Ira Joseph, head of generating fuels and electricity power pricing for S&P Global Platts, and Ryan Ouwerkerk, manager of Americas natural gas pricing, are joined…
Feb 23, 2021
Ira Joseph, head of generating fuels and electricity power pricing for S&P Global Platts, and Ryan Ouwerkerk, manager of Americas natural gas pricing, are joined by Kelsey Hallahan and Arsalan Syed, pricing specialists from the North American natural gas team, to untangle the historic Texas freeze and subsequent price movements and what it means for US and global gas markets.
Apr 12, 2021
The premier event for power investors and developers. Where energy connects.
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This year’s event will focus on latest trends in power supply and demand dynamics, decarbonization, digitalization, emerging renewable power technology, global power markets investment, power finance, and power asset valuation / M&A.
Feb 22, 2021
Watson talked to Stuart Elliott, editorial lead for European gas and power, about the state of the market and how it is likely to evolve in view of the energy transition. The interview has been lightly edited for clarity and brevity.
In Eurogas, we see the gas market as very strong. And I think we’ve built a very effective, very efficient gas market in Europe. I think it’s something that we can be proud of. It’s the countries of Europe coming together to deliver, I would say, one of the most liquid markets in the world for any type of energy.
We’ve got a great amount of supply. This isn’t just about the domination of one particular partner to our eastern border. We’ve got LNG coming from all over the world. We’ve got the Southern Gas Corridor now coming over from Azerbaijan. This has to be one of the most liquid markets that there’s ever been. There is very strong infrastructure and very effective markets.
Perhaps in Central and Eastern Europe, there’s still work to be done in certain areas. We also see that some infrastructure still needs to be built, but we have the LNG terminal in Krk in Croatia just coming on, there will be another one in Greece soon.
So we’re more or less there, the jigsaw has been made. We’re just putting the last pieces in. And so there is a general feeling across policymakers, regulators, and analysts who see the gas market as one of the best functioning energy markets in the world today.
We have seen a situation that’s been quite unique. I don’t think any of us could have imagined how bad things would get with the pandemic.
And so of course, the pandemic has had a massive impact on the gas market and indeed has led to volatility and a suppression of demand. Nevertheless, we are seeing a rebound, and I think we will see that continue. It may not get back up to the high peaks that we had for gas consumption in Europe in the last few years before the pandemic, but we’ll be around about that mark. And we’ll be set like that for about 10 years.
I want to be an optimist on the pandemic and say, yes, we’re going to get back to some level of normality, and that will mean that the volatility will reduce. And natural gas will definitely be a fuel of the 20s. In fact, you could even argue that it will be the fuel of the decade.
Well, we might have had a pandemic, but the European Commission has been super busy. And yes, this year is going to be a super year of legislation. What we are dealing with is the greenest European Commission there’s ever been. They have a very, very strong push on climate policy.
Needless to say, we are fully engaged on all fronts. When we look at how we see the future of gas, we don’t see it in a vacuum. We see a growing synergy with other sectors. So sector integration, as it’s often called, as a kind of buzzword. But really what we are thinking is that we will see greater reliance between gas and electricity and we think the gas and electricity will become the dominant forms of fuels towards 2050.
Today, you’ve got oil—we’re still living in the generation of oil, oil is the king, and then gaseous fuels and then electricity. And we expect in the next 30 years that to be inverted. So you have electricity then gas and then liquid fuels.
Today, gas is doing its job reducing carbon emissions across Europe, replacing oil in heating and coal in electricity. But gas alone won’t get us all way to carbon neutrality. So we’re going to need to change gas as well. And so we think under the renewable energy directive, we need more recognition for the role of things like hydrogen and biomethane. And we need Europe to start really embracing that change sooner rather than later.
So we’ve been calling for targets for renewable and decarbonized gases within the renewable energy directive. Make a level playing field between different gases and set targets to actually deliver them in the renewable energy directive. The gas industry is calling for a renewable gas target of 11% in final gas consumption by 2030.
We also believe there should be a decarbonization of gas in general. And so alongside that renewable target, we’re calling for a 20% greenhouse gas intensity reduction on a baseline of 2018 by 2030. This will help us also deliver hydrogen, which is derived from natural gas and coupled with CCS.
