Policies failed to keep up with technology.
Barriers to small island grid uptake of modern renewable energy power include outdated regulations that have not kept up with technology, according to the Institute of for Energy Economics and Financial Analysis (IEEFA). Indeed, the Philippines presents a prime example of how techno-economic change has outpaced government regulation.
Under current regulation, for example, no incentives exist for island electric cooperatives (or those in SPUG areas) to procure cheaper sources because whatever the outcome, savings accrue exclusively to the missionary fund and none to the franchise ratepayers.
This is a classic case of moral hazard. This system tends to be biased against renewable generation because franchise managers would rather stick with diesel generation they are used to, even though more expensive.
Here's more from IEEFA:
Section 12 of the Renewable Energy Act of 2008 mandated the DoE, upon recommendation of the National Renewable Energy Board (NREB) to set a minimum renewable energy uptake in off-grid areas from available renewable resources in the islands.
According to Pete Maniego, former NREB chair, the recommendatory task was delegated to NPC-SPUG. As of June 2016, however, NPC-SPUG had not made any final recommendations. Since sunlight is abundant in all off-grid areas, the binding constraint would be land availability, and anecdotal evidence suggests large tracts are available.
Furthermore, the tariff-setting system for island electric cooperatives under the ERC is based on cash adequacy for operating and maintenance costs and an arbitrarily set cap on capital expenditures.
This means there is no incentive for electric cooperatives to even be more efficient or reduce costs. Private distribution utilities, on the other hand, benefit from a
performance-based regulation, which leads to operational and investment efficiency.
Still, private distribution utilities lack incentives to procure least-cost power supply because of full pass-through of fuel costs on contracts that address demand from captive customers, most of which are residential.
Prudent reform would have the ERC and NEA set up and enforce policy to require electric cooperatives and private distribution utilities alike to optimize procurement. Such reform would reduce the cost of electricity by tightening competition between power generators.
For fossil-fuel power generators, up to 80% of operating cost comes from fuel. Optimizing procurement levels the playing field for renewable power generators and reduces the UCME cost for ratepayers and taxpayers by phasing out subsidies for imported diesel.
The ERC and NEA can amend their tariff-setting system to favor performance and thus award gains as a result of increased efficiency and lower costs. It is clear that from a technological standpoint, there is the capability to implement cheaper alternatives, but in terms of integrating that capability into government regulation, there has not been much progress.
Cooperatives will also require training in renewable energy supply procurement—in part because of unfounded fears of running afoul of their diesel contract obligations.
The Department of Energy (DOE) can enjoin NPC-SPUG to speed up hybridization of its plants and to install maximum renewable energy for incremental load and in new sites identified for electrification. Moreover, the NEA can direct electric cooperatives to be technology-neutral in the procurement of power.
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Pioneering technology expert tells ADIPEC Energy Dialogue up to 80 per cent of plant shutdowns could be mitigated through combination of advanced electrification, automation and digitalisation technologies
Greater use of renewables in power management processes offers oil and gas companies opportunities to create efficiencies, sustainability and affordability when modernising equipment, or planning new CAPEX projects
Abu Dhabi, UAE – XX August 2020 – Leveraging the synergies created by the convergence of electrification, automation and digitalisation, can create significant cost savings for oil and gas companies when making both operational and capital investment decisions, according to Dr Peter Terwiesch, President of Industrial Automation at ABB, a Swiss-Swedish multinational company, operating mainly in robotics, power, heavy electrical equipment, and automation technology areas.
Participating in the latest ADIPEC Energy Dialogue, Dr Terwiesch said up to 80 per cent of energy industry plant shutdowns, caused by human error, or rotating machinery or power outages, could be mitigated through a combination of electrification, automation and digitalisation.
“Savings are clearly possible not only on the operation side but also, using the same synergies between dimensions, you can bring down the cost schedule and risk of capital investment, especially in a time when making projects work economically is harder,” explained Dr Terwiesch.
A pioneering technology leader, who works closely with utility, industry, transportation and infrastructure customers, Dr Terwiesch said despite the increasing investment by oil and gas companies in renewables and the growing use of renewables to generate electricity, both for individual and industrial uses, hydrocarbons will continue to have an important role in creating energy, in the short to medium term.
