Electricity Shortage in California: Issues for Petroleum and Natural Gas Supply

1. Summary

2. Electricity Reliability Issues in California

3. Petroleum Refineries

4. Constraints Outside the Refinery Gate

5. Petroleum Product Prices and Supply Disruptions

6. Natural Gas

6. Natural Gas

  1. The California Market for Natural Gas
  2. Background
  3. How Do Current Gas Market Conditions in California Compare to Last Summer?
  4. Impact of Electricity Outages
  5. Conclusion
  6. End Notes


A. The California Market for Natural Gas

The expanding economy of the 1990's and the increasing demand for natural gas helped bring about a 19-percent growth in United States natural gas consumption between 1991 and 2000.[1] During that time, enough additional natural gas pipeline capacity was installed in the United States to satisfy the market as it expanded. Few instances of capacity constraint or bottleneck occurred and gas service has been reliable. But in 2000 the demand for natural gas in some areas of the country, particularly in California, approached capacity limitations.

In 2001, the natural gas market in California has been substantially affected by a drop in hydropower resources in the Northwestern United States and, consequently, a drop in electric power generation from that source. As a result, greater demand has been placed on the gas-fired electric power plants in the West, especially in California. Increased demand for natural gas to power these plants has brought about a corresponding demand for natural gas that has strained the capabilities of both interstate pipelines that transport gas from outside the State, and intrastate pipelines that transport gas to markets within the State. The combination of increased demand and strained delivery systems has contributed to the large increase in gas prices in California during the past year.[2] With the higher prices and greater demand has come a call for new pipeline capacity to be built into and within the State.

Efforts to increase natural gas supply within California could be dampened somewhat by the expected electricity outages in the State during the summer of 2001. Rotating outages of electricity have occurred in California in recent weeks in an effort to reduce electricity load. These outages have averaged about 2 hours in duration, per occurrence, and are expected to continue throughout the summer. One question that arises is what impact, if any, will the electricity outages have on the natural gas supply and delivery system in the State.

Unless electricity outages become frequent, the impact on the natural gas industry is likely to be minimal, in terms of natural gas supply storage and transportation. All firm loads are expected to be satisfied. The outages may have a financial impact on natural gas producers, processors, pipelines and storage operators in that additional costs will be incurred during the electricity outages.

Producers, particularly those using enhanced oil recovery methods in southern California, rely heavily on electricity, and production may be impacted for the duration of each electricity outage, and perhaps a bit longer. Oil producers, particularly small operators, currently rely more on the grid for their electricity rather than distributed generation to power their operations.


B. Background

California relies heavily on natural gas to satisfy its energy needs. In 1999, approximately 29 percent of the total energy consumed in the State was natural gas. In addition, the State's natural gas market, which is dominated by industrial (including electricity generation by non-utilities) and residential use, has been growing at a robust rate in recent years. Deliveries to consumers in California increased at an annual average rate of 4 percent between 1995 and 2000. Between 1999 and 2000, end-use consumption of gas in California increased by 8.1 percent. In contrast, the annual growth in end-use consumption of gas in the United States was considerably less than the California rate -- only 1.2 percent between 1995 and 2000, and 5.2 percent between 1999 and 2000. Industrial uses (including cogeneration and non-utility generation applications) accounted for 43 percent of end-use gas consumption in California in 2000. Residential consumption accounted for about 28 percent, while commercial and electric utilities each accounted for about 14 percent of the State's end-use consumption in that year.

In 2000, the pattern of monthly gas consumption in California differed from the single winter peak, seen in 1998 and 1999, to a dual peak. In 2000, the California gas market had a summer peak nearly as high as its normal winter peak (Figure 6-1). The winter peak results from heating load by residential consumers while the summer peak stems from the effects of high cooling demand on output requirements from electric generators (both utilities and cogenerators).

Figure 6-1. Total Natural Gas Deliveries to California.

