Navigant Research Blog

HVDC: The Future of Long-Distance and Renewables Transmission

— January 11, 2018

A quick glance at the US Department of Energy’s wind speed maps is enough to see that, in the US, wind energy is mostly where the people aren’t. The population megalopolises of the east and west coasts are thousands of miles away from the central states with high wind energy, challenging traditional high voltage alternating current (HVAC) transmission networks to overcome expensive and high loss transmission issues. Internationally, the same problem exists: How do developers make the most of untapped remote renewable resources?

Can the Solution Be HVDC?

High voltage direct current (HVDC) is a high capacity, long-distance transmission system with low losses. More expensive to build than HVAC power lines, an HVDC network becomes more cost-effective in the long run for distances of 400 miles or more on land and just 30 miles underwater. HVDC lines of 800 kV or more are commonly referred to as UHVDC (ultra-HVDC) As in the US, much of the world’s most valuable renewable resources are remotely located, and require long-distance transmission.

Delivering Energy with HVDC

(Source: Clean Line Energy Partners)

According to Navigant Research’s report Transmission System Upgrades for Renewable Energy Integration, global HVDC revenue is expected to grow at a compound annual growth rate of 9.5% from 2016 to 2025 and reach $12.7 billion by 2025. It focuses on HVDC’s application to renewables integration; the revenue figures do not account for HVDC installations for non-renewables transmission. The report also includes an in-depth analysis of the drivers, barriers, costs, and benefits of a HVDC system, a few of which are listed below.

HVDC systems can do the following:

  • Connect distances of more than 2,000 miles
  • Transmit up to 3 times more power than AC systems of equivalent voltage in a similar right-of-way
  • Transmit the same amount of power as an AC network in significantly smaller right-of-way
  • Interconnect grids over land and under sea
  • Provide grid operators with greater control over power flow with minimal losses

If HVDC Networks Are So Great, Why Aren’t They Everywhere?

Despite the benefits of HVDC, financial and regulatory barriers limit the construction of new HVDC networks. Current restrictions on right-of-way permitting and heavily controlled costs have suppressed penetration of HDVC systems, but that may change now that there are several significant projects underway. A few of the most significant upcoming projects are the following:

  • India-North-East Agra: The world’s first multiterminal UHVDC transmission link. The 800 kV, 1,073-mile link will supply enough power to serve 90 million people. Scheduled for completion in 2019.
  • United Kingdom-Western HVDC Link: The world’s first 600 kV or higher subsea HVDC network, with 239 of 262 total miles underwater. It is scheduled for completion in 2018.
  • Iceland-UK IceLink: This early-stage project will transmit power between Iceland and the UK. It will be 620-745 miles long, and will operate at 800 kV-1,100 kV. Estimated completion is 2027, and it will supply power to serve approximately 1.6 million homes.

Latest in HDVC

In early November 2017, the world’s first ­1,100 kV UHVDC transformer passed its type test, confirming the design criteria and operating parameters of the unit. Designed and built collaboratively by ABB and Siemens, the transformer will be commissioned in 2018 for installation as part of the Changji-Guquan link. Spanning 2,040 miles (3,284 km), the link will set world records for voltage, transmission capacity, and distance.

Looking Forward

Despite the high capital costs of HVDC, the benefits are clear, both for renewables and fossil fuel generation. The long-distance, high capacity systems can bring power to areas in need, deliver power from offshore wind farms to mainland cities, and reduce the environmental impact of transmission networks with smaller footprints. The commissioning of the Changji-Guquan link is a major step toward future intercontinental, long-distance, underwater, and over-land HVDC transmission systems, and it won’t be the last.


As Natural Gas Electricity Generation Grows, Risks and Opportunities Emerge for Energy Consumers

— October 26, 2016

Natural gas is becoming increasingly vital to US electricity generation. With vast new resources made available by hydraulic fracturing, use of the fuel is growing across various sectors, especially in the area of electricity. Although coal has led electricity generation since before 1950, natural gas finally took the highest share for most of 2015 and almost all of 2016 (as seen in the chart below).

While many welcome the growth of this cheap, low-emissions fuel, some risks are arising for energy consumers. Put simply: a system that depends heavily on natural gas is more susceptible to supply shocks. With slumping production and demand from the electricity sector, prices are already trending up. The monthly Henry Hub price reached $2.99/MMBtu in September, the highest in 20 months. This may be exacerbated by a colder winter that is driving predictions of higher gas and electricity prices and volatility compared to last year. And this week marks 1 year since the largest natural gas leak in US history hit southern California, the fallout of which still reminds us how unforeseen disasters can shock supplies.

This type of volatility can affect everything from household budgeting to the balance sheets of multi billion-dollar utilities. Notably, commercial and industrial electricity consumers can be heavily affected to the tune of millions of dollars by volatility in gas prices, electricity prices, or both. Thankfully, advances in alternative generation options exist to mitigate these risks.

