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It’s been an interesting year for the midstream as the industry continues to largely perform well in the midst of a price downturn. Much of this insulation from price movements is due to midstream assets having fee-based contracts that mitigate exposure to commodity prices.
Storage has been a key component in allowing producers to keep some of their production out of the market, but the large overhangs in gas, liquids and crude storage are further preventing price improvements.
The big question on everyone’s mind is when are prices going to turn around? But the real question is: When does demand return?
The current downturn isn’t so much akin to supply racing ahead of demand as it is to supply racing so far ahead of demand that it lapped it. In many ways the old conventions aren’t applicable: drilling efficiency has gotten to the point where the U.S. Energy Information Administration (EIA) and industry analysts are no longer relying on rig counts to forecast production output.
Instead, rig releases have grown in importance in determining the number of wells being drilled across the country.
While the outright rig count can decrease, producers are now able to drill the same amount of wells, or even more wells, by cutting their drill times.
“Producers are getting better and better all the time at what they do—they’re drilling faster and getting more volumes out of every well. What that means is that as we wait for demand to pick up, we’re also lowering the cost of production and the cost to bring on incremental volumes of gas, liquids and crude,” Bernadette Johnson, managing partner and director, research and analytics at Ponderosa Advisors LLC, told Midstream Business.
There are long-term positives for demand, particularly natural gas, as new facilities come online in the next five years. Lower crude prices may negatively impact this demand as the spread between crude and gas prices narrows. This will make projects tied to crude not look as good as they were before the price crash. However, it is expected that most of these projects will still be built at some point.
All eyes on gas storage
Johnson said that low prices are primarily short-term concerns until winter demand increases to help shave off some of the production overhang. Until then, the focus will remain on storage and the natural gas sector’s ability to absorb extra volumes.
“Natural gas storage is tracking pretty close to the five-year average, but since we’re producing at such a high level there will be increased downward pressure on prices,” she said. “It’s similar to what we’ve seen the last few years where high storage levels mean prices have to drop to incentivize coal to gas switching and other demands. Once winter shows up the problem is greatly alleviated.”
New rules for propane
Then there are the gas liquids. The NGL barrel is a much different animal than its crude oil counterpart. For one thing there isn’t a physical NGL barrel, rather a weighted composite value of the five NGL streams in a 42-gallon barrel (bbl). They are then divided into two classes: light and heavy products.
While heavy NGL values are typically more closely related to West Texas Intermediate crude prices, light NGL values are a little different. Ethane is aligned with natural gas prices and the other light NGL, propane, is influenced by both gas and crude prices. Consequently, the bottom is being created by the next lowest product in the barrel for liquids.
This dual influence has historically helped propane maintain solid prices, but like many hydrocarbon markets in a post-shale gale world, things have changed. Propane prices have been especially difficult to forecast with market trends vastly different than in the past. It’s hard to believe that after the polar vortex and Arctic chills in winter 2013 to 2014, which saw heating demand and gas and propane prices spike, that propane storage would reach record levels 18 months later. This, despite the strength of LPG exports during the same time frame.
In many ways, producers have gotten too good at doing their job. Supplies can be replenished much faster than in the past, and it is no longer seasonal heating demand, but exports that will drive propane prices.
The export option
Because propane is a seasonal product, it is hard to work off excess supplies outside of the peak demand season. The good news for propane is, that unlike crude oil, NGL and condensate can be exported.
“We’ve reached the point where exports will have the biggest impact on propane prices,” Robert Hain, managing director, En*Vantage Inc., said during Morgan Stanley’s “NGL State of the Union” webinar. In addition, he stated that the market must adapt to this new reality of excess supply and new transportation flows.
As an example, he noted that the Edmonton, Alberta, market has been weakest for propane, with the price at zero or below at various points this year.
“Some producers didn’t quite understand the situation with the Cochin Pipeline moving from propane to condensate. This made it so that rail was the only real way to transport propane out of the region. Those that were fully aware of the situation leased their rail cars early,” he said.
However, even this preparation has its own headwinds as the Hattiesburg, Miss., rail terminal embargoed incoming rail cars due to traffic congestion caused by increased propane cars. This resulted in propane being burned as a fuel in western Canada.
Unlike ethane, propane cannot be rejected, which means that the product does not have the same safety mechanism built into the market. “I don’t think there’s a limit on how low propane prices can go because gas has to recover propane. So unless producers cut back or bypass gas, which I don’t think they’ll do, the price can only go lower if production is increased,” Hain said.
