Attached files
| file | filename |
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| 8-K - 8-K - PINNACLE WEST CAPITAL CORP | a8-k033117earnings.htm |
| EX-99.1 - EXHIBIT 99.1 - PINNACLE WEST CAPITAL CORP | exhibit991033117.htm |
First Quarter 2017
FIRST QUARTER 2017 RESULTS
May 2, 2017
First Quarter 20172
FORWARD LOOKING STATEMENTS AND
NON-GAAP FINANCIAL MEASURES
This presentation contains forward-looking statements based on current expectations, including statements regarding our earnings guidance and financial outlook and
goals. These forward-looking statements are often identified by words such as “estimate,” “predict,” “may,” “believe,” “plan,” “expect,” “require,” “intend,” “assume,”
“project” and similar words. Because actual results may differ materially from expectations, we caution you not to place undue reliance on these statements. A number
of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS. These factors
include, but are not limited to: our ability to manage capital expenditures and operations and maintenance costs while maintaining high 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), and the effects of
energy conservation measures and distributed generation; power plant and transmission system performance and outages; competition in retail and wholesale power
markets; regulatory and judicial decisions, developments and proceedings; new legislation, ballet 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 investments; 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 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 extend the rights for continued power plant operations; and restrictions on dividends or other provisions in our credit agreements
and ACC orders. These and other factors are discussed in Risk Factors described in Part I, Item 1A of the Pinnacle West/APS Annual Report on Form 10-K for the fiscal
year ended December 31, 2016, which you should review carefully before placing any reliance on our financial statements, disclosures or earnings outlook. Neither
Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by law.
In this presentation, references to net income and earnings per share (EPS) refer to amounts attributable to common shareholders.
We present “gross margin” per diluted share of common stock. Gross margin refers to operating revenues less fuel and purchased power expenses. Gross margin is a
“non-GAAP financial measure,” as defined in accordance with SEC rules. The appendix contains a reconciliation of this non-GAAP financial measure to the referenced
revenue and expense line items on our Consolidated Statements of Income, which are the most directly comparable financial measures calculated and presented in
accordance with generally accepted accounting principles in the United States of America (GAAP). We view gross margin as an important performance measure of the
core profitability of our operations.
We refer to “on-going earnings” in this presentation, which is also a non-GAAP financial measure. We also provide a reconciliation to show the impacts associated with
certain regulatory adjustments. We believe on-going earnings and these adjustments included in the reconciliation provide investors with a useful indicator of our
results that is comparable among periods because it excludes the effects of unusual items that may occur on an irregular basis.
Investors should note that these non-GAAP financial measures may involve judgments by management, including whether an item is classified as an unusual item.
These measures are key components of our internal financial reporting and are used by our management in analyzing the operations of our business. We believe that
investors benefit from having access to the same financial measures that management uses.
First Quarter 20173
Gross
Margin(1)
$0.06
ON-GOING EPS VARIANCES
1ST QUARTER 2017 VS. 1ST QUARTER 2016
Other, net
$0.01
D&A
$(0.04)
O&M(1)
$0.11
1Q 2016 1Q 2017
$0.04
$0.21
(1) Excludes costs and offsetting operating revenues, associated with renewable energy (excluding AZ Sun) and demand side management programs.
See non-GAAP reconciliation.
Gross Margin
Weather $ 0.03
Sales $ (0.04)
LFCR $ 0.04
Other $ 0.03
Interest, net
of AFUDC
$(0.02)
Effective
Tax Rate
$0.05
First Quarter 20174
0
10,000
20,000
30,000
40,000
'07 '08 '09 '10 '11 '12 '13 '14 '15 '16 '17
Single Family Multifamily
ECONOMIC
INDICATORS
Arizona and Metro Phoenix remain
attractive places to live and do
business
Single Family & Multifamily Housing Permits
Maricopa County
Above-average job growth in financial
services
Maricopa County ranked #1 in U.S. for
population growth in 2016
- U.S. Census Bureau March 2017
E
Scottsdale ranked best place in the
U.S. to find a new job in 2017;
4 other valley cities ranked in Top 20
- WalletHub January 2017
Housing construction on pace to have
its best year since 2007
Vacancy rates in office and retail space
have fallen to pre-recessionary levels
0%
5%
10%
15%
20%
25%
'07 '08 '09 '10 '11 '12 '13 '14 '15 '16 '17
Nonresidential Building Vacancy – Metro Phoenix
Vacancy Rate
Office
Retail
Industrial
Q1
First Quarter 2017
APPENDIX
First Quarter 20176
2017 KEY DATES
ACC Key Dates / Docket # Q1 Q2 Q3 Q4
Key Recurring Regulatory Filings
Lost Fixed Cost Recovery
E-01345A-11-0224 Jan 15
Transmission Cost Adjustor
E-01345A-11-0224 May 15
