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PINNACLE WEST CAPITAL CORP - 10-K - MANAGEMENT'S DISCUSSION AND ANALYSIS
(Edgar Glimpses Via Acquire Media NewsEdge) OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
The following discussion should be read in conjunction with Pinnacle West's
Consolidated Financial Statements and APS's Consolidated Financial Statements
and the related Notes that appear in Item 8 of this report. For information on
factors that may cause our actual future results to differ from those we
currently seek or anticipate, see "Forward-Looking Statements" at the front of
this report and "Risk Factors" in Item 1A.
OVERVIEW
Pinnacle West owns all of the outstanding common stock of APS. APS is a
vertically-integrated electric utility that provides either retail or wholesale
electric service to most of the state of Arizona, with the major exceptions of
about one-half of the Phoenix metropolitan area, the Tucson metropolitan area
and Mohave County in northwestern Arizona. APS accounts for essentially all of
our revenues and earnings, and is expected to continue to do so.
Areas of Business Focus
Operational Performance, Reliability and Recent Developments.
Nuclear. APS operates and is a joint owner of Palo Verde. In 2012, Palo Verde
achieved its best generation year ever, producing over 31 million
megawatt-hours, with an overall station capacity factor of 92.3%. In 2012, Palo
Verde successfully refueled both Unit 2 and Unit 3. APS management continues to
work closely with regulators and others in the nuclear industry to analyze the
lessons learned and address any rulemaking or improvements resulting from the
March 2011 events impacting the Fukushima Daiichi Nuclear Power Station in
Japan.
Coal and Related Environmental Matters. APS-operated coal plants, Four Corners
and Cholla, achieved net capacity factors for APS of 71% and 75%, respectively,
in 2012. These capacity factors were lower than in prior years primarily due to
lower gas prices resulting in higher production from our gas fleet. APS is
focused on the impacts on its coal fleet that may result from increased
regulation and potential legislation concerning greenhouse gas emissions.
Concern over climate change and other emission-related issues could have a
significant impact on our capital expenditures and operating costs in the form
of taxes, emissions allowances or required equipment upgrades for these plants.
APS is closely monitoring its long-range capital management plans, understanding
that any resulting regulation and legislation could impact the economic
viability of certain plants, as well as the willingness or ability of power
plant participants to fund any such equipment upgrades.
SCE, a participant in Four Corners, has indicated that certain California
legislation may prohibit it from making emission control expenditures at the
plant. On November 8, 2010, APS and SCE entered into the Asset Purchase
Agreement, providing for the purchase by APS of SCE's 48% interest in each of
Units 4 and 5 of Four Corners. The purchase price is $294 million, subject to
certain adjustments. Completion of the purchase by APS is subject to the
receipt of approvals by the ACC, the CPUC and the FERC. On March 29, 2012, the
CPUC issued an order approving the sale. On April 18, 2012, the ACC voted to
allow APS to move forward with the purchase. The Asset Purchase Agreement
provides that the purchase price will be reduced by $7.5 million for each month
between October 1,
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2012 and the closing date. The ACC reserved the right to review the prudence of
the transaction for cost recovery purposes in a future proceeding if the
purchase closes. The ACC also authorized an accounting deferral of certain
costs associated with the purchase until any such cost recovery proceeding
concludes. The FERC application seeking authorization for the transaction was
approved on November 27, 2012. The principal remaining condition to closing is
the negotiation and execution of a new coal supply contract on terms reasonably
acceptable to APS.
On December 19, 2012, BHP Billiton, the parent company of BNCC, the coal
supplier and operator of the mine that serves Four Corners, announced that it
has entered into a Memorandum of Understanding with the Navajo Nation setting
out the key terms under which full ownership of BNCC would be sold to the Navajo
Nation. BHP Billiton would be retained by BNCC under contract as the mine
manager and operator until July 2016. Key terms of the new coal supply contract
are being finalized by the Navajo Nation and APS and the other Four Corners
co-owners.
As a result of this proposed change in ownership of BNCC, APS now expects that a
new coal supply contract would be executed upon completion of negotiations and
following the endorsement of the transfer of ownership of the stock of BNCC to a
new Navajo Nation commercial enterprise to be established by the Navajo Nation
Tribal Council. The decision of the Tribal Council is currently expected to
occur in the second quarter of 2013.
Pursuant to the Asset Purchase Agreement, either APS or SCE has a right to
terminate the Agreement if satisfaction of the closing conditions had not
occurred by December 31, 2012, unless the party seeking to terminate is then in
breach of the Agreement.
APS, on behalf of the Four Corners participants, negotiated amendments to an
existing facility lease with the Navajo Nation which extends the Four Corners
leasehold interest from 2016 to 2041. The Navajo Nation approved these
amendments in March 2011. The effectiveness of the amendments also requires the
approval of the DOI, as does a related federal rights-of-way grant which the
Four Corners participants will pursue. A federal environmental review is
underway as part of the DOI review process.
APS has announced that, if APS's purchase of SCE's interests in Units 4 and 5 at
Four Corners is consummated, it will close Units 1, 2 and 3 at the plant. APS
owns 100% of Units 1-3. These events will change the plant's overall generating
capacity from 2,100 MW to 1,540 MW and APS's entitlement from the plant from 791
MW to 970 MW. When the ACC approved APS moving forward with the purchase of
Units 4 and 5, it also approved the recovery of any unrecovered costs associated
with the closure of Units 1, 2 and 3. The Settlement Agreement in APS's most
recent retail rate case allows APS to seek a rate adjustment to reflect the Four
Corners transaction should the transaction close (see Note 3).
APS cannot predict whether the mutual right to terminate in the Asset Purchase
Agreement will be exercised by a party to that agreement in the future, whether
BHP Billiton and the Navajo Nation will consummate the transfer of ownership of
BNCC, or whether the coal supply contract will be finalized and executed, such
that closing of APS's purchase of SCE's interest in Four Corners can occur.
Transmission and Delivery. APS is working closely with regulators to identify
and plan for transmission needs resulting from the current focus on renewable
energy. The capital expenditures table presented in the "Liquidity and Capital
Resources" section below includes the next three years of new
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transmission projects along with other transmission costs for upgrades and
replacements. APS is also working to establish and expand smart grid
technologies throughout its service territory designed to provide long-term
benefits both to APS and its customers. APS is piloting and deploying a variety
of technologies that are intended to allow customers to better monitor their
energy use and needs, minimize system outage durations as well as the number of
customers that experience outages, and facilitate greater cost savings to APS
through improved reliability and the automation of certain distribution
functions, including remote meter reading and remote connects and disconnects.
Renewable Energy. The ACC approved the RES in 2006. The renewable energy
requirement is 4% of retail electric sales in 2013 and increases annually until
it reaches 15% in 2025. In the settlement agreement related to the 2008 retail
rate case, APS agreed to exceed the RES standards, committing to 1,700 GWh of
new renewable resources to be in service by year-end 2015 in addition to its
2008 renewable resource commitments. Taken together, APS's commitment is
estimated to be approximately 12% of APS's estimated retail energy sales by
year-end 2015, which is more than double the existing RES target of 5% for that
year. A component of the RES is focused on stimulating development of
distributed energy systems (generally speaking, small-scale renewable
technologies that are located on customers' properties).
On June 29, 2012, APS filed its annual RES implementation plan, covering the
2013-2017 timeframe and requesting 2013 RES funding of $97 million to $107
million. In a final order dated January 31, 2013, the ACC approved a budget of
$103 million for APS's 2013 RES plan. That budget includes $4 million for
residential distributed energy incentives and $0.1 million for commercial
distributed energy up-front incentives, but did not include any funds for
commercial distributed energy production-based incentives. The ACC further
ordered that a hearing take place to consider: (i) APS's proposal to establish
compliance with distributed energy requirements by tracking and recording
distributed energy, rather than acquiring and retiring renewable energy credits;
and (ii) removing retail sales to APS's largest industrial customers when
calculating APS's compliance with the annual RES requirements.
