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10-K

Table of Contents

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K



[X]	ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015



[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-3523

WESTAR ENERGY, INC.

(Exact name of registrant as specified in its charter)



Kansas		48-0290150
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)



818 South Kansas Avenue, Topeka, Kansas 66612		(785) 575-6300
(Address, including Zip code and telephone number, including area code, of registrant’s principal executive offices)

Securities registered pursuant to section 12(b) of the Act:



Common Stock, par value $5.00 per share		New York Stock Exchange
(Title of each class)		(Name of each exchange on which registered)

Securities registered pursuant to section 12(g) of the Act: None

Indicate by check mark whether the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Act). Yes X No ____

Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No X

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ____

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes X No ____

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Act). Check one:

Large accelerated filer X Accelerated filer Non-accelerated filer Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes No X

The aggregate market value of the voting common equity held by non-affiliates of the registrant was approximately $4,831,132,308 at June 30, 2015.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.



Common Stock, par value $5.00 per share		141,622,586 shares
(Class)		(Outstanding at February 17, 2016)

DOCUMENTS INCORPORATED BY REFERENCE:



Description of the document		Part of the Form 10-K
Portions of the Westar Energy, Inc. definitive proxy statement to be used in connection with the registrant’s 2016 Annual Meeting of Shareholders		Part III (Item 10 through Item 14) (Portions of Item 10 are not incorporated by reference and are provided herein)

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TABLE OF CONTENTS



		Page
	PART I
Item 1.	Business	7
Item 1A.	Risk Factors	15
Item 1B.	Unresolved Staff Comments	19
Item 2.	Properties	20
Item 3.	Legal Proceedings	21
Item 4.	Mine Safety Disclosures	21
	PART II
Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters	22
Item 6.	Selected Financial Data	24
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	49
Item 8.	Financial Statements and Supplementary Data	52
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	110
Item 9A.	Controls and Procedures	110
Item 9B.	Other Information	111
	PART III
Item 10.	Directors and Executive Officers of the Registrant	112
Item 11.	Executive Compensation	112
Item 12.	Security Ownership of Certain Beneficial Owners and Management	112
Item 13.	Certain Relationships and Related Transactions	112
Item 14.	Principal Accountant Fees and Services	112
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	113
Signatures		118

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GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations or acronyms that are found throughout this report.



Abbreviation or Acronym		Definition
AFUDC		Allowance for funds used during construction
ARO		Asset retirement obligation
BNSF		BNSF Railway Company
Btu		British thermal units
CAA		Clean Air Act
CCB		Coal combustion byproducts
CO		Carbon monoxide
CO₂		Carbon dioxide
COLI		Corporate-owned life insurance
CPP		Clean Power Plan
CWA		Clean Water Act
CWIP		Construction work in progress
DOE		Department of Energy
DSPP		Direct Stock Purchase Plan
ECRR		Environmental Cost Recovery Rider
EPA		Environmental Protection Agency
EPS		Earnings per share
Exchange Act		Securities Exchange Act of 1934
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FPA		Federal Power Act
GAAP		Generally Accepted Accounting Principles
GHG		Greenhouse gas
IM		Integrated Marketplace
JEC		Jeffrey Energy Center
KCC		Kansas Corporation Commission
KCPL		Kansas City Power & Light Company
KDHE		Kansas Department of Health and Environment
KGE		Kansas Gas and Electric Company
La Cygne		La Cygne Generating Station
LTISA Plan		Long-term incentive and share award plan
MATS		Mercury and Air Toxics Standards
MMBtu		Millions of British thermal units
Moody’s		Moody’s Investors Service
MW		Megawatt(s)
MWh		Megawatt hour(s)
NAAQS		National Ambient Air Quality Standards
NDT		Nuclear Decommissioning Trust
NEIL		Nuclear Electric Insurance Limited
NOx		Nitrogen oxides
NRC		Nuclear Regulatory Commission
PCB		Polychlorinated biphenyl
PM		Particulate matter
PPB		Parts per billion
PRB		Powder River Basin

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Prairie Wind		Prairie Wind Transmission, LLC
ROE		Return on equity
RSU		Restricted share unit
RTO		Regional transmission organization
S&P		Standard & Poor’s Ratings Services
S&P 500		Standard & Poor’s 500 Index
S&P Electric Utilities		Standard & Poor’s Electric Utility Index
SEC		Securities and Exchange Commission
SO₂		Sulfur dioxide
SPP		Southwest Power Pool, Inc.
SSCGP		Southern Star Central Gas Pipeline
TFR		Transmission formula rate
VaR		Value-at-Risk
VIE		Variable interest entity
Wolf Creek		Wolf Creek Generating Station

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FORWARD-LOOKING STATEMENTS

Certain matters discussed in this Annual Report on Form 10-K are “forward-looking statements.” The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we “believe,” “anticipate,” “target,” “expect,” “estimate,” “intend” and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. Such statements address future events and conditions concerning matters such as, but not limited to:


-	amount, type and timing of capital expenditures,


-	earnings,


-	cash flow,


-	liquidity and capital resources,


-	litigation,


-	accounting matters,


-	possible corporate restructurings, acquisitions and dispositions,


-	compliance with debt and other restrictive covenants,


-	interest rates and dividends,


-	environmental matters,


-	regulatory matters,


-	nuclear operations, and


-	the overall economy of our service area and its impact on our customers’ demand for electricity and their ability to pay for service.

What happens in each case could vary materially from what we expect because of such things as:


-	risks related to operating in a heavily regulated industry that is subject to unpredictable political, legislative, judicial and regulatory developments, which can impact our operations, results of operations, and financial condition,


-	the difficulty of predicting the magnitude and timing of changes in demand for electricity, including with respect to emerging competing services and technologies and conservation and energy efficiency measures,


-	the impact of weather conditions, including as it relates to sales of electricity and prices of energy commodities,


-	equipment damage from storms and extreme weather,


-	economic and capital market conditions, including the impact of inflation or deflation, changes in interest rates, the cost and availability of capital and the market for trading wholesale energy,


-	the impact of changes in market conditions on employee benefit liability calculations and funding obligations, as well as actual and assumed investment returns on invested plan assets,


-	the impact of changes in estimates regarding our Wolf Creek Generating Station (Wolf Creek) decommissioning obligation,


-	the existence or introduction of competition into markets in which we operate,


-	the impact of changing laws and regulations relating to air and greenhouse gas (GHG) emissions, water emissions, waste management and other environmental matters,


-	risks associated with execution of our planned capital expenditure program, including timing and receipt of regulatory approvals necessary for planned construction and expansion projects as well as the ability to complete planned construction projects within the terms and time frames anticipated,


-	cost, availability and timely provision of equipment, supplies, labor and fuel we need to operate our business,


-	availability of generating capacity and the performance of our generating plants,


-	changes in regulation of nuclear generating facilities and nuclear materials and fuel, including possible shutdown or required modification of nuclear generating facilities,


-	additional regulation due to Nuclear Regulatory Commission (NRC) oversight to ensure the safe operation of Wolf Creek, either related to Wolf Creek’s performance, or potentially relating to events or performance at a nuclear plant anywhere in the world,


-	uncertainty regarding the establishment of interim or permanent sites for spent nuclear fuel storage and disposal,


-	homeland and information and operating systems security considerations,


-	changes in accounting requirements and other accounting matters,


-	changes in the energy markets in which we participate resulting from the development and implementation of real time and next day trading markets, and the effect of the retroactive repricing of transactions in such markets following execution because of changes or adjustments in market pricing mechanisms by regional transmission organizations (RTOs) and independent system operators,

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-	reduced demand for coal-based energy because of actual or potential climate impacts and the development of alternate energy sources,


-	current and future litigation, regulatory investigations, proceedings or inquiries,


-	cost of fuel used in generation and wholesale electricity prices, and


-	other factors discussed elsewhere in this report, including in “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,“ and in other reports we file from time to time with the Securities and Exchange Commission (SEC).

These lists are not all-inclusive because it is not possible to predict all factors. This report should be read in its entirety. No one section of this report deals with all aspects of the subject matter. The reader should not place undue reliance on any forward-looking statement, as forward-looking statements speak only as of the date such statements were made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made.

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PART I

ITEM 1. BUSINESS

GENERAL

Overview

We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K to “the company,” “we,” “us,” “our” and similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term “Westar Energy” refers to Westar Energy, Inc., a Kansas corporation incorporated in 1924, alone and not together with its consolidated subsidiaries.

We provide electric generation, transmission and distribution services to approximately 700,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy’s wholly-owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.

Strategy

We expect to continue operating as a vertically integrated, regulated, electric utility. Significant elements of our strategy include maintaining a flexible, clean and diverse energy supply portfolio. In doing so, we continue to expand renewable generation, build and upgrade our electrical infrastructure and develop systems and programs with regard to how our customers use energy and interact with us.

OPERATIONS

General

As noted above, we supply electric energy at retail to customers in Kansas. We also supply electric energy at wholesale to municipalities and electric cooperatives in Kansas, and have contracts for the sale or purchase of wholesale electricity with other utilities.

Following is the percentage of our revenues by customer classification. Classification of customers as residential, commercial and industrial requires judgment and our classifications may be different from other companies. Assignment of tariffs is not dependent on classification.



	Year Ended December 31,
	2015		2014		2013
Residential	31	%	31	%	31	%
Commercial	29	%	28	%	28	%
Industrial	16	%	16	%	16	%
Wholesale	13	%	15	%	15	%
Transmission	10	%	9	%	9	%
Other	1	%	1	%	1	%
Total	100	%	100	%	100	%

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The percentage of our retail electricity sales by customer class was as follows.



	Year Ended December 31,
	2015		2014		2013
Residential	33	%	34	%	34	%
Commercial	39	%	38	%	38	%
Industrial	28	%	28	%	28	%
Total	100	%	100	%	100	%

Generating Capability and Firm Capacity Purchases

We have 6,267 megawatts (MW) of generating capability in service. See “Item 2. Properties” for additional information about our generating units. Further, we purchase electricity pursuant to long-term contracts from renewable generation facilities with an installed design capacity of 920 MW. Our generating capability and net generation by source are summarized below.



Source	Capability (MW)	Percent of Total Capability		Net Generation (MWh)	Percent of Total Net Generation
Coal	3,213	44	%	17,352,379	71	%
Nuclear	551	8	%	4,056,184	16	%
Natural gas/diesel	2,354	33	%	1,301,884	5	%
Renewable	1,069	15	%	2,061,255	8	%
Total	7,187	100	%	24,771,702	100	%

We have entered into four additional wind energy agreements. One agreement is for approximately 200 MW of additional installed designed capability. In addition, we have begun constructing a wind generating facility expected to have a designed installed capability of approximately 280 MW. The last two agreements are for approximately 100 MW each with Westar holding an option for the purchase of one of the facilities. These four agreements are to provide approximately 680 MW generating capability by early 2017.

Our aggregate 2015 peak system net load of 5,167 MW occurred in July 2015. Because of the intermittent nature of wind generation, only 152 MW of net accredited generating capacity is associated with our wind generation facilities. Our net accredited generating capacity, combined with firm capacity purchases and sales and potentially interruptible load, provided a capacity margin of 20% above system peak responsibility at the time of our 2015 peak system net load, which satisfied Southwest Power Pool, Inc. (SPP) planning requirements.

Under wholesale agreements, we provide firm generating capacity to other entities as set forth below.



Utility (a)	Capacity (MW)	Expiration
Midwest Energy, Inc.	120	May 2017
Midwest Energy, Inc.	35	May 2017
Mid-Kansas Electric Company, LLC	172	January 2019
Kansas Power Pool	59	December 2022
Midwest Energy, Inc.	150	May 2025
Total	536

_______________

(a)

Under a wholesale agreement that expires in May 2039, we provide base load capacity to the city of McPherson, Kansas, and in return the city provides peaking capacity to us. During 2015, we provided approximately 89 MW to, and received approximately 148 MW from, the city. The amount of base load capacity provided to the city is based on a fixed percentage of its annual peak system load. The city is a full requirements customer of Westar Energy. The agreement for the city to provide capacity to us is treated as a capital lease.

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Fossil Fuel Generation

The effectiveness of a fuel to produce heat is measured in British thermal units (Btu). The higher the Btu content of a fuel, the smaller the volume of fuel that is required to produce a given amount of electricity. We measure the quantity of heat consumed during the generation of electricity in millions of British thermal units (MMBtu).

Coal

Jeffrey Energy Center (JEC): The three coal-fired units at JEC have an aggregate capacity of 2,146 MW, of which we own or consolidate through a variable interest entity (VIE) a combined 92% share, or 1,975 MW. We have a long-term coal supply contract with Alpha Natural Resources, Inc. to supply coal to JEC from surface mines located in the Powder River Basin (PRB) in Wyoming. The contract contains a schedule of minimum annual MMBtu quantities. All of the coal used at JEC is purchased under this contract, which expires December 31, 2020. The contract provides for price escalation based on certain costs of production. The price for quantities purchased in excess of the scheduled annual minimum is subject to renegotiation every five years to provide an adjusted price for the ensuing five years that reflects the market prices at the time of renegotiation. The most recent price adjustment was effective January 1, 2013.

The BNSF Railway Company (BNSF) and Union Pacific Railroad Company transport coal to JEC under a long-term rail transportation contract. The contract term continues through December 31, 2020, at which time we plan to enter into a new contract. The contract price is subject to price escalation based on certain costs incurred by the railroads.

The average delivered cost of coal consumed at JEC during 2015 was approximately $1.74 per MMBtu, or $29.01 per ton.

La Cygne Generating Station (La Cygne): The two coal-fired units at La Cygne have an aggregate generating capacity of 1,398 MW. Our share of the units is 50%, or 699 MW, of which we either own directly or consolidate through a VIE. La Cygne uses primarily PRB coal but one of the two units also uses a small portion of locally-mined coal. The operator of La Cygne, Kansas City Power & Light Company (KCPL), arranges coal purchases and transportation services for La Cygne. Approximately 95%, 90% and 35% of La Cygne’s PRB coal requirements are under contract for 2016, 2017 and 2018, respectively. About 90%, 85% and 100% of those commitments under contract are fixed price for 2016, 2017 and 2018, respectively. As the PRB coal contracts expire, we anticipate that KCPL will negotiate new supply contracts or purchase coal on the spot market.

All of the La Cygne PRB coal is transported under KCPL’s rail transportation agreements with BNSF through 2018 and Kansas City Southern Railroad through 2020. During 2015, our share of average delivered cost of coal consumed at La Cygne was approximately $1.88 per MMBtu, or $32.64 per ton.

Lawrence and Tecumseh Energy Centers: Lawrence and Tecumseh Energy Centers have an aggregate generating capacity of 539 MW. We purchase PRB coal for these energy centers under a contract with Arch Coal, Inc. that provides for 100% of the coal requirements for these facilities through 2017. BNSF transports coal for these energy centers under a contract that expires in December 2020.

