Natural Gas

Early in 2012, soon after Japan’s Fukushima disaster, two California nuclear power plants called SONGS 2 and SONGS 3 (stands for San Onofre Nuclear Generating Station) shut down for the foreseeable future.  This pulled roughly 2,200 MW of base load generation out of the Southern California supply stack. The California System Operator (CAISO) scrambled for several weeks to bring replacement power into the system, and succeeded admirably.  The grid held together and weathered last year’s hot summer.  Now as the summer of 2013 starts to come into focus, there are lots of questions about the SONGS units –which are still off line – and what California’s overall power generation load will mean for natural gas demand and prices.  Today we survey the measures that made things work last year and examine the most likely market developments expected for Summer 2013.

Last year natural gas power burn increased by 6 Bcf/d over 2011. This year power burn levels in the first quarter were down 10 percent from 2012. Peabody Energy reported last week that coal consumption for generation is growing this year versus 2012. Today we ask whether 2012 power burn was an anomaly and what we should expect in 2013.

Last week (April 9, 2013) South African firm SASOL held an investor strategy day in New York. The company confirmed it is moving ahead with plans to build a 100 Mb/d gas-to-liquids (GTL) plant in Lake Charles, LA. Shell is evaluating plans for a similar plant in LA. The plant feedstock will be up to 1 Bcf/d of dry natural gas and output will be very low sulfur diesel, naphtha and liquefied petroleum gas (LPG). A year ago in April 2012 the economics looked very positive because of the wide spread between gas prices and refined products but the margins have narrowed since then. Today we look at prospects for this plant and others like it.

These days natural gas can be traded in spot, term, or financial at over 120 locations across the US. Deals can be executed by Apps, by instant messages and by high-speed algorithm. And it is reported that a few human beings actually still trade gas bilaterally over the telephone as was done in the time of the Cro-Magnons. None of that would be happening without the big bang. Today we recall how the dust settled after the big bang in natural gas markets.

Storage, the great balancing mechanism of the natural gas market in North America is heading toward another evolution in its usage, flow patterns and economics.  Not too many years ago, natural gas storage was the hottest midstream investment opportunity going, expected to synchronize inbound flotillas of LNG imports with seasonal domestic demand.  Winter vs. summer price differentials were wide, prices were volatile and storage economics looked great.  When shale gas happened, those differentials evaporated along with storage economics.  Today another phase looms for natural gas storage as Marcellus and now Utica production ramp up on top of (or more accurately, underneath) the largest storage region in the world – the Northeast U.S.  This is a big topic with big implications.  So rather than jumping into the middle of the upcoming gas storage transformation, we will walk through a multi-part North America natural gas storage blog series -  its history and status, its challenges, who’s involved, and finally what could be in store going forward.  Today we’ll start with some natural gas storage basics.

Earlier this week (see Spring, Spring, Spring is in the Air) we looked at the US natural gas supply demand picture. Our analysis focused on the 25 percent run up in NYMEX natural gas futures prices to $4/MMBtu this year (they have since slipped back to close yesterday at $3.90/MMBtu). Prices rose because high winter demand helped demolish a huge gas storage surplus that hung over the market and depressed prices since last spring. The market should not forget however that for a time last year – with prices below $2/MMBtu and Lower 48 dry gas production through the roof - there was talk of hitting the “storage wall”. A sharp increase in power burn soaked up 6 Bcf/d of natural gas last summer and helped the market out of that scrape.

Last Thursday (March 28, 2013) the CME Henry Hub natural gas futures contract closed out the first quarter of 2013 at $4.024/MMBtu (prices slipped 0.9 cents to $4.015/MMBtu Monday). A year ago the futures price was $2.126/MMBtu – about half what it is today. During that same period, US dry gas production has risen by 0.5 Bcf/d to 64.1 Bcf/d and natural gas power burn has fallen by 2.2 Bcf/d (source: Bentek). With production still increasing and demand from power generation falling it seems unlikely that the market can sustain $4/MMBtu prices. Today we look at the supply demand picture at the end of the winter season.

Over the past two years, natural gas production from the Appalachian region has soared with growth in the Marcellus pushing total production beyond 10.5 Bcf/d.  Just next door the Utica Shale is coming into focus with attractive economics due to the natural gas liquids, crude oil and condensate production.  The looming question is natural gas takeaway capacity.  With Marcellus production continuing to grow and Utica supplies coming on, production in the Northeast will soon exceed regional consumption and will need to be moved out of the region to other markets in the U.S. and Canada.  To accomplish this, new pipelines have been proposed and reversals of existing infrastructure that was originally built to transport gas into the region are being implemented. Today we review another of the proposed projects.