The majority of natural gas supplies to the California market are transported from other States. In 1999, California produced 372 billion cubic feet of gas, about 18 percent of the gas delivered to customers in the State. The remaining 82 percent was transported to the State by five interstate pipeline companies [4] that collectively brought gas produced in Canada, the Rocky Mountain area, and the Permian and San Juan basins in the U.S. Southwest.[5] Interstate pipeline capacity into California is estimated by EIA to be 7.3 billion cubic feet per day (Figure 6-2, Table 6-1).[6] This compares to the California Energy Commission (CEC) estimate of 7.0 billion cubic feet per day.[7] There appears to be an imbalance between the ability of the interstate gas pipeline system to deliver gas to California and the in-State pipeline capacity to receive gas at the border. The CEC has estimated the imbalance at 300 million cubic feet per day (MMcf/d), or about 4 percent of interstate delivery capacity. EIA estimates that the shortfall in receipt, or take-away, capacity is 590 MMcf/d, or 8 percent of EIA's estimated interstate delivery capacity (Table 6-1). The EIA estimate was derived by comparing interstate capacities at specific border crossings with the CEC estimates of intrastate receipt capacity.

Approximately 80 percent of gas produced in California is extracted as a co-product from oil wells in southern California. Non-associated gas accounts for the remaining 20 percent of gas production. In 1999, dry marketed production of natural gas in California totaled 372 billion cubic feet (bcf), approximately 294 bcf from oil wells and approximately 78 bcf from gas wells.[8] As a share of deliveries to consumers, gas from oil wells in California satisfied 14 percent of deliveries to consumers in 1999, whereas gas from gas wells in the state satisfied only 4 percent of consumer deliveries. The remaining 82 percent of gas deliveries to consumers is transported from sources outside the state.

Figure 6-2. Major Natural Gas Pipeline Transportation Routes in the Western U.S., 2000.

Table 6-1. Key Natural Gas Pipeline Capacity Levels into the State of California, by Location and Pipeline
Region/ Delivering Pipeline Interstate
Delivery
Capacity 1
(MMcf/d)		 Receiving Pipeline Intrastate
Receipt
Capacity 2
(MMcf/d)		 Shortfall
in Receipt
Capacity
(MMcf/d)
Southern California
Topock, AZ.
       El Paso Natural Gas Co   540 SoCal Gas Co   540
El Paso Natural Gas Co 1,140 PG&E Gas Co 1,140 3
El Paso Natural Gas Co     400 4 Mojave Pipeline Co   400
Transwestern Pipeline   225 PG&E Gas Co       0 3
Transwestern Pipeline   190 SoCal Gas Co       50 5
     Subtotal Topock, AZ. 2,495 2,130 365
Ehrenberg, AZ.
El Paso Natural Gas Co 1,210 SoCal Gas Co 1,210     0
Needles, CA.
Transwestern Pipeline     750 6 SoCal Gas Co   750     0
CA/NV line
Kern River Trans Co     750 7 Kern River Transmission Co   700   50
     Subtotal Southern California 5,205 4,790 415
 
Northern California
Malin, OR.
PG&E Gas Transmission - NW   1,970 8 Pacific Gas & Electric Co 1,905
PG&E Gas Transmission - NW     110 9 Tuscarora Pipeline       0
     Subtotals Northern California 2,080 1,905 175
 
Total California   7,285 10 6,695 590
1 Capacity levels shown in this column are based upon data independently compiled by EIA from company sources. In many cases the design capacity (as listed on the company's web site, for instance) for a particular delivery point is greater than that listed here due to operational variations on the pipeline system and/or contractual volume levels. For example, Kern River Transmission's CA/NV State line capacity is listed as 780 MMcf/d on its web site vs 750 MMcf/d level reported as the average by other sources.
2 Capacity levels shown in this column are based upon information made available in the California Energy Commission's May 2001 study of "Natural Gas Infrastructure Issues (Draft)".
3 PG&E has an interconnect with two interstate pipeline companies at Topock, Arizona (El Paso Natural Gas Co. and Transwestern Pipeline Co.). PG&E's 300 Line (from Topock, Arizona to Kern River Station near Kramer Junction, California) can carry only 1,140 MMcf/d out of Topock, AZ, but could receive as much as 1,365 from El Paso and Transwestern (1,140 + 225 MMcf/d) if the Line 300 were expanded.
4 The Mojave system is supplied by the El Paso System (which can deliver up to 400 MMcf/d) and Transwestern (150 MMcf/d) at Topock, Arizona, although only a maximum of 400 MMcf/d can be delivered at one time and carried into California.
5 Includes the receipt capacity reported for the Hector Road/Mojave Pipeline interconnect within California.
6 In the California Energy Commission's report the capacity for the "Transwestern at Needles" is reported as 1,090 MMcf/d but does not list any corresponding receipt capacities for Transwestern at Topock, for either SoCal, PG&E, or Mojave.
7 Non-winter average capacity level. Summertime capacity is 700 MMcf/d while during the winter months Kern River Transmission capacity can be as high as 800 MMcf/d.
8 Summertime capacity level. Amount that can be delivered to Malin, Oregon during the winter months drops due to increased demand for natural gas in the States north of California.
9 About 90 MMcf/d of the 110 MMcf/d capacity entering California on the Tuscarora Pipeline feeds into Nevada. However, the California Energy Commission's report does not include Tuscarora in its list of Interstate suppliers to the State.
10 The California Energy Commission's report presents 7,040 MMcf/d as the total interstate natural gas pipeline delivery capacity compared with the EIA's 7,125 MMcf/d (7,285 MMcf/d adjusted for Tuscarora's 110 MMcf/d and Kern River's 750 vs 700 summertime capacity), a difference of 85 MMcf/d.