During 2015, the average delivered cost of coal consumed in the Lawrence units was approximately $1.75 per MMBtu, or $31.30 per ton. The average delivered cost of coal consumed in the Tecumseh units was approximately $1.76 per MMBtu, or $31.46 per ton.

Natural Gas

We use natural gas as a primary fuel at our Gordon Evans, Murray Gill, Hutchinson, Spring Creek and Emporia Energy Centers and at the State Line facility. We can also use natural gas as a supplemental fuel in the coal-fired units at Lawrence and Tecumseh Energy Centers. During 2015, we consumed 13.4 million MMBtu of natural gas for a total cost of $48.9 million, or approximately $3.64 per MMBtu. Natural gas accounted for approximately 5% of the total MMBtu of fuel we consumed and approximately 11% of our total fuel expense in 2015. From time to time, we may enter into contracts, including the use of derivatives, in an effort to manage the cost of natural gas. For additional information about our exposure to commodity price risks, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

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We maintain a natural gas transportation arrangement for Hutchinson Energy Center with Kansas Gas Service. The agreement has historically expired on April 30 of each year and is renegotiated for an additional one year term. We meet a portion of our natural gas transportation requirements for Gordon Evans, Murray Gill, Lawrence, Tecumseh and Emporia Energy Centers through firm natural gas transportation capacity agreements with Southern Star Central Gas Pipeline (SSCGP). We meet all of the natural gas transportation requirements for the State Line facility through a firm transportation agreement with SSCGP. The firm transportation agreement that serves Gordon Evans and Murray Gill Energy Centers expires in April 2020, and the agreement for Lawrence and Tecumseh Energy Centers expires in April 2030. The agreement for the State Line facility extends through October 2022, while the agreement for Emporia Energy Center is in place until December 2028, and is renewable for five-year terms thereafter. We meet all of the natural gas transportation requirements for Spring Creek Energy Center through an interruptible month-to-month transportation agreement with ONEOK Gas Transportation, LLC.

Diesel

We use diesel to start some of our coal generating stations, as a primary fuel in the Hutchinson No. 4 combustion turbine and in our diesel generators. We purchase No. 2 diesel in the spot market. We maintain quantities in inventory that we believe will allow us to facilitate economic dispatch of power and satisfy emergency requirements. We do not use significant amounts of diesel in our operations.

Nuclear Generation

General

Wolf Creek is a 1,171 MW nuclear power plant located near Burlington, Kansas. KGE owns a 47% interest in Wolf Creek, or 551 MW. Wolf Creek’s operating license, issued by the NRC, is effective until 2045. Wolf Creek Nuclear Operating Corporation, an operating company owned by each of the plant’s owners in proportion to their ownership share of the plant, operates the plant. The plant’s owners pay operating costs proportionate to their respective ownership share.

Fuel Supply

Wolf Creek has on hand or under contract all of the uranium and conversion services needed to operate through March 2018 and approximately 37% of the uranium and conversion services needed after that date through September 2022. The owners also have under contract all of the uranium enrichment and fabrication services required to operate Wolf Creek through March 2027 and September 2025, respectively. All such agreements have been entered into in the ordinary course of business.

Operations and Regulation

Plant performance, including extended or unscheduled shutdowns of Wolf Creek, could cause us to purchase replacement power, rely more heavily on our other generating units and/or reduce amounts of power available for us to sell in the wholesale market. Plant performance also affects the degree of regulatory oversight and related costs.

Wolf Creek normally operates on an 18-month planned refueling and maintenance outage schedule. As authorized by our regulators, incremental maintenance costs of planned refueling and maintenance outages are deferred and amortized ratably over the period between planned refueling and maintenance outages. In early 2015, Wolf Creek underwent a planned refueling and maintenance outage. Our share of the outage costs were approximately $31.9 million. The next refueling and maintenance outage is planned for the fall of 2016.

The NRC evaluates, monitors and rates various inspection findings and performance indicators for Wolf Creek based on safety significance. Although not expected, the NRC could impose an unscheduled plant shutdown due to security or safety concerns. Those concerns need not be related to Wolf Creek specifically, but could be due to concerns about nuclear power generally or circumstances at other nuclear plants in which we have no ownership.

See Note 13 of the Notes to Consolidated Financial Statements, “Commitments and Contingencies,” for additional information regarding our nuclear operations.

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Wind Generation

Wind is our primary source of renewable energy. As of December 31, 2015, we owned approximately 149 MW of designed installed wind capability and had under contract the purchase of wind energy produced from approximately 1,314 MW of designed installed wind capability. Of the 1,314 MW under contract, 914 MW are currently in operation and approximately 400 MW are associated with agreements that are scheduled to deliver power beginning in early 2017. We have begun constructing a wind generating facility that is expected to have a designed installed capability of approximately 280 MW and is scheduled to begin delivering power in early 2017.

Other Fuel Matters

The table below provides our weighted average cost of fuel, including transportation costs.



	2015		2014		2013
Per MMBtu:
Nuclear	$	0.66	$	0.66	$	0.75
Coal	1.77		1.80		1.82
Natural gas	3.64		5.71		4.41
Diesel	15.55		21.31		22.89
All generating stations	1.74		1.90		1.91

Per MWh Generation:
Nuclear	$	6.72	$	6.79	$	7.86
Coal	19.78		20.04		20.26
Natural gas/diesel	37.16		62.84		46.38
All generating stations	18.44		20.27		20.45

Our wind production has no associated fuel costs and is, therefore, not included in the table above.

Purchased Power

In addition to generating electricity, we also purchase power. Factors that cause us to purchase power include contractual arrangements, planned and unscheduled outages at our generating plants, favorable wholesale energy prices compared to our costs of production, weather conditions and other factors. In 2015, purchased power comprised approximately 28% of our total fuel and purchased power expense. Our weighted average cost of purchased power per Megawatt hour (MWh) was $27.28 in 2015, $37.26 in 2014 and $33.63 in 2013.

Transmission

Regional Transmission Organization

The Federal Energy Regulatory Commission (FERC) requires owners of regulated transmission assets to allow third parties nondiscriminatory access to their transmission systems. We are a member of the SPP RTO and transferred the functional control of our transmission system, including the approval of transmission service, to the SPP. The SPP coordinates the operation of our transmission system within an interconnected transmission system that covers all or portions of 14 states. The SPP collects revenues for the use of each transmission owner’s transmission system. Transmission customers transmit power purchased and generated for sale or bought for resale in the wholesale market throughout the entire SPP system. Transmission capacity is sold on a first come/first served non-discriminatory basis. All transmission customers are charged rates applicable to the transmission system in the zone where energy is delivered, including transmission customers that may sell power inside our certificated service territory. The SPP then distributes as revenue to transmission owners the amounts it collects from transmission users less an amount it retains to cover administrative expenses.

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Southwest Power Pool Integrated Market

The SPP launched their new Integrated Marketplace (IM) in March 2014. The IM is similar to organized power markets currently operating in other RTOs. The IM impacts how we commit and sell the output from our generation facilities and buy power to meet the needs of our customers. The SPP has the authority to start and stop generating units participating in the market and selects the lowest cost resource mix to meet the needs of the various SPP customers while ensuring reliable operations of the transmission system.

Transmission Investments

We own a 50% interest in Prairie Wind Transmission, LLC (Prairie Wind), which is a joint venture between us and Electric Transmission America, LLC, which itself is a joint venture between affiliates of American Electric Power Company, Inc. and Berkshire Hathaway Energy Company. In 2014, Prairie Wind completed construction on, and energized, a 108 mile 345 kV double-circuit transmission line that is now being used to provide transmission service in the SPP.

In 2011, the FERC issued Order No. 1000, which revised the FERC’s existing regulations governing the process for planning enhancements and expansions of the electric transmission grid, along with the corresponding process for allocating the costs of such expansions. Among other things, Order No. 1000 sets forth a framework pursuant to which certain transmission projects that are approved by the RTOs become subject to a competitive bidding process whereby qualified entities can build and own the transmission facilities, even if the entities are not located in the service territory covered by the transmission facilities. This process is complicated, and is governed by Order No. 1000 and the tariff each RTO has with the FERC. In addition, notwithstanding the competitive processes created by Order No. 1000, incumbent utilities maintain a right of first refusal for certain transmission projects, depending on, among other things, the date by which the projects must be completed, the size of the projects and whether the incumbent utilities have pre-existing facilities that are being impacted by the projects.

We are actively participating in transmission planning activities and implementation of Order No. 1000 in the SPP and the Midcontinent Independent System Operator, Inc. We believe we have opportunities to develop transmission infrastructure, including projects pursuant to which we, as the incumbent, have a right of first refusal and those projects that are subject to the Order No. 1000 competitive processes. However, due in part to the long-term nature of transmission planning activities, the uncertainty surrounding the implementation of the Clean Power Plan (CPP) and its impact on the region’s generating fleet and the infancy of implementation of Order No. 1000, we are unable to predict the impact of Order No. 1000. Accordingly, in our forecasted capital expenditure table, there are no dollars of investment associated with Order No. 1000 projects.

Regulation and Our Prices

Kansas law gives the Kansas Corporation Commission (KCC) general regulatory authority over our retail prices, extensions and abandonments of service and facilities, the classification of accounts, the issuance of some securities and various other matters. We are also subject to the jurisdiction of FERC, which has authority over wholesale electricity sales, including prices, the transmission of electric power and the issuance of some securities. We are subject to the jurisdiction of the NRC for nuclear plant operations and safety. Regulatory authorities have established various methods permitting adjustments to our prices for the recovery of costs. For portions of our cost of service, regulators allow us to adjust our prices periodically through the application of a formula that tracks changes in our costs, which reduces the time between making expenditures or investments and reflecting them in the prices we charge customers. However, for the remaining portions of our cost of service, we must file a general rate review, which lengthens the period of time between when we make and recover expenditures and a return on our investments. See Note 3 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation,” for information regarding our rate proceedings with the KCC and FERC.

Environmental Matters

We are subject to various federal, state and local environmental laws and regulations. Environmental laws and regulations affecting our operations are overlapping, complex, subject to changes, have become more stringent over time and are expensive to implement. Such laws and regulations relate primarily to air quality, water quality, the use of water and the handling, disposal and clean-up of hazardous and non-hazardous substances and wastes, including coal combustion byproducts (CCBs). These laws and regulations oftentimes require a lengthy and complex process for obtaining licenses, permits and approvals from governmental agencies for new, existing or modified facilities. If we fail to comply with such laws, regulations and permits, or fail to obtain and maintain necessary permits, we could be fined or otherwise sanctioned by regulators, and such fines or the cost of sanctions may not be recoverable in our prices. We have incurred and will continue to incur significant capital and other expenditures to comply with environmental laws and regulations.

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Historically, we were permitted to recover certain of the costs associated with environmental projects through an environmental cost recovery rider, which, in general, allowed us to annually file with the KCC to adjust our prices for qualifying environmental improvements. In connection with the 2015 state general rate review, we agreed to no longer make annual filings with the KCC to adjust our prices to include costs associated with investments in air quality control equipment made during the prior year. The existing balance of costs associated with these investments were rolled into base prices. In the future, we will need to seek approval from the KCC for individual projects.

See “Item 1A. Risk Factors” and Notes 3 and 13 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation - KCC Proceedings - Environmental Costs” and “Commitments and Contingencies - Environmental Matters,” respectively, for more information regarding environmental trends, risks and laws and regulations.

Renewable Energy Standard

In May 2015, Kansas repealed a state mandate to maintain a minimum amount of renewable energy sources, effective January 1, 2016.

Safety and Health Regulation

The safety and health of our employees is vital to our business. We are subject to a number of federal and state laws and regulations, including the Occupational Safety and Health Act of 1970. We have measures in place to promote the safety and health of our employees and to monitor our compliance with such laws and regulations.

Information Technology

We rely upon information technology networks and systems to process, transmit and store electronic information, and to manage or support a variety of business processes and activities, including the generation, transmission and distribution of electricity, supply chain functions and the invoicing and collection of payments from our customers. These networks and systems are in some cases owned or managed by third-party service providers. Cybersecurity breaches, criminal activity, terrorist attacks and other disruptions to our information technology infrastructure, including infrastructure owned by third-parties we utilize, could interfere with our operations, could expose us or our customers or employees to a risk of loss and could expose us to liability or regulatory penalties or cause us reputational damage or other harm to our business. We have taken measures to secure our network and systems, but such measures may not be sufficient, especially due to the increasing sophistication of cyberattacks. See “Item 1A. Risk Factors” for additional information.

SEASONALITY

Our electricity sales and revenues are seasonal, with the third quarter typically accounting for the greatest of each. Our electricity sales are impacted by weather conditions, the economy of our service territory and other factors affecting customers’ demand for electricity.

EMPLOYEES

As of February 17, 2016, we had 2,330 employees, 1,235 of which were covered by a contract with Locals 304 and 1523 of the International Brotherhood of Electrical Workers that extends through June 30, 2017.

ACCESS TO COMPANY INFORMATION

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K are available free of charge either on our Internet website at www.westarenergy.com or through requests addressed to our investor relations department. These reports are available as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. The information contained on our Internet website is not part of this document.

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EXECUTIVE OFFICERS OF THE COMPANY



Name	Age	Present Office	Other Offices or Positions Held During the Past Five Years

Mark A. Ruelle	54	Director, President and Chief Executive Officer (since August 2011)	Westar Energy, Inc. Director, President and Chief Financial Officer (May 2011 to July 2011) Executive Vice President and Chief Financial Officer (January 2003 to April 2011)
Bruce A. Akin	51	Senior Vice President, Power Delivery (since January 2015)	Westar Energy, Inc. Vice President, Power Delivery (February 2012 to December 2014) Vice President, Operations Strategy and Support (July 2007 to February 2012)
Jerl L. Banning	55	Senior Vice President, Operations Support and Administration (since January 2015)	Westar Energy, Inc. Vice President, Human Resources and IT (January 2014 to December 2014) Vice President, Human Resources (February 2010 to December 2013)
John T. Bridson	46	Senior Vice President, Generation and Marketing (since January 2015)	Westar Energy, Inc. Vice President, Generation (February 2011 to December 2014) Executive Director, Generation (May 2010 to February 2011)
Gregory A. Greenwood	50	Senior Vice President, Strategy (since August 2011)	Westar Energy, Inc. Vice President, Major Construction Projects (December 2009 to July 2011)
Anthony D. Somma	52	Senior Vice President, Chief Financial Officer and Treasurer (since August 2011)	Westar Energy, Inc. Vice President, Treasurer (February 2009 to July 2011)
Larry D. Irick	59	Vice President, General Counsel and Corporate Secretary (since February 2003)
Kevin L. Kongs	53	Vice President, Controller (since November 2013)	Westar Energy, Inc. Assistant Controller (October 2006 to November 2013)

Executive officers serve at the pleasure of the board of directors. There are no family relationships among any of the executive officers, nor any arrangements or understandings between any executive officer and other persons pursuant to which he was appointed as an executive officer.

