A NEW STUDY PUBLISHED in Nature Geoscience concludes climate change could shift wind production from the Northern Hemisphere to the Southern Hemisphere.

The study, produced by researchers at the University of Colorado Boulder, said modern assessments of wind energy potential is based on the current state of the planet’s climate and doesn’t take into account changes in the climate due to greenhouse gas emissions.

Researchers applied an industry wind turbine power curve to simulations of high and low future emissions scenarios in ten fully-coupled global climate modes to investigate large-scale changes in wind power across the globe.

The calculations revealed decreases in wind potential in the Northern Hemisphere’s mid-latitudes and increases across the tropics and the Southern Hemisphere, though both had substantial regional variations.

The changes across the northern mid-latitudes appeared over time in both emissions scenarios, while the Southern Hemisphere changes appear critically sensitive to each individual emissions scenario.

The northern decreases were due to polar amplification, while the southern increases were due to enhanced land-sea thermal gradients.

Though the power industry continues to endure rapid change in technology, demand and regulation, the five keynote speakers at POWER-GEN International 2017 focused on making the most of a changing market through convergence and collaboration.

Blake Moret, president and CEO of Rockwell Automation, said the convergence of automation and industrial operations requires strong hardware and software — but also people who can understand them both.

“One of the particular challenges that affects this industry and many others is the demand for skilled labor,” he said. “People who want to do this type of work and people who are comfortable with interacting with industrial control equipment.”

As a result, Rockwell encourages the concept of lifelong learning to its employees and clients in order to become more agile and integrate both IT and OT as they both continue to evolve.

Automation isn’t an instant process — companies must take the time to identify their problems, conduct studies, identify results and find ways to scale them across their entire fleet.

Though the challenge may seem daunting, industrial automation benefits companies by identifying ways to make operations more efficient. Moret said his company can typically lower downtime by 50 percent and increase efficiency by 25 percent.

“As we simplify these processes, we can find more ways to be more productive,” he said.

Paul Browning, president and CEO of Mitsubishi Hitachi Power Systems Americas, came to POWER-GEN with a surprise announcement — the company has officially broken ground on the world’s first 65 percent efficient combined-cycle power plant that will be capable of fully autonomous operations. That 600 MW system should be ready by 2020.

Though the dramatic drop in the cost of electricity from renewable sources has been well-documented, Browning said natural gas has experienced a similar drop in cost, with an estimated drop of 12 percent each year over the last decade. Natural gas now produces electricity at $41 per MWh.

In some cases, the cost drop has been even more extreme. MHPS recently helped the Grand River Dam Authority replace its coal-fired Unit 3 with a gas-fired turbine that is the company’s first J-class turbine in North America.

“The delivered cost of electricity from that plant is less than the rail costs of coal deliveries alone,” Browning said.

Most nations of the world have signed up for ambitious carbon reduction goals via the Paris Agreement, and carbon emissions from China have started to peak. However, Browning noted that the power industry has already lowered carbon dioxide emissions by 24 percent since 2005. Studies indicate 40 percent of that was from renewables, 53 percent from a switch from coal to natural gas and the remainder is from the natural gas fleet becoming more efficient.

“This change was driven not by politics, but by markets and technology,” he said.

Even developing nations have started to switch from purchasing the less-advanced offerings from MHPS to the company’s more efficient technologies.

Stan Connally, chairman, president and CEO of Gulf Power, said Southern Company, parent company of Gulf Power, is now concentrating on finding more ways to fill in the value chain for their customers.

“Our relationship with the customer is changing,” he said. “The meter itself used to be a one-way device. Now it can provide information to the customer behind it in ways we hadn’t imagined.”

That’s motivated Southern to undertake acquisitions and create Southern Company Gas, a distribution company, and PowerSecure, an energy solutions provider.

In particular, PowerSecure provides distributed generation, fuel cells, energy storage and microgrids to better provide customers with on-site solutions. Connally said that, on average, PowerSecure’s 800 employees in Florida maintained 98 percent reliability during Hurricane Irma and its aftermath. That provided Southern Company with even more data on how to help its customers.

“Florida was the epicenter of our learning this year,” he said.

Stefan Bird, president and CEO of Pacific Power, said his company has strongly embraced wind and solar power, and is in the process of repowering its entire existing wind fleet to further take advantage of renewable generation.

However, that has presented a problem, as wind and solar power generation isn’t constant. Wind generators can go from zero generation to full capacity and back multiple times per day.

Though one popular solution is energy storage, Bird touted diversification as a way to keep power flowing even when certain resources are at rest.

“If you can put together a portfolio with uncorrelated assets, you have much lower risk,” Bird said.

Part of that diversification comes from Pacific Power’s membership in the Western Energy Imbalance Market. Under this system, participants import and export energy as needed on a minute-to-minute basis to keep power flow constant. For example, California exports surplus power during the day thanks to its strong solar generation, while importing power at night from windier areas that are still generating.

Bird estimated Pacific Power alone has saved $250 million in three years thanks to the arrangement.

But even coal can become a flexible resource, as he said Pacific Power has improved its equipment and controls to be able to ramp up and down more closely to changing power needs than the company has been able to in the past.

J. Patrick Kennedy, CEO at OSIsoft, said his operational intelligence company has run into the issue of software increasing much faster than the devices they’re meant to optimize. The power generation industry is no different.

“At the end of the day, customers want to lower the cost of power,” he said. “And it takes very sophisticated systems to do that.”

To give just one example, Kennedy said his company sourced battery storage for the construction for its new headquarters. At first, the battery cost $500,000, but before the project was finished, that cost dropped to less than half that.

“Every incremental drop in price of a solar cell, a battery or any other device will end up doubling and tripling the volume of these things,” he said.

That increased volume will help explode the amount of potential data points that can be measured. Though Kennedy said people tout that one trillion devices are waiting to enter the cloud, that doesn’t count the data already there and all kinds of sensors that haven’t been imagined yet.

Additionally, all that data will have multiple ownership rights, especially as increasing technology leads vendors to manage the products they supply. With the power industry, data ownership could change along with hourly changes in power needs and production.

However, Kennedy said that future technology isn’t impossible to predict, and his company and its clients don’t have to wait for trends to emerge before becoming prepared.

“What becomes dominant sits in the market 30 years before that,” he said. It just hasn’t been perfected. Everything we have to support exists today. Now we have to find out what we have to support.”

Near the end of the 19th century, the “Devil’s Rope,” or barbed wire, divided the West protecting the assets of farmers from ranchers who wanted to maintain their traditional way of life — an open range upon which their cattle could graze unfettered. Outlaw groups were recruited to cut fences and reestablish open access to land and public water sources. This did not sit well with farmers, who turned to lawmen for help. This conflict grew and eventually became known as the great Fence Cutter War.

Fast forward to the present time. We’ve erected an array of perimeter-based protection to safeguard not farmland, but industrial cyber assets. However, a new breed of fence cutters – nation state threat actors and malicious insiders – have successfully breached our best defenses, putting safety, reliability, and ultimately profitability of our nations critical infrastructure at risk.

Why have our best efforts to secure power plants fallen short? The answer is that we’ve taken an IT-centric versus a production-centric approach to industrial control system (ICS) cybersecurity. This has left the systems responsible for plant safety and production vulnerable to malicious attacks or unintended incidents.

Securing ICS is certainly a challenge, as the endpoints that matter most are highly complex and proprietary. Unfortunately, power generation facilities don’t often have an accurate, comprehensive inventory of all their systems. Also, despite the existence of known vulnerabilities within ICS assets that exist on process control networks (PCNs), industrial companies today still struggle with vulnerability identification and management.