So we see that these two tools will give us a pathway to start investing in the types of gas that we want to have by 2050. And if we do it now, it will cost less than if we wait until 2030 and then start acting then.
Underneath the targets, in our hierarchy of asks, comes guarantees of origin. And we want to see guarantees of origin being given and recognized for all types of gas. It is allowed today in the renewable energy directive for member states to issue guarantees of origin for non-renewable energy sources. So that would cover blue hydrogen. And so we’re very happy about that.
But we would like it to be not just left to the whim of the member states and actually make it an unequivocal statement. So we’re looking to change that so there is more clarity that blue hydrogen should be treated the same way. I think the European Commission would agree with us that there should be a harmonized system for GOs. We would like to have one harmonized system, so from Portugal to Poland, from Finland to Greece, you can trade them. That will create a liquid, effective market in GOs.
In principle, we believe very strongly that in the first few stages of the decarbonization of gas, we will need hydrogen blending. We think that given the state of the distribution grid, you can actually blend relatively effectively up until around 20% without having to make major changes to household appliances. And now when you get to about 20%, our view is that it’s probably cheaper to switch to dedicated hydrogen [infrastructure]. When you get to 20%, switch, that’s the message that we have.
We can understand why there’s an idea to have a separate grid for hydrogen. We think though, you first use the existing grid, use the blending and when you’ve got to a certain volume, then you switch and you’ve saved yourself building a whole separate grid from the very beginning.
It’s going to save a lot of time, a lot of money if you use existing grid. We’ve got over 2 million km of distribution system in Europe. We use that instead of trying to build a whole new hydrogen system, it just makes so much more economic sense. It’s realistic as well.
I don’t think there should be too much concern about who is actually owning and operating those networks either because they’ve done a very good job for methane, and they can do a very good job for hydrogen. I’m not sure that I would agree that this should be left entirely in the hands of big private companies who run their own hydrogen networks today.
I think we need a much more democratic use of hydrogen for the future, and that means using the existing infrastructure and helping the current operators make that transition to deal with the new gases that are coming in.
Let’s not throw the baby out with the bathwater, because we actually really will need those people to help us run an effective market. They’ve been fundamental in making sure that the gas market works today, and I think they’ll be fundamental in making sure the market of hydrogen works in the future. Trying to complicate the hydrogen market will probably be the downfall of it, keeping it simple and looking at what has worked for methane is a good way to take hydrogen forward.
I would say definitely. Looking at the current southern neighborhood policy that came out this week from the European Commission, they talk about 40 GW of electrolyzers being deployed in that region. I don’t think all of that hydrogen that they produce is going to be consumed in North Africa, and I don’t think all the rest of it is going to be piped automatically through the pipes to Italy and Spain. There’s a very good chance that it can be liquefied and you go from LNG to liquid hydrogen (LH2). And then you’ve got Croatia LNG just across the Mediterranean. You can upgrade it in time to start dealing with LH2 and that becomes a meaningful part of our economy. And this is the direction that policy is heading in.
And what do you think about the traditional gas suppliers to Europe by pipeline, so Russia and Norway. Do you think the onus is on them to decarbonize the gas at source using CCS to produce hydrogen and then send that through their big networks to customers? Or do you think they’ll just carry on sending natural gas and then it’s up to the customer to decarbonize it when they get it?
I think it will depend on the economics. Is it going to be cheaper to send natural gas and decarbonize at this end? Or is it going to be cheaper to change the infrastructure that’s bringing gas from east to west or north to south and then get them to build the CCS plants or the pyrolysis plants and send hydrogen down those pipes? I think that in the end, the market will decide what is the most effective way to do that.
That’s the vision we would have at Eurogas, definitely to have it as a market—a tradable market commodity. I think that is actually very crucial to the overall cost effectiveness of hydrogen. We also believe that at the moment, we shouldn’t have separate markets, and indeed, hydrogen should be traded within the gas market. Why would you change that when it’s worked so well for consumers? I don’t understand why you want to create a whole new market for hydrogen separate from a methane market. At the end of the day, a consumer isn’t buying hydrogen or methane, they’re buying warmth or something to cook with. So I think that’s what we should remember. It’s the consumers that matter.
