ITEM 1. BUSINESS
GENERAL
BACKGROUNDCapitalized terms and abbreviations are defined in the glossary. Dollars are in millions, unless otherwise noted.
PPLTalen Energy Corporation,, through its principal subsidiary Talen Energy Supply, is a North American competitive energy and power generation and marketing company headquartered in Allentown, Pennsylvania, is an energyPennsylvania. Talen Energy produces and utility holding company that was incorporated in 1994. Through subsidiaries, PPL generatessells electricity, capacity and ancillary services from its fleet of power plants totaling approximately 17,400 MW of generating capacity. Talen Energy's portfolio of generation assets is principally located in the northeastern, northwesternNortheast, Mid-Atlantic and southeastern U.S.; markets wholesale or retail energy primarily in the northeastern and northwestern portionsSouthwest regions of the U.S.; delivers electricity to customers in Pennsylvania, Kentucky, Virginia, Tennessee and the U.K.; and delivers natural gas to customers in Kentucky. See "Item 2. Properties" for additional information on Talen Energy's plants.
PPL's overall strategy is to achieve stable, long-term growth in its regulated electricity delivery businesses through efficient operationsTalen Energy's business was formed on June 1, 2015 by the spinoff of Talen Energy Supply, the competitive power generation business owned by PPL, and strong customerthe substantially contemporaneous combination of that business with RJS Power, the competitive power generation business controlled by Riverstone Holdings LLC, under a new holding company, Talen Energy Corporation. See Notes 1, 3 and regulatory relations, and disciplined optimization of energy supply margins in its energy supply business while mitigating volatility in both cash flows and earnings.
In pursuing this strategy, in 2011 and 2010, PPL completed two significant acquisitions that have reduced PPL's overall business risk profile and reapportioned the mix of PPL's regulated and competitive businesses by increasing the regulated portion of its business:
| · | On April 1, 2011, PPL, through an indirect, wholly owned subsidiary, PPL WEM, completed its acquisition of all the outstanding ordinary share capital of Central Networks East plc and Central Networks Limited, the sole owner of Central Networks West plc, together with certain other related assets and liabilities (collectively referred to as Central Networks and subsequently renamed WPD Midlands), from subsidiaries of E.ON AG. WPD Midlands operates two regulated distribution networks that serve five million end-users in the Midlands area of England. |
| · | On November 1, 2010, PPL acquired all of the limited liability company interests of E.ON U.S. LLC from a wholly owned subsidiary of E.ON AG. Upon completion of the acquisition, E.ON U.S. LLC was renamed LG&E and KU Energy LLC (LKE). LKE is engaged in regulated utility operations through its subsidiaries, LG&E and KU. |
See Note 106 to the Financial Statements for additional information on both acquisitions.the spinoff and acquisition.
Each rate-regulated business plansTalen Energy seeks to make materialoptimize the value from its competitive power generation assets and marketing portfolio while mitigating near-term volatility in both cash flow and earnings metrics. Talen Energy endeavors to accomplish this by matching projected output from its generation assets with forward power sales in the wholesale and retail markets while effectively managing exposure to fuel price volatility, counterparty credit risk and operational risk. Talen Energy is focused on safe, reliable, and resilient operations, disciplined capital investments overinvestment, portfolio optimization, cost management and the next several years to improve infrastructure and customer reliability. See "Item 7. Management's Discussion and Analysispursuit of Financial Condition and Results of Operations - Financial Condition - Liquidity and Capital Resources" for information on each Registrant's capital expenditure projections.value-enhancing growth opportunities.
ATo manage financing costs and access to credit markets, and to fund capital expenditures and growth opportunities, a key objective of PPL's business strategyTalen Energy is to maintain adequate liquidity capacity. In addition, Talen Energy has a strongfinancial risk management policy and operational procedures that, among other things, are designed to monitor and manage exposure to earnings and cash flow volatility related to, as applicable, changes in energy and fuel prices, interest rates, counterparty credit profile. PPL's recent growth in rate-regulated businesses has provided the organization with an enhanced corporate level financing alternative, through PPL Capital Funding, that further enables PPL to support targeted credit profiles cost effectively across all of PPL's rated companies. As a result, PPL plans to further utilize PPL Capital Funding in addition to continued direct financing byquality and the operating companies,performance of generating units. To manage these risks, Talen Energy generally uses contracts such as appropriate.forwards, options, swaps and insurance contracts primarily focused on mitigating cash flow volatility within the next 12 month period.
AtThe following chart illustrates Talen Energy's organizational structure as of December 31, 2012, PPL had:2015.
Talen Energy's subsidiaries, Talen Generation, Raven, Jade, Sapphire, and MACH Gen, own and operate competitive power generation facilities. Another Talen Energy subsidiary, Talen Energy Marketing, markets the output of Talen Energy's plants, electricity, capacity and ancillary services, and other energy-related products in competitive wholesale and retail markets.
Talen Energy Marketing sells the output of its affiliated generation facilities to a diverse group of wholesale customers, including RTOs and ISOs, utilities, cooperatives, municipalities, power marketers, and financial counterparties. Talen Energy Marketing also sells the output of its affiliated generation plants to commercial, industrial and residential retail customers.
Talen Energy earns revenue primarily by participating in energy and capacity markets and by providing related ancillary services.
The energy markets in which Talen Energy participates are designed to meet the short-term needs for electricity. They include day-ahead markets, where hourly prices are calculated for the next operating day based on bids and offers, and real-time spot markets, in which energy is continuously bought and sold based on actual grid operating conditions.
| · | $12.3 billion in operating revenues for the year (56% from regulated businesses), |
The capacity markets in which Talen Energy participates are designed to procure sufficient generating capacity to meet forecasted peak demand to ensure that the longer-term needs for electricity are met to keep the applicable power grids operating reliably. PJM and ISO-NE procure capacity three years in advance whereas NYISO conducts three nearer term auctions; a six-month summer and winter strip auction, a monthly auction and a spot auction. Capacity markets provide generation owners, such as Talen Energy, some forward-looking revenue visibility.
Ancillary services, such as non-spinning reserves, responsive reserves and regulation up/down, are supplied in some of the markets in which Talen Energy operates to help maintain system reliability by compensating generators for being available during short-term capacity shortage conditions.
Talen Energy's generation fleet is diverse in terms of fuel, technology, dispatch characteristics and location. A majority of Talen Energy's revenue comes from the sale of electricity produced by its generation facilities. Talen Energy also produces additional revenue from the sale of capacity within the PJM, ISO-NE and NYISO markets as well as by providing ancillary services.
The charts below illustrate the composition and diversity of Talen Energy's generation portfolio capacity (summer rating) by market and fuel type as of December 31, 2015:
The charts above do not reflect the completed or announced divestitures of approximately 1,400 MW of generation capacity to satisfy the FERC approved mitigation in connection with the RJS Power acquisition. See "Acquisitions and Divestitures" below and Notes 1 and 6 to the Financial Statements for additional information.
MARKETS
Included in the table below are the markets in which Talen Energy operates and the revenue opportunities presented by each:
|
| · | 10.5 million end-users of its utility services, |
| · | approximately 19,000 MW of generation (44% within regulated businesses), and |
| · | approximately 18,000 full-time employees. |
PPL's principal subsidiaries at December 31, 2012 are shown below (* denotes an SEC registrant).
| | | | | | | | | PPL Corporation* | | | | | | | | |
| | | | | | Revenue Opportunities |
Markets | | Category | | Location | | Energy Market | | Capacity Market | | Ancillary Services |
PJM | | RTO | | All or part of thirteen states in the Northeast U.S. and the District of Columbia (DE, IL, IN, KY, MD, MI, NC, NJ, OH, PA, TN, VA & WV) | | X | | X | | | X |
ERCOT | | ISO | | Majority of the State of Texas | | X | | - | | X |
NYISO | | ISO | | State of New York | | X | | PPL Capital FundingX | | X |
ISO-NE | | RTO | | |
New England states (CT, MA, ME, NH, RI & VT) | | | |
X | | X | | X |
WECC (a) | | Investor Owned Utilities | | 14 States in the Western U.S., 2 Canadian provinces and northern Baja Mexico (AZ, CA, CO, ID, MT, NE, NM, NV, OR, SD, portion of TX, UT, WA & WY) | | X | | - | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | LKE*
| | | PPL Global
● Engages in the regulated distribution of electricity in the U.K.
| | PPL Electric*
● Engages in the regulated transmission and distribution of electricity in Pennsylvania
| | | PPL Energy Supply*
| | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
LG&E*
● Engages in the regulated generation, transmission, distribution and sale of electricity in Kentucky, and distribution and sale of natural gas in Kentucky
| | | KU*
● Engages in the regulated generation, transmission, distribution and sale of electricity, primarily in Kentucky
| | | | | | PPL EnergyPlus
● Performs energy marketing and trading activities
● Purchases fuel
| | | PPL Generation
● Engages in the competitive generation of electricity, primarily in Pennsylvania and Montana
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| | | | | | | | | | | | | | | | | | | | | | | |
| | | Kentucky Regulated
Segment
| | U.K. Regulated
Segment
| | Pennsylvania Regulated Segment
| | Supply
Segment
| | X |
In addition to PPL Corporation, the other SEC registrants included in this filing are: | |
(a) | Members are uniquely structured in that they typically do not have organized markets, but rather, are organized into 38 separate Balancing Authorities (BAs). Each BA is responsible for balancing loads and resources within their respective boundaries. |
LG&E and KU Energy LLC, headquartered in Louisville, Kentucky, is a holding company with regulated utility operations through subsidiaries, LG&E and KU, and is a subsidiary of PPL. LKE, formed in 2003, is the successor to a Kentucky entity incorporated in 1989.See "Item 2. Properties" for additional information on Talen Energy's generating plants, including each plants' market location.
Recent Market Developments
PJM
Louisville GasAs a result of unusual market and Electric Company, headquartered in Louisville, Kentucky, is a regulated utility engagedweather volatility in the first quarter of 2014, PJM determined that changes were necessary to ensure system reliability. In December 2014, PJM proposed to add an enhanced Capacity Performance (CP) product to the capacity market structure to permit additional compensation for generation transmission, distributionowners/operators to make the necessary investments to maintain system reliability in exchange for stronger performance requirements, with higher penalties for non-performers. For more information on recent PJM market developments, see "Item 7. Combined Management's Discussion and saleAnalysis of electricityFinancial Condition and Results of Operations" for additional information.
ERCOT
The PUCT and ERCOT have taken significant measures to improve scarcity pricing in ERCOT. ERCOT's system-wide offer cap was increased from $7,000 per MWh to $9,000 per MWh effective June 1, 2015. An operating reserve demand curve (ORDC) was implemented in June 2014, which is intended to produce longer periods of gradually increasing scarcity prices, and the distributionPUCT and saleERCOT are currently evaluating whether any changes need to be made to improve the operation of natural gas in Kentucky. LG&E was incorporated in Kentucky in 1913. At December 31, 2012, LG&E owned 3,354 MW of electric power generation capacity and is implementing capital projects at an existing generation facility to provide 141 MW of additional generating capacity by the end of 2015. LG&E also anticipates retiring 563 MW of coal-fired generating capacity by the end of 2015 to meet certain environmental regulations. LG&E and KU jointly dispatch their generation units with the lowest cost generation used to serve their retail native load.ORDC during scarcity conditions.
Kentucky Utilities Company, headquartered in Lexington, Kentucky, is a regulated utility engaged in the generation, transmission, distribution and sale of electricity in Kentucky, Virginia and Tennessee. KU was incorporated in Kentucky in 1912 and Virginia in 1991. KU serves its Virginia customers under the Old Dominion Power name while its Kentucky and Tennessee customers are served under the KU name. At December 31, 2012, KU owned 4,833 MW of electric power generation capacity and is implementing capital projects at an existing generation facility owned by LG&E to provide 499 MW of additional generating capacity by the end of 2015. KU retired the remaining 71 MW unit at the Tyrone plant in February 2013. KU also anticipates retiring 163 MW of coal-fired generating capacity by the end of 2015 to meet certain environmental regulations. KU and LG&E jointly dispatch their generation units with the lowest cost generation used to serve their retail native load.NYISO
PPL Electric Utilities Corporation, headquarteredThe NYISO will be undertaking its triennial Demand Curve Reset (DCR) process, which will reset the capacity auction parameters, potentially impacting compensation to capacity resources. Draft tariff sheets reflecting recommended changes to the DCR process are to be presented to the NYISO's Installed Capacity Working Group in Allentown, Pennsylvania, is a direct subsidiary of PPL incorporated in Pennsylvania in 1920 and a regulated public utility. PPL Electric delivers electricity in its Pennsylvania service territory and provides electricity supply to retail customers in that territory as a PLR under the Customer Choice Act.February 2016.
PPLTwo major initiatives, Reform the Energy Supply, LLC, headquarteredVision and the Clean Energy Standard are being pursued in Allentown, Pennsylvania,New York State. Both of these initiatives are long term endeavors and either or both could have impacts on the overall New York energy market. Talen Energy is an indirect subsidiary of PPL formed in 2000still assessing any potential impacts to both the market and is an energy company engaged through its subsidiaries in the generation and marketing of electricity, primarily in the northeastern and northwestern power markets of the U.S. PPL Energy Supply's major operating subsidiaries are PPL EnergyPlus and PPL Generation. In January 2011, PPL Energy Supply distributed its entire membership interest in PPL Global to its parent, PPL Energy Funding (the parent holding company of PPL Energy Supply and PPL Global with no other material operations), to better align PPL's organizational structure with the manner in which it manages these businesses and reports segment information in its consolidated financial statements. The distribution separated the U.S.-based competitive energy marketing and supply business from the U.K.-based regulated electricity distribution business. See Note 9 to the Financial Statements for additional information. The 2010 operating results of PPL Global, which represented the U.K. Regulated segment (formerly International Regulated), are classified as discontinued operations. At December 31, 2012, PPL Energy Supply owned or controlled 10,591 MW of electric power generation capacity and is implementing capital projects at certain of its existing generation facilities in Pennsylvania and Montana to provide 153 MW of additional generating capacity by the end of 2013.portfolio.
PPL's utility subsidiaries,ISO-NE
ISO-NE added an enhanced Performance Incentive (PI) product to the capacity market structure to permit additional compensation for generation owners/operators to make the necessary investments to maintain system reliability in exchange for stronger performance requirement, with higher penalties for non-performers without exception. The PI product was first implemented in the ninth forward capacity auction for delivery year 2018/19, which was held in February 2015. ISO-NE merged the Northeast Massachusetts zone with the Southeastern Massachusetts/Rhode Island capacity zone to create the import-constrained Southern New England (SENE) zone. The tenth forward capacity auction will now only consist of two zones: SENE and toRest of Pool (including Maine, Western/Central Massachusetts, New Hampshire and Vermont). In addition,
ISO-NE has unveiled a lesser extent, certain competitive supply subsidiaries, are subject to extensive regulation bynew, sloped demand curve design that could be implemented for the FERC related to wholesale power saleseleventh forward capacity auction and related transactions, electricity transmission service, accounting practices, issuances and sales of securities, acquisitions and sales of utility properties and payments of dividends. PPL and LKE are subject to certain FERC regulations as holding companies under PUHCA and the Federal Power Act, including with respect to accounting and record-keeping, inter-system sales of non-power goods and services and acquisitions of securities in, or mergers with, certain types of electric utility companies.would likely put downward pressure on clearing prices.
RESERVE MARGINS
SuccessorReserve margin is a measure of generation capacity available to meet peak demand. Each ISO/RTO sets a target reserve margin to ensure grid reliability, which is used as an indicator of a supply surplus or deficit based on the requirement. If the actual reserve margin exceeds the requirement, the system is in a surplus and Predecessor Financial Presentation(LKE, LG&Eenergy prices should remain lower and KU)stable. A deficit to the required reserve margin could trigger energy price spikes and volatility, sending a signal to the market that more capacity is needed. PJM, NYISO, and ISO-NE have forward looking capacity markets to procure sufficient capacity to meet forecasted demand. ERCOT operates in an energy only market, where scarcity pricing sends the signal to develop more capacity. Each market is currently well supplied and reserve margins exceed their targets and low energy prices are reflective of the adequate reserves. The table below contains the target reserve margin and the expected reserve margin for the 2015/16 planning year for each of the aforementioned ISOs/RTOs:
|
| | | | | | |
ISO/RTO | | Target Reserve Margin (a) | | 2015/16 Planning Year Reserve Margin (a) |
PJM (b) | | 15.6 | % | | 20.2 | % |
NYISO | | 17.0 | % | | 24.7 | % |
ISO-NE | | 15.0 | % | | 22.8 | % |
ERCOT | | 13.8 | % | | 15.7 | % |
| |
(a) | Source: data obtained from applicable ISO/RTO or other federal agency publications. |
| |
(b) | PJM announced that the target reserve margin increased to 16.5% for planning year 2019/20. |
OPERATIONS
LKE's, LG&E's and KU's Financial Statements and related financial and operating data include the periods before and after PPL's acquisition of LKE on November 1, 2010 and have been segregated to present pre-acquisition activity as the Predecessor and post-acquisition activity as the Successor. Certain accounting and presentation methods were changed to acceptable alternatives to conform to PPL's accounting policies, and the cost bases of certain assets and liabilities were changed as of November 1, 2010 as a result of the application of push-down accounting. Consequently, the financial position, results of operations and cash flows for the Successor periods are not comparable to the Predecessor periods; however, the core operations of LKE, LG&E and KU have not changed as a result of the acquisition.Revenues by Segment
Segment Information
(PPL)
PPLTalen Energy is organized into four reportablein two segments: Kentucky Regulated, U.K. Regulated (name changed in 2012 from International Regulated), Pennsylvania RegulatedEast and Supply. There were no changes to reportable segments in 2012 other thanWest, based on geographic location. The East segment includes the name change noted above.
A comparison of PPL's three regulated segments is shown below: |
| | | | | | | | | | |
| | | KY Regulated (a) | | U.K. Regulated (b) | | PA Regulated (c) |
| | | | | | | | | | |
For the year ended December 31, 2012: | | | | | | | | | |
| Operating Revenues (in billions) | | $2.8 | | $2.3 | | $1.8 |
| Net Income Attributable to PPL Shareowners (in millions) | | $177 | | $803 | | $132 |
| Electric energy delivered (GWh) | | 30,908 | | 77,467 | | 36,023 |
At December 31, 2012: | | | | | | | | |
| Regulatory Asset Base (in billions) (d) | | $6.7 | | $8.6 | | $3.5 |
| Service area (in square miles) | | 9,400 | | 21,400 | | 10,000 |
| End-users (in millions) | | 1.3 | | 7.8 | | 1.4 |
(a) | Business activities include the generation, transmission, distribution and sale of electricity and the distribution and sale of natural gas. |
(b) | Business activities include the distribution of electricity. |
(c) | Business activities include the transmission and distribution of electricity. |
(d) | Represents RAV for U.K. Regulated, capitalization for KY Regulated and rate base for PA Regulated. |
(PPL Energy Supply)
PPL Energy Supply has operated in a single reportable segment since 2011. Prior to 2011, PPL Energy Supply's segments consisted of Supply and U.K. Regulated (formerly International Regulated). In January 2011, PPL Energy Supply distributed its 100% membership interest in PPL Global to its parent, PPL Energy Funding, to better align PPL's organizational structure with the manner in which it manages its businesses and reports segment information in its consolidated financial statements. The distribution separated the U.S.-based competitive energygenerating, marketing and supply business fromtrading activities in PJM, NYISO and ISO-NE. The West segment includes the U.K.-based regulated electricity distribution business. The 2010 operating results of PPL Global, which represented the U.K. Regulated segment, are classified as discontinued operations for PPL Energy Supply.
(PPL Electric, LKE, LG&Egenerating, marketing and KU)
PPL Electric, LKE, LG&Etrading activities located in ERCOT and KU each operate within a single reportable segment.
(PPL)
WECC. See Note 2 to the Financial Statements for financial information about the segments.
· | Kentucky Regulated Segment (PPL)
|
| |
| Consists of the operations of LKE, which owns and operates regulated public utilities engaged in the generation, transmission, distribution and sale of electricity and the distribution and sale of natural gas, representing primarily the activities of LG&E and KU. The Kentucky Regulated segment also includes interest expense related to the 2010 Equity Units that were issued to partially finance the acquisition of LKE. |
(PPL, LKE, LG&E and KU)
LKE became a wholly owned subsidiary of PPL on November 1, 2010. LG&E and KU are engaged in the regulated generation, transmission, distribution and sale of electricity in Kentucky and, in KU's case, Virginia and Tennessee. LG&E also engages in the distribution and sale of natural gas in Kentucky. LG&E provides electric service to approximately 393,000 customers in Louisville and adjacent areas in Kentucky, covering approximately 700 square miles in 9 counties. LG&E provides natural gas service to approximately 318,000 customers in its electric service area and 7 additional counties in Kentucky. KU provides electric service to approximately 510,000 customers in 77 counties in central, southeastern and western Kentucky; approximately 29,000 customers in 5 counties in southwestern Virginia; and fewer than 10 customers in Tennessee, covering approximately 4,800 non-contiguous square miles. KU also sells wholesale electricity to 12 municipalities in Kentucky under load following contracts. In Virginia, KU operates under the name Old Dominion Power Company.
In September 2010, the KPSC approved a settlement agreement among PPL and all of the intervening parties to PPL's joint application to the KPSC for approval of its acquisition of ownership and control of LKE. In the settlement agreement, the parties agreed that LG&E and KU would commit that no base rate increases would take effect before January 1, 2013. Under the terms of the settlement, LG&E and KU retained the right to seek approval for the deferral of "extraordinary and uncontrollable costs." Interim rate adjustments continued to be permissible during that period through existing fuel, environmental and demand side management recovery mechanisms. In October 2010, both the VSCC and the TRA approved the transfer of control of LKE to PPL. The orders and the settlement agreement approved by the KPSC contained certain other commitments by LG&E and KU with regard to operations, workforce, community involvement and other matters.
Also in October 2010, the FERC approved the application for the transfer of control of the utilities. The approval included various conditional commitments, such as a continuation of certain existing undertakings with intervenors in prior cases, an agreement not to terminate certain KU municipal customer contracts prior to January 2017, an exclusion of any transaction-related costs from wholesale energy and tariff customer rates to the extent that LG&E and KU have agreed not to seek recovery of the same transaction-related costs from retail customers and agreements to coordinate with intervenors in certain pending matters.
See Note 10 to the Financial Statements for additional information on regulatory matters related toTalen Energy's segments and the acquisition.
LG&E and KU provide electricity delivery service, and LG&E provides natural gas distribution service, in their respective service territories pursuant to certain franchises, licenses, statutory service areas, easements and other rights or permissions granted by state legislatures, cities or municipalities or other entities.
There are currently no other electric public utilities operating within the electric service areas of LKE. From time to time, bills are introduced into the Kentucky General Assembly which seek to authorize, promote or mandate increased distributed generation, customer choice or other developments. Neither the Kentucky General Assembly nor the KPSC has adopted or approved a plan or timetable for retail electric industry competition in Kentucky. The nature or timing of any legislative or regulatory actions regarding industry restructuring and their impact on LKE, which may be significant, cannot currently be predicted. Virginia, formerly a deregulated jurisdiction, has enacted legislation that implemented a hybrid model of cost-based regulation. KU's operations in Virginia have been and remain regulated.
Alternative energy sources such as electricity, oil, propane and other fuels provide indirect competition for natural gas revenues of LKE. Marketers may also compete to sell natural gas to certain large end-users. LG&E's natural gas tariffs include gas price pass-through mechanisms relating to its sale of natural gas as a commodity; therefore, customer natural gas purchases from alternative suppliers do not generally impact profitability. However, some large industrial and commercial customers may physically bypass LG&E's facilities and seek delivery service directly from interstate pipelines or other natural gas distribution systems.
Details of operating revenues by customer class are shown below.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Year Ended | | Year Ended | | Two Months Ended | | | Ten Months Ended |
| | December 31, 2012 | | December 31, 2011 | | December 31, 2010 | | | October 31, 2010 |
| | | | | % of | | | | | % of | | | | | % of | | | | | | % of |
| | Revenue | | Revenue | | Revenue | | Revenue | | Revenue | | Revenue | | | Revenue | | Revenue |
LKE (a) | | | | | | | | | | | | | | | | | | | | | | | | | |
Commercial | | $ | 723 | | | 26 | | $ | 719 | | | 26 | | $ | 123 | | | 25 | | | $ | 573 | | | 26 |
Industrial | | | 551 | | | 20 | | | 533 | | | 19 | | | 86 | | | 17 | | | | 424 | | | 19 |
Residential | | | 1,071 | | | 39 | | | 1,087 | | | 39 | | | 219 | | | 44 | | | | 886 | | | 40 |
Retail - other | | | 270 | | | 10 | | | 269 | | | 9 | | | 43 | | | 9 | | | | 212 | | | 10 |
Wholesale - municipal | | | 102 | | | 4 | | | 104 | | | 4 | | | 15 | | | 3 | | | | 88 | | | 4 |
Wholesale - other (b) | | | 42 | | | 1 | | | 81 | | | 3 | | | 8 | | | 2 | | | | 31 | | | 1 |
Total | | $ | 2,759 | | | 100 | | $ | 2,793 | | | 100 | | $ | 494 | | | 100 | | | $ | 2,214 | | | 100 |
| | | | | | | | | | | | | | | | | | | | | | | | | |
LG&E | | | | | | | | | | | | | | | | | | | | | | | | | |
Commercial | | $ | 374 | | | 28 | | $ | 372 | | | 27 | | $ | 66 | | | 26 | | | $ | 287 | | | 27 |
Industrial | | | 170 | | | 13 | | | 152 | | | 11 | | | 26 | | | 10 | | | | 122 | | | 12 |
Residential | | | 548 | | | 41 | | | 561 | | | 41 | | | 113 | | | 44 | | | | 446 | | | 42 |
Retail - other | | | 131 | | | 10 | | | 130 | | | 10 | | | 22 | | | 9 | | | | 98 | | | 9 |
Wholesale - other (b) (c) | | | 101 | | | 8 | | | 149 | | | 11 | | | 27 | | | 11 | | | | 104 | | | 10 |
Total | | $ | 1,324 | | | 100 | | $ | 1,364 | | | 100 | | $ | 254 | | | 100 | | | $ | 1,057 | | | 100 |
| | | | | | | | | | | | | | | | | | | | | | | | | |
KU | | | | | | | | | | | | | | | | | | | | | | | | | |
Commercial | | $ | 349 | | | 23 | | $ | 347 | | | 22 | | $ | 57 | | | 22 | | | $ | 286 | | | 23 |
Industrial | | | 381 | | | 25 | | | 381 | | | 25 | | | 60 | | | 23 | | | | 302 | | | 24 |
Residential | | | 523 | | | 34 | | | 526 | | | 34 | | | 106 | | | 40 | | | | 440 | | | 35 |
Retail - other | | | 139 | | | 9 | | | 139 | | | 9 | | | 21 | | | 8 | | | | 114 | | | 9 |
Wholesale - municipal | | | 102 | | | 7 | | | 104 | | | 7 | | | 15 | | | 6 | | | | 88 | | | 7 |
Wholesale - other (b) (c) | | | 30 | | | 2 | | | 51 | | | 3 | | | 4 | | | 1 | | | | 18 | | | 2 |
Total | | $ | 1,524 | | | 100 | | $ | 1,548 | | | 100 | | $ | 263 | | | 100 | | | $ | 1,248 | | | 100 |
(a) | The LKE Successor information also represents PPL's Kentucky Regulated segment. |
(b) | Includes wholesale and transmission revenues. |
(c) | Includes intercompany power sales and transmission revenues, which are eliminated upon consolidation at LKE. |
At December 31, 2012, LKE owned, controlled or had an ownership interest in generating capacity (summer rating) of 8,187 MW, of which 3,354 MW related to LG&E and 4,833 MW related to KU, in Kentucky, Indiana, and Ohio. See "Item 2. Properties - Kentucky Regulated Segment" for a complete list of LKE's generating facilities.
The system capacity of LKE's owned or controlled generation is based upon a number of factors, including the operating experience and physical condition of the units, and may be revised periodically to reflect changes in circumstances.
During 2012, LKE's Kentucky power plants generated the following amounts of electricity.
| Thousands of MWh |
Fuel Source | LKE | | LG&E | | KU |
Coal (a) | 32,820 | | 15,051 | | 17,769 |
Oil / Gas | 1,340 | | 463 | | 877 |
Hydro | 250 | | 212 | | 38 |
Total (b) | 34,410 | | 15,726 | | 18,684 |
(a) | Includes 990 MWh of power generated by and purchased from OVEC for LKE, 685 MWh for LG&E and 305 MWh for KU. |
(b) | This generation represents a 4% decrease for LKE, a 4% decrease for LG&E and a 3% decrease for KU from 2011 output. |
A significant portion of LG&E's and KU's generated electricity was used to supply its retail and municipal customer base.
LG&E and KU jointly dispatch their generation units with the lowest cost generation used to serve their retail native load. When LG&E has excess generation capacity after serving its own retail native load and its generation cost is lower than that of KU, KU purchases electricity from LG&E. When KU has excess generation capacity after serving its own retail native load and its generation cost is lower than that of LG&E, LG&E purchases electricity from KU.
See "Item 2. Properties - Kentucky Regulated Segment" for additional information regarding LG&E's and KU's plans for development of Cane Run Unit 7. KU retired the remaining 71 MW unit at the Tyrone plant in February 2013. LG&E and KU also anticipate retiring 563 MW and 163 MW of coal-fired generating capacity by the end of 2015 to meet certain environmental regulations.
Coal is expected to be the predominant fuel used by LG&E and KU for baseload generation for the foreseeable future. However, natural gas will play a more significant role starting in 2015 when Cane Run Unit 7 is expected to be placed into operation. This unit is expected to be used for baseload generation. Natural gas and oil will continue to be used for intermediate and peaking capacity and flame stabilization in coal-fired boilers.
Fuel inventory is maintained at levels estimated to be necessary to avoid operational disruptions at coal-fired generating units. Reliability of coal deliveries can be affected from time to time by a number of factors including fluctuations in demand, coal mine production issues and other supplier or transporter operating difficulties. To enhance the reliability of natural gas supply, LG&E and KU have secured long-term pipeline capacity on the interstate pipeline serving the new combined cycle unit and six simple cycle combustion turbine units.
LG&E and KU have entered into coal supply agreements with various suppliers for coal deliveries through 2017 and normally augment their coal supply agreements with spot market purchases, as needed.
For their existing units, LG&E and KU expect for the foreseeable future to purchase most of their coal from western Kentucky, southern Indiana, southern Illinois and Ohio. The use of high sulfur coal increased during 2012 due to the installation of scrubbers and the sulfuric acid mist mitigation system at KU's E.W. Brown plant. In 2013 and beyond, LG&E and KU may purchase certain quantities of ultra-low sulfur content coal from Wyoming for blending at TC2. Coal is delivered to the generating plants by barge, truck and rail.
(PPL, LKE and LG&E)
Five underground natural gas storage fields, with a current working natural gas capacity of approximately 15 Bcf, are used in providing natural gas service to LG&E's firm sales customers. By using natural gas storage facilities, LG&E avoids the costs typically associated with more expensive pipeline transportation capacity to serve peak winter heating loads. Natural gas is stored during the summer season for withdrawal during the following winter heating season. Without this storage capacity, LG&E would be required to purchase additional natural gas and pipeline transportation services during winter months when customer demand increases and the prices for natural gas supply and transportation services are typically at their highest. Several suppliers under contracts of varying duration provide competitively priced natural gas. At December 31, 2012, LG&E had a 12 Bcf inventory balance of natural gas stored underground with a carrying value of $42 million.
LG&E has a portfolio of supply arrangements of varying terms with a number of suppliers designed to meet its firm sales obligations. These natural gas supply arrangements include pricing provisions that are market-responsive. In tandem with pipeline transportation services, these natural gas supplies provide the reliability and flexibility necessary to serve LG&E's natural gas customers.
LG&E purchases natural gas supply transportation services from two pipelines. LG&E has contracts with one pipeline that are subject to termination by LG&E between 2015 and 2018. Total winter capacity under these contracts is 194,900 MMBtu/day and summer capacity is 88,000 MMBtu/day. LG&E has a contract with another pipeline that expires in October 2014. Total winter and summer capacity under this contract is 20,000 MMBtu/day during both seasons.
(PPL, LKE, LG&E and KU)
LG&E is subject to the jurisdiction of the KPSC and the FERC, and KU is subject to the jurisdiction of the KPSC, the FERC, the VSCC and the TRA. LG&E and KU operate under a FERC-approved open access transmission tariff. LG&E and KU contract with the Tennessee Valley Authority to act as their transmission reliability coordinator. LG&E and KU contracted with Southwest Power Pool, Inc. (SPP), to function as their independent transmission operator, pursuant to FERC requirements under a contract that expired on August 31, 2012. After receiving FERC approval, LG&E and KU transferred from SPP to TranServ International, Inc. as their independent transmission operator beginning September 1, 2012.
In February 2013, LG&E and KU submitted a compliance filing to the FERC reflecting their participation with other utilities in the Southeastern Regional Transmission Planning relating to certain FERC Order 1000 requirements. FERC Order 1000, issued in July 2011, establishes certain procedural and substantive requirements relating to participation, cost allocation and non-incumbent developer aspects of regional and inter-regional electric transmission planning activities.
LG&E's and KU's Kentucky base rates are calculated based on a return on capitalization (common equity, long-term debt and short-term debt) including certain adjustments to exclude non-regulated investments and costs recovered separately through other rate mechanisms. As such, LG&E and KU earn a return on the net cash invested in regulatory assets and regulatory liabilities.
KU's Virginia base rates are calculated based on a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions). All regulatory assets and liabilities, except the levelized fuel factor, are excluded from the return on rate base utilized in the calculation of Virginia base rates; therefore, no return is earned on the related assets.
KU's rates to municipal customers for wholesale requirements are calculated based on annual updates to a rate formula that utilizes a return on rate base (net utility plant plus working capital less deferred taxes and miscellaneous deductions). All regulatory assets and liabilities are excluded from the return on rate base utilized in the development of municipal rates; therefore, no return is earned on the related assets.
See Note 6 to the Financial Statements for additional information on cost recovery mechanisms.
2012 Kentucky Rate Case
In June 2012, LG&E and KU filed requests with the KPSC for increases in annual base electric rates of approximately $62 million at LG&E and approximately $82 million at KU and an increase in annual base gas rates of approximately $17 million at LG&E. In November 2012, LG&E and KU along with all of the parties filed a unanimous settlement agreement. Among other things, the settlement provided for increases in annual base electric rates of $34 million at LG&E and $51 million at KU and an increase in annual base gas rates of $15 million at LG&E. The settlement agreement also included revised depreciation rates that result in reduced annual electric depreciation expense of approximately $9 million for LG&E and approximately $10 million for KU. The settlement agreement included an authorized return on equity at LG&E and KU of 10.25%. On December 20, 2012, the KPSC issued orders approving the provisions in the settlement agreement. The new rates became effective on January 1, 2013. In addition to the increased base rates, the KPSC approved a gas line tracker mechanism for LG&E to provide for recovery of costs associated with LG&E's gas main replacement program, gas service lines and risers.
FERC Wholesale Rates
In May 2012, KU submitted to the FERC the annual adjustments to the formula rate which incorporated certain proposed increases. These rates became effective as of July 1, 2012.
· | U.K. Regulated Segment (PPL)
|
| |
| Includes WPD, a regulated electricity distribution business in the U.K. |
WPD, through indirect wholly owned subsidiaries, operates four of the 15 regulated distribution networks providing electricity service in the U.K. With the April 2011 acquisition of WPD Midlands, the number of end-users served has more than doubled totaling 7.8 million across 21,400 square miles in Wales, southwest and central England. See Note 10 to the Financial Statements for additional information on the acquisition.
Details of revenue by
categorysegment for the years ended December 31
as adjusted to reflect the November 2015 segment reevaluation referenced above, are
shown below.as follows: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2015 | | 2014 | | 2013 |
| East | | West | | Total | | East | | West | | Total | | East | | West | | Total |
Energy | | | | | | | | | | | | | | | | | |
Wholesale energy (a) | $ | 2,631 |
| | $ | 211 |
| | $ | 2,842 |
| | $ | 2,609 |
| | $ | 128 |
| | $ | 2,737 |
| | $ | 2,846 |
| | $ | 95 |
| | $ | 2,941 |
|
Retail energy | 1,022 |
| | 73 |
| | 1,095 |
| | 1,162 |
| | 81 |
| | 1,243 |
| | 945 |
| | 82 |
| | 1,027 |
|
Total Energy | 3,653 |
| | 284 |
| | 3,937 |
| | 3,771 |
| | 209 |
| | 3,980 |
| | 3,791 |
| | 177 |
| | 3,968 |
|
Energy-related businesses (b) | 544 |
| | — |
| | 544 |
| | 601 |
| | — |
| | 601 |
| | 527 |
| | — |
| | 527 |
|
Total | $ | 4,197 |
| | $ | 284 |
| | $ | 4,481 |
| | $ | 4,372 |
| | $ | 209 |
| | $ | 4,581 |
| | $ | 4,318 |
| | $ | 177 |
| | $ | 4,495 |
|
| | 2012 | | 2011 | | 2010 |
| | Revenue | | % of Revenue | | Revenue | | % of Revenue | | Revenue | | % of Revenue |
Utility revenues (a) | | $ | 2,289 | | | 98 | | $ | 1,618 | | | 98 | | $ | 727 | | | 96 |
Energy-related businesses | | | 47 | | | 2 | | | 35 | | | 2 | | | 34 | | | 4 |
Total | | $ | 2,336 | | | 100 | | $ | 1,653 | | | 100 | | $ | 761 | | | 100 |
(a) | The above years are not comparable as WPD Midlands was acquired in April 2011. 2011 includes eight months of activity as WPD Midlands' results are recorded on a one-month lag. |
WPD's energy-related businesses revenues include ancillary activities that support the distribution business, including telecommunications and real estate. WPD's telecommunication revenues are from the rental of fiber optic cables primarily attached to WPD's overhead electricity distribution network. WPD also provides meter services to businesses across the U.K.
WPD is authorized by Ofgem to provide electric distribution services within its concession areas and service territories, subject to certain conditions and obligations. For instance, WPD is subject to Ofgem regulation of the regulated revenue it can earn and the quality of service it must provide, and WPD can be fined or have its licenses revoked if it does not meet the mandated standard of service.
Although WPD operates in non-exclusive concession areas in the U.K., it currently faces little competition with respect to end-users connected to its network. WPD's four distribution businesses, WPD (South West), WPD (South Wales), WPD (West Midlands) and WPD (East Midlands), are thus regulated monopolies which operate under regulatory price controls.
The operations of WPD (South West), WPD (South Wales), WPD (East Midlands) and WPD (West Midlands) are regulated by Ofgem under the direction of the Gas and Electricity Markets Authority. The Electricity Act 1989 provides the fundamental legal framework of electricity companies and established licenses that required each of the DNOs to develop, maintain and operate efficient distribution networks. Ofgem has established a price control mechanism that restricts the amount of revenue that can be earned by regulated business and provides for an increase or reduction in revenues based on incentives or penalties for exceeding or underperforming against pre-established targets.
This regulatory structure is an incentive-based regulatory structure in comparison to the U.S. utility businesses which operate under a cost-based regulatory framework. Under the UK regulatory structure, electricity distribution revenues are currently set every five years, but extending to eight years in the next price control period beginning in April 2015. The revenue that DNOs can earn in each of the five years is the sum of: i) the regulator's view of efficient operating costs, ii) a return on the capital from the RAV plus an annual adjustment for the inflation determined by Retail Price Index (RPI) for the prior calendar year, iii) a return of capital from the RAV (i.e. depreciation), and iv) certain pass-through costs over which the DNO has no control. Additionally, incentives are provided for a range of activities including exceeding certain reliability and customer service targets.
WPD is currently operating under DPCR5 which was completed in December 2009 and is effective for the period from April 1, 2010 through March 31, 2015. Ofgem allowed WPD (South West) and WPD (South Wales) an average increase in total revenues, before inflationary adjustments, of 6.9% in each of the five years and WPD Midlands an average increase in total revenues, before inflationary adjustments, of 4.5% in each of the five years. The revenue increase includes reimbursement for higher operating and capital costs to be incurred driven by additional requirements. In DPCR5, Ofgem decoupled WPD's allowed revenue from volume delivered over the five-year price control period. However, in any fiscal period WPD's revenue could be negatively affected if its tariffs and the volume delivered do not fully recover the allowed revenue for a given period. Under recoveries are recovered in the next regulatory year, however, PPL does not record a receivable for under recoveries in the current period. Over recoveries are reflected in the current period as a liability and are not included in revenue.
In addition to providing a base regulated revenue allowance, Ofgem has established incentive mechanisms to provide significant opportunities to enhance overall returns by improving network efficiency, reliability and customer service. Some of the more significant incentive mechanisms under DPCR5 include:
· | Interruptions Incentive Scheme (IIS) - This incentive has two major components: 1) Customer interruptions and 2) Customer minutes lost and is designed to incentivize the DNOs to invest and operate their networks to manage and reduce both the frequency and duration of power outages experienced by customers. The target for each DNO is based on a benchmark of data from the last four years of the prior price control period. |
Effective April 1, 2012, an additional customer satisfaction incentive mechanism was implemented that includes a customer satisfaction survey, a complaints metric and a measure of stakeholder engagement. This incentive replaced the customer response telephone performance incentive that was effective April 1, 2010.
· | Line Loss Incentive - This incentive existed in the prior price control review, DPCR4, and was designed to incentivize DNOs to invest in lower loss equipment, to change the way they operate their systems to reduce losses, and to detect theft and unregistered meters. In November 2012, Ofgem issued a decision not to activate the DPCR5 line loss incentive. See Note 6 to the Financial Statements for information on Ofgem's review of line loss calculations. |
· | Information Quality Incentive (IQI) - The IQI is designed to incentivize the DNOs to provide good quality information when they submit their business plans to Ofgem during the price control process and to execute the plan they submitted. The IQI eliminates the distinction between capital expenditure and operating expense and instead looks at total expenditure. Total expenditure is allocated 85% to "slow pot" which is added to RAV and recovered over 20 years through the regulatory depreciation of the RAV and 15% to "fast pot" which is recovered during the current price control review period. The IQI then provides for incentives or penalties at the end of DPCR5 based on the ratio of actual expenditures to the expenditures submitted to Ofgem that were the basis for the revenues allowed during the five-year price control review period. |
At the beginning of DPCR5, WPD was awarded $301 million in incentive revenue of which $222 million will be included in revenue throughout the current price control period with the balance recovered over subsequent price control periods. Since the beginning of DPCR5, WPD earned additional incentive revenue, primarily from IIS of $83 million and $30 million for the regulatory years ended March 31, 2012 and 2011, which will be included in revenue for the 2013-14 and 2012-13 regulatory years.
In October 2010, Ofgem announced a new pricing model that will be effective for the U.K. electricity distribution sector, including WPD, beginning April 2015. The model, known as RIIO (Revenues = Incentives + Innovation + Outputs), is intended to encourage investment in regulated infrastructure. The next electricity distribution price control review is referred to as RIIO-ED1. In September 2012, Ofgem published a strategy consultation document providing an overview of its approach for RIIO-ED1 and is expected to publish a policy decision document in February 2013. Key components of the RIIO-ED1 are: an extension of the price review period to eight years, increased emphasis on outputs and incentives, enhanced stakeholder engagement including network customers, a stronger incentive framework to encourage more efficient investment and innovation, expansion of the current Low Carbon Network Fund to stimulate innovation and continued use of a single weighted average cost of capital. Ofgem has also indicated that the depreciation of the RAV for RAV additions after April 1, 2015 will change from 20 years to 45 years. Management is in the process of creating the "well-justified business plans" required by Ofgem for WPD's four DNOs. These plans are expected to be submitted to Ofgem in July 2013 as part of the RIIO-ED1 review process. Once the business plans are complete, management will be in a better position to determine the effect of RIIO-ED1 on future financial results. See "Item 1A. Risk Factors - Risks Related to U.K. Regulated Segment."
The majority of WPD's revenue is known as DUoS and is derived from charging energy suppliers for the delivery of electricity to end-users and thus its customers are the suppliers to those end-users. Ofgem requires that all licensed electricity distributors and suppliers become parties to the Distribution Connection and Use of System Agreement. This agreement sets out how creditworthiness will be determined and, as a result, whether the supplier needs to provide collateral.
· | Pennsylvania Regulated Segment (PPL)
|
| |
| Includes the regulated electric delivery operations of PPL Electric. |
(PPL and PPL Electric)
PPL Electric is subject to regulation as a public utility by the PUC, and certain of its transmission activities are subject to the jurisdiction of the FERC under the Federal Power Act. PPL Electric delivers electricity to approximately 1.4 million customers in a 10,000-square mile territory in 29 counties of eastern and central Pennsylvania. PPL Electric also provides electricity supply in this territory as a PLR.
Details of electric revenues by customer class for the years ended December 31, are shown below.
| | 2012 | | 2011 | | 2010 |
| | Revenue | | % of Revenue | | Revenue | | % of Revenue | | Revenue | | % of Revenue |
| | | | | | | | | | | | | | | | | | |
Residential | | $ | 1,108 | | | 63 | | $ | 1,266 | | | 67 | | $ | 1,469 | | | 60 |
Industrial | | | 53 | | | 3 | | | 62 | | | 3 | | | 123 | | | 5 |
Commercial | | | 366 | | | 21 | | | 431 | | | 23 | | | 588 | | | 24 |
Other (a) (b) | | | 236 | | | 13 | | | 133 | | | 7 | | | 275 | | | 11 |
Total | | $ | 1,763 | | | 100 | | $ | 1,892 | | | 100 | | $ | 2,455 | | | 100 |
(a) | Includes regulatory over- or under-recovery reconciliation mechanisms, pole attachment revenues, street lighting and net transmission revenues. |
(b) | Included in these amounts for 2012, 2011 and 2010 are $3 million, $11 million and $7 million of retail and wholesale electric to affiliate revenue which is eliminated in consolidation for PPL. |
| Franchise, Licenses and Other Regulations |
PPL Electric is authorized to provide electric public utility service throughout its service area as a result of grants by the Commonwealth of Pennsylvania in corporate charters to PPL Electric and companies to which it has succeeded and as a result of certification by the PUC. PPL Electric is granted the right to enter the streets and highways by the Commonwealth subject to certain conditions. In general, such conditions have been met by ordinance, resolution, permit, acquiescence or other action by an appropriate local political subdivision or agency of the Commonwealth.
Pursuant to authorizations from the Commonwealth of Pennsylvania and the PUC, PPL Electric operates a regulated distribution monopoly in its service area. Accordingly, PPL Electric does not face competition in its electric distribution business.
The PPL Electric transmission business, operating under the purview of the FERC-approved PJM Open Access Transmission Tariff, is subject to competition from entities that are not incumbent PJM transmission owners with respect to building and ownership of transmission facilities within PJM. No authority has yet been promulgated that sets forth the parameters of non-incumbent competition.
Transmission and Distribution
PPL Electric's transmission facilities are within PJM, which operates the electric transmission network and electric energy market in the Mid-Atlantic and Midwest regions of the U.S.
PJM serves as a FERC-approved RTO to promote greater participation and competition in the region it serves. In addition to operating the electric transmission network, PJM also administers regional markets for energy, capacity and ancillary services. A primary objective of any RTO is to separate the operation of, and access to, the transmission grid from market participants that buy or sell electricity in the same markets. Electric utilities continue to own the transmission assets and to receive their share of transmission revenues, but the RTO directs the control and operation of the transmission facilities.
As a transmission owner, PPL Electric's transmission revenues are billed to PJM in accordance with a FERC tariff that allows recovery of transmission costs incurred, a return on transmission-related plant and an automatic annual update. As a PLR, PPL Electric also purchases transmission services from PJM. See "PLR" below.
In April 2010, the FERC issued an order concluding that under the PJM Open Access Transmission Tariff, PJM may, but is not required to, designate an entity other than the incumbent PJM transmission owner to own and construct economic expansion projects and receive cost-of-service based compensation for the use of its facilities. Additionally, the FERC directed PJM to file tariff changes necessary for non-incumbent transmission owners to be provided opportunity to propose and construct transmission projects in accordance with exclusions specified in the April 2010 order and consistent with state and local laws and regulations. PJM tariff changes are currently under review by the FERC.
PPL Electric's distribution base rates are calculated based on a return on rate base (net utility plant plus a cash working capital allowance less plant-related deferred taxes and other miscellaneous additions and deductions such as materials and supplies inventories and customer deposits and advances) plus certain operating expenses. Operating expenses included in PPL Electric's distribution base rates include wages and benefits, other operation and maintenance expenses, depreciation, and taxes.
In November 2004, Pennsylvania enacted the AEPS, which requires electricity distribution companies and electricity generation suppliers to obtain a portion of the electricity sold to retail customers in Pennsylvania from alternative energy sources. Under the default service procurement plans approved by the PUC, PPL Electric purchases all of the alternative energy generation supply it needs to comply with the AEPS.
Act 129 creates an energy efficiency and conservation program, a demand side management program, smart metering technology requirements, new PLR generation supply procurement rules, remedies for market misconduct, and changes to the existing AEPS.
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, a DSIC. In August 2012, the PUC issued a final implementation order adopting procedures, guidelines and a model tariff for implementation of Act 11. Act 11 requires utilities to file an LTIIP as a prerequisite to filing for recovery through the DSIC. The LTIIP is mandated to be a five- to ten-year plan describing projects eligible for inclusion in the DSIC. PPL Electric filed its LTIIP in September 2012 and the PUC subsequently approved the LTIIP on January 10, 2013. PPL Electric filed a petition requesting permission to establish a DSIC on January 15, 2013 with rates proposed to be effective beginning May 1, 2013.
See "Regulatory Matters - Pennsylvania Activities" in Note 6 to the Financial Statements for additional information regarding Act 129, Act 11 and other legislative and regulatory impacts.
PLR
The Customer Choice Act requires Electric Distribution Companies (EDCs), including PPL Electric, to act as a PLR of electricity supply for customers who do not choose to shop for supply with a competitive supplier and provides that electricity supply costs will be recovered by the PLR pursuant to regulations established by the PUC. As of December 31, 2012, the following percentages of PPL Electric's customer load were provided by competitive suppliers: 46% of residential, 84% of small commercial and industrial and 99% of large commercial and industrial customers. The PUC continues to be interested in expanding the competitive market for electricity. See "Regulatory Matters - Pennsylvania Activities" in Note 6 to the Financial Statements for additional information.
PPL Electric's cost of electricity generation is based on a competitive solicitation process. The PUC approved PPL Electric's default service plan for the period January 2011 through May 2013, which includes 14 solicitations for electricity supply beginning January 1, 2011 with a portion extending beyond May 2013. Pursuant to this plan, PPL Electric contracts for all of the electricity supply for residential, small commercial and small industrial customers, large commercial and large industrial customers who elect to take that service from PPL Electric. These solicitations include a mix of spot market purchases and long-term and short-term purchases ranging from five months to ten years to fulfill PPL Electric's obligation to provide customer electricity supply as a PLR. To date, PPL Electric has concluded all of its planned competitive solicitations under the plan.
The PUC has directed all EDCs to file default service procurement plans for the period June 1, 2013 through May 31, 2015. PPL Electric filed its plan in May 2012. In that plan, PPL Electric proposed a process to obtain supply for its default service customers and a number of initiatives designed to encourage more customers to purchase electricity supply from the competitive retail market. In its January 24, 2013 final order, the PUC approved PPL Electric's plan with modifications and directed PPL Electric to establish collaborative processes to address several retail competition issues.
Numerous alternative suppliers have offered to provide generation supply in PPL Electric's service territory. Whether its customers purchase electricity supply from these alternative suppliers or from PPL Electric as a PLR, the purchase of such supply has no impact on the financial results of PPL Electric. The costs to purchase PLR supply, including charges paid to PJM for related transmission services, are passed directly by PPL Electric to its PLR customers without markup. See "Energy Purchase Commitments" in Note 15 to the Financial Statements for additional information regarding PPL Electric's solicitations.
Rate Cases
2012 Rate Case
In March 2012, PPL Electric filed a request with the PUC to increase distribution rates by approximately $105 million, effective January 1, 2013. On December 28, 2012, in its final order, the PUC approved a 10.4% return on equity and a total distribution revenue increase of about $71 million. The approved rates became effective January 1, 2013.
Also in its December 28, 2012 final order, the PUC directed PPL Electric to file a proposed Storm Damage Expense Rider within 90 days following the order. PPL Electric plans to file a proposed Storm Damage Expense Rider with the PUC and, as part of that filing, request recovery of the $28 million of qualifying storm costs incurred as a result of the October 2012 landfall of Hurricane Sandy.
See "Regulatory Matters - Pennsylvania Activities - Storm Costs" in Note 6 to the Financial Statements for additional information on Hurricane Sandy.
FERC Formula Rates
Transmission rates are regulated by the FERC. PPL Electric's transmission revenues are billed in accordance with a FERC-approved PJM open access transmission tariff that utilizes a formula-based rate recovery mechanism.
PPL Electric has initiated its formula rate 2012, 2011 and 2010 Annual Updates. Each update has been subsequently challenged by a group of municipal customers. In August 2011, the FERC issued an order substantially rejecting the 2010 formal challenge and the municipal customers filed a request for rehearing of that order. In September 2012, the FERC issued an order setting for evidentiary hearings and settlement judge procedures a number of issues raised in the 2010 and 2011 formal challenges. Settlement conferences were held in late 2012 and early 2013. In February 2013, the FERC set for evidentiary hearings and settlement judge procedures a number of issues in the 2012 formal challenge and consolidated that
challenge with the 2010 and 2011 challenges. PPL Electric anticipates that there will be additional settlement conferences held in 2013. PPL and PPL Electric cannot predict the outcome of the foregoing proceedings, which remain pending before the FERC.
In March 2012, PPL Electric filed a request with the FERC seeking recovery of its regulatory asset related to the deferred state tax liability that existed at the time of the transition from the flow-through treatment of state income taxes to full normalization. This change in tax treatment occurred in 2008 as a result of prior FERC initiatives that transferred regulatory jurisdiction of certain transmission assets from the PUC to FERC. At December 31, 2012 and December 31, 2011, $52 million and $53 million are classified as taxes recoverable through future rates and included on the Balance Sheets in "Other Noncurrent Assets - Regulatory assets." In May 2012, the FERC issued an order approving PPL Electric's request to recover the deferred tax regulatory asset over a 34-year period beginning June 1, 2012.
See Note 6 to the Financial Statements for additional information on rate mechanisms.
(PPL and PPL Energy Supply)
· | Supply Segment |
| |
| Owns and operates competitive domestic power plants to generate electricity; markets and trades this electricity, purchased power, and other energy-related products to competitive wholesale and retail markets; and acquires and develops competitive domestic generation projects. Consists primarily of the activities of PPL Generation and PPL EnergyPlus. |
PPL Energy Supply has generation assets that are located in the northeastern and northwestern U.S. markets. The northeastern generating capacity is located primarily in Pennsylvania within PJM and northwestern generating capacity is located in Montana. PPL Energy Supply enters into energy and energy-related contracts to hedge the variability of expected cash flows associated with its generating units and marketing activities, as well as for trading purposes. PPL EnergyPlus sells the electricity produced by PPL Energy Supply's generation plants based on prevailing market rates. PPL Energy Supply's total expected generation in 2013 is anticipated to be used to meet its committed contractual sales. PPL Energy Supply has entered into commitments of varying quantities and terms for 2014 and beyond.
Details of revenue by category for the years ended December 31, are shown below.
| | | 2012 | | 2011 | | 2010 |
| | | Revenue | | % of Revenue | | Revenue | | % of Revenue | | Revenue | | % of Revenue |
Energy | | | | | | | | | | | | | | | | | | |
| Wholesale (a) | | $ | 4,200 | | | 76 | | $ | 5,240 | | | 82 | | $ | 4,347 | | | 85 |
| Retail | | | 848 | | | 16 | | | 727 | | | 11 | | | 415 | | | 8 |
| Trading | | | 4 | | | | | | (2) | | | | | | 2 | | | |
| Total energy | | | 5,052 | | | 92 | | | 5,965 | | | 93 | | | 4,764 | | | 93 |
Energy-related businesses (b) | | | 448 | | | 8 | | | 464 | | | 7 | | | 364 | | | 7 |
Total | | $ | 5,500 | | | 100 | | $ | 6,429 | | | 100 | | $ | 5,128 | | | 100 |
(a) | Included in these amounts for 2012, 2011,2015, 2014 and 20102013 are $78$14 million, $26$84 million and $320$51 million of wholesale electricity sales to ana former affiliate, PPL Electric, which are eliminated in consolidation for PPL.Electric. |
| |
(b) | Energy-related businesses are mechanical contracting and services subsidiaries that primarily support the generation and marketing and trading businesses in Talen Energy's East segment. Activities of PPL Energy Supply. Their activitiesthese businesses include developing renewable energy projects and providing energy-related products and services to commercial and industrial customers through their mechanical contracting and services subsidiaries. Energy-related businesses for PPL's Supply segment had additional revenues not related to PPL Energy Supply of $13 million, $8 million and $11 million for 2012, 2011 and 2010, which are not included in this table. customers. |
Power Generation by Fuel Source and physical condition of the units, and may be revised periodically to reflect changes in circumstances. Generating capacity controlled by PPL Generation and other PPL Energy Supply subsidiaries includes power obtained through PPL EnergyPlus' power purchase agreements. See "Item 2. Properties - Supply Segment" for a complete listing of PPL Energy Supply's generating capacity.Segment
During 2012, PPL2015, Talen Energy Supply owned or controlled power plants (including facilities for which Talen Energy has the rights to the output) that generated the following amounts of electricity.electricity (by segment):
|
| | | | | | | | |
| GWh |
Fuel Source | East | | West | | Total |
Nuclear (a) | 18,505 |
| | — |
| | 18,505 |
|
Natural Gas/Oil | 15,320 |
| | 2,470 |
| | 17,790 |
|
Coal | 18,181 |
| | 3,775 |
| | 21,956 |
|
Hydro | 903 |
| | — |
| | 903 |
|
Renewables (b) | 293 |
| | — |
| | 293 |
|
Total | 53,202 |
| | 6,245 |
| | 59,447 |
|
| | | Thousands of MWhs |
Fuel Source | | Northeastern | | Northwestern | | Total |
| | | | | | | |
Nuclear | | 15,224 | | | | 15,224 |
Oil / Gas | | 9,383 | | | | 9,383 |
Coal | | 16,857 | | 3,232 | | 20,089 |
Hydro | | 552 | | 3,443 | | 3,995 |
Renewables (a) | | 342 | | | | 342 |
Total | | 42,358 | | 6,675 | | 49,033 |
| |
(a) | PPLRepresents Talen Energy's share of the total output. |
| |
(b) | In 2015, Talen Energy Supply subsidiaries ownowned or controlcontrolled renewable energy projects (including facilities for which Talen Energy has the rights to the output) located in Pennsylvania, New Jersey, Vermont Connecticut and New Hampshire with aan aggregate generating capacity (summer rating) of 7026 MW. PPL EnergyPlus sellsTalen Energy Marketing sold the energy, capacity and RECs produced by these plants into the wholesale market as well as to commercial and industrial and institutional customers. In November 2015, projects that had an aggregate generating capacity of 19 MW were sold. For the projects sold, the above generation amounts include generation through their date of sale. |
PPL Energy Supply's generation subsidiaries are EWGs that sell electricity into wholesale markets. EWGs are subject to regulation by the FERC, which has authorized these EWGs to sell the electricity generated at market-based prices. This electricity is sold to PPL EnergyPlus under FERC-jurisdictional power purchase agreements. PPL Susquehanna is subject to the jurisdiction of the NRC in connection with the operation of the Susquehanna nuclear units. Certain of PPL Energy Supply's other subsidiaries are subject to the jurisdiction of the NRC in connection with the operation of their fossil plants with respect to certain level and density monitoring devices. Certain operations of PPL Generation's subsidiaries are also subject to OSHA and comparable state statutes.
See Note 9 to the Financial Statements for information on the 2011 sale of certain non-core generation facilities, the 2010 sale of the Long Island generation business and the 2010 completion of the sale of the Maine hydroelectric generation business.Fuel Supply
See "Item 2. Properties - Supply Segment"Properties" for additional information regarding PPL Generation's plans for capital projects in Pennsylvania and Montana that are expected to provide 153 MW of additional electric generating capacity by the end of 2013.
PPL EnergyPlus acts as agent for PPL Generation to procure and optimize its various fuels.
Coal
Pennsylvania
PPL EnergyPlus actively manages PPL Energy Supply's coal requirements by purchasing coal principally from mines located in northern Appalachia.
During 2012, PPL Generation purchased 5.6 million tons of coal required for its wholly owned Pennsylvania plants under short-term and long-term contracts. The amount of coal in inventory varies from time to time depending on market conditions and plant operations.
PPL Generation, by and through its agent PPL EnergyPlus, has agreements in place that will provide more than 23 million tons of PPL Generation's projected coal needs for the Pennsylvania power plants from 2013 through 2018.
A PPL Generation subsidiary owns a 12.34% interest in the Keystone plant and a 16.25% interest in the Conemaugh plant. PPL Generation owns a 12.34% interest in Keystone Fuels, LLC and a 16.25% interest in Conemaugh Fuels, LLC. The Keystone plant contracts with Keystone Fuels, LLC for its coal requirements, which provided 4.3 million tons of coal to the Keystone plant in 2012. The Conemaugh plant requirements are purchased under contract from Conemaugh Fuels, LLC, which provided 4.1 million tons of coal to the Conemaugh plant in 2012.
All PPL Generation coal plants within Pennsylvania are equipped with scrubbers, which use limestone in their operations. Acting as agent for PPL Generation, PPL EnergyPlus has entered into contracts with limestone suppliers that will provide for those plants' limestone requirements through 2014. During 2012, 382,000 tons of limestone were delivered to Brunner Island and Montour under these contracts. Annual limestone requirements approximate 400,000-500,000 tons.
Montana
PPL Montana has a 50% leasehold interest in Colstrip Units 1 and 2, and a 30% leasehold interest in Colstrip Unit 3. NorthWestern owns a 30% interest in Colstrip Unit 4. PPL Montana and NorthWestern have a sharing agreement that governs each party's responsibilities and rights relating to the operation of Colstrip Units 3 and 4. Under the terms of that agreement, each party is responsible for 15% of the total non-coal operating and construction costs of Colstrip Units 3 and 4, regardless of whether a particular cost is specific to Colstrip Unit 3 or 4 and is entitled to take up to 15% of the available generation from Units 3 and 4. Each party is responsible for its own coal costs. PPL Montana, along with the other Colstrip owners, is party to contracts to purchase 100% of its coal requirements with defined coal quality characteristics and specifications. PPL Montana, along with the other Colstrip Units 1 and 2 owner, has a long-term purchase and supply agreement with the current supplier for Units 1 and 2, which provides these units 100% of their coal requirements through December 2014, and at least 85% of such requirements from January 2015 through December 2019. PPL Montana, along with the other Colstrip Units 3 and 4 owners, has a long-term coal supply contract for Units 3 and 4, which provides these units 100% of their coal requirements through December 2019.
These units were originally built with scrubbers and PPL Montana has entered into a long-term contract to purchase the limestone requirements for these units. The contract extends through December 2030.
Coal supply contracts are in place to purchase low-sulfur coal with defined quality characteristics and specifications for PPL Montana's Corette plant. The contracts covered 100% of the plant's coal requirements in 2012 and similar contracts are in place to supply 100% of the expected coal requirements through 2014.
Oil and Natural Gas
Pennsylvania
PPL Generation's Martins Creek Units 3 and 4 burn both oil and natural gas. During 2012, 100% of the physical gas requirements for the Martins Creek units were purchased on the spot market while oil requirements were supplied from inventory. At December 31, 2012, there were no long-term agreementsfuel source for oil or natural gas for these units.
Short-term and long-term gas transportation contracts are in place for approximately 38%each of the maximum daily requirements of the Lower Mt. Bethel facility. During 2012, 100% of the physical gas requirements were purchased on the spot market.
In 2008, PPL EnergyPlus acquired the rights to an existing long-term tolling agreement associated with the capacity and energy of the Ironwood Facility. In April 2012, an indirect, wholly owned subsidiary of PPL Energy Supply completed the acquisition of the equity interests in the owner and operator of the Ironwood Facility. See Note 10 to the Financial Statements for additional information. Beginning in 2010, PPL EnergyPlus has long-term transportation contracts that can deliver up to approximately 25% of Ironwood's maximum daily gas requirements. Daily gas requirements can also be met through a combination of short-term transportation capacity release transactions coupled with upstream supply. PPL EnergyPlus currently has no long-term physical gas contracts. During 2012, 100% of the physical gas requirements were purchased on the spot market.
Talen Energy's plants.
Nuclear
The nuclear fuel cycle consists of several material and service components: the mining and milling of uranium ore to produce uranium concentrates; the conversion of these concentrates into uranium hexafluoride, a gas component; the enrichment of the hexafluoride gas; the fabrication of fuel assemblies for insertion and use in the reactor core; and the temporary storage and final disposal of spent nuclear fuel.
PPL Susquehanna Nuclear has a portfolio of supply contracts, with varying expiration dates, for nuclear fuel materials and services. These contracts are expected to provide sufficient fuel to permit Unit 1 to operate into the first quarter of 20162020 and Unit 2 to operate into the first quarter of 2017. PPL2019. Susquehanna Nuclear anticipates entering into additional contracts to ensure continued operation of the nuclear units.
Federal law requires the U.S. government to provide for the permanent disposal of commercial spent nuclear fuel, but there is no definitive date by which a repository will be operational. As a result, it was necessary to expand Susquehanna'sSusquehanna Nuclear has an on-site spent fuel storage capacity. To support this expansion, PPL Susquehanna contracted for the design and construction of a spent fuel storage facility employing dry cask fuel storage technology. The facility is modular, so that additional storage capacity can be added as needed. The facility began receiving spent nuclear fuel in 1999. PPL Susquehanna estimates, under current operating conditions, that there is sufficient storage capacity intechnology, which, together with the spent nuclear fuel pools, andhas the on-sitecapacity to accommodate spent fuel expected to be discharged through 2017. This spent fuel storage facility at Susquehannais currently in the process of being expanded to accommodate spent fuel discharged through approximately 2017. If necessary, the on-siteadditional spent fuel storage, facility can be expanded,and assuming appropriate regulatory approvals are obtained, additional expansion will take place in the future such that, together, the spent fuel pools and the expanded dry fuel storage facility will accommodate all of the spent nuclear fuel expected to be discharged through 2044, the current licensed life of the plant.
In 1996, the U.S. Court of Appeals for the District of Columbia Circuit ruled that the Nuclear Waste Policy Act imposed on the DOE an unconditional obligation to begin accepting spent nuclear fuel on or before January 31, 1998. In January 2004, PPL Susquehanna filed suit in the U.S. Court of Federal Claims for unspecified damages suffered as a result of the DOE's breach of its contract to accept and dispose of spent nuclear fuel. In May 2011, the partiesSusquehanna Nuclear entered into a settlement agreement which resolved all claimswith the U.S. Government relating to Susquehanna Nuclear's 2004 lawsuit against the U.S. Government for partial breach of PPLthe standard contract for disposal of spent nuclear fuel. The settlement included reimbursement of certain costs to store spent nuclear fuel at the Susquehanna through December 2013. PPL Susquehanna has received payments for claims through 2011. PPL Susquehanna is eligible to receive payment of annual claims for allowed costs, as set forth in the settlement agreement, that arenuclear plant incurred through December 31, 2013.2013, and Susquehanna Nuclear received payments for its claimed costs for those periods. In exchange, PPL Susquehanna hasNuclear waived any claims against the United States governmentU.S. Government for costs paid or injuries sustained related to storing spent nuclear fuel at the Susquehanna nuclear plant through December 31, 2013. In January 2014, Susquehanna Nuclear entered into an addendum to that agreement to extend the settlement agreement on the same terms for an additional three years to the end of 2016. Susquehanna Nuclear expects to enter into discussions with the DOE this year to further extend the settlement agreement beyond 2016.
Natural Gas and Oil
Talen Energy manages natural gas and oil supply utilizing a combination of contracted purchases, spot market purchases and storage for the commodities and pipeline capacity. The amount and duration of contracted capacity varies due to factors including fuel availability, economic considerations and plant location on the pipeline grid. Talen Energy has various short and
PPL EnergyPlus sells the capacity and electricity produced by PPL Generation subsidiaries, along with purchased power, FTRs, natural gas, oil, uranium, emission allowances and RECs in competitive wholesale and competitive retail markets.
long-term natural gas supply to customersand transportation contracts in Delaware, Maryland, New Jersey, New Yorkplace; however, the majority of the natural gas supply needs are satisfied with short-term transactions on a spot basis.
Oil requirements are normally supplied by inventory and Pennsylvania. Withinreplenished through purchases on the constraints of its hedging policy, PPL EnergyPlusspot market.
Coal
Talen Energy actively manages its portfolioscoal requirements by purchasing coal from mines located in central and northern Appalachia and Colorado for its plants located within PJM and from mines located adjacent to the Colstrip facility in Montana. Coal is delivered by rail, barge or conveyor. Reliability of energycoal deliveries can be affected from time to time by a number of factors including fluctuations in demand, coal mine production issues and energy-related productsother supplier or transporter operating difficulties. Coal inventory is maintained at levels estimated to optimizebe necessary to avoid operational disruptions at coal-fired generating units. Long-term supply contracts support adequate levels of coal inventory and are augmented with spot market purchases, as needed. Talen Energy has long-term supply agreements through 2018 for plants located in PJM and for the Colstrip plant through 2019. The contracts in place are expected to provide 62% of 2016 requirements.
In addition, certain of Talen Energy's plants are equipped with flue gas desulfurization equipment or Scrubbers, which use limestone in their valueoperations. Talen Energy has entered into limestone contracts with suppliers that will provide limestone for the plants located in PJM through 2016 and for the Colstrip plant through 2030 and are expected to limit exposure to price fluctuations. provide 100% of 2016 requirements.
See "Commodity Volumetric Activity" in Note 1910 to the Financial Statements for additional information on Talen Energy's ownership interest in and cost sharing arrangement related to Colstrip.
ACQUISITIONS AND DIVESTITURES
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| | Completion Date | | Capacity (a) | | Markets |
Acquisitions: | | | | | | |
MACH Gen | | November 2015 | | 2,344 MW | | NYISO, ISO-NE, WECC |
RJS Power | | June 2015 | | 5,182 MW | | PJM, ERCOT, ISO-NE |
Divestitures: | | | | | | |
Ironwood | | February 2016 | | 661 MW | | PJM |
C.P. Crane | | February 2016 | | 402 MW | | PJM |
Talen Renewable Energy | | November 2015 | | 19 MW | | Various |
Montana Hydroelectric Business | | November 2014 | | 633 MW | | WECC |
Announced Divestitures: | | | | | | |
Holtwood and Lake Wallenpaupack | | March 2016 (b) | | 308 MW | | PJM |
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(a) | Based on summer rating. |
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(b) | Anticipated closing date. |
See Note 6 to the strategies PPLFinancial Statements for additional information on acquisitions and divestitures.
FRANCHISES AND LICENSES
Talen Energy Supply employsMarketing has a license from the DOE to optimizeexport electricity to Canada. Talen Energy Marketing also has a permit from the National Energy Board of Canada to export firm and interruptible electricity from Canada to the United States.
Susquehanna Nuclear operates Units 1 and 2 pursuant to NRC operating licenses that expire in 2042 for Unit 1 and in 2044 for Unit 2. In 2008, a Talen Energy subsidiary, Bell Bend, LLC, submitted a COLA to the NRC for a new nuclear generating unit (Bell Bend) to be built adjacent to the Susquehanna nuclear plant. Also in 2008, the COLA was formally docketed and accepted for review by the NRC. Talen Energy does not expect the COLA review process with the NRC to be completed prior to 2018. See Note 6 to the Financial Statements for additional information.
Holtwood, LLC, a subsidiary of Talen Generation that owns hydroelectric generating operations in Pennsylvania, operates the Holtwood and Lake Wallenpaupack hydroelectric generating plants pursuant to FERC-granted licenses that expire in 2030 and 2045, respectively. In 2015, Talen Energy announced that it agreed to sell these facilities. The sale is expected to close in March 2016. In connection with the relicensing of these generating facilities, applicable law permits the FERC to relicense the original licensee or license a new licensee or allow the U.S. government to take over the facility. If the original licensee is not
relicensed, it is compensated for its net investment in the facility, not to exceed the fair value of its wholesale and retail energy portfolio.the property taken, plus reasonable damages to other property affected by the lack of relicensing.
Since the early 1990s, there has been increased competition in U.S. energy markets because of federal and state competitive market initiatives. WhileAlthough some states such as Pennsylvania and Montana, have created a competitive market for electricity generation, other states continue to consider different types of regulatory initiatives concerning competition in the power and gas industry.industries. Some states that were considering creating competitive markets have slowed their plans or postponed further consideration. In addition, states that have created competitive markets have, from time to time, considered new market rules and re-regulation measures that could result in more limited opportunities for competitive energy suppliers. Interest in re-regulation, however, has slowed dueHowever, these initiatives have not fully developed as a result of various efforts by industry participants to prevent the current environmenterosion of declining power prices.the competitive market structure. As such, the markets in which PPLTalen Energy Supply participates are highly competitive.
PPLThe power generation business is a regional business that is diverse in terms of industry structure and fundamentals. Demand for electricity may be met by generation capacity based on several competing generation technologies, such as natural gas-fired, coal-fired or nuclear generation, as well as power generation facilities fueled by alternative energy sources, including hydro power, synthetic fuels, solar, wind, wood, geothermal, waste heat and solid waste sources. Talen Energy Supply faces competition in wholesale markets for available energy, capacity and ancillary services. Competition is impacted by electricity and fuel prices, congestion along the power grid, subsidies provided by state and federal governments for new generation facilities, new market entrants, construction by others of new generating assets, technological advances in power generation, the actions of environmental and other regulatory authorities and other factors. PPLIn retail power markets, Talen Energy Supply primarily competes with other electricity suppliers based on its ability to aggregate generation supply at competitive prices from different sources and to efficiently utilize transportation from third-party pipelines and transmission from electric utilities, ISOs and ISOs.RTOs. Competitors in wholesale power markets include regulated utilities, industrial companies, NUGs, competitive subsidiaries of regulated utilities, financial institutions and other energy marketers. See "Item 1A. Risk Factors - RisksFactors-Risks Related to Supply Segment" and PPL's and PPL Energy Supply'sOur Business," "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview"Operations" and NoteNotes 11 and 15 to the Financial Statements for more information concerning the risks faced with respect to competitive energy markets.
See "Energy Marketing" above for a discussion of PPL EnergyPlus' licenses in various states. PPL EnergyPlus also has an export license from the DOE to sell capacity and/or energy to electric utilities in Canada.
PPL Susquehanna operates Units 1 and 2 pursuant to NRC operating licenses that expire in 2042 for Unit 1 and in 2044 for Unit 2.
In 2008, a PPL Energy Supply subsidiary, PPL Bell Bend, LLC, submitted a COLA to the NRC for a new nuclear generating unit (Bell Bend) to be built adjacent to the Susquehanna plant. Also in 2008, the COLA was formally docketed and accepted for review by the NRC. PPL Bell Bend, LLC does not expect to complete the COLA review process with the NRC prior to 2015. See Note 8 to Financial Statements for additional information.
PPL Holtwood operates the Holtwood hydroelectric generating plant pursuant to a FERC-granted license that expires in 2030. In October 2009, the FERC approved the request to expand the Holtwood plant. See Note 8 to the Financial Statements for additional information. PPL Holtwood operates the Wallenpaupack hydroelectric generating plant pursuant to a FERC-granted license that expires in 2044.
PPL's 11 hydroelectric facilities and one storage reservoir in Montana are licensed by the FERC. The Thompson Falls and Kerr licenses expire in 2025 and 2035, the licenses for the nine Missouri-Madison facilities expire in 2040, and the license for the Mystic facility expires in 2050.
In connection with the relicensing of these generating facilities, applicable law permits the FERC to relicense the original licensee or license a new licensee or allow the U.S. government to take over the facility. If the original licensee is not relicensed, it is compensated for its net investment in the facility, not to exceed the fair value of the property taken, plus reasonable damages to other property affected by the lack of relicensing. See Note 15 to the Financial Statements for additional information on the Kerr Dam license.
· | Other Corporate Functions (PPL)
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PPL Services provides corporate functions such as financial, legal, human resources and information technology services. Most of PPL Services' costs are charged directly to the respective PPL subsidiaries for the services provided or are indirectly charged to applicable subsidiaries based on an average of the subsidiaries' relative invested capital, operation and maintenance expenses and number of employees.
PPL Capital Funding, PPL's financing subsidiary, provides financing for the operations of PPL and certain subsidiaries, but PPL Capital Funding's costs are not charged to any Registrant other than PPL. PPL Capital Funding participated significantly in the financing for the acquisitions of LKE and WPD Midlands. The associated financing costs, as well as the financing costs associated with prior issuances of certain other PPL Capital Funding securities, have been and will continue to be assigned to the appropriate segments for purposes of PPL management's assessment of segment performance. PPL's recent growth in rate-regulated businesses provides the organization with an enhanced corporate level financing alternative, through PPL Capital Funding, that further enables PPL to support targeted credit profiles cost effectively across all of PPL's rated companies. As a result, PPL plans to further utilize PPL Capital Funding in addition to continued direct financing by the operating companies, as appropriate. Beginning in 2013, the proceeds and the financing costs associated primarily with PPL Capital Funding's future securities issuances are not expected to be directly assignable or allocable to any segment.
Also, the costs of certain other miscellaneous corporate level activities are not charged to any subsidiaries or allocated or assigned to any segment for purposes of assessing performance by PPL management.
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
SEASONALITY
The demand for and market prices of electricity and natural gas are affected by weather. As a result, the Registrants'Talen Energy's operating results in the future may fluctuate substantially on a seasonal basis, especially when more severe weather conditions such as heat waves or extreme winter weather make such fluctuations more pronounced. The pattern of this fluctuation may change depending on the type and location of the facilities owned, the retail load served and the terms of contracts to purchase or sell electricity. See "Financial Condition"Item 1A. Risk Factors - LiquidityRisks Related to Our Business" and Capital Resources - Environmental"Environmental Matters" in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations"below for additional information regarding climate change.
FINANCIAL CONDITION
See the Registrants'"Financial Condition" in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" for this information.
CAPITAL EXPENDITURE REQUIREMENTS
See "Financial Condition - Liquidity and Capital Resources - Forecasted Uses of Cash - Capital Expenditures" in the Registrants' "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" for information concerning the $2.4 billion of projected capital expenditure requirements for 20132016 through 2017. See Note 15 to the Financial Statements for additional information concerning the potential impact on capital expenditures from environmental matters.
ENVIRONMENTAL MATTERS
The Registrants are subject to certain existing and developing federal, regional, state and local laws and regulations with respect to air and water quality, land use and other environmental matters. The EPA is2020. Included in the processprojections are $137 million of proposing and finalizing an unprecedented number of environmental regulations that will directly affect the electricity industry. These initiatives cover air, water and waste. See "Financial Condition - Liquidity and Capital Resources - Forecasted Uses of Cash - Capital Expenditures" in the Registrants' "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for information concerning environmental capital expenditures during 2012 and projected environmental capital expenditures for the years 2013-2017. Also, see "Environmental Matters" in Note 15 to the Financial Statements for additional information. To comply with primarily air-related environmental requirements, PPL's forecast for capital expenditures reflects awhich reflect Talen Energy's best estimate projection of capital expenditures that may be required within the next five years. Such projections are $1.1 billion for LG&E, $1.2 billion for KU and $246 million for PPL Energy Supply. Actual costs (including capital, emission allowance purchases and operational modifications) may be significantly lower or higher depending on the final compliance requirements and market conditions. Environmental compliance costs incurred by LG&E and KU are subject to recovery through a rate recovery mechanism. See Note 6 to the Financial Statements for additional information.
The Registrants are unable to predict the ultimate effect of evolving environmental laws and regulations upon their existing and proposed facilities and operations and competitive positions. In complying with statutes, regulations and actions by regulatory bodies involving environmental matters, including, among other things, air and water quality, GHG emissions, hazardous and solid waste management and disposal, and regulation of toxic substances, PPL's and LKE's subsidiariesTalen Energy also may be required to modify, replace or cease operating certain of their facilities. PPL's and LKE's subsidiaries may also incur significantenvironmental-related capital expenditures and operating expenses, in amounts which are not now determinable, but could be significant. See "Environmental Matters" below for additional information on the potential impact on capital expenditures from environmental matters.
ENVIRONMENTAL MATTERS
Environmental Laws and Regulations
Extensive federal, state and local environmental laws and regulations are applicable to Talen Energy's air emissions, water discharges and the management of hazardous and solid waste, as well as other aspects of its business. In addition, many of these environmental considerations are also applicable to the operations of key suppliers, or customers, such as coal producers and industrial power users, and may impact the cost for their products or their demand for Talen Energy's services.
It may be necessary for Talen Energy to modify, curtail, replace or cease operation of certain facilities or performance of certain operations to comply with statutes, regulations and other requirements imposed by regulatory bodies, courts or environmental groups. Talen Energy may incur costs to comply with environmental laws and regulations, including increased capital expenditures or operating and maintenance expenses, monetary fines, penalties or other restrictions, which could be material. Legal challenges to environmental permits or rules add to the uncertainty of estimating the future cost of complying with these permits and rules. In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed.
The following is a discussion of the more significant environmental matters impacting Talen Energy's business.
CSAPR
The EPA's CSAPR addresses the interstate transport of fine particulates and ozone by regulating emissions of sulfur dioxide and nitrogen oxide. CSAPR establishes interstate allowance trading programs for sulfur dioxide and nitrogen oxide emissions from fossil-fuel fired plants for 28 states in two phases: Phase 1 trading commenced in January 2015, and Phase 2 trading is expected to commence in 2017. Although Talen Energy does not currently anticipate significant costs to comply with these programs, changes in market or operating conditions, or significant regulatory changes, could result in impacts that are greater than anticipated. Talen Energy is evaluating the EPA's recently released "CSAPR Update Rule" proposal which recommends more stringent ozone season nitrogen oxide budgets for 23 states, including several where Talen Energy owns affected generation. Additional capital and/or operating and maintenance expenses could be imposed on Talen Energy plants in Maryland, New Jersey, New York, Pennsylvania and Texas as a result of this action. Legal challenges to CSAPR are on-going in federal and state court.
NAAQS
In 2008, the EPA revised downward the NAAQS for ozone. As a result, states in the ozone transport region (OTR), including Pennsylvania, Maryland, Massachusetts, New York and New Jersey, are required by the Clean Air Act to impose additional reductions in nitrogen oxide emissions based upon reasonably available control technologies (RACT). PADEP is expected to finalize a RACT rule by the end of the first quarter of 2016 that requires some fossil-fuel fired power plants in Pennsylvania to operate at more stringent nitrogen oxide emission rates starting in 2017. Maryland coal plants operated at reduced nitrogen oxide emission rates during the 2015 ozone season as a result of an emergency action issued by the Governor of Maryland (which later became a final rule) and in November 2015 the MDE promulgated additional nitrogen oxide regulations for Maryland coal plants that require even more stringent operations starting no later than June 2020. In October 2015, the EPA released a final rule that strengthened the NAAQS for ozone. This could lead to even further nitrogen oxide reductions for Talen Energy's fossil-fuel fired plants within and outside of the OTR. State and federal efforts to address interstate transport issues associated with ozone NAAQS, including increased pressure by state environmental agencies and environmental groups to further reduce nitrogen oxide emissions from plants with selective catalytic reduction technology, and updated transport rules such as that proposed by EPA in December 2015 (as discussed above), could additionally lead to further emission reductions and increased compliance costs.
In 2010, the EPA finalized a more stringent NAAQS for sulfur dioxide and required states to identify areas that meet the standard and areas that are in non-attainment or are unclassifiable. In July 2013, the EPA finalized non-attainment designations for parts of the country where attainment is due by 2018. States are working on designations for other areas pursuant to a consent decree between the EPA and Sierra Club approved in March 2015 with 2017 or 2020 deadlines, depending on which designation methodology (modeling or monitoring) is selected. Several of Talen Energy's plants are in areas being evaluated for designation.
Until final rules are promulgated, all non-attainment designations are finalized, and state compliance plans are developed, Talen Energy cannot predict the ultimate outcome of the new NAAQS for ozone and sulfur dioxide on its fleet or plants, or whether they may have a material adverse effect on Talen Energy's financial condition or results of operations. Talen Energy anticipates
that some of the measures required for compliance with the CSAPR (as discussed above) or the MATS and Regional Haze Rules (as discussed below), will help to achieve compliance.
MATS
In February 2012, the EPA finalized a rule (known as the MATS Rule) requiring reductions of mercury and other hazardous air pollutants from fossil-fuel fired power plants by April 2015 with one-and two-year extension opportunities. Subsequently, the U.S. Supreme Court determined that the EPA acted unreasonably by refusing to consider costs when determining whether the MATS regulation was appropriate and necessary. To address the Supreme Court action, the DC Circuit in December 2015 remanded the MATS Rule to the EPA to incorporate a revised appropriate and necessary finding. The EPA has since issued a proposed supplemental finding on cost, claiming that the regulation was appropriate and necessary. The EPA has committed to finalizing the Rule by April 2016. The existing MATS Rule remains in effect. Separate from the EPA's MATS Rule, several states, including Montana and Maryland where Talen Energy owns affected facilities, have enacted regulations requiring mercury emission reductions from coal plants. Talen Energy cannot currently predict whether any costs necessary to comply with the EPA's MATS Rule or similar regulations will have a material adverse effect on Talen Energy's financial condition or results of operations.
Regional Haze
The EPA's regional haze programs were developed under the Clean Air Act to eliminate man-made visibility degradation by 2064. Under the programs, states are required to make reasonable progress every decade, through the application of, among other things, Best Available Retrofit Technology (BART) on power plants commissioned between 1962 and 1977. The primary power plant emissions affecting visibility are sulfur dioxide, nitrogen oxides and particulates. While the focus of regional haze regulation previously was on the western U.S., in December 2015, a final federal implementation plan for Texas was released with an emphasis on coal plants. Minimal impacts are anticipated to Talen Energy's gas fleet in Texas.
As for the eastern U.S., the EPA had determined that region-wide reductions under the CSAPR trading program could, in most instances, be utilized under state programs to satisfy BART requirements for sulfur dioxide and nitrogen oxides. However, the EPA's determination is being challenged by environmental groups. In September 2015, the Third Circuit Court of Appeals vacated portions of the EPA's approval of Pennsylvania's regional haze state implementation plan and remanded the rule to the EPA for further consideration. Talen Energy is unable to determine at this time if the future impacts of regional haze regulation on Talen Energy plants in the eastern U.S. will have a material adverse effect on Talen Energy's financial condition or results of operations. See Note 11 to the Financial Statements for information on a legal decision issued by the Ninth Circuit Court of Appeals in a case involving Talen Montana challenging the EPA's final Regional Haze Federal Implementation Plan for Montana.
New Source Review (NSR)
The EPA has continued its NSR enforcement efforts targeting coal-fired generating plants. The EPA has alleged that modification of these plants has increased their emissions and, consequently, that they are subject to stringent NSR requirements under the Clean Air Act. Talen Energy has responded to several information requests from the EPA, but has received no further substantive communications from the EPA related to those requests since providing its responses. See Note 11 to the Financial Statements for information on a lawsuit filed by environmental groups in March 2013 against Talen Montana and other owners of Colstrip related to NSR.
Climate Change
Physical effects associated with climate change could include the impact of changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to Talen Energy's generation assets, as well as impacts on Talen Energy's customers. In addition, changed weather patterns could potentially reduce annual rainfall in areas where Talen Energy's generation facilities use river water for cooling. Federal and state initiatives to prepare energy assets and infrastructure for the impacts of climate change, such as those actions driven by President Obama's 2013 Climate Action Plan (discussed further below), could result in binding obligations to physically protect Talen Energy's generation assets from climate change impacts.
Talen Energy cannot currently predict whether its businesses will experience these potential risks or whether any related costs will have a material adverse effect on Talen Energy's financial condition or results of operations.
GHG Regulations & Tort Litigation
In April 2010, the EPA and the U.S. Department of Transportation issued new light-duty vehicle emissions standards that applied beginning with 2012 model year vehicles. The EPA stated that this standard authorizes regulation of carbon dioxide emissions from stationary sources under the NSR and Title V operating permit provisions of the Clean Air Act. Following legal challenges, in June 2014, the U.S. Supreme Court ruled that the EPA has the authority to regulate carbon dioxide emissions under the Clean Air Act, but only for stationary sources that would otherwise have been subject to these provisions due to significant increases in emissions of other regulated pollutants. As a result, any new sources or major modifications to an existing GHG source causing a net significant increase in carbon dioxide emissions must comply with best achievable control technology (BACT) permit limits for carbon dioxide if it would otherwise be subject to BACT or lowest achievable emissions rate limits due to significant increases in other regulated pollutants. EPA is expected to propose a de minimis threshold for such permits in June 2016.
In June 2013, President Obama released his Climate Action Plan reiterating the goal of reducing GHG emissions in the U.S. through such actions as regulating power plant emissions, promoting increased use of renewables and clean energy technology, and establishing more restrictive energy efficiency standards. In October 2015, the EPA finalized carbon dioxide regulations for new and existing power plants, and the EPA has proposed a federal implementation plan that would apply to any states that fail to submit an acceptable state plan for the existing plant rule. EPA's existing plant rule has been stayed by the U.S. Supreme Court until all legal challenges to the rule have been resolved. The new plant rule remains in effect and challenges are also outstanding in federal court. Implementation of the new and existing power plant rules could have a significant industry-wide impact, but at this time Talen Energy is unable to determine if the rules will have a material adverse effect on Talen Energy's financial condition or results of operations.
A number of lawsuits have been filed asserting common law claims including nuisance, trespass and negligence against various companies with GHG emitting plants and, although the decided cases to date have not sustained claims brought on the basis of these theories of liability, the law remains unsettled on these claims.
Exemptions for Startup, Shutdown and Malfunction Events
In May 2015, the EPA released a final rule which prohibits states from exempting startup, shutdown and malfunction (SSM) events from compliance requirements in State Implementation Plans (SIPs). The Rule issues a SIP call for each of those states where the SSM provisions in the SIPs of those states fail to meet the EPA's requirements. Affected states, including Arizona, New Jersey, Montana and Texas where Talen Energy owns generation facilities, must submit revised provisions to the EPA in November 2016. Revisions to a SIP or other regulations in other non-affected states where Talen Energy operates could result from this action. The EPA's final rule is being challenged in federal court. Talen Energy cannot currently predict whether revisions to SIPs or other similar regulations will have a material adverse effect on Talen Energy's financial condition or results of operations.
CCRs
The EPA's final rule regulating CCRs, including fly ash, bottom ash and sulfur dioxide scrubber wastes became effective in October 2015. It imposes extensive new requirements, including location restrictions, design and operating standards, groundwater monitoring and corrective action requirements and closure and post-closure care requirements on CCR impoundments and landfills that are located at active power plants and not closed. Under the rule, the EPA will regulate CCRs as non-hazardous under Subtitle D of RCRA and allow beneficial use of CCRs, with some restrictions. This self-implementing rule requires posting of compliance documentation on a publicly accessible website and is only enforceable through citizen suits. Talen Energy expects that its plants using surface impoundments for management and disposal of CCRs, or that previously managed CCRs and continue to manage wastewaters, will be most impacted by the rule. Requirements for covered CCR impoundments and landfills include commencement or completion of closure activities generally between three and ten years from certain triggering events. Talen Energy anticipates incurring capital or operation and maintenance costs prior to that time to address other requirements of the rule, such as groundwater monitoring and disposal facility modifications, or to implement various compliance strategies. The final CCR Rule is being challenged in federal court.
Talen Energy continues to review the Rule and evaluate financial and operational impacts. During 2015, an increase of $41 million was recorded to existing AROs. Further changes to AROs may be required as estimates are refined and compliance with the rule continues. See Note 18 for information on AROs.
ELGs and Standards
The EPA's final ELG regulations that revise discharge limitations for steam electric generation wastewater discharge permits became effective in January 2016. The final limitations are based on the EPA's review of available treatment technologies and their capacity for reducing pollutants and include new requirements for fly ash and bottom ash transport water and for scrubber wastewater. The EPA's final ELG regulations contain requirements that could have a material impact on Talen Energy's coal-fired plants. At the present time, Talen Energy is evaluating the new requirements. The new ELG limitations and standards will be implemented as each plant's discharge permit is renewed. The compliance period for the new requirements is from November 2018 through the end of 2023, based on the date that the permit is renewed and the applicable deadline negotiated with the agencies for that facility. At this point, Talen Energy is unable to estimate a range of reasonably possible compliance costs. The final ELG regulations are being challenged in federal court.
Seepages and Groundwater Infiltration - Pennsylvania and Montana
Talen Energy has completed or is completing assessments of seepages or groundwater infiltration at various active and retired wastewater basins and landfills at certain of its facilities. Talen Energy has completed or is working with agencies to respond to related notices of violations and implement assessment or abatement measures, where required or applicable. A range of reasonably possible losses cannot currently be estimated and, therefore, Talen Energy is unable to determine if any such abatement measures will have a material adverse effect on Talen Energy's financial condition or results of operations.
In August 2012, Talen Montana entered into an Administrative Order on Consent (AOC) with the MDEQ which establishes a comprehensive process to investigate and remediate groundwater seepage impacts related to the wastewater facilities at the Colstrip power plant. The AOC requires that within five years, Talen Montana provide financial assurance to the MDEQ for the costs associated with closure and future monitoring of the waste-water treatment facilities. Talen Montana cannot predict at this time if the actions required under the AOC will create the need to adjust the existing ARO related to this facility. Talen Montana is defending the AOC in litigation brought by environmental groups as discussed in Note 11 to the Financial Statements.
Under the Pennsylvania Clean Streams Law, a subsidiary of Talen Generation is obligated to remediate acid mine drainage at a former mine site and may be required to take additional steps to prevent potential acid mine drainage at a previously capped refuse pile at this mine site. The subsidiary is pumping and treating mine water at the former mine site.
At December 31, 2015, Talen Generation had accrued a discounted liability of $19 million to cover the costs of pumping and treating groundwater at this mine site for 50 years. Talen Energy discounted this liability based on a risk-free rate of 8.41% at the time of the mine closure. Expected undiscounted payments are estimated to be $1 million for each of the years 2016, 2017, 2019, and 2020, $3 million in 2018, and $92 million for work after 2020.
Clean Water Act_316(b) Rule
The EPA's final 316(b) Rule for existing facilities became effective in October 2014 and regulates cooling water intake structures and their impact on aquatic organisms. States are allowed considerable authority to make site-specific determinations under the Rule which requires existing facilities to choose between several options to reduce impingement and entrainment. Plants already equipped with closed-cycle cooling, an acceptable option, would likely not incur substantial compliance costs. Plants equipped with once-through cooling water systems would likely require additional technology to comply with the rule. Talen Energy is evaluating compliance strategies, but does not presently expect to incur material compliance costs. The EPA's final rule is being challenged in federal court.
Waters of the United States (WOTUS)
In June 2015, the EPA and the U.S. Army Corps of Engineers (Army Corps) published their final rule redefining the term WOTUS. The rule, which became effective in August 2015, identifies six types of categorically jurisdictional waters and two categories of waters for which case-by-case evaluations are needed to determine whether a "significant nexus" exists. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order preventing the EPA from implementing the rule nationwide. Talen Energy will continue to evaluate the rule, and while no material impacts to Talen Energy's financial condition or results of operations are anticipated, the redefinition could impact future development actions, such as plant and gas infrastructure expansions, in the event the stay is lifted. Legal challenges are on-going in federal and state court.
Superfund and Other Remediation
From time to time, Talen Energy undertakes investigative or remedial actions in response to notices of violations, spills or other releases at various on-site and off-site locations, negotiates with the EPA and state and local agencies regarding actions
necessary for compliance with applicable requirements, negotiates with property owners and other third parties alleging impacts from Talen Energy's operations and undertakes similar actions necessary to resolve environmental matters which arise in the course of normal operations. Based on analysis to-date, resolution of these environmental matters is not expected to have a material adverse effect on Talen Energy's financial condition or results of operations.
Future investigation or remediation work at sites currently under review, or at sites not currently identified, may result in additional costs for Talen Energy, but at this time Talen Energy is unable to determine if such investigation or remediation work will have a material adverse effect on Talen Energy's financial condition or results of operations.
Other
In addition to the environmental matters discussed above, from time-to-time in the ordinary course of its business, Talen Energy may become involved in other environmental matters or become subject to other environmental statutes, regulations or requirements. In the opinion of management based upon information currently available to Talen Energy, while the outcome of these other environmental matters and proceedings is uncertain, the likely results are not expected, either individually or in the aggregate, to have a material adverse effect on Talen Energy's financial condition or results of operations, although the effect could be material to Talen Energy's results of operations in any interim reporting period.
See Note 11 to the Financial Statements for additional information on environmental matters.
REGULATORY MATTERS
Talen Energy operates in a highly regulated industry and is subject to regulation by various federal and state agencies and in the various regions where it conducts business.
Certain of Talen Energy's generation subsidiaries are EWGs that sell electricity into wholesale markets. EWGs are subject to regulation by the FERC, which has authorized these EWGs to sell the electricity generated at market-based prices. A portion of this electricity is sold to Talen Energy Marketing under FERC-jurisdictional power purchase agreements. Susquehanna Nuclear is subject to the jurisdiction of the NRC in connection with the operation of its Susquehanna nuclear units. In addition, certain of Talen Energy's other subsidiaries are subject to the jurisdiction of the NRC in connection with the operation of their fossil plants with respect to certain level and density monitoring devices. Certain operations of Talen Energy are also subject to OSHA and comparable state statutes.
The following is a discussion of the more significant regulatory matters impacting Talen Energy's business.
Proposed Legislation/Initiatives - Pacific Northwest
In January 2016, legislation was proposed in the State of Washington to provide a means of cost recovery to utility owners of coal-fired generating facilities who commit to retire such facilities. An initiative also was submitted to the Washington legislature that would impose a carbon tax of $25 per ton on fossil fuels in Washington. The 2016 legislature now has three options relative to the initiative - (i) pass the same into law as drafted; (ii) defer action on the same to the voters in November 2016; or (iii) revise and pass the initiative, sending both the original and amended measures to the November 2016 state-wide ballot.
In the same time frame, legislation was proposed in the State of Oregon that would double the renewable mandate in Oregon to 50% by 2040 and would limit Oregon utilities' ability to use coal power in Oregon only until 2030, although one utility there would be able to use a small amount thereafter until 2035. A key provision of the Oregon legislation is that two pending "no coal" initiatives would be withdrawn once the bill becomes law.
Talen Energy cannot predict whether any legislation seeking to achieve these objectives will be enacted in either state or, if enacted, if such legislation would have a material adverse effect on Talen Energy's financial condition or results of operations.
Electricity - Reliability Standards
The NERC is responsible for establishing and enforcing mandatory reliability standards (Reliability Standards) regarding the bulk power system. The FERC oversees this process and independently enforces the Reliability Standards.
The Reliability Standards have the force and effect of law and apply to certain users of the bulk power electricity system, including electric utility companies, generators and marketers. Under the Federal Power Act, the FERC may assess civil penalties of up to $1 million per day, per violation, for certain violations.
Talen Energy monitors its subsidiaries' compliance with the Reliability Standards and continues to self-report potential violations of certain applicable reliability requirements and submit accompanying mitigation plans, as required. The resolution of a number of potential violations is pending.
In the course of implementing their programs to ensure compliance with the Reliability Standards by those Talen Energy subsidiaries subject to the standards, certain other instances of potential non-compliance may be identified from time to time. Talen Energy cannot predict the outcome of these matters, and cannot estimate a range of reasonably possible losses, if any.
Other
In addition to the regulatory matters discussed above, Talen Energy and its subsidiaries are party to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. While the outcome of these other regulatory matters and proceedings is uncertain, the likely results are not expected, either individually or in the aggregate, to have a material adverse effect on Talen Energy's financial condition or results of operations, although the effect could be material to Talen Energy's results of operations in any interim reporting period.
See Note 11 to the Financial Statements for additional information on regulatory matters.
EMPLOYEE RELATIONS
At December 31, 2012, PPL2015, Talen Energy and its subsidiaries had the following4,981 full-time employees.
PPL Energy Supply (a) | | 4,733 |
PPL Electric | | 2,311 |
LKE | | |
| KU | | 931 |
| LG&E | | 991 |
| LKS | | 1,380 |
| Total LKE | | 3,302 |
PPL Global (primarily WPD) | | 6,116 |
PPL Services and other | | 1,267 |
Total PPL | | 17,729 |
(a) | Includesemployees, 2,579 of which were represented by labor unions. These numbers include union employees of mechanical contracting subsidiaries, whose numbers tend to fluctuate due to the nature of this business. |
Approximately 5,600 employees, or 48%, of PPL's domestic workforce are members of labor unions, with four IBEW labor unions representing approximately 4,300 employees. The bargaining agreement with the largest IBEW labor union, which expires in May 2014, covers approximately 1,500 PPL Electric, 1,600 PPL Energy Supply and 400 other employees. Approximately 700 employees of LG&Emechanical contracting subsidiaries and 70 employeestend to fluctuate due to the nature of KU are represented by an IBEW labor union. Both LG&E and KU have three-year labor agreements with the IBEW, which expire in November 2014 and August 2015. The KU IBEW agreement includes a wage reopener in 2014. Approximately 70 employees of KU are represented by a United Steelworkers of America (USWA) labor union, under an agreement that expires in August 2014. PPL Montana's largest bargaining unit, an IBEW labor union, represents approximately 260 employees at the Colstrip plant. The four-year labor agreement expires in April 2016. PPL Montana's second largest bargaining unit, also an IBEW labor union, represents approximately 80 employees at hydroelectric facilities and the Corette plant, under an agreement that expires in April 2013.
Approximately 3,900, or 64%, of PPL's U.K. workforce are members of labor unions. WPD recognizes four unions, the largest of which represents 41% of its union workforce. WPD's Electricity Business Agreement, which covers approximately 3,850 union employees, may be amended by agreement between WPD and the unions and is terminable with 12 months' notice by either side.mechanical contractors' business.
AVAILABLE INFORMATION
PPL'sTalen Energy's Internet website is www.pplweb.com. Onwww.talenenergy.com. Under the Investor Center pageheading of that website, PPLTalen Energy provides access to all SEC filings of the Registrants (including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K,8‑K, and amendments to these reports filed or furnished pursuant to Section 13(d) or 15(d)) free of charge, as soon as reasonably practicable after filing or furnishing with the SEC. Additionally, the Registrants' filings are available at the SEC's website (www.sec.gov) and at the SEC's Public Reference Room at 100 F Street, NE, Washington, DC 20549, or by calling 1-800-SEC-0330.
The RegistrantsWe face various risks associated with theirour businesses. Our businesses, financial condition, cash flows or results of operations could be materially adversely affected by any of these risks. In addition, this report also contains forward-looking and other statements about our businesses that are subject to numerous risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 1511 to the Financial Statements for more information concerning the risks described below and for other risks, uncertainties and factors that could impact our businesses and financial results.
As used in this Item 1A., the terms "we," "our" and "us" generally refer to PPLTalen Energy and its consolidated subsidiaries taken as a whole, or to PPLwhole.
Talen Energy's business was formed on June 1, 2015, by the spinoff of Talen Energy Supply and its consolidated subsidiaries taken as a whole within the Supply segment discussions, or PPL Electricsubsequent combination of that business with RJS Power, to form an independent, publicly traded company (collectively, the "Talen Transactions"). See Notes 1, 3 and its consolidated subsidiaries taken as a whole within6 to the Pennsylvania Regulated segment discussion, or LKE and its consolidated subsidiaries taken as a whole within the Kentucky Regulated segment discussion.Financial Statements for additional information.
Risks Related to All Segments
(PPL, PPL Energy Supply, PPL Electric, LKE, LG&E and KU)
We plan to selectively pursue growth of generation, transmission and distribution capacity, which involves a number of uncertainties and may not achieve the desired financial results.
We plan to pursue expansion of our generation, transmission and distribution capacity over the next several years through power uprates at certain of our existing power plants, the potential construction of new power plants, the potential acquisition of existing plants, the potential construction or acquisition of transmission and distribution projects and capital investments to upgrade transmission and distribution infrastructure. We will rigorously scrutinize opportunities to expand our generating capability and may determine not to proceed with any expansion. These types of projects involve numerous risks. Any planned power uprates could result in cost overruns, reduced plant efficiency and higher operating and other costs. With respect to the construction of new plants, the acquisition of existing plants, or the construction or acquisition of transmission and distribution projects, we may be required to expend significant sums for preliminary engineering, permitting, resource exploration, legal and other expenses before it can be established whether a project is feasible, economically attractive or capable of being financed. Expansion in our regulated businesses is dependent on future load or service requirements and subject to applicable regulatory processes. The success of both a new or acquired project would likely be contingent, among other things, upon the negotiation of satisfactory operating contracts, obtaining acceptable financing and maintaining acceptable credit ratings, as well as receipt of required and appropriate governmental approvals. If we were unable to complete construction or expansion of a project, we may not be able to recover our investment in the project. Furthermore, we might be unable to operate any new or acquired plants as efficiently as projected, which could result in higher than projected operating and other costs and reduced earnings.Our Business
Adverse conditions in the economic and financial markets in which we operateconditions could adversely affect our financial condition and results of operations.
Adverse economic conditions in the financial markets during 2008 and the associated contraction of liquidity in the wholesale energy markets contributed significantly to declines in wholesale energyelectricity prices and hashave significantly impacted our earnings since the second half of 2008.earnings. The breadth and depth of these negative economic conditions had a wide-ranging impact on the U.S. and U.K. business environment, including our businesses. As a result ofIn addition, adverse economic conditions also reduce the economic downturn, demand for energy commodities declined significantly.commodities. This reduced demand continues to impact the key domestic wholesale energyelectricity markets we serve (such as PJM) and our Pennsylvania and Kentucky utility businesses.serve. The combination of lower demand for power and increased supply of natural gas has put downward price pressure on wholesale energyelectricity markets in general, further impacting our energy marketing results. In general, current economic and commodity market conditions will continue to challenge predictability regardingimpact our unhedged future energy margins, liquidity, earnings growth and overall financial condition. In addition, adverse economic conditions, declines in wholesale electricity prices, reduced demand for power and other factors may negatively impact the trading price of our common stock and impact forecasted cash flow, which may require us to evaluate our assets for impairment. Any such impairment could have a material impact on our results of operations and financial statements.
Adverse changes in commodity prices and related costs may decrease our future energy margins, which could adversely affect our earnings and cash flows.
Our energy margins, or the amount by which our revenues from the sale of power exceed our costs to supply power, are impacted by changes in market prices for electricity, fuel, fuel transportation, emission allowances, RECs, electricity capacity and related congestion charges and other costs. Unlike most commodities, the limited ability to store electricity requires that it must be consumed at the time of production. As a result, wholesale market prices for electricity may fluctuate substantially over relatively short time periods and can be unpredictable. Among the factors that influence such prices are:
demand for electricity;
supply of electricity available from current or new generation resources;
variable production costs, primarily fuel (and associated transportation costs) and emission allowance expense for the generation resources used to meet the demand for electricity;
transmission capacity and service into, or out of, markets served;
changes in the regulatory framework for wholesale power markets;
liquidity in the wholesale electricity market, as well as general creditworthiness of key participants in the market; and
weather and economic conditions affecting demand for or the price of electricity or the facilities necessary to deliver electricity.
Our risk management policy and procedures relating to electricity and fuel prices, interest rates and counterparty credit and non-performance risks may not work as planned, and we may suffer economic losses despite such programs.
We actively manage the market risk inherent in our generation and energy marketing activities, as well as our debt and counterparty credit positions. We have implemented procedures to monitor compliance with our risk management policy, including independent validation of transaction and market prices, verification of risk and transaction limits, portfolio stress tests, sensitivity analyses and daily portfolio reporting of various risk management metrics. Nonetheless, our risk management policy may not work as planned. For example, actual electricity and fuel prices may be significantly different or more volatile
than the historical trends and capital, among other things, for capital expendituresassumptions upon which we based our risk management calculations. Additionally, unforeseen market disruptions could decrease market depth and providing collateral to support hedging inliquidity, negatively impacting our energy marketing business. Global bank credit capacity declined and the cost of renewing or establishing new credit facilities increased significantly in 2008, primarily as a result of general credit concerns nationwide, introducing uncertainties as to our businesses' ability to enter into long-term energynew transactions. We enter into financial contracts to hedge commodity "basis risk," and as a result are exposed to the risk that the correlation between delivery points could change with actual physical delivery. Similarly, interest rates could change in significant ways that our risk management procedures were not designed to address. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events result in greater losses or costs than our risk models predict or greater volatility in our earnings and financial position.
In addition, our trading, marketing and hedging activities are exposed to counterparty credit risk and market liquidity risk. As part of our risk management policy, we have established credit procedures to evaluate counterparty credit risk. However, if counterparties fail to perform, we may be forced to enter into alternative arrangements at then-current market prices. In that event, our financial results could be adversely affected.
We do not always hedge against risks associated with electricity and fuel price volatility.
We attempt to mitigate risks associated with satisfying our contractual electricity sales obligations by either reserving generation capacity to deliver electricity or purchasing the necessary financial or physical products and services through competitive markets to satisfy our net firm sales contracts. We also routinely enter into contracts, such as fuel and electricity purchase and sale commitments, or reliably estimate the longer-term costto hedge our exposure to fuel requirements and availability of credit. Although bank credit conditions have improved since mid-2009, and we currently expect to have adequate access to needed credit and capitalother electricity-related commodities. However, based on current conditions, deteriorationeconomic and other considerations, we may decide not to hedge the entire exposure. To the extent we do not hedge against such exposure and fuel requirements and applicable commodity prices change in ways that would be adverse to us, our results of operations and financial position may be adversely affected. To the extent we do hedge, those hedges may not ultimately prove to be effective.
The accounting for our hedging activities may increase the volatility in our quarterly and annual financial results.
We engage in commodity-related marketing and price-risk management activities in order to physically and financially hedge our exposure to market risk with respect to electricity sales from our generation assets, fuel utilized by those assets and emission allowances.
We generally attempt to balance our fixed-price physical and financial purchases and sales commitments in terms of contract volumes and the timing of performance and delivery obligations through the use of financial and physical derivative contracts. These derivatives are recorded on the balance sheet at fair value with changes in the fair value resulting from fluctuations in the underlying commodity prices immediately recognized in earnings, unless the derivative qualifies for the NPNS exception. Specific criteria are required in order to elect the NPNS exception, which permits qualifying hedges to be treated under the accrual accounting method. All economic hedges may not necessarily qualify for the NPNS exception, or we may elect not to utilize the NPNS exception. As a result, our quarterly and annual results are subject to significant fluctuations caused by changes in market prices.
We are exposed to operational, price and credit risks associated with selling and marketing products in the wholesale and retail electricity markets.
We sell electricity in wholesale markets under market-based rates throughout the U.S. and also enter into short-term agreements to market available electricity and capacity from our generation assets with the expectation of profiting from market price fluctuations. It is possible, however, that market price fluctuations and the absence of long-term agreements could adversely impact our profitability and results of operations.