How can you secure what you cannot see? And further, how can you know when a vulnerability on an ICS puts safety and production at risk?

This article examines how the Devil’s Rope of today has left our power industry vulnerable. It also discusses current ICS vulnerability management challenges, as well as how to address them by taking a more production-centric approach to managing vulnerabilities on Level 2, 1, and 0 ICS assets.

ICS Vulnerability Management Challenges

New research from SANS shows that ICS cybersecurity has become a significant concern. Sixty-seven percent of survey respondents reported that they consider the threat to ICS to be either high or severe/critical (SANS Securing Industrial Control Systems, 2017). This fear is born from successful attacks such as the Ukrainian power grid attack in December 2015, the Industroyer/CrashOverride malware attack one year later in December 2016, and a new campaign of attacks targeting energy companies in the spring and summer of 2017 by a group called Dragonfly 2.0. Each showed the ability and will to shut down power.

ICS vulnerabilities present attackers with additional options to compromise grid operators. However, despite the existence of known vulnerabilities on systems within PCNs, industrial process and power companies are still struggling with ICS vulnerability identification and remediation.

ICS Vulnerabilities Don’t Get the Attention They Deserve

Automation systems are vital infrastructure for most industrial processes — especially power generation. As these systems become more advanced and connected, they become increasingly attractive targets. For example, a recent report from Kaspersky Lab highlighted that almost 40 percent of monitored ICS assets faced an attack at some point in the first of half of 2017 (Threat Landscape for Industrial Automation Systems in H1 2017).

Attacks on power plants are garnering more public attention. Despite the growing media hype around vulnerabilities in critical infrastructure though, far too often ICS vulnerabilities do not receive similar attention, typically due to the following reasons:

– Vulnerability exploits under-reported

– False sense of security

– More disclosures than capacity to investigate

Vulnerability Exploits Under Reported

Given that ICS assets in the power industry are high consequence targets, they are attractive to threat actors. Yet, many ICS asset owners pay insufficient attention to ICS vulnerabilities even when exploits may exist in the wild.

Disclosure is a tricky thing. While we have some awareness of who has received audit fines and certain attacks do make the public forum, it is unclear how well companies are preparing for the next attacks. We do know that there are intrinsic challenges to overcome if the battle is to be won.

False Sense of Security

Most ICS asset owners rely on traditional corporate IT practices and solutions, such as network segmentation, firewalls, and air gapping – the modern-day IT version of the “Devil’s rope” – to deny threat actors access to industrial assets. However, they underestimate just how accessible and at risk their assets actually are.

As little as 15 years ago, control systems were stand-alone assets, unconnected to IT networks or the outside world. IT and ICS networks were isolated from each other using different protocols to communicate.

However, the nature of control systems and their connections to IT systems and the Internet has changed. While in the past, control systems were typically custom-built air-gapped systems, today they are IP-addressable and connected. ICS and IT systems increasingly connect and communicate, and more ICS are remotely accessible than ever before.

A 2016 report from Kaspersky Lab, Industrial Control Systems and Their Online Availability, illustrates this trend, as well as the vulnerability risk Internet exposure presents to ICS assets. The research showed 220,558 ICS components could be accessed from the Internet. Even more concerning, this same study found that 92% of these ICS assets had vulnerabilities.

As the report demonstrates, far too often hidden ICS asset connections to the Internet serve as an open door into the heart of industrial controls. Threat actors are skilled at finding and exploiting these gaps in perimeter security in their quest to control or damage systems in the power industry maliciously. Even though network segmentation introduced by NERC CIP has offered modest protections and limited broad-based exposure, cybersecurity professionals should not assume perimeter security solutions alone can protect their ICS assets.

More Disclosures Than Capacity to Investigate

Vulnerabilities are tracked in the NVD using CVE identifiers. Since their launch in 1999, the number of CVEs has grown steadily. More than 51,268 CVEs were published between January 2010 and September 30, 2017. 11,100 CVEs have been published within the first nine months of 2017 alone – a new record.

Traditionally, automation vendors were reluctant to publish discovered vulnerabilities. Some feared that if they were overly transparent regarding vulnerabilities, other vendors would use this information against them. Many preferred to fix vulnerabilities quietly as they worked on an updated version of the product, then asked their customers to upgrade if a vulnerability was publicly disclosed.

After Stuxnet made headlines in 2010, however, it became clear that Level 1 and 0 ICS vulnerabilities could impact industrial facilities. The number of publicly disclosed vulnerabilities began to increase greatly with ICS-CERT advisories for Level 1 and 0 ICS assets increasing sevenfold since 2010 (ICS-CERT Year in Review: Industrial Control Systems Cyber Emergency Response Team 2016).

Many of these vulnerabilities have likely been lurking for years, only coming to light now due to an increased awareness of ICS cybersecurity risk.

Limited Visibility into ICS Vulnerabilities and Risks

Given the sophistication and effectiveness of recent industrial compromises, identifying and remediating known vulnerabilities is one of the best ways to reduce power infrastructure risks. However, despite the existence of known vulnerabilities within systems that exist on PCNs, industrial process and power companies today still struggle to identify ICS vulnerabilities and risks in a timely manner.

When it comes to securing OT assets, most approaches have been IT-centric. This has led to limited success with focus on securing Level 2 endpoints, such as workstations. This approach has also worked for securing routers and switches on the PCN, as these types of devices can avail themselves of the same types of security controls implemented on corporate IT networks.

However, these Level 2 endpoints make up only 20 percent of industrial endpoints.

The remaining 80 percent of industrial endpoints are Level 1 and 0 production-centric endpoints including Distributed Control Systems (DCSs), Programmable Logic Controllers (PLCs), and turbine controls. They also include smart field instrumentation and the sensors that directly connect to process equipment.

Level 1 and 0 assets are invisible to most cybersecurity professionals, as most of the tools used for vulnerability assessment today were not built to support the proprietary architectures and protocols used by ICS endpoints in multi-vendor process control environments. Because Level 1 and 0 assets are invisible or opaque, and because vulnerabilities on Level 2 endpoints are more readily understood and accessible, organizations focus on Level 2 vulnerability management.

However, 80% of endpoints in industrial environments are Level 1 and 0 endpoints. These are the endpoints that matter most in industrial environments.

At the end of the day, most organizations do not have a clear view into all the different endpoints running in their facilities. When automation system vendors publish vulnerability bulletins, managers do not easily know which systems and versions they have. And even when they do know that they have a system with a known vulnerability running in the plant, theytypically cannot quickly tell if the vulnerability still exists, or if it has been remediated. This means they do not know with any degree of confidence whether the endpoint is secure, or if it is vulnerable to exploitation.

OT cybersecurity professionals in the power industry must do a better job of gathering and maintaining an evergreen inventory of all the assets in the plant and assessing these assets against known vulnerabilities. You simply cannot secure what you cannot see.

Vulnerability Investigation Is Manual and Research-Intensive

Compiling the vulnerability management data needed to remediate vulnerabilities effectively in industrial facilities today is a manual and extremely research-intensive process.

OT cybersecurity professionals must monitor many different vulnerability sources, including (but not limited to) the NVD data feed, ICS-CERT alerts and advisories, Microsoft security advisories, and automation vendor security bulletins — all of which contain information about vulnerabilities that can pose risk to industrial facilities.

When a new ICS-CERT advisory or automation vendor bulletin is published, OT cybersecurity professionals send enterprise-wide emails asking asset owners to determine if systems running in multiple facilities across the enterprise are vulnerable, and if so, to send back their remediation plans and timelines.

