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Iran Issues Pre-qualification for Upstream Tenders

Iran is said to be targeting an increase in oil production from 3.85 to 4 million barrels per day by the end of 2016. Iran is also hoping to start export of a new heavy oil, called West Karun, and which is expected to compete with Iraq’s Basra Heavy crude, which has gained a significant market with US and Asian refiners since its launch in 2015.

Iran’s new upstream contract, the Iran Petroleum Contract (IPC), was delayed by parliamentary amendments but is now scheduled for launch in January 2017. The State-owned National Iranian Oil Company (NIOC) has already signed up an IPC with local firm, Persia Oil and Gas Development Company, which is one of eight Iranian contractors authorised to team up with international joint venture partners. Whilst Iran’s production costs may be rock bottom, foreign investment (and currently foreign exchange) is needed to deliver scale and speed of development.

NIOC (on behalf of Iran’s Ministry of Petroleum) has published its “Pre-qualification Questionnaire for Exploration and Production Oil and Gas Companies,” to be completed by 19.11.16 in order for NIOC to publish a “Long List” of qualified applicants on 7.12.16. This list is intended to be valid for two years as a pre-requisite for participating in upstream tenders. NIOC intends to then invite a short-list of qualified applicants from the long list, depending on project type (Short List).

Long List applicants will be scored according to typical technical and financial criteria but with some additional emphasis seemingly echoing NIOC’s objectives, including “scale” and “internationality”. The greatest score (25%) is allocated under the heading “Reliability” to credit ratings. Whilst it seems unusual to delegate financial capability diligence simply to reliance on a third party credit rating agencies, it does reduce the internal resources needed to sift financial data. That said, a number of those with credit ratings (and by definition, public equity or debt) may not yet have the appetite for Iranian investments, whilst those privately funded entrepreneurs and companies with strong balance sheets, may not seemingly participate, assuming that NIOC doesn’t choose to deal with non-compliant applicants.

“Scale” is assessed in terms of production rates and wells drilled over the last three years, with technical capability assessed over the same period and broken down into experience type including conventional and fractured operations, and improved and enhanced oil recovery. Choosing the last three years of oil pricing where some operations may be moth-balled etc. may be significant, but given that it is unclear as to how applicants may be assessed competitively, this is perhaps academic, provided a minimum threshold is demonstrated.

“Internationality” is judged against an “applicant’s headquarters’ business and/or registration place” which is seemingly designed to allow some flexibility to avoid being disadvantaged by a tax headquarters and otherwise to make the best of an organisation’s international operations, and possibly from more than one headquarters, if one takes a literal interpretation of the punctuation.

For the purposes of the Short List, applicants are “requested” to specify their “priorities and interested fields” and whether they wish to act as operator or non-operator. This clearly allows room for judgement versus competitors as to whether applicants would wish to share their commercial position at the outset.

It seems likely that most of the credit-rated applicants who would qualify, are already known to NIOC / have registered their interest more or less formerly. The collation of extra data should enable NIOC to take into account preferences, but to grade applicants and to allocate tender opportunities in a manner perceived as transparent and which tends to avoid the dominance of any particular constituencies. Whilst the application of such process could be regarded as a short-term disincentive to some with an incumbent position, it could also be used to justify the favouring of incumbents, safe in the knowledge that the market was tested first. Otherwise, such process is likely to be regarded more generally as a welcome codification of what is expected to be a hotly-contested new market for lower cost developments.

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Iran Issues Pre-qualification for Upstream Tenders

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


  • September 27, 2016 – In connection with a state visit to China by Canadian Prime Minister Justin Trudeau, Sinoenergy Corporation Ltd. announced its intention to support the operations of Long Run Exploration Ltd. by the injection of an additional CDN$500 million in investment over the next two years
  • September 23, 2016 – Goldman, Sachs & Co. acquired 14.79 million common shares of Prairie Provident Resources Inc. in connection with the business combination of Lone Pine Resources Canada Ltd. and Arsenal Energy Inc. to form Prairie Provident. GS&Co now beneficially owns, controls and directs more than 10 per cent of the outstanding common shares of the amalgamated company.
  • September 20, 2016 – Encana Corporation announced a public offering of 107 million common shares at a price of US$9.35 per share, for gross proceeds of US$1 billion. Encana intends to use roughly half of the net to fund a portion of its 2017 capital program. The majority of this capital program is expected to be allocated to growing Encana’s Permian production.
  • September 20, 2016 – InPlay Oil Corp. and Anderson Energy Inc. announced an agreement to combine to create a new, Cardium-focused producer. InPlay also announced an agreement to acquire Cardium light oil assets in the Pembina region of Alberta from Bellatrix Exploration Ltd. for total consideration of $47 million, made up of $42 million cash, and 16.67 million shares of InPlay having a deemed value of $5 million (30 cents per share).
  • September 12, 2016 – Imperial Oil Limited announced that it will be seeking a buyer for its interest in the Norman Wells Oil Field in the Northwest Territories, though a definitive decision to sell the assets has not been made.
  • September 9, 2016 – Suncor Energy Inc. announced that it will issue an aggregate of $1 billion of senior unsecured Series 5 medium term notes. The offering will be conducted in two tranches consisting of $700 million of senior unsecured Series 5 medium term notes maturing on Sept. 14, 2026, and $300 million of senior unsecured Series 5 medium term notes maturing on Sept. 13, 2046.
  • September 9, 2016 – Crescent Point Energy Corp. entered into an agreement, on a bought deal basis, to sell 33.7 million common shares at $19.30 per share to raise gross proceeds of approximately CDN$650 million. Crescent Point increased its fourth quarter capital budget by $150 million, resulting in budgeted annual capital expenditures of $1.1 billion for 2016.