Note: MMcf/d = million cubic feet per day.
Note: Actual capacity levels on any given day will vary due to operational conditions and to such variables as ambient temperature and elevation.

Sources:
Interstate pipeline capacity: Energy Information Administration, EIAGIS-NG Geographic Information System, State Border Capacity Database;
Intrastate pipeline capacity: California Energy Commission, "Natural Gas Infrastructure Issues," Draft, May 2001.

Storage is an important component of the California natural gas market, and one that is increasing in importance to supplement pipeline capacity and serve as a backup supply source. During peak consumption periods, the industry combines supplies from the producing regions, including imported supplies, with supplies from underground storage to meet customer demands. California storage facilities were utilized extensively this past winter (2000-2001).[9] Weekly storage inventories in the Western region averaged 30 to 40 percent below the 5-year average level throughout the winter.[10] From November 2000 through January 2001, net storage withdrawals in California totaled 73 billion cubic feet (Bcf), or about 11 percent of consumption during the period. This compares with net storage withdrawals of 47 Bcf (about 9 percent of consumption) during the same period a year earlier. Withdrawals from storage in California occur during the summer months because of spikes in consumption, particularly for electric generators.


C. How Do Current Gas Market Conditions in California Compare to Last Summer?

The outlook for natural gas in California the summer of 2001 is for continued strong demand levels and continued high gas acquisition costs due to the existing constraints on the capacity of the California intrastate pipelines to take delivery of natural gas from other regions and the high utilization rates of interstate pipelines serving the California market.[11] Summer gas demand in California, leaving aside the potential impacts on demand from reductions in gas use due to power outages, is expected to grow by 6.8 percent this summer from the 2000 level (Figure 6-3). While still quite high (more than 3 times the expected national growth rate for this summer), this rate of growth is far below the torrid pace in California seen last summer (12.8 percent). A likely slowing in the rate of economic growth in California this year is expected to be offset somewhat by continued strong growth in power-sector demand due to continuing declines in the availability of hydroelectric resources in the region (Figure 6-4). Absent a declining hydroelectric share, summer gas demand would be expected to grow at a rate closer to that expected for electricity demand or about 2.3 percent.

Figure 6-3. California Summer Natural Gas and Electricity Demand.

Figure 6-4. California Summer Natural Gas and Electricity Demand Factors.

Interstate capacity into the California market is approximately the same as it was last year, 7.3 billion cubic feet per day. Although there are several expansion projects underway (discussed later in this analysis), they are not likely to have much impact until later in the year. Utilization rates on interstate pipelines serving the State are expected to be high this summer, even under normal weather conditions. The El Paso line that was disrupted by an explosion last August, although not fully operational, does not result in less gas moving into the State. According to a company spokesperson, shippers are purchasing their gas at other places on the El Paso system and the same amount of gas is going into California as before the disruption, only by different routes[12].

It should be noted that even during peak consumption periods during 2000 and the first few months of 2001, there were no curtailments of natural gas service for the core market in California. According to the California Energy Commission, curtailments have been limited to interruptible customers, including electric generators that have chosen this level of service. Customers who chose firm, guaranteed service continued to receive that level of service and are expected to receive that level of service in the upcoming months.