Asset owners within each plant must sift through spreadsheets and data collected in many different siloed proprietary automation vendor products to find answers. Figuring out what needs to be done to address a vulnerability and what the consequences of vulnerability remediation will be on production requires painful research. In most facilities, there are simply not enough staff in place to stay current with the rapidly evolving OT threat landscape. Many asset owners in facilities lack sufficient cybersecurity knowledge and expertise. Timely, accurate responses from busy asset owners are difficult.

OT cybersecurity professionals in the power industry must have a more automated, efficient way to assess their production-centric endpoints against the latest vulnerability advisories from Microsoft, ICS-CERT, and the automation vendors. When new vulnerabilities are published, plant staff need to know applicability immediately — not weeks, months, or years later. They need to understand the risk level a specific vulnerability presents, and what remediation actions they need to take to prevent a threat actor from exploiting vulnerabilities and negatively impacting power generation or safety.

Limited Visibility into Vulnerability Remediation Effectiveness

Obtaining timely, accurate information on the state of vulnerability remediation activities is difficult in most industrial environments. There are a variety of different automation system brands and models running in a plant — many times 30 or more. Vulnerability remediation tracking and reporting processes still rely on spreadsheets of manually entered information. Such data are error-prone and quickly out of date. And even when accurate, vulnerability management workflows cannot be triggered from data stored in emails and spreadsheets. The state of vulnerability management today means the following is difficult:

• Creating an enterprise-wide view of OT vulnerabilities and remediation states
• Determining if a vulnerability has been remediated or mitigated by a compensating control
• Determining how long vulnerability remediation activities take to complete
• Identifying which facilities are proactively meeting corporate policies regarding vulnerability remediation on critical assets, and which facilities are less proactive or need additional assistance with vulnerability remediation activities

OT cybersecurity professionals must have a better way to manage vulnerability remediation activities and obtain visibility into vulnerability remediation states. Without a continuous view into vulnerability remediation activities and states, OT cybersecurity professionals run the risk of assuming their plants are more secure than they actually are.

Manual, Inconsistent Patch Management

Many organizations have well-established patch and vulnerability management capabilities for their IT-centric endpoints. However, far too many organizations still struggle to assess, implement, and validate patches in plants. This puts ICS assets at risk.

Consistent, systematic patch management is an essential requirement for a secure plant. It reduces the attack surface, improves the overall security of OT systems, and reduces vulnerability risk. However, according to the SANS Securing Industrial Control Systems, 2017 report, patching is a problem in most industrial environments. Only 46 percent of respondents regularly apply vendor-validated patches.

Patch management is a significant challenge, and a major burden, for plant staff. OT systems are highly proprietary, complex systems, implemented with very specific hardware configurations and operating system versions. Due to precise configuration specifications for automation systems, software or configuration changes can cause systems to malfunction and negatively impact process reliability and safety. Patches for OT systems must be thoroughly tested by both the vendor of the industrial control system and asset owners or automation engineers prior to implementation. Due to concerns over uptime requirements, asset owners in plants must plan and schedule ICS updates months in advance. Revalidation may also be required as part of the update process.

The SANS Securing Industrial Control Systems, 2017 report strongly recommends “establishing a fully-staffed, closed-loop program to manage testing and implementation of patches.” Implementing a closed-loop patch management process provides the following benefits:

• Improves operational efficiency by coordinating disparate patch management ownership functions between IT and OT.
• Improves visibility into the current state of patch management activities across assets, facilities, and the business unit.
• Reduces risk by better protecting the organization from headline-grabbing safety incidents and production outages.

Solution: Continuous ICS Vulnerability Management

Obtaining a complete view of the vulnerabilities that reside across the myriad of proprietary automation vendor systems is daunting. However, failure to manage OT vulnerabilities effectively leaves industrial endpoints exposed, and can negatively impact production safety, reliability, and profitability.

PAS has used its more than two decades of expertise in the power and process industries, in combination with its long history of automation vendor platform independence, to deliver continuous ICS cybersecurity vulnerability management for Level 2, 1, and 0 industrial systems. PAS Cyber Integrityâ„¢ provides comprehensive ICS vulnerability

management for complex, multi-vendor industrial power and process environments. Only Cyber Integrity gives the centralized ICS vulnerability insight from a sole source of truth that OT cybersecurity professionals need to protect critical industrial infrastructure effectively.

Automated Vulnerability Assessment

Cyber Integrity automates vulnerability assessment and identifies which ICS assets may have vulnerabilities that put production systems at risk. Cybersecurity teams can see all vulnerabilities across the entire enterprise, or filter to display vulnerabilities by plant, unit, area/zone, or individual asset. Results include the NVD Common Vulnerability Scoring System (CVSS) risk rating for each vulnerability.

Cyber Integrity also provides on-demand vulnerability assessment queries that run against the Cyber Integrity inventory of managed assets for quick assessment of control system vulnerabilities and cyber risk exposure. Results from on-demand queries can be imported into other automation system vendor management consoles that integrate with Cyber Integrity.

Remediation and Mitigation Workflows

A systematic approach to vulnerability mitigation or remediation enables improvements to overall OT security in industrial facilities in a cost-effective way. Industrial facilities that follow good vulnerability management practices prevent incidents by reducing the risk of OT vulnerability exploitation. Reducing the attack surface not only reduces the risk of an unplanned outage, it also better protects the organization from headline grabbing safety incidents and production outages.

Vulnerability remediation workflows in Cyber Integrity give a continuous view into the state of vulnerabilities in the OT environment by enabling documentation, inventory-matching, and reporting on existing vulnerabilities, as well as visibility into the risk associated with the vulnerability and the current state of vulnerability remediation.

Workflows are highly customizable to meet the unique needs of an organization. For example, personnel can define vulnerability remediation workflows for mitigating a specific vulnerability across a group of assets, or to mitigate multiple vulnerabilities across a single asset or group of assets. Personnel can also define workflows for remediating vulnerabilities via patching or other methods, such as implementing a compensating control or performing a system upgrade.

Closed Loop Patch Management

Organizations that implement Microsoft software patches on a prompt basis reduce the risk of OT vulnerability exploitation. Cyber Integrity patch assessment capabilities give a centralized, unified view into current Microsoft patch currency across all managed cyber assets. Cyber Integrity provides highly customizable patch management workflows designed to document and ensure that all proper steps are followed during the various stages of the patching process, including appropriate patch evaluation, testing, implementation, and verification.

Summary views show which systems have patches applied, as well as which systems still need patching.

Vulnerability Dashboards and Trend Views

Customizable vulnerability management dashboards within Cyber Integrity give asset owners, plant staff, OT and IT cybersecurity professionals, and the executive leadership team visibility into the data they need to make informed vulnerability remediation and cyber risk management decisions. Vulnerability trend views display trends over time and can help answer the following types of questions:

• How many critical vulnerabilities have been identified this year compared to the number of vulnerabilities identified during the same period last year?
• How long does it take each plant or unit to mitigate or remediate critical vulnerabilities and reduce risk?
• Which facilities are consistently meeting mandates to address ICS vulnerabilities over time, and which are not?
• Am I compliant with vulnerability management standards?

Summary

There is no question that safety, reliability, and profitability within power and other critical infrastructure facilities face a growing, worldwide threat from cyber attacks. Outlaws are bent on cutting power companies’ cyber versions of the Devil’s Rope. Unfortunately, many ICS asset owners lack an accurate understanding of their true risk — particularly from industrial control system vulnerabilities.

