DEPARTMENT OF STATE

Public Service Commission

FINAL

3008 Rules and Procedures to Implement the Renewable Energy Portfolio Standard (Opened August 23, 2005)

FINDINGS, OPINION, AND ORDER NO. 9289

APPEARANCES:

On behalf of the Delaware Division of the Public Advocate:

DEPUTY ATTORNEY GENERAL

Regina A. Iorii, Esquire

On behalf of the Delaware Public Service Commission Staff:

DEPUTY ATTORNEY GENERAL

Thomas D. Walsh, Esquire

On behalf of the Department of Natural Resources and Environmental Control:

DEPUTY ATTORNEY GENERAL

Devera B. Scott, Esquire

On behalf of Caesar Rodney Institute:

David Stevenson

On behalf of Pro Se Intervenor Gary Myers,

Gary Myers

I. BACKGROUND.

1. In 2005 the General Assembly enacted, and the Governor signed into law, the “Renewable Energy Portfolio Standards Act,” 26 Del.C. §§351-364 (“REPSA”), mandating electric utilities to purchase a portion of their electricity from renewable sources. The General Assembly authorized the Delaware Public Service Commission (“Commission”) to administer REPSA and, in doing so, directed the Commission to adopt rules governing REPSA’s implementation. The REPSA mandate was accomplished by requiring an annually-increasing percentage of electricity sold in Delaware to be procured from Eligible Energy Resources (“EER”).1 The requirement is termed a Renewable Portfolio Standard (“RPS”). The RPS is met through procuring and retiring Renewable Energy Credits (“REC”) produced by EERs. The RPS also has a specific requirement for solar photovoltaic (“PV”) electricity production, referred to as a “solar carveout.” Solar PV resources also generate credits called Solar Renewable Energy Credits (“SREC”), in the same fashion as EERs.

2. In 2006, the Commission promulgated "Rules and Procedures to Implement the Renewable Energy Portfolio Standard" (the "RPS Rules") (Order No. 6931 dated June 6, 2006).

3. REPSA was amended in 2007,2 2010,3 and 2011.4 Relevant to this proceeding, the 2010 Cost-Cap Amendments added Sections 354(i) and (j), which state:

(i) The State Energy Coordinator5 in consultation with the Commission, may freeze the minimum cumulative solar photovoltaics requirement for regulated utilities if the Delaware Energy Office determines that the total cost of complying with this requirement during a compliance year exceeds 1% of the total retail cost of electricity for retail electricity suppliers during the same compliance year. In the event of a freeze, the minimum cumulative percentage from solar photovoltaics shall remain at the percentage for the year in which the freeze is instituted. The freeze shall be lifted upon a finding by the Coordinator, in consultation with the Commission, that the total cost of compliance can reasonably be expected to be under the 1% threshold. The total cost of compliance shall include the costs associated with any ratepayer funded state solar rebate program, SREC purchases, and solar alternative compliance payments.

(j) The State Energy Coordinator in consultation with the Commission, may freeze the minimum cumulative eligible energy resources requirement for regulated utilities if the Delaware Energy Office determines that the total cost of complying with this requirement during a compliance year exceeds 3% of the total retail cost of electricity for retail electricity suppliers during the same compliance year. In the event of a freeze, the minimum cumulative percentage from eligible energy resources shall remain at the percentage for the year in which the freeze is instituted. The freeze shall be lifted upon a finding by the Coordinator, in consultation with the Commission, that the total cost of compliance can reasonably be expected to be under the 3% threshold. The total cost of compliance shall include the costs associated with any ratepayer funded state renewable energy rebate program, REC purchases, and alternative compliance payments.

26 Del.C. §354(i), (j). (“Sections 354(i) and (j)”).

4. In September 2010, the Commission adopted and added 26 Del. Admin. C. §3008 in conformance with the Cost-Cap Amendments.6 These regulations generally mirrored the text of the Cost-Cap Amendments.

5. In April 2012, the Delaware Department of Natural Resources and Environmental Control (“DNREC”) began promulgating regulations7 to establish the process for “freezing” the RPS. The first regulations appeared in the December 2013 Register of Regulations.8 DNREC published second and third revised regulations in 2014 and 2015.9 DNREC Secretary’s Order No. 2015-EC-0047,10 dated December 15, 2015, finalized the regulations, which were memorialized in 7 Del. Admin. C. §104 and effective January 11, 2016.

6. On October 2, 2015, in Docket No. 15-1462, the Delaware Division of the Public Advocate (“DPA”) filed a Petition to open a docket and consider amending 26 Del. Admin. C. §3008-3.2.21 to issue regulations governing when a freeze of the minimum percentages may be declared. On October 12, 2015, the Caesar Rodney Institute (“CRI”) submitted a Petition supporting the DPA’s Petition (the “Joint Petition”).

7. On October 27, 2015, Commission Staff (“Staff”) and DNREC filed a Joint Motion opposing and requesting denial of the Joint Petition. On October 29, 2015, the DPA and CRI filed a joint response (“Joint Response”).

8. On November 3, 2015, the Commission heard oral argument on the Joint Petition, Joint Motion, Joint Response, and other written comments. After deliberations, the Commission entered Order No. 8807, denying the Joint Petition and closing the docket.11

9. On December 7, 2015, the DPA filed a Notice of Appeal of the Commission’s decision in Order No. 8807 with the Superior Court of the State of Delaware (the “Court”).

10. On December 30, 2016, after briefing and oral argument, the Court issued a Memorandum Opinion and Order12 reversing Order No. 8807 and remanding for proceedings consistent with its decision.

11. On February 2, 2017, the Commission adopted Order No. 9025 in Docket No. 15-1462, which: (1) re-opened Docket No. 15-1462 for the limited purpose of complying with the Opinion; (2) reversed Ordering Paragraph No. 21 of Order No. 8807, which denied the Joint Petition; and (3) directed Staff to re-open Regulation Docket 56 for the limited purpose of complying with the Opinion, specifically to promulgate regulations to amend 26 Del. Admin. C. §3008-3.2.21 and related regulations as needed to memorialize the procedures for freezing the minimum cumulative solar photovoltaic and eligible energy resource requirements under 26 Del.C. §354(i) and (j).

12. On February 2, 2017, the Commission adopted Order No. 9024, which stated “the Commission Secretary shall transmit to the Registrar of Regulations for publication on March 1, 2017 in the Delaware Register of Regulations a copy of this Order, along with copies of the proposed and current Rules.13 Order No. 9024 further stated that the Commission Secretary shall provide public notice and, pursuant to 29 Del.C. §§10115(a) and 10116, establish a public comment period through April 24, 2017.14

13. On April 6, 2017, the Commission heard public comments at its regularly-scheduled public meeting. As of April 14, 2017, 104 written public comments were received, including comments from the DPA, CRI, DNREC, and Mr. Gary Myers.

14. On July 20, 2017, Staff filed its Review and Recommendation of the public comments and recommended that the Commission publish revised regulations. On July 25, 2017, after consideration of these public comments and Staff’s recommendation, the Commission adopted Order No. 9090, which ordered the republishing of the revised regulations in the September 1, 2017 Delaware Register of Regulations and opened a comment period through October 2, 2017. Eight written public comments were received prior to the October 2, 2017 deadline, and an additional twenty-four public comments were received after the deadline.

15. On November 17, 2017, Staff published notice of the December 7, 2017 Commission hearing at which the Commission would determine whether to finalize the proposed regulations approved in Order No. 9090 or republish the substantively revised regulations.

II. SUMMARY OF THE EVIDENCE, FINDINGS OF FACT, AND CONCLUSIONS OF LAW.

16. On December 7, 2017, the Commission heard oral argument and deliberated regarding three contested issues. The first issue was which components, as among supply, transmission, and distribution, should be included in the definition of “total retail cost of electricity for retail electricity suppliers?” The second issue was whether the costs of the Qualified Fuel Cell Provider Project (“QFCPP”) energy output,15 which Delmarva is statutorily entitled to use to fulfill its REPSA obligations, should be included in the “Total Cost of Compliance?” The third issue was what discretion the “E&C Director” has to institute or forego a freeze if the statutorily mandated calculations show that the 1% and 3% statutory thresholds have been reached.

17. On January 26, 2018, the Commission issued Order No. 9016, publishing further revised draft regulations reflecting the outcome of the December deliberations and directing the Commission Secretary to transmit the proposed regulations reflecting the Commission’s December 7, 2017 deliberations to the Registrar of Regulations for publication in the February 1, 2018 issue of the Delaware Register of Regulations.16

18. The Commission received multiple written comments on the proposed regulations,17 including a letter from DNREC Secretary Garvin and a response to Secretary Garvin from the former Commission Executive Director.

19. On March 26, 2018, Staff filed a memorandum18 requesting that the Commission enter Proposed Order No. 9197 and Exhibit A thereto and approve as final the most recent draft regulations published in the February Register of Regulations.19

20. Proposed Order No. 9197 was placed on the Commission’s agenda for its March 27, 2018 meeting. At that meeting, the Commission decided to re-open its consideration of the then proposed regulations, including revisiting the voting determinations made at its December 7, 2017 deliberations. On June 5, 2018, the Commission heard and considered such further comments and arguments on the proposed regulations and the three issues identified at the December 7th meeting.20 The Commission then again voted on then-pending proposed regulations and the three central issues. The Commission's resolution of those issues are set out here in these Findings and Order. However, because those resolutions changed the then-proposed regulations substantively, the Commission republished (on July 1, 2018) new and altered proposed regulations in accordance with 29 Del.C. §10118(c).21 The July 2018 proposed rules incorporated the determinations made at the June 5, 2018 meeting. In response to these proposed rules, further comments were received from the DPA, DNREC,22 the Sierra Club, the Delaware Solar Energy Coalition, and two members of the general public. At its meeting on November 8, 2018, the Commission considered such additional comments and determined to adopt the regulations proposed in the July 1 Register Notice as the final regulations. These are the Commission's final findings, opinion, and Order to support such adoption.23

III. Total Retail Cost of Electricity for Retail Electric Suppliers.

A. Staff’s Position: “Total Retail Cost of Electricity for Retail Electricity Suppliers” Includes Supply, Transmission, and Distribution.

21. Staff argued that including supply, transmission, and distribution is the only definition which comports with the Court's directive that the Commission rely on the statute's "plain and ordinary meaning" and not "collapse… plain, and presumably intentional, statutory distinction[s]" where they may exist.24 Properly effectuating the required calculation demands that the definition accords meaning for every word in the statute. Staff explained that adherence to the statutory definitions of the individual terms within "the total retail cost of electricity for retail electricity suppliers" ("TRCE") compelled Staff's definition of TRCE to include supply, transmission, and distribution" definition.

22. Staff contended that “[r]etail electricity supplier[s]” are statutorily defined as “mean[ing] a person or entity that sells electrical energy to end-use customers in Delaware, including but not limited to nonregulated power producers, electric utility distribution companies supplying standard offer, default service, or any successor service to end-use customers.”25 The statute unambiguously confines “retail” sales as those to “end-use customers.” Further support is found in the statutory definition of “end-use customer,” which “means a person or entity in Delaware that purchases electrical energy at retail prices from a retail electricity supplier or municipal electric company.”26 The definition of “wholesale” electric sales is similarly fundamental; the Federal Power Act instructs that the “sale of electric energy at wholesale” means “a sale of electric energy to any person for resale.”27 Thus, because “retail” inextricably defines the “total costs of electricity,” the latter’s plain and ordinary meaning denotes all bottom- line costs of all electricity sold for end-use.

23. Staff then addressed the “total” cost of electricity, stating it is “axiomatic that no commodity of electricity exists without its being delivered to a point of sale.”28 As there are no “electricity stores” where customers can purchase electricity without paying associated transmission or distribution charges, there exists instead a network for electricity delivery and the properties of its use. That is, a customer’s usage of electricity from a retail electricity supplier occurs at the location of end-use connected to the transmission and distribution system. Thus, the qualifier “total” requires that all charges mandated by the supply of electricity service, including distribution and transmission charges, be included in the definition.29

24. Staff continued that the next inquiry must be identifying “who” are the “retail electricity suppliers.” Staff again relied upon the statutory definition: “entit[ies] that sell electrical energy to end-use customers in Delaware,” which include, but are not limited to, “nonregulated power producers, electric utility distribution companies supplying standard offer, default service, or any successor service to end-use customers.”30 Where the statutory definition of “Retail Electricity Supplier” states “electric utility distribution company,” distribution costs must be included in the total costs for that Retail Electric Supplier. Delmarva Power & Light Company (“Delmarva”) is the only standard offer service (“SOS”) provider to end-use customers in Delaware.31 As the exclusive electric distribution utility – and the owner and provider of the distribution network – Delmarva’s distribution service base includes every end-user of electricity in its territory. Any other entity selling electricity to end-use customers similarly, and statutorily, falls within the expansive definition.