2018 DSM/EE Implementation Plan Jun 1
2018 RES Implementation Plan for Reset
of Renewable Energy Adjustor Jul 1
APS Rate Case
E-01345A-16-0036 --------------- See Slide 7 ---------------
Resource Planning and Procurement
E-00000V-15-0094
April 10: Final 2017
IRP Oct 1: Staff Report Due
Reducing System Peak Demand Costs
E-00000J-16-0257 --------------- TBD ---------------
Review, Modernization and Expansion of
Arizona Renewable Energy Standards
E-00000Q-16-0289
Jun 7: Workshop
Investigation Concerning the Future of
the Navajo Generating Station
E-00000C-17-0039
--------------- TBD ---------------
ACC Open Meetings ACC Open Meetings Held Monthly
Other Key Dates Q1 Q2 Q3 Q4
Arizona State Legislature In session Jan 9 – End of Q2
First Quarter 20177
APS RATE CASE
Procedural Schedule
File Settlement Agreement
Direct Testimony in Support of/in Opposition to the
Settlement Agreement (All Parties)
Rebuttal Testimony in Support of/in Opposition to the
Settlement Agreement (All Parties)
Hearing Commencement Date
March 27, 2017
April 3, 2017
April 17, 2017
April 24, 2017
• Filed June 1, 2016
• Docket Number: E-01345A-16-0036
• Additional details, including filing, can be found at
http://www.azenergyfuture.com/rate-review/
First Quarter 20178
2017 PROPOSED RATE CASE SETTLEMENT
Key Financial Proposals – Base Rate Changes
Annualized Base Rate Revenue Changes ($ millions)
Non-fuel, Non-depreciation Base Rate Increase $ 87.2
Decrease fuel and Purchased Power over Base Rates (53.6)
Increase due to Changes in Depreciation Schedules 61.0
Total Base Rate Increase $ 94.6
Key Financial Assumptions
Allowed Return on Equity 10.0%
Capital Structure
Long-term debt 44.2%
Common equity 55.8%
Base Fuel Rate (¢/kWh) 3.0168
Post-test year plant period 12 months
First Quarter 20179
2017 PROPOSED RATE CASE SETTLEMENT
Key Proposals – Revenue Requirement
Four Corners • Cost deferral order from in-service dates to incorporation of SCRs in rates using a step-increase no later than January 1, 2019
Ocotillo Modernization
Project • Cost deferral order from in-service dates to effective date in next rate case
Power Supply Adjustor (PSA) • Modified to include certain environmental chemical costs and third-party battery storage
Property Tax Deferral • Defer for future recovery the Arizona property tax expense above or below the test year rate
Key Proposals – Rate Design
Lost Fixed Cost Recovery
(LFCR)
• Modified to be applied as a capacity (demand) charge per kW for customer with a demand rate and
as a kWh charge for customers with a two-part rate without demand
Environmental Improvement
Surcharge (EIS)
• Increase cumulative per kWh cap rate from $0.00016 to a new rate of $0.00050 and include a
balancing account
Time-of-Use Rates (TOU)
• Modified on-peak period for residential, and extra small through large general service of 3:00 pm –
8:00 pm weekdays
• After May 1, 2018, a new TOU rate will be the standard rate for all new customers (except small
use)
Distributed Generation
• New DG customers eligible for TOU rate with Grid Access Charge or Demand rates
• Resource Comparison Proxy (RCP) for exported energy of $0.129/kWh in year one
AZ Sun II
• Proposed new program for utility-owned solar distributed generation, recoverable through the
Renewable Energy Adjustment Clause (RES), to be no less than $10 million per year, and not more
than $15 million per year
Other Considerations
Rate Case Moratorium • No new general rate case application before June 1, 2019 (3-year stay-out)
Self-Build Moratorium
• APS will not pursue any new self-build generation (with 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
First Quarter 201710
2017 ON-GOING EARNINGS KEY DRIVERS
• EPS guidance issuance pending timing and outcome of APS rate case
• Retail customer growth about 1.5-2.5%
• Weather-normalized retail electricity sales volume growth about 0.0-1.0% after
customer conservation and energy efficiency and distributed renewable generation
• Transmission rate increase
• Operations and maintenance - Planned outages (e.g. Four Corners SCRs)
• Depreciation and amortization - Higher plant balances
• Interest rates
• Higher AFUDC, driven by higher CWIP balances
First Quarter 201711
FINANCIAL OUTLOOK Key Factors & Assumptions as of May 2, 2017
Assumption Impact
Retail customer growth • Projected to average in the range of about 2-3%
• Modestly improving Arizona and U.S. economic conditions
Weather-normalized retail electricity
sales volume growth
• About 0.5-1.5% after customer conservation and energy efficiency and
distributed renewable generation initiatives
Assumption Impact
AZ Sun Program • Additions to flow through RES until next base rate case
• First 50 MW of AZ Sun is recovered through base rates
Lost Fixed Cost Recovery (LFCR) • Offsets 30-40% of revenues lost due to ACC-mandated energy efficiency and
distributed renewable generation initiatives
Environmental Improvement
Surcharge (EIS)
• Assumed to recover up to $5 million annually of carrying costs for
government-mandated environmental capital expenditures
Power Supply Adjustor (PSA) • 100% recovery as of July 1, 2012
Transmission Cost Adjustor (TCA) • TCA is filed each May and automatically goes into rates effective June 1
• Beginning July 1, 2012 following conclusion of the regulatory settlement,
transmission revenue is accrued each month as it is earned.