Although reliable service is anticipated for all core customers in California, it will probably cost more than it did last year. The price of natural gas to residential customers averaged $12.10 per thousand cubic feet in January 2001, a 90-percent increase from the price in January 2000. Prices have dropped considerably since January, but the price of natural gas service will likely be higher this summer than last. The Henry Hub spot price for natural gas in May 2001 is only 20 percent higher than the year-earlier level ($4.25 vs. $3.50 per million Btu), however, citygate prices at California border points are still at high levels, over $8 per million Btu, as of late May 2001. California citygate prices have been subject to extreme volatility over the past year and reached as high as $60 per MMBtu in December 2000.[13] For additional discussion of California natural gas prices refer to Energy Information Administration, U.S. Natural Gas Markets: Recent Trends and Prospects for the Future, SR/OIAF/2001-02 (Washington, DC, May 2001) pp. 21-24.


D. Impact of Electricity Outages

Production/Processing Operations

The largest impact on gas supply in California from electricity outages, although still small in relative terms, is likely to be a decrease in natural gas produced as a co-product with oil, particularly in enhanced oil recovery production in the southern part of the State. In 1999, approximately 14 percent of the gas supply in California (about 80 percent of gas production in the State) was produced as a co-product from oil wells in the State. To the extent there are interruptions in electrical service to producers in California, there may be a proportional decrease in the amount of gas produced in the state. A 2 hour interruption of electricity could result in an approximate 8 percent, or more, reduction in the production from the oil or gas well for that day. If the well was not producing at maximum rate, it may be possible that some or all of the reduction in production could be recovered after electric service is restored. Nevertheless, if the electricity outages become routine or frequent, it would lead to a decrease in oil production, gas production, and gas produced as a co-product of oil.

Electricity outages for short periods of time (1-2 hours per instance), if they are infrequent, may be more an inconvenience or a nuisance for the producers and processors, albeit one that increases the overall cost of production as it may require additional resources to work around or adjust production operations. Advance notice of a planned outage is important, as it enables producers to adjust their operations accordingly to lessen the impact of each outage. Information is not readily available regarding whether producers have back-up generators (for instance powered by diesel fuel) to enable continued operation during a rotating electricity outage. Even with back-up generators, however, the efficiency of their operations would likely be reduced during the period of interruption and perhaps for an hour or two after electricity service is restored. According to industry sources, the starting and stopping of production operations is not as simple as "flipping a switch." This means that a 2-hour outage of electricity may translate to a 3-hour or up to 4-hour period of no or minimal production. As a result, production from the affected wells would be reduced by one-eighth to one-sixth of production for that day (assuming a constant production rate in the absence of the electricity outage).

The impact of electricity outages for producers that already have interruptible electricity supply contracts should be small. Some California producers have determined that they are able to tolerate electricity outages and reportedly have elected interruptible service from their electricity provider, in response to the escalating electricity prices, with the understanding that their electricity service may be curtailed during periods of peak load.

If the electricity outages become frequent, the effect on the production operations in the State will intensify. Some producers are reporting that the routine curtailment and constant stopping and restarting of production equipment pose a threat to the integrity of their wells.[14] This could necessitate additional reconditioning of the wells, which would further escalate the already high cost of producing gas in California. For some producers, electricity costs represent the bulk of their production costs.[15]

Because of State environmental restrictions, oil and gas producers in California rely more heavily on electricity in their operations than do producers in other states. Electric-driven compression is used in producing natural gas to increase pressure within the well, if the ambient pressure in the well is insufficient to extract the gas.[16] Electric motors have no major emissions, are easier to monitor, maintain and control, and may cost less to install. Electricity is also used by both producers and processors of natural gas for control systems and operations and measuring activities. In addition, electricity is used in drying activities of processing plants, during which liquids and other impurities are extracted from the gas before it enters the pipeline system.[17]

Natural gas and oil production in California has been a subject of concern since last year. Indigenous production in 1999 accounted for only about 18 percent of California natural gas supply and about 50 percent of oil supply in the State. There has been a significant drop in the production of oil and gas in the State. The State Onshore and the State Federal (not including Federal Offshore) preliminary oil production data for the months of December 2000, January and February 2001 are 739.1, 713.5, and 725.6 thousand barrels per day (mbpd), respectively. The 25.6 mbpd drop from December to January is currently attributed to the electricity blackouts and high electricity and natural gas prices.[18]

Producers, particularly those using enhanced oil recovery methods in southern California, rely heavily on electricity and natural gas. Production will be impacted for the duration of each electricity outage, and perhaps a bit longer. Oil producers, particularly small operators, currently rely on the grid for their electricity rather than distributed generation to power their operations. Natural gas is used in the generation of steam to be injected in the heavy oil recovery projects. As the price of natural gas skyrocketed, some (perhaps even many) of the small independent operators opted to discontinue the use of gas for the generation of steam and instead sold it to utility companies and other preferential customers. Some operators shut down or reduced their production and cogeneration operations in recent months because of high gas prices and non-payment by the utilities for the electricity sold to the grid.

