It’s so ironic. New England is only a stone’s throw from the burgeoning Marcellus natural gas production area, but pipeline constraints during high-demand periods in the wintertime leave power generators in the six-state region gasping for more gas. Now, with only minimal expansions to New England’s gas pipeline network on the horizon, the region is doubling down on a long-term plan to rely on a combination of gas liquefaction, LNG storage, LNG imports and gas-to-oil fuel switching at dual-fuel power plants to help keep the heat and lights on through those inevitable cold snaps. Today, we discuss recent developments on the gas-supply front in “Patriots Nation.”
This past winter’s gas price spikes shined a bright light on the changing dynamics driving Eastern U.S. natural gas markets, especially the growth in gas-fired generation that is contributing to more frequent — and more severe — spikes in gas prices in the region on very cold days. There are other changes too. For one, gas is increasingly flowing from the Northeast to the Southeast as prodigious Marcellus/Utica production growth is pulled into higher-priced, higher-demand growth markets. In today’s blog, we conclude our series on ever-morphing gas markets on the U.S.’s “Right Coast” by examining how gas pipeline flows back East have changed on days besides the winter peaks, how much demand could be unlocked by forthcoming pipeline projects, and what that new demand will mean for flow and price patterns.
The worst of this winter’s cold has passed, but the impact of structural changes in U.S. power generation will be felt in natural gas markets for years to come. The generation mix has been changing rapidly in recent years, and the switch from coal to gas is happening at an even faster pace on the East Coast than in the country overall. This switch reflects both coal-plant retirements and ongoing competition between remaining coal plants and gas plants. But low-cost gas supplies in the Marcellus and Utica plays don’t always have ready access to the biggest consuming markets, and this winter, we saw how the increasing call on gas for Eastern power generation can stress the gas pipeline grid and cause price blowouts. Today, we continue a series on Eastern power generation and prices by untangling the sources and drivers of gas-fired generation growth in the region.
After a three-year hiatus, winter returned to the U.S. natural gas market this year in the form of a “Bomb Cyclone” and more than a week of frigid temperatures. The cold weather pushed Henry Hub prices above $6/MMBtu and East Coast prices higher than $100/MMBtu on some days. This winter, the pain wasn’t just confined to New England. Prices at Williams’ Transcontinental Gas Pipeline (Transco) Zone 5, which includes the Carolinas, Virginia and Maryland, hit all-time highs on January 5. Exports from Dominion’s Cove Point terminal in Maryland are only just getting started so it’s not liquefied natural gas (LNG) exports from the East Coast that are driving prices higher. Instead, it’s gas’s increasing role in winter power generation that has been putting pressure on East Coast gas pipeline deliverability. Today, we begin a series explaining why prices have been so high on very cold days this winter and why more price spikes may be ahead.
This winter will be the last go-round for ISO New England’s Winter Reliability Program, under which the electric-grid operator in the natural gas pipeline-challenged region provides financial incentives to dual-fuel power plants if they stockpile fuel oil or LNG as a backup fuel. This coming spring, a long-planned “pay-for-performance” regime will go into effect, and gas-fired generators that can’t meet their commitments to provide power during high-demand periods — such as the polar vortex cold snaps that hit the Northeast in early 2014 — will pay potentially significant penalties. Today, we discuss the pitfalls that the pipeline capacity-challenged region may encounter as its power sector becomes increasingly gas-dependent.
Several large-scale gas pipeline expansions targeting the New England and New York City markets have been sidelined in the past year, either due to insufficient financial backing or the challenges of regulatory rigmarole in the region. But in recent weeks, a couple of smaller-scale projects along existing rights-of-way have managed to cross the finish line, allowing incremental gas supplies to trickle into the region. The new pipeline capacity will provide natural gas utilities and power generators in the region with greater access to additional gas supplies from the nearby Marcellus Shale this winter. Today, we look at recent capacity additions and their potential impacts.
It’s no secret that the political and regulatory environments for new pipeline development in New York and the New England states are notoriously challenging. That reputation has been reaffirmed recently, as several natural gas pipeline projects targeting the region have been sidelined by permitting delays or denials. As a result the region continues to experience gas transportation constraints and price spikes during peak demand periods. But midstreamers have had some success penetrating the New York City metropolitan market (including the Lower Hudson Valley, Long Island and northern New Jersey), which may bode well for the handful of projects currently looking to serve the area. Today, we review recent and planned capacity additions into The Big Apple and its greater metro area.
So far, relatively mild weather this winter has insulated New England natural gas consumers from pipeline capacity-related price spikes that occurred during cold snaps in previous winters. And even if another polar vortex were to happen, it’s likely the regional electric grid operator’s Winter Reliability Program to shift gas-fired generators from pipeline gas to stockpiled oil or LNG would keep the lights on. But New England’s day of reckoning is coming. The region is becoming ever-more dependent on gas-fired power, most gas pipeline projects into New England are stalled or scrapped, and New York’s recently announced plan to close two Indian Point nuclear units will only make matters worse. Today we discuss the still-widening gap between Northeast pipeline capacity and gas demand.
Natural gas utilities and power generators in southern New England will have access to additional gas supplies this winter as Spectra Energy brings its 342-MMcf/d Algonquin Incremental Market (AIM) project into service. But Kinder Morgan’s planned 72-MMcf/d Connecticut Expansion has been set back a year (to November 2017) due to permitting delays and, more important, a multi-state effort to enable electric distribution utilities (EDUs) to contract for gas pipeline capacity for generators appears to have died, and with it prospects for at least one major project. Is New England destined to remain gas-supply constrained for years to come? Today we consider recent developments regarding gas supply in the northeastern corner of the U.S., and what they may mean for Marcellus/Utica producers.
California and New England are two of the nation’s quirkier regions when it comes to energy –– and we mean that in the nicest way possible. So maybe it’s not too surprising that, at a time when the U.S. is just beginning a big push to export natural gas as LNG, the Golden State and “Yankeeland” (as some still refer to New England) are turning to imported LNG to help them deal with possible gas shortages during peak demand periods this coming winter. In neither case is liquefied natural gas considered to be a long-term fix, but –– for now at least –– LNG may be playing a role in keeping the pilot lights lit and the electric lights on. Today, we look at how the stockpiling and use of LNG can still make sense in a nation with an abundant supply of gas.
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.
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.
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?”
U.S. natural gas production growth has spurred a massive build-out of natural gas pipeline capacity in recent years, and a lot more is on the way, particularly out of the Northeast. To Marcellus and Utica producers eager to improve returns on their investments, this incremental pipeline capacity is a long-overdue relief valve for the pressure that’s been building in the region from growing supply congestion and low prices. But pipeline development is an expensive, long-term endeavor, and few, if any, pipeline projects are slam-dunks. Also, market conditions initially driving the development of new takeaway capacity may change, putting a project’s relevance—and, in turn, its utilization and profitability—at risk. In today’s blog, we begin a look at how midstream companies and their potential shippers evaluate (and continually reassess) the economic rationale for new pipeline capacity in today’s very changeable markets.
More than 3,000 MW of new, natural gas-fired generating capacity is either under construction in New England or will be soon, but some of the gas pipeline projects that would ease long-standing constraints into and through the six-state region have hit rough patches. Kinder Morgan in mid-April suspended plans for its Northeast Energy Direct project, a “greenfield” pipeline across Massachusetts and southern New Hampshire, and a few days later the state of New York denied the co-developers of the already-delayed Constitution Pipeline—a key link between the Marcellus and New England--a needed water quality permit. The fates of some other major projects in the Northeast are uncertain too. Today, we provide an update on pipelines in the land of Yankees and Red Sox.