1998 Natural Gas Market Outlook

Natural Gas Market Outlook
Staff Report

Publication Number: P300-98-006
June 1998

This report is written in support of the 1997 Fuels Report. Printed copies of the market report are available from the Energy Commission's publications unit by calling 916-654-5200. The Executive Summary of the document is below.

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Disclaimer: The views and conclusions in this document are those of the staff of the Energy Information and Analysis Division and should not be interpreted as necessarily representing the policies of either the California Energy Commission or the State of California.

EXECUTIVE SUMMARY

The California Energy Commission is required under Section 25310(a) of the California Public Resources Code to prepare a biennial forecast of natural gas prices, supplies, and demand for California over a 20-year period. The forecast is developed in support of the Fuels Report, a comprehensive report to be submitted to the Governor and Legislature describing emerging trends and long-range forecasts for fuels consumed in the state. The Natural Gas Market Outlook documents the Commission's forecast of natural gas prices and supplies for each end-use market sector in the state, adopted on March 18, 1998.

The methodology used to generate the end-use forecasts consists of two steps. The first step entails analyzing the continental market based on resource availability, natural gas transportation capacities and costs, and expected demand for natural gas in regional market sectors. The North American Regional Gas (NARG) model is the principal tool used by the Commission to assess natural gas market fundamentals and generate the California border price forecast. Basic inputs to the NARG model include estimates of resource availability, production costs, pipeline capacity and transportation costs, regional demand projections, and other parameters defining the market fundamentals. Different from previous forecasts, the model applies a methodology to account for reserve appreciation over time. The second step focuses on determining the end-use prices for each market sector in the state. The costs to distribute and deliver natural gas for each customer class is determined. These costs and the California border prices resulting from the first step are then combined to generate the end-use prices for each market sector in each natural gas service region within the state.

Continental Supply and Price Outlook

Natural gas supplies will remain plentiful for the next several decades. The total resource base (gas recoverable with today's technology) for the Lower 48 states is estimated to be about 975 trillion cubic feet (TCF), enough to satisfy current production levels for more than 50 years. Production from Lower 48 states is expected to increase from 17.1 TCF in the 1994 base year to 25.9 TCF in 2019. Gulf Coast and Rocky Mountain supply regions account for most of the increase during the next two decades. Alberta continues to provide the bulk of Canadian production. Canadian exports are projected to rise to 3.9 TCF in 2014 and remain at that level thereafter.

The average wellhead price in the Lower 48 states is expected to increase from $1.55 per thousand cubic feet (MCF) in 1999 to $2.05 per MCF in 2019 (in constant 1995 dollars), representing an annual average increase of 1.4 percent. In Canada, the average price is projected to increase 2 percent per year from $1.10 per MCF in 1999 to $1.65 per MCF by the year 2019. The expected growth rates in wellhead prices are considerably lower than previous Commission estimates, which have consistently been in the range of 3-4 percent. A major factor contributing to this lower growth rate is the incorporation of a reserve appreciation function in the NARG model. Details of the impacts of reserve appreciation are described in this Outlook.

Natural Gas Supplies and Prices at the California Border

Four producing regions supply California with natural gas. Three of them (the Southwest U.S., the Rocky Mountains, and Canada) provide approximately 85 percent of all gas used in the state. The remainder is produced inside California. Total supplies are expected to increase from 5.9 billion cubic feet (BCF) per day in the 1994 base year to 7.8 BCF per day by 2019. No significant changes are anticipated in the market shares of supplies from these four supply regions over the forecast horizon. Southwest supplies will continue to dominate, holding approximately half of the California market. Canadian producers will supply another quarter of the market, with the remainder split between Rocky Mountain and California suppliers.

The average California border price is expected to increase by 1.9 percent per year from $1.68 per MCF in 1999 to $2.46 per MCF in the year 2019.

California End-Use Natural Gas Price Forecast

End-use prices by customer sector and utility are shown in Table A for selected years of the forecast. The analysis indicates that natural gas prices to generate electricity in the Pacific Gas and Electric Company (PG&E) and Southern California Gas Company (SoCalGas) service areas will be very competitive. Also, due to additional costs to transport natural gas through the SoCalGas service area, San Diego Gas and Electric Company (SDG&E) natural gas price for electric generation is about 30 cents higher than that in the SoCalGas service area. This trend will continue as long as the current pricing structure is maintained. The impending merger of SoCalGas and SDG&E and the unbundling of gas utility services could change this situation.

