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A New World Order Part 2:

The Storage Balancing Act in the Pacific

February 3, 2016 | By Callie Kolbe

When the Energy Information Administration (EIA) flipped its storage report from a three-region perspective to a five-region view a few months ago, PointLogic analyzed how the new order would impact the market’s visibility into each region and what that would ultimately mean for modelled injection and withdrawal rates going forward (see “A New World Order Part 1: The Updated EIA Natural Gas Storage Regions are Here to Stay”).

In this edition of Get the Point, we take a look at how increased visibility into the Pacific Region has helped our understanding of gas storage this winter.

The EIA Pacific Storage Region encompasses California, Oregon and Washington.  The natural gas market in these three States has been experiencing a unique balancing act this winter. While the rest of the country’s inventory levels have been well above those of prior years, the Pacific has been only slightly above historic norms – a situation we can now detect with more accuracy than in the past, when the Pacific was estimated as part of a the larger EIA West Region.

What has caused the Pacific region’s storage activity to behave so differently this year and how should the natural gas market interpret its inventory levels once the injection season begins?

Historical Comparison of Lower 48

Winter Demand in the Pacific:

PointLogic’s regional supply and demand balance of the Pacific Region illustrates that the largest fundamental shift this winter compared to prior years has been the significant increase in demand—in large part due to strong El Nino weather patterns this winter.

Since the beginning of the traditional withdrawal season in November 2015, power demand for natural gas in the Pacific has trended well above the prior five-year average. Over the past three months, demand has been, on average, 1.0 billion cubic feet per day (Bcf/d) higher as a direct result of gains in the region’s power and residential and commercial (res/comm) sectors. As depicted in Figure 2 below, this year’s incremental winter demand has not been coupled with a large enough increase in net supply into the region, thus leaving end users to rely more heavily on storage withdrawals. 

EIA Pacific Region Supply/Demand

To support the incremental 1.0 Bcf/d of demand this winter, the Pacific has sourced an additional 0.3 Bcf/d from net inflows, split evenly between flows coming from the Southwest into California and from Canada into Washington. The remainder of the gap has been met by storage inventory withdrawals. According to EIA’s five-region breakout, withdrawal rates in the Pacific this winter-to-date have come in at 8.7 Bcf/week, which is 0.7 Bcf/week higher than the prior five-year average. And this, in turn, has created significant room for upward pricing pressure at regional hubs. Since November 2015, cash basis (spread from Henry Hub) at both PG&E and SoCal has been trading at $0.55/MMBtu and $0.38/MMBtu, respectively, a $0.20/MMBtu and a $0.16/MMBtu premium to the prior five-year averages.

In addition to higher demand, the region’s storage activity has been significantly affected by an ongoing leak at the Aliso Canyon storage site, owned by SoCal Gas. Aliso Canyon represents nearly 60% of SoCal’s storage capacity. Since late October, addressing the leak has caused SoCal to withdraw gas at an accelerated rate compared to past winter seasons (higher withdrawals have relieved pressure in the leaking well). Furthermore, the leak has left open questions about storage this summer if the region’s largest field is not able to meet peak summer demand. (PointLogic has been tracking the dynamics regarding this leak in several news stories, including California Senate Passes Bill to Limit Storage at Aliso Canyon and Aliso Canyon Update: Lawsuits, Leak Progress Report. Also, on Feb. 1, EIA released a report about environmental and reliability concerns.)

This is not the only question for the Pacific Region. With expectations for power demand to remain above average throughout February and March, will the region end the withdrawal season at a deficit to the five-year average? And what will that mean for the gas market this summer?

End of Winter Inventory

Based on recent weather forecasts, PointLogic estimates that demand for the region will remain nearly 0.2 Bcf/d above the prior five-year average throughout February and 0.6 Bcf/d above average in March. Assuming supply availability remains relatively constant, this will require roughly an additional 1.0 Bcf/week to be drawn out of storage. The result would be that another 53 Bcf would be drawn over the next two months, leaving the region with an end–of-season total inventory of 210 Bcf. At that point, inventory would be just 8 Bcf above the prior five-year average and put the region at 68 Bcf below last year.

