Speakers at Asia Power Week in Seoul highlighted the digital transformation of the global power sector, writes Kelvin Ross

Steve Bolze: "digitalization is the biggest change in the power industry that I've seen" Credit: Pennwell

The digitalization of the energy sector is a topic dominating the talk and trends in the industry and it was high on the agenda of speakers at Asia Power Week in Seoul last month.

Indeed, the president of GE Power put a $1.3 trillion value on the digital transformation of the global power sector over the next decade.

Steve Bolze said that the digitalization of the energy sector "is real and it's here. It's the single biggest change in the power industry that I've seen in my career."

Delivering one of the keynote speeches on the opening morning of Asia Power Week in the South Korean capital, Bolze said that "Thomas Edison would not recognize the industry that we operate in today".

He said that the digitalization of the energy sector was "software and analytics working in conjunction - it unlocks whole new levels of performance. There has never been a better time for the investment in technology."

And Bolze also told the audience that Asia was going to be at the forefront of the shift in the global power landscape.

"Advances in power generation technology in Korea and the Asia-Pacific region means that they are emerging as showcases for the world."

He said that with 320 GW of new power expected in the region in the next 20 years, "there has never been a more exciting time for the Asia-Pacific market.

Later that morning, two speakers from ABB described how the intelligent use of data now available in power plants can not only deliver a competitive edge, but provide a solution to current and future challenges in the power industry.

But they were keen to stress that care had to be taken with both the volume of data and the ways in which it is handled.

Manjay Khazanchi, head of Asia Pacific for ABB's Power Generation unit, said that "the most important thing is to be secure. The biggest challenge for all of us today is on security. We are spending a lot of money on R&D to ensure that our systems are secure and safe.

"All this data has to be handled in a manner in which the operators are able to judge and take actions in a proper and appropriate manner, without any loss of data or loss of production."

Taehee Woo said South Korea would invest $27 billion in renewables Credit: Pennwell

He stressed that "too much data is also not good. We have seen cases in power plants where data has been delivered and people do not know what to do with it. "Not having the right infrastructure in place at root level makes big data meaningless. We need to have strong infrastructure procedures in place."

Marco Sanguineti, ABB's power generation head of technology, referred to what he called the "Internet of Things, Services and People".

"The success of our power generation customers will be more and more supported by the intelligent use of data generated by ever-increasing connectivity of devices. The integration of this data with people expertise and knowledge will create additional services in a cycle, delivering unprecedented knowledge of the behaviour and potential of their assets."

He spoke about the 'internetization' of power. "What is changing is the direction of electricity. What once just went left to right is now going left to right, right to left and back, again and again."

Sanguineti said that ABB's Symphony Plus distributed control system was "the result of our careful analysis of the evolving power generation market, and our customers' changing needs driven by global megatrends".

Meanwhile, the rise of renewables in Asia - and their integration into the region's energy mix - was repeatedly highlighted.

Giving the opening speech of the event, South Korea's Second Vice-Minister of Energy, Taehee Woo, said that his country will invest $27 billion in renewables and from next year also begin to retire 10 coal-fired power plants.He said that South Korea had set an ambitious target to cut its greenhouse gas emissions by 37 per cent by 2030, and added that energy storage, windpower and solar would all play a key role.

Woo said that "the power industry is undergoing profound transformation".

"The traditional power business model cannot maintain its competitiveness. The grid has to become smarter."

He said another key strand of Korea's emissions reduction plan would involve retrofitting its existing plants with supercritical technology, and this retrofitting theme was taken up by Heung-Gweon Park of Doosan, who said that retrofitting "could be the stepping stone" for Asia's decarbonization.

"I understand that extending the life of a coal plant does not sound very attractive," he said, but added that all coal plants in South Korea will be supercritical by the end of the next decade.

And after stating that developed countries such as those in Europe had "relatively well-managed the transition to renewables", he warned that "such a drastic transition in Asia could prove to be an unbearable shock".

On the second day of the event, the biggest issues facing EPC companies and power equipment OEMs were tackled.

In a panel discussion, Gerhard Scheffer of Fichtner said EPC companies "need to target new markets - countries with high dynamics such as Iran, Iraq and South Africa, or regions with a different risk portfolio, like Africa and Latin America."

