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Financial parameters of auctions for renewable energy sources

On 3 April 2017, two regulations were published in the Journal of Laws which set out the financial parameters of auctions for renewable energy sources (RES) that will be held in 2017. The government is planning to spend more than PLN 27 billion (approximately €6.5 billion) on support for producers in auctions, which will generate more than 55 TWh of electricity during 15 years. The parameters of the auctions are set out below.

  1. Summary
  • In 2017, fourteen auctions will be organized, each of them dedicated to different groups of installations. Nearly 75 percent of the funds (PLN 20 billion) will be allocated to new installations. Nearly 63 percent of all funds (PLN 17 billion) will be allocated to large installations.
  • So-called stable installations will be the most favored group of installations. The largest part of the funds is allocated to a basket of high-efficiency installations (37 percent of funds in 4 auctions). Biomass installations are expected to be a dominant group in this basket. Significant funds (35 percent in 4 auctions) will be allocated to agricultural biogas installations.
  • It is planned to allocate funds to Waste-to-Energy projects, which should assure the construction of installations with nearly 150 MW of total capacity (one auction dedicated for new, large installations). Part of the funds will be allocated to a basket dedicated to hydro-electric plants, both existing and new (three auctions).
  • Another part of the budget is allocated to a basket for new installations covering “other installations” (15 percent of funds in two auctions). In this basket, two auctions are planned: the first for small installations that, according to the government’s intention, will result in the construction of 300 MW new photovoltaic projects, and the second for large installations, where support could be obtained by nearly 150 MW new wind projects. Significant competition is expected in these two auctions.
  • Installations participating in an auction cannot apply for higher support than the “reference price,” which is determined for each year. The reference price is set separately for 21 categories of installations. In 2017 for example, this price will be PLN 350 per MWh for large installations using wind and PLN 450 per MWh for small installations using solar energy.
  • Auctions will be announced by the President of ERO and cannot be organized earlier than 30 days after its announcement. In light of the RES Act, an auction could be organized at the earliest on 24 May 2017, but no announcements regarding auctions have been made to date.
  1. Auction support scheme

Under the Act of 20 February 2015 on renewable energy sources (RES Act), there are two support schemes for RES installations in Poland. Existing installations can obtain support in the form of certificates of origin (green certificates) and can sell electricity to designated entities at the officially determined price (system of certificates). New installations will compete for support allocated in auctions (auction system) organized by the President of the Energy Regulatory Office (ERO).

The auction system is dedicated mainly to new installations, but existing installations can also transfer to this system (in such case they lose a right to participate in the system of certificates). This system is intended to assure the future development of RES but in a controlled and predictable manner—this may be pursued through the allocation of budgets to auctions where installations favored by the government start and through the reduction of budgets for auctions for unwanted installations. The increase in RES in Poland, and the contemplated impact of auctions in 2017 on the installed capacity of RES, is presented in Figure no 1.

Figure no. 1     Increase in renewables capacity (MW) in Poland

Source: data from President of the ERO. The data concerning the capacity from the auction in 2017 presents only the estimation of the Ministry of Energy.
  1. Split of auctions and auction baskets in the auctions system

Auctions are conducted separately for installations qualified for particular “baskets” (or bands). There are five baskets (two additional baskets will be added from 1 July 2017, but no funds are allocated to them in 2017). The following existing baskets are dedicated to particular RES installations:

  • With a degree of utilization of the installed electricity generation capacity, irrespective of the level of CO2 emission, of more than 3504 MWh/MW/year (basket of high-efficiency installations)
  • Using, for the generation of electricity, biodegradable industrial waste and municipal solid waste of plant or animal origin, including waste from waste treatment systems and waste from water treatment and waste treatment, including in particular sludge, in accordance with the provisions on waste concerning classification of energy recovered from thermal waste treatment (basket of WTE installations)
  • In which emission of carbon dioxide does not exceed 100 kg/MWh, with utilization of total installed capacity of more than 3504 MWh/MW/year (basket of low-emission installations)
  • Using only agricultural biogas to generate energy (basket of biogas installations)
  • Other than those already specified (basket of other installations)

In each of those baskets, separate auctions are organized for existing installations and new installations. Moreover, separate auctions are organized for small installations and large installations. Separate auctions will be organized for so-called upgraded installations, but no budget has been provided in 2017. (as it was in 2016).

Therefore, in each year and in each basket, up to four auctions are possible and in total up to 20 auctions may be organized, each of them dedicated to different groups of installations (40 auctions including upgraded installations).

  1. Budget allocations for 2017

In 2017, the auction budget is PLN 27,177,622,626; support will be provided for the production of 55 562 607 MWh during the coming years. The individual budgets are presented in Table no 1 below:

Table no. 1 Budgets of auctions in 2017

Conclusions from the above data: In 2017, the auctions will be dedicated mainly to new installations—75 percent of funds are allocated to these installations. The most supported technologies are stable installations, i.e. with predictable generation, mainly from the basket for high-efficiency installations (37 percent of all funds) and from the basket for biogas installations (35 percent of all funds). Large installations will be dominant, as 63 percent of all funds have been allocated to these installations. A breakdown of funds between large vs. small and existing vs. new installations is presented in Figure no 2.

Figure no. 2 Breakdown of auction funds in 2017: large v. small and existing v. new installations

Source: Regulation of the Council of Ministers regarding the maximum volume and value of electric energy generated in renewable energy source installations which may be sold by auction in 2016.

A more detailed description of each of the auctions is provided in point 8 below.

  1. Reference prices

An RES installation producer cannot submit at auction a bid that is higher than the maximum ‘reference price’ per MWh. The reference price is determined for each year, separately for each of the 21 categories (42 if we take into account the additional 21 categories for upgraded installations). This division does not coincide with the division into technological baskets. The reference price is uniform for existing and new installations. Parts of the reference prices are determined separately for small and large installations, while others are the same for both categories.

Below, we present the reference prices for the installations that are intended to be supported by the government in 2017. A summary of all reference prices is set out in Appendix 1 below.

Table no. 2 Reference price for certain installations in 2017

  1. Possible auction dates

Under the RES Act, auctions are announced and organized by the President of the ERO. The announcement should be published in the Public Information Bulletin of ERO at least 30 days before the day of the auction starting. The auction cannot be conducted earlier than 60 days after publication of the reference prices.

The regulation determining reference prices in 2017 entered into force on 25 March 2017, therefore this year’s auction can be conducted at the earliest on 24 May 2017 (if the President of the ERO publishes the announcement on 24 April 2017 at the latest). Nevertheless, some media say that the main auctions will be organized in the second half of the year.

  1. The effect of winning an auction and support period

The producer that won the auction will receive support dependent on the capacity of the installation. Producers that have an installation with installed capacity of <500 kW will be entitled to sell their total electricity offered in the auction at the price established at auction to the designated entity (pay-as-bid mechanism). Producers that have an installation with installed capacity of >500 kW will have the right to cover the difference between the market price and the price established at auction in the scope of the volume offered in the auction (termed “return of negative balance”) with the obligation to return the surplus if the market price exceeds the auction price (contract-of-difference mechanism). The support is also not allocated, when the power exchange prices of electricity are lower than zero PLN (with some additional conditions).

The support period for new installations is determined annually together with reference prices. In 2017 it is 15 years. The support period for existing installations is also 15 years, but it is calculated from the date the first electricity is generated and fed to the grid, as confirmed by the issued green certificate.

If, after winning the auction, at least 85 percent of the quantity of electricity declared in the bid is not generated, a fine will be imposed calculated on the basis of the not delivered volume of electricity and a half of the auctioned bid price. In the case of installations with an assumed efficiency of 3504 MWh/ MW/year, a failure to reach declared capacity utilization leads to the obligation to return all public aid obtained through auctions.

  1. Auctions in particular baskets

Below, we present a short description of each basket, stating the types of installation supported in accordance with the government’s intention. Whenever the amount is given together with the name of a specific installation, it means the reference price for this installation. The grading of individual installations into baskets is given for illustration purposes only; we cannot guarantee that in fact the indicated types of installation will start in any given auction.

a. Basket of high-efficiency installations

Four auctions will be organized in this basket, but the funds for small installations (both existing and new) constitute only 9 percent; the funds for large installations dominate.
Auctions for large installations in this basket are dedicated mainly to plants combusting biomass. It is predicted that the following installations can participate in these auctions:

  • Dedicated co-firing combustion installations (DCCI) using biomass, biofuels, biogas or agriculture biogas (325 PLN)
  • Hybrid RES installation with aggregated installed capacity >1 MW (405 PLN)
  • Dedicated biomass combustion installations (DBCI) or biomass hybrid systems (HS) with aggregated installed capacity of up to 50 MW (both 415 PLN)
  • DBCI or HS in CHP with aggregated installed capacity >50 MW and up to 150 MWt of CHP (435 PLN)
  • DBCI or HS in CHP with aggregated installed capacity of up to 50 MW (450 PLN)

Potentially this basket may be joined by investors who plan to develop on-shore wind farms (350 PLN) installing new generation turbines. Some claim that in certain technical configurations it would be possible to achieve efficiency at the level required for this basket.

The government’s intention is a transfer of nearly 50 percent of existing installations combusting biomass (probably the DBCI, although this intention is not clearly stated), but taking into account the reference price it may turn out that the auction winner will be an installation co-firing biomass with coal (DCCI). Competition in this basket is expected, as due to the declining prices of green certificates, a transfer to the auction system may be financially profitable for existing installations.

In the scope of large, new installations, the government is planning to award funds that will result in the construction of approximately 100 MW of DBCI.

Funds for small installations are allocated to installations using biogas other than agricultural, hence for installations using biogas extracted from a landfill site (405 PLN) and biogas extracted from a sewage treatment plant (365 PLN). In the scope of new installations, it is planned to construct approximately 5 MW of capacity for each type of these installations.

b. Basket of WTE installations

In this basket only one auction for large, new installations will be organized. Funds from this basket are intended to provide support for waste incineration plants that produce energy (385 PLN). It is planned that results from the auction support will be given to installations with total capacity of 150 MW.

According to publicly available information, there are five waste incineration plants in Poland which produce nearly 334,000 MWh/year. (This data is an unconfirmed estimation due to the lack of official information in this respect.) Assuming that the winning installation will produce the same amount of MWh every year (which gives production of 309,600 MWh annually), contracting the total volume in this basket will result in an increase in the energy generation of those installations of 92 percent.

c. Basket of low-emission installations

In this basket three auctions will be organized, all addressed to hydro-electric installations (480 PLN) able to achieve at least 3504 MWh/MW/year. Hydro-electric installations below this threshold will need to participate in auctions in the basket of other installations. In addition, large offshore wind energy installations (470 PLN) may potentially take part in auctions in this basket—if such installations will be able to produce more than 3504 MWh/MW/year. Similarly, as in the case of the basket of high-efficiency installations, this basket may be joined by investors planning to install on-shore wind turbines (350 PLN) of a new generation, only if the information on sufficiently efficient technical setups is confirmed.

In the scope of existing installations, it is intended that as a result of the auctions from 2017 and 2016 approximately 80 percent of existing, small hydro plants will be transferred to the auction system. The budget for new installations will enable the construction of 10 MW of small installations and 10 MW of large installations (this indicates that offshore wind plants can take part in the auction only hypothetically).

d. Basket of biogas installations

In this basket four auctions will be organized, each solely for agriculture biogas installations (PLN 550).

The government in its rationale of regulations did not indicate the percent of existing installations that will be transferred to the auction system in this basket. In the scope of auctions dedicated to new installations, it is planned to allocate support to small installations with total aggregated capacity of 70 MW and to large installations with total aggregated capacity of 30 MW.

e. Basket of other installations

In this basket two auctions for new installations are provided.