Exploitation of vulnerabilities in industrial networks can lead to significant consequences. Level 1 and 0 ICS vulnerabilities exist in organizations today, but they are difficult to identify and remediate using current methods. This leads organizations to focus on Level 2 vulnerabilities instead.

However, Level 1 and 0 vulnerabilities are what matter most in industrial environments as they have the greatest influence on production and safety. Automating discovery and elimination of these vulnerabilities should be a top priority for ICS cybersecurity teams and one of the best defenses in a fence cutter war with no end in sight.

David Zahn is chief marketing officer and general manager of the Cybersecurity Business Unit at PAS Global, LLC. Scott Hollis is director of Product Management at PAS Global.

For any new natural gas-fired power generation project, a developer or owner must wrestle with the question “what is the right technology?”. For very small projects, the answer often defaults to reciprocating engines. For very large projects, it is combustion turbines in a combined cycle configuration. But for the facilities in between, the right answer is not always so clear.

This article compares reciprocating engines to simple cycle combustion turbines for a nominal 50 MW gas-fired plant in the Midwest, connected to the electric grid. It evaluates capital costs, operating costs, reliability, operational flexibility, system responsiveness to dispatch requirements, and site considerations.

Background

Inexpensive shale gas has resulted in an increased interest in natural gas-fired power generation in many parts of the nation. The profusion of this new generation, its implications on the utility and distributed generation markets, and project viability are topics of many publications. For the purposes of this paper, it is sufficient to say new natural gas-fired electricity generation is attractive for an owner in the Midwest, and evaluation of their needs indicates approximately 50-MW electric generating capacity is the appropriate size. Additionally, the purpose of the facility is electric generation only; no thermal energy in the form of steam or hot water is being considered.

For all generating facilities, the best-fit technology needs to be evaluated carefully. Developers and owners are making large investments, and need to consider many factors to ensure appropriate returns on that investment. However, conventional wisdom would dictate that a “small” natural gas-fired generating facility is best served by reciprocating internal combustion engines (RICE), as it would be expected to operate intermittently, and that a “large” generating facility is best served by a combined cycle system(s) as it would be expected to operate nearly continuously. But what about this 50-MW facility, which is “mid-sized”? What is the appropriate technology for this installation?

When this study was first contemplated, the primary technology options were intended to be RICE, a simple cycle combustion turbine (CT), and a combined cycle system. However, we quickly determined that the combined cycle arrangement was not going to be cost effective. It is conceivable that a combined cycle plant might be the right choice for a mid-sized facility if the thermal energy can be used and/or the facility will run continuously, but with our premise that the thermal energy has no value beyond additional electric generating capacity, the payback for the additional capital expense was not reasonable. Therefore, this article focuses on a comparison between RICE and simple cycle CT for this application, contemplating the major questions of:

• How much should it cost?
• How will it be used?
• Where will it be located?
• How much will it actually cost?

It is also worth noting that, while this study utilizes a specific example site, the items evaluated can be applied to any project.

How Much Should It Cost?

As a starting point in the evaluation, typical engineering, procurement, and construction (EPC) costs for the technologies were evaluated to establish viability. Property costs were excluded, as the site was already owned, as were permitting and other owner costs since those would be similar regardless of the technology selected.

Based on a sampling of published cost information, average EPC costs for RICE technology is approximately $1100/kW, and $800/kW for CT. The sample selected was based on installations in the 20-100MW size range, where such delineation was possible, and data points that appeared to be outliers were discounted.

Similarly, typical O&M costs were evaluated for the two technologies. Fuel costs, which represent the largest portion of overall operating costs, were excluded, as differences in those costs can be accounted for in the differing efficiencies of the equipment. Apples-to-apples data comparison for these costs proved more difficult, since the data can be represented in a variety of ways.

The non-fuel O&M costs in Figure 2 address both fixed and variable costs for a typical installation. For the most comparable data, over the expected unit life, the average annual O&M cost for RICE was approximately $0.016/kWh and $0.007/kWh for CT.

Operating and maintenance costs for RICE include maintenance labor, engine parts and materials such as oil filters, air filters, spark plugs, gaskets, valves, piston rings, and electronic components, and consumables. The recommended service includes inspections/adjustments and periodic replacement of engine oil and filters, coolant, and spark plugs every 500 to 2,000 hours. A top-end overhaul is recommended between 8,000 and 30,000 operating hours, which includes a cylinder head and turbocharger rebuild, and a major overhaul is performed after 30,000 to 72,000 operating hours, which involves piston/liner replacement, crankshaft inspection, bearings, and seals.

For CTs, the maintenance requirements are less than RICE, and include labor for routine inspections and procedures, and major overhauls. Generally, routine inspections are required every 4,000 operating hours to ensure that the turbine vibration is within tolerance. A gas turbine overhaul is needed every 50,000 to 60,000 operating hours, which includes a complete inspection and rebuild of components to restore the gas turbine to nearly original performance. Note that operating hours for CTs are not directly comparable to RICE operating hours, as virtual hours are added to CTs for starts/stops and excessive load changes.

As shown, typical installed and non-fuel O&M costs are lower for CTs than RICE. The potential advantage of a RICE facility comes into play when operating characteristics and usage considerations are evaluated. Since maintenance costs for RICE installations do not increase with cycling and multiple starts and stops of the equipment, effective O&M costs begin to levelize between the technologies when employed in facilities that will experience this type of operation.

How Will It Be Used?

As engineers, we often seek an optimized solution, a “best fit”. With this mindset, the intended purpose of the generating facility can often drive the technology selection, since the technical characteristics of the equipment inherently lend themselves to different applications. However, careful consideration is still needed, and final selections are, of course, still rooted in economics.

These technologies can be used for a variety of purposes in generating facilities, such as peaking generation, frequency stabilization and renewable generation support, to address reliability and resiliency concerns, and for capacity sales. As part of the comparison for these uses, some of the key differing technical features are shown in Table 1 below.

RICE heat rates are lower and efficiencies higher than CT, which results in lower fuel costs for the same output. Since fuel is the single largest operating expense for a generating facility, this is an important factor. Additionally, RICE efficiency remains steady throughout the load range, whereas CT efficiency decreases at reduced loads. The load range is broader for RICE than CT, both for a single unit, as well as for the total facility due to multiple smaller machines instead of one larger machine.

“For CTs, the maintenance requirements are less than RICE, and include labor for routine inspections and procedures, and major overhauls.”

Reciprocating engines are also able to start-up and reach full load capacity more quickly, and can withstand dramatic changes in load and many starts and stops with minimal impacts to the equipment and maintenance cycles. The ramp rate, both up and down, is substantially higher for RICE than for CT. Although CTs can be cycled, excessive load changes and starts and stops effectively adds operating hours, dramatically increasing maintenance costs.

Based on these characteristics, either RICE or CT appears to be the better fit for certain operational scenarios. When the hours of operation and load range are closer to intermediate load than to a high-cycling type of operation, the lower capital and O&M costs for the CT typically result in a higher return on investment, despite the lower efficiency. When the load profile is more volatile, the lower fuel and O&M costs for the RICE typically results in a higher return on investment, despite the higher installed cost.

Peaking Generation

For peaking applications, both RICE and CT can be viable options. Most of the literature advocates RICE for its fast start capabilities and broader load range as a better match to changing grid needs. Reciprocating engine facilities can reach full load within 3-5 minutes, and depending on the number of units, can operate from 10-100% of total plant load, or even lower. As stated above, they do not decrease in efficiency at reduced load operation, and can withstand many load changes and starts and stops without penalizing maintenance costs.