25. Staff’s final inquiry in according meaning for every word in the statute focused on the meaning of “for” in TRCE. Staff argued that its analysis bares two potential meanings: 1) the total cost “for” electricity services incurred by the retail electricity supplier to provide service; or 2) the total cost “for” selling retail electricity to end-use customers.32 These interpretations distinguish the “total costs for” buying or providing electricity versus the “total costs for” selling electricity. The statute’s use of “retail” must be included in interpreting other language; therefore, the former meaning is precluded. To include only the utility’s costs incurred for providing electricity entertains certain “wholesale” costs in the definition. Namely, Delmarva purchases supply at wholesale, for resale to its end-use customers at retail. The Federal Power Act corroborates that this is a wholesale cost.33 Retail and wholesale transactions are distinct and mutually exclusive; in electricity, there can be many wholesale sales for resale, yet only one retail sale for end-use. If the cost of the power Delmarva purchases at wholesale is included in the definition, that definition cannot be correct. Accordingly, the statute’s plain and ordinary meaning dictates that, due to the inclusion of the word “retail,” only the total cost “for” selling retail electricity to end-use customers can provide the correct definition.34

26. Lastly, Staff emphasized that the Court’s directive not to collapse statutory distinctions provided further support of its inclusive TRCE definition. Twenty-six Del.C. §363 provides “Special Provisions for Municipal Electric Companies and … Cooperatives” for complying with the RPS requirement. Staff points to the contrast between §363(f) and (g) and Delmarva’s requirements under §354(i) and (j). Section 363(f) provides that “[t]he total cost of complying with eligible energy resources shall not exceed 3% of the total cost of the purchased power of the utility35 for any calendar year,” which language is mirrored in § 363(g). In defining the dispositive terms within Sections 354(i) and (j), Staff underscores the “presumably intentional distinction” between “purchased power” and “total retail cost of electricity.”36 The costs in § 363(f) and (g) point explicitly to the “purchased power” which equates the wholesale cost. Additionally, the adjective “total” defines not the total cost of retail electricity (as in Sections 354(i) and (j)) but the total cost only of purchased power (presumably for resale).37 Sections 363(f) and (g) therefore would preclude the cost of delivering electricity to retail customers, and the distinction between the two statutory provisions mandate that such delivery and transmission charges must be included under the instruction of the Order and the language of Sections 354(i) and (j).

B. The DPA’s Position: “Total Retail Cost of Electricity for Retail Electricity Suppliers” Includes only Supply and Transmission.

27. The DPA argued that interpreting Sections 354(i) and (j) required an understanding of what restructuring did to the electric industry. It explained that before restructuring, utilities were vertically integrated, which meant the utilities owned all of the plant used to provide electricity to customers, and billed for all of those functions in one bundle. With restructuring, however, the General Assembly unbundled the supply function from the transmission and distribution functions, and created a commodity (supply/generation) that existed separate and apart from the poles, lines and wires that transmitted and distributed that energy. This unbundling allowed the “[c]ustomers of Delaware electric distribution companies [sic] ... to have the opportunity, but not the obligation, to purchase electricity from their choice of electric suppliers ... .”38 To achieve this, the General Assembly instructed Delmarva to file a plan for implementing retail competition in its service territory, which was to include “[s]eparate prices or rates for electric supply, transmission, distribution and other service (which may later be combined for billing purposes.”39

28. The DPA argued that REPSA recognized the difference between supply and other services, and specifically limited the definitions of “retail electricity supplier” and “end-use customer” to the provision and use of supply.40 It contended that REPSA’s definitions of “end-use customer” and “retail electricity suppliers” showed that the General Assembly intended to differentiate between “electric supply” and “transmission, distribution and other services” because neither the definition of “end-use customer” nor the definition of “retail electricity supplier” includes “distribution” or “delivery.”41 The DPA argued that “’end-use customer’ means ‘a person or entity in Delaware that purchases electrical energy [that is, supply] at retail prices from a Retail Electricity Supplier. ...,”42 and “a ‘retail electric supplier’ means ‘a person or entity that sells electricity energy [that is, supply] to end-use customers in Delaware[.]’”43 The DPA noted that the General Assembly used the word “means” for these definitions, which excluded any meaning that is not stated, and which exhausted the meaning of the defined term.44 The DPA asserted that Delmarva (the electric distribution company supplying SOS) was included in the definition of “retail electricity supplier” because it sells electrical energy (SOS) to end- use customers, not because it also sells distribution and delivery services to end-use customers.”45

29. The DPA next argued that Staff’s definition of TRCE “’collapse[d] the plain, and presumably intentional, statutory distinction” between “retail electricity supplier” and “end-use customer” in concluding the TRCE must be measured by “the total cost that end-use customers pay for all of the functions of the electric utility industry.”46 The DPA explained Staff’s argument as: (1) the electricity that end-use customers buy from either Delmarva or a third- party supplier must be provided to the customer somehow; and (2) therefore, the TRCE for retail electricity suppliers necessarily includes distribution and delivery service costs.47 The DPA called this wrong as a matter of law because it did not recognize “the distinction that the General Assembly made between the cost of electricity as a commodity that can be sold by itself and the cost of how that electricity gets to end-users.”48

30. Next, the DPA stated that Staff’s parsing of separate words in the statutory phrases violated “a fundamental rule of statutory construction - that a statute's words and phrases should not be read in isolation."49 The DPA contended that “[w]hen the statute is read as a whole, the only sensible and logical conclusion is that the appropriate measure [of TRCE] is the retail price that retail electricity suppliers (which includes Delmarva as the SOS provider) charge to their customers.”50

31. Next, the DPA contended that even if Staff’s isolation of the statutory words and phrases were permissible, it still did not produce the conclusion that Staff reached, because it demonstrated a lack of understanding of what electricity restructuring did. As the DPA previously discussed, restructuring unbundled the supply function from the transmission, distribution and delivery functions, and created a competitive market for supply; thus, electricity as a product can and does exist without being delivered to a point of sale, and whether an end-user could purchase electricity from a store was irrelevant.51 The DPA attached a copy of the bill of a customer that purchased electricity supply from a third party to demonstrate that supply and distribution services are separate things that can be (and, in the attached customer’s bill case, are) provided by two different entities, and that a customer can purchase electrical energy as a commodity by itself even though they cannot physically purchase it at a store.52

32. The DPA next took issue with Staff’s contention that TRCE necessarily includes distribution and delivery costs because Delmarva is an SOS provider, is the exclusive distribution utility, and every customer is located in Delmarva’s footprint. Noting Staff’s acknowledgement that there is no competitive market for distribution and delivery service, the DPA argued that Staff’s claim that because the definition of “retail electricity supplier” includes Delmarva, the definition of TRCE must also include distribution and delivery service was both circular and legally wrong for the reasons provided previously.53

33. The DPA further argued that Staff’s explanation for the use of the word “for” in the phrase “for retail electricity suppliers” would lead to the untenable conclusion that there is only one “retail” sale – from Delmarva to the end-user. The DPA observed that this conclusion was inconsistent with Staff’s recognition that the definition of “retail electricity suppliers” encompassed non-Delmarva third-party suppliers. Additionally, this conclusion was directly contrary to the Restructuring Act, which unbundled the electric supply function from distribution and delivery functions and made it possible for end-use customers to purchase their electricity supply directly from whatever third-party suppliers offer retail electric suppliers other than Delmarva.54

34. The DPA argued against Staff’s contention that the language “total cost of purchased power” that the General Assembly used in 26 Del.C. §363 for cooperatives and municipalities demonstrated that the General Assembly meant to include transmission, distribution and delivery costs in the TRCE. First, the DPA argued that because the REPSA provided a particular meaning “retail electricity suppliers,” the Commission was bound by that definition and could not look to different language in another part of the statute to attempt to re-define it. Second, even if it were proper to look to Section 363, the different language was immaterial. The DPA claimed that it had never contended that the TRCE was simply the wholesale cost of supply; the DPA acknowledged that the TRCE also includes other costs such as the profit margin that go into that cost. Third, the DPA argued that it was not surprising that the legislature used a different term for municipalities and cooperatives because those entities are nor-for-profit entities that the Commission does not regulate. The DPA explained that municipalities use the money earned from selling electricity to provide other services to constituents (such as police and fire protection, road repair, and libraries), and the cooperative returns all profits to its member customers. For-profit retail electricity suppliers do neither of these, so it was sensible for the General Assembly to use different terminology for the different entities.55

35. The DPA next argued that if distribution was intended as a component of TRCE, the General Assembly could have omitted the phrase "for retail electricity suppliers" after "the total retail cost of electricity" because the "total retail cost of electricity" would encompass supply, distribution and delivery. Yet that phrase was included and must be given meaning;56 therefore, TRCE must be “the supply costs plus whatever else retail electricity suppliers include in the retail price they charge for electrical energy. ...”57

36. The DPA argued that including distribution costs would result in end-use customers being charged twice for the same costs. In support, the DPA stated that “the General Assembly limited the costs to be considered in Sections 354(i) and (j) to the retail cost of electricity that retail electricity suppliers charge for their product.”58 Including distribution and delivery costs that end-use customers pay results in customers paying those costs twice: once on their actual bills, and again by including those costs in the calculation of the total retail cost of electricity for retail electric suppliers.59 The DPA opposed Staff’s contention that the DPA’s definition would charge end-use customers twice for supply costs, observing that Staff was assuming that the cost of RECs and SRECs are part of the cost of supply; the DPA argued out that the cost of RECs and SRECs are separate from the cost of supply.60

37. Finally, the DPA contended that even assuming that Sections 354(i) and (j) were ambiguous, long-established rules of statutory construction supported the DPA’s proposed definition of TRCE. It pointed out that statutes must be viewed as a whole, and literal or perceived interpretations that yield mischievous or absurd results should be avoided.61 Similarly, an ambiguous statute must be construed to promote its purpose and harmonize it with other statutes within the statutory scheme.62 Lastly, a provision that may seem ambiguous in isolation is frequently clarified by the rest of the statutory scheme because the same terms are used elsewhere in a context that makes its meaning clear or because only one of the meanings produces a substantive effect compatible with the rest of the law.63 The DPA pointed out REPSA’s policy:

(b) The General Assembly finds and declares that the benefits of electricity from renewable energy resources accrue to the public at large, and that electric suppliers and consumers share an obligation to develop a minimum level of these resources in the electricity supply portfolio of the state. These benefits include improved regional and local air quality, improved public health, increased electric supply diversity, increased protection against price volatility and supply disruption, improved transmission and distribution performance, and new economic development opportunities.

(c) It is therefore the purpose and intent of the General Assembly in enacting the Renewable Energy Portfolio Standards Act to establish a market for electricity from these resources in Delaware, and to lower the cost to consumers of electricity from these resources.64

The DPA argued that the General Assembly did not establish a market for distribution and delivery resources because Delmarva has a state-granted monopoly on those services within its designated service territory.65 The DPA also identified other sections of REPSA to support its argument that the statute is concerned with electricity supply, not distribution and delivery service.66

C. DNREC’s Position: “Total Retail Cost of Electricity for Retail Electricity Suppliers” Includes Supply, Transmission, and Distribution.

38. DNREC argued in support of Staff as having properly drafted language defining TRCE in a manner consistent with REPSA and commensurate to the cost of electricity to consumers.

39. Initially, DNREC explained that defining TRCE to mean Delmarva’s wholesale supply costs is wholly inconsistent with the meaning of “retail.” Simply stated, Delmarva is not a retail customer but rather purchases electricity in wholesale markets.

40. Further, TRCE must include all of the costs on customers’ bills because electricity is not a retail product unless and until it is delivered to end-use customers. That cannot be accomplished without distribution. DNREC stated, “there is no such thing as ‘I can get it for you wholesale’ for the retail electric consumer.”67 A customer cannot become an “end-use” customer without purchasing electricity from Delmarva – and that cannot be accomplished without using Delmarva’s transmission and distribution assets. DNREC further argued that because transmission and distribution costs are part of Delmarva’s customers’ bills, transmission and distribution costs must be included components in defining TRCE.68 Under the plain language of Sections 354(i) and (j), “total retail cost of electricity” cannot be “the total costs paid by” Delmarva because Delmarva is not a retail customer; it buys electricity in wholesale markets.69

41. DNREC next stated that the difference in REPSA application to municipal electric companies and rural electric cooperatives bolsters the argument that TRCE must be understood to mean all of customers’ retail costs.70 The cost cap provision in §354(i) and (j) refers to “the total retail cost of electricity” while the cost cap provisions for municipal electric companies and rural electric cooperatives are found in §363(f) and (g), which refer to “the total cost of the purchased power.” DNREC argued that the sharp difference in statutory language was instructive because the General Assembly clearly did not intend that those different terms in correlating section of the same legislation were to mean the same thing. Therefore, DNREC supported defining TRCE to included supply, transmission, and distribution.

D. Mr. Myers’ Position: “Total Retail Cost of Electricity for Retail Electricity Suppliers” Excludes Any Delivery Charges.

42. Mr. Gary Myers (“Mr. Myers”) argued that the definition of TRCE should include only supply costs, to the exclusion of transmission and delivery charges. Mr. Myers posed three arguments on this issue, each similar to the DPA’s.