The auction for small installations is addressed to solar energy installations, but other installations can also take part in this auction:

  • Small onshore wind energy Installations (320 PLN)
  • Small installations using solar energy (450 PLN)
  • Hydro-electric small installations (480 PLN)—installations with efficiency <3504 MWh/MW/year

The last auction in this basket, in December 2016, was the only auction where the bids outstripped available volume (from 152 bids only 84 were chosen). Keen interest is also expected this year, although funds allocated to the auction are nearly three times larger. It is planned that support will be obtained by installations with total capacity of approximately 300 MW in this auction. If solar plants obtain the said support, it will mark a significant increase in the capacity of these installations. The installed capacity of solar energy installations in Poland and the contemplated impact of the auction in 2017 on this capacity is presented in Figure no 3.

Figure no. 3 Installed capacity in PV plants in Poland (in MW)

Source: Data disclosed by President of the ERO. The data concerning the capacity from the auction presents only the estimation of the Ministry of Energy. In 2016 it was intended to support approx. 100 MW of new power, but only 84 offers were chosen in the auction. The aggregated capacity of these offers is unknown, but as the auction was addressed to small installations their aggregated capacity may not exceed 84 MW.

Keen competition is expected in the auction for large installations, which is addressed to wind energy plants. The following installations can take part in this auction:

  • Large onshore wind energy installations (350 PLN)
  • Large installations using solar energy (425 PLN)
  • Large offshore wind energy installations (470 PLN)—installations with efficiency <3504 MWh/MW/year

Keen competition is expected in this basket, which is dominated by onshore wind energy installations. There are two main reasons for this. First, the planned budget provides support for approx. 150 MW, which might be significantly lower capacity than available for existing projects that can submit bids in this auction. In practice, if bids are submitted in the auction for the new installations with higher effectiveness than the level used for the calculation by the government, the volume of offered electricity from these installations will be proportionally higher. In this case, support will be allocated to installations within limits closer to 100 MW of new generation capacity. Second, the negative approach of the current government to wind farms is not a secret. Therefore it is conceivable that the auction in 2017 will be the last one in a few years with funds allocated to this basket. Moreover, the entry into force of the Act of 20 May 2016 on investments concerning wind turbines stipulates that a building permit for wind turbines issued on the basis of zoning decisions will expire if the occupancy permit is not obtained for the wind turbine by 1 July 2019. Based on our own knowledge, quite a large number of wind turbines were developed on the basis of zoning decisions (not on the basis of local zoning plans, as required by the abovementioned Act). Therefore, in light of the time required to build wind turbines, this auction may be the last chance some wind farms have of obtaining the state aid they need to ensure financial profitability of the project, in light of the occupancy permit issue. Building permits for many projects face expiry, and it may prove impossible to obtain new building permits under the new Act.

Appendix no 1
Reference Prices obliging in 2017 (in PLN/MWh)

Appendix no 2
Summary of auctions in 2017 in the order set by the Minister of Energy

 


  1. There are RES installations which started production of renewable energy before 1 July 2016 (existing installations) and after 1 July 2016 (new installations);
  2. There are installations with capacity of up to 1 MW (small installations) and those with capacity of more than 1 MW (large installations).
  3. From 1 January 2018, only RES installations with a capacity less than 500 kW and agricultural biogas installations will be able to benefit from mandatory purchase of electricity.
  4. Taking into account that currently known connection conditions for off-shore installations book capacity around the 1000 MW threshold, exceeding many times the assumed budget of auctions, we treat participation of investors based on this technology as purely hypothetical.
Financial parameters of auctions for renewable energy sources

Significant Developments in Canadian Energy – For the Month of March 2017

Oil Sands / Unconventional

  • March 29, 2017 – Cenovus Energy Inc. (“Cenovus”) agreed to acquire ConocoPhillips’s 50% interest in the FCCL Partnership, which is the companies’ jointly owned oilsands venture operated by Cenovus. Cenovus is also purchasing the majority of ConocoPhillips’s Deep Basin conventional assets in Alberta and British Columbia. These assets have a combined 2017 forecast production of approximately 298,000 boe per day. Total consideration for the purchase is $17.7 billion, including $14.1 billion in cash and 208 million Cenovus common shares.
  • March 9, 2017 – Canadian Natural Resources Limited (“CNRL”) announced an agreement, subject to regulatory approvals, to acquire 70% of the Athabasca Oil Sands Project including 70% of the Scotford upgrader, as well as additional working interests in other producing and non-producing oilsands leases. CNRL has agreed with Shell Canada Limited and certain subsidiaries to acquire its 60% working interest in the Athabasca Oil Sands Project. CNRL and Shell have also agreed with Marathon Oil Corporation to jointly acquire its 20% share in Athabasca Oil Sands Project and related oilsands investments.

Conventional

  • March 24, 2017 – Total Energy Services Inc. (“Total Energy”) acquired a majority of the outstanding common shares of Savanna Energy Services Corp. (“Savanna”). Western Energy Services Corp. stated that Total Energy has taken up 51.6 % of the shares of Savanna under its hostile take-over bid.
  • March 24, 2017 – Pengrowth Energy Corporation entered into an agreement for the sale of its non-producing Montney lands at Bernadet in northeast British Columbia for cash consideration of $92 million. The Bernadet asset encompasses 36.6 sections (100% working interest) of land with no associated production.
  • March 22, 2017 – Trican Well Service Ltd. (“Trican”) and Canyon Services Group Inc. (“Canyon”) have entered into an arrangement agreement pursuant to which Trican has agreed to acquire all of the issued and outstanding common shares of Canyon on the basis of 1.70 common shares of Trican for each outstanding Canyon share. The consideration to be received by Canyon shareholders reflects a value of $6.63 per Canyon share based on the closing price of Trican shares on the Toronto Stock Exchange on March 21, 2017. The aggregate transaction value is approximately $637 million, including the assumption of approximately $40 million in Canyon debt. Upon completion of the transaction, existing holders of Trican shares and Canyon shares will collectively own approximately 56 % and 44 % of the combined company, respectively.
  • March 21, 2017 – Journey Energy Inc. (“Journey”) has entered into a purchase and sale agreement with an undisclosed private company to acquire interests in Central Alberta for an aggregate purchase price of approximately $35.6 million, comprised of $29.6 million of cash and 2.1 million common shares of Journey. The acquisition consists of approximately 2,000 boe per day of high working interest liquids-rich gas production.
  • March 20, 2017 – Pengrowth Energy Corporation announced it has entered into an agreement for the sale of a portion of its Swan Hills assets in north-central Alberta for total cash consideration of $180 million, subject to customary adjustments.
  • March 17, 2017 – Blackbird Energy Inc. (“Blackbird”) entered into a binding agreement with Knowledge Energy Inc. for the acquisition of two gross sections (two net) of Montney rights for total consideration of 1.92 million Blackbird common shares.
  • March 16, 2017 – Total Energy Services Inc. purchased, through the facilities of the Toronto Stock Exchange, 35,000 Savanna Energy Services Corp. shares.
  • March 16, 2017 – Painted Pony Petroleum Ltd. (“Painted Pony”) entered into a share purchase agreement to acquire all of the issued and outstanding shares of UGR Blair Creek Ltd., a privately held 100% controlled subsidiary of Unconventional Resources Canada LP (“URC”), a portfolio investment held in certain private equity funds advised by ARC Financial Corp. and EnCap Investments LP. Pursuant to the agreement, total consideration of 41 million common shares of Painted Pony will be issued to URC. Based on the price per Painted Pony share in respect of the offering of $5.60, total share consideration is $229.6 million.
  • March 9, 2017 – Enerplus Corporation announced agreements to sell Canadian properties located in Alberta and southwest Saskatchewan for aggregate proceeds of $67.3 million, before closing adjustments. The properties to be divested include the majority of Enerplus’s shallow gas assets, as well as its Brooks waterflood property.
  • March 9, 2017 – Northern Petroleum PLC signed an agreement to acquire production wells and facilities located in Alberta in the same area as the company’s existing Rainbow assets. The company will acquire 75% of the assets with its joint venture partner, High Power Petroleum LLC acquiring the remaining 25%.

Midstream

  • March 13, 2017 – The federal government approved NOVA Gas Transmission Ltd.’s Towerbirch Expansion Project subject to 24 binding conditions. The $439-million project will involve the construction of two new pipeline sections totalling approximately 87 kilometres along with associated facilities in northwest Alberta and northeast British Columbia.

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Significant Developments in Canadian Energy – For the Month of March 2017

Significant Developments in Canadian Energy – For the Month of February 2017

Conventional

  • February 13, 2017 – Alberta celebrated the 70th anniversary of the discovery of oil at Leduc #1, which is considered by many to be the start of the modern oil and gas industry in the province. The Government of Alberta marked the anniversary with a special presentation at the Leduc #1 Energy Discovery Centre. Attendees included Marg McCuaig-Boyd, Alberta’s Minister of Energy, Mark Scholz, President of the Canadian Association of Oilwell Drilling Contractors (CADOC), and Tim Hawkins, President of the Leduc/Devon Oilfield Historical Society. The discovery followed years of failures exploratory throughout the province, with Imperial Oil, the well’s proponent, having drilled 133 dry holes previously.
  • February 9, 2017 – Clearview Resources Ltd. closed an acquisition of assets in the Wilson Creek area of Alberta for $11.36, effective Dec. 1, 2016. Following the acquisition, Clearview’s production will be approximately 900 boe per day (roughly 50 percent oil and liquids and 50 percent gas).
  • February 1, 2017 – Alberta Investment Management Corporation (AIMCo) entered into a financing arrangement with Razor Energy Corp. AIMCo has committed a non-revolving term loan facility for a principal amount of $30 million on a four-year term, with an interest rate of 10 per cent payable semi-annually. A portion of the proceeds of the facility were used by Razor to fund the purchase price of the acquisition of certain producing oil and gas interests in the Swan Hills area of Alberta, with the remainder to be used to fund its development program and for general corporate purposes. In consideration of AIMCo providing the facility, Razor issued approximately 10.05 per cent of its outstanding common shares to AIMCO.

Oil Sands / Unconventional

  • February 13, 2017 – Malaysia’s state-owned oil company Petroliam Nasional Bhd (PETRONAS) may consider relocating its Canadian LNG export terminal project if required by Canadian government authorities, according to media reports quoting chairman Mohamad Sidek Hassan. The reports also indicated that PETRONAS has identified a potential new location for the plant to reduce costs and address environmental concerns.

Midstream / Downstream

  • February 23, 2017 – Enbridge Inc. and Spectra Energy Corp. announced that the previously announced merger of the two companies has received all required regulatory clearances under the merger agreement, including from the Canadian Competition Bureau. The transaction closed on February 27, 2017. The merged company will have an enterprise value of approximately CDN$166 billion, with an extensive, North America-wide portfolio of crude oil, liquids and natural gas pipelines, a large portfolio of strong, regulated gas distribution utilities and a growing renewable power generation position.
  • February 16, 2017 – Pembina Pipeline Corporation announced that it had entered into a 20-year infrastructure development and service agreement with Chevron Canada Limited. The agreement includes an area of dedication by Chevron, in excess of 10 gross operated townships (over 230,000 acres), located in Kaybob region of the Duvernay resource play near Fox Creek, Alberta. Under the agreement and subject to Chevron sanctioning development in the region, Chevron has the right to require Pembina to construct, own and operate gas gathering pipelines and processing facilities, liquids stabilization facilities and other supporting infrastructure for the area of dedication, together with Pembina providing long-term service for Chevron on its pipelines and fractionation facilities.
  • February 15, 2017 – Keyera Corp. announced plans for two new projects. First, a new NGL gathering pipeline system (Keylink) that will provide producers in west-central Alberta with a pipeline alternative for transporting NGLs from a number of Keyera gas plants. The estimated cost will be $147-million with an in-service date of mid-2018. Second, Keyera announced a project to expand the liquids handling capacity at the Simonette gas plant to meet customers’ growing needs. The project is expercted to cost $100 million with an in-service date of mid-2018.
  • February 13, 2017 – Gibson Energy Inc. entered into an agreement to sell its industrial propane business for cash consideration of $412 million to Superior Plus LP, which is to be completed through a series of transactions. Pursuant to an option purchase agreement and subject to the fulfilment of customary conditions, Gibson and Superior are obligated to complete the initial transaction pursuant to which Superior will pay non-refundable cash consideration of $412 million and Gibsons will grant an irrevocable option to Superior to acquire 100 per cent of the partnership units and shares of its Canwest and Stittco businesses.
  • February 2, 2017 – Suncor Energy Inc. closed the previously announced sale of its Petro-Canada Lubricants Inc. (PCLI) business to a subsidiary of HollyFrontier Corporation for gross proceeds of $1.125 billion, subject to customary closing adjustments.
Significant Developments in Canadian Energy – For the Month of February 2017

Security interests in the UK Capacity Market: new rules

Lenders and capacity providers in the UK’s Capacity Market will want to take note of new procedures introduced by National Grid in its role as the Capacity Market’s Delivery Body.