When evaluating the cost implications of these attributes (reduced fuel and maintenance costs), RICE may very well be superior. However, CTs can still be an attractive option for peaking applications depending on the specific conditions. For example, many regional organizations have excellent peak prediction tools. This information allows operators to make informed decisions regarding start-up and run time for their CT plants, reducing concerns about response time and cycling operation, as they can choose to respond only to longer duration peaks.

Frequency Stabilization and Renewable Support

Different from peaking applications, the use of generating facilities for frequency stabilization requires fast response. This is most often needed to support the grid as a result of the increased use of renewable generation, due to the non-synchronous generation of wind and solar power. Wind and solar may account for 20% of installed power capacity by 2035, but only contributes about 2% of firm capacity that can be relied on to generate at any given time. Other factors that can lead to grid instability include fast variations in consumption, errors in forecasting, and unexpected disturbances in capacity or loads. As a RICE facility can ramp quickly, it is the rational choice if this is the goal of the facility.

Reliability and Resiliency

Recent natural and man-made disasters have placed reliability and resiliency of our electric power supply at the forefront of national discussion. Both RICE and CT facilities are highly reliable, with up to 98% availability with proper maintenance; this equipment can be counted on to operate when called upon. However, RICE does have some advantages in this area. For our 50-MW plant, a single CT would be employed, as that would be the most economical installation. Since there is only a single unit, versus multiple RICE, the RICE installation has inherent redundancy that the CT could not match. In the event one engine was out of service, the remainder could still produce power. In the unlikely event emergency power was required during a turbine rebuild/replacement, there would be no option for generation. Additionally, RICE facilities can be used for black-start support, as they can be started without auxiliary power. Combustion turbines require auxiliary power to start system components.

Capacity Sales

Some facilities exist for electricity sales to wholesale capacity markets. In this case, either technology is well-suited for the application. Both technologies are completely dispatchable, so they can be utilized when the price of electricity is advantageous for them to do so or when called upon by a grid operator. However, some operators attempt to capture very short-term price spikes, in which case RICE may have an advantage due to its faster response time.

Where Will It Be Located?

Every site is unique, and specific site attributes can have a major impact on the financial viability of a project in general, and on the selection of the appropriate technology. In many cases, these will override the well-established rules discussed above.

Footprint

As illustrated in Table 1, CT systems utilize approximately one-third to one-quarter of the area needed for equivalent RICE generation. Additionally, CTs are relatively lighter weight and do not require substantial support foundations, resulting in less site work overall. This difference in footprint is accounted for in the installation cost of the project, including the typical EPC costs referenced in this paper. However, beyond the common installation costs, this difference in footprint can result in additional costs to the project. For a brownfield site, this may mean additional demolition or remediation services are required. Or for a landlocked area, the expense to purchase additional land could make selection of RICE prohibitively expensive.

Ambient Conditions

Reciprocating engine performance is impacted very little by changes to the incoming air conditions, therefore air pressure reductions at high altitude (up to 3,000-ft above sea level or more) and large ambient temperature ranges (up to 100 °F) do not significantly affect operations. Conversely, CT performance may degrade as much as 10-15% from ISO conditions for the same range due to incoming air properties. High altitude installations need to adjust heat rate/efficiencies in their performance model to properly represent the expected output. To combat the degraded performance for CT at high air temperatures, an inlet air cooler is often installed. This results in improved efficiency of the CT, but requires additional capital expenditure, and operating expense in the form of water usage. Either technology can be effectively utilized, but RICE has the advantage of maintaining base performance.

Natural Gas Pressure

Combustion turbines require much higher inlet gas pressure than RICE, 300-600 psig vs 75-150 psig. If the site has access to a high pressure natural gas line, this may not be of much concern. However, most owners do not have such luxury, and therefore will need to install gas compressors for a CT installation. These compressors are noteworthy pieces of equipment in their own right, with significant capital and O&M expenditures required.

Noise

Both technologies will generate far-field noise when in operation, so proximity to receptors will be a concern regardless of selection. Typically, specifically engineered sound enclosures and/or buildings will be sufficient; however, RICE tend to generate higher frequency noise that is more difficult to control than the lower frequencies produced by CTs. If the site is in an area with sensitive receptors, additional sound mitigation measures may be required, resulting in increased capital costs for the RICE.

Emissions

Both technologies are efficient combustors and have low resulting emissions, and both can be outfitted with selective catalytic reduction (SCR) systems for NOx and CO control. This is an area where the fast start and response time of RICE can be a detriment, as the emissions control equipment does not respond as quickly. During start-up or fast ramping, emissions levels may fluctuate, causing temporary spikes. Average emissions limits are not likely to be a concern in most parts of the U.S., however, permits need to be reviewed carefully for instantaneous or peak allowable emissions levels. Restrictions on instantaneous levels may restrict operational flexibility, resulting in loss of function that impacts the project pro forma.

Water Availability

As noted above, for high ambient temperature installations, CTs will often be outfitted with an inlet air cooler, which will require high purity water. Some CT models also require water injection for cooling and emissions controls. If water scarcity, or the cost of demineralized water, is a concern at a site, the resulting operating costs may favor RICE. Reciprocating engines require an external cooling circuit, but typically utilize a closed-loop system with minimal make-up water needs.

Future Expansion

Both CT and RICE equipment can be supplied as modular units, which can reduce installation costs by shifting labor from the field to the shop. Additional units can be added on site as a path to expand generation capacity in the future. Due to the smaller size of the RICE units, it is far more practical to incrementally expand capacity by adding one engine at a time than it is for CT. If incremental expansion is a possibility for a facility, RICE will permit that expansion, whereas additional CTs will result in major step changes.

Unique Site Considerations

The list of potential site considerations is nearly inexhaustible. There are many unique features to any location that could impact cost and/or technology selection. In many cases, the outcome will be the same regardless of the technology selected, but consideration is still warranted. Some items to evaluate include:

• Does the site share utilities with other facilities? What is the impact of installing new generation capacity on these utilities. For example, will the natural gas consumption restrict capacity or impact pressure for the other users? Will a substation connection or upgrade impact operations?
• For a re-development site, are there opportunities to re-use existing infrastructure, such as electrical distribution equipment, water or compressed air systems, buildings, etc. to reduce capital costs?
• Is there the potential for unknown subsurface conditions, contaminated soil, hazardous materials, or other similar brownfield issues? In cases like these, the smaller footprint of the CT could result in significant savings over the RICE.
• Air permit considerations were noted above, but are there other permitting concerns that could impact the installation? Siting and connection permits can be just as challenging as air permits.
• Does the owner or community have aesthetic concerns or preferences to incorporate?
• Does the installation need to consider future development in the area?

Example Facility

How do the criteria above play out for our 50-MW example facility in the Midwest?

How Much Should It Cost?

As noted in the background, new natural gas-fired electricity generation is attractive for an owner, who intends to generate electricity only; no thermal energy use is being considered. The rough pro forma indicated a breakeven EPC cost of $1100/kW, dependent on the actual estimated O&M expenses. This alone leaves either RICE or CT squarely in contention.

How Will It Be Used?

Like most installations, the facility is intended to address many needs. Its primary purpose is peak shaving, where the owner feels they can save their customers money by avoiding utility peak rates. It is also viewed as a resiliency addition, as many customers in the area are served by a single utility feed; if the primary line goes out this generation can serve as back-up for those users. Also, if electricity prices increase in future PJM capacity auctions, this operator may choose to sell into the open market and take further advantage of their investment. Again, this blend of needs leaves RICE and CT both as viable options, although many would argue that RICE would be the better option for a peaking application as well as for redundancy.