In a study that we did, there is gas in transport. There is hydrogen in transport, but it’s not in passenger vehicles, and it’s not in light commercial vehicles. The majority of that in the future will be electrified. That’s our own study. On the other hand, on heavy-duty road transport, we see that very clearly there will be a strong role for gases—bio LNG or hydrogen. When you’re getting into the heavy-duty and above, you’re definitely talking about hydrogen. Hydrogen can also play a role in trains. There can also be ships—we see LNG coming on to replace oil and bio-LNG can take its place. And there’s aviation. It’s not going to be all biofuel planes. It’s a growth area for us, definitely.
The first point is: get your measurement right, then you can understand if there is a problem. We are very keen to understand the best way to go about measuring, making sure we have harmonized and comparable standards and figures across Europe. So we applaud and welcome the European Commission’s initiatives here, and we’ve been supporting them through our own industry initiatives for a while.
Now the methane supply index is a different matter. That’s quite complicated. As we understand it, there would be a premium or a privilege given to imports from countries that have lower methane footprints. Is that a tax? Does that mean that if you’ve got higher footprint, you’re going to be taxed at the border on entry? How does that work exactly? Because under World Trade Organization rules, you would be considered to have a ‘like’ product, i.e., a molecule of methane is a molecule of methane.
I find it very difficult to see how this can actually fly. It’s not to pour cold water on the idea, but it would need to be extremely clever and extremely flexible.
I think the best way to do it is do international negotiations. So the international observatory that’s been touted under this strategy is a much better way, where we can sit down and talk about the different issues. In my world, this is how you deal with international politics. You talk to your partners. As soon as you start trying to reward people for being good and punish people being bad, they will retaliate. And nothing gets solved. Much better to work with people, talk to them and say, we think that there are issues here. We’re a big consumer of gas. We’d like to work with you to make things better. And I reckon you’ve got a much better chance of getting people to the table and then taking action.
Ira Joseph of S&P Global Platts Analytics and Ryan Ouwerkerk, manager of Americas natural gas pricing for S&P Global Platts, discuss key market fundamentals following…
Feb 02, 2021
Ira Joseph of S&P Global Platts Analytics and Ryan Ouwerkerk, manager of Americas natural gas pricing for S&P Global Platts, discuss key market fundamentals following the historic JKM price movements of early January and the trickle down impact on TTF, and what’s next for the global gas market as it moves into the latter part of winter.
In the latest installment of the S&P Global Platts Commodities Focus podcast, Jason Lindquist, S&P Global Platts senior digital editor, and Harry Weber, a Platts…
Jan 20, 2021
In the latest installment of the S&P Global Platts Commodities Focus podcast, Jason Lindquist, S&P Global Platts senior digital editor, and Harry Weber, a Platts senior natural gas writer in Houston, discuss current trends in the North American midstream sector as operators of gas pipelines and LNG export terminals prepare to release financial results for the fourth quarter of 2020. Volumes, prices and exports are in focus.
A rapid recovery in output from shale basins hard hit by the mid-February freeze lifted US gas production to an 11-month high Feb. 26, dampening…
Feb 26, 2021
A rapid recovery in output from shale basins hard hit by the mid-February freeze lifted US gas production to an 11-month high Feb. 26, dampening recent forward-market bullishness at the Henry Hub.
Estimated at over 92.7 Bcf/d on Feb. 26, domestic production has staged a stunning recovery over the past 10 days, climbing nearly 18 Bcf/d to its highest level since late March 2020, data compiled by S&P Global Platts Analytics showed.
The rebound has come principally from Texas, thanks to the Permian and Texas portion of the Haynesville. Production from the greater Haynesville has more than doubled from its Feb. 18 low, edging into the upper 12 Bcf/d range – now above its pre freeze-off level.
In the Permian, production is up about 3.3 Bcf/d, or nearly 40% over the same period, to an estimated 11.7 Bcf/d. In Oklahoma’s SCOOP/STACK basins, nearly 1 Bcf/d in output has also been recovered since the freeze, lifting total production to an estimated 3.8 Bcf/d Feb. 26.
