California was more severely affected due to the
August 2000 pipeline explosion. The key point is that these two markets
were both severely affected by a combination of market forces and
infrastructure problems that were not faced by other markets in the country.
There is no reason to think that natural gas prices would not spike in an area
where demand severely outstrips supply. Nor is there any reason to think
that prices in an area affected by unique market forces, which cause prices to
spike, would be highly correlated to prices in an area not affected by those
market forces. In fact, there is good reason to suspect just the opposite, that
the prices in the two separate and diverse markets would not be highly
correlated.
DAILY PRICE MOVEMENTS
We now turn to an econometric analysis of daily natural gas price
movements in Southern California and Northern California during the period
from January 4, 1999 to July 31, 2002. Our analysis combines data from the
Southern California market, where there have been allegations of supply
manipulation (during late 2000 and early 2001), and the Northern California
market where there were no such allegations. Importantly, our statistical
24
CEC Report, Figure 7.1, p. 71.
An Economic Analysis of Natural Gas Price Movements During the
Crisis
91
analysis considers daily gas prices for time periods both before and after the
alleged Southern California supply manipulation for each market in
isolation. Our specification and selection of explanatory factors is similar to
other studies published in the literature. For instance, Bopp (2000)25
analyzes daily price movements in natural gas. A related study is Walls
(1994).26
The statistical models test for the statistical significance of: (1) daily
Henry Hub index prices; (2) daily Gulf Coast fuel oil prices; (3) monthly
natural gas consumption in California compared to normalized consumption;
and (4) monthly California natural gas storage. The dependent variable for
both Northern California and Southern California is the natural logarithm of
the end-use market price for natural gas. We also used a dummy variable for
winter because natural gas demand is seasonal. Our analysis also tested for
the relevance (i.e., a statistical difference) of the “critical” eight-month time
period from August 2000, when the explosion on the El Paso Pipeline
occurred, through March 2001. This disruption in Southern California
supply corresponds to the period FERC Administrative Law Judge Wagner
found there was some evidence of pipeline supply shortages for Southern
California.27
Table 10-3 shows the independent variables we used as explanatory
variables in the regression equations. The daily natural gas spot prices we
analyzed for Southern California (so_cal) and Henry Hub are the daily
midpoint spot prices reported in Gas Daily. For Northern California, we
used the average daily midpoint spot prices for Malin and PG&E Citygate
reported in Gas Daily.
25
26
27
Anthony Bopp, “Daily Price Adjustments in the U.S. Market for Natural Gas,” Atlantic
Economic Journal 28 (2000), pp. 254-265.
D. Walls, “An Econometric Analysis of the Market for Natural Gas Futures,” The Energy
Journal 16 (1995), pp. 71-84.
100 FERC ¶63,041 (September 23, 2002).
92
The California Electricity Crisis: What, Why, and What’s Next
Table 10-3. List of Variables
Variables*
Description
Log of So Cal
Gas Price
Natural log of daily Southern California gas price ($/MMbtu). All prices
for So Cal are midpoint prices** reported by Gas Daily.
Log of No Cal
Gas Price
Natural log of daily Northern California gas price ($/MMbtu). No Cal
prices were derived taking the average of the daily PG&E Citygate and
Malin gas prices. All prices for PG&E Citygate and Malin are midpoint
prices reported by Gas Daily.
Log of Henry
Hub Price
Log of Gulf
Coast Heating Oil
Price
Natural log of daily Henry Hub gas price ($/MMbtu). All prices for
Henry Hub are midpoint prices reported by Gas Daily.
Natural log of daily Gulf Coast Heating Oil Spot Price FOB (cents/g).
Log of
Normalized CA
Consumption
Natural log of monthly CA normalized natural gas consumption or
deliveries to all consumers (MMcf). Normalized by dividing by Low
Normal consumption (defined as one standard deviation below the
average consumption of each month (Jan-Dec) between the years 1989
and 1999). Calculated as LOG (Monthly CA NG Consump/Monthly CA
NG Low Normal Consump).
