Exhibit EL-2 Attachment 4 PUCT Docket No Page 144 of 191

Transcription

1 Exhibit EL-2 Attachment 4 Page 144 of 191 that would not benefit under the contract from an increase in the price or value of the nonfinancial asset. (In some circumstances, the exclusion in paragraph also would apply.) Lastly, Topic 460 on guarantees does not affect the guarantors accounting for the guarehtee because that Topic does not apply to a guarantee for which the underlying is related to an asset of the guarantor. Because the manufacturer continues to recognize the residual value of the equipment guaranteed by the manufacturer as an asset (included in the seller-lessors net investment in the lease) if recording a sales-type lease, that guarantee does not meet the characteristics in paragraph and is, therefore, not subject to the guidance in Topic 460. Additionally, if the lease is classified as an operating lease, the manufacturer does not remove the asset from its books, and its guarantee would be a market value guarantee of its own asset. A market value guarantee of the guarantors own asset is not within the scope of Topic 460, and the guidance in paragraphs through for an operating lease is not affected. As a result, the guarantors accounting for the guarantee is unaffected by Topic 460. > > Guarantee Payments Received indemnification payments related to tax effects other than the investment tax credit should be reflected by the lessor in income consistent with the classification of the lease. That is, the payments should be accounted. for as an adjustment of the lessors net investment in the lease if the lease is a salestype lease or a direct financing lease or recognized ratably over the lease term if the lease is an operating lease.» Pattern of Benefit from Use of the Underlying Asset This Subtopic considers the right to control the use of the. underlying asset as the equivalent of physical use. If the lessee controls the use of the underlying asset, recognition of lease income in accordance with paragraph (a) should not be affected by the extent to which the lessee uses the Underlying asset. > illustrations > > Illustration of Lessor Accounting Example 1 illustrates how a lessor would account for sales-type leases and direct financing leases. > > > Example 1 Lessor Accounting Example > > > > Case A Lessor Accounting Sales-Type Lease Lessor enters 'into a 6-year lease of equipment with Lessee, receiving annual lease payments of $9,500, payable at the end of each year. Lessee provides a residual value guarantee of $13,000. Lessor concludes that it

2 Exhibit EL-2 Attachment 4 Page 145 of 191 is probable it will collect the lease payments and any amount necessary to satisfy the residual value guarantee provided by Lessee. The equipment has a 9-year estimated remaining economic life, a carrying amount of $54,000, and a fair value of $62,000 at the commencement date. Lessor expects the residual value of the equipment to be $20,000 at the end of the 6-year lease term. The lease does not transfer ownership of the underlying asset to Lessee or contain an option for Lessee to purchase the underlying asset. Lessor incurs $2,000 in initial direct costs in connection with obtaining the lease, and no amounts are prepaid by Lessee to Lessor. The rate implicit in the lease is percent Lessor classifies the lease as a sales-type lease because the sum of the present valbe of the lease payments and the present value of the residual value guaranteed by the lessee amounts to substantially all of the fair value of the equipment. None of the other criteria to be classified as a sales-type lease are met Lessor measures the net investment in the lease at $62,000 at lease, commencement, which is equal to the fair value of the equipment. The net investment in the lease consists of the lease receivable (which includes the 6 annual payments of $9,500 and the residual value guarantee of $13,000, both discounted at the rate implicit in the lease, which equals $56,920) and the present value of the unguaranteed residual value (the present value of the difference between the expected residual value of $20,000 and the residual value guarantee of $13,000, which equals $5,080). Lessor calculates the selling profit on the lease as $8,000, which is the difference between the lease receivable ($56,920) and the carrying amount of the equipment net of the unguaranteed residual asset ($54,000 $5,080 = $48,920). The initial direct costs do not factor into the calculation of the selling profit in this Example because they are not eligible for deferral on the basis of the guidance in paragraph (c) (that is, because the fair value of the underlying asset is different from its carrying amount at the commencement date) At the commencement date, Lessor derecognizes the equipment (carrying amount of $54,000) and recognizes the net investment in the lease of $62,000 and the selling profit of $8,000. Lessor also pays and recognizes the initial direct costs of $2,000 as an expense =23 At the end of Year 1, Lessor recognizes the receipt of a lease payment of $9,500 and interest on the net investment in the lease (the beginning balance of the net investment in the lease of $62,000 x the rate implicit in the lease of % = $3,400), resulting in a balance in the net investment of the lease of $55,900. For. disclosure purposes, Lessor also calculates, the separate components of the net investment in the lease: the lease receivable and the unguaranteed residual asset. The lease receivable equals $50,541 (the beginning balance of the lease receivable of $56,920 the annual lease payment received of S9,500 + the.amount of interest income on the lease receivable during Year 1 of $3,121, which is $56,920 x %). The unguaranteed residual asset equals $5,360 (the beginning balance of the unguaranteed residual asset of $5,081 + the

3 Exhilit EL-2 Attachment 4 Page 146 of 191 interest income on the unguaranteed residual asset during Year 1 of $279, which is $5,081 x %) At the end of Year 6, Lessor reclassifies the net investment in the lease, then equal to the 'estimated residual value of the underlying asset of $20,000, as equipment > > > > Case B Lessor Accounting Sales-Type Lease Collectibility of the Lease Payments Is Not Probable Assume the same facts and circumstances as in Case A (paragraphs through 55-24), except that it is not probable Lessor will collect the lease'payments and any amount necessary to satisfy the residual value guarantee provided by Lessee. In reaching this conclusion, the entity observes that Lessee's ability and intention to pay may be in doubt because of the following factors: a. Lessee intends to make the lease payments primarily from income derived from its business in which the equipment will bp used (which is a business facing significant risks because of high competition in the industry and Lessee's limited experience) b. Lessee has limited credit history and no significant other income or assets with which to make the payments if the business is not successful In accordance with paragraph , Lessor does not derecognize the equipment and does not recognize a net investment in the lease or any selling profit or selling loss. However, consistent with Case A, Lessor pays and recognizes the initial direct costs of $2,000 as an expense at the commencement date At the end of Year 1, Lessor reassesses whether it is probable it will collect the lease payments and any amount necessary to satisfy the residual value guarantee provided by Lessee and concludes that it is not probable. In addition, neither of the events in paragraph (b) has occufted. The contract has not been terminated and Lessor has not repossessed the equipment because Lessee is fulfilling the terms of the contract. Consequently, Lessor accounts for the $9,500 Year 1 lease payment as a deposit liability in accordance with paragraph Lessor recognizes depreciation expense on the equipment of $7,714 ($54,000 carrying value 4-7-!year useful life) Lessor's accounting in Years 2 and 3 is the same as in Year 1.,At the end of Year 4, Lessee makes the fourth $9,500 annual lease payment such that the deposit liability equals $38,000. Lessor concludes that collectibility of the lease payments and any amount necessary to satisfy the residual value guarantee provided by Lessee is now probable on the basis of Lessee's payment history under the contract and the 'fact that Lessee has been successfully operating its business for four years. Lessor does not reassess the classification of the lease as a sales-type lease

4 Exhibit EL-2 Attachment 4 Page 147 of Consequently, at the end of Year 4, Lessor derecognizes the equipment, which has a carrying amount of $23,143, and recognizes a net investment in the lease of $35,519. The net investment in the lease consists of the lease receivable (the sum of the 2 remaining annual payments of $9,500 and the residual value guarantee of $13,000, discounted at the rate implicit in 'the lease of percent determined at the commencement date, which equals $29,228) and the unguaranteed residual asset (the present value of the difference between the expected residual value of $20,000 and the residual value guarantee of $13,000, which equals $6,291). Lessor recognizes selling profit of $50,376, the difference between (a) the sum of the lease receivable and the carrying amount of the deposit liability ($29,228 lease receivable + $38,000 in lease payments already made = $67,228) and (b) the carrying amount of the equipment, net of the unguaranteed residual asset ($23,143 $6,291 = $16,852) After the end of Year 4, Lessor accounts for the remaining two years cif the lease in the same manner as any other sales-type lease. Consistent with Case A, at the end of Year 6, Lessor reclassifies the net investment in the lease, then equal to the estimated residual value of the underlying asset of $20,000, as equipment. > > > > Case C Lessor Accounting Direct Financing Lease Assume the same facts and circumstances as in Case A (paragraphs thrciugh 55-24), except that the $13,000 residual value guarantee is provided by a third party, not by Lessee. Collectibility of the lease payments and any amount necessary to satisfy the third party residual value guarantee is probable None of the criteria in paragraph to be classified as a sales-type lease are met. Lessor classifies the lease as a direct financing lease because the sum of the present value of the lease payments and the present value of the residual value guaranteed by the third party amounts to substantially all of the fair value of the equipment. In accordance with paragraph , the discount rate used to determine the present value of the lease payments and the guaranteed residual value ( percent) assumes that no initial direct costs will be deferred because, at the commencement date, the fair value of the equipment is different from its carrying amount At the commencement date, Lessor derecognizes the equipment and recognizes a net investment in the lease of $56,000, which is equal to the carrying amount of the underlying asset of $54,000 plus the initial direct costs of $2,000 that are included in the measurement of the net investment in the lease in accordance with paragraph (that is, because the lease is classified as a direct financing lease). The net investment in the lease includes a lease receivable of $58,669 (the present value of the 6 annual lease payments of $9,500 and the third-party residual value guarantee of $13,000, discounted at the rate implicit in the lease of percent), an unguaranteed residual asset of $5,331 (the present value of the difference between the estimated residual value of

5 Exhibit EL-2 Attaclmient 4 Page 148 of 191 $20,000 and the third-party residual value guarantee of $13,000, discounted at percent), and deferred selling profit of $8, Lessor calculates the deferred selling profit of $8,000 in this Example as follows: a. The lease receivable ($58,669); minus b. The carrying amount of the equipment ($54,000), net of the unguaranteed residual asset ($5,331), which equals $48,669; minus c. The initial direct costs included in the measurement of the net investment in the lease ($2,000) At the end of Year 1, Lessor recognizes the receipt of the lease payment of $9,500 and interest on the net investment in the lease of $4,624 (the beginning balance of the net investment in the lease of $56,000 x the discount rate that, at the commencement date, would have resulted in the sum of the lease receivable and the unguaranteed residual asset equaling $56,000, which is percent), resulting in a balance in the net investment of the lease of $51, Also at the end of Year 1, Lessor calculates, for disclosure purposes, the separate components of the net investment in the lease: the lease receivable, the unguaranteed residual asset, and the deferred selling profit. The lease receivable equals $51,895 (the beginning balance of the lease receivable of $58,669 the annual lease payment received of $9,500_+ the amount of interest income on the lease receivable during Year 1 of $2,726, which is $58,669 x 4.646%). The unguaranteed residual asset equals $5,578 (the beginning balance of the unguaranteed residual asset of $5,331 + the interest income, on the unguaranteed residual asset during Year 1 of $247, which is $5,331 x 4.646%). The deferred selling profit equals $6,349 (the initial deferred selling profit of $8,000 $1,651 recognized during Year 1 [the $1,651 is the difference between the interest income recognized on the net investment in the lease during Year 1 of $4,624 calculated in paragraph and the sum of the interest income earned on the lease receivable and the unguaranteed residual asset during Year 1]) At the end Of Year 2, Lessor recognizes the receipt of the lease payment of $9,500 and interest on the net investment in the lease (the beginning of Year 2 balance of the net investment in the lease of $51,124 x 8.258%, which is $4,222), resulting in a carrying amount of the net investment in the lease of $45, Also at the end of Year 2, Lessor calculates the separate components of the net investment in the lease. The lease receivable equals $44,806 (the beginning of Year 2 balance of $51,895 the annual lease payment received of $9,500 + the interest income eamed on the lease receivable during Year 2 of $2,411, which is $51,895 x 4.646%). The unguaranteed residual asset equals $5,837 (the beginning of Year 2 balance of the unguaranteed residual asset of $5,578 + the interest income eamed on the unguaranteed residual asset during

6 Exhibit EL-2 Attachment 4 Page 149 of 191 Year 2 of $259, which is $5,578 x 4.646%). The deferred selling profit equals $4,797 (the beginning of Year 2 balance of deferred selling profit of $6,349 $1,552 recognized during Year 2 [the $1,552 is the difference between'the interest income recognized on the net investment in the lease during Year 2 of $4,222 and the šum of the interest income earned on the lease receivable and the unguaranteed residual asset during Year 2]) At the end of Year 6, Lessor reclassifies the net investment in the lease, then equal to the estimated residual value of. the underlying asset of $20,000, as equipment. > > > > Case D Lessor Accounting Collectibility Is Not Probable Assume the same facts and circumstances as Case C (paragraphs through 55-39), except that collectibility of the lease payments and any amount necessary tó satisfy the residual value guarantee provided by the third party is not prqbable and the lease payments escalate every year over the lease term. Specifically, the lease payment due at the end of Year 1 is $7,000, and subsequent payments increase by $1,000 every year for the remainder of the lease term. Because it is not probable that Lessor will collect the lease payments and any amount necessary to satisfy the residual value guarantee provided by the third party in accordance with paragraph , Lessor classifies the lease as an operating lease Lessor continues to measure the equipment in accordance with Topic 360 on property, plant, and equipment Because collectibility of the lease payments is not probable, Lessor recognizes lease income only when Lessee makes the lease payments, and in the amount of those lease payments. Therefore, Lessor only recognizes lease income of $7,000 at the point in time Lessee makes the end of Year 1 payment for that amount At the end of Year 2, Lessor concludes that collectibility of the remaining lease payments and any amount necessary to satisfy the residual value guarantee provided by the third party is probable; therefore, Lessor recognizes lease income of $12,000. The amount of $12,000 is the difference between lease income 'that would have been recognized through the end of Year 2 ($57,000 in total lease payments ~ 6 years = $9,500 per year x 2 years = $19,000) and the $7,000 in lease income previously recognized. Collectibility of the remaining lease payments remains probable throughout the remainder of the lease term; therefore, Lessor continues to recognize lease income of $9,500 each year. 6. Add Subtopic , with a link to transition paradraph , as follows: [For ease of readability, the new Subtopic is not underlined.]

7 Exhibit EL-2 Attachment 4 Page 150 of 191 Leases Sale and Leaseback Transactions Overview and Background General This Subtopic addresses accounting, for sale and leaseback transactions when a lease has been accounted for in accordance with Subtopic and either Subtopic or Subtopic Scope and Scope Exceptions General This Subtopic follows the same Scope and Scope Exceptions as outlined in' the Overall Subtopic; see Section lf an entity (the seller-lessee) transfers an asset to another' entity (the buyer-lessor) and leases that asset back from the buyer-léssor, both the sellerlessee and the buyer-lessor shall account for the transfer contract and the lease in accordance with Sections , , and See paragraphs through for implementation guidance on the scope of this Subtopic. See Example 3 (paragraphs through 55-44) for an illustration of the scope of this Subtopic. Glossary Commencement Date of the Lease (Commencement Date) The date on which a lessor makes an underlying asset available for use by a lessee. See paragraphs through for implementation guidance on the commencement date. Contract An agreement between two or more parties that creates enforceable rights and obligations. Direct Financing Lease From the perspective of a lessor, a lease that meets none of the criteria in paragraph but meets the criteria in paragraph (b). Fair Value (second definition) The price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date

8 Exhibit EL-2 Attachment 4 Page 151 of 191 Finance Lease From the perspective of a lessee, a lease that meets one or more of the criteria in paragraph Lease A contract, or part of a contract, that conveys the right to control the use of identified property, plant, or equipment (an identified asset) for a period of time in exchange for consideration. Lease Payments See paragraph for what constitutes lease payments from the perspective of a lesšee and a lessor. Lease Term The noncancellable period for which a lessee has the right to use an underlying asset, together with all of the following: Lessee a. Periods covered by an option to extend the lease if the lesee is reasonably certain to exercise that option b. Periods covered by an option to terminate the lease if the lessee is reasonably certain not to exercise that option c. Periods covered by an option to extend (or not to terminate) the lease in which exercise of the option is controlled by the lessor. An entity that enters into a contract to obtain the right to use an underlying asset for a period of time in exchange for consideration. Lessor An entity that enters into a contract to provide the right to use an underlying asset for a period of time in exchange for consideration. Market Participants Buyers and sellers in the principal (or most advantageous) market for the asset or liability that have all of the following characteristics: a. They are independent of each other, that is, they are not related parties, although the price in a related-party transaction may be used as an input to a fair value measurement if the reporting entity has evidence that the transaction was ente-red into at market terms b. They are knowledgeable, having a reasonable understanding about the asset or liability and the transaction using all available information,

9 Exhibit EL-2 Attachment 4 Page 152 of 191 including information that might be obtained through due diligence efforts that are usual and customary c. They are able to enter into a transaction for the asset or liability d. They are willing to enter into a transaction for the asset or liability, that is, they are motivated but not forced or otherwise compelled to do so. Operating Lease From the perspective of a lessee, any lease other than a finance lease. From the perspective of a lessor, any lease other than a sales-type lease or a direct financing lease. Orderly Transaction A transaction filet assumes exposure to the market for a period before the measurement date to allow for marketing activities that are usual and customary for transactions involving such assets or liabilities; it is not a forced transaction (for example, a forced liquidation or distress sale). Related Parties Related parties include: a. Affiliates of the entity b. Entities for which investments in their equity securities would be required, absent the election of the fair' value dption under the Fair Value Option Subsection bf Section , to be accounted for by the equity method by the investing entity c. Trusts for the benefit of employees, such as pension and profit-sharing trusts that are managed by or under the trusteeship of management d. Principal owners of the entity and members of their immediate families e. Management of the entity and members of their immediate families f. Other parties with which the entity may deal if one party controls or can significantly influence the management or operating policies of the other to an extent that one of the transacting parties might be prevented from fully pursuing its own separate interests g. Other parties that can significantly influence the management or operating policies of the transacting parties or that have an ownership interest in one of the transacting parties and can significantly influence the other to an extent that one or more of the transacting parties might be prevented from fully pursuing its own separate interests. Residual Value Guarantee A guarantee made to a lessor`that the value of an underlying asset returned to the lessor at the end of a lease will be at least a specified amount

10 Exhibit EL-2 Attachment 4 Page 153 of 191 Sales-Type Lease From the perspective of a lessor, a lease that meets one or more of the criteria in paragraph Sublease A transaction in which an underlying asset is re-leased by the lessee (or intermediate lessor) to a third party (the sublessee) and the original (or head) lease between the lessor and the lessee remains in effect. Underlying Asset An asset that is the subject of a lease for which a right to use that asset has been conveyed td a lessee. The underlying asset could be a physically distinct portion of a single asset. Recognition Gene'ral > Determining Whether the Transfer of the Asset Is a Sale An entity shall apply the following requirements in Topic 606 on revenue from contracts with customers when determining whether the transfer of an asset shall be accounted for as a sale of the asset: a. Paragraphs through 25-8 on the existence' of a contract b. Paragraph on when an entity satisfies a performance obligation by transferring control of an asset The existence of a leaseback (that is, a seller-lessee's right to use the underlying asset for a period of time) does not, in isolation, prevent the buyerlessor from obtaining control of the asset. However, the buyer-lessor is not considered to have obtained control of the asset in accordance with the guidance on when an entity satisfies a performance obligation by transferring control of an asset in Topic 606 if the leaseback would be classified as a finance lease or a sales-type lease An option for the seller-lessee to repurchase the asset would preclude accounting for the transfer of the asset as a Sale of the asset unless both of the following criteria are met: a. The exercise price of the option is the fair value of the assefat the time the option is exercised. b. There are alternative assets, substantially the same as the transferred asset, readily available in the marketplace

11 Exhibit EL-2 Attachment 4 Page 154 of 191 > Transfer of the Asset Is a Sale If the transfer of the asset is a sale in accordance with paragraphs through 25-3, both of the following apply: a. The seller-lessee shall: 1. Recognize the 'transaction price for the sale at the point in time the buyer-lessor obtains control of the asset in acc6rdance with paragraph in accordance with the guidance on determining the transaction price in paragraphs through Derecognize the carrying amount of the underlying asset 3. Account for the lease in accordance with Subtopic b. The buyer-lessor shall account for the purchase in accordance with other Topics and for the lease in accordance with Subtopic > Transfer of the Asset Is Not a Sale If the transfer of the asset is not a sale in accordance with paragraphs through 25-3, both of the following apply: a. The seller-lessee shall not derecognize the transferred asset and shall account for any amounts received as a financial liability in accordance with other Topics. b. The buyer-lessor shall not recognize the transferred asset and shall account for the amounts paid as a receivable in accordance with other Topics. initial Measurement General > Transfer of the Asset Is a Sale An entity shall determine whether a sale and leaseback transaction is at fair value on the basis of the difference between either of the following, whichever is more readily determinable: a. The sale price of the asset and the fair value of the asset b. The present value of the lease payments and the present value of market rental payments If the sale and leaseback transaction is not at fair value, the entity shall adjust the sale price of the asset on the same basis the entity used to determine that the transaction was not at fair value in accordance with paragraph The entity shall account for both of the following: a. Any increase to the sale price of the asset as a prepayment of rent b. Any reduction of the sale price of the asset as additional financing provided by the buyer-lessor to the seller-lessee. The seller-lessee and

12 Exhibit EL-2 Attachment 4 Page 155 of 191 the buyer-lessor shall account for the additional financing in accordance with other Topics A sale and leaseback transaction is not off market solely because the sale price or the lease payments include a variable component. In determining whether the sale and leaseback transaction, is at fair value, the entity should consider those variable payments it reasonably expects to be entitled to (or to make) on the basis of all of the information (historical, current, and forecast) that is reasonably available to the entity. For a seller-lessee, this would include estimating any variable consideration to which it expects to be entitled in accordance with paragraphs through If the transaction is a related party lease, an entity shall not make the adjustments required in paragraph , but shall provide the required disclosures as discussed in paragraphs and See Examples 1 and 2 (Paragraphs through 55-38) for illustrations of the requirements for a sale and leaseback transaction. > Transfer of the Asset ls Not a Sale The guidance in paragraph notwithstanding, the sellerlessee shall adjust the interest rate on its financial liability as necessary to ensure that both of the following apply: a. Interest on the financial liability is not greater than the principal payments on the financial liability over the shorter of the lease term and the term of the financing. The term of the financing may be shorter than the lease term because the transfer of an asset that does not qualify as a,sale initially may qualify as a sale at a point in time before the end of the lease term. b. The carrying amount of the asset does not exceed the carrying amount of the financial liability at the earlier of the end of the lease term or the date at which control of the asset will transfer to the buyer-lessor (for example, the date at which a repurchase option expires if that date is earlier than the end of the lease term). Disclosure General If a seller-lessee or a buyer-lessor enters into a sale and lease4ck transaction that is accounted for in accordance with paragraphs and through 30-3, it shall provide the disclosures required in paragraphs thrdugh 50-9 for a seller-lessee or paragraphs through for a buyer-lessor