  • September 27, 2016 – the Government of Canada announced its approval, subject to conditions, of Progress Energy’s Pacific North West LNG project. The announcement was made at an evening press conference held in Richmond, British Columbia by federal Ministers Catherine McKenna (Environment), Jim Carr (Natural Resources), and Dominic LeBlanc (Fisheries, Oceans and the Canadian Coast Guard). PETRONAS, the parent company of Progress Energy, subsequently announced that it will be reviewing the project internally in light of the conditions to approval imposed by the federal government and prevailing market conditions.
  • September 19, 2016 – Seven Generations Energy Ltd. announced that it had entered into a development agreement with Steelhead LNG to explore infrastructure development and open new overseas markets for Canadian natural gas. 7G also acquired a minority ownership interest in Steelhead LNG.
  • September 16, 2016 – The Alberta government approved three new oilsands proposals: (a) the Blackpearl Resources Inc. Blackrod SAGD development; (b) the Surmont Energy Ltd. Wildwood oilsands SAGD development; and (c) the Husky Energy Inc. Saleski oilsands development. Collectively these projects represent about $4 billion of potential investment into Alberta’s economy and about 95,000 bbls per day of production.


  • September 29, 2016 –Enbridge Inc. announced an agreement for the sale of liquids pipelines assets in the South Prairie Region to Tundra Energy Marketing Limited for $1.075 billion in cash. Closing of the transaction is expected to close in the fourth quarter of 2016.
  • September 26, 2016 – TransCanada Corporation announced that its wholly-owned subsidiary, Columbia Pipeline Group, Inc. has offered to acquire, for cash, all of the 53.84 million outstanding common units of the master limited partnership, Columbia Pipeline Partners, LP at a price of US$15.75 per common unit (aggregate US$848 million). This represents an 11.3 per cent premium to the 30-day average closing price on September 23, 2016.
  • September 7, 2016 – Veresen Inc. announced that Veresen Midstream secured CDN$650 million of new credit facilities, which will be primarily used to fund Veresen Midstream’s contracted capital projects under construction, including the Sunrise, Tower and Saturn processing facilities.
  • September 6, 2016 – Enbridge Inc. and Spectra Energy Corp. entered into a definitive merger agreement under which Enbridge and Spectra Energy will combine in a stock-for-stock merger transaction, which values Spectra Energy common stock at approximately CDN$37 billion (US$28 billion), based on the closing price of Enbridge’s common shares on September 2, 2016. The combination will create the largest midstream energy company in North America and one of the largest globally based on a pro-forma enterprise value of approximately CDN$165 billion (US$127 billion). The transaction was unanimously approved by the boards of directors of both companies and is expected to close in the first quarter of 2017, subject to shareholder and certain regulatory approvals, and other customary conditions.
  • September 2, 2016 – Enbridge Inc. announced that its affiliate, Enbridge Energy Partners, L.P. (EEP), will defer its US$2.6 billion Sandpiper project in the Bakken and withdraw associated regulatory applications currently before the Minnesota Public Utilities Commission. EEP decided that the project should be delayed until crude oil production in North Dakota recovers sufficiently to support development of new pipeline capacity.

Alternative / Green

  • September 20, 2016 – In connection with Alberta’s Climate Leadership Plan, the provincial government announced the appointment of a task force to provide recommendations on government investment into “climate technology.” The appointees are: Gordon Lambert, chair; W.L. (Vic) Adamowicz; Shelly Vermillion; Suzanne West and Sara Hastings-Simon.
  • September 19, 2016 – Canadian Environment Minister Catherine McKenna announced that Canada will impose a carbon price on provinces that do not adequately regulate emissions by themselves. Details of this new carbon price and how it will be implemented have not yet been announced.
Significant Developments in Canadian Energy – For the Month of September 2016

Aviation emissions – new global deal looks likely

Government officials are negotiating a market-based mechanism to reduce emissions in the international aviation industry. Ministers from over 190 countries have gathered at the International Civil Aviation Organization’s General Assembly in Montreal to discuss and vote on a draft resolution. If passed, it will be the first industry-specific global market-based measure for CO2 emissions.
The prospects of achieving resolution are good. So far, 55 countries, including the US, China and EU member states have indicated their support for the proposal and agreed to sign-up for the initial voluntary stage. However, some states with large aviation emissions have yet to confirm their agreement and the EU has questioned how effective the measure will be in combatting climate change. A deal is expected by the end of the Assembly on 7 October.
The proposal aims to prevent the growth of aviation emissions beyond 2020 levels by requiring airlines to offset emissions with carbon credits. The mechanism would take effect on a voluntary basis from 2021, and become mandatory in 2027 with exceptions for some states which are less developed or have low aviation emissions. The offsetting obligations will be based on the sector average emission growth, and later move to incorporate the actual emission growth of individual airlines.

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Aviation emissions – new global deal looks likely

Polish Green Certificates Held by the Commission to Be Compatible State Aid: a Curious Story Comes to an End

On 2 August 2016, the Commission issued its long-awaited and precedent-setting decision in a case involving Polish green certificates issued to producers of energy from renewable energy sources (RES), following complaints filed as from 2013 in respect of co-firing and hydropower technologies. The Commission concluded its proceedings, extended since then into all RES technologies, at the preliminary examination stage, deciding that the green certificates did involve State aid. However, the Commission held that that aid was compatible with the internal market and decided not to raise objections.

The programme reviewed by the Commission was essentially based on certificates, shaped by the national legislation to be tradable in the market. They were issued to energy producers in respect of the RES energy they generated. Polish laws also required certain businesses to acquire these certificates up to certain levels (quotas), or instead pay a penalty fee, generally used by the authorities to fund other environmental investments. Only one other benefit was offered to the RES producers – selected utilities had the public duty to offtake RES-generated electricity at an average wholesale market price calculated and published annually by the National Regulatory Authority, while RES producers were free to sell their electricity to purchasers of their choice. In particular, no feed-in tariff or guarantee of the green certificates price was provided.

As long as the penalty fee, fixed by the authorities, was in excess of the green certificates price, the committed entities tended to acquire the certificates providing the RES energy producers with cash flow to supplement the proceeds from RES sales and to assure the bankability of RES projects. The support scheme did not discriminate between RES producers; intensity of support measured in certificates issued per MWh of generated RES electricity was exactly the same for any eligible technology. However, due to the open nature of the certificate system, over time the supply of certificates exceeded statutory quotas and the market for green certificates proved to be volatile. In the absence of any specific intervention from the government, prices declined over time, leading to levels currently considered by RES producers to be unsatisfactory, if not unsustainable.