APS has a diverse portfolio of existing and planned renewable resources totaling
1,090 MW, including solar, wind, geothermal, biomass and biogas. Of this
portfolio, 667 MW are currently in operation and 423 MW are under contract for
development or are under construction. Renewable resources in operation include
81 MW of solar facilities owned by APS, 349 MW of long-term purchased power
agreements, and an estimated 237 MW of customer-sited, third-party owned
distributed energy resources.
To achieve our RES requirements, as mentioned above, to date APS has entered
into contracts for 423 MW of renewable resources that are planned, in
development or under construction. APS's strategy to procure these resources
includes new facilities to be owned by APS, purchased power contracts for new
facilities and ongoing development of distributed energy resources. Through the
AZ Sun Program, APS has executed contracts for the development of 118 MW of new
solar generation, representing an investment commitment of approximately $502
million. See Note 3 for additional details of the AZ Sun Program, including the
related cost recovery. APS has also entered into long-term purchased power
agreements for 280 MW from solar facilities currently planned, in development or
under construction, and 94 MW from distributed energy resources. Agreements for
the development and completion of future resources are subject to various
conditions, including successful siting, permitting and interconnection of the
project to the electric grid.
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Demand Side Management. In recent years, Arizona regulators have placed an
increased focus on energy efficiency and other demand side management programs
to encourage customers to conserve energy, while incentivizing utilities to aid
in these efforts that ultimately reduce the demand for energy. In
December 2009, the ACC initiated an Energy Efficiency rulemaking, with a
proposed Energy Efficiency Standard of 22% cumulative annual energy savings by
2020. The 22% figure represents the cumulative reduction in future energy usage
through 2020 attributable to energy efficiency initiatives. This ambitious
standard became effective on January 1, 2011 and will likely impact Arizona's
future energy resource needs. The ACC issued an order on April 4, 2012
approving recovery of approximately $72 million of APS's energy efficiency and
demand side management program costs over a twelve-month period beginning
March 1, 2012. This amount does not include $10 million already being recovered
in general retail base rates.
On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan.
In 2013, the standards will require APS to achieve cumulative energy savings
equal to 5% of its 2012 retail energy sales. Later in 2012, APS filed a
supplement to its plan that included a proposed budget for 2013 of $87.6
million. APS expects to receive a decision from the ACC in the second quarter
of 2013.
Rate Matters. APS needs timely recovery through rates of its capital and
operating expenditures to maintain its financial health. APS's retail rates are
regulated by the ACC and its wholesale electric rates (primarily for
transmission) are regulated by the FERC. On June 1, 2011, APS filed a rate case
with the ACC. APS and other parties to the retail rate case subsequently
entered into a Settlement Agreement detailing the terms upon which the parties
have agreed to settle the rate case. See Note 3 for details regarding the
Settlement Agreement terms and for information on APS's FERC rates.
APS has several recovery mechanisms in place that provide more timely recovery
to APS of its fuel and transmission costs, and costs associated with the
promotion and implementation of its demand side management and renewable energy
efforts and customer programs. These mechanisms are described more fully in
Note 3.
As part of APS's proposed acquisition of SCE's interest in Units 4 and 5 of Four
Corners, APS and SCE agreed that upon closing of the acquisition (or in 2016 if
the closing does not occur), the companies will terminate an existing agreement
that provides transmission capacity for SCE to transmit its portion of the
output from Four Corners to California. APS expects to file a request with FERC
seeking authorization to cancel the existing agreement and defer a $40 million
payment to be made by APS associated with the termination and recover the
payment through amortization over a 29-year period. APS believes the costs
associated with the termination of the existing agreement are recoverable, but
cannot predict whether FERC will approve our request; however, if the recovery
is disallowed by FERC, APS would record a charge to its results of operations at
the time of the disallowance.
Financial Strength and Flexibility. Pinnacle West and APS currently have ample
borrowing capacity under their respective credit facilities, and may readily
access these facilities ensuring adequate liquidity for each company. Capital
expenditures will be funded with internally generated cash and external
financings, which may include issuances of long-term debt and Pinnacle West
common stock.
Other Subsidiaries. The operations of El Dorado are not expected to have any
material impact on our financial results, or to require any material amounts of
capital, over the next three years. As a result of the continuing distressed
conditions in the real estate markets, during 2009 our other first-tier
subsidiary, SunCor, undertook a program to dispose of its homebuilding
operations, master-planned
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communities, land parcels, commercial assets and golf courses in order to
eliminate its outstanding debt and, as of December 31, 2012, SunCor had no
assets. In February 2012, SunCor filed for protection under the United States
Bankruptcy Code to complete an orderly liquidation of its business. All
activities of SunCor are now reported as discontinued operations (see Note 21).
SunCor's loss in 2012 is primarily related to a contribution Pinnacle West
expects to make to SunCor's estate as part of a negotiated resolution to the
bankruptcy. We do not expect SunCor's bankruptcy to have a material impact on
Pinnacle West's financial position, results of operations or cash flows.
Key Financial Drivers
In addition to the continuing impact of the matters described above, many
factors influence our financial results and our future financial outlook,
including those listed below. We closely monitor these factors to plan for the
Company's current needs, and to adjust our expectations, financial budgets and
forecasts appropriately.
Electric Operating Revenues. For the years 2010 through 2012, retail electric
revenues comprised approximately 93% of our total electric operating revenues.
Our electric operating revenues are affected by customer growth or decline,
variations in weather from period to period, customer mix, average usage per
customer and the impacts of energy efficiency programs, distributed energy
additions, electricity rates and tariffs, the recovery of PSA deferrals and the
operation of other recovery mechanisms. Off-system sales of excess generation
output, purchased power and natural gas are included in operating revenues and
related fuel and purchased power because they are credited to APS's retail
customers through the PSA. These revenue transactions are affected by the
availability of excess generation or other energy resources and wholesale market
conditions, including competition, demand and prices.
Customer and Sales Growth. Retail customer growth in APS's service territory in
2012 was 1.1% compared with the comparable prior year. For the three years 2010
through 2012, APS's customer growth averaged 0.7% per year. We currently expect
annual customer growth to average about 2% for 2013 through 2015 based on our
assessment of modestly improving economic conditions, both nationally and in
Arizona. Retail electricity sales in kilowatt-hours, adjusted to exclude the
effects of weather variations, increased 0.1% in 2012 compared with the prior
year, reflecting the effects of customer conservation and energy efficiency and
distributed renewable generation initiatives, offset by mildly improving
economic conditions. For the three years 2010 through 2012, APS experienced
annual declines in retail electricity sales averaging 0.1%, adjusted to exclude
the effects of weather variations. We currently estimate that annual retail
electricity sales in kilowatt-hours will remain about flat on average during
2013 through 2015, including the effects of customer conservation and energy
efficiency and distributed renewable generation initiatives, but excluding the
effects of weather variations. A failure of the Arizona economy to continue to
improve could further impact these estimates.
Actual sales growth, excluding weather-related variations, may differ from our
projections as a result of numerous factors, such as economic conditions,
customer growth, usage patterns, impacts of energy efficiency programs and
growth in distributed generation, and responses to retail price changes. Our
experience indicates that a reasonable range of variation in our kilowatt-hour
sales projection attributable to such economic factors under normal business
conditions can result in increases or decreases in annual net income of up to
$10 million.