To the extent that we do have agreements in place to deliver firm electricity and capacity and fail to do so, we could be required to pay damages. These damages would generally be based on the difference between the market price to acquire replacement electricity or capacity and the contract price of any undelivered capacity or electricity. Depending on price volatility in the wholesale electricity markets, such damages could be significant. Extreme weather conditions, unplanned generation facility outages, environmental compliance costs, transmission disruptions, and other factors could affect our ability to meet our obligations, or cause significant increases in the market price of replacement capacity and electricity.
Our wholesale power sales agreements typically include provisions requiring us to post collateral for the benefit of our counterparties if the market price of electricity varies from the contract prices in excess of certain predetermined amounts. We currently believe that we have sufficient liquidity to fulfill our potential collateral obligations under these power sales contracts. However, our obligation to post collateral could exceed the amount of our facilities or our ability to increase our facilities could be limited by financial markets or other factors.
We also face credit risk that counterparties with whom we contract in both the wholesale and retail markets will default in their performance, in which case we may have to sell our electricity into a lower-priced market or make purchases in a higher-priced
market than existed at the inception of the contract. Whenever feasible, we attempt to mitigate these risks using various means, including agreements that require our counterparties to post collateral for our benefit if the market price of electricity varies from the contract price in excess of certain predetermined amounts. However, there can be no assurance that we will avoid counterparty nonperformance risk, including bankruptcy, which could adversely impact our ability to meet our obligations to other parties, which could in turn subject us to claims for damages.
The full-requirements sales contracts that Talen Energy Marketing is awarded do not provide for specific levels of load and actual load significantly below or above our forecasts could adversely affect our energy margins.
We generally hedge our full-requirements sales contracts with our own generation or electricity purchases from third parties. If the actual load is significantly lower than the expected load, we may be required to resell power at a lower price than was contracted for to supply the load obligation, resulting in a financial condition and liquidity. Additionally, regulationsloss. Alternatively, a significant increase in load could adversely affect our energy margins because we are required under the terms of full-requirements sales contracts to provide the electricity necessary to fulfill increased demand at the contract price, which could be adoptedlower than the cost to implementprocure additional electricity on the Dodd-Frank Act and Basel IIIopen market or could mean that we are required to operate our plants to meet the requirements despite the fact that it may be unprofitable to do so. Therefore, any significant decrease or increase in Europe may impose requirementsload compared with our forecasts could have a material adverse effect on our businessesresults of operations and the businesses of others with whom we contract such as banks or other counterparties, or simply result in increased costs to conduct our business or access sources of capital and liquidity upon which the conduct of our businesses is dependent.
financial position.
Our operating revenues could fluctuate on a seasonal basis, especially as a result of extreme weather conditions.
Our businesses are subject to seasonal demand cycles. For example, in some markets demand for, and market prices of, electricity peak during hot summer months, while in other markets such peaks occur in cold winter months. As a result, our overall operating results in the future may fluctuate substantially on a seasonal basis if weather conditions such as heat waves, extreme cold, unseasonably mild weather or severe storms occur. The patterns of these fluctuations may change depending on the type and location of our facilities and the terms of our contracts to sell electricity.
Operating expenses could be affected by weather conditions, including storms, as well as by significant man-mademanmade or accidental disturbances, including terrorism or natural disasters.
Weather and these other factors can significantly affect our profitability or operations by causing outages, damaging infrastructure and requiring significant repair costs. Storm outages and damage often either or both directly decrease revenues and increase expenses, due to reduced usage and higher restoration charges. In addition, weathercosts.
We may experience disruptions in our fuel supply, which could adversely affect our ability to operate our generation facilities.
We purchase fuel and other disturbancesproducts consumed during the production of electricity (such as coal, natural gas, oil, water, uranium, lime, limestone and other chemicals) from a number of suppliers. Delivery of these fuels to our facilities is dependent upon the continuing financial viability of contractual counterparties as well as the infrastructure (including rail lines, rail cars, barge facilities, roadways, riverways and natural gas pipelines) available to serve each generation facility. As a result, we are subject to the risks of disruptions or curtailments in the production of power at our generation facilities if fuel is unavailable at any price or if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure. Disruption in the delivery of fuel, including disruptions as a result of weather, transportation difficulties, global demand and supply dynamics, labor relations, environmental regulations or the financial viability of our fuel suppliers, could adversely affect our ability to operate our facilities, which could result in lower sales and/or higher costs and thereby adversely affect our results of operations.
We have sold forward a portion of our power in order to lock in long-term prices that we deemed to be favorable at the time we entered into the forward sale contracts. In order to hedge our obligations under these forward power sales contracts, we have entered into long-term and short-term contracts for the purchase and delivery of fuel. Many of the forward power sales contracts do not allow us to pass through changes in fuel costs or discharge the power sale obligations in the case of a disruption in fuel supply due to force majeure events or the default of a fuel supplier or transporter. Disruptions in our fuel supplies may affect capital marketstherefore require us to find alternative fuel sources at higher costs, to find other sources of power to deliver to counterparties at a higher cost, or to pay damages to counterparties for failure to deliver power as contracted. Any such event could have a material adverse effect on our financial performance.
We also buy significant quantities of fuel on a short-term or spot market basis. Prices for all of our fuels fluctuate, sometimes rising or falling significantly over a relatively short period of time. The price we can obtain for the sale of electricity may not rise at the same rate, or may not rise at all, to match a rise in fuel or delivery costs. This may have a material adverse effect on our financial performance. Changes in market prices for coal, oil and natural gas may result from the following:
weather conditions;
seasonality;
demand for energy commodities and general economic conditions;
disruption or other constraints or inefficiencies of electricity, gas or coal transmission or transportation;
additional generating capacity;
availability and levels of storage and inventory for fuel stocks;
natural gas, crude oil, refined products and coal production levels;
changes in market liquidity;
federal, state and foreign governmental regulation and legislation; and
the creditworthiness and liquidity of fuel suppliers and/or transporters and their willingness to do business with us.
Our plant operating characteristics and equipment, particularly at our coal-fired plants, often dictate the specific fuel quality to be combusted. The availability and price of specific fuel qualities may vary due to supplier financial or operational disruptions, transportation disruptions and force majeure. At times, coal of a specific quality may not be available at any price, or we may not be able to transport such coal to our facilities on a timely basis. In this case, we may not be able to run the coal facility even if it would be profitable. Operating a coal facility with different quality coal can lead to emission or operating problems. If we have sold forward the power from such a coal facility, we could be required to supply or purchase power from alternate sources, perhaps at a loss. This could have a material adverse impact on the financial results of specific plants and on our results of operations.
Unforeseen circumstances could cause us to hold excess coal inventories and incur contract termination costs.
Because we enter into guaranteed supply contracts to provide for the amount of coal needed to operate our base load coal-fired generating facilities, we may experience periods where we hold excess amounts of coal. For example, extraordinarily low natural gas prices could cause natural gas to be the more cost-competitive fuel compared to coal for generating electricity, and as a result we may reduce or idle coal-fired generating facilities in favor of operating available alternative natural gas-fired generating facilities. In addition, we may incur costs to terminate supply contracts for coal in excess of our generating requirements. For example, to mitigate the risk of oversupply, we incurred charges of $41 million during 2015 to reduce our contracted coal deliveries.
If the services provided by the transmission facilities that deliver the wholesale power from our generation facilities are inadequate, our ability to sell and deliver wholesale power may be materially adversely affected. Furthermore, any change in the structure and operation of, or the various pricing limitations imposed by, the RTOs and ISOs that operate these transmission facilities may adversely affect the profitability of our generation facilities.
We do not own or control the transmission facilities required to sell the wholesale power from our generation facilities. If the transmission service from these facilities is unavailable or disrupted, or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver wholesale power may be materially adversely affected. RTOs and ISOs provide transmission services, administer transparent and competitive power markets and maintain system reliability. Many of these RTOs and ISOs operate in the real-time and day ahead markets in which we sell electricity. The RTOs and ISOs that oversee most of the wholesale power markets impose, and in the future may continue to impose, offer caps and other mechanisms to guard against the potential exercise of market power in these markets as well as price limitations. These types of price limitations and other regulatory mechanisms may adversely affect the profitability of our generation facilities that sell electricity and capacity into the wholesale power markets. Problems or delays that may arise in the formation and operation of maturing RTOs and similar market structures, or changes in geographic scope, rules or market operations of existing RTOs, may also affect our ability to sell, the prices we receive or the cost to transmit power produced by our generating facilities. Rules governing the various regional power markets may also change from time to time, which could affect our costs or revenues. Additionally, if the transmission service from these facilities is unavailable or disrupted, or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver wholesale power may be materially adversely affected. Furthermore, the rates for transmission capacity from these facilities are set by others and thus are subject to changes, some of which could be significant. As a result, our financial condition, results of operations and cash flows may be materially adversely affected.
The FERC has issued regulations that require wholesale electricity transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, there is the potential that fair and equal access to transmission systems will not be available or that transmission
capacity will not be available in the amounts we require. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets or whether ISOs and RTOs in applicable markets will efficiently operate transmission networks and provide related services.
Because our generation facilities are part of interconnected regional grids, we face the risk of blackout due to a disruption on a neighboring interconnected system.
Major electric power blackouts are possible and have occurred, which could disrupt electrical service for extended periods of time. If a blackout were to occur, the impact could result in interruptions to our operations, increased costs to replace existing contractual obligations, the possibility of regulatory investigations and potential operational risks to our facilities. Additionally, in response to a blackout, there could be changes or developments in applicable regulations or market structures that could have longer-term impact on our business and results of operations.
We face intense competition in the competitive power generation market, which may adversely affect our ability to operate profitably and generate positive cash flow.
Our generation business is dependent on our ability to operate successfully in a competitive environment and is not assured of any rate of return on capital investments through a regulated rate structure.
Competition is affected by electricity and fuel prices, relative cost of production of energy products, new market entrants, construction by others of generating assets and transmission capacity, technological advances in power generation, the actions of environmental and other regulatory authorities, establishment of legislation which favors one form of generation over another, such as investment tax credits or production tax credits, and other factors. These competitive factors may negatively affect our ability to sell electricity and related products and services, as well as the prices that we receive for such products and services, which could adversely affect our results of operations and our ability to grow our business.
We sell our available electricity and capacity products into competitive wholesale markets through contracts of varying duration. Competition in the wholesale electricity markets occurs principally on the basis of the price of products and, to a lesser extent, reliability and availability. We believe that the commencement of commercial operation of new electricity generating facilities in the regional markets where we own or control generation facilities and the evolution of demand side management resources will continue to increase competition in the wholesale electricity markets in those regions, which could have an adverse effect on electricity and capacity prices. We also face competition in the wholesale markets for generation capacity and ancillary services.
Competitors in the wholesale power markets in which we operate include regulated utilities, industrial companies, non-utility generators, competitive subsidiaries of regulated utilities, financial institutions and other energy marketers. We compete against these entities based on the cost of producing our products, which can include costs attributable to our access to credit sources and the levels of unsecured credit extended to our competitors.
In retail power markets, we primarily compete with other electricity suppliers based on our ability to aggregate generation supply at competitive prices from different sources and to efficiently utilize transportation from third-party pipelines and transmission from electric utilities, ISOs and RTOs.
Despite federal and state deregulation initiatives, our generation business is still subject to extensive regulation, including requirements that we obtain and comply with government permits and approvals, which may increase our costs, reduce our revenues, or prevent or delay operation of our facilities.
We are required to obtain, and to comply with, numerous permits, approvals, licenses and certificates from federal, state and local governmental agencies. The process of obtaining and renewing necessary permits can be lengthy and complex and can sometimes result in the establishment of permit conditions that make the project or activity for which the permit was sought unprofitable or otherwise unattractive. In addition, such permits or approvals may be subject to denial, revocation or modification under various circumstances. Failure to obtain or comply with the conditions of permits or approvals, or failure to comply with applicable laws or regulations, may result in the delay or temporary suspension of our operations and electricity sales or the curtailment of our power delivery and may subject us to penalties and other sanctions. Although various regulators routinely renew existing licenses, renewal could be denied or jeopardized by various factors, including failure to provide adequate financial assurance for closure; local community, political or other opposition; and executive, legislative or regulatory action. Our cost or inability to obtain and comply with the permits and approvals required for our operations could have a material adverse effect on our operations and cash flows.
In addition, our generation subsidiaries sell electricity into the wholesale market. Generally, our generation subsidiaries and our marketing subsidiaries are subject to regulation by the FERC. The FERC has authorized us to sell generation from our
facilities and power from our marketing subsidiaries at market-based prices. The FERC retains the authority to modify or withdraw our market-based rate authority and to impose "cost of service" rates if it determines that the market is not competitive, that we possess market power or that we are not charging just and reasonable rates. Any reduction by the FERC in the rates we may receive or any unfavorable regulation of our business by state regulators could materially adversely affect our results of operations. In addition, pursuant to PJM's new Capacity Performance construct, we may be subject, in certain PJM emergency events, to economic penalties for generation non-performance, which could be material. See "Item 1. Business-Markets - Recent Market Developments - PJM" in this Form 10-K for additional information.
Our costs to comply with federal, state and local statutes, rules and regulations relating to environmental protection and worker health and safety could be material and could cause the continued operation of certain of our generation facilities to be uneconomic.
Our business is subject to extensive federal, state and local statutes and regulations relating to environmental protection and worker health and safety. These laws and regulations, which have become more stringent over time, impose numerous requirements, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of hazardous materials, the imposition of specific standards addressing worker protection, and the imposition of substantial liabilities and remedial obligations for pollution or contamination.
If there is any delay in obtaining any environmental regulatory approvals necessary for our operations or capital projects, or if we fail to obtain, maintain or comply with any such approvals, operations at our affected facilities could be halted, reduced or subjected to additional costs.
For example, the EPA's ELGs and the EPA's CCR Rule could adversely affect our operations and restrict or delay our ability to obtain permits. Moreover, the EPA's Clean Power Plan could have a significant impact on current operations and future growth.opportunities, though it is not possible at this time to predict how this and other pending and/or recently promulgated regulations and laws will impact our business.
We have spent and expect to spend substantial amounts in the future on measures regarding environmental control and compliance, including, but not limited, with respect to pollution control technology. At some of our older generating facilities, it may be uneconomic for us to install necessary controls to comply with new or proposed legislation or regulations, which could cause us to retire those units.
Certain of our operations pose risks of environmental liability due to leakage, migration, emission, releases or spills of hazardous substances to the air, surface or subsurface soils, surface water or groundwater. We may be required to remediate contaminated properties currently or formerly owned or operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from our own actions that were in compliance with all applicable laws at the time those actions were taken. Certain environmental laws impose strict as well as joint and several liability (that could result in an entity paying more than its fair share) for costs required to remediate and restore sites. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations.
Failure to comply with applicable laws, regulations and permits may result in liability for administrative, civil and/or criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations. In addition, private parties may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws, regulations and permits or for personal injury or property damage.
See "Item 1. Business - Environmental Matters" for additional information regarding environmental laws and regulations applicable to our operations.
Our businesses are subject to physical, market and economic risks relating to potential effects of climate change.
Climate change may produce changes in weather or other environmental conditions, including temperature or precipitation levels, and thus may impact consumer demand for electric power. Temperature increaseselectricity. In addition, the potential physical effects of climate change, such as increased frequency and severity of storms, floods and other climatic events, could resultdisrupt our operations and cause us to incur significant costs in increased summerpreparing for or decreased winter overall electricity consumption and precipitation changes could result in altered availability of water for hydro generation or plant cooling operations.responding to these effects. These or other meteorological changes could lead to increased operating costs, capital expenses or power purchase costs. Greenhouse gas regulationClimate change could increasealso affect the availability of a secure and economical supply of water in some locations, which is essential for the continued operation of our generation plants. See "Item 1. Business - Environmental Matters" for additional information regarding the potential impact of climate change and related regulations on our business.
The availability and cost of electricemission allowances could negatively impact our costs of operations.
We are required to maintain, through either allocations or purchases, sufficient emission allowances for sulfur dioxide, nitrogen oxide and carbon dioxide to support our operations in the ordinary course of operating our power particularly power generatedgeneration facilities. These allowances are used to meet the obligations imposed on us by fossil fuels,various applicable environmental laws. If our operational needs require more than our allocated allowances, we may be forced to purchase such allowances on the open market, which could be costly. If we are unable to maintain sufficient emission allowances to match our operational needs, we may have to curtail our operations so as not to exceed our available emission allowances, or install costly new emission controls. As we use the emission allowances that we have purchased on the open market, costs associated with such purchases will be recognized as operating expense. If such allowances are available for purchase, but only at significantly higher prices, the purchase of such allowances could materially increase our costs of operations in the affected markets.
Changes in legislative and such increasesregulatory policy, including the promotion of renewable energy, energy efficiency, conservation and self-generation, may adversely impact our business.
Economic downturns, periods of high energy supply costs and other factors can lead to changes in or the development of legislative and regulatory policy designed to promote reductions in energy consumption, increased energy efficiency, renewable energy and self-generation by customers. This focus on conservation, renewable energy, energy efficiency and self-generation may result in a decline in electricity demand, which could have a depressive effect on regional economies. Reduced economic and consumer activity in turn adversely affect our service areas -- both generally and specificbusiness.
We are subject to certain industriesrisks associated with nuclear generation, including the risk that our nuclear generating facility could become subject to increased security or safety requirements that would increase capital and consumers accustomedoperating expenditures, uncertainties regarding spent nuclear fuel, and uncertainties associated with decommissioning our plant at the end of its licensed life.
Nuclear generation accounted for about 31% of our 2015 competitive power generation output (including output of (i) RJS as of June 2015, (ii) MACH Gen as of November 2015, (iii) certain of our renewables businesses prior to previously lower cost power -- could reduce demand fortheir sale in November 2015 and (iv) the powerfacilities that we generate, markethave announced are to be sold to satisfy the FERC order approving the combination of Talen Energy Supply and deliver. Also, demand for our energy-related services could be similarly lowered should consumers' preferences or market factors move toward favoring energy efficiency, low-carbon power sources or reduced electric usage.RJS Power). The risks of nuclear generation generally include:
the potential harmful effects on the environment and human health from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials;
We cannot predictlimitations on the outcomeamounts and types of the legal proceedingsinsurance commercially available to cover losses and investigations currently being conductedliabilities that might arise in connection with nuclear operations; and
uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives. The licenses for our currenttwo nuclear units expire in 2042 and past business activities. An adverse determination2044.
The NRC has broad authority under federal law to impose licensing requirements, including security, safety and employee-related requirements for the operation of nuclear generation facilities. In the event of noncompliance, the NRC has authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. In addition, revised security or safety requirements promulgated by the NRC, particularly in response to the 2011 incident in Fukushima, Japan, could necessitate substantial capital or operating expenditures at our Susquehanna nuclear plant. There also remains substantial uncertainty regarding the temporary storage and permanent disposal of spent nuclear fuel, which could result in substantial additional costs to us that cannot be predicted. In addition, although we have no reason to anticipate a serious nuclear incident at our Susquehanna nuclear plant, if an incident did occur, any resulting operational loss, damages and injuries could have a material adverse effect on our financial condition, results of operations, cash flows and financial condition.
Our indebtedness could adversely affect our financial condition and impair our ability to operate our business.
As of December 31, 2015, we had $4,811 million in total indebtedness. Our indebtedness could have important consequences to our future financial condition, operating results and business, including the following:
requiring that a substantial portion of our cash flows from operations be dedicated to payments on our indebtedness instead of other purposes, including operations, capital expenditures and future business opportunities;
limiting our ability to obtain additional debt or equity financing for working capital, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes;
increasing our cost of borrowing; and
limiting our ability to adjust to changing market and economic conditions and limiting our ability to carry out capital spending that is important to our growth.
Although the agreements governing the Talen Energy Supply RCF contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and any additional indebtedness incurred in compliance with these restrictions could be substantial. See Note 5 to the Financial Statements for additional information regarding our indebtedness.
The agreements governing our indebtedness contain covenants that may restrict our operational flexibility.
The Talen Energy Supply RCF contains financial and other covenants that restrict our ability to, among other things:
incur additional indebtedness, or issue guarantees or certain preferred shares;
pay dividends, redeem stock or make other distributions;
repurchase, prepay or redeem subordinated indebtedness;
make investments or acquisitions;
create liens;
make negative pledges;
consolidate or merge with another company;
sell or otherwise dispose of all or substantially all of our assets; and
enter into certain transactions with affiliates.
The Amended STF Agreement and the First Lien Credit and Guaranty Agreement similarly contain customary covenants that may restrict our operational flexibility.
Our ability to borrow additional amounts under these agreements depends upon satisfaction of those covenants. Events beyond our control could affect our ability to meet those covenants. Our failure to comply with obligations under the agreements governing our indebtedness may result in an event of default under those agreements. A default, if not cured or waived, may permit acceleration of our indebtedness. If our indebtedness is accelerated, we cannot be certain that we will have sufficient funds available to pay the accelerated indebtedness or that we will have the ability to refinance the accelerated indebtedness on terms favorable to us or at all. This could have serious consequences to our financial condition, operating results and business and could cause us to become bankrupt or insolvent. See Note 5 to the Financial Statements for additional information regarding our indebtedness.
Our cash flows.
flow and ability to meet debt obligations depend on the performance of our subsidiaries and affiliates.
We are involved in legal proceedings, claimsa holding company and litigation and subject to ongoing state and federal investigations arising outconduct our operations primarily through subsidiaries. Substantially all of our business operations,consolidated assets are held by such subsidiaries. Accordingly, our cash flow and our ability to meet our obligations under certain of our debt instruments depend upon the most significantearnings of whichthese subsidiaries and the distribution or other payment of such earnings to us in the form of dividends, loans or advances or repayment of loans and advances from us. The subsidiaries are summarized in "Legal Matters," "Regulatory Issues"separate and "Environmental Matters - Domestic" in Note 15distinct legal entities and have no obligation to pay any amounts due on the notes or to make any funds available for such payment. The debt agreements of some of our subsidiaries and affiliates contain provisions that might restrict their ability to pay dividends, make distributions or otherwise transfer funds to us upon failing to meet certain financial tests or other conditions prior to the Financial Statements. We cannot predictpayment of other obligations, including operating expenses, debt service and reserves.
Variable rate indebtedness subjects us to the ultimate outcomerisk of these matters, nor can we reasonably estimate the costs or liabilities thathigher interest rates, which could potentially result from a negative outcome in each case.cause our future debt service obligations to increase significantly.
Our borrowings under the Talen Energy Supply RCF and the First Lien Credit and Guaranty Agreement are at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on such variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income would decrease.
Disruption in financial markets could adversely affect our financial condition and results of operations.
Our businesses are heavily dependent on credit and access to capital, among other things, for financing capital expenditures and providing collateral to support hedging in our energy marketing business. Regulations under the Dodd-Frank Act in the United States and Basel III in Europe may impose costly additional requirements on our businesses and the businesses of others with whom we contract, such as banks or other counterparties, or simply result in increased costs to conduct our business or access sources of capital and liquidity upon which the conduct of our businesses is dependent.
We could be negatively affected by rising interest rates, downgrades to our bond credit ratings, adverse credit market conditions or other negative developments in our ability to access capital markets.
In the ordinary course of business, we are reliant upon adequate long-term and short-term financing to fund our significant capital expenditures, debt service and operating needs. As a capital-intensive business, we are sensitive to developments in interest rate levels;rates, credit rating considerations;considerations, insurance, security or collateral requirements;requirements, market liquidity and credit availability and refinancing opportunities necessary or advisable to respond to credit market changes. Changes in these conditions as well as downgrades to our credit ratings could result in increased costs and decreased liquidityavailability of credit.
Recent or future acquisition or divestiture activities may have adverse effects on our business, financial condition and results of operations.
From time to time, we may seek to acquire additional assets or businesses. The acquisition of new assets or businesses is subject to substantial risks, including delays in completing such acquisitions, the failure to identify material problems during due diligence, the risk of over-paying for assets, the ability to retain customers or employees and the inability to arrange financing for an acquisition as may be required or desired. We may acquire assets in geographic regions or markets in which we do not currently operate, which may expose us to increased market and/or regulatory risks. In addition, we may not be able to achieve the anticipated operating and financial benefits of future acquisitions. For example, we may not be able to achieve certain tax benefits related to our regulated utility businesses.recently completed acquisition of MACH Gen to the extent we do not have adequate taxable income in future periods following completion of the acquisition. Further, the integration and consolidation of acquired businesses requires substantial human, financial and other resources and, ultimately, such integration processes may result in unexpected costs or charges and we may not be able to operate the acquired businesses or assets in the manner in which we intended. There can be no assurances that any future acquired businesses will perform as expected or that the returns from such acquisitions will support the indebtedness incurred to acquire them or the capital expenditures needed to develop them.
In addition, we are required to sell certain assets pursuant to the FERC order approving the combination of Talen Energy Supply and RJS Power and we may from time to time choose to sell certain other assets or businesses that are no longer core to our operations. In connection with such dispositions, we may indemnify or guarantee counterparties against certain liabilities, which may result in future costs or liabilities payable by us. For example, we have agreed to indemnify the buyers in each of the Holtwood and Lake Wallenpaupack, Ironwood and Crane transactions against certain losses pursuant to the terms of their respective sale agreements. In addition, we may incur additional costs as a result of disposing of certain assets or businesses, and we may experience write-downs of assets if the carrying value of the assets or business sold exceeds the price received.
Changes in technology may negatively impact the value of our power plants.
A downgradebasic premise of our generation business is that generating electricity at central power plants achieves economies of scale and produces electricity at relatively low prices. There are alternate technologies to supply electricity, most notably fuel cells, micro turbines, batteries, windmills and photovoltaic (solar) cells, the development of which has expanded due to global climate change and energy efficiency concerns. Research and development activities are ongoing to seek improvements in alternate technologies. It is possible that advances will reduce the cost of alternative generation to a level that is equal to or below that of certain central station production. Also, as new technologies are developed and become available, the quantity and pattern of electricity usage (the "demand") by customers could decline, with a corresponding decline in revenues derived by generators. These alternative energy sources could result in a decline to the dispatch and capacity factors of our credit ratingsplants. As a result of all of these factors, the value of our generation facilities could negatively affectbe significantly reduced.
Our facilities may not operate as planned, which may increase our expenses and decrease our revenues and have an adverse effect on our financial performance.
Operation of our power plants, information technology systems and other assets and conduct of other activities subjects us to a variety of risks, including the breakdown or failure of equipment, accidents, security breaches, viruses or outages affecting information technology systems, labor disputes, obsolescence, delivery/ transportation problems and disruptions of fuel supply and performance below expected levels. These events may impact our ability to accessconduct our businesses efficiently and lead to increased costs, expenses or losses. Planned and unplanned outages at our power plants may require us to purchase power at then-current market prices to satisfy our commitments or, in the alternative, pay penalties and damages for failure to satisfy them. Although we maintain customary insurance coverage for certain of these risks, no assurance can be given that such insurance coverage will be sufficient to compensate us fully in the event losses occur.
We plan to optimize our competitive power generation operations, which involves a number of uncertainties and may not achieve the desired financial results.
We plan to optimize our competitive power generation operations. We plan to do this through the construction of new power plants or modification of existing power plants, and the potential closure of certain existing plants and acquisition of plants that may become available for sale. These types of projects involve numerous risks. Any planned power plant modifications could result in cost overruns, reduced plant efficiency and higher operating and other costs. With respect to the construction of new plants or modification of existing plants, we may be required to expend significant sums for preliminary engineering, permitting, resource exploration, legal and other expenses before it can be established whether a project is feasible, economically attractive or capable of being financed. For example, we recently committed capital to co-fire the Brunner Island coal facility on natural gas to better position the plant for low gas price environments, which is expected to be completed by the end of 2016. The success of both a new or acquired project may be contingent, among other things, upon obtaining acceptable financing and increasemaintaining acceptable credit ratings, as well as receipt of governmental approvals. If we were unable to complete construction or expansion of a project, we may not be able to recover our investment in the cost of maintaining our credit facilities andproject. Furthermore, we might be unable to operate any new debt.
Credit ratings assigned by Moody's, Fitchor modified plants as efficiently as projected, which could result in higher than projected operating and S&P to our businesses and their financial obligations have a significant impact on the cost of capital incurred by our businesses. Although we do not expect these ratings to limit our ability to fund short-term liquidity needs or access new long-term debt, any ratings downgrade could increase our short-term borrowingother costs and negatively affect our ability to fund short-term liquidity needs and access new long-term debt. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Liquidity and Capital Resources - Ratings Triggers" for additional information on the impact of a downgrade in our credit rating.
reduced earnings.
Significant increases in our operation and maintenance expenses, including health care and pension costs, could adversely affect our future earnings and liquidity.
We continually focus on limiting and reducing where possible our operation and maintenance expenses. However, we expect to continue to face increased cost pressures in our operations. Increased costs of materials and labor may result from general inflation, increased regulatory requirements (especially in respect of environmental regulations), the need for higher-cost expertise in the workforce or other factors. In addition, pursuant to collective bargaining agreements, we are contractually committed to provide specified levels of health care and pension benefits to certain current employees and retirees. We provide a similar level of benefits to our management employees. These benefits give rise to significant expenses. Due to general inflation with respect to such costs, the aging demographics of our workforce and other factors, we have experienced significant health care cost inflation in recent years, and we expect our health care costs, including prescription drug coverage, to continue to increase despite measures that we have taken and expect to take to require employees and retirees to bear a higher portion of the costs of their health care benefits. In addition, we expect to continue to incur significant costs with respect to the defined benefit pension plans for our employees and retirees. The measurement of our expected future health care and pension obligations costs and liabilitiescosts is highly dependent on a variety of assumptions, most of which relate to factors beyond our control. These assumptions include investment returns, interest rates, health care cost trends, inflation rates, benefit improvements, salary increases and the demographics of plan participants. If our assumptions prove to be inaccurate, our future costs and cash contribution requirements to fund these benefits could increase significantly.
We may be requiredThe loss of key personnel, the inability to record impairment charges in the future for certain of our investments, whichhire and retain qualified employees, and strikes or work stoppages by unionized employees, could adversely affect our earnings.
Under GAAP, we are required to test our recorded goodwill for impairment on an annual basis, or more frequently if events or circumstances indicate that these assets may be impaired. Although no goodwill impairments were recorded based on our annual review in the fourth quarter of 2012, we are unable to predict whether future impairment charges may be necessary.
We also review our long-lived assets, including equity investments, for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. See Notes 1, 9 and 18 to the Financial Statements for additional information on impairment charges taken during the reporting periods. We are unable to predict whether impairment charges, or other losses on sales of other assets or businesses, may occur in future years.
We may incur liabilities in connection with discontinued operations.
In connection with various divestitures, we have indemnified or guaranteed parties against certain liabilities and with respect to certain transactions. These indemnities and guarantees relate, among other things, to liabilities which may arise with respect to the period during which we or our subsidiaries operated the divested business, and to certain ongoing contractual relationships and entitlements with respect to which we or our subsidiaries made commitments in connection with the divestiture.
We are subject to liability risks relating to our generation, transmission and distribution businesses.
The conduct of our physical and commercial operations subjects us to many risks, including risks of potential physical injury, property damage or other financial liability, caused to or by employees, customers, contractors, vendors, contractual or financial counterparties and other third parties.
Our facilities may not operate as planned, which may increase our expenses and decrease our revenues and have an adverse effect on our business, financial position and results of operations.
Our operations depend on the continued efforts of our employees. Retaining key employees and maintaining the ability to attract new employees are important to both our operational and financial performance.
Operation We cannot guarantee that any member of power plants, transmissionour management or any one of our key employees will continue to serve in any capacity for any particular period of time. Certain events, such as an aging workforce, mismatch of skill set or complement to future needs, or unavailability of contract resources may lead to operating challenges and distribution facilities, information technology systemsincreased costs. The challenges we might face as a result of such risks include a lack of resources, losses to our knowledge base and other assetsthe time required to develop new workers' skills. In any such case, costs, including costs for contractors to replace employees, productivity costs and activities subjects ussafety costs, may rise. Failure to a variety of risks,hire and adequately train replacement employees, including the breakdowntransfer of significant internal historical knowledge and expertise to new employees, or failurechanges in the availability and cost of equipment, accidents, security breaches, viruses or outages affecting information technology systems,contract labor disputes, obsolescence, delivery/transportation problems and disruptions of fuel supply and performance below expected levels. These events may impactadversely affect our ability to conductmanage and operate our businesses efficientlybusiness. If we are unable to successfully attract and leadretain an appropriately qualified workforce, our financial position or results of operations could be negatively affected. In addition to increased costs, expenses or losses. Operation of our delivery systems below our expectations may result in lost revenue and increased expense, including higher maintenance costs which may not be recoverable from customers. Planned and unplanned outages at our power plants may require us to purchase power at then-current market prices to satisfy our commitments or, in the alternative, pay penalties and damages for failure to satisfy them.
Although we maintain customary insurance coverage for certain of these risks, no assurance can be given that such insurance coverage will be sufficient to compensate us fullyforegoing, in the event losses occur.that our union employees participate in a strike, work stoppage or engage in other forms of labor disruption, we would be responsible for procuring replacement labor and could experience reduced power generation or outages.
War, other armed conflicts or terrorist attacks, including cyber-based attacks, could have a material adverse effect on our business.
War and terrorist attacks have caused and may continue to cause instability in the world's financial and commercial markets and have contributed to high levels of volatility in prices for oil and gas. Instability and unrest in the Middle East, Afghanistan, Ukraine and Iraq, as well as threats of war or other armed conflict elsewhere, may lead to additional acts of war or terrorism, including in the United States, as well as further disruption and volatility in prices for oil and gas. Armed conflicts and terrorism and their effects on us or our markets may significantly affect our business and results of operations. In addition, we
may incur increased costs for security, including additional physical plant security and integrity risk.security personnel or additional capability following a terrorist incident.
Numerous functions affecting the efficient operation of our businesses are dependent on the secure and reliable storage, processing and communication of electronic data and the use of sophisticated computer hardware and software systems. The operation of our generation plants, including the Susquehanna nuclear plant, and of our energy marketing and fuel trading businesses as well as our transmission and distribution operations are all reliant on cyber-based technologiescomputer systems and networks and, therefore, subject to the risk that such systems could be the target of disruptive actions, principally by terrorists, or vandals or otherwise be compromised by unintentional events.others. As a result, operations could be interrupted, property could be damaged and sensitive customer information could be lost or stolen, causing us to incur significant losses of revenues, other substantial liabilities and damages, and costs to replace or repair damaged equipment.
equipment and damage to our reputation.
We are subject to risks associated with federal and state tax laws and regulations.
Changes in tax law as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact our results of operations. We are required to make judgments in order to estimate our obligations to taxing authorities. These tax obligations include income, property, gross receipts and franchise, sales and use, employment-related and other taxes. We also estimate our ability to utilize tax benefits and tax credits. Due to the revenue needs of the jurisdictions in which our businesses operate, various tax and fee increases may be proposed or considered. We cannot predict whether such tax legislation or regulation will be introduced or enacted or the effect of any such changes on our businesses. If enacted, any changes could increase tax expense and could have a significant negative impact on our results of operations and cash flows.
Risks Relating to or Arising out of the Talen Transactions
If the spinoff conducted as part of the Talen Transactions does not qualify as a tax-free distribution under the Code, including as a result of subsequent acquisitions of stock or equity of PPL or Talen Energy Corporation or Talen Energy Supply, then we may be liable for substantial U.S. federal income taxes or may be required to indemnify PPL.
Among other requirements, the completion of the Talen Transactions was conditioned upon PPL's receipt of a legal opinion of tax counsel to the effect that, the contribution of Talen Energy Supply to HoldCo, together with the spinoff conducted by PPL, will qualify as a reorganization pursuant to Section 368(a)(1)(D) and a tax-free distribution pursuant to Section 355 of the Code, that the merger conducted as part of those transactions will qualify as a reorganization pursuant to Section 368(a) of the Code, and that such merger and the related contribution of RJS to Talen Energy will qualify as a transaction described in Section 351 of the Code. That legal opinion is not binding on the IRS, and the IRS may reach conclusions that are different from the conclusions reached in such opinion. We are not aware of any facts or circumstances that would cause the factual statements or representations on which the legal opinion was based to be materially different from the facts at the time the Talen Transactions were completed. If, notwithstanding the receipt of such opinion, the IRS were to determine the spinoff to be taxable, PPL would recognize a tax liability that could be substantial. We would be jointly and severally liable for such tax liability under applicable Treasury Regulations as a former member of the PPL consolidated federal income tax group.
In addition, the spinoff will be taxable to PPL pursuant to Section 355(e) of the Code if there is a 50% or greater change in ownership (by vote or value) of PPL, Talen Energy Corporation or Talen Energy Supply, directly or indirectly, as part of a plan or series of related transactions that include the spinoff. Because PPL's shareholders collectively owned more than 50% of Talen Energy Corporation's common stock following the Talen Transactions, the Talen Transactions alone will not cause the spinoff to be taxable to PPL under Section 355(e) of the Code. However, Section 355(e) of the Code might apply if acquisitions of stock of PPL before or after the spinoff, or stock or equity of Talen Energy Corporation or Talen Energy Supply after June 1, 2015, are considered to be part of a plan or series of related transactions that include the spinoff. We are not aware of any such plan or series of transactions. Under the separation agreement, however, in certain circumstances and subject to certain limitations, we would be required to indemnify PPL for certain taxes that may be imposed on the spinoff, including taxes that arise because acquisitions of Talen Energy Corporation stock or Talen Energy Supply equity result in the Talen Energy spinoff being taxable under Section 355(e) of the Code.
We are subjectmay not realize the anticipated synergies, cost savings and growth opportunities from the Talen Transactions.
The benefits that we expect to achieve as a result of the riskTalen Transactions will depend, in part, on our ability to realize anticipated growth opportunities, cost savings and other synergies. Our success depends on the continued integration of the Talen Energy and RJS Power businesses, which could result in significant expenses that our workforce and its knowledge base may become depleted in coming years.
PPL is experiencing an increase in attrition due primarily to the number of retiring employees. Over the period from 2014 through 2018, 23.5% of PPL's total workforce is projected to leave the company, with the risk that critical knowledge will be lost and that it may be difficult to replace departed personnel dueestimate accurately at this time. In addition, we may experience challenges when combining separate business cultures, information technology systems and employees, and those challenges may divert senior management's time and attention. Even if we are able to a declining trend incomplete the number of available skilled workers and an increase in competition for such workers.
(PPL, PPL Energy Supply and LKE)
Risk Related to Registrant Holding Companies
PPL's, PPL Energy Supply's and LKE's cash flows and ability to meet their obligations with respect to indebtedness and under guarantees, and PPL's ability to pay dividends, largely depends on the financial performance of their subsidiaries and, as a result, is effectively subordinated to all existing and future liabilities of those subsidiaries.
PPL, PPL Energy Supply and LKE are holding companies and conduct their operations primarily through subsidiaries. Substantiallyintegration successfully, we may not fully realize all of the consolidated assets of these Registrants are held by such subsidiaries. Accordingly, their cash flows and ability to meet their debt and guaranty obligations, as well as PPL's ability to pay dividends, are largely dependent upon the earnings of those subsidiaries and the distribution or other payment of such earnings in the form of dividends, distributions, loans or advances or repayment of loans and advances. The subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts due from their parents or to make any funds available for such a payment. The ability of the subsidiaries of the Registrants to pay dividends or distributions to such Registrants in the future will depend on the subsidiaries' future earnings and cash flows and the needs of their businesses, and may be restricted by their obligations to holders of their outstanding debt and other creditors, as well as any contractual or legal restrictions in effect at such time, including the requirements of state corporate law applicable to payment of dividends and distributions, and regulatory requirements, including restrictions on the ability of PPL Electric, LG&E and KU to pay dividends under Section 305(a) of the Federal Power Act.
Because PPL, PPL Energy Supply and LKE are holding companies, their debt and guaranty obligations are effectively subordinated to all existing and future liabilities of their subsidiaries. Therefore, PPL's, PPL Energy Supply's and LKE's rights and the rights of their creditors, including rights of any debt holders, to participate in the assets of any of their subsidiaries, in the event that such a subsidiary is liquidated or reorganized, will be subject to the prior claims of such subsidiary's creditors. Although certain agreements to which certain subsidiaries are parties limit their ability to incur additional indebtedness, PPL, PPL Energy Supply and LKE and their subsidiaries retain the ability to incur substantial additional indebtedness and other liabilities. In addition, if PPL elects to receive distributions of earnings from its foreign operations, PPL may incur U.S. income taxes, net of any available foreign tax credits, on such amounts.
(PPL, PPL Electric, LKE, LG&E and KU)
Risks Related to Domestic Regulated Utility Operations
Our domestic regulated utility businesses face many of the same risks, in addition to those risks that are unique to the Kentucky Regulated segment and the Pennsylvania Regulated segment. Set forth below are risk factors common to both domestic regulated segments, followed by sections identifying separately the risks specific to each of these segments.
Our profitability is highly dependent on our ability to recover the costs of providing energy and utility services to our customers and earn an adequate return on our capital investments. Regulators may not approve the rates we request.
We currently provide services to our utility customers at rates approved by one or more federal or state regulatory commissions, including those commissions referred to below. While such regulation is generally premised on the recovery of prudently incurred costs and a reasonable rate of return on invested capital, the rates that we may charge our regulated generation, transmission and distribution customers are subject to authorization of the applicable regulatory authorities. There can be no assurance that such regulatory authorities will consider all of our costs to have been prudently incurred or that the regulatory process by which rates are determined will always result in rates that achieve full recovery of our costs or an adequate return on our capital investments. While our rates are generally regulated based on an analysis of our costs incurred in a base year or based on future projected costs, the rates we are allowed to charge may or may not match our costs at any given time. Our regulated utility businesses are subject to substantial capital expenditure requirements over the next several years, which will likely require rate increase requests to the regulators. If our costs are not adequately recovered through rates, it could have an adverse effect on our business, results of operations, cash flows and financial condition.
Our domestic utility businesses are subject to significant and complex governmental regulation.
Various federal and state entities, including but not limited to the FERC, KPSC, VSCC, TRA and PUC regulate many aspects of the domestic utility operations of PPL, including:
· | the rates that we may charge and the terms and conditions of our service and operations; |
· | financial and capital structure matters; |
· | siting, construction and operation of facilities; |
· | mandatory reliability and safety standards and other standards of conduct; |
· | accounting, depreciation and cost allocation methodologies; |
· | acquisition and disposal of utility assets and securities; and |
Such regulations or changes thereto may subject us to higher operating costs or increased capital expenditures and failure to comply could result in sanctions or possible penalties. In any rate-setting proceedings, federal or state agencies, intervenors and other permitted parties may challenge our rate requests, and ultimately reduce, alter or limit the rates we seek.
We could be subject to higher costs and/or penalties related to mandatory reliability standards.
Under the Energy Policy Act of 2005, owners and operators of the bulk power electricity system are now subject to mandatory reliability standards promulgated by the NERC and enforced by the FERC. Compliance with reliability standards may subject us to higher operating costs and/or increased capital expenditures, and violations of these standards could result in substantial penalties which may not be recoverable from customers.
Changes in transmission and wholesale power market structures could increase costs or reduce revenues.
Wholesale revenues fluctuate with regional demand, fuel prices and contracted capacity. Changes to transmission and wholesale power market structures and prices may occur in the future, are not predictable and may result in unforeseen effects on energy purchases and sales, transmission and related costs or revenues. These can include commercial or regulatory changes affecting power pools, exchanges or markets in which PPL participates.
Our domestic regulated businesses undertake significant capital projects and these activities are subject to unforeseen costs, delays or failures, as well as risk of inadequate recovery of resulting costs.
The domestic regulated utility businesses are capital intensive and require significant investments in energy generation (in the case of LG&E and KU) and transmission, distribution and other infrastructure projects, such as projects for environmental compliance and system reliability. The completion of these projects without delays or cost overruns is subject to risks in many areas, including:
· | approval, licensing and permitting; |
· | land acquisition and the availability of suitable land; |
· | skilled labor or equipment shortages; |
· | construction problems or delays, including disputes with third party intervenors; |
· | increases in commodity prices or labor rates; |
· | environmental considerations and regulations; |
· | weather and geological issues; and |
· | political, labor and regulatory developments. |
Failure to complete our capital projects on schedule or on budget, or at all, could adversely affect our financial performance, operations and future growth if such expenditures are not granted rate recovery by our regulators.
Risks Specific to Kentucky Regulated Segment
(PPL, LKE, LG&E and KU)
The costs of compliance with, and liabilities under, environmental laws are significant and are subject to continuing changes.
Extensive federal, state and local environmental laws and regulations are applicable to LG&E's and KU's generation business, including its air emissions, water discharges and the management of hazardous and solid waste, among other business-related activities; and the costs of compliance or alleged non-compliance cannot be predicted but could be material. In addition, our costs may increase significantly if the requirements or scope of environmental laws, regulations or similar rules are expanded or changed. Costs may take the form of increased capital expenditures or operating and maintenance expenses, monetary fines, penalties or forfeitures or other restrictions. Many of these environmental law considerations are also applicable to the operations of our key suppliers, or customers, such as coal producers and industrial power users, and may impact the costs of their products and demand for our services.
Ongoing changes in environmental regulations or their implementation requirements and our compliance strategies relating thereto entail a number of uncertainties.
The environmental standards governing LG&E's and KU's businesses, particularly as applicable to coal-fired generation and related activities, continue to be subject to uncertainties due to ongoing rulemakings and other regulatory developments, legislative activities and litigation. The uncertainties associated with these developments introduce risks to our management of operations and regulatory compliance. Environmental developments, including revisions to applicable standards, changes in compliance deadlines and invalidation of rules on appeal may require major changes in compliance strategies, operations or assets and adjustments to prior plans. Depending on the extent, frequency and timing of such changes, the companies may be subject to inconsistent requirements under multiple regulatory programs, compressed windows for decision-making and short compliance deadlines that may require aggressive schedules for construction, permitting, and other regulatory approvals. Under such circumstances, the companies may face higher risks of unsuccessful implementation of environmental-related business plans, noncompliance with applicable environmental rules, or increased costs of implementation.
Risks Specific to Pennsylvania Regulated Segment
(PPL and PPL Electric)
We may be subject to higher transmission costs and other risks as a result of PJM's regional transmission expansion plan (RTEP) process.
PJM and the FERC have the authority to require upgrades or expansion of the regional transmission grid, which can result in substantial expenditures for transmission owners. As discussed in Note 8 to the Financial Statements, we expect to make substantial expenditures to construct the Susquehanna-Roseland transmission line that PJM has determined is necessary for the reliability of the regional transmission grid. Although the FERC has granted our request for incentive rate treatment of such facilities, we cannot be certain that all costs that we may incur will be recoverable. In addition, the date when these facilities will be in service, which can be significantly impacted by delays related to public opposition or other factors, is subject to the outcome of future events that are not all within our control. As a result, we cannot predict the ultimate financial or operational impact of this project or other RTEP projects on PPL Electric.
We could be subject to higher costs and/or penalties related to Pennsylvania Conservation and Energy Efficiency Programs.
PPL Electric is subject to Act 129 which contains requirements for energy efficiency and conservation programs and for the use of smart metering technology, imposes new PLR electricity supply procurement rules, provides remedies for market misconduct, and made changes to the existing AEPS. The law also requires electric utilities to meet specified goals for reduction in customer electricity usage and peak demand by specified dates (2011 and 2013 for Phase 1 and by 2016 for Phase 2). Utilities not meeting these requirements of Act 129 are subject to significant penalties that cannot be recovered in rates. Numerous factors outside of our control could prevent compliance with these requirements and result in penalties to us.
(PPL)
Risks Related to U.K. Regulated Segment
Our U.K. delivery business is subject to risks with respect to rate regulation and operational performance.
Our U.K. delivery business is rate-regulated and operates under an incentive-based regulatory framework. In addition, its ability to manage operational risk is critical to its financial performance. Disruption to the distribution network could reduce profitability both directly through the higher costs for network restoration and also through the system of penalties and rewards that Ofgem has in place relating to customer service levels.
In December 2009, Ofgem completed its rate review for the five-year period from April 1, 2010 through March 31, 2015, reducing regulatory rate uncertainty in the U.K. Regulated segment until the next rate review which will be effective April 1, 2015. The regulated income of the U.K. Regulated segment and also the RAV are to some extent linked to movements in the Retail Price Index (RPI), a measure of inflation. Reductions in the RPI would adversely impact revenues and the debt-to-RAV ratio.
Our U.K. distribution business exposes us to risks related to U.K. laws and regulations, taxes, economic conditions, foreign currency exchange rate fluctuations, and political conditions and policies of the U.K. government. These risks may reduce the results of operations from our U.K. distribution business:
· | changes in laws or regulations relating to U.K. operations, including tax laws and regulations; |
· | changes in government policies, personnel or approval requirements; |
· | changes in general economic conditions affecting the U.K.; |
· | regulatory reviews of tariffs for distribution companies; |
· | severe weather and natural disaster impacts on the electric sector and our assets; |
· | changes in labor relations; |
· | limitations on foreign investment or ownership of projects and returns or distributions to foreign investors; |
· | limitations on the ability of foreign companies to borrow money from foreign lenders and lack of local capital or loans; |
· | fluctuations in foreign currency exchange rates and in converting U.K. revenues to U.S. dollars, which can increase our expenses and/or impair our ability to meet such expenses, and difficulty moving funds out of the country in which the funds were earned; and |
· | compliance with U.S. foreign corrupt practices laws. |
The WPD Midlands acquisition may not achieve its intended results, including anticipated cost savings, efficiencies and other benefits.
Although we completed the WPD Midlands acquisition with the expectation that it will result in various benefits, including a significant amount ofopportunities, cost savings and other synergies that we expect, either within the anticipated time frame for integration or at all. For example, we may be unable to eliminate all duplicative costs. Also, as a standalone company outside of the PPL and Riverstone groups of companies, we may not be able to replace the resources provided by PPL or Riverstone to the Talen Energy and RJS Power businesses prior to the Talen
Transactions. Alternatively, we may be able to replace them but not at the same or lower cost as what previously was available, and any resulting incremental costs could be material.
Our accounting, management and financial reporting systems may not be adequately prepared to comply with the disclosure controls and operational benefits, there can be no assurance regarding the extentinternal control over financial reporting requirements to which we will be ableare subject.
Prior to realize these cost-savings or other benefits. AchievingJune 1, 2015, our financial results were included within the anticipated benefits, including cost savings, isconsolidated results of PPL, and RJS Power was not subject to a numberthe reporting and other requirements of uncertainties, including whether the businesses acquired can be operated in the manner we intend. Events outside of our control, including but not limited to regulatory changes or developments in the U.K., could also adversely affect our ability to realize the anticipated benefits from the WPD Midlands acquisition.Exchange Act.
The WPD Midlands acquisition exposes us to additional risks and uncertainties with respect to the acquired businesses and their operations.
Although the WPD Midlands acquisition increased our relative investment in regulated operations, which we believe should help mitigate our exposure to downturns in the wholesale power markets, it will increase our dependence on rate-of-return regulation.
The WPD businesses generallyWe now are subject to risks similar to those toreporting and other obligations under the Exchange Act and are responsible for ensuring that all aspects of our business comply with Section 404 of the Sarbanes-Oxley Act, under which we were subject in our pre-acquisition U.K. businesses. These include:
| | |
| · | There are various changes being contemplated by Ofgem to the current electricity distribution, gas transmission and gas distribution regulatory frameworks in the U.K. and there can be no assurance as to the effects such changes will have on our U.K. regulated businesses in the future, including the acquired businesses. In particular, in October 2010, Ofgem announced a new regulatory framework that is expected to become effective in April 2015 for the electricity distribution sector in the U.K. The framework, known as RIIO (Revenues = Incentives + Innovation + Outputs), focuses on sustainability, environmental-focused output measures, promotion of low carbon energy networks and financing of new investments. The new regulatory framework is expected to have a wide-ranging effect on electricity distribution companies operating in the U.K., including changes to price controls and price review periods. Our U.K. regulated businesses' compliance with this new regulatory framework may result in significant additional capital expenditures, increases in operating and compliance costs and adjustments to our pricing models. |
| | |
| · | Ofgem has formal powers to propose modifications to each distribution license. We are not currently aware of any planned modification to any of our U.K. regulated businesses distribution licenses that would result in a material adverse change to the U.K. regulated businesses and PPL. There can, however, be no assurance that a restrictive modification will not be introduced in the future, which could have an adverse effect on the operations and financial condition of the U.K. regulated businesses and PPL. |
| | |
| · | A failure to operate our U.K. networks properly could lead to compensation payments or penalties, or a failure to make capital expenditures in line with agreed investment programs could lead to deterioration of the network. While our U.K. regulated businesses' investment programs are targeted to maintain asset conditions over a five-year period and reduce customer interruptions and customer minutes lost over that period, no assurance can be provided that these regulatory requirements will be met. |
| | |
| · | A failure by any of our U.K. regulated businesses to comply with the terms of a distribution license may lead to the issuance of an enforcement order by Ofgem that could have an adverse impact on PPL. Ofgem has powers to levy fines of up to 10 percent of revenue for any breach of a distribution license or, in certain circumstances, such as insolvency, the distribution license itself may be revoked. Unless terminated in the circumstances mentioned above, a distribution license continues indefinitely until revoked by Ofgem following no less than 25 years' written notice. |
| | |
| · | We will be subject to increased foreign currency exchange rate risks because a greater portion of our cash flows and reported earnings will be generated by our U.K. business operations. These risks relate primarily to changes in the relative value of the British pound sterling and the U.S. dollar between the time we initially invest U.S. dollars in our U.K. businesses and the time that cash is repatriated to the U.S.must maintain effective disclosure controls and procedures and internal control over financial reporting. To comply with these requirements on a stand-alone basis separate from the U.K., including cash flows from our U.K. businesses that may be distributed as future dividends to our shareholders or repayments of intercompany loans. In addition, our consolidated reported earnings on a U.S. GAAP basis may be subject to increased earnings translation risk, which is the result of the conversion of earnings as reported in our U.K. businesses on a British pound sterling basis to a U.S. dollar basis in accordance with U.S. GAAP requirements. |
| | |
| · | Environmental costs and liabilities associated with aspects of the acquired businesses may differ from those of our existing business. |
Risks Related to Supply Segment
(PPL and PPL Energy Supply)
We face intense competition inwith the addition of the RJS Power business, we may need to upgrade our energy supply business, which may adversely affectsystems, implement additional financial and management controls, reporting systems and procedures, and hire additional accounting, legal and finance staff. Along those lines, our ability to operate profitably.
Unlike our regulated utility businesses, our energy supply business is dependentreport on our abilityinternal control over financial reporting in this Form 10-K includes a scope exception for the RJS Power business. It also includes a scope exception for the MACH Gen business acquired in November 2015. We expect to operate in a competitive environmentincur additional annual expenses for the purpose of addressing these reporting and is not assured of any rate of return on capital investments through a predetermined rate structure. Competition is impacted by electricity and fuel prices, new market entrants, construction by others of generating assets and transmission capacity, technological advances in power generation, the actions of environmental and other regulatory authorities and other factors. These competitive factors may negatively impact our ability to sell electricity and related products and services, as well as the prices that we may charge for such products and services, which could adversely affect our results of operations and our ability to grow our business.
We sell our available energy and capacity into the competitive wholesale markets through contracts of varying duration. Competition in the wholesale power markets occurs principally on the basis of the price of products and, to a lesser extent, on the basis of reliability and availability. We believe that the commencement of commercial operation of new electricity generating facilities in the regional markets where we own or control generation capacity and the evolution of demand side management resources will continue to increase competition in the wholesale electricity market in those regions, which could have an adverse effect on capacity prices and the prices we receive for electricity.
We also face competition in the wholesale markets for electricity capacity and ancillary services. We primarily compete with other electricity suppliers based on our ability to aggregate supplies at competitive prices from different sources and to efficiently utilize transportation from third-party pipelines and transmission from electric utilities and ISOs. We also compete against other energy marketers on the basis of relative financial condition and access to credit sources, and our competitors may have greater financial resources than we have.
Competitors in the wholesale power markets in which PPL Generation subsidiaries and PPL EnergyPlus operate include regulated utilities, industrial companies, non-utility generators, competitive subsidiaries of regulated utilities and financial institutions.
Adverse changes in commodity prices and related costs may decrease our future energy margins, which could adversely affect our earnings and cash flows.
Our energy margins, or the amount by which our revenues from the sale of power exceed our costs to supply power, are impacted by changes in market prices for electricity, fuel, fuel transportation, emission allowances, RECs, electricity transmission and related congestion charges and other costs. Unlike most commodities, the limited ability to store electric power requires that it must be consumed at the time of production. As a result, wholesale market prices for electricity may fluctuate substantially over relatively short periods of time and can be unpredictable. Among the factors that influence such prices are:
· | supply and demand for electricity available from current or new generation resources; |
· | variable production costs, primarily fuel (and the associated fuel transportation costs) and emission allowance expense for the generation resources used to meet the demand for electricity; |
· | transmission capacity and service into, or out of, markets served; |
· | changes in the regulatory framework for wholesale power markets; |
· | liquidity in the wholesale electricity market, as well as general creditworthiness of key participants in the market; and |
· | weather and economic conditions impacting demand for or the price of electricity or the facilities necessary to deliver electricity. |
We do not always hedge against risks associated with electricity and fuel price volatility.
We attempt to mitigate risks associated with satisfying our contractual electricity sales obligations by either reserving generation capacity to deliver electricity or purchasing the necessary financial or physical products and services through competitive markets to satisfy our net firm sales contracts. We also routinely enter into contracts, such as fuel and electricity purchase and sale commitments, to hedge our exposure to fuelcompliance requirements, and other electricity-related commodities. However, based on economic and other considerations, we may decide not to hedge the entire exposure of our operations from commodity price risk. To the extent we do not hedge against commodity price risk, our results of operations and financial positionthose expenses may be adversely affected.
We are exposed to operational, price and credit risks associated with selling and marketing products in the wholesale and retail electricity markets.
We purchase and sell electricity in wholesale markets under market-based tariffs authorized by FERC throughout the U.S. and also enter into short-term agreements to market available electricity and capacity from our generation assets with the expectation of profiting from market price fluctuations.significant. If we are unable to deliver firm capacityupgrade our financial and electricity under these agreements, we could be required to pay damages. These damages would generally be based on the difference between the market price to acquire replacement capacity or electricitymanagement controls, reporting systems, IT systems and the contract price of any undelivered capacity or electricity. Depending on price volatilityprocedures in the wholesale electricity markets, such damages could be significant. Extreme weather conditions, unplanned generation facility outages, environmental compliance costs, transmission disruptions,a timely and other factors could affecteffective fashion, our ability to meet our obligations, or cause significant increases insatisfy financial reporting requirements and other rules that apply to reporting companies under the market price of replacement capacityExchange Act and electricity.
Our wholesale power agreements typically include provisions requiring us to post collateral for the benefit of our counterparties if the market price of energy varies from the contract prices in excess of certain pre-determined amounts. We currently believe that we have sufficient credit to fulfill our potential collateral obligations under these power contracts. However, our obligation to post collateral could exceed the amount of our facilities or our ability to increase our facilitiesSarbanes-Oxley Act could be limited by financial markets or other factors. See Note 7impaired. Any failure to the Financial Statements for a discussion of PPL's credit facilities.
We also face credit risk that parties with whom we contract in both the wholesaleachieve and retail markets will default in their performance, in which case we may have to sell our electricity into a lower-priced market or make purchases in a higher-priced market than existed at the time of contract. Whenever feasible, we attempt to mitigate these risks using various means, including agreements that require our counterparties to post collateral for our benefit if the market price of energy varies from the contract price in excess of certain pre-determined amounts. However, there can be no assurance that we will avoid counterparty nonperformance risk, including bankruptcy, which could adversely impact our ability to meet our obligations to other parties, which could in turn subject us to claims for damages.
The load following contracts that PPL EnergyPlus is awarded do not provide for specific levels of load and actual load significantly below or above our forecasts could adversely affect our energy margins.
We generally hedge our load following obligations with energy purchases from third parties, and to a lesser extent with our own generation. If the actual load is significantly lower than the expected load, we may be required to resell power at a lower price than was contracted for to supply the load obligation, resulting in a financial loss. Alternatively, a significant increase in load could adversely affect our energy margins because we are required under the terms of the load following contracts to provide the energy necessary to fulfill increased demand at the contract price, which could be lower than the cost to procure additional energy on the open market. Therefore, any significant decrease or increase in load compared with our forecastsmaintain effective internal controls could have a material adverse effect on our business, financial condition and results of operationsoperations.
Ownership of our common stock is highly concentrated, and financial position.the Riverstone Holders may exert significant influence over matters requiring Board of Directors and/or stockholder approval.
We may experience disruptions inThe Riverstone Holders, each of which is indirectly controlled by Riverstone, collectively beneficially own approximately 35% of the outstanding shares of our fuel supply, which could adversely affect ourcommon stock. As a result, the Riverstone Holders collectively exercise significant influence over all matters requiring stockholder approval for the foreseeable future, including approval of significant corporate transactions. Moreover, pursuant to a stockholder agreement, the Riverstone Holders have the right to appoint individuals to serve on the Board of Directors of Talen Energy Corporation. See "Item 13. Certain Relationships and Related Transactions, and Director Independence." Currently, Messrs. Alexander, Casey and Hoffman serve on the Board of Directors as designees of the Riverstone Holders. As a result, the Riverstone Holders have the ability to operateexert significance influence over matters requiring approval of our generation facilities.Board of Directors and other matters subject to the terms of that stockholder agreement.
We purchase fuel fromThe interests of the Riverstone Holders may conflict with the interests of our other stockholders. The Riverstone Holders may have an interest in having us pursue acquisitions, divestitures and other transactions that, in their judgment, could enhance their investment in us, even though such transactions might involve risks to other stockholders. In addition, Riverstone and its affiliates engage in a broad spectrum of activities, including investments in the power generation industry. In the ordinary course of their business activities, Riverstone and its affiliates may engage in activities where their interests conflict with our interests or those of our stockholders.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Talen Energy Corporation and Talen Energy Supply, LLC
None.
ITEM 2. PROPERTIES
The capacity of generation units is based on a number of suppliers. Disruption infactors, including the deliveryoperating experience and physical conditions of fuelthe units and other products consumed during the production of electricity (suchmay be revised periodically to reflect changed circumstances. Talen Energy's electric generating capacity (summer rating) at December 31, 2015 by segment was as coal, natural gas, oil, water, uranium, lime, limestone and other chemicals), including disruptions as a result of weather, transportation difficulties, global demand and supply dynamics, labor relations, environmental regulations or the financial viability of our fuel suppliers, could adversely affect our ability to operate our facilities, which could result in lower sales and/or higher costs and thereby adversely affect our results of operations.follows.
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| | | | | | | | | | | | | | | | |
Plant | | Owner | | Total MW Capacity | | % Ownership | | Talen Energy's Ownership in MW | | Fuel Type | | State | | Region/ISO |
| | | | | | | | | | | | | | |
East segment | | | | | | | | | | | | | | |
Martins Creek | | Talen Generation | | 1,708 |
| | 100.00 | | 1,708 |
| | Natural Gas/Oil | | PA | | PJM |
Ironwood (a) | | Talen Generation | | 661 |
| | 100.00 | | 661 |
| | Natural Gas | | PA | | PJM |
Lower Mt. Bethel | | Talen Generation | | 555 |
| | 100.00 | | 555 |
| | Natural Gas | | PA | | PJM |
Combustion turbines | | Talen Generation | | 370 |
| | 100.00 | | 370 |
| | Natural Gas/Oil | | PA | | PJM |
Bayonne | | Sapphire | | 165 |
| | 100.00 | | 165 |
| | Natural Gas/Oil | | NJ | | PJM |
Camden | | Sapphire | | 145 |
| | 100.00 | | 145 |
| | Natural Gas/Oil | | NJ | | PJM |
Dartmouth | | Sapphire | | 82 |
| | 100.00 | | 82 |
| | Natural Gas/Oil | | MA | | ISO-NE |
Elmwood Park | | Sapphire | | 70 |
| | 100.00 | | 70 |
| | Natural Gas/Oil | | NJ | | PJM |
Newark Bay | | Sapphire | | 122 |
| | 100.00 | | 122 |
| | Natural Gas/Oil | | NJ | | PJM |
Pedricktown (b) | | Sapphire | | 117 |
| | 100.00 | | 117 |
| | Natural Gas/Oil | | NJ | | PJM |
York | | Sapphire | | 46 |
| | 100.00 | | 46 |
| | Natural Gas | | PA | | PJM |
Montour | | Talen Generation | | 1,528 |
| | 100.00 | | 1,528 |
| | Coal | | PA | | PJM |
Brunner Island | | Talen Generation | | 1,428 |
| | 100.00 | | 1,428 |
| | Coal | | PA | | PJM |
Keystone (c) | | Talen Generation | | 1,718 |
| | 12.34 | | 212 |
| | Coal | | PA | | PJM |
Conemaugh (c) | | Talen Generation | | 1,754 |
| | 16.25 | | 285 |
| | Coal | | PA | | PJM |
Brandon Shores | | Raven | | 1,274 |
| | 100.00 | | 1,274 |
| | Coal | | MD | | PJM |
C.P. Crane (a) | | Raven | | 402 |
| | 100.00 | | 402 |
| | Coal | | MD | | PJM |
H.A. Wagner | | Raven | | 966 |
| | 100.00 | | 966 |
| | Coal/Natural Gas/Oil | | MD | | PJM |
Susquehanna (c) | | Talen Generation | | 2,513 |
| | 90.00 | | 2,262 |
| | Nuclear | | PA | | PJM |
Holtwood (a) | | Talen Generation | | 262 |
| | 100.00 | | 262 |
| | Hydro | | PA | | PJM |
Lake Wallenpaupack (a) | | Talen Generation | | 46 |
| | 100.00 | | 46 |
| | Hydro | | PA | | PJM |
Athens | | MACH Gen | | 969 |
| | 100.00 | | 969 |
| | Natural Gas | | NY | | NYISO |
Millennium | | MACH Gen | | 335 |
| | 100.00 | | 335 |
| | Natural Gas | | MA | | ISO-NE |
Renewables (d) | | N/A | | 7 |
| | 100.00 | | 7 |
| | Renewables | | PA | | PJM |
| | | | 17,243 |
| | | | 14,017 |
| | | | | | |
West segment | | | | | | | | | | | | | | |
Laredo | | Jade | | 181 |
| | 100.00 | | 181 |
| | Natural Gas | | TX | | ERCOT |
Nueces Bay | | Jade | | 648 |
| | 100.00 | | 648 |
| | Natural Gas | | TX | | ERCOT |
Barney Davis | | Jade | | 964 |
| | 100.00 | | 964 |
| | Natural Gas | | TX | | ERCOT |
Harquahala | | MACH Gen | | 1,040 |
| | 100.00 | | 1,040 |
| | Natural Gas | | AZ | | WECC |
Colstrip Units 1 & 2 (c) | | Talen Generation | | 614 |
| | 50.00 | | 307 |
| | Coal | | MT | | WECC |
Colstip Unit 3 (c) | | Talen Generation | | 740 |
| | 30.00 | | 222 |
| | Coal | | MT | | WECC |
| | | | 4,187 |
| | | | 3,362 |
| | | | | | |
Total | | | | 21,430 |
| | | | 17,379 |
| | | | | | |
Unforeseen changes in the price of coal and natural gas could cause us to incur excess coal inventories and contract termination costs.
Extraordinarily low natural gas prices during 2012 caused natural gas to be the more cost competitive fuel compared to coal for generating electricity. Because we enter into guaranteed supply contracts to provide for the amount of coal needed to operate our base load coal-fired generating facilities, we may experience periods where we hold excess amounts of coal if fuel pricing results in our reducing or idling coal-fired generating facilities in favor of operating available alternative natural gas-fired generating facilities. In addition, we may incur costs to terminate supply contracts for coal in excess of our generating requirements.
Our risk management policy and programs relating to electricity and fuel prices, interest rates and counterparty credit and non-performance risks may not work as planned, and we may suffer economic losses despite such programs.
We actively manage the market risk inherent in our generation and energy marketing activities, as well as our debt and counterparty credit positions. We have implemented procedures to monitor compliance with our risk management policy and programs, including independent validation of transaction and market prices, verification of risk and transaction limits, portfolio stress tests, sensitivity analyses and daily portfolio reporting of various risk management metrics. Nonetheless, our risk management programs may not work as planned. For example, actual electricity and fuel prices may be significantly different or more volatile than the historical trends and assumptions upon which we based our risk management calculations. Additionally, unforeseen market disruptions could decrease market depth and liquidity, negatively impacting our ability to enter into new transactions. We enter into financial contracts to hedge commodity basis risk, and as a result are exposed to the risk that the correlation between delivery points could change with actual physical delivery. Similarly, interest rates or foreign currency exchange rates could change in significant ways that our risk management procedures were not designed to address. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events result in greater losses or costs than our risk models predict or greater volatility in our earnings and financial position.
In addition, our trading, marketing and hedging activities are exposed to counterparty credit risk and market liquidity risk. We have adopted a credit risk management policy and program to evaluate counterparty credit risk. However, if counterparties fail to perform, we may be forced to enter into alternative arrangements at then-current market prices. In that event, our financial results are likely to be adversely affected.
Our costs to comply with existing and new environmental laws are expected to continue to be significant, and we plan to incur significant capital expenditures for pollution control improvements that, if delayed, would adversely affect our profitability and liquidity.
Our business is subject to extensive federal, state and local statutes, rules and regulations relating to environmental protection. To comply with existing and future environmental requirements and as a result of voluntary pollution control measures we may take, we have spent and expect to spend substantial amounts in the future on environmental control and compliance.
In order to comply with existing and previously proposed federal and state environmental laws and regulations primarily governing air emissions from coal-fired plants, since 2005 PPL has spent more than $1.6 billion to install scrubbers and other pollution control equipment (primarily aimed at sulfur dioxide, particulate matter and nitrogen oxides with co-benefits for mercury emissions reduction) in its competitive generation fleet. Many states and environmental groups have challenged certain federal laws and regulations relating to air emissions as not being sufficiently strict. As a result, state and federal regulations have been adopted that would impose more stringent restrictions than are currently in effect, which could require us significantly to increase capital expenditures for additional pollution control equipment.
We may not be able to obtain or maintain all environmental regulatory approvals necessary for our planned capital projects which are necessary to our business. If there is a delay in obtaining any required environmental regulatory approval or if we fail to obtain, maintain or comply with any such approval, operations at our affected facilities could be halted, reduced or subjected to additional costs. Furthermore, at some of our older generating facilities it may be uneconomic for us to install necessary pollution control equipment, which could cause us to retire those units.
For more information regarding environmental matters, including existing and proposed federal, state and local statutes, rules and regulations to which we are subject, see "Environmental Matters - Domestic" in Note 15 to the Financial Statements.
We rely on transmission and distribution assets that we do not own or control to deliver our wholesale electricity. If transmission is disrupted, or not operated efficiently, or if capacity is inadequate, our ability to sell and deliver power may be hindered.
We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity and natural gas we sell in the wholesale market, as well as the natural gas we purchase for use in our electricity generation facilities. If transmission is disrupted (as a result of weather, natural disasters or other reasons) or not operated efficiently by ISOs and RTOs, in applicable markets, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual obligations may be hindered, or we may be unable to sell products at the most favorable terms.
The FERC has issued regulations that require wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, there is the potential that fair and equal access to transmission systems will not be available or that transmission capacity will not be available in the amounts we require. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets or whether ISOs and RTOs in applicable markets will efficiently operate transmission networks and provide related services.
Despite federal and state deregulation initiatives, our supply business is still subject to extensive regulation, which may increase our costs, reduce our revenues, or prevent or delay operation of our facilities.
Our generation subsidiaries sell electricity into the wholesale market. Generally, our generation subsidiaries and our marketing subsidiaries are subject to regulation by the FERC. The FERC has authorized us to sell generation from our facilities and power from our marketing subsidiaries at market-based prices. The FERC retains the authority to modify or withdraw our market-based rate authority and to impose "cost of service" rates if it determines that the market is not competitive, that we possess market power or that we are not charging just and reasonable rates. Any reduction by the FERC in the rates we may receive or any unfavorable regulation of our business by state regulators could materially adversely affect our results of operations. See "FERC Market-Based Rate Authority" in Note 15 to the Financial Statements for information regarding recent court decisions that could impact the FERC's market-based rate authority program.
In addition, the acquisition, construction, ownership and operation of electricity generation facilities require numerous permits, approvals, licenses and certificates from federal, state and local governmental agencies. We may not be able to obtain or maintain all required regulatory approvals. If there is a delay in obtaining any required regulatory approvals or if we fail to obtain or maintain any required approval or fail to comply with any applicable law or regulation, the operation of our assets and our sales of electricity could be prevented or delayed or become subject to additional costs.
If market deregulation is reversed or discontinued, our business prospects and financial condition could be materially adversely affected.
In some markets, state legislators, government agencies and other interested parties have made proposals to change the use of market-based pricing, re-regulate areas of these markets that have previously been competitive or permit electricity delivery companies to construct, contract for, or acquire generating facilities. The ISOs that oversee the transmission systems in certain wholesale electricity markets have from time to time been authorized to impose price limitations and other mechanisms to address extremely high prices in the power markets. These types of price limitations and other mechanisms may reduce profits that our wholesale power marketing and trading business would have realized under competitive market conditions absent such limitations and mechanisms. Although we generally expect electricity markets to continue to be competitive, other proposals to re-regulate our industry may be made, and legislative or other actions affecting the electric power restructuring process may cause the process to be delayed, discontinued or reversed in states in which we currently, or may in the future, operate. See "New Jersey Capacity Legislation" and "Maryland Capacity Order" in Note 15 to the Financial Statements.
Changes in technology may negatively impact the value of our power plants.
A basic premise of our generation business is that generating electricity at central power plants achieves economies of scale and produces electricity at relatively low prices. There are alternate technologies to produce electricity, most notably fuel cells, micro turbines, windmills and photovoltaic (solar) cells, the development of which has been expanded due to global climate change concerns. Research and development activities are ongoing to seek improvements in alternate technologies. It is possible that advances will reduce the cost of alternate methods of electricity production to a level that is equal to or below that of certain central station production. Also, as new technologies are developed and become available, the quantity and pattern of electricity usage (the "demand") by customers could decline, with a corresponding decline in revenues derived by generators. These alternative energy sources could result in a decline to the dispatch and capacity factors of our plants. As a result of all of these factors, the value of our generation facilities could be significantly reduced.
We are subject to certain risks associated with nuclear generation, including the risk that our Susquehanna nuclear plant could become subject to increased security or safety requirements that would increase capital and operating expenditures, uncertainties regarding spent nuclear fuel, and uncertainties associated with decommissioning our plant at the end of its licensed life.
Nuclear generation accounted for about 31% of our 2012 generation output. The risks of nuclear generation generally include:
· | |
(a) | Plant was sold in the potential harmful effects onfirst quarter of 2016 or is under an agreement of sale to satisfy the environment and human health from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials; |
· | limitations on the amounts and types of insurance commercially available to cover losses and liabilities that might ariseFERC approved mitigation in connection with nuclear operations; and |
· | uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives. The licenses for our two nuclear units expire in 2042 and 2044.RJS Power acquisition. See Note 211 to the Financial Statements for additional information on the ARO related to the decommissioning. |
The NRC has broad authority under federal law to impose licensing requirements, including security, safety and employee-related requirements for the operation of nuclear generation facilities. In the event of noncompliance, the NRC has authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. In addition, revised security or safety requirements promulgated by the NRC could necessitate substantial capital or operating expenditures at our Susquehanna nuclear plant. There also remains substantial uncertainty regarding the temporary storage and permanent disposal of spent nuclear fuel, which could result in substantial additional costs to PPL that cannot be predicted. In addition, although we have no reason to anticipate a serious nuclear incident at our Susquehanna plant, if an incident did occur, any resulting operational loss, damages and injuries could have a material adverse effect on our results of operations, cash flows and financial condition. See Note 15 to the Financial Statements for a discussion of nuclear insurance.
ITEM 1B. UNRESOLVED STAFF COMMENTS
PPL Corporation, PPL Energy Supply, LLC, PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
None.
(PPL, LKE, LG&E and KU)
Kentucky Regulated Segment
LG&E's and KU's properties consist primarily of regulated generation facilities, electric transmission and distribution assets and natural gas transmission and distribution assets in Kentucky. The electric generating capacity at December 31, 2012 was:
| | | | | LKE | | LG&E | | KU |
| | | | | | | | | | | | | |
| | | Total MW | | Ownership or | | | | Ownership or | | | | Ownership or |
| | | Capacity (b) | | Lease Interest | | | | Lease Interest | | | | Lease Interest |
Primary Fuel/Plant (a) | | Summer | | in MW | | % Ownership | | in MW | | % Ownership | | in MW |
| | | | | | | | | | | | | |
Coal | | | | | | | | | | | | |
| Ghent | | 1,932 | | 1,932 | | | | | | 100.00 | | 1,932 |
| Mill Creek | | 1,472 | | 1,472 | | 100.00 | | 1,472 | | | | |
| E.W. Brown - Units 1-3 | | 684 | | 684 | | | | | | 100.00 | | 684 |
| Cane Run - Units 4-6 | | 563 | | 563 | | 100.00 | | 563 | | | | |
| Trimble County - Unit 1 (c) | | 511 | | 383 | | 75.00 | | 383 | | | | |
| Trimble County - Unit 2 (c) | | 732 | | 549 | | 14.25 | | 104 | | 60.75 | | 445 |
| Green River | | 163 | | 163 | | | | | | 100.00 | | 163 |
| OVEC - Clifty Creek (d) | | 1,304 | | 106 | | 5.63 | | 73 | | 2.50 | | 33 |
| OVEC - Kyger Creek (d) | | 1,086 | | 88 | | 5.63 | | 61 | | 2.50 | | 27 |
| Tyrone (e) | | 71 | | 71 | | | | | | 100.00 | | 71 |
| | | 8,518 | | 6,011 | | | | 2,656 | | | | 3,355 |
Natural Gas/Oil | | | | | | | | | | | | |
| E.W. Brown Unit 5 (f)(g) | | 132 | | 132 | | 53.00 | | 69 | | 47.00 | | 63 |
| E.W. Brown Units 6-7 (f) | | 292 | | 292 | | 38.00 | | 111 | | 62.00 | | 181 |
| E.W. Brown Units 8-11 (g) | | 486 | | 486 | | | | | | 100.00 | | 486 |
| Trimble County Units 5-6 | | 314 | | 314 | | 29.00 | | 91 | | 71.00 | | 223 |
| Trimble County Units 7-10 | | 628 | | 628 | | 37.00 | | 232 | | 63.00 | | 396 |
| Paddy's Run Units 11-12 | | 35 | | 35 | | 100.00 | | 35 | | | | |
| Paddy's Run Unit 13 | | 147 | | 147 | | 53.00 | | 78 | | 47.00 | | 69 |
| Haefling | | 36 | | 36 | | | | | | 100.00 | | 36 |
| Zorn | | 14 | | 14 | | 100.00 | | 14 | | | | |
| Cane Run Unit 11 | | 14 | | 14 | | 100.00 | | 14 | | | | |
| | | 2,098 | | 2,098 | | | | 644 | | | | 1,454 |
Hydro | | | | | | | | | | | | |
| Ohio Falls | | 54 | | 54 | | 100.00 | | 54 | | | | |
| Dix Dam | | 24 | | 24 | | | | | | 100.00 | | 24 |
| | | 78 | | 78 | | | | 54 | | | | 24 |
| | | | | | | | | | | | | |
Total | | 10,694 | | 8,187 | | | | 3,354 | | | | 4,833 |
(a) | LG&EFERC approved mitigation and KU's properties are primarily located in Kentucky, with the exception of the units owned by OVEC. Clifty Creek is located in Indiana and Kyger Creek is located in Ohio. |
(b) | The capacity of generation units is based on a number of factors, including the operating experience and physical conditions of the units, and may be revised periodically to reflect changed circumstances. |
(c) | TC1 and TC2 are jointly owned with Illinois Municipal Electric Agency and Indiana Municipal Power Agency. Each owner is entitled to its proportionate share of the units' total output and funds its proportionate share of capital, fuel and other operating costs. See Note 146 to the Financial Statements for additional information. |
(d) | This unit is owned by OVEC. LKE has a power purchase agreement that entitles LKE to its proportionate share of the unit's total output and LKE funds its proportionate share of fuel and other operating costs. See Note 15 to the Financial Statements for additional information. |
(e) | This unit was retired in February 2013. See Note 8 to the Financial Statements for additional information. |
(f) | Includes a leasehold interest. See Note 11 to the Financial Statements for additional information. |
(g) | There is an inlet air cooling system attributable to these units. This inlet air cooling system is not jointly owned; however, it is used to increase productioninformation on the units to which it relates, resulting in an additional 10 MW of capacity for LG&E and an additional 88 MW of capacity for KU.announced sales. |
For a description of LG&E's and KU's service areas, see "Item 1. Business - Background." At December 31, 2012, LG&E's transmission system included in the aggregate, 45 substations (32 of which are shared with the distribution system) with a total capacity of 7 million kVA and 917 circuit miles of lines. LG&E's distribution system included 97 substations (32 of which are shared with the transmission system) with a total capacity of 5 million kVA, 3,908 miles of overhead lines and 2,390 miles of underground wires. KU's transmission system included 134 substations (55 of which are shared with the distribution system) with a total capacity of 13 million kVA and 4,079 circuit miles of lines. KU's distribution system included 480 substations (55 of which are shared with the transmission system) with transformer capacity of 7 million kVA, 14,134 miles of overhead lines and 2,299 miles of underground conduit.
LG&E's natural gas transmission system includes 4,272 miles of gas distribution mains and 388 miles of gas transmission mains, consisting of 255 miles of gas transmission pipeline, 124 miles of gas transmission storage lines, 6 miles of gas combustion turbine lines and 3 miles of gas transmission pipeline in regulator facilities. Five underground natural gas storage fields, with a total working natural gas capacity of approximately 15 Bcf, are used in providing natural gas service to ultimate consumers. KU's service area includes an additional 11 miles of gas transmission pipeline providing gas supply to natural gas combustion turbine electrical generating units.
Substantially all of LG&E's and KU's respective real and tangible personal property located in Kentucky and used or to be used in connection with the generation, transmission and distribution of electricity and, in the case of LG&E, the storage and distribution of natural gas, is subject to the lien of either the LG&E 2010 Mortgage Indenture or the KU 2010 Mortgage Indenture. See Note 7 to the Financial Statements for additional information.
LG&E and KU continuously reexamine development projects based on market conditions and other factors to determine whether to proceed with the projects, sell, cancel or expand them or pursue other options. At December 31, 2012, LG&E and KU planned to implement the following incremental capacity increases and decreases at the following plants located in Kentucky.
| | | | | | | | | | | |
| | | | | LG&E | | KU | | |
| | | Total Net | | | | | | | | | | Date of |
| | | Summer MW | | | | | | | | | | Incremental |
| | | Capacity (a) | | | | Ownership or | | | | Ownership or | | Capacity |
| | | Increase / | | | | Lease Interest | | | | Lease Interest | | Increase / |
Primary Fuel/Plant | | (Decrease) | | % Ownership | | in MW | | % Ownership | | in MW | | Decrease |
| | | | | | | | | | | | | |
Coal | | | | | | | | | | | | |
| Cane Run - Units 4-6 - (b) | | (563) | | 100.00 | | (563) | | | | | | 2015 |
| Green River - (b) | | (163) | | | | | | 100.00 | | (163) | | 2015 |
| Tyrone - (c) | | (71) | | | | | | 100.00 | | (71) | | 2013 |
| Total Capacity Decreases | | (797) | | | | (563) | | | | (234) | | |
| | | | | | | | | | | | |
Natural Gas | | | | | | | | | | | | |
| Cane Run - Unit 7 (d) | | 640 | | 22.00 | | 141 | | 78.00 | | 499 | | 2015 |
(a) | The capacity of generating units is based on a number of factors, including the operating experience and physical condition of the units, and may be revised periodically to reflect changed circumstances. |
(b) | LG&E and KU anticipate retiring these units by the endPedricktown includes capacity dedicated to serving landlord load (maximum of 2015. See Notes 8 and 15 to the Financial Statements for additional information.11 MW). |
(c) | KU retired this unit in February 2013. See Note 8 to the Financial Statements for additional information. |
(d) | In May 2012, LG&E and KU received approval to build this unit at the existing Cane Run site. See Note 8 to the Financial Statements for additional information. |
(PPL)
U.K. Regulated Segment
For a description of WPD's service territory, see "Item 1. Business - Background." At December 31, 2012, WPD had electric distribution lines in public streets and highways pursuant to legislation and rights-of-way secured from property owners. WPD's distribution system in the U.K. includes 1,592 substations with a total capacity of 68 million kVA, 57,472 circuit miles of overhead lines and 79,755 cable miles of underground conductors.
(PPL and PPL Electric)
Pennsylvania Regulated Segment
For a description of PPL Electric's service territory, see "Item 1. Business - Background." At December 31, 2012, PPL Electric had electric transmission and distribution lines in public streets and highways pursuant to franchises and rights-of-way secured from property owners. PPL Electric's transmission system includes 61 substations with a total capacity of 18 million kVA and 3,973 pole miles in service. PPL Electric's distribution system includes 339 substations with a total capacity of 12 million kVA, 37,031 circuit miles of overhead lines and 8,098 cable miles of underground conductors in service. All of PPL Electric's facilities are located in Pennsylvania. Substantially all of PPL Electric's distribution properties and certain transmission properties are subject to the lien of the PPL Electric 2001 Mortgage Indenture.
See Note 8 to the Financial Statements for information on the Regional Transmission Line Expansion Plan.
(PPL and PPL Energy Supply)
Supply Segment
PPL Energy Supply's electric generating capacity (summer rating) at December 31, 2012 was:
| | | | | | | | | | |
| | | | | | | | PPL Energy Supply's | | |
| | | | | | | | Ownership or | | |
Primary Fuel/Plant | | Total MW Capacity (a) | | % Ownership | | Lease Interest in MW (a) | | Location |
| | | | | | | | | | |
Natural Gas/Oil | | | | | | | | |
| Martins Creek | | 1,745 | | 100.00 | | 1,745 | | Pennsylvania |
| Ironwood | | 665 | | 100.00 | | 665 | | Pennsylvania |
| Lower Mt. Bethel | | 543 | | 100.00 | | 543 | | Pennsylvania |
| Combustion turbines | | 363 | | 100.00 | | 363 | | Pennsylvania |
| | | | 3,316 | | | | 3,316 | | |
| | | | | | | | | | |
Coal | | | | | | | | |
| Montour | | 1,518 | | 100.00 | | 1,518 | | Pennsylvania |
| Brunner Island | | 1,455 | | 100.00 | | 1,455 | | Pennsylvania |
| Colstrip Units 1 & 2 (b) | | 614 | | 50.00 | | 307 | | Montana |
| Conemaugh (c) | | 1,749 | | 16.25 | | 284 | | Pennsylvania |
| Colstrip Unit 3 (b) | | 740 | | 30.00 | | 222 | | Montana |
| Keystone (c) | | 1,714 | | 12.34 | | 212 | | Pennsylvania |
| Corette | | 153 | | 100.00 | | 153 | | Montana |
| | | | 7,943 | | | | 4,151 | | |
| | | | | | | | | | |
Nuclear | | | | | | | | |
| Susquehanna (c) | | 2,528 | | 90.00 | | 2,275 | | Pennsylvania |
| | | | | | | | | | |
Hydro | | | | | | | | |
| Various | | 604 | | 100.00 | | 604 | | Montana |
| Various | | 175 | | 100.00 | | 175 | | Pennsylvania |
| | | | 779 | | | | 779 | | |
| | | | | | | | | | |
Qualifying Facilities | | | | | | | | |
| Renewables (d) | | 61 | | 100.00 | | 61 | | Pennsylvania |
| Renewables | | 9 | | 100.00 | | 9 | | Various |
| | | | 70 | | | | 70 | | |
| | | | | | | | | | |
Total | | 14,636 | | | | 10,591 | | |
(a) | The capacity of generation units is based on a number of factors, including the operating experience and physical conditions of the units, and may be revised periodically to reflect changed circumstances. |
(b) | Represents the leasehold interest held by PPL Montana. See Note 11 to the Financial Statements for additional information. |
(c) | This unit is jointly owned. Each owner is entitled to its proportionate share of the unit's total output and funds its proportionate share of fuel and other operating costs. See Note 1410 to the Financial StatementsStatement for additional information. |
| |
(d) | Includes facilities owned, controlled or for which PPLTalen Energy Supply has the rights to the output.output through agreements of Talen Energy Marketing with third parties. |
Amounts guaranteed by PPL Montour and PPL Brunner Island in connection with an $800 million secured energy marketing and trading facilityCertain of Talen Energy's credit arrangements are secured by liens on the generating facilities owned by PPL Montour and PPL Brunner Island.majority of the plants above. See Note 75 to the Financial Statements for additional information.
PPLTalen Energy's corporate headquarters are located at 835 Hamilton Street, Suite 150, Allentown, PA 18101-1179 under a lease that expires in 2018.
Item 3. Legal Proceedings
Talen Energy Corporation and Talen Energy Supply, from timeLLC
The information required with respect to time reexamines development projects based on market conditions and other factors to determine whether to proceed with the projects, sell, cancel or expand them, execute tolling agreements or pursue other options. Seethis item can be found in Note 1511 to the Financial Statements, for information on PPL Energy Supply's intention, beginning in April 2015, to place its Corette plant in long-term reserve status. At December 31, 2012, PPL Energy Supply subsidiaries planned to implement the following incremental capacity increases.
| | | | | | | PPL Energy Supply | | Expected |
| | | | | Total MW | | Ownership or Lease | | In-Service |
| Primary Fuel/Plant | | Location | | Capacity (a) | | Interest in MW | | Date (b) |
| | | | | | | | | | |
Hydro | | | | | | | | | |
| Holtwood (c) | | Pennsylvania | | 125 | | 125 | (100%) | | 2013 |
| Great Falls (d) | | Montana | | 28 | | 28 | (100%) | | 2013 |
| | | | | | | | | | |
Total | | | | 153 | | 153 | | | |
(a) | The capacity of generating units is based on a number of factors, including the operating experience and physical condition of the units, and may be revised periodically to reflect changed circumstances. |
(b) | The expected in-service dates are subject to receipt of required approvals, permits and other contingencies. |
(c) | This project includes installation of two additional large turbine-generators and the replacement of four existing runners. |
(d) | This project involves construction of a new powerhouse and retirement of the exiting powerhouse. |
ITEM 3. LEGAL PROCEEDINGS
See Notes 5, 6 and 15 to the Financial Statements forwhich provides information regarding legal, tax litigation, regulatory and environmental proceedings and matters.matters and is incorporated by reference into this Item 3.
Item 4. Mine Safety Disclosures
ITEM 4. MINE SAFETY DISCLOSURESTalen Energy Corporation and Talen Energy Supply, LLC
Not applicable.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY,
RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
See "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Liquidity and Capital Resources - Forecasted Uses of Cash" for information regarding certain restrictions on theTalen Energy's ability to pay dividends for PPL, LKE, LG&E and KU.or make distributions.
PPLTalen Energy Corporation
Additional informationTalen Energy Corporation's common stock is traded on the NYSE under the symbol "TLN". The following table sets forth the high and low sales prices for this itemTalen Energy Corporation's common stock for each quarter of the year 2015, as reported on the NYSE.
|
| | | | | | | | | | | | | | |
| | For the 2015 Quarters Ended |
| | Mar. 31 | | June 30 | | Sept. 30 | | Dec. 31 |
Price per common share: (a) | | | | | | | | |
High | | N/A | | $ | 20.50 |
| | $ | 18.02 |
| | $ | 12.09 |
|
Low | | N/A | | $ | 16.87 |
| | $ | 9.83 |
| | $ | 5.73 |
|
| |
(a) | There is no price per common share data available prior to June 1, 2015, which is the date on which Talen Energy Corporation became a publicly traded company. |
Talen Energy Corporation has not declared or paid dividends and does not currently expect to declare or pay dividends on its common stock. Instead, Talen Energy Corporation intends to retain earnings to finance the growth and development of its business and for working capital and general corporate purposes. Talen Energy Corporation's ability to pay dividends to holders of its common stock is set forth inlimited by its ability to obtain cash or other assets from its subsidiaries. Further, certain of the sections entitled "Quarterly Financial, Common Stock Priceagreements governing Talen Energy Corporation's subsidiaries' indebtedness, including the Talen Energy Supply RCF and Dividend Data," "Item 12. Security Ownershipthe First Lien Credit and Guaranty Agreement, restrict the ability of Certain Beneficial Ownerscertain of Talen Energy Corporation's subsidiaries to pay dividends or otherwise transfer assets to Talen Energy Corporation. Any payment of dividends will be at the discretion of Talen Energy Corporation's board of directors and Managementwill depend upon various factors then existing, including earnings, financial condition, results of operations, capital requirements, level of indebtedness, contractual restrictions with respect to payment of dividends, restrictions imposed by applicable law, general business conditions and Related Stockholder Matters" and "Shareowner and Investor Information"other factors that Talen Energy Corporation's board of this report. directors may deem relevant.
At January 31, 2013,29, 2016, there were 66,13053,889 common stock shareownersstockholders of record.
| Issuer Purchase of Equity Securities during the Fourth Quarter of 2012: | | | |
| | | | | | | | | | | | | |
| | | | (a) | (b) | (c) | (d) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | Maximum Number (or |
| | | | | | | | | | | | | Approximate Dollar |
| | | | | | | | | | Total Number of | Value) of Shares |
| | | | | | | | | | Shares (or Units) | (or Units) that May |
| | | | Total Number of | Average Price | Purchased as Part of | Yet Be Purchased |
| | | | Shares (or Units) | Paid per Share | Publicly Announced | Under the Plans |
Period | | | Purchased (1) | (or Unit) | Plans of Programs | or Programs (1) |
October 1 to October 31, 2012 | | | | | | |
November 1 to November 30, 2012 | | | 4,665 | $29.35 | | |
December 1 to December 31, 2012 | | | | | | |
Total | | | 4,665 | $29.35 | | |
There were no purchases by Talen Energy Corporation of its common stock during the fourth quarter of 2015.
(1) | | Represents shares of common stock withheld by PPL at the request of its executive officers to pay income taxes upon the vesting of the officers' restricted stock awards, as permitted under the terms of PPL's ICP and ICPKE. |
PPLTalen Energy Supply, LLC
There is no established public trading market for PPLTalen Energy Supply's membership interests. PPLTalen Energy Funding, a direct wholly owned subsidiary of PPL,Corporation owns all of PPLTalen Energy Supply's outstanding membership interests. Distributions on the membership interests will be paid as determined by PPLTalen Energy Supply's Board of Managers.
PPLTalen Energy Supply made cash distributions, primarily to its former member, PPL Energy Funding Corporation, of $787$219 million in 20122015 and $316 million$1.9 billion in 2011.2014.
ITEM 6. SELECTED FINANCIAL DATA
Talen Energy Corporation's business was formed on June 1, 2015 after the spinoff from PPL and the acquisition by Talen Energy Supply of RJS Power. Talen Energy Supply is considered the accounting predecessor of Talen Energy Corporation. As such, Talen Energy Corporation's consolidated financial information below for 2015 represents twelve months of legacy Talen Energy Supply information consolidated with seven months of RJS information from June 1, 2015, while the 2014 and earlier periods represent only legacy Talen Energy Supply information. See Note 9Notes 1, 3 and 6 to the Financial Statements regardingfor information on the distribution, including $325 millionspinoff and acquisition of cash, of PPL Energy Supply's membership interests in PPL Global to PPL Energy Funding in January 2011.RJS Power.
|
| | | | | | | | | | | | | | | | | | | | |
Talen Energy Corporation (a) (b) | | 2015 | | 2014 | | 2013 | | 2012 | | 2011 |
| | | | | | | | | | |
Income Items (in millions) | | | | | | | | | | |
Operating revenues (c) | | $ | 4,481 |
| | $ | 4,581 |
| | $ | 4,495 |
| | $ | 4,393 |
| | $ | 4,834 |
|
Income (Loss) from continuing operations after income taxes attributable to Talen Energy Corporation stockholders | | (341 | ) | | 187 |
| | (262 | ) | | 428 |
| | 672 |
|
Income (Loss) from discontinued operations (net of income taxes) (d) | | — |
| | 223 |
| | 32 |
| | 46 |
| | 96 |
|
Net Income (Loss) attributable to Talen Energy Corporation stockholders | | (341 | ) | | 410 |
| | (230 | ) | | 474 |
| | 768 |
|
Balance Sheet Items (in millions) (e) | | | | | | | | | | |
Property, plant and equipment, net | | $ | 8,587 |
| | $ | 6,436 |
| | $ | 7,174 |
| | $ | 7,293 |
| | $ | 6,486 |
|
Total assets | | 12,826 |
| | 10,760 |
| | 11,074 |
| | 12,375 |
| | 13,179 |
|
Short-term debt | | 608 |
| | 630 |
| | — |
| | 356 |
| | 400 |
|
Long-term debt (including current portion) | | 4,203 |
| | 2,218 |
| | 2,525 |
| | 3,272 |
| | 3,024 |
|
Common equity | | 4,303 |
| | 3,907 |
| | 4,798 |
| | 3,848 |
| | 4,037 |
|
Total capitalization | | 9,114 |
| | 6,755 |
| | 7,323 |
| | 7,476 |
| | 7,461 |
|
Income (Loss) per share attributable to Talen Energy Corporation stockholders - Basic (f) | | | | | | | | | | |
Income (Loss) from continuing operations | | $ | (3.10 | ) |
| $ | 2.24 |
|
| $ | (3.13 | ) |
| $ | 5.12 |
|
| $ | 8.04 |
|
Income (Loss) from discontinued operations (net of income taxes) (d) | | $ | — |
|
| $ | 2.67 |
|
| $ | 0.38 |
|
| $ | 0.55 |
|
| $ | 1.15 |
|
Net Income (Loss) | | $ | (3.10 | ) |
| $ | 4.91 |
|
| $ | (2.75 | ) |
| $ | 5.67 |
|
| $ | 9.19 |
|
Income (Loss) per share attributable to Talen Energy Corporation stockholders - Diluted (f) | |
|
|
|
|
|
|
|
|
|
Income (Loss) from continuing operations | | $ | (3.10 | ) |
| $ | 2.24 |
|
| $ | (3.13 | ) |
| $ | 5.12 |
|
| $ | 8.04 |
|
Income (Loss) from discontinued operations (net of income taxes) (d) | | $ | — |
|
| $ | 2.67 |
|
| $ | 0.38 |
|
| $ | 0.55 |
|
| $ | 1.15 |
|
Net Income (Loss) | | $ | (3.10 | ) |
| $ | 4.91 |
|
| $ | (2.75 | ) |
| $ | 5.67 |
|
| $ | 9.19 |
|
PPL Electric Utilities Corporation
There is no established public trading market for PPL Electric's common stock, as PPL owns 100% of the outstanding common shares. Dividends paid to PPL on those common shares are determined by PPL Electric's Board of Directors. PPL Electric paid common stock dividends to PPL of $95 million in 2012 and $92 million in 2011.
LG&E and KU Energy LLC
There is no established public trading market for LKE's membership interests. PPL owns all of LKE's outstanding membership interests. Distributions on the membership interests will be paid as determined by LKE's Board of Directors. LKE made cash distributions to PPL of $155 million in 2012 and $533 million in 2011 (including $248 million from the proceeds of a note issuance).
Louisville Gas and Electric Company
There is no established public trading market for LG&E's common stock, as LKE owns 100% of the outstanding common shares. Dividends paid to LKE on those common shares are determined by LG&E's Board of Directors. LG&E paid common stock dividends to LKE of $75 million in 2012 and $83 million in 2011.
Kentucky Utilities Company
There is no established public trading market for KU's common stock, as LKE owns 100% of the outstanding common shares. Dividends paid to LKE on those common shares are determined by KU's Board of Directors. KU paid common stock dividends to LKE of $100 million in 2012 and $124 million in 2011.
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA |
| | | | | | | | | | | | | | | | | | |
PPL Corporation (a) (b) | | | 2012 (c) | | | 2011 (c) | | | 2010 (c) | | | 2009 | | | 2008 |
| | | | | | | | | | | | | | | | | | |
Income Items (in millions) | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 12,286 | | $ | 12,737 | | $ | 8,521 | | $ | 7,449 | | $ | 7,857 |
| Operating income | | | 3,109 | | | 3,101 | | | 1,866 | | | 896 | | | 1,703 |
| Income from continuing operations after income taxes | | | | | | | | | | | | | | | |
| | attributable to PPL shareowners | | | 1,532 | | | 1,493 | | | 955 | | | 414 | | | 857 |
| Net income attributable to PPL shareowners | | | 1,526 | | | 1,495 | | | 938 | | | 407 | | | 930 |
Balance Sheet Items (in millions) (d) | | | | | | | | | | | | | | | |
| Total assets | | | 43,634 | | | 42,648 | | | 32,837 | | | 22,165 | | | 21,405 |
| Short-term debt | | | 652 | | | 578 | | | 694 | | | 639 | | | 679 |
| Long-term debt | | | 19,476 | | | 17,993 | | | 12,663 | | | 7,143 | | | 7,838 |
| Noncontrolling interests | | | 18 | | | 268 | | | 268 | | | 319 | | | 319 |
| Common equity | | | 10,480 | | | 10,828 | | | 8,210 | | | 5,496 | | | 5,077 |
| Total capitalization | | | 30,626 | | | 29,667 | | | 21,835 | | | 13,597 | | | 13,913 |
Financial Ratios | | | | | | | | | | | | | | | |
| Return on average common equity - % | | | 13.76 | | | 14.93 | | | 13.26 | | | 7.48 | | | 16.88 |
| Ratio of earnings to fixed charges (e) | | | 2.9 | | | 3.1 | | | 2.7 | | | 1.9 | | | 3.1 |
Common Stock Data | | | | | | | | | | | | | | | |
| Number of shares outstanding - Basic (in thousands) | | | | | | | | | | | | | | | |
| | | Year-end | | | 581,944 | | | 578,405 | | | 483,391 | | | 377,183 | | | 374,581 |
| | | Weighted-average | | | 580,276 | | | 550,395 | | | 431,345 | | | 376,082 | | | 373,626 |
| Income from continuing operations after income taxes | | | | | | | | | | | | | | | |
| | available to PPL common shareowners - Basic EPS | | $ | 2.62 | | $ | 2.70 | | $ | 2.21 | | $ | 1.10 | | $ | 2.28 |
| Income from continuing operations after income taxes | | | | | | | | | | | | | | | |
| | available to PPL common shareowners - Diluted EPS | | $ | 2.61 | | $ | 2.70 | | $ | 2.20 | | $ | 1.10 | | $ | 2.28 |
| Net income available to PPL common shareowners - | | | | | | | | | | | | | | | |
| | Basic EPS | | $ | 2.61 | | $ | 2.71 | | $ | 2.17 | | $ | 1.08 | | $ | 2.48 |
| Net income available to PPL common shareowners - | | | | | | | | | | | | | | | |
| | Diluted EPS | | $ | 2.60 | | $ | 2.70 | | $ | 2.17 | | $ | 1.08 | | $ | 2.47 |
| Dividends declared per share of common stock | | $ | 1.44 | | $ | 1.40 | | $ | 1.40 | | $ | 1.38 | | $ | 1.34 |
| Book value per share (d) | | $ | 18.01 | | $ | 18.72 | | $ | 16.98 | | $ | 14.57 | | $ | 13.55 |
| Market price per share (d) | | $ | 28.63 | | $ | 29.42 | | $ | 26.32 | | $ | 32.31 | | $ | 30.69 |
| Dividend payout ratio - % (f) | | | 55 | | | 52 | | | 65 | | | 128 | | | 54 |
| Dividend yield - % (g) | | | 5.03 | | | 4.76 | | | 5.32 | | | 4.27 | | | 4.37 |
| Price earnings ratio (f) (g) | | | 11.01 | | | 10.89 | | | 12.13 | | | 29.92 | | | 12.43 |
Sales Data - GWh | | | | | | | | | | | | | | | |
| Domestic - Electric energy supplied - retail (h) | | | 42,379 | | | 40,147 | | | 14,595 | | | 38,912 | | | 40,374 |
| Domestic - Electric energy supplied - wholesale (h) (i) | | | 56,302 | | | 65,681 | | | 75,489 | | | 38,988 | | | 42,712 |
| Domestic - Electric energy delivered - retail (j) | | | 66,931 | | | 67,806 | | | 42,463 | | | 36,689 | | | 38,013 |
| U.K. - Electric energy delivered (k) | | | 77,467 | | | 58,245 | | | 26,820 | | | 26,358 | | | 27,724 |
| |
(a) | | The earningsEarnings each year were affected by severalcertain items that management considers special.believes are not indicative of ongoing operations. See "Results of Operations - Segment Results"EBITDA and Adjusted EBITDA" in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" for a description of specialthose items in 2015, 2014, and 2013. Significant pre-tax items in 2012 and 2011 included unrealized gains on derivative contracts of $91 million and 2010.$120 million, while 2012 included a $29 million coal contract modification payment and 2011 included litigation-related credits of $132 million. The earnings were also affected by theacquisitions and sales of various businesses. See Note 96 to the Financial Statements for aadditional information, including discussion of the discontinued operations in 2012, 20112014 and 2010.2013. |
| |
(b) | | See "Item 1A. Risk Factors" and Notes 61 and 1511 to the Financial Statements for a discussion of uncertainties that could affect PPL'sTalen Energy Corporation's future financial condition. |
| |
(c) | Amounts for prior years have been reclassified to conform to the current presentation related to certain operating revenues and expenses. See "Reclassifications" in Note 1 to the Financial Statements for additional information. |
| Includes WPD Midlands activity since its April 1, 2011 acquisition date. Includes LKE activity since its November 1, 2010 acquisition date. |
(d) | 2014 includes an after-tax gain on the sale of the hydroelectric business in Montana of $206 million. |
| |
(e) | As of each respective year-end. |
(e) | | Computed using earnings and fixed charges of PPL and its subsidiaries. Fixed charges consist of interest on short- and long-term debt, amortization of debt discount, expense and premium - net, other interest charges, the estimated interest component of operating rentals and preferred securities distributions of subsidiaries. See Exhibit 12(a) for additional information. |
(f) | | Based onThe calculation of basic and diluted EPS. |
(g) | | Based on year-end market prices. |
(h) | | The electric energy supplied changes in 2010 reflectearnings per share for 2015 utilized the expirationweighted-average shares outstanding during the year assuming the shares issued to PPL's shareholders were outstanding during the entire year and reflects the impact of the PLR contract between PPL EnergyPlusprivate placement of shares to the Riverstone Holders on the spinoff date. For 2014, 2013, 2012 and PPL Electric as of December 31, 2009. |
(i) | | GWh are included until2011, weighted average shares outstanding assumed the transaction closing for facilities thatshares issued to PPL's shareholders at the spinoff date in 2015 were sold. |
(j)
(k)
| | Prior period volumes were restated to include unbilled volumes.
Year 2011 includes eight months of deliveries associated with the acquisition of WPD Midlands as volumes are reported on a one-month lag.
|
| | outstanding during those entire years. |
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA
PPLTalen Energy Supply, LLC PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
Item 6 is omitted as PPLTalen Energy Supply PPL Electric, LKE, LG&E and KU meetmeets the conditions set forth in General Instructions (I)(1)(a) and (b) of Form 10-K.
PPL CORPORATION AND SUBSIDIARIES
Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations
This "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations" is separately filed by Talen Energy Corporation and Talen Energy Supply. Any information contained herein relating to an individual registrant is filed by such registrant solely on its own behalf, and neither registrant makes any representation as to information relating to the other registrant except that information relating to Talen Energy Supply and its subsidiaries is also attributed to Talen Energy Corporation and information relating to the subsidiaries of Talen Energy Supply is also attributed to Talen Energy Supply. As Talen Energy Corporation is substantially comprised of Talen Energy Supply and its subsidiaries, most disclosures refer to Talen Energy and are intended to be applicable to both registrants. When identification of a particular registrant or subsidiary is considered important to understanding the matter being disclosed, the specific entity's name is used, in particular, for those few disclosures that apply only to Talen Energy Corporation. Each disclosure referring to a subsidiary applies to both Talen Energy Corporation and Talen Energy Supply and each disclosure referring to Talen Energy Supply applies to Talen Energy Corporation through consolidation.
Talen Energy Corporation's obligation to report under the Securities and Exchange Act of 1934, as amended, commenced on May 1, 2015, the date Talen Energy Corporation's Registration Statement on Form S-1 relating to the spinoff transaction was declared effective by the SEC. Talen Energy Supply is a separate registrant and considered the predecessor of Talen Energy Corporation, and therefore, the financial information prior to June 1, 2015 presented in this Annual Report on Form 10-K for both registrants includes only legacy Talen Energy Supply information. From June 1, 2015, upon completion of the spinoff and acquisition, Talen Energy Corporation's and Talen Energy Supply's consolidated financial information also includes RJS. As such, Talen Energy Corporation's and Talen Energy Supply's consolidated financial information presented in this Annual Report on Form 10-K for 2015 represents twelve months of legacy Talen Energy Supply information consolidated with seven months of RJS information from June 1, 2015, while 2014 and 2013 represent only legacy Talen Energy Supply information.
The information provided in this Item 7following should be read in conjunction with PPL'sthe registrants' Consolidated Financial Statements and the accompanying Notes. Capitalized terms and abbreviations are defined in the glossary. Dollars are in millions, except per share data, unless otherwise noted.
"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:
· | "Overview" provides a description of PPL and its business strategy, a summary of Net Income Attributable to PPL Shareowners and a discussion of certain events related to PPL's results of operations and financial condition. |
"Overview," which provides Talen Energy's business strategy, key performance measures, an executive summary and a discussion of key competitive power business dynamics.
· | "Results of Operations" provides a summary of PPL's earnings, a review of results by reportable segment and a description of key factors by segment expected to impact future earnings. This section ends with explanations of significant changes in principal items on PPL's Statements of Income, comparing 2012 with 2011 and 2011 with 2010. |
"Results of Operations" includes "Statement of Income Analysis," which addresses significant changes in principal line items on the Statements of Income comparing 2015 with 2014 and 2014 with 2013 on a GAAP basis. The "Margins" discussion, presented by segment, includes a reconciliation of this non-GAAP financial measure to operating income (loss). The "EBITDA and Adjusted EBITDA" discussion, also presented by segment, includes a reconciliation of these non-GAAP financial measures to operating income (loss) and consolidated net income (loss).
· | "Financial Condition - Liquidity and Capital Resources" provides an analysis of PPL's liquidity position and credit profile. This section also includes a discussion of forecasted sources and uses of cash and rating agency actions. |
"Financial Condition - Liquidity and Capital Resources" provides an analysis of Talen Energy's liquidity positions and credit profiles. This section also includes a discussion of forecasted sources and uses of cash as well as rating agencies and credit considerations.
· | "Financial Condition - Risk Management - Energy Marketing & Trading and Other" provides an explanation of PPL's risk management programs"Financial Condition - Risk Management" provides an explanation of the risk management policy relating to Talen Energy's market and credit risk. |
· | "Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of PPL and that require its management to make significant estimates, assumptions and other judgments of matters inherently uncertain. |
"Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of Talen Energy and that require management to make significant estimates, assumptions and other judgments of inherently uncertain matters.