Under these circumstances the Commission’s decision is of obvious importance for the Polish energy market, which had been awaiting the Commission’s conclusions on the case with some concern. Admittedly, it had been common to believe (for various reasons ranging from technical arguments to policy considerations) that the Commission’s decision would eventually be positive. However, the lack of a formal act terminating the Commission’s proceedings did appear as an impediment and, in particular, had tangible detrimental effects on various transactions involving Polish energy assets. It also added to a variety of other measures, regulatory or financial, recently implemented by the Polish authorities and perceived by part of the RES industry as having a telling harmful impact on their projects.

However, the Commission’s decision is interesting for a number of other reasons, which will only be outlined below.

The protection of legitimate expectations is obviously one of the fundamental principles of the EU legal order and, as such, it has also been held as immensely relevant to State aid matters. In particular, the EU courts made it clear that an unexpected turn in the Commission’s approach towards a particular State aid issue, going against a sufficiently clear and unambiguous line of earlier decisions, cannot result in the recovery of aid from the beneficiaries. As the Commission’s track record indicates (see for instance the Commission’s decision of 2 August 2004 in State Aid implemented by France for France Télécom) in manifest cases the Commission itself has been as reasonable as to rule, where it experienced such a radical change of mood, that its new approach would not apply to the detriment of beneficiaries in receipt of aid previously granted.

Poland introduced its green certificates system without a prior notification in 2005, whereas in the preceding years the Commission explicitly held various similar aid programmes not to qualify as State aid at all. The Commission made it clear inter alia in the decision on the green certificates granted in the UK (N 504/2000 – United Kingdom – Renewables Obligation and Capital Grants for Renewable Technologies), Belgium (N 14/2002 – Belgique – Régime fédéral belge de soutien aux énergies renouvelables) or Sweden (N 789/2002 – Sweden – Green certificates). In addition, outside the formal procedures the Commission officials also provided certain parties from other Member States, upon their request, with comfort letters reiterating that no aid would be found in case of the green certificates available in their respective jurisdictions. The Commission’s approach was largely inspired by the PreussenElektra judgement, although the latter concerned feed-in tariffs and not green certificates. However, that ruling indeed suggested that the award to RES producers, through national legislation, of the option to sell their output to mandatory purchasers does not engage any public funds and, consequently, does not constitute State aid either.

One could observe that over time, and in light of new matters submitted to the Commission’s appraisal (such as the emission allowances), the Commission became uncertain whether its earlier approach towards the green certificates was truly valid. Case law evolved likewise, including through cases such as Essent Netwerk Noord and Others (C-206/06), decided upon on 17 July 2008 by the Court of Justice of the European Union. The judges made a distinction from the PreussenElektra case in ruling that the mere fact of a publicly owned company being charged under national law with collection of funds and subsequently with the disbursement of payments from these funds to certain energy producers allowed for the imputation of these funds as originating from the State.

The Commission’s deliberation process meandered into the decision of 13 July 2011 in the Romanian green certificates case (State aid SA. 33134 2011/N – RO – Green certificates for promoting electricity from renewable sources). The decision is quite curious in that that the Commission discussed in more detail the arguments for both the existence and non-existence of aid in the green certificates systems, but eventually refrained from taking “a definitive position as to the existence of aid”. For the avoidance of doubt, the Commission made these comments despite there being no prior amendment in the Commission’s environmental guidelines, not to mention EU laws that would alter the assessment of the State aid implications in green certificates. In any event, the Commission eventually approved the Romanian green certificates system based on the compatibility of the (potential) aid with the internal market. However, taking into account the rather vague and discursive wording of this decision, as well as the apparent absence of any subsequent decisions dealing specifically with green certificates outside Romania, one might wonder whether the Commission’s decision in the Romanian case could indeed be taken as constitutive of a definite change in the Commission’s practice. The Commission was yet to strike the final chord in the green certificates crescendo.

Under these circumstances the Polish authorities were rather discontented to learn of complaints claiming the Polish green certificates to qualify as State aid (incompatible with the internal market due to the alleged overcompensation inherent in the scheme at hand) and even more of the Commission’s view confirming that the scheme may indeed involve State aid. In that regard the Commission did not seem receptive to any arguments based on its earlier practice and proved determined to rule on the compatibility of the programme despite any such concerns. Also the breakthrough judgment of the Court of Justice in Vent De Colère and Others (C-262/12) dealing with feed-in tariffs, believed by many to undermine the PreussenElektra jurisprudence to a great extent, came to the aid of the Commission in that regard as it imposed a rather extensive notion of public resources in the context of public support schemes applied in the energy sector.

It was under these circumstances that the Polish authorities, albeit contesting the Commission’s new view on the existence of aid in green certificates systems, reasonably focused on demonstrating the compatibility of the scheme and, in any event, the Commission’s decision turned out to be positive. Still, in the event of the Commission taking a negative decision in the Polish RES case, one could expect the rather plausible allegations of the Polish authorities (or of private claimants) of a breach of the legitimate expectations inferred from the Commission’s earlier decisional practice.

The Commission’s positive decision is currently rather unlikely to be challenged as far as the existence of aid is concerned and may thus be expected to stand out as a milestone in the Commission’s State aid practice in the field of energy. Therefore, most likely, we would not have the opportunity to see whether the legitimate expectations defence would be raised in litigation before EU courts and how it would be tackled by the Commission and received by the Court. The fact remains, however, that retroactive adjustment in the Commission’s practice concerning green certificates could just raise the judges’ eyebrows and warrant the annulment of the Commission’s decision. In addition, even though the decision is likely to remain uncontested in respect of the existence of aid, the legitimate protection argument could nonetheless resurface in  private enforcement cases.

On a practical note, the Commission’s decision in the Polish case seems to put an end to the debate on State aid classifications of green certificates, and it should also be taken into account in that capacity in any outstanding procedures pertaining to similar instruments (such as the Polish CHP certificates case still pending at the date of this entry). It may also impact on the identification of State aid in various instruments based on free-of-charge awards of specific benefits or entitlements – in the energy sector or well beyond it.