Where Will It Be Located?

The site is an existing electric generating facility that has been decommissioned, but the building and some equipment remains. Figure 3 below shows an edited aerial view of the example site.

Some of the typical site considerations discussed above do not heavily influence the technology selection for this site. The location is in the Midwest, so altitude or extreme ambient temperature effects are generally negligible. There is an existing gas line to the property at approximately 150-psig operating pressure. Therefore, a gas compressor will be required for CT, which will be accounted for in the EPC and O&M cost estimates; the owner has no concern with installing or operating the compressors. Water is available, and in fact an existing demineralized water system is still functional. There are no specific permitting concerns for either technology. Again, clear drivers towards one technology or the other have not presented themselves, although the added expense of the gas compression may slightly favor RICE.

At this point, the paths start to diverge. The site is large, and has ample clear space. As shown in Figures 4 and 5 below, it appears that the footprint for CT or RICE can be accommodated.

What’s not clear upon first glance are the unique site considerations. As seen in Figure 3, there are currently residences across the street from this facility, and there are plans to modify the same area as a recreational/entertainment district in the future. Therefore, the community has strong preferences to maintain the vintage appearance of the old boiler house, and keep any new equipment out of view from the road. They are also dictating noise restrictions at the road. These restrictions rule out the RICE A arrangement without erecting a barrier wall or upgraded building walls to create an aesthetically pleasing façade and provide additional sound attenuation.

This is an old site, that has had equipment added and removed over its lifetime. The potential to encounter unknown subsurface utilities and structures is high, so a smaller footprint presents less risk. Specifically, regarding the RICE B arrangement, in the half of the clear area near the neighboring building, there are groundwater remediation and monitoring wells for a nearby site. Obtaining approval and relocating these wells to accommodate the RICE B arrangement would be a costly endeavor.

“For a mid-sized generating facility, about 50 MW, either RICE or CT technology, can be the right choice depending on the specific attributes of the project.”

In addition to the demineralized water system already mentioned, the existing stack shown is in good condition for re-use, as is the compressed air system, and some electrical distribution gear. The differentiator is the stack; the single CT could possibly utilize the stack, whereas multiple RICE cannot.

The owners of the proposed generation facility also prefer to leave space for additional capacity. There is space for another CT unit, but increasing the size of the RICE facility would only exacerbate the aesthetic, noise, and subsurface situations.

How Much Will It Actually Cost?

Typical EPC and O&M costs were presented at the beginning of this paper. While average numbers are good to use for screening purposes, as shown in Figures 1 and 2, the actual figures can vary widely. EPC costs for RICE varied from $700/kW to $1700/kW, and from $400/kW to $1100/kW for CT. Non-fuel O&M costs varied from $0.007/kWh to $0.025/kWh for RICE and $0.004/kWh to $0.015/kWh for CT. Based on the factors presented here regarding facility use and location, the reader can gain appreciation for why that variation exists.

For our example project, the system’s essential purpose and expected usage would tend to favor RICE. In a vacuum, that’s likely what the owner would choose to deploy. But footprint, noise, future expansion, and other unique site considerations favor CT. Fortunately, the financial implications of those site factors could be evaluated to select the technology best suited for the project overall.

The EPC cost for the CT installation is approximately $850/kW and the cost for the RICE installation is approximately $1250/kW. In this case, the financial models showed that CT was the preferred choice. Over the lifecycle of the facility, the additional capital associated with site modifications for the RICE installation was costlier than the lower efficiency and O&M penalties associated with less than ideal operation of the CT.

The owner evaluated changing the plant size to see if the financial model would favor RICE at another output. As the facility decreased in size, the differential did close. However, concerns then arose regarding the ability to meet peak load requirements. As the facility increased in size up to approximately 100MW, the preferred technology remained CT.

Conclusion

For a mid-sized generating facility, approximately 50-MW, either RICE or CT technology can be the “right” choice depending on the specific attributes of the project. Conventional wisdom exists for a reason, and often points to the best fit solution. However, like our example facility, care needs to be taken to account for many competing factors before making a final selection, some of which have been discussed in this paper, and others that may be completely unique to an owner/developer or to a specific site. With proper diligence, the proper selection emerges.

Melanie Schmeida is Client Service Leader at Louis Perry Group, a CDM Smith Company.

Power from the Prairie is a proposed 4,000 Megawatt HVDC transmission project in the wind-rich energy resource of the Upper Midwest.

The Northern Prairie region of the United States (i.e., Wyoming, Nebraska, the Dakotas, etc.) has an abundance of wind and wide-open spaces that could be used to develop large, wind-powered electricity generation resources. The opportunity is daily, bi-directional renewable energy swaps between California, the Northern Prairie, Chicago and points East.

Past studies by the Midcontinent Independent System Operator (MISO) have shown that a national high-voltage direct current (HVDC) power transmission grid could significantly improve the capability of wind to reliably and economically supply power to load. But the practical hurdles to developing a suitable nationwide power grid all-at-once are a barrier to such a solution. However, it may be possible to initially achieve such economies and reliable production at a more focused, regional scale, as building blocks toward an eventual nationwide system. Such regional scale must have an abundance of wind (and potentially solar energy too), access to significant markets for such electricity, and the capability to add large-scale, grid-level energy storage where available and cost-effective.

Such development could also be used to enable the State of California to achieve its planned high levels of Renewable Portfolio Standard (50 percent or more) by building sufficient renewables in-state. When California inevitably over-generates from its solar photovoltaic installations during the solar day, it could export the over-production to other states over the network, and then import a previously-contracted “swap” of renewable energy back from other states when the sun sets.

The Power from the Prairie Project

Power from the Prairie is a proposed 4,000 Megawatt HVDC transmission project in the wind-rich energy resource of the Upper Midwest (Figure 1). The new line would extend from Southeast Wyoming across Nebraska or South Dakota to Northwest Iowa or Sioux Falls or Omaha. It would feature a DC/AC/DC terminal in the middle to enable interconnection of large quantities (thousands of MW) of additional renewable energy in Nebraska and South Dakota currently blockaded and unavailable due to lack of transmission for access to markets. The effort may also include grid-level energy storage, if found to provide material benefits in addition to the HVDC line itself.

The goals of Power from the Prairie are:

• Develop low cost electricity with wind resources in the Northern Prairie that will take advantage of the natural geographic and temporal diversity of customer loads as well as wind and solar generation resources across large, inter-regional areas;
• Reduce utility generation capacity reserve requirements and associated costs without sacrificing reliability;
• Enable the economic integration of massive quantities of economical renewable energy resources into the grid–supporting very high Renewable Portfolio Standards (RPS);
• When combined with similar HVDC developments to the West and East, enable large-scale hourly and daily renewable energy swaps between California, Midwest and Eastern states to achieve high levels of renewable energy; and:
• Provide a primarily-clean energy replacement alternative for legacy generation facilities as they are retired.

The result would be an inter-regional, renewable energy superhighway with multiple new ‘on-ramps” for renewable resources currently blockaded due to lack of transmission, enabling renewable energy swaps between regions to make intermittent renewables more reliable. Simply, when viewed along the span of a long, multi-state and efficient HVDC transmission system, renewable energy is always happening somewhere.

