Gas Storage in the California Market - Volatility in the SoCal vs. PG&E Regions

As we discussed in California Embarks on Risky Process - Gas and Electricity Price Volatility Likely Ahead , the California Public Utility Commission (CPUC) reduced the penalties associated with Southern California Gas’s (SoCalGas) operational flow orders (OFO) for the period that ended on September 30. While we cautioned that this could be a risky proposition, it appears to have been a successful experiment that resulted in less volatile electricity prices -- at least when compared to the summer of 2018, a period of some of the greatest volatility seen in recent memory. According to the U.S. Energy Information Administration, the maximum price per Mwh in the summer of 2018 was $360, the minimum was $23 and the average was almost $71. For 2019, the maximum was only $81, the minimum was just $16 and the average was less than $36.

But the California gas market is not out of the woods yet. Despite the image of sunny California, the high season for gas usage in the state, like most of the rest of the country, is the winter season that begins on November 1. In anticipation of this higher demand period, along with natural gas pipeline outages and operational issues last winter in the SoCalGas region, the CPUC adjusted the rules applicable to SoCalGas’s Aliso Canyon storage field. Today, we look at how the gas storage situation is very different in the SoCalGas region as compared to the Pacific Gas & Electric (PG&E) region. Volatility this winter appears to be more likely in the SoCalGas region, even following the CPUC’s revision to the operating rules for the Aliso Canyon storage field. This volatility may be exacerbated by continuing outages on two main SoCalGas gas transmission lines.

Storage in Northern and Southern California

The two largest gas utilities in California are PG&E and Sempra Energy’s SoCalGas. Both utilities own the main gas transmission lines that transport gas to their end-users within the state of California and connect to the interstate pipeline system at or near the state border. They both also operate gas storage facilities in the state. PG&E owns and operates three gas storage fields with a total capacity in excess of 100 Bcf, but by far its largest field is McDonald Island, which has a maximum capacity of 82 Bcf. In addition to these utility-operated storage fields, PG&E’s customers can also access four independently-run storage fields, which, as of 2016, have an estimated total working gas capacity of roughly 236 Bcf. SoCalGas owns and operates four natural gas storage facilities with a combined theoretical storage capacity of 137 Bcf.

Its largest field is Aliso Canyon, which has a stated capacity of 86.2 Bcf. However, since a well failure there in 2015, its working capacity has been greatly reduced. Currently, the CPUC limits the inventory in Aliso Canyon to 34 Bcf and restricts the use of that inventory to system reliability purposes. Set forth below is the storage inventory for each of these utilities at their utility-run facilities over the last two years leading into September of 2019.

SoCalGas

PG&E

Storage Inventories for Winter and Pipeline Outages

As can be seen in the charts above, PG&E’s inventory going into September of this year was almost identical to its inventory in 2018. However, SoCalGas has about 10% less in storage this year as compared to last year. In addition, as mentioned above, PG&E customers have access to independent storage fields for their use. Also, PG&E received approval in its most recent rate case to begin phasing out its use of storage to provide its customers with a commodity price service and will begin ceding that business to the independent storage providers. Therefore, despite its bankruptcy earlier this year, PG&E seems to be in a similar position when compared to last year’s winter season.

SoCalGas, however, faces three unique challenges with regard to its storage -- although the CPUC has taken action to help with two of those problems. First, as seen above, SoCalGas is running behind in filling its storage capacity. The CPUC recognized this fact, and on September 17 it ordered SoCalGas to make an additional 100 MMcf of injection space available to its customers for the month of October and to make further space available on a day-ahead basis to the extent possible during the month of October. The stated goal is to get to 82 Bcf by the end of October.