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ITEM 1A. RISK FACTORS

We operate in market and regulatory environments that involve significant risks, many of which are beyond our control. In addition to other information in this Form 10-K, including “Item 1. Business” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and in other documents we file with the SEC from time to time, the following factors may affect our results of operations, our cash flows and the value of our equity and debt securities. These factors may cause results to differ materially from those expressed in any forward-looking statements made by us or on our behalf. The factors listed below are not intended to be an exhaustive discussion of all such risks, and the statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC.

Weather conditions, including mild and severe weather, may adversely impact our consolidated financial results.

Weather conditions directly influence the demand for electricity. Our customers use electricity for heating in winter months and cooling in summer months. Because of air conditioning demand, typically we produce our highest revenues in the third quarter. Milder temperatures reduce demand for electricity and have a corresponding impact on our revenues. Unusually mild weather in the future could adversely affect our consolidated financial results.

In addition, severe weather conditions can produce storms that can inflict extensive damage to our equipment and facilities, which can require us to incur additional operating and maintenance expense and additional capital expenditures. Our prices may not always be adjusted timely or adequately to reflect these higher costs. Additionally, because many of our power plants use water for cooling, persistent or severe drought conditions could result in limited power production. High water conditions can also impair planned deliveries of fuel to our plants.

Our prices are subject to regulatory review and may not prove adequate to recover our costs and provide a fair return.

We must obtain from state and federal regulators the authority to establish terms and prices for our services. The KCC and, for most of our wholesale customers, FERC, use a cost-of-service approach that takes into account operating expenses, fixed obligations and recovery of and return on capital investments. Using this approach, the KCC and FERC set prices at levels calculated to recover such costs and a permitted return on investment. Except for wholesale transactions for which the price is not so regulated, and except to the extent the KCC and FERC permit us to modify our prices through the application of a formula that tracks changes in certain of our costs, our prices generally remain fixed until changed following a rate review. Further, the adjustments may be modified, limited or eliminated by regulatory or legislative actions. We may apply to change our prices or intervening parties may request that our prices be reviewed for possible adjustment.

Rate proceedings through which our prices and terms of service are determined typically involve numerous parties including electricity consumers, consumer advocates and governmental entities, some of whom take positions adverse to us. In addition, regulators’ decisions may be appealed to the courts by us or other parties to the proceedings. These factors may lead to uncertainty and delays in obtaining or implementing changes to our prices or terms of service. There can be no assurance that our regulators will find all of our costs to have been prudently incurred. A finding that costs have been imprudently incurred can lead to disallowance of recovery for those costs. Further, the prices approved by the applicable regulatory body may not be sufficient for us to recover our costs and to provide for an adequate return on and of capital investments.

We cannot predict the outcome of any rate review or the actions of our regulators. The outcome of rate proceedings, or delays in implementing price changes to reflect changes in our costs, could have a material effect on our consolidated financial results.

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Our costs of compliance with environmental laws and regulations, including those relating to GHG emissions, are significant, and the future costs of compliance with environmental laws and regulations could adversely impact our operations and consolidated financial results.

We are subject to extensive federal, state and local environmental laws and regulations relating to air quality, water quality, the use of water, the handling, disposal and clean-up of hazardous and non-hazardous substances and wastes, natural resources and health and safety. Compliance with these legal requirements, which change frequently and have tended to become more restrictive, requires us to commit significant capital and operating resources toward permitting, emission fees, environmental monitoring, installation and operation of air and water quality control equipment and purchases of air emission allowances and/or offsets. These laws and regulations oftentimes require a lengthy and complex process for obtaining licenses, permits and approvals from governmental agencies for new, existing or modified facilities. If we fail to comply with such laws, regulations and permits, or fail to obtain and maintain necessary permits, we could be fined or otherwise sanctioned by regulators, and such fines or the cost of sanctions may not be recoverable in our prices.

Costs of compliance with environmental laws and regulations or fines or penalties resulting from non-compliance, if not recovered in our prices, could adversely impact our operations and/or consolidated financial results, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated or the number and types of assets we operate increases. We cannot estimate our compliance costs or any possible fines or penalties with certainty, or the degree to which such costs might be recovered in our prices, due to our inability to predict the requirements and timing of implementation of environmental rules or regulations. See “Item 1. Business - Environmental Matters,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Executive Summary-Current Trends and Uncertainties-Environmental Regulation” and Notes 3 and 13 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation - KCC Proceedings - Environmental Costs” and “Commitments and Contingencies - Environmental Matters,” respectively, for additional information.

In addition, we combust large amounts of fossil fuels as we produce electricity. This results in significant emissions of carbon dioxide (CO₂) and other GHGs through the operation of our power plants. Federal legislation regulates the emission of GHGs and numerous states and regions have adopted programs to stabilize or reduce GHG emissions. The Environmental Protection Agency (EPA) regulates GHGs under the Clean Air Act. In October 2015, the EPA published a rule establishing new source performance standards that limit CO₂ emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per MWh depending on various characteristics of the units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate CO₂ emissions from existing power plants. The standards for existing plants are known as the CPP. Under the CPP, interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates must be achieved by 2030. Legal challenges to the CPP were filed by groups of states and industry members, and in February 2016 the U.S. Supreme Court temporarily stayed implementation of the CPP. See Note 13 of the Notes to Consolidated Financial Statements, “Commitments and Contingencies-Environmental Matters” for additional information. We believe these rules, if implemented, could have a material impact on our operations, future generation plants and/or results of operations.

Further, in the course of operating our coal generation plants, we produce CCBs, including fly ash, gypsum and bottom ash, which we must handle, recycle, process or dispose of. We historically have recycled some of our ash production, principally by selling to the aggregate industry. The EPA published a rule to regulate CCBs in April 2015, which will require additional CCB handling, processing and storage equipment and potential closure of certain ash disposal areas. See Note 13 of the Notes to Consolidated Financial Statements, “Commitments and Contingencies-Environmental Matters” for additional information. The impact of this rule on our operations and consolidated financial results could be material.

We could be subject to penalties as a result of mandatory reliability standards, which could adversely affect our consolidated financial results.

As a result of the Energy Policy Act of 2005, owners and operators of the bulk power transmission system, including Westar Energy and KGE, are subject to mandatory reliability standards promulgated by the North American Electric Reliability Corporation and enforced by FERC. If we were found to be out of compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which we might not be able to recover in the prices we charge our customers. This could have a material adverse effect on our consolidated financial results.

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Adverse economic conditions could adversely impact our operations and consolidated financial results.

Our operations are impacted by economic conditions. Adverse economic conditions, including a prolonged recession or capital market disruptions, may:


•	reduce demand for our service;


•	increase delinquencies or non-payment by customers;


•	adversely impact the financial condition of suppliers, which may in turn limit our access to inventory, including coal and natural gas, or capital equipment or increase our costs; and


•	increase deductibles and premiums and result in more restrictive policy terms under insurance policies regarding risks we typically insure against, or make insurance claims more difficult to collect.

A number of commercial and industrial customers have geographically dispersed facilities, and localized factors, including economic conditions, governmental or other incentives and other factors that influence customer operating or capital expenses, which may cause these customers to curtail or eliminate operations at facilities in our service territory and move them to other facilities with competitive advantages. In addition, unexpectedly strong economic conditions can result in increased costs and shortages. Any of the aforementioned events, and others we may not be able to identify, could have an adverse impact on our consolidated financial results.

We are exposed to various risks associated with the ownership and operation of Wolf Creek, any of which could adversely impact our consolidated financial results.

Through KGE’s ownership interest in Wolf Creek, we are subject to the risks of nuclear generation, which include:


•	the risks associated with storing, handling and disposing of radioactive materials and the current lack of a long-term off-site disposal solution for radioactive materials;


•	limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations;


•	uncertainties with respect to the technological and financial aspects of decommissioning Wolf Creek at the end of its life; and


•	costs of measures associated with public safety.

The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements enacted by the NRC could necessitate substantial capital expenditures at Wolf Creek.

An incident at Wolf Creek could have a material impact on our consolidated financial results. Furthermore, the non-compliance of other nuclear facilities operators with applicable regulations or the occurrence of a serious nuclear incident at other facilities anywhere in the world could result in increased regulation of the industry as a whole, which could in turn increase Wolf Creek’s compliance costs and impact our consolidated financial results. Such events could also result in a shutdown of Wolf Creek.

Significant decisions about capital investments are based on forecasts of long-term demand for energy incorporating assumptions about multiple, uncertain factors. Our actual experience may differ significantly from our assumptions, which may adversely impact our consolidated financial results.

We attempt to forecast demand to determine the timing and adequacy of our energy and energy delivery resources. Long-term forecasts involve risks because they rely on assumptions we make concerning uncertain factors including weather, technological change, environmental and other regulatory requirements, economic conditions, social pressures and the responsiveness of customers’ electricity demand to conservation measures and prices. Both actual future demand and our ability to satisfy such demand depend on these and other factors and may vary materially from our forecasts. If our actual experience varies significantly from our forecasts, our consolidated financial results may be adversely impacted.

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Our planned capital investment for the next few years is large in relation to our size, subjecting us to significant risks.

Our anticipated capital expenditures for 2016 through 2018 are approximately $2.7 billion. In addition to risks discussed above associated with recovering capital investments through our prices, and risks associated with our reliance on the capital markets and short-term credit to fund those investments, our capital expenditure program poses risks, including, but not necessarily limited to:


•	shortages, disruption in the delivery and inconsistent quality of equipment, materials and labor;


•	contractor or supplier non-performance;


•	delays in or failure to receive necessary permits, approvals and other regulatory authorizations;


•	impacts of new and existing laws and regulations, including environmental and health and safety laws, regulations and permit requirements;


•	adverse weather;


•	unforeseen engineering problems or changes in project design or scope;


•	environmental and geological conditions; and


•	unanticipated cost increases with respect to labor or materials, including basic commodities needed for our infrastructure such as steel, copper and aluminum.

These and other factors, or any combination of them, could cause us to defer or limit our capital expenditure program and could adversely impact our consolidated financial results.

Our ability to fund our capital expenditures and meet our working capital and liquidity needs may be limited by conditions in the bank and capital markets, by our credit ratings or the market price of Westar Energy’s common stock. Further, capital market conditions can cause fluctuations in the values of assets set aside for employee benefit obligations and the Wolf Creek nuclear decommissioning trust (NDT) and may increase our funding requirements related to these obligations.

To fund our capital expenditures and for working capital and liquidity, we rely on access to capital markets and to short-term credit. Disruption in capital markets, deterioration in the financial condition of the financial institutions on which we rely, any credit rating downgrade or any decrease in the market price of Westar Energy’s common stock may make capital more difficult and costly for us to obtain, may restrict liquidity available to us, may require us to defer or limit capital investments or impact operations or may reduce the value of our financial assets. These could adversely impact our business and consolidated financial results, including our ability to pay dividends and to make investments or undertake programs necessary to meet regulatory mandates and customer demand.

Further, we have significant future financial obligations with respect to employee benefit obligations and the Wolf Creek NDT. The value of the assets needed to meet those obligations are subject to market fluctuations and will yield uncertain returns, which may fall below our expectations for meeting our obligations. Additionally, inflation and changes in interest rates impact the value of future liabilities. In general, when interest rates decline, the value of future liabilities increase. While the KCC allows us to implement a regulatory accounting mechanism to track certain of our employee benefit plan expenses, this mechanism does not allow us to make automatic price adjustments. Only in future rate proceedings may we be allowed to adjust our prices to reflect changes in our funding requirements. Further, the tracking mechanism for these benefit plan expenses is part of our overall rate structure, and as such, it is subject to KCC review and may be modified, limited or eliminated in the future. If these assets are not managed successfully, our consolidated financial results and cash flows could be adversely impacted.

Physical and cybersecurity breaches, criminal activity, terrorist attacks and other disruptions to our facilities or our information technology infrastructure could interfere with our operations, expose us or our customers or employees to a risk of loss and expose us to liability or regulatory penalties or cause reputational damage and other harm to our business.

We rely upon information technology networks and systems to process, transmit and store electronic information, and to manage or support a variety of business processes and activities, including the generation, transmission and distribution of electricity, supply chain functions, and the invoicing and collection of payments from our customers. We also use information technology networks and systems to record, process and summarize financial information and results of operations for internal reporting purposes and to comply with financial reporting, legal and tax requirements. These networks and systems are in some cases owned or managed by third-party service providers. In the ordinary course of business, we collect, store and transmit sensitive data including operating information, proprietary business information belonging to us and third parties and personal information belonging to our customers and employees.

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Our information technology networks and infrastructure, as well as the networks and infrastructure belonging to third-party service providers that we utilize, may be vulnerable to damage, disruptions or shutdowns due to attacks or breaches by hackers or other unauthorized third parties; error or malfeasance by one or more of our or our service providers’ employees; software or hardware upgrades; additions or replacements; malicious software code; telecommunication failures; natural disasters or other catastrophic events. The occurrence of any of these events could, among other things, impact the reliability or safety of our generation, transmission and distribution systems; result in the erasure of data or render our equipment unusable; impact our ability to conduct business in the ordinary course; expose us and our customers, employees and vendors to a risk of loss or misuse of information; and result in legal claims or proceedings, liability or regulatory penalties against us, damage our reputation or otherwise harm our business. We can provide no assurance that we will identify and remedy all security or system vulnerabilities or that unauthorized access or error will be identified and remedied.

Additionally, we cannot predict the impact that any future information technology or terrorist attack may have on the energy industry in general. Our facilities could be direct targets or indirect casualties of such attacks. The effects of such attacks could include disruption to our generation, transmission and distribution systems or to the electrical grid in general, and could increase the cost of insurance coverage or result in a decline in the U.S. economy. Any of the foregoing could adversely impact our operations or financial results

Equipment failures and other events beyond our control may cause extended or unplanned plant outages, which may adversely impact our consolidated financial results.

The generation, distribution and transmission of electricity require the use of expensive and complicated equipment, much of which is aged, and all of which requires significant ongoing maintenance. Our power plants and equipment are subject to extended outages because of equipment failure, weather, transmission system disruption, operator error, contractor or subcontractor failure and other factors. In such events, we must either produce replacement power from our other plants, which may be less efficient or more expensive to operate, purchase power from others at unpredictable and potentially higher costs in order to meet our sales obligations, or suffer outages. Such events could also limit our ability to make sales to customers. Therefore, the occurrence of extended or unplanned outages could adversely affect our consolidated financial results.

Our regulated business model may be threatened by technological advancements that could adversely affect our financial condition and results of operations.