13 Exhibit EL-2 Attachment 4 Page 156 of In addition to the disclosures required by paragraphs through 50-9, a seller-lessee that enters into a sale and leaseback transaction shall disclose both of the following: a. The main terms and conditions of that transaction b. Any gains or losses arising from the transaction separately from gains or losses on disposal of other assets. Implementation Guidance and Illustrations General > Implementation GUidance > > Control of the Underlying Asset before the Commencement Date A lessee may obtain legal title to the underlying asset before that legal title is transferred to the lessor and the asset is leased to the lessee. If the lessee controls the underlying asset (that is, it can direct its use and obtain substantially all of its remaining benefits) before the asset is transferred to the lessor, the transaction is a sale and leaseback transaction that is accounted for in accordance with this Subtopic If the lessee obtains legal title, but does not obtain control of the underlying asset before the asset is transferred to the lessor, the transaction is not a sale and leaseback transaction. For example, this may be the case if a manufacturer, a lessor, and a lessee negotiate a transaction for the^ purchase of an asset from the manufacturer by the lessor, which in turn is leased to the lessee. For tax or other reasons, the lessee might obtain legal title to the underlying asset momentarily before legal title transfers to the lessor. In this case, if the lessee obtains legal title to the asset but does not control the asset before it is transferred to the lessor,- the transacfion is accounted for as a purchase of the asset by the lessor and a lease between the lessor and the lessee. > > Costs of the Lessee Relating to the Construction or Design of an Underlying Asset An entity may negotiate a lease before the underlying asset is available for use by the lessee. For some leases, the underlying asset may need to be constructed or redesigned for use by the lessee. Depending on the terms and conditions of the contract, a lessee may be required to make payments relating to the construction or design of the asset If a lessee incurs costs relating to the construction or design of an underlying asset before the commencement date, the lessee should account for those costs in accordance with other Topics, for example, Topic 330 on inventory or Topic 360 on property, plant, and equipment. Costs relating to the construction

14 Exhibit EL-2 Attachment 4 Page 157 of 191 or design of an underlying asset do not include payments made by the lessee for the right to use the underlying asset. Payments for the right to use the underlying asset are lease payments, regardless of the timing of those ipayments or the form of those payments (for example, a lessee might contribute construction materials for the asset under constructidn) If the lessee controls the underlying 'asset being constructed before the commencernent date, the transaction is accounted for in accordance with this Subtopic. Any one (or more) of the following would demonstrate that the lessee controls an unciehying asset that is under construction before the commencement date: a. The lessee has the right to obtain the partially constructed unclerlying asset at any point during the constructidn period (for example, by making a payment to the lessor). b. The lessor has an enforceable right to payment for its performance to date, and the asset does not have an alternative use (see paragraph ) to the owner-lessor. In evaluating whether the asset has an altemative use to the owner-lessor, an entity should consider the characteristics of the asset that will ultimately be leased. c. The lessee legally owns either: 1. Both the land and the property improvements (for example, a building) that are under construction 2. The non-real-estate asset (for example, a ship or an airplane) that is under construction. d. The lessee controls the land that property improvements will be constructed upon (this includes where the lessee enters into a transaction to transfer the land to the lessor, but the transfer does not qualify as a sale in accordance with paragraphs through 25-3) and does not enter into a lease of the land before the beginning of construction that, together with renewal options, permits the lessor or 'another unrelated third party to lease the land for substantially all of the economic life of the property improvements. e. The lessee is leasing the land that property improvements will be constructed upon, the term of which, together with lessee renewal cptions, is for substantially all of the economic life of the property improvements, and does not enter into a sublease of the land before the beginning of construction that, together with renewal options, permits the lessor oc another unrelated third party to sublease the land for substantially all of the economic life of the property improvements. The list of circumstances above in which a lessee controls an underlying asset that is under construction before the commencement date is not all inclusive. There may be other circumstances that individually or in combination demonstrate that a lessee controls an underlying asset that is under construction before the commencement date

15 Exhibit EL-2 Attachment 4 Page 158 of See Example 3 (paragraphs through 55-44) for an illustration of the scope of this Subtopic. > > Lessee indemnification for Environmental Contaminatioh A provision that requires lessee indemnifications for preexisting environmental contamination does not, on its own, mean that the lessee controlled the underlying asset before the lease commenced regardless of the likelihood of loss resulting from the indemnity. Consequently, the presence of such a provision does nof mean the transaction is in the scope of this Subtopic. > > Sale Subject to a Preexisting Lease An entity owns an interest in an underlying asset and also is a lessee Cinder an operating lease for all or a portion of the underlying asset. Acquisition of an ownership interest in the underlying asset and consummation of the lease oãcurred at or near the same time. This owner-lessee relationship,can occur, for example, when the entity has an investment in a partnership that owns the underlying asset (or a larger asset of which the underlying asset is a distinct portion). The entity subsequently sells ìts interest or the partnership sells the underlying asset to an independent third party, and the entity continues to lease the underlying asset under the preexisting operating lease A transaction should be subject to the guidance in this Subtopic if the scope or price of the preexisting lease is modified in connection with the sale. If the scope or the price of the preexisting lease is not modified in conjunction with the sale, the sale should be accounted for in accordance with other Topics A lease between parties under comnion control should not be considered a preexisting lease. Accordingly, the guidance in this Subtopic should be applied to transactions that include nonfinancial assets withinits scope, except if Topic 980 on regulated operations applies. That is, if one of the parties under common control is a regulated entity With a lease that has been approved by the appropriate regulatory agency, that lease should be considered a preexisting lease. > > Transfer of Tax Benefits A U.S. entity purchases an asset and enters into a contract with a foreign investor that provides that foreign investor with an ownership,right in, but not necessarily title to, the asset. That ownership right enables the foreign investor to claim certain benefits of ownership of the asset fdr tax purposes in the foreign tax jurisdiction The U.S. entity also enters into a contract in the form of a leaseback for the ownership right with the foreign investor. The contract contains a purchase option for the U.S. entity to acquire the foreign investors ownership right in the asset at the end of the lease term

16 Exhibit EL-2 Attachment 4 Page 159 of The foreign investor pays the U.S. entity an amount of cash on the basis of an appraised value of the asset. The U.S. entity immediately transfers a portion of that cash to a third party, and that third party assumes the U.S. entity's obligation to make the future lease payments, including the purchase option payment. The cash retained by the U.S. entity is consideration for the tax benefits to be obtained by the foreign investor in the foreign tax jurisdiction. The U.S. entity may agree to indemnify the foreign investor against certain future events that would redoce the availability of tax benefits to the foreign investor. The U.S. entity also may agree to indemnify the third-party trustee against certain future events The result of the transaction is that both the U.S. entity and the foreign investor have a tax basis in'the same depreciable asset An entity should determine whether the transfer of the ownership right is a sale based on the guidance in paragraphs ihrough Consistent with paragraphs through 25-3, if the leaseback for the ownership right is a finance lease or if the,u.s. entity has an option to repurchase the ownership right at any exercise price other than the fair value of that right on the exercise date, there is no sale. If the transfer of the ownership right is not a sale, consistent with the guidance in paragraph , the entity should account for the cash received from the foreign investor as a financial liability in accordance with other Topics If the transfer of the ownership right is a sale, income recognition for the cash received should be determined on the basis of individual facts and circumstances. Immediate income recognition is not appropriate if there is more than a remote possibility of loss of the cash consideration received because of indemnification or other contingencies The total consideration received by the U.S. entity is compensation for both the tax benefits and the indemnification of the foreign investor or other third-party trustee. The recognition of a liability for the indemnification agreement at inception in accordance with the guidance in Topic 460 on guarantees would reduce the amount of income related to the tax benefits that the seller-lessee would recognize immediately when the possibility of loss is remote. > > Sale-Leaseback-Sublease Transactions An entity enters into a sale and leaseback of an asset that meets. either of the following criteria: a. The asset is subject to an operating lease. b. The asset is subleased or intended to be subleased by the seller-lessee to another party under an operating lease A sale-leaseback-sublease transaction is within the scope of this Subtopic. The existence of the sublease (that is, the operating lease in paragraph (a) or (b)) does not, in isolation, prevent the buyer-lessor from

17 Exhibit EL-2 Attachment 4 Page 160 of 191 obtaining control of the asset in accordance with paragraphs through 25-3, nor does it prevent the seller-lessee from controlling the asset before its transfer to the buyer-lessor (that is, the seller-lessee is subject to the same requirements for determining whether the transfer of the asset is a sale as it would be without the sublease). All facts and circumstances should be considered in deterrnining whether the buyer-lessor obtains control of thé underlying asset from the seller-lessee in a sale-leaseback-sublease transaction. > > Seller-Lessee Guarantee ofthe Residual Value The seller-lessee may guarãntee to the lessor that the residual value will be a stipulated amount at the end of the lease term. If the transfer of the asset is a sale in accordance with paragraphs through 25-3, the seller-lessee residual value guarantee should be accounted for in the same manner as any other residual value guarantee provided by a lessee The residual value guarantee does not, ori its own, preclude accounting for the transaction as a sale 'and leaseback, but should be considered in evaluating whether control of the asset has transferred fo the buyer-lessor in accordance with paragraph For example, a significant residual value guarantee by the seller-lessee may affect an entity's consideration of the " transfer of control indicator in paragraph (d). > Illustrations > > Illustration of Sale and Leaseback Transaction Examples 1 and 2 illustrafe the accounting for sale and leaseback transactions. > > > Example 1 Sale and Leaseback Transaction An entity (Seller) sells a piece of land to an unrelated entity (Buyer) for cash of $2 million. Immediately before the transaction, the land has a carrying amount of $1 million. At the same time, Seller enters into a contract with Buyer for the right to use the land for 10 years (the leaseback), with annual payments of $120,000 payable in arrears. This Example ignores any initial direct costs associated with the transaction. The terms and conditions of the transaction are such that Buyer obtains substantially all the Temaining benefits of the land on the basis of the combination of the cash flows it will receive frorn Seller during the leaseback and the benefits that will be derived from the land at the end of the lease term. In determining that a sale occurs at commencement of the leaseback, Seller considers that, at that date, all of the following apply: a. Seller has a present right to payment of the sales price of $2 million. b. Buyer obtains legal title to the land. c. Buyer has the significant risks and rewards of ownership of the land because, for example, Buyer has the ability to sell the land if the property

18 Exhibit EL-2 Attachment 4 Page 161 of 191 value increases and also must absorb any losses, realized or unrealized, if the property value declines The observable fair value of the land at the date of sale is $1.4 million. Because the fair value of the land is observable, both Seller and Buyer utilize that benchmark in evaluating whether the sale is at market term. Because.the sale is not at fair value (that is, the sales price is significantly in excess of the fair value of the land), both Seller and Buyer adjust for the off-market terms in accounting for the transaction. Seller recognizes a gain of $400,000 ($1.4 million $1 million) on the sale of the land. The amount of the excess sale price of $600,000 ($2 million $1.4 million) is recognized as additional financing from Buyer to Seller (that is, Seller is receiving the additional benafit of financing from Buyer). Sellers incremental borrowing rate is 6 percent. The leaseback is classified as an operating lease At the commencement date, Seller derecognizes the land with a carrying amount of $1 million. Seller recognizes the cash received of $2 million, a financial liability for the additionalfinancing obtained froi-n Buyer of $600,000, and a gain on sale of the land of $400,000: Seller also recognizes a lease liability for the leaseback at the present value of the portion of the 10 contractual leaseback payments attributable to the lease of $38,479 ($120,000 contractual lease payment $81,521 of that lease payment that is attributable to the additional Buyer financing), discounted at the rate of 6 percent, which is $283,210, and a corresponding right-of-use asset of $283,210. The amount of $81,521 is the amount of each $120,000 annual payment that must be attributed to repayment of the principal of the financial liability for that financial liability to reduce to zero by the end of the lease term After initial recognition and measurement, at each period of the lease terrn, Seller will do both of the following: a. Decrease the financing obligation for the amount of each lease payment allocated to that obligation (that is, $81,521) and increase the carrying amount of the obligation for interest accrued using Sellers incremental borrowing rate of 6 percent. For example, at the end of Year 1, the balance of the financial obligation is $554,479 ($600,000 $81,521 + $36,000). b. Recognize the interest expense on the financing obliation (for example, $36,000 in Year 1) and $38,479 in operating lease expense At the end of the lease term, the financing obligation and the lease liability equal $ Also, at the commencement date, Buyer recognizes the land at a cost of $1.4 million and a financial asset for the additional financing provided to Seller of $600,000. Because the lease is an operating lease, at the date of sale E3uyer does not do any accounting for the lease

19 Exhibit EL-2 Attachment 4 Page 162 of In accounting for the additional financing to Seller, Buyer uses 6 percent as the applicable discount rate, which it determined in accordance with paragraphs through Therefore, Buyer will allocate $81,521-of each lease payment to Buyers financial asset and allocate the remaining $38,479 to lease income. After initial recognition and measurement at each period of the lease term, Buyer will do both of the following: a. pecrease the financial asset for the amount of each lease payment received that is allocated to that obligation (that is, $81,521) and increase the carrying amount of the obligation for interest accrued on the financial asset using Sellers incremental borrowing rate of 6 percent. Consistent with Sellers accounting, at the end of Year 1, the carrying amount of the financial asset is $554,479 ($600,000 $81,521 + $36,000). 101 Recognize the interest income on the financing obligation (for example, $33,269 in Year 2) and $38,479 in operating lease income At the end of the lease term, the carrying amount of the financial asset is $0, and Buyer continues to recognize the land. > > > Example 2 Accounting for a Failed Sale and Leaseback Transaction =31 An entity (Seller) sells an asset to an unrelated entity (Buyer) for, cash of $2 milliom Immediately before the transaction, the asset has a carrying amount of $1.8 million and has a remaining useful life of 21 years. At the same time, Seller enters into a contract with Buyer for the right to use the asset for 8 years with annual payments of $200,000 payable at the end of each year and no renewal options..sellers incremental borrowing rate at the date of the transaction is 4 percent. The contract includes an option to repurchase the asset at the end of Year 5 for $800, The exercise price of the repurchase option is fixed and, therefore, is not the fair value of the asset on the exercise date of the option. Consequently, the repurchase option precludes accounting for the transfer of the asset as a sale. Absent the repurchase option, there are no other factors that would preclude accounting for the transfer of the asset as a 'sale Therefore, at the commencement date, Seller accounts for the proceeds of $2 million as a financial liability and continues to account for the asset. Buyer accounts for the payment of $2 million as a financial asset and does not recognize the transferred asset. Seller accounts for its financing obligation, and Buyer accounts for its financial asset in accordance with other Topics, except that, in accordance with paragraph , Seller imputes an interest rate (4.23 percent) to ensure that interest on the financial liability is not greater than the principal payments on the financial liability over the shorter of the lease term and the term of the financing and that the carrying amount of the asset will not exceed the financial liability at the point in time the repurchase option. expires (that is, at the point in time Buyer will obtain control of the asset in accordance with the guidance on satisfying performance obligations in Topic 606). Paragraph

20 Exhibit EL-2 Attachment 4 Page 163 of does not apply to the buyer-lessor; therefore, Buyer recognizes interest income on its financial asset on the basis of the imputed interest rate determined in accordance with paragraphs through 25-13, which in this case Buyer determines to be 4 percent During Year 1, Seller recognizés interest expense of $84,600 (4.23% x $2 million) anq recognizes the payrrient of $200,000 as a reduction of the financial liability. Seller also recognizes depreciation expense of $85,714 ($1.8 million + 21 years). Buyer recognizes interest income of $80,000 (4% x $2 million) and recognizes the payment of $200,000 as a reduction of its financial asset At the end of Year 1, the carrying amount of Sellers financial lia'bility is $1,884,600 ($2 milfign + $84,600 $200,600), and the carrying amount of the underlying asset is $1,714,286 ($1.8 million $85,714). The carrying amount of Buyers financial asset is $1,880,000 ($2 million + $80,000 $200,000) At the end of Year 5, the option to repurchase the asset expires, unexercised by Seller. The repurchase option was the only feature of the arrangement that precluded accounting for the transfer of the asset as a sale. Therefore, upon expiration of the repurchase option, Seller recognizes the sale of the asset by derecognizing the carrying amount of the financial liability of $1,372,077, derecognizing the carrying amount of the underlying asset of $1,371,429, and recognizing a gain of $648. Buyer recognizes the purchase of the asset by derecognizing the carrying amount of its financial asset of $1,350,041 and recognizes the transferred asset at that same amount. The date of sale also is the commencement date of the leaseback for accounting purposes. The lease term is 3 years (8 year contractual leaseback term 5 years already passed at the commencement date). Therefore, Seller recognizes a lease liability at the present value of the 3 remaining contractual leaseback payments of $200,000, discounted at Sellers incremental borrowing rate at the contractually stated commencement date of 4 percent, which is $555,018, and a corresponding right-of-use asset of $555,018. Seller uses the incremental borrowing rate as of the contractual commencement date because that rate more closely reflects the interest rate that would have been considered by Buyer in pricing the lease The lease is classified as an operating lease by both Seller and Buyer. Consequently, in Year 6 and each year thereafter, Seller recognizes a single lease cost of $200,000, while Buyer recognizes lease income of $200,000 and depreciation expense of $84,378 on the underlying asset ($1,350, years remaining useful life) At the end of Year 6 and at each reporting date thereafter, Seller calculates the lease liability at the present value of the remaining lease payments of $200,000, discounted at Sellers incremental borrowing rate of 4 percent. Because Seller does not incur any initial direct costs and there are no prepaid or accrued lease payments, Seller measures the right-of-use asset at an amount equal to the lease liability at each reporting date for the remainder of the lease term. "

21 Exhibit EL-2 Attachment 4 Page 164 of 191 > > illustration of Guidance on Application of Costs of the Lessee Relating to the Construction or Design of an Underlying Asset Example 3 illustrates the guidance on determining whether a lessee contrdls an underlying asset that is under construction before the commencement date. > > > Example 3 Lessee Control over an Asset under Construction Lessee and Lessor enter into a contract whereby Lessor will construct (whether itself or using subcontractors) a building to Lessee's specifications and lease, that building to Lessee for a period of 20 years once construction is completed for an annual lease payment of $1,000,000, increasing by 5 percent per year, plus a percentage of any overruns above the budgeted cost to construct the building. The building is expected to have an economic life of 50 years once it is constructed. Lessee does not legally own the building and does not have a right under the contract to obtain the building while it is under construction (for example, a right to purchase the construction in process from Lessor). In addition, while the building is being developed to Lessees specifications, those specifications are not so specialized that the asset does not have an alternative use to Lessor. > > > > Case A Lessee Does Not Control the Asset under Construction Assume Lessee controls (that is, Lessee is the owner for accounting purposes) the land upon which the building will be constructed and, as part of the contract, Lessee agrees to lease the underlying land to Lessor for an initial period of 25 years. Lessor also is granted a series of six 5-year renewal options for the land lease None of the circumstances in paragraph exist. Even :though Lessee owns`the land (whether legally or for accounting purposes only) upon which the building will be constructed, Lessor legally owns the property improvements and has rights to use the underlying land for at least substantially all of the economic life of the building. Lessee does not own the building and does not have a right under the contract to obtain the building (for example, a. right to purchase the building from Lessor). In addition, the building has analternative use to Lessor. Therefore, Lessee does not control the building under construction. Consequently, the arrangement is not within the scope of this Subtdpic. Lessee and Lessor will account for the lease of the building in accordance with Subtopics and , respectively. If Lessee incurs costs related to the construction or design of the building (for example, architectural services in developing the 'specifications of the building), it will account for those costs as lease payments unless the costs are for goods or services provided to Lessee, in which case Lessee will account for those costs in accordance with other Topics

22 Exhibit EL-2 Attachment 4 Page 165 of 191 > > > > Case B Lessee Controls the Asset under Construction Assume Lessee leases, rather than owns, the land upon which the building will be constructed. Lessee has a 20-year lease of the underlying land and five 10-year renewal options. Therefore, Le'ssee's lease of the underlying land, together with the renewal options, is for at least substantially all of the economic life of the building under construction. Lessee enters into a sublease with Lessor for the right to use the underlying land for 20 years that commences upon completion of the building. The sublease has a single 10-year renewal option available to Lessor Lessee controls the building during the construction period and, therefore, the arrangement is within the scope of this Subtopic. Lessee and Lessor will apply the guidance in this Subtopic to determine whether this arrangement qualifies as a sale and a leaseback or whether this arrangement is, instead, a financing arrangement. Lessee controls the building during the construction period because, in accordance with paragraph (e), Lessee controls the use of the land upon which the building will be constructed for a period that is at least substantially all of the economic life of the building and the sublease entered into with Lessor does nbt both (a) grant Lessor the right to use the land before the beginning of construction and (b) permit Lessor to use the land for substantially all the economic life of the building (that is, the sublease, including Lessor renewal options, only is for 30 years as compared with the 50-year economic life of the building). 7. Add Subtopic , with a link to transition paragraph , as follows: [For ease of readability, the new Subtopic is not underlined.] Leases Leveraged Lease Arrangements Overview and Background General This Subtopic addresses accounting for leases that meet the definition of a leveraged lease. Scope and Scope ExcePtions General This Subtopic addresses accounting for leases that meet the criteria in transition paragraph (z). If a lessee exercises an option to extend a leaše that meets the criteria in transition paragraph (z). that it was not