Storage Operations

Electricity outages for short periods of time are expected to cause only minor problems at storage facilities. Some storage facilities in California use electric-driven compressors to inject gas into storage. (Compression is needed during the injection cycle but not during the withdrawal cycle.[19]) If injections were planned and an electrical outage occurred, the gas intended for injection would need to be absorbed by the system and, if possible, injected when electricity service resumes. Electricity is also used in storage for operations and facility control including valving systems and monitoring (measuring) purposes, although back-up generators (likely gas-fired) are generally in place. If storage injections requiring electric compression are not scheduled to occur at maximum injection rates, the storage injections can be rescheduled for when the power is available. Overall, the impact of brief, infrequent electricity outages on natural gas storage facilities and operations in California would be minor to non-existent.

A considerably more serious concern for storage operators than electricity outages is the extent to which storage stocks can be built up over the summer. If storage injections are low, withdrawals over the summer will lead to exceptionally low storage stocks in the West at the start of winter 2001, adding pressure to the already high gas prices. Rising energy costs and maintaining reliability in energy supply are areas of concern for consumers in California as well as the rest of the nation.

Natural Gas Pipelines

It appears that rolling electric power blackouts in California would have little or no effect upon the operations of either of the two major gas distribution companies located in the State. According to a spokesperson for Southern California Gas Co. (SoCal), none of the company's pipeline system compressor stations run on electricity and all other facilities, such as the stations themselves and dispatching centers, have emergency backup (generators) capability in place.[20] The same can be said for the Pacific Gas & Electric Co. (PG&E) pipeline system, except for one compressor station just south of the San Francisco area that operates two compressors with electricity. In the event of a rolling blackout at that station, up to 50 million cubic feet (MMcf) of service could be lost to the south during a 2-hour disruption (the average of the recent blackout intervals). According to a PG&E spokesperson, the electric compressors are reportedly already on a voluntary load reduction program with the utility and subject to interruption. PG&E also has one electric power compressor unit located at one of its underground storage facilities but says that would only halt injections for a short time.[21] Any flows lost due to a lack of withdrawal capability would be small.

What about natural gas pipeline capacity levels within the State itself?

In California, there is an imbalance between the ability of the interstate gas pipeline system to deliver gas to the California border and the in-State pipeline capacity to receive gas at the border. This imbalance means the ability of take-away capacity at the State border constrains the amount of gas that can be delivered into California by interstate pipeline companies. The California Energy Commission estimates that at least 200 MMcf/d less gas can be picked up at the State border than can be delivered to the State. EIA estimates the total imbalance at about 590 MMcf/d (Table 6-1).

On the PG&E system, which serves northern California above Kern County, capacity levels are in excess of current customer needs even on peak days. According to a company spokesperson, PG&E's daily requirements during the summer are usually below the certificated capacity at the northern California border (at Malin, OR, from PG&E Transmission - NW) by 20-to-30 million cubic feet per day (MMcf/d), while during the winter season that rises to 90+ MMcf/d. Nevertheless, PG&E plans on upgrading and expanding its system in the near future to accommodate a planned increase in capacity on the PG&E Transmission - NW system of more than 300 MMcf/d in 2002 (Table 6-2). The company believes demand will grow sufficiently by then to justify the expansion. It has no plans, however, to increase its capacity on its southern route, which transports gas into California from Arizona, since the current capacity on that section is adequate to meet current customer needs.

The SoCal system, on the other hand, is often operating at or above full capacity. The high spot gas prices currently posted at southern California citygates seem to indicate a lack of adequate pipeline capacity from the Southwest into the State. Although it has been speculated that SoCal may be hesitant to expand its system because, once the hydropower resources return to normal (most likely in 1 to 2 years), less natural gas will be needed for electric power generation, SoCal has in fact announced several projects to expand delivery capacity within the State. SoCal recently filed for two expansion projects, both to be completed in late 2001 (Table 6-2). The first project would increase take-away capacity at three critical points on its system. Although capacity would increase by only about 50-60 MMcf per day at each point, one would increase access to growing California gas production while the other two would upgrade currently constrained interconnections with the interstate network. The second project involves the building of a new 200 MMcf/d, 32-mile lateral that would link the southern part of the SoCal system with an interconnect with the Kern River-Mojave Pipeline located on the northern part of the SoCal system.