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Weather. In forecasting the retail sales growth numbers provided above, we
assume normal weather patterns based on historical data. Historical extreme
weather variations have resulted in annual variations in net income in excess of
$20 million. However, our experience indicates that the more typical variations
from normal weather can result in increases or decreases in annual net income of
up to $10 million.
Fuel and Purchased Power Costs. Fuel and purchased power costs included on our
Consolidated Statements of Income are impacted by our electricity sales volumes,
existing contracts for purchased power and generation fuel, our power plant
performance, transmission availability or constraints, prevailing market prices,
new generating plants being placed in service in our market areas, changes in
our generation resource allocation, our hedging program for managing such costs
and PSA deferrals and the related amortization.
Operations and Maintenance Expenses. Operations and maintenance expenses are
impacted by growth, power plant operations, maintenance of utility plant
(including generation, transmission, and distribution facilities), inflation,
outages, higher-trending pension and other postretirement benefit costs,
renewable energy and demand side management related expenses (which are offset
by the same amount of operating revenues) and other factors. In the settlement
agreement related to the 2008 retail rate case, APS committed to operational
expense reductions from 2010 through 2014 and received approval to defer certain
pension and other postretirement benefit cost increases incurred in 2011 and
2012, which totaled $25 million, as a regulatory asset, until the most recent
general retail rate case decision became effective on July 1, 2012. In
July 2012, we began amortizing the regulatory asset over a 36-month period.
Depreciation and Amortization Expenses. Depreciation and amortization expenses
are impacted by net additions to utility plant and other property (such as new
generation, transmission, and distribution facilities), and changes in
depreciation and amortization rates. See "Capital Expenditures" below for
information regarding the planned additions to our facilities. As a result of
the twenty-year extensions of the operating licenses for each of the Palo Verde
units granted by the NRC in 2011, we decreased our pretax depreciation expense
related to Palo Verde by approximately $34 million per year starting on
January 1, 2012.
Property Taxes. Taxes other than income taxes consist primarily of property
taxes, which are affected by the value of property in-service and under
construction, assessment ratios, and tax rates. The average property tax rate
in Arizona for APS, which owns essentially all of our property, was 9.6% of the
assessed value for 2012, 9.0% for 2011, and 8.0% for 2010. We expect property
taxes to increase as we add new generating units and continue with improvements
and expansions to our existing generating units, transmission and distribution
facilities. (See Note 3 for property tax deferrals contained in the Settlement
Agreement).
Income Taxes. Income taxes are affected by the amount of pretax book income,
income tax rates, certain deductions and non-taxable items, such as AFUDC. In
addition, income taxes may also be affected by the settlement of issues with
taxing authorities.
Interest Expense. Interest expense is affected by the amount of debt
outstanding and the interest rates on that debt (see Note 6). The primary
factors affecting borrowing levels are expected to be our capital expenditures,
long-term debt maturities, equity issuances and internally generated cash flow.
An allowance for borrowed funds used during construction offsets a portion of
interest expense
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while capital projects are under construction. We stop accruing AFUDC on a
project when it is placed in commercial operation.
RESULTS OF OPERATIONS
Pinnacle West's reportable business segment is our regulated electricity
segment, which consists of traditional regulated retail and wholesale
electricity businesses (primarily electricity service to Native Load customers)
and related activities and includes electricity generation, transmission and
distribution.
APSES's and SunCor's operations have been classified as discontinued
operations. Pinnacle West sold its investment in APSES in August 2011. In
February 2012, SunCor filed for protection under the United States Bankruptcy
Code to complete an orderly liquidation of its business (see Note 21).
Operating Results - 2012 compared with 2011
Our consolidated net income attributable to common shareholders for the year
ended December 31, 2012 was $382 million, compared with net income of $339
million for the prior year. The results reflect an increase of approximately
$59 million for the regulated electricity segment primarily due to increases
related to the retail regulatory settlement effective July 1, 2012 (see Note 3),
higher retail transmission revenues, lower depreciation and amortization due to
20-year Palo Verde license extensions received in 2011, and lower net interest
charges due to lower debt balances and lower interest rates in the current year.
The $17 million decrease in discontinued operations is primarily related to a
contribution Pinnacle West expects to make to SunCor's estate as part of a
negotiated resolution to the bankruptcy (see Note 21) and absence of the 2011
gain on sale of our investment in APSES.
The following table presents net income attributable to common shareholders by
business segment compared with the prior year:
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Year Ended
December 31,
2012 2011 Net Change
(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and
purchased power expenses (a) $ 2,299 $ 2,228 $ 71
Operations and maintenance (a) (885 ) (904 ) 19
Depreciation and amortization (404 ) (427 ) 23
Taxes other than income taxes (159 ) (148 ) (11 )
Other income (expenses), net 6 16 (10 )
Interest charges, net of allowance for
borrowed funds used during construction (200 ) (224 ) 24
Income taxes (237 ) (184 ) (53 )
Less income related to noncontrolling
interests (Note 20) (32 ) (28 ) (4 )
Regulated electricity segment net income 388 329 59
All other - (1 ) 1
Income from Continuing Operations
Attributable to Common Shareholders 388 328 60
Income (Loss) from Discontinued
Operations Attributable to Common
Shareholders (b) (6 ) 11 (17 )
Net Income Attributable to Common
Shareholders $ 382 $ 339 $ 43
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(a) Includes effects of 2011 settlement of certain transmission
right-of-way costs, which did not affect net income, but increased both electric
operating revenues and operations and maintenance expenses by $28 million.
Costs related to the settlement were offset by related revenues from SCE, which
leases the related transmission line from APS.
(b) Includes activities related to APSES and SunCor.
Operating revenues less fuel and purchased power expenses Regulated electricity
segment operating revenues less fuel and purchased power expenses were $71
million higher for the year ended December 31, 2012 compared with the prior
year. The following table summarizes the major components of this change:
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Increase (Decrease)
Fuel and
purchased
Operating power
revenues expenses Net change
(dollars in millions)
Impacts of retail regulatory settlement
effective July 1, 2012 $ 64 $ 1 $ 63
Higher retail transmission revenues 41 - 41
Lower fuel and purchased power costs, net
of related deferrals and off-system sales (11 ) (14 ) 3
Lower demand-side management, renewable
energy and similar regulatory surcharges (3 ) 4 (7 )
Settlement in 2011 of certain
prior-period transmission right-of-way
revenues (28 ) - (28 )
Miscellaneous items, net (7 ) (6 ) (1 )
Total $ 56 $ (15 ) $ 71
Operations and maintenance Operations and maintenance expenses decreased $19
million for the year ended December 31, 2012 compared with the prior year
primarily because of:
† A decrease of $28 million related to settlement in 2011
of certain transmission right-of-way costs, which was offset in operating
revenues;
† A decrease of $22 million related to costs fordemand-side management, renewable energy and similar regulatory programs;
† A decrease of $15 million in generation costs, primarily
related to lower nuclear generation costs;
† An increase of $21 million related to employee benefit
costs, including approximately $12 million of pension and other postretirement
costs;
† An increase of $9 million related to higher stock
compensation costs resulting from an improved company stock price and estimated
performance results;
† An increase of $7 million in information technologycosts, primarily related to higher software maintenance; and
† An increase of $9 million due to other miscellaneous
factors.
Depreciation and amortization Depreciation and amortization expenses were $23
million lower for the year ended December 31, 2012 compared with the prior year
primarily due to the impacts of Palo Verde operating license extensions,
partially offset by increased plant in service.
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Taxes other than income taxes Taxes other than income taxes increased $11
million for the year ended December 31, 2012 compared with the prior year
primarily because of higher property tax rates in the current year.
