ATTACHMENT_6_-_2016-11_UKRAINE_ROADMAP_ANCILLARY_SERVICES_AND_BALANCING.pdf

UKRAINE ROAD MAP AND

ACTION PLAN--ANCILLARY

SERVICES AND BALANCING

BLACK SEA REGULATORY INITIATIVE (BSRI)

November 2016 This publication was produced for review by the United States Agency for International Development. It was prepared by NARUC BSRI advisor.

Black Sea Regulatory Initiative: UKRAINE

UKRAINE ROAD MAP AND

ACTION PLAN--ANCILLARY

SERVICES AND BALANCING

BLACK SEA REGULATORY INITIATIVE

Project Title: Black Sea Regulatory Initiative (BSRI)

Sponsoring USAID Office: USAID Bureau for Europe and Eurasia

Cooperative Agreement #: REE-A-00-07-00050-00

Recipient: National Association of Regulatory Utility Commissioners

(NARUC)

Date of Publication: November 2016

This publication was made possible through support provided by the Energy and Infrastructure Division of the Bureau for Europe and Eurasia under the terms of its Cooperative Agreement with the National Association of Regulatory Utility Commissioners, No. # REE-A-00-07-00050-00. The opinions expressed herein are those of the author and do not necessarily reflect the views of the US Agency for International Development or National Association of Regulatory Utility Commissioners.

i

Table of Contents

I. Purpose

II. Overview of Current and Proposed Ancillary Services and Balancing Functions

A. Current Situation

B. Proposed Ancillary Services and Balancing Services

III. Country Priorities / Focal Areas

A. Focus Areas

B. Potential Barriers

C. Conclusion ii

National Association of Regulatory Utility Commissioners (NARUC) 1101 Vermont Ave, NW, Suite 200

Washington, DC 20005 USA Tel: +1-202-898-2210 Fax: +1-202-898-2213 www.naruc.org

For questions regarding this publication, please contact Erin

Hammel (ehammel@naruc.org) or Crissy Godfrey (cgodfrey@naruc.org).

I. Purpose

This Draft Road Map is prepared in collaboration with the National Energy and Utility Regulatory Commission (“NEURC”) of Ukraine as part of the Black Sea Regulatory Initiative (“BSRI”) to provide technical assistance and support to Black Sea national energy regulators. The purpose of the BSRI project funded by the U.S. Agency for International Development through the National Association of Regulatory Commissioners (“NARUC”) is to help the regulators of the four BSRI countries in taking important incremental steps towards energy sector reform. The in-country missions were designed to provide tailored support in areas identified by the regulators themselves. In Ukraine, a new Law on Electricity Market (“Draft Electricity Market Law”) is pending in the Verkhovna Rada (Parliament) and is expected to be enacted shortly. NEURC sought the assistance of NARUC’s consultant in implementing certain aspects of this new law.

Prior to traveling to Ukraine, a “needs” assessment was performed by the BSRI advisor through the NEURC interviews, the statements made by the NEURC representatives at the first BSRI workshop in Tbilisi, the Energy Community Secretariat (“ECS”) reports and other documents on Ukraine’s electricity market available in English, including the latest available translation of the Draft Electricity Market Law.

That law would radically transform Ukraine’s electricity sector from a “Single Buyer” system to a competitive wholesale electricity market. Based on the “needs” assessment and discussions with NEURC, a very small number of issues were identified that were not being dealt with by the ECS or other EU technical assistance and which could be usefully addressed during a one-week working session.

The threeissues which NEURC selected as being of priority were the following:

Ancillary Services Balancing (particularly in the absence of a Balancing Market) Responsibility for Balancing (particularly with regard to RES)

Prior to the in-country assistance, NEURC sent BSRI’s advisor a list of questions dealing with both Ancillary Services and Balancing. In preparation for the trip the BSRI advisor prepared written responses and requested that both S.E. Ukrenergo and S.E. Energorynok be invited to participate in the meetings.