Log of CA
Storage
Natural log of monthly CA natural gas in underground storage (MMcf).
Critical Period
Dummy variable indicating the eight critical months subsequent to the El
Paso Pipeline explosion (8/1/2000-3/31/2001).
Winter Period
Dummy variable indicating observation is during winter (December,
January, February, March).
Crisis Period
(Critical* Winter)
Dummy variable indicating the four crisis months during both the
critical period subsequent to the El Paso Pipeline explosion and the
winter months (12/1/2000-3/31/2001).
* Data from all independent and dependent variables starts in Jan 99 and ends in July 02 and excludes
weekends and national holidays.
** Midpoint prices defined as the average of the low and high of the Common Range, commonly called
the GDA (Gas Daily Average), which is always within a half-cent of the volume-weighted average of all
the deals reported to Gas Daily for each point.
From the outset, we found the data to be serially or auto-correlated. We
used several functional forms and statistical estimation methods to correct
this flaw because autocorrelation affects the validity of the hypothesis being
tested. After experimenting with alternative models and specifications, we
found specifications that included the lagged value of the daily spot price
relative to the Henry Hub price (also lagged) effectively eliminated the serial
correlation. The degree of auto-correlation apparent in the data is quite high.
We conclude that the equations specified in Table 10-4 are the best statistical
An Economic Analysis of Natural Gas Price Movements During the
Crisis
93
choice for Southern and Northern California daily spot price regressions
during the time period January 1999 through July 2002. The final models
were estimated using Ordinary Least Squares (OLS) regression.
Table 10-4. Daily Natural Gas Price Regressions
DEPENDENT VARIABLES
INDEPENDENT VARIABLES
Log of So Cal
Gas Price
1.989
(2.69)
Log of No Cal
Gas Price
1.295
(2.02)
Log of Henry Hub Price
1.006
(45.15)
1.000
(52.01)
Log of Henry Hub Gas Price During Acute CA
Crises
-0.062
(-1.26)
-0.039
(-0.91)
Log of Lagged Natural Gas Spot Price Divided by
Henry Hub Price
0.918
(68.88)
0.902
(57.97)
Log of Gulf Coast Heating Oil Price
0.022
(1.16)
0.012
(0.73)
Critical Period
-0.009
(-0.68)
0.008
(0.68)
Winter Period
-0.019
(-1.87)
-0.010
(-1.14)
Crisis Period
(Critical * Winter)
0.191
(2.15)
0.113
(1.52)
Log of Normalized Natural Gas Consumption
During Acute CA Crises
-0.096
(-1.37)
-0.072
(-1.17)
Log of CA Normalized Natural Gas Consumption
0.031
(1.14)
0.032
(1.36)
Log of CA Natural Gas Storage Amounts
-0.161
(-2.77)
-0.104
(-2.06)
Number of Observations
Corrected R-squared
Durbin-Watson Statistic
Mean of Dependent Variable
892
0.9835
1.93966
1.32917
892
0.98146
1.9033
1.23228
Constant
*t-statistics in parenthesis
The final specification of the independent variables that works best after
various pre-testing is rather straightforward. First, we test the hypothesis that
the daily price in the end-use market (e.g., Southern California) is correlated
with the daily price at Henry Hub. This relationship was significant and
positive in both the Southern and Northern California markets. In fact the
94
The California Electricity Crisis: What, Why, and What’s Next
elasticity of the pass-through from Henry Hub index prices to California
prices was nearly one in both cases. Second, we tested the hypothesis that
the current daily spot price in an end-use market also depends upon the
previous day’s price differential between that market and Henry Hub. This
econometric model uses a dynamic adjustment specification. Dynamic
energy pricing models are discussed in Verleger (1982)28 for crude oil and
Houthhakker, Verleger, and Sheehan (1974)29 for gasoline and electricity. In
our approach, we include the lagged log price in comparison to the lagged
price at the Henry Hub. To the extent that the lagged log price of gas is
above the Henry Hub price, gas prices should adjust upward (i.e., the
predicted price change is positive). This specification is also known as an
error-correction or mean-revision model.30 In logarithmic form, the relevant
variable is the logarithm of the ratio between yesterday’s Southern
California spot price and yesterday’s Henry Hub spot price. This hypothesis
holds with significant probability for both Southern and Northern California.
