PINNACLE WEST CAPITAL CORP - Annual Report: 2019 (Form 10-K)

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•	our ability to manage capital expenditures and operations and maintenance costs while maintaining reliability and customer service levels;

•	variations in demand for electricity, including those due to weather, seasonality, the general economy, customer and sales growth (or decline), the effects of energy conservation measures and distributed generation, and technological advancements;

•	power plant and transmission system performance and outages;

•	competition in retail and wholesale power markets;

•	regulatory and judicial decisions, developments and proceedings;

•	new legislation, ballot initiatives and regulation, including those relating to environmental requirements, regulatory policy, nuclear plant operations and potential deregulation of retail electric markets;

•	fuel and water supply availability;

•	our ability to achieve timely and adequate rate recovery of our costs, including returns on and of debt and equity capital investment;

•	our ability to meet renewable energy and energy efficiency mandates and recover related costs;

•	risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainty;

•	current and future economic conditions in Arizona, including in real estate markets;

•	the direct or indirect effect on our facilities or business from cybersecurity threats or intrusions, data security breaches, terrorist attack, physical attack, severe storms, droughts, or other catastrophic events, such as fires, explosions, pandemic health events or similar occurrences;

•	the development of new technologies which may affect electric sales or delivery;

•	the cost of debt and equity capital and the ability to access capital markets when required;

•	environmental, economic and other concerns surrounding coal-fired generation, including regulation of greenhouse gas emissions;

•	volatile fuel and purchased power costs;

•	the investment performance of the assets of our nuclear decommissioning trust, pension, and other postretirement benefit plans and the resulting impact on future funding requirements;

•	the liquidity of wholesale power markets and the use of derivative contracts in our business;

•	potential shortfalls in insurance coverage;

•	new accounting requirements or new interpretations of existing requirements;

•	generation, transmission and distribution facility and system conditions and operating costs;

•	the ability to meet the anticipated future need for additional generation and associated transmission facilities in our region;

•	the willingness or ability of our counterparties, power plant participants and power plant land owners to meet contractual or other obligations or continue or discontinue power plant operations consistent with our corporate interests; and

•	restrictions on dividends or other provisions in our credit agreements and ACC orders.

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(a)	Up to 60 MW of capacity is available; however, the amount of electricity available to APS under this agreement is based in large part on customer demand and is adjusted annually.

(b)	This is a seasonal capacity exchange agreement under which APS receives electricity during the summer peak season (from May 15 to September 15) and APS returns a like amount of electricity during the winter season (from October 15 to February 15).

(c)	The capacity under this agreement may be increased in 10 MW increments in years 2017 through 2024, up to a maximum of 50 MW.

(d)	Renewable energy purchased power agreements are described in detail below under “Current and Future Resources — Renewable Energy Standard — Renewable Energy Portfolio.”

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(a)	Includes Flagstaff Community Power Project, APS School and Government Program, APS Solar Partner Program, and APS Solar Communities Program.

(b)	Includes rooftop solar facilities owned by third parties. Distributed generation is produced in DC and is converted to AC for reporting purposes.

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Following the passage of the Water Infrastructure Improvements for the Nation Act in 2016, EPA possesses authority to, either, authorize states to develop their own permit programs for CCR management or issue federal permits governing CCR disposal both in states without their own permit programs and on tribal lands. Although ADEQ has taken steps to develop a CCR permitting program, it is not clear when that program will be put into effect. On December 19, 2019, EPA proposed its own set of regulations governing the issuance of CCR management permits.

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On March 1, 2018, as a result of a settlement with certain environmental groups, EPA proposed adding boron to the list of constituents that trigger corrective action requirements to remediate groundwater impacted by CCR disposal activities. Apart from a subsequent proposal issued on August 14, 2019 to add a specific, health-based groundwater protection standard for boron, EPA has yet to take action on this proposal.

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Based on an August 21, 2018 D.C. Circuit decision, which vacated and remanded those provisions of the EPA CCR regulations that allow for the operation of unlined CCR surface impoundments, EPA recently proposed corresponding changes to federal CCR regulations. On November 4, 2019, EPA proposed that all unlined CCR surface impoundments, regardless of their impact (or lack thereof) upon surrounding groundwater, must cease operation and initiate closure by August 31, 2020 (with an optional three-month extension as needed for the completion of alternative disposal capacity).