43. First, Mr. Myer’s claimed that Staff conflated “retail electricity suppliers” with “end-use customers.” He argued that, “[t]he statutory text says nothing about ‘costs paid by customers,’ or ‘all customer costs,’ or even all revenues or costs received by retail electricity suppliers.71 Rather, it directs that the appropriate reference is to be the ‘cost of electricity for retail electricity suppliers:’ that is, the outlay ... incurred ... by retail electricity suppliers to produce or procure electricity.”72 Mr. Myers argued that the statutory text focus is on the cost of electricity for retail electricity suppliers, not the costs or charges paid by retail customers or consumers.73

44. Mr. Myers next argues that “retail electricity suppliers do not incur distribution or delivery charges.”74 Mr. Myers argued that there is a distinction between Delmarva in its role as a supplier versus its role as a distribution utility. That is, distribution and delivery services are separate and distinct from the sale of electrical energy. The former are provided by Delmarva in its role as an electric distribution company.75

45. Regarding what costs retail electricity suppliers pay for "electricity," Mr. Myers stated that the answer lies in REPSA's definition of a "retail electricity supplier," which states that it is an entity "that sells electrical energy to end use customers."76 It can be an independent "power producer[]" or an electric distribution company acting in its capacity as a default or standard offer supply provider. “Electrical energy” is the commodity of a retail electricity supplier's business; therefore, the company bears the costs of procuring (at wholesale), or producing on its own, the "electrical energy" that it will then sell to end-use customers.77

46. Mr. Myers emphasized, however, that the retail electricity supplier, here Delmarva, does not “bear the work[] or costs” for delivery or distribution because those services are separate and distinct from the sale of electrical energy in the “restructured electricity world that prevails.”78 In essence, Delmarva bears delivery costs which its customers then pay to Delmarva via separate delivery charges, but “[r]etail electricity suppliers” accrue no costs related to delivery or distribution because neither is a "retail cost of electricity" for those suppliers.79 Retail electric suppliers simply "utilize" the distribution network of distribution utilities and pay no fee for such use.80 Thus, such, delivery and distribution costs and charges cannot be included as TRCE components.

47. Mr. Myers argued that TRCE does include the electricity supplier’s costs to procure or produce the electricity it then re-sells, which he suggests “might be described as the supplier's ‘wholesale’ cost of power.”81 Mr. Myers expands this argument by stating that adjective “retail” in TRCE suggests that the described amount includes more than the suppliers' "wholesale" costs of power.”82 Rather, “[retail] suggests that the benchmark should include not just the “true" wholesale purchase or production costs, but also the suppliers' additional costs incurred... to retail the electrical energy commodity.”83 Mr. Myers stated that “[t]he benchmark would thus include wholesale purchase or production costs plus the ‘back-office’ and other additional costs incurred by suppliers to retail their electrical energy product.”84

E. Commission Decision.

48. The Commission hereby votes 4-1 to approve the arguments of the DPA and Mr. Myers that excludes any delivery charges from the definition of Total Retail Cost of Electricity for Retail Electric Suppliers. The Commission incorporates by reference the supporting language from both DPA and Mr. Myers.

49. The Commission rejects Staff’s argument that to “capture Total Retail Cost, it is necessary to include the retail costs sold to end-use customers by all Retail Electricity Suppliers.” By doing so, Staff was including Delmarva and, in doing so, “has thus bootstrapped the distribution into the recommended definition of Total Cost of Electricity for Retail Electric Suppliers.”85

50. Also, the Commission relies upon the Restructuring Act, which “mandates that separate charges for supply, transmission, distribution, et cetera, be set forth on the billing to end-use customers even though that doesn't necessarily happen exactly that way as of today.”86

51. Finally, the Commission has found nothing in the record – expert testimony or any evidence – as to transmission charges. Therefore, the Commission must rely on what is in the statutes and the Restructuring Act and the definition of Retail Electric Supplier “so that we have to make our best stab at the statutes.”87

IV. Whether Bloom Costs Should Be Included In “Total Cost of Compliance?”

A. Staff’s Position: Bloom Costs Should Be Excluded.

52. Staff’s initial argument points to the 2011 Bloom Amendments (“2011 Amendments”), wherein the General Assembly amended REPSA to add provisions related to Qualified Fuel Cell Providers (“QFCP”) and Qualified Fuel Cell Provider Projects (“QFCPP” or “Bloom”). Specifically, the 2011 Amendments codified procedures for fuel cells that were, ”manufactured fuel cells in Delaware, capable of being powered by renewable fuels, and designated... as an economic development opportunity for the state.”88 Staff emphasized that the 2011 Amendments did not alter REPSA’s definition of EERs so as to include QFCPPs and, therefore, the QFCPP does not produce RECs or SRECs.89 Staff argued that the 2011 Amendments did, however, provide for REC equivalencies, a method for “reducing” REC and SREC requirements of the Commission-regulated electric company (“CREC”) in proportion to the output of the QFCPP90 in exchange for the monthly disbursement of CREC customers to the QFCPP. Staff argued that Bloom costs must be excluded because § 354(i) and (j) mandate that “the total cost of compliance shall include the costs associated with any ratepayer funded state solar rebate program, SREC purchases, and solar alternative compliance payments,” which Section 354(j) mirrors as to all renewable energy.91 Staff argued that this statutory reading compels excluding Bloom costs in “Total Cost of Compliance” as consistent with the Court’s directive to observe the plain and ordinary meaning in the statute and not to “collapse plain, and presumably intentional, statutory distinction[s]” where they exist.92

53. Staff further contended that Section 363(e) of REPSA bolstered its argument in memorializing parallel cost-cap provisions for municipalities and co-ops, thus providing a similar statutory construction against which to contrast Sections 354(i) and (j). Section 363(e) states: “[t]he total cost of compliance with this section shall include the costs associated with any ratepayer funded renewable energy rebate programs, REC and SREC purchases, or other costs incurred in meeting renewable energy programs.”93 Staff contended that Sections 354(i) and (j) per se have no instruction to include “other costs incurred” in meeting REPSA’s requirement; accordingly, the statute’s plain meaning compels that other costs incurred to meet REPSA’s requirement, aside from those specifically enumerated in Sections 354(i) and (j), must not be included in the calculation of total cost of compliance.94

B. The DPA’s Position: Bloom Costs Should Be Included.

54. The DPA argued that Delaware law makes clear that Bloom must be included in the total cost of compliance. The DPA pointed to 26 Del.C. §353(d), which states the Commission shall develop procedures for tracking the QFCPP generation output such that the energy produced by a QFCPP “’shall fulfill the [CREC’s] state-mandated REC and SREC requirements’ according to the statutorily-defined equivalencies that the DNREC Secretary may adjust.”95 The DPA observed that Section 353(d)(1)a. and (d)(1)b. establish equivalencies of 1 REC for every 1 MWH of energy produced by a QFCPP, and 6 MWH of RECs per l MWH of SRECs.96 DNREC may, after coordination with the Commission and the CREC, adjust these equivalencies.97 Lastly, “the CREC’s right to use a QFCPP's energy output to fulfill its REC and SREC requirements does not expire until the CREC actually applies the output to satisfy its REC and SREC requirements.”98 The DPA argued that “[t]he QFCPP output walks like a REC/SREC and quacks like a REC/SREC. It is a REC/SREC, and the cost of the QFCPP output that Delmarva uses to satisfy its REPSA obligations must be included in the calculation of the total cost of complying with REPSA.”99 The DPA advanced several arguments to support its interpretation.

55. First, the DPA opposed Staff’s contention that the General Assembly created a distinction between “producing” RECS and SRECs through renewable energy generation and “reducing” the number of RECs and SRECs by the Section 353(d) equivalencies. It claimed that Section 353(d) was a clear instruction that Delmarva shall use some of the Bloom output to fulfill its REPSA requirements, and nothing in REPSA indicated otherwise.100 The DPA contended that it was irrelevant that the General Assembly did not amend the definition of “eligible energy resource” because the General Assembly did ensure that Delmarva could fulfill its REPSA requirements with Bloom output that ratepayers pay for, just as they pay for the cost of RECs and SRECs produced from renewable energy generation.101 Moreover, the DPA observed that Section 353(d) specifically provided that Delmarva could use Bloom output to satisfy its SREC requirement in lieu of incurring a solar alternative compliance payment due to lack of SREC availability in the market. The DPA pointed out that Section 354(i) explicitly identifies solar alternative compliance payments as a cost of compliance, and argued that this language would have been unnecessary if Bloom output were not to be considered a compliance cost for purposes of the cost cap.102 The DPA argued that Staff’s interpretation produced a “mischievous or absurd result”103 that did not reflect the General Assembly’s intent that the cost of the QFCPP equivalencies that Delmarva uses to satisfy its REPSA requirements be included in the cost of REPSA compliance. The DPA further stated that “Staffs interpretation deprives ratepayers of the only benefit they have as a result of the 2011 REPSA amendments that force them to pay substantially higher prices for fuel cell-generated energy than for energy that Delmarva could purchase elsewhere.”104

56. Next, the DPA argued that Staff misconstrued the word “include” in Sections 354(i) and (j) by contending that because Sections 354(i) and (i) do not contain the same language as Section 363(e), which states that the total cost of REPSA compliance "shall include . . . other costs incurred in meeting renewable energy programs," the absence of that language from Sections 354(i) and (j) limits the total cost of REPSA compliance to only these items, and because the QFCPP output that the General Assembly has explicitly directed "shall fulfill" Delmarva's REC and SREC requirements is not explicitly listed in Sections 354(i) and (j), it cannot count toward the total cost of REPSA compliance.105 The DPA contended that the Bloom surcharges are purchases of output that fulfill REC and SREC requirements. The DPA asked, “[h]ow is that not a purchase of a REC or SREC?106 Moreover, the DPA’s viewed Staff’s definition of “include” as contrary to the General Assembly’s instruction to give statutory words their “common and approved usage in the English language,” as well as to the Legislative Drafting Manual’s instruction that “’includes’ should be used ‘if a definition is intended to make clear that the term encompasses only some of the specific matter.’”107 The DPA argued that this was indicative of the General Assembly’s not intending to limit compliance costs to the three items specifically identified, but rather to leave room for other similar items such as the Bloom REC and SREC equivalencies.108

57. The DPA next contended that Staff’s comparison of the language of Sections 354(i) and (j) to that of Section 363(e) was out of context. The DPA again noted that Section 363(e) only applies to municipalities and cooperatives, which are statutorily permitted to exempt themselves from compliance with the REPSA as long as they develop and implement a program comparable to REPSA. If they do exempt themselves, they must either contribute to the Green Energy Fund at levels commensurate with other retail electricity suppliers, or create a separate independent fund to be used for energy efficiency and renewable energy technologies or demand side management programs, into which they shall make payments of at least $0.178 for each megawatt hour they sold, transmitted or distributed in Delaware.109 The DPA argued that “other costs incurred in meeting renewable energy programs” language refers to this self- administered fund described in Section 363(d). The DPA pointed out that non-municipal electric companies and non-rural electric cooperatives do not have the option of exempting themselves from REPSA’s requirements, nor may they comply with REPSA by creating a self-administered fund to support energy efficiency technologies, renewable energy technologies or demand side management programs. The DPA argued that “Staff ignore[d] this difference between municipal electric companies/rural electric cooperatives and retail electricity suppliers. But if the statute is to be read as a whole, this difference matters.”110

58. Furthermore, the DPA observed that the Commission had already recognized that the 2011 Amendments added Delaware-manufactured fuel cells to REPSA and allowed energy output from such fuel cells to be considered a resource eligible to fulfill a portion of Delmarva’s REPSA requirements.111 The DPA pointed out that every order the Commission has issued approving Delmarva’s monthly QFCPP filings has contained language acknowledging that the Bloom amendments “added Delaware-manufactured fuel cells to REPSA and allowed energy output from such fuel cells to be considered a resource eligible to fulfill a portion of a Delaware Public Service Commission-regulated electric company’s renewable energy credit requirements under REPSA.”112 Similarly, the Commission’s current regulations acknowledge that Delmarva may use Bloom output to satisfy its REC and SREC requirements as set forth in §353(d). The DPA further argued: “Delmarva may (but does not have to) use QFCPP output to satisfy its REPSA obligations. If it does not use the REPSA output, then it has to purchase RECs and SRECs from somewhere else. Staff does not dispute that the costs of RECs and SRECs purchased elsewhere would be part of the total cost of complying with REPSA. The QFCPP output that Delmarva uses to satisfy its REPSA requirements is equivalent to RECs and SRECs for purposes of REPSA compliance ... .”113

59. The DPA also contended that Staff’s proposal was inconsistent with what Delmarva ratepayers have been told about REPSA compliance costs. The DPA pointed out that Delmarva’s website identifies Bloom as one of the three sources of clean energy generation, and that Delmarva uses the Bloom output to meet approximately half of its REPSA requirements. Similarly, Delmarva’s bills include a separate line item for Renewable Compliance Charges, which is further broken out into (1) Wind & Solar and (2) Delaware Qualified Fuel Cells.114