Significant technological advancements are taking place in the electric industry, including advancements related to self-generation and distributed energy technologies such as fuel cells, micro turbines, wind turbines and solar cells, as well as related to the storage of energy produced by these systems. Adoption of these technologies may increase because of advancements or government subsidies reducing the cost of generating or storing electricity through these technologies to a level that is competitive with our current methods of generating electricity. There is also a perception that generating or storing electricity through these technologies is more environmentally friendly than generating electricity with fossil fuels. Increased adoption of these technologies could reduce electricity demand and the pool of customers from whom fixed costs are recovered, resulting in under recovery of our fixed costs. Increased self-generation and the related use of net energy metering, which allows self-generating customers to receive bill credits for surplus power, could put upward price pressure on our remaining customers. If we were unable to adjust our prices to reflect reduced electricity demand and increased self-generation and net energy metering, our financial condition and results of operations could be adversely affected.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 2. PROPERTIES



							Unit Capability (MW) By Owner (a)
Name		Location	Unit No.		Year Installed	Principal Fuel	Westar Energy	KGE	Total Company Generation	Renewable Purchased Power	Total Generation and Renewable Purchased Power
Renewable Generation:
	Central Plains	Wichita County, Kansas		(a)	2009	Wind	99	—	99	—	99
	Flat Ridge	Barber County, Kansas		(a)	2009	Wind	50	—	50	50	100
	Cedar Bluff	Ness & Trego Counties, Kansas		(a)	2015	Wind	—	—	—	199	199
	Ironwood	Ford County, Kansas		(a)	2012	Wind	—	—	—	168	168
	Kay Wind	Kay County, Kansas		(a)	2015	Wind	—	—	—	200	200
	Meridian Way	Cloud County, Kansas		(a)	2008	Wind	—	—	—	96	96
	Post Rock	Ellsworth & Lincoln Counties, Kansas		(a)	2012	Wind	—	—	—	201	201
	Rolling Meadows	Shawnee County, Kansas			2010	Landfill Gas	—	—	—	6	6
Nuclear:
	Wolf Creek Generating Station (47%):	Burlington, Kansas	1	(b)	1985	Uranium	—	551	551	—	551
Coal:
	Jeffrey Energy Center (92%):	St. Marys, Kansas
	Steam Turbines		1	(b)	1978	Coal	524	146	670	—	670
			2	(b)	1980	Coal	509	142	651	—	651
			3	(b)	1983	Coal	512	142	654	—	654
	La Cygne Station (50%):	La Cygne, Kansas
	Steam Turbines		1	(b)	1973	Coal	—	368	368	—	368
			2	(c)	1977	Coal	—	331	331	—	331
	Lawrence Energy Center:	Lawrence, Kansas
	Steam Turbines		4		1960	Coal	104	—	104	—	104
			5		1971	Coal	370	—	370	—	370
	Tecumseh Energy Center:	Tecumseh, Kansas
	Steam Turbines		7		1957	Coal	65	—	65	—	65
Gas and Diesel:
	Emporia Energy Center:	Emporia, Kansas
	Combustion Turbines		1		2008	Gas	45	—	45	—	45
			2		2008	Gas	44	—	44	—	44
			3		2008	Gas	43	—	43	—	43
			4		2008	Gas	44	—	44	—	44
			5		2008	Gas	158	—	158	—	158
			6		2009	Gas	155	—	155	—	155
			7		2009	Gas	156	—	156	—	156
	Gordon Evans Energy Center:	Colwich, Kansas
	Steam Turbines		1		1961	Gas	—	153	153	—	153
			2		1967	Gas	—	370	370	—	370
	Combustion Turbines		1		2000	Gas	73	—	73	—	73
			2		2000	Gas	71	—	71	—	71
			3		2001	Gas	148	—	148	—	148
	Hutchinson Energy Center:	Hutchinson, Kansas
	Combustion Turbines		1		1974	Gas	56	—	56	—	56
			2		1974	Gas	52	—	52	—	52
			3		1974	Gas	57	—	57	—	57
			4		1975	Diesel	70	—	70	—	70
	Murray Gill Energy Center:	Wichita, Kansas
	Steam Turbines		3		1956	Gas	—	104	104	—	104
			4		1959	Gas	—	86	86	—	86
	Spring Creek Energy Center:	Edmond, Oklahoma
	Combustion Turbines		1		2001	Gas	69	—	69	—	69
			2		2001	Gas	69	—	69	—	69
			3		2001	Gas	67	—	67	—	67
			4		2001	Gas	68	—	68	—	68
	State Line (40%):	Joplin, Missouri
	Combined Cycle		2-1	(b)	2001	Gas	62	—	62	—	62
			2-2	(b)	2001	Gas	64	—	64	—	64
			2-3	(b)	2001	Gas	70	—	70	—	70
Total							3,874	2,393	6,267	920	7,187
	(a) Capability (except for wind generating facilities) represents accredited net generating capacity approved by the SPP. Capability for our wind generating facilities represents the installed design capacity. Due to the intermittent nature of wind generation, these facilities are associated with a total of 152 MW of accredited generating capacity.
	(b) Westar Energy jointly owns State Line (40%) while KGE jointly owns La Cygne unit 1 (50%) and Wolf Creek (47%). We jointly own and consolidate as a VIE 92% of JEC. Unit capacity amounts reflect our ownership and leased percentages only.
	(c) In 1987, KGE entered into a sale-leaseback transaction involving its 50% interest in the La Cygne unit 2. We consolidate the leasing entity as a VIE as discussed in Note 17 of the Notes to Consolidated Financial Statements, “Variable Interest Entities.”

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We own and have in service approximately 6,400 miles of transmission lines, approximately 24,000 miles of overhead distribution lines and approximately 4,900 miles of underground distribution lines.

Substantially all of our utility properties are encumbered by first priority mortgages pursuant to which bonds have been issued and are outstanding.

In 2015, Westar retired three older, smaller generating units at Lawrence Energy Center, Tecumseh Energy Center, and Hutchinson Energy Center with a combined capability of 354 MW.

ITEM 3. LEGAL PROCEEDINGS

Information on legal proceedings is set forth in Notes 3, 13 and 15 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation,” “Commitments and Contingencies” and “Legal Proceedings,” respectively, which are incorporated herein by reference.

ITEM 4. MINE SAFETY DISCLOSURES

Not Applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

STOCK TRADING

Westar Energy’s common stock is listed on the New York Stock Exchange and traded under the ticker symbol WR. As of February 17, 2016, Westar Energy had 17,670 common shareholders of record. For information regarding quarterly common stock price ranges for 2015 and 2014, see Note 19 of the Notes to Consolidated Financial Statements, “Quarterly Results (Unaudited).”

STOCK PERFORMANCE GRAPH

The following graph compares the performance of Westar Energy’s common stock during the period that began on December 31, 2010, and ended on December 31, 2015, to the performance of the Standard & Poor’s 500 Index (S&P 500) and the Standard & Poor’s Electric Utility Index (S&P Electric Utilities). The graph assumes a $100 investment in Westar Energy’s common stock and in each of the indices at the beginning of the period and a reinvestment of dividends paid on such investments throughout the period.



	Dec 2010	Dec 2011	Dec 2012	Dec 2013	Dec 2014	Dec 2015
Westar Energy, Inc.	$100	$120	$125	$147	$196	$209
S&P© 500	$100	$102	$118	$157	$178	$181
S&P© Electric Utilities	$100	$120	$121	$138	$177	$169

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DIVIDENDS

Holders of Westar Energy’s common stock are entitled to dividends when and as declared by Westar Energy’s board of directors.

Quarterly dividends on common stock have historically been paid on or about the first business day of January, April, July and October to shareholders of record as of or about the ninth day of the preceding month. Westar Energy’s board of directors reviews the common stock dividend policy from time to time. Among the factors the board of directors considers in determining Westar Energy’s dividend policy are earnings, cash flows, capitalization ratios, regulation, competition and financial loan covenants. In 2015, Westar Energy’s board of directors declared four quarterly dividends of $0.36 per share, reflecting an annual dividend of $1.44 per share, compared to four quarterly dividends of $0.35 per share in 2014, reflecting an annual dividend of $1.40 per share. On February 24, 2016, Westar Energy’s board of directors declared a quarterly dividend of $0.38 per share payable to shareholders on April 1, 2016. The indicated annual dividend rate is $1.52 per share.

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ITEM 6. SELECTED FINANCIAL DATA



	Year Ended December 31,
	2015		2014		2013		2012		2011
	(In Thousands)
Income Statement Data:
Total revenues	$	2,459,164	$	2,601,703	$	2,370,654	$	2,261,470	$	2,170,991
Net income	301,796		322,325		300,863		282,462		236,180
Net income attributable to Westar Energy, Inc.	291,929		313,259		292,520		273,530		229,269



	As of December 31,
	2015		2014		2013		2012		2011
	(In Thousands)
Balance Sheet Data:
Total assets	$	10,705,666	$	10,288,906	$	9,597,138	$	9,265,231	$	8,682,851
Long-term obligations (a)	3,379,219		3,433,320		3,495,292		3,124,831		2,818,030



	Year Ended December 31,
	2015		2014		2013		2012		2011
Common Stock Data:
Basic earnings per share available for common stock	$	2.11	$	2.40	$	2.29	$	2.15	$	1.95
Diluted earnings per share available for common stock	2.09		2.35		2.27		2.15		1.93
Dividends declared per share	1.44		1.40		1.36		1.32		1.28
Book value per share	25.87		25.02		23.88		22.89		22.03

Average equivalent common shares outstanding (in thousands) (b) (c) (d)	137,958		130,015		127,463		126,712		116,891

_______________


(a)	Includes long-term debt, net, current maturities of long-term debt, capital leases, long-term debt of VIEs, net and current maturities of long-term debt of VIEs. See Note 17 of the Notes to Consolidated Financial Statements, “Variable Interest Entities,” for additional information regarding VIEs.


(b)	In 2011, Westar Energy issued and sold approximately 13.6 million shares of common stock realizing proceeds of $294.9 million.


(c)	In 2014, Westar Energy issued and sold approximately 3.4 million shares of common stock realizing proceeds of $87.7 million.


(d)	In 2015, Westar Energy issued and sold approximately 9.7 million shares of common stock realizing proceeds of $258.0 million.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Certain matters discussed in Management’s Discussion and Analysis are “forward-looking statements.” The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we “believe,” “anticipate,” “target,” “expect,” “estimate,” “intend” and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. See “Forward-Looking Statements” above for additional information.

EXECUTIVE SUMMARY

Description of Business

We are the largest electric utility in Kansas. We produce, transmit and sell electricity at retail to approximately 700,000 customers in Kansas under the regulation of the KCC. We also supply electric energy at wholesale to municipalities and electric cooperatives in Kansas under the regulation of FERC. We have contracts for the sale or purchase of wholesale electricity with other utilities.

Earnings Per Share

Following is a summary of our net income and basic earnings per share (EPS) for the years ended December 31, 2015 and 2014.



	Year Ended December 31,
	2015		2014		Change
	(Dollars In Thousands, Except Per Share Amounts)
Net income attributable to Westar Energy, Inc.	$	291,929	$	313,259	$	(21,330	)
Earnings per common share, basic	2.11		2.40		(0.29		)

Net income attributed to common stock and basic EPS for the year ended December 31, 2015, decreased due primarily to a reduction in equity allowance for funds used during construction (AFUDC), a reduction in transmission revenues for our estimated refund obligation associated with a FERC proceeding and lower retail sales. See Note 3 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation - FERC Proceedings,” for a discussion of the FERC proceeding. Also, energy marketing margins were lower in 2015 than in 2014 due to greater volatility in 2014 of wholesale power prices. Partially offsetting these reductions was a decrease in operations and maintenance expense. EPS was further reduced in 2015 by approximately $0.13 due to the issuance of common stock from our forward sales transactions. See the discussion under “—Operating Results” below for additional information.

Key Factors Affecting Our Performance

The principal business, economic and other factors that affect our operations and financial performance include:


•	weather conditions;


•	the economy;


•	customer conservation efforts;


•	the performance, operation and maintenance of our electric generating facilities and network;


•	conditions in the fuel, wholesale electricity and energy markets;


•	rate and other regulations and costs of addressing public policy initiatives including environmental laws and regulations;


•	the availability of and our access to liquidity and capital resources; and


•	capital market conditions.

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Strategy

Retirement of Generating Units

In 2015, we retired three older, smaller generating units at Lawrence Energy Center, Tecumseh Energy Center and Hutchinson Energy Center with a combined capability of 354 megawatts.

Current Trends and Uncertainties

Environmental Regulation


•	further regulation of GHGs by the EPA, including regulations pursuant to the CPP, and future legislation that could be proposed by the U.S. Congress;


•	various proposed and expected regulations governing air emissions including those relating to National Ambient Air Quality Standards (particularly those relating to particulate matter, nitrogen oxide, ozone, CO and sulfur dioxide) and the Cross-State Air Pollution;


•	the definition of Waters of the United States for purposes of the Clean Water Act; and,


•	the regulation of CCB.

See Note 13 of the Notes to Consolidated Financial Statements, “Commitments and Contingencies—Environmental Matters,” for a discussion of environmental costs, laws, regulations and other contingencies.

Allowance for Funds Used During Construction

AFUDC represents the allowed cost of capital used to finance utility construction activity. We compute AFUDC by applying a composite rate to qualified construction work in progress (CWIP). We credit other income (for equity funds) and interest expense (for borrowed funds) for the amount of AFUDC capitalized as construction cost on the accompanying consolidated statements of income as follows:



	Year Ended December 31,
	2015			2014			2013
	(In Thousands)
Borrowed funds	$	3,505		$	12,044		$	11,706
Equity funds	2,075			17,029			14,143
Total	$	5,580		$	29,073		$	25,849
Average AFUDC Rates	2.7		%	6.7		%	4.8		%

We expect AFUDC for both borrowed funds and equity funds to fluctuate over the next several years as major projects within our capital expenditure program are being completed.

Interest Expense

We expect interest expense to increase over the next several years as we issue new debt securities to fund our capital expenditure program. We continue to believe this increase will be reflected in the prices we are permitted to charge customers, as cost of capital will be a component of future rate proceedings and is also recognized in some of the other rate adjustments we are permitted to make. In addition, short-term interest rates are extremely low by historical standards. We cannot predict to

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what extent these conditions will continue. See Note 9 of the Notes to Consolidated Financial Statements, “Long-Term Debt” for additional information regarding the issuance of long-term debt.

Outstanding Shares of Common Stock

We do not expect to issue additional shares of Westar Energy common stock in 2016, other than modest amounts under our dividend reinvestment plan and for the vesting of restricted share unit (RSU) awards. The shares previously priced through forward sales agreements were issued in 2015. See Note 16 of the Notes to Consolidated Financial Statements, “Common Stock,” for additional information regarding our share issuances.

Customer Growth and Usage

Residential customer additions have moderated since the 2008 recession and residential electricity demand has stabilized and is growing modestly. Overall retail sales have grown as well, and are approaching pre-recession levels. We believe that our overall retail sales growth will be modest driven by industrial demand and stable residential and commercial growth. In addition, with the numerous energy efficiency policy initiatives promulgated through federal, state and local governments, as well as industry initiatives, environmental regulations and the need to strengthen and modernize the grid, which will increase price pressure, we believe customers will continue to adopt more energy efficiency and conservation measures, which will slow or possibly suppress the growth of demand for electricity.