The article was originally published on the StateAidHub 14 September 2016 http://www.stateaidhub.eu/blogs/stateaid/post/7171

Polish Green Certificates Held by the Commission to Be Compatible State Aid: a Curious Story Comes to an End

Due Diligence For Bankable Solar PV Projects

With Gillian Goldsworthy, Melanie Blanchard and Simon Mitchell

Sharp reductions in the price of solar PV technology, dramatic technological advancement and (until recently) generous subsidies for solar PV generation have enabled developers to project reliable and attractive revenues over the lifetime of a solar PV project (up to 35 -40 years). As such, in recent years, solar PV has become an increasingly appealing proposition to funders and has gained acceptance as a “bankable” technology.

Nevertheless, irrespective of the financing structure or size of the project, there are risks associated with the development of solar PV projects on which a funder will require comfort during its due diligence process. Therefore, it is essential that the developer works closely with the funder and provides access to a comprehensive suite of documentation and information.

This article provides an overview on the legal due diligence that, from a UK perspective, is a pre-requisite to the successful development of a financeable ground-mounted solar PV project and focuses on the real estate, planning, grid connection and corporate aspects of the due diligence process.


Once a technically suitable site has been located property due diligence is required to establish whether development of the site is feasible from a legal perspective. In general, property due diligence investigations for a solar PV project will not be substantively different from those carried out for any major acquisition or pre-funding title investigation.


The first steps of a property due diligence exercise is to carry out searches at the Land Registry to ensure that all titles affecting the site are reported on. A funder will also expect local authority enquiries, an environmental search and standard utility enquiries to be raised. Highway Authority enquiries should also be conducted to ensure that the project has vehicular access to a public highway and (if there is an extended cable route) to identify where the cable crosses a highway, or is laid within it, so that it can be established whether the necessary consent has been obtained from the Highway Authority.

Some of the more interesting results of past property searches have included, unexploded ordinance, obsolete pipelines, incapacitated landowners, rights held by minors and sites subject to environmental risks such as flood risk and even nuclear contamination.

Third party rights

Ideally, the site on which the project is located should be free of encumbrances (such as the rights of utility operators to lay and operate their equipment). If encumbrances do exist, it will be necessary to ensure that the project is designed around them and that consents to the works have been obtained (if required).

If the site is affected by restrictive covenants which preclude solar PV (limitation to solely agricultural use can sometimes affect rural properties) then either a release needs be negotiated with the beneficiary of the covenant (if the beneficiary can be located), or defective title insurance must be put in place at a level which would fully compensate the project company for wasted capital costs and loss of future income arising from the project being decommissioned earlier than anticipated. The funder will also want to see that insurance is in place where a site is affected by rights to run service media in unidentified locations, or where mineral rights are excepted from the title.


The site will also need to connect (directly or indirectly) to a public highway in order to ensure the right of vehicular access. Whilst direct access is preferable, a right of way over private land would also be acceptable to a funder, provided that there are no “gaps” in title between the highway and the site. If “gaps” do exist, then a funder will require insurance to be in place.

Right to connect to grid

In most cases, solar PV projects require the right to connect to the grid. Therefore a key part of the property due diligence is to check that both the site and project company have the rights to lay a cable to the point of connection to the grid. The point of connection may be on the site, in which case no separate investigations are needed. However, it is not unusual for the point of connection to be several kilometres away from the site. An essential first step is to find out if the cable/cable works have been adopted by the distribution network operator (DNO) (adoption usually occurs after the project has been commissioned). If the cable has been adopted by the DNO then a funder would not expect further cable route due diligence (other than reviewing the adoption arrangements). However, if the cable has not been adopted then full due diligence on it would be required, with the same title investigations, searches and planning due diligence as carried out for the site itself.


The operational life of a solar PV project can range between 25 and 40 years, depending on the technology used, the underlying rights held by the project and the project’s economics. It is normal for a 25 year lease to be granted, often with an option to renew for a further period of time if the project remains operational. In addition to standard commercial lease provisions, solar leases should require the landlord to grant any necessary easements or leases to the DNO and should permit the project company to share occupation of, or grant a substation lease to a DNO. The landlord should also covenant not to do anything which would obstruct sunlight from reaching the PV panels. Full rights to lay cables and access rights should be included and repair and restoration obligations should be relatively light. A funder will also require a direct agreement from the landlord to facilitate step-in where there is a project company in default. The lease should therefore also contain an express obligation upon the landlord to enter into a direct agreement where a funder requires one.


Planning can often be a sticking point at various stages of the development of a solar PV project, as the timing of planning decisions can be as unpredictable as the decision itself. From our experience, advanced preparation, transparency and openness with the local planning authority will often ensure a smoother process to a successful and financeable project.

In respect to planning, funders will require:

  • planning permission in respect of the PV plant which is clear from the risk of judicial review;
  • planning permission in respect of the cable route works which is clear from the risk of judicial review; and
  • all relevant conditions imposed on the permissions (in particular those required to be discharged prior to commencing works on site) to have been discharged.

Any proposed amendments to the scheme as approved by the planning permission should, if possible, be kept to a minimum and, in any case, the developer should apply for and obtain the consent of the local planning authority before any amendments on-site are undertaken. If the proposed amendment is non-material, as an alternative to the amendment process established under Section 73 of the Town and Country Planning Act 1990 which is used for material changes, the developer should seek to obtain a non-material amendment (NMA) of the planning permission, as the NMA process is usually simpler and quicker than under the Section 73.

Funders will want to see evidence that no enforcement action has been taken in relation to the project, and that the project has been constructed in accordance with the approved plans and conditions imposed on the permission.

Community benefit funding is often offered to community bodies to allow a share of benefits from the projects within the community. All offers should be charitable, open and transparent and in compliance with the applicable anti-bribery legislation (Bribery Act 2010). This is often evidenced by the local/parish council reporting all offers and payments made to their public meetings. One-off payments are, of course, easier for a developer to manage, but more often annual payments are agreed, whereby yearly payments for the life of the project are paid to the community body.  A funder will want to review these arrangements carefully to ensure that all arrangements are compliant with the Bribery Act 2010.

Grid connection

The basic aim of a solar PV project is to generate electricity in order to generate revenues from the sale of such electricity (in addition to any subsidies available for generation). Therefore, the ability to export electricity from the project to the power purchaser is crucial to the viability of the project.

