After averaging more than a nickel below Henry Hub all this year, the California Border natural gas price spiked to 66 cents/MMbtu above Henry on Friday. This kind of price volatility is no surprise to anyone following the radical shifts in California energy markets, starting five years ago when the state legislature enacted its 33%-by-2020 renewable portfolio standard (RPS) law. By mid-2015, more than 14,000 MW of new solar and wind power had pulled down gas demand in California to the point that natural gas prices at the SoCal Border were averaging a negative basis to Henry Hub. Still not satisfied, last year California legislators voted to establish a 50% renewables target for 2030. On top of it all, the West Coast was coming up on a La Niña year that would bring more rain –– and hydroelectric generation –– to the Pacific Northwest and eventually into California. With all that renewable power (solar, wind and hydro), California seemed headed for an unprecedented period of low gas prices, but it did not turn out to be so simple. In today’s blog, we continue our look at California’s power and gas markets with the events and drivers that shaped late 2015 and the first six-plus months of 2016, and consider what’s to come.
California energy markets look quite a bit different today than they did five years ago when the state enacted a renewable portfolio standard (RPS) law that requires every utility and other electricity retailer to serve 33% of their load with renewable energy by 2020. Since then, California has seen huge changes in its energy balances – it shut down the nuclear generating plants at San Onofre, regulators expedited the build-out of new transmission lines to get more wind and solar power into the market, the state implemented a carbon cap-and-trade program, the legislature increased the RPS target to 50%, and SoCal Gas’s Aliso Canyon natural gas storage facility sprung a leak. Today, we look at the changes in California’s energy markets since 2011, and what they mean for future developments in a state far out front in the adoption of renewables and environmental regulation.
Energy Transfer Partners (ETP) is the nation’s second-largest master limited partnership (MLP), with a market capitalization of $19.6 billion, $39.7 billion in 2015 revenue and $8 billion in 2015 capital investments. ETP’s general partner is Energy Transfer Equity (ETE), whose once-promising merger deal with Williams bit the dust in June. ETP’s extensive holdings include several major interstate and intrastate natural gas pipelines, midstream natural gas services, and natural gas liquids (NGL) pipelines and services; it also holds approximately 27.5% of the limited partner interests and all of the general partner interest in Sunoco Logistics Partners (SXL). With ETP’s size, its huge portfolio of midstream assets, and its high-profile general partner, the MLP was an obvious choice for our Spotlight Report series. Today we summarize Part Two of our ETP Spotlight Report, which focuses on the company’s Midstream and Liquids segments.
Since the first LNG ship left its dock in February, Cheniere’s Sabine Pass LNG terminal has exported 17 cargoes containing the super-cooled, liquefied equivalent of over 50 Bcf of natural gas from the first of six planned liquefaction “trains.” And in a monthly progress report filed with the Federal Energy Regulatory Commission last month, Sabine Pass said it expected to begin loading a commissioning cargo from Train 2 in August, with commercial operation of that facility starting as early as September. In today’s blog we provide an update of Sabine Pass’s export activity, as well as the impact on the U.S. gas flows and demand.
Published index prices are the mainstay of most energy commodity markets. That is certainly true of U.S. natural gas. Of all natural gas deals done in the U.S. last year, almost 80% of the total transaction volume was priced based on an index published by one or more of the industry trade publications covering U.S. gas, such as Natural Gas Intelligence, Platts and Argus. But there could be a problem brewing. For publications to compute an index price there must be enough deals reported that are NOT priced on an index - called an “outright” or “fixed” price. If all, even most deals are done at an index price, there can be no index. Does that sound a bit circular? Well it should. In today’s blog we delve into the sometimes arcane world of commodity index pricing. Arcane maybe. But with $150 million in U.S. natural gas moving each day based on index deals, it is worth understanding how all this works, and how things could go awry. Fortunately, it is possible to know quite a bit about how the U.S. natural gas market uses index transactions.