Next, we tested the daily Gulf Coast Heating Oil price as an explanatory
factor because it is known to move seasonally with natural gas prices and
because it reflects worldwide crude oil price movements over time. (In other
models, we found that Gulf Coast Heating Oil prices generally outperform
World Crude Oil prices in natural gas regression equations.) That said, one
can generally only accept the hypothesis of Gulf Coast Heating Oil prices
being positively correlated with daily spot natural gas prices marginally, if at
all.
We considered various natural gas consumption measures as possible
explanatory factors affecting natural gas price movements. The hypothesis
is that when electricity demand, economic factors, or climate conditions
push up demand for natural gas, spot prices would increase, especially if
supply is tight. There are several dimensions to such a hypothesis. First, we
used normalized monthly natural gas consumption (see Table 10-3). A very
cold month or a period with a high level of economic activity would mean
that normalized monthly natural gas consumption (demand) would be
higher. Since this would be especially true in the critical winter period, we
28
Philip K. Verleger, “The Determinants of Official OPEC Crude Oil Prices,” Review of
Economics and Statistics 64 (May 1982), pp. 177-183.
29
H.S. Houthhakker, Philip Verleger and Dennis Sheehan, “Dynamic Demand Analysis for
Gasoline and Residential Electricity,” American Journal of Agricultural Economics (May
1974), pp. 412-418.
30
For an introduction to error-correction model, see W. Greene, Econometric Analysis, 4th
Ed., Chapter 17. The error correction specification we use is: Pt = αP*t + β[ Pt-1 – P*t-1] +
Ztδ + εt where Pt is the logarithm of gas price (Northern or Southern CA), P*t is the
logarithm of the Henry Hub gas index price, Zt are additional explanatory factors with
weights δ, and εt is the unobserved error term.
An Economic Analysis of Natural Gas Price Movements During the
Crisis
95
separately considered the normalized gas consumption measure for the post
pipeline explosion period during the winter (CRISIS). We expected natural
gas supplies to be tighter than normal in Southern California and, to some
lesser degree, statewide in these instances. Two variables emerged from this
analysis: (1) Normalized Consumption and (2) Normalized Consumption
During Crises. Contrary to our expectations, neither variable was significant
in either the Southern California or Northern California markets.
Next, we test for the significance of monthly storage in California.
Storage effects on natural gas prices are discussed in Susmel and Thompson
(1997)31 and more generally in Deaton and Laroque (1992,32 199633) and
Wright and Williams (1982)34. When monthly storage declines, daily spot
prices increase in both California markets. This result was confirmed in
both California markets. Finally, the winter indicator (WINTER) showed
that prices were marginally lower in the winter, all other factors held
constant, although the seasonal price pattern was different in the two
California markets.
We have already discussed some tests for the structural stability of these
results over time. We also considered whether the relationship of natural gas
prices in California markets to the Henry Hub market was significantly
different during the crisis period. In the Southern California market, the
coefficient on the Henry Hub variable in the critical period was negative,
suggesting that the partial correlation of Southern California prices to the
Henry Hub pass-through elasticity was smaller in the critical period than
otherwise. This result did not, however, reach statistical significance. The
Northern California market revealed no significant change in the relationship
of Northern California natural gas prices to the Henry Hub during the critical
period. More interestingly, we found that natural gas prices in Southern
California rose after the pipeline explosion, but that Northern California
prices were not similarly affected.
Figures 10-1 and 10-2 show the actual and predicted daily spot prices for
Southern and Northern California using the OLS equations in Table 10-4.
31
Raul Susmel and Andrew Thompson, “Volatility, Storage and Convenience: Evidence from
Natural Gas Markets,” The Journal of Futures Markets 17 (1997), pp. 17-43.