Aditya Trehan, who heads Siemens' large gas turbine projects in the Asia-Pacific region, said the trend in Asia was for large projects. "We are seeing a lot of bigger power plants - between 2000 MW and 2500 MW - and that means that the number of projects is shrinking." He added that another trend in Asia power projects was "governments are asking, 'How do we localize this industry', and that is going to change the market."

And adapting to change was highlighted when the panellists reflected on the impact of renewables in the power sector.

Markandan Rajagopalan of Wärtsilä said: "We first saw renewables as a threat - now we sell engines as enablers of renewables."

There are several challenges that must be dealt with when considering retrofitting or co-locating battery storage at existing renewable facilities, writes Ross Fairley

Co-locating battery storage and renewables is not a simple proposition Credit: National Grid

In August the UK's National Grid announced which companies had been successful in its first tender for Enhanced Frequency Response (EFR) - a service that achieves 100 per cent active power output at one second (or less) of registering a frequency deviation.

Everyone knew the tender was likely to be competitive with a host of new entrants, utilities and different schemes bidding, but very few expected the winning bids to put forward prices ranging from £7-12 ($9-15)/MWh.

The low pricing resulting from the tender will be heralded by National Grid as a huge success and must surely prompt it to run further tenders in the near future to take account of the competitiveness of the sector. Let's face it, there are a whole variety of "ready to go" storage projects that did not receive EFR contracts and many will be tempted to bid again. Of the projects that were successful and those that failed in the first auction, there are a number that are due to be co-located on existing renewable energy sites.

The logic of locating battery storage on these existing renewables sites is fairly obvious. The purpose of the EFR tender itself, according to National Grid, was to help balance and manage the system, partly as a result of the increased intermittent generation that it has developed into the UK energy mix over many, many years.

If battery storage can help manage that intermittency and can be co-located with renewables projects, it can only help the project developers, National Grid and the wider growth of future renewables projects in the UK. One of the criticisms consistently levelled against the renewables sector, and often overplayed by its opponents and objectors, is the intermittency factor. Anything which combats that intermittency will be useful from a PR and a political perspective, as well as contributing to the economics of projects.

That said, co-locating battery storage on existing renewable energy sites is not the simple proposition that it first seems. Experienced renewable energy generators and those within the energy market who understand energy trading will appreciate that there are a number of factors that need to be considered. All of these factors can be managed, leading to very successful storage sites and renewables projects with enhanced revenue streams.

To start with the basics, most renewable energy sites are leased from a landowner. Indeed, landowners have previously profited considerably from the location of solar and onshore wind projects for many years.

There are a variety of renewables sites that have leases in place and the terms of those will vary in complexity and foresight, often dependent on when they were first drafted. It is very easy to overlook what are relatively small battery storage facilities and consider that they can just be added to a site quite easily.

However, land rights are crucial and the leaseholder or renewables developer will need to think very carefully about whether the existing lease allows for the addition of battery storage on the site. That, of course, is assuming that it is the existing renewables developer with the lease that is adding the energy storage facility, and that that storage facility will not be operated by a separate entity. If a separate entity is requiring a lease, that's a whole new negotiation.

Either way, it is likely that the landowner will need to be approached, either for variation to the existing lease or a brand new property right allowing for battery storage. It is very important to assess the bandwidth of the lease that a developer holds over the site.

Once the real estate rights have been sorted out, we then need to turn to the issue of whether the site has consent for battery storage. It is possible that the existing planning permission for the renewables development will be wide enough to include battery storage, but it is unlikely. Therefore, alterations to the existing planning permission will probably need to be made or a separate planning permission applied for.

One would hope that these variations or a new application altogether would not be controversial, but in these days of very strict grace period qualifications under the Renewables Obligation and its closure to solar and onshore wind projects, the renewables developer has to be very careful that there are not unwanted consequences triggered by such an application or variation. Battery storage is still classed by the regulators, rightly or wrongly, as generation.

Renewable power may find its way to the grid via a battery storage system Credit: National Grid

In fact, this is one of the areas where the regulation needs to be re-examined, and this is currently underway. Whilst it is treated as generation, there is the possibility that an application for planning permission for battery storage could be viewed as an extension to the generating facility on-site.

