XML 85 R15.htm IDEA: XBRL DOCUMENT v3.2.0.727
Utility Rate Regulation
 6 Months Ended
Jun. 30, 2015
Utility Rate Regulation [Line Items]  
Utility Rate Regulation

6. Utility Rate Regulation

(All Registrants)

The following table provides information about the regulatory assets and liabilities of cost-based rate-regulated utility operations.

PPLPPL Electric
June 30,December 31,June 30,December 31,
2015201420152014
Current Regulatory Assets:
Environmental cost recovery$ 16 $ 5
Gas supply clause 1 15
Transmission service charge 7 6 $ 7 $ 6
Other 10 11 3 6
Total current regulatory assets (a)$ 34 $ 37 $ 10 $ 12
Noncurrent Regulatory Assets:
Defined benefit plans$ 745 $ 720 $ 417 $ 372
Taxes recoverable through future rates 319 316 319 316
Storm costs 108 124 38 46
Unamortized loss on debt 74 77 46 49
Interest rate swaps 98 122
Accumulated cost of removal of utility plant 125 114 125 114
AROs 91 79
Other 9 10 1
Total noncurrent regulatory assets$ 1,569 $ 1,562 $ 946 $ 897

Current Regulatory Liabilities:
Generation supply charge $ 31 $ 28 $ 31 $ 28
Demand side management 12 2
Gas supply clause 9 6
Transmission formula rate 66 42 66 42
Storm damage expense 10 3 10 3
Other 9 10 3 3
Total current regulatory liabilities$ 137 $ 91 $ 110 $ 76
Noncurrent Regulatory Liabilities:
Accumulated cost of removal of utility plant$ 693 $ 693
Coal contracts (b) 38 59
Power purchase agreement - OVEC (b) 88 92
Net deferred tax assets 24 26
Act 129 compliance rider 26 18 $ 26 $ 18
Defined benefit plans 21 16
Interest rate swaps 84 84
Other 3 4
Total noncurrent regulatory liabilities$ 977 $ 992 $ 26 $ 18

LKELG&EKU
June 30,December 31,June 30,December 31,June 30,December 31,
201520142015201420152014
Current Regulatory Assets:
Environmental cost recovery$ 16 $ 5 $ 9 $ 4 $ 7 $ 1
Gas supply clause 1 15 1 15
Fuel adjustment clause 4 2 2
Other 7 1 7 1
Total current regulatory assets$ 24 $ 25 $ 10 $ 21 $ 14 $ 4
Noncurrent Regulatory Assets:
Defined benefit plans$ 328 $ 348 $ 203 $ 215 $ 125 $ 133
Storm costs 70 78 39 43 31 35
Unamortized loss on debt 28 28 18 18 10 10
Interest rate swaps 98 122 75 89 23 33
AROs 91 79 33 28 58 51
Other 8 10 2 4 6 6
Total noncurrent regulatory assets$ 623 $ 665 $ 370 $ 397 $ 253 $ 268

Current Regulatory Liabilities:
Demand side management$ 12 $ 2 $ 5 $ 1 $ 7 $ 1
Gas supply clause 9 6 9 6
Fuel adjustment clause 4 4
Gas line tracker 1 3 1 3
Other 1 4 1 4
Total current regulatory liabilities$ 27 $ 15 $ 15 $ 10 $ 12 $ 5
Noncurrent Regulatory Liabilities:
Accumulated cost of removal
of utility plant$ 693 $ 693 $ 303 $ 302 $ 390 $ 391
Coal contracts (b) 38 59 16 25 22 34
Power purchase agreement - OVEC (b) 88 92 60 63 28 29
Net deferred tax assets 24 26 23 24 1 2
Defined benefit plans 21 16 21 16
Interest rate swaps 84 84 42 42 42 42
Other 3 4 2 2 1 2
Total noncurrent regulatory liabilities$ 951 $ 974 $ 446 $ 458 $ 505 $ 516

(a) For PPL, these amounts are included in "Other current assets" on the Balance Sheets.

(b) These liabilities were recorded as offsets to certain intangible assets that were recorded at fair value upon the acquisition of LKE by PPL.

Regulatory Matters

U. K. Activities (PPL)

RIIO-ED1

On April 1, 2015, the RIIO-ED1 eight-year price control period commenced for WPD’s four DNOs. See "Item 1. Business - Segment Information - U. K. Regulated Segment" of PPL's 2014 Form 10-K for additional information on RIIO-ED1.