The majority of solar PV projects are connected to the grid via an electricity distribution network operated by a DNO. The two key contracts between the project company and the DNO, which together govern the establishment and on-going connection to the DNO’s electricity distribution network, are the connection offer and, following connection of the project to the grid, the connection agreement.

Connection Offer

The main document relating to the establishment of the connection of the solar plant to the grid is the connection offer. Pursuant to Sections 16 and 17 of the Electricity Act 1989 (Act), DNOs are obliged to make an offer of connection to a “premises” (which includes a PV plant) when requested to do so by the “owner, occupier or a party acting on their behalf” (which includes a developer of a solar PV project).

Each connection offer will include information in relation to the connection including:

  • The export/import capacity offered.
  • The location of the point of connection.
  • A list of connection works which the DNO is obliged to carry out itself (known as non-contestable works).
  • A list of connection works that the DNO would be willing (but is not obliged) to carry out (known as contestable works). (The developer is free to arrange for an Independent Connection Provider to carry out these contestable works).
  • The cost of connection works.
  • The estimated connection date of the project.
  • Any assumptions that the connection offer is based on, including meeting certain construction milestones and obtaining all necessary third party consents within specified timeframes.

When reviewing the connection offer, the funder will require comfort on issues such as:

  • Whether the connection offer has been validly accepted within the required timeframe.
  • Whether the export/import capacity is sufficient for the project’s planned generation output.
  • Whether all of the connection costs due under the connection offer have been paid.
  • Whether the estimated date of connection is compatible with the project’s eligibility for accreditation under a particular subsidy regime and the revenue impact of missing the estimated date. This is a key issue, particularly in light of the recent significant curtailing of government support available under both the Renewable Obligation and Feed-in Tariff regimes. In such an environment, developers require expert regulatory support in order to navigate an ever-changing legal framework and to assess their eligibility for certain “grace periods”, which may allow the project to benefit from subsidy support after the subsidy has been formally closed.
  • What are the circumstances in which the DNO may unilaterally terminate the connection offer.
  • Are there any other bespoke or onerous features of the connection offer, including the offer being interactive with other connection offers, constraints in the distribution network, the requirement for the DNO to apply for Statement of Works with National Grid, or the obligation for the project company to provide security to the DNO?

Connection Agreement

Once a solar PV project has been commissioned (and thus connected to the grid), the connection offer largely falls away and is superseded by the connection agreement which governs the rights and obligations of the on-going grid connection. The connection agreement will usually incorporate the National Terms of Connection which are the standard terms and conditions setting out the basis on which the DNO will maintain the grid connection. Given the standard form nature of this document, the connection agreement will not generally be the subject of negotiation. However, the funder will be concerned to ensure that the connection agreement is in place for the duration of the financing and, in certain circumstances, will require the DNO to enter into a direct agreement in respect of the connection agreement or to take security over the connection agreement (which will require the consent of the DNO). Any departures from the National Terms of Connection will need to be explained and justified to the funder.


The project company will be party to the lease, connection offer, connection agreement and other project documents (such as a power purchase agreement (PPA) and an Engineering, Procurement, and Construction contract (EPC)). It is also the entity to which the funder will lend (either directly or indirectly via a parent company). Therefore, the ownership, constitution and liabilities of the project company are of key concern to the funder. The principal areas of interest to the funder are:

  • Ownership of the project company’s share capital within the borrower group.
  • Encumbrances over the project company’s share capital (which may need to be removed as pre-condition to financing).
  • Encumbrances over the project company’s business and assets (which may need to be removed as a pre-condition to financing or financing).
  • Inter-company debt owed by the project company’s to the borrower group (which may need to be subordinated to the financing or financing debt).
  • The articles of association of the project company (which may need to be amended to remove any restriction on registration of transfer of shares on an enforcement of security, if the lender is take security over the project company’s share capital).
  • To ascertain if the project company’s has any liabilities (or assets) other than in connection with its solar project.
  • In addition, if there is to be a reorganisation of the project company’s share capital or an intra-group transfer of the project company in connection with the financing, corporate due diligence will cover a review of the relevant documentation and advise on the reorganisation.


This article has provided an overview of the real estate, planning, grid connection and corporate due diligence that funders will require. Legal advisors with experience in finding solutions to the issues unearthed by due diligence and who are able to anticipate funders’ requirements as well as to address their concerns are an integral part of the efficient development of a “bankable” solar PV project. It is important to note that the due diligence described in the article forms only part of the overall legal input, which will include the negotiation of “bankable” project contracts such as the PPA and EPC and advice in relation to the funder’s loan documentation.