Ukrenergo is currently the owner and operator of the high voltage transmission grid and, following the enactment of the new Law will be certified as a Transmission System Operator (“TSO”). Energorynok is currently the Single Buyer of all electricity produced by the five generating companies and is responsible for reselling that electricity to the 27 oblenergos (distribution companies), most of which have been privatized. Following enactment of a new law, Energorynok will be unbundled into three companies— the Market Operator (“MO”), the Guaranteed Buyer of generation from renewable energy sources (“RES”), and an as-yet undefined entity on to which all current debts will be transferred. NEURC invited representatives from both Energorynol and Ukrenergo to participate in the week’s meetings.

In addition to the questions, NEURC sent the BSRI advisor draft chapters on Ancillary Services (“AS Chapters”) and the Real-Time Balancing Market (“Balancing Chapters”) from proposed Market Rules that are under discussion at NEURC. NEURC also sent the BSRI Advisor a document entitled The New Electricity Market Arrangements in Ukraine: A Report prepared by the ECS Project Office (hereinafter “Report”), dated April 2016. That Report describes in detail how the new electricity market will function in the future, including the operation of the competitive day-ahead and intra-day markets, how the TSO will procure Ancillary Services, and how it will balance the system on a moment to moment basis.

II. Overview of Current and Proposed Ancillary Services and Balancing Functions

A. Current Situation

Currently, there are no specific payments made to generators or load for providing frequency control or other Ancillary Services. Nor are any services broken out in the energy price approved by NEURC, although there is currently a separate charge (called a “flexibility charge”) that is paid hourly for tertiary services based on generation profiles. This “flexibility” charge, which is paid only when a generator responds to the instruction of the dispatcher, is paid per kWh of electricity. There is no capacity charge paid for plants to stand ready to provide reserves. Primary regulation (or Frequency Containment Reserve) is provided by Russia without payment, because most of Ukraine is synchronously interconnected to the Unified Power System of Russia.1 Secondary control (or Frequency Restoration Reserve) is provided by Ukraine’s hydropower plants. According to NEURC’s statements during the discussions held in Kyiv, not all thermal generators have the Automated Generator Controls (“AGC”) needed to provide secondary control and would need to invest in the needed equipment to be able to provide such service. With regard to Black Start, the existing Market Rules define the required technical capabilities required for Black Start and, according to NEURC, Ukrenergo has a list of which plants have Black Start capability but the requirements for Black Start are not defined as a service and therefore Black Start is not paid for. In sum, there is currently no market-based or transparent cost-based pricing for ancillary services and balancing energy in Ukraine. Reactive power for voltage support is paid for by Ukrenergo from a fund specifically created to pay for such support; however, Ukrenergo expressed concern that Ukraine has an ageing thermal power plant (“TPP”) population and that the TPPs may not long be able to provide reactive power. It also questioned whether reactive power should be considered an ancillary service.

B. Proposed Ancillary Services and Balancing Services

In the future, according to the Report and to the AS Chapters, the definitions of, and payment for, Ancillary Services will be required to comply with ENTSO-E Codes, including the technical requirements of the Network Code on Load-Frequency Control and Reserves (“NC-LFCR”).2 This means that the Ancillary Services will need to be defined as Frequency Containment Reserve (“FCR”), automatic Frequency Restoration Reserve (aFRR”, manual Frequency Restoration Reserve (“mFRR”), and Replacement Reserve (“RR”). FCR may or may not be paid for but will be mandatory for all Balancing Service Providers (“BSP”) who will be required to execute a standard agreement with the TSO, which will specify the terms and conditions for providing such services. The procurement of aFRR, mFRR and RR will be done through monthly auctions performed by the TSO but participation in the monthly auctions will not be mandatory.

All Ancillary Services providers will be paid a Standby Remuneration Rate. For FCR, the Standby Remuneration Rate paid will be a regulated price approved by NEURC, based on the capital costs of the additional investment required to provide FCR, or the opportunity costs resulting from operating a generating unit below its maximum output. For aFRR, mFRR and RR, the Standby Remuneration Rate paid will be based on the accepted Offer Price for each settlement period obtained in the monthly auction. Each BSP awarded Reserves Capacity in the auction is required to nominate the corresponding quantities for each Settlement Period (defined as one hour) of the trading day on the day before the

1 Only the southwestern part of Ukraine, known as Burshtyn Island, is synchronously connected with the European Union.

2 See Report at 40.

trading day (known as “D-1”). In order to participate in the auctions, generating units and dispatchable load will be required to register their operating characteristics to see if they qualify for the type of Ancillary Services they wish to provide.