Table 6-2. Natural Gas Pipeline Projects Proposed for Development
                   in the Western United States, 2001-2004
State
Ends		 State
Begins		 Project Pipeline Name FERC
Docket Number		 Service Type of
Project 		 Status Scheduled
Service		 Cost
(million$)		  Miles  Added
Capacity
(MMcf/d)
Projects that may impact California in Summer 2001
CA TX Line 2000 Project El Paso Natural Gas Co CP00-422 Interstate New Appr 8/2001 204 1088 230
CA WY Mainline 2001 System Expn Kern River Transmission Co CP01-106 Exp Appr 6/2001 81 922 135
Subtotal 285 2,010 365
Projects that may impact western States and Mexico in late 2001
CA BC 2001 System Expn PG&E Gas Transmission-NW CP01-141 Interstate Exp Appl 2001 na 21 207
CA CA Kern River Interconnect Expn Southern California Gas Co Not applicable New Appl 2001 40 32 200
CA CA 2001 System Expn Southern California Gas Co Not applicable Intrastate Exp Appl 2001 15 0 175
Subtotal 55 53 582
Other 2001
OR OR Coos Bay Project Coos County Pipeline Co Not applicable Intratstate New Ann 2001 30 65 na
WA BC Power Plant Import Sumas Energy 2 CP99-320 Interstate New Appr 2001 na 4.5 140
MX AZ Ductos De Nogales Project El Paso Natural Gas Co CP01-41 Export New Appr 2001 0.42 1 8.5
MX AZ Willcox Lateral El Paso Natural Gas Co CP99-322/323 Export New Appr 2001 30.2 68 130
Subtotal 60 138 278
Total 2001 360 2,169 1,025
Proposed 2002 Projects
AZ AZ Red Rock Expn Transwestern Pipeline Co CP01-115 Interstate Exp Appl 2002 93.3 0 150
CA CA Long Beach Lateral Kern River Transmission Co Not yet filed New On Hold 2002 na na na
CA WY Mainline 2002 System Expn Kern River Transmission Co CP01-31 Exp Appl 2002 80 922 124.5
CA MX Otay Mesa Project Otay Mesa Generating Co CP01-145 Import New Appl 2002 na 0.3 110
CA NM Southern Trails Pipeline Questar Pipeline Co CP99-163 Interstate New Appr 2002 155 705 120
Subtotal 235 1,623 345
NV CA 2002 System Expn Tuscarora Pipeline Co CP01-153 Power Plants/LDC Exp Appl 2002 60 14 94
OR OR Mist Storage Link Phase IV Northwest Natural Gas Co Not applicable Storage Link Exp Appl 2002 35 32 145
WA WA Everett Delta Lateral Northwest Pipeline Co CP01-49 New Appl 2002 17.2 9 130
WA WA Gray Harbor Northwest Pipeline Co Not yet filed Power plant New Ann 2002 na 48 160
Subtotal 17 57 290
MX AZ North Baja Pipeline Project North Baja Pipeline LLC CP22/24/25 Export New Appl 2002 230 215 500
Total 2002 670 1,943 1,533
Proposed 2003 Projects
CA UT Ruby Pipeline Extn Colorado Interstate Gas Co Not yet filed Interstate New Ann 2003 400 850 750
CA WY Mainline 2003 System Expn Kern River Transmission Co Not yet filed Interstate Exp Ann 2003 1,000 0 900
Total 2003 1,400 850 1,650
Proposed 2004 Project
OR OR Mist Storage Link Phase V Northwest Natural Gas Co Not applicable Storage Link Exp Appl 2004 23 20 145
Total 2004 23 20 145
Total 2001-2004 2,494 5,015 4,554
Key to Abbreviations
Type of Project: Exp = Expansion
Status: Ann = Announced; Appl = Applied; Appr = Approved
Source: Energy Information Administration, EIAGIS-NG Geographic Information System, Natural Gas Pipeline Construction Database, as of May 2001.