Smaller gains have come from the offshore Gulf of Mexico and the Bakken, where production receipts are up about 700 MMcf/d and 330 MMcf/d, respectively, since mid-February.
Over the past week, rebounding gas production in Texas and the Midcontinent has hastened a correction in Henry Hub 2021 forward gas prices.
At market settlement Feb. 25, the balance-of-year curve settled at an average $2.90/MMBtu, down nearly 50 cents, or about 14%, from its mid-February high. Excluding record balance-of-month settlement prices recorded in February, the forward average for March to December has seen a smaller, but still significant, drop from a February high at $3.12/MMBtu.
In Texas and Oklahoma, regional hubs hard hit by the February supply crunch have also seen sizeable corrections to their respective March-to-December curves over the past week.
At the West Texas Waha hub, prices are down about 25 cents from their high to $2.75/MMBtu. In East Texas, average prices for March to December are down 24 cents to $2.90/MMBtu. At the NGPL Midcontinent hub in Oklahoma, the forward average has fallen 31 cents to $2.67/MMBtu, S&P Global Platts’ most recently published M2MS data shows.
Falling valuations in the forward gas markets come despite the potential risks posed by storage.
On Feb. 25, NYMEX Henry Hub futures markets shrugged off a report from the US Energy Information Administration showing the second-largest weekly storage withdrawal on record of 338 Bcf for the prior week. Following the report’s release, the NYMEX Henry Hub April contract held flat, later settling down 2 cents on the day to $2.77/MMBtu.
Over the next two reporting weeks, Platts Analytics expects a further 200 Bcf decline in US storage volumes to 1.74 Tcf, with volumes forecast to drop below 1.5 Tcf by early April – a level that could approach the EIA’s reported five-year minimum.
With LNG and pipeline exports expected to trend well-above last summer’s averages this year, a further rebound in gas production – back toward first-quarter 2020 levels around 93 Bcf/d – could be required to recoup the storage deficit prior to next winter’s heating season.
London — European gas buyers are increasingly factoring in the methane footprint of the supplies they secure amid growing concerns over methane emissions associated with…
Mar 02, 2021
Along with the need to tackle CO2 emissions, methane leakage is now rising to the top of the agenda of the energy sector, with many gas and LNG buyers in Europe set to consider the issue in contractual negotiations with suppliers.
Methane is significantly more polluting than carbon dioxide, with estimates suggesting it is 84 times more potent than CO2 over a 20-year timeframe.
According to the International Energy Agency, oil and gas operations worldwide emitted some 72 million mt of methane into the atmosphere in 2020, broadly equivalent to the total energy-related CO2 emissions from the entire EU.
The biggest two emitters, the IEA said, were Russia — Europe’s biggest gas supplier — and the US, which too has emerged as a significant supplier of LNG to Europe.
A number of initiatives are underway — including the MiQ partnership launched in late 2020 — that seek to certify gas supply based on its methane emissions performance.
It is thought this could become a key component in global gas trade in the future, with supplies from individual producing assets graded accordingly.
But how important to buyers of gas in Europe will the ability to differentiate supply based on methane emissions be?
S&P Global Platts reached out to dozens of major European gas buyers to gauge the mood.
Spain’s Naturgy — the country’s biggest gas buyer with a wide portfolio of LNG and pipeline gas import contracts — signaled a clear intent.
“This topic will be part of the negotiations in purchase and sale transactions in the future,” a company spokeswoman said.
“The issue has already been observed in the market and Naturgy is committed to further exploring it,” she said.
Germany’s Uniper — another of Europe’s biggest gas buyers — said methane emissions was “one of the most material issues” for the gas industry and its stakeholders worldwide.
“In the near future, we expect to screen our potential suppliers also in regard of their carbon and methane emissions intensities,” a Uniper spokesman said.
“Currently, our focus is on better transparency and more accurate emission measurements. These activities are currently underway in our global LNG activities across the whole value chain,” it said.
Austria’s OMV — a major buyer of Russian gas as well as LNG into Gate in the Netherlands — also said the issue was a factor to consider.
“OMV is monitoring the ‘greenness’ of gas in terms of availability and market development and this will also be taken into account in the long-term supply portfolio,” it said.