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On November 4, 2019, EPA also proposed to change the manner by which facilities that have committed to cease burning coal in the near-term may qualify for alternative closure. Such qualification would allow CCR disposal units at these plants to continue operating, even though they would otherwise be subject to forced closure under the federal CCR regulations. EPA’s proposal regarding alternative closure would require express EPA authorization for such facilities to continue operating their CCR disposal units under alternative closure.

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•	causing a downgrade of our credit ratings;

•	increasing the cost of future debt financing and refinancing;

•	increasing our vulnerability to adverse economic and industry conditions; and

•	requiring us to dedicate an increased portion of our cash flow from operations to payments on our debt, which would reduce funds available to us for operations, future investment in our business or other purposes.

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•	variations in our quarterly operating results;

•	operating results that vary from the expectations of management, securities analysts and investors;

•	changes in expectations as to future financial performance, including financial estimates by securities analysts and investors;

•	developments generally affecting industries in which we operate;

•	announcements by us or our competitors of significant contracts, acquisitions, joint marketing relationships, joint ventures or capital commitments;

•	announcements by third parties of significant claims or proceedings against us;

•	favorable or adverse regulatory or legislative developments;

•	our dividend policy;

•	future sales by the Company of equity or equity-linked securities; and

•	general domestic and international economic conditions.

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restrictions on our ability to engage in a wide range of “business combination” transactions with an “interested shareholder” (generally, any person who beneficially owns 10% or more of our outstanding voting power, or any of our affiliates or associates who beneficially owned 10% or more of our outstanding voting power at any time during the prior three years) or any affiliate or associate of an interested shareholder, unless specific conditions are met;

•	anti-greenmail provisions of Arizona law and our bylaws that prohibit us from purchasing shares of our voting stock from beneficial owners of more than 5% of our outstanding shares unless specified conditions are satisfied;

•	the ability of the Board of Directors to increase the size of and fill vacancies on the Board of Directors, whether resulting from such increase, or from death, resignation, disqualification or otherwise;

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•	the ability of our Board of Directors to issue additional shares of common stock and shares of preferred stock and to determine the price and, with respect to preferred stock, the other terms, including preferences and voting rights, of those shares without shareholder approval;

•	restrictions that limit the rights of our shareholders to call a special meeting of shareholders; and

•	restrictions regarding the rights of our shareholders to nominate directors or to submit proposals to be considered at shareholder meetings.

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(a)	100% unless otherwise noted.

(b)

Our 29.1% ownership in Palo Verde includes leased interests. See “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Generation Facilities — Nuclear” in Item 1 for details regarding leased interests in Palo Verde.  The other participants are Salt River Project (17.49%), SCE (15.8%), El Paso (15.8%), Public Service Company of New Mexico (10.2%), Southern California Public Power Authority (5.91%), and Los Angeles Department of Water & Power (5.7%).  The plant is operated by APS.

(c)	The other participants are Salt River Project (10%), Public Service Company of New Mexico (13%), Tucson Electric Power Company (7%) and NTEC (7%).  The plant is operated by APS.

(d)	Unit 3 was retired in October 2019 with Units 1 and 2 following in November 2019.

(e)	Ocotillo Steam Units 1 and 2 were retired on January 10, 2019. Units 3 through 7 all went into service on or prior to May 30, 2019 which increased generation capacity by 510 MW.

(f)	Redhawk generation capacity increased by 104 MW following the Advanced Gas Path upgrade installed on both units.

(g)

APS is under contract and currently plans to add battery storage at these AZ Sun sites. Due to the McMicken battery energy storage equipment failure, APS is working with the counterparty for the AZ Sun sites to determine appropriate timing and path forward for such facilities. (See "Business of Arizona Public Service Company - Energy Sources and Resource Planning - Energy Storage" above for details related to these and other energy storage agreements.)

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•	A 2030 target of achieving a resource mix that is 65% clean energy, with 45% of the portfolio coming from renewable energy; and

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•	a test year comprised of twelve months ended June 30, 2019, adjusted as described below;

•	an original cost rate base of $8.87 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;

•	the following proposed capital structure and costs of capital:

•	a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;

•	authorization to defer until APS's next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated;

•	a number of proposed rate and program changes for residential customers, including:

▪	a super off-peak period during the winter months for APS’s time-of-use with demand rates;

▪	additional $1.25 million in funding for limited-income crisis bill program; and

▪	a flat bill/subscription rate pilot program;

•	proposed rate design changes for commercial customers, including an experimental program designed to provide access to market pricing for up to 200 MW of medium and large commercial customers;

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•	recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project (see Note 4 discussion of the 2017 Settlement Agreement); and

•	continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Plant (see Note 4 for details related to the resulting regulatory asset).