2016 Outlook

In 2016, we expect to maintain our current business strategy and regulatory approach. Assuming normal weather, we expect 2016 retail electricity sales to be in line with our projected retail customer growth of about 0.5%.

Absent increases in SPP transmission expense and property tax expense, which are increasing at a much higher rate than inflation and are offset with higher revenues pursuant to our regulatory mechanisms, we anticipate operating and maintenance and selling, general and administrative expenses to be relatively flat in 2016 as compared to 2015. To help fund our capital spending as provided under “—Future Cash Requirements” below, in 2016 we may issue long-term debt, and utilize short-term borrowings by issuing commercial paper until permanent financing is in place.

CRITICAL ACCOUNTING ESTIMATES

Our discussion and analysis of financial condition and results of operations are based on our consolidated financial statements, which have been prepared in conformity with Generally Accepted Accounting Principles (GAAP). Note 2 of the Notes to Consolidated Financial Statements, “Summary of Significant Accounting Policies,” contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions by management. The policies highlighted below have an impact on our reported results that may be material due to the levels of judgment and subjectivity necessary to account for uncertain matters or their susceptibility to change.

Regulatory Accounting

We apply accounting standards that recognize the economic effects of rate regulation. Accordingly, we have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in our prices. Regulatory liabilities represent probable future reductions in revenue or refunds to customers.

The deferral of costs as regulatory assets is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific regulatory orders, regulatory precedent and the current regulatory environment. If we deem it no longer probable that we would recover such costs, we would record a charge against income in the amount of the related regulatory assets.

As of December 31, 2015, we had recorded regulatory assets currently subject to recovery in future prices of approximately $860.9 million and regulatory liabilities of $292.8 million, as discussed in greater detail in Note 3 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation.”

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Pension and Post-retirement Benefit Plans Actuarial Assumptions

We and Wolf Creek calculate our pension benefit and post-retirement medical benefit obligations and related costs using actuarial concepts within the guidance provided by GAAP.

In accounting for our retirement plans and post-retirement benefits, we make assumptions regarding the valuation of benefit obligations and the performance of plan assets. The reported costs of our pension plans are impacted by estimates regarding earnings on plan assets, contributions to the plan, discount rates used to determine our projected benefit obligation and pension costs and employee demographics including age, life expectancy and compensation levels and employment periods. Changes in these assumptions result primarily in changes to regulatory assets, regulatory liabilities or the amount of related pension and post-retirement benefit liabilities reflected on our consolidated balance sheets. Such changes may also require cash contributions.

The following table shows the impact of a 0.5% change in our pension plan discount rate, salary scale and rate of return on plan assets.



Actuarial Assumption	Change in Assumption	Change in Projected Benefit Obligation (a)			Annual Change in Projected Pension Costs (a)
		(Dollars In Thousands)
Discount rate	0.5% decrease	$	87,042		$	8,008
	0.5% increase	(77,767		)	(7,254		)

Compensation	0.5% decrease	(17,147		)	(3,319		)
	0.5% increase	18,219			3,551

Rate of return on plan assets	0.5% decrease	—			3,930
	0.5% increase	—			(3,930		)

_______________


(a)	Increases or decreases due to changes in actuarial assumptions result primarily in changes to regulatory assets and liabilities.

The following table shows the impact of a 0.5% change in the discount rate and rate of return on plan assets and a 1% change in the annual medical trend on our post-retirement benefit plans.



Actuarial Assumption	Change in Assumption	Change in Projected Benefit Obligation (a)			Annual Change in Projected Post-retirement Costs (a)
		(Dollars In Thousands)
Discount rate	0.5% decrease	$	7,587		$	374
	0.5% increase	(7,081		)	(347		)

Rate of return on plan assets	0.5% decrease	—			570
	0.5% increase	—			(570		)

Annual medical trend	1.0% decrease	97			15
	1.0% increase	(95		)	(15		)

_______________


(a)	Increases or decreases due to changes in actuarial assumptions result primarily in changes to regulatory assets and liabilities.

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Revenue Recognition

We record revenue at the time we deliver electricity to customers. We determine the amounts delivered to individual customers through systematic monthly readings of customer meters. At the end of each month, we estimate how much electricity we have delivered since the prior meter reading and record the corresponding unbilled revenue.

Our unbilled revenue estimate is affected by factors including fluctuations in energy demand, weather, line losses and changes in the composition of customer classes. We recorded estimated unbilled revenue of $66.0 million as of December 31, 2015 and $61.0 million as of December 31, 2014.

Income Taxes

We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. We recognize the future tax benefits to the extent that realization of such benefits is more likely than not. We amortize deferred investment tax credits over the lives of the related properties as required by tax laws and regulatory practices. We recognize production tax credits in the year that electricity is generated to the extent that realization of such benefits is more likely than not.

We record deferred tax assets to the extent capital losses, operating losses or tax credits will be carried forward to future periods. However, when we believe based on available evidence that we do not, or will not, have sufficient future capital gains or taxable income in the appropriate taxing jurisdiction to realize the entire benefit during the applicable carryforward period, we record a valuation allowance against the deferred tax asset.

The application of income tax law is complex. Laws and regulations in this area are voluminous and often ambiguous. Accordingly, we must make judgments regarding income tax exposure. Interpretations of and guidance surrounding income tax laws and regulations change over time. As a result, changes in our judgments can materially affect amounts we recognize in our consolidated financial statements. See Note 10, “Taxes,” for additional detail on our accounting for income taxes.

Bonus Depreciation Extension

In December 2015, Congress passed and the President signed into law the “Protecting Americans from Tax Hikes (PATH) Act of 2015” which, among other things, extended bonus depreciation for an additional five-year period encompassing the years 2015 through 2019. Bonus depreciation provides for additional first-year tax depreciation allowance for qualifying property. As a result of the five-year extension in 2015, should we continue to fully utilize the depreciation deductions under bonus depreciation, certain tax credits provided by the State of Kansas related to investments in utility plant may not be realizable requiring us to record a valuation allowance. At this time, we expect to utilize bonus depreciation deductions to the extent necessary to fully utilize the aforementioned Kansas tax credits.

Asset Retirement Obligations

Legal Liability

We have recognized legal obligations associated with the disposal of long-lived assets that result from the acquisition, construction, development or normal operation of such assets. Concurrent with the recognition of the liability, the estimated cost of the asset retirement obligation (ARO) is capitalized and depreciated over the remaining life of the asset. We estimate our AROs based on the fair value of the AROs we incurred at the time the related long-lived assets were either acquired, placed in service or when regulations establishing the obligation became effective.

We initially recorded AROs at fair value for the estimated cost to decommission Wolf Creek (our 47% share), retire our wind generating facilities, dispose of asbestos insulating material at our power plants, remediate ash disposal ponds and dispose of polychlorinated biphenyl contaminated oil. In determining our AROs, we make assumptions regarding probable future disposal costs. A change in these assumptions could have a significant impact on the AROs reflected on our consolidated balance sheets.

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As of December 31, 2015 and 2014, we have recorded AROs of $275.3 million and $230.7 million, respectively. For additional information on our legal AROs, see Note 14 of the Notes to Consolidated Financial Statements, “Asset Retirement Obligations.”

Contingencies and Litigation

We and our subsidiaries are involved in various legal, environmental and regulatory proceedings, and we have estimated the probable cost for the resolution of these proceedings. These estimates are based on an analysis of potential results, assuming a combination of litigation and settlement strategies. It is possible that our future consolidated financial results could be materially affected by changes in our assumptions. See Notes 3, 13 and 15 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulations”, “Commitments and Contingencies” and “Legal Proceedings,” for additional information.

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OPERATING RESULTS

We evaluate operating results based on EPS. We have various classifications of revenues, defined as follows:

Retail: Sales of electricity to residential, commercial and industrial customers. Classification of customers as residential, commercial or industrial requires judgment and our classifications may be different from other companies. Assignment of tariffs is not dependent on classification. Other retail sales of electricity include lighting for public streets and highways, net of revenue subject to refund.

Wholesale: Sales of electricity to electric cooperatives, municipalities, other electric utilities and RTOs, the prices for which are either based on cost or prevailing market prices as prescribed by FERC authority. Revenues from these sales are either included in the retail energy cost adjustment or used in the determinations of base rates at the time of our next general rate review.

Transmission: Reflects transmission revenues, including those based on tariffs with the SPP.

Other: Miscellaneous electric revenues including ancillary service revenues and rent from electric property leased to others. This category also includes transactions unrelated to the production of our generating assets and fees we earn for services that we provide for third parties.

Electric utility revenues are impacted by things such as rate regulation, fuel costs, technology, customer behavior, the economy and competitive forces. Changing weather also affects the amount of electricity our customers use as electricity sales are seasonal. As a summer peaking utility, the third quarter typically accounts for our greatest electricity sales. Hot summer temperatures and cold winter temperatures prompt more demand, especially among residential and commercial customers, and to a lesser extent, industrial customers. Mild weather reduces customer demand. Our wholesale revenues are impacted by, among other factors, demand, cost and availability of fuel and purchased power, price volatility, available generation capacity, transmission availability and weather.

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2015 Compared to 2014

Below we discuss our operating results for the year ended December 31, 2015, compared to the results for the year ended December 31, 2014. Significant changes in results of operations shown in the table immediately below are further explained in the descriptions that follow.



	Year Ended December 31,
	2015			2014			Change			% Change
	(Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential	$	768,618		$	793,586		$	(24,968	)	(3.1	)
Commercial	712,400			727,964			(15,564		)	(2.1	)
Industrial	400,687			414,997			(14,310		)	(3.4	)
Other retail	(17,155		)	(24,180		)	7,025			29.1
Total Retail Revenues	1,864,550			1,912,367			(47,817		)	(2.5	)
Wholesale	318,371			392,730			(74,359		)	(18.9	)
Transmission	241,835			256,838			(15,003		)	(5.8	)
Other	34,408			39,768			(5,360		)	(13.5	)
Total Revenues	2,459,164			2,601,703			(142,539		)	(5.5	)
OPERATING EXPENSES:
Fuel and purchased power	561,065			705,450			(144,385		)	(20.5	)
SPP network transmission costs	229,043			218,924			10,119			4.6
Operating and maintenance	330,289			367,188			(36,899		)	(10.0	)
Depreciation and amortization	310,591			286,442			24,149			8.4
Selling, general and administrative	250,278			250,439			(161		)	(0.1	)
Taxes other than income tax	156,901			140,302			16,599			11.8
Total Operating Expenses	1,838,167			1,968,745			(130,578		)	(6.6	)
INCOME FROM OPERATIONS	620,997			632,958			(11,961		)	(1.9	)
OTHER INCOME (EXPENSE):
Investment earnings	7,799			10,622			(2,823		)	(26.6	)
Other income	19,438			31,522			(12,084		)	(38.3	)
Other expense	(17,636		)	(18,389		)	753			4.1
Total Other Income	9,601			23,755			(14,154		)	(59.6	)
Interest expense	176,802			183,118			(6,316		)	(3.4	)
INCOME BEFORE INCOME TAXES	453,796			473,595			(19,799		)	(4.2	)
Income tax expense	152,000			151,270			730			0.5
NET INCOME	301,796			322,325			(20,529		)	(6.4	)
Less: Net income attributable to noncontrolling interests	9,867			9,066			801			8.8
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	291,929		$	313,259		$	(21,330	)	(6.8	)
BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	2.11		$	2.40		$	(0.29	)	(12.1	)
DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	2.09		$	2.35		$	(0.26	)	(11.1	)

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Rate Review Agreement

Gross Margin

Fuel and purchased power costs fluctuate with electricity sales and unit costs. As permitted by regulators, we adjust our retail prices to reflect changes in the costs of fuel and purchased power. Fuel and purchased power costs for wholesale customers are recovered at prevailing market prices or based on a predetermined formula with a price adjustment approved by FERC. As a result, changes in fuel and purchased power costs are offset in revenues with minimal impact on net income. In addition, SPP network transmission costs fluctuate due primarily to investments by us and other members of the SPP for upgrades to the transmission grid within the SPP RTO. As with fuel and purchased power costs, changes in SPP network transmission costs are mostly reflected in the prices we charge customers with minimal impact on net income. For these reasons, we believe gross margin is useful for understanding and analyzing changes in our operating performance from one period to the next. We calculate gross margin as total revenues, including transmission revenues, less the sum of fuel and purchased power costs and amounts billed by the SPP for network transmission costs. Accordingly, gross margin reflects transmission revenues and costs on a net basis. The following table summarizes our gross margin for the years ended December 31, 2015 and 2014.



	Year Ended December 31,
	2015		2014		Change			% Change
	(Dollars In Thousands)
Revenues	$	2,459,164	$	2,601,703	$	(142,539	)	(5.5	)
Less: Fuel and purchased power expense	561,065		705,450		(144,385		)	(20.5	)
SPP network transmission costs	229,043		218,924		10,119			4.6
Gross Margin	$	1,669,056	$	1,677,329	$	(8,273	)	(0.5	)

The following table reflects changes in electricity sales for the years ended December 31, 2015 and 2014. No electricity sales are shown for transmission or other as they are not directly related to the amount of electricity we sell.



	Year Ended December 31,
	2015	2014	Change		% Change
	(Thousands of MWh)
ELECTRICITY SALES:
Residential	6,364	6,580	(216	)	(3.3	)
Commercial	7,500	7,521	(21	)	(0.3	)
Industrial	5,502	5,601	(99	)	(1.8	)
Other retail	84	86	(2	)	(2.3	)
Total Retail	19,450	19,788	(338	)	(1.7	)
Wholesale	8,492	9,544	(1,052	)	(11.0	)
Total	27,942	29,332	(1,390	)	(4.7	)

Gross margin decreased due primarily to an estimated $13.8 million transmission revenues refund obligation associated with a FERC proceeding. See Note 3 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation - FERC Proceedings,” for a discussion of this proceeding. Energy marketing margin decreased $11.2 million due to greater volatility in 2014 of wholesale power prices. Also contributing to the decrease in gross margin was lower retail electricity sales. The lower residential and commercial electric sales were due to warm winter weather. During 2015, there were approximately 19% fewer heating degree days compared to 2014. The lower industrial sales were due to a few of our larger customers who experienced weaker global demand for their products.

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Income from operations is the most directly comparable measure to our presentation of gross margin that is calculated and presented in accordance with GAAP in our consolidated statements of income. Our presentation of gross margin should not be considered in isolation or as a substitute for income from operations. Additionally, our presentation of gross margin may not be comparable to similarly titled measures reported by other companies. The following table reconciles income from operations with gross margin for the years ended December 31, 2015 and 2014.