The Capacity Market aims to incentivise investment in new electricity generating capacity and ensure reliable electricity supplies for end users. Where a Capacity Provider has third party debt financing, the lender will want to take security over the capacity payments it is entitled to receive by registering a Security Interest in respect of the relevant Capacity Agreement on the Capacity Market Register.

Recently National Grid, as Delivery Body, has changed the way such Security Interests are to be registered.

Previously lawyers acting for lenders (the beneficiaries of the Security Interests) have undertaken registration on behalf of their clients, in line with the other common security registrations at Companies House and where applicable, the Land Registry. All that was required was to submit by email a notice of the Security Interest in a form agreed by the Delivery Body (the Security Interest Notice).  The Delivery Body now requires that Security Interest Notices are registered by the relevant Capacity Provider itself, via the online portal registration system known as the EMR Delivery Body Portal (the Portal).

This means that beneficiaries of the Security Interests, or lawyers acting on their behalf, are no longer able to manage this process, so the Security Interest Notice will need to be submitted to the Capacity Market Register via the Portal by the Capacity Provider or their lawyers (if they are appointed as an agent to act on behalf of the relevant Capacity Provider).

Once a Security Interest Notice has been uploaded to the Portal the Delivery Body will receive notification and following this the Delivery Body will be required to approve (or return) an application to register that Security Interest and update the Capacity Market Register accordingly.

Going forward, it is likely that this process will be reflected in any relevant loan or security document to ensure that, where applicable, borrowers and developers are required to submit a Security Interest Notice to the Delivery Body (or provide evidence of this to the beneficiaries of the Security Interest) as a condition to the terms of the financing.

If you are a Capacity Provider and you have not already signed up to the Portal, information on how to register via the company registration form can be found here. The Delivery Body has also published guidance on how to upload a Security Interest which you can access by clicking here.

If you are experiencing any issues with the Portal, the Delivery Body can be contacted via email at EMR@nationalgrid.com or via telephone on 01926 655300.

Defined terms used in this blog post are taken from the consolidated version of The Capacity Market Rules 2014 published on 14 July 2016, or as introduced by the author.

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Security interests in the UK Capacity Market: new rules

UK “early” Capacity Market auction produces cheapest prices yet

The provisional results of the “early” Capacity Market auction held last week have now been published.

This was an auction exclusively of 1-year capacity agreements, primarily to cover Winter 2017/18, after the UK Government decided that it did not want National Grid to carry on ensuring security of supply during Winter periods by means of a Contingency Balancing Reserve (CBR).  The CBR involved auctions open to generators who would not otherwise be operating in a given Winter period and to demand side response providers.  A Government consultation in March 2016 noted that the prices National Grid were paying under the CBR were increasing and that it introduced distortions into the market.

From Winter 2018/19, of course, the Capacity Market itself will ensure security of supply.  Those with capacity agreements beginning in 2018 will be the capacity providers who bid successfully in a four year ahead auction held in 2014, supplemented by those who win capacity agreements in any subsequent one year ahead auction for delivery in 2018.  Last week’s “early” auction was a one-off bridge between the CBR (now operating for the last time to cover Winter 2016/17) and the fully-fledged Capacity Market regime.  The key difference between the CBR and the Capacity Market is that the CBR (or at least the major part of it) focuses on securing capacity that would otherwise not be in the market, to fill the potential gap between existing generation and projected peak demand, whereas the Capacity Market provides a reliability incentive to all eligible generators and demand side response providers on the market.

Commentary on previous Capacity Market auctions (such as this post from December 2016) has tended to focus on the failure of the four year ahead auctions to result in the award of 15 year agreements to meaningful amounts of large-scale new gas-fired generation projects.  With new projects competing against almost all existing thermal generation, and new reciprocating engine projects able to bear much lower Capacity Market clearing prices than a CCGT project, the auctions have produced low clearing prices, but no obvious successors to the existing big coal-fired plants that the Government wants to close by 2025.

How to evaluate the results of the “early” auction, then?  The provisional results indicate capacity agreements going to 54.43 GW of capacity, at £6.95 kW / year, suggesting total costs to bill payers of around £378 million.  This might look like spectacularly good value compared with the results of the last four year ahead auction (for delivery starting in 2020), where the clearing price was £22.50 kW / year for 52.43 GW of capacity.  But that isn’t really a fair comparison, since about a quarter of the capacity that was awarded agreements for 2020 was new build, whereas less than 4 percent of the capacity awarded agreements in the “early” auction falls into this category.  All the rest will be paid £6.95 for just continuing to operate – which presumably most of them would have done anyway. 

An alternative point of comparison might be with the costs of the CBR.  The most recent Winter for which these are available is 2015/16, when National Grid spent just over £31 million on procuring, testing and utilising less than 3 GW of CBR capacity.  Obviously a much inferior system. 

 

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UK “early” Capacity Market auction produces cheapest prices yet

Significant Developments in Canadian Energy – For the Month of December 2016

Conventional

  • December 15, 2016 – Athabasca Oil Corporation entered into agreements with Statoil ASA and its wholly owned subsidiary Statoil Canada Ltd. to acquire their Canadian thermal oil assets for consideration of $435 million cash, 100 million common shares and contingent value payments triggered at oil prices above US$65 per bbl WTI.
  • December 14, 2016 – Toro Oil & Gas Ltd. entered into a definitive agreement with Steelhead Petroleum Ltd., pursuant to which Steelhead will acquire all of the outstanding common shares and common share purchase warrants of Toro Oil & Gas Ltd. for approximately $44.1 million in cash.
  • December 12, 2016 – Delphi Energy Corp. announced that it closed its strategic agreement with its existing working interest industry partner to accelerate the development of Delphi’s liquids-rich Deep Basin natural gas play at Bigstone in northwest Alberta. Delphi Energy Corp. received approximately $31.3 million in cash for the partner’s equalization of certain working interests and the partner also paid $10.9 million to Delphi for the partner’s carried obligation of the joint drilling program.
  •  December 9, 2016 – The Court of Queen’s Bench of Alberta granted an approval and vesting order for the previously announced purchase and sale of substantially all of the assets and business of Lightstream Resources Ltd. by Ridgeback Resources Inc. for the full amount of the claims outstanding in respect of the company’s 9.875% second lien secured notes due 2019 and debt in priority to the secured notes.
  • December 9, 2016 – ARC Resources Ltd. closed the previously-announced sale of its Saskatchewan assets and operations to Spartan Energy Corp. for total cash consideration of $700 million, subject to customary post-closing adjustments. The effective date of the transaction is October 1, 2016.
  • December 8, 2016 – Spartan Energy Corp. closed its previously announced bought deal public offering, including the exercise in full of the over-allotment option, for aggregate gross proceeds of approximately $287.6 million. Prior to the completion of the prospectus offering, Spartan closed a non-brokered private placement offering for aggregate gross proceeds of $255 million. The aggregate gross proceeds from the prospectus offering and the private placement are approximately $542.6 million.
  • December 6, 2016 – Marquee Energy Ltd. announced the completion of the previously announced acquisition of Marquee Energy Ltd. by Alberta Oilsands Inc. by way of a plan of arrangement and the subsequent completion of the short-form vertical amalgamation to form the “new” Marquee Energy Ltd.
  • December 6, 2016 – Pine Cliff Energy Ltd. closed its previously announced disposition of non-core oil assets for $31.4 million, prior to any closing adjustments, consisting of $26.6 million in cash and $4.8 million in TSX-listed common shares of the purchaser. The disposed assets include approximately 500 boe per day of production weighted 94% to oil located in the Viking area of central Alberta.
  • December 5, 2016 – TransGlobe Energy Corporation entered into a definitive agreement to acquire Cardium light oil and Mannville liquid-rich gas assets in the Harmattan area of west-central Alberta for total consideration of $80 million.
  • December 5, 2016 – Bellatrix Exploration Ltd. entered into an agreement with a TSX-listed issuer to sell certain non-core assets in the Harmattan area of Alberta for $80 million, subject to customary closing adjustments. The transaction is expected to close prior to December 31, 2016, with an effective date of December 1, 2016. The $80 million purchase price will be payable $65 million in cash and $15 million in a vendor take back loan bearing interest at 10% per annum and secured by a first lien charge against the assets being sold.
  • December 2, 2016 – PrairieSky Royalty Ltd. completed four separate acquisition transactions for aggregate consideration of $117.3 million, representing approximately 460 boe per day of royalty production and over 100,000 acres of mineral title and royalty lands.
  • December 2, 2016 – BlackPearl Resources Inc. completed the sale of a gross overriding royalty interest on its Onion Lake property for $55 million. Under the terms of the agreement BlackPearl sold an approximate 1.75% royalty on production from substantially all of its Onion Lake lands.

Unconventional

  • December 15, 2016 – PrairieSky Royalty Ltd. entered into a definitive agreement with Pengrowth Energy Corporation to acquire a 4% gross overriding royalty on current and future phases of its Lindbergh SAGD thermal oil project, as well as seismic over certain lands in British Columbia and Alberta, for total cash consideration of $250 million.

Midstream

  • December 21, 2016 – Alberta Investment Management Corporation on behalf of certain of its clients, agreed to acquire an ownership stake in Howard Energy Partners from EnLink Midstream Partners, LP. The investment, representing an ownership stake of approximately 28% of Howard Energy Partners, makes the Alberta Investment Management Corporation the second largest unitholder in the company. The transaction is expected to close during the first quarter of 2017, subject to customary closing conditions.
  • December 20, 2016 – Tidewater Midstream and Infrastructure Ltd. acquired from a vendor the remaining approximate 37% working interest in the Brazeau River Complex gas plant and the remaining approximate 60% working interest in 105 kilometres of gas gathering pipelines directly connected to the BRC in addition to the remaining working interests for 100% ownership in the previously announced three proven natural gas storage reservoirs that are also directly connected to the BRC for a purchase price of $30 million in cash.
  • December 16, 2016 – Spectra Energy Corp. announced that during a special stockholder meeting, Spectra Energy stockholders voted to approve the previously announced combination of Spectra Energy with Enbridge Inc. in a stock-for-stock merger transaction. Enbridge shareholders also approved the required resolutions in connection with the merger transaction between Enbridge and Spectra at its special meeting of shareholders.
  • December 2, 2016 – Enbridge Inc. together with Enbridge Income Fund Holdings Inc. announced that it closed the previously announced sale of its South Prairie Region assets to Tundra Energy Marketing Limited for $1.075 billion in cash.
Significant Developments in Canadian Energy – For the Month of December 2016

Close but no cigar? What’s different about the T-4 Capacity Market auction results of 2016?

They say a picture is worth a thousand words, so rather than writing a lengthy post on the provisional results of the four-year ahead GB Capacity Market Auction, published on 9 December 2016 by National Grid, we are focusing on two pictures and inviting you to spot the difference between them.

The first, immediately below, shows the progress of bidding in the 2016 auction.  In simple terms:

  • the process starts with all prequalified potential providers of capacity “in” at the cap price of £75/kw/year and the price then goes down by £5 with each round;
  • the auction clears when the purple line, whose progress from right to left shows how many bidders are left in after each round, converges with the red line “demand curve” drawn on the graph by the Government as part of the auction parameters;
  • all bidders still in at that point get a capacity agreement at the clearing price.