Monthly Net Electricity Generation, All Sectors (Jan 2011 – Dec 2016)

AForni Blog

(Source: US Energy Information Administration)

Alternative Generation Advances

Renewables include technology solutions like wind and solar, and (in this context) other zero-emissions complements like battery storage and demand response. These technologies are being broadly embraced thanks to government support, cost declines, and emissions reductions initiatives. The dramatic growth in corporate renewable power purchase agreements is one of the most powerful examples of the Energy Cloud in action.

Onsite gas-fueled generation may seem subject to the same market vicissitudes affecting natural gas, but it has some key advantages, even over renewables. First, customers installing fuel cells, gensets, or microturbines can purchase long-term gas contracts that will guarantee a certain rate for gas (and therefore electricity)—a key risk mitigation tool. Compared to centralized generation, onsite gas generation is installed faster and with less regulatory risk, while also eliminating the transmission and distribution energy losses (and risks) of the electric grid. Compared to renewables, these technologies can be installed in a far smaller footprint and, crucially, generate electricity without relying on the wind or sun.

Onsite dual-fuel generation consists of gensets, turbines, or microturbines that can operate on diesel and natural gas (and often, other fuels). Such equipment has many of the same advantages of onsite gas-fueled generation, with the added bonus of accepting multiple fuel types. While natural gas is often the preferred fuel (due to emissions requirements and lower cost), shocks to natural gas supply and/or price can make an alternate fuel like diesel favorable, if only for a short period. Diesel can also be stored onsite, ensuring access in a major catastrophe. This technology has been most embraced in the US oil & gas sector, but has growing applications both stateside and abroad. Watch for the coming revolution in liquefied natural gas to open new opportunities in flexible generation, too.

Natural gas will be an important electricity fuel for a long time to come. But in an era with baseload in decline and renewables on the rise, these tools should not only mitigate natural gas risk, but also build flexibility into an electric grid that sorely needs it.


Europe’s Energy Transition Megatrends and Tipping Points, Part V: Globalisation and Regionalisation of Energy Resources

— September 2, 2016

Oil and Gas ProductionJan Vrins coauthored this post.

In our initial blog on Europe’s energy transition, we discussed seven megatrends that are fundamentally changing how we produce and use power. Here we discuss how the globalisation and regionalisation of energy resources is fundamentally changing the European energy industry.

What’s Happening?

The EU is actively aiming to deliver on Europe’s 2030 climate and energy targets while ensuring security of supply and affordable prices. The EU also seeks to be a world leader in renewable energy. Achieving these goals requires a transformation of Europe’s electricity system. To assist in this transformation, the EU must achieve a balance of meeting consumers’ expectations, delivering benefits from new technologies, and facilitating investments in low-carbon generation while also recognising the interdependence of member states. A critical part of this initiative is connecting isolated national and regional electricity systems to secure supply to help achieve a truly integrated EU-wide energy market—a key enabler for the continent and one that goes well beyond precursors such as Nord Pool. While the United Kingdom’s vote to leave the EU raises a number of questions about future policy, it is too early to say what effect Brexit will have on the United Kingdom’s participation in the EU’s future single energy market. (The United Kingdom has, however, been an enthusiastic proponent of this to date.) What is clear is that a focus on greater levels of interconnection (both offshore and onshore) and energy efficiency will continue to be necessary aspects of EU energy policy—and ones that receive much scrutiny.

To get access to the necessary energy supply and resources, more regions, countries, energy markets, and utilities—including those in Europe—are looking beyond the traditional borders of their energy business and territory.

What’s Driving This Change?

The main drivers behind this globalisation and regionalisation of energy resources are:

  • Access to cheaper natural gas globally
  • Accelerated shift of generation resources to renewables, which requires greater system flexibility to maintain security of supply
  • Economic and political imperatives for energy import and export

Access to Cheap Natural Gas Globally

Driven by a technology breakthrough applied in the field, shale gas has transformed the North American gas market and stands poised to significantly affect the global gas market in the future. On February 24, 2016, for the first time in history, liquefied natural gas (LNG) from North America was exported from the contiguous United States—from the Cheniere Sabine Pass facility in Louisiana—to Europe, a historic moment in the North American gas industry.

Globally diverse sources of natural gas and increased movement of these sources—in the form of LNG by ship—is becoming increasingly prevalent from places far from one another. As Australia, the United States, and Canada follow Qatar with plans to export LNG in large volumes, the global gas market is poised for a renaissance. Although the LNG industry has been a victim of its own success as prices have declined, the growing availability of gas to global markets is set to impact places that never previously had access. This movement is bringing with it the opportunity for new gas-powered industries such as petrochemicals and an increased availability of cleaner gas-fired power generation to people and places around the world.

Extensive European infrastructure for gas transmission, including pipelines and new LNG facilities, is helping ensure that cheap gas will be available in most parts of Europe. There is a lag effect as to how this impacts gas generation development; however, in the short to medium term, it at least underpins gas’ ability to remain a key fuel source for heating, industrial use, and flexible power generation. While the latter use may fly in the face of carbon targets, with questions around new nuclear and other baseload low-carbon generation, the net reduction from replacing coal with gas is still significant and may prove to be at least a convenient bridging arrangement.

