While SCADA systems comprise a relatively small portion of the cost of a large-scale PV power production facility, they are critically important to project success.
To keep everyone’s lights on, grid operators must be able to balance supply and demand across long-distance networks of high-voltage power lines. Supervisory control and data acquisition (SCADA) systems are what allow grid operators to monitor and dispatch power plants—often across vast areas—in response to constantly changing loads. As the solar industry matures and expands its presence on the electric grid, PV power plants are facing increased scrutiny regarding remote monitoring and control. While developers of rooftop projects can activate PV systems and leave them to run on their own, grid operators increasingly tend to require remote monitoring and control capabilities in utility-scale PV applications. Though these requirements are similar to those that apply to conventional generation sources, they may take solar industry veterans by surprise.
In this article, we provide a high-level overview of the North American utility grid and discuss how reliability coordinators and balancing authorities work together to maintain power quality and grid reliability. We briefly look at California to better understand some of the challenges grid operators face when greening the grid. We then take a PV plant–level look at SCADA systems and conclude by sharing best practices for the successful implementation of SCADA systems in large-scale PV plants.
SCADA is deceptively simple on the surface and devilishly complex in the details. Trade-offs that seem small in early utility negotiations can present very large issues for the project team in the field during construction and commissioning. Correctly establishing SCADA implementation requirements as early as possible can ensure project completion on schedule and under budget. Leaving things until the last minute nearly always guarantees delays and gaps in the command and control network. In this arena, it is wise to involve experts sooner rather than later, as the cost of their input will more than pay for itself over the operating asset’s life.
Balancing the Large Machine
The North American Electric Reliability Corporation (NERC) is responsible for maintaining the security and reliability of the bulk power system in North America. Its area of responsibility extends from the northern portion of Baja California, Mexico, across the continental US and Canada. There are four independently operating power grids, shown in Figure 1, within NERC’s purview: the Eastern Interconnection, the Texas Interconnection, the Quebec Interconnection and the Western Interconnection.
Within these large interconnections, reliability coordinators and balancing authorities are responsible for the proper operation of the bulk electric system, in much the same way that air traffic controllers ensure quality and reliability for the aviation industry. Reliability coordinators manage a wide-area view, with the aim of ensuring that the interconnection does not operate outside permitted limits, which could lead to instability or outages. Balancing authorities, meanwhile, are responsible for maintaining the real-time electricity balance within specific regions. NERC recognizes nearly 20 reliability coordinators and more than 100 balancing authorities.
According to a July 2016 blog post (see Resources) on the US Energy Information Administration (EIA) website: “Most, but not all, balancing authorities are electric utilities that have taken on the balancing responsibilities for a specific portion of the power system.” To avoid potential conflicts of interest, however, independent third-party entities known as regional transmission operators (RTOs) or independent system operators (ISOs) operate the bulk electric system in important regions of North America, as shown in Figure 2. These regions are responsible for much of the economic activity in North America, and the RTOs and ISOs ensure fair and transparent access to market transactions and the transmission network. The EIA blog post clarifies as follows: “All of the [RTOs and ISOs] also function as balancing authorities. ERCOT [Electric Reliability Council of Texas] is unique in that the balancing authority, [the] interconnection and the regional transmission organization are all the same entity and physical system.”
As described by the authors of the NERC technical document “Balancing and Frequency Control” (see Resources): “Each interconnection is actually a large machine, as every generator within the island is pulling in tandem with others to supply electricity to all customers.” If the output of these generators does not match customer demand, speed of rotation and frequency within the interconnection changes. The authors explain: “If the total interconnection generation exceeds customer demand, frequency increases beyond the target value, typically 60 Hz, until energy balance is achieved. Conversely, if there is a temporary generation deficiency, frequency declines until balance is again restored at a point below the scheduled frequency.” While the scheduled 60 Hz frequency target allows for some variation, the acceptable range is quite small, on the order of ±0.02 Hz.
For grid operators, frequency is the fundamental measure of power system health. An imbalance between load and generation causes frequency to vary, as do grid congestion or equipment faults. Because grid reliability is critically important, and the power system, interconnections and balancing areas are so large, multiple levels of balancing and frequency control govern the system. The primary control level, for example, includes governors on generators and load-interruption capabilities, which can adjust frequency within seconds and stabilize the power grid in the event of a disturbance. Meanwhile, the secondary control level allows grid operators to maintain the generation-to-load balance over a period of minutes.