23 Exhibit EL-2 Attachment 4 Page 166 of 191 previously reasonably assured of exercising, the exercise of that option shall be considered a lease modification as described in paragraph (z). Glossary Acquiree The business or businesses that the acquirer obtains control of in a business combination. This term also includes a nonprofit activity or business that a notfor-profit acquirer obtains control of in an acquisition by a not-for-profit entity. Acquirer The entity that obtains control of the acquiree. However, in a business combination in which a variable interest entity (VIE) is acquired, the primary beneficiary of that entity always is the acquirer. Acquisition by a Not-for-Profit Entity A transaction or other event in which a not-for-profit acquirer obtains control of one or more nonprofit activities or businesses and initially recogpizes their assets and liabilities in the acquirers financial statements. When applicable guidance in Topic 805 is applied by a not-for-profit entity, the term business combination has the same meaning as this term has for a for-profit entitjt. Likewise, a reference to business combinations in guidance that links to Topic 805 has the same meaning as a reference to acquisitions by not-for-profit entities. Business An integrated set of activities and assets that is capable of being conducted and managed for the purpose of providing a return in the form of dividends, lower costs, or other economic benefits directly to investors or other owners, members, or participants. Additional guidance op what a business consists of is presented in paragraphs =4 through ' Business Combination A transaction or other event in which an acquirer obtains control of one or more businesses. Transactions sometimes referred to as true mergers or mergers of equals also are business combinations. See also Acquisition by a Not-for-Profit Entity. Commencement Date of the Lease (Commencement Date) The date on which a lessor makes an underlying asset available for use by a lessee. See paragraphs through for implementation guidance on the commencement date

24 Exhibit EL-2 Attachment 4 Page 167 of 191 Contract An agreement between two or more parties that creates enforceable rights and obligations. Delayed Equity Investment In leveraged lease transactions that have been structured with terms such that the lessee's rent payments begin one to two years after lease inception, equity contributions the lessor agrees to make (in the lease agreement or a separate binding contract) that are used to service the nonrecourse debt during this brief period. The total amount of the lessors contributions is specifically limited by the agreements. Estimated Residual Value The estimated fair value of the leased property at the end of the lease term. Fair Value (second definition) The price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Lease A cofitract, or part of a contract, that conveys the right to control the use of identified property, plant, or equipment (an identified asset) for a period of time in exchange for consideration. Lease inception The date of the lease agreement or commitment, if earlier. For purposes of this definition, a commitment shall be in writing, signed by the parties in interest to the transaction, and shall specifically set forth the principal provisions of the transaction. If any of the principal provisions are yet to be negotiated, such a preliminary agreement or commitment does not qualify for purposes of this definition. Lease Modification A change to the terms and conditions of a contract that results in a change in the scope of or the consideration for a lease (fgr example, a change to the terms and conditions of the contract that adds or terthinates the right tó use one or more underlying assets or extends or shortens the contractual lease term). Lease Payments See paragraph for what constitutes lease payments from the perspective of a lessee and a lessor

25 Exhibit EL-2 Attachment 4 Page 168 of 191 Lease Term The noncancellable pariod for which a lessee has the right to use an underlying asset, together with all of the following: a. Periods covered by an option to extend the lease if the lessee is reasonably certain to exercise that option b. Periods covered by an option to terminate the lease if the lessee is reasonably certain not to exercise that option c. Periods covered by an option" to extend (or not to terminate) the lease in which exercise of the option is controlled by the lessor. Legal Entity Any legal structure used to conduct activities or to hold assets. Some examples of such structures are corporations, partnerships, limited liability companies, grantor trusts, and other trusts. Lessee An entity that enters into a contract to obtain the right to use an underlying asset for a period of time in exchange for consideration. Lessor An entity that enters into a contract. to provide the right to use an underlying asset for a period of time in exchange for consideration. Leveraged Lease From the perspective of a lessor, a lease that was classified as a leveraged lease in accordance with the leases guidance in effect before the effective date and for which the commencement date is before the effective date. Market Participants Buyers and sellers in the principal (or rnost advantageous) market for the aeset or liability that have all of the following characteristics: a. They are independent of each other, that is, they are not related parties, although the price in a related-party transaction may be used as an input to a fair value measurement if the reporting entity has evidènce that the transaction was entered into at market terms b. They are knowledgeable, having a reasonable understanding about the asset or liability and the transaction using all available information, including information that might be obtained through due diligence efforts that are usual and customary c. They are able to enter into a transaction for the asset or liability d. They are willing to enter into a transaction for the asset or liability, that is, they are motivated but not forced or otherwise compelled to do so

26 Exhibit EL-2 Attachment 4 Page 169 of 191 Minimum Lease Payments Minimum lease payments comprise the payments that the lessee is obligated to make or can be required to make in connection with the leased property, excluding both of the following: a. Contingent rentals b. Any guarantee by the lessee of the lessor's debt and the lessee's obligation to pay (apart from the rental payments) eiecutory costs such as insurance, maintenance, and taxes in connection with the leased property. If the lease contains a bargain purchase option, only the minimum rental payments over the lease term and the payment called for by the bargain purchase option are required to be included in the minimum lease payments. Otherwise, minimum lease payments include all of the following: a. The minimum rental payments called for by the lease over the lease term.. b. Any guarantee of the residual value at the expiration of the lease term, whether or not payment of the guarantee constitutes a purchase of the leased property or of rental payments beyond the lease term by the lessee (including a third party related to the lessee) or a third party unrelated to either the lessee or the lessor, provided the third party is financially capable of discharging the obligations that may arise from the guarantee. If the lessor has the right to require the lessee to purchase the property at termination of the lease for a certain or determinable amount, that amount is required to be considered a lessee guarantee of the residual value. If the lessee agrees to make up any deficiency below a stated amount in the lessor's realization of the residual value, the residual value guarantee to be included in the minimum lease payments is required to be the stated amount, rather than an estimate of the deficiency to be made up. c. Any payment that the lessee must make or can be required to make upon failure to renew or extend the lease at the expiration of the lease term, whether or not the payment would constitute a purchase of the leased property. Note that the definition of lease term includes all periods, if any, for which failure to renew the lease imposes a penalty on the lessee in an amount such that renewal appears, at lease inception, to be reasonably assured. If the lease term has been extended because of that provision, the related penalty is not included in minimum lease payments. d. Payments made before the beginning of the lease term. The lessee is required to use the same interest rate Ao accrete payments to be made before the beginning of the lease term that it uses to discount lease payments to be made during the lease term. e. Fees that are paid by the lessee tip the owners of the special-purpose entity for structuring the lease transaction. Such fees are required to be

27 Exhibit EL-2 Attachment 4 Page 170 of 191 included as part of minirnum lease payments (but not included in the fair' value of the leased property). Lease payments that depend on a factor directly related to the future use of the leased property, such as rnachine hours of use or sales volume during the lease term, are contingent rentals and, accordingly, are excluded from minimum lease payments in their entirety. However, lease payments that depend on an existing index or rate, such as the Consumer Price Index or the prime interest rate, are required to be included in minimum lease payments based on the index or rate existing at lease inception; any increases or decreases in lease payments that result from subsequent changes in the index or rate are contingent rentals and, thus, affect the determination of income as accruable. Not-for-Profit Entity An entity that possesses the following characteristics, in varying degrees, ttiat distinguish it from a business entity: a. Contributions of significant amounts of resources from resource providers who do not expect commensurate or proportionate pecuniary return b. Operating purposes other than to provide goods or services at a profit c. Absence of ownership interests like those of business entities. Entities that clearly fall outside this definition include the following: a. All investor-owned entities b. 'Entities that provide dividends, lower costs, or other economic benefits directly and proportionately 'to their ciwners, members, or participants, such as mutual insurance entities, credit unions, farm and rural electric cooperatives, and employee benefit plans. Orderly Transaction A transaction that assumes exposure to the market for a period before the measurement date to allow for marketing activities that are usual and customary for transactions involving such assets or liabilities; it is not a forced transaction (for example, a forced liquidation or distress sale). Related Parties Related parties include: a. Affiliates of the entity b. Entities for which investments in their equity securities would be required, absent the election of the fair value option under the Fair Value Option Subsection of Section , to be accounted for by the equity method by the investing entity

28 Exhibit EL-2 Attachment 4 Page 171 of 191 c. Trusts for the benefit of employees, such as pension and profit-shaiing trusts that are managed by or under the trusteeship of management - d. Principal owners of the entity and members of their immediate families e. Management of the entity and members of their immediate families f. Other parties with vtihich the entity may deal if one party controls or can significantly influence the management or operating policies of the other to an extent that one of the transacting parties might be prevented from fully pursuing its own separate interests g. Other parties that can significantly influence the management or operating policies of the transacting parties or that have an ownership interest in one of the transacting parties and 6an significantly influence the other to an extent that one or more of the transacting parties might be prevented from fully pursuing its own separate interests. Underlying Asset An asset that is the subject of a lease for which a right to use that asset has been conveyed to a lessee. The underlying asset could be a physically distinct portion of a single asset. Variable Interest Entity A legal entity subject to consolidation according to the provisions of the Variable Interest Entities Subsections of Subtopic Recognition General A lessor shall record its investment in aleveraged lease. The net of the balances of the following accounts as measured in accordance.with this Subtopic shall represent the lessors initial and continuing investment in leveraged leases: a. Rentals receivable b. Investment-tax-credit receivable c. Estimated residual value of the leased asset d. Unearned and deferred income. > Leveraged Lease Acquired in a Business Combination or an Acquisition by- a Not-for-Profit Entity In a business combination or an acquisition by a* not-for-profit entity, the acquiring entity shall retain the classification of the acquired entitys investment as a lessor in a leveraged lease at the date of the combination. The net investment of the acquired leveraged lease shall be disaggregated into its component parts, namely net rentals receivable, estimated residual value, and unearned income including discount to adjust other componentš to present value

29 Exhibit EL-2 Attachment 4 Page 172 of 191 Initial Measurement General A lessor shall initially measure its investment in a leveraged lease net of the nonrecourse debt (as discussed in paragraph ). The net of the balances of the following accounts shall represent the initial and continuing investment in leveraged leases: a. Rentals receivable, nét of that portion of the rental applicable to principal and interest on the nonrecourse debt. b. A receivable for the amount of the investment tax credit to be realized on the transaction. c. The estimated residual value of the leased asset. The estimated residual value shall not exceed the amount estimated at lease inception except if the lease agreement includes a provision to escalate minimum lease payments either for increases in construction or acquisition cost of the leased property or for increases in some other measure of cost or value (such as general price levels) during the construction or preacquisition period. In that case, the effect of any indreases that have occurred shall be considered in the determination of the estimated residual value of the underlying asset at lease inception. d. Uneamed and deferred income consisting of both of the following: I. The estimated pretax lease income (or loss), after deducting initial direct costs, remaining to be allocated to income over the lease term The investment tax credit remaining to be allocated to income over the lease term. > Leveraged Lease-Acquired in a Business Combination or an Acquisition by a Not-for-Profit Entity In a business, combination or an acquisition by a not-for-profit entity, the acquiring entity shall assign an amount to the acquired net investment. in the leveraged lease in accordance with the general guidance in Topic 805 on business combinations, based on the remaining future cash flows and giving appropriate recognition to the estimated future tax effects of those cash flows. Subsequent Measurement General > Leveraged Lease Acquired in a Business Combination or an Acquisition by a Not-for-Profit Entity

30 Exhibit EL-2 Attachment 4 - Page 173 of In a business combination or an acquisition by a not-for-profit entity, the acquiring entity shall subsequently account for its acquired investment as a lessor in a leveraged lease in accordance with the guidance in this Subtopic as it would for any other leveraged lease. > income Recognition on a Leveraged Lease The investment in leveraged leases minus deferred taxes arising from differences between pretax accounting income and taxable income shall represent the lessor's net investment in leveraged leases for purposes of computing periodic net income from the leveraged lease. Given the original investment and using the projected cash receipts and disbursements over the term of the lease, the rate of return on the net investment in the years in which it is positive shall be computed. The rate is that rate that, when applied to the net investment in the years in which the net investment is positive, will distribute the net income to those years and_is distinct from the interest rate implicit in the lease. In each year, whether positive or not, the difference between the net cash flow and the amount of inccime recognized, if any, shall serve to increase or reduce the net investment balance. The use of the term years is not intended to preclude application of the accounting prescribed in this paragraph to shorter accounting periods The net income (or loss) that a lessor recognizes on a leveraged lease shall be composed of the following three elements: a. Pretax lease income (or loss) b. Investment tax credit c. Tax effect of pretax lease income (or loss) The pretax lease income (or loss) and investment tax credit elements shall be allocated in proportionate amounts from the unearned, and deferred income included in the lessors net investment (as described in paragraph (d)). The tax effect of the pretax lease income (or loss) recognized shall be reflected in tax expense for the year. The 'tax effect of the difference between.pretax accounting income (or loss) and taxable income (or loss) for the year shall be charged or credited to deferred taxes lf, at any time during the lease term the application of the method prescribed in this Subtopic would result in a loss being allocated to future years, that loss shall be.recognized immediately. This situation might arige in circumstances in which one of the important assumptions affecting net income is revised (see paragraphs through 35-15). > > Changes in Assumptions Any estimated residual value and all other important assumptions affecting estimated total net income from the leveraged lease shall be reviewed at least annually. The rate of return and the allocation 'of income to positive investment years shall be recalculated from lease inception following the method

31 Exhibit EL-2 Attachment 4 Page 174 of 191 described in paragraphs through 35-4 and Using the revised assumption if, during the lease term, any of the following conditions occur: a. The estimate of the residual value is determined to be excessive, and the decline in the residual value is judged to be other,than temporary. b. The revision of another important assumption changes the estimated total net income frorn the lease. c. The projected timing of the income tax cash flows is revised The lessor shall update all assumptions used to calculate total and periodic income if the lessor is performing a recalculation of the leveraged lease. That recalculation shall include actual cash flows up to the date of the recalculation and projected cash flows following the date of recalculation The accounts constituting the net investment balance shall be adjusted to conform to the recalculated balances, and the change in the net investment shall be recognized as a gain or loss hi the year in which the assumption is changed. The gain or loss shall be re'cognized as follows: a. The pretax gain or loss shall be included in income from continuing operations before income taxes in the same line item in which leveraged lease income is recognized. b. The tax effect of the gain or loss shall be included in the income tax line item. c. An upward adjustment of the estimated residual value (including any guaranteed portion) shall not be made The projected timing of' income tax cash flows generated by the leveraged lease is an important assumption and shall be reviewed annually, or more frequently, if events or changes in circumstances indicate that a change in timing has occurred or is projected to occur. The income effect of a change in the income tax rate shall be recognized in the first accounting period ending on or after the date on which the legislation effecting a rate change becomes law A revision of the projected timing of the income tax cash flows applies only to changes or projected changes in the timing of income taxes that are directly related to the leveraged lease transaction. For example, a change in timing or projected timing of the tax benefits generated by a leveraged lease as a result of any of the following circumstances would require a recalculation because that change in timing is directly related to that lease: a. An interpretation of the tax law b. A change in the lessors assessment of the likelihood of prevailing in a challenge by the taxing authority c. A change in the lessors expectations about settlement with the taxing authority In contrast, as discussed in paragraph , a change in timing of incomelaxes solely as a result of an alternative minimum,tax credit or

32 Exhibit EL-2 Attachment 4 Page 175 of 191 insufficient taxable income of the lessor would not require a recalculation of a leveraged lease because that change in timing is not directly related to that lease. A recalculation would not be required unless there is an indication that the previous assumptions about total after-tax net iricome from the leveraged lease were no longer valid Tax positions shall be reflected in the lessors initial calculation or subsequent recalculation on the recognition, measurement, and derecognition criteria in paragraphs , , and The determination of when a tax position 'no longer meets those criteria is a matter of individual facts and circumstances evaluated in light of all available evidence If the lessor expects to enter into a settlement of a tax position relating to a leveraged lease with a taxing authority, the cash flows following the date of recalculation shall include projected cash flows between the date of the recalculation and the date of any projected settlement and a projected settlement amount at the date of the projected settlement The recalculation of income from the leveraged lease shall not 'include interest or penalties in the cash flows from the leveraged lease Advance payments and deposits made with a taxing authority shall not be considered an actual cash flow of the leveraged lease; rather, those payments and deposits shall be included in the projected settlement amount > Effect of Alternative Minimum Tax An entity shall include assumptions about the effect of the altemative minimum tax, considering its consolidated tax position, in leveraged lease computations Any difference between altemative minimum tax depreciation and the tax depreciation assumed in the leveraged lease or between income recognition for financial reporting purposes and altemative minimum tax income could, depending on the lessor's overall tax situation, result in alternative minimum tax or the utilization of alternative minimum tax credits If alternative minimum tax is paid or an alternative minimum tax credit is utilized, the total cash flows from the leveraged lease could be changed and the lessors net investment in the leveraged lease and income recognition would be affected If a change to the tax assumptions changes total estimated after-tax net income, the rate of return on the leveraged lease shall be recalculated from inception, the accounts constituting the lessors net investment shall be adjusted, and a gain or loss shall be recognized in the year in which the assumption is changed However, an entity whose tax position frequently varies between alternative minimum tax and regular tax shall not be required to recalculate the

33 Exhibit EL-2 Attachment 4 Page 176 of 191 rate of return on the leveraged lease each year unless there is an indication that the original assumptions regarding total after-tax net income from the lease are no longer valid. In n that circumstance, the entity shall be required to revise the leveraged lease computations in any period in which total net income from the leveraged lease changes because of the effect of the altemative minimum tax on cash flows for the lease. > Transfer of Minimum Rental Payments If a lessor sells substantially all of the minimum rental payments associated with a leveraged lease and retains an interest in the residual value of the leased asset, the lessor shall not recognize increases in the value of the lease residual to its estimated value over the remaining lease term. The' lessor shall report any remaining interest thereafter at its carrying amount at the date of the sale of the lease payments. If it is determined subsequently that the fair value of the residual value of the leased asset has declined below the carrying amount of the interest retained and that decline is other than temporary, the asset shall be written down to fair value, and the amount of the write-down shall be recognized as a loss. That fair value becomes the asset's new carrying amount, and the asset shall not be increased for any subsequent increase in its fair value before its sale or disposition. Other Presentation Matters General For purposes of presenting the investment in a leveraged lease in the lessor's balance sheet, the amount of related deferred taxes shall be presented separately (from the remainder of the net investrnent). In the income statement or the notes to that statement, separ6te presentation (from each other) shall be made of pretax income from the leveraged lease, the tax effect of pretax income, and the amount of investment tax credit recognized as income during the period. > income Taxes and Leveraged Leases Integration of the results of income tax accounting for leveraged leases with the other results of accounting for income taxes under Topic 740 on income taxes is required if deferred tax credits related to leveraged leases are the only source (see paragraph ) for recognition of a tax benefit for deductible temporary differences and carryforwards not related to leveraged leases. A valuation allowance is not necessary if deductible temporary differences and carryforwards will offset taxable amounts from future recovery of the net investment in the leveraged lease. However, to the extent that the amount of deferred tax credits for a leveraged lease as determined in accordance with this Subtopic differs from the amount of the deferred tax liability related to the

34 Exhibit EL-2 Attachment 4 Page 177 of 191 leveraged lease that would otherwise result from applying the guidance in Topic 740, that difference is preserved and is not a source of taxable income for recognition of the tax benefit of deductible temporary differences and operating loss or tax credit carryforwards This Subtopic requires that the tax effect of any difference between the assigned value and the tax basis of a leveraged lease at the date of a business -combination or an acquisition by a not-for-profit entity shall not be accounted for as a deferred tax credit. Any tax effects included in unearned and deferred income as required by this Subtopic shall not be offset by the deferred tax consequences of other temporary differences or by the tax benefit of operating loss or tax credit carryforwards. However, deferred tax credits that arise after the date of a combination shall be accounted for in the same manner as for leveraged leases that were not acquired in a combination. Disclosure General If leveraged léasing is a significant part of the lessor's businéss activities in terms of revenue, net income, or assets, the components of the net investment balance in leveraged leases as set forth in paragraph shall be disclosed in the notes to financial statements For guidance on disclosures about financing receivables, which indude receivables relating to a lessors rights to payments from leveraged leases, see the guidance beginning in paragraphs A, , and If accounting for the effect on leveraged leases of the change in tax rates results in a significant variation from the customary relationship between income tax expense and pretax accounting income and the reason for that variafion is not otherwise apparent, the lessor shall disclose the reason for that variation. implementation Guidance and Illustrations General > implementation Guidance > > Leveraged Lease involving an Existing Asset of a Regulated Entity Although the carrying amount of an asset acquired previously may not differ significantly from its fair value, it is unlikely that the two will be the s'ame. However, regulated utilities have argued that the carrying amounts of certain of

35 Exhibit ELL2 Attachment 4 Page 178 of 191 their assets always equal the fair value based on the utility's ability to recover that cost in conjunction with a franchise to sell a related service in a specified area. That argument is not valid when considering the value of the asset to a third-party purchaser that does not own that franchise. > > Delayed Equity Investment A delayed equity investment frequently obligates the lessor to make up the shortfall between rent and debt service in the first several years of the transaction. The type of recourse debt re'gulting from the delayed equity investment does not contradict the notion of nonrecourse and, therefore, does not preclude leveraged lease accounting as long as other requirements of leveraged lease accounting are met. Therlessors related obligation should be recorded as a liability at present value at lease inception Recognition of the liability would increase the lessor's net investment on which the lessor bases its pattern of income recognition. While the increase to the net investment results in an increase in income, it may be offset by the accrual of interest on the liability. > > Income Taxes Related to Leveraged Leases The accounting for income taxes related to leveraged leases set forth in this Subtopic is not consistent with the guidance in TOpic 740 on income taxes The integration of the results of accounting for income taxes related to leveraged leases with the other results of accounting for income taxes as required by Topic 740 is an issue if all of the following exist: a. The accounting for a leveraged lease requires recognition of deferred tax credits. b. The guidance in Topic 740 limits the recognition of a tax benefit for deductible temporary differences and carryforwards not related to the leveraged lease. c. Unrecognized tax benefits in this paragraph could offset taxable amounts that result from future recovery of the net investment in the leveraged lease. > Illustrations > > Example 1: Lessors Accounting for a Leveragdd Lease This Example illustrates a lessors accounting for a leveraged lease in accordance with the guidance in this Subtopic. It also illustrates one way of meeting.the disclosure requirements in paragraphs and as applied to a leveraged lease. The Example does not encompass all circumstances that may arise about leveraged leases; rather, the Example is based on a single instance of a leveraged lease. The elements of accounting and reporting illustrated for this Example of a leveraged lease are as follows:

36 Exhibit EL-2 Attachment 4 Page 179 of 191 a. Cash flow analysis by Years (see paragraph ) b. Allocation of annual cash flow to investment and income (see paragraph ) c. Journal entries for lessor's initial investment and first year of operation (see paragraph ) d. Financial statements including notes at end of second year (see paragraph ) e. Accounting for a revision in the estimated residual value of the leased asset assurried to occur in the eleventh year of the lease (from $200,000 to $120,000): 1. Revised allocation of annual cash flow to investment and income (see paragraph ) 2. Balances in investment accounts at beginning of the eleventh year before revised estimate (see paragraph' ) 3. Journal entries (see paragraph ) 4. Adjustment of invetment accounts (see paragraph ) This Example has the following terms and assumptions. Cost of leased asset (equipment) Lease term Lease rental payments Residual value Financing. Equity investment bylessor Long-term nonrecourse debt Depreciation allowable to leisor for income tax purposes Lessor's income tax rate (federal and state) investment taxcredit initial direct costs $1,000, years, dating from January 1, 1975 $90,000 per year (payable last day of each year) $200,000 estimated to be realbed 1 year after lease termination; in the eleventh year of the lease the estimate is reduced to $120,000 $400,000 $600300, bearing interest at 9% and repayable in annual installments (on last day of each year) of $74, year asset depreciation range life using double-declining-balance method for the first 2 years (with the half-year convention election applied in the first year) and sum-of-years digits method for remaining life, depreciated to $100,000 salvage value 50.4% (assumed to continue in existence throughout the terrii of the lease) 10% of equipment cost or $100,000 (realized bythe lessor on last day of first year of lease) For simplicity, initial direct costs have not been included in the illustration

37 Exhibit EL-2 Attachment 4 Page 180 of Cash flow analysis by years follows. Year Gross Lease Rentals and Residual Value 2 Depreciation (for income Tax Purposes) 3 Loan Interest Payments 4 Taxable Income (Loss) (Col ) 5 Income Tax Credits (Charge') (Col %) 6 Loan Principal Payments 7 Investment Tax Credtt Realized a Annual Cash Row (Col ) Cum ubtive Cash Row initial Investment - - 5(400,000) $ (400,000) 1 $ 90,000 $ 142,857 $ $(106,857) $, 53,856 $ $ 100, (230,579) 2 90, ,898 52,161 (207,059) 104, ,923 (110,656) 3 90, ,075 50,156 (147,231) 74,204 24,279 89,769 (20,887) 4 90, ,061 47,971 (111,032) 55,960 26,464 71,525 50, , ,048 45,589 (74,637) 37,617 28,846 53, , ,000 53,061 42,993 (6,054) 3,051 31,442 18, , , ,163 49,837 (25,118) (9,553) 112,883 a 90,000 37,079 52,921 (26,672) 37,357 (11,108) 101, ,717 56,263 (28367) 40,719 (12,803) 88, ,000 30,052 59,948 (30,214) 44,383 (14,649) 74, ,000 26,058 63,942 (32,227) (16,663) 57, ,000 21,704 68,296 (34,421) '52,732 (18,857) 38, ,000 16,957 73,043 (36,813) 57,478 (21,248) 17, ,000-11, (39,420) ' (23,856) (6,301) 15 90,000 6,145 83,855 (42,263) 68,290 (26,698) (32,999) , , ,000 (50 400) ,601 Totals $1,55C,000 $ 1 000, ,530 $ 33,470 5 (16,869) 5600,000 $ 100,000 $ Allocation of annual cash flow to investment and income follows Annual Cash Row Components of income 1.4 Lessoes Net Total investment at (from Co(. 8 Tax Effect Beginning of of Paragraph Allocated to Allocated to Pretax of Pretax Investment Year Year ) investment income ts) Income Income Tax Credit 1 $ 400,000 $ 169,421 $ 134,833 $ $ 9,929 $ (5,004) $ 29, , ,923 96, (3,317) 19, ,173 89,769 75,227 14,542 4,174 (2,104) ,946 71,525 63, ,307 (1,163) 6, A58 53,182 50,635 2, (366) 2,184 6 (21,177) 18,616 18,616 _ 7 (39 793) (9,553) (9,553) 8 (30 240) (11,108) (11,108) 9 (19,132) (12,803) (12,803) 10 (6,329) (14,649) (14,649) 11 8,320 (15,663) (17,382) (104) ,702 (18557) (21,079) 2, (321) ,031 (21,248) (25,293) 4,045 1,161 (585) 3, ,074 (23,856) (30,088) 6,232 1,789 (902) 5, ,162 (26,698) (35,532) 8,834 2,536 (1,278) 7, , ,694 11,906 3,418 (1,723) 10,211 Totals $ 516,601 $ 400,000 $ 116, ,470 $ (16,869) S 100,000 (a) Lease income s recognized as S' ofthe unrecovered investment at the beginning of each year in which the net investment is positnie The rata is that rate which, if applied to the net investment in the years in which the net investment positii.e will distnbute lhe net income (net cash flow) to those years (b) Each component IS allocated among the years of positive net investment in proporbon to the allocaton of net income in column

38 Exhibit EL-2 Attachment 4 Page 181 of illustrative joumal entries for the year ending December 31, 1975, follow. Lessors Initial Investment De bit Credit Rentals receivable (table in paragraph , total of column 1 minus residual value, minus totals of columns 3 and 6) $ 233,470 Investment tax credit receivable (table in paragraph , colurnn 7) 100,000 Estrnated residual value (paragraph ) 200,000 Unearned and deferred income (table in paragraph , totals of columns 5 and 7) $133,470 Cash 400,000 Record lessors initial investment First Year of Operation Journal Enfry Cash. 15,565 Rentals receivable (table in paragraph , column 1 rn mus columns 3 and 6) 15,565 Collection of first years net rental Journal Entty 2 Cash (4 100,000 Investment taxcredit receivable (table in paragraph , column 7) 100,000 Recei pt of investm ent tax credit Journal Entry 3 Unearned and deferred income 9,929 Income from leveraged leases (table in paragraph , column 5) 9,929 Recognition of first years porbon of pretax income allocated in the same proportion as the allocation of total income 1,34, ,601).33,470 = 9,929 Joumal Entry 4 Unearned and deferred income 29,663 Imestmenttax credit recognized (table in paragraph , column 7) 29,663 Recognition of first years portion of investment tax credit allocated in the same proportion as the allocation of total income (34, ,601).100,000 = 29,663 Joumal Enfry 5 Cash (table in paragraph , column 5) (0 53,856 Income tax evense (table in paragraph , column 6) 5,004 Deferred taxes To record receipt of first years tax credit from lease operation, to charge income thx expense for tax effect of pretax accounting income, and to recognize as deferred taxes the taxeffect of the difference between pretax accounting income and the tax loss for the year, calculated as follows Tax loss (table in paragraph , column 4) $(106,857) Pretax accountng income 9,929 Difference $( ) Deferred taxes ($116, %) $ ,860 ' (a) Receipts of the imestment tax credit a nd other tax benefits are shown as cash receipts for sim plicity only Those receipts probably would not be in the form of immediate cash inflow Instead, they likelywould be in the form of reauced payments of taxes on other income of the lessor or on the combined income of the lessor and other entities whose operations are Joined Aith the lessors operatons in a consolidated tax return,

39 Exhibit EL-2 Attachment 4 Page 182 of The following are illustrative partial financial statements including notes. BALANCE SHEET ASSETS LIABILITIES December 31, December 31, Investment in Defared taxes arising leveraged leases $334,708 $324,027 from leveraged leases $166,535 $ 58,860 INCOME STATEMENT (lgnonng all income and expense items other than those relating to leveraged leasing) !nom e torn leveraged leases 6,582 $ 9929 income bebre taxes and imestmen t tax credit 6,582 9,929 Less income tax expense ('') (3,317) (5 004) 3,265 4,925 investment tax credit recognized (a, 19, Net incorn e $ 22,929 $ i1111i C (a) Theše two items rn ay be netted for purposes of presentabon m the income statern ent, provided that the separate amounts are disclosed in a note to financial statements The following are notes to the illustrative financial statements included in this Example. Investment in Leveraged Leases Entity is the lessor in a leveraged lease agreement entered into in 1975 under which mining equipment having an estimated economic life of 18 years was 'leased for a term of 15 years. Entity's equity investment represented 40 percent of the purchase price; the remaining 60 percent was fumished by third-party financing in the form of long-term debt that provides for no recourse against Entity and is secured by a first lien on the property. At the end of the lease term, the equipment is turned back to Entity. The residual value at that time is estimated to be 20 percent of cost. For federal income tax purposes, Entity receives the investment tax credit and has the benefit of tax deductions for depreciation on the entire leased asset and for interest on the long-term debt. During the early years df the lease, those deductions exceed the lease rental income, and substantial excess deductions are available to be applied against Entitys other income. In the later years of the lease, rental income will exceed the deductions and taxes will be payable. Deferred taxes ai-e provided to reflect this reversal. Entitys net investment in leveraged leases is composed of the following elements

40 Exhibit EL-2 Attachment 4 Page 183 of 191 Rentals receivable (net of pnncipal and interest on the nonrecourse debt) Estimated residual value of leased assets Less' Unearned and deferred income investment in leveraged leases Less. Deferred taxes arising from leveraged leases Net investment in leveraged leases December 31, $ 202,340 $ 217, , ,000 (67,632) (93,878) ' 334, ,027 (166,535) (58,860) $ 168,173 $ 265, Allocation of annual cash flow to investment and income follows, revised to include new residual value estimate Annual Cash Row Components of income Lessor's Net Allocated Tax Effect investment at to Allocated to PretaX of Pretax In4stment Year Beginning of Year Total investment Income 111 Loss Loss Tax Credit 1 $ $ 169, ,458 $ 26,963 $ (16,309) $ 8,220 $ , ,360 (10,501) 5,293 22, ,979 89,769 79,323 10,446 (6,319) 3,164 13, ,656 71,525 66,425 5,100 (3,085) , , , (377) ' (43329) 18,616 18,616 7 (61,945) (9 553) (9553) 8 (52 392) (11,108). (11,108) 9 r' (41284) (12 803) (12,803) 10 (28,481) (14,649) (14549) 11 (13,832) (16 663) (16,663) (18 857) (19,048) 191 (115) ,879 (21248) (22,723) 1,475 (892) 450 ", (23556) (26562) 3906 (1,819) 916 3, ,464 (26598) (31515) 4,817 (Z914) 1,469 6, , ,979 6,941 (4,199) 2,116 9,024 Totals $ 476, ,000 $ 76,921 $ (46530) $ 23,451 $ (a) The revised allocation rate is A,

41 Exhthit EL-2 Attachment 4 Page 184 of Balances / in investment accounts before revised estimate of residual value follow Unearned and Deferred Income -6 7 Rentals Receivable (I Estimated Residual Value Investment Tax Credit Receivable Pretax Income (Loss) P) Investment Tax Credit (q Deferred Taxes I4) Net investment (Col ) less (Col ) Initial investment $ 233, ,000 $ 1 cos= $ 33,470 $ 100,000 $ $ 400,000 Changes m war of operabon 1 (15,565) (100,000) (9,929) (29,663) 58,860 (134,833) 2 (15,565) (6,582) (19,664) 107,675 (96,994) 3 (15,565) (4,174) (12,472) 76,308 (75,227) 4 (15,565) (2,307) (6,893) 57,123 (63,488) 5 (15565) (731) (2 184) 37,985 (50,635) 6 (15,565) '3,051 (18 616) 7 (15,565) (25,118) 9,553 8 (15,564) (26,672) 11,108 9 (15,564) (28,367) 12, (15,565) (30,214) 14,649 Balances, beginning of eleventh year $ 77,822 $ $ S 9,747 $ 29, ,631 $ 8,320 (a) Table in paragraph , column 1, excluding residual value, minus columns 3 and 6 (b) Table in paragraph , =lumn 5. (c) Table in paragraph , column 7 1. (d) of difference between taxable income (loss) in column 4 of the table in paragraph and pretax accounting income (loss) in column 5 of the table in paragraph

42 Exhibit EL-2 Attachment 4 Page 185 of Illustrative journal entries invomng a reduction in residual value follow. Joumal Enfry 1 Pretax income (or loss) Unearned and deferred income Pretax income (loss): Balance at end of tenth year $ 9,747 Revised balance (9,939) (b) Adjustment (19,686) Deferred investment tax credit Balance at end of tenth year 29,124 (`) Revised balance 21,360 (` Adjustrnent (7,764) Investrnenttaxcredit recognized Estimated residual value To record: a. The cumulative effect on pretax income and the effect on future income resulting frorn the decrease in estimated residual value: b Reduction in estimated residual value Less portion attributable to future years (unearned and deferred income) Cumulative effect (charged against current income) The cumulative and future effect of the change in allocation of the investment tax credit resulting from the reduction in estimated residual elue Debit $ 60,314 27,450 Credit $ 7,764 80,000 $80,000 (19,686) $60,314 Joumal Entry 2 Deferred taxes Income tax expense To recognize deferred taxes for the difference between pretax accounting income (or loss) and taxable income (or loss) forthe effect of the reduction in estimated residual value: Pretax accounting loss per Journal Entry 1 Tax income (or loss) Difference $(60,314) $(60,314) 30,398 30,398 Deferred taxes ($60,314 x 50.4%) $(30,398) (a) Table in paragraph , column 4. (b) Table in paragraph , total of column 5 minus amounts applicable to the first 10 years. (c) Table in paragraph :13, column 5. (d) Table in paragraph , total of column 7 minus amounts applicable to the first 10 years

43 Exhibit EL-2 Attachment 4 Page 186 of Adjustment of investment accounts for revised estimates of residual value follows Unearned and Deferred income l kt Investment Balances, beginning of eleventh year (table m paragraph ) Adjustmentof estimated residual value and unearned and deferred income (table in paragraph , Journal Enty 1) Adjustment of deferred taxes for the cumulative effect on pietax accounting income (table in paragraph , Journal Entry 2) Adjusted balances, beginning of eleventh year Estimated Pretax (CoL 1 + 2) Rentals Residual Income Investment Deferred less (Col. 3 Receivable Value (Loss) Tax Credit Taxes +4 +5) $ 77,822 $200,000 $ 9,747 $ 29,124 $230,631 $ 8,320 (80,000) (19,686) (7,764) (52,550) (30,398) 30,398 $ 77,822 $120,000 $(9,939) $ 21,360 $200,233 $ (13,832) (4 (a) Table in paragraph , column 1 > > Example 2: income Taxes Related to a Leveraged Lease This Example illustrates integration of the results of a lessor's income tax accounting for leveraged leases (in accordance with the guidance in this Subtopic) with the other results of accounting for income taxes as required by Topic At the end of Year 1 (the current year), an entity has two temporary differences The first temporary difference is for a leveraged lease that was entered into in a prior year. During Year 1, the enacted tax rate for Year 2 and thereafter changes from 40 percent to 35 percent After adjusting for the change in estimated total net income from the lease as a result of the change in tax rates, the components of the investment in the leveraged lease at the end of Year 1 are as follows

44 Exhibit EL-2 Attachment 4 Page 187 of 191 Net rentals receivable plus residual value minus unearned pretax income $ 150,000 Reduced by: Deferred investment tax credit $9,000 Deferred tax credits 39,000 48,000 Net investment in leveraged lease for financial reporting $ 102, The second temporary difference is a $120,000 estimated liability for warranty expense that will result in a tax deduction in Year 5 when the liability is expected to be paid. Absent consideration of the deferred tax credits attributable to the leveraged lease, the weight of available evidence indicates that a valuation allowance is needed for the entire amount of the deferred tax asset related to that $120,000 deductible temporary difference The tax basis of the investment in the leveraged lease at the end of Year 1 is $41,000. The amount of the deferred tax liability for that leveraged lease that would otherwise result from the application of guidance in Topic 740 on income taxes is determined as follows. Net rentals receivable plus residual value minus unearned pretax income $ 150,000 Temporary difference for deferred investment tax credit 9,000 Tax basis of leveraged lease Tem porary difference Deferred tax liability (35 percent) 141,000 41,000 $ 100,000 $ 35, Loss carryback (to Year 2) and loss carryforward (to Year 20) of the $120,000 tax deduction for warranty expense in Year 5 would offset the $100,000 of taxable amounts resulting from future recovery of the net investment in the leveraged lease over the remainder of the lease term At the end of Year 1, the entity recognizes a $42,000 ($120,000 at 35 percent) deferred tax asset and a related $7,000 valuation allowance. The effect is to recognize a $35,000 net deferred tax benefit for the reduction in deferred tax credits attributable to the leveraged lease. Deferred tax credits attributable to the leveraged lease determined under the guidance in this Subtopic are $39,

45 Exhibit EL-2 Attachment 4 Page 188 of 191 However, the deferred tax liability determined is only $35,000. The $4,000 difference is not available for offsetting. > > Example 3: Effect of Advance Payments and Deposits on Recalculation bf a Leveraged Lease This Example illustrates how (in accordance with the guidance in paragraph and other paragraphs) a lessor would include advance payments and deposits in a recalculation of a leveraged lease resulting from a determination by the lessdr that it would enter into a settlement of a tax position arising from a leveraged lease This Example assumes that the lessor has concluded that the position originally taken on the tax return would meet the more-likely-than-not threshold in Subtopic on income taxes. It also assumes that the lessor would conclude that the estimate of $50 for the projected lease-in, lease-out settlement is consistent with the measurement guidance in that Subtopic A lessor makes an advance payment of $25 on July 1, 2007, $10 of which is estimated to be associated with issues arising from a lease-in, lease-out transaction.-on July 1, 2007, the lessor changes its assumption about the timing of the tax cash flows and projects a settlement with the Internal Revenue Service on September 1, The projected settlement would resplt in a payment to the taxing authority of $125 of which $50 is associated with the lease-in, lease-out transaction. On July 1, 2007, when the lessor recalculates the leveraged lease, the lessor would include a $50 cash flow on September 1, 2009, as a projected outflow in the leveraged lease recalculation. > > Example 4: Léveraged Lease Acquired in a Busines:i Combination or an Acquisition by a Not-for-Profit Entity This Example illustrates one way that a lessors investment in a leveraged lease might be valued by the acquiring entity in a business combination or an acquisition by a not-for-profit entity and the subsequent accounting for the investment in accordance with the guidance in this Subtopic. The elements of accounting and reporting illustrated for this Example are as follows: a. Acquiring entity's cash flow analysis by years (see paragraph ) b. Acquiring entity's valuation of investment in the leveraged lease (see paragraph ) c. Acquiring entity's allocation of annual cash flow t6 investment and income (see paragraph ) d. Joumal entry fol:, recording allocation of purchase price to net investment in the leveraged lease (see paragraph ) e. Journal entries for the year ending December 31, 1984 (Year 10 of the lease) (see paragraph )

46 Exhibit EL-2 Attachment 4 Page 189 of This Example has the following terms and assumptions. Cost of leased asset (equipment) Lease term Lease rental payments Residual value Financing Equity investment by lessor Long-term nonrecourse debt Depreciation allowable to lessor for income tax purposes Lessees income tax rate (federal and state) Investment tax credit Initial direct costs Date of business combination Tax status of business combination Appropriate interest rate for valuing net-of-tax retum on investment $1,000, years, dating from January 1, 1975 $90,000 per year (payable last day of each year) $200,000 estimated to be realized 1 year after lease termination $400,000 $600,000, bearing interest at 9% and repayable in annual installments (on last day of each year) of $74, year asset depreciation range life using double-declining-balance method for the first 2 years (with the half-year convention election applied in the first year) and sum-of-years digits method for remaining life, depreciated to $100,000 salvage value 50.4% (assumed to continue in existence throughout the term of1he lease) 10% of equipment cost or $100,000 (realized by the lessor on last day of first year of lease) For simplicity, initial direct costs have not been included in the illustration January 1, 1982 Nontemble transaction 414% Acquiring entity's cash flow analysis by years follows. Year Gross Lease Rentals and Res klual Value Depreciation (for income Tax Purposes) Loan Interest Payments Taxable income (Col ) income Tax (Charges) (CoL 4 5oftq Loan Principal Payments Annual Cash Row (Cot ) 8.$ 90,000 $ 37,079 $ 52,921 $ (26,672) $ 37,357 $ (11,108) 9 90,000 03,717 56,283 (28,367) 40,719 (12,803) 10 90,000 30,052 59,948 (30,214) 44,383 (14,649) 11 90,000 26,058 63,942 (32,227) 48,378 (16,663) 12 90,000 21,704 68,296 (34 421) 52,732 (18,857) 13 90,000 16,957 73,043 (36,613) 57,478 (21,248) 14 90, ,215 (39,420) 62,651 (23.856) 15 90,000 6,145 83,855 (42,263) 68,290 (26,698) ,000 $ 140, ,000 (50,400) 149,600 Totals S 920,000 $ $183,497 $ 636,503 $ (320,797) $ , MIIIMMIONNIMOIM