“If you look at the energy density constraints, clearly electricity is gaining share but electricity is not the source of energy; it is a conduit of energy. The energy has to come from somewhere and that can be hydrocarbons, or nuclear, or renewables.” he said.
Nevertheless, he added, the greater use of renewables to generate electricity offers oil and gas companies the option of integrating a higher share of renewables into power management processes to create efficiencies, sustainability and affordability when modernising equipment, or planning new CAPEX projects.
The ADIPEC Energy Dialogue is a series of online thought leadership events created by dmg events, organisers of the annual Abu Dhabi International Exhibition and Conference. Featuring key stakeholders and decision-makers in the oil and gas industry, the dialogues focus on how the industry is evolving and transforming in response to the rapidly changing energy market.
With this year’s in person ADIPEC exhibition and conference postponed to November 2021, the ADIPEC Energy Dialogue, along with insightful webinars, podcasts and on line panels continue to connect the oil and gas industry, with the challenges and opportunities shaping energy markets in the run up to, and following, a planned three-day live stream virtual ADIPEC conference taking place from November 9-11.
An industry first of its kind, the online conference will bring together energy leaders, ministers and global oil and gas CEOs to assess the collective measures the industry needs to put in place to fast-track recovery, post COVID-19.
To watch the full ADIPEC Energy Dialogue series go to: https://www.youtube.com/watch?v=QZzUd32n3_s&t=6s
Utility-scale battery storage systems are increasingly being installed in the United States. In 2010, the United States had seven operational battery storage systems, which accounted for 59 megawatts (MW) of power capacity (the maximum amount of power output a battery can provide in any instant) and 21 megawatthours (MWh) of energy capacity (the total amount of energy that can be stored or discharged by a battery). By the end of 2018, the United States had 125 operational battery storage systems, providing a total of 869 MW of installed power capacity and 1,236 MWh of energy capacity.
Battery storage systems store electricity produced by generators or pulled directly from the electrical grid, and they redistribute the power later as needed. These systems have a wide variety of applications, including integrating renewables into the grid, peak shaving, frequency regulation, and providing backup power.
Most utility-scale battery storage capacity is installed in regions covered by independent system operators (ISOs) or regional transmission organizations (RTOs). Historically, most battery systems are in the PJM Interconnection (PJM), which manages the power grid in 13 eastern and Midwestern states as well as the District of Columbia, and in the California Independent System Operator (CAISO). Together, PJM and CAISO accounted for 55% of the total battery storage power capacity built between 2010 and 2018. However, in 2018, more than 58% (130 MW) of new storage power capacity additions, representing 69% (337 MWh) of energy capacity additions, were installed in states outside of those areas.
In 2018, many regions outside of CAISO and PJM began adding greater amounts of battery storage capacity to their power grids, including Alaska and Hawaii, the Electric Reliability Council of Texas (ERCOT), and the Midcontinent Independent System Operator (MISO). Many of the additions were the result of procurement requirements, financial incentives, and long-term planning mechanisms that promote the use of energy storage in the respective states. Alaska and Hawaii, which have isolated power grids, are expanding battery storage capacity to increase grid reliability and reduce dependence on expensive fossil fuel imports.
Source: U.S. Energy Information Administration, Form EIA-860, Annual Electric Generator Report
Note: The cost range represents cost data elements from the 25th to 75th percentiles for each year of reported cost data.
Average costs per unit of energy capacity decreased 61% between 2015 and 2017, dropping from $2,153 per kilowatthour (kWh) to $834 per kWh. The large decrease in cost makes battery storage more economical, helping accelerate capacity growth. Affordable battery storage also plays an important role in the continued integration of storage with intermittent renewable electricity sources such as wind and solar.
Additional information on these topics is available in the U.S. Energy Information Administration’s (EIA) recently updated Battery Storage in the United States: An Update on Market Trends. This report explores trends in battery storage capacity additions and describes the current state of the market, including information on applications, cost, market and policy drivers, and future project developments.