Four Corners Acquisition • Four Corners rate increase effective January 1, 2015
Potential Property Tax Deferrals (2012 retail rate settlement): Assume 60% of property tax increases relate to
tax rates, therefore, will be eligible for deferrals (Deferral rates: 50% in 2013; 75% in 2014 and thereafter)
Gross Margin – Customer Growth and Weather (2017-2019)
Gross Margin – Related to 2012 Retail Rate Settlement
First Quarter 201712
RATE BASE
APS’s revenues come from a
regulated retail rate base and
meaningful transmission business
$6.5
$8.3
$1.4
$1.8
2015 2016* 2017 2018 2019
APS Rate Base Growth
Year-End
ACC FERC
Total Rate Base
Projected
Most Recent Rate Decisions
ACC
As Filed 6/1/2016
FERC
Rate Effective Date 7/1/2017 6/1/2016
Test Year Ended 12/31/20151 12/31/2015
Rate Base $6.8B $1.4B
Equity Layer 56% 56%
Allowed ROE 10.5% 10.75%
1 Adjusted to include post test-year plant in service through 6/30/2017
83%
17%
Generation & Distribution Transmission
*2016 rate base pending update following FERC Form 1 filing
Rate base $ in billions, rounded
First Quarter 201713
$221 $223 $281 $217
$79
$237 $119
$8
$220
$197
$100
$41
$102
$4
$17
$16
$127
$207
$136
$152
$388
$398
$415
$491
$87
$71
$71
$84
2016 2017 2018 2019
APS CAPITAL
EXPENDITURES
Capital expenditures are funded
primarily through internally
generated cash flow
($ Millions)
$1,224
$1,337
Other
Distribution
Transmission
Renewable
Generation
Environmental(1)
Traditional
Generation
Projected
$1,139
New Gas
Generation(2)
• The table does not include capital expenditures related to 4CA’s 7% interest in the Four Corners Power Plant Units 4 and 5 of
$30 million in 2016, $27 million in 2017, $15 million in 2018 and $6 million in 2019.
• 2017 – 2019 as disclosed in First Quarter 2017 Form 10-Q.
(1) Includes Selective Catalytic Reduction controls at Four Corners with in-service dates of Q4 2017 (Unit 5) and Q1 2018 (Unit 4)
(2) Ocotillo Modernization Project: 2 units scheduled for completion in Q4 2018, 3 units scheduled for completion in Q1 2019
$1,009
First Quarter 201714
OPERATIONS &
MAINTENANCE
Goal is to keep O&M per kWh flat,
adjusted for planned outages
$754 $761 $788
$805 $772
$828
$150 $124
$137 $103
$96
$83
2011 2012 2013 2014 2015 2016
PNW Consolidated RES/DSM*
*Renewable energy and demand side management expenses are offset by adjustment mechanisms.
($ Millions)
First Quarter 201715
Credit Ratings
• A- or equivalent ratings or better at S&P, Moody’s
and Fitch
2017 Major Financing Activities
• $250 million re-opening in March of APS’s
outstanding 4.35% senior unsecured notes due
November 2045
• Currently expect up to $600 million of long-term
debt issuance from two transactions, one at PNW
(including refinancing of its $125 million term loan)
and one at APS
We are disclosing credit ratings to enhance understanding of
our sources of liquidity and the effects of our ratings on our
costs of funds.
BALANCE SHEET STRENGTH
$50
$600
$250
$125
$-
$100
$200
$300
$400
$500
$600
2017 2018 2019 2020
APS PNW
($Millions)
Debt Maturity Schedule
First Quarter 201716
249
357 339
442
610
710 641
783
871 939
523
836
484
680
832
715
1,157 1,158
1,349
1,141
1,002
1,189
1,077
1,168
1,154
760
1,268
1,003
1,293
1,415 1,374
2,051
1,644
1,489
1,348
1,5471,616
1,809
2,182
0
250
500
750
1,000
1,250
1,500
1,750
2,000
2,250
2,500
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2014 Applications 2015 Applications 2016 Applications 2017 Applications
* Monthly data equals applications received minus cancelled applications. As of March 31, 2017 approximately 58,000
residential grid-tied solar photovoltaic (PV) systems have been installed in APS’s service territory, totaling more than 445
MWdc of installed capacity. Excludes APS Solar Partner Program residential PV systems.