Overview
Introduction
PPLTalen Energy is an energya North American competitive power generation and utility holdingmarketing company with headquartersheadquartered in Allentown, Pennsylvania. Through subsidiaries, PPL generatesTalen Energy produces and sells electricity, capacity and ancillary services from its fleet of power plants in the northeastern, northwestern and southeastern U.S., markets wholesale and retail energy primarily in the northeastern and northwestern portions of the U.S., delivers electricity to customers in Pennsylvania, Kentucky, Virginia, Tennessee and the U.K. and delivers natural gas to customers in Kentucky.
PPL's principal subsidiaries are shown below (* denotes an SEC registrant):
| | | | | | | | | PPL Corporation* | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | PPL Capital Funding | | | | | | |
| | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | LKE*
| | | PPL Global
● Engages in the regulated distribution of electricity in the U.K.
| | PPL Electric*
● Engages in the regulated transmission and distribution of electricity in Pennsylvania
| | | PPL Energy Supply*
| | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
LG&E*
● Engages in the regulated generation, transmission, distribution and sale of electricity in Kentucky, and distribution and sale of natural gas in Kentucky
| | | KU*
● Engages in the regulated generation, transmission, distribution and sale of electricity, primarily in Kentucky
| | | | | | PPL EnergyPlus
● Performs energy marketing and trading activities
● Purchases fuel
| | | PPL Generation
● Engages in the competitive generation of electricity, primarily in Pennsylvania and Montana
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Kentucky Regulated
Segment
| | U.K. Regulated
Segment
| | Pennsylvania Regulated Segment
| | Supply
Segment
| | |
Business Strategy
PPL's overall strategy is to achieve stable, long-term growth in its regulated electricity delivery businesses through efficient operations and strong customer and regulatory relations, and disciplined optimization of energy supply margins in its energy supply business while mitigating volatility in both cash flows and earnings. In pursuing this strategy, PPL acquired LKE in November 2010 and WPD Midlands in April 2011. These acquisitions have reduced PPL's overall business risk profile and reapportioned the mix of PPL's regulated and competitive businesses by increasing the regulated portion of its business. Each of the rate-regulated businesses plans to make material capital investments over the next several years to improve infrastructure and customer reliability. As a result of these acquisitions,totaling approximately 71% of PPL's assets were in its regulated businesses17,400 MW at December 31, 20122015, principally located in the Northeast, Mid-Atlantic and approximately 73%Southwest regions of "Net Income Attributable to PPL Shareowners" was from regulated businessesthe U.S. See "Item 2. Properties" for the year ended December 31, 2012.additional information on Talen Energy's power plants. For a more detailed description of Talen Energy's business, see "Item 1. Business."
Business Strategy
The increase in regulated assets is expected to provide earnings stability through regulated returns on equity and the ability to recover costs of capital investments, in contrast to the competitive energy supply business where earnings and cash flows are subject to commodity market volatility.
Results for periods prior to the acquisitions of LKE and WPD Midlands are not comparable with, or indicative of, results for periods subsequent to the acquisitions.
With the acquisition of WPD Midlands, PPL has a higher proportion of overall earnings subject to foreign currency translation risk. The U.K. subsidiaries also have currency exposure to the U.S. dollar to the extent they have U.S. dollar denominated debt. To manage these risks, PPL generally uses contracts such as forwards, options and cross currency swaps that contain characteristics of both interest rate and foreign currency exchange contracts.
PPL's strategy for its energy supply business isTalen Energy seeks to optimize the value from its competitive power generation assets and marketing portfolio. PPLportfolio while mitigating near-term volatility in both cash flow and earnings metrics. Talen Energy endeavors to doaccomplish this by matching energy supplyprojected output from its generation assets with load, or customer demand, under contracts of varying durations with creditworthy counterparties to capture profitsforward power sales in the wholesale and retail markets while effectively managing exposure to energy and fuel price volatility, counterparty credit risk and operational risk. Talen Energy is focused on safe, reliable, and resilient operations, disciplined capital investment, portfolio optimization, cost management and the pursuit of value enhancing growth opportunities.
To manage financing costs and access to credit markets, and to fund capital expenditures and growth opportunities, a key objective of PPL's business strategyTalen Energy is to maintain a strong credit profile and strongadequate liquidity position.capacity. In addition, PPLTalen Energy has a financial risk management policy and operational risk management programsprocedures that, among other things, are designed to monitor and manage its exposure to earnings and cash flow volatility related to, as applicable, changes in energy and fuel prices, interest rates, counterparty credit quality and the operating performance of its generating units. To manage these risks, Talen Energy generally uses contracts such as forwards, options, swaps and insurance contracts primarily focused on mitigating cash flow volatility within the next 12 month period.
Financial and Operational DevelopmentsKey Performance Measures
Net Income AttributableIn addition to PPL Shareowners
Net Income Attributableoperating income (loss), Talen Energy utilizes Adjusted EBITDA and Margins, both non-GAAP financial measures, as indicators of performance for its business, with Adjusted EBITDA as the primary financial performance measure used by management to PPL Shareownersevaluate its business and monitor results of operations. Results for the years ended December 31 by segment and in total was:were as follows.
|
| | | | | | | | | | | |
| 2015 | | 2014 | | $ Change |
Net Income (Loss) | $ | (341 | ) | | $ | 410 |
| | $ | (751 | ) |
| | | | |
|
Operating Income (Loss) | (39 | ) | | 397 |
| | (436 | ) |
| | | | |
|
Adjusted EBITDA | 1,002 |
| | 759 |
| | 243 |
|
| | | | |
|
Margins | 1,899 |
| | 1,653 |
| | 246 |
|
| | | 2012 | | 2011 | | 2010 | |
| | | | | | | | | | | |
Kentucky Regulated (a) | | $ | 177 | | $ | 221 | | $ | 26 | |
U.K. Regulated (b) | | | 803 | | | 325 | | | 261 | |
Pennsylvania Regulated | | | 132 | | | 173 | | | 115 | |
Supply | | | 414 | | | 776 | | | 612 | |
Corporate and Other (c) | | | | | | | | | (76) | |
Net Income Attributable to PPL Shareowners | | $ | 1,526 | | $ | 1,495 | | $ | 938 | |
| | | | | | | | | | | |
EPS - basic | | $ | 2.61 | | $ | 2.71 | | $ | 2.17 | |
EPS - diluted | | $ | 2.60 | | $ | 2.70 | | $ | 2.17 | |
(a) | LKE was acquired on November 1, 2010. Therefore, 2012 and 2011 include a full year of LKE results, while 2010 includes two months of LKE results. |
(b) | WPD Midlands was acquired on April 1, 2011 and its results are recorded on a one-month lag. Therefore, 2012 includes a full year of WPD Midlands' results, while 2011 includes eight months of WPD Midlands' results. 2011 was also impacted by certain acquisition related costs. These costs are considered special items by management and are discussed in further detail in "Results of Operations - Earnings - U.K. Regulated Segment." See Notes 7 and 10 to the Financial Statements for additional information on the acquisition and related financing. |
(c) | Includes $22 million, after tax ($31 million, pre-tax), of certain third-party acquisition-related costs, including advisory, accounting, and legal fees associated with the acquisition of LKE that are recorded in "Other Income (Expense) - net" on the Statement of Income. Also includes $52 million, after tax ($80 million, pre-tax), of 2010 Bridge Facility costs that are recorded in "Interest Expense" on the Statement of Income. These costs are considered special items by management. See Notes 7 and 10 to the Financial Statements for additional information on the acquisition and related financing. |
Earnings in 2012 increased 2% over 2011 and earnings in 2011 increased 59% over 2010. The changes in Net Income Attributable to PPL Shareowners from year to year were, in part, attributable to the acquisition of LKE and WPD Midlands and certain items that management considers special. See "Results of Operations" for a detailed analysis of Talen Energy's results, the definitions of Margins and Adjusted EBITDA and a reconciliation of these non-GAAP measures to related GAAP measures.
Executive Summary
The increase in Margins, a primary driver to changes in the other three earnings measures reflected above, was primarily due to a $237 million increase related to the RJS and MACH Gen generating facilities acquired in 2015.
The declines in operating income (loss) and net income (loss) were substantially due to non-cash goodwill and other asset impairment charges recorded in 2015. Net income (loss) was also negatively impacted by an $80 million after-tax charge related to a debt extinguishment in 2015, and net income (loss) in 2014 benefited from a $206 million after-tax gain on the sale of the hydroelectric generating facilities in Montana. See Note 6 to the Financial Statements for additional information on the sale of the hydroelectric generating facilities.
Several of the key financial and operational developments that impacted results for the year ended December 31, 2015 were as follows:
Spinoff from PPL - During 2015, Talen Energy incurred certain restructuring, TSA and other charges in connection with the spinoff from PPL. See Note 1 to the Financial Statements for additional information on the spinoff, acquisition and related charges.
Impairment Charges - During 2015, management considered a number of events and changes in circumstances and concluded that impairment assessments for goodwill and certain long-lived assets were necessary. The charges recorded were as follows:
|
| | | | | | | | | | | | | | | | | |
| | | Pre-tax | | After-tax |
| | | Third Quarter | | Fourth Quarter | | Total | | Total |
| Goodwill | | $ | 466 |
| | $ | (1 | ) | | $ | 465 |
| | $ | 444 |
|
| Sapphire plants and C.P. Crane plant | | 122 |
| | 67 |
| | 189 |
| | 113 |
|
| Total | | $ | 588 |
| | $ | 66 |
| | $ | 654 |
| | $ | 557 |
|
In addition to the impairment assessments that resulted in these charges, management also tested its coal-fired generation facilities located primarily within the PJM market for impairment and concluded that the plants were not impaired at December 31, 2015. The recoverability assessment is very sensitive to forward energy and capacity price assumptions as well as forecasted operation and maintenance and capital spending and further declines could negatively impact future testing results. The carrying value of these coal-fired generation facilities was more than $3 billion as of December 31, 2015. See Notes 14 and 16 to the Financial Statements for additional information on the impairment testing that occurred and the charges recorded in 2015.
Loss on Debt Extinguishment - In conjunction with the termination of a remarketing dealer's right to remarket certain senior unsecured notes, Talen Energy recorded a pre-tax charge of $134 million. See Note 5 to the Financial Statements for additional information.
Coal Contract Modification - To mitigate the risk of oversupply of coal due to reduced dispatching of coal-fired generation facilities, primarily as a result of the continued decline in natural gas prices. Talen Energy incurred pre-tax charges of $41 million in the third quarter of 2015 to reduce its contracted coal deliveries in 2015 through 2018.
Acquisition of MACH Gen - In November 2015, Talen Energy obtained 2,344 MW (summer rating) of generating capacity with the completion of the acquisition of all of the membership interests of MACH Gen for cash consideration of approximately $600 million. In addition, $578 million of a MACH Gen subsidiary's debt remained outstanding after the acquisition. See Notes 5 and 6 to the Financial Statements for additional information.
Divestiture of Talen Renewable Energy - In November 2015, Talen Energy completed the sale of Talen Renewable Energy for $116 million. See Note 6 to the Financial Statements for additional information.
Divestiture of Ironwood, Holtwood, Lake Wallenpaupack and C.P. Crane Power Plants - In October 2015, Talen Energy announced the sale of these facilities, with an aggregate generating capacity of approximately 1,400 MW, to satisfy a December 2014 FERC order approving the combination of Talen Energy Supply and RJS Power. Upon completion of these divestitures, Talen Energy will have generated $1.5 billion in pre-tax cash proceeds. The sales of Ironwood and C.P. Crane were completed in February 2016. See Note 6 to the Financial Statements for additional information.
Susquehanna Nuclear Plant - The Susquehanna nuclear plant continues to make modifications to address the causes of turbine blade cracking first identified in 2011. Unit 1 completed its planned refueling and turbine inspection outage in June 2014 and installed newly designed shorter last stage blades on one of the low pressure turbines. The same short blade modifications were installed on two of the three turbines on Unit 2 during the spring 2015 scheduled refueling outage. All remaining turbine blade modifications are scheduled to be performed during planned refueling and maintenance outages. The Susquehanna nuclear plant set a single-year generation record and achieved an annualized capacity factor of over 94 percent.
Brunner Island Co-firing Project - Construction is under way and is expected to be completed by the end of 2016. The project is expected to cost $118 million. At December 31, 2015, $23 million of costs associated with the project have been incurred.
Key Competitive Power Business Dynamics
Electricity, natural gas and capacity prices are significant contributors to the profitability of Talen Energy's portfolio. A discussion of PPL's business segments, detailsthe general factors and current market conditions affecting these commodities and Talen Energy's operations follows.
Electricity Prices
Electricity prices impact Talen Energy's operations. The price for electricity varies by region and analysiscan be influenced by a host of supply and demand factors including, but not limited to, generator availability, market design, fuel prices for power generators, transmission congestion, demand growth and seasonality. In 2015, delivered prices for electricity fell, relative to 2014 delivered prices, across the competitive power markets in which Talen Energy operates, primarily driven by unusual market and weather volatility in the first quarter of 2014 and a continued decline in natural gas prices, which are discussed below.
The table below reflects the average around-the-clock day ahead electricity prices at various pricing points located near Talen Energy's power plants for the years ended December 31.
|
| | | | | | | | | | | |
| 2015 (a) | | 2014 (a) | | 2013 (a) |
PJM - West Hub | $ | 35.82 |
| | $ | 51.01 |
| | $ | 38.42 |
|
| | | | | |
PJM - PPL Zone | 33.01 |
| | 52.13 |
| | 38.01 |
|
| | | | | |
PJM - BGE Hub | 43.73 |
| | 60.22 |
| | 41.53 |
|
| | | | | |
ERCOT - North | 25.31 |
| | 35.74 |
| | 33.19 |
|
| | | | | |
ERCOT - South | 25.85 |
| | 36.02 |
| | 33.76 |
|
| | | | | |
NYISO - Zone F | 38.00 |
| | 61.19 |
| | 50.47 |
|
| | | | | |
ISO-NE Mass Hub | 41.90 |
| | 64.56 |
| | 56.42 |
|
| |
(a) | Source: data obtained from applicable ISO/RTO publications. |
If a decline in electricity prices driven by declining gas prices persists, Talen Energy will likely experience lower energy Margins at its coal-fired and nuclear generation facilities as higher priced hedges expire. To mitigate the impact of the consolidated resultsdeclining Margins on coal-fired and nuclear generation facilities, as described above, Talen Energy is pursuing opportunities to modify certain of operations.
Economic and Market Conditions
Unregulated Gross Energy Margins associated with PPL Energy Supply's competitiveits coal-fired generation and marketing business are impacted by changes in market prices and demand for electricityfacilities to be capable of operating on both coal and natural gas, as well as evaluating cost reduction measures at these facilities.
In November 2015, the FERC issued an order on "Price Formation" in the energy and ancillary service markets. These changes and future changes signaled by the FERC in that order may eventually improve pricing and thus compensation for generators in the energy and ancillary services markets, but no assurances can be given that will occur.
In December 2015, the FERC accepted a previously submitted PJM proposal that permits cost-based offers to exceed $2,000/MWh in certain circumstances but limits cost-based offers to $2,000/MWh for the purpose of setting locational marginal prices. Under the proposal, market-based offers are permitted to rise along with cost-based offers but are not permitted to exceed $2,000/MWh or the corresponding cost-based offers. Moreover, electricity providers will be permitted to recover actual costs above $2,000MWh through make-whole payments. In addition, electricity prices will be permitted to rise to $3,700/MWh during certain shortage pricing events. The changes became effective in December 2015.
However, in January 2016, as a part of the Price Formation efforts, the FERC issued a Notice of Proposed Rulemaking (NOPR) for comment which requires each RTO, including PJM, to cap each resource's incremental electricity offer to the higher of $1,000/MWh or that resource's verified cost-based incremental electricity offer. Under this proposal, verified cost-based incremental electricity offers above $1,000/MWh would be used for purposes of calculating Locational Marginal Prices. Comments on this NOPR are due within 60 days and final FERC action on this proposed ruling could modify the above December 2015 acceptance of the PJM proposal.
Capacity Prices
Capacity prices are another key source of revenue for Talen Energy’s operations. Currently, about 80% of Talen Energy's generation capacity is located in markets with a capacity product, including assets in PJM, NYISO and ISO-NE. Similar to electricity, capacity prices are affected by supply and demand fundamentals such as power plant availability, competitionadditions and retirements, imports/exports of capacity from/to adjacent markets, costs associated with plant retrofits, risk premiums associated with penalties for non-performance, demand response products, ISO demand forecasts and reserve margin targets. Over the past three auction cycles, capacity prices have increased in PJM and ISO-NE, primarily attributable to incentive-based changes in the markets for retail customers, fuel costs andcapacity market structures designed to improve operational availability fuel transportation costs and other costs. Current depressed wholesale marketduring periods of peak demand.
The table below reflects the cleared capacity prices for electricitythe zones in which the majority of Talen Energy's plants are located for the three most recent strip auctions.
|
| | | | | | | | | | | |
| 2015/2016 (a) | | 2016/2017 (a) | | 2017/2018 (a) |
PJM - MAAC ($/MW-day) | $ | 167.46 |
| | $ | 119.13 |
| | $ | 120.00 |
|
| | | | | |
PJM - SWMAAC ($/MW-day) | 167.46 |
| | 119.13 |
| | 120.00 |
|
| | | | | |
PJM - RTO ($/MW-day) | 136.00 |
| | 59.37 |
| | 120.00 |
|
| | | | | |
PJM Capacity Performance ($/MW-day) (b) | N/A |
| | 134.00 |
| | 151.50 |
|
| | | | | |
NYISO - Rest of State ($/kW-month) (c) | 1.25 |
| | N/A |
| | N/A |
|
| | | | | |
ISO-NE - Rest of Pool ($/kW-month) | 3.43 |
| | 3.15 |
| | 15.00 |
|
| |
(a) | Source: data obtained from applicable ISO/RTO publications. |
| |
(b) | The capacity performance product percentage of reliability requirements is being phased in through the 2020/2021 auction as described below. |
| |
(c) | Represents the 2015/2016 winter strip auction. Auctions beyond 2015/2016 have not yet been conducted. |
As a result of unusual market and weather volatility in the first quarter of 2014, PJM determined that changes were necessary to ensure system reliability. In December 2014, PJM proposed to add an enhanced Capacity Performance (CP) product to the capacity market structure to permit additional compensation for generation owners/operators to make the necessary investments to maintain system reliability in exchange for stronger performance requirements, with higher penalties for non-performers. In June 2105, the FERC issued an order approving the PJM CP proposal largely as it was filed and the CP product is being phased in through the 2020/2021 auction based on a percentage of capacity to meet reliability requirements. The phase in percentage was set at 60% for 2016/2017, 70% for 2017/2018 and 80% for both 2018/2019 and 2019/2020. 2020/2021 will be the first auction to procure 100% of the CP product. In August 2015, PJM completed the first base residual auction inclusive of a CP product for the planning year 2018/2019 and subsequently, in late August and September 2015, PJM completed the two CP transitional auctions for planning years 2016/2017 and 2017/2018. The first CP product implementation will begin on June 1, 2016 for the portion procured in the 2016/2017 transitional auction.
In December 2015, PJM altered its process for forecasting load beginning with the most recent 2016 "Load Processing Report" to reflect a shorter period for historical weather data, updated end usage data, and the inclusion of distributed solar generation. The revised process lowered the load forecast. This reduction in load is expected to put downward pressure on PJM capacity prices.
In January 2016, the U.S. Supreme Court reversed the ruling of the U.S. Court of Appeals for the D.C. Circuit Court and upheld the FERC's jurisdiction over rules regarding DR in organized markets. Therefore, DR will be permitted to continue to participate in future PJM energy and capacity auctions.
Natural Gas Prices
Natural gas prices are a key aspect of the current competitive power environment. The extensive development of major shale formations in the U.S. over the past few years has caused natural gas prices to decline. Power prices have resulted fromalso declined substantially due to the high degree of correlation with natural gas prices, weak general weak economic conditions and other factors, including the impact of expanded domestic shale gas development and production.factors. As a result, of these factors, PPLTalen Energy Supply has experienced a shift in the dispatching of its competitive generation fleet from coal-fired to combined-cycle gas-fired generation as illustrated in the following table:generation.
| | | Average Utilization Factors (a) |
| | | 2012 | | | 2009 - 2011 |
Pennsylvania coal plants | | | 69% | | | 87% |
Montana coal plants | | | 67% | | | 89% |
Combined-cycle gas plants | | | 98% | | | 72% |
Environmental Regulations
(a) | All periods reflect the year ended December 31. |
This reduction in coal-fired generation output had resulted in a surplus of coal inventory at certain of PPLTalen Energy Supply's Pennsylvania coal plants. To mitigate the risk of exceeding available coal storage, PPL Energy Supply incurred pre-tax charges of $29 million in 2012 to reduce its 2012 and 2013 contracted coal deliveries. PPL Energy Supply will continue to manage its coal inventory to mitigate the financial impact and physical implications of an oversupply; however, no additional coal contract modifications are expected at this time.
In addition, current economic and commodity market conditions indicate a lower value of unhedged future energy margins (primarily in 2014 and forward years) compared to the energy margins in 2012. As has been PPL Energy Supply's practice in periods of changing business conditions, PPL Energy Supply continues to review its future business and operational plans, including capital and operation and maintenance expenditures, as well as its hedging strategies, to help counter the financial effects of low commodity prices.
PPL's businesses areis subject to extensive federal, state and local environmental laws, rules and regulations. Although PPLregulations, including those pertaining to CCRs, GHG, effluent limitation guidelines and MATS. In 2015, the EPA published the final rules related to GHG regulations for new and existing power plants that could have a significant industry-wide impact. Talen Energy Supply's competitive generation assets are well positioned to meetis in the process of evaluating these requirements, certain regulated generation assets at LG&E and KU will require substantial capital investment. LG&E and KU project $2.3 billion of capital investment over the next five years to satisfy certain of these requirements.rules. See Note 15 to the Financial Statements"Financial Condition - Environmental Matters" below for additional information on these requirements. These requirements have resulted in LKE's anticipated retirementIn 2015, Talen Energy recorded increases to existing AROs of five coal-fired units with a combined summer capacity rating of 726 MW by 2015. KU retired the 71 MW unit at the Tyrone plant in February 2013. See Note 8 to the Financial Statements for additional information regarding the anticipated retirement of these units as well as plans to build a combined-cycle natural gas facility in Kentucky. Also, in 2012 KU recorded a $25$41 million pre-tax impairment of its EEI investment as a result of environmental regulationsa review of the 2015 CCR rule. Further changes to AROs may be required as estimates are refined and low energy prices. Finally, in September 2012 PPL announced its intention, beginning in April 2015, to place its Corette plant in long-term reserve status, suspendingcompliance with the plant's operation due to expected market conditions and the costs to comply with MATS. The Corette plant asset group's carrying amount at December 31, 2012 was approximately $68 million. Although the Corette plant asset group was not determined to be impaired at December 31, 2012, it is reasonably possible that an impairment could occur in future periods, as higher priced sales contracts settle, adversely impacting projected cash flows.rule continues.
Other Regulatory Matters
In lightThere have been attempts in Ohio by certain companies to have their utilities be permitted to subsidize several uneconomic merchant generation assets owned by non-utility affiliates. Those attempts are being opposed by many generator and consumer interests both in Ohio and at the FERC. Additional efforts to oppose on grounds of these economic and market conditions, as well as current and projected environmental regulatory requirements, PPL considered whether certain of its other generating assets were impaired, and determined that no impairment charges were required at December 31, 2012. PPL is unable to predict whether future environmental requirements or market conditions will result in impairment charges for other generating assets or other retirements.
PPL and its subsidiariesfederal preemption may also be impactedmade in future periods byFederal Court. If approved and not reversed, out of market subsidies could be disruptive to the uncertaintymarket signals for competitive generation and threaten the long-term viability of PJM's markets. It is too early to predict the outcome of these efforts to subsidize uneconomic generators in the worldwide financial and credit markets. In addition, PPL may be impacted by reductions in the credit ratings of financial institutions and evolving regulations in the financial sector. Collectively, these factors could reduce availability or restrict PPL and its subsidiaries' ability to maintain sufficient levels of liquidity, reduce capital market activities, change collateral posting requirements and increase the associated costs to PPL and its subsidiaries.Ohio.
PPLTalen Energy cannot predict the future impact that thesefuture economic and market conditions and regulatory requirements may have on its financial condition or results of operations.
Susquehanna Turbine Blade Inspection
During 2012, PPL Energy Supply performed inspections of the Unit 1 and Unit 2 turbine blades at the PPL Susquehanna nuclear power plant in order to further address the issue of turbine blade cracking that was first identified in 2011. The after-tax earnings impact of these 2012 inspections, including reduced energy-sales margins and repair expenses, was approximately $53 million. The after-tax earnings impact of turbine blade related outages in 2011 was approximately $63 million.
Ironwood Acquisition
In April 2012, an indirect, wholly owned subsidiary of PPL Energy Supply completed the acquisition of the equity interests in the owner and operator of the Ironwood Facility. The Ironwood Facility began operation in 2001 and, since 2008, PPL EnergyPlus has supplied natural gas for the facility and received the facility's full electricity output and capacity value pursuant to a tolling agreement that expires in 2021. The acquisition provides PPL Energy Supply, through its subsidiaries, operational control of additional combined-cycle gas generation in PJM. See Note 10 to the Financial Statements for additional information.
Bankruptcy of SMGT
In October 2011, SMGT, a Montana cooperative and purchaser of electricity under a long-term supply contract with PPL EnergyPlus expiring in June 2019 (SMGT Contract), filed for protection under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the District of Montana. At the time of the bankruptcy filing, SMGT was PPL EnergyPlus' largest unsecured credit exposure. This contract was accounted for as NPNS by PPL EnergyPlus.
The SMGT Contract provided for fixed volume purchases on a monthly basis at established prices. Pursuant to a court order and subsequent stipulations entered into between the SMGT bankruptcy trustee and PPL EnergyPlus, since the date of its Chapter 11 filing through January 2012, SMGT continued to purchase electricity from PPL EnergyPlus at the price specified in the SMGT Contract, and made timely payments for such purchases, but at lower volumes than as prescribed in the SMGT Contract. In January 2012, the trustee notified PPL EnergyPlus that SMGT would not purchase electricity under the SMGT Contract for the month of February. In March 2012, the U.S. Bankruptcy Court for the District of Montana issued an order approving the request of the SMGT bankruptcy trustee and PPL EnergyPlus to terminate the SMGT Contract. As a result, the SMGT Contract was terminated effective April 1, 2012, allowing PPL EnergyPlus to resell to other customers the electricity previously contracted to SMGT under the SMGT Contract.
PPL EnergyPlus' receivable under the SMGT Contract totaled approximately $21 million at December 31, 2012, which has been fully reserved.
In July 2012, PPL EnergyPlus filed its proof of claim in the SMGT bankruptcy proceeding. The total claim is approximately $375 million, including the above receivable, predominantly an unsecured claim representing the value for energy sales that will not occur as a result of the termination of the SMGT Contract. No assurance can be given as to the collectability of the claim, thus no amounts have been recorded in the 2012 financial statements.
PPL Energy Supply cannot predict any amounts that it may recover in connection with the SMGT bankruptcy or the prices and other terms on which it will be able to market to third parties the power that SMGT will not purchase from PPL EnergyPlus due to the termination of the SMGT Contract.
Tax Litigation
In 1997, the U.K. imposed a Windfall Profits Tax (WPT) on privatized utilities, including WPD. PPL filed its federal tax returns for years subsequent to its 1997 and 1998 claims for refund on the basis that the U.K. WPT was creditable. In September 2010, the U.S. Tax Court (Tax Court) ruled in PPL's favor in a dispute with the IRS, concluding that the U.K. WPT is a creditable tax for U.S. tax purposes. As a result, and with finalization of other issues, PPL recorded a $42 million tax benefit in 2010. In January 2011, the IRS appealed the Tax Court's decision to the U.S. Court of Appeals for the Third Circuit (Third Circuit). In December 2011, the Third Circuit issued its opinion reversing the Tax Court's decision, holding that the U.K. WPT is not a creditable tax. As a result of the Third Circuit's adverse determination, PPL recorded a $39 million expense in 2011. In February 2012, PPL filed its petition for rehearing of the Third Circuit's opinion. In March 2012, the Third Circuit denied PPL's petition. In June 2012, the U.S. Court of Appeals for the Fifth Circuit issued a contrary opinion in an identical case involving another company. In July 2012, PPL filed a petition for a writ of certiorari seeking U.S. Supreme Court review of the Third Circuit's opinion. The Supreme Court granted PPL's petition on October 29, 2012, and oral argument was held on February 20, 2013. PPL expects the case to be decided before the end of the Supreme Court's current term in June 2013 and cannot predict the outcome of this matter.
Terminated Bluegrass CTs Acquisition
In September 2011, LG&E and KU entered into an asset purchase agreement with Bluegrass Generation for the purchase of the Bluegrass CTs, aggregating approximately 495 MW, plus limited associated contractual arrangements required for operation of the units, for a purchase price of $110 million, pending receipt of applicable regulatory approvals. In May 2012, the KPSC issued an order approving the request to purchase the Bluegrass CTs. In November 2011, LG&E and KU filed an application with the FERC under the Federal Power Act requesting approval to purchase the Bluegrass CTs. In May 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to approval by the FERC of satisfactory mitigation measures to address market-power concerns. After a review of potentially available mitigation options, LG&E and KU determined that the options were not commercially justifiable. In June 2012, LG&E and KU terminated the asset purchase agreement for the Bluegrass CTs in accordance with its terms and made applicable filings with the KPSC and FERC.
Cane Run Unit 7 Construction
In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build Cane Run Unit 7. In May 2012, the KPSC issued an order approving the request. A formal request for recovery of the costs associated with the construction was not included in the CPCN filing with the KPSC but is expected to be included in future rate case proceedings. LG&E and KU commenced preliminary construction activities in the third quarter of 2012 and project construction is expected to be completed by May 2015. The project, which includes building a natural gas supply pipeline and related transmission projects, has an estimated cost of approximately $600 million.
Future Capacity Needs
In addition to the construction of a combined cycle gas unit at the Cane Run station, LG&E and KU continue to assess future capacity needs. As a part of the assessment, LG&E and KU issued an RFP in September 2012 for up to 700 MW of capacity beginning as early as 2015.
Storm Costs
During 2012, PPL Electric experienced several PUC-reportable storms, including Hurricane Sandy, resulting in total restoration costs of $81 million, of which $61 million were initially recorded in "Other operation and maintenance" on the Statement of Income. In particular, in late October 2012, PPL Electric experienced widespread significant damage to its distribution network from Hurricane Sandy resulting in total restoration costs of $66 million, of which $50 million were initially recorded in "Other operation and maintenance" on the Statement of Income. However, a PPL subsidiary has a $10 million reinsurance policy with a third party insurer, for which a receivable was recorded with an offsetting credit to "Other operation and maintenance" on the Statement of Income. PPL Electric recorded a regulatory asset of $28 million in December 2012 (offset to "Other operation and maintenance" on the Statement of Income). In February 2013, PPL Electric received an order from the PUC granting permission to defer qualifying storm costs in excess of insurance recoveries associated with Hurricane Sandy.
See "Regulatory Matters - Pennsylvania Activities - Storm Costs" in Note 6 to the Financial Statements for information on $84 million of storm costs incurred in 2011.
Rate Case Proceedings
Pennsylvania
In March 2012, PPL Electric filed a request with the PUC to increase distribution rates by approximately $105 million, effective January 1, 2013. In its December 28, 2012 final order, the PUC approved a 10.4% return on equity and a total distribution revenue increase of about $71 million. The approved rates became effective January 1, 2013.
Also, in its December 28, 2012 final order, the PUC ordered PPL Electric to file a proposed Storm Damage Expense Rider within 90 days following the order. PPL Electric plans to file a proposed Storm Damage Expense Rider with the PUC and, as part of that filing, request recovery of the $28 million of qualifying storm costs incurred as a result of the October 2012 landfall of Hurricane Sandy.
Kentucky
In June 2012, LG&E and KU filed requests with the KPSC for increases in annual base electric rates of approximately $62 million at LG&E and approximately $82 million at KU and an increase in annual base gas rates of approximately $17 million at LG&E. In November 2012, LG&E and KU along with all of the parties filed a unanimous settlement agreement. Among other things, the settlement provided for increases in annual base electric rates of $34 million at LG&E and $51 million at KU and an increase in annual base gas rates of $15 million at LG&E. The settlement agreement also included revised depreciation rates that result in reduced annual electric depreciation expense of approximately $9 million for LG&E and approximately $10 million for KU. The settlement agreement included an authorized return on equity at LG&E and KU of 10.25%. On December 20, 2012, the KPSC issued orders approving the provisions in the settlement agreement. The new rates became effective on January 1, 2013. In addition to the increased base rates, the KPSC approved a gas line tracker mechanism for LG&E to provide for recovery of costs associated with LG&E's gas main replacement program, gas service lines and risers.
Regional Transmission Line Expansion Plan
Susquehanna-Roseland
In 2007, PJM directed the construction of a new 150-mile, 500-kilovolt transmission line between the Susquehanna substation in Pennsylvania and the Roseland substation in New Jersey that it identified as essential to long-term reliability of the Mid-Atlantic electricity grid. PJM determined that the line was needed to prevent potential overloads that could occur on several existing transmission lines in the interconnected PJM system. PJM directed PPL Electric to construct the portion of the Susquehanna-Roseland line in Pennsylvania and Public Service Electric & Gas Company to construct the portion of the line in New Jersey.
On October 1, 2012, the National Park Service (NPS) issued its Record of Decision (ROD) on the proposed Susquehanna-Roseland transmission line affirming the route chosen by PPL Electric and Public Service Electric & Gas Company as the preferred alternative under the NPS's National Environmental Policy Act review. On October 15, 2012, a complaint was filed in the United States District Court for the District of Columbia by various environmental groups, including the Sierra Club, challenging the ROD and seeking to prohibit its implementation; and on December 6, 2012, the groups filed a petition for injunctive relief seeking to prohibit all construction activities until the court issues a final decision on the complaint. PPL Electric has intervened in the lawsuit. The chosen route had previously been approved by the PUC and New Jersey Board of Public Utilities.
On December 13, 2012, PPL Electric received federal construction and right of way permits to build on National Park Service lands.
Construction activities have begun on portions of the 101-mile route in Pennsylvania. The line is expected to be completed before the peak summer demand period of 2015. At December 31, 2012, PPL Electric's estimated share of the project cost was $560 million.
PPL and PPL Electric cannot predict the ultimate outcome or timing of any legal challenges to the project or what additional actions, if any, PJM might take in the event of a further delay to its scheduled in-service date for the new line.
Northeast/Pocono
In October 2012, the FERC issued an order in response to PPL Electric's December 2011 request for ratemaking incentives for the Northeast/Pocono Reliability project (a new 58-mile 230 kV transmission line, three new substations and upgrades to adjacent facilities). The incentives were specifically tailored to address the risks and challenges PPL Electric will face in building the project. The FERC granted the incentive for inclusion of all prudently incurred construction work in progress (CWIP) costs in rate base and denied the request for a 100 basis point adder to the return on equity incentive. The order required a follow-up compliance filing from PPL Electric to ensure proper accounting treatment of AFUDC and CWIP for the project, which PPL Electric will submit to the FERC in March 2013. PPL Electric expects the project to be completed in 2017. At December 31, 2012, PPL Electric estimates the total project costs to be approximately $200 million with approximately $190 million qualifying for the CWIP incentive.
Legislation - Regulatory Procedures and Mechanisms
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 DSIC. Such alternative ratemaking procedures and mechanisms provide opportunity for accelerated cost-recovery and, therefore, are important to PPL Electric as it begins a period of significant capital investment to maintain and enhance the reliability of its delivery system, including the replacement of aging distribution assets. In August 2012, the PUC issued a final implementation order adopting procedures, guidelines and a model tariff for the implementation of Act 11. Act 11 requires utilities to file an LTIIP as a prerequisite to filing for recovery through the DSIC. The LTIIP is mandated to be a five- to ten-year plan describing projects eligible for inclusion in the DSIC. In September 2012, PPL Electric filed its LTIIP describing projects eligible for inclusion in the DSIC. The PUC approved the LTIIP on January 10, 2013 and PPL Electric filed a petition requesting permission to establish a DSIC on January 15, 2013, with rates proposed to be effective beginning May 1, 2013.
FERC Formula Rates
In March 2012, PPL Electric filed a request with the FERC seeking recovery of its regulatory asset related to the deferred state tax liability that existed at the time of the transition from the flow-through treatment of state income taxes to full normalization. This change in tax treatment occurred in 2008 as a result of prior FERC initiatives that transferred regulatory jurisdiction of certain transmission assets from the PUC to FERC. At December 31, 2012 and December 31, 2011, $52 million and $53 million respectively, are classified as taxes recoverable through future rates and included on the Balance Sheets in "Other Noncurrent Assets - Regulatory assets." In May 2012, the FERC issued an order approving PPL Electric's request to recover the deferred tax regulatory asset over a 34 year period beginning June 1, 2012.
U.K. Tax Rate Change
In July 2012, the U.K.'s Finance Act of 2012 (the Act) became effective. The Act reduced the U.K. statutory income tax rate from 25% to 24%, retroactive to April 1, 2012 and from 24% to 23%, effective April 1, 2013. As a result of these changes, PPL recognized a deferred tax benefit of $75 million in 2012.
Ofgem Review of Line Loss Calculation
WPD had a $94 million liability recorded at December 31, 2012, compared with $170 million at December 31, 2011, related to the close-out of line losses for the prior price control period, DPCR4. Ofgem is currently consulting on the methodology to be used by all network operators to calculate the final line loss incentive/penalty for the DPCR4. In October 2011, Ofgem issued a consultation paper citing two potential changes to the methodology, both of which would result in a reduction of the liability. In March 2012, Ofgem issued a decision regarding the preferred methodology. In July 2012, Ofgem issued a consultation paper regarding certain aspects of the preferred methodology as it relates to the DPCR4 line loss incentive/penalty and a proposal to delay the target date for making a final decision until April 2013. In October 2012, a license modification was issued to allow Ofgem to publish the final decisions on these matters by April 2013. In November 2012, Ofgem issued an additional consultation on the final DPCR4 line loss close-out that published values for each DNO and further indicated the preferred methodology that would replace the methodology under WPD's licenses. Based on applying the preferred methodology for DPCR4, the liability was reduced by $79 million, with a credit recorded in "Utility" on the Statement of Income, to reflect what WPD expects to be the final close-out settlement under Ofgem's preferred methodology. This consultation also confirmed the final decisions will be published by April 2013. In February 2013, Ofgem issued additional consultation proposing to delay the April 2013 decision date. PPL cannot predict when this matter will be resolved.
Ofgem also stated in the November 2012 consultation that the line loss incentive implemented at the last rate review will be withdrawn and no incentive will apply for the DPCR5 period. That decision resulted in the elimination of the DPCR5 liability of $11 million, with a credit recorded in "Utility" on the Statement of Income.
Equity Forward Contract
In April 2012, PPL made a registered underwritten public offering of 9.9 million shares of its common stock. In conjunction with that offering, the underwriters exercised an option to purchase 591 thousand additional shares of PPL common stock solely to cover over-allotments.
In connection with the registered public offering, PPL entered into forward sale agreements with two counterparties covering the 9.9 million shares of PPL's common stock. Settlement of these initial forward sale agreements will occur no later than April 2013. As a result of the underwriters' exercise of the overallotment option, PPL entered into additional forward sale agreements covering the additional 591 thousand shares of PPL common stock. Settlement of the subsequent forward sale agreements will occur no later than July 2013.
PPL will not receive any proceeds or issue any shares of common stock until settlement of the forward sale agreements. PPL intends to use any net proceeds that it receives upon settlement to repay short-term debt obligations and for other general corporate purposes.
The forward sale agreements are classified as equity transactions. As a result, no amounts will be recorded in the consolidated financial statements until the settlement of the forward sale agreements. Prior to those settlements, the only impact to the financial statements will be the inclusion of incremental shares within the calculation of diluted EPS using the treasury stock method. See Note 7 to the Financial Statements for additional information.
2010 Equity Units
During 2013, two events will occur related to the components of the 2010 Equity Units. PPL will receive proceeds of $1.150 billion through the issuance of PPL common stock to settle the 2010 Purchase Contracts and PPL Capital Funding expects to remarket the 4.625% Junior Subordinated Notes due 2018. See Note 7 to the Financial Statements for additional information.
Redemption of PPL Electric Preference Stock
In June 2012, PPL Electric redeemed all 2.5 million shares of its 6.25% Series Preference Stock, par value $100 per share. The price paid for the redemption was the par value, without premium ($250 million in the aggregate). At December 31, 2011, the preference stock was reflected in "Noncontrolling Interests" on PPL's Balance Sheet.
Results of Operations
The "StatementAs a result of Income Analysis" explains the year-to-year changes in significant earnings components, including certain income statement line items, Kentucky Gross Margins, Pennsylvania Gross Delivery Margins and Unregulated Gross Energy Margins.
On AprilRJS Power acquisition on June 1, 2011, PPL completed its acquisition2015, results for RJS (since the date of WPD Midlands. As PPL is consolidating WPD Midlands on a one-month lag, consistent with its accounting policy on consolidation of foreign subsidiaries, a full year of WPD Midlands' results of operationsacquisition) are included in PPL'sTalen Energy's 2015 results for 2012, and eight months of WPD Midlands' results of operations are included in PPL's results for 2011, with no comparable amounts for 2010.in 2014 and 2013. When discussing PPL'sTalen Energy's results of operations for 20122015 compared with 2011 and 2011 compared with 2010,2014, the results of WPD MidlandsRJS are isolated for purposes of comparability. WPD Midlands'comparability (if significant). At acquisition, the Sapphire operations were classified as discontinued operations. However, in November 2015, when the FERC approved the third mitigation package excluding the Sapphire portfolio, the assets and liabilities and operating results were reclassified to held and used and to continuing operations, as it is no longer probable that the Sapphire portfolio will be sold.
As a result of the MACH Gen acquisition on November 2, 2015, results for MACH Gen (since the date of acquisition) are included within "Segment Results - U.K. Regulated Segment (formerlyin Talen Energy's 2015 results with no comparable amounts in 2014 and 2013. When discussing Talen Energy's results of operations for 2015 compared with 2014, the International Regulated Segment, renamedresults of MACH Gen are isolated for purposes of comparability (if significant).
Talen Energy is organized in 2012)."two segments: East and West, based on geographic location. The East segment includes the generating, marketing and trading activities in PJM, NYISO and ISO-NE. The West segment includes the generating, marketing and trading activities located in ERCOT and WECC. See Note 102 to the Financial Statements for additional information regardingon Talen Energy's segments and the acquisition.segment reevaluation.
On November 1, 2010, PPL completed its acquisition of LKE. LKE's results of operations are included in PPL's results for the full year of 2012 and 2011, while 2010 includes LKE's operating results for the two months ended December 31, 2010. When discussing PPL's results of operations for 2011 compared with 2010, the results of LKE are isolated for purposes of comparability. LKE's results are shown separatelyThe discussion within "Segment Results - Kentucky Regulated Segment." See Note 10 to the Financial Statements for additional information regarding the acquisition.
Tables analyzing changes in amounts between periods within "Segment Results" and "Statement of Income Analysis" are presentedaddresses significant changes in principal line items on the Statements of Income comparing 2015 with 2014 and 2014 with 2013 on a constant U.K. foreign currency exchange rate basis, where applicable, in orderGAAP basis. The "Margins" discussion, presented by segment, includes a reconciliation of that non-GAAP financial measure to isolate the impactoperating income(loss). The "EBITDA and Adjusted EBITDA" discussion, also presented by segment, includes a reconciliation of the change in the exchange rate on the item being explained. Results computed on a constant U.K. foreign currency exchange rate basis are calculated by translating current year results at the prior year weighted-average U.K. foreign currency exchange rate.
Earnings | | | | | | | | | |
| | | | | | | | | | |
| | | 2012 | | 2011 | | 2010 |
| | | | | | | | | | |
Net Income Attributable to PPL Shareowners | | $ | 1,526 | | $ | 1,495 | | $ | 938 |
EPS - basic | | $ | 2.61 | | $ | 2.71 | | $ | 2.17 |
EPS - diluted | | $ | 2.60 | | $ | 2.70 | | $ | 2.17 |
Kentucky Regulated Segment
The Kentucky Regulated segment consists primarily of LKE's results from the operation of regulated electricity generation, transmissionthose non-GAAP financial measures to operating income (loss) and distribution assets, primarily in Kentucky, as well as in Virginia and Tennessee. This segment also includes LKE's results from the regulated distribution and sale of natural gas in Kentucky.
Net Income Attributable to PPL Shareowners includes the following results:
| | | 2012 | | 2011 | | % Change | | 2010 (a) |
| | | | | | | | | | | |
Utility revenues | | $ | 2,759 | | $ | 2,793 | | (1) | | $ | 493 |
Fuel | | | 872 | | | 866 | | 1 | | | 139 |
Energy purchases | | | 195 | | | 238 | | (18) | | | 68 |
Other operation and maintenance | | | 778 | | | 751 | | 4 | | | 139 |
Depreciation | | | 346 | | | 334 | | 4 | | | 49 |
Taxes, other than income | | | 46 | | | 37 | | 24 | | | 2 |
| Total operating expenses | | | 2,237 | | | 2,226 | | | | | 397 |
Other Income (Expense) - net | | | (15) | | | (1) | | 1,400 | | | (1) |
Other-Than-Temporary Impairments | | | 25 | | | | | n/a | | | |
Interest Expense (b) | | | 219 | | | 217 | | 1 | | | 55 |
Income Taxes | | | 80 | | | 127 | | (37) | | | 16 |
Income (Loss) from Discontinued Operations (net of income taxes) | | | (6) | | | (1) | | 500 | | | 2 |
Net Income Attributable to PPL Shareowners | | $ | 177 | | $ | 221 | | (20) | | $ | 26 |
(a) | Represents the results of operations for the two-month period from November 1, 2010 through December 31, 2010. |
(b) | Includes allocated interest expense of $68 million in 2012, $70 million in 2011 and $31 million in 2010 related to the 2010 Equity Units and interest rate swaps. |
The changes in the components of the Kentucky Regulated segment's results between 2012 and 2011 were due to the following factors, which reflect reclassifications for items included in Kentucky Gross Margins and certain items that management considers special. See additional detail of these special items in the table below. The 2011 and 2010 comparison has not been included as the periods are not comparable (2010 includes two months of activity as LKE was acquired on November 1, 2010)consolidated net income (loss).
| | 2012 vs. 2011 |
| | | |
Kentucky Gross Margins | | $ | (8) |
Other operation and maintenance | | | (16) |
Depreciation | | | (10) |
Taxes, other than income | | | (9) |
Other Income (Expense) - net | | | (14) |
Interest Expense | | | (2) |
Income Taxes | | | 31 |
Special items, after-tax | | | (16) |
Total | | $ | (44) |
· | See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Kentucky Gross Margins. |
· | Higher other operation and maintenance in 2012 compared with 2011 primarily due to $11 million of expenses related to an increased scope of scheduled outages and a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs.
|
· | Higher depreciation in 2012 compared with 2011 due to PP&E additions. |
· | Lower other income (expense) - net in 2012 compared with 2011 primarily due to losses from the EEI investment. |
· | Lower income taxes in 2012 compared with 2011 primarily due to lower pre-tax income. |
The following after-tax gains (losses), which management considers special items, also impacted the Kentucky Regulated segment's results.
| | | Income Statement | | | | | | | | | | | |
| | | Line Item | | 2012 | | 2011 | | | 2010 |
| | | | | | | | | | | | |
Adjusted energy-related economic activity, net, net of tax of $0, ($1), $1 | Utility Revenues | | | | | | $ | 1 | | | $ | (1) |
Impairments: | | | | | | | | | | | | |
| Other asset impairments, net of tax of $10, $0, $0 (a) | Other-Than-Temporary-Impairments | | $ | (15) | | | | | | | | |
LKE acquisition-related adjustments: | | | | | | | | | | | | |
| Net operating loss carryforward and other tax-related adjustments | Income Taxes and Other O&M | | | 4 | | | | | | | | |
Other: | | | | | | | | | | | | |
| LKE discontinued operations, net of tax of $4, $1, ($2) (b) | Disc. Operations | | | (5) | | | | (1) | | | | 2 |
Total | | | $ | (16) | | | $ | | | | $ | 1 |
(a) | KU recorded an impairment of its equity method investment in EEI. See Note 18 to the Financial Statements for additional information. |
(b) | 2012 includes an adjustment to an indemnification liability. |
2013 Outlook
Excluding special items, PPL projects higher segment earnings in 2013 compared with 2012, primarily driven by electric and gas base rate increases effective January 1, 2013, returns on additional environmental capital investments and retail load growth, partially offset by higher operation and maintenance.
Earnings in future periods are subject to various risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7"Item 7. Combined Management's Discussion and Notes 6Analysis of Financial Condition and 15Results of Operations" and Note 11 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.
Statement of Income Analysis, Margins, EBITDA and Adjusted EBITDA
The U.K. Regulated segment consists primarilyStatement of the regulated electric distribution operations in the U.K. As a result of the WPD Midlands acquisition on April 1, 2011, the U.K. Regulated segment includes eight months of WPD Midlands' results in 2011. Similar to PPL WW, WPD Midlands' results are recorded on a one-month lag.Income Analysis --
Net Income Attributable to PPL Shareowners includes the following results (includes PPL WW and WPD Midlands on a consolidated basis, except for 2012 and 2011 acquisition-related adjustments, which are shown separately): |
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | | | For the Years Ended December 31, | | |
| 2015 | | 2014 | | Change | | 2014 | | 2013 | | Change |
Wholesale energy (a) (b) (c) | $ | 2,828 |
| | $ | 2,653 |
| | $ | 175 |
| | $ | 2,653 |
| | $ | 2,890 |
| | $ | (237 | ) |
Wholesale energy to affiliate (b) | 14 |
| | 84 |
| | (70 | ) | | 84 |
| | 51 |
| | 33 |
|
Retail energy (a) (b) | 1,095 |
| | 1,243 |
| | (148 | ) | | 1,243 |
| | 1,027 |
| | 216 |
|
Energy-related businesses | 544 |
| | 601 |
| | (57 | ) | | 601 |
| | 527 |
| | 74 |
|
Total Operating Revenues | 4,481 |
| | 4,581 |
| | (100 | ) | | 4,581 |
| | 4,495 |
| | 86 |
|
Fuel (a) (b) (c) | 1,194 |
| | 1,196 |
| | (2 | ) | | 1,196 |
| | 1,048 |
| | 148 |
|
Energy purchases (a) (b) (c) | 676 |
| | 1,054 |
| | (378 | ) | | 1,054 |
| | 1,153 |
| | (99 | ) |
Operation and maintenance | 1,052 |
| | 1,007 |
| | 45 |
| | 1,007 |
| | 961 |
| | 46 |
|
Loss on lease termination | — |
| | — |
| | — |
| | — |
| | 697 |
| | (697 | ) |
Impairments | 657 |
| | — |
| | 657 |
| | — |
| | 65 |
| | (65 | ) |
Depreciation | 356 |
| | 297 |
| | 59 |
| | 297 |
| | 299 |
| | (2 | ) |
Taxes, other than income | 65 |
| | 57 |
| | 8 |
| | 57 |
| | 53 |
| | 4 |
|
Energy-related businesses | 520 |
| | 573 |
| | (53 | ) | | 573 |
| | 512 |
| | 61 |
|
Total Operating Expenses | 4,520 |
| | 4,184 |
| | 336 |
| | 4,184 |
| | 4,788 |
| | (604 | ) |
Operating Income (Loss) | (39 | ) | | 397 |
| | (436 | ) | | 397 |
| | (293 | ) | | 690 |
|
Other Income (Expense) - net | (118 | ) | | 30 |
| | (148 | ) | | 30 |
| | 32 |
| | (2 | ) |
Interest Expense | 211 |
| | 124 |
| | 87 |
| | 124 |
| | 159 |
| | (35 | ) |
Income Taxes | (27 | ) | | 116 |
| | (143 | ) | | 116 |
| | (159 | ) | | 275 |
|
Income (Loss) from Continuing Operations After Income Taxes | (341 | ) | | 187 |
| | (528 | ) | | 187 |
| | (261 | ) | | 448 |
|
Income (Loss) from Discontinued Operations (net of income taxes) | — |
| | 223 |
| | (223 | ) | | 223 |
| | 32 |
| | 191 |
|
Net Income (Loss) | (341 | ) | | 410 |
| | (751 | ) | | 410 |
| | (229 | ) | | 639 |
|
Net Income (Loss) Attributable to Noncontrolling Interests | — |
| | — |
| | — |
| | — |
| | 1 |
| | (1 | ) |
Net Income (Loss) Attributable to Talen Energy Corporation Stockholders | $ | (341 | ) | | $ | 410 |
| | $ | (751 | ) | | $ | 410 |
| | $ | (230 | ) | | $ | 640 |
|
| | | 2012 | | 2011 | | 2010 |
| | | | | | | | | | |
Utility revenues (a) | | $ | 2,289 | | $ | 1,618 | | $ | 727 |
Energy-related businesses | | | 47 | | | 35 | | | 34 |
| Total operating revenues | | | 2,336 | | | 1,653 | | | 761 |
Other operation and maintenance | | | 439 | | | 374 | | | 182 |
Depreciation | | | 279 | | | 211 | | | 117 |
Taxes, other than income | | | 147 | | | 113 | | | 52 |
Energy-related businesses | | | 34 | | | 17 | | | 17 |
| Total operating expenses | | | 899 | | | 715 | | | 368 |
Other Income (Expense) - net | | | (51) | | | 13 | | | 3 |
Interest Expense (b) | | | 421 | | | 336 | | | 135 |
Income Taxes | | | 153 | | | 98 | | | |
WPD Midlands acquisition-related adjustments, net of tax | | | (9) | | | (192) | | | |
Net Income Attributable to PPL (c) | | $ | 803 | | $ | 325 | | $ | 261 |
(a) | Includes $1,423 million in 2012 and $790 million in 2011 for WPD Midlands. |
(b) | Includes allocated interest expense of $47 million and $38 million for 2012 and 2011 related primarily to the 2011 Equity Units. |
(c) | Includes $570 million in 2012 and $137 million in 2011 for WPD Midlands, net of acquisition-related adjustments. |
The changes in the components of the U.K. Regulated segment's results between these periods were due to the following factors, which reflect reclassifications for certain items that management considers special and with WPD Midlands isolated for comparability purposes. See additional detail of special items in the table below. The amounts for PPL WW and WPD Midlands are presented on a constant U.K. foreign currency exchange rate basis in order to isolate the impact of the change in the exchange rate.
| | | 2012 vs. 2011 | | 2011 vs. 2010 |
PPL WW | | | | | | |
| Utility revenues | | $ | 49 | | $ | 77 |
| Other operation and maintenance | | | (26) | | | (10) |
| Interest expense | | | 16 | | | (14) |
| Depreciation | | | (8) | | | (2) |
| Other | | | (4) | | | 5 |
| Income taxes | | | 17 | | | (55) |
WPD Midlands, after-tax | | | 224 | | | 240 |
U.S. | | | | | | |
| Interest expense and other | | | (15) | | | (41) |
| Income taxes | | | (25) | | | 37 |
Foreign currency exchange rates, after-tax | | | (14) | | | 15 |
Special items, after-tax | | | 264 | | | (188) |
Total | | $ | 478 | | $ | 64 |
· | The increase in utility revenues in 2012 compared with 2011 was due to the impact of the April 2012 and 2011 price increases which resulted in $78 million of higher utility revenues, partially offset by $13 million of lower volumes due primarily to a downturn in the economy and weather. |
The increase in utility revenues in 2011 compared with 2010 was due to the impact of the April 2011 and 2010 price increases that resulted in $76 million of additional revenue.
· | The increases in other operation and maintenance in 2012 compared with 2011 and 2011 compared with 2010 were due to higher pension expense resulting from an increase in amortization of actuarial losses. |
· | The decrease in interest expense in 2012 compared with 2011 was due to lower interest expense on index-linked notes. |
The increase in interest expense in 2011 compared with 2010 was due to $11 million of higher interest expense arising from a March 2010 debt issuance.
· | The increase in depreciation expense in 2012 compared with 2011 was due to $10 million of depreciation related to PP&E additions. |
· | The decrease in income taxes in 2012 compared with 2011 was due to the tax deductibility of interest on acquisition financing of $12 million and $9 million from a benefit relating to customer contributions for capital expenditures. |
The increase in income taxes in 2011 compared with 2010 was due to a $46 million benefit recorded in 2010 for realized capital losses that offset a gain relating to a business activity sold in 1999 and $15 million due to higher 2011 pre-tax income.
WPD Midlands
· | Earnings in 2012 compared with 2011 were affected by an additional four months of results in 2012 totaling $171 million, after-tax. |
· | The comparable eight month period was affected by higher utility revenue of $125 million resulting from the April 1, 2012 price increase and $26 million of lower pension expense, partially offset by $26 million of higher taxes due to higher pre-tax income, $25 million of additional interest expense on debt issuances in 2011 and 2012 and $25 million of higher taxes due to a U.K./U.S. intercompany tax transaction. |
U.S.
· | The increase in interest expense and other in 2012 compared with 2011 was due to $9 million of higher interest expense primarily associated with the 2011 Equity Units issued to finance the WPD Midlands acquisition. |
The increase in interest expense and other in 2011 compared with 2010 was due to $38 million of higher interest expense primarily associated with the 2011 Equity Units issued to finance the WPD Midlands acquisition.
· | The increase in income taxes in 2012 compared with 2011 was due to $28 million of tax benefits recorded in 2011 as a result of U.K. pension plan contributions and a $20 million adjustment primarily related to the recalculation of 2010 U.K. earnings and profits, partially offset by $25 million from the U.K./U.S. intercompany tax transaction. |
The decrease in income taxes in 2011 compared with 2010 was due to a $41 million tax benefit resulting from changes in the taxable amount of planned U.K. cash repatriations, a tax benefit of $28 million from U.K. pension plan contributions and lower income taxes due to lower 2011 pre-tax income. These tax benefits were partially offset by $24 million of favorable 2010 adjustments to uncertain tax benefits primarily related to Windfall Profits Tax and $11 million of higher income taxes on interest income related to acquisition financing.
Foreign Currency Exchange Rates
· | Changes in foreign currency exchange rates negatively affected the segment's earnings for 2012 compared with 2011 and positively affected 2011 compared with 2010. The weighted-average exchange rates for the British pound sterling, including the effects of currency hedges, were approximately $1.58 in 2012, $1.61 in 2011, and $1.57 in 2010. |
The following after-tax gains (losses), which management considers special items, also impacted the U.K. Regulated segment's results.
| | | Income Statement | | | | | | | | | |
| | | Line Item | | 2012 | | 2011 | | 2010 |
Foreign currency-related economic hedges, net of tax of $18, ($2), $0 (a) | Other Income-net | | $ | (33) | | $ | 5 | | $ | 1 |
WPD Midlands acquisition-related adjustments: | | | | | | | | | | |
| 2011 Bridge Facility costs, net of tax of $0, $14, $0 (b) | Interest Expense | | | | | | (30) | | | |
| Foreign currency loss on 2011 Bridge Facility, net of tax of $0, $19, $0 (c) | Other Income-net | | | | | | (38) | | | |
| Net hedge gains, net of tax of $0, ($17), $0 (c) | Other Income-net | | | | | | 38 | | | |
| Hedge ineffectiveness, net of tax of $0, $3, $0 (d) | Interest Expense | | | | | | (9) | | | |
| U.K. stamp duty tax, net of tax of $0, $0, $0 (e) | Other Income-net | | | | | | (21) | | | |
| Separation benefits, net of tax of $4, $26, $0 (f) | Other O&M | | | (11) | | | (75) | | | |
| Other acquisition-related adjustments, net of tax of ($1), $20, $0 | (g) | | | 2 | | | (57) | | | |
Other: | | | | | | | | | | |
| Change in U.K. tax rate (h) | Income Taxes | | | 75 | | | 69 | | | 18 |
| Windfall profits tax litigation (i) | Income Taxes | | | | | | (39) | | | 12 |
| Line loss adjustment, net of tax of ($23), $0, $0 (j) | Utility Revenues | | | 74 | | | | | | |
Total | | | $ | 107 | | $ | (157) | | $ | 31 |
(a) | Represents unrealized gains (losses) on contracts that economically hedge anticipated earnings denominated in GBP. |
(b) | Represents fees incurred in connection with establishing the 2011 Bridge Facility. |
(c) | Represents the foreign currency loss on the repayment of the 2011 Bridge Facility, including a pre-tax foreign currency loss of $15 million associated with proceeds received on the U.S. dollar-denominated senior notes issued by PPL WEM in April 2011 that were used to repay a portion of PPL WEM's borrowing under the 2011 Bridge Facility. The foreign currency risk was economically hedged with forward contracts to purchase GBP, which resulted in pre-tax gains of $55 million. |
(d) | Represents a combination of ineffectiveness associated with closed out interest rate swaps and a charge recorded as a result of certain interest rate swaps failing hedge effectiveness testing. |
(e) | Tax on the transfer of ownership of property in the U.K., which is not tax deductible for income tax purposes. |
(f) | 2012 represents severance compensation and early retirement deficiency costs. 2011 primarily represents severance compensation, early retirement deficiency costs and outplacement services for employees separating from the WPD Midlands companies as a result of a reorganization to transition the WPD Midlands companies to the same operating structure as WPD (South West) and WPD (South Wales). 2011 also includes severance compensation and early retirement deficiency costs associated with certain employees who separated from the WPD Midlands companies, but were not part of the reorganization. |
(g) | 2011 primarily includes $34 million, pre-tax, of advisory, accounting and legal fees which are recorded in "Other Income (Expense) - net" on the Statement of Income; $37 million, pre-tax, of costs, primarily related to the termination of certain contracts, rebranding costs and relocation costs that were recorded to "Other operation and maintenance" expense on the Statement of Income; and $6 million, pre-tax, of costs associated with the integration of certain information technology assets, that were recorded in "Depreciation" on the Statement of Income. |
(h) | The U.K. Finance Act of 2012, enacted in July 2012, reduced the U.K. statutory income tax rate from 25% to 24% retroactive to April 1, 2012 and from 24% to 23% effective April 1, 2013. The U.K. Finance Act of 2011, enacted in July 2011, reduced the U.K. statutory income tax rate from 27% to 26% retroactive to April 1, 2011 and reduced the rate from 26% to 25% effective April 1, 2012. The U.K. Finance Act of 2010, enacted in July 2010, reduced the U.K. statutory income tax rate from 28% to 27% effective April 1, 2011. As a result, WPD reduced its net deferred tax liabilities and recognized deferred tax benefits in 2012, 2011 and 2010. WPD Midlands' portion of the deferred tax benefit was $43 million and $35 million for 2012 and 2011. |
(i) | In 2010, the U.S. Tax Court ruled in PPL's favor in a pending dispute with the IRS concluding that the 1997 U.K. Windfall Profits Tax (WPT) imposed on all U.K. privatized utilities, including PPL's U.K. subsidiary, is a creditable tax for U.S. Federal income tax purposes. As a result, PPL recorded an income tax benefit in 2010. In January 2011, the IRS appealed the U.S. Tax Court's decision to the U.S. Court of Appeals for the Third Circuit (Third Circuit). In December 2011, the Third Circuit issued its opinion reversing the Tax Court's decision and holding that the WPT is not a creditable tax. As a result of the Third Circuit's adverse determination, PPL recorded a $39 million expense in 2011. See Note 5 to the Financial Statements for information on 2012 activities related to this case, including the U.S. Supreme Court's decision to grant PPL's petition for a writ of certiorari to review the Third Circuit's opinion. |
(j) | In November 2012, Ofgem issued additional consultation on the final DPCR4 line loss close-out that published values for each DNO and further indicated the preferred methodology that would replace the methodology under WPD's licenses. Based on applying the preferred methodology for DPCR4, WPD Midlands reduced its line loss liability by $86 million, pre-tax. Ofgem also indicated that the line loss incentive implemented at the last rate review will be withdrawn and no incentive will apply for the DPCR5 period. As a result, WPD Midlands reduced their line loss accrual by $11 million, pre-tax. This represents WPD Midlands' portion of the adjustment as the original liability was primarily established through purchase accounting. |
2013 Outlook
Excluding special items, PPL projects higher segment earnings in 2013 compared with 2012, primarily driven by higher electricity delivery revenue and lower income taxes, partially offset by higher operation and maintenance, higher depreciation and higher interest expense.
Earnings in future periods are subject to various risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Notes 6 and 15 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.
Pennsylvania Regulated Segment
The Pennsylvania Regulated segment includes the regulated electric delivery operations of PPL Electric.
Net Income Attributable to PPL Shareowners includes the following results:
| | | 2012 | | 2011 | | % Change | | 2011 | | 2010 | | % Change |
Operating revenues | | | | | | | | | | | | | | | | |
| External | | $ | 1,760 | | $ | 1,881 | | (6) | | $ | 1,881 | | $ | 2,448 | | (23) |
| Intersegment | | | 3 | | | 11 | | (73) | | | 11 | | | 7 | | 57 |
| Total operating revenues | | | 1,763 | | | 1,892 | | (7) | | | 1,892 | | | 2,455 | | (23) |
Energy purchases | | | | | | | | | | | | | | | | |
| External | | | 550 | | | 738 | | (25) | | | 738 | | | 1,075 | | (31) |
| Intersegment | | | 78 | | | 26 | | 200 | | | 26 | | | 320 | | (92) |
Other operation and maintenance | | | 576 | | | 530 | | 9 | | | 530 | | | 502 | | 6 |
Amortization of recoverable transition costs | | | | | | | | n/a | | | | | | | | n/a |
Depreciation | | | 160 | | | 146 | | 10 | | | 146 | | | 136 | | 7 |
Taxes, other than income | | | 105 | | | 104 | | 1 | | | 104 | | | 138 | | (25) |
| Total operating expenses | | | 1,469 | | | 1,544 | | (5) | | | 1,544 | | | 2,171 | | (29) |
Other Income (Expense) - net | | | 9 | | | 7 | | 29 | | | 7 | | | 7 | | - |
Interest Expense | | | 99 | | | 98 | | 1 | | | 98 | | | 99 | | (1) |
Income Taxes | | | 68 | | | 68 | | - | | | 68 | | | 57 | | 19 |
Net Income | | | 136 | | | 189 | | (28) | | | 189 | | | 135 | | 40 |
Net Income Attributable to Noncontrolling Interests (Note 3) | | | 4 | | | 16 | | (75) | | | 16 | | | 20 | | (20) |
Net Income Attributable to PPL Shareowners | | $ | 132 | | $ | 173 | | (24) | | $ | 173 | | $ | 115 | | 50 |
The changes in the components of the Pennsylvania Regulated segment's results between these periods were due to the following factors, which reflect reclassifications for items included in Pennsylvania Gross Delivery Margins.
| | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | |
Pennsylvania Gross Delivery Margins | | $ | 19 | | $ | 66 |
Other operation and maintenance | | | (50) | | | 4 |
Depreciation | | | (14) | | | (10) |
Taxes, other than income | | | (9) | | | 4 |
Other | | | 1 | | | 1 |
Income Taxes | | | | | | (11) |
Noncontrolling Interests | | | 12 | | | 4 |
Total | | $ | (41) | | $ | 58 |
· | See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Pennsylvania Gross Delivery Margins. |
· | Higher other operation and maintenance for 2012 compared with 2011, primarily due to $17 million in higher payroll-related costs due to less project costs being capitalized in 2012, higher support group costs of $11 million and $10 million for increased vegetation management. |
· | Higher depreciation for 2012 compared with 2011 and 2011 compared with 2010 primarily due to PP&E additions. |
· | Higher taxes, other than income for 2012 primarily due to a $10 million tax provision related to gross receipts tax. |
· | Income taxes were flat in 2012 compared with 2011 primarily due to the $22 million impact of lower 2012 pre-tax income primarily offset by $9 million of depreciation not normalized and $9 million of income tax return adjustments, largely related to changes in flow-through regulated tax depreciation. |
| Income taxes were higher in 2011 compared with 2010, due to the $26 million impact of higher 2011 pre-tax income, partially offset by a $14 million tax benefit related to changes in flow-through regulated tax depreciation. |
· | Lower noncontrolling interests in 2012 compared with 2011 due to PPL Electric's redemption of preference securities in June 2012. |
2013 Outlook
PPL projects higher segment earnings in 2013 compared with 2012, due to higher distribution revenues from a distribution base rate increase effective January 1, 2013, and higher transmission margins, partially offset by higher depreciation.
Earnings in future periods are subject to various risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Notes 6 and 15 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.
Supply Segment
The Supply segment primarily consists of the energy marketing and trading activities, as well as the competitive generation and development operations of PPL Energy Supply. In 2011 and 2010, PPL Energy Supply subsidiaries completed the sale of several businesses, which have been classified as Discontinued Operations. See Note 9 to the Financial Statements for additional information.
Net Income Attributable to PPL Shareowners includes the following results:
| | | 2012 | | 2011 | | % Change | | 2011 | | 2010 | | % Change |
Energy revenues | | | | | | | | | | | | | | | | |
| External (a) | | $ | 4,970 | | $ | 5,938 | | (16) | | $ | 5,938 | | $ | 4,444 | | 34 |
| Intersegment | | | 79 | | | 26 | | 204 | | | 26 | | | 320 | | (92) |
Energy-related businesses | | | 461 | | | 472 | | (2) | | | 472 | | | 375 | | 26 |
| Total operating revenues | | | 5,510 | | | 6,436 | | (14) | | | 6,436 | | | 5,139 | | 25 |
Fuel (a) | | | 965 | | | 1,080 | | | | | 1,080 | | | 1,096 | | |
Energy Purchases | | | | | | | | | | | | | | | | |
| External (a) | | | 1,810 | | | 2,277 | | (21) | | | 2,277 | | | 1,344 | | 69 |
| Intersegment | | | 2 | | | 4 | | (50) | | | 4 | | | 3 | | 33 |
Other operation and maintenance | | | 1,032 | | | 882 | | 17 | | | 882 | | | 934 | | (6) |
Depreciation | | | 315 | | | 262 | | 20 | | | 262 | | | 254 | | 3 |
Taxes, other than income | | | 68 | | | 72 | | (6) | | | 72 | | | 46 | | 57 |
Energy-related businesses | | | 450 | | | 467 | | (4) | | | 467 | | | 366 | | 28 |
| Total operating expenses | | | 4,642 | | | 5,044 | | (8) | | | 5,044 | | | 4,043 | | 25 |
Other Income (Expense) - net | | | 18 | | | 43 | | (58) | | | 43 | | | (9) | | (578) |
Other-Than-Temporary Impairments | | | 2 | | | 6 | | (67) | | | 6 | | | 3 | | 100 |
Interest Expense | | | 222 | | | 192 | | 16 | | | 192 | | | 224 | | (14) |
Income Taxes | | | 247 | | | 463 | | (47) | | | 463 | | | 228 | | 103 |
Income (Loss) from Discontinued Operations | | | | | | 3 | | (100) | | | 3 | | | (19) | | (116) |
Net Income | | | 415 | | | 777 | | (47) | | | 777 | | | 613 | | 27 |
Net Income Attributable to Noncontrolling Interests | | | 1 | | | 1 | | | | | 1 | | | 1 | | |
Net Income Attributable to PPL Shareowners | | $ | 414 | | $ | 776 | | (47) | | $ | 776 | | $ | 612 | | 27 |
(a) | Includes the impact from energy-related economic activity. See "Commodity Price Risk (Non-trading) - Economic Activity" in Note 19 to the Financial Statements for additional information. |
The changes in the components of the Supply segment's results between these periods were due to the following factors, which reflect reclassifications for items included in Unregulated Gross Energy Margins and certain items that management considers special. See additional detail of these special items in the table below.
| | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | |
Unregulated Gross Energy Margins | | $ | (197) | | $ | (405) |
Other operation and maintenance | | | (91) | | | (63) |
Depreciation | | | (53) | | | (8) |
Taxes, other than income | | | 8 | | | (10) |
Other Income (Expense) - net | | | (26) | | | 22 |
Interest Expense | | | (20) | | | (12) |
Other | | | 5 | | | (4) |
Income Taxes | | | 136 | | | 107 |
Discontinued operations, after-tax - excluding certain revenues and expenses included in margins | | | | | | 17 |
Special items, after-tax | | | (124) | | | 520 |
Total | | $ | (362) | | $ | 164 |
· | See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Unregulated Gross Energy Margins. |
· | Higher other operation and maintenance in 2012 compared with 2011 due to higher costs at PPL Susquehanna of $27 million including refueling outage costs, payroll-related costs and project costs, $18 million due to the Ironwood Acquisition, $13 million due to eastern fossil and hydroelectric unit outages, $11 million of higher pension expense and $10 million of higher charges from support groups. |
Higher other operation and maintenance in 2011 compared with 2010 primarily due to higher costs at PPL Susquehanna of $27 million largely due to unplanned outages, the refueling outage and payroll-related costs, $23 million higher costs at eastern fossil and hydroelectric units largely due to outages, and $12 million higher net costs at western fossil and hydroelectric units, largely resulting from insurance recoveries received in 2010.
· | Higher depreciation in 2012 compared with 2011 primarily due to a $24 million impact from PP&E additions and $17 million due to the Ironwood Acquisition. |
· | Lower taxes other than income in 2012 compared with 2011 primarily due to lower capital stock tax. |
| Higher taxes other than income in 2011 compared with 2010 primarily due to higher capital stock tax. |
· | Lower other income (expense) - net in 2012 compared with 2011 and higher other income (expense) - net in 2011 compared with 2010 primarily due to a $22 million gain on the July 2011 redemption of Senior Secured Bonds. |
· | Higher interest expense in 2012 compared with 2011 primarily due to hedging activity, which increased interest expense by $30 million and $12 million related to the debt assumed as a result of the Ironwood Acquisition, partially offset by $11 million of lower interest on short-term borrowings and $4 million of higher capitalized interest. |
| Higher interest expense in 2011 compared with 2010 of $13 million primarily due to hedging activity and $8 million due to short-term borrowings, partially offset by $15 million of higher capitalized interest. |
· | Lower income taxes in 2012 compared with 2011 due to lower 2012 pre-tax income, which reduced income taxes by $151 million and $23 million related to lower adjustments to valuation allowances on Pennsylvania net operating losses, partially offset by $21 million related to the impact of prior period tax return adjustments. |
Lower income taxes in 2011 compared with 2010 due to lower 2011 pre-tax income, which reduced taxes by $204 million and a $26 million reduction in deferred tax liabilities related to an updated blended state tax rate resulting from a change in state tax apportionment. These decreases were partially offset by $101 million related to adjustments to valuation allowances on Pennsylvania net operating losses, $16 million in favorable adjustments to uncertain tax benefits recorded in 2010 and an $11 million decrease in the domestic manufacturing deduction resulting from revised bonus depreciation estimates.
The following after-tax gains (losses), which management considers special items, also impacted the Supply segment's results.
| | | Income Statement | | | | | | | | | |
| | | Line Item | | 2012 | | 2011 | | 2010 |
| | | | | | | | | | |
Adjusted energy-related economic activity, net, net of tax of ($26), ($52), $85 | (a) | | $ | 38 | | $ | 72 | | $ | (121) |
Sales of assets: | | | | | | | | | | |
| Maine hydroelectric generation business, net of tax of $0, $0, ($9) (b) | Disc. Operations | | | | | | | | | 15 |
| Sundance indemnification, net of tax of $0, $0, $0 | Other Income-net | | | | | | | | | 1 |
Impairments: | | | | | | | | | | |
| Emission allowances, net of tax of $0, $1, $6 (c) | Other O&M | | | | | | (1) | | | (10) |
| Renewable energy credits, net of tax of $0, $2, $0 | Other O&M | | | | | | (3) | | | |
| Adjustments - nuclear decommissioning trust investments, net of tax of ($2), $0, $0 | Other Income-net | | | 2 | | | | | | |
| Other asset impairments, net of tax of $0, $0, $0 | Other O&M | | | (1) | | | | | | |
LKE acquisition-related adjustments: | | | | | | | | | | |
| Monetization of certain full-requirement sales contracts, net of tax of $0, $0, $89 | (d) | | | | | | | | | (125) |
| Sale of certain non-core generation facilities, net of tax of $0, $0, $37 (e) | Disc. Operations | | | | | | (2) | | | (64) |
| Discontinued cash flow hedges and ineffectiveness, net of tax of $0, $0, $15 (f) | Other Income-net | | | | | | | | | (28) |
| Reduction of credit facility, net of tax of $0, $0, $4 (g) | Interest Expense | | | | | | | | | (6) |
Other: | | | | | | | | | | |
| Montana hydroelectric litigation, net of tax of $0, ($30), $22 | (h) | | | | | | 45 | | | (34) |
| Litigation settlement - spent nuclear fuel storage, net of tax of $0, ($24), $0 (i) | Fuel | | | | | | 33 | | | |
| Health care reform - tax impact (j) | Income Taxes | | | | | | | | | (8) |
| Montana basin seepage litigation, net of tax of $0, $0, ($1) | Other O&M | | | | | | | | | 2 |
| Counterparty bankruptcy, net of tax of $5, $5, $0 (k) | Other O&M | | | (6) | | | (6) | | | |
| Wholesale supply cost reimbursement, net of tax of $0, ($3), $0 | (l) | | | 1 | | | 4 | | | |
| Ash basin leak remediation adjustment, net of tax of ($1), $0, $0 | Other O&M | | | 1 | | | | | | |
| Coal contract modification payments, net of tax of $12, $0, $0 (m) | Fuel | | | (17) | | | | | | |
Total | | | $ | 18 | | $ | 142 | | $ | (378) |
(a) | See "Reconciliation of Economic Activity" below. |
(b) | Gains recorded on the completion of the sale of the Maine hydroelectric generation business. See Note 9 to the Financial Statements for additional information. |
(c) | Primarily represents impairment charges of sulfur dioxide emission allowances. |
(d) | In July 2010, in order to raise additional cash for the LKE acquisition, certain full-requirement sales contracts were monetized that resulted in cash proceeds of $249 million. See "Monetization of Certain Full-Requirement Sales Contracts" in Note 19 to the Financial Statements for additional information. $343 million of pre-tax gains were recorded to "Wholesale energy marketing" and $557 million of pre-tax losses were recorded to "Energy purchases" on the Statement of Income. |
(e) | Consists primarily of the initial impairment charge recorded when the business was classified as held for sale. See Note 9 to the Financial Statements for additional information. |
(f) | As a result of the expected net proceeds from the anticipated sale of certain non-core generation facilities, coupled with the monetization of certain full-requirement sales contracts, debt that had been planned to be issued by PPL Energy Supply in 2010 was no longer needed. As a result, hedge accounting associated with interest rate swaps entered into by PPL in anticipation of a debt issuance by PPL Energy Supply was discontinued. |
(g) | In October 2010, PPL Energy Supply made borrowings under its Syndicated Credit Facility in order to enable a subsidiary to make loans to certain affiliates to provide interim financing of amounts required by PPL to partially fund PPL's acquisition of LKE. Subsequent to the repayment of such borrowing, the capacity was reduced, and as a result, PPL Energy Supply wrote off deferred fees in 2010. |
(h) | In March 2010, the Montana Supreme Court substantially affirmed a June 2008 Montana District Court decision regarding lease payments for the use of certain Montana streambeds. In 2010, PPL Montana recorded a pre-tax charge of $56 million, representing estimated rental compensation for years prior to 2010, including interest. Of this total charge $47 million, pre-tax, was recorded to "Other operation and maintenance" and $9 million, pre-tax, was recorded to "Interest Expense" on the Statement of Income. In August 2010, PPL Montana filed a petition for a writ of certiorari with the U.S. Supreme Court requesting the Court's review of this matter. In June 2011, the U.S. Supreme Court granted PPL Montana's petition. In February 2012, the U.S. Supreme Court overturned the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion. Prior to the U.S. Supreme Court decision, $4 million, pre-tax, of interest expense on the rental compensation covered by the court decision was accrued in 2011. As a result of the U.S. Supreme Court decision, PPL Montana reversed its total pre-tax loss accrual of $89 million, which had been recorded prior to the U.S. Supreme Court decision, of which $79 million pre-tax is considered a special item because it represented $65 million of rent for periods prior to 2011 and $14 million of interest accrued on the portion covered by the prior court decision. These amounts were credited to "Other operation and maintenance" and "Interest Expense" on the Statement of Income. See Note 15 to the Financial Statements for additional information. |
(i) | In May 2011, PPL Susquehanna entered into a settlement agreement with the U.S. Government relating to PPL Susquehanna's lawsuit, seeking damages for the Department of Energy's failure to accept spent nuclear fuel from the PPL Susquehanna plant. PPL Susquehanna recorded credits to fuel expense to recognize recovery, under the settlement agreement, of certain costs to store spent nuclear fuel at the Susquehanna plant. This special item represents amounts recorded |
(b) | Amounts included in 2011 to cover the costs incurred from 1998 through December 2010."Margins" and are not discussed separately. |
(j) | Represents income tax expense recorded as a result of the provisions within Health Care Reform which eliminated the tax deductibility of retiree health care costs |
(c) | Amounts for prior years have been reclassified to conform to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D Coverage. |
(k) | In October 2011, a wholesale customer, SMGT, filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy code. In 2012, PPL EnergyPlus recorded an additional allowance for unpaid amounts under the long-term power contract. In March 2012, the U.S. Bankruptcy Court for the District of Montana approved the request to terminate the contract, effective Aprilcurrent presentation. See "Reclassifications" in Note 1 2012. |
(l) | In January 2012, PPL received $7 million pre-tax, related to electricity delivered to a wholesale customer in 2008 and 2009, recorded in "Wholesale energy marketing-Realized." The additional revenue results from several transmission projects approved at PJM for recovery that were not initially anticipated at the time of the electricity auctions and therefore were not included in the auction pricing. A FERC order was issued in 2011 approving the disbursement of these supply costs by the wholesale customer to the suppliers, therefore, PPL accrued its share of this additional revenue in 2011. |
(m) | As a result of lower electricity and natural gas prices, coal-fired generation output decreased during 2012. Contract modification payments were incurred to reduce 2012 and 2013 contracted coal deliveries. |
Reconciliation of Economic Activity
The following table reconciles unrealized pre-tax gains (losses) from the table within "Commodity Price Risk (Non-trading) - Economic Activity" in Note 19 to the Financial Statements to the special item identified as "Adjusted energy-related economic activity, net."
| | | | 2012 | | 2011 | | 2010 |
Operating Revenues | | | | | | | | | |
| | Unregulated retail electric and gas | | $ | (17) | | $ | 31 | | $ | 1 |
| | Wholesale energy marketing | | | (311) | | | 1,407 | | | (805) |
Operating Expenses | | | | | | | | | |
| | Fuel | | | (14) | | | 6 | | | 29 |
| | Energy Purchases | | | 442 | | | (1,123) | | | 286 |
Energy-related economic activity (a) | | | 100 | | | 321 | | | (489) |
Option premiums (b) | | | (1) | | | 19 | | | 32 |
Adjusted energy-related economic activity | | | 99 | | | 340 | | | (457) |
Less: Unrealized economic activity associated with the monetization of certain | | | | | | | | | |
| full-requirement sales contracts in 2010 (c) | | | | | | | | | (251) |
Less: Economic activity realized, associated with the monetization of certain | | | | | | | | | |
| full-requirement sales contracts in 2010 | | | 35 | | | 216 | | | |
Adjusted energy-related economic activity, net, pre-tax | | $ | 64 | | $ | 124 | | $ | (206) |
| | | | | | | | | | | |
Adjusted energy-related economic activity, net, after-tax | | $ | 38 | | $ | 72 | | $ | (121) |
(a) | See Note 19 to the Financial Statements for additional information. |
(b) | Adjustment for the net deferral and amortization of option premiums over the delivery period of the item that was hedged or upon realization. Option premiums are recorded in "Wholesale energy marketing - Realized" and "Energy purchases - Realized" on the Statements of Income. |
(c) | See "Components of Monetization of Certain Full-Requirement Sales Contracts" below. |
Components of Monetization of Certain Full-Requirement Sales Contracts
The following table provides the components of the "Monetization of Certain Full-Requirement Sales Contracts" special item.
| | 2010 |
| | | |
Full-requirement sales contracts monetized (a) | | $ | (68) |
Economic activity related to the full-requirement sales contracts monetized | | | (146) |
Monetization of certain full-requirement sales contracts, pre-tax (b) | | $ | (214) |
| | | |
Monetization of certain full-requirement sales contracts, after-tax | | $ | (125) |
(a) | See "Commodity Price Risk (Non-trading) - Monetization of Certain Full-Requirement Sales Contracts" in Note 19 to the Financial Statements for additional information. |
(b) | Includes unrealized losses of $251 million, which are reflected in "Wholesale energy marketing - Unrealized economic activity" and "Energy purchases - Unrealized economic activity" on the Statement of Income. Also includes net realized gains of $37 million, which are reflected in "Wholesale energy marketing - Realized" and "Energy purchases - Realized" on the Statement of Income. |
2013 Outlook
Excluding special items, PPL projects lower segment earnings in 2013 compared with 2012, primarily driven by lower energy prices, higher fuel costs, higher operation and maintenance, higher depreciation and higher financing costs, which are partially offset by higher capacity prices and higher nuclear generation output despite scheduled outages for both Susquehanna units to implement a long-term solution to turbine blade issues.
Earnings in future periods are subject to various risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Note 15 to the Financial Statementsbelow for a discussion of the risks, uncertainties and factors that may impact future earnings.
Statementcomponents of the changes to Net Income Analysis --
Margins
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance with GAAP, as well as three non-GAAP financial measures: "Kentucky Gross Margins," "Pennsylvania Gross Delivery Margins" and "Unregulated Gross Energy Margins." These measures are not intended to replace "Operating Income," which is determined in accordance with GAAP, as an indicator of overall operating performance. Other companies may use different measures to analyze and to report on the results of their operations. PPL believes that these measures provide additional criteria to make investment decisions. These performance measures are used, in conjunction with other information, internally by senior management and the Board of Directors to manage the Kentucky Regulated, Pennsylvania Regulated and Supply segment operations, analyze each respective segment's actual results compared with budget and, in certain cases, to measure certain corporate financial goals used in determining variable compensation.
PPL's three non-GAAP financial measures include:
· | "Kentucky Gross Margins" is a single financial performance measure of the Kentucky Regulated segment's electricity generation, transmission and distribution operations as well as its distribution and sale of natural gas. In calculating this measure, fuel and energy purchases are deducted from revenues. In addition, utility revenues and expenses associated with approved cost recovery mechanisms are offset. These mechanisms allow for recovery of certain expenses, returns on capital investments primarily associated with environmental regulations and performance incentives. Certain costs associated with these mechanisms, primarily ECR and DSM, are recorded as "Other operation and maintenance" and "Depreciation." As a result, this measure represents the net revenues from the Kentucky Regulated segment's operations. |
· | "Pennsylvania Gross Delivery Margins" is a single financial performance measure of the Pennsylvania Regulated segment's electric delivery operations, which includes transmission and distribution activities. In calculating this measure, utility revenues and expenses associated with approved recovery mechanisms, including energy provided as a PLR, are offset with minimal impact on earnings. Costs associated with these mechanisms are recorded in "Energy purchases," "Other operation and maintenance," which is primarily Act 129 costs, and "Taxes, other than income," which is primarily gross receipts tax. This performance measure includes PLR energy purchases by PPL Electric from PPL EnergyPlus, which are reflected in "PLR intersegment utility revenue (expense)" in the table below. As a result, this measure represents the net revenues from the Pennsylvania Regulated segment's electric delivery operations. |
· | "Unregulated Gross Energy Margins" is a single financial performance measure of the Supply segment's competitive energy non-trading and trading activities. In calculating this measure, the Supply segment's energy revenues, which include operating revenues associated with certain Supply segment businesses that are classified as discontinued operations, are offset by the cost of fuel, energy purchases, certain other operation and maintenance expenses, primarily ancillary charges, gross receipts tax, which is recorded in "Taxes, other than income," and operating expenses associated with certain Supply segment businesses that are classified as discontinued operations. This performance measure is relevant to PPL due to the volatility in the individual revenue and expense lines on the Statements of Income that comprise "Unregulated Gross Energy Margins." This volatility stems from a number of factors, including the required netting of certain transactions with ISOs and significant fluctuations in unrealized gains and losses. Such factors could result in gains or losses being recorded in either "Wholesale energy marketing" or "Energy purchases" on the Statements of Income. This performance measure includes PLR revenues from energy sales to PPL Electric by PPL EnergyPlus, which are recorded in "PLR intersegment utility revenue (expense)" in the table below. PPL excludes from "Unregulated Gross Energy Margins" the Supply segment's adjusted energy-related economic activity, which includes the changes in fair value of positions used to economically hedge a portion of the economic value of PPL's competitive generation assets, full-requirement sales contracts and retail activities. This economic value is subject to changes in fair value due to market price volatility of the input and output commodities (e.g., fuel and power) prior to the delivery period that was hedged. Also included in adjusted energy-related economic activity is the ineffective portion of qualifying cash flow hedges, the monetization of certain full-requirement sales contracts and premium amortization associated with options. This economic activity is deferred, with the exception of the full-requirement sales contracts that were monetized, and included in Unregulated Gross Energy Margins over the delivery period that was hedged or upon realization. |
Reconciliation of Non-GAAP Financial Measures |
The following tables reconcile "Operating Income" to PPL's three non-GAAP financial measures.
| | | | | 2012 | | 2011 |
| | | | | | | | | | Unregulated | | | | | | | | | | | | | Unregulated | | | | | | | |
| | | | | Kentucky | | PA Gross | | Gross | | | | | | | | Kentucky | | PA Gross | | Gross | | | | | | |
| | | | | Gross | | Delivery | | Energy | | | | | Operating | | Gross | | Delivery | | Energy | | | | | | Operating |
| | | | | Margins | | Margins | | Margins | | Other (a) | | Income (b) | | Margins | | Margins | | Margins | | Other (a) | | Income (b) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Operating Revenues | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Utility | $ | 2,759 | | $ | 1,760 | | | | | $ | 2,289 | (d) | | $ | 6,808 | | $ | 2,791 | | $ | 1,881 | | | | | $ | 1,620 | (d) | | $ | 6,292 |
| PLR intersegment utility | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | revenue (expense) (e) | | | | | (78) | | $ | 78 | | | | | | | | | | | | | (26) | | $ | 26 | | | | | | | |
| Unregulated retail | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | electric and gas | | | | | | | | 865 | | | (21) | (g) | | | 844 | | | | | | | | | 696 | | | 30 | (g) | | | 726 |
| Wholesale energy marketing | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Realized | | | | | | | | 4,412 | | | 21 | (f) | | | 4,433 | | | | | | | | | 3,745 | | | 62 | (f) | | | 3,807 |
| | | Unrealized economic | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | activity | | | | | | | | | | | (311) | (g) | | | (311) | | | | | | | | | | | | 1,407 | (g) | | | 1,407 |
| Net energy trading margins | | | | | | | | 4 | | | | | | | 4 | | | | | | | | | (2) | | | | | | | (2) |
| Energy-related businesses | | | | | | | | | | | 508 | | | | 508 | | | | | | | | | | | | 507 | | | | 507 |
| | | Total Operating Revenues | | 2,759 | | | 1,682 | | | 5,359 | | | 2,486 | | | | 12,286 | | | 2,791 | | | 1,855 | | | 4,465 | | | 3,626 | | | | 12,737 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Operating Expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fuel | | 872 | | | | | | 931 | | | 34 | (h) | | | 1,837 | | | 866 | | | | | | 1,151 | | | (71) | (h) | | | 1,946 |
| Energy purchases | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Realized | | 195 | | | 550 | | | 2,204 | | | 48 | (f) | | | 2,997 | | | 238 | | | 738 | | | 912 | | | 242 | (f) | | | 2,130 |
| | | Unrealized economic | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | activity | | | | | | | | | | | (442) | (g) | | | (442) | | | | | | | | | | | | 1,123 | (g) | | | 1,123 |
| Other operation and | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | maintenance | | 101 | | | 104 | | | 19 | | | 2,611 | | | | 2,835 | | | 90 | | | 108 | | | 16 | | | 2,453 | | | | 2,667 |
| Depreciation | | 51 | | | | | | | | | 1,049 | | | | 1,100 | | | 49 | | | | | | | | | 911 | | | | 960 |
| Taxes, other than income | | | | | 91 | | | 34 | | | 241 | | | | 366 | | | | | | 99 | | | 30 | | | 197 | | | | 326 |
| Energy-related businesses | | | | | | | | | | | 484 | | | | 484 | | | | | | | | | | | | 484 | | | | 484 |
| Intercompany eliminations | | | | | (3) | | | 3 | | | | | | | | | | | | | (11) | | | 3 | | | 8 | | | | |
| | | Total Operating Expenses | | 1,219 | | | 742 | | | 3,191 | | | 4,025 | | | | 9,177 | | | 1,243 | | | 934 | | | 2,112 | | | 5,347 | | | | 9,636 |
| Discontinued operations | | | | | | | | | | | | | | | | | | | | | | | | 12 | | | (12) | (i) | | | |
Total | $ | 1,540 | | $ | 940 | | $ | 2,168 | | $ | (1,539) | | | $ | 3,109 | | $ | 1,548 | | $ | 921 | | $ | 2,365 | | $ | (1,733) | | | $ | 3,101 |
| | | | | 2010 | | |
| | | | | | | | | | Unregulated | | | | | | | | | | | | | | | | | | | | |
| | | | | Kentucky | | PA Gross | | Gross | | | | | | | | | | | | | | | | | | |
| | | | | Gross | | Delivery | | Energy | | | | | Operating | | | | | | | | | | | | |
| | | | | Margins (c) | | Margins | | Margins | | Other (a) | | Income (b) | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Operating Revenues | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Utility | | | | $ | 2,448 | | | | | $ | 1,220 | (d) | | $ | 3,668 | | | | | | | | | | | | | | | | |
| PLR intersegment utility | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | revenue (expense) (e) | | | | | (320) | | $ | 320 | | | | | | | | | | | | | | | | | | | | | | | |
| Unregulated retail | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | electric and gas | | | | | | | | 414 | | | 1 | | | | 415 | | | | | | | | | | | | | | | | |
| Wholesale energy marketing | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Realized | | | | | | | | 4,511 | | | 321 | (f) | | | 4,832 | | | | | | | | | | | | | | | | |
| | | Unrealized economic | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | activity | | | | | | | | | | | (805) | (g) | | | (805) | | | | | | | | | | | | | | | | |
| Net energy trading margins | | | | | | | | 2 | | | | | | | 2 | | | | | | | | | | | | | | | | |
| Energy-related businesses | | | | | | | | | | | 409 | | | | 409 | | | | | | | | | | | | | | | | |
| | | Total Operating Revenues | | | | | 2,128 | | | 5,247 | | | 1,146 | | | | 8,521 | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Operating Expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | | | | | | 1,132 | | | 103 | (h) | | | 1,235 | | | | | | | | | | | | | | | | |
| Energy purchases | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Realized | | | | | 1,075 | | | 1,389 | | | 309 | (f) | | | 2,773 | | | | | | | | | | | | | | | | |
| | | Unrealized economic | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | activity | | | | | | | | | | | (286) | (g) | | | (286) | | | | | | | | | | | | | | | | |
| Other operation and | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | maintenance | | | | | 76 | | | 23 | | | 1,657 | | | | 1,756 | | | | | | | | | | | | | | | | |
| Amortization of recoverable | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | transition costs | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Depreciation | | | | | | | | | | | 556 | | | | 556 | | | | | | | | | | | | | | | | |
| Taxes, other than income | | | | | 129 | | | 14 | | | 95 | | | | 238 | | | | | | | | | | | | | | | | |
| Energy-related businesses | | | | | | | | | | | 383 | | | | 383 | | | | | | | | | | | | | | | | |
| Intercompany eliminations | | | | | (7) | | | 3 | | | 4 | | | | | | | | | | | | | | | | | | | | |
| | | Total Operating Expenses | | | | | 1,273 | | | 2,561 | | | 2,821 | | | | 6,655 | | | | | | | | | | | | | | | | |
| Discontinued operations | | | | | | | | 84 | | | (84) | (i) | | | | | | | | | | | | | | | | | | | |
Total | | | | $ | 855 | | $ | 2,770 | | $ | (1,759) | | | $ | 1,866 | | | | | | | | | | | | | | | | |
(a) | Represents amounts excluded from Margins. |
(b) | As reported on the Statements of Income. |
(c) | LKE was acquired on November 1, 2010. Kentucky Gross Margins were not used to measure the financial performance of the Kentucky Regulated segment in 2010. |
(d) | Primarily represents WPD's utility revenue. 2010 also includes LKE's utility revenues(Loss) for the two-month period subsequent to the November 1, 2010 acquisition. |
(e) | Primarily related to PLR supply sold by PPL EnergyPlus to PPL Electric. |
(f) | Represents energy-related economic activity as described in "Commodity Price Risk (Non-trading) - Economic Activity" within Note 19 to the Financial Statements. For 2012, "Wholesale energy marketing - Realized" and "Energy purchases - Realized" include a net pre-tax loss of $35 million related to the monetization of certain full-requirement sales contracts. 2011 includes a net pre-tax loss of $216 million related to the monetization of certain full-requirement sales contracts and a net pre-tax gain of $19 million related to the amortization of option premiums. 2010 includes a net pre-tax gain of $37 million related to the monetization of certain full-requirement sales contracts and a net pre-tax gain of $32 million related to the amortization of option premiums. |
(g) | Represents energy-related economic activity, which is subject to fluctuations in value due to market price volatility, as described in "Commodity Price Risk (Non-trading) - Economic Activity" within Note 19 to the Financial Statements. |
(h) | Includes economic activity related to fuel as described in "Commodity Price Risk (Non-trading) - Economic Activity" within Note 19 to the Financial Statements. 2012 includes a net pre-tax loss of $29 million related to coal contract modification payments. 2011 includes pre-tax credits of $57 million for the spent nuclear fuel litigation settlement. |
(i) | Represents the net of certain revenues and expenses associated with certain businesses that are classified as discontinued operations. These revenues and expenses are not reflected in "Operating Income" on the Statements of Income. |
Changes in Non-GAAP Financial Measures
The following table shows PPL's three non-GAAP financial measures, as well as the change between periods. The factors that gave rise to the changes are described below the table.
| | | 2012 | | 2011 | | Change | | 2011 | | 2010 | | Change |
| | | | | | | | | | | | | | | | | | | |
Kentucky Gross Margins (a) | | $ | 1,540 | | $ | 1,548 | | $ | (8) | | $ | 1,548 | | | | | $ | 1,548 |
| | | | | | | | | | | | | | | | | | | |
PA Gross Delivery Margins by Component | | | | | | | | | | | | | | | | | | |
| Distribution | | $ | 730 | | $ | 741 | | $ | (11) | | $ | 741 | | $ | 679 | | $ | 62 |
| Transmission | | | 210 | | | 180 | | | 30 | | | 180 | | | 176 | | | 4 |
Total | | $ | 940 | | $ | 921 | | $ | 19 | | $ | 921 | | $ | 855 | | $ | 66 |
| | | | | | | | | | | | | | | | | | | |
Unregulated Gross Energy Margins by Region | | | | | | | | | | | | | | | | | | |
Non-trading | | | | | | | | | | | | | | | | | | |
| Eastern U.S. | | $ | 1,865 | | $ | 2,018 | | $ | (153) | | $ | 2,018 | | $ | 2,429 | | $ | (411) |
| Western U.S. | | | 299 | | | 349 | | | (50) | | | 349 | | | 339 | | | 10 |
Net energy trading | | | 4 | | | (2) | | | 6 | | | (2) | | | 2 | | | (4) |
Total | | $ | 2,168 | | $ | 2,365 | | $ | (197) | | $ | 2,365 | | $ | 2,770 | | $ | (405) |
(a) | LKE was acquired on November 1, 2010. Kentucky Gross Margins were not used to measure the financial performance of the Kentucky Regulated segment in 2010. |
Kentucky Gross Margins
Margins decreased in 2012 compared with 2011, primarily due to $6 million of lower wholesale margins, resulting from lower market prices. Retail margins were $2 million lower, as volumes were impacted by unseasonably mild weather during the first four months of 2012. Total heating degree days decreased 11% compared to 2011, partially offset by a 6% increase in cooling degree days.
PPL acquired LKE on November 1, 2010. Margins for 2011 are included in PPL's results without comparable amounts for 2010.
Pennsylvania Gross Delivery Margins
Distribution
Margins decreased in 2012 compared with 2011, primarily due to a $14 million unfavorable effect of mild weather early in 2012Net Income (Loss) and lower revenue applicable to certain energy-related costs of $3 million due to fewer PLR customers in 2012, partially offset by a $7 million charge recorded in 2011 to reduce a portion of the transmission service charge regulatory asset associated with a 2005 undercollection that was not included in any subsequent rate reconciliations filed with the PUC.
Margins increased in 2011 compared with 2010, largely due to the PPL Electric distribution rate case which increased rates by approximately 1.6% effective January 1, 2011, resulting in improved residential distribution margins of $68 million. Additionally, residential volume variances increased margins by an additional $4 million in 2011, compared with 2010, offset by unfavorable weather of $3 million for residential customers in 2011 compared with 2010. Lastly, lower demand charges and increased efficiency as a result of Act 129 programs resulted in a $5 million decrease in margins for commercial and industrial customers.
Transmission
Margins increased in 2012 compared with 2011, primarily due to increased investment in plant and the recovery of additional costs through the FERC formula-based rates.
Unregulated Gross Energy Margins | | | | | | |
| | | | | | |
Eastern U.S. | | | | | | |
| | | | | | |
The changes in Eastern U.S. non-trading margins were: |
| | | | | | |
| | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | |
Baseload energy prices | | $ | (121) | | $ | (109) |
Baseload capacity prices | | | (37) | | | (90) |
Intermediate and peaking capacity prices | | | (17) | | | (58) |
Full-requirement sales contracts (a) | | | (15) | | | 70 |
Impact of non-core generation facilities sold in the first quarter of 2011 | | | (12) | | | (48) |
Higher nuclear fuel prices | | | (12) | | | (10) |
Net economic availability of coal and hydroelectric units (b) | | | (10) | | | (72) |
Higher coal prices | | | (2) | | | (40) |
Nuclear generation volume (c) | | | | | | (29) |
Intermediate and peaking Spark Spreads | | | 11 | | | 24 |
Retail electric | | | 15 | | | (7) |
Ironwood Acquisition, which eliminated tolling expense (d) | | | 41 | | | |
Monetization of certain deals that rebalanced the business and portfolio | | | | | | (41) |
Other | | | 6 | | | (1) |
| | $ | (153) | | $ | (411) |
(a) | Higher margins in 2011 compared with 2010 were driven by the monetization of loss contracts in 2010 and lower customer migration to alternative suppliers in 2011. |
(b) | Volumes were lower in 2011 compared with 2010 as a result of unplanned outages and the sale of our interest in Safe Harbor Water Power Corporation. |
(c) | Volumes were flat in 2012 compared to 2011 due to an uprate in the third quarter of 2011 offset by higher plant outage costs in 2012. Volumes were lower in 2011 compared with 2010 primarily as a result of the dual-unit turbine blade replacement outages beginning in May 2011. |
(d) | See Note 10 to the Financial Statements for additional information. |
Western U.S.
Non-trading margins were lower in 2012 compared with 2011 due to $34 million of lower wholesale volumes, including $31 million related to the bankruptcy of SMGT, $9 million of higher average fuel prices and $9 million of lower wholesale prices.
Non-trading margins were higher in 2011 compared with 2010 due to higher net wholesale prices of $58 million, partially offset by lower wholesale volumes of $45 million, primarily due to economic reductions in the coal unit output.
Utility Revenues | | | | | | |
| | | | | | | | | |
The increase (decrease) in utility revenues was due to: |
| | | | | 2012 vs. 2011 | | 2011 vs. 2010 |
Domestic: | | | | | | |
| PPL Electric (a) | | $ | (121) | | $ | (567) |
| LKE (b) | | | (34) | | | 2,300 |
| Total Domestic | | | (155) | | | 1,733 |
| | | | | | | | | |
U.K.: | | | | | | |
| PPL WW | | | | | | |
| | Price (c) | | | 78 | | | 76 |
| | Volume (d) | | | (13) | | | (15) |
| | Recovery of allowed revenues (e) | | | (6) | | | 7 |
| | Foreign currency exchange rates | | | (11) | | | 25 |
| | Other | | | (10) | | | 8 |
| | Total PPL WW | | | 38 | | | 101 |
| WPD Midlands (f) | | | 633 | | | 790 |
| Total U.K. | | | 671 | | | 891 |
Total | | $ | 516 | | $ | 2,624 |
(a) | See "Pennsylvania Gross Delivery Margins" for further information. |
(b) | See "Kentucky Gross Margins" for further information. |
(c) | The increase in 2012 compared with 2011 was due to price increases effective April 1, 2012 and April 1, 2011. The increase in 2011 compared with 2010 was due to price increases effective April 1, 2011 and April 1, 2010. |
(d) | The decreases in both periods were primarily due to the downturn in the economy and the unfavorable effect of weather. |
(e) | The decrease in 2012 compared with 2011 was primarily due to a 2012 charge to income for the over-recovery of revenues from customers. The increase in 2011 compared with 2010 was primarily due to a revised estimate of network electricity line losses. |
(f) | Amounts in each period were not comparable as 2011 includes eight months of WPD Midlands' results. The increase in 2012 compared with 2011 was primarily due to four additional months of utility revenue in 2012 of $446 million. The comparable eight month period was $125 million higher in 2012 compared to 2011 due to a price increase effective April 1, 2012. |
Other Operation and Maintenance |
| | | | | | | | |
| | | | | | |
The increase (decrease) in other operation and maintenance was due to: |
| | | | | | | | |
| | | | 2012 vs. 2011 | | 2011 vs. 2010 |
Domestic: | | | | | | |
| LKE (a) | | | | | $ | 612 |
| LKE coal plant maintenance (b) | | $ | 19 | | | |
| Act 129 costs incurred (c) | | | (6) | | | 26 |
| Vegetation management (d) | | | 11 | | | (8) |
| Montana hydroelectric litigation (e) | | | 75 | | | (121) |
| PPL Susquehanna nuclear plant costs (f) | | | 27 | | | 27 |
| Costs at Western fossil and hydroelectric plants (g) | | | (1) | | | 12 |
| Costs at Eastern fossil and hydroelectric plants (h) | | | 13 | | | 23 |
| Ironwood acquisition (i) | | | 18 | | | |
| Payroll-related costs (j) | | | 26 | | | 11 |
| PUC-reportable storm costs, net of insurance recoveries | | | 14 | | | (10) |
| Uncollectible accounts (k) | | | (4) | | | 21 |
| Pension expense | | | 19 | | | (5) |
| Stock based compensation | | | 17 | | | 7 |
| Other | | | 2 | | | (12) |
U.K. Regulated Segment: | | | | | | |
| PPL WW (l) | | | 23 | | | 15 |
| WPD Midlands (m) | | | (85) | | | 313 |
| | | $ | 168 | | $ | 911 |
(a) | 2011 compared with 2010 is not comparable as 2010 includes two months of LKE's results. |
(b) | 2012 compared with 2011 was higher primarily due to $11 million of expense related to an increased scope of scheduled outages. |
(c) | Relates to costs associated with PPL Electric's PUC-approved energy efficiency and conservation plan. These costs are recovered in customer rates. There were initially 15 Act 129 programs which began in 2010 and continued to ramp up in 2011. Some of the energy efficiency programs were reduced or closed in 2012 resulting in lower operation and maintenance expense. |
(d) | PPL Electric incurred more expense in 2010 and 2012 compared to 2011 due to increased vegetation management activities related to transmission lines to comply with federal reliability requirements as well as increased vegetation management for the distribution system in 2012 in an effort to maintain and increase system reliability. |
(e) | In March 2010, the Montana Supreme Court substantially affirmed a June 2008 Montana District Court decision regarding lease payments for the use of certain Montana streambeds. As a result, in the first quarter of 2010, PPL Montana recorded a charge of $56 million, representing estimated rental compensation for the first quarter of 2010 and prior years, including interest. The portion of the total charge recorded to "Other operation and maintenance" on the Statement of Income totaled $49 million. In August 2010, PPL Montana filed a petition for a writ of certiorari with the U.S. Supreme Court requesting the Court's review of this matter. In June 2011, the U.S. Supreme Court granted PPL Montana's petition. In February 2012, the U.S. Supreme Court overturned the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's decision. As a result in 2011, PPL Montana reversed its total loss accrual of $89 million, which had been recorded prior to the U.S. Supreme Court decision, of which $75 million was credited to "Other operation and maintenance" on the Statement of Income. |
(f) | 2012 compared with 2011 was higher primarily due to $11 million of higher payroll-related costs, $7 million of higher project costs and $7 million of higher costs from the refueling outage. 2011 compared with 2010 was higher primarily due to $11 million of higher payroll-related costs, $10 million of higher outage costs and $8 million of higher costs from the refueling outage. |
(g) | 2011 compared with 2010 was higher primarily due to $11 million of lower insurance proceeds. |
(h) | 2012 compared with 2011 was higher primarily due to plant outage costs of $13 million. 2011 compared with 2010 was higher primarily due to plant outage costs of $13 million. |
(i) | There are no comparable amounts in 2011 as the Ironwood Acquisition occurred in April 2012. |
(j) | 2012 compared with 2011 was higher primarily due to higher payroll costs of $17 million in 2012 for PPL Electric due to less project costs being capitalized. |
(k) | 2011 compared with 2010 was higher primarily due to SMGT filing for protection under Chapter 11 of the U.S. Bankruptcy Code, $11 million of damages billed to SMGT were fully reserved. |
(l) | Both periods were higher due to higher pension costs resulting from increased amortization of actuarial losses. |
(m) | Amounts in each period were not comparable as 2011 includes eight months of WPD Midlands' results. The increase in 2012 compared with 2011 was partially due to four additional months of expense in 2012 of $86 million. The comparable eight month period was $171 million lower in 2012 compared to 2011 due to $86 million of lower severance compensation, early retirement deficiency costs and outplacement services for employees separating from the WPD Midlands companies as a result of a reorganization to transition the WPD Midlands companies to the same operating structure as WPD (South West) and WPD (South Wales), $34 million of lower other acquisition related costs, and $26 million of lower pension expense. |
Depreciation
The increase (decrease) in depreciation was due to:
| | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | |
Additions to PP&E | | $ | 65 | | $ | 20 |
LKE (a) (b) | | | | | | 285 |
WPD Midlands (c) | | | 55 | | | 95 |
Ironwood Acquisition (Note 10) | | | 17 | | | |
Other | | | 3 | | | 4 |
Total | | $ | 140 | | $ | 404 |
(a) | For 2011 compared with 2010, includes $32 million of depreciation expense related to TC2, which began to dispatch in January 2011. |
(b) | 2011 compared with 2010 is not comparable as 2010 includes two months of LKE's results. |
(c) | Amounts in each period were not comparable as 2011 includes eight months of WPD Midlands' results. The increase in 2012 compared with 2011 is primarily due to four additional months of expense in 2012 of $49 million. |
Taxes, Other Than Income
The increase (decrease) in taxes, other than income was due to:
| | | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | | |
State gross receipts tax (a) | | $ | (4) | | $ | (5) |
Domestic property tax expense (b) | | | 14 | | | (10) |
Domestic sales and use tax | | | | | | (2) |
State capital stock tax (c) | | | (11) | | | 11 |
LKE (d) | | | | | | 35 |
WPD Midlands (e) | | | 33 | | | 60 |
Other | | | 8 | | | (1) |
Total | | $ | 40 | | $ | 88 |
(a) | The decrease in 2012 compared with 2011 was primarily due to a decrease in taxable electricity revenue. The decrease in 2011 compared with 2010 was primarily due to a decrease in electricity revenue as customers chose alternative suppliers in 2010. This tax is included in "Unregulated Gross Energy Margins" and "Pennsylvania Gross Delivery Margins" above. |
(b) | The increase in 2012 compared with 2011 is primarily due to the fully amortized PURTA refund that was refunded to the customers in 2011 pursuant to PUC regulations. The decrease in 2011 compared with 2010 was primarily due to the amortization of the PURTA refund. This tax is included in "Pennsylvania Gross Delivery Margins" above. |
(c) | The decrease in 2012 compared to 2011 was due to changes in the statutory rate from the prior year. The increase in 2011 compared with 2010 was due in part to the expiration of the Keystone Opportunity Zone credit in 2010 and an agreed to change in a capital stock filing position with the state. |
(d) | 2011 compared with 2010 was not comparable as 2010 includes two months of LKE's results. |
(e) | Amounts in each period were not comparable as 2011 includes eight months of WPD Midlands' results. The increase in 2012 compared with 2011 is primarily due to four additional months of expense in 2012 of $30 million. |
Other Income (Expense) - net | | | | | | |
| | | | | | |
The increase (decrease) in other income (expense) - net was due to: |
| | | | | | |
| | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | |
Change in the fair value of economic foreign currency exchange contracts (Note 19) | | $ | (62) | | $ | 7 |
Net hedge gains associated with the 2011 Bridge Facility (a) | | | (55) | | | 55 |
Foreign currency loss on 2011 Bridge Facility (b) | | | 57 | | | (57) |
Gain on redemption of debt (c) | | | (22) | | | 22 |
Cash flow hedges (d) | | | | | | 29 |
WPD Midlands acquisition-related adjustments in 2011 (Note 10) | | | 55 | | | (55) |
LKE acquisition-related adjustments in 2010 (Note 10) | | | | | | 31 |
Losses from equity method investments | | | (9) | | | (1) |
Other | | | (7) | | | 4 |
Total | | $ | (43) | | $ | 35 |
(a) | Represents a gain on foreign currency contracts in 2011 that hedged the repayment of the 2011 Bridge Facility borrowing. |
(b) | Represents a foreign currency loss in 2011 related to the repayment of the 2011 Bridge Facility borrowing. |
(c) | In July 2011, as a result of PPL Electric's redemption of 7.125% Senior Secured Bonds due 2013, PPL recorded a gain on the accelerated amortization of the fair value adjustment to the debt recorded in connection with previously settled fair value hedges. |
(d) | Represents losses reclassified from AOCI into earnings in 2010 associated with discontinued hedges at PPL for debt that had been planned to be issued by PPL Energy Supply. As a result of the expected net proceeds from the sale of certain non-core generation facilities, coupled with the monetization of full-requirement sales contracts, the debt issuance was no longer needed. |
Other-Than-Temporary Impairments
Primarily due to a $25 million pre-tax impairment of the EEI investment, other-than-temporary impairments increased by $21 million in 2012 compared with 2011. See Notes 1 and 18 to the Financial Statements for additional information.