It is probably fair to say that it is better that the storage solution is treated as a separate installation with separate planning permission required, but that in turn requires separate applications in a timescale that doesn't necessarily fit with the requirements of the battery storage business and developer in reacting quickly to take advantage of National Grid ancillary service tenders, or in building out to the milestones under any awarded contract.

Experienced renewable energy developers will understand this, and will have devised a consenting strategy which will not hinder the existing installation and will make the planning process as slick as it possibly can be for the battery storage project.

Before going any further, it is probably worth pointing out that for projects that have been bank-financed, there may be a considerable hurdle to overcome before the installation of battery storage on the site can commence. Developers that have had the luxury of being able to develop the projects on balance sheet without external project finance are in a really strong position here. Imagine a solar or onshore wind project that has been project financed and is making healthy returns and repaying debt as scheduled under the loan agreement. The big question to ask in those circumstances is why would a funder want, or be encouraged to, change the project or alter it in any way?

Even if the battery storage itself was treated as a separate installation, there may well be impacts on the renewables site in terms of downtime for connections or problems over leasing and land arrangements with the landowner, which would all point to potential complications for the existing project and for the funder who is quite happy with the renewables project as it stands. Doing anything to the existing project is almost certainly going to require the funder's consent, so there is probably an element of persuasion needed in order to fit the battery storage to the site.

One of the key advantages of co-locating battery storage units at existing renewables sites is the ability to maximize the use of the grid capacity at the site which, invariably, the renewables project will not be fully utilizing. As most of the renewables sector will tell you, the prospect of opening up existing grid capacity by installing storage is a tempting prospect and, in some cases, is being looked at very carefully by the Distribution Network Operators (DNOs) themselves to overcome constraints and the cost of upgrades to the system.

Former UK Energy Secretary Amber Rudd visits an energy storage facility Credit: UK Power Networks

Grid connection is a highly technical area and is not necessarily one for the lawyers, but what we can say is that there are detailed grid connection requirements pursuant to many of the ancillary service contracts. These need to be very carefully considered to see whether the grid connection is fit for purpose for battery storage as well as the renewables project.

If the battery storage project is going to be viewed as a separate project within a separate company, there will also need to be consideration as to how the grid connection at the site can be separated out with different design and metering solutions. Where the project companies are different, there ought to be some thought as to what contracts need to be in place between the two companies in terms of shared grid arrangements.

What if the battery storage company does something to hinder the grid connection of the renewables project at the site? What compensation is payable and how is that managed? Shared grid connection arrangements are not simple beasts and, having worked on a number of these for neighbouring solar and wind projects over the years, they need to be carefully thought through. The consequences of one of the shared projects going bust while holding the grid connection - or affecting the other project - needs to be properly evaluated, particularly if funders are involved in either of the two facilities.

Incentives and support mechanisms are, as we know, a crucial part of historic renewables projects. Whilst the subsidy regimes for on-shore wind and solar have been restricted down and, in some cases withdrawn in recent years, many of the existing renewables sites will still be accredited under the feed-in tariff or Renewables Obligation, and that will be crucial to the income that the project and the landowner are obtaining, as well as the repayment of funder's debt.

We have already looked at the issues surrounding debt-funded projects and the concerns that lenders would have of any prejudice to the existing project they have lent to, but if there is any prospect at all of a battery storage unit prejudicing the revenues to be received from the existing renewables projects, then a solution for all needs to be found.

As well as the classification of battery storage being open to debate, National Grid and UK energy regulator Ofgem are aware of the concerns surrounding loss of incentives for generation which is used to charge batteries on-site.

What will be crucial for the further development of storage, renewables and the UK energy mix in years to come is a sensible approach that gives all parties clarity that renewable generation remains classed as renewable, notwithstanding that it may find its way into battery storage and to the grid via the battery.

The existing renewables project will almost certainly have a power purchase agreement (PPA) in place. The PPA offtaker will have entered that contract modelling the generation and the associated Renewables Obligation Certificates it would obtain from that generation. If there is any prospect or intention that renewables generation is filtered away from the renewable energy generating station into battery storage, the PPA provider will probably be concerned.

The PPA will almost certainly contain provisions that constrain the implementation of battery storage on a site, probably not expressly but through various consequential clauses. If there is going to be a link between the renewable generating facility and the battery storage unit, there will probably need to be discussions with the power offtaker of the facility to understand its perspective on whether amendments need to be made to the PPA. On a financed project, all roads for variations of any contract lead back to the funder and any amendments to the PPA will need to be approved by them as well.