According to the NERC technical report, the most common secondary control method is automatic generation control, which monitors and adjusts the power output of multiple generators at different power plants. Grid operators’ control centers choreograph these secondary balancing and frequency control activities, dispatching generators as needed to maintain the load-generation balance. A SCADA network, such as the one shown in Figure 3, allows for centralized data monitoring along with remote control of dispersed power-generation assets. SCADA systems not only provide grid operators with real-time insight into individual plant status and performance, but also allow them to dispatch resources as needed to support grid stability.
PROGRESS IN THE WEST
The biggest balancing authority in the Western Interconnection is the California Independent System Operator (CAISO), a nonprofit public benefit corporation that manages the bulk power system for roughly 80% of California and a small portion of Nevada. According to a CAISO publication documenting company facts and information (see Resources):“As the only independent grid operator in the western United States, [CAISO] grants equal access to 26,000 circuit miles of transmission lines and coordinates diverse energy resources into the grid. It also operates a wholesale power market designed to capture energy from a broad range of resources at the least cost.”
CAISO operates two control centers to manage all of these transactions and dispatches. Its headquarters in Folsom (see opening photo), home to one of the most advanced control centers in the world, features a 6.5-foot-tall and 80-foot-wide visualization screen. The control center also includes the first renewables dispatch desk in the country, which allows CAISO to manage the additional layers of complexity associated with integrating large numbers of variable generation plants. Since California’s renewable portfolio goals require that its investor-owned utilities (IOUs)—including Pacific Gas and Electric Company, Southern California Edison and San Diego Gas & Electric—generate 33% of their electricity from renewable sources by 2020, CAISO is very much at the forefront of the North American effort to develop flexible capacity and implement technologies that allow for a greener, lower-carbon power grid.
As of February 2017, CAISO was monitoring nearly 72,000 MW of generation capacity, including nearly 10,000 MW of solar PV. The peak summer grid demand in California is typically in the range of 45,000 MW–46,000 MW. Because variable renewable generation makes up so much of its power generation mix, CAISO needs solar and wind power plants to respond to automatic generation control signals and other dispatches just as conventional power plants do. That is one reason why California is leading the way in the development of smart inverter standards via its Rule 21 process. The first phase of this effort mandates that inverter-connected distributed energy resources autonomously perform certain grid support functions, such as dynamic power factor or voltage regulation, power curtailment, ramp-up and ramp-down rate controls, frequency controls, and start-up and shutdown controls.
A vast SCADA network—composed of computers, communication pathways, graphical user interfaces and remote intelligent electronic devices—allows CAISO to balance its grid in real time. In addition to allowing grid operators to initiate or update autonomous inverter functions, SCADA systems at PV power plants also ensure accurate settlements. Regardless of whether a PV plant connects at the high-voltage (38 kV–500 kV) transmission or medium-voltage (4 kV–38 kV) distribution level, the interconnecting utility needs to have some communication with and control of the local plant. Power plants that do not meet the grid operator’s SCADA requirements cannot interconnect. Moreover, poorly implemented SCADA solutions and plant controls may not be taking optimal advantage of the grid operator’s price signals.
SCADA and cloud-based monitoring systems are similar in the sense that they both measure and monitor PV system performance variables. What makes SCADA systems unique are their supervisory control capabilities. While grid operators and regulatory entities drive certain SCADA system compliance requirements, other project stakeholders also need insight into PV plant operations. For example, asset managers have a contractual obligation to report plant data to their financial partners and PPA customers. Plant operations managers need plant data to interface with utilities, conduct performance tests and schedule maintenance. O&M providers, meanwhile, must be able to see and respond to alarms and may also need plant data to comply with production or availability guarantees. A successfully implemented SCADA system accounts for the needs of all project stakeholders and eliminates unnecessary duplication where possible.
PLANT CONTROL SYSTEM
The plant-level controller is a key component of a utility SCADA system. The authors of a First Solar white paper about grid-friendly utility-scale PV plants (see Resources) explain: “[The plant-level controller] is designed to regulate real and reactive power from the PV plant, such that it behaves as a single large generator. While the plant is composed of individual small generators (or, more specifically, inverters), the function of the plant controller is to coordinate the power output to provide typical large power plant features such as active power control and voltage regulation.” In First Solar’s plant-level control system, shown in Figure 4, “The plant controller implements plant-level logic and closed-loop control schemes with real-time commands to the inverter to achieve fast and reliable regulation.”