Accelerated Shift of Generation Resources to Renewables

In Part III of this series, we discussed the changing generation mix across Europe. Virtually all net growth in recent years has come from renewables. To achieve this while managing the system security of supply requires much greater flexibility in the way the electricity systems are managed across Europe. Flexibility is essential and the key underpinnings of this are interconnection, storage, and demand response. To date, the most prevalent of these has been the rapid growth in interconnection—for example, the import of French nuclear power to support Germany’s solar boom and the HVDC interconnection to enable the United Kingdom and Denmark to rapidly develop their wind generation sector. It can be argued that without access to hydro reserves from Norway and Sweden, neither country would be able to accelerate their current offshore wind program. This interconnectedness is a strength of the European system, but it also means that, in effect, each nation relies on others for their ultimate security of supply. In the future, the impact of storage will complement this and aid renewables integration and system stability. Storage and the ongoing development of demand response will also lead to local regionalisation, whereby markets at a more local level are necessary to deal with increasingly decentralized generation and the local flexibility enabled by smarter metering.

Economic and Political Imperatives

The third driver may be obvious to some but is the most challenging to achieve in practice in many ways. Greater affordability for consumers across Europe is promoted through a more regional approach to energy supply. However, macroeconomic theory and national politics do not always pull in this same direction. It sounds simple for Norway to increase its exports to the United Kingdom via a new interconnector as both countries gain overall; however, if this leads to higher wholesale prices in Norway through a reduced surplus, then consumers may see an impact on their retail price. To date the economic efficiency of Europe’s market coupling has proven a sound platform for rapidly improving the regionalisation of energy resources across the continent while political will has held firm in most respects. Some initiatives such as the North Sea Grid may work on a region-wide basis yet do not translate into a commercial rationale that leads to specific profitable projects for investors. Given the importance of a united energy policy for maintaining affordability and energy security across the continent, this needs to remain a critical area of policy and regulatory attention as 2030 targets come firmly into focus.

So What Does This Mean?

It is worth reminding ourselves of the underlying objectives as defined by Europe’s Energy Union:

  • Electricity systems will become more reliable, with lower risk of blackouts.
  • Money will be saved by reducing the need to build new power stations.
  • Consumers’ increased choice will put downward pressure on household bills.
  • Electricity grids will be able to better manage increasing levels of renewables, particularly variable renewables like wind and solar.

Looking forward, the EU market, national policymakers, and utilities first need to adapt their long-term resource plans and incorporate regional scenarios for power supply, while also building in a rapidly changing fuel resource mix toward renewables and natural gas. Second, they must think outside the box with regard to securing fuel or access to renewables well beyond their traditional territory borders. Third, to effectively develop system plans, the planning processes need to take into account the entire regional transmission system. Regional entities should find a way to bring together players such as distribution network operators, municipalities, and other smaller industry players to ensure their needs are also addressed and more holistic solutions are presented. Finally, to facilitate and enhance emerging market offerings such as enterprise information management, the planning toolkit needs to expand to better address the challenges of large-scale renewables integration across multiple regions.

This post is the sixth in a series in which we discuss each of the power industry megatrends and the impacts (“so what?”) in more detail. Our next blog will be about merging industries and new entrants. Stay tuned.

Learn more about our clients, projects, solution offerings, and team in our Navigant Energy Practice Overview.


Once Again, Renewables Costs Reach a Record Low

— September 1, 2016

Rooftop SolarOn August 17, Chile announced the results of what the specialized media called the Mega Tender. The country’s energy regulators tendered 12,430 GWh per year of electricity over 20 years starting in 2021—that’s 30% of the load of Chile’s regulated market (residential and small commercial consumers). Not surprisingly, the country received the lowest bids for renewables in history; this is the fourth or fifth time in 2016 that we are seeing record low numbers—it’s also happened in Peru, Mexico, and Dubai.

The lowest solar bid, by Solarpark, will sell electricity for $29.10 per MWh, while wind’s lowest bid was also a record-setting $38.00 per MWh. It is important to note that the projects will start producing electricity in 2021, and as such will probably be built in late 2019 and 2020, giving the developers another 4 years of technology innovations before construction.

One interesting feature of Chile’s auction system is that it splits total load to be tendered into different blocks, differentiating by time of the day when the electricity must be provided instead of dividing it by technology. Block 1 allowed for generation at any time of the day, block 2-A allowed generation only between 11 p.m. and 8 a.m., 2-B allowed generation between 8 a.m. and 6 p.m., and 2-C between 6 p.m. and 11 p.m.

It was expected that wind developers would dominate Blocks 1, 2-A, and 2-C; interestingly, they also got most of 2-B. Solarpark’s Maria Elena Solar project was the lowest bidder in the whole tender, but it was the only winning solar bid in a country famous for its excellent solar resources.

Connecting the Sun

The problem for Chile’s solar industry is that its best resources are concentrated in an unpopulated area of the country—in and around the Atacama desert. A significant number of solar projects were proposed there in the last few years to supply the copper miners in the area, but with the collapse in the price of the metal, a significant amount of solar projects in the area have struggled. For the Chilean solar industry to see significant growth, the country first needs to connect the sunny north to the rest of the country where most population lives.


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