	Year Ended December 31,
	2015		2014		Change			% Change
	(Dollars In Thousands)
Gross margin	$	1,669,056	$	1,677,329	$	(8,273	)	(0.5	)
Less: Operating and maintenance expense	330,289		367,188		(36,899		)	(10.0	)
Depreciation and amortization expense	310,591		286,442		24,149			8.4
Selling, general and administrative expense	250,278		250,439		(161		)	(0.1	)
Taxes other than income tax	156,901		140,302		16,599			11.8
Income from operations	$	620,997	$	632,958	$	(11,961	)	(1.9	)

Operating Expenses and Other Income and Expense Items



	Year Ended December 31,
	2015		2014		Change			% Change
	(Dollars in Thousands)
Operating and maintenance expense	$	330,289	$	367,188	$	(36,899	)	(10.0	)

Operating and maintenance expense decreased due principally to:


•	lower transmission and distribution operations and maintenance expense of $14.8 million due partially to focus on capital replacement for longer term grid resiliency;


•	lower costs at our coal fired plants of $10.5 million, which were principally the result of higher operating and maintenance costs incurred during a 2014 scheduled outage at JEC; and


•	lower costs at Wolf Creek of $10.3 million, which were principally the result of higher operating and maintenance costs incurred during a 2014 scheduled outage.



	Year Ended December 31,
	2015		2014		Change		% Change
	(Dollars in Thousands)
Depreciation and amortization expense	$	310,591	$	286,442	$	24,149	8.4

Depreciation and amortization expense increased due to additions at our power plants, including air quality controls, additions at Wolf Creek to enhance reliability and the addition of transmission facilities. Depreciation related to environmental equipment placed in-service at La Cygne, as approved by the KCC, was deferred until new retail prices became effective in late October 2015.



	Year Ended December 31,
	2015		2014		Change			% Change
	(Dollars in Thousands)
Selling, general and administrative expense	$	250,278	$	250,439	$	(161	)	(0.1	)

Selling, general and administrative expense decreased due primarily to a reduction of $4.2 million in amortization for previously deferred amounts with various energy efficiency programs; however, partially offsetting this decrease was higher labor and employee benefit costs of $5.1 million partially related to restructuring charges.

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	Year Ended December 31,
	2015		2014		Change		% Change
	(Dollars in Thousands)
Taxes other than income tax	$	156,901	$	140,302	$	16,599	11.8

Taxes other than income tax increased due primarily to an increase of $16.9 million in property tax expense. This increase is mostly offset in retail revenue.



	Year Ended December 31,
	2015		2014		Change			% Change
	(Dollars in Thousands)
Investment earnings	$	7,799	$	10,622	$	(2,823	)	(26.6	)

Investment earnings decreased due primarily to recording a $2.2 million lower gain on a trust to secure certain retirement benefit obligations.



	Year Ended December 31,
	2015		2014		Change			% Change
	(Dollars in Thousands)
Other income	$	19,438	$	31,522	$	(12,084	)	(38.3	)

Other income decreased due primarily to our having recorded about $15.0 million less in equity AFUDC due primarily to completion of major construction projects. The decrease was partially offset by our having recorded $2.7 million more in corporate-owned life insurance (COLI) benefits.



	Year Ended December 31,
	2015		2014		Change			% Change
	(Dollars in Thousands)
Interest expense	$	176,802	$	183,118	$	(6,316	)	(3.4	)

Interest expense decreased due primarily to a decrease in long-term interest expense of $14.7 million due to refinancing debt. However, partially offsetting this decrease was a reduction in debt AFUDC of $8.5 million primarily due to reduced CWIP.

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2014 Compared to 2013

Below we discuss our operating results for the year ended December 31, 2014, compared to the results for the year ended December 31, 2013. Significant changes in results of operations shown in the table immediately below are further explained in the descriptions that follow.



	Year Ended December 31,
	2014			2013			Change			% Change
	(Dollars In Thousands, Except Per Share Amounts)
REVENUES:
Residential	$	793,586		$	728,852		$	64,734		8.9
Commercial	727,964			667,106			60,858			9.1
Industrial	414,997			374,825			40,172			10.7
Other retail	(24,180		)	8,939			(33,119		)	(370.5	)
Total Retail Revenues	1,912,367			1,779,722			132,645			7.5
Wholesale	392,730			348,239			44,491			12.8
Transmission	256,838			210,281			46,557			22.1
Other	39,768			32,412			7,356			22.7
Total Revenues	2,601,703			2,370,654			231,049			9.7
OPERATING EXPENSES:
Fuel and purchased power	705,450			634,797			70,653			11.1
SPP network transmission costs	218,924			178,604			40,320			22.6
Operating and maintenance	367,188			359,060			8,128			2.3
Depreciation and amortization	286,442			272,593			13,849			5.1
Selling, general and administrative	250,439			224,133			26,306			11.7
Taxes other than income tax	140,302			122,282			18,020			14.7
Total Operating Expenses	1,968,745			1,791,469			177,276			9.9
INCOME FROM OPERATIONS	632,958			579,185			53,773			9.3
OTHER INCOME (EXPENSE):
Investment earnings	10,622			10,056			566			5.6
Other income	31,522			35,609			(4,087		)	(11.5	)
Other expense	(18,389		)	(18,099		)	(290		)	(1.6	)
Total Other Income (Expense)	23,755			27,566			(3,811		)	(13.8	)
Interest expense	183,118			182,167			951			0.5
INCOME BEFORE INCOME TAXES	473,595			424,584			49,011			11.5
Income tax expense	151,270			123,721			27,549			22.3
NET INCOME	322,325			300,863			21,462			7.1
Less: Net income attributable to noncontrolling interests	9,066			8,343			723			8.7
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY. INC.	$	313,259		$	292,520		$	20,739		7.1
BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	2.40		$	2.29		$	0.11		4.8
DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	2.35		$	2.27		$	0.08		3.5

Rate Review Agreement

In November 2013, the KCC issued an order allowing us to adjust our prices to include the additional investment in the La Cygne environmental upgrades, as discussed below, and to reflect cost reductions elsewhere. The new prices were expected to increase our annual retail revenues by approximately $30.7 million.

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Gross Margin

The following table summarizes our gross margin for the years ended December 31, 2014 and 2013.



	Year Ended December 31,
	2014		2013		Change		% Change
	(Dollars In Thousands)
Revenues	$	2,601,703	$	2,370,654	$	231,049	9.7
Less: Fuel and purchased power expense	705,450		634,797		70,653		11.1
SPP network transmission costs	218,924		178,604		40,320		22.6
Gross Margin	$	1,677,329	$	1,557,253	$	120,076	7.7

The following table reflects changes in electricity sales for the years ended December 31, 2014 and 2013. No electricity sales are shown for transmission or other as they are not directly related to the amount of electricity we sell.



	Year Ended December 31,
	2014	2013	Change	% Change
	(Thousands of MWh)
ELECTRICITY SALES:
Residential	6,580	6,523	57	0.9
Commercial	7,521	7,480	41	0.5
Industrial	5,601	5,407	194	3.6
Other retail	86	86	—	—
Total Retail	19,788	19,496	292	1.5
Wholesale	9,544	8,593	951	11.1
Total	29,332	28,089	1,243	4.4

Gross margin increased due primarily to higher retail revenues, principally the result of higher retail prices. Average retail prices were about 6% higher than 2013, resulting from recovery of investments we made in our transmission infrastructure and air quality controls at our power plants. Retail revenues were also impacted by more electricity sales resulting principally from increased sales to industrial customers.

The following table reconciles income from operations with gross margin for the years ended December 31, 2014 and 2013.



	Year Ended December 31,
	2014		2013		Change		% Change
	(Dollars In Thousands)
Gross margin	$	1,677,329	$	1,557,253	$	120,076	7.7
Less: Operating and maintenance expense	367,188		359,060		8,128		2.3
Depreciation and amortization expense	286,442		272,593		13,849		5.1
Selling, general and administrative expense	250,439		224,133		26,306		11.7
Taxes other than income tax	140,302		122,282		18,020		14.7
Income from operations	$	632,958	$	579,185	$	53,773	9.3

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Operating Expenses and Other Income and Expense Items



	Year Ended December 31,
	2014		2013		Change		% Change
	(Dollars in Thousands)
Operating and maintenance expense	$	367,188	$	359,060	$	8,128	2.3

Operating and maintenance expense increased due principally to:


•	a $6.4 million increase in operating and maintenance costs at our plants primarily for planned outages at our coal fired plants;


•	a $4.3 million increase in operating and maintenance costs to enhance reliability of our transmission systems; and,


•	an approximately $3.9 million increase in costs at Wolf Creek attributable primarily to a planned outage in the first and second quarters of 2014; however,


•	partially offsetting these increases was a $7.8 million decrease in amounts expensed for previously deferred storm costs.



	Year Ended December 31,
	2014		2013		Change		% Change
	(Dollars in Thousands)
Depreciation and amortization expense	$	286,442	$	272,593	$	13,849	5.1

Depreciation and amortization expense increased due to plant additions, including air quality controls, and transmission facilities as well as increased amortization related primarily to implementing new software systems.



	Year Ended December 31,
	2014		2013		Change		% Change
	(Dollars in Thousands)
Selling, general and administrative expense	$	250,439	$	224,133	$	26,306	11.7

Selling, general and administrative expense increased due primarily to:


•	higher labor and employee benefit costs of $10.6 million;


•	a $6.1 million increase in fees related primarily to implementing new software systems; and,


•	an increase in the allowance for uncollectible accounts of $2.7 million.



	Year Ended December 31,
	2014		2013		Change		% Change
	(Dollars in Thousands)
Taxes other than income tax	$	140,302	$	122,282	$	18,020	14.7

Taxes other than income tax increased due primarily to a $16.2 million increase in property taxes, which are offset in retail revenues.

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	Year Ended December 31,
	2014		2013		Change			% Change
	(Dollars in Thousands)
Other income	$	31,522	$	35,609	$	(4,087	)	(11.5	)

Other income decreased due primarily to our having recorded about $6.9 million less in COLI benefits. The decrease was partially offset by our having recorded $2.9 million more in equity AFUDC.



	Year Ended December 31,
	2014		2013		Change		% Change
	(Dollars in Thousands)
Income tax expense	$	151,270	$	123,721	$	27,549	22.3

Income tax expense increased due primarily to higher income before income taxes.

Financial Condition

A number of factors affected amounts recorded on our balance sheet as of December 31, 2015, compared to December 31, 2014.



	As of December 31,
	2015		2014		Change		% Change
	(Dollars in Thousands)
Fuel inventory and supplies	$	301,294	$	247,406	$	53,888	21.8

Coal inventory increased $44.3 million due to improved rail performance and due to reduced coal plant utilization. In addition, materials and supplies increased $10.9 million due primarily to improved substation reliability.



	As of December 31,
	2015		2014		Change		% Change
	(Dollars in Thousands)
Property, plant and equipment, net	$	8,524,902	$	8,162,908	$	361,994	4.4

Property, plant and equipment, net of accumulated depreciation, increased due primarily to plant additions for air quality controls, additional transmission facilities, additions for our wind energy project and revisions to our AROs.

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	As of December 31,
	2015		2014		Change			% Change
	(Dollars in Thousands)
Regulatory assets	$	860,918	$	859,778	$	1,140		0.1
Regulatory liabilities	292,811		343,485		(50,674		)	(14.8	)
Net regulatory assets	$	568,107	$	516,293	$	51,814		10.0

Total regulatory assets increased due primarily to the following items:


•	a $60.6 million increase in debt reacquisition costs related to the redemption of Westar Energy first mortgage bonds;


•	a $15.4 million increase in deferred depreciation expense and carrying costs related to our capital investment associated with environmental upgrades at La Cygne;


•	a $5.9 million increase in conditional AROs;


•	a $5.4 million increase in amounts deferred for Wolf Creek refueling and maintenance outages;


•	a $5.0 million increase in amounts deferred for property taxes; however,


•	partially offsetting these increases was an $81.8 million decrease in deferred employee benefit costs, due principally to an increase in the discount rates used to calculate our and Wolf Creek’s pension benefit obligations and the adoption of updated mortality tables; and


•	a $9.9 million decrease in amounts due from customers for future income taxes.

Total regulatory liabilities decreased due primarily to the following reasons:


•	a $34.4 million decrease in amounts collected but not yet spent to dispose of plant assets; and


•	a $20.6 million decrease in refund obligations related to amounts we have collected from our customers in excess of our actual cost of fuel and purchased power; however,


•	partially offsetting these decreases was a $16.7 million increase in pension and other post-retirement benefit costs.



	As of December 31,
	2015		2014		Change			% Change
	(Dollars in Thousands)
Short-term debt	$	250,300	$	257,600	$	(7,300	)	(2.8	)

Short-term debt decreased due to decreased issuances of commercial paper.



	As of December 31,
	2015		2014		Change			% Change
	(Dollars in Thousands)
Long-term debt, net	$	3,163,950	$	3,187,080	$	(23,130	)	(0.7	)

In 2015, Westar Energy issued $550.0 million in principal amount of first mortgage bonds. Proceeds of these issuances were used to retire $575.0 million in principal amount of Westar Energy first mortgage bonds. For more information on our long-term debt, see Note 9 of the Notes to Consolidated Financial Statements, “Long-term Debt.”

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	As of December 31,
	2015		2014		Change			% Change
	(Dollars in Thousands)
Current maturities of long-term debt of variable interest entities	$	28,309	$	27,933	$	376		1.3
Long-term debt of variable interest entities	138,097		166,565		(28,468		)	(17.1	)
Total long-term debt of variable interest entities	$	166,406	$	194,498	$	(28,092	)	(14.4	)

Total long-term debt of VIEs decreased due principally to the VIEs that hold the JEC and La Cygne leasehold interests having made principal payments totaling $27.9 million.



	As of December 31,
	2015		2014		Change		% Change
	(Dollars in Thousands)
Deferred income tax liabilities	$	1,591,430	$	1,445,851	$	145,579	10.1

Long-term deferred income tax liabilities increased due primarily to the use of bonus and accelerated depreciation methods during the year.



	As of December 31,
	2015		2014		Change			% Change
	(Dollars in Thousands)
Accrued employee benefits	$	462,304	$	532,622	$	(70,318	)	(13.2	)

Accrued employee benefits decreased due primarily to lower pension and post-retirement benefit obligations as a result of increases in the discount rates used to calculate our and Wolf Creek’s pension benefit obligations and the adoption of updated mortality tables.



	As of December 31,
	2015		2014		Change		% Change
	(Dollars in Thousands)
Asset retirement obligations	$	275,285	$	230,668	$	44,617	19.3

AROs increased due primarily to a new ARO of approximately $34.4 million as a result of the CCB regulation published by the EPA. See Note 13 of the Notes to Consolidated Financial Statements, “Commitments and Contingencies.” and Note 14 of the Notes to Consolidated Financial Statements, “Asset Retirement Obligations,” for additional information.

