Attached files
| file | filename |
|---|---|
| EX-99.1 - EXHIBIT 99.1 - PINNACLE WEST CAPITAL CORP | pnw201709308kexhibit991.htm |
| 8-K - 8-K - PINNACLE WEST CAPITAL CORP | a8-kfor93017earnings.htm |
Third Quarter 2017
THIRD QUARTER 2017 RESULTS
November 3, 2017
Third 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 and in Part II, Item 1A of the Pinnacle West/APS Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, 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 “electricity 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 EPS” in this presentation, which is also a non-GAAP financial measure. 2017 and 2018 on-going EPS are currently projected to be the same as
2017 and 2018 GAAP EPS, respectively. We believe on-going earnings provides 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.
Third Quarter 20173
CONSOLIDATED EPS COMPARISON
2017 VS. 2016
$2.46 $2.35
2017 2016
3rd Quarter
GAAP Net Income
$2.46 $2.35
3rd Quarter
On-Going Earnings
$4.16
$3.47
2017 2016
Year-to-Date
GAAP Net Income
$4.16 $3.47
Year-to-Date
On-Going Earnings
Third Quarter 20174
Gross
Margin(1)
$0.22
ON-GOING EPS VARIANCES
3RD QUARTER 2017 VS. 3RD QUARTER 2016
Other, net
$(0.01)
Interest, net
of AFUDC
$0.01
O&M(1)
$(0.02)
3Q 2016 3Q 2017
$2.35
$2.46
D&A
$(0.07)
(1) Excludes costs and offsetting operating revenues associated with renewable energy and demand side management programs.
See non-GAAP reconciliation in Appendix.
Other Taxes
$(0.02)
Gross Margin
Rate Increase $ 0.13
Sales $ 0.02
Weather $ 0.02
Transmission $ 0.04
LFCR $ (0.01)
Other $ 0.02
Third Quarter 20175
ECONOMIC
INDICATORS
Arizona and Metro Phoenix remain
attractive places to live and do
business
E
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
Q3
Above-average job growth in tourism,
health care, manufacturing, financial
services, and construction
Maricopa County ranked #1 in U.S. for
population growth in 2016
- U.S. Census Bureau March 2017
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
10,000
20,000
30,000
40,000
'07 '08 '09 '10 '11 '12 '13 '14 '15 '16 '17
Single Family Multifamily
Single Family & Multifamily Housing Permits
Maricopa County
Third Quarter 20176
ON-GOING EPS GUIDANCE
AS OF NOVEMBER 3, 2017
2017 Guidance 2018 Guidance
$4.15 – $4.30
+ Rate increase*
+ Adjustment mechanisms, primarily
Transmission Cost Adjustor (TCA)
and Lost Fixed Cost Recovery
(LFCR)
+ Selective Catalytic Reduction (SCR)
and Ocotillo deferrals*
+ Modest sales growth
– Higher D&A due to plant additions
and rates*
– Higher O&M, primarily planned fossil
outages
– Higher Taxes Other Than Income
Taxes, primarily higher property
taxes*
– Higher Interest
– Lower AFUDC
Key Drivers 2017 - 2018
$4.25 – $4.45
See key factors and assumptions in appendix.
* 2017 Rate Review Order specific items.
Third Quarter 2017
APPENDIX
Third Quarter 20178
2017 ON-GOING
EPS GUIDANCE
Key Factors & Assumptions as of
November 3, 2017
2017
Electricity gross margin* (operating revenues, net of fuel and
purchased power expenses) $2.45 – $2.50 billion
• Retail customer growth about 1.5-2.5%
• Weather-normalized retail electricity sales volume about 0-1.0% higher compared
to prior year taking into account effects of customer conservation, energy
efficiency and distributed renewable generation initiatives
• Actual weather through September; normal weather patterns remainder of year
Operating and maintenance (O&M)* $830 – $850 million
Other operating expenses (depreciation and amortization, taxes other than
income taxes, and other miscellaneous expenses) $725 – $745 million
Interest expense, net of allowance for borrowed and equity funds used during
construction (Total AFUDC $65 million) $150 – $160 million
Net income attributable to noncontrolling interests $20 million
Effective tax rate 33%
Average diluted common shares outstanding 112.6 million
On-going EPS Guidance $4.15 – $4.30
* Excludes O&M of $80 million, and offsetting revenues, associated with renewable energy and demand side management programs.