Due Diligence For Bankable Solar PV Projects

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


  • August 2, 2016 – Quattro Exploration and Production Ltd. has signed a letter of intent for the sale of certain oil and gas production facilities and lands in Western Canada to an Alberta-based oil and gas exploration and production company. The aggregate purchase price for the acquisition is $24.25 million including cash payments totalling $8 million, the issuance of four million class A common shares at a price of $0.05 per common share, representing a minimum 12.5% of the seller’s common shares outstanding at closing and the assumption of estimated decommissioning liabilities totaling $12.25 million.
  • August 2, 2016 – Canadian Energy Services & Technology Corp. has completed the acquisition of all of the production and specialty chemical business assets of Catalyst Oilfield Services, LLC.
  • August 2, 2016 – Williams and Williams Partners are expected to finalize the agreement on the sale of their Canadian business during the third quarter of 2016, with expected combined proceeds in excess of $1 billion. Williams Partners’ share will be in excess of $800 million and will help reduce the need for external capital-funding.
  • August 5, 2016 – GMP Capital Inc. has agreed to acquire FirstEnergy Capital Corp. Under the definitive purchase agreement, GMP will acquire FirstEnergy for total consideration on closing of $98.6 million, consisting of approximately $58.9 million in restricted GMP common shares, with the remainder being paid by GMP through the issuance of an unsecured promissory note.
  • August 10, 2016 – Keyera Corp. has acquired an additional 35% ownership interest from Bellatrix Exploration Ltd. in the O’Chiese Nees-Ohpawganu’ck gas plant and the associated gathering pipelines. Total consideration for the acquisition was $112.5 million, which included the additional working interest in the facilities, a 10-year take-or-pay commitment, an area dedication agreement and a prepayment of 35% of the estimated future construction costs of Phase 2 of Alder Flats.
  • August 15, 2016 – Tidewater Midstream and Infrastructure Ltd. has entered into a take or pay agreement with a new customer, for approximately all of the current spare capacity at the Brazeau River Complex on a two-year basis beginning in Q4 2016.
  • August 15, 2016 – Tidewater Midstream and Infrastructure Ltd. entered into an agreement to acquire a 100% working interest in a 33 mmcf per day sour, deep-cut gas processing facility, 250 kilometres of related pipelines and 600 acres of heavy industrial land at west Edmonton for total cash consideration of $11 million, which includes a five-to-ten year take or pay agreement with the related upstream production.
  • August 17, 2016 – Enerflex Ltd. has entered into an agreement, on a bought deal basis, with a syndicate of underwriters led by Scotiabank and TD Securities Inc., pursuant to which the underwriters have agreed to purchase 7.79 million common shares of Enerflex at a price of $12.85 per common share for gross proceeds of approximately $100 million. The company has granted the underwriters an option to purchase up to an additional 1.17 million common shares at the same price and on the same terms as the offering, exercisable in whole or in part at any time up until the date which is 30 days following the closing of the offering. If the over-allotment option is exercised in full the total gross aggregate proceeds will be approximately $115 million.
  • August 18, 2016 – Seven Generations Energy Ltd. closed its acquisition of Montney natural gas assets from Paramount Resources Ltd. for approximately $1.9 billion in total consideration consisting of cash, Seven Generations shares and the assumption of a portion of Paramount’s debt.
  • August 19, 2016 – Perisson Petroleum Corporation has completed the final stage of the closing process related to the purchase of the Twining assets by completing the final statement of adjustments related to the purchase.
  • August 24, 2016 – Horizon North Logistics Inc. has completed the acquisition of Empire Camp Equipment Ltd. which provides camp and well site buildings for the Energy, Mining & Construction sectors.
  • August 25, 2016 – Ikkuma Resources Corp. has completed a strategic acquisition of certain Foothills natural gas assets for $2.7 million.
  • August 26, 2016 – Altura Energy Inc. has entered into an agreement to purchase high-quality oil assets located in east-central Alberta. The acquisition is expected to close on September 21, 2016 for cash consideration of $4 million, subject to closing adjustments.


  • August 3, 3016 – Bear Paw Pipeline Corporation Inc., an indirect wholly owned subsidiary of Liquefied Natural Gas Limited received approval from the Nova Scotia Utility and Review Board to construct a 62.5 kilometre natural gas pipeline from Goldboro to the proposed Bear Head LNG export facility in Point Tupper, Richmond County, Nova Scotia.
  • August 8, 2016 – Inter Pipeline Ltd. has entered into an agreement to acquire the shares of the Williams Companies Inc.’s and Williams Partners L.P.’s Canadian natural gas liquids midstream businesses for cash consideration of $1.35 billion, subject to closing adjustments. The transaction is expected to close in the third quarter of 2016 and is subject to approval under the Competition Act.
Significant Developments in Canadian Energy – For the Month of August 2016

Successful procurement challenge against the Nuclear Decommissioning Authority

On 29 July the High Court handed down its judgment in the high-profile Energy Solutions (ES) v Nuclear Decommissioning Authority (NDA) case.  The case concerned the competition to become the “Parent Body Organisation” (PBO) for 12 sites operating “Magnox” nuclear power stations, together with two other sites.  The PBO would become the regulated site licence company responsible for the decontamination and decommissioning of the various sites.

As one would expect, the procurement process involved the evaluation of highly technical submissions and involved very substantial amounts of public money: the total budget for decommissioning work during the initial even years of the contract was £4.211 billion.

ES bid with Bechtel in a consortium named Reactor Site Solutions (RSS) and was unsuccessful.  The contract was awarded to Cavendish Fluor Partnership (CFP) following a bid evaluation which showed a narrow winning margin of 1.06 percentage points in favour of the CFP bid.  ES challenged the outcome of the evaluation, seeking damages from the NDA (Bechtel did not challenge the award process).

ES spent approximately £10 million preparing the tender for the competition and expected to receive approximately £100 million in fees for its role in managing the delivery of the decommissioning work. Although damages are not addressed in the judgment, these figures give a rough idea of the potential value of ES’s claim.

The judgment runs to over 300 pages. In this blog post we can only draw attention to a small number of the interesting points that the case raises.

Legal issues

The key issues the court had to decide can be summarised as being:

  1. If properly evaluated, should the RSS bid have received a different or higher mark than that awarded by the NDA evaluation?
  2. Should CFP have been excluded from the procurement on the grounds of being non-compliant?  If not, and if properly evaluated, should the CFP bid have received a different or lower mark than that awarded by the NDA evaluation?
  3. What was the impact of information that witnesses providing evidence in support of  ES’s claim were offered “win bonuses” to be paid if  the claim was successful?

Scoring of the RSS bid

In considering the first issue, the judge set out some very useful guidance on the standard expected of authorities carrying out evaluations, fleshing out the idea that the courts will intervene where there has been a “manifest error” in the assessment of the bid.

The judgment also gives useful clarification on the role of the debrief documentation in the context of providing reasons. The judgment sets out that the reasons provided in the debrief documentation will be the actual basis for assessment as to whether there has been a manifest error.  The defendant authority will not be able to argue that, for different reasons other than those given as part of the debrief (which may come to light later), the scores were in fact correct.  The test of manifest error will be applied to those reasons given in the debrief documentation.  However, the information which may come to light later may be used by the defendant authority to make arguments relating to “causation” – that is to say, such information may very well be relevant to what the score should have been.  For example if a manifest error is revealed in the debrief documentation, this would amount to a breach of the procurement rules.  However, the defendant authority may well be able to argue that, had the evaluation been carried out properly taking account of factors which weren’t revealed in the debrief document, the score would not be changed and the claimant would not have suffered a loss.