We talk a lot here in the RBN blogosphere about the bearish market effects of the Shale Revolution, and frequently highlight the U.S. Northeast natural gas region — rapidly growing gas production from the Marcellus/Utica; oversupplied, trapped-gas conditions; and resulting regional price discounts. These dynamics are driving massive investments in pipeline reversals, expansions and new capacity to move the gas to market. Northeast producers are counting on that increase in takeaway capacity to relieve price pressure and balance the market. But all this gas moving out of the region needs a home. Fortunately, new demand is emerging, from exports (to Mexico and overseas LNG) and into the U.S. power sector. One of the big growth regions is the U.S. Southeast, where power utilities are investing heavily in building out their fleet of gas-fired generation plants and are banking on this new, unfettered access to cheap Marcellus/Utica gas supply. Today’s blog provides an update on power generation projects coming up in the southern half of the Eastern Seaboard, based on a recent report by our good friends at Natural Gas Intelligence — “Southern Exposure: Gas-Fired Generators Rising in the Southeast; But Will Northeast Gas Show Up?”
With liquefaction capacity and supply of liquefied natural gas on the rise and LNG demand flat, prices for super-cooled, liquefied gas are low and may well stay low into the early 2020s. That’s a concern for LNG suppliers, who (like all suppliers) would prefer it if demand was soaring and supply was a little tight. There are some rays of hope, though, in what many have seen as a gloomy time for the LNG sector. After all, with spot LNG prices below $5/MMBtu (far lower than they were 30 months ago) and ample supplies of LNG available, a growing list of nations are looking either to become LNG importers or to significantly expand their LNG imports. Today, we continue our review of the LNG market with a look at the new demand that may be spurred by supply surpluses and low prices.
June was somewhat of a game-changer for the 2016 U.S. natural gas market. Summer weather finally arrived and U.S. consumption, particularly from power burn, was at record highs, as were exports to Mexico. Meanwhile, production volumes sagged, flattening and even declining versus year-ago levels in recent weeks. The market response to all of this was swift. The CME/NYMEX Henry Hub prompt futures contract ripped nearly $1.00 higher over the last five weeks to flirt with the $3.00/MMBtu mark.
The international market for liquefied natural gas (LNG) is in the midst of a wrenching transition. The old order, founded largely on long-term, oil-indexed contracts that called for certain volumes of LNG to be delivered by specified Point A to specified Point B, is being replaced by a new order characterized by intense competition among suppliers, new sources of supply (and demand), a glut of liquefaction capacity expected to last at least a few years, more spot purchases, and contracts incorporating destination flexibility—and, for many, tied to natural gas (not oil) prices. Today, we continue our exploration of the industry’s fast-changing dynamics with a look at the fierce battle now under way among LNG suppliers for market share, and at new approaches to pricing LNG.
It’s no secret that a long list of pipeline projects have been proposed to help move natural gas out of the Northeast production areas. But if you were a Marcellus or Utica producer, how would you decide whether you were interested in new capacity that hadn’t been proposed or built yet? Of course, pipeline companies have armies of engineers, cost estimators, and market analysts to bring one of these monster projects to fruition. But for anyone else, particularly in the early stages, how do you even know it’s a reasonable idea? For anyone testing a concept, you need a way to ballpark some scenarios for a new pipe. We’ve been running a blog series on our RBN Pipeline Economics Estimation Model, a quick, rule-of-thumb “sanity test” for new capacity. Today, we wrap up our walk-through of the model, with a real-world example to gauge the accuracy of the model, and then with a discussion on how the model can be used to measure economies of scale in picking the minimum volume you probably need for a new pipeline.