Other income (expenses), net Other income (expenses), net, decreased $10
million for the year ended December 31, 2012 compared with the prior year
primarily because of higher investment losses of approximately $2 million and
other non-operating expenses of approximately $8 million in the current year.
Interest charges, net of allowance for borrowed funds used during construction
Interest charges, net of allowance for borrowed funds used during construction,
decreased $24 million for the year ended December 31, 2012 compared with the
prior year primarily because of lower debt balances and lower interest rates in
the current year.
Income taxes Income taxes were $53 million higher for the year ended
December 31, 2012 compared with the prior year primarily due to higher pre-tax
income in the current year and a lower effective tax rate in 2011.
Discontinued Operations
Results from discontinued operations decreased $17 million primarily due to a
contribution Pinnacle West expects to make to SunCor's estate as part of a
negotiated resolution to the bankruptcy (see Note 21) and absence of a gain
related to the sale of our investment in APSES in 2011.
Operating Results - 2011 compared with 2010
Our consolidated net income attributable to common shareholders for the year
ended December 31, 2011 was $339 million, compared with net income of $350
million for the prior year. The $11 million net decrease consisted of a $14
million decrease in income from discontinued operations and a $3 million
increase in income from continuing operations primarily related to the regulated
electricity segment. Regulated electricity segment results reflect increased
revenues related to weather and higher retail transmission charges and decreased
operations and maintenance expenses. These positive factors were offset by
higher depreciation and amortization due to increased plant in service, higher
property taxes due to increased property tax rates and higher income taxes,
including income tax benefits recognized in the prior year.
In addition, income from discontinued operations for the year ended December 31,
2011 included a gain of approximately $10 million after income taxes related to
the sale of our investment in APSES. Income from discontinued operations in the
prior year was due to a $25 million gain after income taxes related to the sale
of APSES's district cooling business (see Note 21).
The following table presents net income attributable to common shareholders by
business segment compared with the prior year:
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Year Ended
December 31,
2011 2010 Net Change
(dollars in millions)
Regulated Electricity Segment:
Operating revenues less fuel and purchased
power expenses (a) (b) $ 2,228 $ 2,134 $ 94
Operations and maintenance (a) (b) (904 ) (870 ) (34 )
Depreciation and amortization (427 ) (415 ) (12 )
Taxes other than income taxes (148 ) (135 ) (13 )
Other income (expenses), net 16 18 (2 )
Interest charges, net of allowance for
borrowed funds used during construction (224 ) (226 ) 2
Income taxes (184 ) (161 ) (23 )
Less income related to noncontrolling
interests (Note 20) (28 ) (20 ) (8 )
Regulated electricity segment net income 329 325 4
All other (1 ) - (1 )
Income from Continuing Operations
Attributable to Common Shareholders 328 325 3
Income from Discontinued Operations
Attributable to Common Shareholders (c) 11 25 (14 )
Net Income Attributable to Common
Shareholders $ 339 $ 350 $ (11 )
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(a) Includes effects of 2011 settlement of certain prior-period
transmission rights-of-way related to Four Corners, which did not affect net
income, but increased both electric operating revenues and operations and
maintenance expenses by $28 million. Costs related to the settlement were
offset by related revenues from SCE, which leases the related transmission line
from APS.
(b) Operating revenues less fuel and purchased power expensesincludes amounts related to demand-side management, renewable energy and similar
regulatory surcharges, which were substantially offset in operations and
maintenance.
(c) Includes activities related to APSES and SunCor.
Regulated electricity segment
This section includes a discussion of major variances in income and expense
amounts for the regulated electricity segment.
Operating revenues less fuel and purchased power expenses Regulated electricity
segment operating revenues less fuel and purchased power expenses were $94
million higher for the year ended December 31, 2011 compared with the prior
year. The following table describes the major components of this change:
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Increase (Decrease)
Fuel and
purchased
Operating power
revenues expenses Net change
(dollars in millions)
Higher demand-side management, renewable
energy and similar regulatory surcharges $ 29 $ 1 $ 28
Settlement of certain prior-period
transmission rights-of-way 28 - 28
Effects of weather on usage per customer 33 13 20
Higher retail transmission charges 10 - 10
Higher line extension revenues (Note 3) 7 - 7
Higher usage per customer 8 6 2
Refund of PSA deferrals (33 ) (40 ) 7
Higher fuel and purchased power costs, net
of off-system sales (27 ) (24 ) (3 )
Miscellaneous items, net 2 7 (5 )
Total $ 57 $ (37 ) $ 94
Operations and maintenance Operations and maintenance expenses increased $34
million for the year ended December 31, 2011 compared with the prior year
primarily because of:
† An increase of $28 million related to settlement in 2011
of certain transmission rights-of-way costs, which was offset in operating
revenues;
† An increase of $27 million related to costs for
demand-side management, renewable energy, and similar regulatory programs, which
were offset in operating revenues;
† A decrease of $16 million related to employee benefit
costs; and
† A decrease of $5 million due to other miscellaneous
factors.
Depreciation and amortization Depreciation and amortization expenses were $12
million higher for the year ended December 31, 2011 compared with the prior year
primarily because of increased plant in service.
Taxes other than income taxes Taxes other than income taxes increased $13
million for the year ended December 31, 2011 compared with the prior year
primarily because of higher property tax rates in the current period.
Income taxes Income taxes were $23 million higher for the year ended
December 31, 2011 compared with the prior year. This increase was primarily due
to the effects of higher pretax income in the current year and income tax
benefits recognized in the prior year related to a reduction in the Company's
2010 effective income tax rate.
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Discontinued Operations
Income from discontinued operations for year ended December 31, 2011 included a
gain of $10 million related to the sale of our investment in APSES. Income from
discontinued operations for the year ended December 31, 2010 included an after
tax gain of $25 million related to the sale of APSES's district cooling business
(see Note 21).
LIQUIDITY AND CAPITAL RESOURCES
Overview
Pinnacle West's primary cash needs are for dividends to our shareholders and
principal and interest payments on our indebtedness. On December 19, 2012, the
Pinnacle West Board of Directors declared a quarterly dividend of $0.545 per
share of common stock, payable on March 1, 2013 to shareholders of record on
February 1, 2013. During 2012, Pinnacle West increased its indicated annual
dividend from $2.10 per share to $2.18 per share. The level of our common stock
dividends and future dividend growth will be dependent on declaration by our
Board of Directors based on a number of factors including our financial
condition, payout ratio, free cash flow and other factors.
Our primary sources of cash are dividends from APS and external debt and equity
issuances. An ACC order requires APS to maintain a common equity ratio of at
least 40%. As defined in the ACC order, the common equity ratio is total
shareholder equity divided by the sum of total shareholder equity and long-term
debt, including current maturities of long-term debt. At December 31, 2012,
APS's common equity ratio, as defined, was 57%. Its total shareholder equity
was approximately $4.1 billion, and total capitalization was approximately $7.2
billion. Under this order, APS would be prohibited from paying dividends if
such payment would reduce its total shareholder equity below approximately $2.9
billion, assuming APS's total capitalization remains the same. This restriction
does not materially affect Pinnacle West's ability to meet its ongoing cash
needs or ability to pay dividends to shareholders.
APS's capital requirements consist primarily of capital expenditures and
maturities of long-term debt. APS funds its capital requirements with cash from
operations and, to the extent necessary, external debt financing and equity
infusions from Pinnacle West.