Interest Expense
The increase (decrease) in interest expense was due to:
| | | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | | |
2011 Bridge Facility costs related to the acquisition of WPD Midlands (Notes 7 and 10) | | $ | (44) | | $ | 44 |
2010 Bridge Facility costs related to the acquisition of LKE (Notes 7 and 10) | | | | | | (80) |
2010 Equity Units (a) | | | (2) | | | 28 |
2011 Equity Units (b) | | | 12 | | | 34 |
Short-term debt interest expense (c) | | | (12) | | | 11 |
Interest expense on the March 2010 WPD (South Wales) and WPD (South West) debt issuance | | | | | | 11 |
Inflation adjustment on U.K. Index-linked Senior Unsecured Notes | | | (12) | | | 5 |
LKE (d) | | | | | | 126 |
WPD Midlands (e) | | | 80 | | | 154 |
Ironwood Acquisition (Note 10) | | | 12 | | | |
Hedging activities and ineffectiveness | | | 29 | | | 11 |
Capitalized interest (f) | | | (6) | | | (17) |
Montana hydroelectric litigation (g) | | | 10 | | | (20) |
Other | | | (4) | | | (2) |
Total | | $ | 63 | | $ | 305 |
(a) | Interest related to the issuance in June 2010 to support the LKE acquisition. |
(b) | Interest related to the issuance in April 2011 to support the WPD Midlands acquisition. |
(c) | 2012 compared with 2011 was lower primarily due to lower interest rates on 2012 short-term borrowings coupled with lower fees on credit facilities. 2011 compared with 2010 was higher primarily due to increased borrowings in 2011 and an increase in commitment fees on credit facilities. |
(d) | 2011 compared with 2010 is not comparable as 2010 includes two months of LKE's results. |
(e) | Amounts in each period are not comparable as 2011 includes eight months of WPD Midlands' results. The increase in 2012 compared with 2011 is primarily due to four additional months of expense in 2012 of $74 million. |
(g) | In March 2010, the Montana Supreme Court substantially affirmed a June 2008 Montana District Court decision regarding lease payments for the use of certain Montana streambeds. In August 2010, PPL Montana filed a petition for a writ of certiorari with the U.S. Supreme Court requesting the Court's review of this matter. In 2011 and 2010, PPL Montana, recorded $4 million and $10 million of interest expense on the rental compensation covered by the court decision. In February 2012, the U.S. Supreme Court overturned the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion. As a result, in the fourth quarter of 2011 PPL Montana reversed its total loss accrual of $89 million, which had been recorded prior to the U.S. Supreme Court decision, of which $14 million was credited to "Interest Expense" on the Statement of Income. |
Income Taxes
The increase (decrease) in income taxes was due to:
| | | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | | |
Higher (lower) pre-tax book income | | $ | (296) | | $ | 168 |
State valuation allowance adjustments (a) | | | (23) | | | 101 |
State deferred tax rate change (b) | | | 7 | | | (26) |
Domestic manufacturing deduction (c) | | | | | | 11 |
Federal and state tax reserve adjustments (d) | | | (40) | | | 99 |
Federal and state tax return adjustments (e) | | | 33 | | | (14) |
U.S. income tax on foreign earnings net of foreign tax credit (f) | | | 57 | | | (59) |
U.K. Finance Act adjustments (g) | | | 2 | | | (16) |
Foreign valuation allowance adjustments (h) | | | (147) | | | (68) |
Foreign tax reserve adjustments (h) | | | 134 | | | (141) |
U.K. capital loss benefit (h) | | | | | | 261 |
Foreign tax return adjustments | | | (6) | | | |
Health Care Reform | | | | | | (8) |
LKE (i) | | | | | | 125 |
Depreciation not normalized (a) | | | 9 | | | (14) |
WPD Midlands (j) | | | 146 | | | (2) |
Net operating loss carryforward adjustments (k) | | | (9) | | | |
Other | | | (13) | | | 11 |
Total | | $ | (146) | | $ | 428 |
(a) | During 2011, the Pennsylvania Department of Revenue issued interpretive guidance on the treatment of bonus depreciation for Pennsylvania income tax purposes. The guidance allows 100% bonus depreciation for qualifying assets in the same year bonus depreciation is allowed for federal income tax purposes. Due to the decrease in projected taxable income related to bonus depreciation and a decrease in projected future taxable income, PPL recorded a $43 million state deferred income tax expense related to deferred tax valuation allowances during 2011. |
Additionally, the 100% Pennsylvania bonus depreciation deduction created a current state income tax benefit for the flow-through impact of Pennsylvania regulated state tax depreciation. The federal provision for 100% bonus depreciation generally applies to property placed into service before January 1, 2012. The placed in-service deadline is extended to January 1, 2013 for property that has a cost in excess of $1 million, has a production period longer than one year and has a tax life of at least ten years. PPL's tax deduction for 100% bonus regulated tax depreciation was significantly lower in 2012 than in 2011.
Pennsylvania H.B. 1531, enacted in October 2009, increased the net operating loss limitation to 20% of taxable income for tax years beginning in 2010. Based on the projected revenue increase related to the expiration of the generation rate caps in 2010, PPL recorded a $72 million state deferred income tax benefit related to the reversal of deferred tax valuation allowances related to the future projections of taxable income over the remaining carryforward period of the net operating losses during 2010.
(b) | Changes in state apportionment resulted in reductions to the future estimated state tax rate at December 31, 2012 and 2011. PPL recorded a $19 million deferred tax benefit in 2012 and a $26 million deferred tax benefit in 2011 related to its state deferred tax liabilities. |
(c) | In December 2010, Congress enacted legislation allowing for 100% bonus depreciation on qualified property. The increased tax depreciation eliminated the tax benefit related to the domestic manufacturing deduction in 2012 and 2011. |
(d) | In 1997, the U.K. imposed a Windfall Profits Tax (WPT) on privatized utilities, including WPD. PPL filed its federal income tax returns for years subsequent to its 1997 and 1998 claims for refund on the basis that the U.K. WPT was creditable. In September 2010, the U.S. Tax Court (Tax Court) ruled in PPL's favor in a dispute with the IRS, concluding that the U.K. WPT is a creditable tax for U.S. tax purposes. As a result and with the finalization of other issues, PPL recorded a $42 million tax benefit in 2010. In January 2011, the IRS appealed the Tax Court's decision to the U.S. Court of Appeals for the Third Circuit (Third Circuit). In December 2011, the Third Circuit issued its opinion reversing the Tax Court's decision, holding that the U.K. WPT is not a creditable tax. As a result of the Third Circuit's adverse determination, PPL recorded a $39 million expense in 2011. In February 2012, PPL filed a petition for rehearing of the Third Circuit's opinion. In March 2012, the Third Circuit denied PPL's petition. In June 2012, the U.S. Court of Appeals for the Fifth Circuit issued a contrary opinion in an identical case involving another company. In July 2012, PPL filed a petition for a writ of certiorari seeking U.S. Supreme Court review of the Third Circuit's opinion. The Supreme Court granted PPL's petition on October 29, 2012, and oral argument was held on February 20, 2013. PPL expects the case to be decided before the end of the Supreme Court's current term in June 2013 and cannot predict the outcome of this matter. |
In 2010, the Tax Court ruled in PPL's favor in a dispute with the IRS, concluding that street lighting assets are depreciable for tax purposes over seven years. As a result, PPL recorded a $7 million tax benefit to federal and state income tax reserves and related deferred income taxes during 2010.
(e) | During 2012, PPL recorded $16 million in federal and state income tax expense related to the filing of the 2011 federal and state income tax returns. Of this amount, $5 million relates to the reversal of prior years' state income tax benefits related to regulated depreciation. PPL changed its method of accounting for repair expenditures for tax purposes effective for its 2008 tax year. In August 2011, the IRS issued guidance regarding the use and evaluation of statistical samples and sampling estimates for network assets. The IRS guidance provided a safe harbor method of determining whether the repair expenditures for electric transmission and distribution property can be currently deducted for tax purposes. PPL adopted the safe harbor method with the filing of its 2011 federal income tax return. |
During 2011, PPL recorded $17 million in federal and state tax benefits related to the filing of the 2010 federal and state income tax returns. Of this amount, $7 million in tax benefits related to an additional domestic manufacturing deduction resulting from revised bonus depreciation amounts and $3 million in tax benefits related to the flow-through impact of Pennsylvania regulated state tax depreciation.
(f) | During 2012, PPL recorded a $23 million adjustment to federal income tax expense related to the recalculation of 2010 U.K. earnings and profits. |
During 2011, PPL recorded a $28 million federal income tax benefit related to U.K. pension contributions.
During 2010, PPL recorded additional U.S. income tax expense primarily resulting from increased taxable dividends.
(g) | The U.K.'s Finance Act of 2012, enacted in July 2012, reduced the U.K. statutory income tax rate from 25% to 24% retroactive to April 1, 2012 and from 24% to 23% effective April 1, 2013. As a result, PPL reduced its net deferred tax liabilities and recognized a $75 million deferred tax benefit in 2012 related to both rate decreases. WPD Midlands' portion of the deferred tax benefit is $43 million. |
The U.K.'s Finance Act of 2011, enacted in July 2011, reduced the U.K. statutory income tax rate from 27% to 26% retroactive to April 1, 2011 and from 26% to 25% effective April 1, 2012. As a result, PPL reduced its net deferred tax liabilities and recognized a $69 million deferred tax benefit in 2011 related to both rate decreases. WPD Midlands' portion of the deferred tax benefit is $35 million.
The U.K.'s Finance Act of 2010, enacted in July 2010, reduced the U.K. statutory income tax rate from 28% to 27% effective April 1, 2011. As a result, PPL reduced its net deferred tax liabilities and recognized an $18 million deferred tax benefit in 2010.
(h) | During 2012, PPL recorded a $5 million tax benefit following resolution of a U.K. tax issue related to interest expense. |
During 2011, WPD reached an agreement with the HMRC related to the amount of the capital losses that resulted from prior years' restructuring in the U.K. and recorded a $147 million foreign tax benefit for the reversal of tax reserves related to the capital losses. Additionally, WPD recorded a $147 million valuation allowance for the amount of capital losses that, more likely than not, will not be utilized.
During 2010, PPL recorded a $261 million foreign tax benefit in conjunction with losses resulting from restructuring in the U.K. A portion of these losses offset tax on a deferred gain from a prior year sale of WPD's supply business. WPD recorded a $215 million valuation allowance for the amount of capital losses that, more likely than not, will not be utilized.
(i) | 2011 compared with 2010 was not comparable as 2010 includes two months of LKE's results. |
(j) | Amounts in each period were not comparable as 2011 includes eight months of WPD Midlands' results. The increase in 2012 compared with 2011 was primarily due to higher pre-tax book income. |
(k) | During 2012, PPL recorded adjustments to deferred taxes related to net operating loss carryforwards of LKE based on income tax return adjustments. |
See Note 5 to the Financial Statements for additional information on income taxes.
Discontinued Operations
Operating Income (Loss) from Discontinued Operations (net of income taxes) decreased by $8 million in 2012 compared with 2011 primarily due to an adjustment recorded in 2012 to a liability for indemnifications related to the termination of the WKE lease in 2009.
Income (Loss) from Discontinued Operations (net of income taxes) increased by $19 million in 2011 compared with 2010 primarily due to after-tax impairment charges recorded in 2010 totaling $62 million related to assets associated with certain non-core generation facilities sold in 2011 that were written down to their estimated fair value (less cost to sell). The impacts of these charges were offset by the net results of certain other discontinued operations.
See Note 9 to the Financial Statements for additional information.
Noncontrolling Interests
"Net Income Attributable to Noncontrolling Interests" decreased by $12 million in 2012 compared with 2011. The decrease is primarily due to PPL Electric's June 2012 redemption of all 2.5 million shares of its preference stock.
Financial Condition
Liquidity and Capital Resources
PPL expects to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents, credit facilities and commercial paper issuances. Additionally, subject to market conditions, PPL currently plans to access capital markets in 2013.
PPL's cash flows from operations and access to cost-effective bank and capital markets are subject to risks and uncertainties including, but not limited to:
· | changes in electricity, fuel and other commodity prices; |
· | operational and credit risks associated with selling and marketing products in the wholesale power markets; |
· | potential ineffectiveness of the trading, marketing and risk management policy and programs used to mitigate PPL's risk exposure to adverse changes in electricity and fuel prices, interest rates, foreign currency exchange rates and counterparty credit; |
· | unusual or extreme weather that may damage PPL's transmission and distribution facilities or affect energy sales to customers; |
· | reliance on transmission and distribution facilities that PPL does not own or control to deliver its electricity and natural gas; |
· | unavailability of generating units (due to unscheduled or longer-than-anticipated generation outages, weather and natural disasters) and the resulting loss of revenues and additional costs of replacement electricity; |
· | the ability to recover and the timeliness and adequacy of recovery of costs associated with regulated utility businesses; |
· | costs of compliance with existing and new environmental laws and with new security and safety requirements for nuclear facilities; |
· | any adverse outcome of legal proceedings and investigations with respect to PPL's current and past business activities; |
· | deterioration in the financial markets that could make obtaining new sources of bank and capital markets funding more difficult and more costly; and |
· | a downgrade in PPL's or its rated subsidiaries' credit ratings that could adversely affect their ability to access capital and increase the cost of credit facilities and any new debt. |
See "Item 1A. Risk Factors" for further discussion of risks and uncertainties that could affect PPL's cash flows.
At December 31, PPL had the following:
| | 2012 | | 2011 | | 2010 |
| | | | | | | | | |
Cash and cash equivalents | | $ | 901 | | $ | 1,202 | | $ | 925 |
Short-term investments (a) | | | | | | 16 | | | 163 |
| | $ | 901 | | $ | 1,218 | | $ | 1,088 |
Short-term debt | | $ | 652 | | $ | 578 | | $ | 694 |
(a) | 2010 amount represents tax-exempt bonds issued by Louisville/Jefferson County, Kentucky on behalf of LG&E that were subsequently purchased by LG&E. Such bonds were remarketed to unaffiliated investors in January 2011. See Note 23 to the Financial Statements for further discussion. |
At December 31, 2012, $225 million of cash and cash equivalents were denominated in GBP. If these amounts would be remitted as dividends, PPL may be subject to additional U.S. taxes, net of allowable foreign tax credits. Historically, dividends paid by foreign subsidiaries have been limited to distributions of the current year's earnings. See Note 5 to the Financial Statements for additional information on undistributed earnings of WPD.
The changes in PPL's cash and cash equivalents position for the years ended December 31 resulted from:
| | 2012 | | 2011 | | 2010 |
| | | | | | | | | |
Net cash provided by (used in) operating activities | | $ | 2,764 | | $ | 2,507 | | $ | 2,033 |
Net cash provided by (used in) investing activities | | | (3,123) | | | (7,952) | | | (8,229) |
Net cash provided by (used in) financing activities | | | 48 | | | 5,767 | | | 6,307 |
Effect of exchange rates on cash and cash equivalents | | | 10 | | | (45) | | | 13 |
Net Increase (Decrease) in Cash and Cash Equivalents | | $ | (301) | | $ | 277 | | $ | 124 |
Operating Activities
Net cash provided by operating activities increased by 10%, or $257 million, in 2012 compared with 2011. The increase was the net effect of:
· | an increase of $339 million in net income, when adjusted for non-cash components; and |
· | a decrease of $60 million in defined benefit plan funding; partially offset by |
· | changes in working capital of $178 million, primarily driven by changes in prepayments and net regulatory assets/liabilities offset by the changes in counterparty collateral. |
Included in the above amounts is the impact of having an additional four months of WPD Midlands operations in 2012. WPD Midlands' cash from operating activities increased by $190 million in 2012 compared with 2011.
Net cash provided by operating activities increased by 23%, or $474 million, in 2011 compared with 2010. The increase was the net effect of:
· | operating cash provided by LKE, $743 million, and WPD Midlands, $234 million; |
· | cash from components of working capital, $435 million, primarily related to changes in prepaid income and gross receipts taxes; partially offset by |
· reduction in cash from counter party collateral, $172 million:
· lower gross energy margins, $240 million after-tax:
· | proceeds from monetizing certain full-requirement sales contracts in 2010, $249 million: |
· | higher interest payments of $44 million; and |
· | increases in other operating outflows of $233 million (including $90 million of higher operation and maintenance expenses and defined benefits funding). |
A significant portion of PPL's Supply segment operating cash flows is derived from its competitive baseload generation business activities. PPL employs a formal hedging program for its baseload generation fleet, the primary objective of which is to provide a reasonable level of near-term cash flow and earnings certainty while preserving upside potential of power price increases over the medium term. See Note 19 to the Financial Statements for further discussion. Despite PPL's hedging practices, future cash flows from operating activities from its Supply segment are influenced by commodity prices and, therefore, will fluctuate from period to period.
PPL's contracts for the sale and purchase of electricity and fuel often require cash collateral or other credit enhancements, or reductions or terminations of a portion of the entire contract through cash settlement,period were, in the event of a downgrade of PPL's or its subsidiaries' credit ratings or adverse changes in market prices. For example, in addition to limiting its trading ability, if PPL's or its subsidiaries' ratings were lowered to below "investment grade" and there was a 10% adverse movement in energy prices, PPL estimates that, based on its December 31, 2012 positions, it would have been required to post additional collateral of approximately $438 million with respect to electricity and fuel contracts. PPL has in place risk management programs that are designed to monitor and manage its exposure to volatility of cash flows related to changes in energy and fuel prices, interest rates, foreign currency exchange rates, counterparty credit quality and the operating performance of its generating units.
Investing Activities
The primary use of cash in investing activities in 2012 was for capital expenditures. In 2011, the primary uses of cash in investing activities were for the acquisition of WPD Midlands and capital expenditures. In 2010, the primary uses of cash in investing activities were for the acquisition of LKE and capital expenditures. See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 2013 through 2017.
Net cash used in investing activities was $3.1 billion in 2012 compared with $7.9 billion in 2011. Excluding the impact of cash used for the 2011 acquisition of WPD Midlands, net cash used in investing activities increased by $934 million in 2012 compared with 2011. This increase reflects $618 million of higher capital expenditures, $381 million less in asset sale proceeds (2011 sale of certain non-core generation facilities) and a $143 million reduction in proceeds from the sale of certain investments (other than securities in the nuclear plant decommissioning trust funds) partially offset by a $239 million net change in restricted cash and cash equivalents. See Note 9 to the Financial Statements for additional information on the sale of certain non-core generation facilities and Note 10 to the Financial Statements for additional information regarding the WPD Midlands acquisition.
Net cash used in investing activities was $7.9 billion in 2011 compared with $8.2 billion in 2010. The 2011 amount includes the use of $5.8 billion of cash for the acquisition of WPD Midlands, while 2010 includes $6.8 billion for the acquisition of LKE. See Note 10 to the Financial Statements for additional information regarding the acquisitions. Excluding the impact of the acquisitions, net cash used in investing activities increased by $772 million in 2011 compared with 2010. This increase reflects $890 million of higher capital expenditures and a $228 million net change in restricted cash, partially offset by $219 million of additional proceeds from the sale of certain businesses or facilities and $163 million of proceeds from the sale of investments, other than securities in the nuclear plant decommissioning trust funds. PPL received proceeds of $381 million in 2011 from the sale of certain non-core generation facilities compared with proceeds of $162 million in 2010 from the sale of the Long Island generation business and certain Maine hydroelectric generation facilities. See Note 9 to the Financial Statements for additional information on the sale of these businesses or facilities.
Financing Activities
Net cash provided by financing activities was $48 million in 2012 compared with $5.8 billion in 2011. The decrease of $5.7 billion was primarily the result of lower net long-term debt issuances of $3.4 billion and less proceeds from the issuance of common stock of $2.2 billion. Both of these decreases were primarily related to the 2011 acquisition of WPD Midlands. The decrease also included $250 million paid to redeem a subsidiary's preference stock and $87 million of higher common stock dividends. These decreases were partially offset by a $199 million net change in short-term debt.
Net cash provided by financing activities was $5.8 billion in 2011 compared with $6.3 billion in 2010, primarily as a result of issuance of long-term debt and equity relatedpart, attributable to the acquisition of WPD Midlands in 2011RJS Power, MACH Gen and the acquisition of LKE in 2010. The decrease of $540 million was primarily the result of lower net long-term debt issuances of $87 million, lower proceeds from the issuance of common stock of $144 million, $180 million of higher common stock dividends and a $195 million decrease in net, short-term debt.
See "Forecasted Sources of Cash" for a discussion of PPL's plans to issue debt and equity securities, as well as a discussion of credit facility capacity available to PPL. Also see "Forecasted Uses of Cash" for a discussion of plans to pay dividends on common securities in the future, as well as maturities of long-term debt.
Long-term Debt and Equity Securities
The long-term debt and equity securities activity for the year ended December 31, 2012 was:
| | | | | | | | | | Equity |
| | | | Debt | | Issuances |
| | | | Issuances (a) | | Retirements | | (Redemptions) |
| | | | | | | | | | | |
PPL Capital Funding Senior Notes (b) | | $ | 798 | | $ | (99) | | | |
PPL Electric First Mortgage Bonds | | | 249 | | | | | | |
WPD (East Midlands) Senior Notes | | | 176 | | | | | | |
PPL Electric preference stock (c) | | | | | | | | $ | (250) |
| | Total Cash Flow Impact | | $ | 1,223 | | $ | (99) | | $ | (250) |
| | | | | | | | | | Equity |
| | | | Debt | | Issuances |
| | | | Issuances (a) | | Retirements | | (Redemptions) |
| | | | | | | | | |
Assumed through consolidation - Ironwood Acquisition (d) | | $ | 258 | | | | | | |
Non-cash Exchanges: | | | | | | | | | |
| LKE Senior Notes (e) | | $ | 250 | | $ | (250) | | | |
| | | | | | | | | | | |
Net Increase (decrease) | | $ | 1,382 | | | | | $ | (250) |
(a) | Issuances are net of pricing discounts, where applicable and exclude the impact of debt issuance costs. |
(b) | Senior unsecured notes of $99 million were redeemed at par prior to their 2047 maturity date. |
(c) | In June 2012, PPL Electric redeemed all 2.5 million shares of its 6.25% Series Preference Stock, par value $100 per share, which was included in "Noncontrolling Interests" on the 2011 Balance Sheet. |
(d) | Includes $24 million of fair value adjustments resulting from the purchase price allocation. See Note 10 to the Financial Statements for additional information on the acquisition. |
(e) | In June 2012, LKE completed an exchange of all its outstanding 4.375% Senior Notes due 2021 issued in September 2011 in a transaction not registered under the Securities Act of 1933, for similar securities that were issued in a transaction registered with the SEC. |
In addition to the above, in April 2012, PPL made a registered underwritten public offering of 9.9 million shares of its common stock. In conjunction withseveral items that offering, the underwriters exercised an option to purchase 591 thousand additional shares of PPL common stock solely to cover over-allotments.
In connection with the registered public offering, PPL entered into forward sale agreements with two counterparties covering the 9.9 million shares of PPL common stock. Settlement of these initial forward sale agreements will occur no later than April 2013. As a result of the underwriters' exercise of the overallotment option, PPL entered into additional forward sale agreements covering the additional 591 thousand shares of PPL common stock. Settlement of the subsequent forward sale agreements will occur no later than July 2013. Upon any physical settlement of any forward sale agreement, PPL will issue and deliver to the forward counterparties shares of its common stock in exchange for cash proceeds per share equal to the forward sale price. The forward sale price will be calculated based on an initial forward price of $27.02 per share reduced during the period the contracts are outstanding as specified in the forward sale agreements. PPL may, in certain circumstances, elect cash settlement or net share settlement for all or a portion of its rights or obligations under the forward sale agreements.
PPL will not receive any proceeds or issue any shares of common stock until settlement of the forward sale agreements. PPL intends to use any net proceeds that it receives upon settlement to repay short-term debt obligations and for other general corporate purposes.
The forward sale agreements are classified as equity transactions. As a result, no amounts will be recorded in the consolidated financial statements until the settlement of the forward sale agreements. Prior to those settlements, the only impact to the financial statements will be the inclusion of incremental shares within the calculation of diluted EPS using the treasury stock method.
See Note 7 to the Financial Statements for additional information about long-term debt and equity securities.
Forecasted Sources of Cash
PPL expects to continue to have sufficient sources of liquidity available in the near term, including cash flows from operations, various credit facilities, commercial paper issuances and operating leases. Additionally, subject to market conditions, PPL currently plans to access capital markets in 2013.
Credit Facilities
At December 31, 2012, PPL's total committed borrowing capacity under credit facilities and the use of this borrowing capacity were:
| | | | | | | | | Letters of | | | |
| | | | | | | | | Credit | | | |
| | | | | | | | | Issued | | | |
| | | | | | | | | and | | | |
| | | | | | | Commercial | | |
| | | Committed | | | | Paper | | Unused |
| | | Capacity | | Borrowed | | Backstop | | Capacity |
| | | | | | | | | |
PPL Energy Supply Credit Facilities (a) | | $ | 3,200 | | | | | $ | 631 | | $ | 2,569 |
PPL Electric Credit Facilities (a) (b) | | | 400 | | | | | | 1 | | | 399 |
LG&E Credit Facility (a) | | | 500 | | | | | | 55 | | | 445 |
KU Credit Facilities (a) | | | 598 | | | | | | 268 | | | 330 |
| Total Domestic Credit Facilities (c) (f) | | $ | 4,698 | | | | | $ | 955 | | $ | 3,743 |
| | | | | | | | | | | | | |
PPL WW Credit Facility (d) (e) | | £ | 150 | | £ | 106 | | | n/a | | £ | 44 |
WPD (South West) Credit Facility (e) | | | 245 | | | | | | n/a | | | 245 |
WPD (East Midlands) Credit Facility (e) (g) | | | 300 | | | | | | | | | 300 |
WPD (West Midlands) Credit Facility (e) (g) | | | 300 | | | | | | | | | 300 |
| Total WPD Credit Facilities (h) (f) | | £ | 995 | | £ | 106 | | | | | £ | 889 |
(a) | The syndicated credit facilities, as well as KU's letter of credit facility, each contain a financial covenant requiring debt to total capitalization not to exceed 65% for PPL Energy Supply and 70% for PPL Electric, LG&E and KU, as calculated in accordance with the facility, and other customary covenants. See Note 7 to the Financial Statements for additional information regarding these credit facilities. |
(b) | Includes a $100 million credit facility related to an asset-backed commercial paper program through which PPL Electric obtains financing by selling and contributing its eligible accounts receivable and unbilled revenue to a special purpose, wholly owned subsidiary on an ongoing basis. The subsidiary pledges these assets to secure loans of up to an aggregate of $100 million from a commercial paper conduit sponsored by a financial institution. At December 31, 2012, based on accounts receivable and unbilled revenue pledged, the amount available for borrowing under the facility was $100 million. |
(c) | The commitments under PPL's domestic credit facilities are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than 9% of the total committed capacity. |
(d) | In December 2012, the PPL WW credit facility was subsequently replaced with a credit facility expiring in December 2016 and the capacity was increased to £210 million. |
(e) | The facilities contain financial covenants that require the company to maintain an interest coverage ratio of not less than 3.0 times consolidated earnings before income taxes, depreciation and amortization and total net debt not in excess of 85% of its RAV, calculated in accordance with the credit facility. |
(f) | Each company pays customary fees under its respective syndicated credit facility, as does KU under its letter of credit facility, and borrowings generally bear interest at LIBOR-based rates plus an applicable margin. |
(g) | Under the facilities, WPD (East Midlands) and WPD (West Midlands) each have the ability to request the lenders to issue up to £80 million of letters of credit in lieu of borrowing. |
(h) | The total amount borrowed at December 31, 2012 was a USD-denominated borrowing of $171 million, which equated to £106 million at the time of borrowing and bore interest at 0.8452%. At December 31, 2012, the unused capacity of WPD's committed credit facilities was approximately $1.4 billion. |
The commitments under WPD's credit facilities are provided by a diverse bank group with no one bank providing more than 16% of the total committed capacity.
In addition to the financial covenants noted in the table above, the credit agreements governing the above credit facilities contain various other covenants. Failure to comply with the covenants after applicable grace periods could result in acceleration of repayment of borrowings and/or termination of the agreements. PPL monitors compliance with the covenants on a regular basis. At December 31, 2012, PPL was in compliance with these covenants. At this time, PPLmanagement believes that these covenants and other borrowing conditions will not limit access to these funding sources.
See Note 7 to the Financial Statements for further discussion of PPL's credit facilities.
Commercial Paper
PPL Energy Supply maintains a $750 million commercial paper program to provide an additional financing source to fund its short-term liquidity needs, if and when necessary. Commercial paper issuances are supported by PPL Energy Supply's Syndicated Credit Facility. At December 31, 2012, PPL Energy Supply had $356 million of commercial paper outstanding at a weighted-average interest rate of 0.50%.
PPL Electric maintains a $300 million commercial paper program to provide an additional financing source to fund its short-term liquidity needs, if and when necessary. Commercial paper issuances are currently supported by PPL Electric's Syndicated Credit Facility. PPL Electric had no commercial paper outstanding at December 31, 2012.
In February 2012, LG&E and KU each established a commercial paper program for up to $250 million to provide additional financing sources to fund its short-term liquidity needs, if and when necessary. Commercial paper issuances are supported by LG&E's and KU's Syndicated Credit Facilities. At December 31, 2012, LG&E and KU had $55 million and $70 million of commercial paper outstanding at a weighted average interest rate, for each, of 0.42%.
Operating Leases
PPL and its subsidiaries also have available funding sources that are provided through operating leases. PPL's subsidiaries lease office space, land, buildings and certain equipment. These leasing structures provide PPL additional operating and financing flexibility. The operating leases contain covenants that are typical for these agreements, such as maintaining insurance, maintaining corporate existence and timely payment of rent and other fees.
PPL, through its subsidiary PPL Montana, leases a 50% interest in Colstrip Units 1 and 2 and a 30% interest in Unit 3, under four 36-year, non-cancelable operating leases. These operating leases are not recorded on PPL's Balance Sheets. The leases place certain restrictions on PPL Montana's ability to incur additional debt, sell assetsindicative of ongoing operations. See "EBITDA and declare dividends. See Note 7 to the Financial Statements for a discussion of other dividend restrictions related to PPL subsidiaries.
See Note 11 to the Financial Statements for further discussion of the operating leases.
Long-term Debt and Equity Securities
PPL and its subsidiaries currently plan to incur, subject to market conditions, approximately $2.0 billion of long-term indebtedness in 2013, the proceeds of which will be used to fund capital expenditures and for other general corporate purposes. In addition during 2013, two events will occur related to the components of the 2010 Equity Units. PPL will receive proceeds of $1.150 billion through the issuance of PPL common stock to settle the 2010 Purchase Contracts; and PPL Capital Funding expects to remarket the 4.625% Junior Subordinated Notes due 2018. See Note 7 to the Financial Statements for additional information.
In addition, PPL currently plans to issue new shares of common stock in 2013 in an aggregate amount up to $350 million under its forward contracts (see Note 7 to the Financial Statements for more information), DRIP and various employee stock-based compensation and other plans.
Forecasted Uses of Cash
In addition to expenditures required for normal operating activities, such as purchased power, payroll, fuel and taxes, PPL currently expects to incur future cash outflows for capital expenditures, various contractual obligations, payment of dividends on its common stock and possibly the purchase or redemption of a portion of debt securities.
Capital Expenditures
The tableAdjusted EBITDA" below shows PPL's current capital expenditure projections for the years 2013 through 2017.
| | | | Projected |
| | | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
Construction expenditures (a) (b) | | | | | | | | | | | | | | | |
| Generating facilities | | $ | 814 | | $ | 500 | | $ | 514 | | $ | 717 | | $ | 831 |
| Distribution facilities | | | 1,780 | | | 1,654 | | | 1,712 | | | 1,711 | | | 1,763 |
| Transmission facilities | | | 723 | | | 599 | | | 457 | | | 413 | | | 390 |
| Environmental | | | 750 | | | 812 | | | 536 | | | 312 | | | 128 |
| Other | | | 139 | | | 126 | | | 117 | | | 105 | | | 99 |
| | Total Construction Expenditures | | | 4,206 | | | 3,691 | | | 3,336 | | | 3,258 | | | 3,211 |
Nuclear fuel | | | 152 | | | 145 | | | 153 | | | 158 | | | 162 |
| | Total Capital Expenditures | | $ | 4,358 | | $ | 3,836 | | $ | 3,489 | | $ | 3,416 | | $ | 3,373 |
(a) | Construction expenditures include capitalized interest and AFUDC, which are expected to total approximately $160 million for the years 2013 through 2017. |
(b) | Includes expenditures for certain intangible assets. |
PPL's capital expenditure projections for the years 2013 through 2017 total approximately $18.5 billion. Capital expenditure plans are revised periodically to reflect changes in operational, market and regulatory conditions. For the years presented, this table includes projected costs related to the planned 793 MW of incremental capacity increases for both PPL Energy Supply and LKE, PPL Electric's asset optimization program to replace aging transmission and distribution assets and the PJM-approved regional transmission line expansion project. This table also includes LKE's environmental projects related to existing and proposed EPA compliance standards (actual costs may be significantly lower or higher depending on the final requirements; environmental compliance costs incurred by LG&E and KU in serving KPSC jurisdictional customers are generally eligible for recovery through the ECR mechanism). See Notes 6 and 8 to the Financial Statements for information on LG&E's and KU's ECR plans and the PJM-approved regional transmission line expansion project and the other significant development projects.
PPL plans to fund its capital expenditures in 2013 with cash from operations and proceeds from the issuance of common stock and debt securities.
Contractual Obligations
PPL has assumed various financial obligations and commitments in the ordinary course of conducting its business. At December 31, 2012, the estimated contractual cash obligations of PPL were:
| | | Total | | 2013 | | 2014 - 2015 | | 2016 - 2017 | | After 2017 |
| | | | | | | | | | | | | | | | |
Long-term Debt (a) | | $ | 19,435 | | $ | 751 | | $ | 1,645 | | $ | 946 | | $ | 16,093 |
Interest on Long-term Debt (b) | | | 14,276 | | | 932 | | | 1,704 | | | 1,530 | | | 10,110 |
Operating Leases (c) | | | 507 | | | 109 | | | 191 | | | 58 | | | 149 |
Purchase Obligations (d) | | | 8,770 | | | 2,642 | | | 2,847 | | | 1,604 | | | 1,677 |
Other Long-term Liabilities | | | | | | | | | | | | | | | |
| Reflected on the Balance | | | | | | | | | | | | | | | |
| Sheet under GAAP (e) (f) | | | 607 | | | 560 | | | 47 | | | | | | |
Total Contractual Cash Obligations | | $ | 43,595 | | $ | 4,994 | | $ | 6,434 | | $ | 4,138 | | $ | 28,029 |
(a) | Reflects principal maturities only based on stated maturity dates, except for PPL Energy Supply's 5.70% REset Put Securities (REPS). See Note 7 to the Financial Statements for a discussion of the remarketing feature related to the REPS, as well as discussion of variable-rate remarketable bonds issued on behalf of PPL Energy Supply, LG&E and KU. PPL does not have any significant capital lease obligations. |
(b) | Assumes interest payments through stated maturity, except for the REPS, for which interest is reflected to the put date. The payments herein are subject to change, as payments for debt that is or becomes variable-rate debt have been estimated and payments denominated in British pounds sterling have been translated to U.S. dollars at a current foreign currency exchange rate. |
(c) | See Note 11 to the Financial Statements for additional information. |
(d) | The amounts include agreements to purchase goods or services that are enforceable and legally binding and specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. Primarily includes PPL's purchase obligations of electricity, coal, nuclear fuel and limestone as well as certain construction expenditures, which are also included in the Capital Expenditures table presented above. Financial swaps and open purchase orders that are provided on demand with no firm commitment are excluded from the amounts presented. |
(e) | The amounts include WPD's contractual deficit pension funding requirements arising from actuarial valuations performed in March 2010 and June 2011. The U.K. electricity regulator currently allows a recovery of a substantial portion of the contributions relating to the plan deficit; however, WPD cannot be certain that this will continue beyond the current review period, which extends to March 31, 2015. The amounts also include contributions made or committed to be made for 2013 for PPL's and LKE's U.S. pension plans. See Note 13 to the Financial Statements for a discussion of expected contributions. |
Also included in the amounts are contract adjustment payments related to the Purchase Contract component of the Equity Units. See Note 7 to the Financial Statements for additional information on the Equity Units.
(f) | At December 31, 2012, total unrecognized tax benefits of $92 million were excluded from this table as PPL cannot reasonably estimate the amount and period of future payments. See Note 5 to the Financial Statements for additional information. |
Dividends
PPL views dividends as an integral component of shareowner return and expects to continue to pay dividends in amounts that are within the context of maintaining a capitalization structure that supports investment grade credit ratings. In 2012, PPL's Board of Directors declared an increase to its quarterly dividend on its common stock to 36.0 cents per share (equivalent to $1.44 per share per annum). In February 2013, PPL's Board of Directors declared an increase to its quarterly dividend on its common stock to 36.75 cents per share (equivalent to $1.47 per share per annum). Future dividends will be declared at the discretion of the Board of Directors and will depend upon future earnings, cash flows, financial and legal requirements and other relevant factors at the time. As discussed in Note 7 to the Financial Statements, subject to certain exceptions, PPL may not declare or pay any cash dividend on its common stock during any period in which PPL Capital Funding defers interest payments on its 2007 Series A Junior Subordinated Notes due 2067, its 4.625% Junior Subordinated Notes due 2018, or its 4.32% Junior Subordinated Notes due 2019 or until deferred contract adjustment payments on PPL's Purchase Contracts have been paid. No such deferrals have occurred or are currently anticipated.
See Note 7 to the Financial Statements for other restrictions related to distributions on capital interests for PPL subsidiaries.
Purchase or Redemption of Debt Securities
PPL will continue to evaluate its outstanding debt securities and may decide to purchase or redeem these securities depending upon prevailing market conditions and available cash.
Rating Agency Actions
Moody's, S&P and Fitch periodically review the credit ratings on the debt of PPL and its subsidiaries. Based on their respective independent reviews, the rating agencies may make certain ratings revisions or ratings affirmations.
A credit rating reflects an assessment by the rating agency of the creditworthiness associated with an issuer and particular securities that it issues. The credit ratings of PPL and its subsidiaries are based on information provided by PPL and other sources. The ratings of Moody's, S&P and Fitch are not a recommendation to buy, sell or hold any securities of PPL or its subsidiaries. Such ratings may be subject to revisions or withdrawal by the agencies at any time and should be evaluated independently of each other and any other rating that may be assigned to the securities. The credit ratings of PPL and its subsidiaries affect its liquidity, access to capital markets and cost of borrowing under its credit facilities.
The following table sets forth PPL's and its subsidiaries' security credit ratings as of December 31, 2012.
| | Senior Unsecured | | Senior Secured | | Commercial Paper |
| | | | | | | | | | | | | | | | | | |
Issuer | | Moody's | | S&P | | Fitch | | Moody's | | S&P | | Fitch | | Moody's | | S&P | | Fitch |
| | | | | | | | | | | | | | | | | | |
PPL Energy Supply | | Baa2 | | BBB | | BBB | | | | | | | | P-2 | | A-2 | | F-2 |
| | | | | | | | | | | | | | | | | | |
PPL Capital Funding | | Baa3 | | BBB- | | BBB | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
PPL Electric | | | | | | | | A3 | | A- | | A- | | P-2 | | A-2 | | F-2 |
| | | | | | | | | | | | | | | | | | |
PPL Ironwood | | | | | | | | B2 | | B | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
LKE | | Baa2 | | BBB- | | BBB+ | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
LG&E | | | | | | A | | A2 | | A- | | A+ | | P-2 | | A-2 | | F-2 |
| | | | | | | | | | | | | | | | | | |
KU | | | | | | A | | A2 | | A- | | A+ | | P-2 | | A-2 | | F-2 |
| | | | | | | | | | | | | | | | | | |
PPL WEM | | Baa3 | | BBB- | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
WPD (East Midlands) | | Baa1 | | BBB | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
WPD (West Midlands) | | Baa1 | | BBB | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
PPL WW | | Baa3 | | BBB- | | BBB | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
WPD (South Wales) | | Baa1 | | BBB | | A- | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
WPD (South West) | | Baa1 | | BBB | | A- | | | | | | | | P-2 | | | | |
A downgrade in PPL's or its subsidiaries' credit ratings could result in higher borrowing costs and reduced access to capital markets. PPL and its subsidiaries have no credit rating triggers that would result in the reduction of access to capital markets or the acceleration of maturity dates of outstanding debt.
In addition to the credit ratings noted above, the rating agencies took the following actions related to PPL and its subsidiaries in 2012.
In January 2012, S&P affirmed its rating and revised its outlook, from positive to stable, for PPL Montana's Pass Through Certificates due 2020.
In February 2012, Fitch assigned ratings to the two newly established commercial paper programs for LG&E and KU.
In March 2012, Moody's affirmed the following ratings:
· | the long-term ratings of the First Mortgage Bonds for LG&E and KU; |
· | the issuer ratings for LG&E and KU; and |
· | the bank loan ratings for LG&E and KU. |
Also in March 2012, Moody's and S&P each assigned short-term ratings to the two newly established commercial paper programs for LG&E and KU.
In March and May 2012, Moody's, S&P and Fitch affirmed the long-term ratings for LG&E's 2003 Series A and 2007 Series B pollution control bonds.
Following the announcement of the then-pending acquisition of AES Ironwood, L.L.C. in February 2012, the rating agencies took the following actions:
· | In March 2012, Moody's placed AES Ironwood, L.L.C.'s senior secured bonds under review for possible ratings upgrade. |
· | In April 2012, S&P affirmed the rating of AES Ironwood, L.L.C.'s senior secured bonds. |
In May 2012, Fitch downgraded its rating, from BBB to BBB- and revised its outlook, from negative to stable, for PPL Montana's Pass Through Certificates due 2020.
In June 2012, Fitch assigned a rating and outlook to PPL Capital Funding's $400 million of 4.20% Senior Notes.
In August 2012, Fitch assigned a rating and outlook to PPL Electric's $250 million First Mortgage Bonds.
In August 2012, S&P and Moody's assigned a rating to PPL Electric's $250 million First Mortgage Bonds.
In October 2012, Moody's, S&P and Fitch assigned a rating to PPL Capital Funding's $400 million of 3.50% Senior Notes.
In November 2012, Fitch affirmed the long-term issuer default rating and senior unsecured rating of PPL WW, WPD (South Wales) and WPD (South West).
In November 2012, S&P revised its outlook, from stable to negative, for PPL Montana's Pass Through Certificates due 2020.
In November 2012, Moody's and S&P affirmed the long-term ratings for LG&E's 2007 Series A pollution control bonds.
In December 2012, Fitch affirmed the issuer default ratings, individual security ratings and outlooks for PPL, PPL Capital Funding, PPL Electric, LKE, LG&E and KU.
In December 2012, Fitch affirmed the issuer default rating, individual security rating and revised the outlook, from stable to negative, for PPL Energy Supply.
In February 2013, Moody's upgraded its rating, from Ba1 to B2, and revised the outlook from under review to stable for PPL Ironwood.
Ratings Triggers
As discussed in Note 7 to the Financial Statements, certain of WPD's senior unsecured notes may be put by the holders back to the issuer for redemption if the long-term credit ratings assigned to the notes are withdrawn by any of the rating agencies (Moody's, S&P, or Fitch) or reduced to a non-investment grade rating of Ba1 or BB+ in connection with a restructuring event. A restructuring event includes the loss of, or a material adverse change to, the distribution licenses under which WPD (East Midlands), WPD (South West), WPD (South Wales) and WPD (West Midlands) operate and would be a trigger event in that company. These notes totaled £3.3 billion (approximately $5.3 billion) nominal value at December 31, 2012.
PPL and PPL Energy Supply have various derivative and non-derivative contracts, including contracts for the sale and purchase of electricity and fuel, commodity transportation and storage, tolling agreements, and interest rate and foreign currency instruments, which contain provisions that require PPL and PPL Energy Supply to post additional collateral, or permit the counterparty to terminate the contract, if PPL's or PPL Energy Supply's credit rating were to fall below investment grade. See Note 19 to the Financial Statements for a discussion of "Credit Risk-Related Contingent Features," including a discussion of the potential additional collateral that would have been required for derivative contracts in a net liability position at December 31, 2012. At December 31, 2012, if PPL's and its subsidiaries' credit ratings had been below investment grade, PPL would have been required to prepay or post an additional $501 million of collateral to counterparties for both derivative and non-derivative commodity and commodity-related contracts used in its generation, marketing and trading operations and interest rate and foreign currency contracts.
Guarantees for Subsidiaries
PPL guarantees certain consolidated affiliate financing arrangements that enable certain transactions. Some of the guarantees contain financial and other covenants that, if not met, would limit or restrict the consolidated affiliates' access to funds under these financing arrangements, require early maturity of such arrangements or limit the consolidated affiliates' ability to enter into certain transactions. At this time, PPL believes that these covenants will not limit access to relevant funding sources. See Note 15 to the Financial Statements for additional information about guarantees.
Off-Balance Sheet Arrangements
PPL has entered into certain agreements that may contingently require payment to a guaranteed or indemnified party. See Note 15 to the Financial Statements for a discussion of these agreements.
Risk Management - Energy Marketing & Trading and Other
Market Risk
See Notes 1, 18, and 19 to the Financial Statements for information about PPL's riskitems management objectives, valuation techniques and accounting designations.
The forward-looking information presented below provides estimates of what may occur in the future, assuming certain adverse market conditions and model assumptions. Actual future results may differ materially from those presented. These disclosures are not precise indicators of expected future losses, but only indicators of possible losses under normal market conditions at a given confidence level.
Commodity Price Risk (Non-trading)
PPL segregates its non-trading activities into two categories: hedge activity and economic activity. Transactions that are accounted for as hedge activity qualify for hedge accounting treatment. The economic activity category includes transactions that address a specific risk, but were not eligible for hedge accounting or for which hedge accounting was not elected. This activity includes the changes in fair value of positions used to hedge a portion of the economic value of PPL's competitive generation assets and full-requirement sales and retail contracts. This economic activity is subject to changes in fair value due to market price volatility of the input and output commodities (e.g., fuel and power). Although they do not receive hedge accounting treatment, these transactions are considered non-trading activity. The net fair value of economic positions at December 31, 2012 and 2011 was a net asset/(liability) of $346 million and $(63) million. See Note 19 to the Financial Statements for additional information.
To hedge the impact of market price volatility on PPL's energy-related assets, liabilities and other contractual arrangements, PPL both sells and purchases physical energy at the wholesale level under FERC market-based tariffs throughout the U.S. and enters into financial exchange-traded and over-the-counter contracts. PPL's non-trading commodity derivative contracts range in maturity through 2019.
The following table sets forth the changes in the net fair value of non-trading commodity derivative contracts at December 31, 2012. See Notes 18 and 19 to the Financial Statements for additional information.
| | | Gains (Losses) |
| | | 2012 | | 2011 |
| | | | | | | |
Fair value of contracts outstanding at the beginning of the period | | $ | 1,082 | | $ | 947 |
Contracts realized or otherwise settled during the period | | | (1,005) | | | (517) |
Fair value of new contracts entered into during the period (a) | | | 7 | | | 13 |
Other changes in fair value | | | 389 | | | 639 |
Fair value of contracts outstanding at the end of the period | | $ | 473 | | $ | 1,082 |
(a) | Represents the fair value of contracts at the end of the quarter of their inception. |
The following table segregates the net fair value of non-trading commodity derivative contracts at December 31, 2012 based on the level of observability of the information used to determine the fair value.
| | | Net Asset (Liability) |
| | | Maturity | | | | | | | | Maturity | | | |
| | | Less Than | | Maturity | | Maturity | | in Excess | | Total Fair |
| | | 1 Year | | 1-3 Years | | 4-5 Years | | of 5 Years | | Value |
Source of Fair Value | | | | | | | | | | | | | | | |
Prices based on significant observable inputs (Level 2) | | $ | 452 | | $ | 15 | | $ | (20) | | $ | 5 | | $ | 452 |
Prices based on significant unobservable inputs (Level 3) | | | 8 | | | 10 | | | 3 | | | | | | 21 |
Fair value of contracts outstanding at the end of the period | | $ | 460 | | $ | 25 | | $ | (17) | | $ | 5 | | $ | 473 |
PPL sells electricity, capacity and related services and buys fuel on a forward basis to hedge the value of energy from its generation assets. If PPL were unable to deliver firm capacity and energy or to accept the delivery of fuel under its agreements, under certain circumstances it could be required to pay liquidating damages. These damages would be based on the difference between the market price and the contract price of the commodity. Depending on price changes in the wholesale energy markets, such damages could be significant. Extreme weather conditions, unplanned power plant outages, transmission disruptions, nonperformance by counterparties (or their counterparties) with which it has energy contracts and other factors could affect PPL's ability to meet its obligations, or cause significant increases in the market price of replacement energy. Although PPL attempts to mitigate these risks, there can be no assurance that it will be able to fully meet its firm obligations, that it will not be required to pay damages for failure to perform, or that it will not experience counterparty nonperformance in the future. In connection with its bankruptcy proceedings, a significant counterparty, SMGT, had been purchasing lower volumes of electricity than prescribed in the contract and effective April 1, 2012 the contract was terminated. PPL cannot predict the prices or other terms on which it will be able to market to third parties the power that SMGT will not purchase from PPL EnergyPlus due to the termination of this contract. See Note 15 to the Financial Statements for additional information.
Commodity Price Risk (Trading)
PPL's trading commodity derivative contracts range in maturity through 2017. The following table sets forth changes in the net fair value of trading commodity derivative contracts at December 31, 2012. See Notes 18 and 19 to the Financial Statements for additional information.
| | Gains (Losses) |
| | 2012 | | 2011 |
| | | | | | |
Fair value of contracts outstanding at the beginning of the period | | $ | (4) | | $ | 4 |
Contracts realized or otherwise settled during the period | | | 20 | | | (14) |
Fair value of new contracts entered into during the period (a) | | | 17 | | | 10 |
Other changes in fair value | | | (4) | | | (4) |
Fair value of contracts outstanding at the end of the period | | $ | 29 | | $ | (4) |
(a) | Represents the fair value of contracts at the end of the quarter of their inception. |
The following table segregates the net fair value of trading commodity derivative contracts at December 31, 2012 based on the level of observability of the information used to determine the fair value.
| | | Net Asset (Liability) |
| | | Maturity | | | | | | | | Maturity | | | |
| | | Less Than | | Maturity | | Maturity | | in Excess | | Total Fair |
| | | 1 Year | | 1-3 Years | | 4-5 Years | | of 5 Years | | Value |
Source of Fair Value | | | | | | | | | | | | | | | |
Prices based on significant observable inputs (Level 2) | | $ | 18 | | $ | 10 | | | | | | | | $ | 28 |
Prices based on significant unobservable inputs (Level 3) | | | 1 | | | | | | | | | | | | 1 |
Fair value of contracts outstanding at the end of the period | | $ | 19 | | $ | 10 | | | | | | | | $ | 29 |
VaR Models
A VaR model is utilized to measure commodity price risk in domestic gross energy margins for its non-trading and trading portfolios. VaR is a statistical model that attempts to estimate the value of potential loss over a given holding period under normal market conditions at a given confidence level. VaR is calculated using a Monte Carlo simulation technique based on a five-day holding period at a 95% confidence level. Given the company's disciplined hedging program, the non-trading VaR exposure is expected to be limited in the short-term. The VaR for portfolios using end-of-month results for the period was as follows.
| | | Trading VaR | | Non-Trading VaR |
| | | 2012 | | 2011 | | 2012 | | 2011 |
95% Confidence Level, Five-Day Holding Period | | | | | | | | | | | | |
| Period End | | $ | 2 | | $ | 1 | | $ | 12 | | $ | 6 |
| Average for the Period | | | 3 | | | 3 | | | 10 | | | 5 |
| High | | | 8 | | | 6 | | | 12 | | | 7 |
| Low | | | 1 | | | 1 | | | 7 | | | 4 |
The trading portfolio includes all proprietary trading positions, regardless of the delivery period. All positions not considered proprietary trading are considered non-trading. The non-trading portfolio includes the entire portfolio, including generation, with delivery periods through the next 12 months. Both the trading and non-trading VaR computations exclude FTRs due to the absence of reliable spot and forward markets. The fair value of the non-trading and trading FTR positions was insignificant at December 31, 2012.
Interest Rate Risk
PPL and its subsidiaries issue debt to finance their operations, which exposes them to interest rate risk. PPL utilizes various financial derivative instruments to adjust the mix of fixed and floating interest rates in its debt portfolio, adjust the duration of its debt portfolio and lock in benchmark interest rates in anticipation of future financing, when appropriate. Risk limits under the risk management program are designed to balance risk exposure to volatility in interest expense and changes in the fair value of PPL's debt portfolio due to changes in the absolute level of interest rates.
At December 31, 2012 and 2011, PPL's potential annual exposure to increased interest expense, based on a 10% increase in interest rates, was not significant.
PPL is also exposed to changes in the fair value of its domestic and international debt portfolios. PPL estimated that a 10% decrease in interest rates at December 31, 2012 would increase the fair value of its debt portfolio by $611 million, compared with $635 million at December 31, 2011.
PPL had the following interest rate hedges outstanding at December 31.
| | | 2012 | | 2011 |
| | | | | | | | | Effect of a | | | | | | | | Effect of a |
| | | | | Fair Value, | | 10% Adverse | | | | Fair Value, | | 10% Adverse |
| | | Exposure | | Net - Asset | | Movement | | Exposure | | Net - Asset | | Movement |
| | | Hedged | | (Liability) (a) | | in Rates (b) | | Hedged | | (Liability) (a) | | in Rates (b) |
Cash flow hedges | | | | | | | | | | | | | | | | | | |
| Interest rate swaps (c) | | $ | 1,165 | | $ | (7) | | $ | (34) | | $ | 150 | | $ | (3) | | $ | (3) |
| Cross-currency swaps (d) | | | 1,262 | | | 10 | | | (179) | | | 1,262 | | | 22 | | | (187) |
Fair value hedges | | | | | | | | | | | | | | | | | | |
| Interest rate swaps | | | | | | | | | | | | 99 | | | 4 | | | |
Economic hedges | | | | | | | | | | | | | | | | | | |
| Interest rate swaps (e) | | | 179 | | | (58) | | | (3) | | | 179 | | | (60) | | | (4) |
(a) | Includes accrued interest, if applicable. |
(b) | Effects of adverse movements decrease assets or increase liabilities, as applicable, which could result in an asset becoming a liability. |
(c) | PPL utilizes various risk management instruments to reduce its exposure to the expected future cash flow variability of its debt instruments. These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financing. While PPL is exposed to changes in the fair value of these instruments, any changes in the fair value of such cash flow hedges are recorded in equity or as regulatory assets or liabilities, if recoverable through regulated rates. The changes in fair value of these instruments are then reclassified into earnings in the same period during which the item being hedged affects earnings. Sensitivities represent a 10% adverse movement in interest rates. The positions outstanding at December 31, 2012 mature through 2043. |
(d) | PPL utilizes cross-currency swaps to hedge the interest payments and principal of WPD's U.S. dollar-denominated senior notes. While PPL is exposed to changes in the fair value of these instruments, any change in the fair value of these instruments is recorded in equity and reclassified into earnings in the same period during which the item being hedged affects earnings. Sensitivities represent a 10% adverse movement in both interest rates and foreign currency exchange rates. The positions outstanding at December 31, 2012 mature through 2028. |
(e) | PPL utilizes various risk management instruments to reduce its exposure to the expected future cash flow variability of its debt instruments. These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financing. While PPL is exposed to changes in the fair value of these instruments, any realized changes in the fair value of such economic hedges are recoverable through regulated rates and any subsequent changes in fair value of these derivatives are included in regulatory assets or liabilities. Sensitivities represent a 10% adverse movement in interest rates. The positions outstanding at December 31, 2012 mature through 2033. |
Foreign Currency Risk
PPL is exposed to foreign currency risk, primarily through investments in U.K. affiliates. In addition, PPL's domestic operations may make purchases of equipment in currencies other than U.S. dollars. See Note 1 to the Financial Statements for additional information regarding foreign currency translation.
PPL has adopted a foreign currency risk management program designed to hedge certain foreign currency exposures, including firm commitments, recognized assets or liabilities, anticipated transactions and net investments. In addition, PPL enters into financial instruments to protect against foreign currency translation risk of expected earnings.
PPL had the following foreign currency hedges outstanding at December 31:
| | 2012 | | 2011 |
| | | | | | | | Effect of a 10% | | | | | | | | Effect of a 10% |
| | | | | Fair Value, | | Adverse Movement | | | | | Fair Value, | | Adverse Movement |
| | Exposure | | Net - Asset | | in Foreign Currency | | Exposure | | Net - Asset | | in Foreign Currency |
| | Hedged | | (Liability) | | Exchange Rates (a) | | Hedged | | (Liability) | | Exchange Rates (a) |
| | | | | | | | | | | | | | | | | | |
Net investment hedges (b) | | £ | 162 | | $ | (2) | | $ | (26) | | £ | 92 | | $ | 7 | | $ | (13) |
Economic hedges (c) | | | 1,265 | | | (42) | | | (192) | | | 288 | | | 11 | | | (37) |
(a) | Effects of adverse movements decrease assets or increase liabilities, as applicable, which could result in an asset becoming a liability. |
(b) | To protect the value of a portion of its net investment in WPD, PPL executes forward contracts to sell GBP. The positions outstanding at December 31, 2012 mature through 2013. Excludes the amount of an intercompany loan classified as a net investment hedge. See Note 19 to the Financial Statements for additional information. |
(c) | To economically hedge the translation of expected income denominated in GBP to U.S. dollars, PPL enters into a combination of average rate forwards and average rate options to sell GBP. The forwards and options outstanding at December 31, 2012 mature through 2015. |
NDT Funds - Securities Price Risk
In connection with certain NRC requirements, PPL Susquehanna maintains trust funds to fund certain costs of decommissioning the PPL Susquehanna nuclear plant (Susquehanna). At December 31, 2012, these funds were invested primarily in domestic equity securities and fixed-rate, fixed-income securities and are reflected at fair value on PPL's Balance Sheet. The mix of securities is designed to provide returns sufficient to fund Susquehanna's decommissioning and to compensate for inflationary increases in decommissioning costs. However, the equity securities included in the trusts are exposed to price fluctuation in equity markets, and the values of fixed-rate, fixed-income securities are primarily exposed to changes in interest rates. PPL actively monitors the investment performance and periodically reviews asset allocation in accordance with its nuclear decommissioning trust policy statement. At December 31, 2012, a hypothetical 10% increase in interest rates and a 10% decrease in equity prices would have resulted in an estimated $49 million reduction in the fair value of the trust assets, compared with $43 million at December 31, 2011. See Notes 18 and 23 to the Financial Statements for additional information regarding the NDT funds.
Defined Benefit Plans - Securities Price Risk
See "Application of Critical Accounting Policies - Defined Benefits" for additional information regarding the effect of securities price risk on plan assets.
Credit Risk
Credit risk is the risk that PPL would incur a loss as a result of nonperformance by counterparties of their contractual obligations. PPL maintains credit policies and procedures with respect to counterparty credit (including requirements that counterparties maintain specified credit ratings) and requires other assurances in the form of credit support or collateral in certain circumstances in order to limit counterparty credit risk. However, PPL has concentrations of suppliers and customers among electric utilities, financial institutions and other energy marketing and trading companies. These concentrations may impact PPL's overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions.
PPL includes the effect of credit risk on its fair value measurements to reflect the probability that a counterparty will default when contracts are out of the money (from the counterparty's standpoint). In this case, PPL would have to sell into a lower-priced market or purchase in a higher-priced market. When necessary, PPL records an allowance for doubtful accounts to reflect the probability that a counterparty will not pay for deliveries PPL has made but not yet billed, which are reflected in "Unbilled revenues" on the Balance Sheets. PPL also has established a reserve with respect to certain receivables from SMGT, which is reflected in accounts receivable on the Balance Sheets. See Note 15 to the Financial Statements for additional information.
In 2009, the PUC approved PPL Electric's PLR procurement plan for the period January 2011 through May 2013. To date, PPL Electric has conducted all of its planned competitive solicitations.
Under the standard Supply Master Agreement (the Agreement) for the competitive solicitation process, PPL Electric requires all suppliers to post collateral if their credit exposure exceeds an established credit limit. In the event a supplier defaults on its obligation, PPL Electric would be required to seek replacement power in the market. All incremental costs incurred by PPL Electric would be recoverable from customers in future rates. At December 31, 2012, most of the successful bidders under all of the solicitations had an investment grade credit rating from S&P, and were not required to post collateral under the Agreement. A small portion of bidders were required to post collateral, which totaled less than $1 million, under the Agreement. There is no instance under the Agreement in which PPL Electric is required to post collateral to its suppliers.
See "Overview" in this Item 7 and Notes 15, 16, 18 and 19 to the Financial Statements for additional information on the competitive solicitations, the Agreement, credit concentration and credit risk.
Foreign Currency Translation
The value of the British pound sterling fluctuates in relation to the U.S. dollar. In 2012, changes in this exchange rate resulted in a foreign currency translation gain of $99 million, which primarily reflected a $181 million increase to PP&E offset by an increase of $82 million to net liabilities. In 2011, changes in this exchange rate resulted in a foreign currency translation loss of $51 million, which primarily reflected a $69 million reduction to PP&E offset by a reduction of $18 million to net liabilities. In 2010, changes in this exchange rate resulted in a foreign currency translation loss of $63 million, which primarily reflected a $180 million reduction to PP&E offset by a reduction of $117 million to net liabilities. The impact of foreign currency translation is recorded in AOCI.
Related Party Transactions
PPL is not aware of any material ownership interests or operating responsibility by senior management of PPL, PPL Energy Supply, PPL Electric, LKE, LG&E or KU in outside partnerships, including leasing transactions with variable interest entities, or other entities doing business with PPL. See Note 16 to the Financial Statements for additional information on related party transactions.
Acquisitions, Development and Divestitures
PPL from time to time evaluates opportunities for potential acquisitions, divestitures and development projects. Development projects are reexamined based on market conditions and other factors to determine whether to proceed with the projects, sell, cancel or expand them, execute tolling agreements or pursue other options.
In April 2012, an indirect wholly owned subsidiary of PPL Energy Supply completed the Ironwood Acquisition. In April 2011, PPL, through its indirect, wholly owned subsidiary PPL WEM, completed its acquisition of WPD Midlands. In November 2010, PPL completed its acquisition of LKE. See Note 10 to the Financial Statements for additional information.
See Notes 8, 9 and 10 to the Financial Statements for additional information on the more significant activities.
Environmental Matters
Extensive federal, state and local environmental laws and regulations are applicable to PPL's air emissions, water discharges and the management of hazardous and solid waste, among other areas; and the cost of compliance or alleged non-compliance cannot be predicted with certainty but could be material. In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed by the relevant agencies. Costs may take the form of increased capital expenditures or operating and maintenance expenses, monetary fines, penalties or other restrictions. Many of these environmental law considerations are also applicable to the operations of key suppliers, or customers, such as coal producers and industrial power users, and may impact the cost for their products or their demand for PPL's services.
Physical effects associated with climate change could include the impact of changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to PPL's generation assets, electricity transmission and distribution systems, as well as impacts on customers. In addition, changed weather patterns could potentially reduce annual rainfall in areas where PPL has hydro generating facilities or where river water is used to cool its fossil and nuclear powered generators. PPL cannot currently predict whether its businesses will experience these potential climate change-related risks or estimate the potential cost of their related consequences.
The below provides a discussion of the more significant environmental matters.
Coal Combustion Residuals (CCRs)
In June 2010, the EPA proposed two approaches to regulating CCRs (as either hazardous or non-hazardous) under existing solid waste regulations. A final rulemaking is currently expected before the end of 2015. However, the timing of the final regulations could be accelerated by certain litigation that could require the EPA to issue its regulations sooner. Regulations could impact handling, disposal and/or beneficial use of CCRs. The economic impact could be material if CCRs are regulated as hazardous waste, and significant if regulated as non-hazardous, in accordance with the proposed rule.
Effluent Limitation Guidelines
The EPA is to issue guidelines for technology-based limits in discharge permits for scrubber wastewater and is expected to require dry ash handling. The EPA agreed, in recent settlement negotiations with environmentalists, to propose revisions to its effluent limitation guidelines (ELGs) by April 2013, with a final rule in late 2014. Limits could be so stringent that plants may consider extensive new or modified wastewater treatment facilities and possibly zero liquid discharge operations, the cost of which could be significant. Impacts should be better understood after the proposed rule is issued.
316(b) Cooling Water Intake Structure Rule
In April 2011, the EPA published a draft regulation under Section 316(b) of the Clean Water Act, which regulates cooling water intakes for power plants. The draft rule has two provisions: one requires installation of Best Technology Available (BTA) to reduce mortality of aquatic organisms that are pulled into the plant cooling water system (entrainment), and the second imposes standards for reduction of mortality of aquatic organisms trapped on water intake screens (impingement). A final rule is expected in June 2013. The proposed regulation would apply to nearly all PPL-owned steam electric plants in Pennsylvania, Kentucky, and Montana, potentially even including those equipped with closed-cycle cooling systems. PPL's compliance costs could be significant, especially if the final rule requires closed-cycle systems at plants that do not currently have them or conversions of once-through systems to closed-cycle.
GHG Regulations
In 2013, the EPA is expected to finalize limits on GHG emissions from new power plants and to begin working on a proposal for such emissions from existing power plants. The EPA's proposal on GHG emissions from new power plants would effectively preclude construction of any coal-fired plants and could even be difficult for new gas-fired plants to meet. With respect to existing power plants, the impact could be very significant, depending on the structure and stringency of the final rule. PPL, along with others in the industry, filed comments on the EPA's proposal related to GHG emissions from new plants. With respect to GHG limits for existing plants, PPL will advocate for reasonable, flexible requirements.
MATS
The EPA finalized MATS requiring fossil-fuel fired plants to reduce emissions of mercury and other hazardous air pollutants by April 16, 2015. The rule is being challenged by industry groups and states. The EPA has subsequently proposed changes to the rule with respect to new sources to address the concern that the rule effectively precludes new coal plants. PPL is generally well-positioned to comply with MATS, primarily due to recent investments in environmental controls and approved Environmental Cost Recovery (ECR) plans to install additional controls at some of our Kentucky plants. PPL is evaluating chemical additive systems for mercury control at Brunner Island, and modifications to existing controls at Colstrip for improved particulate matter reductions. In September 2012, PPL announced its intention to place its Corette plant in long-term reserve status beginning in April 2015 due to expected market conditions and costs to comply with MATS.
CSAPR and CAIR
In 2011, the EPA finalized its CSAPR regulating emissions of nitrous oxide and sulfur dioxide through new allowance trading programs which were to be implemented in two phases (2012 and 2014). Like its predecessor, the CAIR, CSAPR targeted sources in the eastern United States. In December 2011, the U.S. Court of Appeals for the District of Columbia Circuit (the Court) stayed implementation of CSAPR, leaving CAIR in place. Subsequently, in August 2012, the Court vacated and remanded CSAPR back to the EPA for further rulemaking, again leaving CAIR in place, pending further EPA action. PPL plants in Pennsylvania and Kentucky will continue to comply with CAIR through optimization of existing controls, balanced with emission allowance purchases. The Court's August decision leaves plants in CSAPR-affected states potentially exposed to more stringent emission reductions due to regional haze implementation (it was previously determined that CSAPR or CAIR participation satisfies regional haze requirements), and/or petitions to the EPA by downwind states under Section 126 of the Clean Air Act requesting the EPA to require plants that allegedly contribute to downwind non-attainment to take action to reduce emissions.
Regional Haze - Montana
The EPA signed its final Federal Implementation Plan (FIP) of the Regional Haze Rules for Montana in September 2012, with tighter emissions limits for Colstrip Units 1 & 2 based on the installation of new controls (no limits or additional controls were specified for Colstrip Units 3 & 4), and tighter emission limits for Corette (which are not based on additional controls). The cost of the potential additional controls for Colstrip Units 1 & 2, if required, could be significant. PPL expects to meet the tighter permit limits at Corette without any significant changes to operations, although other requirements have led to the planned suspension of operations at Corette beginning in April 2015 (see "MATS" discussion above).
See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for further discussion of environmental matters.
Competition
See "Competition" under each of PPL's reportable segments in "Item 1. Business - Segment Information" and "Item 1A. Risk Factors" for a discussion of competitive factors affecting PPL.
New Accounting Guidance
See Notes 1 and 24 to the Financial Statements for a discussion of new accounting guidance adopted and pending adoption.
Application of Critical Accounting Policies
Financial condition and results of operations are impacted by the methods, assumptions and estimates used in the application of critical accounting policies. The following accounting policies are particularly important to the financial condition or results of operations, and require estimates or other judgments of matters inherently uncertain. Changes in the estimates or other judgments included within these accounting policies could result in a significant change to the information presented in the Financial Statements (these accounting policies are also discussed in Note 1 to the Financial Statements). Senior management has reviewed these critical accounting policies, the following disclosures regarding their application and the estimates and assumptions regarding them, with PPL's Audit Committee.
Price Risk Management
See "Price Risk Management" in Note 1 to the Financial Statements, as well as "Risk Management - Energy Marketing & Trading and Other" above.
Defined Benefits
Certain PPL subsidiaries sponsor various qualified funded and non-qualified unfunded defined benefit pension plans. Certain PPL subsidiaries also sponsor both funded and unfunded other postretirement benefit plans. These plans are applicable to the majority of the employees of PPL. PPL and certain of its subsidiaries record an asset or liability to recognize the funded status of all defined benefit plans with an offsetting entry to OCI or regulatory assets and liabilities for amounts that are expected to be recovered through regulated customer rates. Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets. See Note 13 to the Financial Statements for additional information about the plans and the accounting for defined benefits.
PPL and its subsidiaries make certain assumptions regarding the valuation of benefit obligations and the performance of plan assets. When accounting for defined benefits, delayed recognition in earnings of differences between actual results and expected or estimated results is a guiding principle. Annual net periodic defined benefit costs are recorded in current earnings based on estimated results. Any differences between actual and estimated results are recorded in OCI or regulatory assets and liabilities for amounts that are expected to be recovered through regulated customer rates. These amounts in AOCI or regulatory assets and liabilities are amortized to income over future periods. The delayed recognition allows for a smoothed recognition of costs over the working lives of the employees who benefit under the plans. The primary assumptions are:
· | Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due.
|
· | Expected Return on Plan Assets - Management projects the long-term rates of return on plan assets based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes. These projected returns reduce the net benefit costs PPL records currently. |
· | Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement. |
· | Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care. |
In selecting a discount rate for its U.S. defined benefit plans, PPL starts with a cash flow analysis of the expected benefit payment stream for its plans. The plan-specific cash flows are matched against the coupons and expected maturity values of individually selected bonds. This bond matching process begins with the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, serving as the base from which those with the lowest and highest yields were eliminated to develop an appropriate subset of bonds. Individual bonds were then selected based on the timing of each plan's cash flows and parameters were established as to the percentage of each individual bond issue that could be hypothetically purchased and the surplus reinvestment rates to be assumed. At December 31, 2012, PPL decreased the discount rate for its U.S. pension plans from 5.06% to 4.22% and decreased the discount rate for its other postretirement benefit plans from 4.80% to 4.00%.
In selecting a discount rate for its U.K. defined benefit plans, PPL starts with a cash flow analysis of the expected benefit payment stream for its plans. These plan-specific cash flows were matched against a spot-rate yield curve to determine the assumed discount rate, which used an iBoxx British pounds sterling denominated corporate bond index as its base. An individual bond matching approach is not used for U.K. pension plans because the universe of bonds in the U.K. is not deep enough to adequately support such an approach. At December 31, 2012, the discount rate for the U.K. pension plans was decreased from 5.24% to 4.27% as a result of this assessment.
The expected long-term rates of return for PPL's U.S. defined benefit pension and other postretirement benefit plans have been developed using a best-estimate of expected returns, volatilities and correlations for each asset class. PPL management corroborates these rates with expected long-term rates of return calculated by its independent actuary, who uses a building block approach that begins with a risk-free rate of return with factors being added such as inflation, duration, credit spreads and equity risk. Each plan's specific asset allocation is also considered in developing a reasonable return assumption.
At December 31, 2012, PPL's expected return on plan assets decreased from 7.07% to 7.02% for its U.S. pension plans and increased from 5.93% to 5.97% for its other postretirement benefit plans. The expected long-term rates of return for PPL's U.K. pension plans have been developed by PPL management with assistance from an independent actuary using a best-estimate of expected returns, volatilities and correlations for each asset class. For the U.K. plans, PPL's expected return on plan assets decreased from 7.17% to 7.16% at December 31, 2012.
In selecting a rate of compensation increase, PPL considers past experience in light of movements in inflation rates. At December 31, 2012, PPL's rate of compensation increase decreased from 4.02% to 3.98% for its U.S. pension plans and 4.00% to 3.97% for its other postretirement benefit plans. For the U.K. plans, PPL's rate of compensation increase remained at 4.00% at December 31, 2012.
In selecting health care cost trend rates, PPL considers past performance and forecasts of health care costs. At December 31, 2012, PPL's health care cost trend rates were 8.00% for 2013, gradually declining to 5.50% for 2019.
A variance in the assumptions listed above could have a significant impact on accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and OCI or regulatory assets and liabilities for LG&E, KU and PPL Electric. While the charts below reflect either an increase or decrease in each assumption, the inverse of this change would impact the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and OCI or regulatory assets and liabilities for LG&E, KU and PPL Electric by a similar amount in the opposite direction. The sensitivities below reflect an evaluation of the change based solely on a change in that assumption and does not include income tax effects.
At December 31, 2012, the defined benefit plans were recorded as follows.
Pension liabilities | | | (2,084) |
Other postretirement benefit liabilities | | | (301) |
The following chart reflects the sensitivities in the December 31, 2012 Balance Sheet associated with a change in certain assumptions based on PPL's primary defined benefit plans.
| | Increase (Decrease) |
| | | | | Impact on | | | | | Impact on |
| | Change in | | defined benefit | | Impact on | | regulatory |
Actuarial assumption | | assumption | | liabilities | | OCI | | assets |
| | | | | | | | | | | | |
Discount Rate | | | (0.25)% | | $ | 473 | | $ | (389) | | $ | 84 |
Rate of Compensation Increase | | | 0.25% | | | 66 | | | (54) | | | 12 |
Health Care Cost Trend Rate (a) | | | 1.00% | | | 7 | | | (1) | | | 6 |
(a) | Only impacts other postretirement benefits. |
In 2012, PPL recognized net periodic defined benefit costs charged to operating expensebelieve are indicative of $166 million. This amount represents a $12 million increase from 2011, excluding $50 million of separation costs recorded in 2011. The increase was primarily attributable to increased amortization of losses and a non-qualified plan settlement charge recorded in 2012.
The following chart reflects the sensitivities in the 2012 Statement of Income (excluding income tax effects) associated with a change in certain assumptions based on PPL's primary defined benefit plans.
Actuarial assumption | | | Change in assumption | | | Impact on defined benefit costs |
| | | | | | |
Discount Rate | | | (0.25)% | | $ | 24 |
Expected Return on Plan Assets | | | (0.25)% | | | 26 |
Rate of Compensation Increase | | | 0.25% | | | 10 |
Health Care Cost Trend Rate (a) | | | 1.00% | | | 1 |
(a) | Only impacts other postretirement benefits. |
Asset Impairment (Excluding Investments)
Impairment analyses are performed for long-lived assets that are subject to depreciation or amortization whenever events or changes in circumstances indicate that a long-lived asset's carrying amount may not be recoverable. For these long-lived assets classified as held and used, such events or changes in circumstances are:
· | a significant decrease in the market price of an asset; |
· | a significant adverse change in the manner in which an asset is being used or in its physical condition; |
· | a significant adverse change in legal factors or in the business climate; |
· | an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of an asset; |
· | a current period operating or cash flow loss combined with a history of losses or a forecast that demonstrates continuing losses; or |
· | a current expectation that, more likely than not, an asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. |
For a long-lived asset classified as held and used, an impairment is recognized when the carrying amount of the asset is not recoverable and exceeds its fair value. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset is impaired, an impairment loss is recorded to adjust the asset's carrying amount to its estimated fair value. Management must make significant judgments to estimate future cash flows, including the useful lives of long-lived assets, the fair value of the assets and management's intent to use the assets. Alternate courses of action are considered to recover the carrying amount of a long-lived asset, and estimated cash flows from the "most likely" alternative are used to assess impairment whenever one alternative is clearly the most likely outcome. If no alternative is clearly the most likely, then a probability-weighted approach is used taking into consideration estimated cash flows from the alternatives. For assets tested for impairment as of the balance sheet date, the estimates of future cash flows used in that test consider the likelihood of possible outcomes that existed at the balance sheet date, including the assessment of the likelihood of a future sale of the assets. That assessment is not revised based on events that occur after the balance sheet date. Changes in assumptions and estimates could result in significantly different results than those identified and recorded in the financial statements.
In September 2012, PPL Energy Supply announced its intention, beginning in April 2015, to place the Corette coal-fired plant in Montana in long-term reserve status, suspending the plant's operation, due to expected market conditions and the costs to comply with MATS requirements. The Corette plant asset group's carrying amount at December 31, 2012 was approximately $68 million. An impairment analysis was performed for this asset group in the third and fourth quarters of 2012 and it was determined to not be impaired. It is reasonably possible that an impairment could occur in future periods, as higher priced sales contracts settle, adversely impacting projected cash flows.
For a long-lived asset classified as held for sale, an impairment exists when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell. If the asset (disposal group) is impaired, an impairment loss is recorded to adjust the carrying amount to its fair value less cost to sell. A gain is recognized for any subsequent increase in fair value less cost to sell, but not in excess of the cumulative impairment previously recognized.
For determining fair value, quoted market prices in active markets are the best evidence. However, when market prices are unavailable, the Registrant considers all valuation techniques appropriate under the circumstances and for which market participant inputs can be obtained. Generally discounted cash flows are used to estimate fair value, which incorporates market participant inputs when available. Discounted cash flows are calculated by estimating future cash flow streams and applying appropriate discount rates to determine the present value of the cash flow streams.
Goodwill is tested for impairment at the reporting unit level. PPL's reporting units have been determined to be at the operating segment level. A goodwill impairment test is performed annually or more frequently if events or changes in circumstances indicate that the carrying amount of the reporting unit may be greater than the unit's fair value. Additionally, goodwill is tested for impairment after a portion of goodwill has been allocated to a business to be disposed of.
Beginning in 2012, PPL may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative evaluation and test goodwill for impairment using a two-step quantitative test. If the qualitative evaluation (referred to as "step zero") is elected and the assessment results in a determination that it is not more likely than not that the fair value of a reporting unit is less than the carrying amount, the two-step quantitative impairment test is not necessary. However, the quantitative impairment test is required if PPL concludes it is more likely than not the fair value of a reporting unit is less than the carrying amount based on the step zero assessment.
When the two-step quantitative impairment test is elected or required as a result of the step zero assessment, in step one, PPL identifies a potential impairment by comparing the estimated fair value of a reporting unit with its carrying amount, including goodwill, on the measurement date. If the estimated fair value of a reporting unit exceeds its carrying amount, goodwill is not considered impaired. If the carrying amount exceeds the estimated fair value, the second step is performed to measure the amount of impairment loss, if any.
The second step of the quantitative test requires a calculation of the implied fair value of goodwill, which is determined in the same manner as the amount of goodwill in a business combination. That is, the estimated fair value of a reporting unit is allocated to all of the assets and liabilities of that reporting unit as if the reporting unit had been acquired in a business combination and the estimated fair value of the reporting unit was the price paid to acquire the reporting unit. The excess of the estimated fair value of a reporting unit over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. The implied fair value of the reporting unit's goodwill is then compared with the carrying amount of that goodwill. If the carrying amount exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess. The loss recognized cannot exceed the carrying amount of the reporting unit's goodwill.
PPL elected to perform the two-step quantitative impairment test of goodwill for all of its reporting units in the fourth quarter of 2012 and no impairment was recognized. Management used both discounted cash flows and market multiples, which required significant assumptions, to estimate the fair value of the reporting units. For the U.K. Regulated reporting unit, management used only discounted cash flows to estimate the fair value of the reporting unit due to lack of industry comparable transactions. Applying an appropriate weighting to both the discounted cash flow and market multiple valuations (where applicable) a decrease in the forecasted cash flows of 10%, an increase in the discount rate by 25 basis points, or a 10% decrease in the multiples would not have resulted in an impairment of goodwill.
Loss Accruals
Losses are accrued for the estimated impacts of various conditions, situations or circumstances involving uncertain or contingent future outcomes. For loss contingencies, the loss must be accrued if (1) information is available that indicates it is probable that a loss has been incurred, given the likelihood of the uncertain future events, and (2) the amount of the loss can be reasonably estimated. Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." The accrual of contingencies that might result in gains is not recorded unless recovery is assured. Potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events are continuously assessed.
The accounting aspects of estimated loss accruals include (1) the initial identification and recording of the loss, (2) the determination of triggering events for reducing a recorded loss accrual, and (3) the ongoing assessment as to whether a recorded loss accrual is sufficient. All three of these aspects require significant judgment by management. Internal expertise and outside experts (such as lawyers and engineers) are used, as necessary, to help estimate the probability that a loss has been incurred and the amount (or range) of the loss.
No new significant loss accruals were recorded in 2012.
Certain other events have been identified that could give rise to a loss, but that do not meet the conditions for accrual. Such events are disclosed, but not recorded, when it is "reasonably possible" that a loss has been incurred.
When an estimated loss is accrued, the triggering events for subsequently reducing the loss accrual are identified, where applicable. The triggering events generally occur when the contingency has been resolved and the actual loss is paid or written off, or when the risk of loss has diminished or been eliminated. The following are some of the triggering events that provide for the reduction of certain recorded loss accruals:
· | Allowances for uncollectible accounts are reduced when accounts are written off after prescribed collection procedures have been exhausted, a better estimate of the allowance is determined or underlying amounts are ultimately collected. |
· | Environmental and other litigation contingencies are reduced when the contingency is resolved and actual payments are made, a better estimate of the loss is determined or the loss is no longer considered probable. |
Loss accruals are reviewed on a regular basis to assure that the recorded potential loss exposures are appropriate. This involves ongoing communication and analyses with internal and external legal counsel, engineers, operation management and other parties.
See Note 6 and 15 to the Financial Statements for disclosure of loss contingencies accrued and other potential loss contingencies that have not met the criteria for accrual. Note 6 to the Financial Statements includes a discussion of the Ofgem Review of Line Loss Calculation, including the $90 million reduction in the WPD liability.
Asset Retirement Obligations
PPL is required to recognize a liability for legal obligations associated with the retirement of long-lived assets. The initial obligation is measured at its estimated fair value. A conditional ARO must be recognized when incurred if the fair value of the ARO can be reasonably estimated. An equivalent amount is recorded as an increase in the value of the capitalized asset and allocated to expense over the useful life of the asset. Until the obligation is settled, the liability is increased, through the recognition of accretion expense in the statement of income, for changes in the obligation due to the passage of time.
In the case of LG&E and KU, since costs of removal are collected in rates, the depreciation and accretion expense related to an ARO are offset with a regulatory credit on the income statement, such that there is no earnings impact. The regulatory asset created by the regulatory credit is relieved when the ARO has been settled.
See Note 21 to the Financial Statements for further discussion of AROs.
In determining AROs, management must make significant judgments and estimates to calculate fair value. Fair value is developed using an expected present value technique based on assumptions of market participants that considers estimated retirement costs in current period dollars that are inflated to the anticipated retirement date and then discounted back to the date the ARO was incurred. Changes in assumptions and estimates included within the calculations of the fair value of AROs could result in significantly different results than those identified and recorded in the financial statements. Estimated ARO costs and settlement dates, which affect the carrying value of the ARO and the related capitalized asset, are reviewed periodically to ensure that any material changes are incorporated into the latest estimate of the ARO. Any change to the capitalized asset, positive or negative, is amortized over the remaining life of the associated long-lived asset.
At December 31, 2012, AROs totaling $552 million were recorded on the Balance Sheet, of which $16 million is included in "Other current liabilities." Of the total amount, $316 million, or 57%, relates to the nuclear decommissioning ARO. The most significant assumptions surrounding AROs are the forecasted retirement costs, the discount rates and the inflation rates. A variance in any of these inputs could have a significant impact on the ARO liabilities.
The following table reflects the sensitivities related to the nuclear decommissioning ARO liability associated with a change in these assumptions as of December 31, 2012. There is no significant change to the annual depreciation expense of the ARO asset or the annual accretion expense of the ARO liability as a result of changing the assumptions. The sensitivities below reflect an evaluation of the change based solely on a change in that assumption.
| | Change in | | Impact on |
| | Assumption | | ARO Liability |
| | | | | | |
Retirement Cost | | | 10% | | $ | 32 |
Discount Rate | | | (0.25)% | | | 28 |
Inflation Rate | | | 0.25% | | | 32 |
Income Taxes
Significant management judgment is required in developing the provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination of deferred tax assets, liabilities and valuation allowances.
Significant management judgment is required to determine the amount of benefit recognized related to an uncertain tax position. Tax positions are evaluated following a two-step process. The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained. This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position. The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion. The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization, upon settlement, that exceeds 50%. Management considers a number of factors in assessing the benefit to be recognized, including negotiation of a settlement.
On a quarterly basis, uncertain tax positions are reassessed by considering information known at the reporting date. Based on management's assessment of new information, a tax benefit may subsequently be recognized for a previously unrecognized tax position, a previously recognized tax position may be derecognized, or the benefit of a previously recognized tax position may be remeasured. The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements in the future.
At December 31, 2012, it was reasonably possible that during the next 12 months the total amount of unrecognized tax benefits could increase by as much as $10 million or decrease by up to $90 million. This change could result from subsequent recognition, derecognition and/or changes in the measurement of uncertain tax positions related to the creditability of foreign taxes, the timing and utilization of foreign tax credits and the related impact on alternative minimum tax and other credits, the timing and/or valuation of certain deductions, intercompany transactions and unitary filing groups. The events that could cause these changes are direct settlements with taxing authorities, litigation, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.
The balance sheet classification of unrecognized tax benefits and the need for valuation allowances to reduce deferred tax assets also require significant management judgment. Unrecognized tax benefits are classified as current to the extent management expects to settle an uncertain tax position by payment or receipt of cash within one year of the reporting date. Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset. Management considers a number of factors in assessing the realization of a deferred tax asset, including the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies. Any tax planning strategy utilized in this assessment must meet the recognition and measurement criteria utilized to account for an uncertain tax position. Management also considers the uncertainty posed by political risk and the effect of this uncertainty on the various factors that management takes into account in evaluating the need for valuation allowances. The amount of deferred tax assets ultimately realized may differ materially from the estimates utilized in the computation of valuation allowances and may materially impact the financial statements in the future. See Note 5 to the Financial Statements for income tax disclosures.
Regulatory Assets and Liabilities
PPL Electric, LG&E and KU, are subject to cost-based rate regulation. As a result, the effects of regulatory actions are required to be reflected in the financial statements. Assets and liabilities are recorded that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in regulated customer rates. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. In certain cases, regulatory liabilities are recorded based on an understanding or agreement with the regulator that rates have been set to recover costs that are expected to be incurred in the future, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose.
Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory and political environments, the ability to recover costs through regulated rates, recent rate orders to other regulated entities, and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, then asset write-offs would be required to be recognized in operating income. Additionally, the regulatory agencies can provide flexibility in the manner and timing of depreciation of PP&E and amortization of regulatory assets.
At December 31, 2012, PPL had regulatory assets of $1.5 billion and regulatory liabilities of $1.1 billion. All regulatory assets are either currently being recovered under specific rate orders, represent amounts that are expected to be recovered in future rates or benefit future periods based upon established regulatory practices.
See Note 6 to the Financial Statements for additional information on regulatory assets and liabilities.
WPD operates in an incentive-based regulatory structure under distribution licenses granted by Ofgem. WPD's electricity distribution revenues are set every five years through price controls that are not directly based on cost recovery; therefore, WPD is not subject to accounting for the effects of certain types of regulation as prescribed by GAAP and does not record regulatory assets and liabilities.
Other Information
PPL's Audit Committee has approved the independent auditor to provide audit and audit-related services, tax services and other services permitted by Sarbanes-Oxley and SEC rules. The audit and audit-related services include services in connection with statutory and regulatory filings, reviews of offering documents and registration statements, and internal control reviews.
PPL ENERGY SUPPLY, LLC AND SUBSIDIARIES
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The information provided in this Item 7 should be read in conjunction with PPL Energy Supply's Consolidated Financial Statements and the accompanying Notes. Capitalized terms and abbreviations are defined in the glossary. Dollars are in millions unless otherwise noted.
"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:
· | "Overview" provides a description of PPL Energy Supply and its business strategy, a summary of Net Income Attributable to PPL Energy Supply Member and a discussion of certain events related to PPL Energy Supply's results of operations and financial condition. |
· | "Results of Operations" provides a summary of PPL Energy Supply's earnings and a description of key factors expected to impact future earnings. This section ends with explanations of significant changes in principal items on PPL Energy Supply's Statements of Income, comparing 2012 with 2011 and 2011 with 2010. |
· | "Financial Condition - Liquidity and Capital Resources" provides an analysis of PPL Energy Supply's liquidity position and credit profile. This section also includes a discussion of forecasted sources and uses of cash and rating agency actions. |
· | "Financial Condition - Risk Management - Energy Marketing & Trading and Other" provides an explanation of PPL Energy Supply's risk management programs relating to market and credit risk. |
· | "Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of PPL Energy Supply and that require its management to make significant estimates, assumptions and other judgments of matters inherently uncertain. |
Overview
Introduction
PPL Energy Supply is an energy company with headquarters in Allentown, Pennsylvania. Through its subsidiaries, PPL Energy Supply is primarily engaged in the generation and marketing of electricity in two key markets - the northeastern and northwestern U.S.
Business Strategy
PPL Energy Supply's overall strategy is to achieve disciplined optimization of energy supply margins while mitigating volatility in both cash flows and earnings. More specifically, PPL Energy Supply's strategy is to optimize the value from its competitive generation and marketing portfolios. PPL Energy Supply endeavors to do this by matching energy supply with load, or customer demand, under contracts of varying durations with creditworthy counterparties to capture profits while effectively managing exposure to energy and fuel price volatility, counterparty credit risk and operational risk.
To manage financing costs and access to credit markets, a key objective of PPL Energy Supply's business strategy is to maintain a strong credit profile and strong liquidity position. In addition, PPL Energy Supply has financial and operational risk management programs that, among other things, are designed to monitor and manage its exposure to earnings and cash flow volatility related to changes in energy and fuel prices, interest rates, counterparty credit quality and the operating performance of its generating units.
Financial and Operational Developments
Net Income Attributable to PPL Energy Supply Member
Net Income Attributable to PPL Energy Supply Member for 2012, 2011 and 2010 was $474 million, $768 million and $861 million. Earnings in 2012 decreased 38% from 2011 and earnings in 2011 decreased 11% from 2010.
See "Results of Operations" below for further discussion and analysis of the consolidated results of operations.
Economic and Market Conditions
Unregulated Gross Energy Margins associated with PPL Energy Supply's competitive generation and marketing business are impacted by changes in market prices and demand for electricity and natural gas, power plant availability, competition in the markets for retail customers, fuel costs and availability, fuel transportation costs and other costs. Current depressed wholesale market prices for electricity and natural gas have resulted from general weak economic conditions and other factors, including the impact of expanded domestic shale gas development and production. As a result of these factors, PPL Energy Supply has experienced a shift in the dispatching of its competitive generation from coal-fired to combined-cycle gas-fired generation as illustrated in the following table:
| | | Average Utilization Factors (a) |
| | | 2012 | | | 2009 - 2011 |
Pennsylvania coal plants | | | 69% | | | 87% |
Montana coal plants | | | 67% | | | 89% |
Combined-cycle gas plants | | | 98% | | | 72% |
(a) | All periods reflect the years ended December 31. |
This reduction in coal-fired generation output had resulted in a surplus of coal inventory at certain of PPL Energy Supply's Pennsylvania coal plants. To mitigate the risk of exceeding available coal storage, PPL Energy Supply incurred pre-tax charges of $29 million in 2012 to reduce its 2012 and 2013 contracted coal deliveries. PPL Energy Supply will continue to manage its coal inventory to mitigate the financial impact and physical implications of an oversupply; however, no additional coal contract modifications are expected at this time.
In addition, current economic and commodity market conditions indicated a lower value of unhedged future energy margins (primarily in 2014 and forward years) compared to the energy margins in 2012. As has been PPL Energy Supply's practice in periods of changing business conditions, PPL Energy Supply continues to review its future business and operational plans, including capital and operation and maintenance expenditures, as well as its hedging strategies, to help counter the financial effects of low commodity prices.
PPL Energy Supply's businesses are subject to extensive federal, state and local environmental laws, rules and regulations. PPL Energy Supply's competitive generation assets are well positioned to meet these requirements. See Note 15 to the Financial Statements for additional information on these requirements. As a result of these requirements, PPL Energy Supply announced in September 2012 its intention, beginning in April 2015, to place its Corette plant in long-term reserve status, suspending the plant's operation due to expected market conditions and the costs to comply with MATS. The Corette plant asset group's carrying amount at December 31, 2012 was approximately $68 million. Although the Corette plant asset group was not determined to be impaired at December 31, 2012, it is reasonably possible that an impairment could occur in future periods, as higher priced sales contracts settle, adversely impacting projected cash flows.
In light of these economic and market conditions, as well as current and projected environmental regulatory requirements, PPL Energy Supply considered whether certain of its other generating assets were impaired, and determined that no impairment charges were required at December 31, 2012. PPL Energy Supply is unable to predict whether future environmental requirements or market conditions will result in impairment charges for other generating assets or other retirements.
PPL Energy Supply and its subsidiaries may also be impacted in future periods by the uncertainty in the worldwide financial and credit markets. In addition, PPL Energy Supply may be impacted by reductions in the credit ratings of financial institutions and evolving regulations in the financial sector. Collectively, these factors could reduce availability or restrict PPL Energy Supply and its subsidiaries' ability to maintain sufficient levels of liquidity, reduce capital market activities, change collateral posting requirements and increase the associated costs to PPL Energy Supply and its subsidiaries.
PPL Energy Supply cannot predict the future impact that these economic and market conditions and regulatory requirements may have on its financial condition or results of operations.
Susquehanna Turbine Blade Inspection
During 2012, PPL Energy Supply performed inspections of the Unit 1 and Unit 2 turbine blades at the PPL Susquehanna nuclear power plant to further address the issue of turbine blade cracking that was first identified in 2011. The after-tax earnings impact of these 2012 inspections, including reduced energy-sales margins and repair expenses, was approximately $53 million. The after-tax earnings impact of turbine blade related outages in 2011 was approximately $63 million.
Ironwood Acquisition
In April 2012, an indirect, wholly owned subsidiary of PPL Energy Supply completed the acquisition of the equity interests in the owner and operator of the Ironwood Facility. The Ironwood Facility began operation in 2001 and, since 2008, PPL EnergyPlus has supplied natural gas for the facility and received the facility's full electricity output and capacity value pursuant to a tolling agreement that expires in 2021. The acquisition provides PPL Energy Supply, through its subsidiaries, operational control of additional combined-cycle gas generation in PJM. See Note 10 to the Financial Statements for additional information.
Bankruptcy of SMGT
In October 2011, SMGT, a Montana cooperative and purchaser of electricity under a long-term supply contract with PPL EnergyPlus expiring in June 2019 (SMGT Contract), filed for protection under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the District of Montana. At the time of the bankruptcy filing, SMGT was PPL EnergyPlus' largest unsecured credit exposure. This contract was accounted for as NPNS by PPL EnergyPlus.
The SMGT Contract provided for fixed volume purchases on a monthly basis at established prices. Pursuant to a court order and subsequent stipulations entered into between the SMGT bankruptcy trustee and PPL EnergyPlus, since the date of its Chapter 11 filing through January 2012, SMGT continued to purchase electricity from PPL EnergyPlus at the price specified in the SMGT Contract, and made timely payments for such purchases, but at lower volumes than as prescribed in the SMGT Contract. In January 2012, the trustee notified PPL EnergyPlus that SMGT would not purchase electricity under the SMGT Contract for the month of February. In March 2012, the U.S. Bankruptcy Court for the District of Montana issued an order approving the request of the SMGT bankruptcy trustee and PPL EnergyPlus to terminate the SMGT Contract. As a result, the SMGT Contract was terminated effective April 1, 2012, allowing PPL EnergyPlus to resell the electricity previously contracted to SMGT under the SMGT Contract to other customers.
PPL EnergyPlus' receivable under the SMGT Contract totaled approximately $21 million at December 31, 2012, which has been fully reserved.
In July 2012, PPL EnergyPlus filed its proof of claim in the SMGT bankruptcy proceeding. The total claim is approximately $375 million, including the above receivable, predominantly an unsecured claim representing the value for energy sales that will not occur as a result of the termination of the SMGT Contract. No assurance can be given as to the collectability of the claim, thus no amounts have been recorded in the 2012 financial statements.
PPL Energy Supply cannot predict any amounts that it may recover in connection with the SMGT bankruptcy or the prices and other terms on which it will be able to market to third parties the power that SMGT will not purchase from PPL EnergyPlus due to the termination of the SMGT Contract.
Results of Operations
The following discussion provides a summary of PPL Energy Supply's earnings and a description of factors that are expected to impact future earnings. This section ends with "Statement of Income Analysis," which includes explanations of significant year-to-year changes in Unregulated Gross Energy Margins by region and principal line items on PPL Energy Supply's Statements of Income.
Earnings |
| | | | | | | | | | |
Net Income Attributable to PPL Energy Supply Member was: |
| | | | | | | | | | |
| | | 2012 | | 2011 | | 2010 |
| | | | | | | | | | |
Net Income Attributable to PPL Energy Supply Member | | $ | 474 | | $ | 768 | | $ | 861 |
The changes in the components of Net Income Attributable to PPL Energy Supply Member between these periods were due to the following factors, which reflect reclassifications for items included in the Unregulated Gross Energy Margins and certain items that management considers special. See additional detail of these special items in the tables below.
| | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | |
Unregulated Gross Energy Margins | | $ | (197) | | $ | (405) |
Other operation and maintenance | | | (53) | | | (65) |
Depreciation | | | (41) | | | (8) |
Taxes, other than income | | | 6 | | | (9) |
Other Income (Expense) - net | | | (5) | | | |
Interest Expense | | | 16 | | | 4 |
Other | | | (1) | | | |
Income Taxes | | | 102 | | | 146 |
Discontinued operations - Domestic, after-tax - excluding certain revenues and expenses included in margins | | | 3 | | | 16 |
Discontinued operations - International, after-tax | | | | | | (261) |
Special items, after-tax | | | (124) | | | 489 |
Total | | $ | (294) | | $ | (93) |
· | See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Unregulated Gross Energy Margins. |
· | Higher other operation and maintenance in 2012 compared with 2011 due to higher costs at PPL Susquehanna of $27 million including refueling outage costs, payroll-related costs and project costs, $18 million due to the Ironwood Acquisition, $13 million due to outages at eastern fossil and hydroelectric units and $10 million of charges from support groups partially offset by $34 million of trademark royalties with an affiliate in 2011 for which the agreement was terminated December 31, 2011. |
Higher other operation and maintenance in 2011 compared with 2010, primarily due to higher costs at PPL Susquehanna of $30 million largely due to unplanned outages, the refueling outage and payroll-related costs, higher costs at eastern fossil and hydroelectric units of $20 million, largely due to outages, and higher costs at western fossil and hydroelectric units of $15 million, largely resulting from insurance recoveries received in 2010.
· | Higher depreciation in 2012 compared with 2011 primarily due to a $16 million impact from PP&E additions and $17 million due to the Ironwood Acquisition. |
· | Lower interest expense in 2012 compared with 2011 of $14 million due to the impact of redeeming debt not replaced and redeeming debt replaced at a lower interest rate, $10 million due to lower interest on short-term borrowings and $7 million due to 2011 including the acceleration of deferred financing fees related to the July 2011 redemption, partially offset by a $12 million increase related to the debt assumed as a result of the Ironwood Acquisition. |
· | Lower income taxes in 2012 compared with 2011 due to lower 2012 pre-tax income, which reduced income taxes by $110 million and $20 million related to lower adjustments to valuation allowances on Pennsylvania net operating losses, partially offset by $26 million related to the impact of prior period tax return adjustments. |
Lower income taxes in 2011 compared with 2010, due to lower 2011 pre-tax income, which reduced income taxes by $196 million and a $26 million reduction in deferred tax liabilities related to an updated blended state tax rate as a result of a change in state apportionment. These decreases were partially offset by $74 million related to adjustments to valuation allowances on Pennsylvania net operating losses, $13 million in favorable adjustments to uncertain tax benefits recorded in 2010 and an $11 million decrease in the domestic manufacturing deduction tax benefit resulting from revised bonus depreciation estimates.
· | Discontinued operations - International, represents the results of PPL Global which was distributed to PPL Energy Supply's parent, PPL Energy Funding in January 2011. See Note 9 to the Financial Statements for additional information. |
The following after-tax gains (losses), which management considers special items, also impacted the results.
| | | Income Statement | | | | | | | | | |
| | | Line Item | | 2012 | | 2011 | | 2010 |
| | | | | | | | | | |
Adjusted energy-related economic activity, net, net of tax of ($26), ($52), $85 | (a) | | $ | 38 | | $ | 72 | | $ | (121) |
Sales of assets: | | | | | | | | | | |
| Maine hydroelectric generation business, net of tax of $0, $0, ($9) (b) | Disc. Operations | | | | | | | | | 15 |
| Sundance indemnification, net of tax of $0, $0, $0 | Other Income-net | | | | | | | | | 1 |
Impairments: | | | | | | | | | | |
| Emission allowances, net of tax of $0, $1, $6 (c) | Other O&M | | | | | | (1) | | | (10) |
| Renewable energy credits, net of tax of $0, $2, $0 | Other O&M | | | | | | (3) | | | |
| Adjustments - nuclear decommissioning trust investments, net of tax of ($2), $0, $0 | Other Income-net | | | 2 | | | | | | |
| Other asset impairments, net of tax of $0, $0, $0 | Other O&M | | | (1) | | | | | | |
LKE acquisition-related adjustments: | | | | | | | | | | |
| Monetization of certain full-requirement sales contracts, net of tax of $0, $0, $89 | (d) | | | | | | | | | (125) |
| Sale of certain non-core generation facilities, net of tax of $0, $0, $37 (e) | Disc. Operations | | | | | | (2) | | | (64) |
| Reduction of credit facility, net of tax of $0, $0, $4 (f) | Interest Expense | | | | | | | | | (6) |
Other: | | | | | | | | | | |
| Montana hydroelectric litigation, net of tax of $0, ($30), $22 | (g) | | | | | | 45 | | | (34) |
| Litigation settlement - spent nuclear fuel storage, net of tax of $0, ($24), $0 (h) | Fuel | | | | | | 33 | | | |
| Health care reform - tax impact (i) | Income Taxes | | | | | | | | | (5) |
| Montana basin seepage litigation, net of tax of $0, $0, ($1) | Other O&M | | | | | | | | | 2 |
| Counterparty bankruptcy, net of tax of $5, $5, $0 (j) | Other O&M | | | (6) | | | (6) | | | |
| Wholesale supply cost reimbursement, net of tax of $0, ($3), $0 | (k) | | | 1 | | | 4 | | | |
| Ash basin leak remediation adjustment, net of tax of ($1), $0, $0 | Other O&M | | | 1 | | | | | | |
| Coal contract modification payments, net of tax of $12, $0, $0 (l) | Fuel | | | (17) | | | | | | |
Total | | | $ | 18 | | $ | 142 | | $ | (347) |
(a) | See "Reconciliation of Economic Activity" below. |
(b) | Gains recorded on completion of the sale of the Maine hydroelectric generation business. See Note 9 to the Financial Statements for additional information. |
(c) | Primarily represents impairment charges of sulfur dioxide emission allowances. |
(d) | In July 2010, in order to raise additional cash for the LKE acquisition, certain full-requirement sales contracts were monetized that resulted in cash proceeds of $249 million. See "Monetization of Certain Full-Requirement Sales Contracts" in Note 19 to the Financial Statements for additional information. $343 million of pre-tax gains were recorded to "Wholesale energy marketing" and $557 million of pre-tax losses were recorded to "Energy purchases" on the Statement of Income. |
(e) | Consists primarily of the initial impairment charge recorded when the business was classified as held for sale. See Note 9 to the Financial Statements for additional information. |
(f) | In October 2010, PPL Energy Supply made borrowings under its Syndicated Credit Facility in order to enable a subsidiary to make loans to certain affiliates to provide interim financing of amounts required by PPL to partially fund PPL's acquisition of LKE. Subsequent to the repayment of such borrowing, the capacity was reduced, and as a result, PPL Energy Supply wrote off deferred fees in 2010. |
(g) | In March 2010, the Montana Supreme Court substantially affirmed a June 2008 Montana District Court decision regarding lease payments for the use of certain Montana streambeds. In 2010, PPL Montana recorded a pre-tax charge of $56 million, representing estimated rental compensation for years prior to 2010, including interest. Of this total charge $47 million, pre-tax, was recorded to "Other operation and maintenance" and $9 million, pre-tax, was recorded to "Interest Expense" on the Statement of Income. In August 2010, PPL Montana filed a petition for a writ of certiorari with the U.S. Supreme Court requesting the Court's review of this matter. In June 2011, the U.S. Supreme Court granted PPL Montana's petition. In February 2012, the U.S. Supreme Court overturned the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion. Prior to the U.S. Supreme Court decision, $4 million, pre-tax, of interest expense on the rental compensation covered by the court decision was accrued in 2011. As a result of the U.S. Supreme Court decision, PPL Montana reversed its total pre-tax loss accrual of $89 million, which had been recorded prior to the U.S. Supreme Court decision, of which $79 million pre-tax is considered a special item because it represented $65 million of rent for periods prior to 2011 and $14 million of interest accrued on the portion covered by the prior court decision. These amounts were credited to "Other operation and maintenance" and "Interest Expense" on the Statement of Income. See Note 15 to the Financial Statements for additional information. |
(h) | In May 2011, PPL Susquehanna entered into a settlement agreement with the U.S. Government relating to PPL Susquehanna's lawsuit, seeking damages for the Department of Energy's failure to accept spent nuclear fuel from the PPL Susquehanna plant. PPL Susquehanna recorded credits to fuel expense to recognize recovery, under the settlement agreement, of certain costs to store spent nuclear fuel at the Susquehanna plant. This special item represents amounts recorded in 2011 to cover the costs incurred from 1998 through December 2010. |
(i) | Represents income tax expense recorded as a result of the provisions within Health Care Reform which eliminated the tax deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D Coverage. |
(j) | In October 2011, a wholesale customer, SMGT, filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy code. In 2012, PPL EnergyPlus recorded an additional allowance for unpaid amounts under the long-term power contract. In March 2012, the U.S. Bankruptcy Court for the District of Montana approved the request to terminate the contract, effective April 1, 2012. |
(k) | In January 2012, PPL received $7 million pre-tax, related to electricity delivered to a wholesale customer in 2008 and 2009, recorded in "Wholesale energy marketing-Realized." The additional revenue results from several transmission projects approved at PJM for recovery that were not initially anticipated at the time of the electricity auctions and therefore were not included in the auction pricing. A FERC order was issued in 2011 approving the disbursement of these supply costs by the wholesale customer to the suppliers, therefore, PPL Energy Supply accrued its share of this additional revenue in 2011. |
(l) | As a result of lower electricity and natural gas prices, coal-fired generation output decreased during 2012. Contract modification payments were incurred to reduce 2012 and 2013 contracted coal deliveries. |
Reconciliation of Economic Activity
The following table reconciles unrealized pre-tax gains (losses) from the table within "Commodity Price Risk (Non-trading) - Economic Activity" in Note 19 to the Financial Statements to the special item identified as "Adjusted energy-related economic activity, net."
| | | | 2012 | | 2011 | | 2010 |
Operating Revenues | | | | | | | | | |
| | Unregulated retail electric and gas | | $ | (17) | | $ | 31 | | $ | 1 |
| | Wholesale energy marketing | | | (311) | | | 1,407 | | | (805) |
Operating Expenses | | | | | | | | | |
| | Fuel | | | (14) | | | 6 | | | 29 |
| | Energy Purchases | | | 442 | | | (1,123) | | | 286 |
Energy-related economic activity (a) | | | 100 | | | 321 | | | (489) |
Option premiums (b) | | | (1) | | | 19 | | | 32 |
Adjusted energy-related economic activity | | | 99 | | | 340 | | | (457) |
Less: Unrealized economic activity associated with the monetization of certain | | | | | | | | | |
| full-requirement sales contracts in 2010 (c) | | | | | | | | | (251) |
Less: Economic activity realized, associated with the monetization of certain | | | | | | | | | |
| full-requirement sales contracts in 2010 | | | 35 | | | 216 | | | |
Adjusted energy-related economic activity, net, pre-tax | | $ | 64 | | $ | 124 | | $ | (206) |
| | | | | | | | | | | |
Adjusted energy-related economic activity, net, after-tax | | $ | 38 | | $ | 72 | | $ | (121) |
(a) | See Note 19 to the Financial Statements for additional information. |
(b) | Adjustment for the net deferral and amortization of option premiums over the delivery period of the item that was hedged or upon realization. Option premiums are recorded in "Wholesale energy marketing - Realized" and "Energy purchases - Realized" on the Statements of Income. |
(c) | See "Components of Monetization of Certain Full-Requirement Sales Contracts" below. |
Components of Monetization of Certain Full-Requirement Sales Contracts
The following table provides the components of the "Monetization of Certain Full-Requirement Sales Contracts" special item.
| | 2010 |
| | | |
Full-requirement sales contracts monetized (a) | | $ | (68) |
Economic activity related to the full-requirement sales contracts monetized | | | (146) |
Monetization of certain full-requirement sales contracts, pre-tax (b) | | $ | (214) |
| | | |
Monetization of certain full-requirement sales contracts, after-tax | | $ | (125) |
(a) | See "Commodity Price Risk (Non-trading) - Monetization of Certain Full-Requirement Sales Contracts" in Note 19 to the Financial Statements for additional information. |
(b) | Includes unrealized losses of $251 million, which are reflected in "Wholesale energy marketing - Unrealized economic activity" and "Energy purchases - Unrealized economic activity" on the Statement of Income. Also includes net realized gains of $37 million, which are reflected in "Wholesale energy marketing - Realized" and "Energy purchases - Realized" on the Statement of Income. |
2013 Outlook
Excluding special items, PPL Energy Supply projects lower earnings in 2013 compared with 2012, primarily driven by lower energy prices, higher fuel costs, higher operation and maintenance, higher depreciation and higher financing costs, which are partially offset by higher capacity prices and higher nuclear generation output despite scheduled outages for both Susquehanna units to implement a long-term solution to turbine blade issues.