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•	A decrease of $42 million related to public outreach costs at the parent company primarily associated with the ballot initiative in 2018;

•	A decrease of $28 million in fossil generation costs primarily due to lower planned outages and operating costs, including $4 million of Navajo Plant costs which were offset in depreciation and amortization;

•	A decrease of $19 million related to employee benefit costs;

•	A decrease of $18 million related to costs for renewable energy and similar regulatory programs, which are offset in operating revenues and purchased power;

•	An increase of $12 million for costs related to information technology;

•	An increase of $12 million related to consulting costs; and

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•	A decrease of $3 million for other miscellaneous factors.

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(a)	APS Solar Communities program, energy storage, renewable projects and other clean energy projects

(b)	Primarily information systems and facilities projects

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(a)	The long-term debt matures at various dates through 2049 and bears interest principally at fixed rates.  Interest on variable-rate long-term debt is determined by using average rates at December 31, 2019 (see Note 7).

(b)	See Note 6 for further details.

(c)	Our fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation (see Notes 4 and 11).

(d)	Contracts to purchase renewable energy credits in compliance with the RES (see Note 4).

(e)	These contractual obligations include commitments for capital expenditures and other obligations.

(f)	Payments to the noncontrolling interests relate to the Palo Verde sale leaseback (see Note 19).

(g)	Commitments relating to purchased power lease contracts are included within the fuel and purchased power commitments line above (see Note 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.

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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.

(b)	This assumes a 1% change in the initial and ultimate healthcare cost trend rate.

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(a)

These contracts are economic hedges of our forecasted purchases 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.

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•

We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs of recently completed plant and costs deferred as regulatory assets and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•	We evaluated the Company’s disclosures related to regulatory accounting, specifically the impact of rate regulation on the financial statements, including the balances recorded and regulatory developments.

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We read relevant regulatory rate orders issued by the ACC for APS and other public utilities in Arizona, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedence of the ACC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory asset and liability balances for completeness.

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We read management’s preliminary rate filings submitted and testimony given to the ACC regarding the 2019 Retail Rate Case filed in October 2019 and monitored activity by intervenors, the ACC and its staff. The filing is still under review with the ACC. We read the filing and related testimony to assess the likelihood of recovery in future rates or of a future reduction in rates based on the information available as of our report date.

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We evaluated management’s assessment of the probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities based on applicable regulatory orders or precedence set by the ACC under similar circumstances. For certain regulatory assets or liabilities where management’s assessment is based on precedence established by the ACC under similar circumstances and not

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(b)	In 2018, the Company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Cuts and Jobs Act of 2017 (the "Tax Act") on items within accumulated other comprehensive income to retained earnings.

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•	material and labor;

•	contractor costs;

•	capitalized leases;

•	construction overhead costs (where applicable); and

•	allowance for funds used during construction.

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•	a test year comprised of twelve months ended June 30, 2019, adjusted as described below;

•	an original cost rate base of $8.87 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;

•	the following proposed capital structure and costs of capital:

•	a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;

•	authorization to defer until APS's next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated;

•	a number of proposed rate and program changes for residential customers, including:

▪	a super off-peak period during the winter months for APS’s time-of-use with demand rates;

▪	additional $1.25 million in funding for APS's limited-income crisis bill program; and

▪	a flat bill/subscription rate pilot program;

•	proposed rate design changes for commercial customers, including an experimental program designed to provide access to market pricing for up to 200 MW of medium and large commercial customers;

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•	recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project (see discussion below of the 2017 Settlement Agreement); and

•	continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Plant (see "Navajo Plant" below).