Following the close of the Intra-Day Market, market participants submit their Final Physical Positions and Final Import/Export Nominations to the Market Management Software and their Generation/Load schedules to the TSO. These submissions must be made no later than 50 minutes before the Settlement Period. Within five minutes of these submissions being made, market participants are notified of their Final Physical Position by the Market Management Software through validation.3 Any changes in system load, resource availability, and system conditions that occur after these notifications are dealt with by real-time balancing procured through a Real-Time Balancing Market. This market will be operated by the TSO in real-time at hourly intervals. Participation in the Real-Time Balancing Market will be obligatory for all BSPs who will be required to make available any capacity remaining after the acceptance of Ancillary Services offers in the monthly auctions. Reserve Capacity schedules for reserves nominated on D-1 remain in effect during the trading day. Any market participant that does not make a Balancing Energy Offer will be charged a Non-Compliance Charge.

Balancing Energy Offers must be submitted by both BSPs and the Guaranteed Buyer of RES for each generating unit they operate which has the technical capability of changing its generation schedule, as well as for each Dispatchable Load and Combined Heat and Power (“CHP”) units they represent. Such offers are made for upward or downward deviations from the Generation/Load Schedule and must be submitted before the Balancing Market Gate Closure, which is set at 45 minutes prior to the Settlement Period (in other words, five minutes after the submission of their Generation/Load schedules). For upward balancing, BSPs are paid the highest price accepted in order to balance the system if it is short;

for downward balancing, BSPs who made offers to buy energy if the system is long, will be paid the lowest offer accepted in order to balance the system. The only time that the marginal price will not used is if there is an imbalance “caused by system constraints or constraints in interconnectors” that occur after validated interconnector nominations have been submitted, in those cases the balancing energy offers are “tagged” and the offers are not used in calculating the imbalance price. Such “tagging” will be at the sole discretion of the TSO, acting as a reasonable and prudent operator.

The TSO is required to make forecasts—the TSO’s forecasts concern load and injections from RES producers who are not receiving a “green tariff” once the level of those RES producers’ injections reaches a certain (as yet undefined) percentage of total annual energy injections. This forecast must be published at least 2 hours before the DAM Gate Closure. The Guaranteed Buyer of RES from producers who receive the preferential “green tariff” is also required to produce a forecast to the TSO for the units it represents (those which have hourly meters) and submits this forecast for every Settlement Period (defined as an hour) of the trading day. The forecast has to be submitted no later than 8 pm of the day before the trading day (D-1) and must be updated on a rolling basis every four hours.

There is no discussion in the two documents as to how the cost of balancing in real-time is allocated— this is apparently found in another document (Section 4) which was not made available. However, there is a discussion in the Report on this topic, and the ECS recommends that the simplest approach in an immature market such as Ukraine’s is to pass the cost of FRR and RR to all suppliers proportionate to their consumption profile.

3 According to Sections 10.7 and 10.8 of the draft Balancing Chapters, a validation notice of the submitted schedules is also sent by the TSO but the Balancing Chapters are silent as to when the notice validating the schedules is provided.

III. Country Priorities / Focal Areas

A. Focus Areas

The focus of the discussions in Kyiv between the BSRI Advisor and representatives of NEURC, Energorynok and Ukrenergo (herein informally referred to as the “BSRI Working Group”) was on the interim two-year period which will follow enactment of the Draft Electricity Market Law, which passed a first reading in the Parliament on 22 September 2016.4 Under the latest English translation available of the Draft Electricity Market Law, the DAM, IDM, ancillary services market and balancing market period will be phased in and not become effective until two years following the enactment of the law, while the existing market design will continue to operate in parallel with the new design as it is phased in. The NEURC, Ukrenergo and Energorynok representatives believe that it could take more than two years before the ancillary services and balancing markets come into existence. NEURC’s priority now, therefore, is to understand what it should, and can, do to prepare during the interim period.