Creating a structured environment
Ethane is tracking closer to natural gas as the market is also awaiting structural demand to arrive since it isn’t a seasonal product, but instead dependent on petrochemical demand.
“While we’re waiting for new crackers to come online in the next few years, I think prices could hover around 18 to 20 cents per gallon (gal) until the cracker demand shows up or gas prices increase and bring ethane prices up with it,” Johnson said. She added that the upside for ethane prices is likely to be capped at a high of 25 to 29 cents per gal until more cracking capacity comes online in 2018 since the market is so long.
Though demand may be somewhat muted, it is important to note that these forecasted prices represent the beginning of a recovering market as they would cover transportation and fractionation costs to Mont Belvieu, Texas, and see more ethane being recovered.
While ethane prices will begin their slow recovery this year, natural gas prices will have the most volatility, according to Johnson. “Long term, we don’t think that $2.50 per MMBtu [million Btu] gas is the answer since it won’t incentivize enough supply when structural demand comes online later this decade,” she said.
The Marcellus and Utica shales are exceptions for producers where gas drilling is the focal point, thanks to the proximity to the premium Northeast markets along with tremendous drilling economics in the region that are keeping these plays profitable and active. Not only are the Marcellus and Utica expected to hold firm in production, they are expected to increase. Gas wells in the Appalachian Basin are proving to be more profitable than condensate and crude wells in other parts of the country.
“Ethane will remain at parity with natural gas prices because we have such large volumes of ethane supplies. If ethane exports take off this will increase prices by 5 to 10 cents per gal, which covers fractionation and transport costs to Mont Belvieu. This would allow for more ethane recovery,” Johnson added.
There will be more recovery, but ethane rejection will still continue until more cracking capacity comes online. Since ethane can be left in the natural gas stream when rejected, it doesn’t need to drop any lower than the gas parity price. Though propane can’t be rejected since it can’t be left in the gas stream, it does work off of this aspect as it will almost always be valued greater than ethane.
“Propane could drop as low as ethane, but that would be a short-term situation as propane will generally be priced above ethane because they’re substitutes in the petrochemical sector. When propane prices drop low enough crackers with flexibility will crack propane instead of ethane because of propane’s higher content and the secondary products you get from it,” Johnson said.
Export demand isn’t enough
Even if there is a cold winter with strong heating demand, propane prices will not experience a corresponding increase since the storage level is expected to be a record 96 million bbl this fall. This past winter was certainly a difficult season for both gas and propane prices as they failed to experience the highs of the previous winter and its very cold temperatures, but things could have been far worse for propane without LPG exports.
“Exports saved the day for propane for a while by giving the market some relief until supply grew so much that even exports weren’t enough to absorb the extra volumes. Exports allowedus to send butane and propane to the global market, but at the end of the day, demand is still the deciding factor. If there’s not enough international demand to soak up our incremental volumes, we’re going to see really low prices,” Johnson said.
She noted that exports are not the silver bullet that some were hoping for when they took off two years ago, but are instead just a piece of the puzzle as commodities become more globally linked. Natural gas will begin to become more exposed to global prices as U.S. LNG exports grow. The same holds true for LPG, ethane and condensate exports out of the U.S.
On a long-term basis, exports will help the market perform better as volumes will be directed to areas with greater demand for certain production quantities and qualities, while redirecting other forms of production to markets better able to handle it.
Since ethane prices will work as the floor for propane, they will help the rest of the NGL barrel improve as propane serves as the floor for butane and isobutane, which will in turn serve as the floor for natural gasoline prices. Ponderosa Advisors doesn’t anticipate NGL prices returning to traditional oil-linked levels in the near term because the industry is long on supplies.
This oversupply situation will cause West Texas Intermediate crude prices to remain at $40 to $50 per bbl levels throughout the remainder of 2015. Johnson noted that these prices aren’t high enough to support any global crude production growth.
“We know there will be global crude demand growth and to meet this growth, we will need prices higher than $50 per bbl,” she said. As such, Ponderosa Advisors anticipates a ceiling of $75 per bbl combined with a gas price ceiling of $5.25 per MMBtu, with NGL prices somewhere in the middle.
Unusual crude build
The crude market is a combination of what is being seen with gas and liquids as there are concerns over both storage and infrastructure holding prices back. There had been some optimism surrounding crude prices as they gained steam in the spring, pushing past $60 per bbl, but since that time they’ve gone back down to the $45 per bbl range as summer turned to fall.