Pacific Storage Inventory

Should temperatures trend closer to historical norms, then the region’s inventories would likely remain at a surplus to the prior five-year average.

Over the past five winter seasons, storage withdrawals in the Pacific region have averaged nearly 850 MMcf/d, or 6 Bcf/week, through February (which typically averages 9 Bcf/week) and March (which typically averages 2 Bcf/week). If the Pacific matched that pace for the remainder of this winter, storage would end at 219 Bcf, which would place the region at nearly a 14 Bcf surplus to the prior five-year average. It would still be at a 53 Bcf deficit to where inventories finished the withdrawal season last year.

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Summer 2016 Storage Considerations: Hydropower

While inventories appear on track to begin the summer very close to the five-year average, there’s another big factor to consider when looking at how Pacific natural gas demand and prices will move in the summer months: hydropower. Quite simply, hydropower this year seems poised to be much more productive than in the last few years that were plagued with drought conditions. The elevated water levels could limit upward pressure on natural gas pricing in the region as hydropower generated electricity displaces some demand from natural gas-fired generation.  

Traders seem to be taking increased hydro into account already. Current forward basis for the 2016 summer strip at both PG&E and SoCal City Gates are trending well below historical averages. Over the past three summers, cash basis has averaged $0.38/MMBtu at PG&E Citygate and $0.07/MMBtu at SoCal Border, a $0.31.MMBtu spread between the two hubs. Presently, the Summer 2016 forward basis curve places PG&E at $0.21/MMBtu and SoCal at a negative ($0.045)/MMBtu. This makes the forward market spread between the two California hubs nearly $0.26/MMBtu, almost a nickel tighter than the average of the last three summers. The weaker price environment in California reflects the expectations for healthy storage levels and low demand throughout this summer.

Hydropower plays an important role in the region, and a higher water year could reduce the region’s reliance on natural gas to meet summer electricity loads. This would keep more gas in storage even if power demand in the region grows.

Nearly 65% of hydropower produced within the Lower 48 comes from EIA’s West Region, with half of that alone coming just out of the state of Washington. Within the West, hydropower has represented about 25% of the region’s total generation since 2003 and has a cyclical relationship with natural gas.

The effect is large and immediate. In 2012, water supply at the Grand Coulee Dam in Washington (the largest hydroelectric power producer in the United States) was recorded by the Northwest River Forecast Center to be 138% of normal. That summer, the West generated nearly 780,000 megawatt hours per day (MWh/d) from hydropower, which was nearly 130,000 MWh/d more than from natural gas.

Conversely, during drought conditions, as was experienced last year, hydropower is limited and natural gas can fill the gap. Last summer the Grand Coulee Dam barely topped 77% of normal, and the region generated just under 636,000 MWh/d from hydropower, which was nearly 111,000 MWh/d less than generation from natural gas. This year, water supply at the Grand Coulee Dam is expected to be at around 95% of normal throughout the summer.

Based on recent data from the Northwest River Forecast Center, the productive Grand Coulee Dam in 2016 will not be an anomaly. The majority of Pacific Northwest has seen precipitation levels significantly above normal this winter -- the effects of an El Nino winter. The result has led to higher than normal snow pack levels and the majority of water supply basins ranging from 90% to 113% of normal.  

Precipitation Overview

Ultimately, weather will dictate how quickly the region’s gas inventories will be replenished this summer. However, higher water availability this year on top of the region’s increasing reliance on renewable resources like solar and wind for electricity generation could signal even more of a bearish outlook for regional natural gas pricing hubs, as it suggests that hydropower may push some gas-fired generation out of the stack. Given that the region will likely begin the injection season near the prior five-year average, a reduced reliance on natural gas due to hydropower will help to alleviate some of the pricing pressure from higher power demand and reduced capacity at the Aliso Canyon storage facility.

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