Interstate Pipelines Serving California

Since the beginning of 2001, at least six projects have been proposed to bring additional pipeline capacity into California. Two of these projects--the Kern River Transmission Company 2001 Expansion (135 MMcf/d) and the El Paso Line 2000 Project (230 MMcf/d)--are slated for completion this summer and therefore could have an almost immediate impact on the state's energy market. Currently, Kern River Transmission is delivering only about 500 MMcf/d into California although it is capable of delivering up to 750 MMcf/d (summertime capacity). The reason for this is that about 200 MMcf/d is being diverted to power plants in the Las Vegas area. To help rectify this situation, Kern River will expand its overall system especially north of Las Vegas, which will allow more gas to enter California. This "emergency" expansion is scheduled to be in service by June 2001, perhaps in time to help mitigate the expected high demand for natural gas during the upcoming summer months.

Most of the other proposals will not have an impact on the California capacity market until 2002 and beyond. Meanwhile, the interstate natural gas pipelines serving California have adequate capacity to meet current demand within the State, although all but Kern River and Mojave have been operating at full capacity much of the time during the past several months. The interstates have the capability to deliver more than 7.3 billion cubic feet per day to the State if needed. According to the California Energy Commission, the major in-state natural gas service providers, PG&E and SoCal Gas, are fully utilizing their receipt capacity at the State border.

Several of the interstate pipeline projects proposed to increase capacity to California will not terminate at the State border, but will extend into territories previously the domain of SoCal Gas. Questar's Southern Trails and Kern River Transmission's expansion proposal will both terminate in the Long Beach-Los Angeles area (although this segment of both projects is on hold due to an inability of both pipelines to interest customers who may be subject to price penalties from SoCal under current State-imposed restrictions).

Currently about 17 percent of California's gas demand is met from in-state production compared to 14 percent in 1998-99. Higher prices for natural gas have helped bring about a large increase in production within the State over the past several years (by more than 8 percent in 2000 alone). If this growth in production is sustainable then it should help alleviate the increasing demands placed on the interstate pipeline system. However, the other States in the region do not have this resource and are almost entirely dependent upon the interstate pipeline network for their natural gas supplies.


E. Conclusion

Electricity outages for short periods of time would likely have only minimal effects on the natural gas supply and delivery system within California. All firm service contracts are expected to be met and production and storage operations will be relatively unaffected. Of concern are cost-related issues that affect production and storage stock builds. For example, California producers using enhanced oil recovery methods are particularly affected by high energy prices as their operations require both electricity and natural gas. As a result, some of these producers have curtailed operations. This is leading to reduced production of both oil and natural gas within the State, reduced cogeneration of electricity by these qualifying facilities, and therefore less electricity sold to the grid by these producers.


F. End Notes

1. Total natural gas consumption in 2000 was 22.7 trillion cubic feet, Natural Gas Monthly, DOE/EIA-0130(2001/04) (Washington, DC, May, 2001), Table 3. Total natural gas consumption in 1991 was 19.04 trillion cubic feet, Annual Energy Review, DOE/EIA-0384(00) (Washington, DC, July 2000), Table 6.5.

2. Additional upward pressure was put on prices as a result of a disruption of flow along one segment of the El Paso Gas Co. system, but a combination of market adjustments, including alternate transportation, gas from storage, and fuel switching, avoided the occurrence of widespread shortages.

3. According to the California Department of Conservation, Division of Oil, Gas, and Geothermal Resources, oil production in 1999 was 311.5 million barrels. Of that total, 193.6 million barrels was produced in 1999 using three enhanced oil recovery techniques: thermal-steam (143.9 million barrels), waterflood (45.1 million barrels) and gas injection (4.6 million barrels).

4. Interstate pipeline companies that deliver gas to California are: El Paso Natural Gas Company, Transwestern Pipeline Company, Kern River Transmission Company, Mojave Pipeline Company, and Pacific Gas and Electric Gas Transmission - Northwest Pipeline Company and PG&E Transmission - Northwest Company.

5. According to the California Energy Commission, in 1999 Canada supplied 28 percent of gas receipts in the State, the Southwest supplied 46 percent, and the Rockies supplied 10 percent. California Natural Gas Market Analysis and Issues, California Energy Commission, November 21, 2000.