Ultimately, with storage in its infancy and the technology developing fast, batteries pose a real opportunity for the UK energy market and should be here to stay. We will see more EFR and ancillary service tenders being run by National Grid, but they are not the be-all and end-all for battery storage developers.

The revenues that can be derived from battery storage units are wide-ranging, and it is key to any battery storage investor and operator to understand how those revenues stack up and which ones are mutually exclusive. For those, however, looking at installing storage on existing renewables sites, the above will hopefully provide a useful checklist. A number of projects have already addressed these concerns and have come out the other side, so the future for storage is exciting.

Ross Fairley is a partner in the Energy, Power and Utilities team at independent UK law firm Burges Salmon LLP

New England consumers, who will pay much more for electricity and natural gas than their counterparts elsewhere in the US because of inadequate interstate gas pipeline capacity, are the exception to an otherwise good supply picture heading into the winter heating season, the American Petroleum Institute’s chief economist said.

Nabors Industries Ltd. reported the signing of an agreement to form a joint venture in Saudi Arabia to own, manage, and operate onshore drilling rigs. The JV, which will be equally owned by Saudi Aramco and Nabors, is expected to be formed and commence operations in second-quarter 2017.

TransCanada Corp. reported that the Canadian government has given the go-ahead on the pipeline operator’s $1.3-billion NGTL System expansion project, which includes five pipeline sections totaling 230 km and the addition of two compression facilities.

Chevron Corp. has encountered a $5-billion cost blow-out with its Wheatstone LNG project in Western Australia.

Consol Energy Inc., Pittsburgh, and Noble Energy Inc., Houston, have agreed to separate their 50-50 joint venture formed in 2011 for the exploration, development, and operation primarily of Marcellus shale properties in Pennsylvania and West Virginia.

GE celebrates the first anniversary of its acquisition of Alstom on November 2^nd and President and CEO of Power Services, Paul McElhinney, says the company’s improved scope in terms of offerings is becoming increasingly evident.

At a press briefing at the company’s European Baden, Switzerland offices on Friday, McElhinney spoke about the power unleashed by GE and Alstom coming together, placing particular spotlight on additive manufacturing and digital 'Total Plant', solutions which he believes will have a fundamental impact on the power industry over the next decade.

Referring to its newly found total plant capability, he said, “We honestly, without Alstom, might have tried to do this because that is where our customers in their conversations want us to go but we would have been challenged in our ability to do it because of lack of expertise in certain parts of the plant.”

“Alstom is very strong on boilers, very strong on balance of plant, very strong on steam, on generator and when you marry it to GE strength on gas, its complementary technology taking the best of both. It’s an interesting new generation of upgrade offerings which are frankly better than either company could have done on their own.”

“We are one year old next week and a much better company.”

Twelve months on from the deal being sealed, GE has gradually started to see the substance emerging from pooling resources with Alstom. While cultural assimilation continues, it is the extent of technological offerings coming to the fore that is causing most excitement.

McEllhiney admitted GE has never serviced a boiler in its entire history. The new reality where the company can engage on the total plant, rather than six different conversations with individual service providers for individual pieces of equipment on the power island, is vastly preferable.

While the recent Paris agreement seemed to be another nail in the coffin of the coal-fired power industry, GE aren’t quite seeing it that way. They’re taking a pragmatic approach to helping their global client base, particularly in Asia, meet the regulatory challenge posed by COP21 rather than burying heads in the sand.

“Coal is an interesting topic when it comes to power gen because depending on where in the world you go you hear coal is dead, has no future. Our view, if you look at the next 25 years, is that coal remains relatively flat in terms of the percentage of generation globally. Renewables and gas increase but coal stays relatively flat.”

“So we have developed a specific suite of offerings around coal fired power plants that recognise the challenges our customers have based on the Paris agreement. COP21 now forces our customers to have to consider fairly significant changes to coal plants in order to comply with the requirements countries have signed up to. We’ve developed plant-wide solutions that can reduce emissions by double digits, improve efficiency by 4 plus per cent, really transform the efficiency and operating environment of some of those coal plants so that they are significantly more attractive in a post Paris world.”