Many of APS's current capital expenditure projects qualify for bonus
depreciation. The American Taxpayer Relief Act of 2012, signed into law on
January 2, 2013, includes provisions extending the eligibility for 50% bonus
depreciation to qualified property placed in service in 2013. As a result of
this provision, and the previously enacted bonus depreciation provisions
provided for in the Tax Relief, Unemployment Insurance Reauthorization and Job
Creation Act of 2010, total cash tax benefits of up to $400-$500 million are
expected to be generated for APS through accelerated depreciation. The cash
generated is an acceleration of the tax benefits that APS would have otherwise
received over 20 years. It is anticipated that these cash benefits will be
fully realized by APS by the end of 2013, with a majority of the benefit
realized as of December 31, 2012.
Summary of Cash Flows
The following tables present net cash provided by (used for) operating,
investing and financing activities for the years ended December 31, 2012, 2011
and 2010 (dollars in millions):
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Pinnacle West Consolidated
2012 2011 2010
Net cash flow provided by operating activities $ 1,171 $ 1,125 $ 750
Net cash flow used for investing activities (873 ) (782 ) (576 )
Net cash flow used for financing activities (305 ) (420 ) (209 )
Net decrease in cash and cash equivalents $ (7 ) $ (77 ) $ (35 )
Arizona Public Service Company
2012 2011 2010
Net cash flow provided by operating activities $ 1,176 $ 1,128 $ 695
Net cash flow used for investing activities (873 ) (834 ) (747 )
Net cash flow provided by (used for) financing activities (319 ) (374 ) 31
Net decrease in cash and cash equivalents $ (16 ) $ (80 ) $ (21 )
Operating Cash Flows
2012 Compared with 2011 Pinnacle West's consolidated net cash provided by
operating activities was $1,171 million in 2012, compared to $1,125 million in
2011, an increase of $46 million in net cash provided. The increase is
primarily related to a $77 million reduction of cash collateral posted and a
decrease of $23 million in cash paid for interest in the current year, partially
offset by a $26 million increase in property tax payments, a $65 million pension
contribution in 2012 (approximately $12 million of which is reflected in capital
expenditures) and other changes in working capital.
2011 Compared with 2010 Pinnacle West's consolidated net cash provided by
operating activities was $1,125 million in 2011, compared to $750 million in
2010, an increase of $375 million in net cash provided. The increase is
primarily due to the $161 million change in collateral and margin posted, as a
result of changes in commodity prices and expiration of prior hedge contracts,
and a $200 million voluntary pension contribution in 2010 (approximately $40
million of which is reflected in capital expenditures). In addition, APS's
operating cash flows included income tax payments to the parent company of
approximately $81 million in 2010.
Other Pinnacle West sponsors a qualified defined benefit pension plan and a
non-qualified supplemental excess benefit retirement plan for the employees of
Pinnacle West and our subsidiaries. The requirements of the Employee Retirement
Security Act of 1974 ("ERISA") require us to contribute a minimum amount to the
qualified plan. We contribute at least the minimum amount required under ERISA
regulations, but no more than the maximum tax-deductible amount. The minimum
required funding takes into consideration the value of plan assets and our
pension benefit obligations. Under ERISA, the qualified pension plan was 105%
funded as of January 1, 2012 and 101% funded as of January 1, 2013. The assets
in the plan are comprised of fixed-income, equity, real estate, and short-term
investments. Future year contribution amounts are dependent on plan asset
performance and plan actuarial assumptions. We made contributions to our
pension plan totaling $65 million in 2012, zero in 2011 and $200 million in
2010. The minimum contributions for the pension plan due in 2013, 2014 and 2015
under the recently enacted Moving Ahead for Progress in the 21st Century Act
(MAP-21) are estimated to be zero, $89 million and $112 million, respectively.
We expect to make voluntary contributions totaling $140 million to the pension
plan in 2013, and contributions up to approximately $175 million in each of 2014
and 2015. With regard to contributions to our other postretirement benefit
plans, we made a contribution of approximately $23 million in 2012, $19 million
in 2011, and $17
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million in 2010. The contributions to our other postretirement benefit plans
for 2013, 2014 and 2015 are expected to be approximately $20 million each year.
The $70 million long-term income tax receivable on the Consolidated Balance
Sheets represents the anticipated refunds related to an APS tax accounting
method change approved by the Internal Revenue Service ("IRS") in the third
quarter of 2009. This amount is classified as long-term, as there remains
uncertainty regarding the timing of this cash receipt. Further clarification of
the timing is expected from the IRS within the next twelve months.
Investing Cash Flows
2012 Compared with 2011 Pinnacle West's consolidated net cash used for
investing activities was $873 million in 2012, compared to $782 million in 2011,
an increase of $91 million in net cash used. The increase in net cash used for
investing activities is primarily due to the absence of $55 million in proceeds
from the sale of life insurance policies in 2011 and the absence of $45 million
in proceeds from the sale of Pinnacle West's investment in APSES in 2011.
2011 Compared with 2010 Pinnacle West's consolidated net cash used for
investing activities was $782 million in 2011, compared to $576 million in 2010,
an increase of $206 million in net cash used. The increase in net cash used for
investing activities is primarily due to an increase of $131 million in capital
expenditures and a decrease of $126 million in net proceeds from the sales of
our non-utility businesses (see Note 21), partially offset by $55 million of
proceeds from the sale of life insurance policies in 2011.
Capital Expenditures The following table summarizes the estimated capital
expenditures for the next three years:
Capital Expenditures
(dollars in millions)
Estimated for the Year Ended
December 31,
2013 2014 2015
APS
Generation:
Nuclear Fuel $ 58 $ 82 $ 83
Renewables 190 42 -
Environmental 21 86 187
Four Corners Units 4 and 5 253 - -
Other Generation 142 246 340
Distribution 260 304 312
Transmission 152 204 200
Other (a) 45 69 66
Total APS $ 1,121 $ 1,033 $ 1,188
--------------------------------------------------------------------------------(a) Primarily information systems and facilities projects.
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Generation capital expenditures are comprised of various improvements to APS's
existing fossil and nuclear plants. Examples of the types of projects included
in this category are additions, upgrades and capital replacements of various
power plant equipment, such as turbines, boilers and environmental equipment.
For purposes of this table, we have assumed the consummation of APS's purchase
of SCE's interest in Four Corners Units 4 and 5 and the subsequent shutdown of
Units 1-3, as discussed in the "Overview" section above. As a result, we
included the estimated $253 million purchase price under Generation and have not
included environmental expenditures for Units 1-3. We have not included
estimated costs for Cholla's compliance with EPA's Arizona regional haze
rule since we have challenged the rule judicially and are considering our future
options with respect to that plant if the rule is upheld. We are also
monitoring the status of certain environmental matters, which, depending on
their final outcome, could require modification to our environmental
expenditures.
Distribution and transmission capital expenditures are comprised of
infrastructure additions and upgrades, capital replacements, and new customer
construction. Examples of the types of projects included in the forecast
include power lines, substations, and line extensions to new residential and
commercial developments.
Capital expenditures will be funded with internally generated cash and external
financings, which may include issuances of long-term debt and Pinnacle West
common stock.
Financing Cash Flows and Liquidity
2012 Compared with 2011 Pinnacle West's consolidated net cash used for
financing activities was $305 million in 2012, compared to $420 million in 2011,
a decrease of $115 million in net cash used. The decrease in net cash used for
financing activities is primarily due to an increase of $92 million in APS's
short-term debt borrowings in 2012. In addition, APS had $56 million in higher
issuances of long-term debt, partially offset by $99 million in higher
repayments of long-term debt. Pinnacle West had $100 million in lower
repayments of long-term debt partially offset by $50 million in lower debt
issuances (see below).
2011 Compared with 2010 Pinnacle West's consolidated net cash used for
financing activities was $420 million in 2011, compared to $209 million in 2010,
an increase of $211 million in net cash used. The increase in net cash used for
financing activities is primarily due to $78 million of long-term debt
repayments, net of issuances of long-term debt (see below), and proceeds of $253
million from the issuance of equity in April 2010 (which was infused into APS),
partially offset by $121 million lower repayments of short-term borrowings at
Pinnacle West.