At the plant level, much of the control equipment is housed near the point of interconnection with the utility. In some cases, that equipment is located within a dedicated substation control room; in other cases, it is enclosed in freestanding boxes, installed at ground level or on poles overhead. Depending on the system configuration, the substation has some combination of disconnects, breakers, meters, capacitor and reactor banks, energy storage systems and generator step-up transformers, as well as other components that collect and report component-level data. Typically, dedicated fiber-optic networks originate at the substation and connect to the individual equipment pads.
Components and connections can vary significantly at the pad level. In general, some combination of internet-style connections, industrial control connections and intelligent devices measure, translate, package and transmit data collected from the nearby equipment within the array. Data from across the PV power plant’s inverters, tracker controllers, weather stations and other inverter pad equipment, along with data collected at the substation, go to a real-time controller. The real-time controller runs analytical routines on that data to determine what, if any, changes operators need to make in running the plant to stay within the programmed operating limits.
Security. Because the plant controller is connected to the outside world, grid or plant operators, or other parties with secure access, can change the plant operating limits at any time via the human-machine interface (HMI). It is typical for a PV plant to have multiple outside connections to serve multiple stakeholders. Some of the plants we have worked on have as many as five separate internet connections. Regardless of the connection type—which could be fiber-optic cables, copper telephone lines, cellular modems, and microwave or other radio relays—the security of outside connections is a critical concern.
For instance, CAISO has specific security requirements for connections to its dedicated energy control network. While NERC defines many of these requirements, the Federal Energy Regulatory Commission (FERC) oversees it; one of FERC’s mandates is to approve minimum cybersecurity requirements for the bulk power system. Many utilities base their security protocols on CAISO and NERC standards, but nongovernmental parties to the project often have their own security requirements regarding authentication and encryption.
Network design. Understanding how devices within the project site will talk to one another is a significant part of SCADA implementation. As discussed in the article “Commercial PV System Data Monitoring, Part One” (SolarPro, October/November 2011), sites can rely on many different types of network architectures—such as transmission control protocol/internet protocol (TCP/IP), open data protocol, modbus and controller area network bus (CANbus)—as well as different layers of programming abstractions. For example, users interact with SCADA systems via the applications layer; data are packetized at the transport layer; message routing takes place at the internet layer; and physical components connect to one another at the link layer. At utility-scale PV power plants, multiple network types can exist simultaneously, and it is necessary to transfer data between these networks to operate the plant successfully.
In a plant with large central inverters, it is common for a TCP/IP-based network to connect directly to each inverter via fiber-optic cables. In some cases, the inverter also collects information from the inverter step-up transformer; in other cases, SCADA designers route this information to an analog input/output (I/O) device, and use a historian to record and digitize these data. A plant with string inverters more commonly has a media converter or datalogger near the transformer. One side of this device connects to the plant’s fiber-optic network, while the other collects information from the inverters and transformer based on whatever protocols are available. The pad-level controller could be receiving inverter data from one or more RS-485 networks, I/O data from the transformer, inputs from tracker-motor controllers and weather stations, plus reports from any other networked devices.
STRATEGIES FOR SUCCESS
When conceptualizing a SCADA system, you must consider three major areas: communications between on-site equipment, such as inverters, weather stations and transformers; communications with off-site regulators, such as utilities and grid operators; and communications with off-site stakeholders, including lenders, asset managers and O&M providers. These three distinct areas have overlapping interests, requirements and technical options for the project. If designers do not know or understand the requirements in each area during the design stage, the resulting SCADA system may have gaps or redundancies that will affect long-term operation, diagnostics and reporting.
To better understand where gaps or pain points may exist in the project’s life cycle, we interviewed subject matter experts representing several experienced SCADA providers, including AlsoEnergy, Draker, Nor-Cal Controls and Trimark Associates (see Resources for a Trimark white paper on best practices). Here we summarize common themes from these conversations and share some of our own strategies for success.
Get experts involved early. All the subject matter experts emphasized the importance of engaging a SCADA design consultant in the earliest project stages. From a certain perspective, modules, inverters and racking are the three major pivots for a solar farm, both financially and in terms of delivery. It is common for SCADA design to take a backseat to these big three items, since monitoring and control systems carry a lower price tag and have shorter equipment lead times. Our experience has shown, however, that a fragile SCADA system can bring an otherwise perfectly built PV site to its knees. Improper handling of SCADA design and implementation can hold up important project milestones—such as substantial or final completion—for weeks or months.