The big right to left moves occurred when the price moved between £35 and £30 and below £25.  In particular, each of these moves saw 6GW of capacity drop out.

2016 progress of bidding chart

Now look at the equivalent presentation of results from last year’s auction.  The purple line slopes more gradually, and the biggest right to left moves happen much earlier on in the bidding, between £60 and £50.  (The picture from 2014 is very similar to the 2015 one.)

2015 progress of bidding chart

It’s only an educated guess, of course, but it seems likely that much of the big leftward shifts in both auctions represented the exiting of bidders with plans to build large-scale proposed combined cycle gas turbine (CCGT) plants.  As a group, they are almost certain to have higher per MW development costs than other categories of new build projects competing for capacity agreements (small gas or diesel projects based on reciprocating engines, open-cycle gas projects, or battery based storage).  And the amount of capacity involved corresponds roughly with the big CCGT projects in the auction.

If the above is correct, why were proposed new big CCGT plants apparently prepared to tolerate prices almost 50% lower this year?  Perhaps they were hoping that a price between £30 and £35 would be where the auction cleared this time, on the basis that:

  • the clearing price is effectively set by the bidding behaviour of a sub-set of the smaller-scale, distribution-connected, fossil fuel generators;
  • on top of their power sales revenue, these smaller-scale generators have two main projected sources of income: capacity agreements and so-called residual demand TNUoS benefits;
  • Ofgem has issued what amounted to a warning that residual demand TNUoS benefits could be very sharply reduced by the time plants bidding in this year’s auction are commissioned;
  • the anticipated loss in residual demand TNUoS benefit revenue would be enough to push the smaller-scale generators to want a significantly higher capacity market price than the clearing prices seen in 2014 and 2015, both of which were below £20;
  • lower gas prices and slightly higher projected wholesale power prices may make a low capacity market price more bearable for CCGT plant, and there may other ways to mitigate merchant risk through innovative trading arrangements.

Maybe Ofgem’s warning wasn’t strong enough.  Maybe the smaller-scale generators reckon that Ofgem’s bark will turn out to have been worse than its bite on this.  In any event, the outcome has shown that for now, simply expanding the amount of capacity to be procured under an auction, as the Government appeared to be hoping when it adopted a limited change of approach to the 2016 auction, isn’t enough to ensure that some new GB CCGT plant is financeable and gets built.  Instead, a somewhat higher price will be paid to all successful bidders, including existing plant, for a larger amount of capacity than the Government thought we really needed.

As usual on these occasions, the Government has professed itself happy with the result of the auction, and it is fair to note that of the two new gas-fired plants with a capacity of around 300 MW that have been successful in the auction, one is described in the Capacity Market register as being CCGT.  But if a new generation of big CCGT plants is an important part of our new lower carbon power mix, there is some way to go.  A possibly more promising approach to using a capacity market to stimulate new CCGT build is suggested by the European Commission’s recent Winter Package of Energy Union proposals: set a date beyond which existing coal-fired plant will be ineligible for capacity market payments.  This is not among the options canvassed in the Government’s recent consultation on achieving the closure of coal-fired plant by 2025.  There would of course be an element of risk in adopting such an approach (coal plant might stay open because it can still make money without a subsidy, resulting in overcapacity, or alternatively coal plant might close immediately, before the new CCGT plant is built, leaving a generation gap), but it might be worth considering.

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Close but no cigar? What’s different about the T-4 Capacity Market auction results of 2016?

Something for everyone? The European Commission’s Winter “Clean Energy” Package on Energy Union (November 2016)

On 30 November 2016, the European Commission officially unveiled the latest instalment of its ongoing Energy Union initiative, which will reform some of the central pieces of EU energy legislation.  Referred to in advance as the “Winter Package” (not to be confused with the rather more limited package released in February 2016), it has been published as the “Clean Energy for all Europeans” proposals and is the most significant series of proposals yet to emerge under the Commission’s “Energy Union” brand.  It will have far-reaching implications within and potentially beyond the existing EU single energy market.

There is a lot to consider in these proposals, and we will return to some of the issues they raise in more depth and from other perspectives in future posts. What follows is an overview and some initial thoughts from a predominantly UK-based viewpoint.

Important though it is, many of the Winter Package’s proposed reforms are evolutionary rather than revolutionary.  Some could even be criticised for lacking ambition.  The Commission’s proposals certainly provide opportunities for newer technologies such as storage and demand side response and for those seeking to make use of newer commercial models such as aggregation or community energy schemes, but all these groups are still likely to need to work hard in many cases to exploit the leverage that the new rules would give them.  It is interesting that what has been picked up most in early news reports of the Winter Package is the Commission’s move to end subsidies for coal-fired plant.  This is a significant step, but it is only one part of a complex and multi-layered set of draft legislative measures, and is one of the few instances in those measures of a provision that overtly tilts the playing field in favour of or against a particular technology in a new way.

The story so far

Let’s begin by reminding ourselves what Energy Union is about. The project is said to have five “dimensions”.  These are:

  • Security, solidarity & trust: the buzz-words are “diversification of supply” and “co-operation between Member States” – all informed by anxieties about over-dependence on Russian gas.
  • A fully-integrated internal energy market: going beyond the 2009 “Third Package” of gas and electricity market liberalisation measures (and their ongoing implementation through the promulgation of network codes) to achieve genuine EU-wide single gas and power markets.
  • Energy efficiency: using less energy can be hard, but it is the best way to meet environmental objectives and it can also be a significant source of new jobs and economic growth.
  • Climate action – decarbonising the economy: signing and ratifying the Paris CoP21 Agreement was the easy bit.  How is the EU going to achieve deep decarbonisation of not only its power but also its heat and transport sectors so as to meet its UNFCCC obligations?
  • Research, innovation & competitiveness: can European businesses still take the lead in developing technologies that will save the planet, and also make money out of commercialising them?

In other words, Energy Union is about everything that matters in EU energy policy.  To date, at least in relation to electricity markets, the initiative has involved a lot of consultation but not many concrete legislation proposals.  The new Winter Package goes a long way towards redressing this balance, but it shows there is still a lot of work to do.

What is in the Winter Package?

The documents published by the Commission (all available from this link) include legislative proposals and a range of explanatory and background policy documents.  The legislative proposals are for:

We comment below on what seem to us at this stage to be the most interesting points in these, and also on the Communication on Accelerating Clean Energy Innovation (the Innovation Communication).

The Revised IMED

Overall impressions

The legislative elements of the Winter Package are all inter-related, but the Revised IMED is as good a place to start as any.  Its early articles include two programmatic statements:

  • National legislation must “not unduly hamper cross-border flows of electricity, consumer participation including through demand-side response, investments into flexible energy generation, energy storage, the deployment of electro-mobility or new interconnectors”.
  • Electricity suppliers must be free to determine their own prices.  Non-cost reflective power prices should only apply for a transitional period to vulnerable customers, and should be phased out in favour of other means of support except in unforeseeable emergencies.

In some ways, this sets the tone for the more specific provisions that follow.  It often seems that the Commission never loses an opportunity to put forward legislation in the form of a directly applicable Regulation rather than in the form of a Directive that by definition requires Member States to take implementing measures in order fully to embed its effect within national regulation.  However, the revised IMED, like its predecessor, stands out as a classic old-school Directive, in which EU legislators tell Member States lots of results to be achieved, but do not prescribe many of the means by which this is to happen.  Moreover, even the expression of those objectives is (inevitably) qualified: in other words, get rid of the barriers to the Commission’s vision of Energy Union, except the ones you can justify.  Of course, that is slightly unfair: as noted below, there are at least one or two eye-catching points in the revised IMED, and there are significant changes proposed in other parts of the Winter Package that should further the objectives of the revised IMED, but it arguably demonstrates less willingness to get to grips with some of the most difficult of the longer-term and more fundamental changes in the market than the call for evidence on moving towards a smart, flexible energy system that was published on 10 November by the UK government and GB energy regulator Ofgem (although admittedly the UK authorities are only asking questions, not proposing solutions at this stage).

A market for consumers (and prosumers)

The revised IMED would enhance the rights of consumers generally in a variety of ways.  For example:

  • Price increases are to be notified and explained in advance, giving them the opportunity to switch before an increase takes effect.  Switching must take no longer than three weeks.
  • Termination fees may only be charged where a fixed term contract is terminated prematurely, and must not exceed the direct economic loss to the supplier.
  • All consumers are to be entitled, on request, to a “dynamic electricity price contract” which reflects spot market price fluctuations at least as frequently as market settlement occurs.  They will of course need smart meters to make this work (see further below).
  • All consumers are to be entitled to contract with aggregators, without the consent of their supplier, and to end such contracts within three weeks.

In addition, special consideration is given to two newly defined categories of persons.

  • “Active consumers” are defined as individuals or groups “who consume, store or sell electricity generated on their premises, including through aggregators, or participate in demand response or energy efficiency schemes”, but who do not do so commercially / professionally.
  • “Local energy communities” are defined as organisations “effectively controlled by local shareholders or members, generally non-profit driven or generally value rather than profit-driven…engaged in local energy generation, distribution, aggregation storage, supply or energy efficiency services, including across borders”.

Active consumers are to be:

  • entitled to undertake their chosen activities “in all organised markets” without facing disproportionately burdensome procedures or charges; and
  • encouraged to participate alongside generators in all organised markets.  Obviously in most cases they will do this through aggregators, who are to be treated “in a non-discriminatory manner, on the basis of their technical capabilities”.  For example, they are not to be required to pay compensation to suppliers or generators (contrary to some of the suggestions in the UK call for evidence referred to above).

Local energy communities:

  • are similarly not to be discriminated against;
  • may “establish community networks and autonomously manage them” and “purchase and sell electricity in all organised markets”;
  • must not make participation in a local energy community compulsory, or limit it to those who are shareholders in or members of the community; and
  • will be subject to the unbundling rules for distribution system operators if they are DSOs.

As in the original Directive 2009/72/EC, there are provisions requiring improvements to customer billing and encouraging the rollout of smart meters.

  • Customers should receive bills once a month where remote reading of the meter is possible.
  • Where a Member State has decided not to mandate smart meters for cost-benefit reasons, they are to revisit their assessment “periodically” and report the results to the Commission.
  • The draft Directive sets out functionalities that smart meters must include where a Member State mandates their rollout.  In such cases, the costs of smart metering deployment are to be shared between all consumers.  In other cases, every customer is entitled, on request, to receive a smart meter that complies with a slightly reduced set of functionalities.
  • The implementation of smart metering must encourage active participation of consumers in the electricity supply market (although this may be qualified by a cost-benefit analysis).
  • There are a number of provisions reflecting both concerns about cybersecurity and the importance of making useful data securely available to legitimate market participants.

DSOs (and EVs)

There has been no shortage of recent commentary on how the shift towards decentralised generation of electricity, combined with the potential for storage and more active consumer behavior, may require changes in the role of the 2,400 market participants that the IMED has always called distribution system operators, but which in many jurisdictions have historically not had, even within their own networks, the kind of “system operator” responsibilities of a transmission system operator.  The recent UK call for evidence on flexibility appears at least prepared to contemplate some significant realignment of the respective functions of DSOs and TSOs.  There is nothing so fundamental in the revised IMED, but there are a number of new provisions about DSOs.

  • DSOs are to be allowed, and incentivised, to procure services such as distributed generation, demand response and storage in order to make their networks operate more efficiently.  DSOs will be paid for this, and must specify standardised market products for these services.
  • Every two years, DSOs must update five to ten year network development plans for new investments, “with particular emphasis on the main distribution infrastructure which is required…to connect new generation capacity and new loads including re-charging points for electric vehicles”, as well as demand response, storage, energy efficiency etc.
  • DSOs serving isolated systems or fewer than 100,000 consumers can be excused from this requirement, but note that in general, those operating “closed distribution systems” are to be subject to the same rules as other DSOs under the revised IMED.

