Attached files
| file | filename |
|---|---|
| EX-99.1 - EXHIBIT 99.1 - PINNACLE WEST CAPITAL CORP | pnw20161231exhibit991.htm |
| 8-K - 8-K - PINNACLE WEST CAPITAL CORP | pnw201612318-kearningsrele.htm |
Fourth Quarter and Full-Year 2016
FOURTH QUARTER AND
FULL-YEAR 2016 RESULTS
February 24, 2017
Fourth Quarter and Full-Year 20162
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.
Fourth Quarter and Full-Year 20163
CONSOLIDATED EPS COMPARISON
2016 VS. 2015
$0.47
$0.37
2016 2015
4th Quarter
GAAP Net Income
$0.47 $0.37
4th Quarter
On-Going Earnings
$3.95 $3.92
2016 2015
Full-Year
GAAP Net Income
$3.95 $3.92
Full-Year
On-Going Earnings
Fourth Quarter and Full-Year 20164
O&M(1)
$0.06
ON-GOING EPS VARIANCES
4TH QUARTER 2016 VS. 4TH QUARTER 2015
Interest, net
of AFUDC
$0.01
4Q 2015 4Q 2016
Gross Margin(1),(2)
Sales $ (0.03)
LFCR $ 0.03
Transmission $ (0.01)
Other $ 0.01
$0.37
$0.47
D&A(2)
$(0.01)
Other, net
$0.03Other
Taxes
$0.01
(1) Excludes costs and offsetting operating revenues, associated with renewable energy (excluding AZ Sun) and demand side management programs.
(2) Excludes revenues and offsetting depreciation and amortization expense related to reduced Palo Verde system benefits charge.
See non-GAAP reconciliation.
Fourth Quarter and Full-Year 20165
Gross
Margin(1), (2)
$0.33
ON-GOING EPS VARIANCES
FULL YEAR 2016 VS. 2015
O&M(1)
$(0.30)
D&A(2)
$(0.03)
Other, net
$(0.02)
Interest, net
of AFUDC
$0.02
$3.92
$3.95
2015 2016
Other
Taxes
$0.03
Gross Margin
Weather $ 0.02
Sales $ 0.05
LFCR $ 0.09
Transmission $ 0.08
Transmission Line Sale $ 0.03
AZ Sun $ 0.01
Other $ 0.05
(1) Excludes costs and offsetting operating revenues, associated with renewable energy (excluding AZ Sun) and demand side management programs.
(2) Excludes revenues and offsetting depreciation and amortization expense related to reduced Palo Verde system benefits charge.
See non-GAAP reconciliation.
Fourth Quarter and Full-Year 20166
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
construction and financial services
Metro Phoenix growth rate 3rd fastest
among top 15 metro areas
- U.S. Census Bureau March 2016
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
Nonresidential Net Absorption – Metro Phoenix
(2)
(1)
-
1
2
3
4
5
'10 '11 '12 '13 '14 '15 '16
Millions Sq. Ft
Office Retail
Fourth Quarter and Full-Year 2016
APPENDIX
Fourth Quarter and Full-Year 20168
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 10 ---------------
Resource Planning and Procurement
E-00000V-15-0094 April 3: Final IRP due
Reducing System Peak Demand Costs
E-00000J-16-0257 --------------- TBD ---------------
Review, Modernization and Expansion of
Arizona Renewable Energy Standards
E-00000Q-16-0289
--------------- TBD ---------------
ACC Open Meetings ACC Open Meetings Held Monthly
* April 2017: Final IRP due
Other Key Dates Q1 Q2 Q3 Q4
Arizona State Legislature In session Jan 9 – End of Q2
Fourth Quarter and Full-Year 20169
2016 APS RATE CASE
Procedural Schedule
Staff and Intervenor Direct Testimony (ex rate design)
Staff and Intervenor Direct Testimony (Rate Design)
APS Rebuttal Testimony
Staff Resource Comparison Proxy (RCP) Direct Testimony
Settlement Deadline
APS and Intervener RCP Rebuttal Testimony
Staff and Intervenor Surrebuttal Testimony
Prehearing Conference
Proposed Hearing Commencement Date
December 28, 2016
February 3, 2017
February 24, 2017
March 10, 2017
March 17, 2017
March 31, 2017
April 14, 2017
April 20, 2017
April 24, 2017