Need for Additional Interstate Pipeline Capacity to California

Despite the fact that excess interstate pipeline capacity now exists, additional pipeline capacity will be needed at the California border during the next two decades. Staff estimates a need for additional delivery capacity from the Rocky Mountains in 2004 and from Canada in 2009.

Additional delivery capacity at Wheeler Ridge will be needed by 2009 to accommodate additional flows from these regions. Expansion of the pipelines moving San Juan Basin gas to California will be needed by 2004, while take-away capacity will be needed on the SoCalGas system at Topock (at the California border) by 2009.

TABLE A
CALIFORNIA BASECASE END-USE PRICE FORECAST BY SECTOR AND UTILITY
1995 DOLLARS PER MCF

Utility
And Year Core Noncore System
Total

Resid Comm Indust Comm Indust TEOR Cogen EG

PG&E
1995
1997
2000
2005
2010
2017
6.35
7.13
6.09
5.67
5.59
5.57

6.41
7.12
6.08
5.67
5.59
5.58

4.67
4.69
3.42
3.44
3.49
3.63

2.52
3.45
3.01
3.10
3.21
3.46

1.85
2.80
2.05
2.21
2.37
2.68

1.52
2.58
1.98
2.17
2.34
2.64

2.24
2.66
1.99
2.16
2.31
2.62

2.24
2.66
1.99
2.16
2.31
2.62

3.57
4.27
3.36
3.31
3.33
3.52

SoCalGas
1995
1997
2000
2005
2010
2017

6.69
6.93
5.91
5.84
5.78
5.86

6.55
5.19
4.20
4.22
4.26
4.45

5.85
4.26
3.28
3.37
3.46
3.71

2.39
3.07
2.27
2.51
2.70
3.02

2.29
3.06
2.26
2.51
2.69
3.01

2.01
2.85
2.28
2.53
2.73
3.04

2.26
2.87
1.99
2.24
2.44
2.77

2.26
2.87
1.99
2.24
2.44
2.77

4.26
4.42
3.44
3.53
3.59
3.78

SDG&E
1995
1997
2000
2005
2010
2017

6.44
6.88
6.24
6.15
5.98
5.92

6.32
6.18
5.55
5.51
5.38
5.37

5.31
4.72
4.11
4.18
4.18
4.31

2.71
3.32
2.60
2.80
2.94
3.21

2.74
3.32
2.60
2.80
2.94
3.21

n/a
n/a
n/a
n/a
n/a
n/a

2.18
3.07
2.39
2.59
2.74
3.03

2.18
3.07
2.39
2.59
2.74
3.03

4.01
4.56
3.89
3.78
3.76
3.90

Notes:

1995 prices are historical values.
1997 prices are based on partial 1997 supply and price data.
2000 and subsequent year prices are forecasted.
Adopted March 18, 1998, by the California Energy Commission for the 1997 Fuels Report.

Sensitivity Analysis

Although the forecast is based on a "most likely" perspective of market expectations, it is important to recognize the many uncertainties surrounding the competitive natural gas marketplace. To address this critical issue, staff performed a number of sensitivity cases to study how various assumptions could impact the results of the basecase projections. Sensitivity cases addressed the power generation market, resource availability, technology advances, overall demand, and market structural changes.

Perhaps, the greatest uncertainty in today's natural gas market concerns future natural gas demand for electricity generation throughout the United States. In California, for example, the utility companies are divesting their fossil fuel-fired generation facilities while, at the same time, new power plants are being proposed to be constructed within the state. While some of the divested power plants may continue as 'must-run' facilities, there is still uncertainty regarding whether the new proposed facilities will replace existing plants or serve incremental power to meet the state's needs. To analyze this issue and also consider the impact of power generation changes throughout the U.S., several sensitivities were run with different assumptions about the level of natural gas demand. Results indicate that an increase in total U.S. natural gas consumption of nearly 20 percent above the basecase levels, increases Lower 48 average wellhead prices by 22 percent above basecase projections by 2019.

Sensitivities focusing on California studied the impacts of assumptions, such as retiring older fossil fuel-fired power plants, replacing imports of electricity by more efficient in-state generation facilities, and advancing the retirement of some nuclear-powered generation capacity in the state. These assumptions cover a range of 20 percent above and below basecase demand assumptions for power generation by the end of the forecast horizon. This results in a moderate variation of natural gas prices at the State's border, being less than 10 cents per MCF compared to basecase projections by the end of the forecast horizon.