“Crude stock levels are really high—typically you don’t see storage builds in the summer and we did. It’s a similar story to gas where we’re already sitting at high storage levels before weak fall demand hits. Fall in the crude market means demand drops and maintenance downtime for refineries as they retool for their winter blends. Maintenance season takes a lot of refinery run capacity offline, which will lead to further builds, and we don’t have a lot of room in storage to absorb it,” Johnson added.
The demand that crude is waiting on is also different because it is global rather than domestic. Though this provides more opportunities, there are additional headwinds. China’s economy isn’t growing as fast as it was previously, which is worrying since much of the growth is coming from Asia. “If China’s growth is slower than we thought just a few months ago, that’s not a good sign for a quick price recovery or for the short- and medium-term outlook,” Johnson said.
The past year has seen crude and NGL prices decouple and while this situation can be expected to reverse as prices improve, Johnson said that some parts of the relationships won’t be returning as fast. “NGL prices used to track more closely with crude, then their relative value dropped, and they have started to track more closely with gas and this will continue,” she said.
While the heavy portion of the NGL barrel is becoming further decoupled from crude, its demand levels are almost completely tied in to crude production. Butane and isobutane are used in gasoline blending while natural gasoline is used as a diluent for oil sands production. As the crude and gasoline markets get longer, heavy NGL prices will drop and be further linked to gas prices via the lighter NGL products serving as their floor.
Storage spreads disappearing
Natural gas has been oversupplied for the last few years, which has consistently raised fears of storage reaching full capacity. This is especially true since seasonal spreads seem to be disappearing, according to Johnson.
“The seasonal spread that used to support the value of storage went away when the market went very supply long. This caused the marketplace to come to the realization that we could bring significant volumes on very quickly and didn’t necessarily need to plan six months in advance with storage,” she said. This has caused storage values to diminish in the past decade and they may never come back to previous levels, which has resulted in only incremental storage capacity expansions.
Despite all of this, there is little chance that storage will hit capacity due to the market’s efficiency, which makes it almost impossible to exceed storage as it will do whatever is necessary to create additional demand.
“We haven’t injected as fast as a lot of people assumed we would this year, but the risk that we will reach capacity still hasn’t gone away. Every year for the past five years, except for when there was a polar vortex, there has been this concern that we’ll exceed storage and we never do because the market sorts it out,” Johnson said.
Avoid the ceiling
The general consensus is that storage capacity is 4.3 trillion cubic feet. To hit this ceiling, storage injections would need steady, strong growth throughout the summer. It is also worth noting that underground storage capacity fluctuates based on injection rates, which makes it difficult to get a handle on the exact capacity level. If the injection rate is steady then there is more capacity.
“I don’t believe we’ll approach gas storage limits this year,” Vincent Piazza, senior energy analyst at Bloomberg Intelligence, told Midstream Business. “We’ll likely see close to four trillion cubic feet of storage by the traditional start of winter, Nov. 1, and those levels won’t help prices, but we’re very far from reaching storage constraints.”
Though they may not have been as fast as some expected, injection rates still exceeded the five-year average during the summer injection season.
Katherine Teller, natural gas analyst at the EIA, said that for the most part, the injection season was pretty uneventful as it stayed on track with expectations.
“We had pretty big gas storage withdrawals this winter, though not as large as the previous winter. Gas prices have remained low and production high, but not as high as previously anticipated due to freeze-offs and weather-related declines earlier in the year,” Teller told Midstream Business.
Teller noted that production has been steady this year despite the decrease in rig counts because of advances being made in efficiencies by producers. This changing landscape has resulted in EIA looking at new factors to determine its storage and price forecasts.
“We try not to look at the rig count at the same importance level anymore. What it means is totally different now that efficiencies have improved so much. At EIA, we try not to focus so much on the overall rig count and instead on where the rigs are at and how much production is coming from them,” she said.
EIA anticipated underground gas storage levels to be 3.956 trillion cubic feet (Tcf) at the end of October and 1.892 Tcf by the end of winter heating season in March 2016, which would be close to normal levels but higher than the last two years since the winter forecast anticipates normal temperatures. In accordance with this storage outlook, EIA anticipates gas prices to remain relatively low throughout 2016 in the high $2 to low $3 per million Btu range with a slight increase in 2017.
Crude in the long term
More worrying is the storage situation with crude and liquids, which both hit record levels this year. While the crude and propane markets will eventually work themselves out, Teller noted it will take some time.