Ofgem Review of Line Loss Calculation

In March 2014, Ofgem issued its final decision on the DPCR4 line loss incentives and penalties mechanism. As a result, during the first quarter of 2014 WPD increased its liability by $65 million for over-recovery of line losses with a reduction to "Utility" revenues on the Statement of Income. WPD began refunding the liability to customers on April 1, 2015 and will continue through March 31, 2019. The liability at June 30, 2015 was $88 million.

Kentucky Activities (PPL, LKE, LG&E and KU)

Rate Case Proceedings

On November 26, 2014, LG&E and KU filed requests with the KPSC for increases in annual base rates for LG&E's electric and gas operations and KU's electric operations.  On April 20, 2015, LG&E and KU, and the other parties to the proceeding, filed a unanimous settlement agreement with the KPSC.  The settlement agreement was approved by the KPSC on June 30, 2015. Among other things, the settlement provides for increases in the annual revenue requirements associated with KU base electricity rates of $125 million and LG&E base gas rates of $7 million.  The annual revenue requirement associated with base electricity rates at LG&E was not changed.  Although the settlement did not establish a specific return on equity with respect to the base rates, an authorized 10% return on equity will be utilized in the ECR and GLT mechanisms.  The settlement agreement provides for deferred recovery of costs associated with Green River Units 3 and 4 through their retirement.  The new regulatory asset will be amortized over three years. The settlement also provides regulatory asset treatment for the difference between pension expense currently booked in accordance with LG&E and KU’s pension accounting policy and pension expense using a 15 year amortization period for actuarial gains and losses. The new rates and all elements of the settlement became effective July 1, 2015.

KPSC Landfill Proceedings

On May 22, 2015, LG&E and KU filed an application with the KPSC for a declaratory order that the existing CPCN and ECR approvals regarding the initial phases of construction and rate recovery of the landfill for management of CCRs at the Trimble County Station remain in effect. The current design of the proposed landfill provides for construction in substantially the same location as originally proposed with approximately the same storage capacity and expected useful life. On May 20, 2015, the owner of an underground limestone mine filed a complaint with the KPSC requesting it to revoke the CPCN for the Trimble County landfill and limit recovery of costs for the Ghent Station landfill on the grounds that, as a result of cost increases, the proposed landfill no longer constitutes the least cost alternative for CCR management. The KPSC has initiated its own investigation, consolidated the proceedings, and ordered an accelerated procedural schedule. Although the companies continue to believe that the landfills at the Trimble County and Ghent stations are the least cost options and the CPCN and prior KPSC determinations provide the necessary regulatory authority to proceed with construction of the landfill and obtain cost recovery, LG&E and KU are currently unable to predict the outcome or impact of the pending proceedings.

Pennsylvania Activities (PPL and PPL Electric)

Act 11 authorizes the PUC to approve two specific ratemaking mechanisms: the use of a fully projected future test year in base rate proceedings and, subject to certain conditions, the use of a Distribution System Improvement Charge (DSIC). Such alternative ratemaking procedures and mechanisms provide opportunity for accelerated cost-recovery and, therefore, are important to PPL Electric as it is in a period of significant capital investment to maintain and enhance the reliability of its delivery system, including the replacement of aging distribution assets.

Rate Case Proceeding

On March 31, 2015, PPL Electric filed a request with the PUC for an increase in its annual distribution revenue requirement of approximately $167.5 million.  The proposal would result in a rate increase of 3.9% on a total bill basis and is expected to become effective on January 1, 2016.  PPL Electric's application includes a request for an authorized return-on-equity of 10.95%.  The application is based on a fully projected future test year of January 1, 2016 through December 31, 2016. PPL Electric cannot predict the outcome of this proceeding.

Distribution System Improvement Charge (DSIC)

On March 31, 2015, PPL Electric filed a petition requesting a waiver of the DSIC cap of 5% of billed revenues and approval to increase the maximum allowable DSIC from 5% to 7.5% for service rendered after January 1, 2016. PPL Electric filed the petition concurrently with its 2015 rate case and the Administrative Law Judge granted PPL Electric's request to consolidate these two proceedings. PPL Electric cannot predict the outcome of this proceeding.