• Filed June 1, 2016
• Propose new rates go into effect on July 1, 2017
• Docket Number: E-01345A-16-0036
• Additional details, including filing, can be found at
http://www.azenergyfuture.com/rate-review/
Fourth Quarter and Full-Year 201610
ARIZONA ELECTRIC UTILITIES
GENERAL RATE CASES
UNS Electric (93,000 customers)
Docket # E-04204A-15-0142
Application Filed May 5, 2015
Hearing (Mar 1 – 24, 2016)
Phase One Decision (Decision No. 75697, Aug 18, 2016)
UNSE Customer Education Plan on Rates : Filed Sep 30, 2016
Final Non-DG Rates Approved: Feb 8, 2017
Phase Two (Net Metering Issues) Testimony: Mar – Jun 2017
Phase Two Hearing: Begins June 28, 2017
Phase Two Decision: Expected Oct 2017
Tucson Electric Power Company (415,000 customers)
Docket # E-01933A-15-0322
Application Filed Nov 5, 2015
Non-unanimous Revenue Requirement Settlement Filed (Aug 15, 2016)
Hearing (Sep 8 – 20, 2016)
Phase One Decision: Feb 9, 2017
Phase Two (Net Metering Issues) Testimony: Mar – Jun 2017
Phase Two Hearing : Begins Jun 28, 2017
Phase Two Decision: Expected Oct 2017
Sulphur Springs Valley Electric Cooperative (58,000 customers)
Docket # E-01575A-15-0312
Application Filed Aug 31, 2015
Hearing (May 17 – 27 , 2016)
Decision in Phase One (Decision No. 75788, Nov 11, 2016)
Phase Two (Net Metering Issues) Testimony: Apr – Jun 2017
Phase Two Hearing: Begins Jul 20, 2017
Phase Two Decision: Expected Nov 2017
Trico Electric Cooperative (38,000 customers)
Docket # E-01461A-15-0363
Application Filed Oct 23, 2015
Non-unanimous Revenue Requirement Settlement (Jul 8, 2016)
Hearing (Aug 17, 2016)
Decision: Feb 9, 2017
No Phase Two Proceeding Necessary
Fourth Quarter and Full-Year 201611
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
• AFUDC
Fourth Quarter and Full-Year 201612
FINANCIAL OUTLOOK Key Factors & Assumptions as of February 24, 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
Fourth Quarter and Full-Year 201613
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 - Proposed 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
Fourth Quarter and Full-Year 201614
$221 $219 $284 $214
$79
$237 $119
$8
$220
$195
$105
$61
$102
$4
$1
$127
$206
$137
$150
$388
$402
$406
$480
$87
$74
$72
$81
2016 2017 2018 2019
APS CAPITAL
EXPENDITURES
Capital expenditures are funded
primarily through internally
generated cash flow
($ Millions)
$1,224
$1,337
Other
Distribution
Transmission
Renewable
Generation
Environmental(1)
Traditional
Generation
Projected
$1,124
New Gas
Generation(2)
• The table does not include capital expenditures related to 4CA’s 7% interest in Four Corners 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 2016 Form 10-K.
(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
$994
Fourth Quarter and Full-Year 201615
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)
Fourth Quarter and Full-Year 201616
Credit Ratings
• A- rating or better at S&P, Moody’s and Fitch
2016 Major Financing Activities
• $100 million 3-year term loan closed April 2016
• $350 million 30-year 3.75% APS senior unsecured
notes issued May 2016
• $250 million 10-year 2.55% APS senior unsecured
notes issued September 2016
2017 Major Financing Activities
• Currently expect up to $850 million of long-term
debt, including refinance of $125 million PNW term
loan
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
Fourth Quarter and Full-Year 201617
• Funded status of the pension plan finished
2016 at 88%, unchanged from YE 2015.