47 Exhibit EL-2 Attachment 4 Page 190 of Acquiring entitys valuation of investment in the leveraged lease follows. Cash Flow Present Value at 414% Net-of-Tax Rate 1. Rentals receivable (net of principal and interest on the nonrecourse debt) ($15, at ihe end of each year for 8 years) $ 102, Estimated residual value ($200,000 realizable atthe end of 9 years) 134, Future tax payments (various amounts payable over 9 years see the table in paragraph ) (253,489) Net present value $ (16,245) Acquiring entitys allocation of annual cash flow to investment and income follows (see footnote (a)). 2 3 Annual Cash flow Components of Income 110 Total from Col 7 of the Table in Net Investment at Paragraph Allocated to Allocated to Pretax Tax Effect of Year Beginning of Year Investment Income 14 Income Pretax Income 8 $ (16,245) $ (11,108) $ (11,108) 9 (5,137) (12,803) (12603) ,666 (14,649) (14,973) $ 324 $ 5,530 5 (5,206) 11 22,639 (16,663) (17,621) ,353 (15,395) 12 40,260 (18,857) (20,561) 1,704 29,087 (27,383) (21,248) (23622) 2,574 43,937 (41,363) (23,856) (27,439) 3,583 61,160 (57,577) ,082 (26,698) (31,443) 4,745 80,995 (76,250) , , ,525 6, ,698 (97,623) Totals $ 3,718 $ (16,245) $ 19, ,760 $ (320,797) (a) Lease income is recogramd as 4 233% of the unrecovered investment at the beginning of each year in which the net investment is positve The rate is that rate which, if applied to the net investnent in the years in which the net investment is posith.e, will distribute the net income (net cat h low) to those years (b) Each component is allocated among the years of posibie net Investment in proportion to lhe allocaton of net income in column 4 Journal Entry 2 in the table in paragraph includes an example of this computation illustrative joumal entry for recording allocation of purchase price to net investment in the leveraged lease follows. Rentals receivable (table in paragraph , total of column 1 minus res)dual value, minus totals of columns 3 ahd 6) $ 124,515 Estimated residual value (paragraph ) 200,000 Purchase price allocation cleanng account (paragraph , present value) 16,245 Unearned and deferred income (paragraph , present value, rninus total of rentals receivable and estimated residual value) $ 340,

48 Exhibit EL-2 Attachment 4 Page 191 of Illustrative journal entries for year ending December 31, 19Y4, follows. Third Year of Operation after the Business Combination (Year 10 of the Lease) Journal Entry 1 Cash Rentals receivable (table in paragraph , column 1 minus columns 3 and 6) Collection of years net rental Journal Entry 2 Unearned and deferred income Income from leveraged leases (table in paragraph , column 5) Recognition of pretax income for the year allocated' in the same proportion as the allocation of total income computed as follows: ([$324 + $19,963] x $340,760 = $5,530) Journal Entry 3 Deferred taxes (table in paragraph , column 5, minirs table in paragraph , column 6) Income taxexpense (table in paragraph , column-6) Cash (table in paragraph , column 5) To record payment of taxfor the year $15,565 $ 5,530 $25,008 5,206 $15,565 $ 5,530 $30,

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50 A, STANDARD &POOR'S RATINGS SERVICES McGRAW HILL FINANCIAL Exhibit EL-2 Attachment 5 Page 1 of 23 RatingsDirect Criteria l Corporates l Utilities: Key Credit Factors For The Regulated Utilities Industry Primary Credit Analysts: Richard Creed, Melbourne (61) ; richard.creed@standardandpoors.corn Barbara A Eiseman, New York (1) ; barbara.eiseman@standardandpoors.com Vittoria Ferraris, Milan (39) ; vittorialerraris@standardandpoors.com Sergio Fuentes, Buenos Aires (54) ; sergioluentes@standardandpoors.com Gabe Grosberg, New York (1) ; gabagrosberg@standardandpoors.com Parvathy Iyer, Melbourne (61) ; parvathyiyer@standardandpoors.com Gerrit W Jepsen, CFA, New York (1) ; gerrit.jepsen@standardandpoors.coiri Andreas Kindahl, Stockholm (46) ; andreas.kindahl@standardandpoors.com John D Lindstroni, Stockholm (46) ; john.lindstrom@standardandpoors.com Nicole D Martin, Toronto (1) ; nicole.martin@standardandpoors.com Sherman A Myers, New York (1) ; sherman.myers@standardandpoors.com Dirnitri Nikas, New York (1) ; dimitri.nikas@standardandpoors.com Ana M Olaya-Rotonti, New York (1) ; ana.olaya-rotonti@standardandpoors.com Hirold Shibata, Tokyo (81) ; hiroki.shibata@standardandpoors.com Todd A Shipman, CFA, New York (1) ; todd.shipman@standardandpoors.com Alf Stenqvist, Stockholm (46) ; alfstenqvist@standardandpoors.com Tania Tsoneva, CFA, London (44) ; tania.tsoneva@standardandpoors.com Mark J Davidson, London (44) ; markj.davidson@standardandpoors,com Criteria Officer: Mark Puccia, New York (1) ; mark.puccia@standardandpoors.com Table Of Contents SCOPE OF THE CRITERIA SUMMARY OF THE CRITERIA IMPACT ON OUTSTANDING RATINGS EFFECTIVE DATE AND TRANSITION NOVEMBER 19, :a

51 Exhibit EL-2 Attacbment 5 Page 2 of 23 Table Of Contents (cont.) METHODOLOGY Part I--Business Risk Analysis Part II--Financial Risk Analysis Part III--Rating Modifiers Appendix--Frequently Asked Questions RELATED CRITERIA AND RESEARCH NOVEMBER 19, Aitz813u0ozus

52 Exhibit EL-2 Attachment 5 Page 3 of 23 Criteria I Corporates I Utilities: Key Credit Factors For The Regulated Utilitjes Industry (Editor's Note: This criteria article supersedes "Key Credit Factors: Business And Financial Risks In The Investor-Owned Utilities Industry," published Nov. 26, 2008, 'Assessing US. Utility Regulatory Environments," Nov. 7, 2007, and "Revised Methodology For Adjusting Amounts Reported By UK. GAAP Water Companies For Infrastructure Renewals Accounting," Jan. 27, 2010.) 1. Standard & Poor's Ratings Services is refining and adapting its methodology and assumptions for its Key Credit Factors: Criteria For Regulated Utilities. We are publishing these criteria in conjunction with our corporate criteria (see "Corporate Methodology, published Nov. 19, 2013). This article relates to our criteria article, "Principles Of Credit Ratings," Feb. 16, This criteria article supersedes "Key Credit Factors: Business And Financial Risks In The Investor-Owned Utilities Industry," Nov. 26, 2008, "Criteria: Assessing US. Utility Regulatory Environments," Nov. 7, 2007, and "Revised Methodology For Adjusting Amounts Reported By UK GAAP Water Companies For Infrastructure Renewals Accounting," Jan. 27, SCOPE OF THE CRITERIA 3. These criteria apply to entities where regulated utilities represent a material part of their business, other than U.S. public power, water, sewer, gas, and electric cooperative utilities that are owned by federal, state, or local governmental bodies or by ratepayers. A regulated utility is defined as a corporation that offers an essential or near-essential infrastructure product, commodity, or service with little or no practical substitute (mainly electricity, water, and gas), a business model that is shielded from competition (naturally, by law, shadow regulation, or by government policies and oversight), and is subject to comprehensive regulation by a regulatory body or implicit oversight of its rates (sometimes referred to as tariffs), service quality and terms of service. The regulators base the rates that they set on some form of cost recovery, including an economic return on assets, rather than relying on a market price. The regulated operations can range from individual parts of the utility value chain (water, gas, and electricity networks or "grids," electricity generatiem, retail operations, etc.) to the entire integrated chain, from procurement to sales to the end customer. In some jurisdictions, our view of government support can also affect the final rating outcome, as per our government-related entity criteria (see "General Criteria: Rating Government-Related Entities: Methodology and Assumptions," Dec. 9, 2010). SUMMARY OF THE CRITERIA 4 Standard & Poors is updating its criteria for analyzing regulated utilities, applying its corporate criteria. The criteria for evaluating the competitive position of regulated utilities amend and partially supersede the "Competitive Position" section of the corporate criteria when evaluating these entities. The criteria for determining the cash flow leverage NOVEPdBER 19, :028 I 30002U

53 Criteria I Exhibit EL-2 Attachment 5 Page 4 of 23 Corporates I Utilities: Key Credit Factors For,The Regulated Utilities Industiy assessment partially supersede the "Cash Flow/Leverage section of the corporate criteria for the purpose of evaluating regulated utilities. The section on liquidity for regulated utilities partially amends existing criteria. All other sections of the corporate criteria apply to the analysis of regulated utilities. IMPACT ON OUTSTANDING RATINGS 5. These criteria could affect the issuer credit ratings of about 5% of regulated utilities globally due primarily to the introduction of new financial benchmarks in the corporate criteria. Almost all ratings changes are expected to be no more than one notch, and most are expected to be in an upward direction. EFFECTIVE DATE AND TRANSITION 6. These criteria are effective immediately on the date of publication. METHODOLOGY Part I--Business Risk Analysis. Industry risk 7. Within the framework of Standard & Poor's general criteria for assessing industry risk, we view regulated utilities as a "very low rise industry (category ' V). We derive this assessment from our view of the segment's low risk (2') cyclicality and very low risk (r) competitive risk and growth assessment. 8 In our view, demand for regulated utility services typically exhibits low cyclicality, being a function of such key drivers as employment growth, household formation, and general economic trends. Pricing is non-cyclical, since it is usually based in some form on the cost of providing service. Cyclic ality 9. We assess cyclicality for regulated utilities as low risk (2'). Utilities typically offer products and services that are essential and not easily replaceable. Based on our analysis of global Compustat data, utilities had an average peak-to-trough (PTT) decline in revenues of about 6% during recessionary periods since Over the same period, utilities had an average PTT decline in EBITDA margin of about 5% during recessionary periods, with PTT EBITDA margin declines less severe in more recent periods. The PTT drop in profitability that occurred in the most recent recession ( ) was less than the long-term average. 10, With an average drop in revenues of 6% and an average profitability decline of 5%, utilities cyclicality assessment calibrates to low risk (2'). We generally consider that the higher the level of profitability cyclicality in an industry the higher the credit risk of entities operating in that industry However, the overall effect of cyclicality on an industrys risk profile may be mitigated or exacerbated by an industrys competitive and growth environment. NOVEMBER 19, :b9a 30002U

54 ExInlit EL-2 Attachment 5 Page 5 of 23 Criteria I Corporates I Utilities: Key Credit Factors For The Regulated Utilities Industry Competitive risk and growth 11, We view regulated utilities as warranting a very low risk ( I') competitive risk and growth assessment. For competitive risk and growth, we assess four sub-factors as low, medium, or high risk. These sub-factors are; Effectiveness of industry barriers to entry; Level and trend of industry profit margins; Risk of secular change and substitution by products, services, and technologies; and Risk in growth trends. Effectiveness of barriers to entry--low risk 12. Barriers to entry are high. Utilities are normally shielded from direct competition. Utility services are commonly naturally monopolistic (they are not efficiently delivered through competitive channels and often require access to public thoroughfares for distribution), and so regulated utilities are granted an exclusive franchise, license, or concession to serve a specified territory in exchange for accepting an obligation to serve all customers in that area and the regulation of its rates and operations. Level and trend of industry profit margins--low risk 15. Demand is sometimes and in some places subject to a moderate degree of seasonality and weather conditions can significantly affect sales levels at times over the short term. However, those factors even out over time, and there is little pressure on margins if a utility can pass higher cost along to customers via higher rates. Risk of secular change and substitution of products, services, and technologies--low risk 14. Utility products and services are not overly subject to substitution. Where substitution is possible, as in the case of natural gas, consurner behavior is usually stable and there is not a lot of switching to other fuels. Where switching does occur, cost allocation and rate design practices in the regulatory process can often mitigate this risk so that utility profitability is relatively indifferent to the substitutions. Risk in industry growth trends low risk 15. As noted above, regulated utilities are not highly cyclical. However, the industry is often well established and, in our view, long-range demographic trends support steady demand for essential utility services over the long term. As a result; we would expect revenue growth to generally match GDP when economic growth is positive. B. Country risk 16. In assessing "country rise for a regulated utility our analysis uses the same methodology as with other corporate issuers (see "Corporate Methodologr). C. Competitive position 17 In the corporate criteria, competitive position is assessed as ( V) excellent, (2') strong, (3') satisfactory, (4') fair, (5') weak, or (6') vulnerable. 18. The analysis of competitive position includes a review of Competitive advantage, Scale, scope, and diversity, Operating efficiency, and Profitability. NOVEMBER 19, :

55 Exhibit EL-2 Attachment 5 Page 6 of 23 Criteria I Corporates I Utilities: Key 'Credit Factors For The Regulated Utilities Industry 19. In the corporate criteria we assess the strength of each of the first three components. Each component is assessed as either: (1) strong, (2) strong/adequate, (3) adequate, (4)adequate/weak, or (5) weak. After assessing these components, we determine the preliminary competitive position assessment by ascribing a specific weight to each component. The applicable weightings will depend on the companys Competitive Position Group Profile. The group profile for regulated utilities is "National Industries & Utilities," with a weighting of the three components as follows: competitive advantage (60%), scale, scope, and diversity (20%), and operating efficiency (20%). Profitability is assessed by combining two sub-components: level of profitability and the volatility of profitability. 20. "Competitive advantage cannot be measured with the same sub-factors as competitive firms because utilities are not primarily subject to influence of market forces. Therefore, these criteria supersede the "competitive advantage" section of the corporate criteria. We analyze instead a utility's "regulatory advantage (section 1 below). Assessing regulatory advantage 21. The regulatory framework/regimes influence is of critical importance when assessing regulated utilities credit risk because it defmes the environment in which a utility operates and has a significant bearing on a utility's financial performance. 22. We base our assessment of the regulatory framework's relative credit supportiveness on our view of how regulatory stability, efficiency of tariff setting procedures, financial stability, and regulatory independence protect a utility's credit quality and its ability to recover its costs and earn a timely return. Our view of these four pillars is the foundation of a utilitys regulatory support. We then assess the utilitys business strategy, in particular its regulatory strategy and its ability to manage the tariff-setting process, to arrive at a final regulatory advantage assessment 23. When assessing regulatory advantage, we first consider four pillars and sub-factors that we believe are key for a utility to recover all its costs, on time and in full, and earn a retum on its capital employed: 24 Regulatory stability: Transparency of the key components of the rate setting and how these are assessed Predictability that lowers uncertainty for the utility and its stakeholders Consistency in the regulatory framework over time 25. Tariff-setting procedures and design: Recoverability of all operating and capital costs in full Balance of the interests and concems of all stakeholders affected Incentives that are achievable and contained 26. Financial stability: Timeliness of cost recovery to avoid cash flow volatility Flexibility to allow for recovery of unexpected costs if they arise Attractiveness of the framework to attract long-term capital Capital support during construction to alleviate funding and cash flow pressure during periods of heavy investments 27. Regulatory independence and insulation: NOVEMBER 19, A928 j 30002(

56 Exhibit EL-2 Attachment 5 Page 7 of 23 Criteria I Corporates I Utilities: Key Credit Factors For The Regulated Utilities Industry Market framework and energy policies that support long-term financeability of the utilities and that is clearly enshrined in law and separates the regulator's powers Risks of political intervention is absent so that the regulator can efficiently protect the utility's credit profile even during a stressful event.28. We have surnmarized the key characteristics of the assessments for regulatory advantage in table 1. Table 1 Preliminary Regulatory Advantage Assessment Qualifier What it means Guidance Strong Adequate The utility has a major regulatory advantage due to one or a combination The utility operates'in a regulatory climate that is of factors that support cost recovery and a return on capital combined transparent, predictable, and consistent from a with lower than average volatility of earnings and cash flows. credit perspective_ There are strong prospects that the utility can sustain this advantage over The utility can fully and timely recover all its fixed the long term. and variable operating costs, Investments and capital costs (depreciation and a reasonable return on the asset base). This should enable the utility to withstand economic downturns and political risks better than other utilities. The tariff set may include a pass-through mechanism for major expenses such as commodity costs, or a higher retum on new assets, effectively shielding the utility from volume and input cost risks. Any incentives in the regulatory scheme are contained and symmetrical. The tariff set includes mechanisms allowing for a tariff adjustment for the timely recovery of volatile or unexpected operating and capital costs. There is a track record of earning a stable, compensatory rate of retum in cash thmugh various economic and political cycles and a projected ability to maintain that record. There is support of cash flows during construction of large projects, and pre-approval of capital investment programs and large projects lowers the risk of subsequent disallowances of capital costs. The utility operates under a regulatory system that is sufficiently insulated from political intervention to efficiently protect the utilitys credit risk profile even during stressful events. The utility has some regulatory advantages and protection, but not to the It operates in a regulatory envimnment that is less extent that it leads to a superior business model or durable benefit. transparent, less predictable, and less consistent from a credit perspective. The utility has some but not all drivers of well-managed regulatory risk. Certain regulatory factors support the business's long-term stability and viability but could result in periods of below-average levels of profitability and greater profit volatility. However, overall these regulatory drivers are partially offset by the utility's disadvantages or lack of sustainability of other factors. The utility is exposed to delays or is not, with sufficient certainty, able to recover all of its fixed and variable operating costs, investments. and capital costs (depreciation and a reasonable return on the asset base) within a reasonable time. Incentive ratemaldng practices are asymmetrical and material, and could detract from credit quality. The utility is exposed to the risk that it doesn't recover unexpected or volatile costs in a full or less than timely manner due to lack of flexible reopeners or annual revenue adjustments. There is an uneven track record of earning a compensatory rate of return in cash through various economic and political cycles and a projected ability to maintain that record. WIVW.STANDARDANDPOORS.COM/RATINGSDIRECT NOVEMBER 19, :CA920 3(

57 Exhibit EL-2 Attachment 5 Page 8 of 23 Criteria I Corporates I Utilities: Key Credit Factors For The Regulated Utilities Industry Table 1 Preliminary Regulatory Advantage Assessment (cont.) There is little or no support of cash flows during construction, and investment decisions on large projects (and therefore the risk of subsequent disallowances of capital costs) rest mostly with the utility The utility operates under a regulatory system that is not sufficiently insulated from political intervention and is sometimes subject to overt political influence. Weak The utility suffers from a complete breakdown of regulatory protection The utility operates in an opaque regulatory climate that places the utility at a significant disadvantage. that lacks transparency, predictability and consistency. The utility's regulatory risk is such that the long-term cost recovery and investrnent return is highly uncertain and materially delayed, leading to volatile or weak cash flows. There is the potential for material stranded assets with no prospect of recovery. The utility cannot fiilly and/or timely recover its fixed and variable operating costs, investments, and capital costs (depreciation and a reasonable return on the asset base). There is a track record of earning minimal or negative rates of return in ash through various economic and political cycles and a projected inability to improve that record sustainably The utility must make significant capital commitments with no solid legal basis for the full recovery of capital costs. Ratemaking practices actively harm credit quality. The utility is regularly subject to overt political 1 influence. 29. After determining the preliminary regulatory advantage assessment, we then assess the utility's business strategy. Most importantly, this facior addresses the effectiveness of a utilitys management of the regulatory risk in the jurisdiction(s) where it operates. In certain jurisdictions, a utilitys regulatory strategy and its ability to manage the tariff-setting process effectively so that revenues change with costs can be a compelling regulatory risk factor. A utility's approach and strategies surrounding regulatory matters can create a durable "competitive advantage" that differentiates it from peers, especially if the risk of politidal intervention is high. The assesiment of a utilitys business strategy is informed by historical performance and its forward-looking business objectives. We evaluate these objectives in the context of industry dynamics and the regulatory climate in which the utility operates, as evaluated through the factors cited in paragraphs We modify the preliminary regulatory advantage assessment to reflect this influence positively or negatively. Where business strategy has limited effect relative to peers, we view the implications as neutral and make no adjustment. A positive assessment improves the preliminary regulatory advantage assessment by one category and indicates that management's business strategy is expected to bolster its regulatory advantage through favorable commission rulings beyond what is typical for a utility in that jurisdiction. Conversely, where management's strategy or businesses decisions result in adverse regulato'ry outcomes relative to peers, such as failure to achieve typical cost recovery or allowed returns, we adjust the preliminary regulatory advantage assessment one category worse. In extreme cases of poor strategic execution, the preliminary regulatory advantage assessment is adjusted by two categories worse (when possible; see table 2) to reflect manakement decisions that are likely to result in a significantly adverse regulatory outcome relative to peers. NOVEMBER 19, :a.: 1 I

58 Exhibit EL-2 Attachment 5 PUCT Docket No Page 9 of 23 Criteria I Corporates I Utilities: Key Credit Factors For The Regulated Utilities Industry Table 2 Determining The Final Regulatory Advantage Assessment Strategy modifier-- Preliminary regulatory advantage score Positive Neutral Negative Very negative Strong Strong Strong Strong/Adeqnate Adequate Strong/Adequate Strong Strong/Adequate Adequate Adequate/Weak Adequate Strong/Adequate Adequate Adequate/Weak Weak Adequate/Weak Adequate Adequate/Weak Weak Weak Weak Adequate/Weak Weak Weak Weak Scale, scope, and diversity 31. We consider the key factors for this component of competitive position to be primarily operational scale and diversity of the geographic, economic, and regulatory foot prints. We focus on a utility's markets, service territories, and diversity and the extent that these attributes can contribute to cash flow stability while dampening the effect of economic and market threats. 32. A utility that warrants a Strong or Strong/Adequate assessment has scale, scope, and diversity that support the stability of its revenues and profits by limiting its vulnerability to most combinations of adverse factors, events, or trends. The utilitys significant advantages enable it to withstand economic, regional, competitive, and technological threats better than its peers. It typically is characterized by a combination of the following factors: A large and diverse customer base with no meaningful customer concentration risk, where residential and small to medium commercial customers typically provide most operating income. The utilitys range of service territories and regulatory jurisdictions is better than others in the sector. Exposure to multiple regulatory authorities where we assess preliminary regulatory advantage to be at least Adequate. In the case of exposure to a single regulatory regime, the regulatory advantage assessment is either Strong or Strong/Adequate. No meaningful exposure to a single or few assets or suppliers that could hurt operations or could not easily be replaced. 33 A utility that warrants a Weak or Weak/Adequate assessment lacks scale, scope, and diversity such that it compromises the stability and sustainability of its revenues and profits. The utility's vulnerability to, or reliance on, various elements of this sub-factor is such that it is less likely than its peers to withstand economic, competitive, or technological threats. It typically is characterized by a combination of the following factors: A small customer base, especially if burdened by customer and/or industry concentration combined with little economic diversity and average to below-average economic prospects; Exposure to a single service territory and a regulatory authority with a preliminary regulatory advantage assessment of Adequate or Adequate/Weak; or Dependence on a single supplier or asset that cannot easily be replaced and which hurts the utilitys operations. 34 We generally believe a larger service territory with a diverse customer base and average to above-average economic growth prospects provides a utility with cushion and flexibility in the recovery of operating costs and ongoing investment (including replacement and growth capital spending), as well is lessening the effect of extemal shocks (i.e., NOVEMBER LOOM