APS's net cash used for financing activities was $374 million in 2011, compared
to net cash provided of $31 million in 2010, an increase of $405 million in net
cash used. APS's increase in net cash used for financing activities is
primarily due to $107 million of long-term debt repayments, net of issuances of
long-term debt (see below), and proceeds of $253 million from the infusion of
equity from Pinnacle West in April 2010. In addition, APS increased its
dividend payment to Pinnacle West by $47 million in 2011.
Significant Financing Activities During the year ended December 31, 2012,
Pinnacle West's total dividends paid per share of common stock was $2.12 per
share, which resulted in dividend payments of $225 million.
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On January 13, 2012, APS issued $325 million of 4.50% unsecured senior notes
that mature on April 1, 2042. The net proceeds from the sale were used along
with other funds to repay at maturity APS's $375 million aggregate principal
amount of 6.50% senior notes on March 1, 2012.
On May 1, 2012, pursuant to the mandatory tender provision, APS purchased all
$32 million of the Maricopa County, Arizona Pollution Control Corporation
Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo
Verde Project), 2009 Series B, due 2029. On June 1, 2012 these bonds were
remarketed. Currently, the interest rate on these bonds is reset daily by a
remarketing agent. The daily rate at December 31, 2012 was 0.13% per annum.
Additionally, the bonds are supported by a letter of credit. These bonds are
classified as long-term debt on our Consolidated Balance Sheets at December 31,
2012 and were classified as current maturities of long-term debt on our
Consolidated Balance Sheets at December 31, 2011.
On June 1, 2012, pursuant to the mandatory tender provision, APS changed the
interest rate mode for the approximately $38 million of Navajo County, Arizona
Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona
Public Service Company Cholla Project), 2009 Series A. The new term rate period
for these bonds commenced on June 1, 2012, and ends, subject to a mandatory
tender, on May 29, 2014. During this time, the bonds will bear interest at a
rate of 1.25% per annum. These bonds are classified as long-term debt on our
Consolidated Balance Sheets at December 31, 2012 and were classified as current
maturities of long-term debt on our Consolidated Balance Sheets at December 31,
2011.
On November 1, 2012 APS redeemed at par all $90 million of the Maricopa County,
Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds
(Arizona Public Service Company Palo Verde Project) 2002 Series A, due 2029.
On November 29, 2012, Pinnacle West entered into a $125 million term loan that
matures November 27, 2015. Pinnacle West used the proceeds of the loan to repay
its existing term loan of $125 million. Interest rates are based on Pinnacle
West's senior unsecured debt credit ratings or, if unavailable, its long-term
issuer ratings.
Available Credit Facilities Pinnacle West and APS maintain committed revolving
credit facilities in order to enhance liquidity and provide credit support for
their commercial paper programs.
At December 31, 2012, Pinnacle West's $200 million credit facility, which
matures in November 2016, was available to refinance indebtedness of the Company
and for other general corporate purposes, including credit support for its $200
million commercial paper program. Pinnacle West has the option to increase the
amount of the facility up to a maximum of $300 million upon the satisfaction of
certain conditions and with the consent of the lenders. At December 31, 2012,
Pinnacle West had no outstanding borrowings under its credit facility, no
letters of credit outstanding and no commercial paper borrowings.
At December 31, 2012, APS had two credit facilities totaling $1 billion,
including a $500 million credit facility that matures in February 2015, and a
$500 million facility that matures in November 2016. APS may increase the
amount of each facility up to a maximum of $700 million upon the satisfaction of
certain conditions and with the consent of the lenders. APS will use these
facilities to refinance indebtedness and for other general corporate purposes.
Interest rates are based on APS's senior unsecured debt credit ratings.
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The APS facilities described above are available to support APS's $250 million
commercial paper program, for bank borrowings or for issuances of letters of
credit. At December 31, 2012, APS had no outstanding borrowings under its
revolving credit facilities or letters of credit. In addition, APS had
commercial paper borrowings of $92 million at December 31, 2012.
See "Financial Assurances" in Note 11 for a discussion of APS's separate
outstanding letters of credit.
Other Financing Matters See Note 3 for information regarding the PSA approved
by the ACC.
See Note 3 for information regarding the settlement related to the 2008 retail
rate case, which includes ACC authorization and requirements of equity infusions
into APS of at least $700 million by December 31, 2014 ($253 million of which
was infused into APS from proceeds of a Pinnacle West equity issuance in 2010).
See Note 18 for information related to the change in our margin and collateral
accounts.
Debt Provisions
Pinnacle West's and APS's debt covenants related to their respective bank
financing arrangements include maximum debt to capitalization ratios. Pinnacle
West and APS comply with this covenant. For both Pinnacle West and APS, this
covenant requires that the ratio of consolidated debt to total consolidated
capitalization not exceed 65%. At December 31, 2012, the ratio was
approximately 46% for Pinnacle West and 45% for APS. Failure to comply with
such covenant levels would result in an event of default which, generally
speaking, would require the immediate repayment of the debt subject to the
covenants and could cross-default other debt. See further discussion of
"cross-default" provisions below.
Neither Pinnacle West's nor APS's financing agreements contain "rating triggers"
that would result in an acceleration of the required interest and principal
payments in the event of a rating downgrade. However, our bank credit
agreements contain a pricing grid in which the interest rates we pay for
borrowings thereunder are determined by our current credit ratings.
All of Pinnacle West's loan agreements contain "cross-default" provisions that
would result in defaults and the potential acceleration of payment under these
loan agreements if Pinnacle West or APS were to default under certain other
material agreements. All of APS's bank agreements contain cross-default
provisions that would result in defaults and the potential acceleration of
payment under these bank agreements if APS were to default under certain other
material agreements. Pinnacle West and APS do not have a material adverse
change restriction for credit facility borrowings.
See Note 6 for further discussions of liquidity matters.
Credit Ratings
The ratings of securities of Pinnacle West and APS as of February 15, 2013 are
shown below. We are disclosing these credit ratings to enhance understanding of
our cost of short-term and long-term capital and our ability to access the
markets for liquidity and long-term debt. The ratings reflect the respective
views of the rating agencies, from which an explanation of the significance of
their ratings
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may be obtained. There is no assurance that these ratings will continue for any
given period of time. The ratings may be revised or withdrawn entirely by the
rating agencies if, in their respective judgments, circumstances so warrant.
Any downward revision or withdrawal may adversely affect the market price of
Pinnacle West's or APS's securities and/or result in an increase in the cost of,
or limit access to, capital. Such revisions may also result in substantial
additional cash or other collateral requirements related to certain derivative
instruments, insurance policies, natural gas transportation, fuel supply, and
other energy-related contracts. At this time, we believe we have sufficient
available liquidity resources to respond to a downward revision to our credit
ratings.
Moody's Standard & Poor's Fitch
Pinnacle West
Corporate credit rating Baa2 BBB+ BBB
Commercial paper P-3 A-2 F3
Outlook Stable Stable Stable
APS
Corporate credit rating Baa1 BBB+ BBB
Senior unsecured Baa1 BBB+ BBB+
Secured lease obligation bonds Baa1 BBB+ BBB+
Commercial paper P-2 A-2 F3
Outlook Stable Stable Stable
Off-Balance Sheet Arrangements
See Note 20 for a discussion of the impacts on our financial statements of
consolidating certain VIEs.