32
Angus Deaton and Guy Laroque, “On the Behavior of Commodity Prices,” Review of
Economic Studies 59 (1992), pp. 1-23.
33
Angus Deaton and Guy Laroque, “Competitive Storage and Commodity Price Dynamics,”
Journal of Political Economy 104 (1996), pp. 896-923.
34
Jeffrey C. Williams and Brian D. Wright, “The Economic Role of Commodity Storage,”
The Economic Journal 92 (Sept 1982), pp. 596-614.
96
The California Electricity Crisis: What, Why, and What’s Next
There is very little difference between actual and predicted natural gas prices
during the roughly three and one-half year period.
$60.00
$50.00
PREDICTED
ACTUAL
$/M M BTU
$40.00
$30.00
$20.00
$10.00
2
2
l-0
2
-0
ay
M
Ju
02
-0
ar
M
Ja
No
v-
n-
01
01
1
Se
p-
1
Ju
ay
M
M
l-0
1
-0
01
ar
-0
00
v-
n-
No
Ja
0
00
Se
Ju
ay
M
p-
0
l-0
0
-0
00
ar
M
Ja
-0
99
n-
99
v-
pSe
No
9
Ju
ay
M
M
l-9
9
-9
99
-9
ar
nJa
9
$0.00
Figure 10-1. Southern California Natural Gas Prices
$60.00
$50.00
PREDICTED
ACTUAL
$/MMBTU
$40.00
$30.00
$20.00
$10.00
Ju
l- 0
2
2
ay
M
M
ar
-0
-0
2
02
n-
Ja
01
No
v-
01
p-
Se
Ju
l- 0
1
1
1
-0
ay
M
M
ar
-0
01
n-
vNo
Ja
00
00
p-
Se
l- 0
Ju
ay
M
0
0
-0
0
00
-0
ar
M
n-
Ja
99
No
v-
99
9
pSe
l- 9
Ju
9
-9
M
ay
-9
99
n-
ar
M
Ja
9
$0.00
Figure 10-2. Northern California Natural Gas Prices
Next, these same comparisons are shown in Figures 10-3 and 10-4 for the
period January 1, 2000 through June 20, 2001 to correspond to the expanded
period the FERC has permitted for scrutiny in the Refund Case, which we
will discuss in greater detail in Chapter 11. Again, there are only minor
An Economic Analysis of Natural Gas Price Movements During the
Crisis
97
differences between actual and predicted values using these regression
equations.
$60.00
$50.00
ACTUAL
PREDICTED
$/MMBTU
$40.00
$30.00
$20.00
$10.00
-0
M 0
ar
-0
0
Ap
r-0
M 0
ay
-0
0
Ju
n00
Ju
l-0
0
Au
g00
Se
p00
O
ct
-0
0
N
ov
-0
D 0
ec
-0
0
Ja
n01
Fe
b0
M 1
ar
-0
1
Ap
r-0
M 1
ay
-0
1
Ju
n01
Fe
b
Ja
n
-0
0
$0.00
Figure 10-3. Southern California Natural Gas Prices (Jan 2000-Jun 2001)
$60.00
$50.00
ACTUAL
PREDICTED
$30.00
$20.00
$10.00
n00
Fe
b0
M 0
ar
-0
0
Ap
r-0
M 0
ay
-0
0
Ju
n00
Ju
l-0
0
Au
g00
Se
p00
O
ct
-0
0
N
ov
-0
D 0
ec
-0
0
Ja
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Fe
b0
M 1
ar
-0
1
Ap
r-0
M 1
ay
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n01
$0.00
Ja
$/MMBTU
$40.00
Figure 10-4. Northern California Natural Gas Prices (Jan 2000-Jun 2001)
98
The California Electricity Crisis: What, Why, and What’s Next
SIMULATION ANALYSIS
Regulatory attention focused on the natural gas supply disruption in the eight
months subsequent to the El Paso Pipeline accident. Thus, the focus is on
the predicted price differences in the eight critical months subsequent to the
El Paso Pipeline explosion relative to the other months in the analysis. Here,
the four winter months (December, January, February, and March) are most
important. For the critical period, one can predict what prices would have
been if all explanatory factors had been the same as they were in actuality,
except that the period of time was normal (i.e., the period of time where the
dummy variable for the critical period would be equal to zero). In this “but
for” analysis, we predict natural gas prices assuming that the time periods
were neither critical nor in crisis. In performing this simulation, we
eliminated variables appearing as interactions with the critical period
dummy if they had insignificant coefficients. Since no critical period
variables were significant in the Northern California regressions, we do not
present a “but for” analysis in this case. Table 10-5 presents the modified
regression models used in the simulations.