59 Exhibit EL-2 Attachment 5 Page 10 of 23 Criteria I Corporates I Utilities: Key Credit Factors For The Regulated Utilities Industry extreme local weather) since the incremental effect on each customer declines as the scale increases. 35 We consider residential and small 'commercial customers as having more stable usage patterns and being less exposed to periodic economic weakness, even after accounting for some weather-driven usage variability Significant industrial exposure along with a local economy that largely depends on one or few cyclical industries potentially contributes to the cyclicality of a utilitys load and financial performance, magnifying the effect of an economic downturn. 36 A utilitys cash flow generation and stability can benefit from operating in multiple geographic regions that exhibit average to better than average levels of wealth, employment, and growth that underpin the local economy and support long-term growth. Where opérations are in a single geographic region, the risk can be ameliorated if the region is sufficiently large, demonstrates economic diversity and has at least average demographic characteristics. 37. The detriment of operating in a single large geographic area is subject to the strength of regulatory assessment. Where a utility operates in a single large geographic area and has a strong regulatory assessment, the benefit of diversity can be incremental. Operating efficiency 38. We consider the key factors for this component of competitive position to be: Compliance with the terms of its operating license, including safety, reliability, and environmental standards; Cost management; and Capital spending: scale, scope, and management. 39. Relative 'to peers, we analyze how successful a utility management achieves-the above factors within the levels allowed by the regulator in a manner that promotes cash flow stability We consider how management of these factors reduces the prospect of penalties for noncompliance, operating costs being greater than allowed, and capital projects running over budget and time, which could hurt full cost recovery. 40 The relative importance of the above three factors, particularly cost and capital spending management, is determined by the typê of regulation under which the utility operates. Utilities operating under robust "cost plus" regimes tend to be more insulated given the high degree of confidence costs will invariably be passed through to customers. Utilities operating under incentive-based regimes are likely to be. more sensitive to achieving regulatory standards. This is partieularly so in the regulatory regimes that involve active consultation between regulator and utility and market testing as opposed to just handing down an outcome on a more arbitrary basis. 41, In some jurisdictions, the absolute performance standards are less relevant than how the utility performs against the regulator's performance benchmarks. It is this performance that will drive any penalties or incentive payments and can be a determinant of the utilities credibility on operating and asset-management plans with its regulator. 42, Therefore, we consider that utilities that perform these functions well are more likely to consistently achieve determinations that maximize the likelihood of cost recovery and full inclusion of capital spending in their asset bases. Where regulatory resets are more at the discretion of the utility, effective cost management;including of labor, may allow for more control over the timing and magnitude of rate filings to maximize the chances of a constructive outcome such as full operational and capital cost recovery while protecting against reputational risks. NOVEMBER 19, e

60 Exhibit EL-2 Attachment 5 Page 11 of 23 Criteria I Corporates 1 Utilities: Key Credit Factors For The Regulated Utilities Industry 43 A regulated utility that warrants a Strong or Strong/Adequate assessment for operating efficiency relative to peers generates reventes and profits through minimizing costs, increasing efficiencies, and asset utilization. It typically is characterized by a combination of the following: High safety record; Service reliability is strong, with a track record of meeting operating performance requirements of stakeholders, including those of regulatdrs. Moreover, the utilitys asset profile (including age and technology) is such that we have confidence that it could sustain favorable performance against targets; Where applicable, the utility is well-placed to meet current and potential future environmental standards; Management maintains very good cost control. Utilities with the highest assessment for operating efficiency have shown an ability to manage both their fixed and variable costs in line with regulatory expectations (including labor and working-capital management being in line with regulator's allowed collection cycles); or There is a history of a high level of project rnanagement execution in capital spending programs, including large one-time projects, almost invariably withiii regulatory allowances for timing and budget. 44. A regulated utility that warrants an Adequate assessment for operating efficiency relative to peers has a combination of cost position and efficiency factors that support profit sustainability cornbined with average volatility. Its cost structure is similar to its peers. It typically is characterized by a Combination of the following factors: High safety performance; Service reliability is satisfactory with a track record of mostly meeting operating performance requirements of stakeholders, including those of regulators. We have confidence that a favorable performance against targets can be mostly sustained; Where ipplicable, the utility may be challenged to comply with current and future environmental standards that could increase in the mediurn term; Management maintains adequate cost control. Utilities that we assess as having adequate operating efficiency mostly manage their fixed and variable costs in line with regulatory expectations (including labor and working capital rnanagement being mostly in line with regulator's allowed collection cycles); or There is a history of adequate project rnanagement skills in capital spending programs within regulatory allowances for timing and budget. 45, A regulated utility that warrants a weak or weak/adequate assessment for operating efficiency relative to peers has a combination of cost position and efficiency factors that fail to support profit sustainability combined with below-average volatility. Its cost structure is worse than its peers. It typically is characterized by a combination of the following: Poor safety performance; Service reliability has been sporadic or non-existent with a track record of not meeting operating performance requirements of stakeholders, including those of regulators. We do not believe the utility can consistently meet performance targets without additional capital spending, Where applicable, the utility is challenged to comply with current environmental standards and is highly vulnerable to more onerous standards; Management typically exceeds operating costs authorized by regulators; Inconsistent project management skills as evidenced by cost overruns and delays including for maintenance capital spending; or The capital spending program is large and complex and falls into the weak or weak/adequate assessment, even if NOVEMBER 19, i2a920 I

61 Exhibit EL-2 Attachment 5 Page 12 of 23 Criteria I Corporates I Utilities: Key Credit Factors For The Regulated Utilities Industry operating efficiency is generally otherwise considered adequate. Profitability 46. A utility with above-average profitability would, relative to its peers, generally earn a rate of return at or above what regulators authorize and have minimal exposure to earnings volatility from affiliated unregulated business activities or market-sensitive regulated operations. Conversely, a utility with below-average profitability would generally earn rates of return well below the authorized return relative to its peers or have significant exposure to earnings volatility from affiliated unregulated business activities or market-sensitive regulated operations. 47. The profitability assessment consists of "level of profitability" and "volatility of profitability." Level of profitability 48 Key measures of general profitability for regulated utilities commonly include ratios, which we compare both with those of peers and those of companies in other industries to reflect different countries regulatory frameworks and business environments: EBITDA margin, Return on capital (ROC), and Return on equity (ROE). 49. In many cases. EBITDA as a percentage of sales (i.e., EBITDA margin) is a key indicator of profitability This is because the book value of capital does not always reflect true earning potential, for example when governments privatize or restructure incumbent state-owned utilities. Regulatory capital values can vary with those of reported capital because regulatory capital values are not inflation-indixed and could be subject to different assumptions concerning depreciation. In general, a country's inflation rate or required rate of return on equity investment is closely linked to a utility company's profitability. We do not adjust our analysis for these factors, because we can make our assessment through a peer comparison. 50, For regulated utilities gubject to full cost-of-service regulation and return-on-investment requirements, we normally measure profitability using ROE, the ratio of net income available for common stockholders to aver* common equity. When setting rates, the regulator ultimately bases its decision on an authorized ROE. However, different factors such as variances in costs and usage may influence the return a utility is actually able to earn, and consequently our analysis of profitability for cost-of-service-based utilities centers on the utility's ability to consistently earn the authorized ROE. 51. We will use return on capital when pass-through costs distort profit margins--for instance congestion fevenues or collection of third-party revenues. This is also the case when the utility uses accelerated depreciation of assets, which in our view might not be sustainable in the long run. Volatility of profitability 52, We may observe a clear difference between the volatility of actual profitability and the volatility of underlying regulatory profitability In these cases, we could use the regulatory accounts' as a proxy to ju-dge the stability of earnings. 53 We use actual returns to calculate the standard error of regression for regulated utility issuers (only if there are at least WIAM.STANDARDANDPOORS.COM/RATINGSDIRECT NOVEMBER 19, [2:HP

62 Exhibit EL-2 Attachment 5 Page 13 of 23 Criteria I Corporates I Utilities: Key Credit Factors For The Regulated Utilities Industry seven years of historical annual data to ensure meaningful results). If we believe recurring mergers and acquisitions or currency fluctuations affect the results, we may make adjustments. Part II Financial Risk Analysis D. Accounting 54. Our analysis of a companys financial statements begins with a review of the accounting to determine whether the statements accurately measure a company's performance and position relative to its peers and the larger universe of corporate entities. To allow for globally consistent and comparable fmancial analyses, our rating analysis may include quantitative adjustments to a companys reported results. These adjustments also align a company's reported figures with our view of underlying economic conditions and give us a more accurate portrayal of a companys ongoing business. We discuss adjustments that pertain broadly to all corporate sectors, including this sector, in "Corporate Methodology: Ratios And Adjustments." Accounting characteristics and analytical adjustments' unique to this sector are discussed below. Accounting characteristics 55 Some important accounting practices for utilities include: For integrated electric utilities that meet native load obligations in part with third-party power contracts, we use our purchased power methodology to adjust measures for the debt-like obligation such contracts represent (see below). Due to distortions in leverage measures from the substantial seasonal working-capital requirements of natural gas distribution utilities, we adjust inventory and debt balances by netting the value of inventory against outstanding short-term borrowings. This adjustment provides an accurate view of the companys balance sheet by reducing seasonal debt balances when we see a very high certainty of near-term cost recovery (see below). We deconsolidate securitized debt (and associated revenues and expenses) that has been accorded specialized recovery provisions (see below). For water utilities that report under UK. GAAP, we adjust ratios for infrastructure renewals accounting, which permits water companies to capitalize the maintenance spending on their infrastructure assets (see below). The adjustments aim to Make those water companies that report under UK. GAAP more comparable to those that report under accounting regimes that'do not permit infrastructure renewals accounting: 56. In the U.S. and selectively in other regions, utilities employ "regulatory accountine which permits a rate-regulated company to defer some revenues and expenses to match the thning of the recognition of those items in rates as determined by regulators. A utility subject to regulatory accounting will therefore have assets and liabilities on its books that an unregulated corporation, or even regulated utilities in many other global regions, cannot record. We do not aajust GAAP earnings or balance-sheet figureš to remove the effects of regulatory accounting. However, aspore countries adopt International Financial Reporting Standards (IFRS), the use of regulatory accounting will become more scarce. IFRS does not currently provide for any recognition of the effects of rate regulation for financial reporting purposes, but it is considering the use of regulatory accounting. We do not anticipate altering our fundamental financial analysis of utilities because of the use or non-use of regulatory accounting. We will continue to analyze the effects of regulatory actions on a utilitys fmancial health. OORS.COM /RATINGSDIRE CT NOVEMBER 19, :U

63 Exhibit EL-2 Attachment 5 Page 14 of 23 Criteria I Corporates I Utilities: Key Credit Factors For The Regulated Utilities Industry Purchased power adjustment 57 We view long-term purchased power agreements (PPA) as creating fixed, debt-like financial obligations that represent substitutes for debt-financed capital investments in generation capacity By adjusting financial measures to incorporate PPA fixed obligations, we achieve greater comparability of utilities that finance and build generation capacity and those that purchase capacity to satisfy new load. PPAs do benefit utilities by shifting various risks to the electricity generators, such as construction risk and most of the operating risk. The principal risk borne by a utility that relies on PPAs is recovering the costs of the financial obligation in rates. (See "Standard & Poor's Methodology For Imputing Debt for U.S. Utilities Power Purchase Agreements," May 7, 2007, for more background and information on the adjustment.) 58 We calculate the present value (PV) ofthe future stream of capacity payments under the contracts as reported in the fmancial statement footnotes or'as supplied directly by the company. The discount rate used is the same as the one used in the operating lease adjustment, i.e., 7%. For US. companies, notes to the financial statements enumerate capacity payments for the coming five years, and a thereafter period. Company forecasts show the detail underlying the thereafter amount, or we divide the amount reported as diereafter by the average of the capacity payments in the preceding five years to get an approximation of annual payments after year five. 59. We also consider new contracts that will start during the forecast period. The company provides us the information regarding these contracts. If these contracts represent extensions of existing PPAs, they are immediately included in the PV calculation. However, a contract sometimes is executed in anticipation of incremental future needs, so the energy will not flow until some later period and there are no interim payments. In these instances, we incorporate that contract in our projections, starting in the year that energy deliveries begin under the contract. The projected PPA debt is included in projected ratios as a current rating factor,'even though it is not included in the current-year ratio calculations. 60. The PV is adjusted to reflect regulatory or legislative cost-recovery mechanisms when present. Where there is no explicit regulatory or legislative recovery of PPA costs, as in most European countries, the PV may be adjusted for other mitigating factors that reduce the risk of the PPAs to the utility, such as a limited economic importance of the PPAs to the utilitys overall portfolio.the adjustment reduces the debt-equivalent amount by multiplying the PV by a specific risk factor. 61. Risk factors based on regulatoiy or legislative cost recovery typically range between 0% and 50%, but can be as high as 100%. A 100% risk factor would signify that subitantially all risk related to contractual obligations rests on the company, with no regulatory or legislative support. A 0% risk factor indicates that the burden of the contractual payments rests solely with ratepayers, as when the utility merely acts as a conduit for the delivery of a third paftys electricity. These utilities are barred from developing new generation assets, and the power supplied to their customers is sourced through a state auction or third parties that act as intermediaries between retail customers and electricity suppliers. We employ a 50% risk factor in cases where regulators use base rates for the recovery of the fixed PPA costs. If a regulator has established a separate adjustment mechanism for recovery of all prudent PPA costs, a risk factor of 25% is employed. In certain jurisdictions, true-up mechanisms are more favorable and frequent than the review of base rates, but still do not amount to pure fuel adjustment clauses. Such mechanisms may be triggered by financial thresholds or passage of prescribed periods of time. In these instances, a risk factor between 25% and 50% is NOVEMBER 19, :.;928 =MOM 00758

64 Criteria I Exhibit EL-2 Attachment 5 Page 15 of 23 Corporates I Utilities: Key Credit Factors For The Regulated Utilities Industry employed. Specialized, legislatively created cost-recovery mechanisms may lead to risk factors between 0% and 15%, depending on the legislative provisions for cost recovery and the supply function borne by the utility. Legislative guarantees of complete and timely recovery of costs are particularly important to achieving the lowest risk factors. We also exclude short-term PPAs where they serve merely as gap fillers, pending either the construction of new capacity or the execution of long-term PPAs. F. Where there is no explicit regulatory or legislative recovery of PPA costs, the risk factor is generally 100%. We may use a lower risk factor if mitigating factors reduce the risk of the PPAs on the utility. Mitigating factors include a long position in owned generation capacity relative to the utilitys customer supply needs that limits the importance of the PPAs to the utility or the ability to resell power in a highly liquid market at minimal loss. A utility with surplus owned generation capacity would be assigned a risk factor of less than 100%, generally 50% or lower, because we would assess its reliance on PPAs as limited. For fixed capacity payments under PPAs related to renewable power, we use a risk factor of less than 100% if the utility benefits from government subsidies. The risk factor reflects the degree of regulatory recovery through the government subsidy. 63. Given the long-term mandate of electric utilities to meet their customers demand for electricity, and also to enable comparison of companies with different contract lengths, we may use an evergreening methodology Evergreen treatment extends the duration of short- and intermediate-term contracts to a common length of about 12 years. To quantify the cost of the extended capacity, we use empirical data regarding the cost of.developink new peaking capacity, incorporating regional differences. The cost of new capacity is translated into a dollars-per-kilowatt-year figure using a proxy weighted-average cost of capital and a proxy capital recovery period. 64. Some PPM are treated as operating leases for accounting purposes--based on the tenor of the PPA or the residual value of the asset on the PPA's expiration. We accord PPA treatment to those ob1igations, 4in lieu of lease treatment; rather, the PV of the stream of capacity payments associated with these PPAs is reduced to reflect the applicable risk factor. 65. Long-term transmission contracts can also substitute for new generation, and, accordingly, may fall under our PPA methodology. We sometimes view these types of transmission arrangements as extensions of the power plants to which they are connected or the markets that they serve. Accordingly, we impute debt for the fixed costs associated with such transmission contracts. 66, Adjustment procedures: Data requirements: Future capacity payments obtained from the financial statement footnotes or from management. Discount rate: 7%. Analytically determined risk factor. Calculations: Balance sheet debt is increased by the PV of the stream of capacity payments multiplied by the risk factor. Equity is not adjusted because the recharacterization of the PPA implies the creation of an asset, which offsets the debt. Property, plant, and equipment and total assets are increased for the implied creation of an asset equivalent to the NOVEMBER 19, :

65 Exhibit EL-2 Attachment 5 Page 16 of 23 Criteria I Corporates 1 Utilities: Key Credit Factors For The Regulated Utilities Industry debt. An implied interest expense for the imputed debt is determined by multiplying the discount rate by the amount of imputed debt (or average PPA imputed debt, if there is fluctuation of the level), and is added to interest expense. We impute a depreciation component to PPAs. The depreciation component is determinéd by multiplying the relevant year's capacity payment by the risk factor and then subtracting the implied PPA-related interest for that year. Accordingly, the impact of PPAs on cash flow measures is timpered. The cost amount attributed to depreciation is reclassified as capital spending, thereby increasing operating cash flow and funds from operations (FFO). Some PPA contracts refer only to a single, all-in energy price. We identify an implied capacity price within such an all-in energy price, to determine an implied capacity iiayment associated with the PRA. This implied capacity payment is expressed in dollars per kilowatt-year, multiplied by the number of kilowatts under contract. (In cases that exhibit markedly different capacity factors, such as wind power, the relation of capacity payrnent to the all-in charge is adjusted accordingly.) Operating income before depreciation and amortiztion (D&A) and EBITDA are increased for the imputed interest expense'and imputed depreciation'component, the total of which equals the entire amount paid for PPA (subject to the risk factor).. Operating income after D&A and EBIT are increased for interest expense. Natural gas inventory adjustment 67 In jurisdictions where a pass-through rnechanism is used to recover purchased natural gas costs of gas distribution utilities within one year, we adjust for seasonal changes in short-debt tied to building inventories of natural Os in non-peak periods for later use to meet peak loads in peak months. Such short-term debt is not considered to be part of the utilitys permanent capital. Any history of non-trivial disallowances of purchased gas costs would preclude the use of this adjustment. The accounting of natural gas inventories and associated short-term debt used to finance the purchases must be segregated from other trading activities....,.? 68. Adjustment procedures: Data requirements: Short-term debt amount associated with seasonal purchases of natural gas devoted to rneeting peak-load needs of captive utility customers (obtained from the company). Calculations: Adjustment to debt--(are subtract the identified short-term debt from total debt. Securitized debt adjustment 69. For regulated utilities, we deconsolidate debt (and associated revenues and expenses) that the utility issues as part of a securitization of costs that have been segregated for specialized recovery by the government entity constitutionally authorized to mandate such recovery if the securitization structure contains a number of protective features: An irrevocable, non-bypassable charge and an absolute transfer and first-priority security interest in transition property; Periodic adjustments (true-up") of the charge to remediate over- or under-collections compared with the debt service obligation. The true-up ensures collections match debt service over time and do not divergé significantly in the short run; and, 4 Reserve accounts to cover any temporary short-term shortfall in collections. NOVEMBER 19, L=2.6 I 30002U

66 Exhibit EL-2 Attachment 5 Page 17 of 23 Criteria I Corporates I Utilities: Key Credit Fadors For The Regulated Utilities Industry 70. Full cost recovery is in most instances mandated by statute. Examples of securitized costs include "stranded coste (above-market utility costs that are deemed unrecoverable when a transition from regulation to competition occurs) and unusually large restoration costs following a major weather event such as a hurricane. If the defined features are present, the securitization effectively makes all consumers responsible for principal and interest payments, and the utility is simply a pass-through entity for servicing the debt. We therefore remove the debt and related revenues and expenses from our measures. (See "Securitizing Stranded Costs," Jan. 18, 2001, for background information.) 71 Adjustment procedures: Data requirements: Amount of securitized debt on the utilitys balance sheet at period end; Interest expense related to securitized debt for the period; and Principal payments on securitized debt during the period. Calculations: Adjustment to debt: We subtract the securitized debt from total debt. Adjustment to revenues: We reduce revenue allocated to securitized debt principal and interest. The adjustment is the surn of interest and principal payments made during the year. Adjustment to operating income after depreciation and amortization (D&A) and EBIT: We reduce D&A related to the securitized debt, which is assumed to equal the principal payments during the period. As a result, the reduction to operating income after D&A is only for the interest portion. Adjustment to interest expense: We remove the interest expense of the securitized debt from total interest expense. Operating cash flows: We reduce operating cash flows for revenues and increase for the assumed interest amount related to the securitized debt. This results in a net decrease to operating cash flows equal to the principal repayment amount. Infrastructure renewals expenditure 72. In England and Wales, water utilities can report under either 1FRS or U.K. GAAP. Those that report under U.K. GAAP are allowed to adopt infrastructure renewals accounting, which enables the companies to capitalize the maintenance spending on their underground assets, called infrastructure renewals expenditure (IRE). Under IFRS, infrastructure renewals accounting is not permitted and maintenance expenditure is charged to earnings in the year incurred. This difference typically results ir; lower adjusted operating cash flows for those companies that report maintenance expenditure as an operating cash flow under IFRS, than for those that report it as capital expenditure under U.K. GAAR We therefore make fmancial adjustments to amounts reported by water issuers that apply UK. GAAP, with the aim of making ratios more comparable with those issuers that report under IFRS and U.S. GAAP. For example, we deduct IRE from EBITDA and FFO. 7'3. IRE does not always consist entirely of maintenance expenditure that would be expensed under IFRS. A portion of IRE can relate to costs that would be eligible for capitalization as they meet the recognition criteria for a new fixed asset set out in International Accounting Standard 16 that addresses property, plant, and equipment. In such cases, we may refine our adjustment to UK. GAAP companies so that we only deduct from FFO the portion of IRE that would not be capitalized under IFRS. However, the information to make such a refinement would need to be of high quality, reliable, and ideally independently verified by a third party, such as the company's auditor. In the absence of this, we assume NOVEMBER 19, u U