60. Finally, the DPA pointed out that the proposed regulations contained definitions for “Qualified Fuel Cell Provider” and “Qualified Fuel Cell Provider Project.” The DPA queried why these definitions were necessary if the Bloom output did not count toward the total cost of compliance.115

C. DNREC’s Position: Bloom Costs Should Be Excluded.

61. DNREC first argued that Bloom costs must be excluded because the legislature did not intend otherwise; namely, Bloom was not enumerated among the definitional components of the cost of compliance in Section 354(i) and (j).116 DNREC’s position was that including Bloom costs is contrary to the plain language of REPSA because inclusion of Bloom costs in the calculations, as proposed by the Commission, is directly at odds with subsections 354(i) and (j). Sections 354(i) and (j) are clear that they relate to “the total cost of complying with” the “minimum cumulative solar photovoltaics requirement” and the “minimum cumulative eligible energy resources requirement.” These terms are statutorily defined. Id. §352(6). These definitions explicitly do not include Bloom costs. Indeed, Bloom costs, which are powered by natural gas, are explicitly excluded from the definitions of eligible energy resources and solar photovoltaics. See id. §352(6)(e) (“Electricity generated by a fuel cell powered by renewable fuels”) (emphasis added); id. § 352(20) (“‘Renewable fuel’ mean a fuel that is derived from eligible energy resources. The term does not include a fossil fuel or waste product from a fossil fuel source.”) (emphasis added). DNREC contended that including Bloom costs, as contemplated by proposed regulations subsections 3.2.21.1.6, 3.2.21.1.7, 3.2.21.3.7, 3.2.21.3.8, and 3.2.21.4.4, is directly contrary to the plain language of REPSA.117

62. DNREC’s next argued that Bloom is not statutorily defined as an EER under REPSA; accordingly, by legislative definition Bloom cannot produce RECs.118 DNREC stated that “Bloom output is not traded as RECs, is not used by any other utilities to meet their RPS requirements, and is not traded or tracked on PJM GATS, the system used to monitor and retire RECs. Instead the power generated by Bloom is used to offset Delmarva’s required REC or SREC purchases through a specific, limited process.”119 Instead, Bloom output is the subject of a special tariff as authorized in 364(d) and approved by the Commission on April 17, 2012 in Order 8136, Docket No. 11-362. As this tariff cannot be frozen, it cannot be part of the freeze process under 354 (i) & (j). DNREC argued that neither it nor the Commission have the statutory authority to freeze Bloom costs, and therefore the attempt to include those costs in the calculations under § 354(i) & (j) is wholly at odds with the framework applicable to Bloom.120 DNREC contended that the legislature intent in not defining Bloom as an EER shows a clear intent: Bloom does not generate RECS.121

D. Mr. Myers’ Position: Bloom Costs Should Be Included.

63. Mr. Myers’ first argued that while a QFCPP's energy output does not meet all the definitional requirements of “REC or SREC equivalents” under either 26 Del.C. §352(18) or 352(25) – for example, the “equivalencies” cannot be traded – the dispositive inquiry is not whether “the equivalencies are, or are not, technical RECs.”122 Rather, the dispositive inquiry is “whether the surcharge payments paid for the Bloom generation that creates such equivalencies constitute a part of the "total cost of complying" with [REPSA].”123 Mr. Myers contended that “the statutory text repeatedly answers ‘yes.’”124

64. Next, Mr. Myers argued 26 Del.C. §354(e) codified (i) Delmarva’s “sole responsibility to ‘procur[e] RECs, SRECs and any other attributes needed to comply with subsection [354](a) . . . with respect to all energy delivered to [its] end use customers[,]’”125 and (ii) a “decree[] that the ‘equivalencies’ created by Bloom Energy output were available as a means to ‘comply’ with those REPSA annual percentage requirements.”126 Mr. Myers stressed that Bloom costs should be included because its “energy output ‘shall fulfill [DP&L's] state-mandated REC and SREC requirements set forth in § 354.’”127 Further, Mr. Myers argued that each Bloom output equates a REC or SREC because it is both “fungible, just like tradable RECs” and can be “banked” and used to meet REPSA requirements in a subsequent compliance year.128

65. Mr. Myers further argued that the 2011 Amendments did not change REPSA’s annual percentage requirements; on the contrary, the 2011 Amendments gave Bloom status as REC and SREC “equivalents” which “then can be used to meet or ‘fulfill’ the pre-existing REPSA percentage requirements.”129 Thus, Mr. Myers argued, Delmarva customers’ “monthly payments... to Bloom for such REC ‘equivalents’ (used to fulfill “the state-mandated REC and SREC requirements set forth in §354”) are part and parcel of the ‘total cost of complying with” ’‘the minimum cumulative solar photovoltaics requirements’ or ‘the minimum cumulative eligible energy resources requirement.’”130

66. Continuing, Mr. Myers offered additional excerpts from the legislative history surrounding the Bloom Amendments and resulting Commission proceedings, arguing that many have characterized the output of the QFCPP as “fulfilling” the RPS requirements.131

67. Next, Mr. Myers argued that REPSA’s 2010 definition of “total cost of compliance” did not include REC/SCREC equivalencies, nor Bloom costs, because the Bloom Amendments were not enacted until 2011. Mr. Myers argued that “[w]hen a statutory definition uses the term ‘includes.’ [sic] the presumptive, common understanding is that such term ‘signal[s] that the list that follows is meant to be illustrative rather than exclusive."132 Thus, because “the Bloom Energy surcharge payments easily share the same characteristics as the costs described in the definitional listings[,]” and “the statutory text [and] legislative history [are] rife with statements that such REC equivalents will be used to fulfill [Delmarva’s] ‘REC and SREC requirements,’ Bloom should be included in the total cost of compliance in § 354(i)&(j).133

68. Mr. Myers also argued that the “constitutional avoidance canon” states that agencies “should avoid interpretations that would render a statute unconstitutional, if that can be done without impairing the legislature’s purpose.”134 Mr. Myers emphasized the quandary of the Federal Power Act’s135 federal preemption of state actions, arguing that “[t]he Bloom Energy scheme bears a striking, if not mirror, resemblance to Maryland’s ‘contract for differences,’” which he stated was struck down by the Supreme Court as unconstitutional.136 Mr. Myers submits that the Supreme Court has held that “States may not seek to achieve ends, however legitimate… that intrude on FERC’s authority over interstate wholesale rates.”137

E. CRI’s Position: Bloom Costs Should Be Included.

69. CRI first argued that “the Commission has repeatedly established ratepayers receive an offsetting value from the legislated renewable energy attributes of the QFCP project, so clearly the QFCP costs need to be included, and the proposed regulation needs clarifying language to do so.”138

70. CRI then argued that including Bloom was supported in PSC Order 8835, wherein Delmarva was directed to “modify its bill format to either (1) break the existing Renewable Portfolio Compliance Charge into two line items on its electrical customers' bill, one containing the monthly QFCP charge, the other containing the remaining components of the Renewable Compliance Charge[,] or (b) add a one line description note on the bill that separately identifies the monthly QFCP charge.”139

F. Public Comments regarding Bloom Costs In Cost of Compliance.

71. Hundreds of citizens filed public comments concerning this issue. The Commission considered the following, which were summarized as follows: (a) sixty-six (66) wanted Bloom included in the Cost of Compliance; (b) one hundred and forty-nine (149) did not want Bloom included; and (c) fifteen (15) did not want any changes because they did not want any increase in their utility bills which may result.

G. Commission Decision.

72. The Commission hereby unanimously votes in favor of Mr. Myers and the DPA that all Bloom costs should be included.140 The Commission incorporates by reference the supporting language from both the DPA and Mr. Myers.

73. First, the Commission finds Section 354(i) to be dispositive: “[t]he total cost of compliance shall include the cost associated with any ratepayer funded [state renewable energy rebate program, REC purchases, and alternative compliance payments.]”141 And, “and ratepayers would clearly support the notion that they are paying in part, at least the Bloom energy.”142

74. The Commission relies on two clear points: (a) Bloom clearly is not a State Solar Rebate Program and not an SREC purchase; and (b) Bloom is not a Solar Alternative Compliance Payment.143 This finding is supported by the mirrored language in Section 354(j).144

75. The Commission also finds compelling the fact that the cost of compliance statute preceded the Bloom amendments, “[a]nd the Legislature never clarified whether or not Bloom was part of the Section 354(i).”145

76. Next, as Mr. Myers argued, Delmarva was not a purchaser of SRECs. Rather, pursuant to 26 Del.C. §364(d), it is solely the agent for collection and disbursement of funds for Bloom and uses Bloom energy output to fulfill its REPSA obligations. Thus, the Bloom energy output “acts, basically, as a solar REC under REPSA.”146

77. Finally, the Commission’s decision to include Bloom in the cost of compliance – where “there’s no clear language in the statute indicating that it should be included” – is “because of the fact that Delmarva fulfills its REPSA obligations through the Bloom payments.”147

V. What Discretion Does The Director Of The Division Of Energy & Climate Have To Institute Or Forego A Freeze If The Statutorily Mandated Calculations Show That The 1% And 3% Thresholds Have Been Reached?

A. Staff’s Position: The Commission Should Determine By Order Whether to Adopt The E&C Director’s Determination After Consultation.

78. Staff argued that because the Commission – and not DNREC – has the exclusive and original jurisdiction over regulated utilities and because a Commission order is necessary to institute a freeze, the Commission should consider the E&C Director's determination under Section 354(i) before the Commission decides whether to freeze the RPS.148 Staff also argued that Sections 354(i) and (j) use distinctive language ("may" versus "shall") should be bound to the specific context of this proceeding and the guidance of the Court. In this context, the Opinion provides explicit direction to not collapse presumably intentional statutory distinctions where they may occur in the text; Staff views this as direction to give separate meanings to the terms “may” and “shall” in Sections 354(i) and (j).149

79. Moreover, Staff argued that under the Proposed Regulations, the Commission would have the ability to deliberate over the E&C Director's determination and then decide whether to freeze or not to freeze the RPS. Staff noted that when the Commission exercises a freeze, such action would change the level of RPS compliance required from the CREC. As a result, the Proposed Regulations limit the Commission’s authority to matters within its jurisdiction. Staff argued that this language protects the Commission from any potential court appeal in which it may be forced to defend an order with which it does not agree.150

80. Finally, Staff argues that the Proposed Regulations allow the Commission to consider and review DNREC’s determination that “the total cost of compliance can reasonably be expected to be under the […] threshold.” Because the statute directs that the freeze “shall be lifted” upon a finding of reasonableness, Staff argues that the Proposed Regulations allow the Commission to consider and decide whether to lift the freeze, based on the E&C Director determination, by deciding whether the determination is “reasonable” in accordance with the statute.151

B. The DPA’s Position: The Revised Regulations Have Satisfied Its Issues, But Public Comment Should Be Allowed At The Consultation.

81. The DPA stated that it is satisfied with the language of the Proposed Regulations except that the Proposed Regulations should provide for public comments during the actual consultation process rather than during the public comment portion of the Commission's meetings.152 As noted by the DPA, public comments after the Commission has already deliberated and reached a decision would make the public’s input pointless. In addition, the DPA emphasized that public commenters often provide both valuable insight and a point of view that the Commission may not have considered.153

C. Mr. Myers’ Position: DNREC Has No Discretion, And The Regulations Are Insufficient.

82. Mr. Myers argues that both "may" (in Section 364(i)) and "shall" (in Section 364(j)) impose a mandatory duty on the E&C Director. According to Mr. Myers, judicial opinions hold that when a government official is given a discretionary power to be exercised to protect or benefit the public welfare or to guarantee a right granted to a third party, the "may" term imposes a duty to act without any discretion.154 According to Mr. Myers, that is the scenario here: the E&C Director holds the power to suspend the RPS mandates to protect ratepayers from paying for renewable energy costs at levels the General Assembly has already determined to be excessive.155 In contrast, Section 364(j)'s use of the word "shall" does not grant the Director any right or privilege. Instead, such word simply emphasizes that once the cost levels are expected to fall below the cap limits, the Director has a ministerial duty to return to the "normal" statutory RPS scheme. In both instances, he notes that although one sentence uses "may" and the second uses "shall," both directives are obligatory.156

83. Mr. Myers also argues that the Commission should reject the notion that the Director has the discretionary authority to forego a freeze otherwise required by the percentage cap levels.157 According to Mr. Myers, the wording in 26 Del.C. §362(b) stresses that the Commission, not DNREC, has the final say on how freezes will occur. In Mr. Myers’ view, neither the statutory text nor the legislative history supports the discretionary power claimed by the Director.