• The pension plan continues to employ a
liability driven investment strategy in order to
reduce volatility in the plan’s funded status.
PENSION & OTHER POST RETIREMENT
BENEFITS (“OPEB”)
90% 88% 88%
YE 2014 YE 2015 YE 2016
Pension Funded Status(1)
Expense(2) 2016A 2017E
Pension(1) $19 $24
OPEB ($12) ($19)
Contributions 2016A 2017E 2018E 2019E
Pension $100 $100 Up to $100
Up to
$100
OPEB $0.8 $0.4 $0.0 $0.0
Expense Assumptions 2016 2017
Discount Rate: Pension 4.37% 4.08%
Expected Long-Term Return
on Plan Assets: Pension 6.90% 6.55%
(1) Excludes supplemental excess benefit retirement plan calculated on a PBO basis.
(2) Excludes approximately 50% of total estimated expense which is attributable to amounts capitalized or billed to electric generating plant
joint owners.
Data as of February 24, 2017
($ in millions)
Fourth Quarter and Full-Year 201618
249
357 339
442
610
710 641
783
871 939
523
836
0
250
500
750
1000
1250
1500
1750
2000
2250
2500
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 January 31, 2017 approximately 55,000
residential grid-tied solar photovoltaic (PV) systems have been installed in APS’s service territory, totaling more than 420
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
12
2009 2011 2013 2015 2017
Residential DG (MWdc) Annual Additions
Fourth Quarter and Full-Year 201619
(8)
(4) (1)
4
(5)
13
(17)
4
$(20)
$(15)
$(10)
$(5)
$0
$5
$10
$15
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
GROSS MARGIN EFFECTS OF WEATHER
VARIANCES VS. NORMAL
Pretax
Millions
All periods recalculated to current 10-year rolling average (2005-2014)
2015
$(8) Million
2016
$(5) Million
Fourth Quarter and Full-Year 201620
12
7
11 11
8
4
7 6
11
14
18
12
12
15
18
13
$0
$10
$20
$30
$40
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
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
2015
$96 Million
2016
$83 Million
Fourth Quarter and Full-Year 201621
NON-GAAP MEASURE RECONCILIATION
$ millions pretax, except per share amounts 2016 2015
Operating revenues* 739$ 734$
Fuel and purchased power expenses* (243) (232)
Gross margin 496 502 (0.03)$
Adjustments:
Renewable energy (excluding AZ Sun) and
demand side management programs (14) (18) 0.02
Palo Verde system benefits charge 2 - 0.01
Adjusted gross margin 484$ 484$ -$
Depreciation and amortization* (123)$ (125)$ 0.01$
Adjustments:
Palo Verde system benefits charge - (4) 0.02
Adjusted depreciation and amortization 123$ (121)$ (0.01)$
* Line items from Consolidated Statements of Income
Three Months Ended
December 31, EPS
Impact
Fourth Quarter and Full-Year 201622
NON-GAAP MEASURE RECONCILIATION
$ millions pretax, except per share amounts 2016 2015
Operating revenues* 3,499$ 3,495$
Fuel and purchased power expenses* (1,076) (1,101)
Gross margin 2,423 2,394 0.16$
Adjustments:
Renewable energy (excluding AZ Sun) and
demand side management programs (61) (78) 0.09
Palo Verde system benefits charge 14 - 0.08
Adjusted gross margin 2,376$ 2,316$ 0.33$
Depreciation and amortization* (486)$ (494)$ 0.05$
Adjustments:
Palo Verde system benefits charge (2) (16) 0.08
Adjusted depreciation and amortization (484)$ (478)$ (0.03)$
* Line items from Consolidated Statements of Income
Twelve Months Ended
December 31, EPS
Impact
Fourth Quarter and Full-Year 201623
CONSOLIDATED STATISTICS
2016 2015 Incr (Decr) 2016 2015 Incr (Decr)
ELECTRIC OPERATING REVENUES (Dollars in Millions)
Retail
Residential 332$ 328$ 4$ 1,730$ 1,702$ 28$
Business 362 349 13 1,605 1,584 21
Total Retail 694 677 17 3,335 3,286 49
Sales for Resale (Wholesale) 30 40 (10) 95 149 (54)
Transmission for Others 7 7 - 28 34 (6)
Other Miscellaneous Services 6 10 (4) 32 23 9
Total Electric Operating Revenues 737$ 734$ 3$ 3,490$ 3,492$ (2)$
ELECTRIC SALES (GWH)
Retail
Residential 2,671 2,767 (96) 13,195 13,160 35
Business 3,460 3,445 15 14,827 14,791 36
Total Retail 6,131 6,212 (81) 28,022 27,951 71
Sales for Resale (Wholesale) 1,045 2,357 (1,312) 3,767 6,340 (2,573)
Total Electric Sales 7,176 8,569 (1,393) 31,789 34,291 (2,502)
RETAIL SALES (GWH) - WEATHER NORMALIZED
Residential 2,648 2,727 (79) 13,297 13,366 (69)
Business 3,431 3,417 14 14,766 14,695 71
Total Retail Sales 6,079 6,144 (65) 28,063 28,061 2
Retail sales (GWH) (% over prior year) (1.1)% -
AVERAGE ELECTRIC CUSTOMERS
Retail Customers
Residential 1,066,711 1,053,177 13,534 1,061,814 1,046,990 14,824
Business 132,173 130,846 1,327 131,697 130,505 1,192
Total Retail 1,198,884 1,184,023 14,861 1,193,511 1,177,495 16,016
Wholesale Customers 46 47 (1) 46 47 (1)
Total Customers 1,198,930 1,184,070 14,860 1,193,557 1,177,542 16,015
Total Customer Growth (% over prior year) 1.3% 1.4%
RETAIL USAGE - WEATHER NORMALIZED (KWh/Average Customer)
Residential 2,482 2,589 (107) 12,523 12,766 (243)
Business 25,960 26,118 (158) 112,120 112,602 (482)
3 Months Ended December 31, 12 Months Ended December 31,
Fourth Quarter and Full-Year 201624
CONSOLIDATED STATISTICS
2016 2015 Incr (Decr) 2016 2015 Incr (Decr)
WEATHER INDICATORS - RESIDENTIAL
Actual
Cooling Degree-Days 57 73 (16) 1,720 1,822 (102)
Heating Degree-Days 282 463 (181) 679 717 (38)
Average Humidity 29% 41% (12)% 27% 31% (4)%
10-Year Averages (2005 - 2014)
Cooling Degree-Days 41 41 - 1,768 1,768 -
Heating Degree-Days 346 346 - 835 835 -
Average Humidity 27% 27% - 25% 25% -
ENERGY SOURCES (GWH)
Generation Production
Nuclear 2,276 2,202 74 9,384 9,464 (80)
Coal 2,376 2,621 (245) 6,687 10,921 (4,233)
Gas, Oil and Other 1,508 1,988 (480) 8,270 6,573 1,697
Renewables 93 106 (13) 397 529 (132)
Total Generation Production 6,252 6,916 (664) 24,738 27,487 (2,748)
Purchased Power - -
Conventional 753 941 (188) 5,737 5,614 123
Resales 188 83 105 785 380 404
Renewables 430 454 (24) 1,825 1,794 31
Total Purchased Power 1,371 1,478 (107) 8,346 7,788 558
Total Energy Sources 7,624 8,394 (771) 33,084 35,274 (2,190)
POWER PLANT PERFORMANCE
Capacity Factors - Owned
Nuclear 90% 87% 3% 93% 94% (1)%
Coal 36% 71% (35)% 46% 74% (29)%
Gas, Oil and Other 31% 27% 4% 28% 22% 6%
Solar 22% 25% (3)% 24% 23% 1%
System Average 46% 51% (5)% 45% 50% (5)%
3 Months Ended December 31, 12 Months Ended December 31,