67 Exhibit EL-2 Attachment 5 page 18 of 23 Criteria I Corporates I Utilities: Key Credit Factors For The Regulated Utilities Industry that the entire amount of IRE would have been expensed under IFRS and we accordingly deduct the full expenditure frorn FFO. 74. Adjustment procedures: Data requirements: UK. GAAP accounts typically provide little information on the portion of capita] spending that relates to renewals accounting, or the related depreciation, which is referred to as the infrastructure renewals charge. The information we use for our adjustments is, however, found in the regulatory cost accounts submitted annually by the water companies to the Water Services Regulation Authority, which regulates all water companies in England and Wales. Calculations: EBITDA: Reduced by the value of IRE that was capitalized in the period. EBIT: Adjusted for the difference between the adjustment to EBITDA and the reduction in the depreciation expense, depending on the degree to which the actual cash spending in the current year matches the planned spending over the five-year regulatory review period. Cash flow from operations and FFO: Reduced by the value of IRE that was capitalized in the period. Capital spending: Reduced by the value of infrastructure renewals spending that we reclassify to cash flow from operations. Free operating cash flow: No impact, as the reduction in operating cash flows is exactly offset by the reduction in capital spending. E. Cash flow/leverage analysis 75 In assessing the cash flow adequacy of a regulated utility, our analysis uses the same methodology as with other corporate issuers (see "Corporate Methodology"). Weassess cash flow/leverage on a six-point scale ranging from (1') minimal to (6) highly leveraged. These scores are determined by aggregating the assessments of a range of credit ratios, predominantly cash flow-based, which complement each other by focusing attention on the different levels of a company's cash flow waterfall in relation to its obligations. 76 The corporate methodology provides benchinark ranges for various cash flow ratios we associate with different cash flow leverage assessments for standard volatility medial volatility, and low volatility industries. The tables of benchmark ratios differ for a given ratio and cash flow leverage assessment along two dimensions: the starting point for the ratio range and the width of the ratio range. 77. If an industrys volatility levels are low, the threshold levels for the applicable ratios to achieve a given cash flow leverage assessment are less stringent, although the width of the ratio range is narrower. Conversely, if an industry has standard levels of volatility the threshold levels for the applicable ratios to achieve a given cash flow leverage assessment may be elevated, but with a wider range of values. 78. We apply the "low-volatility" table to regulated utilities that qualify under the corporate criteria and with all of the following characteristics: A vast majority of operating cash flows come from regulated operations that are predominantly at the low end of the utility risk spectrum (e.g., a'network," or distribution/transmission business unexposed to commodity risk and with very low operating risk); A "strone regulatory advantage assessment; NOVEMBER 19, 2013 IS 12:a

68 ExInbit EL-2 Attachment 5 Page 19 of 23 Criteria I Corporates I Utilities: Key Credit Factors For The Regulated Utilities Industry An established track record of normally stable credit measures that is expected to continue; A demonstrated long-term track record of low funding costs (credit spread) for long-term debt that is expected to continue; and Non-utility activities that are in a separate part of the group (as defined in our group rating methodology) that we consider to have "nonstrategic" group status and are not deemed high risk and/or volatile. 79 We apply the "medial volatility table to companies that do not qualify under paragraph 78 with: A majority of operating cash flows from regulated activities with an "adequate or better regulatory advantage assessment; or About one-third or more of consolidated operating cash flow comes from regulated utility activities with a "strong" regulatory advantage and where the average of its remaining activities have a competitive position assessment of '3' or better. BO We apply the "standard-volatility' table to companies that do not qualify under paragraph 79 and with either: About one-third or less of its operating cash flow comes from regulated utility activities, regardless of its regulatory advantage assessment; or A regulatory advantage assessment of "adequate/wear or "weak." Part In--Rating Modifiers F. Diversification/portfolio effect 81 In assessing the diversification/portfolio effect on a regulated utility, our analysis uses the same methodology as with other corporate issuers (see "Corporate Methodologr). G. Capital structure 82. In assessing the quality of the capital structure of a regulated utility, we use the same methodology as with other corporate issuers (see "Corporate Methodology"). H. Liquidity 83. In assessing a utility's liquidity/short-term factors, our analysis is consistent with the methodology that applies to corporate issuers (See "Methodology And Assumptions: Liquidity Descriptors For Global Corporate Issuers," Nov. 19, 2013) except for the standards for "adequate" liquidity set out in paragraph 84 below. 84. The relative certainty of financial performance by utilities operating under relatively predictable regulatory monopoly frameworks make these utilities attractive to investors even in times of economic stress and market turbulence compared to conventional industrials. For this reason, utilities with business risk profiles of at least "satisfactorr meet our definition of "adequate liquidity based on a slightly lower ratio of sources to uses of funds of 1.1x compared with the standard 1.2x. Also, recognizing the eash flow stability of regulated utilities we allow more discretion when calculating covenant headroom. We consider that utilities have adequate liquidity if they generate positive sources over uses, even if forecast EBITDA declines by 10% (compared with the 15% benchmark for corporate issuers) before covenants are breached. NOVEMBER 19, :192a 3aonu

69 Exhibit EL-2 Attachment 5 Page 20 of 23 Criteria I Corporates I Utilities: Key Credit Factors For The Regulated Utilities Industry I. Financial Policy 85 In assessing financial policy on a regulated utility, our analysis uses the same methodology as with other corporate issuers (see "Corporate Methodologr). J. ManageMent and governance 86. In assessing management and governance on'a regulated utility, our analysis uses the same methodology as with other corporate issuers (see "Corporate Methodology"): K. Comparable ratings analysis 87, In assessing the comparable ratings analysis on a regulated utility, our analysis uses the same methodology as with other corporate issuers (see "Corporate Methodology"). Appendix Frequently Asked Questidns,Does Standard & Poofs expect That the business strategy modifier to the preliminary regulatory advantage will be used extensively? 88. Globally, we expect management's influence will be neutral in most jurisdictions. Where the regulatory assessment is "strong," it is less likely that a negative business strategy modifier would he used due to the nature of the regulatory regime that led to the "strong" assessment in the first place. Utilities in "adequatefweale and "weak" regulatory regimes are challenged to outperform due to the uncertainty of such regulatory regimes. For a positive use of the business strategy modifier, there would need to be a track record of the utility consistently outperforming the parameters Iaid down under a regulatory regime, and we would need to believe this could be sustained. The business strategy modifier is most likely to be used when the preliminary regulatory advantage assessment is "strong/adequate" because the starting point in the assessment is reasonably supportive, and a utility has shown it manages regulatory risk better or worse than its peers in that regulatory environment and we expect that advantage or disadvantage will persist. An example would be a utility that can consistently earn or exceed its authorized return in a jurikliction where most other utilities struggle to do so. If a utility is treated differently by a regulator due to perceptions of poor customer service or reliability and the "operating efficiency component of the competitive position assessment does not fully capture the effect on the business risk profile, a negative business strategy modifier could be used to accurately incorporate it into our analysis. We expect very few utilities will be assigned a "very negative" business strategy modifier. Does a relatively strong or poor relationship between the utility and its regulator compared with its peers in the same jurisdiction necessarily result in a positive or negative adjustment to the preliminary regulatory advantage assessment? 89. No. The business strategy modifier is used to differentiate a companys regulatory advantage within a jurisdiction where we believe management's business strategy has and will positively or negatively affect regulatory outcomes beyond what is typical for other utilities in that jurisdiction. For instance, in a regulatory jurisdiction where allowed returns are negotiated rather than set by formula, a utility that is consistently authorized higher returns (and is able to earn that retum) could warrant a positive adjustment. A management team that cannot negotiate an approved capital spending program to improve its operating performance. could be assessed negatively if its performance lags behind peeis in the same regulatory jurisdiction. NOVEMBER 19, :m

70 Criteria I Exhibit EL-2 Attachment 5 Page 21 of 23 Corporates! Utilities: Key Credit Factors For The Regulated Utilities Industry What is your definition of regulatory jurisdiction? 90 A regulatory jurisdiction is defined as the area over which the regulator has oversight and could include single or multiple subsectors (water, gas, and power). A geographic region may have several regulatory jurisdictions. For example, the Office of Gas and Electricity Markets and the Water Services Regulation Authority in the U.K. are considered separate regulatory jurisdictions. In Ontario, Canada, the Ontario Energy Board represents a single jurisdiction with regulatory oversight for power and gas. Also, in Australia, the Australian Energy Regulator would be considered a single jurisdiction given that it is responsible for both electricity and gas transmission and distribution networks in the entire country, with the exception of Western Australia. Are there examples of different preliminary regulatory advantage assessments in the same country or jurisdiction? 91. Yes. In Israel we rate a regulated integrated power utility and a regulated gas transmission system operator (TSO). The power utility's relationship with its regulator is extremely poor in our view, which led to significant cash flow volatility in a stress scenario (when terrorists blew up the gas pipeline that was then Israel's main source of natural gas, the utility was unable to negotiate compensation for expensive alternatives in its regulated tariffs). We view the gas TS0's relationship with its regulator as very supportive and stable. Because we already reflected this in very different preliminary regulatory advantage assessments, we did not modify the preliminary assessments because the two regulatory environments in Israel differ and were not the result of the companies respective business strategies. How is regulatory advantage assessed for utilities that are a natural monopoly but are not regulated by a regulator or a specific regulatory framework, and do you use the regulatory modifier if they achieve favorable treatment from the government as an owner? 92 The four regulatory pillarš remain the same. On regulatory stability we look at the stability of the setup, with more emphasis on the historical track record and our e4ectations regarding future changes. In tariff-setting procedures and design we look at the utilitys ability to fully recover operating costs, investments requirements, and debt-service obligations. In financial stability we look at the degree of flexibility in tariffs to counter volume risk or commodity risk. The flexibility can also relate to the level of indirect competition the utility faces. For example, while Nordic district heating companies operate under a natural monopoly, their tariff flexibility is partly restricted by customers' option to change to a different heating source if tariffs are significantly increased. Regulatory independence and insulation is mainly based on the perceived risk of political intervention to change the setup that could affect the utilitys credit profile. Although political intervention tends to be mostly negative, in certain cases political ties due to state ownership might positively influence tariff determination. We believe that the four pillars effectively capture the benefits from the close relationship between the utility and the state as an owner; therefore, we do not foresee the use of the regulatory modifier. In table I, when describing a "strong' regulatory advantage assessment, you mention that there is support of cash flows during construction of large projects, and preapproval of capital investment programs and large projects lowers the risk of subsequent disallowances of capital costs. Would this preclude a "stronr regulatory advantage assessment in jurisdictions where those practices are absent? 93. No. The table is guidance as to what we would typically expect from a regulatory framework that we would assess as "strong." We would expect some frameworks with no capital support during construction to receive a "strong" regulatory advantage assessment if in aggregate the other factors we analyze support that conclusion. NOVEMBER 19, :028 I 30002U

71 Exhibit EL-2 Attachment 5 Page 22 of 23 Criteria] Corporates 1 Utilities: Key Credit Factors For The Regulated Utilities Industry RELATED CRITERIA AND RESEARCH Corporate Methodology, Nov. 19, 2013 Group Rating Methodology, Nov. 19, 2013 Industry Risk For Corporate And Public Finance Enterprises, Nov. 19, 2013 Corporate Methodology: Ratios And Adjustments, Nov. 19, 2013 Ratings Above The Sovereign Corporate And Government Ratings: Methodology And Assumptions, Nov. 19, 2013 Methodology And Assumptions: Liquidity Descriptors For Global Corporate Issuers, Nov. 19, 2013 Collateral Coverage And Issue Notching Rules For '1+ And '1' Recovery Ratings On Senior Bonds Secured By Utility Real Property, Feb. 14, 2013 Methodology: Management And Governance Credit Factors For Corporate Entities and Insurers, Nov. 13, 2012 General Criteria: Principles Of Credit Ratings, Feb. 16, 2011 General Criteria: Rating Government-Related Entities: Methodology Arid Assumptions, Dec. 9, 2010 Sianderci & Poor's (Australia) PtY Ltd. holds Australian financial services linence number under the Corporations Act Standard poor's credit ratings and related research are not intended for and must pot be distributed to any person in Anstra1i.4 other than' a wholesale ' 'client (as defined in Chapter 7 of the Corporations Act). : These criteria represent the specific application of fundamental principles that define credit risk and ratings opinions. Their use is determined by issuer- or issue-specific attributes as well as Standard & Poo?s Ratings Services' assessment of the credit and, if applicable, structural risks for a given issuer or issue rating. Methodology and assumptions may change from time to time as a result Of market and economic conditions, issuer- or issue-specific factors, or new empirical evidence that would affect our credit judgment. NOVEMBER 19, :b228 I 30002u

72 Exhibit EL-2 Attachment 5 Page 23 of 23 Copyright by Standard & Poor's Financial Services LLC. All rights reserved. No content (including ratings, credit-related analises and data, valuations, model, software or other application or output therefrom) or any part thereof (Content) may be modified., reverse engineered, reproduced or distributed in any form by any means, or stored in a database or retrieval system, without the prior written permission of Standard & Poor's Financial Services LLC or its affiliates (collectively, S&P). The Content shall not be used for any unlawful or unauthorized purposes. S&P and any third-party prdviders, as well as their directors, officers, shareholders, employees or agents (collectively S&P Parties) do not guarantee the accuracy, Completeness, timeliness or availability of the Content. S&P Parties are not responsible for any eners_or omissions (negligent or otherwise), regardless of the cause, for the results obtained from the use of the Content, or for the security or maintenance of any data input by the user. The Content is provided on an "as is" basis. S&P PARTIES DISCLAIM ANY AND ALL EXPRESS OR IMPLIED WARRANTIES, INCLUDING, BUT NOT LIMITED TO, ANY WARRANTIES OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE OR USE, FREEDOM FROM BUGS, SOFTWARE ERRORS OR DEFECTS, THAT THE CONTENTS FUNCTIONING WILL BE UNINTERRUPTED, OR THAT THE CONTENT WILL OPERATE WITH ANY SOFTWARE OR HARDWARE CONFIGURATION. In no event shall S&P Parties be liable to any party for any direct, indirect, incidental, exemplary, compensatory, punitive, special or consequential damages, costs, expenses, legal fees, or losses (including, without limitation, lost income or lost profits and opportunity costs or losses caused by negligence) in connection with any use of the Content even if advised of the possibility of such damages. Credit-related and other analyses, including ratings, and statements in the Content are statements of opinion as of the date they are expressed and not statements of fact. S&P's opinions, analyses, and rating acknowledgment decisions (described below) are not recommendations to purchase, hold, or sell any securities or to make any investment decisions, and do not address the suitability of any security. S&P assumes no obligation to update the Content following publication in any form or format. The Content should not be relied on and is not a substitute for the skill, judgment and experience of the user, its management, employees, advisors and/or clients when making investment and other business decisions. S&P does not act as a fiduciary or an investment advisor except where registered as such. While S&P has obtained information from sources it believes to be reliable, S&P does not perform an audit and undertakes no duty of due diligence or independent verification of any information it receives. To the extent that regulatory authorities allow a rating agency to acknowledge in one jurisdiction a rating issued in another jurisdiction for certain regulatory purposes, S&P reserves the right to assign, withdraw, or suspend such acknowledgement at any time and in its sole discretion. S&P Parties disclaim any duty whatsoever arising out of the assignment, withdrawal, or suspension of an acknowledgment as well as any liability for any damage alleged to have been suffered on account thereof. S&P keeps certain activities of its business units separate from each other in order to preserve the independence and objectivity of their respective activities_ As a result, certain business units of S&P may have information that is not available'to other S&P business units. S&P has established policies and procedures to maintain the confidentiality Of certain nonpublic information received in connection with each analytical process. S&P may receive compensation for its ratings and certain analyses, normally from issuers or underwriters of securities or from obligors. S&P reserves the right to disseminate its opinions and analyses. S&P's public ratings and analyses are made available on its Web sites, (free of charge), and and (subscription) and (subscription) and may be distributed through other means, including via S&P publications and third-party redistributors. Additional information about our ratings fees is available at WV/W.STANBARDANDPOORS.COM/RATINGSDIRECT NOVEMBER 19, a2.8 l

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74 Exhibit EL-2 Attachment 6 Page 1 of 63 - DECEMBER 23, 2013 INFRASTRUCTURE RATING METFIODOLOGY Regulated Electric and Gas Utilities Table of Contents'. SUMMARY ABCUT THE RATED UNIVERSE 4 ABOUT THIS RATING METHODOLOGY 6 DISCUSSION OF THE GP,ID FACTORS 9 CONCLUSION: SUMMAR.Y OF THE GRID- INDICATED RATING OUTCOMES 31 APPENDIX A. REGULATED ELECTRIC AND GAS UTIUDES METHODOLOGY FACTOR GRID 33 APPENDIX B: REGULATED ELECTRIC AND GAS UTRITIES -ASSIGNED RATINGS AND GRID-INDICATED RATINGS FOR A SELECTED CROSS-SECTION OF ISSUERS 39 APPENDIX REGULATED ELECTRIC AND GAS UTILITY GRID OUTCOMES AND 0:17LIER DISCUSSION 41 APPENDIX D: ARPROAO-I TO PATINGS WIT! IIN A UTIUTY FAMILY 46 APPENDIX E: BRIEF DESCRIPTIONS OF rp IE TYPES or COMPANIES RATED UNDER TIIISMCDIODOLOGY 45 APPENDIX F; KEY INDUSTRY ISSUES OVER 7HE INTERMEDIATE TERM 52 APPENDW P.EGIONAL AND OTHER CONSIDERATIONS se APPENDIX H. TREATMENT Of POWER PJR CHASE AGREEMENTS ("PPAS1 58 MOODY'S RELATED RESEARCH 62 Analyst Contacts: NEW YORK ter ' - Semi)/ Credt Offker hurrenamuldys ui Michael C. Hzgearty rqz Symmary This rating methodology explains Moody's approach to assessing credit risk for regulated electric and gas utilities globally and is intended to provide general guidance that helps companies, investors, and other interested market participants understand how qualitative 4 and quantitative risk characteristics are likely to affect rating outcomes for companies in the regulated electric and gas utility industry. This document does not include an exhaustive tieatment of an factors that are reflected in Moodys ratings but should enable the reader to understand the qualitative considerations and financial information and ratios tha.t are u;ually most important for ratings in this sector. This rating methodology replaces the Rating Methodology for Regulated Electric and Gas thilities published in August While reflecting many of the same core principles as the 2009 methodology, this updated document provides a more transparent presentation of the rating considerations that are usually most important for companies in this sector and incorporates refinements in our analysis that better reflect credit fimdamenrals of the industry. No rating changes will result from publication of this rating methodology. This report indudes a detailed rating grid and illustrative examples that compare the mapping of rated public companies against the factors in the grid. The grid is a reference tool that can be used to approximate credit profiles within the regulated dectric and gas utility sector in most cases. The grid provides summarized guidance for the factors that are generally most important in assigning ratings to companies in the regulated electric and gas utility industry. However, the grid is a summary that does not include every rating consideration. The weights shown for each factor in the grid represent an approximation of their importance for rating decisions but actual importance may vary substantially. In addition, the illustrative mapping examples in this document use historical results while raings are based on our forward-looking expectations. As a result, the grid-indicated rating is ;lot expected to match the actual rating of each cosilpany. coni Jrnl lemmtrad eutte kt.najing Dreciur lames, r-flostea:rmeudp..toin W. Ty -42.ss MaAwng DI:error -!fri.dler Voi 'an Ine.J Vr. tm This update may not be cffective in some hubdictions until certain requirements arc met 00769

75 Exhibit EL-2 Attachment 6 Page 2 of 63 MO6DY'S INVESTORS SERVICE 1 INFRAST RUC WRE The grid contains foiir key factors that are important in our assessment for ratings in the regulated electric and gas utility sector, 'and a notching factor for structural subordination at holding companies: I. Regulatory Frainework 2. Ability to Recover Costs and Farn Returns 3. Diversification 4. Financial Strength Some of these factors also encompass a number of sub-factors. Since an issuer's scoring on a particular grid factor or sub-factor ofien will not match its overall rating, in Appendix C we include a discussion of some of the grid "outliers" companies whose grid-indicated raring for a specific sub-factor differs significantly fiom the actual rating in order to provide additional insights. This rating methodology is not intended to be an exhaustive discussion of all factors that our analysts consider in assigning ratings in this sector. We note that our analysis for ratings in this sector covers factors that are common across all industries such as ownership, management, liquidity, corporate legal structure, governance and country related risks which are not explained in detail in this document, as well as factors that can be meaningful on a company-specific basis. Our ratings consider these and other qualitative considerations that do not lend themselves to a transparent presentation in a grid format. The grid used for this methodology reflects a decisfon to favor a relatively simple and transparent presentation rather than a more complex grid that would map grid-indicated ratings more closely to actual ratings. Highlights of this report include: >> An overview of the rated universe A summary of the rating methodology A disaission of the key rating factors that drive ratings Comments on the rating methodology assumptions and limitations, including a discussion of rating considerations that are not included in the grid The Appendices show the full grid (Appendix A), a list of the companiei included in our illustrative sample universe of issuers with their ratings, grid-indicated ratings and country of domicile (Appendix B), tables that illustrate the application or the grid to the sample universe of issuers, with explanatory comments on some of the more significant differences between the grid-implied rating for each subfactor and our actual rating (Appendix C)2, our approach to ratings within a utility family (Appendix D), a description of the various types of companies rated under this methodology (Appendix E), key industry issues over the intermediate term (Appendix F), regional and other considerations (Appendix G), and treatment of power purchase agreements (Appendix H). In general, the rating (tit other indicator of credit strength) utilized for comparison to the gnd-implied rating is the stnior unsecured rating for investment-grade issuers, the Corporate Family Rating (CFR) for speculative-grade issuers and the Baseline Credit Assessment (BCA) for Government Related Issuers (GRIs). Individual debt instrument ratings also factor in decisions on notching for seniority level 2nd collateral. Related documents that provide additional insight in this area are the rating methodologies 'Loss Given Default for Speculative Grade Non-Financial Companies in the US Canada and EMEA" published June 2009, and "Updated Summary Guidancx for Notching Bonds, Preferred ctock.s and Hybrid Securities ofcorpotate Issuers, published February DECLVEsi R 21, 2013 RA ML1HODOLO.,, kti..:jlaiei> LUC IR IC AMU C.16 Ul RIMS 00770