The court also looked at the elements of manifest error. In determining whether there was an error the judge ruled that regard should be had to three factors: (1) the criteria for the award of the score; (2) the reasons; and (3) the score itself.  To avoid being in error, all of the elements need to “agree”.  It is not sufficient that the score determined at the end of the process is correct: there could still be manifest error if the reasoning does not support the final score awarded.  It would then be a question of causation as to whether the breach actually impacted on the outcome of the competition.

The court went on to apply these tests in relation to a large number of ES’s disputed scored responses, and found that there had been manifest errors in the scoring.  In the absence of these errors, ES would have been awarded a higher score.

Scoring the CFP bid

The court then conducted a similar exercise in relation to the CFP bid, and found that it had been scored too generously.  Much of the detail in relation to this aspect of the judgment is set out in a confidential annex, as it concerns commercially sensitive information.

One interesting aspect of the judgment is the hard line the judge takes in relation to the application of the so-called “threshold issues”.  These concerned the scoring of a number of questions which required a bidder to receive a score above a certain level for specific requirements in order to be deemed to have “passed”.  Bids which failed to meet the threshold were required under to be excluded under the tender rules.

The judge considered in what circumstances it may be permissible for an authority to waive a requirement to disqualify a tender which did not reach a threshold.  The conclusion reached offers little scope for flexibility.  He found that the doctrine of “proportionality” would only rarely be of assistance, and (unsurprisingly) did not allow an authority to alter scores in a way which avoided the threshold being breached.  In circumstances where the requirement to act transparently (following the terms set out in the tender documentation) and the requirement to act in a proportional manner come into conflict, transparency has primacy.  The judgment also considers other factors which may be taken into account when determining whether the proper course of action is to exclude a bidder.  The clear guidance provided by the judgment in this area will be useful to awarding authorities, even if the relatively strict approach underlying it may not always be entirely welcomed by them.

Win bonuses for witnesses (!)

ES made a shock revelation just before the judgment was due to be heard.  It had come to light that a number of their witnesses were to be given a bonus in the event that the claim was successful.  In one case the bonus was £100,000 plus 0.5% of any damages awarded.

This payment for the provision of witness evidence contravenes long-standing rules that prohibit such practices.  (On the other hand, recompense for time spent by consultants is permitted “provided the rate is reasonable and represents the witness’s loss of earnings”.)

So how did the judge address this revelation at such a late stage in proceedings?  The answer is “pragmatically”.  Although the defence sought an order that the case be dismissed entirely or reheard, he refused those requests.  Instead he assessed the degree of dishonesty involved in the agreements (deciding that there was none) and determined that it would be wholly disproportionate to grant either of the remedies requested.  For good measure, he also stated that even if the evidence was to be disregarded entirely (which he did not think was necessary) the same outcome would have been reached on the basis of the documentary evidence and the evidence provided by the NDA witnesses.

Concluding comments

This is a highly significant judgment for those involved in public procurement and will be a timely reminder to awarding authorities about the need for providing well-founded reasons for scores in debrief documents.

The astounding detail in the judgment and quality of the reasoning means that the half-life of the precedents set by the judgment may be long (if it survives any possible appeal).  However, given the significance of the damages claimed, and the contentiousness of some of the issues, it is quite possible that the NDA will not let matters rest where they are.  Some indication of their fighting spirit is given by the fact that litigation on a preliminary issue (concerning to the lawfulness of seeking damages but not the prevention of the award of the contract) was, at the point at which the judgment was published, due to be heard in the Supreme Court.




Successful procurement challenge against the Nuclear Decommissioning Authority

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


  • July 26, 2016 – TORC Oil & Gas Ltd. entered into an agreement with Zargon Oil & Gas Ltd. to acquire light oil assets in southeast Saskatchewan. The acquisition includes 1,120 boe per day (roughly 95 per cent light oil and liquids) of producing assets for total cash consideration of $89.5 million, subject to customary closing adjustments.
  • July 13, 2016 – In response to industry requests, the Alberta government announced that oil and gas producers can apply to opt in to Alberta’ new Modernized Royalty Framework for wells that otherwise would not have been drilled. This represents a change to the previously announced schedule, which had the Modernized Royalty Framework slated to take effect January 1, 2017. The stated intent of this change is to allow producers to make new investments, or decide to keep investments in Alberta. Further discussion of the Modernized Royalty Framework can be found in previous Dentons articles, available here and here.
  • July 6, 2016 – Seven Generations Energy Ltd. (7G) reached an agreement to acquire approximately 30,000 bbls of oil equivalent of daily production, 155 net sections in the Montney play having 199 million boe in proved reserves from Paramount Resources Ltd. for approximately CAD$1.9 billion in total consideration consisting of cash, 7G shares and the assumption of a portion of Paramount’s debt. This acquisition will significantly expand 7G’s ownership in the Montney Nest liquids-rich natural gas play.


  • July 18, 2016 – Husky Energy Inc. closed a transaction to create a new entity, Husky Midstream Limited Partnership, which will assume ownership of certain midstream assets in the Lloydminster region of Alberta and Saskatchewan. Husky received $1.7 billion in cash proceeds from the transaction, which will be applied to strengthening the company’s balance sheet.
  • July 15, 2016 – TransCanada Corporation announced the signing of a memorandum of understanding with four major unions and the Pipe Line Contractors Association of Canada for work on the Energy East pipeline project. The MOU provides that thousands of the skilled pipeline trade jobs required to build the project will be awarded to members of the PLCAC and the four union partners, including the United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada, Labourers International Union of North America, International Union of Operating Engineers and Teamsters Canada.
  • July 15, 2016 – Reuters, citing sources familiar with the situation, reported that Williams Cos. Inc. attracted at least seven bidders for the sale of its Canadian business unit, which could pay up to $2 billion for the acquisition.
  • July 14, 2016 – Devon Energy Corporation announced that it had entered into a definitive agreement to sell its 50 per cent interest in Access Pipeline to Wolf Midstream Inc., a portfolio company of Canada Pension Plan Investment Board, for consideration of CAD$1.4 billion