•	an agreement by APS not to file another general retail rate case application before June 1, 2019;

•	an authorized return on common equity of 10.0%;

•	a capital structure comprised of 44.2% debt and 55.8% common equity;

•	a cost deferral order for potential future recovery in APS’s next general retail rate case for the construction and operating costs APS incurs for its Ocotillo modernization project;

•	a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing SCR equipment at Four Corners;

•	a deferral for future recovery (or credit to customers) of the Arizona property tax expense above or below a specified test year level caused by changes to the applicable Arizona property tax rate;

•	an expansion of the PSA to include certain environmental chemical costs and third-party energy storage costs;

•	a new AZ Sun II program (now known as APS Solar Communities) for utility-owned solar distributed generation ("DG") with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the RES, to be no less than $10 million per year in capital costs, and not more than $15 million per year in capital costs;

•	an increase to the per kWh cap for the environmental improvement surcharge from $0.00016 to $0.00050 and the addition of a balancing account;

•	rate design changes, including:

▪	a change in the on-peak time of use period from noon - 7 p.m. to 3 p.m. - 8 p.m. Monday through Friday, excluding holidays;

▪	non-grandfathered DG customers would be required to select a rate option that has time of use rates and either a new grid access charge or demand component;

▪	a Resource Comparison Proxy (“RCP”) for exported energy of 12.9 cents per kWh in year one; and

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•	an agreement by APS not to pursue any new self-build generation (with certain exceptions) having an in-service date prior to January 1, 2022 (extended to December 31, 2027 for combined-cycle generating units), unless expressly authorized by the ACC.

•	APS must file a rate case no later than October 31, 2019, using a June 30, 2019 test-year;

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•	until the conclusion of the rate case being filed no later than October 31, 2019, APS must provide information on customer bills that shows how much a customer would pay on their most economical rate given their actual usage during each month;

•	APS customers can switch rate plans during an open enrollment period of six months;

•	APS must identify customers whose bills have increased by more than 9% and that are not on the most economical rate and provide such customers with targeted education materials and an opportunity to switch rate plans;

•	APS must provide grandfathered net metering customers on legacy demand rates an opportunity to switch to another legacy rate to enable such customers to fully benefit from legacy net metering rates;

•	APS must fund and implement a supplemental customer education and outreach program to be developed with and administered by ACC Staff and a third-party consultant; and

•	APS must fund and organize, along with the third-party consultant, a stakeholder group to suggest better ways to communicate the impact of changes to adjustor cost recovery mechanisms (see below for discussion on cost recovery mechanisms), including more effective ways to educate customers on rate plans and to reduce energy usage.

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•	APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;

•	An adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;

•	The PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);

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The PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered or refunded through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and

•	The PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.

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•	Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to September 1, 2017, based on APS's 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility;

•	Customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and

•	Once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years.

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(a)	This asset represents the future recovery of pension benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues.  See Note 8 for further discussion.

(b)	See “Cost Recovery Mechanisms” discussion above.

(c)	Subject to a carrying charge.

(d)	There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”

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(a)	For purposes of presentation on the Statement of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as "Deferred income taxes" under Cash Flows From Operating Activities.

(b)	See “Cost Recovery Mechanisms” discussion above.

(c)	In accordance with regulatory accounting, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.

(d)	See Note 8.

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(a)	This schedule does not reflect the timing of redemptions that may occur prior to maturities.

(b)	The weighted-average rate for the variable rate pollution control bonds was 1.54% at December 31, 2019 and 1.76% at December 31, 2018.

(c)	The weighted-average interest rate was 2.12% at December 31, 2019.

(d)	The weighted-average interest rate was 2.20% at December 31, 2019 and 3.02% at December 31, 2018.

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(a)	These investments primarily represent assets valued using NAV as a practical expedient, and have not been classified in the fair value hierarchy.

(b)	This category consists primarily of debt securities issued by municipalities.

(c)	This category primarily consists of U.S. common stock equities.

(d)	These funds invest in international common stock equities.

(e)	This category includes plan receivables and payables.

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(a)	These investments primarily represent assets valued using NAV as a practical expedient, and have not been classified in the fair value hierarchy.

(b)	This category consists primarily of debt securities issued by municipalities.

(c)	This category primarily consists of U.S. common stock equities.

(d)	These funds invest in U.S. and international common stock equities.

(e)	This category includes plan receivables and payables.

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(a)	See Note 19.

(b)	Weighted-average of interests.

(c)	PacifiCorp owns Cholla Unit 4 (see Note 4 for additional information) and APS operates the unit for PacifiCorp.  The common facilities at Cholla are jointly-owned.

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(a)	Total take-or-pay commitments are approximately $2.2 billion.  The total net present value of these commitments is approximately $1.6 billion.