Earnings in future periods are subject to various risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Note 15 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.
Statement of Income Analysis --
Unregulated Gross Energy Margins
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as a non-GAAP financial measure, "Unregulated Gross Energy Margins." "Unregulated Gross Energy Margins" is a single financial performance measure of PPL Energy Supply's competitive energy non-trading and trading activities. In calculating this measure, PPL Energy Supply's energy revenues, which include operating revenues associated with certain PPL Energy Supply businesses that are classified as discontinued operations, are offset by the cost of fuel, energy purchases, certain other operation and maintenance expenses, primarily ancillary charges, gross receipts tax, which is recorded in "Taxes, other than income," and operating expenses associated with certain PPL Energy Supply businesses that are classified as discontinued operations. This performance measure is relevant to PPL Energy Supply due to the volatility in the individual revenue and expense lines on the Statements of Income that comprise "Unregulated Gross Energy Margins." This volatility stems from a number of factors, including the required netting of certain transactions with ISOs and significant fluctuations in unrealized gains and losses. Such factors could result in gains or losses being recorded in either "Wholesale energy marketing" or "Energy purchases" on the Statements of Income. This performance measure includes PLR revenues from energy sales to PPL Electric by PPL EnergyPlus, which are recorded in "Wholesale energy marketing to affiliate" revenue. PPL Energy Supply excludes from "Unregulated Gross Energy Margins" adjusted energy-related economic activity, which includes the changes in fair value of positions used to economically hedge a portion of the economic value of PPL Energy Supply's competitive generation assets, full-requirement sales contracts and retail activities. This economic value is subject to changes in fair value due to market price volatility of the input and output commodities (e.g., fuel and power) prior to the delivery period that was hedged. Also included in adjusted energy-related economic activity is the ineffective portion of qualifying cash flow hedges, the monetization of certain full-requirement sales contracts and premium amortization associated with options. This economic activity is deferred, with the exception of the full-requirement sales contracts that were monetized, and included in "Unregulated Gross Energy Margins" over the delivery period that was hedged or upon realization. This measure is not intended to replace "Operating Income," which is determined in accordance with GAAP, as an indicator of overall operating performance. Other companies may use different measures to analyze and to report on the results of their operations. PPL Energy Supply believes that "Unregulated Gross Energy Margins" provides another criterion to make investment decisions. This performance measure is used, in conjunction with other information, internally by senior management to manage PPL Energy Supply's operations, analyze actual results compared with budget and measure certain corporate financial goals used in determining variable compensation.
Reconciliation of Non-GAAP Financial Measures
The following tables reconcile "Operating Income" to "Unregulated Gross Energy Margins" as defined by PPL Energy Supply for the period ended December 31.
| | | | | | 2012 | | 2011 |
| | | | | | Unregulated | | | | | | | | Unregulated | | | | | | |
| | | | | | Gross Energy | | | | | Operating | | Gross Energy | | | | | | Operating |
| | | | | | Margins | | Other (a) | | Income (b) | | Margins | | Other (a) | | Income (b) |
| | | | | | | | | | | | | | | | | | |
Operating Revenues | | | | | | | | | | | | | | | | | | | | |
| Wholesale energy marketing | | | | | | | | | | | | | | | | | | | | |
| | | | Realized | | $ | 4,412 | | $ | 21 | (c) | | $ | 4,433 | | $ | 3,745 | | $ | 62 | (c) | | $ | 3,807 |
| | | | Unrealized economic activity | | | | | | (311) | (d) | | | (311) | | | | | | 1,407 | (d) | | | 1,407 |
| Wholesale energy marketing | | | | | | | | | | | | | | | | | | | | |
| | to affiliate | | | 78 | | | | | | | 78 | | | 26 | | | | | | | 26 |
| Unregulated retail electric and gas | | | 865 | | | (17) | (d) | | | 848 | | | 696 | | | 31 | (d) | | | 727 |
| Net energy trading margins | | | 4 | | | | | | | 4 | | | (2) | | | | | | | (2) |
| Energy-related businesses | | | | | | 448 | | | | 448 | | | | | | 464 | | | | 464 |
| | | Total Operating Revenues | | | 5,359 | | | 141 | | | | 5,500 | | | 4,465 | | | 1,964 | | | | 6,429 |
| | | | | | 2012 | | 2011 |
| | | | | | Unregulated | | | | | | | | Unregulated | | | | | | |
| | | | | | Gross Energy | | | | | Operating | | Gross Energy | | | | | | Operating |
| | | | | | Margins | | Other (a) | | Income (b) | | Margins | | Other (a) | | Income (b) |
Operating Expenses | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 931 | | | 34 | (e) | | | 965 | | | 1,151 | | | (71) | (e) | | | 1,080 |
| Energy purchases | | | | | | | | | | | | | | | | | | | | |
| | | | Realized | | | 2,204 | | | 56 | (c) | | | 2,260 | | | 912 | | | 248 | (c) | | | 1,160 |
| | | | Unrealized economic activity | | | | | | (442) | (d) | | | (442) | | | | | | 1,123 | (d) | | | 1,123 |
| Energy purchases from affiliate | | | 3 | | | | | | | 3 | | | 3 | | | | | | | 3 |
| Other operation and maintenance | | | 19 | | | 1,022 | | | | 1,041 | | | 16 | | | 913 | | | | 929 |
| Depreciation | | | | | | 285 | | | | 285 | | | | | | 244 | | | | 244 |
| Taxes, other than income | | | 34 | | | 35 | | | | 69 | | | 30 | | | 41 | | | | 71 |
| Energy-related businesses | | | | | | 432 | | | | 432 | | | | | | 458 | | | | 458 |
| | | Total Operating Expenses | | | 3,191 | | | 1,422 | | | | 4,613 | | | 2,112 | | | 2,956 | | | | 5,068 |
| Discontinued Operations | | | | | | | | | | | | | 12 | | | (12) | (f) | | | |
Total | | $ | 2,168 | | $ | (1,281) | | | $ | 887 | | $ | 2,365 | | $ | (1,004) | | | $ | 1,361 |
| | | | | | 2010 | |
| | | | | | Unregulated | | | | | | | |
| | | | | | Gross Energy | | | | | Operating | |
| | | | | | Margins | | Other (a) | | Income (b) | |
Operating Revenues | | | | | | | | | | | |
| Wholesale energy marketing | | | | | | | | | | | |
| | | | Realized | | $ | 4,511 | | $ | 321 | (c) | | $ | 4,832 | |
| | | | Unrealized economic activity | | | | | | (805) | (d) | | | (805) | |
| Wholesale energy marketing | | | | | | | | | | | |
| | to affiliate | | | 320 | | | | | | | 320 | |
| Unregulated retail electric and gas | | | 414 | | | 1 | (d) | | | 415 | |
| Net energy trading margins | | | 2 | | | | | | | 2 | |
| Energy-related businesses | | | | | | 364 | | | | 364 | |
| | | Total Operating Revenues | | | 5,247 | | | (119) | | | | 5,128 | |
| | | | | | | | | | | | | | | |
Operating Expenses | | | | | | | | | | | |
| Fuel | | | 1,132 | | | (36) | (e) | | | 1,096 | |
| Energy purchases | | | | | | | | | | | |
| | | | Realized | | | 1,389 | | | 247 | (c) | | | 1,636 | |
| | | | Unrealized economic activity | | | | | | (286) | (d) | | | (286) | |
| Energy purchases from affiliate | | | 3 | | | | | | | 3 | |
| Other operation and maintenance | | | 23 | | | 956 | | | | 979 | |
| Depreciation | | | | | | 236 | | | | 236 | |
| Taxes, other than income | | | 14 | | | 32 | | | | 46 | |
| Energy-related businesses | | | | | | 357 | | | | 357 | |
| | | Total Operating Expenses | | | 2,561 | | | 1,506 | | | | 4,067 | |
| Discontinued Operations | | | 84 | | | (84) | (f) | | | | |
Total | | $ | 2,770 | | $ | (1,709) | | | $ | 1,061 | |
(a) | Represents amounts excluded from Margins. |
(b) | As reported on the Statements of Income. |
(c) | Represents energy-related economic activity as described in "Commodity Price Risk (Non-trading) - Economic Activity" within Note 19 to the Financial Statements. For 2012, "Wholesale energy marketing - Realized" and "Energy purchases - Realized" include a net pre-tax loss of $35 million related to the monetization of certain full-requirement sales contracts. 2011 includes a net pre-tax loss of $216 million related to the monetization of certain full-requirement sales contracts and a net pre-tax gain of $19 million related to the amortization of option premiums. 2010 includes a net pre-tax gain of $37 million related to the monetization of certain full-requirement sales contracts and a net pre-tax gain of $32 million related to the amortization of option premiums. |
(d) | Represents energy-related economic activity, which is subject to fluctuations in value due to market price volatility, as described in "Commodity Price Risk (Non-trading) - Economic Activity" within Note 19 to the Financial Statements. |
(e) | Includes economic activity related to fuel as described in "Commodity Price Risk (Non-trading) - Economic Activity" within Note 19 to the Financial Statements. 2012 includes a net pre-tax loss of $29 million related to coal contract modification payments. 2011 includes pre-tax credits of $57 million for the spent nuclear fuel litigation settlement. |
(f) | Represents the net of certain revenues and expenses associated with certain businesses that are classified as discontinued operations. These revenues and expenses are not reflected in "Operating Income" on the Statements of Income. |
Changes in Non-GAAP Financial Measures
Unregulated Gross Energy Margins are generated through PPL Energy Supply's competitive non-trading and trading activities. PPL Energy Supply's non-trading energy business is managed on a geographic basis that is aligned with its generation fleet. The following table shows PPL Energy Supply's non-GAAP financial measure, Unregulated Gross Energy Margins, for the periods ended December 31, as well as the change between periods. The factors that gave rise to the changes are described below the table.
| | | 2012 | | 2011 | | Change | | 2011 | | 2010 | | Change |
| | | | | | | | | | | | | | | | | | | |
Non-trading | | | | | | | | | | | | | | | | | | |
| Eastern U.S. | | $ | 1,865 | | $ | 2,018 | | $ | (153) | | $ | 2,018 | | $ | 2,429 | | $ | (411) |
| Western U.S. | | | 299 | | | 349 | | | (50) | | | 349 | | | 339 | | | 10 |
Net energy trading | | | 4 | | | (2) | | | 6 | | | (2) | | | 2 | | | (4) |
Total | | $ | 2,168 | | $ | 2,365 | | $ | (197) | | $ | 2,365 | | $ | 2,770 | | $ | (405) |
Unregulated Gross Energy Margins | | | | | | |
| | | | | | |
Eastern U.S. | | | | | | |
| | | | | | |
The changes in Eastern U.S. non-trading margins were: |
| | | | | | |
| | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | |
Baseload energy prices | | $ | (121) | | $ | (109) |
Baseload capacity prices | | | (37) | | | (90) |
Intermediate and peaking capacity prices | | | (17) | | | (58) |
Full-requirement sales contracts (a) | | | (15) | | | 70 |
Impact of non-core generation facilities sold in the first quarter of 2011 | | | (12) | | | (48) |
Higher nuclear fuel prices | | | (12) | | | (10) |
Net economic availability of coal and hydroelectric units (b) | | | (10) | | | (72) |
Higher coal prices | | | (2) | | | (40) |
Nuclear generation volume (c) | | | | | | (29) |
Intermediate and peaking Spark Spreads | | | 11 | | | 24 |
Retail electric | | | 15 | | | (7) |
Ironwood Acquisition, which eliminated tolling expense (d) | | | 41 | | | |
Monetization of certain deals that rebalanced the business and portfolio | | | | | | (41) |
Other | | | 6 | | | (1) |
| | $ | (153) | | $ | (411) |
(a) | Higher margins in 2011 compared with 2010 were driven by the monetization of loss contracts in 2010 and lower customer migration to alternative suppliers in 2011. |
(b) | Volumes were lower in 2011 compared with 2010 as a result of unplanned outages and the sale of our interest in Safe Harbor Water Power Corporation. |
(c) | Volumes were flat in 2012 compared to 2011 due to an uprate in the third quarter of 2011 offset by higher plant outage costs in 2012. Volumes were lower in 2011 compared with 2010 primarily as a result of the dual-unit turbine blade replacement outages beginning in May 2011. |
(d) | See Note 10 to the Financial Statements for additional information. |
Western U.S.
Non-trading margins were lower in 2012 compared with 2011 due to $34 million of lower wholesale volumes, including $31 million related to the bankruptcy of SMGT, $9 million of higher average fuel prices and $9 million of lower wholesale prices.
Non-trading margins were higher in 2011 compared with 2010 due to higher net wholesale prices of $58 million, partially offset by lower wholesale volumes of $45 million, primarily due to economic reductions in the coal unit output.
Energy-Related Businesses
The $10 million increase inNet contributions to the East segment's operating income (loss) from energy-related businesses decreased by $4 million in 20122015 compared with 2011 primarily relates2014. Net contributions to the East segment's operating income (loss) increased by $13 million in 2014 compared with 2013. During 2014, Talen Energy recorded a $17 million increase to "Energy-related businesses" revenues on the 2014 Statements of Income related to prior periods and the timing of revenue recognition for a mechanical services businesses,contracting and engineering subsidiary. See Note 1 to the Financial Statements for additional information. Excluding the impact of the 2014 adjustment, the change in 2015 compared with 2014 was an increase of $13 million due to improvedhigher margins on existing construction projects at the mechanical contracting and energy service projectsengineering subsidiaries. The change in 2012 and a decrease in affiliate trademark expenses.2014 compared with 2013 was primarily due to the $17 million revenue adjustment.
Operation and Maintenance
The increase (decrease) in other operation and maintenance was due to:
|
| | | | | | | |
| 2015 vs. 2014 | | 2014 vs. 2013 |
East segment: | | | |
RJS - Raven and Sapphire (a) | $ | 104 |
| | $ | — |
|
MACH Gen - Athens and Millennium (a) | 7 |
| | — |
|
Fossil and Hydro (b) | (51 | ) | | (9 | ) |
Nuclear (c) | (21 | ) | | 33 |
|
Talen Energy Marketing (d) | (25 | ) | | 4 |
|
Energy Services (e) | (17 | ) | | 4 |
|
West segment: | | | |
RJS - Jade (a) | 22 |
| | — |
|
MACH Gen - Harquahala (a) | 3 |
| | — |
|
Talen Montana (f) | 23 |
| | (20 | ) |
Other: | | | |
Accelerated stock-based compensation (g) | 25 |
| | — |
|
TSA costs | 29 |
| | — |
|
Restructuring costs (h) | 12 |
| | — |
|
Transaction costs (i) | 20 |
| | — |
|
Separation benefits (j) | (17 | ) | | 17 |
|
Separation costs (k) | (14 | ) | | 16 |
|
Other (l) | (55 | ) | | 1 |
|
Total | $ | 45 |
|
| $ | 46 |
|
| | | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | | |
Montana hydroelectric litigation (a) | | $ | 75 | | $ | (121) |
PPL Susquehanna nuclear plant costs (b) | | | 27 | | | 30 |
Uncollectible accounts (c) | | | (5) | | | 15 |
Costs at Western fossil and hydroelectric plants (d) | | | (1) | | | 15 |
Costs at Eastern fossil and hydroelectric plants (e) | | | 13 | | | 20 |
Impacts from emission allowances (f) | | | | | | (15) |
Ironwood Acquisition (g) | | | 18 | | | |
Trademark royalties (h) | | | (34) | | | |
Pension expense | | | 11 | | | 1 |
Other | | | 8 | | | 5 |
Total | | $ | 112 | | $ | (50) |
(a) | In March 2010, the Montana Supreme Court substantially affirmed a June 2008 Montana District Court decision regarding lease payments for the use of certain Montana streambeds. As a result, in the first quarter of 2010, PPL Montana recorded a charge of $56 million, representing estimated rental compensation for the first quarter of 2010 and prior years, including interest. The portion of the total charge recorded to "Other operation and maintenance" on the Statement of Income totaled $49 million. In August 2010, PPL Montana filed a petition for a writ of certiorari with the U.S. Supreme Court requesting the Court's review of this matter. In June 2011, the U.S. Supreme Court granted PPL Montana's petition. In February 2012, the U.S. Supreme Court overturned the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion. As a result, in 2011 PPL Montana reversed its total loss accrual of $89 million, which had been recorded prior to the U.S. Supreme Court decision, of which $75 million was credited to "Other operation and maintenance" on the Statement of Income. |
(b) | 2012 compared with 2011 was higher primarily due to $11 million of higher payroll-related costs, $7 million of higher project costs and $7 million of higher costs from the refueling outage. 2011 compared with 2010 was higher primarily due to $11 million of higher payroll-related costs, $10 million of higher outage costs and $8 million of higher costs from the refueling outage. |
(c) | 2011 compared with 2010 was higher primarily due to SMGT filing for protection under Chapter 11 of the U.S. Bankruptcy Code, $11 million of damages billed to SMGT were fully reserved. |
(d) | 2011 compared with 2010 was higher primarily due to $11 million of lower insurance proceeds. |
(e) | 2012 compared with 2011 was higher primarily due to net plant outage costs of $13 million. 2011 compared with 2010 was higher primarily due to plant outage costs of $13 million. |
(f) | 2011 compared with 2010 was lower due to lower impairment charges of sulfur dioxide emission allowances. |
(g)(a) | There are no comparable amounts in the 20112014 or 2013 periods as the Ironwood Acquisition occurredRJS was acquired in April 2012.June 2015 and MACH Gen was acquired in November 2015. |
(h) | In 2011 |
(b) | The decrease for 2015 compared with 2014 and 2010, PPLthe decrease for 2014 compared with 2013 was primarily due to lower coal plant outage costs. |
| |
(c) | The decrease for 2015 compared with 2014 was primarily due to $11 million of lower outage costs and $13 million of lower contractor costs supporting operations. The increase in 2014 compared with 2013 was primarily due to higher contractor costs supporting operations. |
| |
(d) | The decrease for 2015 compared with 2014 was primarily due to lower payroll related costs attributable to restructuring activities. |
| |
(e) | The decrease for 2015 compared with 2014 was primarily due to the gain on the sale of Talen Renewable Energy Supplyin November 2015. |
| |
(f) | The increase for 2015 compared with 2014 was charged trademark royalties by an affiliate.primarily due to $8 million of higher coal plant outage costs and $7 million of costs associated with the retirement of the Corette plant in 2015. The agreementdecrease in 2014 compared with 2013 was primarily due to the elimination of $20 million of rent expense associated with the Colstrip lease that was terminated in December 2011.2013. |
| |
(g) | Related to the spinoff transaction. See Note 1 to the Financial Statements for additional information. |
| |
(h) | The increase for 2015 compared with 2014 was due to costs recorded in 2015 related to the spinoff transaction, including expenses for the FERC-required mitigation plan and legal and professional fees. |
| |
(i) | The increase for 2015 compared with 2014 was due to costs recorded in 2015 related to the RJS, MACH Gen and mitigation asset sale transactions. |
| |
(j) | The decrease for 2015 compared with 2014 and the increase in 2014 compared with 2013 was due to bargaining unit one-time voluntary retirement benefits recorded in 2014 as a result of the ratification of the IBEW Local 1600 three-year labor agreement in June 2014. |
| |
(k) | The decrease for 2015 compared with 2014 and the increase in 2014 compared with 2013 was primarily due to costs incurred in 2014 related to restructuring in anticipation of the spinoff, which included cash severance compensation, lump sum COBRA reimbursement payments and outplacement services. |
| |
(l) | The decrease for 2015 compared with 2014 was primarily due to lower corporate expenses. |
Loss on Lease Termination
A $697 million charge was recorded in 2013 for the termination of the Colstrip operating lease to facilitate the sale of the Montana hydroelectric generating facilities. See Note 6 to the Financial Statements for additional information.
Impairments
Impairments in 2015 primarily include a $465 million goodwill impairment, a $175 million impairment of the Sapphire plants and a $14 million impairment of the C.P. Crane plant (all included in the East segment). 2013 includes a $65 million impairment of the Corette plant (included in the West segment). These impairments exclude those recorded to "Income (Loss) from Discontinued Operations (net of income taxes)" on the 2014 Statement of Income. See Note 16 to the Financial Statements for additional information.
Depreciation
Depreciation increased by $41$59 million in 20122015 compared with 2011,2014, primarily due to $16increases in the East and West segments of $31 million attributableand $25 million, primarily related to the acquisitions of RJS Power and MACH Gen. There are no comparable amounts in 2014 and 2013 for RJS or MACH Gen as their acquisition occurred in 2015.
Depreciation decreased by $2 million in 2014 compared with 2013, primarily due to an $8 million increase in the East segment and a $10 million decrease in the West segment. The increase in the East segment was partially due to $13 million from PP&E additions and $17 million attributablein part due to the Ironwood Acquisitioncompleted Holtwood expansion project in April 2012. Depreciation increased by $8 million2013. The decrease in 2011 compared with 2010,the West segment was primarily due to PP&E additions.decreases from the impairment of the Corette plant and the write off of leasehold improvement assets in conjunction with the termination of the operating lease at the Colstrip facility, both of which occurred in 2013. See Note 14 to the Financial Statements for additional information on the Corette impairment and Note 6 to the Financial Statements for information on the Colstrip operating lease termination.
Taxes, Other Than Income
Taxes, other than income decreasedincreased by $2$8 million in 2012for 2015 compared with 2011,2014. This increase was primarily due to a$11 million related to RJS, $7 million decrease in state capital stock tax offset by aimpacting the East segment and $4 million increase in state gross receipts tax.
impacting the West segment. Taxes other than income increased by $25$4 million in 20112014 compared with 2010, primarily due to $16 million of higher Pennsylvania gross receipts tax expense2013, within the East segment. There are no comparable amounts in 2014 and 2013 for RJS as a result of an increasethe acquisition occurred in retail electricity sales by PPL EnergyPlus. This tax is included in "Unregulated Gross Energy Margins." The increase also includes $8 million of higher Pennsylvania capital stock tax due in part to the expiration of the Keystone Opportunity Zone credit in 2010 and an agreed to change in a capital stock tax filing position with the state.2015.
Other Income (Expense) - net
See Note 17 to the Financial Statements for details.
Interest Income from Affiliates
InterestOther income from affiliates(expense) - net decreased by $6$148 million in 20122015 compared with 2011,2014 and decreased by $2 million in 2014 compared with 2013. The decrease in 2015 compared with 2014 was primarily due to lower average loan balancesthe recording of a $134 million charge for a termination payment to a remarketing dealer related to an October 2015 debt extinguishment and a $9 million decrease in 2015 in net earnings on the NDT funds. See Note 5 for additional information on the debt extinguishment. The decrease in 2014 compared with PPL Energy Funding.2013 resulted from 2013 including a gain of $8 million related to adjustments to liabilities for a former mining subsidiary partially offset by a $5 million increase in 2014 in net earnings on the NDT funds.
Interest Expense
The increase (decrease) in interest expense was due to:
| | | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | | |
Long-term debt interest expense (a) | | $ | (11) | | | |
Short-term debt interest expense (b) | | | (10) | | $ | 7 |
Ironwood Acquisition (Note 10) | | | 12 | | | |
Capitalized interest | | | | | | (16) |
Net amortization of debt discounts, premiums and issuance costs (c) | | | (9) | | | (3) |
Montana hydroelectric litigation (d) | | | 10 | | | (20) |
Other | | | 2 | | | (2) |
Total | | $ | (6) | | $ | (34) |
|
| | | | | | | |
| 2015 vs. 2014 | | 2014 vs. 2013 |
Long-term debt interest expense (a) | $ | 56 |
| | $ | (50 | ) |
MACH Gen (b) | 6 |
| | — |
|
Short-term debt interest expense | 11 |
| | 7 |
|
Capitalized interest (c) | 3 |
| | 14 |
|
Net amortization of debt discounts, premiums and issuance costs (d) | 11 |
| | (4 | ) |
Other | — |
| | (2 | ) |
Total | $ | 87 |
| | $ | (35 | ) |
| |
(a) | The increase in 2015 compared with 2014 was due to a debt issuance in May 2015 and the assumption of an RJS Power subsidiary's debt in June 2015 in connection with the RJS Power acquisition, partially offset by a debt maturity in August 2014. The increase in expense from the RJS Power related debt was $35 million. See Note 6 to the Financial Statements for information on the acquisition. The decrease in 2014 compared with 2013 was primarily due to the redemptionrepayment of $250 million of 7.0% Senior Notes due 2046debt in July 2011 along with the repayment of $500 million of 6.4% Senior Notes due 2011 and subsequent issuance of $500 million of 4.6% Senior Notes due 2021, bothDecember 2013. |
| |
(b) | Represents interest on long-term debt. There are no comparable amounts in the fourth quarter of 2011.2014 or 2013 periods as MACH Gen was acquired in November 2015. See Note 6 to the Financial Statements for additional information on the acquisition. |
(b) | 2012 |
(c) | The increase in 2014 compared with 20112013 was lower primarily due to lower interest rates on 2012 short-term borrowings coupled with lower fees on credit facilities. 2011the Holtwood hydroelectric expansion project placed in service in November 2013. |
| |
(d) | The increase in 2015 compared with 20102014 was higher primarily due to increased borrowings in 2011 and an increase in commitment fees on credit facilities. |
(c) | The periods include the impact of accelerating the amortization of deferred financing fees of $7 million in 2011, due to the July 2011 redemption, as noted above,write-off of its 7.00% Senior Notes due 2046. 2011 comparedfees associated with 2010Talen Energy Supply's $3 billion syndicated credit facility that was slightly offset by the impact of accelerating the amortization of deferred financing fees of $10 millionterminated in 2010, due to the September 2010 expiration and subsequent replacement of its $3.2 billion 5-year Syndicated Credit Facility. |
(d) | In March 2010, the Montana Supreme Court substantially affirmed a June 2008 Montana District Court decision regarding lease payments for the use of certain Montana streambeds. In August 2010, PPL Montana filed a petition for a writ of certiorariconnection with the U.S. Supreme Court requesting the Court's review of this matter. In 2011 and 2010, PPL Montana recorded $4 million and $10 million of interest expense on the rental compensation covered by the court decision. In February 2012, the U.S. Supreme Court overturned the Montana Supreme Court decision and remanded the case to the Montana Supreme Court for further proceedings consistent with the U.S. Supreme Court's opinion. As a result, in the fourth quarter of 2011 PPL Montana reversed its total loss accrual of $89 million, which had been recorded prior to the U.S. Supreme Court decision, of which $14 million was credited to "Interest Expense" on the Statement of Income.spinoff. |
Income Taxes
The increase (decrease) in income taxes was due to:
| | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | |
Higher (lower) pre-tax book income | | $ | (191) | | $ | 134 |
State valuation allowance adjustments (a) | | | (20) | | | 74 |
State deferred tax rate change (b) | | | 7 | | | (26) |
Domestic manufacturing deduction (c) (d) | | | | | | 11 |
Federal and state tax reserve adjustments | | | (4) | | | 13 |
Federal and state tax return adjustments (d) | | | 26 | | | (16) |
Health Care Reform (e) | | | | | | (5) |
Other | | | | | | (1) |
| | $ | (182) | | $ | 184 |
|
| | | | | | | |
| 2015 vs. 2014 | | 2014 vs. 2013 |
Change in pre-tax income at current tax rates (a) | $ | (36 | ) | | $ | 298 |
|
RJS (b) | (49 | ) | | — |
|
MACH Gen (b) | (5 | ) | | — |
|
Federal and state uncertain tax benefits recognized (c) | (12 | ) | | — |
|
State deferred tax rate change (d) | (16 | ) | | (16 | ) |
Goodwill impairment (e) | (21 | ) | | — |
|
Federal income tax credits (f) | (9 | ) | | 8 |
|
Federal and state tax return adjustments | (7 | ) | | (6 | ) |
Other | 12 |
| | (9 | ) |
Total | $ | (143 | ) | | $ | 275 |
|
| |
(a) | During 2011,Excludes income taxes related to RJS and MACH Gen as there are no comparable amounts in 2014 or 2013 as their acquisition occurred in 2015. Also excludes the Pennsylvania Departmentimpact of Revenue issued interpretive guidancethe goodwill impairment recorded in 2015 because the effective tax rate on the treatmentimpairment does not bear a customary relationship to the recognized loss as a result of bonus depreciation for Pennsylvania income tax purposes. The guidance allows 100% bonus for qualifying assetsa significant portion of the impairment being related to non-deductible goodwill. |
| |
(b) | There are no comparable amounts in the same year bonus depreciation is allowed2014 or 2013 periods as RJS was acquired in June 2015 and MACH Gen was acquired in November 2015. |
| |
(c) | In 2015, open audits for federal incomethe tax purposes. Due toyears 2008 - 2011 were settled by PPL with the decreaseIRS resulting in projected taxable incomea tax benefit of $12 million for Talen Energy's portion of the settlement of previously unrecognized tax benefits. |
| |
(d) | During 2015, 2014 and 2013, Talen Energy recorded adjustments related to bonus depreciation and a decrease in projected future taxable income, PPL Energy Supply recorded $22 million inits December 31 state deferred income tax expense related to deferred tax valuation allowances during 2011. |
Pennsylvania H.B. 1531, enacted in October 2009, increased the net operating loss limitation to 20% of taxable income for tax years beginning in 2010. Based on the projected revenue increase related to the expiration of the generation rate caps, PPL Energy Supply recorded a $52 million state deferred income tax benefit related to the reversal of deferred tax valuation allowances over the remaining carryforward period of the net operating losses during 2010.
(b) | Changesliabilities as a result of annual changes in state apportionment resulted in reductions toand the impact on the future estimated state income tax rate at December 31, 2012 and 2011. PPL Energy Supply recorded a $19 million deferred tax benefit in 2012 and a $26 million deferred tax benefit in 2011 related to its state deferred tax liabilities.rate. |
(c) | In December 2010, Congress enacted legislation allowing for 100% bonus depreciation on qualified property. The increased tax depreciation deduction eliminated the tax benefits related to domestic manufacturing deductions in 2012 and 2011. |
(d)(e) | During 2011, PPL recorded $22 million in federalFederal and state tax benefits relatedimpacts attributable to the filingdeductible portion of goodwill that was impaired during the 2010 federal and state income tax returns. Of that amount, $7 million in tax benefits related to an additional domestic manufacturing deduction resulting from revised bonus depreciation amounts. |
(e) | Beginning in 2013, provisions within Health Care Reform eliminated the tax deductibilitythird quarter of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D Coverage. As a result, PPL Energy Supply recorded deferred income tax expense during 2010. |
| 2015. See Note 516 to the Financial Statements for additional information on income taxes.the goodwill impairment. |
| |
(f) | During 2015, Talen Energy recorded a benefit primarily related to the recognition of previously unamortized tax credits as a result of the sale of Talen Renewable Energy in November 2015. During 2013, Talen Energy recorded a deferred tax benefit related to investment tax credits on progress expenditures for the Holtwood hydroelectric plant expansion. See Note 6 to the Financial Statements for additional information. |
See Note 4 to the Financial Statements for additional information.
101
Income (Loss) from Discontinued Operations (net of income taxes)
Income (Loss) from Discontinued Operations (net of income taxes) decreased by $240 millionfor 2014 and 2013 includes the Montana hydroelectric generating facilities which were sold in 2011 compared with 2010. The decrease in 2011 compared with 2010 was primarily due to the presentation of PPL Global as Discontinued Operations as a result of the January 2011 distribution by PPL Energy Supply of its membership interest in PPL Global to its parent, PPL Energy Funding. In 2011, the results of PPL Global are no longer consolidated within PPL Energy Supply.November 2014. See Note 96 to the Financial Statements for additional information.
Margins
Management utilizes "Margins," a non-GAAP financial measure, as an indicator of performance for its business.
"Margins" is defined as energy revenues offset by the cost of fuel, energy purchases, certain operation and maintenance expenses, primarily ancillary charges, and gross receipts tax, recorded in "Taxes, other than income." This performance measure is relevant due to the volatility in the individual revenue and expense lines on the Statements of Income that comprise "Margins." This volatility stems from a number of factors, including the required netting of certain transactions with ISOs, RTOs and significant fluctuations in unrealized gains and losses. Such factors could result in gains or losses being recorded in either "Wholesale energy," "Retail energy" or "Energy purchases" on the Statements of Income. This performance measure includes PLR revenues from energy sales to PPL Electric by Talen Energy Marketing, which prior to June 1, 2015, are reflected in "Wholesale energy to affiliate" in the reconciliation table below. "Margins" excludes unrealized (gains) losses on: energy related economic activity, which includes the changes in fair value of positions used to economically hedge a portion of the economic value of the competitive generation assets, full-requirement sales contracts and retail activities; and trading activities. These derivatives are subject to changes in fair value due to market price volatility of the input and output commodities (e.g., fuel and power) prior to the delivery period that was hedged or when realized. Energy related economic activity includes premium amortization associated with options. Unrealized gains and losses related to derivatives and premium amortization associated with options are deferred and included in "Margins" over the delivery period of the item that was hedged or upon realization.
This measure is not intended to replace "Operating Income (Loss)," which is determined in accordance with GAAP, as an indicator of overall operating performance. Other companies may use different measures to analyze and report their results of operations. Management believes this measure provides additional useful criteria to make investment decisions. This
performance measure is used, in conjunction with other information, by senior management to manage Talen Energy's operations and analyze actual results compared with budget.
Reconciliation of Margins
The following tables contain the components from the Statements of Income that are included in Margins and a reconciliation to "Operating Income (Loss)" for the years ended December 31.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2015 | | 2014 |
| East Segment | | West Segment | | Reconciling Items (a) | | Operating Income (b) | | East Segment | | West Segment | | Reconciling Items (a) | | Operating Income (b) |
Operating Revenues | | | | | | | | | | | | | | | |
Wholesale energy | $ | 2,531 |
| | $ | 222 |
| | $ | 75 | (c) | | $ | 2,828 |
| | $ | 2,496 |
| | $ | 96 |
| | $ | 61 | (c) | | $ | 2,653 |
|
Wholesale energy to affiliate (d) | 14 |
| | — |
| | — |
| | 14 |
| | 84 |
| | — |
| | — |
| | 84 |
|
Retail energy | 1,039 |
| | 73 |
| | (17 | ) (c) | | 1,095 |
| | 1,135 |
| | 81 |
| | 27 | (c) | | 1,243 |
|
Energy-related businesses | — |
| | — |
| | 544 |
| | 544 |
| | — |
| | — |
| | 601 |
| | 601 |
|
Total Operating Revenues | 3,584 |
| | 295 |
|
| 602 |
|
| 4,481 |
|
| 3,715 |
| | 177 |
|
| 689 |
|
| 4,581 |
|
| | | | | | | | | | | | | | | |
Operating Expenses | | | | | | | | | | | | | | | |
Fuel | 1,038 |
| | 120 |
| | 36 | (c) | | 1,194 |
| | 1,097 |
| | 72 |
| | 27 | (c) | | 1,196 |
|
Energy purchases | 723 |
| | 34 |
| | (81 | ) (c) | | 676 |
| | 971 |
| | 26 |
| | 57 | (c) | | 1,054 |
|
Operation and maintenance | 16 |
| | — |
| | 1,036 |
| | 1,052 |
| | 22 |
| | — |
| | 985 |
| | 1,007 |
|
Impairments (Note 16) | — |
| | — |
| | 657 |
| | 657 |
| | — |
| | — |
| | — |
| | — |
|
Depreciation | — |
| | — |
| | 356 |
| | 356 |
| | — |
| | — |
| | 297 |
| | 297 |
|
Taxes, other than income | 41 |
| | — |
| | 24 |
| | 65 |
| | 43 |
| | — |
| | 14 |
| | 57 |
|
Energy-related businesses | 8 |
| | — |
| | 512 |
| | 520 |
| | 8 |
| | — |
| | 565 |
| | 573 |
|
Total Operating Expenses | 1,826 |
| | 154 |
|
| 2,540 |
|
| 4,520 |
|
| 2,141 |
| | 98 |
|
| 1,945 |
|
| 4,184 |
|
Total | $ | 1,758 |
| | $ | 141 |
|
| $ | (1,938 | ) |
| $ | (39 | ) | | $ | 1,574 |
| | $ | 79 |
|
| $ | (1,256 | ) |
| $ | 397 |
|
|
| | | | | | | | | | | | | | | | |
| 2013 | |
| East Segment | | West Segment | | Reconciling Items (a) | | Operating Income (b) | |
Operating Revenues | | | | | | | | |
Wholesale energy | $ | 3,086 |
| | $ | 98 |
| | $ | (294 | ) (c) | | $ | 2,890 |
| |
Wholesale energy to affiliate (d) | 51 |
| | — |
| | — |
| | 51 |
| |
Retail energy | 933 |
| | 82 |
| | 12 | (c) | | 1,027 |
| |
Energy-related businesses | — |
| | — |
| | 527 |
| | 527 |
| |
Total Operating Revenues | 4,070 |
| | 180 |
|
| 245 |
|
| 4,495 |
| |
| | | | | | | | |
Operating Expenses | | | | | | | | |
Fuel | 966 |
| | 78 |
| | 4 | (c) | | 1,048 |
| |
Energy purchases | 1,265 |
| | 23 |
| | (135 | ) (c) | | 1,153 |
| |
Operation and maintenance | 20 |
| | — |
| | 941 |
| | 961 |
| |
Loss on lease termination | — |
| | — |
| | 697 |
| | 697 |
| |
Impairments | — |
| | — |
| | 65 |
| | 65 |
| |
Depreciation | — |
| | — |
| | 299 |
| | 299 |
| |
Taxes, other than income | 37 |
| | — |
| | 16 |
| | 53 |
| |
Energy-related businesses | 7 |
| | — |
| | 505 |
| | 512 |
| |
Total Operating Expenses | 2,295 |
| | 101 |
|
| 2,392 |
|
| 4,788 |
| |
Total | $ | 1,775 |
| | $ | 79 |
|
| $ | (2,147 | ) |
| $ | (293 | ) | |
| |
(a) | Represents amounts excluded from Margins. |
| |
(b) | As reported on the Statements of Income. |
| |
(c) | Includes unrealized gains (losses) on energy-related economic activity, which is subject to fluctuations in value due to market price volatility. See "Commodity Price Risk (Non-trading) - Economic Activity" within Note 15 to the Financial Statements. Also includes unrealized gains (losses) on trading activity of $(37) million, $27 million and $(6) million for 2015, 2014 and 2013. Amounts have been adjusted for option premiums of $8 million and $(10) million for 2015 and 2014. To mitigate the risk of oversupply, Talen Energy incurred charges of $41 million during 2015 to reduce its contracted coal deliveries, which is also included in this amount. See Note 11 to the Financial Statements for additional information. 2015 also includes net realized gains on certain derivative contracts that were early-terminated of $13 million and a prior period revenue adjustment of $(7) |
million. See Note 1 to the Financial Statements for additional information on the revenue adjustment. 2015, 2014 and 2013 includes OCI amortization on non-active derivative positions of $(11) million, $(11) million and $(13) million.
| |
(d) | Amounts recorded prior to the spinoff for activity with PPL Electric. |
Changes in Margins
The following table shows Margins by segment for the years ended December 31, as well as the change between periods. Margins do not include operations related to those assets classified as discontinued operations. The factors that gave rise to the changes are described following the table.
|
| | | | | | | | | | | | | | | | | | | |
| | | Change |
| 2015 | | 2014 | | 2013 | | 2015 vs. 2014 | | 2014 vs. 2013 |
East segment | $ | 1,758 |
| | $ | 1,574 |
| | $ | 1,775 |
| | $ | 184 |
| | $ | (201 | ) |
West segment | 141 |
| | 79 |
| | 79 |
| | 62 |
| | — |
|
Total | $ | 1,899 |
| | $ | 1,653 |
| | $ | 1,854 |
| | $ | 246 |
| | $ | (201 | ) |
East Segment
East segment Margins increased $162 million in 2015 from the Raven and Sapphire portfolios. There are no comparable amounts in the 2014 or 2013 periods as the acquisition of Raven and Sapphire occurred during 2015.
Excluding the impact of the Raven, Sapphire and MACH Gen acquisitions, East segment Margins increased in 2015 compared with 2014 by $22 million primarily due to higher realized energy prices of $68 million, improved spark spreads of $59 million, higher nuclear availability of $51 million and lower average fuel prices of $24 million, substantially offset by lower capacity prices of $55 million, gains realized in 2014 on certain commodity positions of $46 million, the net effect of unusual market and weather volatility in the first quarter of 2014 as discussed below of $38 million, lower volumes on full-requirement sales contracts of $25 million and retail electric activity of $12 million.
East segment Margins decreased in 2014 compared with 2013 primarily due to lower realized energy prices of $354 million and lower capacity prices of $34 million, partially offset by favorable asset performance of $70 million, gains realized in 2014 on certain commodity positions of $46 million, unusual market and weather volatility in 2014 as discussed below of $38 million and gas optimization of $26 million.
During the first quarter of 2014, the PJM region experienced unusually cold weather conditions, higher demand and congestion patterns, causing rising natural gas and electricity prices in spot and near-term forward markets. Due to these market dynamics, Talen Energy captured opportunities on unhedged generation, which were offset primarily by losses incurred by under-hedged full-requirement sales contracts and retail electric portfolios, which were not fully hedged or able to be fully hedged given the higher load conditions and lack of market liquidity.
West Segment
West segment Margins increased $68 million in 2015 compared with 2014 from the Jade portfolio. There are no comparable amounts in the 2014 and 2013 periods as the acquisition of Jade occurred during 2015.
EBITDA and Adjusted EBITDA
In addition to operating income (loss), EBITDA and Adjusted EBITDA, non-GAAP financial measures are other indicators of performance for Talen Energy's business, with Adjusted EBITDA as the primary financial performance measure used by management to evaluate its business and monitor results of operations.
EBITDA represents net income (loss) before interest expense, income taxes, depreciation and certain amortization. Adjusted EBITDA represents EBITDA further adjusted for certain non-cash and other items that management believes are not indicative of ongoing operations including, but not limited to, unrealized gains and losses on derivative contracts, stock-based compensation expense, asset retirement obligation accretion, impairments, gains and losses on securities in the NDT funds, gains or losses on sales, dispositions or retirements of assets, debt extinguishments and transition, transaction and restructuring costs.
EBITDA and Adjusted EBITDA are not intended to represent cash flows from operations, operating income (loss) or net income (loss) as defined by U.S. GAAP as indicators of operating performance and are not necessarily comparable to similarly-
titled measures reported by other companies. Management cautions investors that amounts presented in accordance with Talen Energy's definitions of EBITDA and Adjusted EBITDA may not be comparable to similar measures disclosed by other companies because not all companies calculate EBITDA and Adjusted EBITDA in the same manner. Talen Energy believes EBITDA and Adjusted EBITDA are useful to investors and other users of these financial statements in evaluating Talen Energy's operating performance because they provide additional tools to compare business performance across companies and across periods. Talen Energy believes that EBITDA is widely used by investors to measure a company's operating performance without regard to such items as interest expense, income taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. Additionally, Talen Energy believes that investors commonly adjust EBITDA information to eliminate the effect of restructuring and other expenses, which vary widely from company to company and impair comparability. Talen Energy adjusts for these and other items, as management believes that these items would distort their ability to efficiently view and assess the company's core operating trends. In summary, management primarily uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, as a measure of certain corporate financial goals used to determine variable compensation and in communications with the Talen Energy Corporation Board of Directors, senior management, shareholders, creditors, analysts and investors concerning Talen Energy's financial performance.
Reconciliations of EBITDA and Adjusted EBITDA
The tables below provide reconciliations of EBITDA and Adjusted EBITDA to operating income (loss) on a segment basis and to net income (loss) on a consolidated basis for the years ended December 31.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2015 | | 2014 |
| East Segment |
| West Segment |
| Other |
| Total | | East Segment | | West Segment | | Other | | Total |
Net income (loss) |
|
|
|
|
|
| $ | (341 | ) | | | | | | | | $ | 410 |
|
(Income) loss from discontinued operations (net of tax) |
|
|
|
|
|
| — |
| | | | | | | | (223 | ) |
Interest expense |
|
|
|
|
|
| 211 |
| | | | | | | | 124 |
|
Income taxes |
|
|
|
|
|
| (27 | ) | | | | | | | | 116 |
|
Other (income) expense - net |
|
|
|
|
|
| 118 |
| | | | | | | | (30 | ) |
Operating income (loss) | $ | 198 |
|
| $ | 2 |
|
| $ | (239 | ) |
| $ | (39 | ) | | $ | 558 |
| | $ | 71 |
| | $ | (232 | ) | | $ | 397 |
|
Depreciation | 327 |
|
| 26 |
|
| 3 |
|
| 356 |
| | 296 |
| | 1 |
| | — |
| | 297 |
|
Other income (expense) - net | 19 |
|
| (2 | ) |
| (135 | ) |
| (118 | ) | | 29 |
| | — |
| | 1 |
| | 30 |
|
EBITDA | $ | 544 |
|
| $ | 26 |
|
| $ | (371 | ) |
| $ | 199 |
| | $ | 883 |
| | $ | 72 |
| | $ | (231 | ) | | $ | 724 |
|
Unrealized (gain) loss on derivative contracts (a) | (175 | ) |
| 25 |
|
| — |
|
| (150 | ) | | 15 |
| | (32 | ) | | — |
| | (17 | ) |
Stock-based compensation expense (b) | — |
|
| — |
|
| 40 |
|
| 40 |
| | — |
| | — |
| | 18 |
| | 18 |
|
(Gain) loss from NDT funds | (15 | ) |
| — |
|
| — |
|
| (15 | ) | | (26 | ) | | — |
| | — |
| | (26 | ) |
ARO accretion | 33 |
|
| 1 |
|
| — |
|
| 34 |
| | 32 |
| | — |
| | — |
| | 32 |
|
Coal contract adjustment (c) | 41 |
| | — |
| | — |
| | 41 |
| | — |
| | — |
| | — |
| | — |
|
Impairments (d) | 657 |
| | — |
| | — |
| | 657 |
| | — |
| | — |
| | — |
| | — |
|
REPS Remarketing | — |
| | — |
| | 134 |
| | 134 |
| | — |
| | — |
| | — |
| | — |
|
Mechanical subsidiary revenue adjustment (e) | — |
| | — |
| | — |
| | — |
| | (17 | ) | | — |
| | — |
| | (17 | ) |
TSA costs | — |
|
| — |
|
| 29 |
|
| 29 |
| | — |
| | — |
| | — |
| | — |
|
Separation benefits (f) | — |
|
| — |
|
| 2 |
|
| 2 |
| | — |
| | — |
| | 33 |
| | 33 |
|
Corette closure costs (g) | — |
|
| 4 |
|
| — |
|
| 4 |
| | — |
| | — |
| | — |
| | — |
|
Terminated derivative contracts (h) | (13 | ) |
| — |
|
| — |
|
| (13 | ) | | — |
| | — |
| | — |
| | — |
|
Revenue adjustment (i) | 7 |
|
| — |
|
| — |
|
| 7 |
| | — |
| | — |
| | — |
| | — |
|
Transaction costs | — |
|
| — |
|
| 20 |
|
| 20 |
| | — |
| | — |
| | — |
| | — |
|
Restructuring costs (j) | — |
|
| — |
|
| 12 |
|
| 12 |
| | — |
| | — |
| | 1 |
| | 1 |
|
Other (k) | 1 |
|
| — |
|
| — |
|
| 1 |
| | 11 |
| | — |
| | — |
| | 11 |
|
Adjusted EBITDA | $ | 1,080 |
|
| $ | 56 |
|
| $ | (134 | ) |
| $ | 1,002 |
| | $ | 898 |
| | $ | 40 |
| | $ | (179 | ) | | $ | 759 |
|
|
| | | | | | | | | | | | | | | | |
| 2013 | |
| East Segment | | West Segment | | Other | | Total | |
Net income (loss) |
|
|
|
|
|
| $ | (230 | ) | |
(Income) loss from discontinued operations (net of tax) |
|
|
|
|
|
| (32 | ) | |
Noncontrolling interest | | | | | | | 1 |
| |
Interest expense |
|
|
|
|
|
| 159 |
| |
Income taxes |
|
|
|
|
|
| (159 | ) | |
Other (income) expense - net |
|
|
|
|
|
| (32 | ) | |
Operating income (loss) | $ | 652 |
| | $ | (750 | ) | | $ | (195 | ) |
| $ | (293 | ) | |
Depreciation | 288 |
| | 11 |
| | — |
| | 299 |
| |
Other income (expense) - net | 30 |
| | — |
| | 2 |
|
| 32 |
| |
Noncontrolling interest | (1 | ) | | — |
| | — |
|
| (1 | ) | |
EBITDA | $ | 969 |
|
| $ | (739 | ) |
| $ | (193 | ) |
| $ | 37 |
| |
Unrealized (gain) loss on derivative contracts (a) | 133 |
| | 3 |
| | — |
|
| 136 |
| |
Stock-based compensation expense (b) | — |
| | — |
| | 16 |
|
| 16 |
| |
(Gain) loss from NDT funds | (22 | ) | | — |
| | — |
|
| (22 | ) | |
ARO accretion | 29 |
| | — |
| | — |
|
| 29 |
| |
Impairments (d) | — |
| | 65 |
| | — |
| | 65 |
| |
Loss on lease termination (Note 6) | — |
| | 697 |
| | — |
|
| 697 |
| |
Other (k) | 13 |
| | (2 | ) | | — |
|
| 11 |
| |
Adjusted EBITDA | $ | 1,122 |
|
| $ | 24 |
|
| $ | (177 | ) |
| $ | 969 |
| |
| |
(a) | Represents unrealized gains (losses) on derivatives. See "Commodity Price Risk (Non-trading) - Economic Activity" and "Commodity Price Risk (Trading)" in Note 15 to the Financial Statements for additional information on derivatives. Amounts have been adjusted for option premiums of $8 million and $(10) million for 2015 and 2014. |
| |
(b) | 2015 includes a charge for the acceleration of expense as a result of the spinoff. See Note 1 to the Financial Statements for additional information. For periods prior to June 2015, represents the portion of PPL's stock-based compensation cost allocable to Talen Energy. Amounts prior to June 2015 were cash settled with a former affiliate. |
| |
(c) | To mitigate the risk of oversupply, Talen Energy incurred pre-tax charges of $41 million in 2015 in connection with an agreement to reduce its contracted coal deliveries. See Note 11 to the Financial Statements for additional information. |
| |
(d) | 2015 includes charges for goodwill and certain long-lived assets. 2013 includes a charge for the Corette plant and related emission allowances. See Notes 14 and 16 to the Financial Statements for additional information. |
| |
(e) | In 2014, Talen Energy recorded $17 million to "Energy-related businesses" revenues related to prior periods and the timing of revenue recognition for a mechanical contracting and engineering subsidiary. See Note 1 to the Financial Statements for additional information. |
| |
(f) | In June 2014, Talen Energy Supply's largest IBEW local ratified a new three-year labor agreement. In connection with the new agreement, estimated bargaining unit one-time voluntary retirement benefits of $17 million were recorded. In addition, 2014 includes separation costs of $16 million related to the spinoff transaction. |
| |
(g) | Operations were suspended and the Corette plant was retired in March 2015. |
| |
(h) | Represents net realized gains on certain derivative contracts that were early-terminated due to the spinoff transaction. |
| |
(i) | Relates to a prior period revenue adjustment for the receipt of revenue under a transmission operating agreement with Talen Energy Supply's former affiliate, PPL Electric. See Note 1 to the Financial Statements for additional information. |
| |
(j) | Costs related to the spinoff transaction, including expenses associated with the FERC-required mitigation and legal and professional fees. |
| |
(k) | All periods include OCI amortization on non-active derivative positions and 2015 includes a gain on the sale of Talen Renewable Energy. |
Changes in Adjusted EBITDA
The following table shows Adjusted EBITDA by segment for the years ended December 31 as well as the change between periods. The factors that gave rise to the changes are described following the table.
|
| | | | | | | | | | | | | | | | | | | |
| | | Change |
| 2015 | | 2014 | | 2013 | | 2015 vs. 2014 |
| 2014 vs. 2013 |
East | $ | 1,080 |
| | $ | 898 |
| | $ | 1,122 |
| | $ | 182 |
| | $ | (224 | ) |
West | 56 |
| | 40 |
| | 24 |
| | 16 |
| | 16 |
|
Other | (134 | ) | | (179 | ) | | (177 | ) | | 45 |
| | (2 | ) |
Total | $ | 1,002 |
| | $ | 759 |
| | $ | 969 |
| | $ | 243 |
| | $ | (210 | ) |
East Segment
The increase in the East segment in 2015 compared with 2014 was primarily due to higher Margins driven by the addition of the Raven and Sapphire operations, higher realized energy prices, improved spark spreads, higher nuclear availability and lower average fuel prices. These factors were partially offset by lower capacity prices, gains that were realized in 2014 on certain commodity positions, the net effect of unusual market and weather volatility in the first quarter of 2014, lower volumes on full-requirements sales contracts, and retail electric sales activity. The net improvements in Margins were partially offset by higher operation and maintenance expenses, reflecting the addition of the Raven and Sapphire operations partially offset by lower outage costs for coal-fired units and other cost reductions attributable to the spinoff from PPL.
The decrease in the East segment in 2014 compared with 2013 was primarily due to lower Margins driven by lower realized energy and capacity prices, partially offset by favorable asset performance, gains on certain commodity positions and net benefits of unusual market and weather volatility in the first quarter of 2014.
West Segment
The increase in the West segment in 2015 compared with 2014 was primarily due to the addition of the Jade operations in Texas, partially offset by higher coal-fired plant outage costs.
The increase in the West segment in 2014 compared with 2013 was primarily due to the elimination of rent expense associated with the Colstrip lease, which was terminated in December 2013.
Other
The increase in 2015 compared with 2014 was primarily due to lower corporate expenses, which were primarily a result of cost reductions attributable to the spinoff from PPL.
See "Margins" and "Statement of Income Analysis" above for a more detailed analysis of the changes.
Financial Condition
Liquidity and Capital Resources
PPL Energy Supply expects to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents, credit facilities and commercial paper issuances. In 2013, PPL Energy Supply anticipates receiving capital contributions from its member, as well.
PPL Energy Supply'sTalen Energy's cash flows from operations and access to cost-effectivecost effective bank and capital markets are subject to risks and uncertainties including, but not limited to:
· | changes in electricity, fuel and other commodity prices; |
· | operational and credit risks associated with selling and marketing products in the wholesale power markets; |
· | potential ineffectiveness of the trading, marketing and risk management policy and programs used to mitigate PPL Energy Supply's risk exposure to adverse changes in electricity and fuel prices, interest rates and counterparty credit; |
· | reliance on transmission and distribution facilities that PPL Energy Supply does not own or control to deliver its electricity and natural gas; |
· | unavailability of generating units (due to unscheduled or longer-than-anticipated generation outages, weather and natural disasters) and the resulting loss of revenues and additional costs of replacement electricity; |
· | costs of compliance with existing and new environmental laws and with new security and safety requirements for nuclear facilities; |
· | any adverse outcome of legal proceedings and investigations with respect to PPL Energy Supply's current and past business activities; |
· | deterioration in the financial markets that could make obtaining new sources of bank and capital markets funding more difficult and more costly; and |
· | a downgrade in PPL Energy Supply's or its rated subsidiaries' credit ratings that could adversely affect their ability to access capital and increase the cost of credit facilities and any new debt. |
uncertainties. See "Item 1A. Risk Factors" for furthera discussion of risks and uncertainties that could affect PPL Energy Supply'sTalen Energy's cash flows.
At December 31, PPLTalen Energy Supply had the following:
following at December 31:
| | 2012 | | 2011 | | 2010 |
| | | | | | | | | |
Cash and cash equivalents | | $ | 413 | | $ | 379 | | $ | 661 |
Short-term debt | | $ | 356 | | $ | 400 | | $ | 531 |
The changes in PPL Energy Supply's cash and cash equivalents position resulted from:
| | 2012 | | 2011 | | 2010 |
| | | | | | | | | |
Net cash provided by (used in) operating activities | | $ | 784 | | $ | 776 | | $ | 1,840 |
Net cash provided by (used in) investing activities | | | (469) | | | (668) | | | (825) |
Net cash provided by (used in) financing activities | | | (281) | | | (390) | | | (612) |
Effect of exchange rates on cash and cash equivalents | | | | | | | | | 13 |
Net Increase (Decrease) in Cash and Cash Equivalents | | $ | 34 | | $ | (282) | | $ | 416 |
Operating Activities |
| | | | | | | | | | | |
| 2015 | | 2014 | | 2013 |
Cash and cash equivalents | $ | 141 |
| | $ | 352 |
| | $ | 239 |
|
Short-term debt | 608 |
| | 630 |
| | — |
|
Net cash provided by (used in) operating, investing, and financing activities increased by 1%, or $8 million, in 2012 compared with 2011. This was primarily due to a $92 million decrease in net cash used in other operating activities (includes a $77 million reduction in defined benefit plan funding)for the years ended December 31 and a $23 million decrease in net cash used in working capital (including a changethe changes between periods were as follows.
|
| | | | | | | | | | | | | | | | | | | |
| 2015 | | 2014 | | 2013 | | 2015 vs. 2014 | | 2014 vs. 2013 |
Operating activities | $ | 768 |
| | $ | 462 |
| | $ | 410 |
| | $ | 306 |
| | $ | 52 |
|
Investing activities | (915 | ) | | 497 |
| | (631 | ) | | (1,412 | ) | | 1,128 |
|
Financing activities | (64 | ) | | (846 | ) | | 47 |
| | 782 |
| | (893 | ) |
Operating Activities
NetThe components of the change in cash provided by (used in) operating activities decreased by 58%, or $1.1 billion, in 2011 compared with 2010. This was primarily due to lower gross energy margins of $240 million, after-tax, proceeds from monetizing certain full-requirements sales contracts in 2010 of $249 million, a reduction in cash from counter party collateral of $172 million, increases in other operating outflows of $200 million (including higher operation and maintenance expenses and defined benefits funding of $123 million) and the loss of operating cash from PPL Global ($203 million for 2010). In January 2011, PPL Energy Supply distributed its membership interest in PPL Global to its parent, PPL Energy Funding. See Note 9 to the Financial Statements for additional information on the distribution.were as follows.
|
| | | | | | | |
| 2015 vs. 2014 | | 2014 vs. 2013 |
Change - Cash Provided (Used) | | | |
Net income | $ | (751 | ) | | $ | 639 |
|
Non-cash components | 919 |
| | (656 | ) |
Working capital | 199 |
| | (46 | ) |
Defined benefit plan funding | (39 | ) | | 78 |
|
Other operating activities | (22 | ) | | 37 |
|
Total | $ | 306 |
| | $ | 52 |
|
A significant portion of PPL Energy Supply'sTalen Energy's operating cash flows is derived from its baseloadcompetitive generation business activities. PPLTalen Energy Supply employs a formal hedging program for its competitive baseload generation fleet, the primary objective of which is to provide a reasonable level of near-term cash flow and earnings certainty while preserving upside potential of power price increases over the medium term.term to benefit from power price increases. See Note 1915 to the Financial Statements for further discussion. Despite PPL Energy Supply'sTalen Energy's hedging practices, future cash flows from operating activities are influenced by commodityenergy and capacity prices and, therefore, will fluctuate from period to period.
PPL Energy Supply'sTalen Energy's contracts for the sale and purchase of electricity and fuel often require cash collateral or other credit enhancements,cash equivalents (e.g. letters of credit), or reductions or terminations of a portion of the entire contract through cash settlement, in the event of a downgrade of PPLTalen Energy Supply's or its subsidiary's credit ratings or adverse changes in market prices. For example, in addition to limiting its trading ability, if PPL Energy Supply's or its subsidiary's ratings were lowered to below "investment grade" and there was a 10% adverse movement in energy prices PPLor as a result of a downgrade in credit ratings, Talen Energy Supply estimates that, based on its December 31, 20122015 positions, it would have hadbeen required to post additional collateral of approximately $368$227 million with respect to electricity and fuel contracts. PPLTalen Energy Supplyhad adequate liquidity sources at December 31, 2015 if it would have been required to post this additional collateral. Talen Energy has in place risk management programs that are designed to monitor and manage its exposure to volatility of cash flows related to changes in energy and fuel prices, interest rates, foreign currency exchange rates, counterparty credit quality and the operating performance of its generating units.
Talen Energy had a $306 million increase in cash provided by operating activities in 2015 compared with 2014.
Net income (loss) decreased by $751 million between the periods. However, the decrease was more than offset by $919 million of non-cash components. The non-cash components consisted primarily of an increase in goodwill and other asset impairments of $642 million, a decrease in gains on the sale of assets of $306 million, an increase in non-cash amortization of $59 million, partially offset by an increase in unrealized gains on hedging and other hedging activities of $123 million. The increase in cash from operating activities from changes in working capital was partially due to a decrease in accounts receivable, fuel, materials and supplies, prepayments and increases in counterparty collateral (due in part to market price movement), partially offset by decreases in accounts payable. The decrease in fuel, materials and supplies related to increases that occurred in 2014 from coal inventory build-up and increases in fuel oil inventory at higher average prices. The decrease to accounts payable was related to the timing of certain plant outage payments, the change in market prices of gas and the settlement of the PPL affiliated accounts payable in advance of the June 1, 2015 spinoff. The decrease in prepayments was primarily due to income tax payments made in 2014.
Pension funding was $39 million higher in 2015.
Talen Energy had a $52 million increase in cash provided by operating activities in 2014 compared with 2013.
Net income improved by $639 million between the periods, however, this included an additional $656 million of net non-cash benefits, including a $315 million pre-tax gain in 2014 on the sale of the Montana hydroelectric generating facilities, a $426 million charge in 2013 to terminate the operating lease arrangement for interests in the Montana Colstrip facility and acquire the previously leased interests, and $167 million of lower unrealized losses on hedging activities. These non-cash benefits were partially offset by a $270 million decrease in deferred income tax benefits. The net $17 million decline from net income and non-cash adjustments in 2014 compared with 2013 reflects lower Margins, higher operation and maintenance expenses and other factors. Cash provided by operating activities in 2014 included a $176 million payment to PPL in November 2014 to satisfy the tax liability related to the gain on the sale of the Talen Montana hydroelectric facilities. Cash provided by operating activities in 2013 included a $271 million
payment in December in connection with terminating the operating lease arrangement for interests in the Montana Colstrip facility and acquiring the previously leased interests.
Pension funding was $78 million lower in 2014.
Investing Activities
The primary usecomponents of the change in cash inprovided by (used in) investing activities is capital expenditures. See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 2013 through 2017.were as follows |
| | | | | | | |
| 2015 vs. 2014 | | 2014 vs. 2013 |
Change - Cash Provided (Used) | | | |
Expenditures for PP&E | $ | (35 | ) | | $ | 167 |
|
Acquisitions & divestitures, net | (1,387 | ) | | 900 |
|
Restricted cash and cash equivalent activity | 195 |
| | (86 | ) |
Purchase and sale of investments, net | — |
| | (1 | ) |
Other investing activities | (185 | ) | | 148 |
|
Total | $ | (1,412 | ) | | $ | 1,128 |
|
Net cash used in investing activities decreased $199 million in 2012In 2015 compared with 2011,2014, "Acquisitions & divestitures, net" primarily as a resultreflects the November 2015 purchase of a $396MACH Gen for $603 million change in notes receivableand 2014 includes proceeds from affiliates and a $232 million change in restricted cash and cash equivalents,the sale of the Talen Montana hydroelectric generating facilities, partially offset by $381proceeds of $116 million less in asset sale proceeds (2011from the sale of non-core generation facilities) and $84 million used to fund the 2012 Ironwood Acquisition (seeTalen Renewable Energy in November 2015. See Note 106 to the Financial Statements for additional information on this acquisition).
Netthe acquisition and divestitures. The change in "Restricted cash usedand cash equivalent activity" relates to collateral requirements to support Talen Energy's commodity hedging program. This change is primarily due to changes in forward energy commodity prices. The change in "Other investing activities decreased $157 million in 2011 compared with 2010,activities" was primarily as a result of a decrease of $348 million in capital expenditures and a $219 million increase in the proceeds received from the sale of businesses, which are discussed in Note 9due to the Financial Statements. The decrease in cash used in investing activities from the above items was partially offset by an increase2014 receipt of $198$164 million related to notes receivable from affiliatesa U.S. Department of the Treasury grant for the Rainbow Dam and $212 million from changes in restricted cash and cash equivalents.Holtwood hydroelectric expansion capital projects.
In January 2011, PPL Energy Supply distributed its 100% membership interest2014 compared with 2013, the decrease in PPL Global"Expenditures for PP&E" was partially due to its parent, PPL Energy Funding.expenditures made in 2013 for the Holtwood hydroelectric expansion project. "Acquisitions & divestitures, net" reflects the 2014 sale of the Talen Montana hydroelectric generating facilities. See Note 96 to the Financial Statements for additional information. Excluding PPL Global, PPL Energy Supply's net cash usedinformation on the sale. The change in "Other investing activitiesactivities" was $544due to the receipt of $164 million in 2014 from U.S. Department of Treasury grants for 2010.the Rainbow Dam and Holtwood hydroelectric expansion capital projects.
Financing Activities
NetThe components of the change in cash usedprovided by (used in) financing activities were as follows.
|
| | | | | | | |
| 2015 vs. 2014 | | 2014 vs. 2013 |
Change - Cash Provided (Used) | | | |
Capital contributions from/distributions to predecessor member, net | $ | 1,032 |
| | $ | (2,336 | ) |
Debt issuances/redemptions, net | 574 |
| | 438 |
|
Change in short-term debt, net | (792 | ) | | 986 |
|
Other | (32 | ) | | 19 |
|
Total | $ | 782 |
| | $ | (893 | ) |
Talen Energy required $783 million less in financing activities was $281 million in 2012sources for 2015 compared with $390 million2014. In 2015, as a result of the terms of the spinoff transaction, the improvement in 2011 and $612 millioncapital contributions/distributions to predecessor member, net resulted from a reduction in 2010. The decrease from 2011 to 2012 primarily reflects the 2011 distribution of cash included in the net assets of PPL Global toactivity with PPL Energy Funding and a decreaseCorporation. Changes in net retirement of long-term debt, partially offset by higher net distributions to Member. The decrease from 2010 to 2011 primarily reflects lower net distributions to Member, partially offset by lower net issuances of long-term debt and the distribution of cash included in the net assets of PPL Global to PPL Energy Funding.
In 2012, cash used in financing activities primarily consisted of $787 million in distributionsrelated to Member and a $44 million net decrease in short-term debt partially offset by $563resulted from proceeds from 2014 borrowings of $630 million that were needed at that time to fund increased collateral requirements to support Talen Energy's commodity hedging program that were then repaid in contributions from Member.
In 2011, cash used in financing activities primarily consisted2015 using the $591 million of a $325 million distribution of cash included in the net assets of PPL Global to PPL Energy Funding, $316 million in distributions to Member, and net debt retirements of $200 million, partially offset by $461 million in contributions from Member.
In 2010, cash used in financing activities primarily consisted of $4.7 billion in distributions to Member, partially offset by $3.6 billion in contributions from Member and net debt issuances of $509 million. The distributions to and contributions from Member during 2010 primarily relate to the funds received by PPL in June 2010proceeds from the issuance of common stocklong-term debt. In addition, in 2015, in connection with the RJS Power acquisition, $38 million of short-term debt borrowings under the then-outstanding RJS Power Holdings, LLC credit facility were repaid and 2010 Equity Units. These funds were invested bythe facility was terminated in connection with the acquisition.
In 2014, financing activities included distributions of $836 million to PPL of the proceeds from the Talen Montana hydroelectric generating facilities sale, net of a subsidiarytax liability payment and proceeds from the U.S. Department of Treasury grant for the Holtwood hydroelectric expansion capital project.
In 2013, financing activities included net capital contributions of $1.1 billion from PPL Energy Funding Corporation to Talen Energy Supply until they were returned to its Memberfund debt maturities, repay short-term debt and terminate the operating lease arrangement for interests in October 2010the Montana Colstrip facility and acquire the previously leased interests. Debt repayments included a $300 million debt maturity and the $437 million repayment by an unconsolidated trust of outstanding debt related to be available to partially fund PPL'sthe acquisition of LKE and pay certain acquisition-related fees and expenses.the previously leased Lower Mt. Bethel facility.
See "Long-term Debt and Equity Securities" below for additional information on current year activity. See "Forecasted Sources of Cash" for a discussion of PPL Energy Supply'sTalen Energy's plans to issue debt securities,access the capital markets, as well as a discussion of credit facility capacity available to PPLTalen Energy Supply. Also see "Forecasted Uses of Cash" for information regardinga discussion of Talen Energy Supply's and a subsidiary's maturities of PPL Energy Supply's long-term debt.
Long-term Debt and Equity Securities
Talen Energy activity for 2015 included:
|
| | | | | | | | | | | | |
| | Debt | | Stock Issuances |
| | Issuances (a) | | Retirements | |
| | | | | | |
Cash Transactions | | $ | 600 |
| | $ | 335 |
| | $ | — |
|
Non-cash Transactions (b) | | 1,950 |
| | 231 |
| | 902 |
|
| |
(a) | Issuances are net of pricing discounts, where applicable and excludes the impact of debt issuance costs. |
| |
(b) | "Debt Issuances" include long-term debt that remained outstanding as part of the RJS Power and MACH Gen acquisitions and the remarketing and exchange of PEDFA debt. "Retirements" represents the remarketing and exchange of PEDFA debt. "Stock Issuances" only applies to Talen Energy Corporation and includes common stock issued to the Riverstone Holders in connection with the RJS Power acquisition based on the June 1, 2015 closing "when-issued" market price. |
See Note 5 to the Financial Statements for additional information about long-term debt securities and Note 1 to the Financial Statements for additional information on equity issued as part of the spinoff from PPL and simultaneous acquisition of RJS Power.
Forecasted Sources of Cash
PPLTalen Energy Supply expects to continue to have sufficient sources ofadequate liquidity available in the near term, includingfrom operating cash flows, from operations, variouscash and cash equivalents and credit facilities, commercial paper issuances, operating leases and contributions from member.arrangements. Additionally, although Talen Energy currently does not plan to access the capital markets, it may decide to do so based on market conditions. The discussion below regarding credit arrangements of Talen Energy Supply apply to Talen Energy Corporation through consolidation.
Revolving Credit Facilities
At December 31, 2012, PPLTalen Energy Supply'sSupply and a subsidiary maintain credit facilities to enhance liquidity and provide credit support. The amounts "Borrowed" below are recorded as "Short-term debt" on the Balance Sheets. The total committed borrowing capacity under outstanding credit facilities and the use of this borrowing capacity at December 31, were:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2015 | | 2014 |
| Committed Capacity | | Borrowed | | Letters of Credit Issued | | Unused Capacity | | Committed Capacity | | Borrowed | | Letters of Credit Issued | | Unused Capacity |
Credit Facilities | $ | 2,010 |
| | $ | 608 |
| | $ | 194 |
| | $ | 1,208 |
| | $ | 3,150 |
| | $ | 630 |
| | $ | 259 |
| | $ | 2,261 |
|
| | | | | | | | | Letters of | | | |
| | | | | | | | | Credit | | | |
| | | | | | | | | Issued | | | |
| | | | | | | | | and | | | |
| | | | | | | | | Commercial | | | |
| | | Committed | | | | | Paper | | Unused |
| | | Capacity | | Borrowed | | Backup | | Capacity |
| | | | | | | | | | | | | |
Syndicated Credit Facility (a) | | $ | 3,000 | | | | | $ | 499 | | $ | 2,501 |
Letter of Credit Facility | | | 200 | | | n/a | | | 132 | | | 68 |
Total PPL Energy Supply Credit Facilities (b) | | $ | 3,200 | | | | | $ | 631 | | $ | 2,569 |
On June 1, 2015, in connection with the completion of the spinoff transaction, Talen Energy Supply entered into the Talen Energy Supply RCF and replaced Talen Energy Supply's previously existing $3 billion unsecured syndicated credit facility that existed at December 31, 2014. At December 31, 2014, the $630 million of outstanding principal amount under the old facility was repaid prior to the termination of the old facility and any outstanding letters of credit were transferred to the Talen Energy Supply RCF.The Talen Energy Supply RCF provides capacity for letters of credit and short-term borrowings and requires Talen Energy Supply to maintain a senior secured net debt to adjusted EBITDA ratio (as defined in the agreement) of less than or equal to 4.50 to 1.00 as of the last day of any fiscal quarter. Talen Energy Supply pays customary fees on the facility and borrowings bear interest at its option at either a defined base rate or LIBOR-based rates, in each case plus an applicable margin.
(a) | This facility contains a financial covenant requiring PPL Energy Supply's debt to total capitalization not to exceed 65%, as calculated in accordance with the facility, and other customary covenants. |
Table of Contents
The commitments at December 31, 2015 under the Talen Energy Supply RCF are provided by a diverse bank group, with no one bank or its affiliates providing an aggregate commitment of more than 8% of the total committed capacity. In February 2016, Talen Energy repaid all $600 million of its then-outstanding short-term debt obligations under the Talen Energy Supply RCF, primarily with cash proceeds from the sale of Ironwood.
(b) | The commitments under PPL Energy Supply's credit facilities are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than 11% of the total committed capacity. |
The New MACH Gen RCF remained outstanding after the November 2015 MACH Gen acquisition. The New MACH Gen RCF provides capacity for short-term borrowings and up to $120 million of letters of credit. New MACH Gen pays customary fees on the facility and borrowings bear interest at 12-month LIBOR plus an applicable margin.
In addition to the financial covenants noted above, the credit agreements governing the above credit facilities contain various other covenants. Failure to comply with the covenants after applicable grace periods could result in acceleration of repayment of borrowings and/or termination of the agreements. PPLTalen Energy Supply monitors compliance with the covenants on a regular basis. At December 31, 2012, PPL2015, Talen Energy Supply was in compliance with these covenants. At this time PPLTalen Energy Supply believes that these covenants and other borrowing conditions will not limit access to these funding sources.
Other Facilities
Talen Energy Supply maintains a $1.3 billion secured energy marketing and trading facility whereby Talen Energy Supply will receive credit to be applied to satisfy collateral posting obligations related to Talen Energy's energy marketing and trading activities with counterparties participating in the facility.
See Note 75 to the Financial Statements for further discussion of PPL Energy Supply'sTalen Energy's credit facilities.
Commercial Paperand other arrangements.
PPL Energy Supply maintains a $750 million commercial paper program to provide an additional financing source to fund its short-term liquidity needs, if and when necessary. Commercial paper issuances are supported by PPL Energy Supply's Syndicated Credit Facility. At December 31, 2012, PPL Energy Supply had $356 million of commercial paper outstanding at a weighted-average interest rate of approximately 0.50%.
Operating Leases
PPL Energy Supply and its subsidiaries also have available funding sources that are provided through operating leases. PPL Energy Supply's subsidiaries lease office space, land, buildings and certain equipment. These leasing structures provide PPL Energy Supply additional operating and financing flexibility. The operating leases contain covenants that are typical for these agreements, such as maintaining insurance, maintaining corporate existence and timely payment of rent and other fees.
PPL Energy Supply, through its subsidiary PPL Montana, leases a 50% interest in Colstrip Units 1 and 2 and a 30% interest in Unit 3, under four 36-year, non-cancelable operating leases. These operating leases are not recorded on PPL Energy Supply's Balance Sheets. The leases place certain restrictions on PPL Montana's ability to incur additional debt, sell assets and declare dividends.
See Note 11 to the Financial Statements for further discussion of the operating leases.
Contributions from Member
From time to time, PPL Energy Supply's Member, PPL Energy Funding, makes capital contributions to PPL Energy Supply. PPL Energy Supply uses these contributions to fund capital expenditures and for other general corporate purposes.
Forecasted Uses of Cash
In addition to expenditures required for normal operating activities, such as purchased power, payroll, fuel and taxes, PPLTalen Energy Supply currently expects to incur future cash outflows for capital expenditures, various contractual obligations distributions to its Member and possibly thecould purchase or redemption ofredeem a portion of its or a subsidiary's outstanding debt securities.
Capital Expenditures
The table below shows PPL Energy Supply'sTalen Energy's current capital expenditure projections for the years 20132016 through 2017.2020.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Projected |
| | Total | | 2016 | | 2017 | | 2018 | | 2019 | | 2020 |
| | | | | | | | | | | | |
Sustenance | | $ | 1,310 |
| | $ | 233 |
| | $ | 305 |
| | $ | 295 |
| | $ | 257 |
| | $ | 220 |
|
Nuclear fuel | | 608 |
| | 82 |
| | 114 |
| | 132 |
| | 137 |
| | 143 |
|
Growth | | 113 |
| | 108 |
| | 3 |
| | 1 |
| | 1 |
| | — |
|
Information technology | | 120 |
| | 54 |
| | 15 |
| | 20 |
| | 17 |
| | 14 |
|
Environmental | | 137 |
| | 17 |
| | 15 |
| | 16 |
| | 50 |
| | 39 |
|
Regulatory | | 61 |
| | 26 |
| | 26 |
| | 8 |
| | 1 |
| | — |
|
Discretionary | | 31 |
| | 6 |
| | 6 |
| | 7 |
| | 6 |
| | 6 |
|
Total (a) (b) | | $ | 2,380 |
| | $ | 526 |
| | $ | 484 |
| | $ | 479 |
| | $ | 469 |
| | $ | 422 |
|
| | | | Projected |
| | | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
Construction expenditures (a) (b) | | | | | | | | | | | | | | | |
| Generating facilities | | $ | 387 | | $ | 248 | | $ | 247 | | $ | 241 | | $ | 292 |
| Environmental | | | 94 | | | 89 | | | 22 | | | 20 | | | 21 |
| Other | | | 26 | | | 34 | | | 15 | | | 15 | | | 15 |
| | Total Construction Expenditures | | | 507 | | | 371 | | | 284 | | | 276 | | | 328 |
Nuclear fuel | | | 152 | | | 145 | | | 153 | | | 158 | | | 162 |
Total Capital Expenditures | | $ | 659 | | $ | 516 | | $ | 437 | | $ | 434 | | $ | 490 |
| |
(a) | Construction expendituresDoes not include the Holtwood and Lake Wallenpaupack hydroelectric projects, the Ironwood natural gas combined-cycle plant, and the C.P. Crane coal-fired power plant, which have been sold or are under an agreement to sell. See Note 6 to the Financial Statements for additional information on the divestitures. |
| |
(b) | Includes capitalized interest, which, over all years, is expected to total approximately $82 million for the years 2013 through 2017.$60 million. |
(b) | Includes expenditures for certain intangible assets. |
PPL Energy Supply's capital expenditure projections for the years 2013 through 2017 total approximately $2.5 billion. Capital expenditure plans are revised periodically to reflect changes in operational, market and regulatory conditions. This table includes projected costs related to the planned 153 MW of incremental capacity increases. See Note 8 to the Financial Statements for information regarding the significant development projects.
PPL Energy Supply plans to fund its capital expenditures in 2013 with cash from operations and equity contributions from PPL Energy Funding.
Contractual Obligations
PPL Energy Supply has assumed various financial obligations and commitments in the ordinary course of conducting its business. At December 31, 2012, the estimated contractual cash obligations of PPL Energy Supply were:
| | | Total | | 2013 | | 2014 - 2015 | | 2016 - 2017 | | After 2017 |
| | | | | | | | | | | | | | | | |
Long-term Debt (a) | | $ | 3,249 | | $ | 751 | | $ | 635 | | $ | 386 | | $ | 1,477 |
Interest on Long-term Debt (b) | | | 1,169 | | | 196 | | | 265 | | | 167 | | | 541 |
Operating Leases (c) | | | 362 | | | 76 | | | 143 | | | 39 | | | 104 |
Purchase Obligations (d) | | | 3,047 | | | 863 | | | 878 | | | 696 | | | 610 |
Other Long-term Liabilities | | | | | | | | | | | | | | | |
| Reflected on the Balance | | | | | | | | | | | | | | | |
| Sheet under GAAP (e) (f) | | | 105 | | | 105 | | | | | | | | | |
Total Contractual Cash Obligations | | $ | 7,932 | | $ | 1,991 | | $ | 1,921 | | $ | 1,288 | | $ | 2,732 |
(a) | Reflects principal maturities only based on stated maturity dates, except for the 5.70% REset Put Securities (REPS). See Note 7 to the Financial Statements for a discussion of the remarketing feature related to the REPS, as well as discussion of variable-rate remarketable bonds. PPL Energy Supply does not have any significant capital lease obligations. |
(b) | Assumes interest payments through stated maturity, except for the REPS, for which interest is reflected to the put date. The payments herein are subject to change, as payments for debt that is or becomes variable-rate debt have been estimated. |
(c) | See Note 11 to the Financial Statements for additional information. |
(d) | The amounts include agreements to purchase goods or services that are enforceable and legally binding and specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. Primarily includes PPL Energy Supply's purchase obligations of electricity, coal, nuclear fuel and limestone as well as certain construction expenditures, which are also included in the Capital Expenditures table presented above. Financial swaps and open purchase orders that are provided on demand with no firm commitment are excluded from the amounts presented. |
(e) | The amounts represent contributions made or committed to be made for 2013 for PPL's U.S. pension plans. See Note 13 to the Financial Statements for a discussion of expected contributions. |
(f) | At December 31, 2012, total unrecognized tax benefits of $30 million were excluded from this table as PPL Energy Supply cannot reasonably estimate the amount and period of future payments. See Note 5 to the Financial Statements for additional information. |
Distributions to Member
From time to time, as determined by its Board of Managers, PPL Energy Supply makes distributions to its member.
Purchase or Redemption of Debt Securities
PPL Energy Supply will continue to evaluate its outstanding debt securities and may decide to purchase or redeem these securities depending upon prevailing market conditions and available cash.
Rating Agency Actions
Moody's, S&P and Fitch periodically review the credit ratings on the debt securities of PPL Energy Supply and its subsidiaries. Based on their respective independent reviews, the rating agencies may make certain ratings revisions or ratings affirmations.
A credit rating reflects an assessment by the rating agency of the creditworthiness associated with an issuer and particular securities that it issues. The credit ratings of PPL Energy Supply and its subsidiaries are based on information provided by PPL Energy Supply and other sources. The ratings of Moody's, S&P and Fitch are not a recommendation to buy, sell or hold any securities of PPL Energy Supply or its subsidiaries. Such ratings may be subject to revisions or withdrawal by the agencies at any time and should be evaluated independently of each other and any other rating that may be assigned to the securities. The credit ratings of PPL Energy Supply and its subsidiaries affect its liquidity, access to capital markets and cost of borrowing under its credit facilities.
The following table sets forth PPL Energy Supply's and its subsidiaries' security credit ratings as of December 31, 2012.
| | Senior Unsecured | | Senior Secured | | Commercial Paper |
Issuer | | Moody's | | S&P | | Fitch | | Moody's | | S&P | | Fitch | | Moody's | | S&P | | Fitch |
| | | | | | | | | | | | | | | | | | |
PPL Energy Supply | | Baa2 | | BBB | | BBB | | | | | | | | P-2 | | A-2 | | F-2 |
| | | | | | | | | | | | | | | | | | |
PPL Ironwood | | | | | | | | B2 | | B | | | | | | | | |
A downgrade in PPL Energy Supply's or its subsidiaries' credit ratings could result in higher borrowing costs and reduced access to capital markets. PPL Energy Supply and its subsidiaries have no credit rating triggers that would result in the reduction of access to capital markets or the acceleration of maturity dates of outstanding debt.
In addition to the credit ratings noted above, the rating agencies took the following actions related to PPL Energy Supply and its subsidiaries in 2012.
In January 2012, S&P affirmed its rating and revised its outlook, from positive to stable, for PPL Montana's Pass Through Certificates due 2020.
Following the announcement of the then-pending acquisition of AES Ironwood, L.L.C. in February 2012, the rating agencies took the following actions:
· | In March 2012, Moody's placed AES Ironwood, L.L.C.'s senior secured bonds under review for possible ratings upgrade. |
· | In April 2012, S&P affirmed the rating of AES Ironwood, L.L.C.'s senior secured bonds. |
In May 2012, Fitch downgraded its rating, from BBB to BBB- and revised its outlook, from negative to stable, for PPL Montana's Pass Through Certificates due 2020.
In November 2012, S&P revised its outlook, from stable to negative, for PPL Montana's Pass Through Certificates due 2020.
In December 2012, Fitch affirmed the issuer default rating, individual security rating and revised the outlook, from stable to negative, for PPL Energy Supply.
In February 2013, Moody's upgraded its rating, from Ba1 to B2, and revised the outlook from under review to stable for PPL Ironwood.
Ratings Triggers
PPL Energy Supply has various derivative and non-derivative contracts, including contracts for the sale and purchase of electricity and fuel, commodity transportation and storage, tolling agreements and interest rate instruments, which contain provisions that require PPL Energy Supply to post additional collateral, or permit the counterparty to terminate the contract, if PPL Energy Supply's credit rating were to fall below investment grade. See Note 19 to the Financial Statements for a discussion of "Credit Risk-Related Contingent Features," including a discussion of the potential additional collateral that would have been required for derivative contracts in a net liability position at December 31, 2012. At December 31, 2012, if PPL Energy Supply's credit rating had been below investment grade, PPL Energy Supply would have been required to prepay or post an additional $385 million of collateral to counterparties for both derivative and non-derivative commodity and commodity-related contracts used in its generation, marketing and trading operations and interest rate contracts.
Guarantees for Subsidiaries
PPL Energy Supply guarantees certain consolidated affiliate financing arrangements that enable certain transactions. Some of the guarantees contain financial and other covenants that, if not met, would limit or restrict the consolidated affiliates' access to funds under these financing arrangements, require early maturity of such arrangements or limit the consolidated affiliates' ability to enter into certain transactions. At this time, PPL Energy Supply believes that these covenants will not limit access to relevant funding sources. See Note 15 to the Financial Statements for additional information about guarantees.
Off-Balance Sheet Arrangements
PPL Energy Supply has entered into certain agreements that may contingently require payment to a guaranteed or indemnified party. See Note 15 to the Financial Statements for a discussion of these agreements.
Risk Management - Energy Marketing & Trading and Other
Market Risk
See Notes 1, 18, and 19 to the Financial Statements for information about PPL Energy Supply's risk management objectives, valuation techniques and accounting designations.
The forward-looking information presented below provides estimates of what may occur in the future, assuming certain adverse market conditions and model assumptions. Actual future results may differ materially from those presented. These disclosures are not precise indicators of expected future losses, but only indicators of possible losses under normal market conditions at a given confidence level.
Commodity Price Risk (Non-trading)
PPL Energy Supply segregates its non-trading activities into two categories: hedge activity and economic activity. Transactions that are accounted for as hedge activity qualify for hedge accounting treatment. The economic activity category includes transactions that address a specific risk, but were not eligible for hedge accounting or for which hedge accounting was not elected. This activity includes the changes in fair value of positions used to hedge a portion of the economic value of PPL Energy Supply's competitive generation assets and full-requirement sales and retail contracts. This economic activity is subject to changes in fair value due to market price volatility of the input and output commodities (e.g., fuel and power). Although they do not receive hedge accounting treatment, these transactions are considered non-trading activity. The net fair value of economic positions at December 31, 2012 and 2011 was a net asset/(liability) of $346 million and $(63) million. See Note 19 to the Financial Statements for additional information.
To hedge the impact of market price volatility on PPL Energy Supply's energy-related assets, liabilities and other contractual arrangements, PPL Energy Supply both sells and purchases physical energy at the wholesale level under FERC market-based tariffs throughout the U.S. and enters into financial exchange-traded and over-the-counter contracts. PPL Energy Supply's non-trading commodity derivative contracts range in maturity through 2019.
The following table sets forth the changes in the net fair value of non-trading commodity derivative contracts at December 31, 2012. See Notes 18 and 19 to the Financial Statements for additional information.
| | Gains (Losses) |
| | 2012 | | 2011 |
| | | | | | |
Fair value of contracts outstanding at the beginning of the period | | $ | 1,082 | | $ | 958 |
Contracts realized or otherwise settled during the period | | | (1,005) | | | (523) |
Fair value of new contracts entered into during the period (a) | | | 7 | | | 13 |
Other changes in fair value | | | 389 | | | 634 |
Fair value of contracts outstanding at the end of the period | | $ | 473 | | $ | 1,082 |
(a) | Represents the fair value of contracts at the end of the quarter of their inception. |
The following table segregates the net fair value of non-trading commodity derivative contracts at December 31, 2012, based on the level of observability of the information used to determine the fair value.
| | | Net Asset (Liability) |
| | | Maturity | | | | | | | | Maturity | | | |
| | | Less Than | | Maturity | | Maturity | | in Excess | | Total Fair |
| | | 1 Year | | 1-3 Years | | 4-5 Years | | of 5 Years | | Value |
Source of Fair Value | | | | | | | | | | | | | | | |
Prices based on significant observable inputs (Level 2) | | $ | 452 | | $ | 15 | | $ | (20) | | $ | 5 | | $ | 452 |
Prices based on significant unobservable inputs (Level 3) | | | 8 | | | 10 | | | 3 | | | | | | 21 |
Fair value of contracts outstanding at the end of the period | | $ | 460 | | $ | 25 | | $ | (17) | | $ | 5 | | $ | 473 |
PPL Energy Supply sells electricity, capacity and related services and buys fuel on a forward basis to hedge the value of energy from its generation assets. If PPL Energy Supply were unable to deliver firm capacity and energy or to accept the delivery of fuel under its agreements, under certain circumstances it could be required to pay liquidating damages. These damages would be based on the difference between the market price and the contract price of the commodity. Depending on price changes in the wholesale energy markets, such damages could be significant. Extreme weather conditions, unplanned power plant outages, transmission disruptions, nonperformance by counterparties (or their counterparties) with which it has energy contracts and other factors could affect PPL Energy Supply's ability to meet its obligations, or cause significant increases in the market price of replacement energy. Although PPL Energy Supply attempts to mitigate these risks, there can be no assurance that it will be able to fully meet its firm obligations, that it will not be required to pay damages for failure to perform, or that it will not experience counterparty nonperformance in the future. In connection with its bankruptcy proceedings, a significant counterparty, SMGT, had been purchasing lower volumes of electricity than prescribed in the contract and effective April 1, 2012 the contract was terminated. PPL Energy Supply cannot predict the prices or other terms on which it will be able to market to third parties the power that SMGT will not purchase from PPL EnergyPlus due to the termination of this contract. See Note 15 to the Financial Statements for additional information.
Commodity Price Risk (Trading)
PPL Energy Supply's trading commodity derivative contracts range in maturity through 2017. The following table sets forth changes in the net fair value of trading commodity derivative contracts at December 31, 2012 . See Notes 18 and 19 to the Financial Statements for additional information.
| | | Gains (Losses) |
| | | 2012 | | 2011 |
| | | | | | | |
Fair value of contracts outstanding at the beginning of the period | | $ | (4) | | $ | 4 |
Contracts realized or otherwise settled during the period | | | 20 | | | (14) |
Fair value of new contracts entered into during the period (a) | | | 17 | | | 10 |
Other changes in fair value | | | (4) | | | (4) |
Fair value of contracts outstanding at the end of the period | | $ | 29 | | $ | (4) |
(a) | Represents the fair value of contracts at the end of the quarter of their inception. |
The following table segregates the net fair value of trading commodity derivative contracts at December 31, 2012, based on the level of observability of the information used to determine the fair value.
| | | Net Asset (Liability) |
| | | Maturity | | | | | | | | Maturity | | | |
| | | Less Than | | Maturity | | Maturity | | in Excess | | Total Fair |
| | | 1 Year | | 1-3 Years | | 4-5 Years | | of 5 Years | | Value |
Source of Fair Value | | | | | | | | | | | | | | | |
Prices based on significant observable inputs (Level 2) | | $ | 18 | | $ | 10 | | | | | | | | $ | 28 |
Prices based on significant unobservable inputs (Level 3) | | | 1 | | | | | | | | | | | | 1 |
Fair value of contracts outstanding at the end of the period | | $ | 19 | | $ | 10 | | | | | | | | $ | 29 |
VaR Models
A VaR model is utilized to measure commodity price risk in domestic gross energy margins for its non-trading and trading portfolios. VaR is a statistical model that attempts to estimate the value of potential loss over a given holding period under normal market conditions at a given confidence level. VaR is calculated using a Monte Carlo simulation technique based on a five-day holding period at a 95% confidence level. Given the company's disciplined hedging program, the non-trading VaR exposure is expected to be limited in the short-term. The VaR for portfolios using end-of-month results for the period was as follows.
| | | Trading VaR | | Non-Trading VaR |
| | | 2012 | | 2011 | | 2012 | | 2011 |
95% Confidence Level, Five-Day Holding Period | | | | | | | | | | | | |
| Period End | | $ | 2 | | $ | 1 | | $ | 12 | | $ | 6 |
| Average for the Period | | | 3 | | | 3 | | | 10 | | | 5 |
| High | | | 8 | | | 6 | | | 12 | | | 7 |
| Low | | | 1 | | | 1 | | | 7 | | | 4 |
The trading portfolio includes all proprietary trading positions, regardless of the delivery period. All positions not considered proprietary trading are considered non-trading. The non-trading portfolio includes the entire portfolio, including generation, with delivery periods through the next 12 months. Both the trading and non-trading VaR computations exclude FTRs due to the absence of reliable spot and forward markets. The fair value of the non-trading and trading FTR positions was insignificant at December 31, 2012.
Interest Rate Risk
PPL Energy Supply and its subsidiaries issue debt to finance their operations, which exposes them to interest rate risk. PPL and PPL Energy Supply utilize various financial derivative instruments to adjust the mix of fixed and floating interest rates in PPL Energy Supply's debt portfolio, adjust the duration of its debt portfolio and lock in benchmark interest rates in anticipation of future financing, when appropriate. Risk limits under the risk management program are designed to balance risk exposure to volatility in interest expense and changes in the fair value of PPL Energy Supply's debt portfolio due to changes in the absolute level of interest rates.
At December 31, 2012 and 2011, PPL Energy Supply's potential annual exposure to increased interest expense, based on a 10% increase in interest rates, was not significant.
PPL Energy Supply is also exposed to changes in the fair value of its debt portfolio. PPL Energy Supply estimated that a 10% decrease in interest rates at December 31, 2012 would increase the fair value of its debt portfolio by $52 million, compared with $53 million at December 31, 2011.
NDT Funds - Securities Price Risk
In connection with certain NRC requirements, PPL Susquehanna maintains trust funds to fund certain costs of decommissioning the PPL Susquehanna nuclear plant (Susquehanna). At December 31, 2012, these funds were invested primarily in domestic equity securities and fixed-rate, fixed-income securities and are reflected at fair value on PPL Energy Supply's Balance Sheet. The mix of securities is designed to provide returns sufficient to fund Susquehanna's decommissioning and to compensate for inflationary increases in decommissioning costs. However, the equity securities included in the trusts are exposed to price fluctuation in equity markets, and the values of fixed-rate, fixed-income securities are primarily exposed to changes in interest rates. PPL actively monitors the investment performance and periodically reviews asset allocation in accordance with its nuclear decommissioning trust policy statement. At December 31, 2012, a hypothetical 10% increase in interest rates and a 10% decrease in equity prices would have resulted in an estimated $49 million reduction in the fair value of the trust assets, compared with $43 million at December 31, 2011. See Notes 18 and 23 to the Financial Statements for additional information regarding the NDT funds.
Defined Benefit Plans - Securities Price Risk
See "Application of Critical Accounting Policies - Defined Benefits" for additional information regarding the effect of securities price risk on plan assets.
Credit Risk
Credit risk is the risk that PPL Energy Supply would incur a loss as a result of nonperformance by counterparties of their contractual obligations. PPL Energy Supply maintains credit policies and procedures with respect to counterparty credit (including requirements that counterparties maintain specified credit ratings) and requires other assurances in the form of credit support or collateral in certain circumstances in order to limit counterparty credit risk. However, PPL Energy Supply has concentrations of suppliers and customers among electric utilities, financial institutions and other energy marketing and trading companies. These concentrations may impact PPL Energy Supply's overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions.
PPL Energy Supply includes the effect of credit risk on its fair value measurements to reflect the probability that a counterparty will default when contracts are out of the money (from the counterparty's standpoint). In this case, PPL Energy Supply would have to sell into a lower-priced market or purchase from a higher-priced market. When necessary, PPL Energy Supply records an allowance for doubtful accounts to reflect the probability that a counterparty will not pay for deliveries PPL Energy Supply has made but not yet billed, which are reflected in "Unbilled revenues" on the Balance Sheets. PPL Energy Supply also has established a reserve with respect to certain receivables from SMGT, which is reflected in accounts receivable on the Balance Sheets. See Note 15 to the Financial Statements for additional information.
See "Overview" in this Item 7 and Notes 16, 18 and 19 to the Financial Statements for additional information on credit concentration and credit risk.
Related Party Transactions
PPL Energy Supply is not aware of any material ownership interests or operating responsibility by senior management of PPL Energy Supply in outside partnerships, including leasing transactions with variable interest entities, or other entities doing business with PPL Energy Supply. See Note 16 to the Financial Statements for additional information on related party transactions.
Acquisitions, Development and Divestitures
PPL Energy Supply from time to time evaluates opportunities for potential acquisitions, divestitures and development projects. Development projects are reexamined based on market conditions and other factors to determine whether to proceed with the projects, sell, cancel or expand them, execute tolling agreements or pursue other options.
Incremental capacity increases of 153 MW are currently planned, primarily at existing PPL Energy Supply generating facilities. See "Item 2. Properties - Supply Segment" for additional information.
See Notes 8 and 9 to the Financial Statements for additional information on the more significant activities, including the 2012 Ironwood Acquisition.
Environmental Matters
Extensive federal, state and local environmental laws and regulations are applicable to PPL Energy Supply's air emissions, water discharges and the management of hazardous and solid waste, among other areas; and the cost of compliance or alleged non-compliance cannot be predicted with certainty but could be material. In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed by the relevant agencies. Costs may take the form of increased capital expenditures or operating and maintenance expenses; monetary fines, penalties or other restrictions. Many of these environmental law considerations are also applicable to the operations of key suppliers, or customers, such as coal producers and industrial power users, and may impact the cost of their products or their demand for PPL Energy Supply's services.
Physical effects associated with climate change could include the impact of changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to PPL Energy Supply's generation assets as well as impacts on customers. In addition, changed weather patterns could potentially reduce annual rainfall in areas where PPL Energy Supply has hydro generating facilities or where river water is used to cool its fossil and nuclear powered generators. PPL Energy Supply cannot currently predict whether its businesses will experience these potential climate change-related risks or estimate the potential cost of their related consequences.
The below provides a discussion of the more significant environmental matters.
Coal Combustion Residuals (CCRs)
In June 2010, the EPA proposed two approaches to regulating CCRs (as either hazardous or non-hazardous) under existing solid waste regulations. A final rulemaking is currently expected before the end of 2015. However, the timing of the final regulations could be accelerated by certain litigation that could require the EPA to issue its regulations sooner. Regulations could impact handling, disposal and/or beneficial use of CCRs. The economic impact could be material if CCRs are regulated as hazardous waste, and significant if regulated as non-hazardous, in accordance with the proposed rule.
Effluent Limitation Guidelines
The EPA is to issue guidelines for technology-based limits in discharge permits for scrubber wastewater and is expected to require dry ash handling. The EPA agreed, in recent settlement negotiations with environmentalists, to propose revisions to its effluent limitation guidelines (ELGs) by April 2013, with a final rule in late 2014. Limits could be so stringent that plants may consider extensive new or modified wastewater treatment facilities and possibly zero liquid discharge operations, the cost of which could be significant. Impacts should be better understood after the proposed rule is issued.
316(b) Cooling Water Intake Structures Rule
In April 2011, the EPA published a draft regulation under Section 316(b) of the Clean Water Act, which regulates cooling water intakes for power plants. The draft rule has two provisions: one requires installation of Best Technology Available (BTA) to reduce mortality of aquatic organisms that are pulled into the plants cooling water system (entrainment), and the second imposes standards for reduction of mortality of aquatic organisms trapped on water intake screens (impingement). A final rule is expected in June 2013. The proposed regulation would apply to nearly all PPL Energy Supply-owned steam electric plants in Pennsylvania and Montana, potentially even including those equipped with closed-cycle cooling systems. PPL Energy Supply's compliance costs could be significant, especially if the final rule requires closed-cycle systems at plants that do not currently have them or conversions of once-through systems to closed-cycle.
GHG Regulations
In 2013, the EPA is expected to finalize limits on GHG emissions from new power plants and to begin working on a proposal for such emissions from existing power plants. The EPA's proposal on GHG emissions from new power plants would effectively preclude construction on any coal-fired plants and could even be difficult for new gas-fired plants to meet. With respect to existing power plants, the impact could be very significant, depending on the structure and stringency of the final rule. PPL Energy Supply, along with others in the industry, filed comments on the EPA's proposal related to GHG emissions from new plants. With respect to GHG limits for existing plants, PPL Energy Supply will advocate for reasonable, flexible requirements.
MATS
The EPA finalized MATS requiring fossil-fuel fired plants to reduce emissions of mercury and other hazardous air pollutants by April 16, 2015. The rule is being challenged by industry groups and states. The EPA has subsequently proposed changes to the rule with respect to new sources to address the concern that the rule effectively precludes new coal plants. PPL Energy Supply is generally well-positioned to comply with MATS due to its recent investment in, and installation of, environmental controls such as wet flue gas desulfurization systems. PPL Energy Supply is evaluating chemical additive systems for mercury control at Brunner Island, and modifications to existing controls at Colstrip for improved particulate matter reductions. In September 2012, PPL Energy Supply announced its intention to place its Corette plant in long-term reserve status beginning in April 2015 due to expected market conditions and costs to comply with MATS.
CSAPR and CAIR
In 2011, the EPA finalized its CSAPR regulating emissions of nitrous oxide and sulfur dioxide through new allowance trading programs which were to be implemented in two phases (2012 and 2014). Like its predecessor, the CAIR, CSAPR targeted sources in the eastern United States. In December 2011, the Court of Appeals for the D.C. Circuit (the Court) stayed implementation of CSAPR, leaving CAIR in place. Subsequently, in August 2012, the Court vacated and remanded CSAPR back to the EPA for further rulemaking, again leaving CAIR in place, pending further EPA action. PPL Energy Supply plants in Pennsylvania will continue to comply with CAIR through optimization of existing controls, balanced with emission allowance purchases. The Court's August decision leaves plants in CSAPR-affected states potentially exposed to more stringent emission reductions due to regional haze implementation (it was previously determined that CSAPR or CAIR participation satisfies regional haze requirements), and/or petitions to the EPA by downwind states under Section 126 of the Clean Air Act requesting the EPA to require plants that allegedly contribute to downwind non-attainment to take action to reduce emissions.
Regional Haze - Montana
The EPA signed its final Federal Implementation Plan (FIP) of the Regional Haze Rules for Montana in September 2012, with tighter emissions limits for Colstrip Units 1 & 2 based on the installation of new controls (no limits or additional controls were specified for Colstrip Units 3 & 4), and tighter emission limits for Corette (which are not based on additional controls). The cost of the potential additional controls for Colstrip Units 1 & 2, if required, could be significant. PPL Energy Supply expects to meet the tighter permit limits at Corette without any significant changes to operations, although other requirements have led to the planned suspension of operations at Corette beginning in April 2015 (see "MATS" discussion above).
See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for additional information on environmental matters.
Competition
See "Item 1. Business - Segment Information - Supply Segment - Competition" and "Item 1A. Risk Factors" for a discussion of competitive factors affecting PPL Energy Supply.
New Accounting Guidance
See Notes 1 and 24 to the Financial Statements for a discussion of new accounting guidance adopted and pending adoption.
Application of Critical Accounting Policies
Financial condition and results of operations are impacted by the methods, assumptions and estimates used in the application of critical accounting policies. The following accounting policies are particularly important to the financial condition or results of operations, and require estimates or other judgments of matters inherently uncertain. Changes in the estimates or other judgments included within these accounting policies could result in a significant change to the information presented in the Financial Statements (these accounting policies are also discussed in Note 1 to the Financial Statements). Senior management has reviewed these critical accounting policies, the following disclosures regarding their application and the estimates and assumptions regarding them, with PPL's Audit Committee.
Price Risk Management
See "Price Risk Management" in Note 1 to the Financial Statements, as well as "Risk Management - Energy Marketing & Trading and Other" above.
Defined Benefits
PPL Energy Supply subsidiaries sponsor and participate in various qualified funded and non-qualified unfunded defined benefit pension plans. A PPL Energy Supply subsidiary also sponsors an unfunded other postretirement benefit plan. PPL Energy Supply records the liability and net periodic defined benefit costs of its plans and the allocated portion of those plans sponsored by PPL Services based on participation in those plans. PPL Energy Supply subsidiaries record an asset or liability to recognize the funded status of all defined benefit plans with an offsetting entry to OCI. Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets. See Note 13 to the Financial Statements for additional information about the plans and the accounting for defined benefits.
PPL Services and PPL Energy Supply make certain assumptions regarding the valuation of benefit obligations and the performance of plan assets. When accounting for defined benefits, delayed recognition in earnings of differences between actual results and expected or estimated results is a guiding principle. Annual net periodic defined benefit costs are recorded in current earnings based on estimated results. Any differences between actual and estimated results are recorded in OCI. These amounts in AOCI are amortized to income over future periods. The delayed recognition allows for a smoothed recognition of costs over the working lives of the employees who benefit under the plans. The primary assumptions are:
· | Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due.
|
· | Expected Return on Plan Assets - Management projects the long-term rates of return on plan assets based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes. These projected returns reduce the net benefit costs PPL records currently. |
· | Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement. |
· | Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care. |
In selecting a discount rate for their U.S. defined benefit plans, PPL Services and PPL Energy Supply start with a cash flow analysis of the expected benefit payment stream for their plans. The plan-specific cash flows are matched against the coupons and expected maturity values of individually selected bonds. This bond matching process begins with the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, serving as the base from which those with the lowest and highest yields were eliminated to develop an appropriate subset of bonds. Individual bonds were then selected based on the timing of each plan's cash flows and parameters were established as to the percentage of each individual bond issue that could be hypothetically purchased and the surplus reinvestment rates to be assumed. At December 31, 2012, PPL Services decreased the discount rate for its U.S. pension plans from 5.07% to 4.22% and PPL Energy Supply decreased the discount rate for its pension plan from 5.12% to 4.25%. PPL Services decreased the discount rate for its other postretirement benefit plan from 4.81% to 4.02% and PPL Energy Supply decreased the discount rate for its other postretirement benefit plan from 4.60% to 3.77%.
The expected long-term rates of return for PPL Services and PPL Energy Supply's U.S. defined benefit pension and other postretirement benefit plans have been developed using a best-estimate of expected returns, volatilities and correlations for each asset class. PPL management corroborates these rates with expected long-term rates of return calculated by its independent actuary, who uses a building block approach that begins with a risk-free rate of return with factors being added such as inflation, duration, credit spreads and equity risk. Each plan's specific asset allocation is also considered in developing a reasonable return assumption. At December 31, 2012, PPL Services' and PPL Energy Supply's expected return on plan assets remained at 7.00% for their U.S. pension plans and increased from 5.70% to 5.75% for PPL Services' other postretirement benefit plan.
In selecting a rate of compensation increase, PPL Energy Supply considers past experience in light of movements in inflation rates. At December 31, 2012, PPL Services and PPL Energy Supply's rate of compensation increase decreased from 4.00% to 3.95% for their U.S. plans.
In selecting health care cost trend rates, PPL Services and PPL Energy Supply consider past performance and forecasts of health care costs. At December 31, 2012, PPL Services' and PPL Energy Supply's health care cost trend rates were 8.00% for 2013, gradually declining to 5.50% for 2019.
A variance in the assumptions listed above could have a significant impact on accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and OCI. While the charts below reflect either an increase or decrease in each assumption, the inverse of this change would impact the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and OCI by a similar amount in the opposite direction. The sensitivities below reflect an evaluation of the change based solely on a change in that assumption and does not include income tax effects.
At December 31, 2012, the defined benefit plans were recorded as follows.