Relationship to Other Efforts

DOE/NREL Interconnections Seam Study

The U.S. Department of Energy (DOE) Grid Modernization Program includes aggressive initial efforts toward a national high voltage direct current (HVDC) transmission grid overlay over the existing alternating current (AC) system. As part of the Program, the National Renewable Energy Laboratory (NREL) is performing a $1.3 million “Interconnections Seam Study” examining the conceptual and economic feasibility of such a national transmission overlay, combined with renewable energy.

The term “Seams” refers to the current boundaries between the Western Interconnection, Eastern Interconnection, and Electric Reliability Council of Texas (ERCOT) systems. See Figure 2. These three alternating current (AC) systems operate independently, and asynchronously. That is, their 60-cycle AC waveforms are not aligned. They are connected together only at seven relatively small (200 MW or less) AC/DC/AC terminals located along their seams. The Seams Study is examining how transfers across the Seams (and thus between the Interconnections) can be significantly increased in the future.

The use of HVDC transmission technology is important because: a) it is more efficient over long distances; b) its power flow is electronically controllable /throttleable (compared to AC systems where the power flows by the path of least resistance); and: c) it can be used to interconnect asynchronous AC systems. The latter benefit is critical to enabling large-scale renewable energy transfers across the Interconnection “Seams”.

The intended result is that the Seams Study will provide a global look at the generic, conceptual feasibility of a nationwide HVDC transmission overlay. Preliminary results of the Study, to be publicly released in early 2018, indicate such a national HVDC transmission grid combined with renewables would be a cost-effective resource for electric customers. NREL staff is sharing modeling data and study results with the Power from the Prairie team.

A follow-on Concept Development Study (CDS) described later in this paper will define and examine the economics and other key factors of a Power from the Prairie development–entailing a specific HVDC line route with specific project participants, and identifying who would benefit from such a project. The PftP CDS will provide a focused, project- and utility sponsor-specific look at one initial element of such a nationwide infrastructure, plus concepts of how such transmission elements could be accomplished.

Other HVDC Transmission Developments

The Power from the Prairie line would form a go-between for several currently under-development HVDC transmission line development projects. To the West in Wyoming, it would link with either the Anschutz “TransWest Express” project from South Central Wyoming to Delta, Utah to Las Vegas. This project is already on the Trump Administration’s’ priority list for infrastructure projects. Alternatively, PftP could link with the Duke-ATC Transmission “Zephyr” line from Southeast Wyoming to Delta, Utah.

Once at Delta, Utah, there is an existing HVDC transmission line from there to Los Angeles called the Southern Transmission System (STS). This 500 kVDC, 2400 MW line currently delivers baseload energy from the 1,900-MW coal-fired Intermountain Power Project at Delta to Southern California. The plant is scheduled to be retired in 2025.

To the East, Power from the Prairie would link to similar HVDC projects like the Rock Island Clean Line from Northwest Iowa to Chicago and PJM Interconnection. Although Rock Island is experiencing court challenges in Illinois, unfortunately such challenges are part of the business of such developments. In the spirit of DOE Grid Modernization and Seams Study efforts, the authors believe such projects will eventually proceed.

Large Scale Energy Storage

A Power from the Prairie effort could include two types of large, grid-scale energy storage: virtual and physical.

Virtual Storage

Virtual storage refers to a system that exhibits the characteristics of storage, but does not entail physical storage. Energy swaps between California and Upper Midwest States would be virtual storage. From California’s perspective, they would export energy to other states via the HVDC system during renewable overproduction time periods in California. Later, California would receive renewable energy back from those states to complete the swap. To California, it looks like storage is happening somewhere else. When in reality, the other States may in fact be consuming California’s renewable overproduction, and then returning their own surplus renewable energy to California.

This virtual storage approach is not unique to Power from the Prairie. Minnesota Power recently enacted a similar scheme to send surplus North Dakota wind energy northward to Manitoba. Manitoba later returns hydro-based renewable energy to Minnesota Power when Minnesota Power needs it. And the exchange does not necessarily involve physical storage. Instead, in this innovative way the parties take advantage of the time diversity between the output of their renewable resources (both dispatchable and non-dispatchable), and the timing of their respective customers’ needs for electricity.

Physical Storage

With regard to physical storage, we are all now accustomed to the ongoing discussion and potential of battery storage. The Tesla Powerwall 2 for example, offering residential battery storage applications of 14 kilowatt-hours (kWh) of storage can be installed for a capital installed cost of about $540 per kWh of storage. And battery costs are projected to continue to decline.

For Power from the Prairie purposes, larger scale and storage duration are required. Grid-level storage offers particular advantages because, if sited correctly, it can be used as a transmission asset, enabling twice the amount of renewable energy to be sent down limited transmission capacity compared to renewables integration with just conventional, gas-fired generation alone. Simply, you intentionally “super-size” the capacity of renewable energy located electrically behind the storage compared to available outlet transmission capacity. Then, when the renewable output is more than the outlet transmission capacity can handle, you store the excess and release it later when the renewables are producing less, or when the transmission constraint is otherwise relieved.

Schulte Associates LLC has recently performed feasibility studies for large-scale (1200 MW or more, 48 hours of storage) compressed air energy storage (CAES) installations. Such a CAES installation at Delta Utah, a world-class CAES site candidate, could be combined with Wyoming wind and HVDC transmission to replace the existing 1900 MW coal-fired Intermountain Power Project at Delta. Such CAES would have a capital cost of only about $40 per kWh stored. And if you are storing wind energy that is subject to extended lulls, 48 hours of storage at full output is a lot better than the eight to ten hours typically assumed for stationery batteries.

Schulte Associates LLC has also been involved in feasibility studies for the Gregory County pumped hydro storage project combined with renewables in Central South Dakota. At 1200 MW or more and 26 hours of storage, this site is located directly on the route of the Power from the Prairie line.

Such physical storage could offer additional cost and reliability benefits than just the virtual storage benefits of the HVDC line itself.

The California Conundrum

The State of California along with Hawaii lead the nation in plans for renewable energy development. California law (Senate Bill 350) specifies a statewide Renewable Portfolio Standard (RPS) of 50% of total retail electric energy sales by the year 2030. That means, under penalty of law, California electric utilities must provide 50% of their total retail electric sales from renewable sources by 2030.

Recently, an even more aggressive bill, SB 100, was introduced that would have increased the RPS to 60% by 2030, with an intent to achieve 100% clean energy by 2045. This measure did not pass this year, but is sure to arise again in the next legislative session.

What does such a high RPS mean in terms of what practically needs to be done? Let’s do the math. California electric customers have an average annual load factor of about 55%. Renewable energy resources located in California (wind and solar) typically have an average annual capacity factor of about 25%. And California so far indicates a preference for having its renewable resources located in-state.

A 50% RPS based on annual energy means California will need to install renewable production capacity meeting or exceeding its annual peak electric demand by 2030. That’s the highest electric demand that happens on the hottest day of the year. That’s fine. But having that much installed production capacity that is non-dispatchable means California will be over-generating on all other sunny days during the year. Particularly in the spring, fall and winter, when electric loads are lower. The state is already experiencing periods when market prices go negative (that is, there is more generation than the market needs, and producers need to pay to generate; not get paid for it. And the 50% RPS level (much less the higher RPS levels being contemplated) is still many years in the future.

This California renewables over-production during the day needs to find a market. Conversely, California needs renewable resources to serve its loads when the sun is not shining there.