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Following the passage of the Water Infrastructure Improvements for the Nation Act in 2016, EPA possesses authority to, either, authorize states to develop their own permit programs for CCR management or issue federal permits governing CCR disposal both in states without their own permit programs and on tribal lands. Although ADEQ has taken steps to develop a CCR permitting program, it is not clear when that program will be put into effect. On December 19, 2019, EPA proposed its own set of regulations governing the issuance of CCR management permits.

•

On March 1, 2018, as a result of a settlement with certain environmental groups, EPA proposed adding boron to the list of constituents that trigger corrective action requirements to remediate groundwater impacted by CCR disposal activities. Apart from a subsequent proposal issued on August 14, 2019 to add a specific, health-based groundwater protection standard for boron, EPA has yet to take action on this proposal.

•

Based on an August 21, 2018 D.C. Circuit decision, which vacated and remanded those provisions of the EPA CCR regulations that allow for the operation of unlined CCR surface impoundments, EPA recently proposed corresponding changes to federal CCR regulations. On November 4, 2019, EPA proposed that all unlined CCR surface impoundments, regardless of their impact (or lack thereof) upon surrounding groundwater, must cease operation and initiate closure by August 31, 2020 (with an optional three-month extension as needed for the completion of alternative disposal capacity).

•

On November 4, 2019, EPA also proposed to change the manner by which facilities that have committed to cease burning coal in the near-term may qualify for alternative closure. Such qualification would allow CCR disposal units at these plants to continue operating, even though they would otherwise be subject to forced closure under the federal CCR regulations. EPA’s proposal regarding alternative closure would require express EPA authorization for such facilities to continue operating their CCR disposal units under alternative closure.

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(a)	Represents counterparty netting, margin, and collateral. See Note 17.

(b)	Represents net pending securities sales and purchases.

(c)	Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.

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(a)	Represents counterparty netting, margin, and collateral. See Note 17.

(b)	Represents net pending securities sales and purchases.

(c)	Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.

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(a)	Includes swaps and physical and financial contracts.

(a)	Includes swaps and physical and financial contracts.

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(a)	Units granted includes awards that will be cash settled of 48,972 in 2019, 66,252 in 2018, and 67,599 in 2017.

(b)	Reflects the target payout level.

(a)	Includes 141,621 of awards that will be cash settled.

(b)	The nonvested performance shares are reflected at target payout level.

(c)	We account for forfeitures as they occur.

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(a)	During the years ended December 31, 2019, 2018, and 2017, we had no losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.

(b)	Amounts are before the effect of PSA deferrals.

(a)	Amounts are before the effect of PSA deferrals.

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(a)	All of our gross recognized derivative instruments were subject to master netting arrangements.

(b)	No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(c)	Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $1,185 and cash margin provided to counterparties of $405.

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(a)	All of our gross recognized derivative instruments were subject to master netting arrangements.

(b)	No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.

(c)	Represents cash collateral and cash margin that is not subject to offsetting.  Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument.  Includes cash collateral received from counterparties of $1,310 and cash margin provided to counterparties of $156.

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(a)	This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.

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(a)	As of December 31, 2019, the amortized cost basis of these available-for-sale investments is $691 million.

(b)	Represents net pending securities sales and purchases.

(a)	As of December 31, 2018, the amortized cost basis of these available-for-sale investments is $635 million.

(b)	Represents net pending securities sales and purchases.

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(a)	Proceeds are reinvested in the nuclear decommissioning trusts or other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union trust.

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(a)	These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 8.

(b)	These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 17.

(a)	These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost.  See Note 8.

(b)	These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA.  See Note 17.

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(a)

This amount includes shares subject to outstanding performance share awards and restricted stock unit awards at the maximum amount of shares issuable under such awards.  However, payout of the performance share awards is contingent on the Company reaching certain levels of performance during a three-year performance period.  If the performance criteria for these awards are not fully satisfied, the award recipient will receive less than the maximum number of shares available under these grants and may receive nothing from these grants.

(b)	The weighted-average exercise price in this column does not take performance share awards or restricted stock unit awards into account, as those awards have no exercise price.

(c)

Awards under the 2012 Plan can take the form of options, stock appreciation rights, restricted stock, performance shares, performance share units, performance cash, stock grants, stock units, dividend equivalents, and restricted stock units.  Additional shares cannot be awarded under the 2007 Plan.  However, if an award under the 2012 Plan is forfeited, terminated or canceled or expires, the shares subject to such award, to the extent of the forfeiture, termination, cancellation or expiration, may be added back to the shares available for issuance under the 2012 Plan.

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