Another area where uncertainty in demand exists is the penetration of natural gas as a transportation fuel. While progress on bringing in natural gas powered vehicles (NGV) has been slower than anticipated, the potential exists to convert many fleet vehicles, trucks or buses to run on natural gas. A sensitivity case was designed to capture this effect by assuming a significant increase in natural gas use in NGVs. A maximum incremental demand of 1.9 TCF was assumed to be consumed by NGVs, which is equivalent to converting nearly 20 million vehicles in the Lower 48 states to use natural gas as fuel. This case shows that the wellhead price rises by around 13 cents per MCF by the year 2019. A second case was run to test the impacts if in addition to the NGV use, other end-use technologies were commercialized to use natural gas, increasing the incremental demand by nearly 4 TCF by the end of the forecast horizon. This case shows a wellhead price increase of around 30 cents per MCF above basecase projections.

Several other sensitivity cases covering aspects of resource estimates, technology impacts and market structural changes were also run and are described in detail in the Outlook.

Finally, several individual sensitivity cases were integrated to provide assumptions for a high price case and a low price case. These two cases were generated to provide an upper and lower bound on the direction of future natural gas prices. The high price case generated wellhead prices that are 50-75 cents per MCF higher than the basecase over the forecast horizon. In contrast, the low price case produced prices 40-60 cents per MCF lower than the basecase.

In conclusion, the analysis documents a future natural gas market that will be stable over the long term with plentiful supplies at adequate prices. While market conditions and increasing competition in all sectors of the market may result in more volatile (short-term) pricing, the same competitive forces will provide consumers the level of options they desire and provide overall benefits to all consumers. As has been experienced in the past, the market will find ways to ensure that natural gas will be available on demand to consumers either through increased capacity of existing pipelines or by building new pipelines. While the pipeline network is integrated, key expansions of segments and interconnections of the major corridors can achieve higher deliverability without adding new or major pipelines. Of special importance is the creation of natural gas hub centers which increase utilization of existing capacity through streamlining capacity utilization and exchange transactions. Further, programs such as capacity release help in utilization of unused capacity held by various shippers which would otherwise be stranded.

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Utility And Year	Core			Noncore					System Total
Utility And Year	Resid	Comm	Indust	Comm	Indust	TEOR	Cogen	EG	System Total
PG&E 1995 1997 2000 2005 2010 2017	6.35 7.13 6.09 5.67 5.59 5.57	6.41 7.12 6.08 5.67 5.59 5.58	4.67 4.69 3.42 3.44 3.49 3.63	2.52 3.45 3.01 3.10 3.21 3.46	1.85 2.80 2.05 2.21 2.37 2.68	1.52 2.58 1.98 2.17 2.34 2.64	2.24 2.66 1.99 2.16 2.31 2.62	2.24 2.66 1.99 2.16 2.31 2.62	3.57 4.27 3.36 3.31 3.33 3.52
SoCalGas 1995 1997 2000 2005 2010 2017	6.69 6.93 5.91 5.84 5.78 5.86	6.55 5.19 4.20 4.22 4.26 4.45	5.85 4.26 3.28 3.37 3.46 3.71	2.39 3.07 2.27 2.51 2.70 3.02	2.29 3.06 2.26 2.51 2.69 3.01	2.01 2.85 2.28 2.53 2.73 3.04	2.26 2.87 1.99 2.24 2.44 2.77	2.26 2.87 1.99 2.24 2.44 2.77	4.26 4.42 3.44 3.53 3.59 3.78
SDG&E 1995 1997 2000 2005 2010 2017	6.44 6.88 6.24 6.15 5.98 5.92	6.32 6.18 5.55 5.51 5.38 5.37	5.31 4.72 4.11 4.18 4.18 4.31	2.71 3.32 2.60 2.80 2.94 3.21	2.74 3.32 2.60 2.80 2.94 3.21	n/a n/a n/a n/a n/a n/a	2.18 3.07 2.39 2.59 2.74 3.03	2.18 3.07 2.39 2.59 2.74 3.03	4.01 4.56 3.89 3.78 3.76 3.90
Notes: 1995 prices are historical values. 1997 prices are based on partial 1997 supply and price data. 2000 and subsequent year prices are forecasted. Adopted March 18, 1998, by the California Energy Commission for the 1997 Fuels Report.