84. Mr. Myers also argued that the Proposed Regulations create technical difficulties in two ways. First, the citations to the Administrative Procedures Act (“APA”) that Staff cited in support of calling the E&C Director's decision to freeze the RPS requirements a "final agency action" did not support such a conclusion in fact. Mr. Myers asserted that 29 Del.C. §10141(b) was limited to making, amending, or repealing regulations, and 29 Del.C. §10141(a) was limited to judicial action on the unlawfulness of a regulation. In contrast, the E&C Director's decision to freeze/not freeze cannot be squeezed into the definition of a "regulation" under the APA. In support of this argument, he notes that the APA requires public notice in the Register of Regulations and the opportunity for public comments, neither of which have been considered within the Proposed Regulations as drafted. In addition, he argues that under the APA, a final decision on a regulation must be based on all of the testimonial and written evidence and information submitted.158 However, the Proposed Regulations do not allow for submissions of public comments.159

85. Mr. Myers also argues that the Proposed Regulations distort basic administrative law principles and violate the Delaware Constitution.160 He points out that the separation of powers doctrine assigns to the legislature the duty to decide major policy issues--not the executive branch as set forth in the Proposed Regulations. He also argues that Article I, section 10 of the Delaware Constitution precludes an executive official from being granted the power to suspend the operation of a statutory enactment based on her discretionary finding or view that the previously enacted statutory benefit or regime no longer remains good public policy.161

D. DNREC’s Position: The E&C Director Has The Authority To Calculate The Total Costs Of Compliance And The Discretion To Freeze The RPS In Consultation With The Commission.

86. DNREC argued that the Commission should reject any attempt to limit the authority of the E&C Director regarding decision-making authority under both 26 Del.C. §354(i) and (j).162 Moreover, DNREC argued that when a statute uses two different words in the same paragraph of the same statute, one can only conclude that the words convey different meanings. Hence, "may," as used in Section 354(i) confers discretion, whereas "shall" means the E&C Director does not have discretion regarding lifting a freeze.163 In addition, DNREC argued that the statutory language used in Section 354(i) is unambiguous and therefore a review of legislative history was unnecessary.

87. DNREC also argued that the words “in consultation with” the Commission hinges upon the E&C Director's exercise of discretion, and a freeze cannot be declared without the Director’s affirmative decision to freeze the RPS.164 According to DNREC, the Director has no reason to consult with the Commission unless and until the Director decides to freeze the RPS caps.165

88. DNREC argued that this Docket was “for the limited purpose of complying with the Memorandum Opinion, issued December 30, 2016, in Delaware Division of the Public Advocate v. Delaware Public Service Commission.” (PSC Order No. 9024, p. 3.) As stated by Judge LeGrow, that purpose is “to promulgate regulations for freezing the minimum renewable energy purchase requirements, including regulations regarding when and how the calculations will be made.”166 DNREC argued that the Commission should not expand the scope of this docket beyond Judge LeGrow’s ruling and in no case is it legally permissible to utilize this rulemaking to deviate from the plain meaning and purpose of REPSA. DNREC argued that, in particular, REPSA is explicit that DNREC has authority not only to perform the calculation, but also to determine, after consultation with the Commission, whether a freeze of the RPS requirement should be implemented and when a freeze should be lifted, and Judge LeGrow confirmed this. In support of its argument, DNREC cites Judge LeGrow’s decision: “the General Assembly gave DNREC the ability to calculate cost caps and determine, in consultation with the Commission, whether a freeze should be implemented and subsequently lifted.”167 Despite this, the proposed regulations seek to give the Commission the ultimate authority on this. DNREC argues this exceeds both the clear direction from Judge LeGrow and the plain language of REPSA.168

89. DNREC further argued that §354 (i) and (j) provide not a ceiling, but a floor. That is, if the cost of compliance falls under the 3 percent and 1 percent thresholds, there is no authority to freeze the RPS. On the other hand, if the cost of compliance rises above the 3 percent or 1 percent thresholds, DNREC has authority to exercise its discretion to freeze the increases in the minimum RPS standards, then bringing that determination to the Commission for consultation. In contrast, the proposed regulations in sections 3.2.21.5 and 3.2.21.6 appears to provide the Commission with the ultimate authority to decide whether a freeze will be implemented: “the Commission shall consider the determination and issue an Order to the CREC as to whether to institute a Freeze.” Proposed Regulation §3.2.21.6.2. Such a regulation conflicts with the plain language of REPSA.169

90. DNREC further argued that the proposed regulations regarding unfreezing, sections 3.2.21.7, 3.2.21.8, and 3.2.21.9, are similarly in conflict with REPSA, which provides that a “freeze shall be lifted upon a finding by the Coordinator, in consultation with the Commission, that the total cost of compliance can reasonably be expected to be under the [1% or 3%] threshold,” 29 Del.C. §354(i), (j) (emphasis added); i.e., the authority is DNREC’s and the freeze must be lifted upon a finding by DNREC. In contrast, the proposed regulations take that authority away from DNREC and provide the Commission with discretion to “consider the determination and issue an Order to the CREC as to whether to resume. . ..” Proposed Regulation §3.2.21.9.2 (emphasis added). DNREC argued that such a regulation conflicts with the plain language of REPSA.170 DNREC asserted that the allocation of authority between the Commission and DNREC is further underscored by the alternative statutory language found in Sections 354(c) and (d) where the Legislature provided the Commission with authority; as the Legislature plainly knew how to provide such a delegation of authority in subsections (c) and (d), the distinction in subsections (i) and (j) must have meaning.171

91. DNREC also found issue with a portion of the Proposed Regulations that, according to DNREC, would effectively create a right of judicial review of the Director’s determination to freeze or not to freeze the RPS.172 Because the Proposed Regulations state that the E&C Director’s decision is a final agency action under 29 Del.C. §10141(b), the Proposed Regulations effectively create a right of judicial review of the Director’s determination. This language, according to DNREC, is erroneous for six reasons.

92. First, no language in REPSA exists to support this new proposed right of judicial review. According to DNREC, Section 362(b) limits the Commission's regulatory authority to specifying procedures for freezing the RPS and adjusting the alternative compliance payment — not for contesting the Director’s decision to freeze or not to freeze. Because REPSA has no provision for an appeal and because the regulatory authority of the Commission in this matter is limited to the matters specified in §362(b), DNREC argues that the Proposed Regulations cannot add a new right of judicial review.

93. Second, the Opinion173 did not require any right of judicial review or even suggest it. According to DNREC, the Court in that decision stated that Section 362(b) contains the only explicit rule-making authority granted by the General Assembly.174 Hence, the Commission reopened this docket for the limited purpose of complying with the Delaware Superior Court's Memorandum Opinion in that case.

94. Third, to create a right of judicial review would exceed the scope of PSC Order Nos. 9024 and 9025. Because the issues were limited in those orders, DNREC argued that the Commission should not expand the scope of this docket to include the additional matter of creating a right of judicial review.

95. Fourth, the language in the Proposed Regulations that created this new right of judicial review was based on an incorrect interpretation of 29 Del.C. §10141(b). That statute, DNREC argued, does not support the conclusion that DNREC's decision to freeze the RPS is a "final agency action" because DNREC is not subject the provisions of the APA that govern case decisions and the subsequent right to judicial review.

96. Fifth, the Commission lacks the authority to assert or create a right to judicial review for another state agency. DNREC argued that Title 29 governs judicial review of a DNREC decision, and matters within Title 29 extend beyond the purview of the Commission. Thus, DNREC contended that the Commission does not have the authority under Title 29 to decide this matter for a state agency not subject to its regulation.

97. DNREC further argued that Staff had not offered a sufficient policy basis or legal reasoning for asserting a right of judicial review. Although Staff cited to an "intense disagreement,"175 DNREC asserted that this disagreement by itself did not provide sufficient basis for asserting a right to judicial review.

98. Finally, DNREC generally objected to the proposed regulations as contrary to the underlying statutory purpose of REPSA. As declared in REPSA, “It is therefore the purpose and intent of the General Assembly in enacting the Renewable Energy Portfolio Standards Act to establish a market for electricity from these resources in Delaware, and to lower the cost to consumers of electricity from these resources.” (26 Del.C. §351 (emphasis added).) To that end, “the benefits of electricity from renewable energy resources accrue to the public at large, and that electric suppliers and consumers share an obligation to develop a minimum level of these resources in the electricity supply portfolio of the state. These benefits include improved regional and local air quality, improved public health, increased electric supply diversity, increased protection against price volatility and supply disruption, improved transmission and distribution performance, and new economic development opportunities.” Id. To that purpose, REPSA reiterates numerous times that its goal is to meet 25% of electricity from eligible energy resources by 2025, and that once reached the percentage can never be lower than 2025 levels. (26 Del.C. §354(b), (c), (d). Measured by the purpose and intent of REPSA, the RPS is working. The RPS has created a market for eligible energy resources that has led to a consistent, long-term expansion in the market for eligible energy resources and a consistent, long-term decline in REC and SREC prices. Any amendments to Reg. 3008 that would interfere with the long-term development of renewable energy—even as renewable energy costs are falling as intended— is inconsistent with the purpose of REPSA.176

E. CRI’s Position: The Director Must Freeze RPS Compliance If The Cost Caps Are Reached.

99. CRI argued that both the words “may” in Section 354(i) and “shall” in Section 354(j) both mean the same thing—that DNREC must freeze the minimum cumulative solar photovoltaics/eligible energy resources requirements for regulated utilities if the cost caps are reached. According to CRI, the General Assembly stated in legislative hearings that if a cost cap were to be exceeded, this fact caused an absolute “circuit breaker” to occur in order to protect ratepayers.177 Hence, CRI’s position was that the E&C Director does not have discretion in deciding whether to freeze or not freeze the cost caps.

F. Commission Decision.

100. This Commission, by a vote of 4-1 (Chairman Winslow dissenting) finds that Staff’s arguments are persuasive and holds that Staff's position on this issue is the correct view. The Commission has the exclusive jurisdiction over RPS compliance — not the E&C Director. Moreover, the Commission has exclusive jurisdiction over Delmarva, as the distribution company, regarding RPS compliance. This position of authority places the Commission in an ideal position in which to review and determine, after consultation with the E&C Director, whether to freeze or not freeze RPS compliance. The Commission therefore can veto DNREC's determination on whether to institute a freeze or not.

101. Thus, the Commission will determine by order whether to adopt DNREC's determination after consulting with DNREC. If DNREC's calculations determine that either the 1% or the 3% requirements have been met, the Commission shall consult with DNREC as to whether a freeze of the yearly increase should be instituted or not. Twenty days after the consultation, DNREC will submit to the Commission a written decision that includes the basis for its determination, including the basis of why it decided to declare a freeze or not. At the next regularly scheduled Commission meeting, we will consider DNREC's determination and issue an order to the CREC as to whether to institute a freeze or not.

NOW, THEREFORE, IT IS HEREBY ORDERED BY THE AFFIRMATIVE VOTE OF NOT FEWER THAN THREE COMMISSIONERS:

1. That this Findings, Opinion and Order constitute the Commission's issuance of its conclusion under 29 Del.C. §10113(a) to adopt as final the "Rules and Procedures to Implement the Renewable Energy Portfolio Standard" (Opened August 23, 2005) (26 Del. Admin. C. §3008) set forth in Exhibit "A" to this Order, which amend the current regulations set forth in attached Exhibit "B." In accordance with 29 Del.C. §10118, these Regulations shall become effective on December 12, 2018.

2. That, pursuant to 29 Del.C. §§1133 and 10115(a), the Secretary shall transmit to the Registrar of Regulations for publication in the December 2018 Delaware Register of Regulations a copy of this Order.

3. The Commission reserves jurisdiction and authority to enter such further orders as may be deemed necessary or proper.

BY ORDER OF THE COMMISSION:

3008 Rules and Procedures to Implement the Renewable Energy Portfolio Standard (Opened August 23, 2005)

1.1 The following words and terms, when used in this Regulation, should have the following meanings unless the context clearly indicates otherwise:

"Alternative Compliance Payment" or "ACP" means a payment of a certain dollar amount per megawatt hour, which a Retail Electricity Supplier may submit in lieu of supplying the minimum percentage of RECs required under Section subsection 3.3.5 of this Regulation.

"Commission" means the Delaware Public Service Commission.

"Compliance Year" means the calendar year beginning with June 1 and ending with May 31 of the following year, for which a Retail Electricity Supplier must demonstrate that it has met the requirements of this Regulation.

“CREC” means a Commission-regulated electric distribution company.

"Customer-Sited Generation" means a Generation Unit that is interconnected on the End-Use Customer's side of the retail electricity meter in such a manner that it displaces all or part of the metered consumption of the End-Use Customer.

"DNREC" means Delaware Department of Natural Resources and Environmental Control.

"E&C Director" means the Director of the Division of Energy & Climate, as the immediate successor to the State Energy Coordinator, to include any subsequent successor.

