Daily Energy Blog

This winter the Northeast US is being blasted with record cold weather. As a result, daily natural gas prices in both New York and New England have spiked more than $30/MMBtu above the US benchmark at Henry Hub, LA. But the average price you’ll pay for natural gas in the region will likely depend on whether you root for the New York Giants or the New England Patriots. With their dismal records and embarrassing mistakes, it’s not easy being a Giants (or Jets) fan these days. But on average – thanks to new gas pipeline capacity added this past fall, natural gas prices in New Jersey and New York have remained less volatile relative to US benchmark Henry Hub, LA than prices in New England. That is because the six-state region continues to suffer from woefully inadequate gas transmission infrastructure. Today we begin a two-part analysis of the still-stalled effort to deliver more supplies to gas-hungry New England.

While most of the country is enjoying the benefits that low cost North American supplies of natural gas bring to local and regional economies, many parts of the Northeast US and Atlantic Canada are still heavily reliant on expensive oil-based products for residential, commercial and industrial use. That is in spite of the proximity of burgeoning supplies of natural gas in the Marcellus and Utica shale basins. The challenge in converting users away from oil lies in infrastructure build out and deciding who will pay. Today we begin a two part series on the slow conversion process and new solutions to supply natural gas to customers before pipeline infrastructure is built.

The golden years of natural gas abundance in which we find ourselves are sparking tremendous enthusiasm among potential users of the fuel, from power generators to major industrial companies, to exporters both current and potential.  After all, a trifecta of cheap, abundant, and clean is hard to resist.  But the big question is  how supply and demand really shake out after everyone’s enthusiasm results in new and growing use of the resource.  Is the natural gas industry going to be able to supply all the new demand without prices going up the way they have in the past, most recently hitting double-digits at Henry Hub just five years ago?  The first step in order to weigh supply against demand is to have a plausible scenario of what that demand might be. What does it all add up to?  So in today’s blog we will see how much demand we should be trying to meet, to be followed later by a next installment to see how producers might meet it.

The CME natural gas futures market has been trading in a narrow 40 cent range between $3.40/MMBtu and $3.80/MMBtu since the end of the summer. The onset of winter and the first storage withdrawals last week (according to EIA) have done little to jump start prices. The prompt Henry Hub futures market closed at $3.702 yesterday (November 21, 2013). The dominating story remains increased supply from new production. Today we look at how supplies are weighing on spot prices and futures market speculation.

The June 2013 decision by Southern California Edison (SCE) to permanently shut down its San Onofre Nuclear Generation Station (SONGS)—the largest power generator in the region—got the attention of the natural gas industry, and for good reason.  Natural gas interests view gas-fired generation as the logical replacement for the now-gone 2,200 MW nuclear capacity, but many other forces are at work. In this two-part series we examine southern California’s electricity cunundrum, and how big a part natural gas is likely to play in keeping the lights and air conditioning on and the pool pumps pumping.

The two-unit, 2,200-MW SONGS facility for years was a linchpin in the region’s electric grid (see Play Me A Songs). A relatively low-cost, around-the-clock generator at a pivotal location, San Onofre provided critical voltage support—an electrical engineer’s way of saying it kept the grid on an even keel. Natural gas interests expect SONGS capacity to be replaced by gas fired generation. And gas will surely have a significant role in the electricity future of the Los Angeles Basin, San Diego, and California as a whole. But because of state policies and Federal rules, among other things, utilities and merchant power companies may well end up consuming less gas than they do now, and commercial and industrial firms may use more.

One big factor is California’s push for renewable energy and energy efficiency - including combined heat and power (CHP) plants that squeeze as much energy as possible out of each btu. Another is federal rules that will require about 3,800 MW of older gas-fired plants in southern California that use “once-through cooling” to be retired by 2020 (see Figure 1; note SONGS is just north of San Diego). Once-through cooling  - like it sounds - releases cooling water after its been used only once, instead of recycling it—the preferred method now.

Figure 1

Source: California Energy Commission (Click to Enlarge)

Another 1,200 MW of gas-fired capacity in southern California is aging, inefficient and also likely to be taken offline  within a few years. Regulators, gas-plant owners and others also need to wonder, how might the gas-delivery needs of power generators be affected by plans to export LNG from the region’s ports, or plans to pipe more U.S. gas south to Mexico?

In the first half of this two-part series we consider the closure of SONGS and how state policy and federal regulations are shaping natural gas’s future role in the southernmost third of the Golden State. In the second half, we will examine in more detail where gas demand is headed in California—and why—and what that means for gas producers with access to that market.

SCE decided in June it no longer made economic sense to hold out hope that SONGS units 2 and 3 could be restarted any time soon. Both units--which are co-owned by SCE (78.2%), San Diego Gas & Electric (20%) and the city of Riverside (1.8%)--had been taken offline in January 2012, Unit 2 for a planned routine outage and Unit 3 when operators detected a small leak in a steam generator tube. (Unit 1 was retired in 1992.) Subsequent testing found premature wear in tubes throughout both units’ steam generators, which had been replaced in 2009-10. It looked as if it might take years for federal nuclear regulators to approve fixing and restarting the units, so SCE and the other co-owners of SONGS decided it was better to pull the plug on them and work with state regulators to plan for replacing their output and reworking parts of southern California’s transmission system to keep the grid on an even keel without the nuclear capacity. As a result the power-supply situation in the LA Basin and San Diego this past summer was dicey, with utilities worried that the loss of a key transmission line or big gas-fired unit during a heat wave could cut off power to hundreds of thousands or even millions of customers.

It seems like everybody and his uncle are planning new methanol production capacity in the U.S. The economics certainly are compelling. Low natural gas prices are attracting methanol projects like a magnet, especially to the Gulf Coast; domestic and foreign demand for methanol is rising; and methanol prices are as high as they’ve been in five years. But companies are always looking for an angle, a competitive edge, a chance to make their project the most cost-efficient—and profitable—of all. Today, in “Cheap Trick: ‘I Want You to Want Me(thanol)’”--we consider Valero Energy’s methanol initiative and its cheap trick: a plan to add 1.6 million to 1.8 million tons per annum (MMtpa) of methanol capacity for an investment of only about $700 million. That’s around half what it would normally cost.

Chemicals, gas-to-liquids (GTL), steel and other industries that consume large volumes of natural gas either directly or as a fuel, expecting the new era of low and stable gas prices to continue are planning tens of billions of dollars in new or expanded facilities in the U.S. But how many of those plans will become a reality? Could the much-anticipated industrial renaissance be undermined by the higher gas prices that might come with the approval of a few more LNG export terminals, new environmental regulations that spur still more gas-fired power generation, and higher natural gas exports to Mexico? Those are critically important questions to gas producers and marketers, who are struggling to figure out just how quickly—and how much—demand for gas will rise. Today we continue our exploration of industrial demand for natural gas.