Specifically, NEUC’s focus is on whether it should attempt to identify the needed ancillary services and assign costs for the provision of both such services and real-time balancing, so that NEURC, Ukrenergo and Energorynok gain some experience with how such services work before introducing the competitive markets. NEURC’s concern, as is always the case when changes are made to existing procedures, is whether introducing ancillary services and balancing markets would increase electricity costs to consumers.5 Electricity tariffs are currently below the cost of production and Ukraine’s government has already committed to raising such tariffs over the next several years to make them cost-compensatory.6 NEURC therefore wants to know what steps it can take to “test” the provision of ancillary services and balancing without a further increase in consumers’ tariffs.

B. Potential Barriers

In discussing whether to introduce ancillary services and balancing during the interim period on a basis other than the competitive markets foreseen in the Draft Electricity Market Law and in the AS and Balancing Chapters of the draft Market Rules, a number of problems peculiar to the Ukrainian electricity system emerged. They include:

(1) Developing a Cost Based Pricing Methodology

The assumption during the BSRI Working Group discussion was that ancillary services and balancing during the interim two-year period would be provided under regulated tariffs approved by NEURC. The issue was how to develop a price for such services. Both NEURC and Ukrenergo say they do not know

4 Another new law, On the National Commission for State Regulation of Energy and Public Utilities Sector (“Regulator Law”), passed its second reading on the same day and becomes effective as soon as it is signed by the President.

5 NEURC and Energorynok did a preliminary calculation based on a simplified model, comparing 2015 consumer tariffs with projected 2017 tariffs, and found that there would be a sharp increase in tariffs. Ukrenergo objected to this study on the grounds that it had not been consulted and that the increase would be dwarfed by the scheduled increases in any event.

6 The tariffs are supposed to reach cost compensatory levels by 2017 but according to members of the BSRI Working Group, that target is unlikely to be met because the price of imported gas from Russia, which is denominated in EUR, has increased, as has imported uranium for the nuclear plant which generates over 40% of the electricity consumed in Ukraine, and because deliveries of anthracite for coal units have been interrupted (the anthracite mines are located in Eastern Ukraine) due to the fighting with separatists.

how to determine what ancillary services should cost because the data needed to develop a cost-based methodology is not available since the plants were, for the most part, built with government funds.

During meetings with international advisors it was mentioned that DTEK, the owner of the thermal power plants in Burshtyn Island, is paying for ancillary services under a NEURC approved tariff;

therefore, some estimate of what secondary and tertiary ancillary services cost must already exist.

NEURC also stated that it has drafted a framework regulation for the payment of ancillary services7 during the interim period, which would have required a further implementing regulation to calculate the price to be paid. This draft regulation was not implemented because there was disagreement on its usefulness, since the pricing regime would not have been consistent with the Draft Electricity Market Law. Moreover, the framework regulation would have addressed only secondary and tertiary regulation, while primary regulation and Black Start pricing would have been addressed at a later date.

(2) Lack of Technical Data Analysis Capability

Another problem identified by Ukrenergo is that it cannot determine when a power plant is providing ancillary services when directed to do so, even though it has telemetry data indicating when a plant is operational, because it does not have the software or the detailed modeling of each turbine generator to be able to analyze the telemetry data to determine what specific services a plant is providing Ukrenergo stated that, even though the World Bank has retained an expert to draft an RFP for the software needed by both Ukrenergo and Energorynok to operate the new DAM, IDM, ancillary services market and balancing markets, the RFP did not include this particular type of software.

(3) Physical Configuration of TPPs and Installation of Ancillary Services Equipment

In the BSRI Working Group meetings, Ukrenergo stated that when it asks generating units to report what equipment they have installed to provide ancillary services, it has no way of checking whether the responses received are accurate because it cannot detect from the telemetry data whether such equipment has actually been installed. It said that 13 TPPs have been refurbished with governors that should allow them to provide load following (primary control) services. But when Ukrenergo sent the 13 TPPs a data request, asking them if they had the necessary equipment that complied with ENTSO-E technical requirements, only two responded that they were able to provide primary control.

Subsequently Ukrenergo sought to test their capabilities but when the two TPPs were asked to provide load following, only one was able to do so.8 Ukrenergo is therefore unsure of what equipment was actually installed and whether it truly had the capability to provide the primary frequency control that Ukraine will need, if it is to make itself less reliant on Russia’s system.