Crude storage is different than gas storage because it isn’t seasonal, but operational in nature where volumes are stored because refineries are undergoing maintenance turnarounds. Crude storage grew so much this year that it caused prices to fall drastically from summer 2014. While lower crude prices have increased gasoline demand, it hasn’t helped support crude above the mid- to upper-$40 per bbl range, which is indicative of a longer-term global oversupply.
On the liquid side, propane inventories have hit record levels and while there is seasonal demand for home heating and crop-drying, these are unlikely to help turn the market back around this winter. “The current inventory levels are unprecedented and the NGL market isn’t as efficient as the gas market. There aren’t as many traders out there looking at supply-demand balance,” Johnson said.
The danger for these markets is that any price improvements will encourage increased production and put more pressure on storage. In addition, prices are very sensitive to any macroeconomic or geopolitical influences in the current environment. This happened earlier in the year when there was hope that prices could shoot above $60 per bbl before they tumbled back to the $40 per bbl range in the face of multiple headwinds from the Middle East and Asia.
“When prices were hovering around $60 per bbl, we heard producers saying if they continued at that level they’d start to add rigs back in the summer, but if you look at the International Energy Agency data, we’re now more long than we were when prices first collapsed. If production activity ramps up in different areas that are currently on hold, or if uncompleted well inventory starts showing up, it will only prolong this low price pain period or push prices down even lower until this supply overhang is corrected,” Johnson said.
The Appalachian Basin is changing the face of the energy industry in various ways: helping the U.S. become energy self-sufficient; changing the Northeast from a demand center to a supply center; and helping the U.S. become an energy exporter. The latest move is resulting in a reconfiguration of the North American midstream industry with pipeline flows reversing north to south and the creation of new infrastructure in the Northeast.
These changes are necessary to handle the huge volumes coming out of the plays, which remain the most economic for producers in the current downturn.
“There is a very substantive structural shift in output growth and that is being driven by the Northeast,” Piazza said. Despite the rig count in the Appalachian Basin being down roughly 32% year-over-year, the combined production out of the Marcellus and Utica have been running an impressive average of 19 Bcf/d. While growth trends remain more muted recently, output remains resilient.
This increases the likelihood that subdued gas prices will continue because gas-on-gas competition will continue as production out of the Northeast will suppress price increases into 2017, Piazza said. This competition will further increase as more pipeline capacity is brought online in the next few years and allow more volumes from across the country move into new markets. Pipeline capacity will increase by 3.6 Bcf/d in 2015, 4.4 Bcf/d in 2016 and more than 20 Bcf/d in 2016 and 2017.
“LNG exports will really need to take off to help tighten supply balances. The amount of industrial and gas generation capacity coming online seems to be fairly well understood, but the question is how much of the excess capacity will be soaked up by LNG exports,” he added. That said, he noted that breakeven prices are wide-ranging not just in regions and states, but even down to individual counties due to production efficiencies and cost concessions.
Getting better and better
“We saw that the Marcellus got better over time since it’s still a young play relative to E&P drilling and it continues to see improvements. I think the same will hold true in other plays as well, including liquids,” Piazza said.
Therein lies the dichotomy: as the industry has gotten better and better at producing hydrocarbons cheaply, demand has yet to keep pace.
It’s tempting to say that the champagne days of the early shale revolution are over, but given the amount of demand being forecast from the Southeast, Northeast and Midwest in the U.S. as well as Asia, Mexico and Europe internationally, it is a safer assumption that the industry isn’t waiting for a bubble to burst as much as the release valve on storage to be opened to these areas.
A lack of storage and pipeline capacity in New England limits ﬂexibility for power generators and other customers.
Go west, young man,” was famously used to describe the U.S. expansion to the West in the 19th century, but for the natural gas industry, this pilgrimage is moving in the opposite direction.
However, unlike the vast openness the American West represented in Horace Greeley’s famous quote, the Northeast is identiﬁed by large populations concentrated in small areas built over centuries. This makes construction of energy infrastructure exceedingly more difﬁcult than in other parts of the country.
New York and New England represent the markets offering both the highest prices and most growth potential in North America for natural gas. However, getting volumes to these markets is proving troublesome, just as the journey that American settlers had in developing the Western states all those years ago.
Near and yet so far
Despite being close to the large amounts of gas produced out of the Marcellus and Utica shales, the industry has found it difﬁcult to take advantage of the Northeast market premiums. These struggles are related to population density, limited infrastructure and opposition from concerned citizens and environmentalists.