An Economic Analysis of Natural Gas Price Movements During the
Crisis
99
Table 10-5. Daily Natural Gas Price Regressions for Simulations
DEPENDENT VARIABLES
INDEPENDENT VARIABLES
Log of So Cal
Gas Price
2.240
(3.29)
Log of No Cal
Gas Price
1.629
(2.81)
0.987
(53.36)
1.001
(75.9)
---
---
Log of Lagged Natural Gas Spot Price
Divided by Henry Hub Price
0.931
(79.22)
0.913
(64.96)
Log of Gulf Coast Heating Oil Price
0.029
(1.61)
0.015
(1.01)
Critical Period
---
---
Winter Period
-0.021
(-2.23)
-0.009
(-1.22)
Crisis Period
(Critical * Winter)
0.033
(1.79)
---
---
---
Log of CA Normalized Natural Gas
Consumption
0.006
(0.25)
0.015
(0.73)
Log of CA Natural Gas Storage Amounts
-0.181
(-3.4)
-0.131
(-2.89)
892
0.98346
1.95623
1.32917
892
0.98142
1.92074
1.23228
Constant
Log of Henry Hub Price
Log of Henry Hub Gas Price During
Acute CA Crises
Log of Normalized Natural Gas
Consumption During Acute CA Crises
Number of Observations
Corrected R-squared
Durbin-Watson Statistic
Mean of Dependent Variable
* t-statistics in parenthesis
We also used the modified regression model to predict daily Southern
California natural gas prices during the fourteen-month period from May
2000 through June 2001. These prices can be compared to the actual prices
during this period. These are shown using monthly averages in Table 10-6
for Southern California and in Table 10-7 for Northern California.
100
The California Electricity Crisis: What, Why, and What’s Next
Table 10-6. Average Monthly Actual and Predicted Southern California Natural Gas Prices
CRITICAL/
PREDICTED
MONTH
ACTUAL PREDICTED
NOT CRITICAL
(NOT CRITICAL)
May 2000
NOT CRITICAL
$3.60
$3.64
$3.64
Jun 2000
NOT CRITICAL
$4.68
$4.71
$4.71
Jul 2000
NOT CRITICAL
$4.64
$4.65
$4.65
Aug 2000
CRITICAL
$5.25
$5.29
$5.29
Sep 2000
CRITICAL
$6.06
$6.19
$6.19
Oct 2000
CRITICAL
$5.62
$5.69
$5.69
Nov 2000
CRITICAL
$9.83
$9.23
$9.23
Dec 2000
CRISIS
$25.71
$25.22
$24.22
Jan 2001
CRISIS
$12.67
$13.01
$12.59
Feb 2001
CRISIS
$19.11
$18.56
$17.96
Mar 2001
CRISIS
$14.30
$14.09
$13.64
Apr 2001
NOT CRITICAL
$13.83
$13.42
$13.42
May 2001
NOT CRITICAL
$12.00
$11.58
$11.58
Jun 2001
NOT CRITICAL
$6.65
$6.70
$6.70
Avg Price (5/2000 – 6/2001)
Avg Price During Critical Period:
Avg Price During Crisis Period:
$10.14
$12.08
$17.78
$10.00
$11.93
$17.56
$9.84
$11.66
$17.00
Table 10-7. Average Monthly Actual and Predicted Northern California Natural Gas Prices
CRITICAL/
PREDICTED
MONTH
ACTUAL PREDICTED
NOT CRITICAL
(NOT CRITICAL)
May 2000
NOT CRITICAL
$3.47
$3.51
$3.51
Jun 2000
NOT CRITICAL
$4.46
$4.49
$4.49
Jul 2000
NOT CRITICAL
$4.18
$4.21
$4.21
Aug 2000
CRITICAL
$4.67
$4.72
$4.72
Sep 2000
CRITICAL
$5.69
$5.76
$5.76
Oct 2000
CRITICAL
$5.48
$5.52
$5.52
Nov 2000
CRITICAL
$9.45
$8.79
$8.79
Dec 2000
CRISIS
$20.34
$19.69
$19.69
Jan 2001
CRISIS
$10.44
$10.65
$10.65
Feb 2001
CRISIS
$10.62
$10.48
$10.48
Mar 2001
CRISIS
$8.04
$7.98
$7.98
Apr 2001
NOT CRITICAL
$10.49
$10.13
$10.13
May 2001
NOT CRITICAL
$6.23
$6.26
$6.26
Jun 2001
NOT CRITICAL
$3.83
$3.91
$3.91
Avg Price (5/2000 – 6/2001)
Avg Price During Critical Period:
Avg Price During Crisis Period:
$7.57
$9.20
$12.25