(4) Damage to TPPs Caused by Provision of Secondary Control

The ancillary services market proposed for Ukraine under the AS Chapters would, unlike those in the U.S., be voluntary (except for primary control). But because appropriate prices for secondary control have not been developed, a voluntary market during the transition period may not result in many volunteers. In 2011 Ukrenergo executed a contract for aFRR (secondary control) from a hydropower plant which it knew had received IFI loans to install the necessary equipment. But the HPP refused to renew the contract after six months, in part on the grounds that its equipment was being damaged due to the vibrations caused by providing such service.

7 That document was not available in English so it was not possible to review it.

8 Ukrenergo representative said that, because only two TPPs were supposedly providing primary control when requested, it was able to detect their actual provision of such services. But if multiple plants are required to provide primary ancillary services, Ukrenergo claims that it will not be able to tell which TPPs are providing primary control.

(5) Inconsistent Definitions and Technical Parameters for Ancillary Services

The Draft Electricity Market Law assumes that the definition of ancillary services in Ukraine and the technical standards will have to correspond to the ENTSO-E definitions; however, according to both NEURC and Ukrenergo, neither the definition currently used for tertiary reserves nor the technical standards applicable today correspond to the ENTSO-E definition and parameters. In the future, a new Network Code, in the process of being drafted by international consultants, will contain the appropriate definitions and technical standards. But there is no reference to ancillary services standards in the current set of documents dating from the Soviet period, containing applicable “norms.” NEURC and Ukrenergo are therefore at a loss to know what standards to apply in the interim period.

(6) Enforcing Ancillary Services Obligations

Another major topic of discussion in the BSRI Working Group meetings was how to enforce the provision of ancillary services if reserves are not actually provided when needed. Under the old law, NEURC’s authority to penalize non-compliance with license conditions and regulations is capped at 85,000 UAH (equivalent to about US$3,300). It is unclear, however, what NEURC’s authority is to penalize non-compliance with ancillary services obligations. The group explored the possibility of relying on the current generation license, which states:

The licensee is obliged to implement all operating order of the dispatcher according to the rules of technical operation and existing instructions unless in contradiction of their technical /security standards.

But it was determined that the requirement to comply with the current technical standards is not helpful because those standards were drafted in 1996 and do not contain any reference to ancillary services. In addition, a document approved by the Cabinet of Ministers which contains frequency and voltage control requirements and is a translation from an English technical standard was not made compulsory by the Cabinet Resolution. Since it is only voluntary, NEURC and Ukrenergo did not believe that they could require TPPs to comply with such standards.9

(7) Balancing and RES Producers

Under the amendments to the existing Electricity Market Law known as Law No. 66310 Energorynok is required to buy all output from RES producers selling electricity under a preferential Feed-in-Tariff known as the “green tariff.” Under the Draft Electricity Market Law, the Guaranteed Buyer will take over this obligation so Energotynok’s power purchase agreement is only for one year. RES producers selling at the “green tariff” do not have to do their own balancing—instead the Guaranteed Buyer is required to do the balancing for the RES sellers11 it represents. Currently RES producers represent only 1% of all generation but a number of larger wind farms are on the horizon and there is no cap on the Guaranteed Buyer’s purchase obligation. NEURC and Energorynok expressed concern regarding this balancing obligation, even though it will gradually phase out under the Draft Electricity Market Law. As

9 NEURC was particularly concerned about how it could impose obligations on private generators and said that private generators frequently challenge NEURC’s decisions in court and that courts are notoriously subject to corruption.

10 No English translation has been done of Law No. 663 and this Road Map relies on the statements made in the BSRI Working Group meetings regarding its content.

11 This obligation extends only to wind and solar plants; small hydropower plants (“SHPPs”) are required to do their own balancing.

of 2030 the Guaranteed Buyer will no longer be required to buy RES electricity at the “green tariff” and RES plants will be required to do their own balancing and can create their own “Balance Responsible Group” if they so choose. Under the new law, the Guaranteed Buyer will have to sell into the DAM, even though it is likely to sell at a loss; however, for the interim period, a fund has been created to compensate the Guaranteed Buyer for the difference between the “green tariff” purchase price and the DAM price. After the new law goes into effect, the TSO will be responsible for compensating the Guaranteed Buyer for this difference and passing the differential through to all transmission users through its transmission tariff. Energorynok also asked repeatedly where “balancing energy” would come from and one of its representatives12 expressed the belief that it would come from tertiary reserves.