Making matters more difﬁcult is that New York and New England utilities are only recently embracing natural gas as a heating and power generation fuel on a large scale. This requires a lot of educational efforts for both utilities and customers as the midstream grows in the region.
Because of the age of many of the cities and towns in this part of the country, their energy sources are as outdated as some of their other infrastructure. Coal and heating oil are the primary energy sources in much of New York and New England, which makes it a prime target to meet greenhouse gas emission reduction goals for regulators and legislators while also securing a theoretically cheaper energy source for local consumers.
Operators in the region have found that not only do projects designed to build gas markets in the Northeast face opposition from environmentalist and others, but also from the NIMBY (not in my backyard) movement. While some people may agree in theory with the need to improve access to natural gas, others oppose construction of new infrastructure designed to improve this access because they deem it too close to their homes, ofﬁces or places of leisure.
Difficult, but not impossible
One of the most interesting aspects of the New England pipeline dilemma is this sociopolitical-driven opposition. “It’s a really unique situation where you have this huge resource base in the Marcellus stranded from a potentially massive market in the northeastern United States. It’s a short distance between the two regions. You wouldn’t see this situation in Russia, China, Japan or even Germany,” Thomas Campbell, director, LNG and gasiﬁcation at Stratas Advisors, told Midstream Business.
Even with these obstacles, the shale gale is slowly but surely making its way into the Northeast as natural gas displaces more and more coal and heating oil in the region. The winter of 2013 to 2014 provided a wake-up call to the region that there was a real need for increased transportation capacity for natural gas into the Northeast.
During that winter’s infamous polar vortex, gas prices spiked dramatically in the Northeast with spot prices approaching $100 per million Btu (MMBtu) in New England from the $4.75 per MMBtu range they had been trading.
There are several reasons for this price spike: limited pipeline capacity into the region with only Spectra Energy’s Algonquin Pipeline and Kinder Morgan Inc.’s Tennessee Pipeline providing access to Marcellus gas into New England; along with the struggles of both New York and New England converting to natural gas and still getting used to securing supplies on an as-needed basis.
“[Securing volumes] is one of the most vexing questions to suppliers and regulators,” Casey O’Shea, spokesman at the Center for Liqueﬁed Natural Gas, told Midstream Business. “If you look at citygate prices [in the Northeast] over the last few winters, you’re looking at supply-constrained areas and there’s a real question over how to meet the demand.”
Reverse course for LNG
The lack of pipeline and storage capacity, especially in New England, that limits ﬂexibility for power generators and other customers has seen the region run counter to much of the rest of North America by continuing to seek LNG imports to secure supplies.
“Having the gas in the ground and producing it is one thing, but you need the infrastructure to get it to market,” Dena Wiggins, president and CEO of the Natural Gas Supply Association, told Midstream Business. “The U.S. Federal Energy Regulatory Commission has been very active certiﬁcating pipelines with 16,000 miles of pipeline in the last 15 years, but not a lot of that has occurred in the Northeast. That was brought to bear in the winter of 2013 to 2014 with the takeaway being it is important to make arrangements to buy gas in advance. You don’t want to wait until the coldest day in January to buy gas.”
GDF Suez Energy North America LLC’s Distrigas LNG terminal in Everett, Mass., has been at the forefront in helping New England customers secure supplies through other means beside pipelines. Though the facility has been in operation for more than 40 years, it is still ﬁnding new uses to help supply natural gas into New England since it is located behind the point of constraint.
The company announced in the second quarter that it had secured its largest contract in more than 25 years as it signed a 10-year deal to sell LNG to New England utilities. GDF Suez will deliver volumes in the summer with it being stored to meet peak demand in the winter. Terms call for the company to deliver an undisclosed utility with 6 billion cubic feet (Bcf) of LNG for this upcoming winter and a minimum of 3 Bcf/year from 2016 to 2024.
“These LNG sales agreements underscore the important role LNG plays in advancing natural gas supply security and price stability for New England—today and well into the future,” GDF Suez North America president and CEO Frank Katulak said in a release.
The importance of such long-term contracts was highlights during the price spike in the 2013-2014 winter – not due to the spike – but because a lot of gas in the region was being bought at a much lower price
“There was a lot of coverage of high prices, but those utilities that made arrangements in advance paid a price based on the [industry standard] Henry Hub price. The volume of gas sold at those high spot price levels was fairly small,” Wiggins said while adding that pipelines were at full capacity from utilities with ﬁrm contracts securing volumes.
