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A State Divided:

The Split California Natural Gas Storage Market

February 1, 2017 | By Callie Kolbe

A new market dynamic is evolving in the state of California as utilities and energy providers have been forced to grapple with opposing signals about securing natural gas supply necessary to meet heating demand via pipeline inflows and storage withdrawals this winter. A new level of resourcefulness has been necessary as traditional heating season strategies no longer apply.

This winter has been slightly cooler and wetter than normal in California, a fortunate development that helped to alleviate drought conditions that have persisted for the past several years. However, there has been little relief from an energy procurement standpoint as the behavior of storage activity and inflowing supply to meet incremental demand for northern and southern California has changed significantly.

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This week’s Get the Point will analyze how the utilization of storage capacity has behaved this winter amid the well-documented chaos of the Aliso Canyon outage. We also will discuss what to expect for the Northern California and Southern California gas markets as the end of winter approaches. 

California as a whole has 376 Bcf of working gas storage capacity. Northern California accounts for the majority of working gas storage service in the state. In the north, there are eight separate storage fields that can provide natural gas to PG&E’s service area. PG&E is the largest utility in the state, and controls nearly 103 Bcf of capacity, with the remaining 138 Bcf operated by four independent storage facilities.

The southern half of the state’s storage fields are operated by SoCalGas, the state’s second-largest gas utility. These remaining four fields represent 135 Bcf of capacity, of which 86 Bcf is provided by the significantly compromised Aliso Canyon facility.  

Total Working Gas Storage Capacity

Northern California meets winter demand with stronger storage withdrawals

Since December, storage withdrawals in northern California (PG&E) have been particularly strong as cooler temperatures blanketed the state and net pipeline inflows fell below typical winter averages. 

PointLogic Energy tracks daily injection and withdrawal activity for each of the eight storage fields in the northern half of California. Since December, combined reported withdrawal activity has averaged 1.2 Bcf/d, which is 0.7 Bcf/d higher than last year’s average for the same time frame and 0.4 Bcf/d stronger than the prior five-year average. This has left storage inventories reported by PG&E in northern California at just over 66 Bcf, or nearly 11 Bcf (14%) below last year’s end-of-January levels. (See graph below.)

The significant uptick in withdrawal activity this year has corresponded with slightly colder temperatures in the region. Temperatures for Northern California averaged just over 2 degrees cooler for the months of December and January compared to the prior five-year historical average of 52 degrees Fahrenheit.  

Northern California Net Storage Activity

Most notably, Northern California has not been able to rely as much on pipeline inflows this winter, which has exacerbated the need for withdrawal activity.PointLogic estimates that cross-border pipeline flows into Northern California via the Redwood Path on PG&E’s California Gas Transmission have averaged 1.1 Bcf/d in both December and January, or roughly 0.3 Bcf/d lower than the prior five-year average.

Lower pipeline flows can be attributed to lower firm capacity commitments. PG&E reports the Redwood Path to have firm commitments totaling roughly 1.4 Bcf/d for December through March of this year. This committed volume is significantly less than prior years, which had been pushed over 2.0 Bcf/d. The lower flows via pipeline into Northern California have necessitated strong storage withdrawals to meet demand in December and January. 

Southern California left to source supply from neighboring regions

Conversely, throughout December and January Southern California has relied less upon storage withdrawals and more on pipeline inflows to meet winter demand. 

Unlike Northern California, storage fields in southern California began the winter season at an inventory level and a daily net withdrawal rate that were significantly below prior years due to ongoing issues at Aliso Canyon. Throughout December and January, storage withdrawals in Southern California averaged 0.26 Bcf/d, which was 0.65 Bcf/d lower than last year and 0.44 Bcf/d lower than the prior five-year average.

Total inventories recorded by SoCal in the southern part of the state currently sit at roughly 44 Bcf, which remains well below the prior five-year end of January average of 81 Bcf. (See graph below.)

Winter temperatures in Southern California have behaved similarly to those in the northern half of the state at 2 degrees cooler than in prior years. This implies that heating demand for natural gas has been relatively in line, if not slightly higher, this year than in previous years.

In order to meet this winter demand, Southern California has relied more heavily upon net inflows from cross-border pipelines. PointLogic Energy’s Flow Tracker illustrates that flows into southern California averaged just over 4 Bcf/d in December, which was nearly 0.5 Bcf/d higher than the prior five- year average. This trend has continued through January with average flows maintaining a level of 4 Bcf/d, or roughly 0.6 Bcf/d higher, than prior years. Most of this observed uptick has been delivered to SoCal’s system from El Paso Natural Gas Pipeline via the Ehrenberg interconnect located in La Paz County, Ariz.

Southern California Net Storage Activity

Looking Ahead

Despite Aliso Canyon’s brief net withdrawal last week (Jan. 23-24), storage activity in Southern California will likely remain controlled through February, which will maintain the need for stronger than normal pipeline inflows into the sub-region.

Over the next month, demand across California is expected to fall somewhat as above-average temperatures are anticipated for California through most of February. The expected softer demand levels throughout both ‘NOCAL’ and ‘SOCAL’ will ultimately place downward pressure on the state’s pricing hubs. Within Northern California, Malin cash basis has traded at an average discount of $0.03/MMBtu in January. This discount will likely increase through February as withdrawal activity remains high amid historically low pipeline inflows.

Southern California will likely remain in the opposite situation with weak storage withdrawals and strong net inflows. The need to source supply from outside the state has kept upward pressure on SoCal Border cash basis, which has traded at an average premium of $0.01/MMBtu through January.

Softer demand through February will alleviate some of the economic pressure on the SoCal Border hub and could bring cash basis down to a slight discount. However, due to the sub-region’s limitations in drawing from storage, regional spreads with SoCal Border will likely stay tighter than usual. 

Stay tuned to PointLogic as we track the situation on both sides of the divide in California.  

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