France’s Engie — which late last year pulled out of talks with US LNG supplier NextDecade amid pressure from the French government and environmentalist groups over the environmental credentials of fracked gas — had a similar line.
“We have started to engage with our suppliers on this issue, not only methane intensity but also carbon footprint,” a spokeswoman said, adding that new supply negotiations represented an opportunity to progress the debate.
However, Engie said methane leakage had no role to play in current hub trading practices or in its existing long-term contracts with the likes of Russia’s Gazprom, Norway’s Equinor, and Algeria’s Sonatrach.
“On the hubs, the origin of the gas which is traded is not differentiated,” the spokeswoman said, making it difficult to engage on methane with the original supplier.
“We have to think of other mechanisms that could be also applicable to term contracts, for example guarantees of origin. Also, we would need a database that gives the information. Such a recognized and reliable data base does not exist,” she said.
Nonetheless, Engie is encouraged that big producers are “working together to report methane emissions more and more accurately.”
Dutch gas trader GasTerra also questioned how hub traded gas could be differentiated.
“Buyers who buy gas on a hub don’t know where their gas comes from,” a GasTerra spokesman said. “To change that we would need to develop a trading system with guarantees of origin, comparable with the market for green electricity and green gas.”
The European Commission last October published its first ever strategy aimed at curbing methane emissions and plans to bring forward legislative proposals on the issue over the course of 2021.
It plans to focus its initial legislative proposals on “low-cost” initiatives for the energy sector such as methane emissions detection and repair, and the elimination of gas flaring.
But the strategy also includes plans for the EC to engage with producer countries on best practices for cutting methane emissions.
The EC said that if producing countries did not make significant commitments to cutting methane emissions, it would consider proposing legislation on targets, standards or other incentives to ensure lower emissions for fossil gas used in the EU.
Italy’s Eni — a major buyer of gas from Russia and North Africa — said it was “fully committed” to reducing methane emissions and was actively working with partners worldwide on the subject.
“We are closely following the ongoing legislative process within the EU, including the application of possible standards for gas entering the EU,” Eni said.
“We believe that new supply standards could potentially help tackle the methane issue. From a market perspective, we believe that such measures should be part of a wider initiative in order not to fragment the global LNG market,” it said. “A global standard, applicable worldwide, would be more effective as all gas producers worldwide would have to comply with it.”
Shell also believes the EU should legislate on a methane performance standard.
Speaking on an IP Week panel Feb. 24, Shell’s head of integrated gas, Maarten Wetselaar, said Europe should put a performance standard in the legislation that is imposed on imported gas.
Then, “the EU can…make sure it only buys gas from geographies that also adopt policies like those in the EU,” Wetselaar said.
Wetselaar said there were increasing signs that gas buyers were also becoming more exacting over the methane performance of the gas they buy.
“As customers become more mindful of the gas they buy, that will drive improvement,” he said.
Mark Brownstein, from the Environmental Defense Fund, also said on the panel there were noticeable shifts in gas buying behavior.
“What we are starting to see is that customers for gas are beginning to ask important questions about where the gas is coming from and the environmental integrity with which it is being produced and shipped,” Brownstein said.
Not everyone is in favor of the EU imposing legislation, however.
Speaking in an interview with Platts last month, James Watson, secretary general of industry body Eurogas, said the EU should bring its external gas suppliers to the table for dialogue, rather than look to impose any kind of penalty on significant emitters.
“As soon as you start trying to reward people for being good and punish people for being bad, they will retaliate,” he said.
“It is much better to work with people. You’ve got a much better chance of getting people to the table and then taking action,” Watson said.
To some extent, it will be up to the producers and exporters to make the necessary changes and eliminate methane leakage and curb other greenhouse gas emissions.
European buyers are certainly taking notice of what exporters are doing to mitigate leaks.
Jouni Liimatta, the head of trading at Finland’s Gasum, said the company would favor LNG suppliers that took account of their carbon footprints, such as those whose LNG production facilities used renewable energy.
“That reduces the carbon footprint along the whole value chain, and we are looking for those kinds of LNG suppliers that consider those factors,” Liimatta said.