Regardless of whose system ultimately gets installed at the new power plant, project developers need to engage a SCADA consultant as soon as generator interconnection agreement negotiations begin, as these will determine the project’s monitoring, control, security and data storage needs. According to Gregg Barchi, the East Coast sales director for Draker: “There needs to be an industry-wide paradigm shift with regard to monitoring. The earlier we get involved, the better. If an NDA [nondisclosure agreement] needs to be in place for this to happen, we can do that.”
Scott McKinney is the senior marketing manager at Trimark Associates, a SCADA solutions provider headquartered in Folsom, California. He notes that it is important to establish fiber-optic specifications early in the project: “Regardless of the type of inverter system, the network structure is based on the specified number of strands, fiber type and connector type. Making the wrong assumptions and failing to ensure compatibility between all components can result in extra costs and project delays.”
In addition to supporting decisions about the fiber-optic system, an early collaboration with a SCADA provider can also bring clarity to other aspects of the data collection network. Stakeholders need to discuss other communication cables and connector types, software compatibility, security protocols, encryption requirements and component selection. The sooner they finalize these decisions, the better off everyone will be in terms of managing the capital costs and the project schedule.
Gather information in advance. To commence commercial operations and generate revenue, PV resource owners must meet grid operators’ SCADA and compliance-related requirements. Understanding these requirements starts with gathering as much information as possible. You begin by reviewing applicable contracts, including the PPA, generator interconnection agreement, asset management (AM) and O&M agreements, and relevant utility studies. You are looking for information regarding SCADA control equipment specifications, weather station specifications, utility command and control software requirements, references to federal software security protocols, and synchronization and performance testing requirements.
We recommend, in addition to doing a thorough documentation review, putting in a call with the utility—or, if applicable, the grid operator (ISO/RTO)—to verify compliance details. Most performance testing standards require that you collect and average data in 1- or 5-minute intervals at the time of the test. Other requirements come into play based on generating capacity thresholds. For example, NERC has cybersecurity requirements—outlined in its critical infrastructure protection (CIP) standards—that apply to projects larger than 75 MWac. CAISO, meanwhile, requires at least two weather stations for projects with a capacity greater than 5 MWac. It is important to convey these requirements to SCADA design consultants and get their feedback on the scope of work.
Many grid operators make their SCADA requirements publicly available in advance. For example, a CAISO document, “Business Practice Manual for Direct Telemetry,” contains a list of minimum required data points and specifications for weather stations and communications. The data points or I/O list is a good tool for consolidating, reviewing and streamlining the SCADA data required by multiple project stakeholders. While ISO or utility requirements form the core of this list, it should also include data points required for performance testing and monitoring to meet the needs of the O&M and AM teams.
Several positive outcomes are likely if you draft the I/O list early in the project life cycle and use this as a working document during project development. For example, you can identify where different parties have overlapping requirements and look for opportunities to streamline these to improve efficiency. You can strategically design some redundancy into the system to improve resiliency. You can also have key SCADA component vendors review the list to ensure that their products are capable of providing the requested data points. The published specifications include information about the number of instruments, instrument accuracy, minimum polling rates and data retention requirements. It is important to consult instrument vendors to ensure that they can meet these requirements and to determine whether they must perform periodic recalibration to maintain measurement accuracy.
Trimark’s McKinney emphasizes: “The I/O list is the foundation for communications, automation logic, historization and reports. If you understand the I/O list, you can establish effective control logic, key performance indicator metrics, alerts and alarms, and analytical reports. The I/O list is the starting point for the entire SCADA system, so it’s critical to get it right, right from the start.”
Get everyone on the same page. Implementing a successful SCADA system is a team effort, which means that you need to have all team members at the table. As soon as you know the AM and O&M providers for the project, you should engage them in the SCADA design and development process. This helps avoid SCADA commissioning delays and last-minute change orders to meet specialized reporting or system integration requirements.
It is important to remember that utilities are actively learning about PV power plants, just as the solar industry is learning about grid integration. As a result, the utility may have a different understanding of its own PV power plant control needs at the end of the project development life cycle than at the beginning. For example, it is not uncommon for project developers to find out toward the end of construction that a PV power plant needs to provide VAR support through the inverters, through a capacitor bank or both. It is important to maintain clear and open communications with the utility as projects move through their milestones, as periodic communication with the utility can help you avoid this type of scenario.
Unless utilities are large enough to have their own SCADA department, they often consult with SCADA providers to translate their control needs into project-specific requirements. According to Mesa Scharf, utility solutions manager at AlsoEnergy: “To facilitate informed conversations with utilities, EPCs or project developers should have a well-defined scope for SCADA controls and communications. Any entity that owns or operates a large number of sites will also benefit from having its own standard set of SCADA requirements.”