Second, the CPUC seems to have recognized that the usage limits it had placed on Aliso Canyon made it less valuable as a buffer against gas price volatility. In November of 2017, the CPUC had put in place a protocol that allowed withdrawal from Aliso Canyon only as an “asset of last resort” to be “used for withdrawals after all other alternatives have been exhausted.” In July of this year, the CPUC loosened these restrictions substantially and even took into account comments that SoCalGas had filed on proposed revisions to the protocol. Under the new protocol, withdrawals from Aliso Canyon can be made whenever the following conditions are met:

1. SoCalGas determines that preliminary OFO calculations result in a Stage 2 low OFO or higher for the applicable gas day; 
2. Aliso Canyon is above 70% of its maximum allowable inventory between February 1 and March 31; in such case, SoCalGas may withdraw from Aliso Canyon until inventory declines to 70% of its maximum allowable inventory;
3. The Honor Rancho and/or La Goleta storage fields decline to 110% of fixed month-end minimum inventory requirements; and/or
4. There is an imminent and identifiable risk of gas curtailments created by an emergency condition that would impact public health and safety or result in curtailments of electric load that could be mitigated by withdrawals from Aliso Canyon.

Third, the demand on SoCalGas’s storage may be higher than in past winters if two pipeline outages that are currently in place on SoCalGas’s system remain throughout part or all of the winter season. In late 2017, a rupture occurred on SoCalGas’s Line 235, a major transmission line (530 MMcf/day) in the SoCalGas system that connects with the interstate pipeline system at Needles. The rupture occurred at a point where Line 235 was parallel to another major transmission line in the SoCalGas system, Line 4000 (270 MMcf/day). SoCalGas began repairs on Line 235 in early 2019 and originally projected that it would be back in service by mid-April. However, there have been additional problems discovered each time the pipeline has been repressurized since then. In fact, SoCalGas’s most recent announcement indicates that it is now repairing leak numbers 11, 14 and 15.

What’s the Path Forward for SoCalGas’s Line Outages?

The original plan was to complete the repairs to line 235, restore it to service at a reduced pressure, run an inline inspection (ILI) tool through it, and then take down line 4000 to repair some anomalies that had been detected in that line as a result of an ILI run report from June 2018. The restoration of line 235 to even limited service has been delayed a number of times since the original mid-April estimate. In fact, the restoration of service date was moved to May 9, then June 4, July 29, August 29 and, most recently, October 14, 2019. Even following that limited restoration of service, the pipeline will still need to have an ILI run completed, which could lead to it being taken out of service again, if a major anomaly is found.

The ILI report for line 4000 was approved in June 2018. However, according to the most recent report from SoCalGas, a new ILI was completed the week of September 3, 2019. Although SoCalGas has not reported what was found by that ILI, it did modify its plans and announced that line 4000 will be taken out of service even before Line 235 is restored to limited service. SoCalGas attributed its revision in plans to the “necessity to validate the in-line inspection of line 4000 and in consideration of the upcoming winter season.” As a result, line 4000 was taken out of service on September 19 and is expected to return to service on November 14, 2019.

SoCalGas had noted in the past that the 2018 ILI found no “immediate safety conditions” with the line. The lack of a similar statement about the 2019 ILI and the change in plans may be an indication that the 2019 ILI found conditions which required the pipeline’s removal from service ahead of schedule. Given the history of both of these pipelines, the confidence in SoCalGas to meet the restoration of service date for either line cannot be very high. If further problems are discovered, it could mean that one or both lines will be unavailable for service for much of the winter season. The inability to flow gas on a daily basis from the interstate pipeline system will lead to even more pressure on the need for storage and could result in substantial volatility in prices during the coldest days of winter.

The Interstate Pipelines that Feed California

As stated earlier, the interstate pipeline system generally connects with the transmission systems in California at or near the state’s border. Set forth below is a map of those connections taken from a 2018 California Gas Report prepared for the CPUC by the utilities.

1. El Paso Natural Gas
2. Gasoducto Bajanorte (GB)
3. Gas Transmission Northwest (GTN)
4. Kern River Pipeline
5. Mojave Pipeline
6. North Baja Pipeline
7. Northwest Pipeline
8. Paiute Pipeline
9. Pacific Gas & Electric Company
10. Questar Southern Trail Pipeline
11. Rockies Express
12. San Diego Gas & Electric Company
13. Southern California Gas Company
14. Transportadora de Gas Natural (TGN)
15. TransCanada Pipeline
16. Transwestern Pipeline
17. Tuscarora Pipeline
18. Unused
19. Ruby Pipeline
20. Kern River Expansion
21. Sunstone Pipeline
22. Transcolorado Pipeline
23. Pacific Connector Pipeline

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