$7.48
$9.06
$12.10
$7.48
$9.06
$12.10
For Southern California, the difference between predicted and actual
prices increases in the crisis months when we exclude the critical period
effect. With respect to the regulatory scrutiny period (after the pipeline
An Economic Analysis of Natural Gas Price Movements During the
Crisis
101
explosion), actual prices averaged $12.08 for Southern California. The best
prediction is that prices would average $11.93, or 15¢ less. This difference
is about 1.2 percent of the actual price. Without adjusting for the critical
period factors, the predicted price would decrease by 27¢ from the predicted
price. Hence, we conclude that the pipeline explosion caused an estimated
2.3 percent price increase in Southern California natural gas prices during
the critical period.
During the four-month crisis period, the average predicted price was
$17.56. Without adjusting for critical period factors, the average predicted
price was $17.00. This is a 56¢ decrease from the predicted actual price.
Hence, we conclude that the El Paso explosion caused prices to increase in
Southern California by 3.2 percent during the crisis period.
In Northern California, the effect of the El Paso Pipeline explosion on
natural gas prices was not significant. The predicted price for the crisis
period averaged $9.06, 14¢ or 1.5 percent lower than the actual price. Since
the critical period effects were insignificant in Northern California markets,
the predicted price differentials demonstrating the effects of the El Paso
Pipeline explosion are equal to zero.
CONCLUSION
Our main conclusions are that underlying factors, especially the prices at and
relative to Henry Hub, explain the underlying natural gas prices to a
considerable extent. The daily natural gas analysis rejects the hypothesis that
natural gas prices were somehow artificially inflated during this period. If
the natural gas markets had been manipulated, we would expect to see
evidence of higher prices in both Northern and Southern California, all other
things equal. This was not the case. Evidence shows that Southern California
prices were higher due to the El Paso pipeline explosion. The alternative
hypothesis that the critical period was a period of market manipulation must
be rejected unless it is plausible that only Southern California prices were
subject to manipulation. Finally, the relationship of California prices to the
Henry Hub was not dramatically shifted in the period that subsequently
received regulatory scrutiny. Yet, this relationship with Henry Hub prices
does not, by itself, completely explain price setting in California. Other
factors, including the limited gas storage, excess demand, seasonality, and
the pipeline explosion, help explain California prices. Thus, a formula for
setting prices during the refund period based solely on Henry Hub index
prices and transportation costs must certainly miss the mark as it cannot
102
The California Electricity Crisis: What, Why, and What’s Next
possibly adjust for the pipeline explosion, limited gas storage, or the excess
demand for natural gas.