Pension liabilities | | $ | (295) |
Other postretirement benefit liabilities | | | (77) |
The following chart reflects the sensitivities in the December 31, 2012 Balance Sheet associated with a change in certain assumptions based on PPL Services' and PPL Energy Supply's primary defined benefit plans.
| | | Increase (Decrease) |
| | | Change in | | | Impact on defined | | | |
Actuarial assumption | | | assumption | | | benefit liabilities | | | Impact on OCI |
| | | | | | | | | |
Discount Rate | | | (0.25)% | | $ | 56 | | $ | (56) |
Rate of Compensation Increase | | | 0.25% | | | 9 | | | (9) |
Health Care Cost Trend Rate (a) | | | 1.00% | | | 1 | | | (1) |
(a) | Only impacts other postretirement benefits. |
In 2012, PPL Energy Supply was allocated and recognized net periodic defined benefit costs charged to operating expense of $44 million. This amount represents a $10 million increase from 2011.
The following chart reflects the sensitivities in the 2012 Statement of Income (excluding income tax effects) associated with a change in certain assumptions based on PPL's and PPL Energy Supply's primary defined benefit plans.
Actuarial assumption | | | Change in assumption | | | Impact on defined benefit costs |
| | | | | | |
Discount Rate | | | (0.25)% | | $ | 4 |
Expected Return on Plan Assets | | | (0.25)% | | | 3 |
Rate of Compensation Increase | | | 0.25% | | | 2 |
Asset Impairment (Excluding Investments)
Impairment analyses are performed for long-lived assets that are subject to depreciation or amortization whenever events or changes in circumstances indicate that a long-lived asset's carrying amount may not be recoverable. For these long-lived assets classified as held and used, such events or changes in circumstances are:
· | a significant decrease in the market price of an asset; |
· | a significant adverse change in the manner in which an asset is being used or in its physical condition; |
· | a significant adverse change in legal factors or in the business climate; |
· | an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of an asset; |
· | a current period operating or cash flow loss combined with a history of losses or a forecast that demonstrates continuing losses; or |
· | a current expectation that, more likely than not, an asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. |
For a long-lived asset classified as held and used, an impairment is recognized when the carrying amount of the asset is not recoverable and exceeds its fair value. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset is impaired, an impairment loss is recorded to adjust the asset's carrying amount to its estimated fair value. Management must make significant judgments to estimate future cash flows, including the useful lives of long-lived assets, the fair value of the assets and management's intent to use the assets. Alternate courses of action are considered to recover the carrying amount of a long-lived asset, and estimated cash flows from the "most likely" alternative are used to assess impairment whenever one alternative is clearly the most likely outcome. If no alternative is clearly the most likely, then a probability-weighted approach is used taking into consideration estimated cash flows from the alternatives. For assets tested for impairment as of the balance sheet date, the estimates of future cash flows used in that test consider the likelihood of possible outcomes that existed at the balance sheet date, including the assessment of the likelihood of a future sale of the assets. That assessment is not revised based on events that occur after the balance sheet date. Changes in assumptions and estimates could result in significantly different results than those identified and recorded in the financial statements.
In September 2012, PPL Energy Supply announced its intention, beginning in April 2015, to place the Corette coal-fired plant in Montana in long-term reserve status, suspending the plant's operation, due to expected market conditions and the costs to comply with MATS requirements. The Corette plant asset group's carrying amount at December 31, 2012 was approximately $68 million. An impairment analysis was performed for this asset group in the third and fourth quarters of 2012 and it was determined to not be impaired. It is reasonably possible that an impairment could occur in future periods, as higher priced sales contracts settle, adversely impacting projected cash flows.
For a long-lived asset classified as held for sale, an impairment exists when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell. If the asset (disposal group) is impaired, an impairment loss is recorded to adjust the carrying amount to its fair value less cost to sell. A gain is recognized for any subsequent increase in fair value less cost to sell, but not in excess of the cumulative impairment previously recognized.
For determining fair value, quoted market prices in active markets are the best evidence. However, when market prices are unavailable, the Registrant considers all valuation techniques appropriate under the circumstances and for which market participant inputs can be obtained. Generally discounted cash flows are used to estimate fair value, which incorporates market participant inputs when available. Discounted cash flows are calculated by estimating future cash flow streams and applying appropriate discount rates to determine the present value of the cash flow streams.
Goodwill is tested for impairment at the reporting unit level. PPL Energy Supply's reporting unit has been determined to be at the operating segment level. A goodwill impairment test is performed annually or more frequently if events or changes in circumstances indicate that the carrying amount of the reporting unit may be greater than the unit's fair value. Additionally, goodwill is tested for impairment after a portion of goodwill has been allocated to a business to be disposed of.
Beginning in 2012, PPL Energy Supply may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative evaluation and test goodwill for impairment using a two-step quantitative test. If the qualitative evaluation (referred to as "step zero") is elected and the assessment results in a determination that it is not more likely than not the fair value of the reporting unit is less than the carrying amount, the two-step quantitative impairment test is not necessary. However, the quantitative impairment test is required if PPL Energy Supply concludes it is more likely than not that the fair value of the reporting unit is less than the carrying amount based on the step zero assessment.
When the two-step quantitative impairment test is elected or required as a result of the step zero assessment, in step one, PPL Energy Supply identifies a potential impairment by comparing the estimated fair value of PPL Energy Supply (the goodwill reporting unit) with its carrying amount, including goodwill, on the measurement date. If the estimated fair value exceeds its carrying amount, goodwill is not considered impaired. If the carrying amount exceeds the estimated fair value, the second step is performed to measure the amount of impairment loss, if any.
The second step of the quantitative test requires a calculation of the implied fair value of goodwill, which is determined in the same manner as the amount of goodwill in a business combination. That is, the estimated fair value is allocated to all of PPL Energy Supply's assets and liabilities as if PPL Energy Supply had been acquired in a business combination and the estimated fair value of PPL Energy Supply was the price paid. The excess of the estimated fair value of PPL Energy Supply over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. The implied fair value of PPL Energy Supply's goodwill is then compared with the carrying amount of that goodwill. If the carrying amount exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess. The loss recognized cannot exceed the carrying amount of PPL Energy Supply's goodwill.
PPL Energy Supply elected to perform the two-step quantitative impairment test of goodwill in the fourth quarter of 2012 and no impairment was recognized. Management used both discounted cash flows and market multiples, which required significant assumptions, to estimate the fair value of PPL Energy Supply. Applying an appropriate weighting to both the discounted cash flow and market multiple valuations, a decrease in the forecasted cash flows of 10%, an increase in the discount rate by 25 basis points, or a 10% decrease in the multiples would not have resulted in an impairment of goodwill.
Loss Accruals
Losses are accrued for the estimated impacts of various conditions, situations or circumstances involving uncertain or contingent future outcomes. For loss contingencies, the loss must be accrued if (1) information is available that indicates it is probable that a loss has been incurred, given the likelihood of the uncertain future events, and (2) the amount of the loss can be reasonably estimated. Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." The accrual of contingencies that might result in gains is not recorded unless recovery is assured. Potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events are continuously assessed.
The accounting aspects of estimated loss accruals include (1) the initial identification and recording of the loss, (2) the determination of triggering events for reducing a recorded loss accrual, and (3) the ongoing assessment as to whether a recorded loss accrual is sufficient. All three of these aspects require significant judgment by management. Internal expertise and outside experts (such as lawyers and engineers) are used, as necessary, to help estimate the probability that a loss has been incurred and the amount (or range) of the loss.
No new significant loss accruals were recorded in 2012.
Certain other events have been identified that could give rise to a loss, but that do not meet the conditions for accrual. Such events are disclosed, but not recorded, when it is "reasonably possible" that a loss has been incurred.
When an estimated loss is accrued, the triggering events for subsequently reducing the loss accrual are identified, where applicable. The triggering events generally occur when the contingency has been resolved and the actual loss is paid or written off, or when the risk of loss has diminished or been eliminated. The following are some of the triggering events that provide for the reduction of certain recorded loss accruals:
· | Allowances for uncollectible accounts are reduced when accounts are written off after prescribed collection procedures have been exhausted, a better estimate of the allowance is determined or underlying amounts are ultimately collected. |
· | Environmental and other litigation contingencies are reduced when the contingency is resolved and actual payments are made, a better estimate of the loss is determined or the loss is no longer considered probable. |
Loss accruals are reviewed on a regular basis to assure that the recorded potential loss exposures are appropriate. This involves ongoing communication and analyses with internal and external legal counsel, engineers, operation management and other parties.
See Note 15 to the Financial Statements for disclosure of loss contingencies accrued and other potential loss contingencies that have not met the criteria for accrual.
Asset Retirement Obligations
PPL Energy Supply is required to recognize a liability for legal obligations associated with the retirement of long-lived assets. The initial obligation should be measured at its estimated fair value. A conditional ARO must be recognized when incurred if the fair value of the ARO can be reasonably estimated. An equivalent amount should be recorded as an increase in the value of the capitalized asset and allocated to expense over the useful life of the asset. Until the obligation is settled, the liability is increased, through the recognition of accretion expense in the statement of income, for changes in the obligation due to the passage of time. See Note 21 to the Financial Statements for further discussion of AROs.
In determining AROs, management must make significant judgments and estimates to calculate fair value. Fair value is developed using an expected present value technique based on assumptions of market participants that considers estimated retirement costs in current period dollars that are inflated to the anticipated retirement date and then discounted back to the date the ARO was incurred. Changes in assumptions and estimates included within the calculations of the fair value of AROs could result in significantly different results than those identified and recorded in the financial statements. Estimated ARO costs and settlement dates, which affect the carrying value of the ARO and the related capitalized asset, are reviewed periodically to ensure that any material changes are incorporated into the latest estimate of the ARO. Any change to the capitalized asset, positive or negative, is amortized over the remaining life of the associated long-lived asset.
At December 31, 2012, AROs totaling $375 million were recorded on the Balance Sheet, of which $10 million is included in "Other current liabilities." Of the total amount, $316 million, or 84%, relates to the nuclear decommissioning ARO. The most significant assumptions surrounding AROs are the forecasted retirement costs, the discount rates and the inflation rates. A variance in any of these inputs could have a significant impact on the ARO liabilities.
The following table reflects the sensitivities related to the nuclear decommissioning ARO liability associated with a change in these assumptions as of December 31, 2012. There is no significant change to the annual depreciation expense of the ARO asset or the annual accretion expense of the ARO liability as a result of changing the assumptions. The sensitivities below reflect an evaluation of the change based solely on a change in that assumption.
| | Change in | | Impact on |
| | Assumption | | ARO Liability |
| | | | | | |
Retirement Cost | | | 10% | | $ | 32 |
Discount Rate | | | (0.25)% | | | 28 |
Inflation Rate | | | 0.25% | | | 32 |
Income Taxes
Significant management judgment is required in developing the provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination of deferred tax assets, liabilities and valuation allowances.
Significant management judgment is required to determine the amount of benefit recognized related to an uncertain tax position. Tax positions are evaluated following a two-step process. The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained. This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position. The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion. The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization, upon settlement, that exceeds 50%. Management considers a number of factors in assessing the benefit to be recognized, including negotiation of a settlement.
On a quarterly basis, uncertain tax positions are reassessed by considering information known at the reporting date. Based on management's assessment of new information, a tax benefit may subsequently be recognized for a previously unrecognized tax position, a previously recognized tax position may be derecognized, or the benefit of a previously recognized tax position may be remeasured. The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements in the future.
At December 31, 2012, it was reasonably possible that during the next 12 months the total amount of unrecognized tax benefits could increase by as much as $1 million or decrease by up to $30 million. This change could result from subsequent recognition, derecognition and/or changes in the measurement of uncertain tax positions related to the timing and utilization of tax credits and the related impact on alternative minimum tax, the timing and/or valuation of certain deductions, intercompany transactions and unitary filing groups. The events that could cause these changes are direct settlements with taxing authorities, litigation, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.
The balance sheet classification of unrecognized tax benefits and the need for valuation allowances to reduce deferred tax assets also require significant management judgment. Unrecognized tax benefits are classified as current to the extent management expects to settle an uncertain tax position by payment or receipt of cash within one year of the reporting date. Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset. Management considers a number of factors in assessing the realization of a deferred tax asset, including the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies. Any tax planning strategy utilized in this assessment must meet the recognition and measurement criteria utilized to account for an uncertain tax position. Management also considers the uncertainty posed by political risk and the effect of this uncertainty on the various factors that management takes into account in evaluating the need for valuation allowances. The amount of deferred tax assets ultimately realized may differ materially from the estimates utilized in the computation of valuation allowances and may materially impact the financial statements in the future. See Note 5 to the Financial Statements for income tax disclosures.
Other Information
PPL's Audit Committee has approved the independent auditor to provide audit, audit-related and tax services permitted by Sarbanes-Oxley and SEC rules. The audit and audit-related services include services in connection with statutory and regulatory filings, reviews of offering documents and registration statements, and internal control reviews. See "Item 14. Principal Accounting Fees and Services" for more information.
PPL ELECTRIC UTILITIES CORPORATION AND SUBSIDIARIES
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The information provided in this Item 7 should be read in conjunction with PPL Electric's Consolidated Financial Statements and the accompanying Notes. Capitalized terms and abbreviations are defined in the glossary. Dollars are in millions unless otherwise noted.
"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:
· | "Overview" provides a description of PPL Electric and its business strategy, a summary of Net Income Available to PPL and a discussion of certain events related to PPL Electric's results of operations and financial condition. |
· | "Results of Operations" provides a summary of PPL Electric's earnings and a description of key factors expected to impact future earnings. This section ends with explanations of significant changes in principal items on PPL Electric's Statements of Income, comparing 2012 with 2011 and 2011 with 2010. |
· | "Financial Condition - Liquidity and Capital Resources" provides an analysis of PPL Electric's liquidity position and credit profile. This section also includes a discussion of forecasted sources and uses of cash and rating agency actions. |
· | "Financial Condition - Risk Management" provides an explanation of PPL Electric's risk management programs relating to market and credit risk. |
· | "Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of PPL Electric and that require its management to make significant estimates, assumptions and other judgments of matters inherently uncertain. |
Overview
Introduction
PPL Electric is an electricity transmission and distribution service provider in eastern and central Pennsylvania with headquarters in Allentown, Pennsylvania. PPL Electric is subject to regulation as a public utility by the PUC, and certain of its transmission activities are subject to the jurisdiction of FERC under the Federal Power Act. PPL Electric delivers electricity in its Pennsylvania service area and provides electricity supply to retail customers in that territory as a PLR under the Customer Choice Act.
Business Strategy
PPL Electric's strategy and principal challenge is to own and operate its electricity delivery business at the most efficient cost while maintaining high quality customer service and reliability. PPL Electric anticipates that it will have significant capital expenditure requirements for at least the next five years. In order to manage financing costs and access to credit markets, a key objective for PPL Electric's business is to maintain a strong credit profile and strong liquidity position.
Timely recovery of costs to maintain and enhance the reliability of PPL Electric's delivery system including the replacement of aging distribution assets is required in order to maintain strong cash flows and a strong credit profile. Traditionally, such cost recovery would be pursued through periodic base rate case proceedings with the PUC. As such costs continue to increase, more frequent rate case proceedings may be required or an alternative rate-making process would need to be implemented in order to achieve more timely recovery. See "Regulatory Matters - Pennsylvania Activities - Legislation - Regulatory Procedures and Mechanisms" in Note 6 to the Financial Statements for information on Pennsylvania's new alternative rate-making mechanism.
Transmission costs are recovered through a FERC Formula Rate mechanism which is updated annually for costs incurred and assets placed in service. Accordingly, increased costs including for the replacement of aging transmission assets and the PJM-approved Regional Transmission Line Expansion Plan are recovered on a timely basis.
Financial and Operational Developments
Net Income Available to PPL
Net Income Available to PPL for 2012, 2011 and 2010 was $132 million, $173 million and $115 million. Earnings in 2012 decreased 24% from 2011 and earnings in 2011 increased 50% over 2010.
See "Results of Operations" below for further discussion and analysis of PPL Electric's earnings.
Redemption of Preference Stock
In June 2012, PPL Electric redeemed all 2.5 million shares of its 6.25% Series Preference Stock, par value $100 per share. The price paid for the redemption was the par value, without premium ($250 million in the aggregate). At December 31, 2011, the preference stock was reflected on PPL Electric's Balance Sheet in "Preferred securities."
Storm Costs
During 2012, PPL Electric experienced several PUC-reportable storms, including Hurricane Sandy, resulting in total restoration costs of $81 million, of which $61 million were initially recorded in "Other operation and maintenance" on the Statement of Income. In particular, in late October 2012, PPL Electric experienced widespread significant damage to its distribution network from Hurricane Sandy resulting in total restoration costs of $66 million, of which $50 million were initially recorded in "Other operation and maintenance" on the Statement of Income. Although PPL Electric had storm insurance coverage, the costs incurred from Hurricane Sandy exceeded the policy limits. Probable insurance recoveries recorded during 2012 were $18.25 million, of which $14 million were included in "Other operation and maintenance" on the Statements of Income. PPL Electric recorded a regulatory asset of $28 million in December 2012 (offset to "Other operation and maintenance" on the Statement of Income). In February 2013, PPL Electric received an order from the PUC granting permission to defer qualifying storm costs in excess of insurance recoveries associated with Hurricane Sandy.
See "Regulatory Matters - Pennsylvania Activities - Storm Costs" in Note 6 to the Financial Statements for information on $84 million of storm costs incurred in 2011.
Rate Case Proceeding
In March 2012, PPL Electric filed a request with the PUC to increase distribution rates by approximately $105 million, effective January 1, 2013. In its December 28, 2012 final order, the PUC approved a 10.4% return on equity and a total distribution revenue increase of about $71 million. The approved rates became effective January 1, 2013.
Also, in its December 28, 2012 final order, the PUC directed PPL Electric to file a proposed Storm Damage Expense Rider within 90 days following the order. PPL Electric plans to file a proposed Storm Damage Expense Rider with the PUC and, as part of that filing, request recovery of the $28 million of qualifying storm costs incurred as a result of the October 2012 landfall of Hurricane Sandy.
Regional Transmission Line Expansion Plan
Susquehanna-Roseland
In 2007, PJM directed the construction of a new 150-mile, 500-kilovolt transmission line between the Susquehanna substation in Pennsylvania and the Roseland substation in New Jersey that it identified as essential to long-term reliability of the Mid-Atlantic electricity grid. PJM determined that the line was needed to prevent potential overloads that could occur on several existing transmission lines in the interconnected PJM system. PJM directed PPL Electric to construct the portion of the Susquehanna-Roseland line in Pennsylvania and Public Service Electric & Gas Company to construct the portion of the line in New Jersey.
On October 1, 2012, the National Park Service (NPS) issued its Record of Decision (ROD) on the proposed Susquehanna-Roseland transmission line affirming the route chosen by PPL Electric and Public Service Electric & Gas Company as the preferred alternative under the NPS's National Environmental Policy Act review. On October 15, 2012, a complaint was filed in the United States District Court for the District of Columbia by various environmental groups, including the Sierra Club, challenging the ROD and seeking to prohibit its implementation; and on December 6, 2012, the groups filed a petition for injunctive relief seeking to prohibit all construction activities until the court issues a final decision on the complaint. PPL Electric has intervened in the lawsuit. The chosen route had previously been approved by the PUC and New Jersey Board of Public Utilities.
On December 13, 2012, PPL Electric received federal construction and right of way permits to build on National Park Service lands.
Construction activities have begun on portions of the 101-mile route in Pennsylvania. The line is expected to be in service before the peak summer demand period of 2015. At December 31, 2012, PPL Electric's estimated share of the project cost was $560 million.
PPL and PPL Electric cannot predict the ultimate outcome or timing of any legal challenges to the project or what additional actions, if any, PJM might take in the event of a further delay to its scheduled in-service date for the new line.
Northeast/Pocono
In October 2012, the FERC issued an order in response to PPL Electric's December 2011 request for ratemaking incentives for the Northeast/Pocono Reliability project (a new 58-mile 230 kV transmission line, three new substations and upgrades to adjacent facilities). The incentives were specifically tailored to address the risks and challenges PPL Electric will face in building the project. The FERC granted the incentive for inclusion of all prudently incurred construction work in progress (CWIP) costs in rate base and denied the request for a 100 basis point adder to the return on equity incentive. The order required a follow-up compliance filing from PPL Electric to ensure proper accounting treatment of AFUDC and CWIP for the project, which PPL Electric will submit to the FERC in March 2013. PPL Electric expects the project to be completed in 2017. At December 31, 2012, PPL Electric estimates the total project costs to be approximately $200 million with approximately $190 million qualifying for the CWIP incentive.
Legislation - Regulatory Procedures and Mechanisms
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 DSIC. Such alternative ratemaking procedures and mechanisms provide opportunity for accelerated cost-recovery and, therefore, are important to PPL Electric as it begins a period of significant capital investment to maintain and enhance the reliability of its delivery system, including the replacement of aging distribution assets. In August 2012, the PUC issued a final implementation order adopting procedures, guidelines and a model tariff for the implementation of Act 11. Act 11 requires utilities to file an LTIIP as a prerequisite to filing for recovery through the DISC. The LTIIP is mandated to be a five- to ten-year plan describing projects eligible for inclusion in the DISC. In September 2012, PPL Electric filed its LTIIP describing projects eligible for inclusion in the DSIC. The PUC approved the LTIIP on January 10, 2013 and PPL Electric filed a petition requesting permission to establish a DSIC on January 15, 2013, with rates proposed to be effective beginning May 1, 2013.
FERC Formula Rates
In March 2012, PPL Electric filed a request with the FERC seeking recovery of its regulatory asset related to the deferred state tax liability that existed at the time of the transition from the flow-through treatment of state income taxes to full normalization. This change in tax treatment occurred in 2008 as a result of prior FERC initiatives that transferred regulatory jurisdiction of certain transmission assets from the PUC to FERC. At December 31, 2012 and December 31, 2011, $52 million and $53 million respectively, are classified as taxes recoverable through future rates and are included on the Balance Sheets in "Other Noncurrent Assets - Regulatory assets." In May 2012, the FERC issued an order approving PPL Electric's request recover the deferred tax regulatory asset over a 34 year period beginning June 1, 2012.
Results of Operations
The following discussion provides a summary of PPL Electric's earnings and a description of factors that are expected to impact future earnings. This section ends with "Statement of Income Analysis," which includes explanations of significant year-to-year changes in Pennsylvania Gross Delivery Margins by component and principal line items on PPL Electric's Statements of Income.
The utility business is influenced by seasonality in the weather. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year. Revenue is generally higher during the first and third quarters of a year due to higher demand as a result of winter and summer periods. On the other hand, revenue tends to be lower during the second and fourth quarters due to lower demand as a result of milder weather.
Earnings | | | | | | | | | |
| | | | | | | | | | |
Net Income Available to PPL was: |
| | | | | | | | | | |
| | | 2012 | | 2011 | | 2010 |
| | | | | | | | | | |
Net Income Available to PPL | | $ | 132 | | $ | 173 | | $ | 115 |
The changes in the components of Net Income Available to PPL between these periods were due to the following factors which reflect reclassifications for items included in gross delivery margins.
| | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | |
Pennsylvania Gross Delivery Margins | | $ | 19 | | $ | 66 |
Other operation and maintenance | | | (50) | | | 4 |
Depreciation | | | (14) | | | (10) |
Taxes, other than income | | | (9) | | | 4 |
Other | | | 1 | | | 1 |
Income Taxes | | | | | | (11) |
Distributions on Preferred Securities | | | 12 | | | 4 |
Total | | $ | (41) | | $ | 58 |
· | See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Pennsylvania Gross Delivery Margins. |
· | Higher other operation and maintenance for 2012 compared with 2011, primarily due to $17 million in higher payroll-related costs due to less project costs being capitalized in 2012, higher support group costs of $11 million and $10 million for increased vegetation management. |
· | Higher depreciation for 2012 compared with 2011 and 2011 compared with 2010 primarily due to PP&E additions. |
· | Higher taxes, other than income for 2012 primarily due to a $10 million tax provision related to gross receipts tax. |
· | Income taxes were flat in 2012 compared with 2011 primarily due to the $22 million impact of lower 2012 pre-tax income primarily offset by $9 million of depreciation not normalized and $9 million of income tax return adjustments, largely related to changes in flow-through regulated tax depreciation. |
| Income taxes were higher in 2011 compared with 2010, due to the $26 million impact of higher 2011 pre-tax income, partially offset by a $14 million tax benefit related to changes in flow-through regulated tax depreciation. |
· | Lower distributions on preferred securities in 2012 compared to 2011 due to the preference stock redemption in June 2012. |
2013 Outlook
PPL Electric projects higher earnings in 2013 compared with 2012, due to higher distribution revenues from a distribution base rate increase effective January 1, 2013, and higher transmission margins, partially offset by higher depreciation.
Earnings in future periods are subject to various risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Notes 6 and 15 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.
Statement of Income Analysis --
Pennsylvania Gross Delivery Margins
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as a non-GAAP financial measure, "Pennsylvania Gross Delivery Margins." "Pennsylvania Gross Delivery Margins" is a single financial performance measure of PPL Electric's Pennsylvania regulated electric delivery operations, which includes transmission and distribution activities. In calculating this measure, utility revenues and expenses associated with approved recovery mechanisms, including energy provided as a PLR, are offset with minimal impact on earnings. Costs associated with these mechanisms are recorded in "Energy purchases," "Energy purchases from affiliate," "Other operation and maintenance," which is primarily Act 129 costs, and "Taxes, other than income" which is primarily gross receipts tax. As a result, this measure represents the net revenues from PPL Electric's Pennsylvania regulated electric delivery operations. This measure is not intended to replace "Operating Income," which is determined in accordance with GAAP, as an indicator of overall operating performance. Other companies may use different measures to analyze and to report on the results of their operations. PPL Electric believes that "Pennsylvania Gross Delivery Margins" provides another criterion to make investment decisions. This performance measure is used, in conjunction with other information, internally by senior management to manage PPL Electric's operations and analyze actual results to budget.
Reconciliation of Non-GAAP Financial Measures |
The following tables reconcile "Operating Income" to "Pennsylvania Gross Delivery Margins" as defined by PPL Electric for the period ended December 31.
| | | | | | 2012 | | 2011 |
| | | | | | PA Gross | | | | | | | | PA Gross | | | | | | |
| | | | | | Delivery | | | | | Operating | | Delivery | | | | | | Operating |
| | | | | | Margins | | Other (a) | | Income (b) | | Margins | | Other (a) | | Income (b) |
| | | | | | | | | | | | | | | | | | |
Operating Revenues | | | | | | | | | | | | | | | | | | | | |
| Retail electric | | $ | 1,760 | | | | | | $ | 1,760 | | $ | 1,881 | | | | | | $ | 1,881 |
| Electric revenue from affiliate | | | 3 | | | | | | | 3 | | | 11 | | | | | | | 11 |
| | | Total Operating Revenues | | | 1,763 | | | | | | | 1,763 | | | 1,892 | | | | | | | 1,892 |
| | | | | | | | | | | | | | | | | | | | | | | | |
Operating Expenses | | | | | | | | | | | | | | | | | | | | |
| Energy purchases | | | 550 | | | | | | | 550 | | | 738 | | | | | | | 738 |
| Energy purchases from affiliate | | | 78 | | | | | | | 78 | | | 26 | | | | | | | 26 |
| Other operation and | | | | | | | | | | | | | | | | | | | | |
| | maintenance | | | 104 | | $ | 472 | | | | 576 | | | 108 | | $ | 422 | | | | 530 |
| Depreciation | | | | | | 160 | | | | 160 | | | | | | 146 | | | | 146 |
| Taxes, other than income | | | 91 | | | 14 | | | | 105 | | | 99 | | | 5 | | | | 104 |
| | | Total Operating Expenses | | | 823 | | | 646 | | | | 1,469 | | | 971 | | | 573 | | | | 1,544 |
Total | | $ | 940 | | $ | (646) | | | $ | 294 | | $ | 921 | | $ | (573) | | | $ | 348 |
| | | | | | 2010 | | |
| | | | | | PA Gross | | | | | | | | | | | | | | |
| | | | | | Delivery | | | | | Operating | | | | | | | | |
| | | | | | Margins | | Other (a) | | Income (b) | | | | | | |
| | | | | | | | | | | | | | | | | | |
Operating Revenues | | | | | | | | | | | | | | | | | | | | |
| Retail electric | | $ | 2,448 | | | | | | $ | 2,448 | | | | | | | | | | |
| Electric revenue from affiliate | | | 7 | | | | | | | 7 | | | | | | | | | | |
| | | Total Operating Revenues | | | 2,455 | | | | | | | 2,455 | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Operating Expenses | | | | | | | | | | | | | | | | | | | | |
| Energy purchases | | | 1,075 | | | | | | | 1,075 | | | | | | | | | | |
| Energy purchases from affiliate | | | 320 | | | | | | | 320 | | | | | | | | | | |
| Other operation and | | | | | | | | | | | | | | | | | | | | |
| | maintenance | | | 76 | | $ | 426 | | | | 502 | | | | | | | | | | |
| Amortization of recoverable | | | | | | | | | | | | | | | | | | | | |
| Depreciation | | | | | | 136 | | | | 136 | | | | | | | | | | |
| Taxes, other than income | | | 129 | | | 9 | | | | 138 | | | | | | | | | | |
| | | Total Operating Expenses | | | 1,600 | | | 571 | | | | 2,171 | | | | | | | | | | |
Total | | $ | 855 | | $ | (571) | | | $ | 284 | | | | | | | | | | |
| (a) | Represents amounts excluded from Margins. |
| (b) | As reported on the Statements of Income. |
Changes in Non-GAAP Financial Measures
The following table shows PPL Electric's non-GAAP financial measure, "Pennsylvania Gross Delivery Margins" for the periods ended December 31, as well as the change between periods. The factors that gave rise to the change are described below the table.
| | | 2012 | | 2011 | | Change | | 2011 | | 2010 | | Change |
| | | | | | | | | | | | | | | | | | | |
PA Gross Delivery Margins by Component | | | | | | | | | | | | | | | | | | |
| Distribution | | $ | 730 | | $ | 741 | | $ | (11) | | $ | 741 | | $ | 679 | | $ | 62 |
| Transmission | | | 210 | | | 180 | | | 30 | | | 180 | | | 176 | | | 4 |
| Total | | $ | 940 | | $ | 921 | | $ | 19 | | $ | 921 | | $ | 855 | | $ | 66 |
Distribution
Margins decreased in 2012 compared with 2011, primarily due to a $14 million unfavorable effect of mild weather early in 2012 and lower revenue applicable to certain energy-related costs of $3 million due to fewer PLR customers in 2012, partially offset by a $7 million charge recorded in 2011 to reduce a portion of the transmission service charge regulatory asset associated with a 2005 undercollection that was not included in any subsequent rate reconciliations filed with the PUC.
Margins increased in 2011 compared with 2010, largely due to the PPL Electric distribution rate case which increased rates by approximately 1.6% effective January 1, 2011, resulting in improved residential distribution margins of $68 million. Additionally, residential volume variances increased margins by an additional $4 million in 2011, compared with 2010, offset by unfavorable weather of $3 million for residential customers in 2011 compared with 2010. Lastly, lower demand charges and increased efficiency as a result of Act 129 programs resulted in a $5 million decrease in margins for commercial and industrial customers.
Transmission
Margins increased in 2012 compared with 2011, primarily due to increased investment in plant and the recovery of additional costs through the FERC formula-based rates.
Other Operation and Maintenance
The increase (decrease) in other operation and maintenance was due to:
| | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | |
Act 129 costs incurred (a) | | $ | (6) | | $ | 26 |
Vegetation management (b) | | | 10 | | | (8) |
Payroll-related costs (c) | | | 17 | | | 4 |
Allocation of certain corporate support group costs | | | 11 | | | 3 |
PUC-reportable storm costs, net of insurance recovery | | | 7 | | | |
Uncollectible accounts | | | 1 | | | 7 |
Other | | | 6 | | | (4) |
Total | | $ | 46 | | $ | 28 |
(a) | Relates to costs associated with PPL Electric's PUC-approved energy efficiency and conservation plan. These costs are recovered in customer rates. There were initially 15 Act 129 programs which began in 2010 and continued to ramp up in 2011. Some of the energy efficiency programs were reduced or closed in 2012 resulting in lower operation and maintenance expense. |
(b) | PPL Electric incurred more expense in 2010 and 2012 compared to 2011 due to increased vegetation management activities related to transmission lines to comply with federal reliability requirements as well as increased vegetation management for the distribution system in 2012 in an effort to maintain and increase system reliability. |
(c) | Higher payroll costs of $17 million in 2012 compared to 2011 due to less project costs being capitalized. |
Taxes, Other Than Income
Taxes, other than income increased by $1 million in 2012 compared with 2011. The increase was primarily a result of the net effect of the fully amortized PURTA refund to customers of $10 million in 2011, partially offset by a decrease in gross receipts tax of $7 million in 2012.
Taxes, other than income decreased by $34 million in 2011 compared with 2010. This decrease was primarily due to $21 million of lower Pennsylvania gross receipts tax expense on lower retail electricity revenue as customers continue to select alternative suppliers in 2011. The decrease was also impacted by the amortization of a PURTA refund of $10 million in 2011. Pennsylvania gross receipts tax and the PURTA refund are included in "Pennsylvania Gross Delivery Margins."
Depreciation
Depreciation increased by $14 million in 2012 compared with 2011 and by $10 million in 2011 compared with 2010, primarily due to PP&E additions as part of ongoing investments to replace aging infrastructure.
Financing Costs
The increase (decrease) in financing costs, which includes "Interest Expense", "Interest Expense with Affiliate" and "Distributions on Preferred Securities," was due to:
| | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | |
Long-term debt interest expense | | $ | 1 | | $ | (3) |
Distributions on preferred securities (a) | | | (12) | | | (4) |
Amortization of debt issuance costs (b) | | | 1 | | | 5 |
Other | | | (1) | | | (3) |
Total | | $ | (11) | | $ | (5) |
(a) | Decreases for both periods are due to the redemption of preference stock in 2012 and preferred stock in 2010. |
(b) | The increase in 2011 compared with 2010 was primarily due to amortization of loss on reacquired debt associated with the redemption of senior secured bonds in 2011. |
Income Taxes
The increase (decrease) in income taxes was due to:
| | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | |
Higher (lower) pre-tax book income | | $ | (22) | | $ | 26 |
Federal and state tax reserve adjustments (a) | | | 1 | | | 3 |
Federal and state tax return adjustments (b) | | | 11 | | | (3) |
Depreciation not normalized (c) | | | 9 | | | (14) |
Other | | | 1 | | | (1) |
Total | | $ | | | $ | 11 |
(a) | In July 2010, the U.S. Tax Court ruled in PPL Electric's favor in a dispute with the IRS, concluding that street lighting assets are depreciable for tax purposes over seven years. As a result, PPL Electric recorded a $7 million tax benefit to federal and state income tax reserves and related deferred income taxes during 2010. |
(b) | PPL Electric changed its method of accounting for repair expenditures for tax purposes effective for its 2008 tax year. In August, 2011, the IRS issued guidance regarding the use and evaluation of statistical samples and sampling estimates for network assets. The IRS guidance provided a safe harbor method of determining whether the repair expenditures for electric transmission and distribution property can be currently deducted for tax purposes. PPL Electric adopted the safe harbor method with the filing of its 2011 federal income tax return and recorded a $5 million adjustment to federal and state income tax expense resulting from the reversal of prior years' state income tax benefits related to regulated depreciation. |
During 2011, PPL Electric recorded a $5 million federal and state income tax benefit as a result of filing its 2010 federal and state income tax returns. The tax benefit primarily related to the flow-through impact of Pennsylvania regulated 100% bonus tax depreciation.
(c) | During 2011, the Pennsylvania Department of Revenue issued interpretive guidance on the treatment of bonus depreciation for Pennsylvania income tax purposes. The guidance allows 100% bonus depreciation for qualifying assets in the same year bonus depreciation is allowed for federal income tax purposes. The 100% Pennsylvania bonus depreciation deduction created a current state income tax benefit for the flow-through impact of Pennsylvania regulated state tax depreciation. The federal provision for 100% bonus depreciation generally applies to property placed in service before January 1, 2012. The placed in-service deadline is extended to January 1, 2013 for property that has a cost in excess of $1 million, has a production period longer that one year and has a tax life of at least ten years. The PPL Electric's tax deduction for 100% bonus depreciation was significantly lower in 2012 than in 2011. |
See Note 5 to the Financial Statements for additional information on income taxes.
Financial Condition
Liquidity and Capital Resources
PPL Electric continues to focus on maintaining a strong credit profile and liquidity position. PPL Electric expects to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents, credit facilities and commercial paper issuances. Additionally, subject to market conditions, PPL Electric currently plans to issue long-term debt in 2013.
PPL Electric's cash flows from operations and access to cost-effective bank and capital markets are subject to risks and uncertainties including, but not limited to:
· | unusual or extreme weather that may damage PPL Electric's transmission and distribution facilities or affect energy sales to customers; |
· | the ability to recover and the timeliness and adequacy of recovery of costs associated with regulated utility businesses; |
· | any adverse outcome of legal proceedings and investigations with respect to PPL Electric's current and past business activities; |
· | deterioration in the financial markets that could make obtaining new sources of bank and capital markets funding more difficult and more costly; and |
· | a downgrade in PPL Electric's credit ratings that could adversely affect its ability to access capital and increase the cost of credit facilities and any new debt. |
See "Item 1A. Risk Factors" for further discussion of risks and uncertainties that could affect PPL Electric's cash flows.
At December 31, PPL Electric had the following:
| | 2012 | | 2011 | | 2010 |
| | | | | | | | | |
Cash and cash equivalents | | $ | 140 | | $ | 320 | | $ | 204 |
The changes in PPL Electric's cash and cash equivalents position resulted from:
| | 2012 | | 2011 | | 2010 |
| | | | | | | | | |
Net cash provided by (used in) operating activities | | $ | 389 | | $ | 420 | | $ | 212 |
Net cash provided by (used in) investing activities | | | (613) | | | (477) | | | (403) |
Net cash provided by (used in) financing activities | | | 44 | | | 173 | | | (90) |
Net Increase (Decrease) in Cash and Cash Equivalents | | $ | (180) | | $ | 116 | | $ | (281) |
Operating Activities
Net cash provided by operating activities decreased by 7%, or $31 million, in 2012 compared with 2011, primarily due to changes in working capital of $82 million partially offset by a decrease in defined benefit plan contributions of $54 million. Changes in working capital included $108 million from regulatory assets and liabilities, net and $56 million from prepayments, partially offset by $95 million from accounts payable.
Net cash provided by operating activities increased by 98%, or $208 million, in 2011 compared with 2010, primarily due to changes in working capital of $322 million (including lower gross receipts tax payments, a federal income tax refund and changes in over/under collections of the generation supply and transmission service charges). These changes were partially offset by an increase in defined benefit plan contributions of $58 million and $25 million related to storm costs incurred in 2011 and recorded as a long-term regulatory asset.
Investing Activities
The primary use of cash in investing activities is capital expenditures. See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 2013 through 2017.
Net cash used in investing activities was $613 million in 2012 compared with $477 million in 2011. The change from 2011 to 2012 primarily reflects an increase of $143 million in capital expenditures in 2012.
Net cash used in investing activities was $477 million in 2011 compared with $403 million in 2010. The change from 2010 to 2011 primarily reflects an increase of $80 million in capital expenditures in 2011.
Financing Activities
Net cash provided by financing activities was $44 million in 2012 compared with $173 million in 2011. The change from 2011 to 2012 primarily reflects the $250 million preference stock redemption in 2012, offset by a $62 million increase in net debt issuances and a $50 million increase in contributions from PPL.
Net cash provided by financing activities was $173 million in 2011 compared with net cash used in financing activities of $90 million in 2010. The change from 2010 to 2011 primarily reflects $187 million of net debt issuances in 2011 and $54 million of preferred stock redemptions in 2010.
PPL Electric's debt and equity financing activity in 2012 was:
| | | | Issuance | | | Retirements |
| | | | | | | |
Preference Stock | | | | | $ | (250) |
First Mortgage Bonds, net of a discount or underwriting fees | | $ | 249 | | | |
| Total | | $ | 249 | | $ | (250) |
Net decrease | | | | | $ | (1) |
See Note 7 to the Financial Statements for more detailed information regarding PPL Electric's financing activities in 2012.
Forecasted Sources of Cash
PPL Electric expects to continue to have sufficient sources of liquidity available in the near term, including cash flows from operations, credit facilities, commercial paper issuances and the issuance of long-term debt.
Credit Facilities
At December 31, 2012, PPL Electric's total committed borrowing capacity under its credit facilities and the use of this borrowing capacity were:
| | | | | | | | | Letters of | | | |
| | | | | | | | | Credit Issued | | | |
| | | | | | | and | | |
| | | Committed | | | | Commercial | | Unused |
| | | Capacity | | Borrowed | | Paper Backstop | | Capacity |
| | | | | | | | | |
Syndicated Credit Facility (a) | | $ | 300 | | | | | $ | 1 | | $ | 299 |
Asset-backed Credit Facility (b) | | | 100 | | | | | | n/a | | | 100 |
Total PPL Electric Credit Facilities | | $ | 400 | | | | | $ | 1 | | $ | 399 |
(a) | PPL Electric's Syndicated Credit Facility contains a financial covenant requiring PPL Electric's debt to total capitalization not to exceed 70%, as calculated in accordance with the credit facility, and other customary covenants. |
The commitments under this credit facility are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than 5% of the total committed capacity.
(b) | PPL Electric obtains financing by selling and contributing its eligible accounts receivable and unbilled revenue to a special purpose, wholly owned subsidiary on an ongoing basis. The subsidiary pledges these assets to secure loans of up to an aggregate of $100 million from a commercial paper conduit sponsored by a financial institution. At December 31, 2012, based on accounts receivable and unbilled revenue pledged, the amount available for borrowing under this facility was $100 million. |
In addition to the financial covenants noted above, the credit agreements governing the credit facilities contain financial and various other covenants. Failure to comply with the covenants after applicable grace periods could result in acceleration of repayment of borrowings and/or termination of the agreements. PPL Electric monitors compliance with the covenants on a regular basis. At December 31, 2012, PPL Electric was in compliance with these covenants. At this time, PPL Electric believes that these covenants and other borrowing conditions will not limit access to these funding sources.
See Note 7 to the Financial Statements for further discussion of PPL Electric's credit facilities.
Commercial Paper
PPL Electric maintains a $300 million commercial paper program to provide an additional financing source to fund its short-term liquidity needs, if and when necessary. Commercial paper issuances are currently supported by PPL Electric's Syndicated Credit Facility. PPL Electric had no commercial paper outstanding at December 31, 2012.
Contributions from PPL
From time to time PPL may make capital contributions to PPL Electric. PPL Electric may use these contributions for general corporate purposes.
Long-term Debt Securities
PPL Electric currently plans to incur, subject to market conditions, up to $400 million of long-term indebtedness in 2013, the proceeds of which will be used to fund capital expenditures and for other general corporate purposes.
The Economic Stimulus Package
In April 2010, PPL Electric entered into an agreement with the DOE, in which the agency is to provide funding for one-half of a $38 million smart grid project. The project included the deployment of smart grid technology to strengthen reliability, save energy and improve electric service for 60,000 Harrisburg, Pennsylvania area customers. It also provides benefits beyond the Harrisburg region, helping to speed power restoration across PPL Electric's 29-county service territory. Work on the grant project is complete as of December 31, 2012.
Forecasted Uses of Cash
In addition to expenditures required for normal operating activities, such as purchased power, payroll, and taxes, PPL Electric currently expects to incur future cash outflows for capital expenditures, various contractual obligations, payment of dividends on its common stock and possibly the purchase or redemption of a portion of its debt securities.
Capital Expenditures
The table below shows PPL Electric's current capital expenditure projections for the years 2013 through 2017.
| | | | Projected |
| | | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
Construction expenditures (a) (b) | | | | | | | | | | | | | | | |
| Distribution facilities | | $ | 352 | | $ | 321 | | $ | 309 | | $ | 294 | | $ | 297 |
| Transmission facilities | | | 616 | | | 532 | | | 399 | | | 357 | | | 313 |
| Total Capital Expenditures | | $ | 968 | | $ | 853 | | $ | 708 | | $ | 651 | | $ | 610 |
(a) | Construction expenditures include AFUDC, which is expected to total approximately $54 million for the years 2013 through 2017. |
(b) | Includes expenditures for intangible assets. |
PPL Electric's capital expenditure projections for the years 2013 through 2017 total approximately $3.8 billion. Capital expenditure plans are revised periodically to reflect changes in operational, market and regulatory conditions. The table includes projected costs for the asset optimization program focused on the replacement of aging transmission and distribution assets, and the PJM-approved regional transmission line expansion project. See Note 8 to the Financial Statements for additional information.
PPL Electric plans to fund its capital expenditures in 2013 with cash from operations, equity contributions from PPL, and proceeds from the issuance of debt securities.
Contractual Obligations
PPL Electric has assumed various financial obligations and commitments in the ordinary course of conducting its business. At December 31, 2012, the estimated contractual cash obligations of PPL Electric were:
| | | | Total | | 2013 | | 2014 - 2015 | | 2016 - 2017 | | After 2017 |
| | | | | | | | | | | | | | | | | |
Long-term Debt (a) | | $ | 1,974 | | | | | $ | 110 | | | | | $ | 1,864 |
Interest on Long-term Debt (b) | | | 1,711 | | $ | 91 | | | 181 | | $ | 171 | | | 1,268 |
Purchase Obligations (c) | | | 357 | | | 111 | | | 103 | | | 53 | | | 90 |
Other Long-term Liabilities | | | | | | | | | | | | | | | |
| Reflected on the Balance | | | | | | | | | | | | | | | |
| Sheet under GAAP (d) (e) | | | 88 | | | 88 | | | | | | | | | |
Total Contractual Cash Obligations | | $ | 4,130 | | $ | 290 | | $ | 394 | | $ | 224 | | $ | 3,222 |
(a) | Reflects principal maturities only based on stated maturity dates. PPL Electric does not have any capital or operating lease obligations. |
(b) | Assumes interest payments through stated maturity. |
(c) | The amounts include agreements to purchase goods or services that are enforceable and legally binding and specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. Primarily includes PPL Electric's purchase obligations of electricity. Open purchase orders that are provided on demand with no firm commitment are excluded from the amounts presented. |
(d) | The amounts represent contributions made or committed to be made for 2013 for PPL's U.S. pension plans. See Note 13 to the Financial Statements for a discussion of expected contributions. |
(e) | At December 31, 2012, total unrecognized tax benefits of $26 million were excluded from this table as PPL Electric cannot reasonably estimate the amount and period of future payments. See Note 5 to the Financial Statements for additional information. |
Dividends
From time to time, as determined by its Board of Directors, PPL Electric pays dividends on its common stock to its parent, PPL.
Purchase or Redemption of Debt Securities
PPL Electric will continue to evaluate its outstanding debt securities and may decide to purchase or redeem these securities depending upon prevailing market conditions and available cash.
Rating Agency Actions
Moody's, S&P and Fitch periodically review the credit ratings on the debt securities of PPL Electric. Based on their respective independent reviews, the rating agencies may make certain ratings revisions or ratings affirmations.
A credit rating reflects an assessment by the rating agency of the creditworthiness associated with an issuer and particular securities that it issues. The credit ratings of PPL Electric are based on information provided by PPL Electric and other sources. The ratings of Moody's, S&P and Fitch are not a recommendation to buy, sell or hold any securities of PPL Electric. Such ratings may be subject to revisions or withdrawal by the agencies at any time and should be evaluated independently of each other and any other rating that may be assigned to the securities. PPL Electric's credit ratings affect its liquidity, access to capital markets and cost of borrowing under its credit facilities.
The following table sets forth PPL Electric's security credit ratings as of December 31, 2012.
| | Senior Secured | | Commercial Paper |
| | | | | | | | | | | | |
Issuer | | Moody's | | S&P | | Fitch | | Moody's | | S&P | | Fitch |
| | | | | | | | | | | | |
PPL Electric | | A3 | | A- | | A- | | P-2 | | A-2 | | F-2 |
A downgrade in PPL Electric's credit ratings could result in higher borrowing costs and reduced access to capital markets. PPL Electric does not have credit rating triggers that would result in the reduction of access to capital markets or the acceleration of maturity dates of outstanding debt.
In addition to the credit ratings noted above, the rating agencies took the following actions related to PPL Electric in 2012.
In August 2012, Fitch assigned a rating and outlook to PPL Electric's $250 million First Mortgage Bonds.
In August 2012, S&P and Moody's assigned a rating to PPL Electric's $250 million First Mortgage Bonds.
In December 2012, Fitch affirmed the issuer default rating, individual security rating and the outlook for PPL Electric.
Off-Balance Sheet Arrangements
PPL Electric has entered into certain agreements that may contingently require payment to a guaranteed or indemnified party. See Note 15 to the Financial Statements for a discussion of these agreements.
Risk Management
Market Risk
Commodity Price and Volumetric Risk - PLR Contracts
PPL Electric is exposed to market price and volumetric risks from its obligation as PLR. The PUC has approved a cost recovery mechanism that allows PPL Electric to pass through to customers the cost associated with fulfilling its PLR obligation. This cost recovery mechanism substantially eliminates PPL Electric's exposure to market price risk. PPL Electric also mitigates its exposure to volumetric risk by entering into full-requirement energy supply contracts for the majority of its PLR obligations. These supply contracts transfer the volumetric risk associated with the PLR obligation to the energy suppliers.
Interest Rate Risk
PPL Electric issues debt to finance its operations, which exposes it to interest rate risk. At December 31, 2012 and 2011, PPL Electric had no potential annual exposure to increased interest expense, based on its current debt portfolio. PPL Electric is also exposed to changes in the fair value of its debt portfolio. PPL Electric estimated that a 10% decrease in interest rates at December 31, 2012 would increase the fair value of its debt portfolio by $93 million, compared with $94 million at December 31, 2011.
Credit Risk
Credit risk is the risk that PPL Electric would incur a loss as a result of nonperformance by counterparties of their contractual obligations. PPL Electric requires that counterparties maintain specified credit ratings and requires other assurances in the form of credit support or collateral in certain circumstances in order to limit counterparty credit risk. However, PPL Electric has concentrations of suppliers, financial institutions and customers. These concentrations may impact PPL Electric's overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions.
In 2009, the PUC approved PPL Electric's PLR procurement plan for the period January 2011 through May 2013. To date, PPL Electric has conducted all of its planned competitive solicitations.
Under the standard Supply Master Agreement (the Agreement) for the competitive solicitation process, PPL Electric requires all suppliers to post collateral if their credit exposure exceeds an established credit limit. In the event a supplier defaults on its obligation, PPL Electric would be required to seek replacement power in the market. All incremental costs incurred by PPL Electric would be recoverable from customers in future rates. At December 31, 2012, most of the successful bidders under all of the solicitations had an investment grade credit rating from S&P, and were not required to post collateral under the Agreement. A small portion of bidders were required to post collateral, which totaled less than $1 million, under the Agreement. There is no instance under the Agreement in which PPL Electric is required to post collateral to its suppliers.
See Notes 15, 16, 18 and 19 to the Financial Statements for additional information on the competitive solicitations, the Agreement, credit concentration and credit risk.
Related Party Transactions
PPL Electric is not aware of any material ownership interests or operating responsibility by senior management of PPL Electric in outside partnerships, including leasing transactions with variable interest entities, or other entities doing business with PPL Electric. See Note 16 to the Financial Statements for additional information on related party transactions.
Environmental Matters
Physical effects associated with climate change could include the impact of changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to PPL Electric's electricity transmission and distribution systems, as well as impacts on customers. PPL Electric cannot currently predict whether its businesses will experience these potential climate change-related risks or estimate the potential cost of their related consequences.
See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for a discussion of environmental matters.
Competition
See "Item 1. Business - Segment Information - Pennsylvania Regulated Segment - Competition" for a discussion of competitive factors affecting PPL Electric.
New Accounting Guidance
See Notes 1 and 24 to the Financial Statements for a discussion of new accounting guidance adopted and pending adoption.
Application of Critical Accounting Policies
Financial condition and results of operations are impacted by the methods, assumptions and estimates used in the application of critical accounting policies. The following accounting policies are particularly important to the financial condition or results of operations, and require estimates or other judgments of matters inherently uncertain. Changes in the estimates or other judgments included within these accounting policies could result in a significant change to the information presented in the Financial Statements (these accounting policies are also discussed in Note 1 to the Financial Statements). Senior management has reviewed these critical accounting policies, the following disclosures regarding their application and the estimates and assumptions regarding them, with PPL's Audit Committee.
Defined Benefits
PPL Electric participates in a qualified funded defined benefit pension plan, an unfunded non-qualified defined benefit plan and a funded other postretirement benefit plan, sponsored by other PPL subsidiaries and administered through PPL Services. PPL Electric is allocated a significant portion of the liability and net periodic defined benefit pension and other postretirement costs of the plans sponsored by other PPL subsidiaries based on participation in those plans. PPL Electric records an asset or liability to recognize the funded status of all defined benefit plans with an offsetting entry to regulatory assets. Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets. See Note 13 to the Financial Statements for additional information about the plans and the accounting for defined benefits.
PPL Services makes certain assumptions regarding the valuation of benefit obligations and the performance of plan assets. When accounting for defined benefits, delayed recognition in earnings of differences between actual results and expected or estimated results is a guiding principle. Annual net periodic defined benefit costs are recorded in current earnings based on estimated results. Any differences between actual and estimated results are recorded in regulatory assets for amounts that are expected to be recovered through regulated customer rates. The amount in regulatory assets is amortized to income over future periods. The delayed recognition allows for a smoothed recognition of costs over the working lives of the employees who benefit under the plans. The primary assumptions are:
· | Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due.
|
· | Expected Return on Plan Assets - Management projects the long-term rates of return on plan assets based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes. These projected returns reduce the net benefit costs PPL records currently. |
· | Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement. |
· | Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care. |
In selecting a discount rate for its U.S. defined benefit plans, PPL Services starts with a cash flow analysis of the expected benefit payment stream for its plans. The plan-specific cash flows are matched against the coupons and expected maturity values of individually selected bonds. This bond matching process begins with the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, serving as the base from which those with the lowest and highest yields were eliminated to develop an appropriate subset of bonds. Individual bonds were then selected based on the timing of each plan's cash flows and parameters were established as to the percentage of each individual bond issue that could be hypothetically purchased and the surplus reinvestment rates to be assumed. At December 31, 2012, PPL Services decreased the discount rate for its U.S. pension plans from 5.07% to 4.22% and decreased the discount rate for its other postretirement benefit plans from 4.81% to 4.02%.
The expected long-term rates of return for PPL Services' U.S. defined benefit pension and other postretirement benefit plans have been developed using a best-estimate of expected returns, volatilities and correlations for each asset class. PPL management corroborates these rates with expected long-term rates of return calculated by its independent actuary, who uses a building block approach that begins with a risk-free rate of return with factors being added such as inflation, duration, credit spreads and equity risk. Each plan's specific asset allocation is also considered in developing a reasonable return assumption. At December 31, 2012, PPL Services' expected return on plan assets remained at 7.00% for its U.S. pension plan and increased from 5.70% to 5.75% for its other postretirement benefit plan.
In selecting a rate of compensation increase, PPL Services considers past experience in light of movements in inflation rates. At December 31, 2012, PPL Services' rate of compensation increase decreased from 4.00% to 3.95% for its U.S. plans.
In selecting health care cost trend rates for PPL Services' other postretirement benefit plans, PPL Services considers past performance and forecasts of health care costs. At December 31, 2012, PPL Services' health care cost trend rates were 8.00% for 2013, gradually declining to 5.50% for 2019.
A variance in the assumptions listed above could have a significant impact on the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and the regulatory assets allocated to PPL Electric. While the charts below reflect either an increase or decrease in each assumption, the inverse of this change would impact the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and regulatory assets by a similar amount in the opposite direction. The sensitivities below reflect an evaluation of the change based solely on a change in that assumption and does not include income tax effects.
At December 31, 2012, the defined benefit plans were recorded as follows.
Pension liabilities | | $ | (237) |
Other postretirement benefit liabilities | | | (61) |
The following chart reflects the sensitivities in the December 31, 2012 Balance Sheet associated with a change in certain assumptions based on PPL Services' primary defined benefit plans.
| | | Increase (Decrease) |
| | | Change in | | Impact on defined | | Impact on |
Actuarial assumption | | | assumption | | benefit liabilities | | regulatory assets |
| | | | | | | | | |
Discount Rate | | | (0.25)% | | $ | 46 | | $ | (46) |
Rate of Compensation Increase | | | 0.25% | | | 7 | | | (7) |
Health Care Cost Trend Rate (a) | | | 1.00% | | | 1 | | | (1) |
(a) | Only impacts other postretirement benefits. |
In 2012, PPL Electric was allocated net periodic defined benefit costs charged to operating expense of $22 million. This amount represents a $4 million increase compared with the charge recognized during 2011.
The following chart reflects the sensitivities in the 2012 Statement of Income (excluding income tax effects) associated with a change in certain assumptions based on PPL Services' primary defined benefit plans.
Actuarial assumption | | | Change in assumption | | | Impact on defined benefit costs |
| | | | | | |
Discount Rate | | | (0.25)% | | $ | 3 |
Expected Return on Plan Assets | | | (0.25)% | | | 3 |
Rate of Compensation Increase | | | 0.25% | | | 1 |
Loss Accruals
Losses are accrued for the estimated impacts of various conditions, situations or circumstances involving uncertain or contingent future outcomes. For loss contingencies, the loss must be accrued if (1) information is available that indicates it is probable that a loss has been incurred, given the likelihood of the uncertain future events, and (2) the amount of the loss can be reasonably estimated. Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." The accrual of contingencies that might result in gains is not recorded unless recovery is assured. Potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events are continuously assessed.
The accounting aspects of estimated loss accruals include (1) the initial identification and recording of the loss, (2) the determination of triggering events for reducing a recorded loss accrual, and (3) the ongoing assessment as to whether a recorded loss accrual is sufficient. All three of these aspects require significant judgment by management. Internal expertise and outside experts (such as lawyers and engineers) are used, as necessary, to help estimate the probability that a loss has been incurred and the amount (or range) of the loss.
No new significant loss accruals were recorded in 2012.
Certain other events have been identified that could give rise to a loss, but that do not meet the conditions for accrual. Such events are disclosed, but not recorded, when it is "reasonably possible" that a loss has been incurred.
When an estimated loss is accrued, the triggering events for subsequently reducing the loss accrual are identified, where applicable. The triggering events generally occur when the contingency has been resolved and the actual loss is paid or written off, or when the risk of loss has diminished or been eliminated. The following are some of the triggering events that provide for the reduction of certain recorded loss accruals:
· | Allowances for uncollectible accounts are reduced when accounts are written off after prescribed collection procedures have been exhausted, a better estimate of the allowance is determined or underlying amounts are ultimately collected. |
· | Environmental and other litigation contingencies are reduced when the contingency is resolved and actual payments are made, a better estimate of the loss is determined or the loss is no longer considered probable. |
Loss accruals are reviewed on a regular basis to assure that the recorded potential loss exposures are appropriate. This involves ongoing communication and analyses with internal and external legal counsel, engineers, operation management and other parties.
See Note 15 to the Financial Statements for disclosure of loss contingencies accrued and other potential loss contingencies that have not met the criteria for accrual.
Income Taxes
Significant management judgment is required in developing the provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination of deferred tax assets, liabilities and valuation allowances.
Significant management judgment is required to determine the amount of benefit recognized related to an uncertain tax position. Tax positions are evaluated following a two-step process. The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained. This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position. The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion. The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization, upon settlement, that exceeds 50%. Management considers a number of factors in assessing the benefit to be recognized, including negotiation of a settlement.
On a quarterly basis, uncertain tax positions are reassessed by considering information known at the reporting date. Based on management's assessment of new information, a tax benefit may subsequently be recognized for a previously unrecognized tax position, a previously recognized tax position may be derecognized, or the benefit of a previously recognized tax position may be remeasured. The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements in the future.
At December 31, 2012, it was reasonably possible that during the next 12 months the total amount of unrecognized tax benefits could increase by as much as $11 million or decrease by up to $25 million. This change could result from the timing and/or valuation of certain deductions, intercompany transactions and unitary filing groups. The events that could cause these changes are direct settlements with taxing authorities, litigation, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.
The balance sheet classification of unrecognized tax benefits and the need for valuation allowances to reduce deferred tax assets also require significant management judgment. Unrecognized tax benefits are classified as current to the extent management expects to settle an uncertain tax position by payment or receipt of cash within one year of the reporting date. Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset. Management considers a number of factors in assessing the realization of a deferred tax asset, including the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies. Any tax planning strategy utilized in this assessment must meet the recognition and measurement criteria utilized to account for an uncertain tax position. See Note 5 to the Financial Statements for income tax disclosures.
Regulatory Assets and Liabilities
PPL Electric's electricity delivery business is subject to cost-based rate regulation. As a result, the effects of regulatory actions are required to be reflected in the financial statements. Assets and liabilities are recorded that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in regulated customer rates. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. In certain cases, regulatory liabilities are recorded based on an understanding or agreement with the regulator that rates have been set to recover costs that are expected to be incurred in the future, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose.
Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory and political environments, the ability to recover costs through regulated rates, recent rate orders to other regulated entities, and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, then asset write-offs would be required to be recognized in operating income. Additionally, the regulatory agencies can provide flexibility in the manner and timing of depreciation of PP&E and amortization of regulatory assets.
At December 31, 2012, PPL Electric had regulatory assets of $853 million and regulatory liabilities of $60 million. All regulatory assets are either currently being recovered under specific rate orders, represent amounts that are expected to be recovered in future rates or benefit future periods based upon established regulatory practices.
See Note 6 to the Financial Statements for additional information on regulatory assets and liabilities.
Revenue Recognition - Unbilled Revenue
Revenues related to the sale of energy are recorded when energy is delivered to customers. Because customers are billed on cycles which vary based on the timing of the actual meter reads taken throughout the month, PPL Electric records estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of energy delivered to customers since the date of the last reading of their meters. The unbilled estimate is based on daily load models, the meter read schedule, and actual weather data. The unbilled accrual is based on estimated usage for each customer class, and the current rate schedule pricing. At December 31, 2012 and 2011, PPL Electric had unbilled revenue of $110 million and $102 million.
Other Information
PPL's Audit Committee has approved the independent auditor to provide audit, audit-related and tax services permitted by Sarbanes-Oxley and SEC rules. The audit and audit-related services include services in connection with statutory and regulatory filings, reviews of offering documents and registration statements, and internal control reviews. See "Item 14. Principal Accounting Fees and Services" for more information.
LG&E AND KU ENERGY LLC AND SUBSIDIARIES
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The information provided in this Item 7 should be read in conjunction with LKE's Consolidated Financial Statements and the accompanying Notes. Capitalized terms and abbreviations are defined in the glossary. Dollars are in millions, unless otherwise noted.
"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:
· | "Overview" provides a description of LKE and its business strategy, a summary of Net Income and a discussion of certain events related to LKE's results of operations and financial condition. |
· | "Results of Operations" provides a summary of LKE's earnings and a description of key factors expected to impact future earnings. This section ends with explanations of significant changes in principal items on LKE's Statements of Income, comparing 2012 with 2011 and 2011 with 2010. |
· | "Financial Condition - Liquidity and Capital Resources" provides an analysis of LKE's liquidity position and credit profile. This section also includes a discussion of forecasted sources and uses of cash and rating agency actions. |
· | "Financial Condition - Risk Management" provides an explanation of LKE's risk management programs relating to market and credit risk. |
· | "Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of LKE and that require its management to make significant estimates, assumptions and other judgments of matters inherently uncertain. |
Overview
Introduction
LKE, headquartered in Louisville, Kentucky, is a holding company. LKE became a wholly owned subsidiary of PPL when PPL acquired all of LKE's interests from E.ON US Investments Corp. on November 1, 2010. LKE has regulated utility operations through its subsidiaries, LG&E and KU, which constitute substantially all of LKE's assets. LG&E and KU are engaged in the generation, transmission, distribution and sale of electric energy. LG&E also engages in the distribution and sale of natural gas. LG&E and KU maintain their separate identities and serve customers in Kentucky under their respective names. KU also serves customers in Virginia under the Old Dominion Power name and in Tennessee under the KU name. Refer to "Item 1. Business - Background" for a description of LKE's business.
Business Strategy
LKE's overall strategy is to provide reliable, safe, competitively priced energy to its customers and reasonable returns on regulated investments to its member.
A key objective for LKE is to maintain a strong credit profile through managing financing costs and access to credit markets. LKE continually focuses on maintaining an appropriate capital structure and liquidity position.
Successor and Predecessor Financial Presentation
LKE's Financial Statements and related financial and operating data include the periods before and after PPL's acquisition of LKE on November 1, 2010 and have been segregated to present pre-acquisition activity as the Predecessor and post-acquisition activity as the Successor. Certain accounting and presentation methods were changed to acceptable alternatives to conform to PPL's accounting policies, and the cost bases of certain assets and liabilities were changed as of November 1, 2010 as a result of the application of push-down accounting. Consequently, the financial position, results of operations and cash flows for the Successor periods are not comparable to the Predecessor periods; however, the core operations of LKE have not changed as a result of the acquisition.
Financial and Operational Developments
Net Income
Net Income for 2012, 2011 and 2010 was $219 million, $265 million and $237 million. Earnings in 2012 decreased 17% from 2011 and earnings in 2011 increased 12% from 2010.
See "Results of Operations" for a discussion and analysis of LKE's earnings.
Rate Case Proceedings
In June 2012, LG&E and KU filed requests with the KPSC for increases in annual base electric rates of approximately $62 million at LG&E and approximately $82 million at KU and an increase in annual base gas rates of approximately $17 million at LG&E. In November 2012, LG&E and KU along with all of the parties filed a unanimous settlement agreement. Among other things, the settlement provided for increases in annual base electric rates of $34 million at LG&E and $51 million at KU and an increase in annual base gas rates of $15 million at LG&E. The settlement agreement also included revised depreciation rates that result in reduced annual electric depreciation expense of approximately $9 million for LG&E and approximately $10 million for KU. The settlement agreement included an authorized return on equity at LG&E and KU of 10.25%. On December 20, 2012, the KPSC issued orders approving the provisions in the settlement agreement. The new rates became effective on January 1, 2013. In addition to the increased base rates, the KPSC approved a gas line tracker mechanism for LG&E to provide for recovery of costs associated with LG&E's gas main replacement program, gas service lines and risers.
Equity Method Investment
KU owns 20% of the common stock of EEI. Through a power marketer affiliated with its majority owner, EEI sells its output to third parties. KU's investment in EEI is accounted for under the equity method of accounting. KU's direct exposure to loss as a result of its involvement with EEI is generally limited to the value of its investment. During the fourth quarter of 2012, KU concluded that an other-than-temporary decline in the value of its investment in EEI had occurred. Accordingly, KU recorded a $15 million impairment charge, net of taxes, related to this investment as of December 31, 2012, bringing the investment balance to zero. The impairment charge is shown in the line "Other-Than-Temporary Impairments" on the Statement of Income for the year ended December 31, 2012.
Registered Debt Exchange Offer by LKE
In June 2012, LKE completed an exchange of all its outstanding 4.375% Senior Notes due 2021 issued in September 2011 in a transaction not registered under the Securities Act of 1933, for similar securities that were issued in a transaction registered under the Securities Act of 1933. See Note 7 to the Financial Statements for additional information.
Commercial Paper
In February 2012, LG&E and KU each established a commercial paper program for up to $250 million to provide an additional financing source to fund their short-term liquidity needs, if and when necessary. Commercial paper issuances are supported by the issuer's credit facility. At December 31, 2012, $125 million of commercial paper was outstanding.
Terminated Bluegrass CTs Acquisition
In September 2011, LG&E and KU entered into an asset purchase agreement with Bluegrass Generation for the purchase of the Bluegrass CTs, aggregating approximately 495 MW, plus limited associated contractual arrangements required for operation of the units, for a purchase price of $110 million, pending receipt of applicable regulatory approvals. In May 2012, the KPSC issued an order approving the request to purchase the Bluegrass CTs. In November 2011, LG&E and KU filed an application with the FERC under the Federal Power Act requesting approval to purchase the Bluegrass CTs. In May 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to approval by the FERC of satisfactory mitigation measures to address market-power concerns. After a review of potentially available mitigation options, LG&E and KU determined that the options were not commercially justifiable. In June 2012, LG&E and KU terminated the asset purchase agreement for the Bluegrass CTs in accordance with its terms and made applicable filings with the KPSC and FERC.
Cane Run Unit 7 Construction
In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build Cane Run Unit 7. In May 2012, the KPSC issued an order approving the request. A formal request for recovery of the costs associated with the construction was not included in the CPCN filing with the KPSC but is expected to be included in future rate case proceedings. LG&E and KU commenced preliminary construction activities in the third quarter of 2012 and project construction is expected to be completed by May 2015. The project, which includes building a natural gas supply pipeline and related transmission projects, has an estimated cost of approximately $600 million.
In conjunction with this construction and to meet new, more stringent EPA regulations with a 2015 compliance date, LG&E and KU anticipate retiring five older coal-fired electric generating units at the Cane Run and Green River plants, which have a combined summer capacity rating of 726 MW. In addition, KU retired the remaining 71 MW unit at the Tyrone plant in February 2013.
Future Capacity Needs
In addition to the construction of a combined cycle gas unit at the Cane Run station, LG&E and KU continue to assess future capacity needs. As a part of the assessment, LG&E and KU issued an RFP in September 2012 for up to 700 MW of capacity beginning as early as 2015.
Results of Operations
As previously noted, LKE's results for the periods after October 31, 2010 are on a basis of accounting different from its results for periods prior to November 1, 2010. See "Overview - Successor and Predecessor Financial Presentation" for further information.
The utility business is affected by seasonal weather. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year. Revenue and earnings are generally higher during the first and third quarters and lower during the second and fourth quarters due to weather.
The following table summarizes the significant components of net income for 2012, 2011 and 2010 and the changes therein:
Earnings
| | | | Successor | | | Predecessor |
| | | | | | | | Two Months | | | Ten Months |
| | | | Year Ended | | Year Ended | | Ended | | | Ended |
| | | | December 31, | | December 31, | | December 31, | | | October 31, |
| | | | 2012 | | 2011 | | 2010 | | | 2010 |
| | | | | | | | | | | | | | | |
| Net Income | | $ | 219 | | $ | 265 | | $ | 47 | | | $ | 190 |
The changes in the components of Net Income between these periods were due to the following factors, which reflect reclassifications for items included in Margins and certain items that management considers special. See additional detail of these special items in the table below.
| | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | |
Margins | | $ | (8) | | $ | 92 |
Other operation and maintenance | | | (16) | | | (5) |
Depreciation | | | (10) | | | (43) |
Taxes, other than income | | | (9) | | | (14) |
Other Income (Expense) - net | | | (14) | | | (13) |
Interest Expense | | | (4) | | | 29 |
Income Taxes | | | 31 | | | (18) |
Special items, after-tax | | | (16) | | | |
Total | | $ | (46) | | $ | 28 |
· | See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Margins. |
· | Higher other operation and maintenancein 2012 compared with 2011 primarily due to $11 million of expenses related to an increased scope of scheduled outages and a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs.
|
· | Higher depreciation in 2012 compared with 2011 due to PP&E additions. |
Higher depreciation in 2011 compared with 2010 primarily due to TC2 commencing dispatch in January 2011.
· | Higher taxes, other than income in 2011 compared with 2010 primarily due to a $9 million state coal tax credit that was applied to 2010 property taxes. The remaining increase was due to higher assessments, primarily from significant property additions. |
· | Lower other income (expense) - net in 2012 compared with 2011 primarily due to losses from the EEI investment. |
Lower other income (expense) - net in 2011 compared with 2010 primarily due to $19 million of other income from the establishment of a regulatory asset in 2010 for previously recorded losses on interest rate swaps.
· | Lower interest expense in 2011 compared with 2010 due to lower interest rates and lower average long-term debt balances. Lower interest rates contributed $17 million to the decrease in interest expense, as the interest rates on the first mortgage bonds were lower than the rates on the loans from E.ON AG affiliates, which were replaced. |
· | Lower income taxes in 2012 compared with 2011 primarily due to lower pre-tax income. |
Higher income taxes in 2011 compared with 2010 primarily due to higher pre-tax income.
The following after-tax gains (losses), which management considers special items, also impacted earnings.
| | Income Statement | | Successor | | | Predecessor |
| | Line Item | | 2012 | | 2011 | | 2010 | | | 2010 |
| | | | | | | | | | | | | | | |
| Net operating loss carryforward and other tax-related adjustments | Income Taxes and Other O&M | | $ | 4 | | | | | | | | | | |
| Asset impairment, net of tax of $10 (a) | Other-Than-Temporary Impairments | | | (15) | | | | | | | | | | |
| Discontinued operations adjustment, net of tax of $4 (b) | Discontinued Operations | | | (5) | | | | | | | | | | |
| Energy-related economic activity, net of tax of $0, ($1), $1, $0 (c) | Operating Revenues | | | | | $ | 1 | | $ | (1) | | | | |
| BREC terminated lease, net of tax of $0, $1, ($2), $1 (d) | Discontinued Operations | | | | | | (1) | | | 2 | | | $ | (1) |
Total | | | $ | (16) | | $ | | | $ | 1 | | | $ | (1) |
(a) | KU recorded an impairment of its equity method investment in EEI. See Note 18 to the Financial Statements for additional information. |
(b) | 2012 includes an adjustment to an indemnification liability. |
(c) | Represents net unrealized gains (losses) on contracts that economically hedge anticipated cash flows. |
(d) | Represents costs associated with a terminated lease of WKE for the generating facilities of BREC. See Note 9 to the Financial Statements for additional information. |
2013 Outlook
Excluding special items, LKE projects higher earnings in 2013 compared with 2012, primarily driven by electric and gas base rate increases effective January 1, 2013, returns on additional environmental capital investments and retail load growth, partially offset by higher operation and maintenance.
Earnings in future periods are subject to various risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Notes 6 and 15 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.
Statement of Income Analysis --
Margins
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as a non-GAAP financial measure, "Margins." Margins is not intended to replace "Operating Income," which is determined in accordance with GAAP as an indicator of overall operating performance. Other companies may use different measures to analyze and to report on the results of their operations. Margins is a single financial performance measure of LKE's electricity generation,
transmission and distribution operations as well as its distribution and sale of natural gas. In calculating this measure, fuel and energy purchases are deducted from revenues. In addition, utility revenues and expenses associated with approved cost recovery mechanisms are offset. These mechanisms allow for recovery of certain expenses, returns on capital investments primarily associated with environmental regulations and performance incentives. Certain costs associated with these mechanisms, primarily ECR and DSM, are recorded as "Other operation and maintenance" and "Depreciation." As a result, this measure represents the net revenues from LKE's operations. This performance measure is used, in conjunction with other information, internally by senior management to manage operations and analyze actual results compared with budget.
Reconciliation of Non-GAAP Financial Measures
The following tables reconcile "Operating Income" to "Margins" as defined by LKE for 2012, 2011 and 2010.
| | | | | | 2012 Successor | | | | 2011 Successor |
| | | | | | | | | | | Operating | | | | | | | | | Operating |
| | | | | | Margins | | Other (a) | | Income (b) | | | | Margins | | Other (a) | | Income (b) |
| | | | | | | | | | | | | | | | | | |
Operating Revenues | | $ | 2,759 | | | | | $ | 2,759 | | | | $ | 2,791 | | $ | 2 | | $ | 2,793 |
Operating Expenses | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 872 | | | | | | 872 | | | | | 866 | | | | | | 866 |
| Energy purchases | | | 195 | | | | | | 195 | | | | | 238 | | | | | | 238 |
| Other operation and maintenance | | | 101 | | $ | 677 | | | 778 | | | | | 90 | | | 661 | | | 751 |
| Depreciation | | | 51 | | | 295 | | | 346 | | | | | 49 | | | 285 | | | 334 |
| Taxes, other than income | | | | | | 46 | | | 46 | | | | | | | | 37 | | | 37 |
| | | Total Operating Expenses | | | 1,219 | | | 1,018 | | | 2,237 | | | | | 1,243 | | | 983 | | | 2,226 |
Total | | $ | 1,540 | | $ | (1,018) | | $ | 522 | | | | $ | 1,548 | | $ | (981) | | $ | 567 |
| | | | | | Successor | | | Predecessor |
| | | | | | Two Months Ended December 31, 2010 | | | Ten Months Ended October 31, 2010 |
| | | | | | | | | | | Operating | | | | | | | | | Operating |
| | | | | | Margins | | Other (a) | | Income (b) | | | Margins | | Other (a) | | Income (b) |
| | | | | | | | | | | | | | | | | | |
Operating Revenues | | $ | 495 | | $ | (1) | | $ | 494 | | | $ | 2,214 | | | | | $ | 2,214 |
Operating Expenses | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 138 | | | | | | 138 | | | | 723 | | | | | | 723 |
| Energy purchases | | | 68 | | | | | | 68 | | | | 211 | | | | | | 211 |
| Other operation and maintenance | | | 14 | | | 127 | | | 141 | | | | 57 | | $ | 529 | | | 586 |
| Depreciation | | | 7 | | | 42 | | | 49 | | | | 35 | | | 200 | | | 235 |
| Taxes, other than income | | | | | | 2 | | | 2 | | | | | | | 21 | | | 21 |
| | | Total Operating Expenses | | | 227 | | | 171 | | | 398 | | | | 1,026 | | | 750 | | | 1,776 |
Total | | $ | 268 | | $ | (172) | | $ | 96 | | | $ | 1,188 | | $ | (750) | | $ | 438 |
(a) | Represents amounts excluded from Margins. |
(b) | As reported on the Statements of Income. |
Changes in Non-GAAP Financial Measures
Margins decreased by $8 million for 2012 compared with 2011, primarily due to $6 million of lower wholesale margins resulting from lower market prices. Retail margins were $2 million lower, as volumes were impacted by unseasonably mild weather during the first four months of 2012. Total heating degree days decreased 11% compared to 2011, partially offset by a 6% increase in cooling degree days.
Margins increased by $92 million for 2011 compared with 2010. New KPSC rates went into effect on August 1, 2010, contributing to an additional $112 million in operating revenue over the prior year. Partially offsetting the rate increase were lower retail volumes resulting from weather and economic conditions.
Other Operation and Maintenance | | | | | |
| | | | | | |
The increase (decrease) in other operation and maintenance was due to: |
| | |
| 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | |
Coal plant maintenance (a) | $ | 19 | | $ | 4 |
Distribution maintenance (b) | | 7 | | | 8 |
Administrative and general (c) | | (7) | | | (1) |
Steam operation (d) | | 2 | | | 10 |
Fuel for generation (e) | | | | | 11 |
Other generation maintenance | | | | | (4) |
Other | | 6 | | | (4) |
Total | $ | 27 | | $ | 24 |
(a) | Coal plant maintenance costs increased in 2012 compared with 2011 primarily due to $11 million of expenses related to an increased scope of scheduled outages, as well as $5 million of increased maintenance at the Ghent plant on the scrubber system and primary fuel combustion system. |
(b) | Distribution maintenance costs increased in 2012 compared with 2011 primarily due to a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs. |
Distribution maintenance costs increased in 2011 compared with 2010 primarily due to $17 million of expenses related to amortization of storm restoration-related costs, a hazardous tree removal project initiated in August 2010 and an increase in pipeline integrity work. This increase was offset by a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs.
(c) | Administrative and general costs decreased in 2012 compared with 2011 primarily due to a decrease in pension expense resulting from pension funding and lower interest cost. |
(d) | Steam operation costs increased in 2011 compared with 2010 primarily due to higher variable costs as a result of TC2 commencing dispatch in 2011. |
(e) | Fuel handling costs are included in other operation and maintenance on the Statements of Income for the Successor periods and are in fuel on the Statement of Income for the Predecessor period. |
Depreciation
The increase (decrease) in depreciation was due to:
| | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | |
TC2 (dispatch began in January 2011) | | | | $ | 32 |
E.W. Brown sulfur dioxide scrubber equipment (placed in-service in June 2010) | | | | | 8 |
Other additions to PP&E | $ | 12 | | | 10 |
Total | $ | 12 | | $ | 50 |
Taxes, Other Than Income
Taxes, other than income increased by $9 million in 2012 compared with 2011 due in part to a $4 million increase in property taxes resulting from property additions, higher assessed values and changes in property classifications to categories with higher tax rates.
Taxes, other than income increased by $14 million in 2011 compared with 2010 primarily due to a $9 million state coal tax credit that was applied to 2010 property taxes. The remaining increase was due to higher assessments, primarily from significant property additions.
Other Income (Expense) - net
The increase (decrease) in other income (expense) - net was due to:
| | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | |
Earnings (losses) from the EEI investment | $ | (9) | | $ | (2) |
Depreciation expense on TC2 joint-use assets held for future use | | | | | 3 |
Losses on interest rate swaps (a) | | | | | (19) |
Other | | (5) | | | 5 |
Total | $ | (14) | | $ | (13) |
(a) | A regulatory asset was established in 2010 for previously recorded losses on interest rate swaps. |
Other-Than-Temporary Impairments
Other-than-temporary impairments increased by $25 million in 2012 compared with 2011 due to the $25 million pre-tax impairment of the EEI investment. See Notes 1 and 18 to the Financial Statements for additional information.
Interest Expense
The increase (decrease) in interest expense was due to:
| | | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | | |
Interest rates (a) | | $ | (2) | | $ | (17) |
Long-term debt balances (b) | | | 8 | | | (15) |
Other | | | (2) | | | 3 |
Total | | $ | 4 | | $ | (29) |
(a) | Interest expense decreased in 2011 compared with 2010 primarily due to lower interest rates on senior notes and first mortgage bonds issued in November 2010 compared with the rates on the loans from E.ON AG affiliates that were in place through October 2010. |
(b) | Interest expense increased in 2012 compared with 2011 due to the LKE $250 million senior notes that were issued in September 2011. |
Interest expense decreased in 2011 compared with 2010 as the long-term debt balances were lower for the majority of 2011. The debt balances increased in September 2011 due to the issuance of the LKE $250 million senior notes.
Income Taxes | | |
| | | | | | | |
The increase (decrease) in income taxes was due to: |
| | | |
| | | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | | |
Change in pre-tax income | | $ | (34) | | $ | 19 |
Net operating loss carryforward adjustments (a) | | | (9) | | | |
Other | | | (4) | | | |
Total | | $ | (47) | | $ | 19 |
(a) | Adjustments to deferred taxes related to net operating loss carryforwards based on income tax return adjustments. |
Income (Loss) from Discontinued Operations (net of income taxes) |
Income (loss) from discontinued operations (net of income taxes) decreased by $5 million in 2012 compared with 2011 primarily related to an adjustment to the estimated liability for indemnifications related to the termination of the WKE lease in 2009.
Financial Condition
Liquidity and Capital Resources
LKE expects to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents and its credit facilities, including commercial paper issuances. Additionally, subject to market conditions, subsidiaries of LKE currently plan to access capital markets in 2013.
LKE's cash flows from operations and access to cost-effective bank and capital markets are subject to risks and uncertainties including, but not limited to:
· | changes in commodity prices that may increase the cost of producing or purchasing power or decrease the amount LKE receives from selling power; |
· | operational and credit risks associated with selling and marketing products in the wholesale power markets; |
· | unusual or extreme weather that may damage LKE's transmission and distribution facilities or affect energy sales to customers; |
· | reliance on transmission facilities that LKE does not own or control to deliver its electricity and natural gas; |
· | unavailability of generating units (due to unscheduled or longer-than-anticipated generation outages, weather and natural disasters) and the resulting loss of revenues and additional costs of replacement electricity; |
· | the ability to recover and the timeliness and adequacy of recovery of costs associated with regulated utility businesses; |
· | costs of compliance with existing and new environmental laws; |
· | any adverse outcome of legal proceedings and investigations with respect to LKE's current and past business activities; |
· | deterioration in the financial markets that could make obtaining new sources of bank and capital markets funding more difficult and more costly; and |
· | a downgrade in LKE's or its rated subsidiaries' credit ratings that could adversely affect their ability to access capital and increase the cost of credit facilities and any new debt. |
See "Item 1A. Risk Factors" for further discussion of risks and uncertainties affecting LKE's cash flows.
At December 31, LKE had the following:
| | | | |
| | 2012 | | 2011 | | 2010 |
| | | | | | | | | |
Cash and cash equivalents | | $ | 43 | | $ | 59 | | $ | 11 |
Short-term investments (a) | | | | | | | | | 163 |
| | $ | 43 | | $ | 59 | | $ | 174 |
| | | | | | | | | |
Short-term debt (b) | | $ | 125 | | | | | $ | 163 |
(a) | Represents tax-exempt bonds issued by Louisville/Jefferson County, Kentucky, on behalf of LG&E that were purchased from the remarketing agent in 2008. Such bonds were remarketed to unaffiliated investors in January 2011. See Note 7 to the Financial Statements for additional information. |
(b) | Borrowings in 2012 were made under LG&E's and KU's commercial paper programs and borrowings in 2010 were made under LG&E's syndicated credit facility. See Note 7 to the Financial Statements for additional information. |
The changes in LKE's cash and cash equivalents position resulted from: |
| | | | | Successor | | | Predecessor |
| | | | | | | | | Two Months | | | Ten Months |
| | | | | Year Ended | | Year Ended | | Ended | | | Ended |
| | | | | December 31, | | December 31, | | December 31, | | | October 31, |
| | | | | 2012 | | 2011 | | 2010 | | | 2010 |
| | | | | | | | | | | | | |
Net cash provided by (used in) operating activities | | $ | 747 | | $ | 781 | | $ | 26 | | | $ | 488 |
Net cash provided by (used in) investing activities | | | (756) | | | (277) | | | (211) | | | | (426) |
Net cash provided by (used in) financing activities | | | (7) | | | (456) | | | 167 | | | | (40) |
Net Increase (Decrease) in Cash and Cash Equivalents | | $ | (16) | | $ | 48 | | $ | (18) | | | $ | 22 |
Operating Activities
Net cash provided by operating activities decreased by 4%, or $34 million, in 2012 compared with 2011, primarily as a result of:
· | Net income adjusted for non-cash items declined by $94 million, which included an $85 million reduction in deferred income taxes due primarily to the utilization of a capital loss carry forward in 2011. |
· | Working capital cash flow changes declined by $66 million driven primarily by changes in receivables and unbilled revenues due to milder December weather in 2011 than in 2012 and 2010 and more income tax receivables collected in 2011 than in 2012. |
· | These items were offset by $126 million increase in other operating cash flows driven by $100 million reduction in pension funding. |
Net cash provided by operating activities increased by 52%, or $267 million, in 2011 compared with 2010, primarily as a result of:
· | an increase in net income adjusted for non-cash effects of $178 million (deferred income taxes and investment tax credits of $101 million, depreciation of $50 million, amortization of regulatory assets of $24 million and other noncash items of $3 million, partially offset by unrealized (gains) losses on derivatives of $14 million, defined benefit plans - expense of $13 million and loss from discontinued operations - net of tax of $1 million); |
· | an increase in cash inflows related to income tax receivable of $79 million primarily due to net operating losses of $40 million recorded in 2010 and the payment of $40 million received by LKE for tax benefits in 2011; |
· | a net decrease in cash provided from accounts receivable and unbilled revenues of $75 million due to colder weather in December 2010 as compared with December 2009 and milder weather in December 2011 as compared with December 2010; and |
· | a decrease in cash outflows of $28 million due to lower inventory levels in 2011 as compared with 2010 driven by $32 million for fuel inventory purchased in 2010 for TC2 that was not used until 2011 when TC2 began dispatch, $21 million due to lower coal burn as a result of unplanned outages at LG&E's Mill Creek plant and $6 million for decreases in gas storage volumes, partially offset by $22 million for KU's E.W. Brown and Ghent plants due primarily to increases in coal prices and $7 million for increases in coal in-transit; partially offset by |
· | an increase in discretionary defined benefit plan contributions of $105 million made in order to achieve LKE's long-term funding requirements. |
Investing Activities
Net cash used in investing activities increased by 173%, or $479 million, in 2012 compared with 2011, primarily as a result of:
· | an increase in capital expenditures of $291 million, primarily due to coal combustion residuals projects at Ghent and E.W. Brown, environmental air projects at Mill Creek and Ghent, and construction of Cane Run Unit 7; and
|
· | a decrease in the proceeds from the sale of other investments of $163 million in 2011. |
Net cash used in investing activities decreased by 57%, or $360 million, in 2011 compared with 2010, as a result of:
· | proceeds from the sale of other investments of $163 million in 2011;
|
· | a decrease in capital expenditures of $122 million, primarily due to the completion of KU's scrubber program in 2010 and TC2 being dispatched in 2011; and
|
· | an increase from a change in notes receivable from affiliates of $107 million; partially offset by |
· | proceeds from sales of discontinued operations of $21 million in 2010; and
|
· | a decrease in restricted cash of $11 million.
|
See "Forecasted Uses of Cash" for detail regarding capital expenditures for the years 2013 through 2017.
Financing Activities
Net cash used in financing activities was $7 million in 2012 compared with net cash used in financing activities of $456 million in 2011, primarily as a result of decrease in distributions to PPL.
In 2012, cash used in financing activities consisted of:
· | distributions to PPL of $155 million; partially offset by
|
· | the issuance of $125 million of short-term debt in the form of commercial paper; and
|
· | an increase in notes payable with affiliates of $25 million.
|
Net cash used in financing activities was $456 million in 2011 compared with net cash provided by financing activities of $127 million in 2010, primarily as a result of increased distributions to PPL and reduced contributions from PPL.
In 2011, cash used in financing activities consisted of:
· | distributions to PPL of $533 million, which includes $248 million using the proceeds of the long-term debt issuance noted below;
|
· | a repayment on a revolving line of credit of $163 million; |
· | the payment of debt issuance and credit facility costs of $8 million; and |
· | the repayment of debt of $2 million; partially offset by |
· | the issuance of senior notes of $250 million. |
In the two months of 2010 following PPL's acquisition of LKE, cash provided by financing activities of the Successor consisted of:
· | the issuance of senior unsecured notes and first mortgage bonds of $2,890 million after discounts; |
· | the issuance of debt of $2,784 million to a PPL affiliate to repay debt due to E.ON AG affiliates upon the closing of PPL's acquisition of LKE; |
· | an equity contribution from PPL of $1,565 million; and |
· | a draw on a revolving line of credit of $163 million; partially offset by |
· | the repayment of debt to E.ON AG affiliates of $4,319 million upon the closing of PPL's acquisition of LKE; |
· | the repayment of debt to a PPL affiliate of $2,784 million upon the issuance of senior unsecured notes and first mortgage bonds; |
· | distributions to PPL of $100 million; and |
· | the payment of debt issuance and credit facility costs of $32 million. |
In the ten months of 2010 preceding PPL's acquisition of LKE, cash used in financing activities by the Predecessor consisted of:
· | the repayment of debt to an E.ON AG affiliate of $900 million; |
· | distributions to E.ON US Investments Corp. of $87 million; and |
· | a net decrease in notes payable with affiliates of $3 million; partially offset by |
· | the issuance of debt of $950 million to an E.ON AG affiliate. |
See "Forecasted Sources of Cash" for a discussion of LKE's plans to issue debt securities, as well as a discussion of credit facility capacity available to LKE. Also see "Forecasted Uses of Cash" for a discussion of plans to pay dividends on common securities in the future, as well as maturities of long-term debt.
LKE's long-term debt securities activity through December 31, 2012 was:
| | | | Debt |
| | | | Issuances | | Retirement |
Non-cash Exchanges (a) | | | | | | |
| LKE Senior Unsecured Notes | | $ | 250 | | $ | (250) |
(a) | In June 2012, LKE completed an exchange of all of its outstanding 4.375% Senior Notes due 2021 issued in September 2011, in a transaction not registered under the Securities Act of 1933, for similar securities that were issued in a transaction registered under the Securities Act of 1933. |
See Note 7 to the Financial Statements for additional information about long-term debt securities.
Auction Rate Securities
At December 31, 2012, LG&E's and KU's tax-exempt revenue bonds that are in the form of auction rate securities and total $231 million continue to experience failed auctions. Therefore, the interest rate continues to be set by a formula pursuant to the relevant indentures. For the period ended December 31, 2012, the weighted-average rate on LG&E's and KU's auction rate bonds in total was 0.22%.
Forecasted Sources of Cash
LKE expects to continue to have sufficient sources of cash available in the near term, including various credit facilities, its commercial paper programs, issuance of debt securities and operating cash flow.
Credit Facilities
At December 31, 2012, LKE's total committed borrowing capacity under its credit facilities and the use of this borrowing capacity were:
| | | | | | Borrowed / | | | | | | |
| | | Committed | | Commercial | | Letters of | | Unused |
| | | Capacity | | Paper Issued | | Credit Issued | | Capacity |
| | | | | | | | | |
LKE Credit Facility with a subsidiary of PPL Energy Funding Corporation | | $ | 300 | | $ | 25 | | | | | $ | 275 |
LG&E Credit Facility (a) (d) | | | 500 | | | 55 | | | | | | 445 |
KU Credit Facilities (a) (b) (d) | | | 598 | | | 70 | | $ | 198 | | | 330 |
| Total Credit Facilities (c) | | $ | 1,398 | | $ | 150 | | $ | 198 | | $ | 1,050 |
(a) | In November 2012, LG&E and KU amended their syndicated credit facilities to extend the expiration dates to November 2017. In addition, LG&E increased its credit facility's capacity to $500 million. |
(b) | In August 2012, the KU letter of credit facility agreement was amended and restated to allow for certain payments under the letter of credit facility to be converted to loans rather than requiring immediate payment. |
(c) | The $1.098 billion of commitments under LG&E's and KU's domestic credit facilities are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than 11% of the total committed capacity; however, the PPL affiliate provided a commitment of approximately 21% of the total facilities listed above. The syndicated credit facilities, as well as KU's letter of credit facility, each contain a financial covenant requiring debt to total capitalization not to exceed 70% for LG&E or KU, as calculated in accordance with the facility, and other customary covenants. |
(d) | Each company pays customary fees under their respective syndicated credit facilities, as well as KU's letter of credit facility, and borrowings generally bear interest at LIBOR-based rates plus an applicable margin. |
See Note 7 to the Financial Statements for further discussion of LKE's credit facilities.
Operating Leases
LKE and its subsidiaries also have available funding sources that are provided through operating leases. LKE's subsidiaries lease office space, gas storage and certain equipment. These leasing structures provide LKE additional operating and financing flexibility. The operating leases contain covenants that are typical for these agreements, such as maintaining insurance, maintaining corporate existence and timely payment of rent and other fees.
See Note 11 to the Financial Statements for further discussion of the operating leases.
Capital Contributions from PPL
From time to time PPL may make capital contributions to LKE. LKE may use these contributions to fund capital expenditures, make capital contributions to its subsidiaries and for other general corporate purposes.
Long-term Debt Securities
LG&E and KU currently plan to issue, subject to market conditions, up to $350 million for LG&E and $300 million for KU, of first mortgage bond indebtedness in 2013, the proceeds of which will be used to fund capital expenditures and for other general corporate purposes.
Forecasted Uses of Cash
In addition to expenditures required for normal operating activities, such as purchased power, payroll, fuel and taxes, LKE currently expects to incur future cash outflows for capital expenditures, various contractual obligations, distributions to PPL and possibly the purchase or redemption of a portion of debt securities.
Capital Expenditures
The table below shows LKE's current capital expenditure projections for the years 2013 through 2017.
| | | | Projected |
| | | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
Capital expenditures (a) | | | | | | | | | | | | | | | |
| Generating facilities | | $ | 427 | | $ | 251 | | $ | 267 | | $ | 476 | | $ | 540 |
| Distribution facilities | | | 233 | | | 227 | | | 263 | | | 257 | | | 281 |
| Transmission facilities | | | 107 | | | 68 | | | 59 | | | 56 | | | 77 |
| Environmental | | | 655 | | | 722 | | | 513 | | | 292 | | | 107 |
| Other | | | 48 | | | 45 | | | 43 | | | 48 | | | 39 |
| | Total Capital Expenditures | | $ | 1,470 | | $ | 1,313 | | $ | 1,145 | | $ | 1,129 | | $ | 1,044 |
(a) | LKE generally expects to recover these costs over a period equivalent to the related depreciable lives of the assets through rates. The 2013 total excludes amounts included in accounts payable as of December 31, 2012. |
LKE's capital expenditure projections for the years 2013 through 2017 total approximately $6.1 billion. Capital expenditure plans are revised periodically to reflect changes in operational, market and regulatory conditions. This table includes current estimates for LKE's environmental projects related to existing and proposed EPA compliance standards. Actual costs may be significantly lower or higher depending on the final requirements and market conditions. Environmental compliance costs incurred by LG&E and KU in serving KPSC jurisdictional customers are generally eligible for recovery through the ECR mechanism.
LKE plans to fund its capital expenditures in 2013 with cash on hand, cash from operations, short-term debt and issuance of debt securities.
Contractual Obligations
LKE has assumed various financial obligations and commitments in the ordinary course of conducting its business. LKE is not liable for the debts of LG&E and KU, nor are LG&E and KU liable for the debts of one another. Accordingly, creditors of LG&E and KU may not satisfy their debts from the assets of LKE absent a specific contractual undertaking by LKE or LG&E and KU to pay the creditors or as required by applicable law or regulation. At December 31, 2012, the estimated contractual cash obligations of LKE were:
| | | | Total | | 2013 | | 2014 - 2015 | | 2016 - 2017 | | After 2017 |
| | | | | | | | | | | | | | | | | |
Long-term Debt (a) | | $ | 4,085 | | | | | $ | 900 | | | | | $ | 3,185 |
Interest on Long-term Debt (b) | | | 2,586 | | $ | 139 | | | 274 | | $ | 250 | | | 1,923 |
Operating Leases (c) | | | 90 | | | 15 | | | 27 | | | 14 | | | 34 |
Coal and Natural Gas Purchase | | | | | | | | | | | | | | | |
| | Obligations (d) | | | 2,558 | | | 789 | | | 1,176 | | | 501 | | | 92 |
Unconditional Power Purchase | | | | | | | | | | | | | | | |
| | Obligations (e) | | | 1,038 | | | 30 | | | 60 | | | 64 | | | 884 |
Construction Obligations (f) | | | 1,757 | | | 836 | | | 639 | | | 282 | | | |
Pension Benefit Plan Obligations (g) | 153 | | | 153 | | | | | | | | | |
Other Obligations (h) | | | 30 | | | 7 | | | 14 | | | 8 | | | 1 |
Total Contractual Cash Obligations | | $ | 12,297 | | $ | 1,969 | | $ | 3,090 | | $ | 1,119 | | $ | 6,119 |
(a) | Reflects principal maturities only based on stated maturity dates. See Note 7 to the Financial Statements for a discussion of variable-rate remarketable bonds issued on behalf of LG&E and KU. LKE has no capital lease obligations. |
(b) | Assumes interest payments through stated maturity. The payments herein are subject to change, as payments for debt that is or becomes variable-rate debt have been estimated. |
(c) | See Note 11 to the Financial Statements for additional information. |
(d) | Represents contracts to purchase coal, natural gas and natural gas transportation. See Note 15 to the Financial Statements for additional information. |
(e) | Represents future minimum payments under OVEC power purchase agreements through June 2040. See Note 15 to the Financial Statements for additional information. |
(f) | Represents construction commitments, including commitments for the Mill Creek and Ghent environmental air projects, Cane Run Unit 7, Ghent landfill and Ohio Falls refurbishment which are also reflected in the Capital Expenditures table presented above. |
(g) | Based on the current funded status of LKE's qualified pension plans, no cash contributions are required. See Note 13 to the Financial Statements for a discussion of expected contributions. |
(h) | Represents other contractual obligations. |
Dividends
From time to time, as determined by its Board of Directors, LKE pays dividends to the sole member, PPL.
As discussed in Note 7 to the Financial Statements, LG&E's and KU's ability to pay dividends is limited under a covenant in each of their revolving line of credit facilities. This covenant restricts their debt to total capital ratio to not more than 70%. See Note 7 to the Financial Statements for other restrictions related to distributions on capital interests for LKE subsidiaries.
Purchase or Redemption of Debt Securities
LKE will continue to evaluate purchasing or redeeming outstanding debt securities and may decide to take action depending upon prevailing market conditions and available cash.
Rating Agency Actions
Moody's, S&P and Fitch periodically review the credit ratings on the debt securities of LKE and its subsidiaries. Based on their respective independent reviews, the rating agencies may make certain ratings revisions or ratings affirmations.
A credit rating reflects an assessment by the rating agency of the creditworthiness associated with an issuer and particular securities that it issues. The credit ratings of LKE and its subsidiaries are based on information provided by LKE and other sources. The ratings of Moody's, S&P and Fitch are not a recommendation to buy, sell or hold any securities of LKE or its subsidiaries. Such ratings may be subject to revisions or withdrawal by the agencies at any time and should be evaluated independently of each other and any other rating that may be assigned to the securities. The credit ratings of LKE and its subsidiaries affect its liquidity, access to capital markets and cost of borrowing under its credit facilities.
The following table sets forth LKE's and its subsidiaries' security credit ratings as of December 31, 2012.
| | Senior Unsecured | | Senior Secured | | Commercial Paper |
| | | | | | | | | | | | | | | | | | |
Issuer | | Moody's | | S&P | | Fitch | | Moody's | | S&P | | Fitch | | Moody's | | S&P | | Fitch |
| | | | | | | | | | | | | | | | | | |
LKE | | Baa2 | | BBB- | | BBB+ | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
LG&E | | | | | | A | | A2 | | A- | | A+ | | P-2 | | A-2 | | F-2 |
| | | | | | | | | | | | | | | | | | |
KU | | | | | | A | | A2 | | A- | | A+ | | P-2 | | A-2 | | F-2 |
In addition to the credit ratings noted above, the rating agencies took the following actions related to LKE and its subsidiaries:
In February 2012, Fitch assigned ratings to the two newly established commercial paper programs for LG&E and KU.
In March 2012, Moody's affirmed the following ratings:
· | the long-term ratings of the First Mortgage Bonds for LG&E and KU; |
· | the issuer ratings for LG&E and KU; and |
· | the bank loan ratings for LG&E and KU. |
Also in March 2012, Moody's and S&P each assigned short-term ratings to the two newly established commercial paper programs for LG&E and KU.
In March and May 2012, Moody's, S&P and Fitch affirmed the long-term ratings for LG&E's 2003 Series A, and 2007 Series B pollution control bonds.
In November 2012, Moody's and S&P affirmed the long-term ratings for LG&E's 2007 Series A pollution control bonds.
In December 2012, Fitch affirmed the issuer default ratings, individual security ratings and outlooks for LKE, LG&E and KU.
Ratings Triggers
LKE and its subsidiaries have various derivative and non-derivative contracts, including contracts for the sale and purchase of electricity, fuel, commodity transportation and storage and interest rate instruments, which contain provisions requiring LKE and its subsidiaries to post additional collateral, or permitting the counterparty to terminate the contract, if LKE's or the subsidiaries' credit rating were to fall below investment grade. See Note 19 to the Financial Statements for a discussion of "Credit Risk-Related Contingent Features," including a discussion of the potential additional collateral that would have been required for derivative contracts in a net liability position at December 31, 2012. At December 31, 2012, if LKE's or its subsidiaries' credit ratings had been below investment grade, the maximum amount that LKE would have been required to post as additional collateral to counterparties was $78 million for both derivative and non-derivative commodity and commodity-related contracts used in its generation and marketing operations, gas supply and interest rate contracts.
Off-Balance Sheet Arrangements
LKE has entered into certain agreements that may contingently require payment to a guaranteed or indemnified party. See Note 15 to the Financial Statements for a discussion of these agreements.
Risk Management
Market Risk
See Notes 1, 18 and 19 to the Financial Statements for information about LKE's risk management objectives, valuation techniques and accounting designations.
The forward-looking information presented below provides estimates of what may occur in the future, assuming certain adverse market conditions and model assumptions. Actual future results may differ materially from those presented. These disclosures are not precise indicators of expected future losses, but only indicators of possible losses under normal market conditions at a given confidence level.
Commodity Price Risk (Non-trading)
LG&E's and KU's rates are set by regulatory commissions and the fuel costs incurred are directly recoverable from customers. As a result, LG&E and KU are subject to commodity price risk for only a small portion of on-going business operations. LKE sells excess economic generation to maximize the value of the physical assets at times when the assets are not required to serve LG&E's or KU's customers. See Note 19 to the Financial Statements for additional disclosures.
The balance and change in net fair value of LKE's commodity derivative contracts for the periods ended December 31, 2012, 2011 and 2010 are shown in the table below.
| | | | | Gains (Losses) |
| | | | | Successor | | | Predecessor |
| | | | | | | | | Two Months | | | Ten Months |
| | | | | Year Ended | | Year Ended | | Ended | | | Ended |
| | | | | December 31, | | December 31, | | December 31, | | | October 31, |
| | | | | 2012 | | 2011 | | 2010 | | | 2010 |
| | | | | | | | | | | | | | | | |
Fair value of contracts outstanding at the beginning of the period | | | | | $ | (2) | | | | | | | |
Contracts realized or otherwise settled during the period | | | | | | (3) | | | | | | $ | 3 |
Fair value of new contracts entered into during the period | | | | | | | | | | | | | (4) |
Other changes in fair value (a) | | | | | | 5 | | $ | (2) | | | | 1 |
Fair value of contracts outstanding at the end of the period | | | | | $ | | | $ | (2) | | | $ | |
(a) | Represents the change in value of outstanding transactions and the value of transactions entered into and settled during the period. |
Interest Rate Risk
LKE and its subsidiaries issue debt to finance their operations, which exposes them to interest rate risk. LKE utilizes various financial derivative instruments to adjust the mix of fixed and floating interest rates in its debt portfolio when appropriate. Risk limits under LKE's risk management program are designed to balance risk, exposure to volatility in interest expense and changes in the fair value of LKE's debt portfolio due to changes in the absolute level of interest rates.
At December 31, 2012 and 2011, LKE's potential annual exposure to increased interest expense, based on a 10% increase in interest rates, was not significant.
LKE is also exposed to changes in the fair value of its debt portfolio. LKE estimated that a 10% decrease in interest rates at December 31, 2012, would increase the fair value of its debt portfolio by $113 million compared with $125 million at December 31, 2011.
LKE had the following interest rate hedges outstanding at: | | |
| | | | | | | | | | | | | | | | | | | |
| | | December 31, 2012 | | December 31, 2011 |
| | | | | | | | | Effect of a | | | | | | | | Effect of a |
| | | | | | Fair Value, | | 10% Adverse | | | | | Fair Value, | | 10% Adverse |
| | | Exposure | | Net - Asset | | Movement | | Exposure | | Net - Asset | | Movement |
| | | Hedged | | (Liability) (a) | | in Rates | | Hedged | | (Liability) (a) | | in Rates |
Economic hedges | | | | | | | | | | | | | | | | | | |
| Interest rate swaps (b) | | $ | 179 | | $ | (58) | | $ | (3) | | $ | 179 | | $ | (60) | | $ | (4) |
Cash flow hedges | | | | | | | | | | | | | | | | | | |
| Interest rate swaps (b) | | | 300 | | | 14 | | | (18) | | | | | | | | | |
(a) | Includes accrued interest. |
(b) | LKE utilizes various risk management instruments to reduce its exposure to the expected future cash flow variability of its debt instruments. These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financing. While LKE is exposed to changes in the fair value of these instruments, any realized changes in the fair value of such economic and cash flow hedges are recoverable through regulated rates and any subsequent changes in fair value of these derivatives are included in regulatory assets or liabilities. Sensitivities represent a 10% adverse movement in interest rates. The positions outstanding at December 31, 2012 mature through 2043. |
Credit Risk
LKE is exposed to potential losses as a result of nonperformance by counterparties of their contractual obligations. LKE maintains credit policies and procedures to limit counterparty credit risk including evaluating credit ratings and financial information along with having certain counterparties post margin if the credit exposure exceeds certain thresholds. LKE is exposed to potential losses as a result of nonpayment by customers. LKE maintains an allowance for doubtful accounts based on a historical charge-off percentage for retail customers. Allowances for doubtful accounts from wholesale and municipal customers and for miscellaneous receivables are based on specific identification by management. Retail, wholesale and municipal customer accounts are written-off after four months of no payment activity. Miscellaneous receivables are written-off as management determines them to be uncollectible.
Certain of LKE's derivative instruments contain provisions that require it to provide immediate and on-going collateralization of derivative instruments in net liability positions based upon LKE's credit ratings from each of the major credit rating agencies. See Notes 18 and 19 to the Financial Statements for information regarding exposure and the risk management activities.
Related Party Transactions
LKE is not aware of any material ownership interest or operating responsibility by senior management of LKE, LG&E or KU in outside partnerships, including leasing transactions with variable interest entities or other entities doing business with LKE. See Note 16 to the Financial Statements for additional information on related party transactions.
Environmental Matters
Protection of the environment is a major priority for LKE and a significant element of its business activities. Extensive federal, state and local environmental laws and regulations are applicable to LKE's air emissions, water discharges and the management of hazardous and solid waste, among other areas, and the costs of compliance or alleged non-compliance cannot be predicted with certainty but could be material. In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed from prior versions by the relevant agencies. Costs may take the form of increased capital expenditures or operating and maintenance expenses; monetary fines, penalties or forfeitures or other restrictions. Many of these environmental law considerations are also applicable to the operations of key suppliers, or customers, such as coal producers, industrial power users, etc.; and may impact the costs for their products or their demand for LKE's services.
Physical effects associated with climate change could include the impact of changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to LKE's generation assets and electricity transmission and distribution systems, as well as impacts on customers. In addition, changed weather patterns could potentially reduce annual rainfall in areas where LKE has hydro generating facilities or where river water is used to cool its fossil powered generators. LKE cannot currently predict whether its businesses will experience these potential climate change-related risks or estimate the potential cost of their related consequences.
See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for a discussion of environmental matters.
New Accounting Guidance
See Notes 1 and 24 to the Financial Statements for a discussion of new accounting guidance adopted and pending adoption.
Application of Critical Accounting Policies
Financial condition and results of operations are impacted by the methods, assumptions and estimates used in the application of critical accounting policies. The following accounting policies are particularly important to the financial condition or results of operations, and require estimates or other judgments of matters inherently uncertain. Changes in the estimates or other judgments included within these accounting policies could result in a significant change to the information presented in the Financial Statements (these accounting policies are also discussed in Note 1 to the Financial Statements). LKE's senior management has reviewed these critical accounting policies, the following disclosures regarding their application and the estimates and assumptions regarding them, with PPL's Audit Committee.
Revenue Recognition - Unbilled Revenue
Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers of LG&E's and KU's retail operations are billed on cycles which vary based on the timing of the actual reading of their electric and gas meters, LKE records estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of electricity and gas delivered to customers since the date of the last reading of their meters. The unbilled revenues reflect consideration of estimated usage by customer class, the effect of different rate schedules, changes in weather, and where applicable, the impact of weather normalization or other regulatory provisions of rate structures. In addition to the unbilled revenue accrual resulting from cycle billing, LKE makes additional accruals resulting from the timing of customer bills. The accrual of unbilled revenues in this manner properly matches revenues and related costs. At December 31, 2012 and 2011, LKE had unbilled revenue balances of $156 million and $146 million.
LKE and certain of its subsidiaries sponsor and participate in qualified funded and non-qualified unfunded defined benefit pension plans. LKE also sponsors a funded other postretirement benefit plan. These plans are applicable to the majority of the employees of LKE and its subsidiaries. LKE records an asset or liability to recognize the funded status of all defined benefit plans with an offsetting entry to OCI or regulatory assets or liabilities. Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets. See Note 13 to the Financial Statements for additional information about the plans and the accounting for defined benefits.