C. Conclusion

The week’s discussions concluded with a tentative consensus among participants—that developing a cost-based methodology for ancillary services and balancing energy during the interim period would be a useful exercise, notwithstanding the problems identified above. NEURC therefore requested some suggestions as to what steps to take, assuming any actions would have to be in compliance with the existing law, to develop such cost-based methodology. The Road Map and Action plan below attempts to identify such steps and the order in which they should occur. They are as follows:

1. Identify and approve the ancillary services which will be needed by the TSO to operate in a liberalized market.

2. Determine the technical standards that should be applicable to such ancillary services.

3. Identify and certify the units (in addition to the hydropower plants that can provide aFRR) that have the capability to provide the needed ancillary services.

4. Make a determination as to which ancillary services should be obligatory and which should be voluntary.

5. Break out from the current electricity price the actual cost of providing each needed ancillary service and determine what price should be paid for ancillary services if costs of capital and depreciated rate base are not available.

6. Develop a Terms of Reference for, and purchase, software needed to monitor the provision of ancillary services.

7. Develop enforcement mechanisms and penalties for non-compliance with the dispatcher’s instructions.

8. Develop methodologies to mitigate the impact of generation imbalances caused by RES producers under “green tariffs.”

ROAD MAP AND ACTION PLAN FOR NEURC

ACTIONS THAT CAN BE UNDERTAKEN IMMEDIATELY (BEGIN 2016)

Action/Event Legislative Authority

Entity Responsible

When Notes and Comments

1. Identify and approve the Ancillary Services needed by the TSO for operation in a liberalized market

The Regulatory Guidelines list the ancillary services generally accepted as being needed for a liberalized, competitive wholesale market to function:

Frequency Containment Reserves (FCR or Primary Reserves): This category typically includes operating reserves with the activation time up to 30 seconds. They are usually activated automatically and locally.

Frequency Restoration Reserves (FRR Secondary Reserves) These are deployed both automatically and manually within between 30 seconds and 15 minutes when an imbalance arises to replace used up Primary reserves. The ECS proposed AS Chapters distinguish between automatic and manual, calling them aFRR (or secondary control) and mFRR (or fast-acting tertiary reserve).

Replacement Reserves (Tertiary Reserves) These are deployed manually between 15 minutes and longer time frames to replace secondary reserves.

Current Electricity Market Law

Ukrenergo (as future TSO) with the definitions to be approved by

NEURC

Immediately The descriptions of ancillary services vary from country to country (e.g. Georgia’s draft “Concept of System Services Arranging” calls them “System Services”). The purpose of EU’s Third Energy Package” is to try to harmonize definitions and ancillary service products to promote regional capacity markets. ACER directed ENTSO-E to develop network codes which would provide standardized formulations of ancillary services. The Regulatory Guidelines recommend using such definitions for the BSRI countries. For the interim period and beyond, Ukraine is unlikely to have sufficient units with the necessary equipment to distinguish between automatic and manual reserves.

Action/Event Legislative Authority

Entity Responsible

When Notes and Comments

2. Determine the technical standards that should be applicable to such ancillary services.

The target technical parameters for ancillary services are set forth in the NC- LFCR (See, e.g. Article 19 for Frequency Quality Defining Parameters). But each country has to adapt those parameters to its particular system and the transmission systems to which it is interconnected. The NC-LFCR lists the different time frames used for the restoration of frequency in the different control regions in Europe, which range from 10 to 20 minutes. Ukraine’s TSO should therefore develop the time frames and individual parameters that its generators and dispatchable loads are capable of meeting, even if those parameters do strictly adhere to a specification in the NC-LFCR, as long as they observe the quality criteria established in the NC-LFCR.

Current Law Ukrenergo to develop; NEURC to approve following a public procedure.

All participants in the BSRI Working Group agreed that Ukrenergo currently has the authority to develop the necessary technical standards.

