As temperatures dropped well below freezing in the Northeast U.S. around Christmas, Bloomberg reported that in New England, natural gas spot prices rose more than threefold to the highest in over three years and “turned the region into the world’s priciest market,” with gas for next-day delivery on Enbridge’s Algonquin system settling at $35.35 per million British thermal units.
A few days later, the spot prices in New England had fallen back to $19.75, as reported by MassLive.
When one considers that the NYMEX price for natural gas on that day was sitting at a few cents above $3/mmbtu, that’s some pretty pricey gas that New Englanders were paying for. Back in the “old days,” i.e., before the advent of the production of natural gas from shale formations, a winter event like this, combined with a storage level that is well within the 5-year range, would have sent that NYMEX price up dramatically, where it would have lingered until things warmed up. But in today’s world, that price represented a rise of barely 10%.
So what, you might ask, is going on in New England? As MassLive reported, the biggest reason for what will be a short-term blowout in natural gas prices for power providers is a lack of pipeline capacity.
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For most of the past year, the ongoing boom in the Permian Basin has sucked all the oxygen out of the room in terms of media reporting on the oil and gas industry in Texas. The mergers and acquisitions frenzy of 2016 raised per-acre acquisition costs to $40,000, and that in turn led a rapid rise in the Permian’s rig count and subsequent drilling boom to take advantage of the higher oil prices that came about at the end of the year. That story, which has resulted in the Permian’s becoming not only the nation’s largest oil producing basin, but also it’s second largest natural gas producing basin (more on that next week), is very compelling and needed to be told.
But the last year has seen another compelling growth story come about in the state’s other major oil play, the Eagle Ford Shale region of South Texas. It’s a story in which the region’s rig count has more than tripled in a year, from less than 30 to more than 90, in which new-well productivity has more than doubled in less than two years, and in which the economic driver that turned this historically poor region into the nation’s hottest economic development area from 2011 thru mid-2014 has begun to rise again.
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The growing glut of natural gas on the global market – spurred in part by increased exports of Liquefied Natural Gas (LNG) by U.S. producers over the last year – reminds us of the dynamic nature of the domestic natural gas market, and the role shifting public policies have played into that over the years.
My own frame of reference here begins during the summers of 1977 and 1978, when I earned college tuition money by taking summer jobs on pipeline crews in deep South Texas. In 1978, the Congress and the Carter Administration had become convinced by some really bad science that the U.S. would actually run out of natural gas in a few decades, and thus needed to conserve what little remaining reserves it had on-hand for home heating usage. Acting on this belief, then-President Jimmy Carter signed into law the Natural Gas Policy Act (NGPA) and the Fuel Use Act (FUA), both of which had major impacts on natural gas markets, and both of which inhibited investment in new natural gas-buring infrastructure.
The NGPA discouraged investment in drilling for new natural gas reserves by allowing the federal government to establish ceiling prices producers could receive for various categories of natural gas that were established under the law. The FUA was even more prohibitive on the demand side of the natural gas ledger, prohibiting utility companies from building new gas-fired power plants. The result? A Democratic Administration ironically actively encouraged the building of dozens of new coal-fired and nuclear power plants all over the United States, many of which are still operating, much to the chagrin of today’s climate alarm lobby.
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