Over the past 20-some days, U.S. natural gas prices have gone from being the lowest in more than a decade to very close to last year’s levels. The July 2016 CME/NYMEX Henry Hub natural gas futures contract on Thursday (June 23) settled at $2.698/MMBtu, up about 70 cents (36%) from where the June contract expired ($1.963/MMBtu on May 26) and also up nearly 50 cents (23%) from where the July contract started as prompt month on May 27 (at $2.169). Market buying to unwind short positions initially kick-started the rally, but since then hot weather and a boost in power demand has kept the rally going. National average temperatures have averaged nearly 8 degrees (Fahrenheit, or F) higher in June to date versus May, and in the past week they’ve climbed above the peak summer levels normally not seen until mid- to late-July. Gas consumption on a temperature-adjusted basis also soared in the first half of June, led by power burn (gas use for power generation). The combination of hot weather and higher gas usage per degree of demand has been practically made-to-order for the oversupplied gas market, and has led to record power burn in June to date. But higher prices have the potential for bearish consequences—the recent gains have catapulted natural gas prices well above prices for coal on a cost-per-MMBtu basis—making the latter fuel more economically competitive in the power generation sector. That’s welcome news for coal producers, but what will it do to natural gas demand and in turn gas prices? Today, we look at the shift in the coal-gas price relationship and the potential impact to power burn and the gas market.
New and expansion natural gas pipeline projects have been part and parcel of the shale production boom in the U.S. Northeast. In fact, Northeast gas production could not have reached anywhere near its current level and become a major natural gas supplier to the U.S. without the substantial addition of takeaway capacity out of the Marcellus/Utica shale areas. At the same time, the competition among pipeline developers jockeying to be in the right place at the right time has been fierce. And now, low natural gas prices and uncertainty about future production growth have only increased the competition---not all projects will make it to in-service. The risks are higher for big pipeline projects, but so are the stakes. These days, the overall risk tolerance among shippers and investors is low, especially among producers. So if you’re a producer, how can you make sure you don’t end up on the wrong side of a transportation deal? In today’s blog, we continue our walk-through of the RBN Pipeline Economics Estimation Model. We’ll follow up in a later installment with a real-world test and other ways to use the model.
It’s been two years since Hawaii’s electric and natural gas utilities made their first, tentative moves toward ending their dependence on crude oil (for power generation and the production of synthetic natural gas) by shipping in liquefied natural gas (LNG) from western Canada and the U.S. mainland. While Hawaii Gas has secured state regulatory approval to ramp up the number of LNG-filled ISO containers it receives, the gas utility and Hawaiian Electric have so far failed to agree on a comprehensive LNG plan. Also, some state officials remain concerned that simply replacing oil with LNG will undermine Hawaii’s plan to get all its electricity from renewable sources by 2045. Today, we provide an update of the Aloha State’s fits-and-starts transition to LNG.
The U.S. Energy Information Administration (EIA) on Thursday (June 9) reported a surprisingly bullish 65-Bcf injection for the week ended June 3—that was 8.0 Bcf below our Natgas Billboard estimate and more than 10 Bcf below the Bloomberg industry average assessment. In response, the CME/NYMEX Henry Hub July natural gas contract screamed about 15 cents higher following the report to a settle of $2.617/MMBtu, the highest daily settle for the prompt month in nearly 9 months. Thursday’s gains extended a rally that began on May 31 (2016) just after the July contract rolled to the front of the futures curve. It’s likely the rally was initially spurred by market participants looking to cover their short positions. But in the past week, an increasingly bullish fundamental picture has emerged prompting us to raise our price outlook (in our June 10 NATGAS Billboard report). In today’s blog, we analyze the fundamentals behind rising natural gas prices.
We’ve spent a lot of time here in the RBN blogosphere discussing the trials and tribulations of natural gas producers in the Marcellus and Utica shales who are “trapped behind the pipe,” unable to get sufficient takeaway capacity to move supply to market (both within and outside the U.S. Northeast region) where they could get a higher price for their gas. Pipeline companies have ponied up billions of dollars to build lots of pipe to alleviate these constraints and much more investment is planned. Of course, those pipelines and their committed shippers hope that the investment will pay off long-term – that the economics for building the pipe will justify the cost. The pipeline will have scores of engineers, lawyers and accountants to figure that out. But what if you just want to make a quick-and-dirty estimate of the economics? Well, there is a way. In today’s blog, we walk through the factors you need to consider when your boss runs in and asks, “Hey—what would it cost to move gas there in a new pipe?”