"Eligible Energy Resources" means the following energy sources located within the PJM region or imported into the PJM region and tracked through the PJM Market Settlement System:

Solar Photovoltaic Energy Resources means solar photovoltaic or solar thermal energy technologies that employ solar radiation to produce electricity or to displace electricity use;

Electricity derived from wind energy;

Electricity derived from ocean energy including wave or tidal action, currents, or thermal differences;

Geothermal energy technologies that generate electricity with a steam turbine, driven by hot water or steam extracted from geothermal reservoirs in the earth's crust;

Electricity generated by a fuel cell powered by Renewable Fuels;

Electricity generated by the combustion of gas from the anaerobic digestion of organic material;

Electricity generated by a hydroelectric facility that has a maximum design capacity of 30 megawatts or less from all generating units combined that meet appropriate environmental standards as determined by DNREC (see DNREC Regulation's Secretary's Order No. 2006-A-0035);

Electricity generated from the combustion of biomass that has been cultivated and harvested in a sustainable manner as determined by DNREC, and is not combusted to produce energy in a waste to energy facility or in an incinerator (see DNREC Regulation's Secretary's Order No. 2006-A-0035);

Electricity generated by the combustion of methane gas captured from a landfill gas recovery system; provided, however, that:

Increased production of landfill gas from production facilities in operation prior to January 1, 2004 demonstrates a net reduction in total air emissions compared to flaring and leakage;

Increased utilization of landfill gas at electric generating facilities in operation prior to January 1, 2004 (i) is used to offset the consumption of coal, oil, or natural gas at those facilities, (ii) does not result in a reduction in the percentage of landfill gas in the facility's average annual fuel mix when calculated using fuel mix measurements for 12 out of any continuous 15 month period during which the electricity is generated, and (iii) causes no net increase in air emissions from the facility; and

Facilities installed on or after January 1, 2004 meet or exceed 2004 Federal and State air emission standards, or the Federal and State air emission standards in place on the day the facilities are first put into operation, whichever is higher.

"End-Use Customer" means a person or entity in Delaware that purchases electrical energy at retail prices from a Retail Electricity Supplier.

"Freeze" means suspension of the implementation of the annual increase in RPS under 26 Del.C. §354(a), (b), (i) and (j).

"Fund" or “Green Energy Fund” means the Delaware Green Energy Fund as authorized under 26 Del.C. §1014(a).

"GATS" means the Generation Attribute Tracking System developed by PJM-Environmental Information Services, Inc. (PJM-EIS).

"Generation Attribute" means a non-price characteristic of the electrical energy output of a Generation Unit including, but not limited to, the Unit's fuel type, geographic location, emissions, vintage, and RPS eligibility.

"Generation Unit" means a facility that converts a fuel or an energy resource into electrical energy.

"Industrial Customer" means an End-Use Customer with a North American Industry Classification System (NAICS) Manufacturing Sector Code.

"Municipal Electric Company" means a public corporation created by contract between 2 or more municipalities pursuant to provisions of Title 22, Chapter 13 of the Delaware Code and the electric utilities that are municipally owned within the State of Delaware.

"New Renewable Generation Resources" means Eligible Energy Resources first going into commercial operation after December 31, 1997.

"Non-Exempt Customers" means all customers of the Commission-regulated electricity company that have not been certified by the Commission as exempt from the RPS under subsection 2.2.

"Peak Demand" shall have the same meaning as and be determined consistently with how such term or a similar term is defined and determined in the applicable utility's tariff then in effect and approved by the Commission. For customers with more than one account, the peak demands shall be aggregated for all accounts. The calculation will be applied in the current year based on the Peak Demand, as defined above, in the prior year.

"PJM" or "PJM Interconnection" means the regional transmission organization (RTO) that coordinates the movement of wholesale electricity in the PJM region, or its successors at law.

"PJM region" means the area within which the movement of wholesale electricity is coordinated by PJM Interconnection. The PJM region is as described in the Amended and Restated Operating Agreement of PJM.

“Qualified Fuel Cell Provider” means an entity that:

a. By no later than the commencement date of commercial operation of the full nameplate capacity of a fuel cell project, manufactures fuel cells in Delaware that are capable of being powered by renewable fuels, and

b. prior to approval of required tariff provisions, is designated by the Director of the Delaware Economic Development Office and the Secretary of DNREC as an economic development opportunity.”

“Qualified Fuel Cell Provider Project” (or “QFCPP”) means a fuel cell power generation project located in Delaware owned and/or operated by a Qualified Fuel Cell Provider under a tariff approved by the Commission pursuant to 26 Del.C. §364(d).

"Renewable Energy Credit" or ("REC") means a tradable instrument comprised of all the Generation Attributes equal to 1 megawatt-hour of electricity derived from Eligible Energy Resources and that is used to track and verify compliance with the provisions of this Regulation. A REC does not include emission reduction credits and/or allowances encumbered or used by a Generation Unit for compliance with local, state, or federal operating and/or air quality permits associated with the 1 megawatt-hour of electricity.

"Renewable fuel" means a fuel that is derived from Eligible Energy Resources. This term does not include a fossil fuel or a waste product from a fossil fuel source.

"RPS" or "Renewable Energy Portfolio Standard" means the percentage of electricity sales at retail in the State that is to be derived from Eligible Energy Resources.

"Retail Electricity Product" means an electrical energy offering that is distinguished by its Generation Attributes only and that is offered for sale by a Retail Electricity Supplier to End-Use Customers. Multiple electrical energy offerings with the same Generation Attributes may be considered a single Retail Electricity Product.

"Retail Electricity Supplier" means a person or entity that sells electrical energy to End-Use Customers in Delaware, including, but not limited to, non-regulated power producers, electric utility distribution companies supplying standard offer, default service, or any successor service to End-Use Customers. A Retail Electricity Supplier does not include a Municipal Electric Company for the purposes of this Regulation.

"Rural Electric Cooperative" means a non-stock, non-profit, membership corporation organized pursuant to the Federal "Rural Electrification Act of 1936" and operated under the cooperative form of ownership.

"Solar Alternative Compliance Payment" or "SACP" means a payment of a certain dollar amount per megawatt-hour, which a Retail Electricity Supplier or Municipal Electric Supplier may submit in lieu of supplying the Minimum Percentage from Solar Photovoltaic required under Section subsection 3.3.4 of this Regulation.

"Solar Renewable Energy Credit" or "SREC" means a tradable instrument that is equal to 1 megawatt-hour of retail electricity sales in the State that is derived from Solar Photovoltaic Energy Resources and that is used to track and verify compliance with the provisions of this Regulation.

"Sustainable Energy Utility" or ("SEU") is the nonprofit entity according to the provisions of 29 Del.C. §8059 that develops and coordinates programs for energy end-users in Delaware for the purpose of promoting the sustainable use of energy in Delaware.

"Total Retail Cost of Electricity" means the total costs paid by Non-Exempt Customers of the Commission-regulated electric company for the supply and transmission of retail electricity, including costs paid to third party suppliers, during a respective Compliance Year.

"Total Retail Sales" means retail sales of electricity within the State of Delaware exclusive of sales to any Industrial Customer with a Peak Demand in excess of 1,500 kilowatts.

2.1 The benefits of electricity from renewable energy resources accrue to the public at large, and electric suppliers and consumers share an obligation to develop a minimum level of these resources in the electric supply portfolio of the State. The purpose of this Regulation, in support of 26 Del.C. Subchapter III-A, is to set forth the rules for governing the RPS.

2.2 This Regulation shall apply to all retail electricity sales in the State of Delaware except for retail electricity sales of Municipal Electric Companies and retail electricity sales to any Industrial Customer with a Peak Demand in excess of 1,500 kilowatts.

2.2.1 An Industrial Customer with Peak Demand in excess of 1,500 kilowatts may elect to have its load exempt from this Regulation provided that it meets the definitions found in Section subsection 1.1 and:

2.2.1.1 submits a notice to the Commission's Staff including, but not limited to, Name and Address of Industrial Customer, and NAICS Code, and load for each account;

2.2.1.1.1 the Commission's Staff shall, within thirty (30) days of receipt of the notice, provide to the Industrial Customer an acknowledgement of the status, exempt or non-exempt, of the Industrial Customer; and

2.2.1.2 submits the Commission's Staff acknowledgement referenced in Section subsection 2.2.1.1.1 of this Regulation to its Retail Electricity Supplier.

2.2.2 For an End-Use Customer with multiple accounts totaling in excess of 1,500 kilowatts within an applicable utility's service territory and served by a single Retail Electricity Supplier, to have its load exempt, the aggregate of its accounts with an NAICS Manufacturing Sector Code must have a Peak Demand of at least 751 kilowatts and it must follow the procedure found in Section subsection 2.2.1.

2.3 Any Rural Electric Cooperative that has opted-out of Commission regulation by its membership pursuant to 26 Del.C. §223 of the Delaware Code shall, for all purposes of administering and applying this Regulation, be treated as a Municipal Electric Company during any period of time the Rural Electric Cooperative is exempt from Commission regulation.

2.4 A Rural Electric Cooperative may elect to be exempt from the requirements of this Regulation if it develops and implements a program for its ratepayers that is comparable to the RPS beginning in 2013. A Rural Electric Cooperative electing to be exempt from this Regulation must notify the Commission of such election and shall be subject to the requirements set forth in 26 Del.C. §363. A Rural Electric Cooperative not electing to be exempt from this Regulation shall be subject to this Regulation and the applicable provisions of 26 Del.C. §363.

3.1 Certifying and Decertifying Eligible Energy Resources:

3.1.1 The Commission through its Staff will certify Generation Units as Eligible Energy Resources based on the definition of Eligible Energy Resources found in Section subsection 1.1 of this Regulation.

3.1.2 Any Generation Unit seeking certification as an Eligible Energy Resource must submit an Application for Certification as an Eligible Energy Resource Under the Delaware Renewable Energy Portfolio Standard (Application) to the Commission. This may include Customer-Sited Generation or a Generation Unit owned or operated by a Municipal Electric Company.

3.1.3 Customer-sited generation is eligible to be considered an Eligible Energy Resource provided the facility is physically located in Delaware.

3.1.4 Commission Staff will review the Application and will notify the applicant of its approval as an Eligible Energy Resource or of any deficiencies in its Application within 30 days of receipt. The applicant will have the opportunity to revise its submission, if appropriate.

3.1.5 If an Eligible Energy Resource, once notified by Commission Staff, fails to provide the required documentation or missing information within 60 days of the date of such notification, the Application will be dismissed and must be resubmitted.

3.1.6 If Commission Staff finds the Generation Unit to be in compliance with this Regulation and other applicable law, Staff will issue a State of Delaware Certification Number.

3.1.7 Upon receipt of the State of Delaware Certification Number, a Generation Unit will be deemed an Eligible Energy Resource.

3.1.8 Upon designation as an Eligible Energy Resource, the Generation Unit's owner shall be entitled to one (1) REC for each mega-watt hour of energy derived from Eligible Energy Resources other than Solar Photovoltaic Energy Resources. Upon designation as an Eligible Energy Resource, the owner of a Generation Unit employing Solar Photovoltaic Energy Resources shall be entitled to one (1) SREC for each mega-watt hour of energy derived from Solar Photovoltaic Energy Resource. SRECs and RECs will be created and supplied by the PJM-EIS GATS, or its successor at law. Eligible Energy Resources are subject to applicable PJM-EIS GATS rules and shall pay applicable PJM-EIS GATS fees.

3.1.8.1 The Commission may establish or participate in another renewable energy tracking system, if the Commission finds that PJM-EIS's GATS is not applicable or not suited to meet the needs or requirements of the RPS.

3.1.9 If a Generation Unit is deemed an Eligible Energy Resource and the Eligible Energy Resource's GATS account continues to be maintained in good standing, the Eligible Energy Resource may achieve a Delaware designation for RECs or SRECs recorded with PJM-EIS's GATS for the calendar year being traded in GATS at the time of the Commission Staff's approval of the Eligible Energy Resource.

3.1.10 An Eligible Energy Resource will remain certified unless substantive changes are made to its operational characteristics. Substantive changes include but are not limited to changes in fuel type, fuel mix and generator type. An Eligible Energy Resource making substantive changes to its operational characteristics shall notify the Commission of such changes at least 30 days prior to the effective date of such changes. At such time, the Generation Unit shall submit a revised Application, which shall be subject to review and re-certification.

3.1.11 An Eligible Energy Resource must provide updates to any changes to information submitted in the Application within 30 days of those changes becoming effective. These changes include but are not limited to changes in ownership of the generating unit, changes in ownership of the RECs or SRECs, changes in system size, or the deactivation of the unit.

3.1.12 RECs or SRECs created by an Eligible Energy Resource shall remain valid for compliance, subject to Section subsection 3.2.7, Section subsection 3.3.3 and Section subsection 3.3.4 of this Regulation, even if that Eligible Energy Resource is subsequently decertified for eligibility.