Utility command and control requirements can be highly variable. While California’s Rule 21 includes smart inverter requirements, grid operators implement some of the dynamic grid support functions only on a case-by-case basis. Additional interconnection agreement requirements may also apply; we have seen requirements for direct transfer trip, curtailment, breaker and plant operations status, availability and energy production forecasts. If the utility requests controls such as curtailment, voltage regulation or volt-VAR support, you need clearly defined response times, ramp rates, acceptable third-party commands and security protocols.
McKinney notes that it is increasingly common for PV resources to have to respond to curtailment orders: “We see many sites that are curtailed every day. There are two important issues with curtailment. First, the ‘requests’ can be issued as frequently as every 5 minutes. So the only practical way to execute these orders is through system automation. Second, it’s important to manage power at the point of interconnection, which means resources must be able to coordinate all their inverters to maximize power delivery at the interconnection point and not dip below the allowable maximum if a cloud reduces generation in part of the array.”
Meeting utility command and control orders requires a combination of SCADA hardware, inverter hardware, communications protocols and software programing. As in any industry, communications standards vary among different manufacturers. As a result, you need to discuss inverter technology decisions with your SCADA providers to confirm that you can meet stakeholder requirements for remote site access, control capabilities and interfaces.
McKinney recommends that project stakeholders establish an up-front agreement regarding cybersecurity requirements: “Handling this correctly avoids unnecessary changes due to misunderstandings or differing interpretations. If the NERC-CIP compliance scheme isn’t defined early on, the project can suffer from last-minute hardware changes, rack-space issues and remote access restrictions.”
Establish a SCADA project lead. It is essential to clearly designate a leader for the SCADA design process. Potential candidates include the SCADA provider, a developer’s representative, the design engineering project manager or a team leader from the EPC firm. Once you have designated the SCADA team leader, you can establish a SCADA working group, which should hold regular meetings with key stakeholders in attendance. This working group might include representatives from the EPC, resource owner, AM and O&M teams, SCADA provider, inverter and tracker suppliers, and utility.
Multiple parties are involved in the process of supplying SCADA system components, installing them, terminating communications cables and commissioning the system. To coordinate all these efforts, it is extremely helpful to have the SCADA working group create a responsibilities matrix early in the design process. As illustrated in Table 1, this matrix assigns ownership of each piece of equipment and establishes which team members need to coordinate to complete each task.
Clearly define the scope of work. The responsibilities matrix aids in the process of evaluating bids from various vendors to ensure that there are no scope-of-work gaps and that you manage interface points between scopes from the outset. This allows you to clearly communicate to all involved parties an understanding of their responsibility. A clearly defined scope of work is critical when you are developing a request for proposal (RFP). The working group must address many questions: How much of the SCADA plan set will the design engineering firm complete, and where do vendors need to step in with their own shop drawings? Will the SCADA provider be on-site during commissioning, or does the EPC team have a qualified individual to serve as field technician in communication with the SCADA provider? When the project goes from the EPC to O&M, will the SCADA provider need to provide training, or will the EPC complete the handoff?
The process of releasing and responding to RFPs is an early opportunity for project developers and SCADA providers to get on the same page with regard to SCADA specifications and equipment decisions. “The request should be as specific as possible,” notes Rob Lopez, director of business development at Nor-Cal Controls. “The list of details should include inverter make, model, capacity and quantity; tracker make, model and quantity of tracker controllers; site power meter make and model; substation IED [intelligent electronic device] specifications; single-line and system block diagrams; site layout; fiber-optic network specifications [single-mode or multimode cable, fiber core diameter, connector type]; communications enclosure locations; contractually required controls; AM and O&M interface requirements [visibility only or advanced controls]; quantity and approximate locations of weather stations; measurement parameters and sensor accuracy requirements; overall project schedule, including SCADA activities; and, if applicable, description of control room.”
Ensure software compatibility. Meeting the needs of multiple stakeholder groups requires multiple HMIs. In terms of software integration, the design team frequently overlooks the AM interface and the operations interface. After the team has built and commissioned the project, someone will need to monitor and ensure continuous operation of the generator. According to Alex Martinez, manager of AM at Coronal Energy, Powered by Panasonic: “Accurate data is critical to analyze past, present and future plant performance. The SCADA system is the backbone of our operations.”