An industry standard for methane emissions was one of the main issues raised by European buyers.
Portugal’s EDP said: “EDP is supportive of the emergence of an industry standard regarding the measurement of supply chain methane intensity.”
Initiatives such as MiQ are seen as helping support decarbonization issues given the varying levels of methane leakage across global gas suppliers, while the main challenge is seen as the rate of adoption by large gas producers and governments.
MiQ, in an interview with Platts in January, said it would be in producers’ own interests to adopt its standardization.
“It could be considered a cost of running their business, a license to operate to get certified,” MiQ senior adviser Georges Tijbosch said.
“I think that’s where the market is probably going — consumers are going to ask for gas to be certified as low-methane,” Tijbosch said. “We think that utilities and consumers are no longer going to accept buying gas that is high in methane emissions or that is uncertified.”
Europe-based global traders are also taking the issue of methane emissions increasingly seriously.
“The market is evolving and ‘greenness’ is a factor people are beginning to consider,” a spokeswoman at Vitol said.
However, she said, “greenness” is determined by a number of factors, not just methane intensity.
These include the source of the feedgas, liquefaction technology, the length of voyage, regasification technology and end use, she said.
“In terms of mitigating emissions, we anticipate a growing demand for more accurate measurement of the carbon footprint of a cargo, alongside measures to maximize efficiencies and offset emissions,” she said.
Global trader Trafigura also said methane slippage, as well as all greenhouse gas emissions, was a factor taken into consideration in its procurement strategy.
A company spokesperson said the industry, including Trafigura, was currently focused on data collection around emissions along the value chain, but that there was a “clear direction of travel” aimed at mitigating emissions.
Houston — The “chicken-and-egg” problem of getting power to natural gas production and transportation facilities using electricity from generators that could not get sufficient natural…
Feb 26, 2021
During a joint Energy Resources and State Affairs committee meeting, Rep. Eddie Lucio III, a Brownsville Democrat, called the Catch 22 situation “the commonsense component … that is infuriating to Texans.”
Texas Rep. Charlie Geren, a Fort Worth Republican, compared the situation that resulted in about 3 million Texas power customers lacking power over about three days to the old riddle of “Which came first, the chicken or the egg?”
“This was a conundrum, right?” Geren said. “How do we make sure these systems still have what is essential?”
Those essentials include power for natural gas wells, processing plants and compressor facilities, but Texas Energy Reliability Council Chairman James Cisarik said keeping natural gas flowing to power plants requires operational water, communication and transportation infrastructure.
Texas Railroad Commission Chairman Christi Craddick said her agency did its job “better than anyone else did,” because gas was delivered to more than 99.9% of the residences that use gas for heat.
But Rep. Todd Hunter, a Houston Republican, said, “This was a dysfunctional, awful event where people died.”
Rep. Donna Howard, an Austin Democrat, noted that Electric Reliability Council of Texas President and CEO Bill Magness said Thursday that his staff “did their job, too.”
“I really appreciate that everybody did their job, but clearly it wasn’t enough,” Howard said.
Craddick said, “I don’t know what happened to the gas-fired power plants; that’s not in our world.”
The natural gas system had “multiple points along the line” from the wellhead to the generator to the wires where problems occurred that brought down the system, Howard said.
“ERCOT didn’t understand that they needed the power flowing into the oil fields, in order to get power to people,” Howard said.
A speaker who was not identified for the webcast told Howard “you don’t have to worry about the imprudent ones, because they’ll be out of business.”
Howard responded, “the problem is they might take some Texans down with them as they fail.”
Rep. Tom Craddick, a Midland Republican, said gas generators could have contracted for firm gas supply, but chose not to do so.
Attorney Katie Coleman, an attorney representing Texas Industrial Energy Consumers and the Texas Association of Manufacturers, pointed out that some have raised the idea of establishing a capacity market in ERCOT, but said, “Until you solve the problem of getting gas to the generators you have, getting more gas generators on the grid doesn’t matter.”
RRC Chairman Craddick said, “We don’t have regulations for weatherization, but prudent companies … do have backup compressors.”
Lucio said he understands the desire of business to avoid government intrusion in their affairs and that “it’s in the best interest” of natural gas suppliers to be online, “but they didn’t, and they failed.”