Third Quarter 20179
2018 ON-GOING
EPS GUIDANCE
Key Factors & Assumptions as of
November 3, 2017
2018
Electricity gross margin* (operating revenues, net of fuel and
purchased power expenses) $2.61 – $2.66 billion
• Retail customer growth about 1.5-2.5%
• Weather-normalized retail electricity sales volume about 0.5-1.5% higher
compared to prior year taking into account effects of customer conservation,
energy efficiency and distributed renewable generation initiatives
• Assumes normal weather
Operating and maintenance (O&M)* $860 – $880 million
Other operating expenses (depreciation and amortization, Four Corners SCRs and
Ocotillo deferrals, taxes other than income taxes, and other miscellaneous expenses) $790 – $810 million
Interest expense, net of allowance for borrowed and equity funds used during
construction (Total AFUDC $55 million) $190 – $200 million
Net income attributable to noncontrolling interests $20 million
Effective tax rate 34%
Average diluted common shares outstanding 113.2 million
On-going EPS Guidance $4.25 – $4.45
* Excludes O&M of $90 million, and offsetting revenues, associated with renewable energy and demand side management programs.
Third Quarter 201710
FINANCIAL OUTLOOK Key Factors & Assumptions as of November 3, 2017
Assumption Impact
Retail customer growth • Expected to average about 2-3% annually
• 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
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 $14 million annually of carrying costs for government-mandated
environmental capital expenditures (cumulative per kWh cap rate of $0.00050)
Power Supply Adjustor (PSA) • 100% recovery
• Includes certain environmental chemical costs and third-party battery storage
Transmission Cost Adjustor (TCA) • TCA is filed each May and automatically goes into rates effective June 1
• Transmission revenue is accrued each month as it is earned.
APS Solar Communities • Additions to flow through RES until next base rate case
Four Corners Units 4 and 5 SCRs • 2019 step increase
Property Tax Rate Deferral: APS is allowed to defer for future recovery (or credit to customers) the Arizona property tax expense above
(or below) the 2015 test year caused by changes to the applicable composite property tax rate.
Gross Margin – Customer Growth and Weather (2017-2019)
Gross Margin – Related to 2017 Rate Review Order
Outlook Through 2019: Goal of earning more than 9.5% Return on Equity (earned Return on Equity based on average Total
Shareholder’s Equity for PNW consolidated, weather-normalized)
Third Quarter 201711
DIVIDEND GROWTH
Pinnacle West’s indicated annual
dividend is $2.78 per share;
targeting ~6% annual dividend
growth
$2.10
$2.18
$2.27
$2.38
$2.50
$2.62
$2.78
2011 2012 2013 2014 2015 2016 2017 2018 2019
Dividend Growth Goal
Indicated Annual Dividend Rate at Year-End
Targeted
Future dividends subject to declaration at Board of Directors’ discretion.