A part of the integration of Alstom’s expertise into the company is manifested in the recently launched Fleet360 platform, which showcases its improved total plant capabilities to service both GE and cross-fleet power generation equipment for utility and industrial plant operators worldwide.

It allows for customized solutions for operators that deliver better performance and value for their entire fleets. McElhinney says that while the world will experience fluctuating demands for energy in various regions, over the long term, the demand for power is expected to rise by 50 percent over the next 20 to 25 years, placing a greater priority on utilities to keep their existing generation assets operating at optimal performance levels.

“On the gas side we have started to incorporate digital in a big way into how we talk to customers and offerings provided to customers. It’s part of the digital initiative journey we’ve been on for four hand a half years and very personal to (CEO) Jeff Immelt who really spearheaded this since then.”

What used to be perceived as almost an obscurity in the business, or a hard sell, is now a staple dialogue in the power sector.

“It’s remarkable. When I go around the world and speak to CEOs of our customers - until last year digital was like a forced topic; for most customers it wasn’t a natural topic of conversation.”

“There were some very early adopters but for most customers it was something we brought into the conversation, something that didn’t happen naturally – I would say that this year every conversation with every customer anywhere in the world digital is brought up by the customers.”

The transformation of attitudes is part of a broader change brought about due to economic pressure. Digital is now being trusted as a means of surviving and gaining in an increasingly competitive scenario. GE has seen the benefits for itself.

“There is a recognition that industrial productivity has effectively stalled. We are all in a slow growth world. So customers are being forced to find ways to generate their own growth. The environment is not creating enough demand for customers so the focus has been more on creating internal productivity.”

“All of the things we have done in digital we have started internally in GE, so before we went to customers and said this what the benefits of digital could be we took digital and adopted it internally for use in our own factories, shops, our own manufacturing processes, our own industrial platforms and it has driven significant productivity inside GE.”

Some of the earliest adopters, McEllhiney notes, were the most ‘challenged’ in the sector. In Europe where market pain is most visibly acute, digital is becoming almost a necessity, he says.

“Now with certain parts of Europe and the world its more about getting on the grid fast when the demand manifests and get off the grid fast which translates in our world to start up time and turn down time. We take digital without any hardware changes to the equipment and we have been able to dramatically reduce start up time and turn down time so customers can be a lot more agile in terms of trying to take back the benefit of market opportunities.”

“I would say digital has become an integrated part of our business ad now as we move to total plant which is OEM agnostic – because when you move to total plant there is lot of different equipment on site from lots of different manufacturers and OEMs so the conversation has really changed and the timing of Alstom could not have been better.”

Another exciting development accelerated by the acquisition is the prospect of additive manufacturing or 3D printing of power plant solutions. The press team who visited Switzerland last week were treated to a demonstration of GE’s work in this area.

Additive manufacturing, or 3D printing refers to processes used to synthesize a three-dimensional object in which successive layers of material are formed under computer control to create an object. Objects can be of almost any shape or geometry and are produced from digital model data 3D model or another electronic data source such as an Additive Manufacturing File (AMF) file.

Last week the company celebrated the installation of the world’s largest 3-D printed part in its GT13E2 gas turbine at Vattenfall’s Heizkraftwerk Berlin-Mitte power plant in Germany. The 3-D printed Combustor Zone 1 Segment, which was manufactured at GE’s plant in Birr, Switzerland, weighs 4.5 Kg and is the size of a laptop.

GE has been working with the technology for around six or seven years and its seen as having a likely huge impact on cost and cycle times as it continues to develop. It also offers a perfect complement to the company’s growing digital prowess.

“When you think of the future, consider a repair shop, we have 53 such shops around the world. Potentially we are coming to a point where we can print parts at the customer site, not in the next few years but eventually. Fundamentally that changes your mindset around the concept of footprint, of repair shop, warehouse, inventory costs and cycle time.”

“In terms of trends- for us total plant is new but we now have that capability, digital is clearly emerging and additive manufacturing is clearly emerging and they will have a fundamental impact on the industry when we look out over the next decade and beyond.

When compromise stands no chance, balance gains appeal as a measure of policy.

General Electric Co. has agreed to merge its oil and gas business with Baker Hughes Inc., creating an equipment, technology, and services provider with $32 billion of combined revenue and operations in more than 120 countries.