76 Exhibit EL-2 Attachment 6 Page 3 of 63 INFRASTRUCTURE What's Changed While incorporating many of the 'core principles of the 2009 version, this methodology updates how the four key rating Factors are defined, and how certain sub-factors are weighted in the grid. More specifically, this methodology introduces four equalli, weighted sub-factors into the two raring factors that are related to regulation the Regulatory Framework and the Ability to Recover Costs and Earn Returns in order to provide more granularity and transparency on the overall regulatory environment, which is the most important consideration for this sector. The weighting of the grid indicators for diversification are unchanged, but the proposed descriptive criteria have been refined to place greater emphasis on the economic and regulatory diversity of each utility's service area rather than the diversity of operations, because we think this emphasis better distinguishes credit risk. We have refined the definitions of the Generation and Fuel Diversity subfactor to better incorporate the full range of rhallenges that can affect a particular fuel type. While the overall weighting of the Financial Strength Factor is unchanged, the weighting for two subfactors that seek to measure debt in relation ro cash flow has increased. The 15% weight for CFO Pre- WC/Debt reflects our view that this is the single most predictive financial measure, followed in importance by CFO Pre-WC - Dividends/Debt with a 10% grid weighting..the additional weighting of these ratios is balanced by the elimination of a separate liquidity sub-factor that had a 10% weighting in the prior grid'. Liquidity assessment remains a key focus of our analysis. However, we consider it as a qualitative assessment outside the grid because its credit importance varies greatly over time and by issuer and accordingly is not well represented by a fixed grid weight: See "Other Rating Considerations" for insights on liquidity analysis in this sector. Lower financial metric thresholds have been introduced for certain utilities viewed as having lower business risk, for instance many US natural gas local distribution companies (LDCs) and certain US electric transmission and distribution companies (T&Ds, which lack generation but generally retain some procurement responsibilities for customers). The low end of the scale in the methodology grid has been extended from B to Caa to better capture our views of more challenging regulatory environments and weaker performance. We have introduced minor changes to financial metric thresholds at the lower end of the scale, primarily to incorporate this extension of the grid. We have incorporated scorecard notching for structural subordination at holding companies. Ratings already incorporated structural subordination, but including an adjustment in the scorecard will result in a closer alignment of grid-indicated outcomes and ratings for holding companies. Treatment of first mortgage bonds (primarily in the US), which was the subject of a Request for Comment in 2009 and adopted subsequent to the 2009 methodology, is summarized in Appendix G. This methodology describes the analytical framework used in dtermining credit ratings. In some instances our analysis is also guided by additional publications which describe our approach for analytical considerations that are not specific to any single sector. Exarnples of such considerations include but are not limited to: the assignmmt of short-term ratings, the relative ranking of different classes of debt and hybrid securities, how sovereign credit quality affects non-sovèreign issuers, and the assessment of credit support from other entities. Documents that describe our approach to such crosssector methodological considerations can be found Iiere. DECL1BE1"2.3,e-, RAI INC;.1L1HODOLO'-:;; RE(.-)LAIED LUC NI( ANL LAS,1' ILI 'WS 00771

77 Exhibit EL-2 Attachment 6 Page 4 of 63 1, INVESTORS SERVICE-- - INFRA TRUC URE About the Rated Universe The Regulated Electric and Gas Utilities rating methodology applies to rate-regulated3 electric and gas utilities that are not Networks4. Regulated Electric and Gas Utilities are companies whose predominant5 business is the sale of electricity and/or gas or related services under a rate-regulated framework, in most cases to retail customers. Also included under this methodology are rate-regulated utilities that own generating assets as any material part of their business, utilities whose charges or bills to customers include a meaningful component related to the electric or gas commodity, utilities whose rates are regulated at a sub-sovereign level (e.g. by provinces, states or municipalities), arid companies providing an independent system operator function to an electric grid. Companies rated under this rnethodology are primarily rate-regulated monopolies or, in certain circumstances, companies that may not be outright monopolies but where government regulation effectively sets prices and limits competition. This rating methodólogy covers regulated electric and gas utilities worldwide. These companies are engaged in the production, transmission, coordination, distribution and/or sale of electricity and/or natural gas, and they are either investor owned companies, commercially oriented government owned companies or, in the case of independent system operators, not-for-profit or similar entities. As detailed in Appendix E, this methodology covers a wide variety of companies active in the sector, including vertically integrated utilities, transmission and distribution utilities with retail customers and/or sub-sovereign regulation, local gas distribution utility companies (LDCs), independent system operators, and regulated generation companies. These companies may be operating companies or holding companies. An over-arching consideration for regulated utilities is the regulatory environment in which they operate. While regulation is also a key consideration for networks, a utility's regulatory environment is in comparison often more dynamic and more subject to political intervention. The direct relationship that a regulated utility has with the retail customer, including billing for electric or gas supply that has substantial price volatility, can lead to a more politically charged rate-setting environment. Similarly, regulation at the sub-sovereign level is often more accessible for participation by interveners, including disaffected customers and the politicians who want their votes. Our views of regulatory environments evolve over rime in accordance with our observations of regulatory, political, and judicial events that affect issuers in the sector. This methodology pertains to regulated electric and gas utilities and excludes the following types of issuers, which are covered by separate rating methodologies: Regulated Networks, Unregulated Utilities and Power Companies, Public Power Utilities, Municipal Joint Action Agencies, Electric Cooperatives, Regulated Water Companies and Natural Gas Pipelines. Companies in many industries are regulated. We use the term rate-regulated to distinguish companies whose rates (by which we also 111Call tariffs or revenues in general) 2re set by regulators. Regulated Electric and GaS Networks are companies whose predominant business is purely the transmission and/or distribution of electricity and/or natural gas without Involvernent in the procurement or sale of electricity and/or gas; whose charges to customers thus do not include a meaningful commodity cost component; which sell mainly (or in many cases exclusively) to non-retail customers; and which are rate-regulated under a national framework. 5 We generally consider a company to be predominantly a regulated electric ancl gas utility when a majority of its cash flows, prosp,..tively and on a sustained basis, are derived from regulated electdc and gas utility businesses. Since cash flows can be volatile (such that a company might have a majority of utility cash flows simply duc to a cyclical downturn al its non-utility businesses), we may also consider the breakdown of assets and/or debt of a company to determine which business is predominant. Lit.Lt-sL 3, 2O RA'INC,11.1H,X)OLO(.', FaLULAIED LLK 'MK ANT, CAS tritilles 00772

78 Exhibit EL-2 Attachment 6 Page 5 of 63 OODY. :SONVESTORS-S-ERVICE, INF RAST RUC T U RE Other Related Methodologies >) Regulated Electric and Gas Networks Unregulated Utilities and Power Companies >> Natural Gas Pipelines >> US Public Power Electric Utilities with Generation Ownership Exposure >> US Electric Generation & Transmission Cooperatives >> US Municipal joint Action Agencies Government Related Issuers: Methodology Update Global Regulated Water Uti1iee5 The rated universe includes approximately 315 entities that are either utility operating companies or a parent holding company with one or more utility company subsidiaries that operate predominantly in the electric and gas utility business. These companies account for about US$730 billion of total outstanding long-term debt instruments. The Regulated Electric and Gas Utility sector is predominantly investment grade, reflecting the stability generally conferred by regulation that typically sets prices and also limits competition, such that defaults have been lower than in many other non-financial corporate sectors. However, the nature of regulation can vary significantly from jurisdiction to jurisdiction. Most issuers at the lower end of the ratings spectrum operate in challenging regulatory environments. Additional information about the ratings and default performance of the sector can be found in our publication "Infrastructure Default and Recovery Rates H1. As shown on the following table, the ratings spectrum for issuers in the sector (both holding companies and operating companies) ranges from Aia to Ca: EXHIBIT 1 Regulated Electric and Gas Utilities' Senior Unsecured Ratings Distribution _ M1 Aaa Aal Aa2 Aa3 Al A2 A3 Baal Baa2 B Bal 8,2 Ba3 B1 B2 B3 Caal Caa2 Caa3 Ca Source. M000Ys Investors servtca, ratings as of &camber 21)13 DEut,-bER 22, 20;2 kik' IN i; methovjloc, kitailaild LIED IR IC A:ID CAS UT HI IILS 00773

79 Exhibit EL-2 Attachment 6, Peke 6 of 63' MO6DV'S INVESTORS SERVICE" INFRASTRUCTURE About this Rating Methodology This report explains the rating methodology for regulated electric and gas utilities in seven sections, which are summarized as follows: 1. Identification and Discussion of the Rating Factors in the Grid The grid in this rating methodology focuses on four rating factors. the four factors are comprised of sub-factors that provide further detail: Factor / Sub-Factor Weighting - RegUlated Utilities- - Broad 12-ating Sub-Factor Broad Rating Factors Factorweighting Rating Sub-Factor Weighting Regulatory Framework 25% Legislative and Judicial Underpinnings of the Regulatory 12.5% Framework Consistency and Predictability of Regulation, 12.5% Ability to Recover Costs 25%, Timeliness of Recovery of Operating and Capital Costs, 12.5% and Earn Returns Sufficiency of Rates and Returris 125% Diversification 10% Market Position 5%* Financial Strength, Key 40% Financial Metrics Generation and Fuel Diversity 5%** CFO -Pre-WC + Interest/ Interest 7.5% CFO pre-wc / Debt 15.0% CFO pre-wc - Dividends / Debt 10.0% Debt/Capitalization 7.5% Total 100% 100% Notching 4djustment Holding Company Structural Subordination 0 to -3 *10% weight for issuers that-lack generation, "0% weight for issuers that lack generation 2. Measurement or Estimation a Factors in the Grid We explain our general approach for scoring each grid factor and show the weights used in the grid. We also provide a rationale for why each of these grid components is meaningful as a credit indicator. The information used in assessing the sub-factors is generally found in or calculated from inforination in company financial statements, derived from other observations or estimated by Moody's analysts. Our ratings are forward-looking and reflect 'our expectations for future financial and operating performance. However, historical results are helpful in understanding patterth and trends of a company's performance as well as for peer comparisons. We Utilize historical data (in most cases, an average of the last three years of reported results) in this document to illustrate the application of the rating grid. All of the quantitative credit metrics incorporate Moody's standard adjustments to income statement, cash flow statement and balance sheet amounts for restructuring, impairment, off-balance sheet accounts, receivable securitization programs, under-funded pension obligations, and recurring operating leases. DbIlLt' Rif, RATING R1T11-TODOLOG, REGOLA I LD LUG'? RIC AND LAS LITILiIILI, 00774

80 Exhibit EL-2 Attachment 6 Page 7 of 63.1'11000Y:5 1-1VV-6.iTORS SVCF INFASTRUCIURE For definitionš of Moody's most common ratio terms plea.se see Moody's Basic Definitions for Credit Statistics, I Iser's C e (June 2011, document #78480). For a description of Moody's standard adjustments, please see Moody's Approach to Global Standard Adjustments in the Analysis of Financial Statements for Non-Financial Corporations December 2010 (128137). These documents can be found at under the Research and Ratings diiectory. In most cases;the illustrative examples in this document use historic financial data from a recent three,. year period. HoWever, the factors in the grid can be assessed using various time periods. For example, rating committees may find it analytically useful to examine both historic and expected future performance for periods of several years or more, of for individual twelve month periods. 3. Mapping Factors to ttie Rating Categoiies After estimating or calculating each sub-factor, the outcomes for each of the sub-factors are mapped to a broad Moody's rating catcioiy (Aaa, Aa, A, Baa, Ba, B, or Caa). 4. Mapping Issuers to the Grid and Discussion of Grid Outliers In Appendix C, we Provide a table showing how each company in the sample set of issuers maps to grid-indicated ratings for each radng sub-factor and factor. We highlight companies whose gridindicated performance on a specific Sub:factor is two or more broad rating categories higher or lower tha.n its actual rating and discuss the general reasons for such positive and negative outliers for a partici, la r sub-factor. 5: Assumptions, Limitations and Rating ConsideratiOns Not Included in the Grid This section discusses limitations in the use of the grid to map against actual ratings, some of the additional factors that are not included in the grid but can be important in determining ratings, and limitations and assumptions that pertain to the overall rating methodology. 6. Determining the Overall Grid-Indicated Rating To determine the overall grid-indicated rating, we comiert each of the sub-factor ratings into a numeric value based upon the scale below. Aaa Aa A Ban Ba & Caa Ca DEU.r 5'ER i RA-ING ML1HOL,01.00':NE.G,11.ArLD CSRc,Â1D I,AS LIDUDES 00775

81 Exhibit EL-2 Attachment 6 Paie 8 of 63,frtOo'DY'S'INESTORS SERVICE INFRASTRUCTURE The nunierical score for each sub-factor is multiplied by the weight for that sub-factor with the results then summed to produce a composite weighted-factor score. The composite weighted factor score is then mapped back fo an alphanumeric rating based on the ranges in the table below. Grid-indicated Rating.' Grid-indicated Rating Aggregate Weighted Tot:al Factor Score Aaa x < 1.5 Aal 1 5 a x < 2.5 AaZ 2.5 sx< 3.5 Aa3 3.5 sx<4.5 Al 4.5 sx < 5.5 A2 A3 5.5 sx< s x <7.5 Baal 7.5 s x < 8.5 Baa2 8.5 s x-< 9.5 Baa3 9.5 s x < 10.5 Bal 10.5 a x < a x < 12.5 Ba s x < 13.5 B s x < s x.'< x < 165 Caal 16.5 a x < 17.5 Caa x 185 Caa s x < 19.5 Ca x 19.5 For example, an issuer with a composite weighted factor score,of 11.7 would have a Ba2 grid-indicated rating. We used a similar procedure to derive the grid indicated ratings shown in the illustrative examples., 7. Appendices The Appendices provide illustrative examples of grid-indicated ratings based im historical fmancial information'and also provide additional ct.ommeritary and insights on our view of credit risks in 'this industry.. DV...tr5fi RÁ ENG MCI 110DOLOC.,. R.LCAILMED ELECTRIC AND C,AS litllilis 00776

82 Exhibit EL-2 Attachment 6 Page 9 of 63 '1ApotirlvvEsTOTSE14/ICE:;" INFRASTRU TURE Discussion of the Grid Factors Moody's analysis of electric and gas utilities focuses On four broad factors: >> Regulatory Framework >> Ability to Recover Costs and Earn Returns >> Diveis'ification >> Financial Strength There is also a notching factor for holding company structural subordination. Factor 1: Regulatory Framework (25%) Why it Matters For rate-regulated utilities, which typically operate as a rnonopoly, the regulatory environrnent and how the utility adapts to that environment are`the mifist important credit considerations. The regulatory environment is comprised of n;vo rating factors - the Regulatory Framework and ifs corollary factor, the Ability to Recover Costs and Earn Returns. Broadly spenking, the Regulatory Framework is the foundation for how all the decisions that affect Utilities are made (including the setting of rates), as well as the predictability Ind consistency of decision-making provided by that foundation. The Ability to Recover Costs and Earn Returns relates more directly to the actual decisions, including their tinreliness and the rate-setring outcomes. Utility rates6 are set in a political/regulatory process rather than a competitive or free-market Process; thus, the Regulatory Framework is a key determinantuf the success of utility. The Regulatory Framework has many components: the governing body and the utility legislation or decrees it enacts, the manner in which regulators are appointed or elected, the rules and procedures promulgated by :those regulators, the judiciary that interprets the laws and rules and that arbitrates disagreements, and the manner in which the utility Manages the political and regulatory process. In many cases, utilities have experienced credit stress or default primarily or at least secondarily because of a break-down or obstacle in the'regulatory Framework for instance, laws that Prohibited regiaators froth including investments in uncompleted power plants or plants not deemed "used and usefur in rates, or a disagreement about rate-making that could not be resolved until after the utility had defaulted on its debts. How We Assess Legislative and judicial Underpinnings of the Regulatory Framework for the Grid For this sub-factor, we consider the scope, clarity, transparency, supportiveness and granularity of utility legislation, decrees, and rules as theyapply to the issuer. We also consider the strength of the regulator's authority over rate-making and other regulatory issues affecting the utility, the effectiveness of the judiciary or other independent body in arbitrating disputes in a disinterested manner, and whether the utility's monopoly has meaningful or growing carve-outs. In addition, we look at how well developed the framework is both how fully fleshed out the rules and regulations are and how well tested it is the extent to which regulatory or judicial decisions have created a body of precedent that will heir determine future rate-making. Since the focus of our scoring is on each issuer, we corisider 6 In jurisdictions where utility revenues include matenal government subsidy payments, we consider utility rates to be inclusive of these payments, and We thus evaluate sub-factors la, lb, 2a and 2b in light of both rates and material subsidy payments. For example, we would consider the kgal and judicial underpinnings and consistency and predictability of subsidies as well 2S rates. DE(Lf.SER 23, io istinc, NE 1 HODOL0.1.,,, ltic, JLAILD MID LAS ILI 11ES 00777

83 Exhibit EL-2 Attachment 6 Page 10 of 63 MOODY'S: INVESTORS SERVICE AS1 RUCTURE how., effective the utility is in navigating the regulatory frameivork both the utility's ability to shape the framework and adapt to it. A utility operating in a regulatory framework that is characterized by legislation that is credit supportive of utilities and eliminates doubt by prescribing many of the procedures that the regulators will use in determining fair rates (which legislation may show evidence of being responsive to the needs of the utility in general or specific ways), a long history of transparent rate-setting, and a judiciary that has provided ample precedent by impartially adjudicating disagreements in a manner that addresses ambiguities in the laws and iules will receive higher scores in the Legislative and Judiclal Underpinnings sub-factor. A utility operating in a regulatory framework that, by statute or practice, allows the regulator to arbitrarily prevent the utiliry from recovering its costs or earning a reasonable return on prudently incurred investments, or where regulatory decisions may be reversed by politicians seeking to enhance their populist appeal will receive a much lower sore. - In general, we view national utility regulation as being less liable to political intervention than regulation by state, provincial or municipal entities, so the very highest scoring in this sub-faotor is reserved for this category. However, we ackno*ledge that states and provinces in some countries rnay be larger than small nations, such that their regulators may be equally "above-the-fray" in term's of impartial and technically-oriented rate setting, and very high scoring may be. appropriate. The relevant judicial system can be a major factor in the regulatory framework. This is particularly true in litigious societies like the Unit'ed States, where disagreements between the utility and its state or municipal regulator may eventually be adjudicated in federal district courts or even by the US Supreme Court. In addition, bankruptcy proceeding's in the 'US take place in federal courts, which have at times been able to impose rate settlement agreements on state or municipal regulators. As a result, the range of dejisions available fo state regulators may be effectively circumscribed by court precedent at the state or fedeial level, which we generally view as favorable for thecreditsupportiveness of the regulatory framework. Electric and gas utilities are generally presumed to have a strong monopoly that will continue into the foreseeable finure, and this expectation has allowed these companies to have greater leverage than companies in other sectors with similar ratings. Thus, the existence of a monopoly in itself is unlikely to be a driver of strong `scoring in this sub-factor. On the other hand, a strong challenge to the monopoly could cause lower scoring, because the utility can only recover its costs and investments and service its debt if customers purchase its services. There have some instances of incursions into utilities' monopoly, including municipalization, self-generation, distributed generation with`net metering, `o'r unauthorized u.se (beyond the level for which the utility receives compensation in rates). Incursions that are growing significantly or li-aving a meaningful impact on rates for customers that remain with the utility could have a negative impact on scoring' of this Sub-factor and on factor 2 -Ability to Recover Costs and Earn Returns. The scoring of this sub-factor may not be the same for every utility in a particular jurisdiction. We have observed that some utilities appear to have greater sway over the relevant utiliry legislation and promulgation of rules than other utilities even those in the sarne jurisdiction. The content and tone of publicly filed documents and regulatory decisions sometimes indicates that the management team at one utility. has better responsiveness to and credibility with its regulators or legislators than the management at another utility, fl DtarB.,..ft 23, 2013 NAT ING 1111HODOLO6V, ULArEt. LI:KINK AND MUMS 00778

84 Exhibit EL-2 Attachment 6 PUCT DOCket No Page 11 of 63 INFRASTRUC uri While the underpinnings to the regulatory framework tend to change relatively slowly, they do evolve, and our factor scoring will seek to reflect that evolution. For instance, a new framewoik will typically become tested over time as regulatory decisions are issued, or perhaps litigated, thereby setting a Vody of precedent. Utilities may seek changes to Iaws in order to permit thein to securitize certain costs or collect interim rates, or a jurisdiction in which rates were previously recovered primarily in base rate proceedings may institute riders and trackers. These changes would likely impact scoring' of sub-factor 2b - Tiineliness of Recovely of Operating and Capital Costs, but they may also be sufficiently significarlt,to indicae a change in the regulatory underpinnings. On the negative side, a judiciaty that, had formerly been independent may start to issue decisions that indicate it is conforming its decisions to the eipectiiions of an executive branch that wants to mandate lower rates. DELLY3..i 22, 2012 %MING WIHOL) lay: FEU:I:A.1ED UK11;11:ANC C,AS ILI.IkS 00779

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