Certain assumptions are made by LKE and certain of its subsidiaries regarding the valuation of benefit obligations and the performance of plan assets. When accounting for defined benefits, delayed recognition in earnings of differences between actual results and expected or estimated results is a guiding principle. Annual net periodic defined benefit costs are recorded in current earnings based on estimated results. Any differences between actual and estimated results are recorded in OCI or regulatory assets and liabilities for amounts that are expected to be recovered through regulated customer rates. These amounts in regulatory assets and liabilities are amortized to income over future periods. The delayed recognition allows for a smoothed recognition of costs over the working lives of the employees who benefit under the plans. The primary assumptions are:
· | Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due. |
· | Expected Long-term Return on Plan Assets - Management projects the long-term rates of return on plan assets based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes. These projected returns reduce the net benefit costs LKE records currently. |
· | Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement. |
· | Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care. |
In selecting a discount rate for its defined benefit plans LKE starts with a cash flow analysis of the expected benefit payment stream for its plans. The plan-specific cash flows are matched against the coupons and expected maturity values of individually selected bonds. This bond matching process begins with the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, serving as the base from which those with the lowest and highest yields are eliminated to develop an appropriate subset of bonds. Individual bonds are then selected based on the timing of each plan's cash flows and parameters are established as to the percentage of each individual bond issue that could be hypothetically purchased and the surplus reinvestment rates to be assumed. At December 31, 2012, LKE decreased the discount rate for its pension plans from 5.08% to 4.24% and decreased the discount rate for its other postretirement benefit plan from 4.78% to 3.99%.
The expected long-term rates of return for LKE's defined benefit pension plans and defined other postretirement benefit plan have been developed using a best-estimate of expected returns, volatilities and correlations for each asset class. LKE management corroborates these rates with expected long-term rates of return calculated by its independent actuary, who uses a building block approach that begins with a risk-free rate of return with factors being added such as inflation, duration, credit spreads and equity risk. Each plan's specific asset allocation is also considered in developing a reasonable return assumption. At December 31, 2012, LKE's expected return on plan assets decreased from 7.25% to 7.10%.
In selecting a rate of compensation increase, LKE considers past experience in light of movements in inflation rates. At December 31, 2012, LKE's rate of compensation increase remained at 4.00%.
In selecting health care cost trend rates LKE considers past performance and forecasts of health care costs. At December 31, 2012, LKE's health care cost trend rates were 8.00% for 2013, gradually declining to 5.50% for 2019.
A variance in the assumptions listed above could have a significant impact on accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and OCI or regulatory assets and liabilities for LKE. While the charts below reflect either an increase or decrease in each assumption, the inverse of the change would impact the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and OCI or regulatory assets and liabilities for LKE by a similar amount in the opposite direction. The sensitivities below reflect an evaluation of the change based solely on a change in that assumption and does not include income tax effects.
At December 31, 2012, the defined benefit plans were recorded as follows:
Pension liabilities (a) | | $ | 417 |
Other postretirement benefit liabilities | | | 141 |
(a) | Amount includes current and noncurrent portions. |
The following chart reflects the sensitivities in the December 31, 2012 Balance Sheet associated with a change in certain assumptions based on LKE's primary defined benefit plans.
| | Increase (Decrease) |
| | | | | Impact on | | | | | Impact on |
| | Change in | | defined benefit | | Impact on | | regulatory |
Actuarial assumption | | assumption | | liabilities | | OCI | | assets |
| | | | | | | | | | | | |
Discount Rate | | | (0.25)% | | $ | 59 | | $ | (22) | | $ | 37 |
Rate of Compensation Increase | | | 0.25% | | | 10 | | | (6) | | | 4 |
Health Care Cost Trend Rate (a) | | | 1% | | | 5 | | | (1) | | | 4 |
(a) | Only impacts other postretirement benefits. |
In 2012, LKE recognized net periodic defined benefit costs charged to operating expense of $40 million. This amount represents an $11 million decrease from 2011. This decrease in expense for 2012 was primarily attributable to the increase in the expected return on plan assets resulting from pension contributions of $57 million, a reduction in the amortization of outstanding losses and lower interest cost.
The following chart reflects the sensitivities in the 2012 Statement of Income (excluding income tax effects) associated with a change in certain assumptions based on LKE's primary defined benefit plans.
Actuarial assumption | | | Change in assumption | | | Impact on defined benefit costs |
| | | | | | |
Discount Rate | | | (0.25)% | | $ | 4 |
Expected Return on Plan Assets | | | (0.25)% | | | 3 |
Rate of Compensation Increase | | | 0.25% | | | 1 |
Health Care Cost Trend Rate (a) | | | 1% | | | |
(a) | Only impacts other postretirement benefits. |
Asset Impairment (Excluding Investments)
Impairment analyses are performed for long-lived assets that are subject to depreciation or amortization whenever events or changes in circumstances indicate that a long-lived asset's carrying amount may not be recoverable. For these long-lived assets classified as held and used, such events or changes in circumstances are:
· | a significant decrease in the market price of an asset; |
· | a significant adverse change in the extent or manner in which an asset is being used or in its physical condition; |
· | a significant adverse change in legal factors or in the business climate; |
· | an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of an asset; |
· | a current-period operating or cash flow loss combined with a history of losses or a forecast that demonstrates continuing losses; or |
· | a current expectation that, more likely than not, an asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. |
For a long-lived asset classified as held and used, impairment is recognized when the carrying amount of the asset is not recoverable and exceeds its fair value. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset is impaired, an impairment loss is recorded to adjust the asset's carrying amount to its estimated fair value. Management must make significant judgments to estimate future cash flows including the useful lives of long-lived assets, the fair value of the assets and management's intent to use the assets. Alternate courses of action are considered to recover the carrying amount of a long-lived asset, and estimated cash flows from the "most likely" alternative are used to assess impairment whenever one alternative is clearly the most likely outcome. If no alternative is clearly the most likely, then a probability-weighted approach is used taking into consideration estimated cash flows from the alternatives. For assets tested for impairment as of the balance sheet date, the estimates of future cash flows used in that test consider the likelihood of possible outcomes that existed at the balance sheet date, including the assessment of the likelihood of a future sale of the assets. That assessment is not revised based on events that occur after the balance sheet date. Changes in assumptions and estimates could result in significantly different results than those identified and recorded in the financial statements.
For a long-lived asset classified as held for sale, impairment exists when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell. If the asset (disposal group) is impaired, an impairment loss is recorded to adjust the carrying amount to its fair value less cost to sell. A gain is recognized for any subsequent increase in fair value less cost to sell, but not in excess of the cumulative impairment previously recognized.
For determining fair value, quoted market prices in active markets are the best evidence. However, when market prices are unavailable, LKE considers all valuation techniques appropriate under the circumstances and for which market participant inputs can be obtained. Generally discounted cash flows are used to estimate fair value, which incorporates market participant inputs when available. Discounted cash flows are calculated by estimating future cash flow streams and applying appropriate discount rates to determine the present value of the cash flow streams.
Goodwill is tested for impairment at the reporting unit level. LKE's reporting units have been determined to be at the operating segment level. A goodwill impairment test is performed annually or more frequently if events or changes in circumstances indicate that the carrying amount of the reporting unit may be greater than the unit's fair value. Additionally, goodwill is tested for impairment after a portion of goodwill has been allocated to a business to be disposed of.
Beginning in 2012, LKE may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative assessment and directly test goodwill for impairment using a two-step quantitative test. If the qualitative evaluation (referred to as "step zero") is elected and the assessment results in a determination that it is not more likely than not the fair value of a reporting unit is less than the carrying amount, the two-step quantitative impairment test is not necessary. However, the quantitative impairment test is required if LKE concludes it is more likely than not the fair value of a reporting unit is less than the carrying amount based on the step zero assessment.
When the two-step quantitative impairment test is elected or required as a result of the step zero assessment in step one, LKE identifies a potential impairment by comparing the estimated fair value of a reporting unit with its carrying amount, including goodwill, on the measurement date. If the estimated fair value of a reporting unit exceeds its carrying amount, goodwill is not considered impaired. If the carrying amount exceeds the estimated fair value, the second step is performed to measure the amount of impairment loss, if any.
The second step of the quantitative test requires a calculation of the implied fair value of goodwill which is determined in the same manner as the amount of goodwill in a business combination. That is, the estimated fair value of a reporting unit is allocated to all of the assets and liabilities of that reporting unit as if the reporting unit had been acquired in a business combination and the estimated fair value of the reporting unit was the price paid to acquire the reporting unit. The excess of the estimated fair value of a reporting unit over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. The implied fair value of the reporting unit's goodwill is then compared with the carrying amount of that goodwill. If the carrying amount exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess. The loss recognized cannot exceed the carrying amount of the reporting unit's goodwill.
LKE elected to perform the two-step quantitative impairment test of goodwill for all of its reporting units in the fourth quarter of 2012 and no impairment was recognized. Management used both discounted cash flows and market multiples, which required significant assumptions to estimate the fair value of each reporting unit. Applying an appropriate weighting to both the discounted cash flow and market multiple valuations, a decrease in the forecasted cash flows of 10%, an increase in the discount rate by 25 basis points, or a 10% decrease in the multiples would not have resulted in an impairment of goodwill.
Loss Accruals
Losses are accrued for the estimated impacts of various conditions, situations or circumstances involving uncertain or contingent future outcomes. For loss contingencies, the loss must be accrued if (1) information is available that indicates it is probable that a loss has been incurred, given the likelihood of the uncertain future events and (2) the amount of the loss can be reasonably estimated. Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." The accrual of contingencies that might result in gains is not recorded unless recovery is assured. Potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events are continuously assessed.
The accounting aspects of estimated loss accruals include (1) the initial identification and recording of the loss, (2) the determination of triggering events for reducing a recorded loss accrual and (3) the ongoing assessment as to whether a recorded loss accrual is sufficient. All three of these aspects require significant judgment by management. Internal expertise and outside experts (such as lawyers and engineers) are used, as necessary to help estimate the probability that a loss has been incurred and the amount (or range) of the loss.
In 2012, the estimated liability for indemnifications related to the 2009 termination of the WKE lease was increased.
Certain other events have been identified that could give rise to a loss, but that do not meet the conditions for accrual. Such events are disclosed, but not recorded, when it is reasonably possible that a loss has been incurred. Accounting guidance defines "reasonably possible" as cases in which "the future event or events occurring is more than remote, but less than likely to occur."
When an estimated loss is accrued, the triggering events for subsequently adjusting the loss accrual are identified, where applicable. The triggering events generally occur when the contingency has been resolved and the actual loss is paid or written off, or when the risk of loss has diminished or been eliminated. The following are some of the triggering events that provide for the adjustment of certain recorded loss accruals:
· | Allowances for uncollectible accounts are reduced when accounts are written off after prescribed collection procedures have been exhausted, a better estimate of the allowance is determined or underlying amounts are ultimately collected. |
· | Environmental and other litigation contingencies are reduced when the contingency is resolved, LKE makes actual payments, a better estimate of the loss is determined or the loss is no longer considered probable. |
Loss accruals are reviewed on a regular basis to assure that the recorded potential loss exposures are appropriate. This involves ongoing communication and analyses with internal and external legal counsel, engineers, operation management and other parties.
See Note 15 to the Financial Statements for additional information.
Asset Retirement Obligations
LKE is required to recognize a liability for legal obligations associated with the retirement of long-lived assets. The initial obligation is measured at its estimated fair value. An equivalent amount is recorded as an increase in the value of the capitalized asset and allocated to expense over the useful life of the asset. Until the obligation is settled, the liability is increased, through the recognition of accretion expense in the Consolidated Statements of Income, for changes in the obligation due to the passage of time. Since costs of removal are collected in rates, the accretion and depreciation are offset with a regulatory credit on the income statement, such that there is no earnings impact. The regulatory asset created by the
regulatory credit is relieved when the ARO has been settled. An ARO must be recognized when incurred if the fair value of the ARO can be reasonably estimated. See Note 21 to the Financial Statements for related disclosures.
In determining AROs, management must make significant judgments and estimates to calculate fair value. Fair value is developed using an expected present value technique based on assumptions of market participants that considers estimated retirement costs in current period dollars that are inflated to the anticipated retirement date and then discounted back to the date the ARO was incurred. Changes in assumptions and estimates included within the calculations of the fair value of AROs could result in significantly different results than those identified and recorded in the financial statements. Estimated ARO costs and settlement dates, which affect the carrying value of various AROs and the related assets, are reviewed periodically to ensure that any material changes are incorporated into the estimate of the obligations. Any change to the capitalized asset is amortized over the remaining life of the associated long-lived asset.
At December 31, 2012, LKE had AROs comprised of current and noncurrent amounts, totaling $131 million recorded on the Balance Sheet. Of the total amount, $90 million, or 69%, relates to LKE's ash ponds, landfills and natural gas mains. The most significant assumptions surrounding AROs are the forecasted retirement costs, the discount rates and the inflation rates. A variance in the forecasted retirement costs, the discount rates or the inflation rates could have a significant impact on the ARO liabilities.
The following chart reflects the sensitivities related to LKE's ARO liabilities for ash ponds, landfills and natural gas mains at December 31, 2012:
| | Change in | | Impact on |
| | Assumption | | ARO Liability |
| | | | | | |
Retirement Cost | | | 10% | | $ | 11 |
Discount Rate | | | (0.25)% | | | 3 |
Inflation Rate | | | 0.25% | | | 8 |
Significant management judgment is required in developing the provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination of deferred tax assets, liabilities and valuation allowances.
Significant management judgment is required to determine the amount of benefit recognized related to an uncertain tax position. Tax positions are evaluated following a two-step process. The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained. This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position. The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion. The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization, upon settlement, that exceeds 50%. Management considers a number of factors in assessing the benefit to be recognized, including negotiation of a settlement.
On a quarterly basis, uncertain tax positions are reassessed by considering information known at the reporting date. Based on management's assessment of new information, a tax benefit may subsequently be recognized for a previously unrecognized tax position, a previously recognized tax position may be derecognized, or the benefit of a previously recognized tax position may be remeasured. The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements in the future.
At December 31, 2012, LKE's existing reserve exposure to either increases or decreases in unrecognized tax benefits during the next 12 months is $1 million. This change could result from subsequent recognition, derecognition and/or changes in the measurement of uncertain tax positions. The events that could cause these changes are direct settlements with taxing authorities, litigation, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.
The balance sheet classification of unrecognized tax benefits and the need for valuation allowances to reduce deferred tax assets also require significant management judgment. Unrecognized tax benefits are classified as current to the extent management expects to settle an uncertain tax position by payment or receipt of cash within one year of the reporting date. Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset. Management considers a number of factors in assessing the realization of a deferred tax asset, including the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies. Any tax planning strategy utilized in this assessment must meet the recognition and measurement criteria utilized to account for an uncertain tax position. See Note 5 to the Financial Statements for related disclosures.
Regulatory Assets and Liabilities
LKE's subsidiaries, LG&E and KU, are cost-based rate-regulated utilities. As a result, the effects of regulatory actions are required to be reflected in the financial statements. Assets and liabilities are recorded that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in regulated customer rates. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. In certain cases, regulatory liabilities are recorded based on an understanding with the regulator that rates have been set to recover costs that are expected to be incurred in the future, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose. The accounting for regulatory assets and liabilities is based on specific ratemaking decisions or precedent for each transaction or event as prescribed by the FERC, the KPSC, the VSCC and the TRA.
Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory and political environments, the ability to recover costs through regulated rates, recent rate orders to other regulated entities and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, then asset write-off would be required to be recognized in operating income. Additionally, the regulatory agencies can provide flexibility in the manner and timing of the depreciation of PP&E and amortization of regulatory assets.
At December 31, 2012, LKE had regulatory assets of $649 million and regulatory liabilities of $1,011 million. All regulatory assets are either currently being recovered under specific rate orders, represent amounts that are expected to be recovered in future rates or benefit future periods based upon established regulatory practices.
See Note 6 to the Financial Statements for additional information on regulatory assets and liabilities.
Other Information
PPL's Audit Committee has approved the independent auditor to provide audit, tax and other services permitted by Sarbanes-Oxley and SEC rules. The audit services include services in connection with statutory and regulatory filings, reviews of offering documents and registration statements, and internal control reviews. See "Item 14. Principal Accounting Fees and Services" for more information.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The information provided in this Item 7 should be read in conjunction with LG&E's Financial Statements and the accompanying Notes. Capitalized terms and abbreviations are defined in the glossary. Dollars are in millions, unless otherwise noted.
"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:
· | "Overview" provides a description of LG&E and its business strategy, a summary of Net Income and a discussion of certain events related to LG&E's results of operations and financial condition. |
· | "Results of Operations" provides a summary of LG&E's earnings and a description of key factors expected to impact future earnings. This section ends with explanations of significant changes in principal items on LG&E's Statements of Income, comparing 2012 with 2011 and 2011 with 2010. |
· | "Financial Condition - Liquidity and Capital Resources" provides an analysis of LG&E's liquidity position and credit profile. This section also includes a discussion of forecasted sources and uses of cash and rating agency actions. |
· | "Financial Condition - Risk Management" provides an explanation of LG&E's risk management programs relating to market and credit risk. |
· | "Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of LG&E and that require its management to make significant estimates, assumptions and other judgments of matters inherently uncertain.
|
Overview
Introduction
LG&E, headquartered in Louisville, Kentucky, is a regulated utility engaged in the generation, transmission, distribution and sale of electric energy and distribution and sale of natural gas in Kentucky. LG&E and its affiliate, KU, are wholly owned subsidiaries of LKE. LKE, a holding company, became a wholly owned subsidiary of PPL when PPL acquired all of LKE's interests from E.ON US Investments Corp. on November 1, 2010. Following the acquisition, both LG&E and KU continue operating as subsidiaries of LKE, which is now an intermediary holding company in PPL's group of companies. Refer to "Item 1. Business - Background" for a description of LG&E's business.
Business Strategy
LG&E's overall strategy is to provide reliable, safe, competitively priced energy to its customers and reasonable returns on regulated investments to its shareowner.
A key objective for LG&E is to maintain a strong credit profile through managing financing costs and access to credit markets. LG&E continually focuses on maintaining an appropriate capital structure and liquidity position.
Successor and Predecessor Financial Presentation
LG&E's Financial Statements and related financial and operating data include the periods before and after PPL's acquisition of LKE on November 1, 2010 and have been segregated to present pre-acquisition activity as the Predecessor and post-acquisition activity as the Successor. Certain accounting and presentation methods were changed to acceptable alternatives to conform to PPL's accounting policies, and the cost bases of certain assets and liabilities were changed as of November 1, 2010 as a result of the application of push-down accounting. Consequently, the financial position, results of operations and cash flows for the Successor periods are not comparable to the Predecessor periods; however, the core operations of LG&E have not changed as a result of the acquisition.
Financial and Operational Developments
Net Income
Net Income for 2012, 2011 and 2010 was $123 million, $124 million and $128 million. Earnings in 2012 decreased 1% from 2011 and earnings in 2011 decreased 3% from 2010.
See "Results of Operations" for a discussion and analysis of LG&E's earnings.
Rate Case Proceedings
In June 2012, LG&E filed a request with the KPSC for an increase in annual base electric rates of approximately $62 million and an increase in annual base gas rates of approximately $17 million. In November 2012, LG&E along with all of the parties filed a unanimous settlement agreement. Among other things, the settlement provided for increases in annual base electric rates of $34 million and an increase in annual base gas rates of $15 million. The settlement agreement also included revised depreciation rates that result in reduced annual electric depreciation expense of approximately $9 million. The settlement agreement included an authorized return on equity of 10.25%. On December 20, 2012, the KPSC issued an order approving the provisions in the settlement agreement. The new rates became effective on January 1, 2013. In addition to the increased base rates, the KPSC approved a gas line tracker mechanism to provide for recovery of costs associated with LG&E's gas main replacement program, gas service lines and risers.
Commercial Paper
In February 2012, LG&E established a commercial paper program for up to $250 million to provide an additional financing source to fund its short-term liquidity needs, if and when necessary. Commercial paper issuances are supported by LG&E's Syndicated Credit Facility. At December 31, 2012, LG&E had $55 million of commercial paper outstanding.
Terminated Bluegrass CTs Acquisition
In September 2011, LG&E and KU entered into an asset purchase agreement with Bluegrass Generation for the purchase of the Bluegrass CTs, aggregating approximately 495 MW, plus limited associated contractual arrangements required for operation of the units, for a purchase price of $110 million, pending receipt of applicable regulatory approvals. In May 2012, the KPSC issued an order approving the request to purchase the Bluegrass CTs. In November 2011, LG&E and KU filed an application with the FERC under the Federal Power Act requesting approval to purchase the Bluegrass CTs. In May 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to approval by the FERC of satisfactory mitigation measures to address market-power concerns. After a review of potentially available mitigation options, LG&E and KU determined that the options were not commercially justifiable. In June 2012, LG&E and KU terminated the asset purchase agreement for the Bluegrass CTs in accordance with its terms and made applicable filings with the KPSC and FERC.
Cane Run Unit 7 Construction
In September 2011, LG&E and KU filed a CPCN with the KPSC requesting approval to build Cane Run Unit 7. In May 2012, the KPSC issued an order approving the request. LG&E will own a 22% undivided interest and KU will own a 78% undivided interest in the new generating unit. A formal request for recovery of the costs associated with the construction was not included in the CPCN filing with the KPSC but is expected to be included in future rate case proceedings. LG&E and KU commenced preliminary construction activities in the third quarter of 2012 and project construction is expected to be completed by May 2015. The project, which includes building a natural gas supply pipeline and related transmission projects, has an estimated cost of approximately $600 million.
In conjunction with this construction and to meet new, more stringent EPA regulations with a 2015 compliance date, LG&E anticipates retiring three older coal-fired electric generating units at the Cane Run plant, which have a combined summer capacity rating of 563 MW.
Future Capacity Needs
In addition to the construction of a combined cycle gas unit at the Cane Run station, LG&E and KU continue to assess future capacity needs. As a part of the assessment, LG&E and KU issued an RFP in September 2012 for up to 700 MW of capacity beginning as early as 2015.
Results of Operations
As previously noted, LG&E's results for the periods after October 31, 2010 are on a basis of accounting different from its results for periods prior to November 1, 2010. See "Overview - Successor and Predecessor Financial Presentation" for further information.
The utility business is affected by seasonal weather. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year. Revenue and earnings are generally higher during the first and third quarters and lower during the second and fourth quarters due to weather.
The following table summarizes the significant components of net income for 2012, 2011 and 2010 and the changes therein:
Earnings
| | | | Successor | | | Predecessor |
| | | | | | | | Two Months | | | Ten Months |
| | | | Year Ended | | Year Ended | | Ended | | | Ended |
| | | | December 31, | | December 31, | | December 31, | | | October 31, |
| | | | 2012 | | 2011 | | 2010 | | | 2010 |
| | | | | | | | | | | | | | | |
| Net Income | | $ | 123 | | $ | 124 | | $ | 19 | | | $ | 109 |
The changes in the components of Net Income between these periods were due to the following factors, which reflect reclassifications for items included in Margins and certain items that management considers special.
| | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | |
Margins | | $ | 3 | | $ | 39 |
Other operation and maintenance | | | 3 | | | (10) |
Depreciation | | | (4) | | | (13) |
Taxes, other than income | | | (5) | | | (5) |
Other Income (Expense) - net | | | (1) | | | (16) |
Other | | | 4 | | | (1) |
Special items, after-tax | | | (1) | | | 2 |
Total | | $ | (1) | | $ | (4) |
The net unrealized gains (losses) on contracts that economically hedge anticipated cash flows are considered special items by management. There were no unrealized gains (losses) in 2012.
· | See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Margins. |
· | Higher other operation and maintenance in 2011 compared with 2010 primarily due to higher distribution maintenance costs of $8 million due to amortization of storm restoration related costs and a hazardous tree removal project initiated in August 2010. |
· | Higher depreciation in 2011 compared with 2010 primarily due to TC2 commencing dispatch in January 2011. |
· | Lower other income (expense) - net in 2011 compared with 2010 primarily due to $19 million of other income from the establishment of a regulatory asset in 2010 for previously recorded losses on interest rate swaps. |
2013 Outlook
Excluding special items, LG&E projects higher earnings in 2013 compared with 2012, primarily driven by electric and gas base rate increases effective January 1, 2013, returns on additional environmental capital investments and retail load growth, partially offset by higher operation and maintenance.
Earnings in future periods are subject to various risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Notes 6 and 15 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.
Statement of Income Analysis --
Margins
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as a non-GAAP financial measure, "Margins." Margins is not intended to replace "Operating Income," which is determined in accordance with GAAP as an indicator of overall operating performance. Other companies may use different measures to analyze and to report on the results of their operations. Margins is a single financial performance measure of LG&E's electricity generation, transmission and distribution operations as well as its distribution and sale of natural gas. In calculating this measure, fuel and energy purchases are deducted from revenues. In addition, utility revenues and expenses associated with approved cost recovery mechanisms are offset. These mechanisms allow for recovery of certain expenses, returns on capital investments primarily associated with environmental regulations and performance incentives. Certain costs associated with these mechanisms, primarily ECR and DSM, are recorded as "Other operation and maintenance" and "Depreciation." As a result, this measure represents the net revenues from LG&E's operations. This performance measure is used, in conjunction with other information, internally by senior management to manage operations and analyze actual results compared with budget.
Reconciliation of Non-GAAP Financial Measures
The following tables reconcile "Operating Income" to "Margins" as defined by LG&E for 2012, 2011 and 2010.
| | | | | | 2012 Successor | | | | 2011 Successor |
| | | | | | | | | | | Operating | | | | | | | | | Operating |
| | | | | | Margins | | Other (a) | | Income (b) | | | | Margins | | Other (a) | | Income (b) |
| | | | | | | | | | | | | | | | | | |
Operating Revenues | | $ | 1,324 | | | | | $ | 1,324 | | | | $ | 1,363 | | $ | 1 | | $ | 1,364 |
Operating Expenses | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 374 | | | | | | 374 | | | | | 350 | | | | | | 350 |
| Energy purchases | | | 175 | | | | | | 175 | | | | | 245 | | | | | | 245 |
| Other operation and maintenance | | | 45 | | $ | 318 | | | 363 | | | | | 42 | | | 321 | | | 363 |
| Depreciation | | | 3 | | | 149 | | | 152 | | | | | 2 | | | 145 | | | 147 |
| Taxes, other than income | | | | | | 23 | | | 23 | | | | | | | | 18 | | | 18 |
| | | Total Operating Expenses | | | 597 | | | 490 | | | 1,087 | | | | | 639 | | | 484 | | | 1,123 |
Total | | $ | 727 | | $ | (490) | | $ | 237 | | | | $ | 724 | | $ | (483) | | $ | 241 |
| | | | | | Successor | | | Predecessor |
| | | | | | Two Months Ended December 31, 2010 | | | Ten Months Ended October 31, 2010 |
| | | | | | | | | | | Operating | | | | | | | | | Operating |
| | | | | | Margins | | Other (a) | | Income (b) | | | Margins | | Other (a) | | Income (b) |
| | | | | | | | | | | | | | | | | | |
Operating Revenues | | $ | 255 | | $ | (1) | | $ | 254 | | | $ | 1,057 | | | | | $ | 1,057 |
Operating Expenses | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 60 | | | | | | 60 | | | | 306 | | | | | | 306 |
| Energy purchases | | | 63 | | | | | | 63 | | | | 155 | | | | | | 155 |
| Other operation and maintenance | | | 9 | | | 58 | | | 67 | | | | 28 | | $ | 253 | | | 281 |
| Depreciation | | | | | | 23 | | | 23 | | | | 6 | | | 109 | | | 115 |
| Taxes, other than income | | | | | | 1 | | | 1 | | | | | | | 12 | | | 12 |
| | | Total Operating Expenses | | | 132 | | | 82 | | | 214 | | | | 495 | | | 374 | | | 869 |
Total | | $ | 123 | | $ | (83) | | $ | 40 | | | $ | 562 | | $ | (374) | | $ | 188 |
(a) | Represents amounts excluded from Margins. |
(b) | As reported on the Statements of Income. |
Changes in Non-GAAP Financial Measures
Margins increased by $3 million for 2012 compared with 2011, primarily due to $9 million of higher retail margins as a result of new environmental investments. This increase was partially offset by lower wholesale margins of $6 million as volumes were impacted by lower market prices. Retail volumes were consistent with the prior year as increased industrial sales offset declines associated with unseasonably mild weather during the first four months of 2012. Total heating degree days decreased 13% compared to 2011, partially offset by a 7% increase in cooling degree days.
Margins increased by $39 million for 2011 compared with 2010. New KPSC rates went into effect on August 1, 2010, contributing to an additional $48 million in operating revenue over the prior year. Partially offsetting the rate increase were lower retail volumes resulting from weather and economic conditions.
Other Operation and Maintenance | | | | | |
| | | | | | |
The increase (decrease) in other operation and maintenance was due to: |
| | |
| | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | |
Administrative and general (a) | $ | (5) | | $ | 4 |
Distribution maintenance (b) | | (1) | | | 8 |
Fuel for generation (c) | | | | | 5 |
Coal plant maintenance (d) | | 2 | | | (5) |
Other | | 4 | | | 3 |
Total | $ | | | $ | 15 |
(a) | Administrative and general costs decreased in 2012 compared with 2011 primarily due to a decrease in pension expense resulting from pension funding and lower interest cost. |
(b) | Distribution maintenance costs increased in 2011 compared with 2010 primarily due to amortization of storm restoration-related costs, a hazardous tree removal project initiated in August 2010 and an increase in pipeline integrity work. |
(c) | Fuel handling costs are included in other operation and maintenance on the Statements of Income for the Successor periods and are in fuel on the Statement of Income for the Predecessor period. |
(d) | Coal plant maintenance costs increased in 2012 compared with 2011 primarily due to an increased scope of scheduled outages. |
Coal plant maintenance costs decreased in 2011 compared with 2010 primarily due to the timing of scheduled maintenance outages and non-outage boiler maintenance.
Depreciation
Depreciation increased by $5 million in 2012 compared with 2011 due to PP&E additions.
Depreciation increased by $9 million in 2011 compared with 2010 primarily due to TC2 commencing dispatch in January 2011.
Taxes, Other Than Income
Taxes, other than income increased by $5 million in 2012 compared with 2011 due in part to a $2 million increase in property taxes resulting from property additions, higher assessed values and changes in property classifications to categories with higher tax rates.
Taxes, other than income increased by $5 million in 2011 compared with 2010 primarily due to a $4 million state coal tax credit that was applied to 2010 property taxes. The remaining increase was due to higher assessments, primarily from significant property additions.
Other Income (Expense) - net
Other income (expense) - net decreased by $16 million in 2011 compared with 2010 primarily due to $19 million of other income from the establishment of a regulatory asset for previously recorded losses on interest rate swaps in 2010.
Interest Expense
The increase (decrease) in interest expense was due to:
| | | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | | |
Interest rates (a) | | $ | (2) | | $ | (7) |
Long-term debt balances (b) | | | | | | 2 |
Other | | | | | | 3 |
Total | | $ | (2) | | $ | (2) |
(a) | Interest expense decreased in 2011 compared with 2010 due to lower interest rates on first mortgage bonds issued in November 2010 compared with the rates on the loans from E.ON AG affiliates that were in place through October 2010. |
(b) | Interest expense increased in 2011 compared with 2010 due to lower long-term debt balances for the first ten months of 2010. |
Financial Condition
Liquidity and Capital Resources
LG&E expects to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents and its credit facilities, including commercial paper issuances. Additionally, subject to market conditions, LG&E currently plans to access capital markets in 2013.
LG&E's cash flows from operations and access to cost-effective bank and capital markets are subject to risks and uncertainties including, but not limited to:
· | changes in commodity prices that may increase the cost of producing or purchasing power or decrease the amount LG&E receives from selling power; |
· | operational and credit risks associated with selling and marketing products in the wholesale power markets; |
· | unusual or extreme weather that may damage LG&E's transmission and distribution facilities or affect energy sales to customers; |
· | reliance on transmission facilities that LG&E does not own or control to deliver its electricity and natural gas; |
· | unavailability of generating units (due to unscheduled or longer-than-anticipated generation outages, weather and natural disasters) and the resulting loss of revenues and additional costs of replacement electricity; |
· | the ability to recover and the timeliness and adequacy of recovery of costs associated with regulated utility businesses; |
· | costs of compliance with existing and new environmental laws; |
· | any adverse outcome of legal proceedings and investigations with respect to LG&E's current and past business activities; |
· | deterioration in the financial markets that could make obtaining new sources of bank and capital markets funding more difficult and more costly; and |
· | a downgrade in LG&E's credit ratings that could adversely affect its ability to access capital and increase the cost of credit facilities and any new debt. |
See "Item 1A. Risk Factors" for further discussion of risks and uncertainties affecting LG&E's cash flows.
At December 31, LG&E had the following:
| | | | |
| | 2012 | | 2011 | | 2010 |
| | | | | | | | | |
Cash and cash equivalents | | $ | 22 | | $ | 25 | | $ | 2 |
Short-term investments (a) | | | | | | | | | 163 |
| | $ | 22 | | $ | 25 | | $ | 165 |
| | | | | | | | | |
Short-term debt (b) | | $ | 55 | | | | | $ | 163 |
(a) | Represents tax-exempt bonds issued by Louisville/Jefferson County, Kentucky, on behalf of LG&E that were purchased from the remarketing agent in 2008. Such bonds were remarketed to unaffiliated investors in January 2011. See Note 7 to the Financial Statements for additional information. |
(b) | Borrowings in 2012 were made under LG&E's commercial paper program and borrowings in 2010 were made under LG&E's syndicated credit facility. See Note 7 to the Financial Statements for additional information. |
The changes in LG&E's cash and cash equivalents position resulted from: |
| | | | | Successor | | | Predecessor |
| | | | | | | | | Two Months | | | Ten Months |
| | | | | Year Ended | | Year Ended | | Ended | | | Ended |
| | | | | December 31, | | December 31, | | December 31, | | | October 31, |
| | | | | 2012 | | 2011 | | 2010 | | | 2010 |
| | | | | | | | | | | | | |
Net cash provided by (used in) operating activities | | $ | 308 | | $ | 325 | | $ | (8) | | | $ | 189 |
Net cash provided by (used in) investing activities | | | (289) | | | (42) | | | (63) | | | | (107) |
Net cash provided by (used in) financing activities | | | (22) | | | (260) | | | 69 | | | | (83) |
Net Increase (Decrease) in Cash and Cash Equivalents | | $ | (3) | | $ | 23 | | $ | (2) | | | $ | (1) |
Operating Activities
Net cash provided by operating activities decreased by 5%, or $17 million, in 2012 compared with 2011, primarily as a result of:
· | Working capital cash flow changes declined by $65 million driven primarily by changes in receivables and unbilled revenues due to milder December weather in 2011 than in 2012 and 2010, and lower inventory levels in 2011 as compared with 2010 driven by lower gas prices. |
· | The decline was offset by $44 million increase in other operating cash flows driven by $43 million reduction in pension funding. |
Net cash provided by operating activities increased by 80%, or $144 million, in 2011 compared with 2010, primarily as a result of:
· | a decrease in working capital related to accounts receivable and unbilled revenues of $86 million primarily due to the timing of cash receipts and colder weather in December 2010 as compared with December 2009 and milder weather in December 2011 as compared with December 2010; |
· | an increase in net income adjusted for non-cash effects of $34 million (the recording of a regulatory asset for previously recorded losses on interest rate swaps of $22 million, deferred income taxes and investment tax credits of $17 million, depreciation of $9 million, partially offset by unrealized (gains) losses on derivatives of $14 million, defined benefit plans - expense of $3 million and other noncash items of $3 million); |
· | a decrease in cash outflows of $32 million due to lower inventory levels in 2011 as compared with 2010 driven by $21 million due to lower coal burn as a result of unplanned outages at the Mill Creek plant, $8 million for fuel inventory purchased in 2010 for TC2 that was not used until 2011 when TC2 began dispatch and $6 million for decreases in gas storage volumes; |
· | a decrease in cash refunded to customers of $25 million due to prior period over-recoveries related to the gas supply clause filings in 2009; and |
· | a decrease in cash outflows related to accrued taxes of $22 million due to the timing of payments of accrued tax liabilities in 2011 and 2010; partially offset by |
· | an increase in discretionary defined benefit plan contributions of $44 million made in order to achieve LG&E's long-term funding requirements; and |
· | an increase in working capital related to accounts payable of $41 million, which was driven primarily by the timing of cash payments and a decrease in natural gas purchases of $18 million in 2011 as compared with 2010 due to a decrease in combustion turbine generation as a result of the dispatch of TC2 beginning in January 2011. |
Investing Activities
Net cash used in investing activities increased by $247 million, in 2012 compared with 2011, primarily as a result of:
· | a decrease in the proceeds from the sale of other investments of $163 million in 2011; and |
· | an increase in capital expenditures of $90 million due primarily to construction of Cane Run Unit 7 and Mill Creek environmental air projects. |
Net cash used in investing activities decreased by 75%, or $128 million, in 2011 compared with 2010, as a result of:
· | proceeds from the sale of other investments of $163 million in 2011; and |
· | a decrease in capital expenditures of $24 million due primarily to TC2 being dispatched in 2011; partially offset by |
· | proceeds from the sale of assets of $48 million in 2010; and |
· | a decrease in restricted cash of $11 million. |
See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 2013 through 2017.
Financing Activities
Net cash used in financing activities was $22 million, in 2012 compared with $260 million in 2011, primarily as a result of changes in short-term debt.
In 2012, cash used in financing activities consisted of:
· | the payment of common stock dividends to LKE of $75 million; partially offset by |
· | the issuance of short-term debt in the form of commercial paper of $55 million. |
Net cash used in financing activities was $260 million, in 2011 compared with $14 million in 2010, primarily as a result of changes in short-term debt.
In 2011, cash used in financing activities consisted of:
· | a repayment on a revolving line of credit of $163 million; |
· | the payment of common stock dividends to LKE of $83 million; |
· | a net decrease in notes payable with affiliates of $12 million; and |
· | the payment of debt issuance and credit facility costs of $2 million. |
In the two months of 2010 following PPL's acquisition of LKE, cash provided by financing activities of the Successor consisted of:
· | the issuance of first mortgage bonds of $531 million after discounts; |
· | the issuance of debt of $485 million to a PPL affiliate to repay debt due to an E.ON AG affiliate upon the closing of PPL's acquisition of LKE; and |
· | a draw on a revolving line of credit of $163 million; partially offset by |
· | the repayment of debt to an E.ON AG affiliate of $485 million upon the closing of PPL's acquisition of LKE; |
· | the repayment of debt to a PPL affiliate of $485 million upon the issuance of first mortgage bonds; |
· | a net decrease in notes payable with affiliates of $130 million; and |
· | the payment of debt issuance and credit facility costs of $10 million. |
In the ten months of 2010 preceding PPL's acquisition of LKE, cash used in financing activities by the Predecessor consisted of:
· | the payment of common stock dividends to LKE of $55 million and |
· | a net decrease in notes payable with affiliates of $28 million. |
See "Forecasted Sources of Cash" for a discussion of LG&E's plans to issue debt securities, as well as a discussion of credit facility capacity available to LG&E. Also see "Forecasted Uses of Cash" for a discussion of plans to pay dividends on common securities in the future, as well as maturities of long-term debt.
LG&E had no long-term debt securities activity during the year.
See Note 7 to the Financial Statements for additional information about long-term debt securities.
Auction Rate Securities
At December 31, 2012, LG&E's tax-exempt revenue bonds that are in the form of auction rate securities and total $135 million continue to experience failed auctions. Therefore, the interest rate continues to be set by a formula pursuant to the relevant indentures. For the period ended December 31, 2012, the weighted-average rate on LG&E's auction rate bonds in total was 0.20%.
Forecasted Sources of Cash
LG&E expects to continue to have sufficient sources of cash available in the near term, including various credit facilities, its commercial paper program, issuance of debt securities and operating cash flow.
Credit Facilities
At December 31, 2012, LG&E's total committed borrowing capacity under its Syndicated Credit Facility and the use of this borrowing capacity were:
| | | | | Commercial | | Letters of | | Unused |
| | | Capacity | | Paper Issued | | Credit Issued | | Capacity |
| | | | | | | | | |
Syndicated Credit Facility (a) (b) (c) | | $ | 500 | | $ | 55 | | | | | $ | 445 |
(a) | The commitments under LG&E's Syndicated Credit Facility are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than 6% of the total committed capacity available to LG&E. |
(b) | In November 2012, LG&E amended the Syndicated Credit Facility to extend the expiration date to November 2017. In addition, LG&E increased the credit facility capacity to $500 million. |
(c) | LG&E pays customary fees under its syndicated credit facility, and borrowings generally bear interest at LIBOR-based rates plus an applicable margin. |
LG&E participates in an intercompany money pool agreement whereby LKE and/or KU make available to LG&E funds up to $500 million at an interest rate based on a market index of commercial paper issues. At December 31, 2012, there was no balance outstanding.
See Note 7 to the Financial Statements for further discussion of LG&E's credit facilities.
Operating Leases
LG&E also has available funding sources that are provided through operating leases. LG&E leases office space, gas storage and certain equipment. These leasing structures provide LG&E additional operating and financing flexibility. The operating leases contain covenants that are typical for these agreements, such as maintaining insurance, maintaining corporate existence and timely payment of rent and other fees.
See Note 11 to the Financial Statements for further discussion of the operating leases.
Capital Contributions from LKE
From time to time LKE may make capital contributions to LG&E. LG&E may use these contributions to fund capital expenditures and for other general corporate purposes.
Long-term Debt Securities
LG&E currently plans to issue, subject to market conditions, up to $350 million of first mortgage bond indebtedness in 2013, the proceeds of which will be used to fund capital expenditures and for other general corporate purposes.
Forecasted Uses of Cash
In addition to expenditures required for normal operating activities, such as purchased power, payroll, fuel and taxes, LG&E currently expects to incur future cash outflows for capital expenditures, various contractual obligations, payment of dividends on its common stock and possibly the purchase or redemption of a portion of debt securities.
Capital Expenditures
The table below shows LG&E's current capital expenditure projections for the years 2013 through 2017.
| | | | Projected |
| | | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
Capital expenditures (a) | | | | | | | | | | | | | | | |
| Generating facilities | | $ | 138 | | $ | 111 | | $ | 131 | | $ | 225 | | $ | 232 |
| Distribution facilities | | | 144 | | | 140 | | | 166 | | | 165 | | | 174 |
| Transmission facilities | | | 59 | | | 31 | | | 19 | | | 16 | | | 16 |
| Environmental | | | 324 | | | 336 | | | 249 | | | 186 | | | 42 |
| Other | | | 22 | | | 22 | | | 20 | | | 23 | | | 19 |
| | Total Capital Expenditures | | $ | 687 | | $ | 640 | | $ | 585 | | $ | 615 | | $ | 483 |
(a) | LG&E generally expects to recover these costs over a period equivalent to the related depreciable lives of the assets through rates. The 2013 total excludes amounts included in accounts payable as of December 31, 2012. |
LG&E's capital expenditure projections for the years 2013 through 2017 total approximately $3.0 billion. Capital expenditure plans are revised periodically to reflect changes in operational, market and regulatory conditions. This table includes current estimates for LG&E's environmental projects related to existing and proposed EPA compliance standards. Actual costs may be significantly lower or higher depending on the final requirements and market conditions. Environmental compliance costs incurred by LG&E in serving KPSC jurisdictional customers are generally eligible for recovery through the ECR mechanism.
LG&E plans to fund its capital expenditures in 2013 with cash on hand, cash from operations, short-term debt and issuance of debt securities.
Contractual Obligations
LG&E hasTalen Energy Supply and its subsidiaries have assumed various financial obligations and commitments in the ordinary course of conducting its business. At December 31, 2012, the2015, estimated contractual cash obligations of LG&E were:were as follows.
|
| | | | | | | | | | | | | | | | | | | | |
| | Total | | 2016 | | 2017-2018 | | 2019-2020 | | After 2020 |
Long-term Debt (a) | | $ | 4,228 |
| | $ | 396 |
| | $ | 429 |
| | $ | 1,423 |
| | $ | 1,980 |
|
Interest on Long-term Debt (b) | | 1,560 |
| | 236 |
| | 408 |
| | 306 |
| | 610 |
|
Operating Leases (c) | | 81 |
| | 19 |
| | 26 |
| | 10 |
| | 26 |
|
Purchase Obligations (d) | | 2,703 |
| | 621 |
| | 948 |
| | 319 |
| | 815 |
|
Other Long-term Liabilities Reflected on the Balance Sheet under GAAP (e)(f) | | 40 |
| | 40 |
| | — |
| | — |
| | — |
|
Total Contractual Cash Obligations | | $ | 8,612 |
| | $ | 1,312 |
| | $ | 1,811 |
| | $ | 2,058 |
| | $ | 3,431 |
|
| | | | Total | | 2013 | | 2014 - 2015 | | 2016 - 2017 | | After 2017 |
| | | | | | | | | | | | | | | | | |
Long-term Debt (a) | | $ | 1,109 | | | | | $ | 250 | | | | | $ | 859 |
Interest on Long-term Debt (b) | | | 839 | | $ | 37 | | | 70 | | $ | 66 | | | 666 |
Operating Leases (c) | | | 35 | | | 5 | | | 11 | | | 5 | | | 14 |
Coal and Natural Gas Purchase | | | | | | | | | | | | | | | |
| | Obligations (d) | | | 1,512 | | | 378 | | | 697 | | | 345 | | | 92 |
Unconditional Power Purchase | | | | | | | | | | | | | | | |
| | Obligations (e) | | | 719 | | | 21 | | | 42 | | | 44 | | | 612 |
Construction Obligations (f) | | | 735 | | | 382 | | | 273 | | | 80 | | | |
Pension Benefit Plan Obligations (g) | 42 | | | 42 | | | | | | | | | |
Other Obligations (h) | | | 8 | | | 2 | | | 4 | | | 2 | | | |
Total Contractual Cash Obligations | | $ | 4,999 | | $ | 867 | | $ | 1,347 | | $ | 542 | | $ | 2,243 |
| |
(a) | Reflects principal maturities only based on stated maturity dates. 2016 includes the $41 million redemption of the Senior Secured Notes of a Talen Ironwood Holdings, LLC subsidiary. See Note 75 to the Financial Statements for a discussion of variable-rate remarketable bonds issued on behalf of LG&E. LG&E has noadditional information. Talen Energy does not have any significant capital lease obligations. |
| |
(b) | Assumes interest payments through stated maturity.maturity or earlier put dates. The payments herein are subject to change, as payments for debt that is or becomes variable-rate debt have been estimated. |
(c) | 2016 includes the $14 million make whole premium paid in connection with the redemption of the Senior Secured Notes of a Talen Ironwood Holdings, LLC subsidiary. See Note 115 to the Financial Statements for additional information. |
(d) | Represents contracts to purchase coal, natural gas and natural gas transportation. |
(c) | See Note 157 to the Financial Statements for additional information. |
| |
(d) | The amounts primarily include as applicable, the purchase obligations of electricity, coal, nuclear fuel and limestone as well as certain construction expenditures, which are also included in the "Capital Expenditures" table presented above. Financial swaps and open purchase orders that are provided on demand with no firm commitment are excluded from the amounts presented. The amounts also include a $132 million contract related to the Ironwood facility, which was sold in February 2016. |
| |
(e) | RepresentsThe amounts include Talen Energy's contributions committed to be made in 2016 for its pension plans. |
| |
(f) | At December 31, 2015, total unrecognized tax benefits of $31 million were excluded from this table as management cannot reasonably estimate the amount and period of future minimum payments under OVEC power purchase agreements through June 2040.payments. See Note 154 to the Financial Statements for additional information. |
(f) | Represents construction commitments, including commitments for the Mill Creek environmental air projects, Cane Run Unit 7 and Ohio Falls refurbishment which are also reflected in the Capital Expenditures table presented above. |
(g) | Based on the current funded status of LG&E's qualified pension plan and LKE's qualified pension plan, which covers LG&E employees, no cash contributions are required. See Note 13 to the Financial Statements for a discussion of expected contributions. |
(h) | Represents other contractual obligations. |
Dividends/Distributions
Dividends
Talen Energy Corporation does not expect to pay dividends in 2016. From time to time, as determined by its Board of Directors, LG&E pays dividendsManagers, Talen Energy Supply may pay distributions to its sole shareholder, LKE.member. Certain of Talen Energy Supply's debt agreements include covenants that could effectively restrict the payment of distributions, loans or advances, either directly to Talen Energy Corporation or to Talen Energy Supply or one of its subsidiaries.
As discussed inSee "Item 1A. Risk Factors" and Note 75 to the Financial Statements LG&E's ability to pay dividends is limited under a covenant in its $500 million revolving line of credit facility. This covenant restricts the debt to total capital ratio to not more than 70%. See Note 7 to the Financial Statements for these and other restrictions related to distributions on capital interests for LG&E.Talen Energy.
Purchase or Redemption of Debt Securities
LG&ETalen Energy will continue to evaluate purchasing or redeeming outstanding debt securities and may decide to take actionpurchase or redeem these securities depending upon prevailing market conditions and available cash.
Rating Agency ActionsAgencies and Credit Considerations
Moody's, S&P and Fitch periodically review the credit ratings on the debt securities of LG&E. Based on their respective independent reviews, the rating agencies may make certain ratings revisions or ratings affirmations.
A credit rating reflects an assessment by the rating agency of the creditworthiness associated with an issuer and particular securities that it issues. The credit ratings of LG&E are based on information providedissued by LG&E and other sources. The ratings of Moody's, S&P and Fitchrating agencies are not a recommendationrecommendations to buy, sell or hold any debt securities of LG&E.Talen Energy, and they are often based in part on information provided by Talen Energy and other sources. Such ratings may be subject to revisions or withdrawal by the agencies at any time and should be evaluated independently of each other and any other rating that may be assigned to the securities. TheTalen Energy's credit ratings of LG&Emay affect its liquidity, access to capital markets and cost of borrowing under its credit facilities.borrowing.
The following table sets forth LG&E's securitythe credit ratings issued by Moody's and Standard & Poor's for outstanding debt securities or credit facilities of Talen Energy Supply as of December 31, 2012.2015.
|
| | Senior Unsecured | | Senior Secured | | Commercial Paper |
| | | | | | | | | | | | | | | | | | |
Issuer | | Moody's | | S&P |
| FitchSenior Unsecured | | Moody'sBa3 | | S&PB+ |
Senior Secured | | FitchBaa2 | | Moody'sBB |
Corporate Issuer Rating | | S&PBa2 | | FitchB+ |
Outlook | | Negative | | | | | | | | | | | | | | | | |
LG&E | | | | | | A | | A2 | | A- | | A+ | | P-2 | | A-2 | | F-2Stable |
In addition to the credit ratings noted above, the rating agencies took the following actions related to LG&E:
In February 2012, Fitch assigned ratings to LG&E's newly established commercial paper program.
In March 2012, Moody's affirmed the following ratings:
· the issuer ratings for LG&E; and
· the bank loan ratings for LG&E.
Also in March 2012, Moody's and S&P each assigned short-term ratings to LG&E's newly established commercial paper program.
In March and May 2012, Moody's, S&P and Fitch affirmed the long-term ratings for LG&E's 2003 Series A and 2007 Series B pollution control bonds.
In November 2012, Moody's and S&P affirmed the long-term ratings for LG&E's 2007 Series A pollution control bonds.
In December 2012, Fitch affirmed the issuer default ratings, individual security ratings and outlook for LG&E.
Ratings Triggers
LG&E has variousVarious derivative and non-derivative contracts, including contracts for the sale and purchase of electricity and fuel, commodity transportation and storage and interest rate instruments which contain provisions requiring LG&E to postthat require the posting of additional collateral, or permittingpermit the counterparty to terminate the contract, if LG&E'sthose contracts, upon a downgrade in Talen Energy Supply's credit rating were to fall below investment grade.rating. See Note 1915 to the Financial Statements for a discussion of "Credit Risk-Related Contingent Features," including a discussion of the potential additional collateral that would have been requiredrequirements for Talen Energy for derivative contracts in a net liability position at December 31, 2012. At December 31, 2012, if LG&E's credit ratings had been below investment grade, the maximum amount that LG&E would have been required to post as additional collateral to counterparties was $57 million for both derivative and non-derivative commodity and commodity-related contracts used in its generation and marketing operations, gas supply and interest rate contracts.2015.
Talen Energy has no credit rating triggers that, by themselves, would result in the reduction of access to capital markets or the acceleration of maturity dates of outstanding debt.
Guarantees for Subsidiaries
Talen Energy Supply guarantees certain consolidated affiliate financing arrangements. Some of the guarantees contain financial and other covenants that, if not met, would limit or restrict the consolidated affiliates' access to funds under these financing arrangements, accelerate maturity of such arrangements or limit the consolidated affiliates' ability to enter into certain transactions. See Note 11 to the Financial Statements for additional information about guarantees.
Off-Balance Sheet Arrangements
LG&ETalen Energy has entered into certain agreements that may contingently require payment to a guaranteed or indemnified party. See Note 1511 to the Financial Statements for a discussion of these agreements.
Risk Management
Market Risk
Market Risk
See Notes 1, 1814 and 1915 to the Financial Statements for information about LG&E'sTalen Energy's risk management objectives, valuation techniques and accounting designations.
The forward-looking information presented below provides estimates of what may occur in the future, assuming certain adverse market conditions and model assumptions. Actual future results may differ materially from those presented. These disclosures are not precise indicators of expected future losses, but only indicators of possible losses under normal market conditions at a given confidence level.
Commodity Price Risk (Non-trading)
LG&E's rates are set by regulatory commissionsTalen Energy's non-trading activity includes economic hedge transactions that address a specific risk. This activity includes the changes in fair value of positions used to hedge a portion of the economic value of Talen Energy's competitive generation assets and the fuel costs incurred are directly recoverable from customers. As a result, LG&Efull-requirement sales and retail contracts. This economic activity is subject to commoditychanges in fair value due to market price risk for only a small portion of on-going business operations. LG&E sells excess economic generation to maximize the valuevolatility of the physical assets at times when the assets are not required to serve LG&E's or KU's customers.input and output commodities (e.g., fuel and power). See Note 1915 to the Financial Statements for additional disclosures.information.
To hedge the impact of market price volatility on Talen Energy's energy-related assets, liabilities and other contractual arrangements, Talen Energy subsidiaries both sell and purchase physical energy at the wholesale level under FERC market-based tariffs throughout the U.S. and enter into financial exchange-traded and over-the-counter contracts. Talen Energy's non-trading commodity derivative contracts range in maturity through 2020.
The balance and changefollowing table sets forth the changes in the net fair value of LG&E'snon-trading commodity derivative contracts for the periodsyears ended December 31. See Notes 14 and 15 to the Financial Statements for additional information.
|
| | | | | | | | |
| | Gains (Losses) |
| | 2015 | | 2014 |
Fair value of contracts outstanding at the beginning of the period | | $ | 53 |
| | $ | 107 |
|
Contracts realized or otherwise settled during the period | | (133 | ) | | 328 |
|
Fair value of new contracts entered into during the period (a) | | 5 |
| | (12 | ) |
Other changes in fair value | | 220 |
| | (370 | ) |
Fair value of contracts outstanding at the end of the period |
| $ | 145 |
| | $ | 53 |
|
| |
(a) | Represents the fair value of contracts at the end of the quarter of their inception. Includes the impact of contracts acquired as part of the RJS Power and MACH Gen acquisitions. |
The following table segregates the net fair value of non-trading commodity derivative contracts at December 31, 2015, based on the observability of the information used to determine the fair value.
|
| | | | | | | | | | | | | | | | | | | |
| Net Asset (Liability) |
| Maturity Less Than 1 Year | | Maturity 1-3 Years | | Maturity 4-5 Years | | Maturity in Excess of 5 Years | | Total Fair Value |
Source of Fair Value | | | | | | | | | |
Prices based on significant observable inputs (Level 2) | $ | 89 |
| | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | 96 |
|
Prices based on significant unobservable inputs (Level 3) | 31 |
| | 17 |
| | 1 |
| | — |
| | 49 |
|
Fair value of contracts outstanding at the end of the period | $ | 120 |
| | $ | 17 |
| | $ | 8 |
| | $ | — |
| | $ | 145 |
|
Talen Energy subsidiaries sell electricity, capacity and related services and buy fuel on a forward basis to hedge the value of energy from Talen Energy's generation assets. If these Talen Energy subsidiaries were unable to deliver firm capacity and energy or to accept the delivery of fuel under their agreements, under certain circumstances they could be required to pay liquidated damages. These damages would be based on the difference between the market price and the contract price of the commodity. Depending on price changes in the wholesale energy markets, such damages could be significant. Extreme weather conditions, unplanned power plant outages, transmission disruptions, nonperformance by counterparties (or their counterparties) with which it has energy contracts and other factors could affect Talen Energy's ability to meet its obligations, and/or cause significant increases in the market price of replacement energy. Although Talen Energy attempts to mitigate these risks, the company cannot assure that it will be able to fully meet its firm obligations, that it will not be required to pay damages for failure to perform, or that it will not experience counterparty nonperformance in the future.
Commodity Price Risk (Trading)
Talen Energy's trading commodity derivative contracts range in maturity through 2019. The following table sets forth changes in the net fair value of trading commodity derivative contracts for the years ended December 31. See Notes 14 and 15 to the Financial Statements for additional information.
|
| | | | | | | |
| Gains (Losses) |
| 2015 | | 2014 |
Fair value of contracts outstanding at the beginning of the period | $ | 48 |
| | $ | 11 |
|
Contracts realized or otherwise settled during the period | (68 | ) | | (60 | ) |
Fair value of new contracts entered into during the period (a) | 4 |
| | 5 |
|
Other changes in fair value | 25 |
| | 92 |
|
Fair value of contracts outstanding at the end of the period | $ | 9 |
| | $ | 48 |
|
| |
(a) | Represents the fair value of contracts at the end of the quarter of their inception. |
The following table segregates the net fair value of trading commodity derivative contracts at December 31, 2015, based on the observability of the information used to determine the fair value.
|
| | | | | | | | | | | | | | | | | | | |
| Net Asset (Liability) |
| Maturity Less Than 1 Year | | Maturity 1-3 Years | | Maturity 4-5 Years | | Maturity in Excess of 5 Years | | Total Fair Value |
Source of Fair Value | | | | | | | | | |
Prices based on significant observable inputs (Level 2) | $ | 6 |
| | $ | — |
| | $ | (2 | ) | | $ | — |
| | $ | 4 |
|
Prices based on significant unobservable inputs (Level 3) | 5 |
| | — |
| | — |
| | — |
| | 5 |
|
Fair value of contracts outstanding at the end of the period | $ | 11 |
| | $ | — |
| | $ | (2 | ) | | $ | — |
| | $ | 9 |
|
VaR Models
A VaR model is utilized to measure commodity price risk in competitive margins for the non-trading and trading portfolios. VaR is a statistical model that attempts to estimate the value of potential loss over a given holding period under normal market conditions at a given confidence level. VaR is calculated using a Monte Carlo simulation technique based on a
five-day holding period at a 95% confidence level. Given Talen Energy's hedging program, the non-trading VaR exposure is expected to be limited in the short-term. The VaR for portfolios using end-of-month results for the year ended December 31, 2012, 2011 and 2010 are shown in the table below.2015 was as follows.
|
| | | | | | | |
| Trading VaR | | Non-Trading VaR |
95% Confidence Level, Five-Day Holding Period | | | |
Period End | $ | — |
| | $ | 37 |
|
Average for the Period | 1 |
| | 18 |
|
High | 4 |
| | 37 |
|
Low | — |
| | 8 |
|
| | | | | Gains (Losses) |
| | | | | Successor | | | Predecessor |
| | | | | | | | | Two Months | | | Ten Months |
| | | | | Year Ended | | Year Ended | | Ended | | | Ended |
| | | | | December 31, | | December 31, | | December 31, | | | October 31, |
| | | | | 2012 | | 2011 | | 2010 | | | 2010 |
| | | | | | | | | | | | | | | | |
Fair value of contracts outstanding at the beginning of the period | | | | | $ | (1) | | | | | | | |
Contracts realized or otherwise settled during the period | | | | | | (3) | | | | | | $ | 3 |
Fair value of new contracts entered into during the period | | | | | | | | | | | | | (4) |
Other changes in fair value (a) | | | | | | 4 | | $ | (1) | | | | 1 |
Fair value of contracts outstanding at the end of the period | | | | | $ | | | $ | (1) | | | $ | |
The trading portfolio includes all proprietary trading positions, regardless of the delivery period. All positions not considered proprietary trading are considered non-trading. The non-trading portfolio includes the entire portfolio, including generation, with delivery periods through the next 12 months. Both the trading and non-trading VaR computations exclude FTRs due to the absence of reliable spot and forward markets. The fair value of the non-trading and trading FTR positions was insignificantat December 31, 2015.
Interest Rate Risk
(a) | Represents the change in value of outstanding transactions and the value of transactions entered into and settled during the period. |
Interest Rate Risk
LG&ETalen Energy, directly or through its subsidiaries, issues debt to finance its operations, which exposes it to interest rate risk. LG&E utilizesTalen Energy may utilize various financial derivative instruments to adjust the mix of fixed and floating interest rates in its debt portfolio, adjust the duration of its debt portfolio and lock in components of current market interest rates in anticipation of future financing, when appropriate. Risk limits under LG&E'sthe risk management programpolicy are designed to balance risk,mitigate interest rate exposure toand volatility in interest expense and changes in the fair value of LG&E's debt portfolio due to changes in the absolute level of interest rates.expense.
AtTalen Energy had no interest rate hedges outstanding at December 31, 20122015 and 2011, LG&E's2014.
Talen Energy is exposed to a potential annual exposure to increased interest expense, based on a 10% increase in interest rates, was not significant.
LG&E is also exposedexpense and to changes in the fair value of its debt portfolio. LG&EThe estimated thatimpact of a 10% decreaseadverse movement in interest rates at December 31, 2012,2015 would cause an insignificant increase in interest expense and a $119 million increase in the fair value of its debt portfolio by $27 million. This estimate is unchanged fromdebt. At December 31, 2011.2014, the estimated impact of a 10% adverse movement in interest rates would cause an insignificant increase in interest expense and a $46 million increase in the fair value of debt.
NDT Funds - Securities Price Risk
LG&E had the following interest rate hedges outstanding at: |
| | | | | | | | | | | | | | | | | | | |
| | | December 31, 2012 | | December 31, 2011 |
| | | | | | | Effect of a | | | | | | Effect of a |
| | | | | Fair Value, | | 10% Adverse | | | | Fair Value, | | 10% Adverse |
| | | Exposure | | Net - Asset | | Movement | | Exposure | | Net - Asset | | Movement |
| | | Hedged | | (Liability) (a) | | in Rates | | Hedged | | (Liability) (a) | | in Rates |
Economic hedges | | | | | | | | | | | | | | | | | | |
| Interest rate swaps (b) | | $ | 179 | | $ | (58) | | $ | (3) | | $ | 179 | | $ | (60) | | $ | (4) |
Cash flow hedges | | | | | | | | | | | | | | | | | | |
| Interest rate swaps (b) | | | 150 | | | 7 | | | (9) | | | | | | | | | |
In connection with certain NRC requirements, Susquehanna Nuclear maintains trust funds to fund certain costs of decommissioning the Susquehanna Nuclear plant. At December 31, 2015, these funds were invested primarily in domestic equity securities and fixed-rate, fixed-income securities and are reflected at fair value on the balance sheet. The mix of securities is designed to provide returns sufficient to fund Susquehanna Nuclear's decommissioning and to compensate for inflationary increases in decommissioning costs. However, the equity securities included in the trusts are exposed to price fluctuation in equity markets, and the values of fixed-rate, fixed-income securities are primarily exposed to changes in interest rates. Talen Energy actively monitors the investment performance and periodically reviews asset allocation in accordance with its nuclear decommissioning trust policy statement. At December 31, 2015, a hypothetical 10% increase in interest rates and a 10% decrease in equity prices would have resulted in an estimated $74 million reduction in the fair value of the trust assets compared with $73 million at December 31, 2014. See Notes 14 and 19 to the Financial Statements for additional information regarding the NDT funds.
(a) | Includes accrued interest. |
Defined Benefit Plans - Securities Price Risk(b) | LG&E utilizes various risk management instruments to reduce its exposure to the expected future cash flow variability of its debt instruments. These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financing. While LG&E is exposed to changes in the fair value of these instruments, any realized changes in the fair value of such economic and cash flow hedges are recoverable through regulated rates and any subsequent changes in fair value of these derivatives are included in regulatory assets or liabilities. Sensitivities represent a 10% adverse movement in interest rates. The positions outstanding at December 31, 2012 mature through 2043. |
See "Application of Critical Accounting Policies - Defined Benefits" for additional information regarding the effect of securities price risk on Talen Energy plan assets. Credit Risk
LG&ECredit risk is exposed to potential lossesthe risk that Talen Energy would incur a loss as a result of nonperformance by counterparties of their contractual obligations. LG&ETalen Energy maintains credit policiesprocedures with respect to counterparty credit (including requirements that counterparties maintain specified credit standards) and proceduresrequire other assurances in the form of credit support or collateral in certain circumstances in order to limit counterparty credit risk. However, Talen Energy has concentrations of suppliers and customers among electric utilities, financial institutions and other energy marketing and trading companies. These
concentrations may impact Talen Energy's overall exposure to credit risk, including evaluatingpositively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions.
Talen Energy includes the effect of credit ratings and financial information along with having certain counterparties post margin ifrisk on its fair value measurements to reflect the credit exposure exceeds certain thresholds. LG&E is exposedprobability that a counterparty will default when contracts are out of the money (from the counterparty's standpoint). In this case, Talen Energy would have to potential losses assell into a result of nonpayment by customers. LG&E maintainslower-priced market or purchase in a higher-priced market. When necessary, Talen Energy records an allowance for doubtful accounts basedto reflect the probability that a counterparty will not pay for deliveries Talen Energy has made but not yet billed, which are reflected in "Unbilled revenues" on a historical charge-off percentage for retail customers. Allowances for doubtful accounts from wholesale customers and miscellaneous receivables are based on specific identification by management. Retail and wholesale customer accounts are written-off after four months of no payment activity. Miscellaneous receivables are written-off as management determines them to be uncollectible.the Balance Sheets.
Certain of LG&E's derivative instruments contain provisions that require it to provide immediate and on-going collateralization of derivative instruments in net liability positions based upon LG&E's credit ratings from each of the major credit rating agencies. See Notes 1814 and 19 to the Financial Statements for information regarding exposure and the risk management activities.
Related Party Transactions
LG&E is not aware of any material ownership interest or operating responsibility by senior management in outside partnerships, including leasing transactions with variable interest entities or other entities doing business with LG&E. See Note 1615 to the Financial Statements for additional information on related party transactions.credit concentration and credit risk.
Acquisitions, Development and Divestitures
Environmental Matters
Protection ofTalen Energy from time to time evaluates opportunities for potential acquisitions, divestitures and development projects. Development projects are reexamined based on market conditions and other factors to determine whether to proceed with the environment is a major priority for LG&E and a significant element of its business activities. Extensive federal, state and local environmental laws and regulations are applicable to LG&E's air emissions, water discharges and the management of hazardous and solid waste, amongprojects, sell, cancel or expand them, execute tolling agreements or pursue other areas, and the costs of compliance or alleged non-compliance cannot be predicted with certainty but could be material. In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed from prior versions by the relevant agencies. Costs may take the form of increased capital expenditures or operating and maintenance expenses; monetary fines, penalties or forfeitures or other restrictions. Many of these environmental law considerations are also applicable to the operations of key suppliers, or customers, such as coal producers, industrial power users, etc.; and may impact the costs for their products or their demand for LG&E's services.
Physical effects associated with climate change could include the impact of changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to LG&E's generation assets and electricity transmission and distribution systems, as well as impacts on customers. In addition, changed weather patterns could potentially reduce annual rainfall in areas where LG&E has hydro generating facilities or where river water is used to cool its fossil powered generators. LG&E cannot currently predict whether its businesses will experience these potential climate change-related risks or estimate the potential cost of their related consequences.
options. See "Item 1. Business - Environmental Matters" and Note 156 to the Financial Statements for information on the RJS Power acquisition, the MACH Gen acquisition, the Talen Montana hydroelectric sale, and the announced divestitures of assets to satisfy a December 2014 FERC order approving the combination with RJS Power.
Environmental Matters
The following is a discussion of the more significant environmental matters impacting Talen Energy's business this fiscal year. See "Item 1. Business" for additional information on environmental matters.
CSAPR
Annual and seasonal nitrogen oxide emission allowance trading programs, as well as annual sulfur dioxide emission allowance trading, commenced in 2015 for 28 states under the EPA's CSAPR Rule. In December 2015, the EPA proposed a "CSAPR Update Rule" which recommends more stringent ozone season nitrogen oxide budgets for 23 states, including several where Talen owns affected generation. Additional capital and/or operating and maintenance expenses could be imposed on Talen plants in Maryland, New Jersey, New York, Pennsylvania and Texas as a result of this action.
NAAQS
Regulations to address more stringent National Ambient Air Quality Standard (NAAQS) for ozone established by the EPA advanced in Pennsylvania and Maryland in 2015. In Pennsylvania, these regulations seek to establish reasonably available control technologies (RACT) for fossil-fuel fired power plants nitrogen oxide and volatile organic compound emissions. Maryland coal plants operated at reduced nitrogen oxide emission rates during the 2015 ozone season as a result of an emergency action issued by the Governor (which later became a final rule), and in November 2015 the MDE promulgated additional nitrogen oxide regulations for Maryland coal plants that require even more stringent operations starting no later than June 2020. Actions were taken at the federal level in 2015 to tighten the NAAQS for ozone as well. More specifically, in October 2015, the EPA released a final rule establishing a more stringent national standard for ozone.
Pertaining to the EPA's 2010 NAAQS for sulfur dioxide, the EPA and Sierra Club entered into an approved consent decree on March 2, 2015 that establishes deadlines for remaining area designations. Several of Talen's affected plants are in undesignated areas.
Compliance with these regulations, or those that could be developed to address the EPA's 2010 sulfur dioxide NAAQS and/or 2015 ozone NAAQS, could lead to increased capital and/or operating and maintenance expenses for Talen Energy's fossil-fuel fired power plants.
MATS
Compliance with the EPA's MATS Rule commenced in April 2015 for those plants that did not receive a compliance extension. The rule has increased capital and operating and maintenance expenses for some of Talen Energy's power plants. The U.S. Supreme Court determined in June 2015 that the EPA acted unreasonably by refusing to consider costs when determining whether the MATS regulation was appropriate and necessary. The EPA responded with a proposed supplemental finding in November 2015 claiming that the regulation was appropriate and necessary based on cost. In December 2015, to address the
June 2015 Supreme Court action, the DC Circuit remanded the MATS Rule to the EPA to incorporate a revised appropriate and necessary finding.
Regional Haze
In September 2015, the Third Circuit Court of Appeals vacated portions of the EPA's approval of Pennsylvania's Regional Haze State Implementation Plan and remanded the Rule to the EPA for further consideration. Talen Energy is unable to determine at this time if the future impacts of Regional Haze on Talen Energy's Pennsylvania fossil-fuel fired power plants will have a material adverse effect on its financial condition or results of operations.
GHG Regulations
The EPA's final rules for new and existing power plants were published in the Federal Register in October 2015, along with a proposed federal implementation plan for those states that fail to submit an acceptable state implementation plan for the existing plant rule. EPA's existing plant rule has been stayed by the U.S. Supreme Court until all legal challenges to the rule have been resolved. The new plant rule remains in effect and challenges are also outstanding in federal court. Talen Energy is unable to determine if the rules will have a material adverse effect on Talen Energy's financial condition or results of operations, but increased capital and operating and maintenance costs could be imposed.
Exemptions for Startup, Shutdown and Malfunction Events
In June 2015, the EPA published a Final Rule which prohibits states from exempting startup, shutdown and malfunction events from compliance requirements in SIPs. Revisions to SIPs or other regulations in states where Talen Energy operates could impact operations and financial conditions.
CCRs
The EPA's final rule regulating CCRs as non-hazardous wastes, which imposes extensive new self-implementing requirements on CCR impoundments and landfills, became effective in October 2015. Talen Energy expects that its plants using surface impoundments for management and disposal of CCRs, or that previously managed CCRs and continue to manage wastewaters, will be most impacted by this rule. Talen Energy anticipates incurring capital, operating and/or maintenance costs to address other provisions of the rule, such as groundwater monitoring and disposal facility modifications. The final CCR Rule is being challenged in federal court. During 2015, an increase of $41 million was recorded to existing AROs. Further changes to AROs may be required as estimates are refined and compliance with the rule continues.
ELGs and Standards
The EPA's final ELG regulations that revise discharge limitations for steam electric generation wastewater permits were published in the Federal Register in November 2015. The regulations contain requirements that could significantly impact Talen Energy's coal-fired plants. At this point, Talen Energy is unable to estimate a range of reasonably possible compliance costs. The regulations are being challenged in federal court.
Waters of the United States (WOTUS)
In June 2015, the EPA and the U.S. Army Corps of Engineers published their final rule redefining the term WOTUS, and in October 2015, the U.S. Court of Appeals for the Sixth Circuit issued an order preventing the EPA from implementing the rule nationwide. In the event the stay is lifted, and the regulation survives separate legal challenges, the redefinition could impact future development actions, such as plant and gas infrastructure expansions.
New Accounting Guidance
See Notes 1 and 2421 to the Financial Statements for a discussion of new accounting guidance adopted and pending adoption.
Application of Critical Accounting Policies
Financial condition and results of operations are impacted by the methods, assumptions and estimates used in the application of critical accounting policies. The following accounting policies are particularly important to an understanding of the reported financial condition or results of operations, and require management to make estimates or other judgments of matters that are inherently uncertain. Changes in the estimates or other judgments included within these accounting policies could result in a
significant change to the information presented in the Financial Statements (these accounting policies are also discussed in Note 1 to the Financial Statements). LG&E's seniorSenior management has reviewed with Talen Energy Corporation's Audit Committee these critical accounting policies, the following disclosures regarding their application and the estimates and assumptions regarding them, with PPL's Audit Committee.
Revenue Recognition - Unbilled Revenue
them.
Revenues relatedPrice Risk Management
See "Price Risk Management" in Note 1 to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers of LG&E's retail operations are billed on cycles which vary based on the timing of the actual reading of their electric and gas meters, LG&E records estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of electricity and gas delivered to customers since the date of the last reading of their meters. The unbilled revenues reflect consideration of estimated usage by customer class, the effect of different rate schedules, changes in weather and where applicable, the impact of weather normalization or other regulatory provisions of rate structures. In addition to the unbilled revenue accrual resulting from cycle billing, LG&E makes additional accruals resulting from the timing of customer bills. The accrual of unbilled revenues in this manner properly matches revenues and related costs. At December 31, 2012 and 2011, LG&E had unbilled revenue balances of $72 million and $65 million.
Defined Benefits
Financial Statements, as well as "Risk Management" above.
LG&E sponsorsDefined Benefits
Talen Energy Supply and participatescertain of its subsidiaries sponsor or participate in, as applicable, various qualified funded and non-qualified unfunded defined benefit pension plans and participates in aboth funded and unfunded other postretirement benefit plan.plans. These plans are applicable to the majority of theTalen Energy's employees of LG&E. The plans LG&E participates in are sponsored by LKE. LKE allocates a portion of the liability and net periodic defined benefit pension and other postretirement costs of certain plans to LG&E based(based on its participation. LG&Eeligibility for their applicable plans). Talen Energy records an asset or liability, with an offsetting entry to AOCI to recognize the funded status of all defined benefit plans with an offsetting entry to regulatory assetsthat it or liabilities.its subsidiaries sponsor. Consequently, the funded status of all sponsored defined benefit plans is fully recognized on the Balance Sheets. See Note 139 to the Financial Statements for additional information about the plans and the accounting for defined benefits.benefits including a discussion of the newly created pension and other postretirement benefit plans sponsored by Talen Energy Supply that replaced Talen Energy Supply's participation in similar PPL plans effective with the June 1, 2015 spinoff.
CertainManagement makes certain assumptions are made by LKE and LG&E regarding the valuation of benefit obligations and the performance of plan assets. When accounting for defined benefits, delayed recognition in earnings of differences between actual results and expected or estimated results is a guiding principle. Annual net periodic defined benefit costs are recorded in current earnings based on estimated results. Any differences between actual and estimated results are recorded in regulatory assets and liabilities for amounts that are expected to be recovered through regulated customer rates.AOCI. These amounts in regulatory assets and liabilitiesAOCI are amortized to income over future periods. The delayed recognition allows for a smoothed recognition of costs over the working lives of the employees who benefit under the plans. The primary assumptions are:
· | Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due. |
· | Expected Long-term Return on Plan Assets - Management projects the long-term rates of return on plan assets based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes. These projected returns reduce the net benefit costs LG&E records currently. |
Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due.
· | Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement. |
Expected Return on Plan Assets - Management projects the long-term rates of return on plan assets that will be earned over the life of each plan. These projected returns reduce the net periodic defined benefit costs currently recorded.
· | Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care. |
Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement.
Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care.
In selecting a discount rate foraddition to the economic assumptions above that are evaluated annually, management must also make assumptions regarding the life expectancy of employees covered under their defined benefit pension and other postretirement benefit plans. At December 31, 2014 or June 1, 2015, as applicable, the plan sponsors adopted the mortality tables issued by the Society of Actuaries in October 2014 (RP-2014 base tables) for all applicable defined benefit pension and other postretirement benefit plans. At December 31, 2014 or June 1, 2015, as applicable, the plan sponsors also selected the IRS BB 2-Dimensional mortality improvement scale on a generational basis for all applicable defined benefit pension and other postretirement benefit plans. These mortality assumptions reflect the recognition of both improved life expectancies and the expectation of continuing improvements in life expectancies.
For the applicable periods ended December 31, 2015, Talen Energy's defined benefit pension and other postretirement benefit plans LKE and LG&Eincurred actuarial losses of $50 million primarily due to lower actual return on plan assets compared to the expected return on plan assets partially offset by an increase in the discount rate.
In selecting the discount rates for applicable defined benefit plans, the plan sponsors start with a cash flow analysis of the expected benefit payment stream for their plans. The plan-specific cash flows are matched against the coupons and expected maturity values of individually selected bonds. This bond matching process begins with the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, serving as the base from which those with the lowest and highest yields are eliminated to develop an appropriate subset of bonds. Individual bonds are then selected based on the timing of each
plan's cash flows and parameters are established as to the percentage of each individual bond issue that could be hypothetically purchased and the surplus reinvestment rates to be assumed. At December 31, 2012, LKE decreased
To determine the discount rate for its pensionexpected return on plan from 5.12% to 4.26%. LG&E decreasedassets, the discount rate for its pension plan from 5.05% to 4.20%. LKE decreasedsponsors project the discount rate for its other postretirement benefit plan from 4.78% to 3.99%.
The expected long-term rates of return for LKE's and LG&E's defined benefit pension plans and LKE's defined other postretirement benefiton plan have been developedassets using a best-estimate of expected returns, volatilities and correlations for each asset class. LKE and LG&E management corroborates these rates with expected long-term rates of return calculated by its independent actuary, who uses a building block approach that begins with a risk-free rate of return with factors being added such as inflation, duration, credit spreads and equity risk. Each plan's specific current and expected asset allocation isallocations are also considered in developing a reasonable return assumption. At December 31, 2012, LKE's and LG&E's expected return on plan assets decreased from 7.25% to 7.10%.
In selecting a rate of compensation increase, LKE and LG&Ethe plan sponsors consider past experience in light of movements in inflation rates. At December 31, 2012, LKE's
The following table provides the weighted-average assumptions used for discount rate, expected return on plan assets and LG&E's rate of compensation increase remained at 4.00%.December 31, 2015.
|
| | | |
Assumption | | |
Discount Rate | | |
Pension | | 4.65 | % |
Other Postretirement | | 4.60 | % |
Expected return on plan assets | | |
Pension | | 7.00 | % |
Other Postretirement | | 6.37 | % |
Rate of compensation increase | | |
Pension | | 3.98 | % |
Other Postretirement | | 3.98 | % |
In selecting health care cost trend rates, LKE considersthe plan sponsors consider past performance and forecasts of health care costs. At December 31, 2012, LKE's2015, the health care cost trend rates for all plans were 8.00%6.8% for 2013,2016, gradually declining to 5.50% for 2019.an ultimate trend rate of 5.0% in 2020.
A variance in the assumptions listed above could have a significant impact on accrued defined benefit liabilitiespension obligations, reported annual net periodic pension costs and related AOCI. At December 31, 2015, the accrued pension obligations and related items and the portions related to the most significant plan were recorded in the financial statements as follows.
|
| | | | | | | | |
| | Total | | Most Significant Plan |
Balance Sheet: | | | | |
Accrued pension obligations | | $ | (340 | ) | | $ | (323 | ) |
AOCI (pre-tax) | | 453 |
| | 390 |
|
Statement of Income: | | | | |
Pension costs | | $ | 48 |
| | $ | 28 |
|
The following table reflects the impact of changes in certain assumptions for Talen Energy's most significant plan. The table reflects either an increase or assets,decrease in each assumption. The inverse of this change would impact the accrued pension obligation, reported annual net periodic defined benefit costs and regulatory assets and liabilities for LG&E. While the charts below reflect either an increase or decrease in each assumption, the inverse of the change would impact the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and regulatory assets and liabilities for LG&EAOCI by a similar amount in the opposite direction. The sensitivities below reflect an evaluation of the change based solely on a change in that assumption and does not include income tax effects.assumption.
|
| | | | | | | | | | | | | | |
| | | Increase (Decrease) |
Actuarial assumption | Sensitivity | | Accrued Pension Obligation | | AOCI (pre-tax) | | Pension Costs |
Discount rate | (0.25 | )% | | $ | 51 |
| | $ | 51 |
| | $ | 5 |
|
Expected return on plan assets | (0.25 | )% | | n/a |
| | n/a |
| | 3 |
|
Rate of compensation increase | 0.25 | % | | 7 |
| | 7 |
| | 2 |
|
At December 31, 2012, the defined benefit plans were recorded as follows:
Pension liabilities | | $ | 102 |
Other postretirement benefit liabilities | | | 81 |
The following chart reflects the sensitivities in the December 31, 2012 Balance Sheet associated with a change in certain assumptions based on LG&E's primary defined benefit plans.
| | Increase (Decrease) |
| | | | | Impact on | | | | | Impact on |
| | Change in | | defined benefit | | Impact on | | regulatory |
Actuarial assumption | | assumption | | liabilities | | OCI | | assets |
| | | | | | | | | | | | |
Discount Rate | | | (0.25)% | | $ | 21 | | | | | $ | 21 |
Rate of Compensation Increase | | | 0.25% | | | 2 | | | | | | 2 |
Health Care Cost Trend Rate (a) | | | 1% | | | 1 | | | | | | 1 |
(a) | Only impacts other postretirement benefits. |
In 2012, LG&E recognized net periodic defined benefit costs charged to operating expense of $18 million. This amount represents a $3 million decrease from 2011. This decrease in expense for 2012 was primarily attributable to the increase in the expected return on plan assets resulting from pension contributions of $21 million, a reduction in the amortization of outstanding losses and lower interest cost.
The following chart reflects the sensitivities in the 2012 Statement of Income (excluding income tax effects) associated with a change in certain assumptions based on LG&E's primary defined benefit plans.
Actuarial assumption | | | Change in assumption | | | Impact on defined benefit costs |
| | | | | | |
Discount Rate | | | (0.25)% | | $ | 2 |
Expected Return on Plan Assets | | | (0.25)% | | | 1 |
Rate of Compensation Increase | | | 0.25% | | | |
Health Care Cost Trend Rate (a) | | | 1% | | | |
(a) | Only impacts other postretirement benefits. |
Asset Impairment (Excluding Investments)
Impairment analyses are performed for long-lived assets that are subject to depreciation or amortization whenever events or changes in circumstances indicate that a long-lived asset's carrying amount may not be recoverable. For these long-lived assets classified as held and used, such events or changes in circumstances are:
· | a significant decrease in the market price of an asset; |
a significant decrease in the market price of an asset;· | a significant adverse change in the extent or manner in which an asset is being used or in its physical condition; |
a significant adverse change in the extent or manner in which an asset is being used or in its physical condition;
· | a significant adverse change in legal factors or in the business climate; |
Table of Contentsa significant adverse change in legal factors or in the business climate;
· | an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of an asset; |
an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of an asset;
· | a current-period operating or cash flow loss combined with a history of losses or a forecast that demonstrates continuing losses; or |
a current period operating or cash flow loss combined with a history of losses or a forecast that demonstrates continuing losses; or
· | a current expectation that, more likely than not, an asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. |
a current expectation that, more likely than not, an asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
For a long-lived asset classified as held and used, an impairment is recognized when the carrying amount of the asset is not recoverable and exceeds its fair value. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset is impaired, an impairment loss is recorded to adjust the asset's carrying amount to its estimated fair value. Management must make significant judgments to estimate future cash flows, including the useful lives of long-livedthe assets, the fair value offorward prices for energy, capacity and fuel in the markets where the assets are utilized, the amount of capital and operations and maintenance spending and management's intent tointended use of the assets. Alternate courses of action are considered to recover the carrying amount of a long-lived asset, and estimated cash flows from the "most likely" alternative are used to assess impairment whenever one alternative is clearly the most likely outcome. If no alternative is clearly the most likely, then a probability-weighted approach is used, taking into consideration estimated cash flows from the alternatives. For assets tested for impairment as of the balance sheet date, the estimates of future cash flows used in that test consider the likelihood of possible outcomes that existed at the balance sheet date, including thean assessment of the likelihood of a future sale of the assets. That assessment is not revised based on events that occur after the balance sheet date. Changes in assumptions and estimates could result in significantlymaterially different results than those identified and recorded in the financial statements.
For a long-lived asset classified as held for sale, an impairment exists when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell. If the asset (disposal group) is impaired, an impairment loss is recorded to adjust the carrying amount to its fair value less cost to sell. A gain is recognized in future periods for any subsequent increase in fair value less cost to sell, but not in excess of the cumulative impairment previously recognized. If the asset (disposal group) no longer qualifies for classification as held for sale, it must be reclassified as held and used and its carrying value must be adjusted to the lower of its estimated fair value at that time or its carrying value when initially classified as held for sale adjusted for depreciation through the reclassification date.
For determining fair value, quoted market prices in active markets are the best evidence. However, when market prices are unavailable, LG&ETalen Energy considers all valuation techniques appropriate under the circumstances and for which market participant inputs can be obtained. Generally discounted cash flows are used to estimate fair value, which incorporates market participant inputs when available. Discounted cash flows are calculated by estimating future cash flow streams and applying appropriate discount rates to determinedetermining the present value of the cash flow streams.streams using risk-adjusted discount rates.
In 2015, Talen Energy recorded pre-tax impairment charges of $189 million ($113 million after-tax) applicable to certain assets (classified as held and used and held for sale). See Notes 14 and 16 to the Financial Statements for details on the evaluation and charges recorded.
In 2012, LG&E did not recognize an impairment of any long-lived assets.
Goodwill is tested for impairment at the reporting unit level. LG&E'sTalen Energy has determined its reporting unit has been determinedunits to be at the same level as its operating segment level.segments. At December 31, 2015, Talen Energy is organized in two operating segments/reporting units: East and West, primarily based on geographic location. Prior to the RJS acquisition, Talen Energy operated within a single operating segment/reporting unit. A goodwill impairment test is performed annually or more frequently if events or changes in circumstances indicate that the carrying amount of the reporting unit may be greater than the reporting unit's fair value. Additionally, goodwill is tested for impairment after a portion of goodwill has been allocated to a business to be disposed of.
Beginning in 2012, LG&ETalen Energy may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative assessmentevaluation and directly test goodwill for impairment using a two-step quantitative test. If the qualitative evaluation (referred to as "step zero") is elected and the assessment results in a determination that it is not more likely than not that the fair value of thea reporting unit is less than the carrying amount, the two-step quantitative impairment test is not necessary. However, the quantitative impairment test is required if LG&E concludes it is more likely than not the fair value of the reporting unit is less than the carrying amount based on the step zero assessment.
When the two-step quantitative impairment test is elected or required as a result of the step zero assessment, in step one, LG&E identifiesTalen Energy determines whether a potential impairment exists by comparing the estimated fair value of LG&E (the goodwilla reporting unit)unit with its carrying amount, including goodwill, on the measurement date. If the estimated fair value exceeds its carrying amount, goodwill is not considered impaired. If the carrying amount exceeds the estimated fair value, the second step is performed to measure the amount of impairment loss, if any.
The second step of the quantitative test requires a calculation of the implied fair value of goodwill, which is determined in the same manner as the amount of goodwill in a business combination. That is, the estimated fair value of a reporting unit is allocated to all of LG&E'sthe assets and liabilities of that reporting unit as if LG&Ethe reporting unit had been acquired in a business combination and the estimated fair value of LG&Ethe reporting unit was the price paid.paid to acquire the reporting unit. The excess of the estimated fair value of LG&Ea reporting unit over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. The implied fair value of LG&E'sthe reporting unit's goodwill is then compared with the carrying amount of that goodwill. If the carrying amount exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess. The loss recognized cannot exceed the carrying amount of LG&E'sthe reporting unit's goodwill.
LG&E elected to perform the two-step quantitativeIn 2015, Talen Energy recorded pre-tax goodwill impairment testcharges of goodwill in the fourth quarter of 2012 and no impairment was recognized. Management used both discounted cash flows and market multiples,$465 million ($444 million after-tax), which required significant assumptions, to estimate the fair value of LG&E. Applying an appropriate weighting to both the discounted cash flow and market multiple valuations, a decrease in the forecasted cash flows of 10%, an increase in the discount rate by 25 basis points, or a 10% decrease in the multiples would not have resulted in an impairment of goodwill.
Losses are accrued for the estimated impacts of various conditions, situations or circumstances involving uncertain or contingent future outcomes. For loss contingencies, the loss must be accrued if (1) information is available that indicates it is probable that a loss has been incurred, given the likelihoodfully impaired all of the uncertain future eventsgoodwill previously recorded on the balance sheet and (2)assigned to the amount of the loss can be reasonably estimated. Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." The accrual of contingencies that might result in gains is not recorded unless recovery is assured. Potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events are continuously assessed.
The accounting aspects of estimated loss accruals include (1) the initial identification and recording of the loss, (2) the determination of triggering events for reducing a recorded loss accrual and (3) the ongoing assessment as to whether a recorded loss accrual is sufficient. All three of these aspects require significant judgment by management. Internal expertise and outside experts (such as lawyers and engineers) are used, as necessary to help estimate the probability that a loss has been incurred and the amount (or range) of the loss.
In 2012, no significant adjustments were made to LG&E's existing contingencies.
Certain other events have been identified that could give rise to a loss, but that do not meet the conditions for accrual. Such events are disclosed, but not recorded, when it is reasonably possible that a loss has been incurred. Accounting guidance defines "reasonably possible" as cases in which "the future event or events occurring is more than remote, but less than likely to occur."
When an estimated loss is accrued, the triggering events for subsequently adjusting the loss accrual are identified, where applicable. The triggering events generally occur when the contingency has been resolved and the actual loss is paid or written off, or when the risk of loss has diminished or been eliminated. The following are some of the triggering events that provide for the adjustment of certain recorded loss accruals:
· | Allowances for uncollectible accounts are reduced when accounts are written off after prescribed collection procedures have been exhausted, a better estimate of the allowance is determined or underlying amounts are ultimately collected. |
· | Environmental and other litigation contingencies are reduced when the contingency is resolved, LG&E makes actual payments, a better estimate of the loss is determined or the loss is no longer considered probable. |
Loss accruals are reviewed on a regular basis to assure that the recorded potential loss exposures are appropriate. This involves ongoing communication and analyses with internal and external legal counsel, engineers, operation management and other parties.
East segment/reporting unit. See Note 1516 to the Financial Statements for additional information.details on the evaluation and charges recorded.
Asset Retirement Obligations
LG&E isARO liabilities are required to recognize a liabilitybe recognized for legal obligations associated with the retirement of long-lived assets. The initial obligation is measured at its estimated fair value. An ARO must be recognized when incurred if the fair value of the ARO can be reasonably estimated. An equivalent amount is recorded as an increase in the value of the capitalized asset and allocatedamortized to expense over the useful life of the asset. Until the obligation is settled, the liability is increased, through the recognition of accretion expense in the Statementsstatement of Income,income, for changes in the obligation due to the passage of time. Since costs of removal are collected in rates, the accretion and depreciation are offset with a regulatory credit on the income statement, such that there is no earnings impact. The regulatory asset created by the regulatory credit is relieved when the ARO has been settled. An ARO must be recognized when incurred if the fair value of the ARO can be reasonably estimated. See Note 21 to the Financial Statements for related disclosures.
In determining AROs, management must make significant judgments and estimates to calculate fair value. Fair value is developed using an expected present value technique based on assumptions of market participants that considers estimated retirement costs in current period dollars that are inflated to the anticipated retirement date and then discounted back to the date the ARO was incurred. Changes in assumptions and estimates included within the calculations of the fair value of AROs could result in significantly different results than those identified and recorded in the financial statements. Estimated ARO costs and settlement dates, which affect the carrying value of various AROsthe ARO and the related assets,capitalized asset, are reviewed periodically to ensure that any material changes are incorporated into the latest estimate of the obligations.ARO. Any change to the capitalized asset, positive or negative, is generally amortized over the remaining life of the associated long-lived asset.
At December 31, 2012, LG&E had AROs comprised of current2015, the total recorded balances and noncurrent amounts, totaling $62 million recordedinformation on the Balance Sheet. Of the total amount, $39 million, or 63%, relates to LG&E's ash ponds, landfills and natural gas mains. most significant recorded AROs were as follows.
|
| | | | | | | | | | | |
| | Most Significant AROs |
Total AROs Recorded | | Amount Recorded | | % of Total | | Description |
$ | 501 |
| | $ | 399 |
| | 79.6 | % | | Nuclear decommissioning |
The most significant assumptions surrounding AROs are the forecasted retirement costs (including the settlement dates and the timing of cash flows), the discount rates and the inflation rates. A varianceAt December 31, 2015, a 10% change to retirement costs, a 0.25% decrease in the forecasted retirement costs, the discount ratesrate or a 0.25% increase in the inflation rates couldrate would not have a significant impact on the ARO liabilities.liabilities and would not cause a significant change to the annual depreciation expense of the ARO asset or the annual accretion expense of the ARO liability.
The following chart reflectsSee Note 18 to the sensitivities related to LG&E's ARO liabilitiesFinancial Statements for ash ponds, landfills and natural gas mains at December 31, 2012:additional information on AROs.
| | Change in | | Impact on |
| | Assumption | | ARO Liability |
| | | | | | |
Retirement Cost | | | 10% | | $ | 5 |
Discount Rate | | | (0.25)% | | | 1 |
Inflation Rate | | | 0.25% | | | 5 |
Income Taxes
Significant management judgment is required in developing the provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination ofvaluation allowances that may be required to offset the related deferred tax assets, liabilities and valuation allowances.assets.
Significant management judgment is requiredIn order to determine the amount of benefit to be recognized relatedin relation to an uncertain tax position. Tax positions are evaluated followingposition, Talen Energy uses a two-step process.process to evaluate tax positions. The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained. This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position. The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion. The benefit recognized is measured atas the largest amount of benefit that has a likelihood of realization, upon settlement, that exceeds 50%. Management considers a number of factors in assessing the benefit to be recognized, including negotiation of a settlement.
At December 31, 2012, LG&E's existing reserve exposure to either increases or decreases in unrecognized tax benefits during the next 12 months is less than $1 million. This change could result from subsequent recognition, derecognition and/or changes in the measurement of uncertain tax positions. The events that could cause these changes are direct settlements with taxing authorities, litigation, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.
The balance sheet classification2015, Talen Energy had $31 million of unrecognized tax benefits and the need for valuation allowancesrecorded related to reduce deferred tax assets also require significant management judgment. acquired with MACH Gen. Unrecognized tax benefits are classified as currentrecorded at December 31, 2014 were settled with taxing authorities and PPL prior to the extent management expects to settle an uncertain tax position by payment or receipt of cash within one year of the reporting date. June 1, 2015 spinoff from PPL.
Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset. Management considers a number of factors in assessing the realization of a deferred tax asset, including the ability to carryback attributes, the reversal of temporary differences, future taxable income, and ongoing prudent and feasible tax planning strategies. Any tax planning strategy utilized in this assessment must meet the recognition and measurement criteria utilized to account for an uncertain tax position. Management also considers the uncertainty posed by political risk and the effect of this uncertainty on the various factors that management takes into account in evaluating the need for valuation allowances. The amount of net deferred tax assets ultimately realized may differ materially from the estimates utilized in the computation of valuation allowances and may materially impact the financial statements in the future.
As a result of management's assessment of the realization of deferred tax assets, a valuation allowance of $10 million was recorded at December 31, 2015, primarily related to MACH Gen net operating losses in states where it is expected that a portion of the losses will expire unutilized.
See Note 54 to the Financial Statements for related disclosures.
Regulatory Assets and Liabilities
additional information on income taxes.
LG&EBusiness Combinations - Purchase Price Allocation
On June 1, 2015, substantially contemporaneous with the spinoff by PPL to form Talen Energy, RJS Power was contributed by the Riverstone Holders to become a subsidiary of Talen Energy Supply. Additionally, on November 2, 2015, Talen Energy completed the acquisition of the membership interests of MACH Gen. In accordance with accounting guidance on business combinations, the identifiable assets acquired and the liabilities assumed were measured at fair value at the acquisition date. Fair value is defined as the price that would be received to sell an asset or paid to transfer a cost-based rate-regulated utility. Asliability in an orderly transaction between market participants. The excess of the purchase price over the estimated fair value of the identifiable net assets was recorded as goodwill.
The determination and allocation of fair value to the identifiable assets acquired and liabilities assumed was based on various assumptions and valuation methodologies requiring considerable management judgment, including estimates based on key assumptions of the acquisition, and historical and current market data. The most significant variables in these valuations were the discount rates, the number of years on which to base cash flow projections, as well as the assumptions and estimates used to determine cash inflows and outflows. Although the assumptions were reasonable based on information available at the dates of the acquisitions, actual results may differ from the forecasted amounts and the difference could be material.
The fair value of intangible assets and liabilities (e.g. contracts that have favorable or unfavorable terms relative to market), including coal contracts, a result,pipeline lease and an ash site permit, have been reflected on the effects of regulatory actions are required to be reflected in the financial statements. Assetsbalance sheet. These intangible assets and liabilities are recorded that result frombeing amortized over the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in regulated customer rates. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. In certain cases, regulatory liabilities are recorded based on an understanding with the regulator that rates have been set to recover costs that are expected to be incurred in the future, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose. The accounting for regulatory assets and liabilities is based on specific ratemaking decisions or precedent for each transaction or event as prescribed by the FERC and the KPSC.related contracts' terms.
Management continually assesses whetherGoodwill is measured as the regulatoryexcess of consideration transferred over the net of the acquisition date fair value of the assets are probableacquired and liabilities assumed. Goodwill related to the RJS acquisition of future recovery by considering factors such as changes$393 million was assigned to the East segment. There was no goodwill recorded in the applicable regulatoryprovisional purchase price allocation related to the MACH Gen acquisition. During the third quarter of 2015, impairment testing was completed and political environments,it was determined that all goodwill was impaired and was written off, including the abilitygoodwill recorded related to recover costs through regulated rates, recent rate ordersthe RJS acquisition. See Note 16 to other regulated entitiesthe Financial Statements for additional information regarding the goodwill impairment and Note 6 to the status of any pending or potential deregulation legislation. Based on this continual assessment, management believesFinancial Statements for additional information regarding the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, then asset write-off would be required to be recognized in operating income. Additionally, the regulatory agencies can provide flexibility in the manner and timing of the depreciation of PP&E and amortization of regulatory assets.purchase price allocations.
At December 31, 2012, LG&E had regulatory assets of $419 million and regulatory liabilities of $475 million. All regulatory assets are either currently being recovered under specific rate orders, represent amounts that are expected to be recovered in future rates or benefit future periods based upon established regulatory practices.
See Note 6 to the Financial Statements for additional information on regulatory assets and liabilities.regarding the acquisitions.
Other Information
PPL'sTalen Energy Corporation's Audit Committee has approved the independent auditor to provide audit and audit-related services, tax services and other services permitted by Sarbanes-Oxley and SEC rules. The audit and audit-related services include services in connection with statutory and regulatory filings, reviews of offering documents and registration statements, and internal control reviews. See "Item 14. Principal Accounting Fees and Services" for more information.
KENTUCKY UTILITIES COMPANY
The information provided in this Item 7 should be read in conjunction with KU's Financial Statements and the accompanying Notes. Capitalized terms and abbreviations are defined in the glossary. Dollars are in millions, unless otherwise noted.
"Management's Discussion and Analysis of Financial Condition and Results of Operations" includes the following information:
· | "Overview" provides a description of KU and its business strategy, a summary of Net Income and a discussion of certain events related to KU's results of operations and financial condition. |
· | "Results of Operations" provides a summary of KU's earnings and a description of key factors expected to impact future earnings. This section ends with explanations of significant changes in principal items on KU's Statements of Income, comparing 2012 with 2011 and 2011 with 2010. |
· | "Financial Condition - Liquidity and Capital Resources" provides an analysis of KU's liquidity position and credit profile. This section also includes a discussion of forecasted sources and uses of cash and rating agency actions. |
· | "Financial Condition - Risk Management" provides an explanation of KU's risk management programs relating to market and credit risk. |
· | "Application of Critical Accounting Policies" provides an overview of the accounting policies that are particularly important to the results of operations and financial condition of KU and that require its management to make significant estimates, assumptions and other judgments of matters inherently uncertain. |
Overview
Introduction
KU, headquartered in Lexington, Kentucky, is a regulated utility engaged in the generation, transmission, distribution and sale of electric energy in Kentucky, Virginia and Tennessee. KU and its affiliate, LG&E, are wholly owned subsidiaries of LKE. LKE, a holding company, became a wholly owned subsidiary of PPL when PPL acquired all of LKE's interests from E.ON US Investments Corp. on November 1, 2010. Following the acquisition, both KU and LG&E continue operating as subsidiaries of LKE, which is now an intermediary holding company in PPL's group of companies. Refer to "Item 1. Business - Background" for a description of KU's business.
Business Strategy
KU's overall strategy is to provide reliable, safe, competitively priced energy to its customers and reasonable returns on regulated investments to its shareowner.
A key objective for KU is to maintain a strong credit profile through managing financing costs and access to credit markets. KU continually focuses on maintaining an appropriate capital structure and liquidity position.
Successor and Predecessor Financial Presentation
KU's Financial Statements and related financial and operating data include the periods before and after PPL's acquisition of LKE on November 1, 2010 and have been segregated to present pre-acquisition activity as the Predecessor and post-acquisition activity as the Successor. Certain accounting and presentation methods were changed to acceptable alternatives to conform to PPL's accounting policies, and the cost bases of certain assets and liabilities were changed as of November 1, 2010 as a result of the application of push-down accounting. Consequently, the financial position, results of operations and cash flows for the Successor periods are not comparable to the Predecessor periods; however, the core operations of KU have not changed as a result of the acquisition.
Financial and Operational Developments
Net Income
Net Income for 2012, 2011 and 2010 was $137 million, $178 million and $175 million. Earnings in 2012 decreased 23% from 2011 and earnings in 2011 increased 2% from 2010.
See "Results of Operations" for a discussion and analysis of KU's earnings.
Rate Case Proceedings
In June 2012, KU filed a request with the KPSC for an increase in annual base electric rates of approximately $82 million. In November 2012, KU along with all of the parties filed a unanimous settlement agreement. Among other things, the settlement provided for increases in annual base electric rates of $51 million. The settlement agreement also included revised depreciation rates that result in reduced annual depreciation expense of approximately $10 million. The settlement agreement included an authorized return on equity of 10.25%. On December 20, 2012, the KPSC issued an order approving the provisions in the settlement agreement. The new rates became effective on January 1, 2013.
Equity Method Investment
KU owns 20% of the common stock of EEI. Through a power marketer affiliated with its majority owner, EEI sells its output to third parties. KU's investment in EEI is accounted for under the equity method of accounting. KU's direct exposure to loss as a result of its involvement with EEI is generally limited to the value of its investment. During the fourth quarter of 2012, KU concluded that an other-than-temporary decline in the value of its investment in EEI had occurred. Accordingly, KU recorded a $15 million impairment charge, net of taxes, related to this investment as of December 31, 2012, bringing the investment balance to zero. The impairment charge is shown in the line "Other-Than-Temporary Impairments" on the Statement of Income for the year ended December 31, 2012.
Commercial Paper
In February 2012, KU established a commercial paper program for up to $250 million to provide an additional financing source to fund its short-term liquidity needs, if and when necessary. Commercial paper issuances are supported by KU's Syndicated Credit Facility. At December 31, 2012, KU had $70 million of commercial paper outstanding.
Terminated Bluegrass CTs Acquisition
In September 2011, KU and LG&E entered into an asset purchase agreement with Bluegrass Generation for the purchase of the Bluegrass CTs, aggregating approximately 495 MW, plus limited associated contractual arrangements required for operation of the units, for a purchase price of $110 million, pending receipt of applicable regulatory approvals. In May 2012, the KPSC issued an order approving the request to purchase the Bluegrass CTs. In November 2011, KU and LG&E filed an application with the FERC under the Federal Power Act requesting approval to purchase the Bluegrass CTs. In May 2012, the FERC issued an order conditionally authorizing the acquisition of the Bluegrass CTs, subject to approval by the FERC of satisfactory mitigation measures to address market-power concerns. After a review of potentially available mitigation options, KU and LG&E determined that the options were not commercially justifiable. In June 2012, KU and LG&E terminated the asset purchase agreement for the Bluegrass CTs in accordance with its terms and made applicable filings with the KPSC and FERC.
Cane Run Unit 7 Construction
In September 2011, KU and LG&E filed a CPCN with the KPSC requesting approval to build Cane Run Unit 7. In May 2012, the KPSC issued an order approving the request. KU will own a 78% undivided interest and LG&E will own a 22% undivided interest in the new generating unit. A formal request for recovery of the costs associated with the construction was not included in the CPCN filing with the KPSC but is expected to be included in future rate case proceedings. KU and LG&E commenced preliminary construction activities in the third quarter of 2012 and project construction is expected to be completed by May 2015. The project, which includes building a natural gas supply pipeline and related transmission projects, has an estimated cost of approximately $600 million.
In conjunction with this construction and to meet new, more stringent EPA regulations with a 2015 compliance date, KU anticipates retiring two older coal-fired electric generating units at the Green River plant, which have a combined summer capacity rating of 163 MW. In addition, KU retired the remaining 71 MW unit at the Tyrone plant in February 2013.
Future Capacity Needs
In addition to the construction of a combined cycle gas unit at the Cane Run station, KU and LG&E continue to assess future capacity needs. As a part of the assessment, KU and LG&E issued an RFP in September 2012 for up to 700 MW of capacity beginning as early as 2015.
Results of Operations
As previously noted, KU's results for the periods after October 31, 2010 are on a basis of accounting different from its results for periods prior to November 1, 2010. See "Overview - Successor and Predecessor Financial Presentation" for further information.
The utility business is affected by seasonal weather. As a result, operating revenues (and associated operating expenses) are not generated evenly throughout the year. Revenue and earnings are generally higher during the first and third quarters and lower during the second and fourth quarters due to weather.
The following table summarizes the significant components of net income for 2012, 2011 and 2010 and the changes therein:
Earnings | | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| | | | | | | | Two Months | | | Ten Months |
| | Year Ended | | Year Ended | | Ended | | | Ended |
| | December 31, | | December 31, | | December 31, | | | October 31, |
| | | 2012 | | 2011 | | 2010 | | | 2010 |
| | | | | | | | | | | | | | |
Net Income | | $ | 137 | | $ | 178 | | $ | 35 | | | $ | 140 |
The changes in the components of Net Income between these periods were due to the following factors, which reflect reclassifications for items included in Margins and certain items that management considers special.
| | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | |
Margins | | $ | (10) | | $ | 52 |
Other operation and maintenance | | | (16) | | | (12) |
Depreciation | | | (6) | | | (28) |
Taxes, other than income | | | (4) | | | (9) |
Other Income (Expense) - net | | | (7) | | | (2) |
Interest Expense | | | 1 | | | 8 |
Income Taxes | | | 16 | | | (6) |
Special items, after-tax | | | (15) | | | |
Total | | $ | (41) | | $ | 3 |
As a result of low energy prices and environmental regulations, KU assessed the recoverability of its equity method investment in EEI. KU determined it was impaired, and recorded a $15 million impairment charge, net of taxes, as of December 31, 2012. This impairment is considered a special item by management.
· | See "Statement of Income Analysis - Margins - Changes in Non-GAAP Financial Measures" for an explanation of Margins. |
· | Higher other operation and maintenance in 2012 compared with 2011 primarily due to $8 million of higher coal plant maintenance costs related to an increased scope of scheduled outages and a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs. |
| Higher other operation and maintenance in 2011 compared with 2010 primarily due to $19 million of higher coal plant maintenance costs related to an increased scope of scheduled outages and higher variable costs from increased generation due to TC2 commencing dispatch in January 2011. This increase was partially offset by a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs. |
· | Higher depreciation in 2011 compared with 2010 primarily due to TC2 commencing dispatch in January 2011. |
· | Lower interest expense in 2011 compared with 2010 primarily due to $18 million less expense primarily related to lower interest rates on the first mortgage bonds issued in November 2010 compared with the rates on the loans from E.ON AG affiliates in place through October 2010. This decrease was partially offset by $8 million of higher expense resulting from higher long-term debt balances. |
· | Lower income taxes in 2012 compared with 2011 primarily due to lower pre-tax income. |
2013 Outlook
Excluding special items, KU projects higher earnings in 2013 compared with 2012, primarily driven by electric base rate increases effective January 1, 2013, returns on additional environmental capital investments and retail load growth, partially offset by higher operation and maintenance.
Earnings in future periods are subject to various risks and uncertainties. See "Forward-Looking Information," "Item 1. Business," "Item 1A. Risk Factors," the rest of this Item 7 and Notes 6 and 15 to the Financial Statements for a discussion of the risks, uncertainties and factors that may impact future earnings.
Statement of Income Analysis --
Margins
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as a non-GAAP financial measure, "Margins." Margins is not intended to replace "Operating Income," which is determined in accordance with GAAP as an indicator of overall operating performance. Other companies may use different measures to analyze and to report on the results of their operations. Margins is a single financial performance measure of KU's electricity generation, transmission and distribution operations. In calculating this measure, fuel and energy purchases are deducted from revenues. In addition, utility revenues and expenses associated with approved cost recovery mechanisms are offset. These mechanisms allow for recovery of certain expenses, returns on capital investments primarily associated with environmental regulations and performance incentives. Certain costs associated with these mechanisms, primarily ECR and DSM, are recorded as "Other operation and maintenance" and "Depreciation." As a result, this measure represents the net revenues from KU's operations. This performance measure is used, in conjunction with other information, internally by senior management to manage operations and analyze actual results compared with budget.