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LIQUIDITY AND CAPITAL RESOURCES

Overview

Available sources of funds to operate our business include internally generated cash, short-term borrowings under Westar Energy’s commercial paper program and revolving credit facilities and access to capital markets. We expect to meet our day-to-day cash requirements including, among other items, fuel and purchased power, dividends, interest payments, income taxes and pension contributions, using primarily internally generated cash and short-term borrowings. To meet the cash requirements for our capital investments, we expect to use internally generated cash, short-term borrowings and proceeds from the issuance of debt and equity securities in the capital markets. When such balances are of sufficient size and it makes economic sense to do so, we also use proceeds from the issuance of long-term debt and equity securities to repay short-term borrowings, which are principally related to investments in capital equipment and the redemption of bonds and for working capital and general corporate purposes. In 2016, we expect to continue our significant capital spending program and plan to contribute to our pension trust. We continue to believe that we will have the ability to pay dividends. Uncertainties affecting our ability to meet cash requirements include, among others, factors affecting revenues described in “Item 1A. Risk Factors” and “—Operating Results” above, economic conditions, regulatory actions, compliance with environmental regulations and conditions in the capital markets. For additional information on our future cash requirements, see “—Future Cash Requirements” below.

Capital Structure

As of December 31, 2015 and 2014, our capital structure, excluding short-term debt, was as follows:



	As of December 31,
	2015	2014
Common equity	52%	49%
Noncontrolling interests	<1%	<1%
Long-term debt, including VIEs	48%	51%

Short-Term Borrowings

Westar Energy maintains a commercial paper program pursuant to which it may issue commercial paper up to a maximum aggregate amount outstanding at any one time of $1.0 billion. This program is supported by Westar Energy’s revolving credit facilities. Maturities of commercial paper issuances may not exceed 365 days from the date of issuance and proceeds from such issuances will be used to temporarily fund capital expenditures, to redeem debt on an interim basis, for working capital and/or for other general corporate purposes. As of February 17, 2016, Westar Energy had $308.9 million of commercial paper issued and outstanding.

Westar Energy has two revolving credit facilities in the amounts of $730.0 million and $270.0 million. In September 2015, Westar Energy extended the term of the $730.0 million facility by one year to terminate in September 2019, $20.7 million of which will expire in September 2017. The $270.0 million facility will expire in February 2017. As long as there is no default under the facilities, the $730.0 million facility may be extended an additional year and the aggregate amount of borrowings under the $730.0 million and $270.0 million facilities may be increased to $1.0 billion and $400.0 million, respectively, subject to lender participation. All borrowings under the facilities are secured by KGE first mortgage bonds. Total combined borrowings under the revolving credit facilities and the commercial paper program may not exceed $1.0 billion at any given time. As of February 17, 2016, no amounts were borrowed and $19.2 million of letters of credit had been issued under the $730.0 million facility. No amounts were borrowed and no letters of credit were issued under the $270.0 million facility as of the same date.

A default by Westar Energy or KGE under other indebtedness totaling more than $25.0 million would be a default under both revolving credit facilities. Westar Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio of 65% or less at all times. At December 31, 2015, our ratio was 49%. See Note 8 of the Notes to Consolidated Financial Statements, “Short-Term Debt,” for additional information regarding our short-term borrowings.

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Long-Term Debt Financing

As of December 31, 2015, we had $121.9 million of variable rate, tax-exempt bonds outstanding. While the interest rates for these bonds have been extremely low, we continue to monitor the credit markets and evaluate our options with respect to these bonds.

In February 2016, KGE, as lessee to the La Cygne sale-leaseback, effected a refunding of $162.1 million in outstanding bonds held by the trustee of the lease maturing March 2021. The stated interest rate of the bonds was reduced from 5.647% to 2.398%. See Note 17 of the Notes to Consolidated Financial Statements, “Variable Interest Entities,” for additional information regarding our La Cygne sale-leaseback.

In November 2015, Westar Energy issued $250.0 million in principal amount of first mortgage bonds bearing stated interest at 3.25% and maturing December 2025. Concurrently, Westar Energy issued $300.0 million in principal amount of first mortgage bonds bearing stated interest at 4.25% and maturing December 2045.

Also in November 2015, Westar Energy redeemed $300.0 million in principal amount of first mortgage bonds bearing stated interest at 8.625% maturing in December 2018 for $360.9 million which included a call premium. The call premium was recorded as a regulatory asset and is being amortized over the term of the new bonds.

In August 2015, Westar Energy redeemed $150.0 million in principal amount of first mortgage bonds bearing stated interest at 5.875% and maturing July 2036.

In January 2015, Westar Energy redeemed $125.0 million in principal amount of first mortgage bonds bearing stated interest at 5.95% and maturing January 2035.

The Westar Energy and KGE mortgages each contain provisions restricting the amount of first mortgage bonds that can be issued by each entity. We must comply with such restrictions prior to the issuance of additional first mortgage bonds or other secured indebtedness.

Under the Westar Energy mortgage, the issuance of bonds is subject to limitations based on the amount of bondable property additions. In addition, so long as any bonds issued prior to January 1, 1997, remain outstanding, the mortgage prohibits additional first mortgage bonds from being issued, except in connection with certain refundings, unless Westar Energy’s unconsolidated net earnings available for interest, depreciation and property retirement (which as defined, does not include earnings or losses attributable to the ownership of securities of subsidiaries), for a period of 12 consecutive months within 15 months preceding the issuance, are not less than the greater of twice the annual interest charges on or 10% of the principal amount of all first mortgage bonds outstanding after giving effect to the proposed issuance. As of December 31, 2015, approximately $851.0 million principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in the mortgage, except in connection with certain refundings.

Under the KGE mortgage, the amount of first mortgage bonds authorized is limited to a maximum of $3.5 billion and the issuance of bonds is subject to limitations based on the amount of bondable property additions. In addition, the mortgage prohibits additional first mortgage bonds from being issued, except in connection with certain refundings, unless KGE’s net earnings before income taxes and before provision for retirement and depreciation of property for a period of 12 consecutive months within 15 months preceding the issuance are not less than either two and one-half times the annual interest charges on or 10% of the principal amount of all KGE first mortgage bonds outstanding after giving effect to the proposed issuance. As of December 31, 2015, approximately $1.5 billion principal amount of additional KGE first mortgage bonds could be issued under the most restrictive provisions in the mortgage, except in connection with certain refundings.

Some of our debt instruments contain restrictions that require us to maintain leverage ratios as defined in the credit agreements. We calculate these ratios in accordance with the agreements and they are used to determine compliance with our various debt covenants. We were in compliance with these covenants as of December 31, 2015.

Impact of Credit Ratings on Debt Financing

Moody’s Investors Service (Moody’s) and Standard & Poor’s Ratings Services (S&P) are independent credit-rating agencies that rate our debt securities. These ratings indicate each agency’s assessment of our ability to pay interest and principal when due on our securities.

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In general, more favorable credit ratings increase borrowing opportunities and reduce the cost of borrowing. Under Westar Energy’s revolving credit facilities and commercial paper program, our cost of borrowings is determined in part by credit ratings. However, Westar Energy’s ability to borrow under the credit facilities and commercial paper program are not conditioned on maintaining a particular credit rating. We may enter into new credit agreements that contain credit rating conditions, which could affect our liquidity and/or our borrowing costs.

Factors that impact our credit ratings include a combination of objective and subjective criteria. Objective criteria include typical financial ratios, such as total debt to total capitalization and funds from operations to total debt, among others, future capital expenditures and our access to liquidity including committed lines of credit. Subjective criteria include such items as the quality and credibility of management, the political and regulatory environment we operate in and an assessment of our governance and risk management practices.

As of February 17, 2016, our ratings with the agencies are as shown in the table below.



	Westar Energy First Mortgage Bond Rating	KGE First Mortgage Bond Rating	Westar Energy Commercial Paper	Rating Outlook
Moody’s	A2	A2	P-2	Stable
S&P	A	A	A-2	Stable

Common Stock

Westar Energy’s Restated Articles of Incorporation, as amended, provide for 275.0 million authorized shares of common stock. As of December 31, 2015, Westar Energy had 141.4 million shares issued and outstanding.

In September 2013, Westar Energy entered into two forward sale agreements with two banks. Under the terms of the agreements, the banks, as forward sellers, borrowed 8.0 million shares of Westar Energy’s common stock from third parties and sold them to a group of underwriters for $31.15 per share. Pursuant to over-allotment options granted to the underwriters, the underwriters purchased in October 2013 an additional 0.9 million shares from the banks as forward sellers, increasing the total number of shares under the forward sale agreements to approximately 8.9 million. The underwriters received a commission equal to 3.5% of the sales price of all shares sold under each agreement.

In March 2013, Westar Energy entered into a three-year sales agency financing agreement and master forward sale agreement with a bank. The maximum amount that Westar Energy may offer and sell under the March 2013 agreements is the lesser of an aggregate of $500.0 million or approximately 25.0 million shares, subject to adjustment for share splits, share combinations and share dividends. Under the terms of the sales agency financing agreement, Westar Energy may offer and sell shares of its common stock from time to time. In addition, under the terms of the sales agency financing agreement and master forward sale confirmation, Westar Energy may from time to time enter into one or more forward sale transactions with the bank, as forward purchaser, and the bank will borrow shares of Westar Energy’s common stock from third parties and sell them through its agent. The agent receives a commission equal to 1% of the sales price of all shares sold under the agreements.

In April 2010, Westar Energy entered into a three-year sales agency financing agreement and master forward sale agreement with a bank that was terminated in March 2013. The maximum amount that Westar Energy could offer and sell under the agreements was the lesser of an aggregate of $500.0 million or approximately 22.0 million shares, subject to adjustment for share splits, share combinations and share dividends. Terms under these agreements are generally similar to the March 2013 agreements described above.

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The following table summarizes our common stock activity pursuant to the three forward sale agreements.



	Year Ended December 31,
	2015	2014	2013
Shares that could be settled at beginning of year	9,160,500	12,052,976	1,753,415
Transactions entered	—	—	11,367,673
Transactions settled (a)	9,160,500	2,892,476	1,068,112
Shares that could be settled at end of year	—	9,160,500	12,052,976
_______________
(a) The shares settled during the years ended December 31, 2015, 2014 and 2013, were settled with a physical settlement amount of approximately $254.6 million, $82.9 million and $27.0 million, respectively.

The forward sale transactions were entered into at market prices; therefore, the forward sale agreements had no initial fair value. Westar Energy did not receive any proceeds from the sale of common stock under the forward sale agreements until transactions were settled. Westar Energy settled the forward sale transactions through physical share settlement and recorded the forward sale agreements within equity. The shares under the forward sale agreements were initially priced when the transactions were entered into and were subject to certain fixed pricing adjustments during the term of the agreements. The net proceeds from the forward sale transactions represent the prices established by the forward sale agreements applicable to the time periods in which physical settlement occurred.

Westar Energy used the proceeds from the transactions described above to repay short-term borrowings, with such borrowed amounts principally used for investments in capital equipment, as well as for working capital and general corporate purposes.

Summary of Cash Flows



	Year Ended December 31,
	2015			2014			2013
	(In Thousands)
Cash flows from (used in):
Operating activities	$	714,543		$	824,355		$	702,803
Investing activities	(649,704		)	(838,748		)	(641,901		)
Financing activities	(66,164		)	14,462			(62,244		)
Net (decrease) increase in cash and cash equivalents	$	(1,325	)	$	69		$	(1,342	)

Cash Flows from Operating Activities

Cash flows from operating activities decreased $109.8 million in 2015 compared to 2014 due principally to our having received $62.8 million less for wholesale power sales and transmission services, our having received $51.8 million less from retail customers, our having paid $25.2 million more for the Wolf Creek refueling outage and our having received $10.0 million less for energy marketing activities. Partially offsetting these decreases was our having paid $40.1 million less for coal and natural gas.

Cash flows from operating activities increased $121.6 million in 2014 compared to 2013 due principally to our having received $384.2 million more from retail and wholesale customers. This increase was offset partially by our having paid $227.4 million more for fuel and purchased power.

Cash Flows used in Investing Activities

Cash flows used in investing activities decreased $189.0 million from 2015 to 2014 due primarily to our having invested $151.8 million less in additions to property, plant and equipment and our having received $23.6 million more from our investment in COLI.

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Cash flows used in investing activities increased $196.8 million from 2013 to 2014 due primarily to decreased proceeds from investment in COLI of $104.4 million and increased investment in property, plant and equipment of $72.0 million.

Cash Flows from (used in) Financing Activities

Cash flows from financing activities decreased $80.6 million in 2015 compared to 2014. The decrease was due primarily to our having redeemed $208.4 million more in long-term debt, issuing $129.7 million less in commercial paper, and repaying $23.3 million more for borrowings against the cash surrender value of COLI. Partially offsetting these decreases was our having issued $170.3 million more in common stock and issuing $125.9 million more in long-term debt.

Cash flows from financing activities increased $76.7 million in 2014 compared to 2013. The increase was due primarily to our having borrowed $327.6 million more in short-term debt, our having repaid $104.2 million less for borrowings against the cash surrender value of COLI, and also an increase in issuances of common stock of $54.8 million. This was partially offset by our having paid $327.5 million more to retire, and our having received $74.4 million less from issuances, of long-term debt.

Future Cash Requirements

Our business requires significant capital investments. Through 2018, we expect to need cash primarily for utility construction programs designed to improve and expand facilities related to providing electric service, which include, but are not limited to, expenditures to develop renewable generation, new transmission lines and other improvements to our power plants, transmission and distribution lines and equipment. We expect to meet these cash needs with internally generated cash, short-term borrowings and the issuance of securities in the capital markets.

We have incurred and expect to continue to incur significant costs to comply with existing and future environmental laws and regulations, which are subject to changing interpretations and amendments. Changes to environmental regulations could result in significantly more stringent laws and regulations or interpretations thereof that could affect us and our industry in particular. These laws, regulations and interpretations could result in more stringent terms in our existing operating permits or a failure to obtain new permits could cause a material increase in our capital or operational costs and could otherwise have a material effect on our operations and consolidated financial results.

Capital expenditures for 2015 and anticipated capital expenditures, including costs of removal, for 2016 through 2018 are shown in the following table.



	Actual		Projected
	2015		2016		2017		2018
	(In Thousands)
Generation:
Replacements and other	$	162,367	$	167,300	$	178,700	$	184,400
Environmental	94,620		39,200		17,600		24,000
Wind development	32,760		398,500		800		1,100
Nuclear fuel	15,644		22,600		45,800		25,500
Transmission	158,649		224,900		267,300		251,700
Distribution	182,011		216,300		208,500		192,600
Other	54,177		64,200		75,300		71,700
Total capital expenditures	$	700,228	$	1,133,000	$	794,000	$	751,000

We prepare these estimates for planning purposes and revise them from time to time. Actual expenditures will differ, perhaps materially, from our estimates due to changing regulatory requirements, changing costs, delays or advances in engineering, construction or permitting, changes in the availability and cost of capital and other factors discussed in “Item 1A. Risk Factors.” We and our generating plant co-owners periodically evaluate these estimates and this may result in possibly material changes in actual costs.