3.1.13 An Eligible Energy Resource may be decertified for any of the following:

3.1.13.1 Failure to comply with Sections subsections 3.1.1 through 3.1.11;

3.1.13.2 A material change in circumstances that causes it to become ineligible for certification under Section subsection 3.1;

3.1.13.3 Fraud or misrepresentation in the Application or to PJM-EIS GATS;

3.1.13.4 Failure to properly update the Commission on changes to information submitted in the Application; or

3.1.13.5 Good cause as determined by the Commission.

3.2 Compliance with RPS

3.2.1 The Total Retail Sales of each Retail Electricity Product delivered to End-Use Customers by a Retail Electricity Supplier during any given Compliance Year shall include a minimum percentage of electrical energy sales from Eligible Energy Resources and Solar Photovoltaics as shown in Schedule 1.

Minimum Cumulative Percentage from Eligible Energy Resources includes the Minimum Cumulative Percentage from Solar Photovoltaics

3.2.2 A Retail Electricity Supplier's compliance with Schedule 1 shall be based on accumulating RECs and SRECs equivalent to the current Compliance Year's Cumulative Minimum Percentage of Total Retail Sales of each Retail Electricity Product sold to End-Use Customers subject to Section subsection 3.2.7 of these Regulations and, where appropriate, other Commission regulations.¹ Each Retail Electricity Suppliers shall file a report detailing its compliance with its RPS obligations within 120 days following the end of Compliance Year 2011.

3.2.3 Beginning June 1, 2012, every Commission-regulated electric companies (“CREC”) shall be responsible for procuring RECs, SRECs, and any other attributes needed to comply with the minimum percentage requirements set forth in 26 Del.C. §354 and Section subsection 3.2.1 with respect to all energy delivered to the CREC’s End-Use Customers. Such RECs and SRECs shall be filed annually with the Commission within 120 days following the completion of the Compliance Year. In fulfilling the duty imposed upon it by 26 Del.C. §354(e), a CREC shall succeed to, and assume, the obligations, entitlements, and responsibilities imposed or allowed to a "retail electricity supplier" under the provisions of 26 Del.C. §§354-362, and Sections subsections 3.2, and 3.3, and Sections 4.0 and 5.0 of these regulations.

3.2.3.1 The transitional process set forth in these Regulations shall apply to all Retail Electricity Suppliers that entered into retail electric supply contracts prior to March 1, 2012 that include RPS compliance costs for Compliance Year 2012 and thereafter and that extend beyond June 1, 2012 (such retail electric supply contracts shall be referred to as “Transitional Retail Contracts”. The transitional process will end when the particular contract expires², or is otherwise terminated, or is modified to transfer the RPS compliance costs to the CREC, whichever occurs first.

3.2.3.1.1 On or before March 1, 2012, each Retail Electricity Supplier shall provide the CREC, the Commission Staff and the DPA with identification of all End-Use Customers supplied through a Transitional Retail Contract and shall further provide such supporting data as may be requested. Such identification shall include, but shall not be limited to, the name of the End-Use Customer and the expiration date of the Transitional Retail Contract. All such information required to be submitted hereunder may be submitted confidentially by the Retail Electric Supplier.

3.2.3.1.2 End-Use Customers who dispute their designation may file a complaint with the Commission according to 26 DE Admin. Code §1000.

3.2.3.1.3 Retail Electricity Suppliers shall transfer the RECs and SRECs necessary to meet their RPS compliance obligations for each Transitional Retail Contract for the respective Compliance Year beginning with Compliance Year 2012, to the CREC’s GATS account for retirement at no cost to the CREC. The CREC will provide to the respective Retail Electricity Supplier the sales number based on metered data pertaining to the identified Transitional Retail Contracts for determining its RPS obligation with preliminary data on or before June 15th, and final data on or before August 15th. Ninety percent of the Retail Electricity Supplier’s expected total RECs/SRECs necessary for compliance with its RPS obligations for each Transitional Retail Contract shall be transferred to the CREC’s GATS account on or before August 1st following the end of the Compliance Year, and the remaining RECs and SRECs necessary for compliance with the Retail Electricity Supplier’s RPS compliance obligations for each Transitional Retail Contract shall be transferred to the CREC’s GATS account on or before September 1st following the end of the Compliance Year. Should either of these deadlines fall on a weekend or legal holiday, the deadline will be the next business day following August 1st and September 1st.

3.2.3.1.4 If a Retail Electricity Supplier fails to transfer to the CREC’s GATS account sufficient RECs or SRECs to comply with its RPS obligations for each Transitional Retail Contract, it shall reimburse the CREC for the CREC’s weighted average purchase cost of procuring such RECs and /or SRECs necessary to comply with the Retail Electricity Supplier’s obligations and/or any associated ACPs or SACPs by the CREC. The CREC shall accept the retail supplier’s designation of Transitional Retail Contracts in determining the RPS obligation for such supplier.

3.2.3.1.4.1 The CREC shall notify the Retail Electricity Supplier of its deficiency and the amount owed to the CREC by October 1st of each year. The CREC shall provide the Retail Electricity Supplier with all supporting documentation of the costs incurred, if requested by the Retail Electricity Supplier. The Retail Electricity Supplier shall have fifteen (15) business days to reimburse the CREC or to advise the Commission in writing of any dispute relating to the deficiency. Interest shall accrue for any late payment (after the 15 business days) and shall be payable to the CREC. The interest rate shall be based on Delmarva’s short term debt rate in effect on the date when the payment was due from the Retail Electricity Supplier.

3.2.3.1.5 To protect a CREC and its customers from incurring an ACP or SACP due to a Retail Electricity Supplier’s failure to transfer the appropriate number of RECs and/or SRECs necessary for compliance with its RPS obligations during the transitional process, a CREC may request the Commission to approve a temporary reduction in its RPS obligation or a reduction in the ACP or SACP price for that Compliance Year.

3.2.3.2 Beginning with sales as of June 1, 2012, the CREC will charge all of its distribution system End-Use Customers for RPS compliance costs through a non-bypassable charge based on the weighted average cost of the RECs and SRECs supplied by the CREC.

3.2.3.2.1 Industrial Customers whose peak demand is in excess of 1500 kilowatts and have been acknowledged by the Commission as having their load exempted from the RPS compliance obligations pursuant to 26 Del.C. §353(b), and Sections 1,0 Section 1.0, and subsections 2.2.1, and 2.2.2, shall not be charged the RPS compliance cost permitted by Section subsection 3.2.3.2.

3.2.3.2.2 For a particular compliance year, the total recovery of the RPS compliance costs by the CREC, shall not be an amount greater than the CREC's actual dollar for dollar costs incurred for that compliance year in complying with the State of Delaware's RPS, except that any compliance fee assessed pursuant to 26 Del.C. §358(d) and Section subsection 3.3.5 of this Regulations shall be recoverable only to the extent authorized by 26 Del.C. §358(f)(2) and Section subsection 4.2 of this Regulation.

3.2.3.2.3 The CREC will credit the distribution portion of the bill of the End-User Customers identified in Section subsection 3.2.3.1.1 of these Regulations by the amount equal to the non-bypassable charge for the duration of the Transitional Retail Contract.

3.2.3.3 The CREC and Retail Electricity Suppliers shall place on their websites customer education pertaining to the RPS non-bypassable charge and credit required in Section subsections 3.2.3.2 and 3.2.3.2.1. The CREC shall also include information on the RPS non-bypassable charge and credit on its bill message or bill insert.

3.2.3.4 Retail Electricity Suppliers that prior to March 1, 2012, have entered into contracts to purchase or produce RECs and/or SRECs specifically for Delaware RPS compliance may offer to the CREC those RECs and/or SRECs. The price would be determined by separate agreement between the Retail Electricity Supplier and the CREC. In no case shall the CREC be obligated to purchase any RECs/SRECs from the Retail Electricity Supplier.

3.2.4 CRECs may use energy output produced by a Qualified Fuel Cell Provider Project to fulfill their REC and SREC requirements as set forth in 26 Del.C. § 353(d).

3.2.5 Energy output must be tracked using PJM-EIS GATS or its successor at law or pursuant to Section subsection 3.1.8.1 of this Regulation.

3.2.6 The right of Commission-regulated electric companies to use energy output produced by a Qualified Fuel Cell Provider Project to fulfill their REC and SREC requirements shall not expire until actually applied to fulfill such requirements.

3.2.7 No CREC, or Retail Electricity Supplier with existing contractual electric supply obligations can provide more than 1% of each Compliance Year's Total Retail Sales from Eligible Energy Resources operational before December 31, 1997. The remainder of each year's retail sales, up to the required amount as specified in Section subsection 3.2.1 of this Regulation must come from New Renewable Generation resources. In Compliance Year 2026 and for each Compliance Year thereafter, all Eligible Energy Resources used to meet the cumulative minimum percentage requirements set by the Commission rules shall be New Renewable Generation Resources.

3.2.8 A Retail Electricity Supplier shall not use RECs or SRECs used to satisfy another state's renewable energy portfolio requirements for compliance with Section subsection 3.2.1 and Schedule 1. A Retail Electricity Supplier may sell or transfer any RECs or SRECs not required to meet this Regulation.

3.2.9 On or after June 1, 2006, Eligible Energy Resources may create and accumulate RECs or SRECs for the purposes of calculating compliance with the RPS.

3.2.10 Eligible Energy Resources that do not settle though the PJM Market settlement system must document their actual output of generation, as recorded by appropriate metering, as frequently as PJM-EIS-GATS shall prescribe.

3.2.11 Aggregate generation from small Eligible Energy Resources totaling 100 kilowatts or less of capacity, may be used to meet the requirements of Section subsection 3.2.1 and Schedule 1 provided that the generators or their agents shall document the level of generation, as recorded by appropriate metering, as frequently as PJM-EIS-GATS shall prescribe.

3.2.12 A Retail Electricity Supplier or Rural Electric Cooperative shall receive 300% credit toward meeting the Minimum Cumulative Percentage from Eligible Energy Resources of Sections subsection 3.2.1 and Schedule 1 of the RPS for energy derived from the following sources installed on or before December 31, 2014:

3.2.12.1 Customer-Sited solar photovoltaic physically located in Delaware; or

3.2.12.2 A fuel cell powered by Renewable Fuels for Retail Electricity Suppliers, and such a fuel cell sited in Delaware for Rural Electric Cooperatives.

3.2.13 A Retail Electricity Supplier or Rural Electric Cooperative shall receive 150% credit toward meeting the RPS for wind energy installations sited in Delaware on or before December 31, 2012.

3.2.14 A CREC shall receive 350% credit toward meeting the RPS for energy derived from off-shore wind energy installations sited off the Delaware coast on or before May 31, 2017.

3.2.14.1 To be entitled to 350% credit, contracts for energy and renewable energy credits from such off-shore wind energy installations must be executed by CREC prior to commencement of construction of such installations.

3.2.14.2 CREC shall be entitled to such multiple credits for the life of contracts for renewable energy credits from off-shore wind installations executed pursuant to section subsection 3.2.14.

3.2.15 A Retail Electricity Supplier or a Rural Electric Cooperative shall receive an additional 10% credit toward meeting the RPS for solar or wind energy installations sited in Delaware, provided that a minimum of 50% of the cost of the renewable energy equipment, inclusive of mounting components, relates to Delaware manufactured equipment.

3.2.16 A Retail Electricity Supplier or a Rural Electric Cooperative shall receive an additional 10% credit toward meeting the RPS for solar or wind energy installations sited in Delaware provided that the facility is constructed and/or installed with a workforce that consists of at least 75% Delaware residents and/or the installing company employs in total a minimum of 75% workers who are Delaware residents.

3.2.17 A Retail Electricity Supplier or a Rural Electric Cooperative shall receive credit toward meeting the RPS for electricity derived from the fraction of eligible landfill gas, biomass or biogas combined with other fuels (for a Rural Electric Cooperative the Eligible Energy Resource must be sited in Delaware).

3.2.18 Cumulative minimum percentage requirements of Eligible Energy Resources and Solar Photovoltaic Resources shall be established by Commission rules for Compliance Year 2026 and each subsequent year. In no case shall the minimum percentages established by Commission rules be lower than those required for Compliance Year 2025 in Sections subsection 3.2.1 and Schedule 1. Each of the rules setting such minimum percentage shall be adopted at least two years prior to the minimum percentage being required.

3.2.19 Beginning in Compliance Year 2010, and in each Compliance Year thereafter, the Commission may review the status of Section subsection 3.2.1 and Schedule 1 and report to the legislature on the status of the pace of the scheduled percentage increases toward the goal of 25%. If the Commission concludes at this time that the schedule either needs to be accelerated or decelerated, it may also make recommendations to the General Assembly for legislative changes to the RPS.

3.2.20 Beginning in Compliance Year 2014, and in each Compliance Year thereafter, the Commission may, in the event of circumstances specified in this section and after conducting hearings, accelerate or slow the scheduled percentage increases towards meeting the goal of 25%. The Commission may only slow the increases if the Commission finds that at least 30% of RPS compliance has been met through the ACP or SACP for three (3) consecutive years, despite adequate planning by the CREC and, where applicable, Retail Electricity Suppliers with existing contractual electric supply obligations. The Commission may only accelerate the scheduled percentage increases after finding that the average price for RECs and SRECs eligible for RPS compliance has, for two (2) consecutive years, been below a predetermined market-based price threshold to be established by the Commission. The Commission shall establish the predetermined market-based price threshold in consultation with the Delaware Energy Office. Rules that would alter the percentage targets shall be promulgated at least two years before the percentage change takes effect. In no event shall the Commission reduce the percentage target below any level reached to that point.