Third Quarter 201712
RATE BASE
APS’s revenues come from a
regulated retail rate base and
meaningful transmission business
$6.5 $6.8
$8.2
$1.4 $1.4
$1.8
2015 2016 2017 2018 2019
APS Rate Base Growth
Year-End
ACC FERC
Total Approved Rate Base
Projected
ACC FERC
Rate Effective Date 8/19/2017 6/1/2017
Test Year Ended 12/31/20151 12/31/2016
Rate Base $6.8B $1.4B
Equity Layer 55.8% 55%
Allowed ROE 10.0% 10.75%
1 Adjusted to include post test-year plant in service through 12/31/2016
83%
17%
Generation & Distribution Transmission
Rate base $ in billions, rounded
Third Quarter 201713
$221 $211 $273 $227
$79
$245 $121
$8
$220
$199
$90
$22
$102
$3
$16
$16
$127
$182
$178
$175
$388
$420
$421
$437
$87
$77
$82
$124
2016 2017 2018 2019
APS CAPITAL
EXPENDITURES
Capital expenditures are funded
primarily through internally
generated cash flow
($ Millions)
$1,224
$1,337
Other
Distribution
Transmission
Renewable
Generation
Environmental(1)
Traditional
Generation
Projected
$1,181
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 Third 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
Third Quarter 201714
OPERATIONS &
MAINTENANCE
Goal is to keep O&M per kWh flat,
adjusted for planned outages
751 753 734 756
775 - 785 785 - 795
37 52 38
72 55 - 65
75 - 85$788 $805 $772
$828 $830 - $850
$860 - $880
2013 2014 2015 2016 2017E 2018E*
PNW Consolidated ex RES/DSM** Planned Fleet Outages
* 2018 excludes impacts related to the adoption of the new accounting standard regarding the presentation of pension and postretirement
benefit costs. See Notes 4 and 12 in the Third Quarter 2017 Form 10-Q for additional information.
** Excludes RES/DSM of $137 million in 2013, $103 million in 2014, $96 million in 2015, $83 million in 2016, $80 million in 2017E and
$90 million in 2018E.
($ Millions)
Third Quarter 201715
Palo Verde Generating Station
− Palo Verde will continue to have two refueling outages each year (18 months cycles for each of
the three units)
− APS’s share of the annual planned outage expense at Palo Verde has been between
$18 - $22 million per year since 2013
− Equipment testing, inspections, and plant modifications are performed during the outages that
cannot be done while the unit is online
− Outage duration and cost are driven by scope of planned work as well as emergent work
identified during the outage
Gas/Oil Plants
− No planned cycles; major maintenance outages are based on run hours and/or the number of
starts and overall plant condition
− Increasing levels of solar generation, participation in Energy Imbalance Market, and low gas
prices have resulted in increased starts
Coal Plants
− Major maintenance outage cycles are typically between 6 to 8 years
PLANNED OUTAGE
CYCLES
The length of time between
outages varies from plant to plant
Third Quarter 201716
Credit Ratings
• A- or equivalent ratings or better at S&P, Moody’s
and Fitch
2017 Major Financing Activities
• $300 million 10-year 2.95% APS senior unsecured
notes issued September 2017
• $250 million re-opening in March of APS’s
outstanding 4.35% senior unsecured notes due
November 2045
• Expect up to $350 million of long-term debt
issuance at PNW (including refinancing of its $125
million term loan)
2018 Major Financing Activities
• Currently expect up to $400 million of long-term
debt issuance 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
Third Quarter 201717
2017 RATE REVIEW ORDER*
EFFECTIVE AUGUST 19, 2017
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
*The ACC’s decision is subject to appeals.
Third Quarter 201718
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)
• Increased 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 to
3:00 pm – 8:00 pm weekdays
• After September 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
APS Solar Communities
• 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
2017 RATE REVIEW ORDER*
EFFECTIVE AUGUST 19, 2017
*The ACC’s decision is subject to appeals.
