Natural gas producers in Western Canada are still struggling to find new markets to replace those they’ve lost to Marcellus/Utica producers in recent years. It hasn’t been easy, and they certainly haven’t been helped by the high cost of transporting gas to Ontario and the Upper Midwest, by the failure of LNG export projects in British Columbia to advance, or by the collapse of oil prices that has slowed growth in the oil sands sector (a huge consumer of gas). Despite the gloom, though, there are at least some rays of hope. TransCanada is considering big cuts in pipeline tolls in exchange for commitments to long-term deals. It’s also possible that at least one BC LNG export project may become a reality by the early 2020s. And some gas producers in the Montney shale region in the Canadian Rockies are focusing on areas where they also can produce vast amounts of condensate for use as diluent in the nearby oil sands region. Today, we provide an update on the ongoing (and often frustrating) efforts to expand gas production in BC and Alberta.
The latest natural gas transaction data from the Federal Energy Commission (FERC) shows the natural gas market is increasingly relying on published index prices for transacting physical volumes for day-ahead and month-ahead deliveries. Index prices — volume-weighted averages of all eligible prices reported to index publishers by location — are considered representative of the market and mitigate some of the perceived price risk associated with “fixed-price” deals, in which the price is independently negotiated between counterparties. But in order to make their indices representative and grounded in market reality, publishers — or price reporting agencies (PRAs) — rely strictly on prices from those independent fixed-price deals to set the index in the first place. As more of the deals done are based on index, what happens to the index itself? Today, we continue our review of natural gas transactional data and what it says about how the market is evolving.
Over the past five years, essentially all of the growth in U.S. natural gas production has come from the Marcellus/Utica shale regions in the Northeast, constrained only by takeaway capacity, and as of 2015 the region began producing more gas than it can consume almost all year round. There are about two dozen pipeline projects planned to come online totaling nearly 17.5 Bcf/d over the next few years to help Northeast producers target demand in other regions, namely growing power generation demand, LNG export markets along the U.S. Gulf Coast, (see Back Down South), and Mexico via Texas. But since mid-2014, drilling activity has slowed dramatically across the U.S., including the Northeast, and output in Marcellus/Utica has flattened out. Is it possible that the market is headed toward an overbuild situation in which Northeast takeaway capacity will end up far exceeding regional production? That has certainly happened in just about every other segment of the U.S. energy market — from pipes moving gas east out of the Rockies and Texas, to crude by rail, to crude oil pipelines to the Gulf –– with important implications for the market. Could it happen in the Northeast? Today, we begin a series on the prospect of an overbuilt Northeast gas market.
Until a few years ago, a good bit of the natural gas produced along the Gulf Coast was piped long-distance to warm homes and businesses in the Northeast and the Midwest. Now, though, cheap-to-produce Marcellus and Utica shale gas has come to dominate gas heating and power markets from Boston to Cleveland, and Northeast-sourced gas is starting to move into Louisiana and Texas, competing head-to-head with Gulf Coast production. With Marcellus/Utica gas production in ascendance, what will be the fate of all the gas still being produced along the U.S. Gulf Coast? That’s the subject of RBN’s latest Drill Down Report, highlighted in today’s blog, which describes the battle lines being drawn and the important roles LNG exports and Mexican demand will play in keeping U.S. gas markets in balance.
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.
Crude oil has always been the big draw for producers in the Permian –– and in the especially prolific Delaware Basin within the Permian –– but the wells there also produce large volumes of “wet” natural gas that needs to be gathered, processed and transported to market. A lot’s been written about the Permian’s still-strong oil production and the infrastructure developed to support it; we’ve also covered natural gas liquids (NGLs) in the play. Now it’s time to delve into the gas processing and gas pipeline capacity out of West Texas and southeastern New Mexico, including pipes into the increasingly important Mexican market. Today, we discuss recent developments on the gas side of the U.S.’s hottest (remaining) oil production area.
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.
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.
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.
A few weeks back Rusty Braziel sat down with Don Stowers, Chief Editor of Pennwell’s Oil & Gas Financial Journal, to talk about the big picture – some of the most important issues facing the oil and gas industry, the lasting impact of the Shale Revolution, and Rusty’s thoughts from 40-plus years in the energy business. It turned into the cover story of their June 2016 issue. Today, we recap a few of the interview questions. You can download the full article (along with Rusty’s smiling face on the cover) at the bottom of the blog.
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.
After the $5 billion-plus expansion of the Panama Canal is dedicated this Sunday, June 26, the first “New Panamax” vessel scheduled to pass through the canal’s new, longer, wider locks will be the Lycaste Peace, a Very Large Gas Carrier (VLGC) that is transporting propane from Enterprise Products Partners’ Houston Ship Channel export terminal to Tokyo Bay in Japan. What remains to be seen, though, is how many other supersized vessels carrying propane, liquefied natural gas (LNG) or other hydrocarbons will follow, and how soon. Today, we mark the formal opening of the newly enlarged Atlantic-Pacific short-cut with a look both at the game-changing potential of the expanded canal and the realities of today’s energy and shipping markets.