Immediately Currently the technical parameters and quality criteria used in Ukraine do not conform to ENTSO-E standards. The appropriate parameters need to be determined before trying to assign costs to such services in Step 5.

ACTIONS THAT CAN BE TAKEN IN THE MEDIUM TERM

3. Identify and certify the units (in addition to the hydropower plants that can provide aFRR) that have the capability to provide ancillary services.

Since Ukrenergo and NEURC do not know which plants are capable of providing ancillary services (and NEURC believes that there is a deficit in secondary and tertiary services capability) it is imperative that an engineering assessment be done of the capability of the existing generating units within Ukraine. This should be done by engaging a qualified independent engineer to perform a spot check of selected power plants in each of the eight control areas over a minimum size. The cost of hiring such engineer should be recouped through Ukrenergo’s transmission tariff. If it is determined that there are insufficient plants with the needed technical capability, Ukrenergo should develop the tender requirements consistent with ENTSO-E quality standards and hold a tender, unless under the existing law it is the Ministry of Energy’s function to hold such tenders.

The tender would be to select the power plants willing to install the necessary equipment and provide the needed ancillary services under cost-based tariffs (plus a reasonable rate of return) approved by

NEURC.

Current Law

Ukrenergo should develop the terms of reference for an independent engineering firm to do the assessment.

If it determined by the independent engineer that additional investment is required, Ukrenergo should develop the terms of reference for such additional investment.

1st and 2nd Q 2017 An Inspectorate under the control of the Ministry already exists but neither NEURC nor Ukrenergo thought it would be sufficiently independent or qualified to perform this assessment. NEURC and Ukrenergo were skeptical as to whether an independent Ukrainian engineering firm could be found because of the endemic corruption. In that case, an accredited European firm should be hired to do spot checks and certify the capability of selected units. According to Ukrenergo, there are few generating units capable of providing ancillary services, with primary regulation coming primarily from Russia and secondary regulation coming primarily from hydropower units.

The issue is thus not only one of incompatible standards but potentially also of unavailable compatible units. In addition, there was some disagreement between NEURC and Ukrenergo as to whether the detailed characteristics of each generating unit in Ukraine are known.

4. Make a determination as to which ancillary services should be obligatory and which should be voluntary.

Because of the damage caused to generating units by oscillations/vibrations resulting from only one unit providing aFRR, NEURC either has to provide incentives for sufficient generating units to want to offer to provide aFRR, or it has to pay the lone HPP unit providing the service a sufficiently high tariff to make it want to execute another contract with the attendant vibration/oscillation problems.

It is unclear whether NEURC can make the provision of ancillary services mandatory under the current Electricity Market law. NEURC may therefore have to await the passage of the new law in order to mandate the provision of ancillary services on a temporary basis until the competitive DAM, IDM and Ancillary Services markets are operational.

2nd Q 2017 In the U.S. and in the EU, FCR (primary reserves) are obligatory for all generating units and, in the U.S., the service is provided without a separate charge being paid. Those services should therefore be mandatory.

Participation in the ancillary services market for secondary and tertiary control will be voluntary once that market is established. However, based on Ukrenergo’s experience with the HPP, for the interim “trial” period such services could be made mandatory.

Authority

Entity Responsible

When Notes and Comments

5. Break out from the current electricity price the actual costs of providing each needed ancillary service and determine what price should be paid for ancillary services if costs of capital and depreciated rate base are not available

Under this step, NEURC should first try to determine the cost of providing such services by requiring generators to provide it with the relevant data. NEURC already made this request once before for secondary and tertiary ancillary services according to Ms.