Contractual Obligations
The following table summarizes Pinnacle West's consolidated contractual
requirements as of December 31, 2012 (dollars in millions):
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2014- 2016-
2013 2015 2017 Thereafter Total
Long-term debt payments,
including interest: (a)
APS $ 307 $ 1,191 $ 604 $ 3,283 $ 5,385
Pinnacle West 2 4 125 - 131
Total long-term debt
payments, including interest 309 1,195 729 3,283 5,516
Fuel and purchased power
commitments (b) 489 1,116 955 6,329 8,889
Renewable energy credits (c) 51 81 80 491 703
Purchase obligations (d) 96 29 14 221 360
Coal reclamation 1 74 27 17 119
Nuclear decommissioning
funding requirements 17 36 4 67 124
Noncontrolling interests (e) 17 56 - - 73
Operating lease payments 21 32 7 41 101
Total contractual commitments $ 1,001 $ 2,619 $ 1,816 $ 10,449 $ 15,885
--------------------------------------------------------------------------------
(a) The long-term debt matures at various dates through 2042 and
bears interest principally at fixed rates. Interest on variable-rate long-term
debt is determined by using average rates at December 31, 2012 (see Note 6).
(b) Our fuel and purchased power commitments include purchases
of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural
gas transportation (see Notes 3 and 11).
(c) Contracts to purchase renewable energy credits in
compliance with the RES (see Note 3).
(d) These contractual obligations include commitments for
capital expenditures and other obligations. These amounts do not include the
purchase of SCE's interest in Four Corners Units 4 and 5 due to additional
approvals required. See discussion in "Overview."
(e) Payments to the noncontrolling interests relate to the Palo
Verde Sale Leaseback (see Note 20). We have committed to retain the assets
relating to the noncontrolling interest beyond 2015 either through lease
extensions or by purchasing the assets. If we elect to purchase the assets, the
purchase price will be based on the fair value of the assets at the end of 2015,
and such value is unknown at this time. If we elect to extend the leases, we
will be required to make annual payments beginning in 2016 of approximately $23
million; however, the length of the lease extensions is unknown at this time as
it must be determined through an appraisal process. Due to these uncertainties,
amounts relating to the noncontrolling interests beyond 2015 have not been
included in the table above.
This table excludes $135 million in unrecognized tax benefits because the timing
of the future cash outflows is uncertain. This table also excludes
approximately zero, $89 million and $112 million in estimated minimum pension
contributions for 2013, 2014 and 2015, respectively (see Note 8).
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CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with GAAP, management must
often make estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues, expenses and related disclosures at the date of the
financial statements and during the reporting period. Some of those judgments
can be subjective and complex, and actual results could differ from those
estimates. We consider the following accounting policies to be our most
critical because of the uncertainties, judgments and complexities of the
underlying accounting standards and operations involved.
Regulatory Accounting
Regulatory accounting allows for the actions of regulators, such as the ACC and
the FERC, to be reflected in our financial statements. Their actions may cause
us to capitalize costs that would otherwise be included as an expense in the
current period by unregulated companies. Regulatory assets represent incurred
costs that have been deferred because they are probable of future recovery in
customer rates. Regulatory liabilities generally represent expected future
costs that have already been collected from customers. Management continually
assesses whether our regulatory assets are probable of future recovery by
considering factors such as applicable regulatory environment changes and recent
rate orders to other regulated entities in the same jurisdiction. This
determination reflects the current political and regulatory climate in the state
and is subject to change in the future. If future recovery of costs ceases to
be probable, the assets would be written off as a charge in current period
earnings. We had $1.2 billion of regulatory assets and $847 million of
regulatory liabilities on the Consolidated Balance Sheets at December 31, 2012.
Included in the balance of regulatory assets at December 31, 2012 is a
regulatory asset of $780 million for pension and other postretirement benefits.
This regulatory asset represents the future recovery of these costs through
retail rates as these amounts are charged to earnings. If these costs are
disallowed by the ACC, this regulatory asset would be charged to OCI and result
in lower future earnings.
See Notes 1 and 3 for more information.
Pensions and Other Postretirement Benefit Accounting
Changes in our actuarial assumptions used in calculating our pension and other
postretirement benefit liability and expense can have a significant impact on
our earnings and financial position. The most relevant actuarial assumptions
are the discount rate used to measure our liability and net periodic cost, the
expected long-term rate of return on plan assets used to estimate earnings on
invested funds over the long-term, and the assumed healthcare cost trend rates.
We review these assumptions on an annual basis and adjust them as necessary.
The following chart reflects the sensitivities that a change in certain
actuarial assumptions would have had on the December 31, 2012 reported pension
liability on the Consolidated Balance Sheets and our 2012 reported pension
expense, after consideration of amounts capitalized or billed to electric plant
participants, on Pinnacle West's Consolidated Statements of Income (dollars in
millions):
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Increase (Decrease)
Impact on Impact on
Pension Pension
Actuarial Assumption (a) Liability Expense
Discount rate:
Increase 1% $ (330 ) $ (12 )
Decrease 1% 408 15
Expected long-term rate of return on plan assets:
Increase 1% - (9 )
Decrease 1% - 9
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(a) Each fluctuation assumes that the other assumptions of the
calculation are held constant while the rates are changed by one percentage
point.
The following chart reflects the sensitivities that a change in certain
actuarial assumptions would have had on the December 31, 2012 reported other
postretirement benefit obligation on the Consolidated Balance Sheets and our
2012 reported other postretirement benefit expense, after consideration of
amounts capitalized or billed to electric plant participants, on Pinnacle West's
Consolidated Statements of Income (dollars in millions):
Increase (Decrease)
Impact on Other Impact on Other
Postretirement Benefit Postretirement
Actuarial Assumption (a) Obligation Benefit Expense
Discount rate:
Increase 1% $ (149 ) $ (8 )
Decrease 1% 186 10
Health care cost trend rate (b):
Increase 1% 172 14
Decrease 1% (136 ) (11 )
Expected long-term rate of return
on plan assets - pretax:
Increase 1% - (3 )
Decrease 1% - 3
--------------------------------------------------------------------------------
(a) Each fluctuation assumes that the other assumptions of the
calculation are held constant while the rates are changed by one percentage
point.
(b) This assumes a 1% change in the initial and ultimate health
care cost trend rate.
See Note 8 for further details about our pension and other postretirement
benefit plans.
Derivative Accounting
Derivative accounting requires evaluation of rules that are complex and subject
to varying interpretations. Our evaluation of these rules, as they apply to our
contracts, determines whether we use
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accrual accounting (for derivative instruments designated as normal) or fair
value (mark-to-market) accounting. Mark-to-market accounting requires that
changes in the fair value of derivative instruments are recognized in current
earnings unless certain hedge criteria are met. Effective June 1, 2012, APS
discontinued cash flow hedging for the significant majority of derivative
contracts. APS now defers 100% of changes in fair value on these contracts for
future rate treatment in accordance with the PSA (see Note 3).
See "Market Risks - Commodity Price Risk" below for quantitative analysis. See
"Fair Value Measurements" below for additional information on valuation. See
Note 1 for discussion on accounting policies and Note 18 for a further
discussion on derivative accounting.
Fair Value Measurements
We account for derivative instruments, investments held in our nuclear
decommissioning trust, certain cash equivalents and plan assets held in our
retirement and other benefit plans at fair value on a recurring basis. Fair
value is the price that would be received to sell an asset or paid to transfer a
liability in an orderly transaction between market participants at the
measurement date. We use inputs, or assumptions that market participants would
use, to determine fair market value. The significance of a particular input
determines how the instrument is classified in a fair value hierarchy. We
utilize valuation techniques that maximize the use of observable inputs and
minimize the use of unobservable inputs. The determination of fair value
sometimes requires subjective and complex judgment. Our assessment of the
inputs and the significance of a particular input to fair value measurement may
affect the valuation of the instruments and their placement within a fair value
hierarchy. Actual results could differ from our estimates of fair value. See
Note 1 for discussion on accounting policies and Note 14 for further fair value
measurement discussion.