While New England utilities typically shy away from long-term, ﬁrm contracts for supplies, both pipeline and LNG operators are offering more ﬂexible options such as short-term ﬁrm and no-notice service contracts to help meet peak demand.
As production out of the Marcellus and Utica shales grows, so does the LNG industry’s interest in the region.
“Last year we saw a lot of interest, activity and proposals start to trickle into the East Coast for LNG,” Campbell said. “This was really the ﬁrst time we’d seen that as Gulf Coast and Paciﬁc Coast lines typically garner most of the attention for LNG projects.”
Impact of exports
It’s hard to tell which LNG export projects will move forward and which will fall by the way-side, but one of the more interesting projects is the Downeast LNG project, which would export 460 million cubic feet per day of LNG from a proposed terminal in Robbinston, Maine. This project seeks to capitalize on the construction of expanded pipeline capacity into the region to deliver volumes for export. However, the project would aim to use a dedicated supply line from either Canada or the U.S.
“The dedicated supply pipeline means that the gas volumes for Downeast LNG project will not interfere or impact the supply of natural gas going to industrial, commercial or residential users elsewhere in New England. Consequently, the export of natural gas from the Downeast LNG terminal is not expected to have any impact on the supplies or the cost of natural gas end users in New England,” the company said in a release.
Downeast LNG also said that the facility would have the capability to provide additional gas to the New England market on peak demand days as it would include a 160,000-cubic-meter storage tank that would operate as a peak shaving facility in winter.
Ironically the nascent LNG market may be hindering the development of new large pipelines into the region as several companies have raised the specter of exporting volumes from New England should enough pipeline capacity into the region be built.
“There are inevitable concerns and backlash if you build a pipeline large enough for LNG exports. At that point, the story changes from ‘We’re building this pipeline for New England’ to ‘We’re also looking to export this gas and raise prices and potentially harm this incentive for cheaper natural gas we’re offering in a roundabout way,’” Campbell said.
While there is understandable apprehension from New Englanders over export projects and their impact on prices, Wiggins said that shale production can satisfy both foreign and domestic markets without going through the growing pains of other countries with newfound domestic production. The fear is the U.S. turning into Australia, in which the dual demands of the LNG export and domestic gas markets overwhelm production and dramatically increase domestic prices.
“We just don’t see LNG exports having a direct impact on domestic prices. There’s a lot of gas that can be produced, and we’re looking for markets right now. We see LNG exports as a market for this production,” Wiggins said.
Indeed, the U.S. Energy Information Administration estimates production will be in the 100 Bcf/d threshold by 2040.
Most of the U.S. LNG will be exported from the Gulf Coast, which will further limit the impact on New York and New England prices as the closest terminal with an export license to these regions is Dominion Resources Inc.’s Cove Point in Lusby, Md. Volumes scheduled to be exported from Cove Point are already contracted, which will provide further certainty to the market through a steady demand cycle for this gas.
Construction of a liquefaction train—Cove Point was built as a gas import terminal—is underway and Dominion expects to ship LNG starting in 2017.
As U.S. natural gas production skyrockets, there has been a rush to export LNG with more than 50 projects submitting applications to the U.S. Department of Energy. However, Campbell cautioned that many of these projects will not see the light of day.
“We’re expecting much less than half of these projects to move forward. Who is going to buy the supplies and at what price? That’s the commercial reality. Even outside of the commercial issues, there are technical and cost issues associated with these plants. I don’t see the East Coast being next up to the plate after this current batch of LNG projects under construction now are completed,” he said.
Instead much of the production from the Marcellus and Utica will be shipped to the Gulf Coast for either domestic consumption from the petrochemical market or to be exported from terminals in that region, or will be shipped to East Coast markets.
“Producers are already moving volumes to the Gulf Coast to export. A lot of this gas does have a place in the LNG market, it’s just not in the Northeast,” Campbell said.
In the end, the aspects that make New England and New York attractive to the LNG market are what make them so attractive to producers in the Marcellus and Utica, and pipelines have more advantages, both technically and economically, than LNG terminals. However, LNG in the last year has gained steam as pipeline hurdles continue.
“There’s a lot of fairly cheap LNG on the market that’s getting moved all over the pace,” Campbell said. “We’re likely to see increased LNG utilization at the Distrigas terminal. The problem is that those volumes are ﬂ owing primarily to areas to the south and west of the region, yet volumes will also be needed for the interior parts of New England. Long term, New England will need a pipeline solution.”
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