3.2.21 The minimum percentages from Eligible Energy Resources and Solar Photovoltaic Energy Resources as shown in Section 3.2.1 and Schedule 1 may be frozen for CRECs as authorized by, and pursuant to, 26 Del.C. § 354(i)-(j). For a freeze to occur, the Delaware Energy Office must determines that the cost of complying with the requirements of this Regulation exceeds 1% for Solar Photovoltaic Energy Resources and 3% for Eligible Energy Resources of the total retail cost of electricity for Retail Electricity Suppliers during the same Compliance Year. The total cost of compliance shall include the costs associated with any ratepayer funded state renewable energy rebate program, REC and SREC purchases, and ACPs and SACPs alternative compliance payments.

3.2.21.1 Once frozen, the minimum cumulative requirements shall remain at the percentage for the Compliance Year in which the freeze was instituted.

3.2.21.2 The freeze may be lifted only upon a finding by the State Energy Coordinator, in consultation with the Commission, that the total cost of compliance can reasonably be expected to be under the 1% or 3% threshold, as applicable.

3.2.21 Implementation of Renewable Energy Portfolio Standards Cost Cap Provisions

3.2.21.1 Within 120 days after the end of each Compliance Year, the CREC shall submit to the E&C Director the following information for the applicable Compliance Year:

3.2.21.1.1 The total costs associated with the purchase of SRECs retired to comply with the RPS;

3.2.21.1.2 The total costs associated with all Solar Alternative Compliance Payments as allowed under subsection 4.2;

3.2.21.1.3 The total costs associated with the purchase of RECs retired to comply with the RPS;

3.2.21.1.4 The total costs associated with all Alternative Compliance Payments as allowed under subsection 4.2;

3.2.21.1.5 The Total Retail Cost of Electricity;

3.2.21.1.6 The amount the CREC paid for the QFCPP output that it used to fulfill its REC requirement; and

3.2.21.1.7 The amount the CREC paid for the QFCPP output that it used to fulfill its SREC requirement.

3.2.21.2 Within 120 days after the end of each Compliance Year, the Division of Energy & Climate shall determine the following information for the applicable Compliance Year:

3.2.21.2.1 The total costs associated with any ratepayer funded state solar rebate program; and

3.2.21.2.2 The total costs associated with any ratepayer funded state renewable energy rebate program.

3.2.21.3 The Total Cost of Compliance for Renewable Energy shall be calculated as:

3.2.21.3.1 The total costs associated with any ratepayer funded state solar rebate program, plus

3.2.21.3.2 The total costs associated with the purchase of SRECs retired to comply with the RPS, plus

3.2.21.3.3 The total costs associated with all Solar Alternative Compliance Payments as allowed under subsection 4.2, plus

3.2.21.3.4 The total costs associated with any ratepayer funded state renewable energy rebate program, plus

3.2.21.3.5 The total costs associated with the purchase of RECs retired to comply with the RPS, plus

3.2.21.3.6 The total costs associated with all Alternative Compliance Payments as allowed under subsection 4.2, plus

3.2.21.3.7 The amount the CREC paid for the QFCPP output that it used to fulfill its REC requirement, plus

3.2.21.3.8 The amount the CREC paid for the QFCPP output that it used to fulfill its SREC requirement.

3.2.21.4 The Total Cost of Compliance for Solar Renewable Energy shall be calculated as:

3.2.21.4.1 The total costs associated with any ratepayer funded state solar rebate program, plus

3.2.21.4.2 The total costs associated with the purchase of SRECs retired to comply with the RPS, plus

3.2.21.4.3 The total costs associated with all Solar Alternative Compliance Payments as allowed under subsection 4.2, plus

3.2.21.4.4 The amount the CREC paid for QFCPP output that it used to fulfill its SREC requirement.

3.2.21.5 Within 135 days after the end of each Compliance Year, the E&C Director or its assigned delegate shall calculate the Total Cost of Compliance for Renewable Energy and the Total Cost of Compliance for Solar Renewable Energy as described in subsections 3.2.21.3 and 3.2.21.4 as a percent of the Total Retail Cost of Electricity for the applicable Compliance Year, and shall submit in writing to the Commission its calculations determining whether:

3.2.21.5.1 The Total Cost of Compliance for Solar Renewable Energy during a Compliance Year exceeds 1% of the Total Retail Cost of Electricity during the same Compliance Year; or

3.2.21.5.2 The Total Cost of Compliance for Renewable Energy during a Compliance Year exceeds 3% of the Total Retail Cost of Electricity during the same Compliance Year.

3.2.21.6 If the E&C Director's calculations determine that either subsection 3.2.21.5.1 or 3.2.21.5.2 is met, then in no fewer than 10 days nor more than 30 days the Commission shall conduct at a regularly-scheduled meeting a consultation between the E&C Director and the Commission as to whether a Freeze of the yearly increase in the Minimum Cumulative Percentage from Solar Photovoltaics requirement or a Freeze of the yearly increase in the Minimum Cumulative Percentage from Eligible Energy Resources requirement for CRECs should be instituted as set forth in 26 Del.C. §354 (a), (b), (i), and (j).

3.2.21.6.1 Within 20 days after the consultation, the E&C Director or its assigned delegate shall submit to the Commission its written determination, including the bases for that determination, to declare or not declare a Freeze.

3.2.21.6.2 At the next regularly-scheduled Commission meeting the Commission shall consider the determination and issue an Order to the CREC as to whether to institute a Freeze.

3.2.21.7 In the event of a Freeze of the yearly increase in the Minimum Cumulative Percentage from Solar Photovoltaics for CRECs, if the E&C Director makes a finding that, consistent with the calculation set forth in subsection 3.2.21.5, the Total Cost of Compliance for Solar Renewable Energy can reasonably be expected to be less than 1% of the Total Retail Cost of Electricity during the next Compliance Year, the E&C Director shall provide written notification of its finding to the Commission.

3.2.21.8 In the event of a Freeze of the yearly increase in the Minimum Cumulative Percentage from Eligible Energy Resources for CRECs, if the E&C Director makes a finding that, consistent with the calculation set forth in subsection 3.2.21.5, the Total Cost of Compliance for Renewable Energy can reasonably be expected to be less than 3% of the Total Retail Cost of Electricity during the next Compliance Year, the E&C Director shall provide written notification of its finding to the Commission.

3.2.21.9 In no fewer than 10 days nor more than 30 days after receipt of written notification from the E&C Director, the Commission shall conduct at a regularly-scheduled meeting a consultation between the E&C Director and the Commission as to whether a Freeze of the yearly increase in the Minimum Cumulative Percentage from Eligible Energy Resources requirement or a Freeze of the yearly increase in the Minimum Cumulative Percentage from Solar Photovoltaics requirement for CRECs should be lifted as set forth in 26 Del.C. §354 (a), (b), (i), and (j).

3.2.21.9.1 Within 20 days after the consultation, the E&C Director or its assigned delegate shall submit to the Commission its written determination, including the bases for that determination, of whether the total cost of compliance can reasonably be expected to be under the thresholds set forth in subsections 3.2.21.7 or 3.2.21.8.

3.2.21.9.2 If the E&C Director determines that the total cost of compliance can reasonably be expected to be under the thresholds set forth in subsection 3.2.21.9.1, the Commission shall consider the determination and issue an Order to the CREC as to whether to resume increasing the Minimum Cumulative Percentage from Eligible Energy Resources or the Minimum Cumulative Percentage from Solar Photovoltaic Resources requirement beginning in the Compliance Year for which the calculations of subsections 3.2.21.7 or 3.2.21.8 were performed. When a CREC is ordered to resume the increase of the Minimum Cumulative Percentage, the requirement shall be that of the Compliance Year immediately following the percentage required when the Freeze was instituted.

3.2.22 The Renewable Energy Taskforce shall be formed for the purpose of making recommendations about the establishment of trading mechanisms and other structures to support the growth of renewable energy markets in Delaware according to 26 Del.C. §360(d).

3.3 Verification of Compliance with the RPS

3.3.1 Within 120 days of the end of the Compliance Year 2011, each Retail Electricity Supplier who has made sales to an End-use Customer in the State of Delaware must submit a completed Retail Electricity Supplier's Verification of Compliance with the Delaware Renewable Energy Portfolio Standard Report (Report) which includes, but is not limited to, evidence of the specified number of SRECs and RECs required for that Compliance Year according to Schedule 1 and the Total Retail Sales of each Retail Electricity Product. Beginning with the Compliance Year 2012, the CREC must submit a completed Retail Electricity Supplier’s Verification of Compliance with the Delaware Renewable Energy Portfolio Standard Report (Report) which includes, but is not limited to, evidence of the specified number of SRECs and RECs required for the Compliance Year according to Schedule 1 and the Total Retail Sales of each Retail Electricity Product according to Section subsection 3.2.3.

3.3.2 SRECs or RECs must have been created by PJM-EIS's GATS or its successor at law, or pursuant to Section subsection 3.1.8.1 of this Regulation.

3.3.3 SRECs or RECs, submitted for compliance with this Regulation may be dated no earlier than three (3) years prior to the beginning of the current Compliance Year.

3.3.4 The three (3) year period referred to in Section subsection 3.3.3 shall be tolled during any period that a renewable energy credit or solar renewable energy credit is held by the SEU as defined in 29 Del.C. §8059.

3.3.5 In lieu of standard means of compliance with the RPS, any Retail Electricity Supplier may pay into the Fund an SACP or ACP pursuant to, and in such amounts as stated in, 26 Del.C. §358, or in such other amounts as may be determined by the State Energy Coordinator of the Delaware Energy Office consistent with 26 Del.C. §354(i)-(j).

3.3.6 The Commission Staff shall notify any Retail Electricity Supplier of any compliance deficiencies within 165 days of the close of the current Compliance Year. If the Retail Electricity Supplier is found to be deficient by the Commission Staff, the Retail Electricity Supplier shall be required to pay the appropriate ACP or SACP, according to Section subsection 3.3.5 of this Regulation. All such payments shall be due within 30 days of notification by the Commission Staff. Upon receipt of payment, the Retail Electricity Supplier shall be found to be in compliance for that given year.

3.3.7 All compliance payments, made by a Retail Electricity Supplier, shall be payable to the Delaware Green Energy Fund and sent to the Commission.

4.1 A Retail Electricity Supplier may recover, through a non-bypassable surcharge actual dollar for dollar costs incurred in complying with the State of Delaware's RPS, except that any compliance fee assessed pursuant to Section subsection 3.3.5 of these Rules and Regulation shall be recoverable only to the extent authorized by Section subsection 4.2 of this Regulation.

4.2 A Retail Electricity Supplier may recover any ACP or SACP if the payment of an ACP or SACP is the least cost measure to ratepayers as compared to the purchase of RECs and SRECs to comply with the RPS; or if there are insufficient RECs and SRECs available for the Retail Electricity Supplier to comply with the RPS.

4.3 Any cost recovered under this section shall be disclosed to customers at least annually on inserts accompanying customer bills.

4.4 Special provisions for customers of CRECs. All costs arising out of contracts entered into by a CREC pursuant to 26 Del.C. §1007 (d) shall be distributed among the entire Delaware customer base of such companies through an adjustable non-bypassable charge which shall be established by the Commission. Such costs shall be recovered if incurred as a result of such contracts unless, after Commission review, any such costs are determined by the Commission to have been incurred in bad faith, are the product of waste or out of an abuse of discretion, or in violation of law.

5.1 Under Delaware's Freedom of Information Act, 29 Del.C. Ch. 100, all information filed with the Commission is considered of public record unless it contains "trade secrets and commercial or financial information obtained from a person which is of a privileged or confidential nature." 29 Del.C. §10002(d)(2). To qualify as a non-public record under this exemption, materials received by the Commission must be clearly and conspicuously marked on the title page and on every page containing the sensitive information as "proprietary" or "confidential" or words of similar effect. The Commission shall presumptively deem all information so designated to be exempt from public record status. However, upon receipt of a request for access to information designated proprietary or confidential, the Commission may review the appropriateness of such designation and may determine to release the information requested. Prior to such release, the Commission shall provide the entity that submitted the information with reasonable notice and an opportunity to show why the information should not be released.

5.2 Any End-Use Customer, Retail Electricity Supplier, Eligible Energy Resource, potential Eligible Energy Resource, Qualified Fuel Cell Provider Project or other interested party to which this Regulation may apply may file a complaint with the Commission pursuant to the Rules of Practice and Procedure of the Delaware Public Service Commission.

5.3 The failure to comply with this Regulation may result in penalties, including monetary assessments, suspension or revocation of eligibility as an Eligible Energy Resource, or other sanction as determined by the Commission consistent with 26 Del.C. §205(a), §217, and §1019.