Storm Damage Expense Rider (SDER)

In its December 28, 2012 final rate case order, the PUC directed PPL Electric to file a proposed SDER. The SDER is a reconcilable automatic adjustment clause under which PPL Electric annually will compare actual storm costs to storm costs allowed in base rates and refund or recoup any differences from customers. In March 2013, PPL Electric filed its proposed SDER with the PUC and, as part of that filing, requested recovery of the 2012 qualifying storm costs related to Hurricane Sandy. PPL Electric proposed that the SDER become effective January 1, 2013 at a zero rate with qualifying storm costs incurred in 2013 and the 2012 Hurricane Sandy costs included in rates effective January 1, 2014. In April 2014, the PUC issued a final order approving the SDER with a January 1, 2015 effective date and initially including actual storm costs compared to collections for December 2013 through November 2014. As a result, PPL Electric reduced its regulatory liability by $12 million in March 2014. Also, as part of the April 2014 order, PPL Electric was authorized to recover Hurricane Sandy storm damage costs through the SDER of $29 million over a three-year period beginning January 1, 2015.

On June 20, 2014, the Office of Consumer Advocate (OCA) filed a petition with the Commonwealth Court of Pennsylvania requesting that the Court reverse and remand the April 2014 order permitting PPL Electric to establish the SDER. This matter remains pending before the Commonwealth Court. On January 15, 2015, the PUC issued a final order closing an investigation related to an OCA complaint concerning PPL Electric's October 2014 preliminary SDER calculation and modified the effective date of the SDER to February 1, 2015.

Smart Meter Rider (SMR)

Act 129 requires installation of smart meters for new construction, upon the request of consumers and at their cost, or on a depreciation schedule not exceeding 15 years. Under Act 129, EDCs are able to recover the costs of providing smart metering technology. All of PPL Electric's metered customers currently have advanced meters installed at their service locations capable of many of the functions required under Act 129. PPL Electric conducted pilot projects and technical evaluations of its current advanced metering technology and concluded that the current technology does not meet all of the requirements of Act 129. PPL Electric recovered the cost of its evaluations through a cost recovery mechanism, the Smart Meter Rider. In August 2013, PPL Electric filed with the PUC an annual report describing the actions it was taking under its Smart Meter Plan during 2013 and its planned actions for 2014. PPL Electric also submitted revised SMR charges that became effective January 1, 2014. In June 2014, PPL Electric filed its final Smart Meter Plan with the PUC. In that plan, PPL Electric proposes to replace all of its current meters with advanced meters that meet the Act 129 requirements. Full deployment of the new meters is expected to be complete by the end of 2019. The total cost of the project is estimated to be approximately $450 million, of which approximately $328 million is expected to be capital. PPL Electric proposes to recover these costs through the SMR which the PUC previously approved for recovery of such costs. On April 30, 2015, the Administrative Law Judge assigned by the PUC to review PPL Electric's Smart Meter Plan issued a recommended decision approving the plan with minor modifications. The recommended decision is subject to final approval by and remains pending before the PUC.

Federal Matters

FERC Wholesale Formula Rates (PPL, LKE and KU)

In September 2013, KU filed an application with the FERC to adjust the formula rate under which KU provides wholesale requirements power sales to 12 municipal customers. Among other changes, the application requests an amended formula whereby KU would charge cost-based rates with a subsequent true-up to actual costs, replacing the current formula which does not include a true-up. KU's application proposed an authorized return on equity of 10.7%. Certain elements, including the new formula rate, became effective April 23, 2014, subject to refund. In April 2014, nine municipalities submitted notices of termination, under the original notice period provisions, to cease taking power under the wholesale requirements contracts. Such terminations are to be effective in 2019, except in the case of one municipality with a 2017 effective date. In addition, a tenth municipality has become a transmission-only customer as of June 2015. In July 2014, KU agreed on settlement terms with the two municipal customers that did not provide termination notices and filed the settlement proposal with the FERC for its approval. In August 2014, the FERC issued an order on the interim settlement agreement allowing the proposed rates to become effective pending a final order. If approved, the settlement agreement will resolve the rate case with respect to these two municipalities, including approval of the formula rate with a true-up provision and authorizing a return on equity of 10% or the return on equity awarded to other parties in this case, whichever is lower. In July 2015, KU and the nine terminating municipalities reached a settlement in principle which, subject to FERC approval, would resolve open matters, including providing for certain refunds, approving the formula rate with a true-up provision, and authorizing a 10.25% return on equity. An unresolved matter with one terminating municipality may be the subject of further negotiations or proceedings. KU cannot predict the ultimate outcome of these FERC proceedings regarding its wholesale power agreements with the municipalities, but does not currently anticipate significant remaining refunds beyond amounts already recorded.