OTHER ACCOUNTING MATTERS
See Note 2 for discussion regarding amended accounting guidance adopted during
2012 relating to fair value measurements and disclosures, and the presentation
of comprehensive income.
MARKET AND CREDIT RISKS
Market Risks
Our operations include managing market risks related to changes in interest
rates, commodity prices and investments held by our nuclear decommissioning
trust fund and benefit plan assets.
Interest Rate and Equity Risk
We have exposure to changing interest rates. Changing interest rates will
affect interest paid on variable-rate debt and the market value of fixed income
securities held by our nuclear decommissioning trust fund (see Note 14 and Note
22) and benefit plan assets. The nuclear decommissioning trust fund and benefit
plan assets also have risks associated with the changing market value of its
equity and other non-fixed income investments. Nuclear decommissioning and
benefit plan costs are recovered in regulated electricity prices.
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The tables below present contractual balances of our consolidated long-term and
short-term debt at the expected maturity dates as well as the fair value of
those instruments on December 31, 2012 and 2011. The interest rates presented
in the tables below represent the weighted-average interest rates as of
December 31, 2012 and 2011 (dollars in thousands):
Pinnacle West - Consolidated
Short-Term Variable-Rate Fixed-Rate
Debt Long-Term Debt Long-Term Debt
Interest Interest Interest
2012 Rates Amount Rates Amount Rates Amount
2013 0.38 % $ 92,175 - $ - 4.94 % $ 122,828
2014 - - - - 5.58 % 540,424
2015 - - 1.07 % 157,000 4.79 % 313,420
2016 - - 0.15 % 43,580 6.15 % 314,000
2017 - - - - - -
Years thereafter - - - - 6.21 % 1,840,150
Total $ 92,175 $ 200,580 $ 3,130,822
Fair value $ 92,175 $ 200,268 $ 3,674,958
Variable-Rate Fixed-Rate
Long-Term Debt Long-Term Debt
Interest Interest
2011 Rates Amount Rates Amount
2012 - $ - 6.41 % $ 477,435
2013 - - 4.94 % 122,828
2014 - - 5.91 % 502,274
2015 1.79 % 125,000 4.79 % 313,420
2016 0.09 % 43,580 6.15 % 314,000
Years thereafter - - 6.49 % 1,605,150
Total $ 168,580 $ 3,335,107
Fair value $ 167,018 $ 3,758,811
The tables below present contractual balances of APS's long-term debt at the
expected maturity dates as well as the fair value of those instruments on
December 31, 2012 and 2011. The interest rates presented in the tables below
represent the weighted-average interest rates as of December 31, 2012 and 2011
(dollars in thousands):
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APS - Consolidated
Short-Term Variable-Rate Fixed-Rate
Debt Long-Term Debt Long-Term Debt
Interest Interest Interest
2012 Rates Amount Rates Amount Rates Amount
2013 0.38 % $ 92,175 - $ - 4.94 % $ 122,828
2014 - - - - 5.58 % 540,424
2015 - - 0.13 % 32,000 4.79 % 313,420
2016 - - 0.15 % 43,580 6.15 % 314,000
2017 - - - - - -
Years thereafter - - - - 6.21 % 1,840,150
Total $ 92,175 $ 75,580 $ 3,130,822
Fair value $ 92,175 $ 75,580 $ 3,674,958
Variable-Rate Fixed-Rate
Long-Term Debt Long-Term Debt
Interest Interest
2011 Rates Amount Rates Amount
2012 - $ - 6.41 % $ 477,435
2013 - - 4.94 % 122,828
2014 - - 5.91 % 502,274
2015 - - 4.79 % 313,420
2016 0.09 % 43,580 6.15 % 314,000
Years thereafter - - 6.49 % 1,605,150
Total $ 43,580 $ 3,335,107
Fair value $ 43,580 $ 3,758,811
Commodity Price Risk
We are exposed to the impact of market fluctuations in the commodity price and
transportation costs of electricity and natural gas. Our risk management
committee, consisting of officers and key management personnel, oversees
company-wide energy risk management activities to ensure compliance with our
stated energy risk management policies. We manage risks associated with these
market fluctuations by utilizing various commodity instruments that may qualify
as derivatives, including futures, forwards, options and swaps. As part of our
risk management program, we use such instruments to hedge purchases and sales of
electricity and fuels. The changes in market value of such contracts have a
high correlation to price changes in the hedged commodities.
The following table shows the net pretax changes in mark-to-market of our
derivative positions in 2012 and 2011 (dollars in millions):
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2012 2011Mark-to-market of net positions at beginning of year $ (222 ) $
(239 )
Recognized in earnings (a):
Change in mark-to-market gains (losses) for future
period deliveries 1 (4 )
(Increase) decrease in regulatory asset 37 (1 )
Recognized in OCI:
Change in mark-to-market losses for future period
deliveries (b) (37 ) (95 )
Mark-to-market losses realized during the period 99 117
Change in valuation techniques - -
Mark-to-market of net positions at end of year $ (122 ) $ (222 )
--------------------------------------------------------------------------------(a) Represents the amounts reflected in income after the effect
of PSA deferrals.
(b) The changes in mark-to-market recorded in OCI are dueprimarily to changes in forward natural gas prices.
The table below shows the fair value of maturities of our derivative contracts
(dollars in millions) at December 31, 2012 by maturities and by the type of
valuation that is performed to calculate the fair values, classified in their
entirety based on the lowest level of input that is significant to the fair
value measurement. See Note 1, "Derivative Accounting" and "Fair Value
Measurements," for more discussion of our valuation methods.
Total
Years fair
Source of Fair Value 2013 2014 2015 2016 2017 thereafter value
Observable prices
provided by other
external sources $ (53 ) $ (20 ) $ (1 ) $ - $ - $ - $ (74 )
Prices based on
unobservable inputs (10 ) (9 ) (11 ) (8 ) (4 ) (6 ) (48 )
Total by maturity $ (63 ) $ (29 ) $ (12 ) $ (8 ) $ (4 ) $ (6 ) $ (122 )
The table below shows the impact that hypothetical price movements of 10% would
have on the market value of our risk management assets and liabilities included
on Pinnacle West's Consolidated Balance Sheets at December 31, 2012 and 2011
(dollars in millions):
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December 31, 2012 December 31, 2011
Gain (Loss) Gain (Loss)
Price Up 10% Price Down 10% Price Up 10% Price Down 10%
Mark-to-market changes reported
in:
Earnings (a)
Natural gas $ - $ - $ 1 $ (1 )
Regulatory asset (liability) or
OCI (b)
Electricity 7 (7 ) 5 (5 )
Natural gas 25 (25 ) 27 (27 )
Total $ 32 $ (32 ) $ 33 $ (33 )
--------------------------------------------------------------------------------(a) Represents the amounts reflected in income after the effect
of PSA deferrals.
(b) These contracts are economic hedges of our forecastedpurchases of natural gas and electricity. The impact of these hypothetical
price movements would substantially offset the impact that these same price
movements would have on the physical exposures being hedged. To the extent the
amounts are eligible for inclusion in the PSA, the amounts are recorded as
either a regulatory asset or liability.
Credit Risk
We are exposed to losses in the event of non-performance or non-payment by
counterparties. See Note 18 for a discussion of our credit valuation adjustment
policy.
ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
See "Market and Credit Risks" in Item 7 above for a discussion of quantitative
and qualitative disclosures about market risk.
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