However, although DSOs are to facilitate the adoption of new technologies, such as storage and EVs, they are not encouraged to diversify into actually providing them to end users themselves.

  • Member States are to facilitate EV charging infrastructure from a regulatory point of view, but DSOs may only “own, develop, manage or operate” EV charging points if the regulator allows them to after an open tender process in which nobody else expresses an interest in doing so.  And even then, the service taken on by the DSO must be re-tendered every five years.
  • Similar rules would apply to the development, operation and management of storage facilities by either DSOs or TSOs.  For TSOs, there would be an additional requirement that the storage services or facilities concerned are “necessary” to ensure efficient and secure operation of the transmission system, and are not used to sell electricity to the market.

What makes these provisions significant is that until now, with the IMED in its original form silent on the subject of storage, the operation of storage facilities had been seen as potentially falling within the categories of generation or supply.  This appeared to make the involvement of DSOs or TSOs in storage projects (at least as investors) subject to the general unbundling restrictions, and so has tended to inhibit the progress of energy storage initiatives in a number of cases.  The proposed new rules are restrictive in some respects, but bring a degree of clarity and at least recognise storage as a distinct category.

The Revised Market Regulation

General organisation of the electricity market

Like the revised IMED, the Revised Market Regulation begins with firm statements of purpose: enabling market access for all resource providers and electricity customers, enabling demand response, aggregation and so on.  It goes on to list 14 “principles” with which “the operation of electricity markets shall comply” – starting with “prices are formed based on demand and supply” and finishing with “long-term hedging opportunities allow to hedge parties against price volatility risks”.

Entirely in keeping with these principles, the first specific provision is that all market participants are to be responsible for (or to delegate to a responsible third party) the consequences of any imbalance they create in the electricity system as a result of importing or exporting to or from the grid at a given time more or less than they had said would be the case at that time in previous notifications to the system operator.  This much-trailed provision may be a significant change for renewable generators in some jurisdictions (though not in GB, where imbalance charging reforms are already being implemented).  In an earlier draft, the Revised Market Regulation only permitted sub-500kW renewables or high-efficiency CHP to be exempted from this requirement.  In the published version, this exemption has been broadened to include RES projects that have received state aid that has been cleared by the commission and that have been commissioned before the Revised Market Regulation enters into force.  It also requires that “all market participants” are to have access to the balancing market on non-discriminatory terms, either directly or through aggregators.

There are a number of quite detailed provisions on the overall organisation of electricity markets. We pick out a few of the more notable ones below.

  • There is a shift from a national to a regional approach.  As the explanatory memorandum to the draft Directive puts it: “In certain areas, e.g. for the EU-wide ‘market coupling’ mechanism, TSO cooperation has already become mandatory, and the system of majority voting on some issues has proven to be successful…Following this successful example, mandatory cooperation should be expanded to other areas in the regulatory framework.  To this end, TSOs could decide within ‘Regional Operational Centres’…on those issues where fragmented and uncoordinated national actions could negatively affect the market and consumers (e.g. in the fields of system operation, capacity calculation for interconnectors, security of supply and risk preparedness).”.  Functions to be carried out at a regional level include “the dimensioning of reserve capacity” and “the procurement of balancing capacity”.
  • As far as possible, the organisation of markets is to avoid any rules that could restrict cross-border trading or the participation of smaller players.  So, for example, trades are to be anonymous and in a form that does not distinguish between bidders within and outside a bidding zone.  The minimum bid size is not to exceed 1 MW.
  • Market participants are to be able to trade energy as close to real time as possible, with imbalance settlement periods being set to 15 minutes by 1 January 2025.
  • Long-term (firm, and transferable) transmission rights or equivalent measures are to be put in place to enable e.g. renewable generators to hedge price risks across bidding zone borders.  Such rights are to be allocated in a market-based manner through a single allocation platform.
  • As a general rule, there must be no direct or indirect caps or floors on wholesale power prices, other than a cap at the value of lost load and a floor of minus €2000, or during a 2-year transitional period when a transitional maximum and minimum clearing price may be allowed.  Defined as “an estimation in €/MWh of the maximum electricity price that consumers are willing to pay to avoid an outage”, the value of lost load is to be defined nationally and updated at least every five years.  This concept will evidently need refinement, as there is a difference between what individual consumers may be prepared to pay and the kind of price spikes that it is reasonable for wholesale markets to bear for short periods of time.
  • Dispatching of generation and demand response is to be market-based.  Priority dispatch for renewables is to be brought to an end subject to certain exceptions (these are summarised in the section on the revised RED below).  On the other hand, where redispatch (changing generator output levels) or curtailment is imposed by the system operator other than on market-based criteria, the draft Regulation imposes restrictions on when RES, high-efficiency CHP and self-generated power can be redispatched or curtailed.
  • There is to be a review of the bidding zones within the single electricity market, so as to maximise economic efficiency and cross-border trading opportunities while maintaining security of supply.  In other words, the market coupling process should allow customers to benefit from the availability of lower-priced wholesale power in adjacent markets, but the bidding zone boundaries need to take account of “long-term structural congestion” in the network infrastructure for this to be workable and without adverse side-effects.  TSOs are to participate in the review, but the final decisions are to be taken by the Commission.
  • A significant piece of work is to be undertaken by ACER on “the progressive convergence of transmission and distribution tariff methodologies”.  This is to include, but not be limited to, some issues that have recently proved contentious in the GB context, including the respective shares of tariffs to be paid by those who generate and those who consume power; locational signals (how much more should generators pay if they are located a long way from where the power they generate used); and which network users should be subject to tariffs (would this, for example, open up the question of whether generators connected to the distribution network should pay a share of transmission network charges?).
  • Separately, the draft Regulation sets out some general principles about network charges and restricts both the circumstances in which revenue can be generated from congestion management and the uses to which such revenue can be put.

Resource adequacy (a.k.a. Capacity Markets)

The growth in the share of installed generating capacity in many Member States represented by intermittent renewable generators and the unattractive economics of new large-scale combined cycle gas-fired plant has left many governments in the EU concerned about security of power supply and turning to various forms of capacity market subsidy in order to ensure that the lights stay on.  The Commission has been concerned that capacity markets dampen the price signals that should drive new investment and potentially introduce new barriers to cross-border power flows.  A number of national capacity market regimes have been investigated by the Commission’s DG Competition; both the UK and French approaches to the problem have received state aid clearance.

The starting point of the draft Regulation in this area is an annual assessment of “the overall adequacy of the electricity system to supply current and projected demands for electricity ten years ahead”.  This European-level assessment will form the yardstick against which national proposals to introduce a capacity mechanism are to be judged.  If it has “not identified a resource adequacy concern, Member States shall not introduce capacity mechanisms” and no new contracts shall be concluded under existing capacity mechanisms.  Where capacity mechanisms are introduced, they must not distort the market unnecessarily; interconnected Member States should be consulted; and other approaches, such as interconnection and storage, should be considered first.

The draft Regulation prescribes common elements which capacity mechanisms must contain, including that they must be open to providers in interconnected Member States (unless they take the form of strategic reserves) and that the authorities of one country must not prevent capacity located in their territory from participating in other countries’ capacity mechanisms.  Those participating simultaneously in more than one capacity mechanism “shall be subject to two or more penalties if there is concurrent scarcity in two or more bidding zones that the capacity provider is contracted in”.  Maybe that will help to dampen industry’s appetite for capacity markets.

Finally, the draft Regulation sets an emission limit of 550 gCO2/kWh for plant on which a final investment decision is made after the Regulation enters into force.  Such plant must have emissions below this limit if it is to be eligible for capacity mechanism support.  The draft Regulation goes on to state that generation capacity emitting at this level or higher is “not to be committed in capacity mechanisms 5 years after the entry into force of this Regulation”.  These provisions may be motivated by laudable decarbonisation objectives, but they must at the very least risk precipitating a rush to take final investment decisions in new coal-fired generating capacity over the next two years.  It is possible, but unlikely, that they might stimulate further investment in carbon capture and storage (to bring the emissions of coal-fired plants below the threshold).  Previous experience with emissions limit rules also suggests that much will depend on how emissions are measured – the usual trick of polluting plant being to argue that they should be counted not per hour of generation, but averaged out over time so as to allow for plant to run above the limit for short periods.  This is bound to be an area for lively negotiations between Member States and in the European Parliament.

The Commission’s proposals in relation to capacity markets need to be read alongside DG Competition’s final report on its investigation and the accompanying Staff Working Paper.  We will look in more detail at this aspect of the proposals and how it might affect existing Member State initiatives in a future post.  For now, it is sufficient to note that although this part of the Winter Package is entirely consistent with the logic of the evolving single electricity market, for some, it may simply appear to be an unacceptable blow to the principle of Member States’ self-determination of their own generating mix.

Institutions

In addition to its existing roles, the TSO umbrella body, ENTSO-E, will acquire new responsibilities for the European resource adequacy assessment and in relation to the Regional Operational Centres, including adopting a proposal for defining the regions which each will cover, and generally monitoring and reporting on their performance.  A parallel umbrella body for DSOs, with consultative functions, is also to be set up.

The draft Regulation devotes a number of articles to the Regional Operational Centres. They will be limited liability companies established by TSOs (with adequate cover for potential liabilities incurred by the impact of their decisions).  Their role is to complement TSO functions by ensuring the smooth operation of the interconnected transmission system, but apparently from the perspective of planning and analysis rather than real-time  operational control.  Specific areas of their work (listed under 17 headings) include outage planning coordination, calculating the minimum entry capacity available for participation of foreign capacity in capacity mechanisms, and much else besides.

This area of the draft Regulation will need careful development and implementation if the proliferation of new bodies and functions is not to result in confusion and a lack of accountability.  However, the question of whether to grant Regional Operational Centres binding decision-making powers in relation to some of their potential functions is left to be decided by the national regulatory authorities of a system operating region.

The Revised RED

Target for 2030

The existing Renewable Energy Directive (2009/28/EC) sets out the binding national targets for each Member State to achieve a specified proportion of its energy consumption to be obtained from renewable energy sources (RES) by 2020, contributing to an EU-wide goal of 20% of final energy from RES.  The revised RED starts from a slightly different point, since EU leaders decided in 2014 to move away from legally binding national RES targets imposed at EU level but to set a goal of achieving at least 27% of energy from RES across the EU by 2030.  The starting point of the revised RED, therefore, is that “Member States shall collectively ensure” that the 27% target is achieved by 2030, whilst, individually, ensuring that they continue to obtain at least as high a proportion of final energy from RES as they were obliged to achieve by 2020.

At this point, you may ask what the enforcement mechanism is for meeting the new EU-wide target.  An answer (of sorts) is to be found in the Governance Regulation – see below.

Power (plus)

With reference to subsidies for RES, the revised RED builds on the principles set out in the Commission’s 2014 guidelines on state aid in the energy and environmental sectors: competitive auctions in which all technologies can compete on a level playing field are to be the norm, with traditional feed-in tariffs limited to small projects.

The revised RED also makes provision on two points that have led to disputes in connection with RES subsidies.  First, picking up on a point that has in the past given rise to litigation under general EU Treaty principles, it would set quotas for the proportion of capacity tendered in RES subsidy auctions that each Member State must throw open to projects from other Member States.  Second, with an eye to the numerous cases brought against Member States either under domestic constitutional / administrative law or under the Energy Charter Treaty, the revised RED attempts to outlaw retrospective reductions in support for RES once that support has been awarded, unless these are required because a state aid investigation by the Commission has found the subsidy received by a project is unduly generous.  Note that while the first of these rules appears to relate only to RES electricity subsidies, the second is expressed in a way that suggests that it relates to all RES projects.   An additional measure of reassurance for investors is a requirement to consult on and publish “a long-term schedule in relation to expected allocation for [RES] support” looking at least three years ahead.