“Moving forward, we can’t just sit back and say, ‘They’ll figure it out,'” Lucio said. “We need to have a comprehensive management plan from the people we regulate. … We gave you the responsibility, and you didn’t do it.”
But the RRC’s Craddick resisted.
“I still believe that mandating something – because one size does not fit all – is a problem for me,” Craddick said.
Todd Staples, Texas Oil & Gas Association president, said not enough gas was delivered for several reasons, including the following:
A loss of power at various sites from the wellhead to the generator
Icy roads that prevented crews from being rotated to production sites
Breakdowns in communication infrastructure, including cell towers
Mechanical issues due to the weather
The loss of power from the grid was the main issue, because almost all wells and gas facilities use electricity, not on-site generation, for electricity, Staples said.
State Affairs Committee Chairman Chris Paddie, a Republican from Marshall, said, “In order to have reliability and resiliency for the whole system, there is an interdependency that is critical, and we have to have adequate infrastructure to do that.”
Houston — All four unaffiliated Electric Reliability Council of Texas board members on Feb. 23 notified the Public Utility Commission of Texas of their plans…
Feb 23, 2021
Also, another unaffiliated director candidate in line to fill an open seat withdrew from consideration. The resignations leave the board with 11 seated members
In the wake of the rolling blackouts that affected about 2.8 million customers across the state, some have questioned the idea of having board members who reside outside Texas.
The resigning board members are:
– Sally Talberg, board chairman, a former Michigan Public Service Commission member
– Peter Cramton, board vice chairman, an economics professor at the University of Cologne, Germany, and the University of Maryland
– Terry Bulger, Finance and Audit Committee chairman, former executive vice president for the US of BMO Financial Group, a Canadian financial services company
– Raymond Hepper, Human Resources and Governance Committee chairman, former general counsel and corporate secretary at ISO New England
The identify of the person who withdrew their candidacy as an unaffiliated director could not be confirmed at deadline.
The remaining 11 board members are ERCOT’s president and CEO, plus representatives of the Public Utility Commission of Texas or some segment of the power market, such as consumer, independent power marketer, independent generator, independent retail electric provider, electric cooperative or municipal power utilities.
Houston — TC Energy’s $1.68 billion acquisition of the master limited partnership that owns some of its affiliated US natural gas pipelines was approved Feb.…
Feb 26, 2021
The transaction is expected to take effect March 3.
The approval by holders of 70% of the TC PipeLines common units represented by proxy or present at a special meeting came despite a large investor’s 11th-hour challenge.
In a Feb. 19 letter to TC PipeLines, asset manager Energy Income Partners, which owned about 11% of outstanding shares as of Dec. 31, said it planned to vote against the merger, arguing that the offer was “inadequate and grossly undervalues TCP’s assets and existing organic growth opportunities.”
TC Energy responded that it would not raise its offer any further than it already had for the about 76% of TC PipeLines shares that it didn’t already own.
The transaction is part of a wave of corporate simplification in the midstream sector designed to make it cheaper for companies that operate pipelines, gathering systems, and processing facilities to fund new growth projects.
In October, TC Energy made a $1.48 billion offer to acquire the outstanding shares of TC PipeLines that TC Energy does not already own, in a bid to put the MLP fully under TC Energy’s umbrella. Two months later, it raised its offer to $1.68 billion, based on the number of shares available at the time.
TC PipeLines unitholders will receive 0.70 common shares of TC Energy for each issued and outstanding publicly held TC PipeLines common unit. The original offer included an exchange ratio of 0.650 common shares of TC Energy for each outstanding TC PipeLines common unit.
A TC Energy subsidiary is the general partner of TC PipeLines, which owns, operates, or holds stakes in gas pipelines that serve the US West, Midwest, and Northeast and interconnect with TC Energy’s larger natural gas pipeline network.
TC PipeLines shares will continue to trade through March 2, then be suspended, TC Energy said in a statement disclosing the results of the shareholder vote.