Third Quarter 201719
OCOTILLO MODERNIZATION PROJECT AND
FOUR CORNERS SCRs
Ocotillo Modernization Project Four Corners SCRs
In-Service Dates
Units 6, 7 – Fall 2018
Units 3, 4 and 5 – Spring 2019
Unit 5 – Late 2017
Unit 4 – Spring 2018
Total Cost (APS) $500 million $400 million
Estimated Cost Deferral $45 million (through 2019) $30 million (through 2018)
Accounting Deferral
− Cost deferral from date of commercial
operation to the effective date of rates
in next rate case
− Includes depreciation, O&M, property
taxes, and capital carrying charge1
− Cost deferral from time of installation
to incorporation of the SCR costs in
rates using a step increase beginning
in 2019
− Includes depreciation, O&M, property
taxes, and capital carrying charge1
• Included in the 2017 Rate Review Order*, APS has been granted Accounting Deferral Orders for two
large generation-related capital investments
– Ocotillo Modernization Project: Retiring two aging, steam-based, natural gas units, and
replacing with 5 new, fast-ramping, combustion turbine units
– Four Corners Power Plant: Installing Selective Catalytic Reduction (SCR) equipment to comply
with Federal environmental standards
1 APS will calculate the capital carrying charge using the 5.13% embedded cost of debt established in the 2017 Rate Review Order.
*The ACC’s decision is subject to appeals.
Third Quarter 201720
(4)
10
(13)
4 2
12
(10)
$(15)
$(10)
$(5)
$0
$5
$10
$15
Q1 Q2 Q3 Q4 Q1 Q2 Q3
GROSS MARGIN EFFECTS OF WEATHER
VARIANCES VS. NORMAL
Pretax
Millions
All periods recalculated to current 10-year rolling average (2005-2014)
2016
$(3) Million
2017
$4 Million
Third Quarter 201721
8
4
7 6 5
2
12
12
15
18
13
12
15
16
$0
$10
$20
$30
$40
Q1 Q2 Q3 Q4 Q1 Q2 Q3
Renewable Energy Demand Side Management
RENEWABLE ENERGY AND
DEMAND SIDE MANAGEMENT EXPENSES*
* Renewable energy and demand side management expenses are offset by adjustment mechanisms.
Pretax
Millions
2016
$83 Million
2017
$62 Million
Third Quarter 201722
NON-GAAP MEASURE RECONCILIATION
$ millions pretax, except per share amounts 2017 2016
Operating revenues* 1,183$ 1,167$
Fuel and purchased power expenses* (310) (336)
Gross margin 873 831 0.23$
Adjustments:
Renewable energy and demand
side management programs (32) (30) (0.01)
Adjusted gross margin 841$ 801$ 0.22$
Operations and maintenance* (224)$ (217)$ (0.04)$
Adjustments:
Renewable energy and demand
side management programs (28) (25) 0.02
Adjusted operations and maintenance (196)$ (192)$ (0.02)$
* Line items from Consolidated Statements of Income
Three Months Ended
September 30, EPS
Impact
Third Quarter 201723
NON-GAAP MEASURE RECONCILIATION
$ millions pretax
Operating revenues* 3,540$ - 3,600$
Fuel and purchased power expenses* (1,010) - (1,020)
Gross margin 2,530 - 2,580
Adjustments:
Renewable energy and demand
side management programs (80) - (80)
Adjusted gross margin 2,450$ - 2,500$
Operations and maintenance* 910$ - 930$
Adjustments:
Renewable energy and demand
side management programs (80) - (80)
Adjusted operations and maintenance 830$ - 850$
* Line items from Consolidated Statements of Income
2017 Guidance
Third Quarter 201724
NON-GAAP MEASURE RECONCILIATION
$ millions pretax
Operating revenues* 3,790$ - 3,850$