Alternative / Green

  • July 18, 2016 – Canada’s Energy minister, Catherine McKenna, announced that the Canada will implement a national price on carbon emissions by the end of this year. The federal government will publish an emissions reduction plan this fall that could include expanded, standardized emissions disclosure requirements for companies. Currently, the provinces are working on an agreement that could see the provinces implementing a mandatory carbon price. Not all provinces support this initiative, and the effect of the proposed federal provincial carbon price on existing provincial measures has yet to be determined.
Significant Developments in Canadian Energy – For the Month of July 2016

Thoughts on the death of DECC

Over the course of 13 and 14 July 2016, UK’s new Prime Minister, Theresa May, appointed the Secretaries of State who will lead the various Departments of Government.  By the end of the process, which was precipitated by the UK’s referendum vote to leave the EU, the Cabinet had gained two new Secretaries of State (for “Exiting the European Union” and “International Trade”).  At the same time, the position of Secretary of State for Energy and Climate Change had been abolished, along with the Department which its holder led (DECC).  To anyone with a professional interest in energy and climate change policy, this will likely have felt like a backward step.  If nothing else, as pointed out by Angus MacNeill, Chair of the House of Commons Energy and Climate Change Committee, it raises some important questions which will need to be answered quickly.

It is, of course, far too early to judge the new Government’s approach to any issue.  After a period of several months in which relatively little in the way of major policy emerged from DECC (no doubt partly because of pre-referendum stasis), there will be a temptation to fall on anything that the Ministers newly appointed to the Department of Business, Energy and Industrial Strategy (BEIS) say in the next few weeks for clues about the future direction of energy and climate change policy – and possibly over-interpret them.  The new regime should be judged on its record rather than its name.

In practical terms, it was probably not feasible for an incoming Prime Minister to create two new Secretary of State posts without losing at least one existing one to compensate – and the former Department for Business, Innovation and Skills has lost a significant chunk of its previous responsibilities (higher education, and, presumably, at least some of international trade), so may have needed some additional bulk.  Historically, the energy portfolio has had its own Department within Government for over 50 of the last 100 years (variously as the Ministry of Power, 1942-1969; the Department of Energy, 1974-1992; and DECC, 2008-2016).  Otherwise (apart from a very brief period in the Ministry of Technology), it has been in the Board of Trade and its successors, the Department of Trade and Industry, the Department of Business, Energy and Regulatory Reform – and now BEIS.  If one looks to international comparisons, practice varies: Germany has a Ministry of Economic Affairs and Energy; Denmark has a Ministry of Energy, Utilities and Climate; in Italy, energy is a matter for the Ministry of Economic Development.  At EU level of course, DG Energy is very much a Directorate-General in its own right: energy has been a key policy area for the EU and its precursors and it will be an important element in both Brexit negotiations and international discussions about post-Brexit trade arrangements with the EU and others.

One thing that distinguishes the new configuration from those other occasions when “energy” has not had its own UK Department, is that on this occasion it does at least feature in the name of the Department that is responsible for it.  It will undoubtedly form a significant part of BEIS’s business.  It is true that “climate change” has lost some profile, but it is also noticeable, if one looks at the DECC organogram, that very few DECC teams could be said to have had an exclusively climate change focus (in any case, when DECC was originally created, only those Defra staff working on climate change mitigation joined the new Department: those working on climate change adaptation remained behind).  Arguably one of the achievements of DECC (and the period of policy formation that immediately preceded it) was to make climate change considerations part of the mainstream of energy policy-making.  The optimistic view would be that with the Climate Change Act 2008 – and its system of carbon budgets, based on work by the independent experts of the Committee on Climate Change (CCC) – well entrenched, there is less need for the symbolism inherent in the name of DECC.  One might also add, more cynically, that there was more than one occasion when having responsibility for climate change policy did not stop DECC Ministers from choosing the “less green” option.

But on a more positive note, there are clearly potential advantages in having “business”, “energy” and “industrial strategy” in the same Department.  As the CCC’s Report on the Fifth Carbon Budget made clear, if we are to achieve the kind of reductions in carbon emissions that we need in order to meet the overall goals of the Climate Change Act, not to mention contributing a fair share to the achievement of the aims of the CoP21 Paris Agreement of December 2015, we will need to go a long way beyond the task of decarbonising the electricity generation sector (admittedly still work-in-progress though that is).  There is a lot to be done in relation to heat and transport, for example, and the challenges are formidable.  Some of this is very much to do with industrial energy use, and having one Department, rather than two, focusing on this area could well make a positive difference (given the inevitable friction that exists between all public sector bodies with shared interests).  Maybe it is even not too much to hope, in this context, that the new Government may revisit the decision to abandon large-scale sponsorship of carbon capture and storage, which is thought by many to have more to offer in a wider industrial context than it necessarily does purely in the electricity generation sector.  At the same time, a Secretary of State for BEIS (Greg Clark) who has come from the Department of Communities and Local Government may be an asset at a time when it is also becoming clear that some aspects of the development of new energy infrastructure are best considered locally, at least within cities.  And “industrial strategy” – unclear as yet though it is what this will involve – could also have a mutually beneficial intra-Departmental relationship with “energy”.  Finally, given that it is only seven years since DECC was partly carved out of one of BEIS’s predecessors, it is to be hoped that this change in the machinery of Government can be accomplished without distracting ex-DECC management too much from the policy agenda (now, of course, supplemented by Brexit).

In the post-Brexit world, nothing is necessarily what it seems.  Any or all of the above speculation may be naïve or misguided.  The new Department should be watched carefully, but today, objectively and at a policy level, it is far too early to say whether (or how much) we should mourn the passing of DECC.


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Thoughts on the death of DECC

Alberta announces new drilling incentive programs

The Government of Alberta recently announced the introduction of two new drilling incentive programs that will commence on January 1, 2017: the Enhanced Hydrocarbon Recovery Program and the Emerging Resources Program. These new programs will replace the drilling incentive programs that are currently in effect. This announcement follows from recommendations made in the Alberta’s Royalty Review Panel’s report of January 29, 2016, which recommended the implementation of a new modernized oil and gas royalty framework. Further discussion of the new drilling incentive programs, as well as background on Alberta’s new modernized oil and gas royalty framework, can be found here.

Alberta announces new drilling incentive programs