London — Construction of a new gas interconnector between Bulgaria and Serbia is set to begin in May, state-owned grid operator Bulgartransgaz said Feb. 26,…
Mar 01, 2021
The Bulgaria-Serbia interconnector — which would run from the Bulgarian capital Sofia via Dimitrovgrad in Serbia to Nis — is backed by the EU as a Project of Common Interest (PCI).
The pipeline — which will have a capacity of 1.8 Bcm/year in the direction Bulgaria-Serbia with the possibility also of reverse flow — is expected to be completed in May 2022, Bulgartransgaz said in a statement.
“The construction of the interconnector with Serbia is a priority in the government’s management program in the energy sector,” Bulgaria’s energy minister Temenuzhka Petkova was quoted as saying in the Bulgartransgaz statement.
Bulgaria and Serbia already linked their gas networks at the end of 2020 to allow Russian gas imported via the TurkStream pipeline to reach Serbia via an expanded grid. Flows began at the start of 2021.
The Bulgaria-Serbia interconnector is a separate project, giving Serbia a non-Russian supply option.
It will enable Serbia to import gas via Bulgaria from the Southern Gas Corridor — bringing gas from Azerbaijan to southern Europe — and as regasified LNG from the existing and planned LNG terminals in Greece.
Bulgartransgaz executive director Vladimir Malinov said the procedure for the selection of a contractor for the construction of the pipeline was currently underway.
Bids from applicants were opened on Feb. 22.
“Eleven candidates have submitted documents for participation in the competition, among them international companies,” Malinov said.
“We expect the construction activities to start in May,” he said.
At a meeting Feb. 26, Petkova and her Serbian counterpart Zorana Mihajlovic agreed also to establish a joint working group to accelerate the establishment of the gas interconnection between the two countries.
Mihajlovic said a tender procedure for the selection of the main contractor for the gas pipeline construction in Serbia would be announced in early March.
The pipeline will run for around 62 km in Bulgaria and 108 km in Serbia.
In January, Bulgartransgaz closed the acquisition of a 20% stake in Gastrade — the developer of the planned floating LNG import facility at Alexandroupolis in northern Greece — and this project will play a part in ensuring the new interconnector can be fully utilized.
Malinov said the implementation of the Serbia interconnector project would “provide an opportunity for Serbia to receive gas from the terminal near Alexandroupolis, where our western neighbors have also requested capacity.”
Greece already has one operating LNG import terminal at Revithoussa, which started operations in 2000 and expanded its capacity in 2018, but the government is supporting a second plant as part of efforts to make the country into a regional gas hub.
Startup of the 5.5 Bcm/year floating storage and regasification unit, which secured 2.6 Bcm/year in capacity bookings following a binding market test in March last year, is expected in 2023.
Bulgaria is also building a new interconnector with Greece — the Interconnector Greece-Bulgaria (IGB) — which will allow Azeri gas to flow northward to Bulgaria and for regasified Greek LNG to reach Bulgaria and then Serbia.
At the meeting Feb. 26, it was agreed that the three projects — the Bulgaria-Serbia interconnector, the IGB and the Alexandroupolis LNG terminal — were being built “in harmony” and were “beneficial for the entire region.”
Bulgaria — historically dependent on Russian gas imports — began importing gas from Azerbaijan via the Southern Gas Corridor at the start of 2021, giving it increased supply diversification.
It also already imported gas via Greece’s Revithoussa LNG terminal with the regasified LNG flowing in a south-north direction into Bulgaria.
The IGB will act as the main source of Azeri gas supply for Bulgaria as offtake from the TAP pipeline in Greece, once it is completed at the end of 2021.
Bulgartransgaz, meanwhile, is seeking a loan of up to Eur155 million to finance its current infrastructure projects. These include the three main projects, as well as the expansion of the Chiren gas storage site in Bulgaria.
The deadline for bids for providing the loan is March 5.
The aim of the Chiren expansion project — which is also backed by the EU as a PCI — is to bring its design capacity to 1 Bcm and and increase its injection and withdrawal rates up to 8-10 million cu m/d.
Chiren — Bulgaria’s only gas storage facility — currently has a capacity of around 0.6 Bcm and an injection/withdrawal rate of up to 4 million cu m/d.
According to Bulgartransgaz, Chiren is a “key instrument” for the functioning of the gas market in Bulgaria.