6. The California Energy Commission reports that a total of 7.0 bcf/d of interstate natural gas pipeline capacity reaches the California border. That figure differs from the 7.3 Bcf/d used by EIA within this report. Among the reasons for the difference is that the CEC does not include the pipeline capacity (110 MMcf/d) of the Tuscarora Pipeline System that receives supplies from the PG&E Gas Transmission - Northwest pipeline at Malin, Oregon, for delivery to Nevada via California. In addition, the Commission reports a lower figure than EIA's 1,970 MMcf/d for PG&E at Malin, Oregon, and for Transwestern Gas Company's deliverability at Topock. Except for the Tuscarora omission, the differences reported between EIA and the CEC are attributable mainly to seasonal capacity variations and to some minor differences in pipeline data compiled by EIA compared with the CEC.

7. California Energy Commission, "Natural Gas Infrastructure Issues", Draft, May 2001.

8. In 1999, gross withdrawals of natural gas (defined as full well-stream volume, including all natural gas plant liquids and all nonhydrocarbon gases, but excluding lease condensate) from oil wells was 342 billion cubic feet and from gas wells was 90 bcf. Marketed production represents gross withdrawals less gas used for repressuring, quantities vented and flared, and nonhydrocarbon gases removed in treating or processing operations. (Natural Gas Annual 1999, DOE/EIA-0131(99), October 2000) A significant portion of the oil produced in California is heavy oil (20 degrees gravity or less) produced through enhanced oil recovery (EOR) steam methods.

9. Also known as working gas inventory.

10. Weekly storage data are available for three regions in the U.S. - the Producing Region, the Consuming East Region and the Consuming West Region. The Consuming West Region consists of all states west of the Mississippi River less Texas, Oklahoma, Kansas, New Mexico, Louisiana, Arkansas, Mississippi, Alabama, Iowa, Nebraska and Missouri.

11. Projections for California presented in this section are illustrative and are based on statistical analysis of the relationships between State gas demand data and State economic and weather data collected by the Energy Information Administration, the Bureau of Economic Analysis, the Census Bureau, and Bureau of Labor Statistics. Weather is assumed to be at normal levels in the State this summer. Hydroelectric power availability in the Pacific Census Division (California, Washington, Oregon) is taken from EIA's May 2001 Short-Term Energy Outlook. The analysis was performed by EIA's Office of Energy Markets and End Use.

12. Public Utilities Fortnightly, March 1, 2001 "Gas and the Power Crises: Chicken or the Egg?"

13. The average spot price at the SoCal citygate was $59.42 per million Btu (Gas Daily, December 12, 2000).

14. Blackouts Crimp California Crude Production, Oil Daily (May 9,2001).

15. According to industry sources, for some independent producers in the State, electricity accounts for up to 60 percent of production costs. (California Independent Producers Association).

16. Some wells are under enough pressure that the oil and gas will flow freely from them without a pump or lifting system. There are only a small number of these formations, and even these usually require a lifting system at some point in their active lives. Most wells, however, require some sort of lifting method to extract the oil and gas present in their formations. The lifting method depends on the depth of the well and whether or not the well has multiple completions. Lifting requires motor-driven pumping. (http//www.naturalgas.org/Product.htm)

17. Natural gas is processed in some manner to remove unwanted water vapor, solids and/or other contaminants that would interfere with pipeline transportation or marketing of the gas. In addition, and equally important, most natural gas is processed to separate from the gas those hydrocarbon liquids that have higher value as separate products. The casinghead gas and/or gas-well gas must be gathered, treated in the field, compressed and pipelined to a central facility for the final processing that will produce pipeline quality natural gas and marketable natural gas liquids.

18. Blackouts Crimp California Crude Production, Gas Daily (May 9, 2001).

19. Based on conversations with Mr. Rusty Cates, International Gas Consulting, and staff at the California Energy Commission and Gas Technology Institute.

20. Electricity is also used for supervisory control and data acquisition (SCADA) systems which are remote controlled equipment used by pipelines and LDCs to operate their gas systems. These computerized networks can acquire immediate data concerning flow, pressure or volumes of gas, as well as control different aspects of gas transmission throughout a pipeline system.

21. Natural gas is compressed during transportation and storage. The standard pressure that gas volumes are measured at is 14.7 Pounds per Square inch (psi). When being transported through pipelines, and when being stored, gas is compressed to save space. Pipelines have compressing stations installed along the line (one about every 100 miles) to ensure that the gas pressure is held high while the gas is being transported. Current pipelines can compress natural gas to nearly 1500 psi, but most tend to operate at closer to 1000 psi.

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