Other points of interest in the draft Directive in connection with RES power include:

  • In a magnificently brief reference to one of the most important market trends in the renewable power sector, the revised RED would require Member States to “remove administrative barriers to corporate long-term power purchase agreements to finance renewables and facilitate their uptake”.
  • The process of applying for permits to build and operate new RES projects is to be streamlined, with a single point of contact co-ordinating the permitting process (including for associated network infrastructure) and ensuring that it does not last longer than three years.  This provision would confers on all RES projects (again, the current language of the draft Directive does not limit this to power sector projects) a benefit currently only conferred at EU level under the Infrastructure Regulation on those projects singled out as Projects of Common Interest – although in its current form it is questionable if it would give a developer thwarted by slow decision-making in a given case a useful remedy.
  • The permitting procedures for repowering of existing projects are to be “simplified and swift” (i.e. not to last more than 1 year), although this may not apply if there are “major environmental or social” impacts.  If you were hoping to be able to demand fast-track treatment for applications to repower existing wind farms with fewer, taller turbines generating more power, don’t hold your breath.
  • The existing RED rules on priority dispatch for RES generators are to be abolished.  This point is reiterated in the Revised Market Regulation.  However, that draft Regulation provides for “grandfathering” of priority dispatch rights for existing RES (and high efficiency CHP) generators until such time as they undergo “significant modifications”.  Exceptions are also permitted for innovative technologies and sub-500kW installations (from 2026, sub-250kW), if no more than 15% of total installed generating capacity in a given Member State benefits from priority dispatch (beyond that level, the threshold is 250kW or 125kW from 2026).
  • The revised RED likes prosumers, or as it calls them, “renewable self-consumers”.  They are to be entitled to sell their surplus power “without being subject to disproportionate procedures and charges that are not cost reflective”, to receive a market price for what they feed into the grid, and not to be regulated as electricity suppliers if they do not feed in more than 10MWh (as a household) or 500MWh (as a business) annually (Member States may set higher limits).
  • The revised RED also likes “renewable energy communities”.  The draft definition of these is a little complicated, but essentially they are locally based entities that are either SMEs or not for profit organisations, which are to be allowed to generate, consume, store and sell renewable electricity, including through PPAs.

Heat, cooling and transport

The revised RED seeks to “mainstream” RES in heating and cooling installations, and in the transport sector.  The means by which it seeks to achieve this are not, at first sight particularly dramatic, given the acknowledged scale and difficulty of the challenge of decarbonising these sectors.

In relation to heat and cooling, Member States are to identify “obligated parties amongst wholesale or retail energy and energy fuel suppliers” and require them to increase the share of RES in their heating and cooling sales by at least 1 percentage point a year.  The obligation should be capable of being discharged either directly or indirectly (including by installing or funding the installation of highly efficient RES heating and cooling systems in buildings).  This does not seem hugely ambitious.  Mention is made of “tradable certificates” – it feels a bit like a combination of the Renewables Obligation, but applied to heat and cooling, and the Clean Development Mechanism under the Kyoto Protocol.  It is also relevant in this context that the revised RED envisages that renewable guarantees of origin (REGOs or GoOs) will in future be available for the production and injection into the grid of renewable gases such as biomethane.

The rules aimed at the transport sector are also based on mandatory requirements on fuel suppliers – in this case to incorporate both a minimum (annually increasing) percentage of certain kinds of RES fuel, waste-based fossil fuel and RES electricity into the transport fuel they supply and to ensure that the parts of that supply that take the form of advanced biofuels and biogas from specified sources (which must constitute a certain part of the overall RES percentage) contribute to an increasing reduction in greenhouse gas emissions.  The provisions for calculating the various percentages are quite complex, involving as they do an element of lifecycle emissions calculation (e.g. considering the emissions from the generation of electricity used to produce advanced biofuels).

On district heating and cooling, the revised RED takes a three-pronged approach.

  • Member States are to ensure that authorities at local, national and regional level “include provisions for the integration and deployment of renewable energy and the utilisation of unavoidable waste heat or cold when planning, designing, building and renovating urban infrastructure, industrial or residential areas and energy infrastructure, including electricity, district heating, and cooling, natural gas and alternative fuel networks”.
  • The efficiency of district heating systems is to be certified.  Providers of such systems must grant access to new customers where they have the capacity to do so (unless they are new and meet exemption criteria based on efficiency and use of renewables).  Customers of systems that are not efficient may disconnect from them in favour of their own RES heat and cooling, but Member States may restrict this right to those who can demonstrate that the customer’s own heating or cooling solution is more efficient.
  • There is to be regular consultation between operators of district heating and gas / electricity networks about the potential to exploit synergies between investments in their respective networks.  Electricity network operators must also assess the potential for using district heating and cooling networks for balancing and energy storage purposes.

This is all unobjectionable.  It is not clear that in itself it will be enough to cause a major expansion of district heating and cooling where it does not already exist, or to significantly increase the take-up of RES heat and cooling options, but perhaps this is the kind of area where an effective policy push can only be delivered at national, or indeed municipal level.

Biomass

Following a trend that has been evident for some time in UK subsidies for RES electricity, the revised RED would appear to prohibit “public support for installations converting biomass into electricity” unless they apply high efficiency CHP, if they have a fuel capacity of 20 MW or more.  However, the precise words setting this out have been moved from the operative provisions of the draft Directive into a recital, which also clarifies that this would not require the termination of support that has already been granted to specific projects, but that new biomass projects will only be able to be counted towards renewables targets if they apply high efficiency CHP.

What is clear is that the revised RED would tighten the sustainability criteria applicable to biofuels and bioliquids at various points in the energy supply chain, with greenhouse gas emissions – for example those arising from land use to grow the raw materials that become biofuels – being designated as a distinct impact to be measured.  If you dig up soil with a high carbon content to grow something that will become biofuel, you may end up increasing rather than reducing overall GHG emissions, so this is obviously to be avoided.

The Governance Regulation

The Governance Regulation is meant to hold everything together.  In particular, it aims to give credible underpinning to the commitments on climate change that the EU as a whole has made under the Paris Agreement (but which must ultimately be delivered by Member State action) and to bridge the gap left by having an EU level 2030 renewables target but no correspondingly increased Member State level targets.  It also gives legislative expression to the EU’s Union-level energy and climate targets to be achieved by 2030, which are:

  • a binding target of at least 40% domestic reduction in economy-wide greenhouse gas emissions as compared with 1990;
  • a binding target of at least 27% for the share of renewable energy consumed in the EU;
  • a target of at least 27% for improving energy efficiency in 2030, to be revised by 2020, having in mind an EU level of 30%;
  • a 15% electricity interconnection target for 2030.

In outline, the Regulation works as follows.

  • Every 10 years, starting in 2019, each Member State is to produce an integrated national energy and climate plan covering a period of ten years, two years ahead (so e.g. the 2019 plan covers 2021 to 2030, and so on).  The plan is to set out, in relation to each of the five dimensions of the Energy Union, the current state of play in the relevant Member State; the national objectives and targets, policies and measures they have adopted; and their projections (including in relation to emissions) going forward to 2040.  The draft Regulation sets out in considerable detail the information which is required to be included.
  • In relation to RES and energy efficiency, Member States are expressly required to take into account the need to contribute towards achieving the relevant EU level targets, and to ensure, collectively, that they are met.  In relation to RES policies, they are also to take into account “equitable distribution of deployment” across the EU, economic potential, geographic constraints and interconnection levels.
  • The draft Regulation states that Member States must consult widely on the plans and suggests that there may also be a need for the preparation of and consultation on a strategic environmental assessment of the draft plans in some cases.
  • Every two years (starting in the first year to which the plans apply), Member States are to report to the Commission on the status of implementation of their plans; on GHG policies, measures and projections; on climate change adaptation and support to developing countries; on progress in relation to renewable energy, energy efficiency and energy security; on internal market benchmarks such as levels of interconnectivity; and on public spending on relevant research and innovation projects.  In addition, the draft Regulation specifies how Member States are to report annually on GHG inventories for UNFCCC purposes.
  • The plans and drafts are to be updated if necessary after five years (with the first draft update in 2023 and the first update in 2024), using the same procedures.  Updates cannot result in Member States setting themselves lower targets.
  • The plans are first to be submitted to the Commission for comment one year in advance, in draft (i.e. first draft by 1 January 2018).  Either at this point or in its annual State of the Energy Union reports, the Commission may make recommendations to individual Member States, for example about “the level of ambition of objectives and targets” in its draft plan, and Member States “shall take utmost account” of these when finalising the plan.  Member States are obliged to issue annual progress reports on their plans and these must include an explanation of how they have taken utmost account of any Commission recommendations and how it has implemented or intends to implement them.  Any failure to implement the Commission’s recommendations must be justified.
  • Member States whose share of RES falls below their 2020 baseline must cover the gap by contributing to an EU-level fund for renewable projects.  If it becomes clear by 2023 that the 2030 RES target is not going to be met, Member States must cover the gap in the same way, or by increasing the percentage of RES fuel to be provided by heat and transport fuel suppliers under the revised RED, or by other means.  Action may also be taken by the Commission at EU level.

The answer to the question of how the 2030 targets are enforced is therefore – and perhaps inevitably – somewhat incomplete.  Whilst one may doubt the usefulness, under the current RED, of the prospect of the Commission taking infraction proceedings against a Member State that fails to reach the required percentage of RES energy by 2020, there is arguably nothing in the Governance Regulation that has even this degree of legal bite when it comes to pushing recalcitrant Member States into action from the centre.  However, ultimately the whole edifice of the Paris Agreement, of which this is effectively a supporting structure, will only work on the basis of a combination of the economic attractions of better energy efficiency, cheaper renewables and other technological advances, and stakeholder pressure, including through democratic and judicial processes.  The Governance Regulation, like the UK’s Climate Change Act 2008 with its system of carbon budgets, certainly provides some scope for interested parties to challenge national authorities who are, for example, failing unjustifiably to implement Commission recommendations.

The Risk Regulation

The Risk Regulation exists to provide “a common framework of rules on how to prevent, prepare for and manage electricity crisis situations, bringing more transparency to the preparation phase and…ensuring that electricity is delivered where it is needed most”.  A common approach to identifying and quantifying risks is seen as essential to building the necessary “trust” and “spirit of solidarity” between Member States.  The draft Regulation would replace the rather less ambitious existing Directive 2005/89/EC.

ENTSO-E is tasked with developing a common risk assessment methodology, on the basis of which it is to draw up and update regional crisis scenarios such as extreme weather conditions, natural disasters, fuel shortages or malicious attacks.  Provision is made for emergency planning at both national and regional levels, with the Regional Operational Centres playing a significant role at various points.  As throughout the Winter Package, emphasis is laid on using market measures wherever possible, so that forced disconnections, for example, should be response of last resort, and Member States facing a crisis should not automatically seek to curtail outbound cross-border power flows.

The ACER Regulation

It comes as no surprise that the Winter Package proposes conferring more powers on ACER.  So, for example, the methodologies and calculations underlying the European resource adequacy assessment will require the approval of, and may be amended by, ACER – since, as one of the recitals to the draft Regulation notes, “fragmented national state interventions in energy markets constitute an increasing risk to the proper functioning of cross-border electricity markets”.  But the draft Regulation is far from representing a major transformation of ACER into an EU energy super-regulator.

The Innovation Communication

The Innovation Communication picks up on a number of the themes emphasised in the various legislative proposals.  It builds on existing initiatives, for example within the framework of the EU’s Horizon 2020 funding programme, for which it includes some new money.  The need to leverage more private sector investment in innovative energy-related technologies is noted, with some examples of where this has already been achieved.  The Communication also states that the Commission, with Member States, will take a leading role in two of the workstreams identified by the international Mission Innovation Initiative.