Making Renewables Distribution Bi-Directional

To-date, all of the proposed HVDC transmission developments designed to move wind energy from the Midwest to load centers have been designed to be one-way, unidirectional. Either from the Midwest to the East, or from the Midwest to the West. In contrast, in addition to enabling renewable energy from the Upper Midwest, Power from the Prairie exhibits an interesting feature for possible use elsewhere: bi-directional renewables distribution (See Figure 4). Renewable energy can travel on Power from the Prairie and its neighboring HVDC lines from the Midwest to the East or West. Or conversely, from California and the Southwest in general to the East.

The challenge of future renewables over-generation from California is probably larger than Power from the Prairie alone can resolve. Perhaps the other proposed HVDC transmission developments should be made bi-directional as well, by connecting them in the middle of the country like Power from the Prairie envisions for the Northern Prairie?

The Concept Development Study

As an initial step in such a regional approach, the Power from the Prairie team plans a Concept Development Study (CDS). The goal of the CDS is to develop initial definition, data and quantified benefits of a Power from the Prairie development to enable the study participants to determine if pursing such a development is in their customers’ and stakeholders’ best interest.

The CDS sponsors include multiple regional utilities and others interested in whether such a development would benefit their customers and stakeholders. The CDS will be performed from their perspective. It will also quantify the value of the proposed HVDC projects to West and East by themselves, and the market opportunities for Power from the Prairie to the West and East. The study, to be performed in mid-2018 as a follow-on to the NRES Seams Study, will entail four Tasks:

Task 1: Resource Modeling and Benefits. This Task will include modeling of the U.S. electric system from the Western Interconnection to the Eastern Interconnection, including the Western Electricity Coordinating Council (WECC), Southwest Power Pool (SPP), Midcontinent Independent System Operator (MISO), and PJM Interconnection (PJM); both with and without the Power from the Prairie development.

Task 2: Technology and Operations. This Task will define applicable HVDC technology options and market structures for operating such an inter-regional HVDC line. It will consider how such a line would operate in relation to regional and RTO/ISO markets. It will consider how automated the HVDC line operation can be, and how renewable and other facilities would request interconnection to it. It will also consider the types of cyber security provisions that need to be included in project design.

Task 3: Organization and Policy. This Task will define organizational options useful for creating a diverse “DC Federation” of participants for implementing such a project. It will also identify federal/state/local regulatory, policy and tariff issues and develop a repeatable roadmap for addressing them when planning and developing similar projects elsewhere.

Task 4: CDS Management, Coordination and Report Writing. This Task will ensure the CDS delivers quality and actionable products on-schedule.

The PftP team plans to complete the CDS by late 2018.

Grid-Level Storage to also be Considered

The CDS will also determine the economic and operational benefits of grid-level storage that could be provided with pumped hydro or compressed air energy storage (CAES) opportunities, and whether they would be incrementally beneficial in addition to the benefits of the HVDC transmission alone. It will also determine the reliability and economic improvements that may be possible through diversity between utility customer loads and available renewable resources across the region, and in conjunction with the large markets of the Midwest and West.

PftP would represent new inter-regional infrastructure in the form of an electric transmission “superhighway” for cost-effective renewable energy, with on-ramps for some of the richest renewable energy resources in the nation. Such resources do not appear in traditional power supply system studies that tend to only focus either on the needs of individual utility systems, or individual independent transmission owners, depending on who the project sponsors are.

In contrast, the PftP CDS will be done as an independent and objective due-diligence determination of who would benefit from such a project, and how much. It would not require development of a cogent, coordinated federal energy policy in advance.

Instead and more simply, let the project participants (utilities, individual states, and others) self-identify themselves in their own respective best interests as a federation of the willing.

Bob Schulte is a Principal in Schulte Associates LLC, an executive management consulting firm with offices in Raleigh, North Carolina. Fredric Fletcher is Chairman of Power from the Prairie LLC.

In recent years, Reciprocating Internal Combustion Engines (RICEs) have been utilized in the North American market to generate electric power and provide fast response to load fluctuations. As such, they have had an important role in maintaining a stable electrical grid. While the majority of these units have operated solely on natural gas, some areas have also utilized liquid fuel in order to provide stability where firm gas supply is unavailable or uneconomical. As the market continues to develop, new technologies have emerged that may impact the utilization of RICEs in the near future.

Primarily, large RICEs (7-20 megawatts [MW]) installed in North America have been of the four-stroke lean-burn variety. These engines have operated with good efficiency, high reliability, and impressive startup and ramp times in order to provide peaking power to the grid. However, RICEs are also used extensively in marine applications to power cruise ships and large freighters. In these applications, two-stroke RICEs operating on liquid fuels have also proven themselves as reliable and efficient prime movers. Their high power-to-weight ratio enables more cargo to be loaded without sacrificing power. Additionally, there are several land-based installations utilizing similar RICEs throughout the world. In general, two-stroke engines can achieve the same emission limits as four-stroke RICEs, though additional controls are required. Also, the two-stroke units are more reliable and efficient when operated continuously. Two-stroke RICEs are able to achieve efficiencies over 50%, while their four-stroke cousins are typically limited to less than 46% efficiency. It should be noted, however, that two-stroke engines require the lubricating medium for the cylinders to be a part of the fuel mixture. This makes them incapable of operating solely on natural gas, as is common for four-stroke RICEs in North America. They require at least 1% of their fuel supply to be liquid fuel in order to ensure that proper lubrication is maintained. Furthermore, the two-stroke engines offer more fuel flexibility than four-stroke engines and can efficiently operate on low-grade sources of liquid fuel.

However, the features that make two-stroke units advantageous are not significant impacts in the North American power generation market. In this arena, RICEs are typically operated in peaking and spinning-reserve modes, which negates the improved reliability of the two-stroke RICEs. When used in peaking applications, there is no conclusive evidence that they are more reliable. Furthermore, while the increased efficiency appears to be advantageous, this is offset by the additional costs required to install a liquid fuel system and provide additional emission controls to meet the strict permitting requirements of the market. Finally, the two-stroke RICEs’ ability to operate efficiently on low-grade fuels loses significance when high-quality and consistent fuels are readily available. It is for these reason that several manufacturers have chosen not to offer their large two-stroke RICEs in the North American market, though there does seem to be demand for smaller units (3-7 MW) that can run as base-load and avoid triggering Prevention of Significant Deterioration (PSD) regulations. Thus, they could be well suited for co-generation or other facility-focused power generation applications.

Another topic in the current market is battery storage. Large-scale battery “farms” are increasingly being viewed as an economical way to reduce volatility on the electrical grid by stabilizing demand and allowing renewable generation to appear more like base load. The theory is that batteries will charge from the grid when generated power exceeds demand and then discharge that power when demand outstrips supply. Until recently, lead-acid batteries had been the most economical option, but their short lifespan of 3-4 years prevented their widespread adoption. Recent advances in Lithium-Ion batteries, with their large capacities and long lifespans, have raised expectations that battery storage will become more profitable.

The question in regard to RICEs, then, is how do they co-exist in a market where batteries are able to reduce and replace the need for their ability to stabilize the grid? On a macro-scale, they do seem to be redundant technologies. However, it is in smaller-scale applications where the two are able to effectively co-exist. Many municipalities and other small-scale power providers already view RICEs as an effective means to free themselves from the fluctuations of market pricing and Power Purchase Agreements (PPAs). When electricity prices are low, it is economical to purchase power to charge batteries and store it for when prices begin to rise. When power pricing is higher, the RICEs can be used to offset the cost once the batteries have been depleted.

As technology continues to advance, so too do the solutions to market problems. Nonetheless, four-stroke RICEs are still appropriate for the North American market for the foreseeable future, though they can expect to share their role with increased battery storage as that technology continues to mature.