The AM team relies heavily on alarms and status messages to ensure smooth, continuous energy generation. It is important to develop alarm definitions as early as possible and to make sure that these meet the contractual obligations of the involved parties. Most SCADA providers assume that component-level alarms, or simple parroting of equipment alarm messages, is sufficient for downstream operators. Typically, however, additional context is required for asset managers to make sense of equipment fault messages. For example, troubleshooting many of the issues that might lead to an open ac contactor requires data about internal and external temperatures. It is also critical for asset owners and operators to be able to track the performance of subsystems or components and generate alarms based on indications of degradation rather than on failure only.
Having a data historian available, whether located on the site or in the cloud, will enable the system to store project data and provide application interfaces to other software systems. While different stakeholder groups may have different HMIs, each one needs programmatic access to the historian’s data for analysis and display. If the historian does not have a standard application programming interface that other software tools can use, the resulting inconsistency will cause difficulties for downstream teams, requiring rectification.
Coordinate schedules in the field. After you have completed all the design work, the next critical step in the process is field coordination. EPCs need to not only include key milestones related to the SCADA system in the construction schedule, but also keep the SCADA provider up-to-date about schedule changes.
“The biggest issue for us,” say McKinney, “is to know when the inverter pads, panelboards and fiber network will be installed. We also need to coordinate conduit runs and network drop terminations. It’s also important that we know when our cabinets should arrive on-site for the electrical contractor to mount.” McKinney warns: “One issue that EPCs often don’t understand is the criticality of CAISO’s New Resource Integration process. To attain meter certification and secure telemetry, the project must meet specific lead times and milestone approval requirements. EPCs are mistaken if they think that their project will somehow get special treatment and that CAISO will excuse them from adhering to its timeline.”
The project schedule must provide sufficient time for SCADA commissioning, which, depending on project size and complexity, may take as little as a few days or as long as several weeks. SCADA commissioning often gets squeezed due to the last-minute provision of power and communications infrastructure to the site. While some tension in this area is inevitable, as there may be networking costs or contractual reasons for delaying energization, EPCs need to weigh these up-front costs against possible liquidated damages incurred due to delays in passing performance and acceptance tests.
The SCADA responsibilities matrix is helpful to facilitate scheduling around vendor needs, especially relative to other project partners. For example, does the EPC need to complete tracker and inverter commissioning before SCADA commissioning can commence? How will the EPC commission the power system: all at once, one circuit at a time or according to some other pattern? Does the utility require a staged (governed) commissioning to ensure grid stability as you bring the new project on line? If so, how will the EPC handle that staging?
Take time to fine-tune the system. As the EPC brings equipment on line, the SCADA system will expose issues in the power network, as it is designed to do. Establishing protocols for how to flag and resolve status and error messages goes a long way toward ensuring a quick resolution. The goal is for vendors to focus on resolving issues rather than pointing fingers at one another and arguing about who is at fault or who is responsible for troubleshooting. In many cases, the SCADA system is the messenger, not the problem; expecting the SCADA vendor to handle troubleshooting is generally not the most efficient method for resolving field issues.
After establishing commercial operations, the O&M team will need to spend some time fine-tuning the alarm system. Alarm thresholds should be programmable so that operators can adjust their sensitivity. This helps prevent issues related to alarm fatigue. If operators receive too many meaningless messages or false alarms, they may overlook alerts associated with real issues that they need to address.
Bill Reaugh / Blue Oak Energy / Davis, CA / blueoakenergy.com
Rowan Beckensten / Blue Oak Energy / Davis, CA / blueoakenergy.com
Debbie Gross / Blue Oak Energy / Davis, CA / blueoakenergy.com
David Brearley / SolarPro / Ashland, OR / solarprofessional.com
California Independent System Operator Corporation, “California ISO Company Information and Facts,” caiso.com, August 2016
First Solar, “‘Grid-Friendly’ Utility-Scale PV Plants,” white paper, firstsolar.com, August 2013
NERC, “Balancing and Frequency Control,” technical document, nerc.com, January 2011
Trimark Associates, “Best Technology Practices: Effective, Utility-Scale Solar Power Resources,” white paper, trimarkassoc.com, February 2016
US Energy Information Administration, “US Electric System Is Made Up of Interconnections and Balancing Authorities,” blog post, eia.gov, July 20, 2016
AlsoEnergy / 866.303.5668 / alsoenergy.com
Draker / 866.486.2717 / drakerenergy.com
Nor-Cal Controls / 530.621.1255 / norcalcontrols.net
Trimark Associates / 916.357.5970 / trimarkassoc.com