Four particular priorities are singled out as technology focus areas for EU innovation funding:

  • Energy storage solutions, including the (perhaps not unambitious) objective of “re-launching the production of battery cells in Europe”.
  • Electro-mobility and a more integrated urban transport system, which amongst other things will include tackling “fragmentation in the developing market of low-emission transport”.
  • Decarbonising the EU building stock by 2050: going beyond “today’s nearly zero-energy designs” to include e.g. the application of circular economy principles.
  • Integration of renewables: reducing the costs of existing established technologies; promoting new technologies like building-integrated photovoltaics; and intensifying efforts to integrate renewables through storage and the transport sector.

Energy Efficiency

Last but not least, energy efficiency. The two draft Directives on this make less wide-ranging changes to the existing legislation.

Under the revised Energy Efficiency Directive, Member States will be obliged to deliver the equivalent of 1.5% of annual energy sales (by volume) to final consumers over the period 2021-2030 – but with scope to determine how those savings are phased.

As regards the Energy Performance of Buildings Directives, there is an emphasis on encouraging the use of smart technologies.  There is also a requirement, when building or carrying out major renovations of buildings with more than 10 car parking spaces, to install one alternative fuel re-charging point for every 10 spaces in a non-residential context and to put in pre-cabling for re-charging points for EVs in all spaces in a residential context.  In the non-residential context at least, the re-charging point must be “capable of starting and spotting charging in relation to price signals”.  There are also some new requirements to monitor the energy efficiency of non-residential buildings, presumably in the hope that if their owners become aware of how much inefficiencies of design or operation are costing them, they will invest in improvements.

At the same time, the Commission has issued an ecodesign working plan for 2016-2019, reminding us as it does so that EU ecodesign and energy labelling deliver “energy savings equivalent to the annual consumption of Italy” and “save almost €500 per year” on household energy bills, as well as delivering approximately €55 billion extra revenue for industry.

Brexit

One of the many energy-sector questions raised by the UK’s decision to leave the EU is on what terms participants in the electricity markets in GB and Northern Ireland (and indeed the Republic of Ireland, until such time as it has a direct interconnection with Continental Europe) may be able to continue to participate in the EU’s single electricity market in a post-Brexit world.  Possible models for this include membership of the European Economic Area (as an EFTA, rather than an EU state) or joining the Energy Community (many of whose members are candidates for EU membership, but disputes within which are resolved by a political Association Council without reference to the Court of Justice of the EU).

The Winter Package in its published form casts no direct light on this subject.  However, in a version of the main legislative proposals that was leaked only a couple of weeks before they were published, a number of the draft measures (such as the draft revised IMED) included a couple of articles that appeared to offer some grounds for hope – if continued UK membership of the single EU electricity market is the sort of prospect that makes you hopeful.

  • Like the EU itself, the Energy Community is currently operating on (or is working towards) the version of the single electricity and gas markets set out in the Third Package of EU liberalisation measures adopted in 2009.  The leaked draft revised IMED set out a process for the Energy Community and the Commission to incorporate the revised Directive into the Energy Community’s legislative framework.  So if the UK was happy with the final form of the Winter Package legislation, the option of continuing to be subject to and getting the benefit of it as a member of the Energy Community would be a possible option.
  • On the other hand, once the UK ceases to be an EU Member State, and assuming it does not opt for EEA membership, it will simply become a “third country” (with or without the benefit of a bespoke EU / UK free trade agreement).  The leaked draft revised IMED suggested that third countries may participate in the single electricity market provided that they agree to adopt, and apply, “the main provisions” of the Winter Package legislation; EU state aid rules; the REMIT rules on wholesale energy market integrity; “environmental rules with relevant for the power sector”; and rules on enforcement and judicial oversight that require it to submit either to the authority of the Commission and the CJEU or “to a specific non-domestic enforcement body and a neutral non-domestic Court or arbitration body which is independent from the respective third country”.

Reading these provisions in the UK, it was hard not to see them as drafted with Brexit in mind.  Of course, the EU is, or aspires to be, physically connected to power systems in other non-EU countries as well (such as the potential solar energy exporters of North Africa), so it would be wrong to see them entirely in that light.

How the absence of such provisions, or the prospect of their potential reinsertion, will affect the dynamics of the UK’s participation in negotiations on the Winter Package (which is likely to take place while the UK is still a Member State) is another question.  In our view, the UK and its electricity industry stakeholders should in any event try to play a leading and constructive role in the whole of the negotiations on the Winter Package, as they have in negotiation on past internal energy market measures.

Maybe, in one sense, it is better that the draft provisions on third country participation have not been included at this stage.  Similar provisions could be negotiated on a standalone basis later, and include the gas as well as electricity single markets, for example.  By leaving them out of the Winter Package (for whatever reason), the Commission may have prevented the UK team from being unduly distracted from the main subject of the legislative proposals, or expending its negotiating capital on their Brexit dimension.

Provisional conclusions

The Winter Package covers a lot of ground, but then it needs to do so, since the next ten years are acknowledged to be crucial to the success of global efforts to avoid dangerous climate change.  It may not be as radical as some would like, but then whilst some of its requirements are already more or less met by a number of Member States, for others they may represent a considerable challenge.  In one sense it is a timely reminder of both the scope and the limitations of the European project.

There are a lot of links between the individual pieces of draft legislation.  There are also a number of areas where the drafting suggests that some key concepts have not yet been absolutely fully thought out.  Steering negotiations so as to result in a clear and coherent legal framework will be difficult.  The risks of (calculated or inadvertent) lack of clarity in the final texts may be higher than is usual with EU legislation, leading to wrangles with regulators and before the courts down the line – or simply having a chilling effect on what could be useful activity.  However, since the need for action is urgent, waiting for perfect legislation is not a luxury the EU can afford.  So it is vital that those with an interest in making Energy Union work scrutinise the parts of the Winter Package that matter to them carefully, and tell their national governments or MEPs where they find it wanting.

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Something for everyone? The European Commission’s Winter “Clean Energy” Package on Energy Union (November 2016)

Significant Developments in Canadian Energy – For the Month of November 2016

Conventional

  • November 29, 2016 – Raging River Exploration Inc. closed a Viking consolidation transaction. The company acquired approximately 620 boe per day — 97 per cent light oil — of production and 24 net sections of land prospective for Viking light oil, for total cash consideration of approximately CDN$58 million subject, to customary adjustments. In a separate release, Northern Blizzard Resources Inc. said it completed the sale of Viking light-oil assets in the Coleville area of Saskatchewan for cash consideration of CDN$58 million, subject to customary adjustments.
  • November 23, 2016 – Lightstream Resources Ltd. announced that sale procedures under the Companies’ Creditors Arrangement Act (CCAA) have concluded and that the credit bid submitted by the ad hoc committee of holders of approximately 91.5 per cent of the company’s 9.875 per cent second lien secured notes due 2019 is the successful bid. In accordance with the sale procedures, the company will seek to implement the credit bid by finalizing the terms of the definitive agreements and applying to the Court of Queen’s Bench of Alberta for an approval and vesting order anticipated to be heard on Dec. 8, 2016.
  • November 23, 2016 – Baytex Energy Corp. entered into an agreement to acquire heavy oil assets located in the Peace River area of northern Alberta for cash consideration of CDN$65 million, subject to customary adjustments. The assets add approximately 3,000 boe per day of production and more than double Baytex’s land base in the area. The acquisition will be funded through a concurrent $100 million bought deal financing.
  • November 18, 2016 – Spartan Energy Corp. entered into an agreement with ARC Resources Ltd. to acquire assets in southeast Saskatchewan for cash consideration of CDN$700 million, subject to customary adjustments. The acquisition will be funded through Spartan’s pro forma credit facility and through committed concurrent equity financings totalling CDN$505 million.
  • November 11, 2016 – ConocoPhillips announced plans to divest of US$5 billion to US$8 billion in assets, which will include assets in Western Canada. “These will be primarily North American gas assets, including some assets from our Western Canada Business Unit,” company spokesperson Rob Evans said, when asked following an analyst day event whether assets from Canada would be included.  “Specific details on Western Canada assets to be [marketed] are currently being worked out,” he added.
  • November 8, 2016 – Delphi Energy Corp. has entered into a non-binding Letter of Intent with an existing working interest partner. This transaction is intended to accelerate the development of its liquids-rich Deep Basin natural gas play at Bigstone in northwest Alberta. Under the LOI, the partner will undertake a CDN$40 million (gross) joint drilling program, to be completed before July 15, 2017, of which Delphi will contribute CDN$6 million while retaining a 65 percent working interest, in approximately five to six wells to be drilled at Bigstone Montney. The partner will contribute CDN$20 million in capital, along with its 35 per cent working interest share of CDN$14 million. In addition to the above drilling capital contribution, Delphi will receive CDN$30 million in cash at closing for equalization consideration.
  • November 2, 2016 – Tamarack Valley Energy Ltd. and Spur Resources Ltd. entered into an arrangement agreement providing for the acquisition by Tamarack of all the issued and outstanding common shares of Spur. As consideration, Tamarack will issue an aggregate of 90.1 million common shares of Tamarack and CDN$57.3 million in cash. Tamarack will also be assuming Spur’s net debt, estimated to be CDN$25.7 million as at Nov. 30, 2016, after accounting for proceeds from the exercise of all outstanding options of Spur, and severance and transaction costs. Based upon the previous 10-day VWAP of Tamarack of CDN$3.60 per share, the total consideration payable by Tamarack, including the assumption of debt, is approximately CDN$407.5 million.

Unconventional

  • November 7, 2016 – Woodfibre LNG will commence construction on British Columbia’s first liquefied natural gas processing and export terminal in 2017. The facility near Squamish, north of Vancouver, will export 2.1 million tonnes a year once it is operational in 2020, according to a company statement.
  • November 4, 2016 – Athabasca Oil Corporation announced an upsizing of the previously completed contingent bitumen royalty on its thermal assets with Burgess Energy Holdings L.L.C. for additional cash consideration of CDN$128.5 million. Including the initial royalty, Athabasca has now raised total cash proceeds of CDN$257 million.

Midstream

  • November 30, 2016 – The federal government announced that it had approved Kinder Morgan Inc.’s proposal to more than double the capacity of its Trans Mountain pipeline. Prime Minister Justin Trudeau also said Ottawa had vetoed Enbridge Inc.’s proposed Northern Gateway line, which would have taken crude from Alberta’s oilsands to the Pacific coast. It approved Enbridge’s plan to replace Canadian segments of Line 3, which carries crude from Alberta to Wisconsin.
  • November 16, 2016 – Tidewater Midstream and Infrastructure Ltd. entered into an agreement with to acquire an approximate 50 per cent working interest in 150 kilometres of gas gathering pipelines which are directly connected to Tidewater’s existing Brazeau River Complex (BRC), in addition to three natural gas storage reservoirs that are also directly connected to the BRC by means of the acquired pipelines, for a purchase price of CDN$15 million in cash.
  • November 3, 2016 – Union Gas announced the commercial in-service of a CDN$391 million expansion of natural gas pipeline and compression facilities that will move an incremental 0.4 PJ/d (.36 Bcf/d) of natural gas supplies through its Dawn-Parkway System, which links markets in eastern Canada and the northeast U.S. with the Dawn Hub. The facilities placed into commercial service comprise approximately 20 kilometres of 48-inch diameter pipeline between Hamilton and Milton, Ont., and an additional compressor facility at the existing Lobo Compressor Station near London.

Petrochemicals Manufacturing

  • November 4, 2016 – A part of the acquisition by Inter Pipeline Ltd.  (IPL) of The Williams Companies Inc.’s and Williams Partners L.P.’s  Canadian natural gas liquids midstream businesses, IPL assumes responsibility for the potential construction of a CDN$1.85 billion propane dehydrogenation (PDH) facility located near the Redwater Olefinic Fractionator. This facility would convert locally sourced propane into more valuable polymer grade propylene. Inter Pipeline is also assessing the commercial viability of constructing an additional processing facility, which would convert propylene into polypropylene, a solid plastic used in manufacturing a wide range of finished products. The preliminary estimate for the polypropylene facility is approximately CDN$1.3 billion. IPL is currently pursuing long-term, fee based offtake agreements with a number of global plastics manufacturing and marketing companies. Subject to securing appropriate commercial contracts, Inter Pipeline anticipates making final investment decisions on the PDH and polypropylene facilities by mid-2017, with both plants operational by mid-2021.