Note: www.arizonagoessolar.org logs total residential application volume, including cancellations. Solar water heaters can also be found
on the site, but are not included in the chart above.
RESIDENTIAL PV
APPLICATIONS* 10 18 22 44 51
57
74
133
34
2009 2011 2013 2015 2017
Residential DG (MWdc) Annual Additions
Q1
First Quarter 201717
(4)
13
(17)
4
2
$(20)
$(15)
$(10)
$(5)
$0
$5
$10
$15
Q1 Q2 Q3 Q4 Q1
GROSS MARGIN EFFECTS OF WEATHER
VARIANCES VS. NORMAL
Pretax
Millions
All periods recalculated to current 10-year rolling average (2005-2014)
2016
$(4) Million
2017
$2 Million
First Quarter 201718
8
4
7 6 5
12
15
18
13
12
$0
$10
$20
$30
$40
Q1 Q2 Q3 Q4 Q1
Renewable Energy Demand Side Management
RENEWABLE ENERGY AND
DEMAND SIDE MANAGEMENT EXPENSES*
* O&M expenses related to renewable energy and demand side management programs are partially offset by comparable revenue amounts
Pretax
Millions
2016
$83 Million
2017
$17 Million
First Quarter 201719
NON-GAAP MEASURE RECONCILIATION
$ millions pretax, except per share amounts 2017 2016
Operating revenues* 677$ 677$
Fuel and purchased power expenses* (212) (221)
Gross margin 465 456 0.05$
Adjustments:
Renewable energy (excluding AZ Sun) and
demand side management programs (13) (15) 0.01
Adjusted gross margin 452$ 441$ 0.06$
Operations and maintenance* 220$ 243$ 0.12$
Adjustments:
Renewable energy and demand
side management programs (17) (20) (0.01)
Adjusted operations and maintenance 203$ 223$ 0.11$
* Line items from Consolidated Statements of Income
Three Months Ended
March 31, EPS
Impact
First Quarter 201720
CONSOLIDATED STATISTICS
2017 2016 Incr (Decr)
ELECTRIC OPERATING REVENUES (Dollars in Millions)
Retail
Residential 302$ 299$ 3$
Business 337 341 (4)
Total Retail 639 640 (1)
Sales for Resale (Wholesale) 24 20 4
Transmission for Others 10 8 2
Other Miscellaneous Services 4 9 (5)
Total Electric Operating Revenues 677$ 677$ -$
ELECTRIC SALES (GWH)
Retail
Residential 2,457 2,509 (52)
Business 3,261 3,312 (51)
Total Retail 5,718 5,821 (103)
Sales for Resale (Wholesale) 1,074 995 79
Total Electric Sales 6,792 6,816 (24)
RETAIL SALES (GWH) - WEATHER NORMALIZED
Residential 2,454 2,601 (147)
Business 3,245 3,292 (47)
Total Retail Sales 5,699 5,893 (194)
Retail sales (GWH) (% over prior year) (3.3)%
AVERAGE ELECTRIC CUSTOMERS
Retail Customers
Residential 1,079,381 1,063,751 15,630
Business 132,520 131,162 1,358
Total Retail 1,211,901 1,194,913 16,988
Wholesale Customers 45 44 1
Total Customers 1,211,946 1,194,957 16,989
Total Customer Growth (% over prior year) 1.4%
RETAIL USAGE - WEATHER NORMALIZED (KWh/Average Customer)
Residential 2,273 2,445 (172)
Business 24,489 25,097 (608)
3 Months Ended March 31,
2017 2016 Incr (Decr)
WEATHER INDICATORS - RESIDENTIAL
Actual
Cooling Degree-Days - - -
Heating Degree-Days 436 396 40
Average Humidity - - -
10-Year Averages (2005 - 2014)
Cooling Degree-Days - - -
Heating Degree-Days 482 482 -
Average Humidity - - -
ENERGY SOURCES (GWH)
Generation Production
Nuclear 2,512 2,545 (33)
Coal 2,134 1,302 832
Gas, Oil and Other 1,118 1,758 (640)
Renewables 99 111 (12)
Total Generation Production 5,863 5,716 147
Purchased Power
Conventional 593 647 (54)
Resales 204 78 126
Renewables 482 437 45
Total Purchased Power 1,278 1,162 116
Total Energy Sources 7,141 6,878 263
POWER PLANT PERFORMANCE
Capacity Factors - Owned
Nuclear 102% 101% 1%
Coal 59% 35% 24%
Gas, Oil and Other 16% 25% (9)%
Solar 24% 30% (6)%
System Average 44% 42% 2%
3 Months Ended March 31,