Reconciliation of Non-GAAP Financial Measures
The following tables reconcile "Operating Income" to "Margins" as defined by KU for 2012, 2011 and 2010.
| | | | | | 2012 Successor | | | | 2011 Successor |
| | | | | | | | | | | Operating | | | | | | | | | Operating |
| | | | | | Margins | | Other (a) | | Income (b) | | | | Margins | | Other (a) | | Income (b) |
| | | | | | | | | | | | | | | | | | |
Operating Revenues | | $ | 1,524 | | | | | $ | 1,524 | | | | $ | 1,548 | | | | | $ | 1,548 |
Operating Expenses | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 498 | | | | | | 498 | | | | | 516 | | | | | | 516 |
| Energy purchases | | | 109 | | | | | | 109 | | | | | 112 | | | | | | 112 |
| Other operation and maintenance | | | 55 | | $ | 329 | | | 384 | | | | | 49 | | $ | 313 | | | 362 |
| Depreciation | | | 49 | | | 144 | | | 193 | | | | | 48 | | | 138 | | | 186 |
| Taxes, other than income | | | | | | 23 | | | 23 | | | | | | | | 19 | | | 19 |
| | | Total Operating Expenses | | | 711 | | | 496 | | | 1,207 | | | | | 725 | | | 470 | | | 1,195 |
Total | | $ | 813 | | $ | (496) | | $ | 317 | | | | $ | 823 | | $ | (470) | | $ | 353 |
| | | | | | Successor | | | Predecessor |
| | | | | | Two Months Ended December 31, 2010 | | | Ten Months Ended October 31, 2010 |
| | | | | | | | | | | Operating | | | | | | | | | Operating |
| | | | | | Margins | | Other (a) | | Income (b) | | | Margins | | Other (a) | | Income (b) |
| | | | | | | | | | | | | | | | | | |
Operating Revenues | | $ | 263 | | | | | $ | 263 | | | $ | 1,248 | | | | | $ | 1,248 |
Operating Expenses | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 78 | | | | | | 78 | | | | 417 | | | | | | 417 |
| Energy purchases | | | 28 | | | | | | 28 | | | | 147 | | | | | | 147 |
| Other operation and maintenance | | | 6 | | $ | 59 | | | 65 | | | | 29 | | $ | 242 | | | 271 |
| Depreciation | | | 6 | | | 20 | | | 26 | | | | 29 | | | 90 | | | 119 |
| Taxes, other than income | | | | | | 1 | | | 1 | | | | | | | 9 | | | 9 |
| | | Total Operating Expenses | | | 118 | | | 80 | | | 198 | | | | 622 | | | 341 | | | 963 |
Total | | $ | 145 | | $ | (80) | | $ | 65 | | | $ | 626 | | $ | (341) | | $ | 285 |
(a) | Represents amounts excluded from Margins. |
(b) | As reported on the Statements of Income. |
Changes in Non-GAAP Financial Measures
Margins decreased by $10 million for 2012 compared with 2011, primarily due to $10 million of lower retail margins, as volumes were impacted by unseasonably mild weather during the first four months of 2012. Total heating degree days decreased 9% compared to 2011, partially offset by a 4% increase in cooling degree days.
Margins increased by $52 million for 2011 compared with 2010. New KPSC rates went into effect on August 1, 2010, contributing to an additional $64 million in operating revenue over the prior year. Partially offsetting the rate increase were lower retail volumes resulting from weather and economic conditions.
Other Operation and Maintenance | | | | | |
| | | | | | |
The increase (decrease) in other operation and maintenance was due to: |
| | |
| 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | |
Coal plant maintenance (a) | $ | 17 | | $ | 9 |
Distribution maintenance (b) | | 8 | | | |
Administrative and general (c) | | (5) | | | 7 |
Fuel for generation (d) | | | | | 6 |
Steam operation (e) | | | | | 10 |
Other generation maintenance | | | | | (2) |
Other | | 2 | | | (4) |
Total | $ | 22 | | $ | 26 |
(a) | Coal plant maintenance costs increased in 2012 compared with 2011 primarily due to $8 million of expenses related to an increased scope of scheduled outages, as well as $5 million of increased maintenance on the scrubber system and primary fuel combustion system at the Ghent plant. |
| Coal plant maintenance costs increased in 2011 compared with 2010 primarily due to $8 million of expenses related to an increased scope of scheduled outages. |
(b) | Distribution maintenance increased in 2012 compared with 2011 primarily due to a $6 million credit to establish a regulatory asset recorded when approved in 2011 related to 2009 storm costs. |
(c) | Administrative and general costs decreased in 2012 compared with 2011 primarily due to a decrease in pension expense resulting from pension funding and lower interest cost. |
| Administrative and general costs increased in 2011 compared with 2010 due to higher outside services costs of $2 million, higher labor costs of $1 million and higher pension costs of $1 million. |
(d) | Fuel handling costs are included in other operation and maintenance on the Statements of Income for the Successor periods and are in fuel on the Statement of Income for the Predecessor period. |
(e) | Steam operation costs increased in 2011 compared with 2010 due to increased generation as a result of TC2 commencing dispatch in 2011. |
Depreciation
The increase (decrease) in depreciation was due to:
| | 2012 vs. 2011 | | 2011 vs. 2010 |
| | | | | | |
TC2 (dispatch began in January 2011) | | | | $ | 25 |
E.W. Brown sulfur dioxide scrubber equipment (placed in-service in June 2010) | | | | | 8 |
Other additions to PP&E | $ | 7 | | | 8 |
Total | $ | 7 | | $ | 41 |
Taxes, Other Than Income
Taxes, other than income increased by $9 million in 2011 compared with 2010, primarily due to a $5 million state coal tax credit that was applied to 2010 property taxes. The remaining increase was due to higher assessments, primarily from significant property additions.
Other Income (Expense) - net
Other income (expense) - net decreased by $7 million in 2012 compared with 2011 primarily due to $8 million losses from the EEI investment recorded in 2012.
Other-Than-Temporary Impairments
Other-than-temporary impairments increased by $25 million in 2012 compared with 2011 due to the $25 million pre-tax impairment of the EEI investment. See Notes 1 and 18 to the Financial Statements for additional information.
Interest Expense
Interest expense decreased by $8 million in 2011 compared with 2010, primarily due to $18 million less expense primarily related to lower interest rates on the first mortgage bonds issued in November 2010 compared with the rates on the loans from E.ON AG affiliates in place through October 2010. This decrease was partially offset by $8 million of higher expense resulting from higher long-term debt balances.
Income Taxes
Income taxes decreased by $26 million in 2012 compared with 2011, primarily due to the decrease in pre-tax income.
Income taxes increased by $6 million in 2011 compared with 2010, primarily due to the increase in pre-tax income.
Financial Condition
Liquidity and Capital Resources
KU expects to continue to have adequate liquidity available through operating cash flows, cash and cash equivalents, its credit facilities and commercial paper issuances. Additionally, subject to market conditions, KU currently plans to access capital markets in 2013.
KU's cash flows from operations and access to cost-effective bank and capital markets are subject to risks and uncertainties including, but not limited to:
· | changes in commodity prices that may increase the cost of producing or purchasing power or decrease the amount KU receives from selling power; |
· | operational and credit risks associated with selling and marketing products in the wholesale power markets; |
· | unusual or extreme weather that may damage KU's transmission and distribution facilities or affect energy sales to customers; |
· | reliance on transmission facilities that KU does not own or control to deliver its electricity; |
· | unavailability of generating units (due to unscheduled or longer-than-anticipated generation outages, weather and natural disasters) and the resulting loss of revenues and additional costs of replacement electricity; |
· | the ability to recover and the timeliness and adequacy of recovery of costs associated with regulated utility businesses; |
· | costs of compliance with existing and new environmental laws; |
· | any adverse outcome of legal proceedings and investigations with respect to KU's current and past business activities; |
· | deterioration in the financial markets that could make obtaining new sources of bank and capital markets funding more difficult and more costly; and |
· | a downgrade in KU's credit ratings that could adversely affect its ability to access capital and increase the cost of credit facilities and any new debt. |
See "Item 1A. Risk Factors" for further discussion of risks and uncertainties affecting KU's cash flows.
At December 31, KU had the following:
| | 2012 | | 2011 | | 2010 |
| | | | | | | | | |
Cash and cash equivalents | | $ | 21 | | $ | 31 | | $ | 3 |
| | | | | | | | | |
Short-term debt (a) | | $ | 70 | | | | | | |
(a) | Represents borrowings made under KU's commercial paper program. See Note 7 to the Financial Statements for additional information. |
| The changes in KU's cash and cash equivalents position resulted from: |
| | | | | Successor | | | Predecessor |
| | | | | | | | | Two Months | | | Ten Months |
| | | | | Year Ended | | Year Ended | | Ended | | | Ended |
| | | | | December 31, | | December 31, | | December 31, | | | October 31, |
| | | | | 2012 | | 2011 | | 2010 | | | 2010 |
| | | | | | | | | | | | | |
Net cash provided by operating activities | | $ | 500 | | $ | 444 | | $ | 30 | | | $ | 344 |
Net cash provided by (used in) investing activities | | | (480) | | | (279) | | | (89) | | | | (340) |
Net cash provided by (used in) financing activities | | | (30) | | | (137) | | | 58 | | | | (2) |
Net Increase (Decrease) in Cash and Cash Equivalents | | $ | (10) | | $ | 28 | | $ | (1) | | | $ | 2 |
Operating Activities
Net cash provided by operating activities increased by 13%, or $56 million, in 2012 compared with 2011, primarily as a result of:
· | Other operating cash flows increased by $45 million driven by a $29 million reduction in pension funding. |
· | Working capital cash flows increased by $11 million driven by lower income tax payments as a result of lower taxable income in 2012, offset by changes in receivables and unbilled revenues due to milder December weather in 2011 than in 2012 and 2010. |
Net cash provided by operating activities increased by 19%, or $70 million, in 2011 compared with 2010, primarily as a result of:
· | an increase in net income adjusted for non-cash effects of $115 million (deferred income taxes and investment tax credits of $81 million and depreciation of $41 million, partially offset by defined benefit plans - expense of $2 million and other noncash items of $19 million); |
· | a net decrease in working capital related to unbilled revenues of $21 million due to colder weather in December 2010 as compared with December 2009, and milder weather in December 2011 as compared with December 2010; partially offset by |
· | an increase in discretionary defined benefit plan contributions of $30 million made in order to achieve KU's long-term funding requirements; |
· | the timing of ECR collections of $28 million; and |
· | an increase in cash outflows related to accrued taxes of $28 million due to an accrual in excess of payments made in 2010 for the 2010 tax year and the payment of the 2010 tax liability in 2011, along with payments made in 2011 over the accrual for the 2011 tax year. |
Investing Activities
Net cash used in investing activities increased by 72%, or $201 million, in 2012 compared with 2011, as a result of an increase in capital expenditures of $201 million, primarily due to coal combustion residuals projects at Ghent and E.W. Brown, construction of Cane Run Unit 7 and Ghent environmental air projects.
See "Forecasted Uses of Cash" for detail regarding projected capital expenditures for the years 2013 through 2017.
Net cash used in investing activities decreased by 35%, or $150 million, in 2011 compared with 2010, as a result of a decrease in capital expenditures of $150 million primarily due to the completion of KU's scrubber program in 2010 and TC2 being dispatched in 2011.
Financing Activities
Net cash used in financing activities was $30 million in 2012 compared with net cash provided by financing activities of $137 million in 2011, primarily as a result of less long-term debt issuances and higher dividends to LKE.
In 2012, cash used in financing activities consisted of:
· | the payment of common stock dividends to LKE of $100 million; partially offset by |
· | the issuance of short-term debt in the form of commercial paper $70 million. |
Net cash used in financing activities was $137 million in 2011 compared with net cash provided by financing activities of $56 million in 2010, primarily as a result of less long-term debt issuances and higher dividends to LKE.
In 2011, cash used in financing activities consisted of:
· | the payment of common stock dividends to LKE of $124 million; |
· | a net decrease in notes payable with affiliates of $10 million; and |
· | the payment of debt issuance and credit facility costs of $3 million. |
In the two months of 2010 following the acquisition, cash provided by financing activities of the Successor consisted of:
· | the issuance of first mortgage bonds of $1,489 million after discounts; and |
· | the issuance of debt of $1,331 million to a PPL affiliate to repay debt due to an E.ON AG affiliate upon the closing of PPL's acquisition of LKE; partially offset by |
· | the repayment of debt to an E.ON AG affiliate of $1,331 million upon the closing of PPL's acquisition of LKE; |
· | the repayment of debt to a PPL affiliate of $1,331 million upon the issuance of first mortgage bonds; |
· | a net decrease in notes payable with affiliates of $83 million; and |
· | the payment of debt issuance and credit facility costs of $17 million. |
In the ten months of 2010 preceding PPL's acquisition of LKE, cash used in financing activities by the Predecessor consisted of:
· | the payment of common stock dividends to LKE of $50 million; partially offset by |
· | a net increase in notes payable with affiliates of $48 million. |
See "Forecasted Sources of Cash" for a discussion of KU's plans to issue debt securities, as well as a discussion of credit facility capacity available to KU. Also see "Forecasted Uses of Cash" for a discussion of plans to pay dividends on common securities in the future, as well as maturities of long-term debt.
KU had no long-term debt securities activity during the year.
See Note 7 to the Financial Statements for additional information about long-term debt securities.
Auction Rate Securities
At December 31, 2012, KU's tax-exempt revenue bonds that are in the form of auction rate securities and total $96 million continue to experience failed auctions. Therefore, the interest rate continues to be set by a formula pursuant to the relevant indentures. For the period ended December 31, 2012, the weighted-average rate on KU's auction rate bonds in total was 0.25%.
Forecasted Sources of Cash
KU expects to continue to have sufficient sources of cash available in the near term, including various credit facilities, its commercial paper program, issuance of debt securities and operating cash flow.
Credit Facilities
At December 31, 2012, KU's total committed borrowing capacity under its credit facilities and the use of this borrowing capacity were:
| | | | | Commercial | | Letters of | | Unused |
| | | Capacity | | Paper Issued | | Credit Issued | | Capacity |
| | | | | | | | | |
Syndicated Credit Facility (a) (d) | | $ | 400 | | $ | 70 | | | | | $ | 330 |
Letter of Credit Facility (b) (d) | | | 198 | | | | | $ | 198 | | | |
| Total Credit Facilities (c) | | $ | 598 | | $ | 70 | | $ | 198 | | $ | 330 |
(a) | In November 2012, KU amended its Syndicated Credit Facility to extend the expiration date to November 2017. |
(b) | In August 2012, the KU letter of credit facility agreement was amended and restated to allow for certain payments under the letter of credit facility to be converted to loans rather than requiring immediate payment. |
(c) | The commitments under KU's credit facilities are provided by a diverse bank group, with no one bank and its affiliates providing an aggregate commitment of more than 19% of the total committed capacity available to KU. |
(d) | KU pays customary fees under its syndicated credit facility as well as its letter of credit facility, and borrowings generally bear interest at LIBOR-based rates plus an applicable margin. |
KU participates in an intercompany money pool agreement whereby LKE and/or LG&E make available to KU funds up to $500 million at an interest rate based on a market index of commercial paper issues. At December 31, 2012 there was no balance outstanding.
See Note 7 to the Financial Statements for further discussion of KU's credit facilities.
Operating Leases
KU also has available funding sources that are provided through operating leases. KU leases office space and certain equipment. These leasing structures provide KU additional operating and financing flexibility. The operating leases contain covenants that are typical for these agreements, such as maintaining insurance, maintaining corporate existence and timely payment of rent and other fees.
See Note 11 to the Financial Statements for further discussion of the operating leases.
Capital Contributions from LKE
From time to time LKE may make capital contributions to KU. KU may use these contributions to fund capital expenditures and for other general corporate purposes.
Long-term Debt Securities
KU currently plans to issue, subject to market conditions, up to $300 million of first mortgage bond indebtedness in 2013, the proceeds of which will be used to fund capital expenditures and for other general corporate purposes.
Forecasted Uses of Cash
In addition to expenditures required for normal operating activities, such as purchased power, payroll, fuel and taxes, KU currently expects to incur future cash outflows for capital expenditures, various contractual obligations, payment of dividends on its common stock and possibly the purchase or redemption of a portion of debt securities.
Capital Expenditures
The table below shows KU's current capital expenditure projections for the years 2013 through 2017.
| | | | Projected |
| | | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
Capital expenditures (a) | | | | | | | | | | | | | | | |
| Generating facilities | | $ | 289 | | $ | 140 | | $ | 136 | | $ | 251 | | $ | 308 |
| Distribution facilities | | | 89 | | | 87 | | | 97 | | | 92 | | | 107 |
| Transmission facilities | | | 48 | | | 37 | | | 40 | | | 40 | | | 61 |
| Environmental | | | 331 | | | 386 | | | 264 | | | 106 | | | 65 |
| Other | | | 27 | | | 24 | | | 25 | | | 27 | | | 22 |
| | Total Capital Expenditures | | $ | 784 | | $ | 674 | | $ | 562 | | $ | 516 | | $ | 563 |
(a) | KU generally expects to recover these costs over a period equivalent to the related depreciable lives of the assets through rates. The 2013 total excludes amounts included in accounts payable as of December 31, 2012. |
KU's capital expenditure projections for the years 2013 through 2017 total approximately $3.1 billion. Capital expenditure plans are revised periodically to reflect changes in operational, market and regulatory conditions. This table includes current estimates for KU's environmental projects related to existing and proposed EPA compliance standards. Actual costs may be significantly lower or higher depending on the final requirements and market conditions. Environmental compliance costs incurred by KU in serving KPSC jurisdictional customers are generally eligible for recovery through the ECR mechanism.
KU plans to fund its capital expenditures in 2013 with cash on hand, cash from operations, short-term debt and issuance of debt securities.
Contractual Obligations
KU has assumed various financial obligations and commitments in the ordinary course of conducting its business. At December 31, 2012, the estimated contractual cash obligations of KU were:
| | | | Total | | 2013 | | 2014 - 2015 | | 2016 - 2017 | | After 2017 |
| | | | | | | | | | | | | | | | | |
Long-term Debt (a) | | $ | 1,851 | | | | | $ | 250 | | | | | $ | 1,601 |
Interest on Long-term Debt (b) | | | 1,481 | | $ | 64 | | | 130 | | $ | 126 | | | 1,161 |
Operating Leases (c) | | | 51 | | | 9 | | | 15 | | | 9 | | | 18 |
Coal and Natural Gas Purchase | | | | | | | | | | | | | | | |
| | Obligations (d) | | | 1,046 | | | 411 | | | 479 | | | 156 | | | - |
Unconditional Power Purchase | | | | | | | | | | | | | | | |
| | Obligations (e) | | | 319 | | | 9 | | | 18 | | | 20 | | | 272 |
Construction Obligations (f) | | | 1,023 | | | 455 | | | 366 | | | 202 | | | |
Pension Benefit Plan Obligations (g) | 59 | | | 59 | | | | | | | | | |
Other Obligations (h) | | | 21 | | | 5 | | | 9 | | | 6 | | | 1 |
Total Contractual Cash Obligations | | $ | 5,851 | | $ | 1,012 | | $ | 1,267 | | $ | 519 | | $ | 3,053 |
(a) | Reflects principal maturities only based on stated maturity dates. See Note 7 to the Financial Statements for a discussion of variable-rate remarketable bonds issued on behalf of KU. KU has no capital lease obligations. |
(b) | Assumes interest payments through stated maturity. The payments herein are subject to change, as payments for debt that is or becomes variable-rate debt have been estimated. |
(c) | See Note 11 to the Financial Statements for additional information. |
(d) | Represents contracts to purchase coal, natural gas and natural gas transportation. See Note 15 to the Financial Statements for additional information. |
(e) | Represents future minimum payments under OVEC power purchase agreements through June 2040. See Note 15 to the Financial Statements for additional information. |
(f) | Represents construction commitments, including commitments for the Ghent environmental air projects, Cane Run Unit 7 and Ghent landfill which are also reflected in the Capital Expenditures table presented above. |
(g) | Based on the current funded status of LKE's qualified pension plan, which covers KU employees, no cash contributions are required. See Note 13 to the Financial Statements for a discussion of expected contributions. |
(h) | Represents other contractual obligations. |
Dividends
From time to time, as determined by its Board of Directors, KU pays dividends to its sole shareholder, LKE.
As discussed in Note 7 to the Financial Statements, KU's ability to pay dividends is limited under a covenant in its $400 million revolving line of credit facility. This covenant restricts the debt to total capital ratio to not more than 70%. See Note 7 to the Financial Statements for other restrictions related to distributions on capital interests for KU.
Purchase or Redemption of Debt Securities
KU will continue to evaluate purchasing or redeeming outstanding debt securities and may decide to take action depending upon prevailing market conditions and available cash.
Rating Agency Actions
Moody's, S&P and Fitch periodically review the credit ratings on the debt securities of KU. Based on their respective independent reviews, the rating agencies may make certain ratings revisions or ratings affirmations.
A credit rating reflects an assessment by the rating agency of the creditworthiness associated with an issuer and particular securities that it issues. The credit ratings of KU are based on information provided by KU and other sources. The ratings of Moody's, S&P and Fitch are not a recommendation to buy, sell or hold any securities of KU. Such ratings may be subject to revisions or withdrawal by the agencies at any time and should be evaluated independently of each other and any other rating that may be assigned to the securities. The credit ratings of KU affect its liquidity, access to capital markets and cost of borrowing under its credit facilities.
The following table sets forth KU's security credit ratings as of December 31, 2012.
| | Senior Unsecured | | Senior Secured | | Commercial Paper |
| | | | | | | | | | | | | | | | | | |
Issuer | | Moody's | | S&P | | Fitch | | Moody's | | S&P | | Fitch | | Moody's | | S&P | | Fitch |
| | | | | | | | | | | | | | | | | | |
Kentucky Utilities | | | | | | A | | A2 | | A- | | A+ | | P-2 | | A-2 | | F-2 |
In addition to the credit ratings noted above, the rating agencies took the following actions related to KU:
In February 2012, Fitch assigned ratings to KU's newly established commercial paper program.
In March 2012, Moody's affirmed the following ratings:
· the long-term ratings of the First Mortgage Bonds for KU;
· the issuer ratings for KU; and
· the bank loan ratings for KU.
Also in March 2012, Moody's and S&P each assigned short-term ratings to KU's newly established commercial paper program.
In December 2012, Fitch affirmed the issuer default ratings, individual security ratings and outlook for KU.
Ratings Triggers
KU has various derivative and non-derivative contracts, including contracts for the sale and purchase of electricity, fuel, and commodity transportation and storage, which contain provisions requiring KU to post additional collateral, or permitting the counterparty to terminate the contract, if KU's credit rating were to fall below investment grade. See Note 19 to the Financial Statements for a discussion of "Credit Risk-Related Contingent Features," including a discussion of the potential additional collateral that would have been required for derivative contracts in a net liability position at December 31, 2012. At December 31, 2012, if KU's credit ratings had been below investment grade, the maximum amount that KU would have been required to post as additional collateral to counterparties was $21 million for both derivative and non-derivative commodity and commodity-related contracts used in its generation and marketing operations.
Off-Balance Sheet Arrangements
KU has entered into certain agreements that may contingently require payment to a guaranteed or indemnified party. See Note 15 to the Financial Statements for a discussion of these agreements.
Risk Management
Market Risk
See Notes 1, 18 and 19 to the Financial Statements for information about KU's risk management objectives, valuation techniques and accounting designations.
The forward-looking information presented below provides estimates of what may occur in the future, assuming certain adverse market conditions and model assumptions. Actual future results may differ materially from those presented. These disclosures are not precise indicators of expected future losses, but only indicators of possible losses under normal market conditions at a given confidence level.
Commodity Price Risk (Non-trading)
KU's rates are set by regulatory commissions and the fuel costs incurred are directly recoverable from customers. As a result, KU is subject to commodity price risk for only a small portion of on-going business operations. KU sells excess economic generation to maximize the value of the physical assets at times when the assets are not required to serve KU's or LG&E's customers. See Note 19 to the Financial Statements for additional disclosures.
The balance and change in net fair value of KU's commodity derivative contracts for the periods ended December 31, 2012, 2011 and 2010 were not significant.
Interest Rate Risk
KU issues debt to finance its operations, which exposes it to interest rate risk. KU utilizes various financial derivative instruments to adjust the mix of fixed and floating interest rates in its debt portfolio when appropriate. Risk limits under KU's risk management program are designed to balance risk, exposure to volatility in interest expense and changes in the fair value of KU's debt portfolio due to changes in the absolute level of interest rates.
At December 31, 2012 and 2011, KU's potential annual exposure to increased interest expense, based on a 10% increase in interest rates, was not significant.
KU is also exposed to changes in the fair value of its debt portfolio. KU estimated that a 10% decrease in interest rates at December 31, 2012, would increase the fair value of its debt portfolio by $67 million compared with $72 million at December 31, 2011.
At December 31, 2012, KU had the following interest rate hedges outstanding: |
| | | | | | | | | | |
| | | | | | | Effect of a |
| | | | | Fair Value, | | 10% Adverse |
| | | Exposure | | Net - Asset | | Movement |
| | | Hedged | | (Liability) | | in Rates |
Cash flow hedges | | | | | | | | | |
| Interest rate swaps (a) | | $ | 150 | | $ | 7 | | $ | (9) |
(a) | KU utilizes various risk management instruments to reduce its exposure to the expected future cash flow variability of its debt instruments. These risks include exposure to adverse interest rate movements for outstanding variable rate debt and for future anticipated financing. While KU is exposed to changes in the fair value of these instruments, any realized changes in the fair value of such cash flow hedges are recoverable through regulated rates and any subsequent changes in fair value of these derivatives are included in regulatory assets or liabilities. Sensitivities represent a 10% adverse movement in interest rates. The positions outstanding at December 31, 2012 mature through 2043. |
Credit Risk
KU is exposed to potential losses as a result of nonperformance by counterparties of their contractual obligations. KU maintains credit policies and procedures to limit counterparty credit risk including evaluating credit ratings and financial information along with having certain counterparties post margin if the credit exposure exceeds certain thresholds. KU is exposed to potential losses as a result of nonpayment by customers. KU maintains an allowance for doubtful accounts based on a historical charge-off percentage for retail customers. Allowances for doubtful accounts from wholesale and municipal customers and miscellaneous receivables are based on specific identification by management. Retail, wholesale and municipal customer accounts are written-off after four months of no payment activity. Miscellaneous receivables are written-off as management determines them to be uncollectible.
Certain of KU's derivative instruments contain provisions that require it to provide immediate and on-going collateralization of derivative instruments in net liability positions based upon KU's credit ratings from each of the major credit rating agencies. See Notes 18 and 19 to the Financial Statements for information regarding exposure and the risk management activities.
Related Party Transactions
KU is not aware of any material ownership interest or operating responsibility by senior management in outside partnerships, including leasing transactions with variable interest entities or other entities doing business with KU. See Note 16 to the Financial Statements for additional information on related party transactions.
Environmental Matters
Protection of the environment is a major priority for KU and a significant element of its business activities. Extensive federal, state and local environmental laws and regulations are applicable to KU's air emissions, water discharges and the management of hazardous and solid waste, among other areas, and the costs of compliance or alleged non-compliance cannot be predicted with certainty but could be material. In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed from prior versions by the relevant agencies. Costs may take the form of increased capital expenditures or operating and maintenance expenses; monetary fines, penalties or forfeitures or other restrictions. Many of these environmental law considerations are also applicable to the operations of key suppliers, or customers, such as coal producers, industrial power users, etc.; and may impact the costs for their products or their demand for KU's services.
Physical effects associated with climate change could include the impact of changes in weather patterns, such as storm frequency and intensity, and the resultant potential damage to KU's generation assets and electricity transmission and distribution systems, as well as impacts on customers. In addition, changed weather patterns could potentially reduce annual rainfall in areas where KU has hydro generating facilities or where river water is used to cool its fossil powered generators. KU cannot currently predict whether its businesses will experience these potential climate change-related risks or estimate the potential cost of their related consequences.
See "Item 1. Business - Environmental Matters" and Note 15 to the Financial Statements for a discussion of environmental matters.
New Accounting Guidance
See Notes 1 and 24 to the Financial Statements for a discussion of new accounting guidance adopted and pending adoption.
Application of Critical Accounting Policies
Financial condition and results of operations are impacted by the methods, assumptions and estimates used in the application of critical accounting policies. The following accounting policies are particularly important to the financial condition or results of operations, and require estimates or other judgments of matters inherently uncertain. Changes in the estimates or other judgments included within these accounting policies could result in a significant change to the information presented in the Financial Statements (these accounting policies are also discussed in Note 1 to the Financial Statements). KU's senior management has reviewed these critical accounting policies, the following disclosures regarding their application and the estimates and assumptions regarding them, with PPL's Audit Committee.
Revenue Recognition - Unbilled Revenue |
Revenues related to the sale of energy are recorded when service is rendered or when energy is delivered to customers. Because customers of KU's retail operations are billed on cycles which vary based on the timing of the actual reading of their electric meters, KU records estimates for unbilled revenues at the end of each reporting period. Such unbilled revenue amounts reflect estimates of the amount of electricity delivered to customers since the date of the last reading of their meters. The unbilled revenues reflect consideration of estimated usage by customer class, the effect of different rate schedules, changes in weather, and where applicable, the impact of weather normalization or other regulatory provisions of rate structures. In addition to the unbilled revenue accrual resulting from cycle billing, KU makes additional accruals resulting from the timing of customer bills. The accrual of unbilled revenues in this manner properly matches revenues and related costs. At December 31, 2012 and 2011, KU had unbilled revenue balances of $84 million and $81 million.
KU participates in a qualified funded defined benefit pension plan and a funded other postretirement benefit plan. These plans are applicable to the majority of the employees of KU and are sponsored by LKE. LKE allocates a portion of the liability and net periodic defined benefit pension and other postretirement costs of the plans to KU based on its participation. KU records an asset or liability to recognize the funded status of all defined benefit plans with an offsetting entry to regulatory assets or liabilities. Consequently, the funded status of all defined benefit plans is fully recognized on the Balance Sheets. See Note 13 to the Financial Statements for additional information about the plans and the accounting for defined benefits.
Certain assumptions are made by LKE regarding the valuation of benefit obligations and the performance of plan assets. When accounting for defined benefits, delayed recognition in earnings of differences between actual results and expected or estimated results is a guiding principle. Annual net periodic defined benefit costs are recorded in current earnings based on estimated results. Any differences between actual and estimated results are recorded in regulatory assets and liabilities for amounts that are expected to be recovered through regulated customer rates. These amounts in regulatory assets and liabilities are amortized to income over future periods. The delayed recognition allows for a smoothed recognition of costs over the working lives of the employees who benefit under the plans. The primary assumptions are:
· | Discount Rate - The discount rate is used in calculating the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due. |
· | Expected Long-term Return on Plan Assets - Management projects the long-term rates of return on plan assets based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes. These projected returns reduce the net benefit costs KU records currently. |
· | Rate of Compensation Increase - Management projects employees' annual pay increases, which are used to project employees' pension benefits at retirement. |
· | Health Care Cost Trend Rate - Management projects the expected increases in the cost of health care. |
In selecting a discount rate for its defined benefit plans, LKE starts with a cash flow analysis of the expected benefit payment stream for its plans. The plan-specific cash flows are matched against the coupons and expected maturity values of individually selected bonds. This bond matching process begins with the full universe of Aa-rated non-callable (or callable with make-whole provisions) bonds, serving as the base from which those with the lowest and highest yields are eliminated to develop an appropriate subset of bonds. Individual bonds are then selected based on the timing of each plan's cash flows and parameters are established as to the percentage of each individual bond issue that could be hypothetically purchased and the surplus reinvestment rates to be assumed. At December 31, 2012, LKE decreased the discount rate for its pension plan from 5.12% to 4.26% and decreased the discount rate for its other postretirement benefit plan from 4.78% to 3.99%.
The expected long-term rates of return for LKE's defined benefit pension and other postretirement benefit plans have been developed using a best-estimate of expected returns, volatilities and correlations for each asset class. LKE management corroborates these rates with expected long-term rates of return calculated by its independent actuary, who uses a building block approach that begins with a risk-free rate of return with factors being added such as inflation, duration, credit spreads and equity risk. Each plan's specific asset allocation is also considered in developing a reasonable return assumption. At December 31, 2012, LKE's expected return on plan assets decreased from 7.25% to 7.10%.
In selecting a rate of compensation increase, LKE considers past experience in light of movements in inflation rates. At December 31, 2012, LKE's rate of compensation increase remained at 4.00%.
In selecting health care cost trend rates LKE considers past performance and forecasts of health care costs. At December 31, 2012, LKE's health care cost trend rates were 8.00% for 2013, gradually declining to 5.50% for 2019.
A variance in the assumptions listed above could have a significant impact on accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and regulatory assets and liabilities allocated to KU. While the charts below reflect either an increase or decrease in each assumption, the inverse of the change would impact the accrued defined benefit liabilities or assets, reported annual net periodic defined benefit costs and regulatory assets and liabilities for KU by a similar amount in the opposite direction. The sensitivities below reflect an evaluation of the change based solely on a change in that assumption and does not include income tax effects.
At December 31, 2012, the defined benefit plans were recorded as follows:
Pension liabilities | | $ | 104 |
Other postretirement benefit liabilities | | | 53 |
The following chart reflects the sensitivities in the December 31, 2012 Balance Sheet associated with a change in certain assumptions based on KU's primary defined benefit plans.
| | Increase (Decrease) |
| | | | | Impact on | | | | | Impact on |
| | Change in | | defined benefit | | Impact on | | regulatory |
Actuarial assumption | | assumption | | liabilities | | OCI | | assets |
| | | | | | | | | | | | |
Discount Rate | | | (0.25)% | | $ | 17 | | | | | $ | 17 |
Rate of Compensation Increase | | | 0.25% | | | 3 | | | | | | 3 |
Health Care Cost Trend Rate (a) | | | 1% | | | 3 | | | | | | 3 |
(a) | Only impacts other postretirement benefits. |
In 2012 KU recognized net periodic defined benefit costs charged to operating expense of $11 million. This amount represents a $3 million decrease from 2011. This decrease in expense for 2012 was primarily attributable to the increase in the expected return on plan assets resulting from pension contributions of $15 million, a reduction in the amortization of outstanding losses and lower interest cost.
The following chart reflects the sensitivities in the 2012 Statement of Income (excluding income tax effects) associated with a change in certain assumptions based on KU's primary defined benefit plans.
Actuarial assumption | | | Change in assumption | | | Impact on defined benefit costs |
| | | | | | |
Discount Rate | | | (0.25)% | | $ | 2 |
Expected Return on Plan Assets | | | (0.25)% | | | 1 |
Rate of Compensation Increase | | | 0.25% | | | 1 |
Health Care Cost Trend Rate (a) | | | 1% | | | |
(a) | Only impacts other postretirement benefits. |
Asset Impairment (Excluding Investments)
Impairment analyses are performed for long-lived assets that are subject to depreciation or amortization whenever events or changes in circumstances indicate that a long-lived asset's carrying amount may not be recoverable. For these long-lived assets classified as held and used, such events or changes in circumstances are:
· | a significant decrease in the market price of an asset; |
· | a significant adverse change in the extent or manner in which an asset is being used or in its physical condition; |
· | a significant adverse change in legal factors or in the business climate; |
· | an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of an asset; |
· | a current-period operating or cash flow loss combined with a history of losses or a forecast that demonstrates continuing losses; or |
· | a current expectation that, more likely than not, an asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. |
For a long-lived asset classified as held and used, impairment is recognized when the carrying amount of the asset is not recoverable and exceeds its fair value. The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset is impaired, an impairment loss is recorded to adjust the asset's carrying amount to its estimated fair value. Management must make significant judgments to estimate future cash flows including the useful lives of long-lived assets, the fair value of the assets and management's intent to use the assets. Alternate courses of action are considered to recover the carrying amount of a long-lived asset, and estimated cash flows from the "most likely" alternative are used to assess impairment whenever one alternative is clearly the most likely outcome. If no alternative is clearly the most likely, then a probability-weighted approach is used taking into consideration estimated cash flows from the alternatives. For assets tested for impairment as of the balance sheet date, the estimates of future cash flows used in that test consider the likelihood of possible outcomes that existed at the balance sheet date, including the assessment of the likelihood of a future sale of the assets. That assessment is not revised based on events that occur after the balance sheet date. Changes in assumptions and estimates could result in significantly different results than those identified and recorded in the financial statements.
For a long-lived asset classified as held for sale, impairment exists when the carrying amount of the asset (disposal group) exceeds its fair value less cost to sell. If the asset (disposal group) is impaired, an impairment loss is recorded to adjust the carrying amount to its fair value less cost to sell. A gain is recognized for any subsequent increase in fair value less cost to sell, but not in excess of the cumulative impairment previously recognized.
For determining fair value, quoted market prices in active markets are the best evidence. However, when market prices are unavailable, KU considers all valuation techniques appropriate under the circumstances and for which market participant inputs can be obtained. Generally discounted cash flows are used to estimate fair value, which incorporates market participant inputs when available. Discounted cash flows are calculated by estimating future cash flow streams and applying appropriate discount rates to determine the present value of the cash flow streams.
Goodwill is tested for impairment at the reporting unit level. KU's reporting unit has been determined to be at the operating segment level. A goodwill impairment test is performed annually or more frequently if events or changes in circumstances indicate that the carrying amount of the reporting unit may be greater than the unit's fair value. Additionally, goodwill is tested for impairment after a portion of goodwill has been allocated to a business to be disposed of.
Beginning in 2012, KU may elect either to initially make a qualitative evaluation about the likelihood of an impairment of goodwill or to bypass the qualitative assessment and directly test goodwill for impairment using a two-step quantitative test. If the qualitative evaluation (referred to as "step zero") is elected and the assessment results in a determination that it is not more likely than not the fair value of the reporting unit is less than the carrying amount, the two-step quantitative impairment test is not necessary. However, the quantitative impairment test is required if KU concludes it is more likely than not the fair value of the reporting unit is less than the carrying amount based on the step zero assessment.
When the two-step quantitative impairment test is elected or required as a result of the step zero assessment, in step one, KU identifies a potential impairment by comparing the estimated fair value of KU (the goodwill reporting unit) with its carrying amount, including goodwill, on the measurement date. If the estimated fair value exceeds its carrying amount, goodwill is not considered impaired. If the carrying amount exceeds the estimated fair value, the second step is performed to measure the amount of impairment loss, if any.
The second step of the quantitative test requires a calculation of the implied fair value of goodwill, which is determined in the same manner as the amount of goodwill in a business combination. That is, the estimated fair value is allocated to all of KU's assets and liabilities as if KU had been acquired in a business combination and the estimated fair value of KU was the price paid. The excess of the estimated fair value of KU over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. The implied fair value of KU's goodwill is then compared with the carrying amount of that goodwill. If the carrying amount exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess. The loss recognized cannot exceed the carrying amount of KU's goodwill.
KU elected to perform the two-step quantitative impairment test of goodwill in the fourth quarter of 2012 and no impairment was recognized. Management used both discounted cash flows and market multiples, which required significant assumptions, to estimate the fair value of KU. Applying an appropriate weighting to both the discounted cash flow and market multiple valuations, a decrease in the forecasted cash flows of 10%, an increase in the discount rate by 25 basis points, or a 10% decrease in the multiples would not have resulted in an impairment of goodwill.
Losses are accrued for the estimated impacts of various conditions, situations or circumstances involving uncertain or contingent future outcomes. For loss contingencies, the loss must be accrued if (1) information is available that indicates it is probable that a loss has been incurred, given the likelihood of the uncertain future events and (2) the amount of the loss can be reasonably estimated. Accounting guidance defines "probable" as cases in which "the future event or events are likely to occur." The accrual of contingencies that might result in gains is not recorded unless recovery is assured. Potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events are continuously assessed.
The accounting aspects of estimated loss accruals include (1) the initial identification and recording of the loss, (2) the determination of triggering events for reducing a recorded loss accrual and (3) the ongoing assessment as to whether a recorded loss accrual is sufficient. All three of these aspects require significant judgment by management. Internal expertise and outside experts (such as lawyers and engineers) are used, as necessary to help estimate the probability that a loss has been incurred and the amount (or range) of the loss.
In 2012, no significant adjustments were made to KU's existing contingencies.
Certain other events have been identified that could give rise to a loss, but that do not meet the conditions for accrual. Such events are disclosed, but not recorded, when it is reasonably possible that a loss has been incurred. Accounting guidance defines "reasonably possible" as cases in which "the future event or events occurring is more than remote, but less than likely to occur."
When an estimated loss is accrued, the triggering events for subsequently adjusting the loss accrual are identified, where applicable. The triggering events generally occur when the contingency has been resolved and the actual loss is paid or written off, or when the risk of loss has diminished or been eliminated. The following are some of the triggering events that provide for the adjustment of certain recorded loss accruals:
· | Allowances for uncollectible accounts are reduced when accounts are written off after prescribed collection procedures have been exhausted, a better estimate of the allowance is determined or underlying amounts are ultimately collected. |
· | Environmental and other litigation contingencies are reduced when the contingency is resolved, KU makes actual payments, a better estimate of the loss is determined or the loss is no longer considered probable. |
Loss accruals are reviewed on a regular basis to assure that the recorded potential loss exposures are appropriate. This involves ongoing communication and analyses with internal and external legal counsel, engineers, operation management and other parties.
See Note 15 to the Financial Statements for additional information.
Asset Retirement Obligations |
KU is required to recognize a liability for legal obligations associated with the retirement of long-lived assets. The initial obligation is measured at its estimated fair value. An equivalent amount is recorded as an increase in the value of the capitalized asset and allocated to expense over the useful life of the asset. Until the obligation is settled, the liability is increased, through the recognition of accretion expense in the Statements of Income, for changes in the obligation due to the passage of time. Since costs of removal are collected in rates, the accretion and depreciation are offset with a regulatory credit on the income statement, such that there is no earnings impact. The regulatory asset created by the regulatory credit is relieved when the ARO has been settled. An ARO must be recognized when incurred if the fair value of the ARO can be reasonably estimated. See Note 21 to the Financial Statements for related disclosures.
In determining AROs, management must make significant judgments and estimates to calculate fair value. Fair value is developed using an expected present value technique based on assumptions of market participants that considers estimated retirement costs in current period dollars that are inflated to the anticipated retirement date and then discounted back to the date the ARO was incurred. Changes in assumptions and estimates included within the calculations of the fair value of AROs could result in significantly different results than those identified and recorded in the financial statements. Estimated ARO costs and settlement dates, which affect the carrying value of various AROs and the related assets, are reviewed periodically to ensure that any material changes are incorporated into the estimate of the obligations. Any change to the capitalized asset is amortized over the remaining life of the associated long-lived asset.
At December 31, 2012, KU had AROs totaling $69 million recorded on the Balance Sheet. Of the total amount, $51 million, or 74%, relates to KU's ash ponds and landfill. The most significant assumptions surrounding AROs are the forecasted retirement costs, the discount rates and the inflation rates. A variance in the forecasted retirement costs, the discount rates or the inflation rates could have a significant impact on the ARO liabilities.
The following chart reflects the sensitivities related to KU's ARO liabilities for ash ponds and landfill at December 31, 2012:
| | Change in | | Impact on |
| | Assumption | | ARO Liability |
| | | | | | |
Retirement Cost | | | 10% | | $ | 6 |
Discount Rate | | | (0.25)% | | | 2 |
Inflation Rate | | | 0.25% | | | 3 |
Significant management judgment is required in developing the provision for income taxes, primarily due to the uncertainty related to tax positions taken or expected to be taken in tax returns and the determination of deferred tax assets, liabilities and valuation allowances.
Significant management judgment is required to determine the amount of benefit recognized related to an uncertain tax position. Tax positions are evaluated following a two-step process. The first step requires an entity to determine whether, based on the technical merits supporting a particular tax position, it is more likely than not (greater than a 50% chance) that the tax position will be sustained. This determination assumes that the relevant taxing authority will examine the tax position and is aware of all the relevant facts surrounding the tax position. The second step requires an entity to recognize in the financial statements the benefit of a tax position that meets the more-likely-than-not recognition criterion. The benefit recognized is measured at the largest amount of benefit that has a likelihood of realization, upon settlement, that exceeds 50%. Management considers a number of factors in assessing the benefit to be recognized, including negotiation of a settlement.
On a quarterly basis, uncertain tax positions are reassessed by considering information known at the reporting date. Based on management's assessment of new information, a tax benefit may subsequently be recognized for a previously unrecognized tax position, a previously recognized tax position may be derecognized, or the benefit of a previously recognized tax position may be remeasured. The amounts ultimately paid upon resolution of issues raised by taxing authorities may differ materially from the amounts accrued and may materially impact the financial statements in the future.
At December 31, 2012, KU's existing reserve exposure to either increases or decreases in unrecognized tax benefits during the next 12 months is less than $1 million. This change could result from subsequent recognition, derecognition and/or changes in the measurement of uncertain tax positions. The events that could cause these changes are direct settlements with taxing authorities, litigation, legal or administrative guidance by relevant taxing authorities and the lapse of an applicable statute of limitation.
The balance sheet classification of unrecognized tax benefits and the need for valuation allowances to reduce deferred tax assets also require significant management judgment. Unrecognized tax benefits are classified as current to the extent management expects to settle an uncertain tax position by payment or receipt of cash within one year of the reporting date. Valuation allowances are initially recorded and reevaluated each reporting period by assessing the likelihood of the ultimate realization of a deferred tax asset. Management considers a number of factors in assessing the realization of a deferred tax asset, including the reversal of temporary differences, future taxable income and ongoing prudent and feasible tax planning strategies. Any tax planning strategy utilized in this assessment must meet the recognition and measurement criteria utilized to account for an uncertain tax position. See Note 5 to the Financial Statements for related disclosures.
Regulatory Assets and Liabilities |
KU is a cost-based rate-regulated utility. As a result, the effects of regulatory actions are required to be reflected in the financial statements. Assets and liabilities are recorded that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in regulated customer rates. Regulatory liabilities are recognized for amounts expected to be returned through future regulated customer rates. In certain cases, regulatory liabilities are recorded based on an understanding with the regulator that rates have been set to recover costs that are expected to be incurred in the future, and the regulated entity is accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose. The accounting for regulatory assets and liabilities is based on specific ratemaking decisions or precedent for each transaction or event as prescribed by the FERC, the KPSC, the VSCC or the TRA.
Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as changes in the applicable regulatory and political environments, the ability to recover costs through regulated rates, recent rate orders to other regulated entities and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, then asset write-off would be required to be recognized in operating income. Additionally, the regulatory agencies can provide flexibility in the manner and timing of the depreciation of PP&E and amortization of regulatory assets.
At December 31, 2012, KU had regulatory assets of $230 million and regulatory liabilities of $536 million. All regulatory assets are either currently being recovered under specific rate orders, represent amounts that are expected to be recovered in future rates or benefit future periods based upon established regulatory practices.
See Note 6 to the Financial Statements for additional information on regulatory assets and liabilities.
Other Information
PPL's Audit Committee has approved the independent auditor to provide audit, tax and other services permitted by Sarbanes-Oxley and SEC rules. The audit services include services in connection with statutory and regulatory filings, reviews of offering documents and registration statements, and internal control reviews. See "Item 14. Principal Accounting Fees and Services" for more information.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
PPLTalen Energy Corporation PPLand Talen Energy Supply, LLC PPL Electric Utilities Corporation, LG&E and KU Energy LLC, Louisville Gas and Electric Company and Kentucky Utilities Company
Reference is made to "Risk Management - Energy Marketing & Trading and Other" for PPL and PPL Energy Supply and "Risk Management" for PPL Electric, LKE, LG&E and KUthe Registrants in "Item 7. Combined Management's Discussion and Analysis of Financial Condition and Results of Operations."
(THIS PAGE LEFT BLANK INTENTIONALLY.)
Report of Independent Registered Public Accounting Firm
To theThe Board of Directors and ShareownersStockholders of PPLTalen Energy Corporation
We have audited the accompanying consolidated balance sheets of PPLTalen Energy Corporation and subsidiaries as of December 31, 20122015 and 2011,2014, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2012.2015. Our audits also included the financial statement schedule listed in the Index at Item 15(a)(2). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. We did not audit the 2010 financial statements of LG&E and KU Energy LLC (LKE), a wholly owned subsidiary, which statements reflect total revenues of $494 million for the period November 1, 2010 (date of acquisition) to December 31, 2010. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for LKE, is based solely on the report of the other auditors.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includesstatements, assessing the accounting principles used and significant estimates made by management, as well asand evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and, for 2010, the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of PPLTalen Energy Corporation and subsidiaries at December 31, 20122015 and 2011,2014, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2012,2015, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), PPL Corporation's internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2013 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Philadelphia, Pennsylvania
February 28, 201326, 2016
Report of Independent Registered Public Accounting Firm
To theThe Board of DirectorsManagers and ShareownersSole Member of PPL CorporationTalen Energy Supply, LLC
We have audited PPL Corporation's internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). PPL Corporation's management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in Management's Report on Internal Control over Financial Reporting at Item 9A. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, PPL Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012 based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), theaccompanying consolidated balance sheets of Talen Energy Supply, LLC (formerly known as PPL CorporationEnergy Supply, LLC) and subsidiaries as of December 31, 20122015 and 2011,2014, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2012 and our report dated February 28, 2013 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Philadelphia, Pennsylvania
February 28, 2013
Report of Independent Registered Public Accounting Firm
To the Board of Managers and Sole Member of PPL Energy Supply, LLC
We have audited the accompanying consolidated balance sheets of PPL Energy Supply, LLC and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2012.2015. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of PPLTalen Energy Supply, LLC and subsidiaries at December 31, 20122015 and 2011,2014, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2012,2015, in conformity with U.S. generally accepted accounting principles.
/s/Ernst & Young LLP
Philadelphia, Pennsylvania
February 28, 201326, 2016
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareowners of PPL Electric Utilities Corporation
We have audited the accompanying consolidated balance sheets of PPL Electric Utilities Corporation and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of income, shareowners' equity, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of PPL Electric Utilities Corporation and subsidiaries at December 31, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Philadelphia, Pennsylvania
February 28, 2013
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Sole Member of LG&E and KU Energy LLC
We have audited the accompanying consolidated balance sheets of LG&E and KU Energy LLC and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of income and comprehensive income, cash flows, and equity for each of the two years in the period ended December 31, 2012. Our audits also included the financial statement schedule listed in the index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of LG&E and KU Energy LLC and subsidiaries at December 31, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Ernst & Young LLP
Louisville, Kentucky
February 28, 2013
Report of Independent Registered Public Accounting Firm
To the Member of LG&E and KU Energy LLC
In our opinion, the accompanying consolidated statements of income, comprehensive income, cash flows, and equity present fairly, in all material respects, the results of operations and cash flows of LG&E and KU Energy LLC and its subsidiaries (Successor Company) for the period from November 1, 2010 to December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
As discussed in Note 10 to the consolidated financial statements, on November 1, 2010, PPL Corporation completed its acquisition of LG&E and KU Energy LLC and its subsidiaries. The push-down basis of accounting was used at the acquisition date.
/s/ PricewaterhouseCoopers LLP
Louisville, Kentucky
February 25, 2011
Report of Independent Registered Public Accounting Firm
To the Member of LG&E and KU Energy LLC
In our opinion, the accompanying consolidated statements of income, comprehensive income, cash flows, and equity present fairly, in all material respects, the results of operations and cash flows of LG&E and KU Energy LLC and its subsidiaries (formerly E.ON U.S. LLC, Predecessor Company) for the period from January 1, 2010 to October 31, 2010 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
As discussed in Note 10 to the consolidated financial statements, on November 1, 2010, PPL Corporation completed its acquisition of LG&E and KU Energy LLC and its subsidiaries. The push-down basis of accounting was used at the acquisition date.
/s/ PricewaterhouseCoopers LLP
Louisville, Kentucky
February 25, 2011
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholder of Louisville Gas and Electric Company
We have audited the accompanying balance sheets of Louisville Gas and Electric Company as of December 31, 2012 and 2011, and the related statements of income and comprehensive income, cash flows, and equity for each of the two years in the period ended December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Louisville Gas and Electric Company at December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Louisville, Kentucky(THIS PAGE LEFT BLANK INTENTIONALLY)
February 28, 2013
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Report of Independent Registered Public Accounting Firm
To the Stockholder of Louisville Gas and Electric Company
In our opinion, the accompanying statements of income, comprehensive income, cash flows, and equity present fairly, in all material respects, the results of operations and cash flows of Louisville Gas and Electric Company (Successor Company) for the period from November 1, 2010 to December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
As discussed in Note 10 to the financial statements, on November 1, 2010, PPL Corporation completed its acquisition of LG&E and KU Energy LLC and its subsidiaries. The push-down basis of accounting was used at the acquisition date.
/s/ PricewaterhouseCoopers LLP
Louisville, Kentucky
February 25, 2011
Report of Independent Registered Public Accounting Firm
To the Stockholder of Louisville Gas and Electric Company
In our opinion, the accompanying statements of income, comprehensive income, cash flows, and equity present fairly, in all material respects, the results of operations and cash flows of Louisville Gas and Electric Company (Predecessor Company) for the period from January 1, 2010 to October 31, 2010 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
As discussed in Note 10 to the financial statements, on November 1, 2010, PPL Corporation completed its acquisition of LG&E and KU Energy LLC and its subsidiaries. The push-down basis of accounting was used at the acquisition date.
/s/ PricewaterhouseCoopers LLP
Louisville, Kentucky
February 25, 2011
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholder of Kentucky Utilities Company
We have audited the accompanying balance sheets of Kentucky Utilities Company as of December 31, 2012 and 2011, and the related statements of income and comprehensive income, cash flows, and equity for each of the two years in the period ended December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Kentucky Utilities Company at December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Louisville, Kentucky
February 28, 2013
Report of Independent Registered Public Accounting Firm
To the Stockholder of Kentucky Utilities Company
In our opinion, the accompanying statements of income, comprehensive income, cash flows, and equity present fairly, in all material respects, the results of operations and cash flows of Kentucky Utilities Company (Successor Company) for the period from November 1, 2010 to December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
As discussed in Note 10 to the financial statements, on November 1, 2010, PPL Corporation completed its acquisition of LG&E and KU Energy LLC and its subsidiaries. The push-down basis of accounting was used at the acquisition date.
/s/ PricewaterhouseCoopers LLP
Louisville, Kentucky
February 25, 2011
Report of Independent Registered Public Accounting Firm
To the Stockholder of Kentucky Utilities Company
In our opinion, the accompanying statements of income, comprehensive income, cash flows, and equity present fairly, in all material respects, the results of operations and cash flows of Kentucky Utilities Company (Predecessor Company) for the period from January 1, 2010 to October 31, 2010 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
As discussed in Note 10 to the financial statements, on November 1, 2010, PPL Corporation completed its acquisition of LG&E and KU Energy LLC and its subsidiaries. The push-down basis of accounting was used at the acquisition date.
/s/ PricewaterhouseCoopers LLP
Louisville, Kentucky
February 25, 2011
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
|
CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, |
PPL Corporation and Subsidiaries |
(Millions of Dollars, except share data) |
| | | | | | | | | | | |
| | | | | 2012 | | 2011 | | 2010 |
Operating Revenues | | | | | | |
| Utility | | $ | 6,808 | | $ | 6,292 | | $ | 3,668 |
| Unregulated retail electric and gas | | | 844 | | | 726 | | | 415 |
| Wholesale energy marketing | | | | | | | | | |
| | Realized | | | 4,433 | | | 3,807 | | | 4,832 |
| | Unrealized economic activity (Note 19) | | | (311) | | | 1,407 | | | (805) |
| Net energy trading margins | | | 4 | | | (2) | | | 2 |
| Energy-related businesses | | | 508 | | | 507 | | | 409 |
| Total Operating Revenues | | | 12,286 | | | 12,737 | | | 8,521 |
| | | | | | | | | |
Operating Expenses | | | | | | | | | |
| Operation | | | | | | | | | |
| | Fuel | | | 1,837 | | | 1,946 | | | 1,235 |
| | Energy purchases | | | | | | | | | |
| | | Realized | | | 2,997 | | | 2,130 | | | 2,773 |
| | | Unrealized economic activity (Note 19) | | | (442) | | | 1,123 | | | (286) |
| | Other operation and maintenance | | | 2,835 | | | 2,667 | | | 1,756 |
| Depreciation | | | 1,100 | | | 960 | | | 556 |
| Taxes, other than income | | | 366 | | | 326 | | | 238 |
| Energy-related businesses | | | 484 | | | 484 | | | 383 |
| Total Operating Expenses | | | 9,177 | | | 9,636 | | | 6,655 |
| | | | | | | | | | | | |
Operating Income | | | 3,109 | | | 3,101 | | | 1,866 |
| | | | | | | | | | | | |
Other Income (Expense) - net | | | (39) | | | 4 | | | (31) |
| | | | | | | | | |
Other-Than-Temporary Impairments | | | 27 | | | 6 | | | 3 |
| | | | | | | | | | | | |
Interest Expense | | | 961 | | | 898 | | | 593 |
| | | | | | | | | | | | |
Income from Continuing Operations Before Income Taxes | | | 2,082 | | | 2,201 | | | 1,239 |
| | | | | | | | | | | | |
Income Taxes | | | 545 | | | 691 | | | 263 |
| | | | | | | | | | | | |
Income from Continuing Operations After Income Taxes | | | 1,537 | | | 1,510 | | | 976 |
| | | | | | | | | | | | |
Income (Loss) from Discontinued Operations (net of income taxes) | | | (6) | | | 2 | | | (17) |
| | | | | | | | | | | | |
Net Income | | | 1,531 | | | 1,512 | | | 959 |
| | | | | | | | | | | | |
Net Income Attributable to Noncontrolling Interests | | | 5 | | | 17 | | | 21 |
| | | | | | | | | | | | |
Net Income Attributable to PPL Shareowners | | $ | 1,526 | | $ | 1,495 | | $ | 938 |
| | | | | | | | | | | | |
Amounts Attributable to PPL Shareowners: | | | | | | | | | |
| Income from Continuing Operations After Income Taxes | | $ | 1,532 | | $ | 1,493 | | $ | 955 |
| Income (Loss) from Discontinued Operations (net of income taxes) | | | (6) | | | 2 | | | (17) |
| Net Income | | $ | 1,526 | | $ | 1,495 | | $ | 938 |
| | | | | | | | | | | | |
Earnings Per Share of Common Stock: | | | |
| Income from Continuing Operations After Income Taxes Available to PPL | | | |
| Common Shareowners: | | | | | | | | | |
| | Basic | | $ | 2.62 | | $ | 2.70 | | $ | 2.21 |
| | Diluted | | $ | 2.61 | | $ | 2.70 | | $ | 2.20 |
| Net Income Available to PPL Common Shareowners: | | | | | | | | | |
| | Basic | | $ | 2.61 | | $ | 2.71 | | $ | 2.17 |
| | Diluted | | $ | 2.60 | | $ | 2.70 | | $ | 2.17 |
| | | | | | | | | | | | |
Dividends Declared Per Share of Common Stock | | $ | 1.44 | | $ | 1.40 | | $ | 1.40 |
| | | | | | | | | | | | |
Weighted-Average Shares of Common Stock Outstanding (in thousands) | | | | | | | | | |
| | Basic | | | 580,276 | | | 550,395 | | | 431,345 |
| | Diluted | | | 581,626 | | | 550,952 | | | 431,569 |
| | | | | | | | | | | | |
The accompanying Notes to Financial Statements are an integral part of the financial statements. |
|
FOR THE YEARS ENDED DECEMBER 31, |
PPL Corporation and Subsidiaries |
(Millions of Dollars) |
| | | | | | | | | | | |
| | | | 2012 | | 2011 | | 2010 |
| | | | | | | | | | | |
Net income | | $ | 1,531 | | $ | 1,512 | | $ | 959 |
| | | | | | | | | | | |
Other comprehensive income (loss): | | | | | | | | | |
Amounts arising during the period - gains (losses), net of tax (expense) benefit: | | | | | | | | | |
| Foreign currency translation adjustments, net of tax of $2, ($2), ($1) | | | 94 | | | (48) | | | (59) |
| Available-for-sale securities, net of tax of ($31), ($6), ($31) | | | 29 | | | 9 | | | 29 |
| Qualifying derivatives, net of tax of ($32), ($139), ($148) | | | 39 | | | 202 | | | 219 |
| Equity investees' other comprehensive income (loss), net of tax of ($1), $0, $0 | | | 2 | | | | | | |
| Defined benefit plans: | | | | | | | | | |
| | Prior service costs, net of tax of $0, ($1), ($14) | | | 1 | | | (3) | | | 17 |
| | Net actuarial gain (loss), net of tax of $343, $58, $50 | | | (965) | | | (152) | | | (80) |
| | Transition obligation, net of tax of $0, $0, ($4) | | | | | | | | | 8 |
Reclassifications to net income - (gains) losses, net of tax expense (benefit): | | | | | | | | | |
| Available-for-sale securities, net of tax of $1, $5, $3 | | | (7) | | | (7) | | | (5) |
| Qualifying derivatives, net of tax of $278, $246, $84 | | | (434) | | | (370) | | | (126) |
| Equity investees' other comprehensive (income) loss, net of tax of $0, $0, $0 | | | | | | 3 | | | |
| Defined benefit plans: | | | | | | | | | |
| | Prior service costs, net of tax of ($5), ($5), ($7) | | | 10 | | | 10 | | | 12 |
| | Net actuarial loss, net of tax of ($29), ($19), ($14) | | | 79 | | | 47 | | | 41 |
| | Transition obligation, net of tax of $0, $0, ($1) | | | | | | | | | 2 |
Total other comprehensive income (loss) attributable to PPL Shareowners | | | (1,152) | | | (309) | | | 58 |
| | | | | | | | | | | |
Comprehensive income (loss) | | | 379 | | | 1,203 | | | 1,017 |
| Comprehensive income attributable to noncontrolling interests | | | 5 | | | 17 | | | 21 |
| | | | | | | | | | | |
Comprehensive income (loss) attributable to PPL Shareowners | | $ | 374 | | $ | 1,186 | | $ | 996 |
| | | | | | | | | | | |
The accompanying Notes to Financial Statements are an integral part of the financial statements. |
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, |
PPL Corporation and Subsidiaries |
(Millions of Dollars) |
| | | | | 2012 | | 2011 | | 2010 |
Cash Flows from Operating Activities | | | | | | | | | |
| Net income | | $ | 1,531 | | $ | 1,512 | | $ | 959 |
| Adjustments to reconcile net income to net cash provided by (used in) operating activities | | | | | | | | | |
| | Depreciation | | | 1,100 | | | 961 | | | 567 |
| | Amortization | | | 186 | | | 254 | | | 213 |
| | Defined benefit plans - expense | | | 166 | | | 205 | | | 102 |
| | Deferred income taxes and investment tax credits | | | 424 | | | 582 | | | 241 |
| | Impairment of assets | | | 28 | | | 13 | | | 120 |
| | Unrealized (gains) losses on derivatives, and other hedging activities | | | 27 | | | (314) | | | 542 |
| | Provision for Montana hydroelectric litigation | | | | | | (74) | | | 66 |
| | Other | | | 52 | | | 36 | | | 32 |
| Change in current assets and current liabilities | | | | | | | | | |
| | Accounts receivable | | | 7 | | | (89) | | | (106) |
| | Accounts payable | | | (29) | | | (36) | | | 216 |
| | Unbilled revenues | | | (19) | | | 64 | | | (99) |
| | Prepayments | | | (5) | | | 294 | | | (318) |
| | Counterparty collateral | | | (34) | | | (190) | | | (18) |
| | Taxes | | | 24 | | | (104) | | | 20 |
| | Regulatory assets and liabilities, net | | | (2) | | | 106 | | | (110) |
| | Accrued interest | | | 32 | | | 109 | | | 50 |
| | Other | | | 8 | | | 6 | | | 9 |
| Other operating activities | | | | | | | | | |
| | Defined benefit plans - funding | | | (607) | | | (667) | | | (396) |
| | Other assets | | | (33) | | | (62) | | | (45) |
| | Other liabilities | | | (92) | | | (99) | | | (12) |
| | | Net cash provided by (used in) operating activities | | | 2,764 | | | 2,507 | | | 2,033 |
Cash Flows from Investing Activities | | | | | | | | | |
| Expenditures for property, plant and equipment | | | (3,105) | | | (2,487) | | | (1,597) |
| Proceeds from the sale of certain non-core generation facilities | | | | | | 381 | | | |
| Proceeds from the sale of the Long Island generation business | | | | | | | | | 124 |
| Proceeds from the sale of the Maine hydroelectric generation business | | | | | | | | | 38 |
| Ironwood Acquisition, net of cash acquired | | | (84) | | | | | | |
| Acquisition of WPD Midlands | | | | | | (5,763) | | | |
| Acquisition of LKE, net of cash acquired | | | | | | | | | (6,812) |
| Purchases of nuclear plant decommissioning trust investments | | | (154) | | | (169) | | | (128) |
| Proceeds from the sale of nuclear plant decommissioning trust investments | | | 139 | | | 156 | | | 114 |
| Proceeds from the sale of other investments | | | 20 | | | 163 | | | |
| Net (increase) decrease in restricted cash and cash equivalents | | | 96 | | | (143) | | | 85 |
| Other investing activities | | | (35) | | | (90) | | | (53) |
| | | Net cash provided by (used in) investing activities | | | (3,123) | | | (7,952) | | | (8,229) |
Cash Flows from Financing Activities | | | | | | | | | |
| Issuance of long-term debt | | | 1,223 | | | 5,745 | | | 4,642 |
| Retirement of long-term debt | | | (108) | | | (1,210) | | | (20) |
| Issuance of common stock | | | 72 | | | 2,297 | | | 2,441 |
| Payment of common stock dividends | | | (833) | | | (746) | | | (566) |
| Redemption of preference stock of a subsidiary | | | (250) | | | | | | (54) |
| Debt issuance and credit facility costs | | | (17) | | | (102) | | | (175) |
| Contract adjustment payments on Equity Units | | | (94) | | | (72) | | | (13) |
| Net increase (decrease) in short-term debt | | | 74 | | | (125) | | | 70 |
| Other financing activities | | | (19) | | | (20) | | | (18) |
| | | Net cash provided by (used in) financing activities | | | 48 | | | 5,767 | | | 6,307 |
Effect of Exchange Rates on Cash and Cash Equivalents | | | 10 | | | (45) | | | 13 |
Net Increase (Decrease) in Cash and Cash Equivalents | | | (301) | | | 277 | | | 124 |
Cash and Cash Equivalents at Beginning of Period | | | 1,202 | | | 925 | | | 801 |
Cash and Cash Equivalents at End of Period | | $ | 901 | | $ | 1,202 | | $ | 925 |
| | | | | | | | | | | | |
Supplemental Disclosures of Cash Flow Information | | | | | | | | | |
| Cash paid (received) during the period for: | | | | | | | | | |
| | Interest - net of amount capitalized | | $ | 847 | | $ | 696 | | $ | 458 |
| | Income taxes - net | | $ | 73 | | $ | (76) | | $ | 313 |
| | | | | | | | | | | | |
The accompanying Notes to Financial Statements are an integral part of the financial statements. |
|
PPL Corporation and Subsidiaries |
(Millions of Dollars, shares in thousands) |
| | | | | 2012 | | 2011 |
Assets | | | | | | |
| | | | | | | | | |
Current Assets | | | | | | |
| Cash and cash equivalents | | $ | 901 | | $ | 1,202 |
| Short-term investments | | | | | | 16 |
| Restricted cash and cash equivalents | | | 54 | | | 152 |
| Accounts receivable (less reserve: 2012, $64; 2011, $54) | | | | | | |
| | Customer | | | 745 | | | 732 |
| | Other | | | 79 | | | 91 |
| Unbilled revenues | | | 857 | | | 834 |
| Fuel, materials and supplies | | | 673 | | | 654 |
| Prepayments | | | 166 | | | 160 |
| Price risk management assets | | | 1,525 | | | 2,548 |
| Regulatory assets | | | 19 | | | 9 |
| Other current assets | | | 49 | | | 28 |
| Total Current Assets | | | 5,068 | | | 6,426 |
| | | | | | | | | |
Investments | | | | | | |
| Nuclear plant decommissioning trust funds | | | 712 | | | 640 |
| Other investments | | | 47 | | | 78 |
| Total Investments | | | 759 | | | 718 |
| | | | | | | | | |
Property, Plant and Equipment | | | | | | |
| Regulated utility plant | | | 25,196 | | | 22,994 |
| Less: accumulated depreciation - regulated utility plant | | | 4,164 | | | 3,534 |
| | Regulated utility plant, net | | | 21,032 | | | 19,460 |
| Non-regulated property, plant and equipment | | | | | | |
| | Generation | | | 11,295 | | | 10,514 |
| | Nuclear fuel | | | 524 | | | 457 |
| | Other | | | 726 | | | 637 |
| Less: accumulated depreciation - non-regulated property, plant and equipment | | | 5,942 | | | 5,676 |
| | Non-regulated property, plant and equipment, net | | | 6,603 | | | 5,932 |
| Construction work in progress | | | 2,397 | | | 1,874 |
| Property, Plant and Equipment, net (a) | | | 30,032 | | | 27,266 |
| | | | | | | | | |
Other Noncurrent Assets | | | | | | |
| Regulatory assets | | | 1,483 | | | 1,349 |
| Goodwill | | | 4,158 | | | 4,114 |
| Other intangibles (a) | | | 925 | | | 1,065 |
| Price risk management assets | | | 572 | | | 920 |
| Other noncurrent assets | | | 637 | | | 790 |
| Total Other Noncurrent Assets | | | 7,775 | | | 8,238 |
| | | | | | |
Total Assets | | $ | 43,634 | | $ | 42,648 |
(a) | At December 31, 2012 and December 31, 2011, includes $428 million and $416 million of PP&E, consisting primarily of "Generation," including leasehold improvements, and $10 million and $11 million of "Other intangibles" from the consolidation of a VIE that is the owner/lessor of the Lower Mt. Bethel plant. See Note 22 for additional information. |
|
| | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, |
Talen Energy Corporation and Subsidiaries | | | | | |
(Millions of Dollars, Except Share Data) | | | | | |
| 2015 | | 2014 | | 2013 |
Operating Revenues | | | | | |
Wholesale energy | $ | 2,828 |
| | $ | 2,653 |
| | $ | 2,890 |
|
Wholesale energy to affiliate | 14 |
| | 84 |
| | 51 |
|
Retail energy | 1,095 |
| | 1,243 |
| | 1,027 |
|
Energy-related businesses | 544 |
| | 601 |
| | 527 |
|
Total Operating Revenues | 4,481 |
| | 4,581 |
| | 4,495 |
|
Operating Expenses | | | | | |
Operation | | | | | |
Fuel | 1,194 |
| | 1,196 |
| | 1,048 |
|
Energy purchases | 676 |
| | 1,054 |
| | 1,153 |
|
Operation and maintenance | 1,052 |
| | 1,007 |
| | 961 |
|
Loss on lease termination | — |
| | — |
| | 697 |
|
Impairments | 657 |
| | — |
| | 65 |
|
Depreciation | 356 |
| | 297 |
| | 299 |
|
Taxes, other than income | 65 |
| | 57 |
| | 53 |
|
Energy-related businesses | 520 |
| | 573 |
| | 512 |
|
Total Operating Expenses | 4,520 |
| | 4,184 |
| | 4,788 |
|
Operating Income (Loss) | (39 | ) | | 397 |
| | (293 | ) |
Other Income (Expense) - net | (118 | ) | | 30 |
| | 32 |
|
Interest Expense | 211 |
| | 124 |
| | 159 |
|
Income (Loss) from Continuing Operations Before Income Taxes | (368 | ) | | 303 |
| | (420 | ) |
Income Taxes | (27 | ) | | 116 |
| | (159 | ) |
Income (Loss) from Continuing Operations After Income Taxes | (341 | ) | | 187 |
| | (261 | ) |
Income (Loss) from Discontinued Operations (net of income taxes) | — |
| | 223 |
| | 32 |
|
Net Income (Loss) | (341 | ) | | 410 |
| | (229 | ) |
Net Income (Loss) Attributable to Noncontrolling Interests | — |
| | — |
| | 1 |
|
Net Income (Loss) Attributable to Talen Energy Corporation Stockholders | $ | (341 | ) | | $ | 410 |
| | $ | (230 | ) |
| | | | | |
Earnings Per Share of Common Stock Attributable to Talen Energy Corporation Stockholders: | | | | | |
Basic: | | | | | |
Income (Loss) from continuing operations after income taxes | $ | (3.10 | ) |
| $ | 2.24 |
|
| $ | (3.13 | ) |
Income (Loss) from discontinued operations (net of income taxes) | — |
|
| 2.67 |
|
| 0.38 |
|
Net Income (Loss) | $ | (3.10 | ) | | $ | 4.91 |
| | $ | (2.75 | ) |
Diluted: | | | | | |
Income (Loss) from continuing operations | $ | (3.10 | ) |
| $ | 2.24 |
|
| $ | (3.13 | ) |
Income (Loss) from discontinued operations (net of income taxes) | — |
|
| 2.67 |
|
| 0.38 |
|
Net Income (Loss) | $ | (3.10 | ) | | $ | 4.91 |
| | $ | (2.75 | ) |
| | | | | |
Weighted-Average Shares of Common Stock Outstanding (in thousands) | | | | | |
Basic | 109,898 |
|
| 83,524 |
|
| 83,524 |
|
Diluted | 109,898 |
|
| 83,524 |
|
| 83,524 |
|
The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements.
CONSOLIDATED BALANCE SHEETS AT DECEMBER 31, |
PPL Corporation and Subsidiaries |
(Millions of Dollars, shares in thousands) |
| | | | | 2012 | | 2011 |
Liabilities and Equity | | | | | | |
| | | | | | | | | |
Current Liabilities | | | | | | |
| Short-term debt | | $ | 652 | | $ | 578 |
| Long-term debt due within one year | | | 751 | | | |
| Accounts payable | | | 1,252 | | | 1,150 |
| Taxes | | | 90 | | | 65 |
| Interest | | | 325 | | | 287 |
| Dividends | | | 210 | | | 207 |
| Price risk management liabilities | | | 1,065 | | | 1,570 |
| Regulatory liabilities | | | 61 | | | 73 |
| Other current liabilities | | | 1,219 | | | 1,325 |
| Total Current Liabilities | | | 5,625 | | | 5,255 |
| | | | | | | | | |
Long-term Debt | | | 18,725 | | | 17,993 |
| | | | | | | | | |
Deferred Credits and Other Noncurrent Liabilities | | | | | | |
| Deferred income taxes | | | 3,387 | | | 3,326 |
| Investment tax credits | | | 328 | | | 285 |
| Price risk management liabilities | | | 629 | | | 840 |
| Accrued pension obligations | | | 2,076 | | | 1,313 |
| Asset retirement obligations | | | 536 | | | 484 |
| Regulatory liabilities | | | 1,010 | | | 1,010 |
| Other deferred credits and noncurrent liabilities | | | 820 | | | 1,046 |
| Total Deferred Credits and Other Noncurrent Liabilities | | | 8,786 | | | 8,304 |
| | | | | | | | | |
Commitments and Contingent Liabilities (Notes 6 and 15) | | | | | | |
| | | | | | | | | |
Equity | | | | | | |
| PPL Shareowners' Common Equity | | | | | | |
| | Common stock - $0.01 par value (a) | | | 6 | | | 6 |
| | Additional paid-in capital | | | 6,936 | | | 6,813 |
| | Earnings reinvested | | | 5,478 | | | 4,797 |
| | Accumulated other comprehensive loss | | | (1,940) | | | (788) |
| | Total PPL Shareowners' Common Equity | | | 10,480 | | | 10,828 |
| Noncontrolling Interests | | | 18 | | | 268 |
| Total Equity | | | 10,498 | | | 11,096 |
| | | | | | | | | |
Total Liabilities and Equity | | $ | 43,634 | | $ | 42,648 |
(a) | 780,000 shares authorized; 581,944 and 578,405 shares issued and outstanding at December 31, 2012 and December 31, 2011. |
Table of Contents |
| | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE YEARS ENDED DECEMBER 31, |
Talen Energy Corporation and Subsidiaries |
(Millions of Dollars) | | | | | |
| 2015 | | 2014 | | 2013 |
Net income (loss) | $ | (341 | ) | | $ | 410 |
| | $ | (229 | ) |
Other comprehensive income (loss): | | | | | |
Amounts arising during the period - gains (losses), net of tax (expense) benefit: | | | | | |
Available-for-sale securities, net of tax of $5, ($40), ($72) | (6 | ) | | 35 |
| | 67 |
|
Defined benefit plans: | | | | | |
Prior service costs, net of tax of $1, ($6), ($1) | (3 | ) | | 8 |
| | 2 |
|
Net actuarial gain, net of tax of ($30), $83, ($49) | 46 |
| | (120 | ) | | 71 |
|
Reclassifications from AOCI - (gains) losses, net of tax expense (benefit): | | | | | |
Available-for-sale securities, net of tax of $2, $7, $4 | (2 | ) | | (6 | ) | | (6 | ) |
Qualifying derivatives, net of tax of $12, $17, $84 | (19 | ) | | (25 | ) | | (123 | ) |
Defined benefit plans: | | | | | |
Prior service costs, net of tax of $0, ($1), ($3) | (1 | ) | | 3 |
| | 4 |
|
Net actuarial loss, net of tax of $11, ($4), ($10) | (18 | ) | | 5 |
| | 14 |
|
Total other comprehensive income (loss) attributable to Talen Energy Corporation Stockholders | (3 | ) | | (100 | ) | | 29 |
|
Comprehensive income (loss) | (344 | ) | | 310 |
| | (200 | ) |
Comprehensive income attributable to noncontrolling interests | — |
| | — |
| | 1 |
|
Comprehensive income (loss) attributable to Talen Energy Corporation Stockholders | $ | (344 | ) | | $ | 310 |
| | $ | (201 | ) |
The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements.
|
PPL Corporation and Subsidiaries |
(Millions of Dollars) |
|
| | | | PPL Shareowners | | | | | | |
| | | | Common | | | | | | | | | | | | | | | | | | |
| | | | stock | | | | | | | | | | | | Accumulated | | | | | | |
| | | | shares | | | | | | Additional | | | | | | other | | | Non- | | | |
| | | | outstanding | | | Common | | | paid-in | | | Earnings | | | comprehensive | | | controlling | | | |
| | | | (a) | | | stock | | | capital | | | reinvested | | | loss | | | interests | | | Total |
| | | | | | | | | | | | | | | | | | | | | | |
December 31, 2009 (b) | | 377,183 | | $ | 4 | | $ | 2,280 | | $ | 3,749 | | $ | (537) | | $ | 319 | | $ | 5,815 |
Common stock issued (c) | | 106,208 | | | 1 | | | 2,490 | | | | | | | | | | | | 2,491 |
Purchase Contracts (d) | | | | | | | | (176) | | | | | | | | | | | | (176) |
Stock-based compensation (e) | | | | | | | | 8 | | | | | | | | | | | | 8 |
Net income | | | | | | | | | | | 938 | | | | | | 21 | | | 959 |
Dividends, dividend equivalents, | | | | | | | | | | | | | | | | | | | | |
redemptions and distributions (f) | | | | | | | | | | | (605) | | | | | | (72) | | | (677) |
Other comprehensive income (loss) | | | | | | | | | | | | | | 58 | | | | | | 58 |
December 31, 2010 (b) | | 483,391 | | $ | 5 | | $ | 4,602 | | $ | 4,082 | | $ | (479) | | $ | 268 | | $ | 8,478 |
| | | | | | | | | | | | | | | | | | | | | | |
Common stock issued (c) | | 95,014 | | $ | 1 | | $ | 2,344 | | | | | | | | | | | $ | 2,345 |
Purchase Contracts (d) | | | | | | | | (143) | | | | | | | | | | | | (143) |
Stock-based compensation (e) | | | | | | | | 10 | | | | | | | | | | | | 10 |
Net income | | | | | | | | | | $ | 1,495 | | | | | $ | 17 | | | 1,512 |
Dividends, dividend equivalents, | | | | | | | | | | | | | | | | | | | | |
redemptions and distributions (f) | | | | | | | | | | | (780) | | | | | | (17) | | | (797) |
Other comprehensive income (loss) | | | | | | | | | | | | | $ | (309) | | | | | | (309) |
December 31, 2011 (b) | | 578,405 | | $ | 6 | | $ | 6,813 | | $ | 4,797 | | $ | (788) | | $ | 268 | | $ | 11,096 |
| | | | | | | | | | | | | | | | | | | | | | |
Common stock issued (c) | | 3,543 | | | | | $ | 99 | | | | | | | | | | | $ | 99 |
Common stock repurchased | | (4) | | | | | | | | | | | | | | | | | | |
Stock-based compensation (e) | | | | | | | | 18 | | | | | | | | | | | | 18 |
Net income | | | | | | | | | | $ | 1,526 | | | | | $ | 5 | | | 1,531 |
Dividends, dividend equivalents, | | | | | | | | | | | | | | | | | | | | |
redemptions and distributions (f) | | | | | | | | 6 | | | (845) | | | | | | (255) | | | (1,094) |
Other comprehensive income (loss) | | | | | | | | | | | | | $ | (1,152) | | | | | | (1,152) |
December 31, 2012 (b) | | 581,944 | | $ | 6 | | $ | 6,936 | | $ | 5,478 | | $ | (1,940) | | $ | 18 | | $ | 10,498 |
|
| | | | | | | | | | | |
| | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, |
Talen Energy Corporation and Subsidiaries | | | | | |
(Millions of Dollars) | | | | | |
| 2015 |
| 2014 |
| 2013 |
Cash Flows from Operating Activities | |
| | | |
Net income (loss) | $ | (341 | ) |
| $ | 410 |
|
| $ | (229 | ) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities |
|
|
|
|
|
| |
Pre-tax gain from the sale of Montana hydroelectric generation business | — |
|
| (315 | ) |
| — |
|
Depreciation | 356 |
|
| 313 |
|
| 318 |
|
Amortization | 222 |
|
| 163 |
|
| 156 |
|
Defined benefit plans - expense | 50 |
|
| 42 |
|
| 51 |
|
Deferred income taxes and investment tax credits | (61 | ) |
| (26 | ) |
| (296 | ) |
Impairment of assets | 662 |
|
| 20 |
|
| 65 |
|
Unrealized (gains) losses on derivatives, and other hedging activities | (119 | ) |
| 4 |
|
| 171 |
|
Loss on lease termination | — |
|
| — |
|
| 426 |
|
Other | 46 |
|
| 36 |
|
| 2 |
|
Change in current assets and current liabilities |
|
|
|
| |
Accounts receivable | 115 |
|
| 17 |
|
| 23 |
|
Accounts payable | (147 | ) |
| 2 |
|
| (56 | ) |
Unbilled revenues | 58 |
|
| 68 |
|
| 83 |
|
Fuel, materials and supplies | 12 |
|
| (97 | ) |
| (31 | ) |
Prepayments | 31 |
|
| (53 | ) |
| (5 | ) |
Counterparty collateral | 63 |
|
| (17 | ) |
| (81 | ) |
Price risk management assets and liabilities | (14 | ) |
| (30 | ) |
| 7 |
|
Taxes payable | (23 | ) |
| (3 | ) |
| (31 | ) |
Other | (49 | ) |
| (40 | ) |
| (16 | ) |
Other operating activities | | | | | |
Defined benefit plans - funding | (74 | ) |
| (35 | ) |
| (113 | ) |
Other assets | 4 |
|
| 3 |
|
| (4 | ) |
Other liabilities | (23 | ) |
| — |
|
| (30 | ) |
Net cash provided by operating activities | 768 |
|
| 462 |
|
| 410 |
|
Cash Flows from Investing Activities | |
| | | |
Expenditures for property, plant and equipment | (451 | ) |
| (416 | ) |
| (583 | ) |
Proceeds from the sale of Montana hydroelectric generation business | — |
|
| 900 |
|
| — |
|
Expenditures for intangible assets | (70 | ) |
| (46 | ) |
| (42 | ) |
Acquisition of MACH Gen | (603 | ) | | — |
| | — |
|
Purchases of nuclear plant decommissioning trust investments | (196 | ) |
| (170 | ) |
| (159 | ) |
Proceeds from the sale of nuclear plant decommissioning trust investments | 180 |
|
| 154 |
|
| 144 |
|
Proceeds from the sale of the Renewable business | 116 |
| | — |
| | — |
|
Proceeds from the receipt of grants | — |
|
| 164 |
|
| 3 |
|
Net (increase) decrease in restricted cash and cash equivalents | 87 |
|
| (108 | ) |
| (22 | ) |
Other investing activities | 22 |
|
| 19 |
|
| 28 |
|
Net cash provided by (used in) investing activities | (915 | ) |
| 497 |
|
| (631 | ) |
Cash Flows from Financing Activities | |
| | | |
Issuance of long-term debt | 600 |
|
| — |
|
| — |
|
Retirement of long-term debt | (335 | ) |
| (309 | ) |
| (747 | ) |
Contributions from predecessor member | 82 |
|
| 739 |
|
| 1,577 |
|
Distributions to predecessor member | (217 | ) |
| (1,906 | ) |
| (408 | ) |
Net increase (decrease) in short-term debt | (162 | ) |
| 630 |
|
| (356 | ) |
Other financing activities | (32 | ) |
| — |
|
| (19 | ) |
Net cash provided by (used in) financing activities | (64 | ) |
| (846 | ) |
| 47 |
|
Net Increase (Decrease) in Cash and Cash Equivalents | (211 | ) |
| 113 |
|
| (174 | ) |
Cash and Cash Equivalents at Beginning of Period | 352 |
|
| 239 |
|
| 413 |
|
Cash and Cash Equivalents at End of Period | $ | 141 |
|
| $ | 352 |
|
| $ | 239 |
|
Supplemental Disclosures of Cash Flow Information | | | | | |
Cash paid (received) during the period for: |
|
|
|
|
|
| |
Interest - net of amount capitalized | $ | 169 |
|
| $ | 122 |
|
| $ | 157 |
|
Income taxes - net | $ | 5 |
|
| $ | 310 |
|
| $ | 189 |
|
The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements.
|
| | | | | | | |
CONSOLIDATED BALANCE SHEETS AT DECEMBER 31, |
Talen Energy Corporation and Subsidiaries |
|
|
|
(Millions of Dollars, Shares in Thousands) |
|
|
|
| 2015 |
| 2014 |
Assets | |
| |
Current Assets | |
| |
Cash and cash equivalents | $ | 141 |
|
| $ | 352 |
|
Restricted cash and cash equivalents | 106 |
|
| 176 |
|
Accounts receivable (less reserve: 2015, $1; 2014, $2) |
|
|
|
Customer | 205 |
|
| 186 |
|
Other | 62 |
|
| 103 |
|
Accounts receivable from affiliates | — |
|
| 36 |
|
Unbilled revenues | 160 |
|
| 218 |
|
Fuel, materials and supplies | 508 |
|
| 455 |
|
Prepayments | 52 |
|
| 70 |
|
Price risk management assets | 562 |
|
| 1,079 |
|
Assets held for sale | 954 |
|
| — |
|
Other current assets | 12 |
|
| 26 |
|
Total Current Assets | 2,762 |
|
| 2,701 |
|
Investments | |
| |
Nuclear plant decommissioning trust funds | 951 |
|
| 950 |
|
Other investments | 25 |
|
| 30 |
|
Total Investments | 976 |
|
| 980 |
|
Property, Plant and Equipment | |
| |
Generation | 13,468 |
|
| 11,318 |
|
Nuclear fuel | 652 |
|
| 624 |
|
Other | 342 |
|
| 293 |
|
Less: accumulated depreciation | 6,411 |
|
| 6,242 |
|
Property, plant and equipment, net | 8,051 |
|
| 5,993 |
|
Construction work in progress | 536 |
|
| 443 |
|
Total Property, Plant and Equipment, net | 8,587 |
|
| 6,436 |
|
Other Noncurrent Assets | |
| |
Goodwill | — |
|
| 72 |
|
Other intangibles | 310 |
|
| 257 |
|
Price risk management assets | 131 |
|
| 239 |
|
Other noncurrent assets | 60 |
|
| 75 |
|
Total Other Noncurrent Assets | 501 |
|
| 643 |
|
Total Assets | $ | 12,826 |
|
| $ | 10,760 |
|
The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements.
|
| | | | | | | |
CONSOLIDATED BALANCE SHEETS AT DECEMBER 31, |
Talen Energy Corporation and Subsidiaries |
|
|
|
(Millions of Dollars, Shares in Thousands) |
|
|
|
| 2015 |
| 2014 |
Liabilities and Equity | |
| |
Current Liabilities | |
| |
Short-term debt | $ | 608 |
| | $ | 630 |
|
Long-term debt due within one year | 399 |
| | 535 |
|
Accounts payable | 291 |
| | 361 |
|
Accounts payable to affiliates | — |
| | 50 |
|
Taxes | 16 |
| | 28 |
|
Interest | 43 |
| | 16 |
|
Price risk management liabilities | 431 |
| | 1,024 |
|
Liabilities held for sale | 33 |
| | — |
|
Other current liabilities | 267 |
| | 246 |
|
Total Current Liabilities | 2,088 |
| | 2,890 |
|
Long-term Debt | 3,804 |
| | 1,683 |
|
Deferred Credits and Other Noncurrent Liabilities | | | |
Deferred income taxes | 1,587 |
| | 1,223 |
|
Investment tax credits | 15 |
| | 27 |
|
Price risk management liabilities | 108 |
| | 193 |
|
Accrued pension obligations | 340 |
| | 299 |
|
Asset retirement obligations | 490 |
| | 415 |
|
Other deferred credits and noncurrent liabilities | 91 |
| | 123 |
|
Total Deferred Credits and Other Noncurrent Liabilities | 2,631 |
| | 2,280 |
|
Commitments and Contingent Liabilities (Note 11) |
|
|
|
Equity |
|
|
|
|
|
Predecessor Member's Equity (a) | — |
| | 3,930 |
|
Common Stock - $0.001 par value (b) | — |
| | — |
|
Additional paid-in capital | 4,702 |
| | — |
|
Accumulated deficit | (373 | ) | | — |
|
Accumulated other comprehensive income (loss) | (26 | ) | | (23 | ) |
Total Equity | 4,303 |
|
| 3,907 |
|
Total Liabilities and Equity | $ | 12,826 |
|
| $ | 10,760 |
|
| |
(a) | Represents Talen Energy Supply's predecessor member's equity prior to the June 1, 2015 spinoff transaction. Upon completion of the spinoff, the predecessor member's equity was transferred to Talen Energy Corporation's additional paid-in capital. See Note 1 for additional information on the spinoff. |
| |
(b) | 1,000,000 shares authorized; 128,509 shares issued and outstanding at December 31, 2015. |
The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF EQUITY |
Talen Energy Corporation and Subsidiaries |
(Millions of Dollars) | | | | | | |
| | | | | | | | | | | | | | | | |
| | Common stock shares (a) | | Common stock | | Additional paid-in capital | | Accumulated deficit | | AOCI | | Non-controlling interests | | Predecessor member's equity (b) | | Total |
December 31, 2012 | | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 48 |
| | $ | 18 |
| | $ | 3,782 |
| | $ | 3,848 |
|
Net income (loss) | | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | (230 | ) | | (229 | ) |
Other comprehensive income (loss) | | — |
| | — |
| | — |
| | — |
| | 29 |
| | — |
| | — |
| | 29 |
|
Distributions to predecessor member | | — |
| | — |
| | — |
| | — |
| | — |
| | (19 | ) | | (408 | ) | | (427 | ) |
Contributions from predecessor member | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,577 |
| | 1,577 |
|
December 31, 2013 | | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 77 |
| | $ | — |
| | $ | 4,721 |
| | $ | 4,798 |
|
| | | | | | | | | | | | | | | | |
Net income (loss) | | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 410 |
| | $ | 410 |
|
Other comprehensive income (loss) | | — |
| | — |
| | — |
| | — |
| | (100 | ) | | — |
| | — |
| | (100 | ) |
Distributions to predecessor member | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1,940 | ) | | (1,940 | ) |
Contributions from predecessor member | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 739 |
| | 739 |
|
December 31, 2014 | | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (23 | ) | | $ | — |
| | $ | 3,930 |
| | $ | 3,907 |
|
| | | | | | | | | | | | | | | | |
Net income (loss) from January 1, 2015 to May 31, 2015 | | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 32 |
| | $ | 32 |
|
Net income (loss) from June 1, 2015 to December 31, 2015 | | — |
| | — |
| | — |
| | (373 | ) | | — |
| | — |
| | — |
| | (373 | ) |
Other comprehensive income (loss) | | — |
| | — |
| | — |
| | — |
| | (3 | ) | | — |
| | — |
| | (3 | ) |
Distributions to predecessor member | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (410 | ) | | (410 | ) |
Contributions from predecessor member | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 248 |
| | 248 |
|
Common stock issued for acquisition of RJS Power | | 44,975 |
| | — |
| | 902 |
| | — |
| | — |
| | — |
| | — |
| | 902 |
|
Stock issuance | | 10 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Stock issuance expense | | — |
| | — |
| | (2 | ) | | — |
| | — |
| | — |
| | — |
| | (2 | ) |
Stock-based compensation | | — |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| | — |
| | 2 |
|
Consummation of spinoff transaction (b) | | 83,524 |
| | — |
| | 3,800 |
| | — |
| | — |
| | — |
| | (3,800 | ) | | — |
|
December 31, 2015 | | 128,509 |
|
| $ | — |
|
| $ | 4,702 |
|
| $ | (373 | ) |
| $ | (26 | ) | | $ | — |
|
| $ | — |
| | $ | 4,303 |
|
| |
(a) | Shares in thousands. Each share entitles the holder to one vote on any questionquestions presented at any shareowners'stockholders' meeting. |
| |
(b) | Upon consummation of the spinoff on June 1, 2015, Talen Energy Supply's predecessor member's equity balance was transferred to Talen Energy Corporation's "Additional paid-in capital." See "General - Comprehensive Income" in Note 1 for disclosure of balances of each component of AOCI. |
(c) | 2011 includes the April issuance of 92 million shares of common stock, and 2010 includes the June issuance of 103.5 million shares of common stock. See Note 7 for additional information. All years presented include shares of common stock issued through various stock and incentive compensation plans. |
(d) | 2011 includes $123 million for the 2011 Purchase Contracts and $20 million of related fees and expenses, net of tax. 2010 includes $157 million for the 2010 Purchase Contracts and $19 million of related fees and expenses, net of tax. See Note 7 for additional information. |
(e) | 2012, 2011 and 2010 include $47 million, $33 million and $26 million of stock-based compensation expense related to new and existing unvested equity awards, and $(29) million, $(23) million and $(18) million related primarily to the reclassification from "Stock-based compensation" to "Common stock issued" for the issuance of common stock after applicable equity award vesting periods and tax adjustments related to stock-based compensation. |
(f) | "Earnings reinvested" includes dividends and dividend equivalents on PPL common stock and restricted stock units. "Noncontrolling interests" includes dividends, redemptions and distributions to noncontrolling interests. In April 2010 and June 2012, collectively, PPL Electric redeemed all of its outstanding preferred securities. See Note 3 for additional information on both redemptions.the spinoff. |
The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements.
CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, |
PPL Energy Supply, LLC and Subsidiaries |
(Millions of Dollars) |
| | | | | | | | | | | | |
| | | | | 2012 | | 2011 | | 2010 |
Operating Revenues | | | | | | | | | |
| Wholesale energy marketing | | | | | | | | | |
| | Realized | | $ | 4,433 | | $ | 3,807 | | $ | 4,832 |
| | Unrealized economic activity (Note 19) | | | (311) | | | 1,407 | | | (805) |
| Wholesale energy marketing to affiliate | | | 78 | | | 26 | | | 320 |
| Unregulated retail electric and gas | | | 848 | | | 727 | | | 415 |
| Net energy trading margins | | | 4 | | | (2) | | | 2 |
| Energy-related businesses | | | 448 | | | 464 | | | 364 |
| Total Operating Revenues | | | 5,500 | | | 6,429 | | | 5,128 |
| | | | | | | | | | | | |
Operating Expenses | | | | | | | | | |
| Operation | | | | | | | | | |
| | Fuel | | | 965 | | | 1,080 | | | 1,096 |
| | Energy purchases | | | | | | | | | |
| | | Realized | | | 2,260 | | | 1,160 | | | 1,636 |
| | | Unrealized economic activity (Note 19) | | | (442) | | | 1,123 | | | (286) |
| | Energy purchases from affiliate | | | 3 | | | 3 | | | 3 |
| | Other operation and maintenance | | | 1,041 | | | 929 | | | 979 |
| Depreciation | | | 285 | | | 244 | | | 236 |
| Taxes, other than income | | | 69 | | | 71 | | | 46 |
| Energy-related businesses | | | 432 | | | 458 | | | 357 |
| Total Operating Expenses | | | 4,613 | | | 5,068 | | | 4,067 |
| | | | | | | | | | | | |
Operating Income | | | 887 | | | 1,361 | | | 1,061 |
| | | | | | | | | | | | |
Other Income (Expense) - net | | | 18 | | | 23 | | | 22 |
| | | | | | | | | | | | |
Other-Than-Temporary Impairments | | | 1 | | | 6 | | | 3 |
| | | | | | | | | | | | |
Interest Income from Affiliates | | | 2 | | | 8 | | | 9 |
| | | | | | | | | | | | |
Interest Expense | | | 168 | | | 174 | | | 208 |
| | | | | | | | | | | | |
Income (Loss) from Continuing Operations Before Income Taxes | | | 738 | | | 1,212 | | | 881 |
| | | | | | | | | | | | |
Income Taxes | | | 263 | | | 445 | | | 261 |
| | | | | | | | | | | | |
Income (Loss) from Continuing Operations After Income Taxes | | | 475 | | | 767 | | | 620 |
| | | | | | | | | | | | |
Income (Loss) from Discontinued Operations (net of income taxes) | | | | | | 2 | | | 242 |
| | | | | | | | | | | | |
Net Income | | | 475 | | | 769 | | | 862 |
| | | | | | | | | | | | |
Net Income Attributable to Noncontrolling Interests | | | 1 | | | 1 | | | 1 |
| | | | | | | | | | | | |
Net Income Attributable to PPL Energy Supply Member | | $ | 474 | | $ | 768 | | $ | 861 |
| | | | | | | | | | | | |
Amounts Attributable to PPL Energy Supply Member: | | | | | | | | | |
| Income (Loss) from Continuing Operations After Income Taxes | | $ | 474 | | $ | 766 | | $ | 619 |
| Income (Loss) from Discontinued Operations (net of income taxes) | | | | | | 2 | | | 242 |
| Net Income | | $ | 474 | | $ | 768 | | $ | 861 |
| | | | | | | | | | | | |
The accompanying Notes to Financial Statements are an integral part of the financial statements. |
|
FOR THE YEARS ENDED DECEMBER 31, |
PPL Energy Supply, LLC and Subsidiaries |
(Millions of Dollars) |
| | | | | | | | | | |
| | | | 2012 | | 2011 | | 2010 |
| | | | | | | | | | | |
Net income | | $ | 475 | | $ | 769 | | $ | 862 |
| | | | | | | | | | | |
Other comprehensive income (loss): | | | | | | | | | |
Amounts arising during the period - gains (losses), net of tax (expense) benefit: | | | | | | | | | |
| Foreign currency translation adjustments, net of tax of $0, $0, ($1) | | | | | | | | | (59) |
| Available-for-sale securities, net of tax of ($31), ($6), ($31) | | | 29 | | | 9 | | | 29 |
| Qualifying derivatives, net of tax of ($46), ($164), ($207) | | | 68 | | | 267 | | | 305 |
| Defined benefit plans: | | | | | | | | | |
| | Prior service costs, net of tax of $0, ($2), ($8) | | | 1 | | | (2) | | | 12 |
| | Net actuarial gain (loss), net of tax of $56, $13, $36 | | | (82) | | | (22) | | | (63) |
| | Transition obligation, net of tax of $0, $0, ($3) | | | | | | | | | 6 |
Reclassifications to net income - (gains) losses, net of tax expense (benefit): | | | | | | | | | |
| Available-for-sale securities, net of tax of $1, $5, $3 | | | (7) | | | (7) | | | (5) |
| Qualifying derivatives, net of tax of $291, $242, $99 | | | (463) | | | (353) | | | (145) |
| Equity investees' other comprehensive (income) loss, net of tax of $0, $0, $0 | | | | | | 3 | | | |
| Defined benefit plans: | | | | | | | | | |
| | Prior service costs, net of tax of ($2), ($3), ($5) | | | 5 | | | 4 | | | 9 |
| | Net actuarial loss, net of tax of ($2), ($2), ($14) | | | 10 | | | 4 | | | 39 |
| | Transition obligation, net of tax of $0, $0, ($1) | | | | | | | | | 1 |
Total other comprehensive income (loss) attributable to | | | | | | | | | |
| PPL Energy Supply Member | | | (439) | | | (97) | | | 129 |
| | | | | | | | | | | |
Comprehensive income (loss) | | | 36 | | | 672 | | | 991 |
| Comprehensive income attributable to noncontrolling interests | | | 1 | | | 1 | | | 1 |
| | | | | | | | | | | |
Comprehensive income (loss) attributable to PPL Energy Supply Member | | $ | 35 | | $ | 671 | | $ | 990 |
| | | | | | | | | | | |
The accompanying Notes to Financial Statements are an integral part of the financial statements. |
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, |
PPL Energy Supply, LLC and Subsidiaries | | | |
(Millions of Dollars) | | | |
| | | | | 2012 | | 2011 | | 2010 |
Cash Flows from Operating Activities | | | | | | | | | |
| Net income | | $ | 475 | | $ | 769 | | $ | 862 |
| Adjustments to reconcile net income to net cash provided by (used in) operating activities | | | | | | | | | |
| | Pre-tax gain from the sale of the Maine hydroelectric generation business | | | | | | | | | (25) |
| | Depreciation | | | 285 | | | 245 | | | 365 |
| | Amortization | | | 119 | | | 137 | | | 160 |
| | Defined benefit plans - expense | | | 43 | | | 36 | | | 52 |
| | Deferred income taxes and investment tax credits | | | 152 | | | 317 | | | (31) |
| | Impairment of assets | | | 3 | | | 13 | | | 120 |
| | Unrealized (gains) losses on derivatives, and other hedging activities | | | (41) | | | (283) | | | 536 |
| | Provision for Montana hydroelectric litigation | | | | | | (74) | | | 66 |
| | Other | | | 42 | | | 25 | | | 41 |
| Change in current assets and current liabilities | | | | | | | | | |
| | Accounts receivable | | | (54) | | | 38 | | | (18) |
| | Accounts payable | | | (45) | | | (89) | | | 20 |
| | Unbilled revenues | | | 33 | | | 14 | | | (88) |
| | Counterparty collateral | | | (34) | | | (190) | | | (18) |
| | Taxes | | | (27) | | | 27 | | | 87 |
| | Other | | | (68) | | | (18) | | | 8 |
| Other operating activities | | | | | | | | | |
| | Defined benefit plans - funding | | | (75) | | | (152) | | | (302) |
| | Other assets | | | (41) | | | (30) | | | (71) |
| | Other liabilities | | | 17 | | | (9) | | | 76 |
| | | Net cash provided by (used in) operating activities | | | 784 | | | 776 | | | 1,840 |
Cash Flows from Investing Activities | | | | | | | | | |
| Expenditures for property, plant and equipment | | | (648) | | | (661) | | | (1,009) |
| Proceeds from the sale of certain non-core generation facilities | | | | | | 381 | | | |
| Proceeds from the sale of the Long Island generation business | | | | | | | | | 124 |
| Proceeds from the sale of the Maine hydroelectric generation business | | | | | | | | | 38 |
| Ironwood Acquisition, net of cash acquired | | | (84) | | | | | | |
| Expenditures for intangible assets | | | (45) | | | (57) | | | (82) |
| Purchases of nuclear plant decommissioning trust investments | | | (154) | | | (169) | | | (128) |
| Proceeds from the sale of nuclear plant decommissioning trust investments | | | 139 | | | 156 | | | 114 |
| Issuance of long-term notes receivable to affiliates | | | | | | | | | (1,816) |
| Repayment of long-term notes receivable from affiliates | | | | | | | | | 1,816 |
| Net (increase) decrease in notes receivable from affiliates | | | 198 | | | (198) | | | |
| Net (increase) decrease in restricted cash and cash equivalents | | | 104 | | | (128) | | | 84 |
| Other investing activities | | | 21 | | | 8 | | | 34 |
| | | Net cash provided by (used in) investing activities | | | (469) | | | (668) | | | (825) |
Cash Flows from Financing Activities | | | | | | | | | |
| Issuance of long-term debt | | | | | | 500 | | | 602 |
| Retirement of long-term debt | | | (9) | | | (750) | | | |
| Contributions from member | | | 563 | | | 461 | | | 3,625 |
| Distributions to member | | | (787) | | | (316) | | | (4,692) |
| Cash included in net assets of subsidiary distributed to member | | | | | | (325) | | | |
| Debt issuance and credit facility costs | | | (3) | | | (9) | | | (53) |
| Net increase (decrease) in short-term debt | | | (44) | | | 50 | | | (93) |
| Other financing activities | | | (1) | | | (1) | | | (1) |
| | | Net cash provided by (used in) financing activities | | | (281) | | | (390) | | | (612) |
Effect of Exchange Rates on Cash and Cash Equivalents | | | | | | | | | 13 |
Net Increase (Decrease) in Cash and Cash Equivalents | | | 34 | | | (282) | | | 416 |
| Cash and Cash Equivalents at Beginning of Period | | | 379 | | | 661 | | | 245 |
| Cash and Cash Equivalents at End of Period | | $ | 413 | | $ | 379 | | $ | 661 |
| | | | | | | | | | | | |
Supplemental Disclosures of Cash Flow Information | | | | | | | | | |
| Cash paid (received) during the period for: | | | | | | | | | |
| | | Interest - net of amount capitalized | | $ | 150 | | $ | 165 | | $ | 275 |
| | | Income taxes - net | | $ | 128 | | $ | 69 | | $ | 278 |
| | | | | | | | | | | | |
The accompanying Notes to Financial Statements are an integral part of the financial statements. | | | |
|
PPL Energy Supply, LLC and Subsidiaries |
(Millions of Dollars) |
| | | | | 2012 | | 2011 |
Assets | | | | | | |
| | | | | | | | | |
Current Assets | | | | | | |
| Cash and cash equivalents | | $ | 413 | | $ | 379 |
| Restricted cash and cash equivalents | | | 46 | | | 145 |
| Accounts receivable (less reserve: 2012, $23; 2011, $15) | | | | | | |
| | Customer | | | 183 | | | 169 |
| | Other | | | 31 | | | 31 |
| Accounts receivable from affiliates | | | 125 | | | 89 |
| Unbilled revenues | | | 369 | | | 402 |
| Note receivable from affiliates | | | | | | 198 |
| Fuel, materials and supplies | | | 327 | | | 298 |
| Prepayments | | | 15 | | | 14 |
| Price risk management assets | | | 1,511 | | | 2,527 |
| Other current assets | | | 10 | | | 11 |
| Total Current Assets | | | 3,030 | | | 4,263 |
| | | | | | | |
Investments | | | | | | |
| Nuclear plant decommissioning trust funds | | | 712 | | | 640 |
| Other investments | | | 41 | | | 40 |
| Total Investments | | | 753 | | | 680 |
| | | | | | | |
Property, Plant and Equipment | | | | | | |
| Non-regulated property, plant and equipment | | | | | | |
| | Generation | | | 11,305 | | | 10,517 |
| | Nuclear fuel | | | 524 | | | 457 |
| | Other | | | 294 | | | 245 |
| Less: accumulated depreciation - non-regulated property, plant and equipment | | | 5,817 | | | 5,573 |
| | Non-regulated property, plant and equipment, net | | | 6,306 | | | 5,646 |
| Construction work in progress | | | 987 | | | 840 |
| Property, Plant and Equipment, net (a) | | | 7,293 | | | 6,486 |
| | | | | | | |
Other Noncurrent Assets | | | | | | |
| Goodwill | | | 86 | | | 86 |
| Other intangibles (a) | | | 252 | | | 386 |
| Price risk management assets | | | 557 | | | 896 |
| Other noncurrent assets | | | 404 | | | 382 |
| Total Other Noncurrent Assets | | | 1,299 | | | 1,750 |
| | | | | | | |
Total Assets | | $ | 12,375 | | $ | 13,179 |
(a) | At December 31, 2012 and December 31, 2011, includes $428 million and $416 million of PP&E, consisting primarily of "Generation," including leasehold improvements, and $10 million and $11 million of "Other intangibles" from the consolidation of a VIE that is the owner/lessor of the Lower Mt. Bethel plant. See Note 22 for additional information. |
|
| | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME FOR THE YEARS ENDED DECEMBER 31, |
Talen Energy Supply, LLC and Subsidiaries | | | | | |
(Millions of Dollars) | | | | | |
| 2015 | | 2014 | | 2013 |
Operating Revenues | | | | | |
Wholesale energy | $ | 2,828 |
| | $ | 2,653 |
| | $ | 2,890 |
|
Wholesale energy to affiliate | 14 |
| | 84 |
| | 51 |
|
Retail energy | 1,095 |
| | 1,243 |
| | 1,027 |
|
Energy-related businesses | 544 |
| | 601 |
| | 527 |
|
Total Operating Revenues | 4,481 |
| | 4,581 |
| | 4,495 |
|
Operating Expenses | | | | | |
Operation | | | | | |
Fuel | 1,194 |
| | 1,196 |
| | 1,048 |
|
Energy purchases | 676 |
| | 1,054 |
| | 1,153 |
|
Operation and maintenance | 1,052 |
| | 1,007 |
| | 961 |
|
Loss on lease termination | — |
| | — |
| | 697 |
|
Impairments | 657 |
| | — |
| | 65 |
|
Depreciation | 356 |
| | 297 |
| | 299 |
|
Taxes, other than income | 65 |
| | 57 |
| | 53 |
|
Energy-related businesses | 520 |
| | 573 |
| | 512 |
|
Total Operating Expenses | 4,520 |
| | 4,184 |
| | 4,788 |
|
Operating Income (Loss) | (39 | ) | | 397 |
| | (293 | ) |
Other Income (Expense) - net | (118 | ) | | 30 |
| | 32 |
|
Interest Expense | 211 |
| | 124 |
| | 159 |
|
Income (Loss) from Continuing Operations Before Income Taxes | (368 | ) | | 303 |
| | (420 | ) |
Income Taxes | (27 | ) | | 116 |
| | (159 | ) |
Income (Loss) from Continuing Operations After Income Taxes | (341 | ) | | 187 |
| | (261 | ) |
Income (Loss) from Discontinued Operations (net of income taxes) | — |
| | 223 |
| | 32 |
|
Net Income (Loss) | (341 | ) | | 410 |
| | (229 | ) |
Net Income (Loss) Attributable to Noncontrolling Interests | — |
| | — |
| | 1 |
|
Net Income (Loss) Attributable to Talen Energy Supply Member | $ | (341 | ) | | $ | 410 |
| | $ | (230 | ) |
Amounts Attributable to Talen Energy Supply Member: | | | | | |
Income (Loss) from Continuing Operations After Income Taxes | $ | (341 | ) | | $ | 187 |
| | $ | (262 | ) |
Income (Loss) from Discontinued Operations (net of income taxes) | — |
| | 223 |
| | 32 |
|
Net Income (Loss) | $ | (341 | ) | | $ | 410 |
| | $ | (230 | ) |
The accompanying Notes to Consolidated Financial Statements are an integral part of the financial statements.