Oilfield Services

  • November 24, 2016 – Calfrac Well Services Ltd. entered into an agreement with Peters & Co. Limited, as lead underwriter on behalf of a syndicate of underwriters, pursuant to which the underwriters have agreed to purchase, on a private placement basis, 14,040,000 common shares of Calfrac at a price of CDN$2.85 per share for total gross proceeds of approximately CDN$40 million.
  • November 24, 2016 – Total Energy Services Inc. announced an intention to make an offer to purchase all of the issued and outstanding common shares of Savanna Energy Services Corp. for consideration consisting of common shares of Total. Total anticipates that, if the offer is successful, holders of Savanna shares will receive, in exchange for each Savanna share, 0.1132 of a common share of Total.
  • November 23, 2016 – Alberta Investment Management Corporation (AIMCo) signed a letter of commitment and a subscription agreement, on behalf of certain of its clients, to enter into a strategic financing relationship with Savanna Energy Services Corp. The financing relationship provides for a CDN$200 million debt-with-warrants financing and a private placement of 13 million common shares of Savanna at a price of CDN$1.45 per common share for gross proceeds of CDN$18.85 million.
Significant Developments in Canadian Energy – For the Month of November 2016

Sanctions in Energy: Russia and Iran

US and EU sanctions related to Russia and Iran have a direct and targeted impact on the energy sector. The sanctions regimes against Russia and Iran differ substantially and seem to be moving in different directions. In this article, we explore the challenges facing US and EU energy companies seeking to operate in Russia and Iran.

Brief overview of energy related sanctions against Russia

US Sanctions

Since March 2014, the US has imposed an increasingly strict set of sanctions against Russian and Ukrainian individuals and companies. These sanctions generally fall into four categories: a list of blocked persons and entities, identified as Specially Designated Nationals, or SDNs; much more limited restrictions for specified Russian banks, oil companies and technology companies, identified as a Sectoral Sanctions Identification List or SSI List; export controls; and a full commercial embargo of Crimea. These sanctions are imposed pursuant to several Executive Orders promulgated by President Obama and the Ukraine-Related Sanctions Regulations[1]. US Persons—defined as US citizens and permanent residents, entities organized under US jurisdictions, and persons physically in the United States—must comply.

The US has designated as SDNs a number of key government and military officials (both Russian and from the former Ukrainian Government), individuals with close ties to the Russian Government, and Russian and Crimean entities[2]. US Persons are generally prohibited from transacting with any of these blocked persons, and must freeze such blocked persons’ property in their possession, custody, or control. These SDNs are also banned from traveling to the US. In comparison with the SSI List, SDNs targeted inter alia leaders of the Russian oil companies.

According to SSI List and its related OFAC’s Directives, the following activities by a US Person or within the United States related to oil companies are prohibited, except to the extent provided by law or unless licensed or otherwise authorized by the Office of Foreign Assets Control: the provision, exportation, or re-exportation, directly or indirectly, of goods, services (except for financial services), or technology in support of exploration or production for deep-water, Arctic offshore, or shale projects that have the potential to produce oil in the Russian Federation, or in a maritime area claimed by the Russian Federation and extending from its territory, and that involve any person determined to be subject to this Directive, its property, or its interests in property. The prohibition on the exportation of services includes, for example, drilling services, geophysical services, geological services, logistical services, management services, modeling capabilities, and mapping technologies[3]. The SSI List includes, among others, Russia’s largest energy companies.

EU sanctions

The US and EU sanctions are largely aligned. Like the US, the EU has also adopted sanctions that block persons, restrict financing, limit certain exports, and broadly prohibit trade with Crimea. EU persons—EU citizens and permanent residents, entities organized in EU member states and persons physically in the European Union—must comply.

While there are differences between the US and EU sanctions, these are more of a degree than of a kind. For example, the EU and US do not block an identical set of individuals and entities, but the implications for those blocked persons are the same: a visa ban (for individuals) and a freezing of all assets[4]. Notably for EU companies in the energy sector, EU sanctions prohibit the provision of loans or investment services to Crimean companies, ban exports of goods and technology and prohibit the provision of technical assistance, brokering, construction, or engineering services, in the energy sector and in the prospecting for, and exploration and production of oil, gas, and mineral resources, to any Crimean entity, or for use in Crimea. Contracts signed prior to 20 September 2014 are exempted[5].

Brief overview of energy related sanctions against Iran

On 14 July 2015, the “P5+1” working group (China, France, Germany, Russia, the UK and the US) reached a landmark agreement with the Government of Iran to adopt the Joint Comprehensive Plan of Action (the JCPOA). Under the JCPOA, the P5+1 agreed to implement broad UN, US and EU sanctions relief in exchange for Iran’s ongoing compliance with a number of nuclear-related measures. This sanctions relief will occur in two phases: (1) when the International Atomic Energy Agency (the IAEA) verifies Iran’s compliance with nuclear-related measures, which occurred on 16 January 2016; and (2) when the IAEA, together with the UN Security Council, confirms that Iran’s nuclear materials are being used for peaceful activities, or 18 October 2023, whichever is sooner[6].

US Sanctions

Most of the US sanctions that are suspended—both in the first and second phases—are extraterritorial, i.e., they apply to non-US Persons who do business with Iran. US companies seeking to engage the Iranian market, therefore, need to be aware of the limits of US sanctions relief under the JCPOA, namely:

1. US Persons generally remain prohibited from doing business with Iran. The JCPOA will not lift the general commercial embargo which prohibits US Persons from doing business with Iran, except for certain sales of civilian commercial aircraft to Iran, imports of Iranian-origin carpets and foodstuffs.
2. US companies’ overseas subsidiaries will be licensed to transact with Iran under OFAC’s General License H. The JCPOA will license overseas subsidiaries of US entities for activities consistent with the agreement. However, the licensing methodology and the definition of “overseas subsidiaries” are not described and remain to be clarified.
3. Other US sanctions including those related to counter-terrorism or human rights-related sanctions asserting extraterritorial application[7] will remain in place.
4. On 7 October 2016, OFAC issued updated guidance on several issues. The issues addressed include banking transactions with Iranian banks; dollar-denominated transactions; acceptable due diligence standards; and part-ownership of Iranian companies by entities who remain on the SDN list[8].

With regard to Iran’s vast oil and gas reserves, the first phase of relief will mean the US will no longer sanction non-US Persons who engage in transactions with Iran’s energy, shipping and shipbuilding sectors, or port operations[9]. Nor will the US any longer sanction non-US persons who invest in Iran’s oil, gas and petrochemical sectors; purchase, sell, transport, or market oil, gas and petrochemicals from Iran; export, sell or provide refined petroleum products and petrochemical products to Iran; or otherwise transact with Iran’s energy sector including Naftiran Intertrade Company, National Iranian Oil Company and National Iranian Tanker Company, and associated services[10]. Non-nuclear-related sanctions still remain in place on all companies and persons, regardless of nationality, who seek to do business with any Iranian people or entities which remain on the SDN List.

EU sanctions

EU sanctions relief is far more expansive. Unlike the US, the EU will allow its companies to invest directly in Iran and transact with Iranian persons. EU member states have agreed to terminate or suspend all “economic and financial sanctions” against Iran[11]. As a result of the first phase of sanctions relief under the JCPOA, EU persons are permitted to trade in Iranian crude oil and petroleum products, natural gas and petrochemical products, as well as related financing. Similarly, the sale, supply or transfer of equipment and technology, as well as the provision of technical assistance and training in this sector are permitted. In addition, EU Persons are free to grant financial loans or credit and to participate in joint ventures with any Iranian persons engaged in the oil, gas and petrochemical sectors in Iran or elsewhere.

Implications for energy companies

While the US and EU have both imposed a number of sanctions on Russia that aim directly to constrain investment in Russia’s energy sector—and in particular its future oil development—there are a number of reasons why Russia’s energy sector may possibly continue to attract US and European investment.

To begin with, US and EU sanctions are (thus far) narrowly targeted. Unless specifically prohibited, Russia’s economy, including its energy sector, is fully open to investment. Second, the sanctions against Russia could be lifted, if the situation in Eastern Ukraine and Crimea develops in certain directions. Finally, US and EU companies are more familiar with Russia and Russian business practices in comparison to Iran, a country where numerous other compliance and other business risks are encountered.

During the first phase of sanctions relief under the JCPOA, which began on 16 January 2016, EU energy companies and the overseas subsidiaries (again yet to be defined) of US energy companies will now have the opportunity to engage Iran’s vastly underdeveloped energy sector. It is estimated that the country will need hundreds of billions of dollars of investment to restore its petroleum fields and then further develop them. EU and the overseas subsidiaries of US companies seeking to engage Iran should therefore be prepared to understand and implement an updated sanctions compliance program that ensures they do not inadvertently risk breach of the ongoing EU and US sanctions. These companies will need to also actively monitor Iran’s compliance as determined by the IAEA and the JCPOA Committee, as a breach may trigger a mandatory wind-down and withdrawal.

The same is not true with regard to the remaining US sanctions against Iran, for example, which would require approval by the US Congress. Moreover, critically, the JCPOA provides for UN, US and EU sanctions to “snapback.” This means that while many companies may now be allowed to invest in Iran, they will face the prospect of having to wind down their operations in the event that Iran is found to have breached the JCPOA[12].

“We note that other countries, including Canada, also continue to maintain sanctions against Iran that go beyond the limited sanctions imposed by the UN. To the extent there is any connection to such other countries in particular transactions, country-specific sanctions compliance advice should also be sought.”


[1]31 CFR Part 589.
[2]Executive Orders of the President of the US on “Blocking Property of Certain Persons Contributing to the Situation in Ukraine,” No 13660 dated 6 March, 2014 and No 13661 as of 19 March 2014 “Blocking Property of Additional Persons Contributing to the Situation in Ukraine,” Section 1, 19 December 2014. As a result of blocking sanctions, all property and interests of designated persons which are within (or may come into) the possession and control of any US individual or entity (which extends to a foreign branch of a US entity) are blocked, and an entry into the US of designated persons is suspended.
[3]Directive 4 under Executive Order 13662 of the Office of Foreign Assets Control as of 12 September 2014.
[4]The Council of the European Union, giving force to its Decision 2014/145/CFSP authorizing travel restrictions and the freezing of funds and economic resources of certain individuals believed to have been responsible for actions “which undermine or threaten the territorial integrity, sovereignty and independence of Ukraine“ (“designated individuals”), adopted Council Regulation (EU) No. 269/2014 of 17 March 2014.
[5]US and EU embargo Crimea, and US adopts new Ukraine sanctions law, 29 December 2014.
[6]The second phase of sanctions relief is eight years after “Adoption Day,” defined as 18 October 2015. See http://www.state.gov/secretary/remarks/2015/10/248311.htm
[7]Executive Order of the President of the US on “Blocking the Property and Suspending Entry Into the United States of Certain Persons With Respect to Grave Human Rights Abuses by the Governments of Iran and Syria via Information Technology” No. 13606 dated 22 April 2012.
[8]https://www.treasury.gov/resource-center/sanctions/OFAC-Enforcement/Pages/20161007_33.aspx
[9]Iran Freedom and Counter-Proliferation Act as of 2012, Section 1244(c)(1),(d).
[10]President Obama directs key US agencies to prepare for sanctions waivers under the JCPOA, 21 October 2015 and The Joint Comprehensive Plan of Action: A First Look, 17 July 2015.
[11]In the second step, on Transition Day, the EU will seek to terminate the sanctions suspended in the first step and terminate EU proliferation-related sanctions. As such, EU proliferation-related sanctions, among some other measures, will remain in place for eight years after Implementation Day.
[12]Special thanks to former Managing Associate of Dentons US LLP, Mr. Kenyon Weaver, for his contribution to this article.
Sanctions in Energy: Russia and Iran