Fuel and purchased power expenses* (1,090) - (1,100)
Gross margin 2,700 - 2,750
Adjustments:
Renewable energy and demand
side management programs (90) - (90)
Adjusted gross margin 2,610$ - 2,660$
Operations and maintenance* 950$ - 970$
Adjustments:
Renewable energy and demand
side management programs (90) - (90)
Adjusted operations and maintenance 860$ - 880$
* Line items from Consolidated Statements of Income
2018 Guidance
Third Quarter 201725
CONSOLIDATED STATISTICS
2017 2016 Incr (Decr) 2017 2016 Incr (Decr)
ELECTRIC OPERATING REVENUES (Dollars in Millions)
Retail
Residential 662$ 647$ 15 1,439$ 1,398$ 41$
Business 474 480 (6) 1,245 1,244 1
Total Retail 1,136 1,127 9 2,684 2,642 42
Sales for Resale (Wholesale) 22 24 (2) 63 64 (1)
Transmission for Others 14 8 6 35 21 14
Other Miscellaneous Services 6 7 (1) 16 26 (10)
Total Electric Operating Revenues 1,178$ 1,166$ 12 2,798$ 2,753$ 45$
ELECTRIC SALES (GWH)
Retail
Residential 4,753 4,703 50 10,655 10,524 131
Business 4,310 4,298 12 11,421 11,367 54
Total Retail 9,063 9,001 62 22,076 21,891 185
Sales for Resale (Wholesale) 655 784 (129) 2,278 2,722 (444)
Total Electric Sales 9,718 9,785 (67) 24,354 24,613 (259)
RETAIL SALES (GWH) - WEATHER NORMALIZED
Residential 4,834 4,820 14 10,647 10,668 (21)
Business 4,332 4,332 - 11,374 11,332 42
Total Retail Sales 9,166 9,152 14 22,021 22,000 21
Retail sales (GWH) (% over prior year) 0.2% 0.1%
AVERAGE ELECTRIC CUSTOMERS
Retail Customers
Residential 1,079,344 1,059,173 20,171 1,078,672 1,060,181 18,491
Business 134,830 131,877 2,953 133,667 131,537 2,130
Total Retail 1,214,174 1,191,050 23,124 1,212,339 1,191,718 20,621
Wholesale Customers 40 49 (9) 42 46 (4)
Total Customers 1,214,214 1,191,099 23,115 1,212,381 1,191,764 20,617
Total Customer Growth (% over prior year) 1.9% 1.7%
RETAIL USAGE - WEATHER NORMALIZED (KWh/Average Customer)
Residential 4,479 4,551 (72) 9,871 10,062 (191)
Business 32,130 32,851 (721) 85,089 86,150 (1,061)
3 Months Ended September 30, 9 Months Ended September 30,
Third Quarter 201726
CONSOLIDATED STATISTICS
2017 2016 Incr (Decr) 2017 2016 Incr (Decr)
WEATHER INDICATORS - RESIDENTIAL
Actual
Cooling Degree-Days 1,153 1,160 (7) 1,724 1,663 61
Heating Degree-Days - - - 439 397 42
Average Humidity 32% 31% 1% 26% 27% (1)%
10-Year Averages (2005 - 2014)
Cooling Degree-Days 1,218 1,218 - 1,722 1,722 -
Heating Degree-Days - - - 492 492 -
Average Humidity 31% 31% - 25% 25% -
ENERGY SOURCES (GWH)
Generation Production
Nuclear 2,514 2,417 97 7,147 7,108 39
Coal 2,093 1,680 413 5,635 4,311 1,324
Gas, Oil and Other 2,666 2,732 (66) 5,682 6,762 (1,080)
Renewables 174 138 36 445 409 36
Total Generation Production 7,447 6,967 480 18,909 18,590 319
Purchased Power - -
Conventional 2,223 2,644 (421) 4,644 4,984 (340)
Resales 238 254 (16) 633 839 (207)
Renewables 389 429 (40) 1,462 1,395 67
Total Purchased Power 2,850 3,327 (477) 6,738 7,218 (480)
Total Energy Sources 10,297 10,294 3 25,647 25,808 (161)
POWER PLANT PERFORMANCE
Capacity Factors - Owned
Nuclear 99% 96% 3% 95% 94% 1%
Coal 57% 45% 12% 51% 39% 12%
Gas, Oil and Other 40% 39% 1% 29% 32% (3)%
Solar 35% 33% 2% 34% 33% 1%
System Average 54% 51% 3% 46% 46% -
3 Months Ended September 30, 9 Months Ended September 30,