Karali, but the data received was not technically accurate. If actual cost data is not available because the units were built with state funds, and the cost of service methodology shown in the Regulatory Guidelines cannot be used, NEURC and Ukrenergo should develop pro forma costs using proxies for the type of units providing the ancillary services. Once ancillary services costs have been determined using proxies, a percentage that each of the service’s costs represent of the total energy charge can be allocated from the current energy charge to the providers of each ancillary service without increasing the electricity tariff paid by consumers. This would be a theoretical exercise only if, as claimed by NEURC and Ukrenergo, there are insufficient plants with the necessary equipment to provide primary and secondary reserves. In such case, Current Electricity Market Law

NEURC and Ukrenergo

The theoretical exercise can be performed in 1st Q 2017. But if additional investment is required as suggested by NEURC and Uktenergo, and a tender has to be organized as suggested in Step 3, then 3rd Q

NEURC and Ukrenergo claim that they are not able to determine the cost of generating units using the cost of service methodology found in the Appendices to the Regulatory Guidelines because the needed data is not available. There proxies for the type of units that will be needed to provide ancillary services should be used. Such proxies exist elsewhere, such as Bulgaria, Serbia and other countries that use lignite. For the newer natural gas combined cycle turbine units there are numerous proxies for determining capital costs.

For energy charges, the cost of domestic lignite and imported natural gas would be used. Alternately, NEURC can use the “Best New Entrant” methodology, which is also mentioned in the ECS Report. The “BNE” used in the U.S. is a CCGT.

Authority

Entity Responsible

When Notes and Comments additional plants will have to install the necessary equipment and will have to be compensated for such investment. That may have an impact on current electricity prices, which are still below the cost of providing electricity service.

ACTIONS THAT CAN BE TAKEN IN THE LONGER TERM

6. Develop RFP for the software needed to monitor the provision of ancillary services.

As noted above, Ukrenergo cannot tell from the telemetry data it receives whether ancillary services are being provided when multiple plants are required to provide such services. In the future, all plants will need to provide primary regulation. Ms. Karali agreed with this assessment. Therefore one of the many donors working with the Ukrainian electricity sector needs to assist Ukrenergo in developing first, an RFP for the software needed to analyze telemetry data, and second, to purchase the software needed to monitor power plants being paid to provide ancillary services

International agreement between donor agency and Ukrainian government

Recipient of software following issuance of an RFP would be the Ukrenergo

Ideally 2nd Q 2017 in order to coincide with the completion of the certification of units capable of providing ancillary services, as described in Step 3, but more likely 3rd Q 2017.

As noted above, the TOR for software developed by the World Bank does not include the software needed by Ukrenergo to monitor the provision of ancillary services. If such software is provided by another donor organization, it should be linked to the software used for the DAM and

IDM.

7. Develop enforcement mechanisms and penalties for non-compliance with the dispatcher’s instructions.

Previously NEURC’s enforcement powers were limited to imposing an annual fine of 85,000 UAH (equivalent to approximately $3,300) but under the new Regulator Law, New Law on the Regulator

NEURC 2nd Q 2017 It was unclear from the discussions in the BSRI Working Group what mechanism NEURC would use for enforcing compliance with the new Ancillary Services standards and the

NEURC will have the authority to increase penalties for non-compliance in accordance with the Third Energy Package. That penalty can be up to 10% of revenues. However, because of the lack of a legal “hook” on which NEURC can rely to enforce compliance with the new standards, it may have to await the approval of the Market Rules.

instructions of the TSO since the generator license conditions do not reference the ENTSO-E standards. The draft Market Rules, which will have to be approved by NEURC, will contain a reference to such standards.

8. Develop methodologies to mitigate the impact of generation imbalances caused by RES producers under “green tariffs.”

Because Energorynok, as the Guaranteed Buyer, will be responsible for imbalances caused by RES generators selling their output under “green tariffs” it needs to be able to manage its exposure to imbalances in the real-time balancing market when that market becomes operational. A centralized forecasting service that allows the Guaranteed Buyer to forecast weather changes affecting the output of RES plants should be procured by the Guaranteed Buyer. In addition, the Government should consider introducing reverse auctions to reduce the cost impact of RES on retail electricity prices, in lieu of using Feed-in- Tariffs which are being phased out even in Europe. A description of the reverse auction methodology used in California was provided to Energorynok. See http://www.cpuc.ca.gov/Renewble_Aucton_ Mechanism

Law No. 663 Energorynok and

NEURC

3rd Q 2017 Energorynok should acquire forecasting software and should perform such forecasting for all RES generators on a centralized basis.

Centralizing such forecasting is more efficient and is the preferred option for small and medium sized plants, according to NREL. And, in the future, NEURC should look into using reverse auctions for RES, rather than Feed-in-Tariffs, because of their economic efficiency.