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We will also need significant amounts of cash in the future to meet our long-term debt obligations. The principal amounts of our long-term debt maturities as of December 31, 2015, are as follows.



Year	Long-term debt		Long-term debt of VIEs
	(In Thousands)
2016	$	—	$	28,309
2017	125,000		26,842
2018	—		28,538
2019	300,000		31,485
2020	250,000		32,254
Thereafter	2,526,940		18,843
Total maturities	$	3,201,940	$	166,271

Pension Obligation

The amount we contribute to our pension plan for future periods is not yet known, however, in general we expect to fund our pension plan each year at least to a level equal to current year pension expense. We must also meet minimum funding requirements under the Employee Retirement Income Security Act, as amended by the Pension Protection Act. We may contribute additional amounts from time to time as deemed appropriate.

We contributed $41.0 million to our pension trust in 2015 and $26.4 million in 2014. We expect to contribute approximately $28.0 million in 2016. In 2015 and 2014, we also funded $5.8 million and $7.1 million, respectively, of Wolf Creek’s pension plan contributions. In 2016, we plan to contribute $8.0 million to fund Wolf Creek’s pension plan contributions. See Notes 11 and 12 of the Notes to Consolidated Financial Statements, “Employee Benefit Plans” and “Wolf Creek Employee Benefit Plans,” for additional discussion of Westar Energy and Wolf Creek benefit plans, respectively.

OFF-BALANCE SHEET ARRANGEMENTS

As discussed under “—Common Stock” above and in Note 16 of the Notes to Consolidated Financial Statements, “Common Stock,” Westar Energy entered into several forward sale agreements with banks in 2013 which were fully settled in 2015. The forward sale agreements are off-balance sheet arrangements. We also have off-balance sheet arrangements in the form of operating leases and letters of credit entered into in the ordinary course of business. We did not have any additional off-balance sheet arrangements as of December 31, 2015.

CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

In the course of our business activities, we enter into a variety of contracts and commercial commitments. Some of these result in direct obligations reflected on our consolidated balance sheets while others are commitments, some firm and some based on uncertainties, not reflected in our underlying consolidated financial statements.

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Contractual Cash Obligations

The following table summarizes the projected future cash payments for our contractual obligations existing as of December 31, 2015.



	Total		2016		2017 - 2018		2019 - 2020		Thereafter
	(In Thousands)
Long-term debt (a)	$	3,201,940	$	—	$	125,000	$	550,000	$	2,526,940
Long-term debt of VIEs (a)	166,271		28,309		55,380		63,739		18,843
Interest on long-term debt (b)	2,790,205		146,384		283,113		249,744		2,110,964
Interest on long-term debt of VIEs	27,595		8,697		12,594		5,772		532
Long-term debt, including interest	6,186,011		183,390		476,087		869,255		4,657,279
Pension and post-retirement benefit expected contributions (c)	36,600		36,600		—		—		—
Capital leases (d)	81,133		5,812		10,619		8,652		56,050
Operating leases (e)	59,132		13,550		21,862		14,803		8,917
Other obligations of VIEs (f)	12,866		2,550		10,316		—		—
Fossil fuel (g)	947,522		195,654		358,930		336,560		56,378
Nuclear fuel (h)	113,705		17,895		40,114		36,547		19,149
Transmission service (i)	7,114		7,114		—		—		—
Wind development obligations	259,491		259,491		—		—		—
Unconditional purchase obligations	591,422		497,759		61,943		31,720		—
Total contractual obligations (j)	$	8,294,996	$	1,219,815	$	979,871	$	1,297,537	$	4,797,773

_______________


(a)	See Note 9 of the Notes to Consolidated Financial Statements, “Long-Term Debt,” for individual maturities.


(b)	We calculate interest on our variable rate debt based on the effective interest rates as of December 31, 2015.


(c)	Our contribution amounts for future periods are not yet known. See Notes 11 and 12 of the Notes to Consolidated Financial Statements, “Employee Benefit Plans” and “Wolf Creek Employee Benefit Plans,” for additional information regarding pension and post-retirement benefits.


(d)	Includes principal and interest on capital leases.


(e)	Includes leases for operating facilities, operating equipment, office space, office equipment, vehicles and rail cars as well as other miscellaneous commitments.


(f)	See Note 17 of the Notes to Consolidated Financial Statements, “Variable Interest Entities,” for additional information on VIEs.


(g)	Coal and natural gas commodity and transportation contracts.


(h)	Uranium concentrates, conversion, enrichment and fabrication.


(i)	Includes obligations to SPP for transmission service payments. See Note 13 of the Notes to Consolidated Financial Statements, “Commitments and Contingencies - Fuel, Purchase Power and Transmission Commitments” for additional information.


(j)	We have $1.5 million of unrecognized income tax benefits, including interest, that are not included in this table because we cannot reasonably estimate the timing of the cash payments to taxing authorities assuming those unrecognized income tax benefits are settled at the amounts accrued as of December 31, 2015.

Commercial Commitments

Our commercial commitments as of December 31, 2015, consist of outstanding letters of credit that expire in 2016, some of which automatically renew annually. The letters of credit are comprised of $13.7 million related to transmission projects, $3.9 million related to energy marketing and trading activities, $0.9 million related to workers’ compensation and $1.5 million related to other operating activities for a total outstanding balance of $20.0 million.

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OTHER INFORMATION

Changes in Prices

See Note 3 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation,” for information on our prices.

Wolf Creek Outage

Wolf Creek normally operates on an 18-month planned refueling and maintenance outage schedule. As authorized by our regulators, incremental maintenance costs of planned refueling and maintenance outages are deferred and amortized ratably over the period between planned refueling and maintenance outages. In early 2015, Wolf Creek underwent a planned refueling and maintenance outage. Our share of the outage costs was approximately $31.9 million. The next refueling and maintenance outage is planned for the fall of 2016.

Stock-Based Compensation

We use two types of RSUs for our stock-based compensation awards; those with service requirements and those with performance measures. See Note 11 of the Notes to Consolidated Financial Statements, “Employee Benefit Plans,” for additional information. Total unrecognized compensation cost related to RSU awards with only service requirements was $4.5 million as of December 31, 2015, and we expect to recognize these costs over a remaining weighted-average period of 1.7 years. Total unrecognized compensation cost related to RSU awards with performance measures was $4.0 million as of December 31, 2015, and we expect to recognize these costs over a remaining weighted-average period of 1.7 years.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our fuel procurement and energy marketing activities involve primary market risk exposures, including commodity price risk, credit risk and interest rate risk. Commodity price risk is the potential adverse price impact related to the purchase or sale of electricity and energy-related products. Credit risk is the potential adverse financial impact resulting from non-performance by a counterparty of its contractual obligations. Interest rate risk is the potential adverse financial impact related to changes in interest rates. In addition, our investments in trusts to fund nuclear plant decommissioning and to fund non-qualified retirement benefits give rise to security price risk. Many of the securities in these trusts are exposed to price fluctuations in the capital markets.

Commodity Price Risk

We engage in both financial and physical trading with the goal of managing our commodity price risk, enhancing system reliability and increasing profits. We procure and trade electricity, coal, natural gas and other energy-related products by utilizing energy commodity contracts and a variety of financial instruments, including futures contracts, options and swaps.

We use various types of fuel, including coal, natural gas, uranium and diesel to operate our plants and also purchase power to meet customer demand. Our prices and consolidated financial results are exposed to market risks from commodity price changes for electricity and other energy-related products as well as from interest rates. Volatility in these markets impacts our costs of purchased power, costs of fuel for our generating plants and our participation in energy markets. We strive to manage our customers’ and our exposure to these market risks through regulatory, operating and financing activities and, when we deem appropriate, we economically hedge a portion of these risks through the use of derivative financial instruments for non-trading purposes.

Factors that affect our commodity price exposure are the quantity and availability of fuel used for generation, the availability of our power plants and the quantity of electricity customers consume. Quantities of fossil fuel we use to generate electricity fluctuate from period to period based on availability, price and deliverability of a given fuel type, as well as planned and unscheduled outages at our generating plants that use fossil fuels. Our commodity price exposure is also affected by our nuclear plant refueling and maintenance schedule. Our customers’ electricity usage also varies based on weather, the economy and other factors.

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We trade various types of fuel primarily to reduce exposure related to the volatility of commodity prices. A significant portion of our coal requirements is purchased under long-term contracts to hedge much of the fuel exposure for customers. If we were unable to generate an adequate supply of electricity for our customers, we would purchase power in the wholesale market to the extent it is available, subject to possible transmission constraints, and/or implement curtailment or interruption procedures as permitted in our tariffs and terms and conditions of service.

One way by which we manage and measure the commodity price risk of our trading portfolio is by using a variance/covariance value-at-risk (VaR) model. In addition to VaR, we employ additional risk control processes such as stress testing, daily loss limits, credit limits and position limits. We expect to use similar control processes in the future. The use of VaR requires assumptions, including the selection of a confidence level and a measure of volatility associated with potential losses and the estimated holding period. We express VaR as a potential dollar loss based on a 95% confidence level using a one-day holding period and a 20-day historical observation period. It is possible that actual results may differ significantly from assumptions. Accordingly, VaR may not accurately reflect our levels of exposure. The energy trading and market-based wholesale portfolio VaR amounts for 2015 and 2014 were as follows:



	2015		2014
	(In Thousands)
High	$	514	$	614
Low	56		14
Average	199		76

Interest Rate Risk

We have entered into numerous fixed and variable rate debt obligations. For details, see Note 9 of the Notes to Consolidated Financial Statements, “Long-Term Debt.” We manage our interest rate risk related to these debt obligations by limiting our exposure to variable interest rate debt, diversifying maturity dates and entering into treasury yield hedge transactions. We may also use other financial derivative instruments such as interest rate swaps. We compute and present information about the sensitivity to changes in interest rates for variable rate debt and current maturities of fixed rate debt by assuming a 100 basis point change in the current interest rates applicable to such debt over the remaining time the debt is outstanding.

We had approximately $400.5 million of variable rate debt and current maturities of fixed rate debt as of December 31, 2015. A 100 basis point change in interest rates applicable to this debt would impact income before income taxes on an annualized basis by approximately $3.9 million. As of December 31, 2015, we had $121.9 million of variable rate bonds insured by bond insurers. Interest rates payable under these bonds are normally set through periodic auctions. However, conditions in the credit markets over the past few years caused a dramatic reduction in the demand for auction bonds, which led to failed auctions. The contractual provisions of these securities set forth an indexing formula method by which interest will be paid in the event of an auction failure. Depending on the level of these reference indices, our interest costs may be higher or lower than what they would have been had the securities been auctioned successfully. Additionally, should insurers of those bonds experience a decrease in their credit ratings, such event could increase our borrowing costs. Furthermore, a decline in interest rates generally can serve to increase our pension and post-retirement benefit obligations.

Security Price Risk

We maintain the NDT, as required by the NRC and Kansas statute, to fund certain costs of nuclear plant decommissioning. As of December 31, 2015, investments in the NDT were allocated 50% to equity securities, 29% to debt securities, 6% to combination debt/equity/other securities, 9% to alternative investments, 6% to real estate securities and less than 1% to cash equivalents. As of December 31, 2015 and 2014, the fair value of the NDT investments was $184.1 million and $185.0 million, respectively. Changes in interest rates and/or other market changes resulting in a 10% decrease in the value of the securities would have resulted in an $18.4 million decrease in the value of the NDT as of December 31, 2015.

We also maintain a trust to fund non-qualified retirement benefits. As of December 31, 2015, investments in the trust were comprised of 66% equity securities, 34% debt securities and less than 1% cash equivalents. The fair value of the investments in this trust was $33.9 million as of December 31, 2015, and $35.5 million as of December 31, 2014. Changes in interest rates and/or other market changes resulting in a 10% decrease in the value of the securities would have resulted in a $3.4 million decrease in the value of the trust as of December 31, 2015.

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By maintaining diversified portfolios of securities, we seek to optimize the returns to fund the aforementioned obligations within acceptable risk tolerances, including interest rate risk. However, many of the securities in the portfolios are exposed to price fluctuations in the capital markets. If the value of the securities diminishes, the cost of funding the obligations rises. We actively monitor the portfolios by benchmarking the performance of the investments against relevant indices and by maintaining and periodically reviewing the asset allocations in relation to established policy targets. Our exposure to security price risk related to the NDT is in part mitigated because we are currently allowed to recover decommissioning costs in the prices we charge our customers.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA



TABLE OF CONTENTS	PAGE
Management’s Report on Internal Control Over Financial Reporting	53
Reports of Independent Registered Public Accounting Firm	54
Financial Statements:
Westar Energy, Inc. and Subsidiaries:
Consolidated Balance Sheets as of December 31, 2015 and 2014	56
Consolidated Statements of Income for the years ended December 31, 2015, 2014 and 2013	57
Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013	58
Consolidated Statements of Changes in Equity for the years ended December 31, 2015, 2014 and 2013	59
Notes to Consolidated Financial Statements	60
Financial Schedules:
Schedule II—Valuation and Qualifying Accounts	117

SCHEDULES OMITTED

The following schedules are omitted because of the absence of the conditions under which they are required or the information is included in our consolidated financial statements and schedules presented:

I, III, IV and V.

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

We are responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles (GAAP) and includes those policies and procedures that:


•	Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;


•	Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and


•	Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

We assessed the effectiveness of our internal control over financial reporting as of December 31, 2015. In making this assessment, we used the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, we concluded that, as of December 31, 2015, our internal control over financial reporting is effective based on those criteria. Our independent registered public accounting firm has issued an audit report on the company’s internal control over financial reporting.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Westar Energy, Inc.

Topeka, Kansas

We have audited the internal control over financial reporting of Westar Energy, Inc. and subsidiaries (the "Company") as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule of the Company as of and for the year ended December 31, 2015 of the Company and our report dated February 24, 2016 expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/ Deloitte & Touche LLP

Kansas City, Missouri

February 24, 2016

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Westar Energy, Inc.

Topeka, Kansas

We have audited the accompanying consolidated balance sheets of Westar Energy, Inc. and subsidiaries (the "Company") as of December 31, 2015 and 2014, and the related consolidated statements of income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Westar Energy, Inc. and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2016 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/ Deloitte & Touche LLP

Kansas City, Missouri

February 24, 2016

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WESTAR ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(Dollars in Thousands, Except Par Values)



	As of December 31,
	2015		2014
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,231	$	4,556
Accounts receivable, net of allowance for doubtful accounts of $5,294 and $5,309, respectively	258,286		267,327
Fuel inventory and supplies	301,294		247,406
Prepaid expenses	16,864		15,793
Regulatory assets	109,606		105,549
Other	27,860		28,772
Total Current Assets	717,141		669,403
PROPERTY, PLANT AND EQUIPMENT, NET	8,524,902		8,162,908
PROPERTY, PLANT AND EQUIPMENT OF VARIABLE INTEREST ENTITIES, NET	268,239		278,573
OTHER ASSETS:
Regulatory assets	751,312		754,229
Nuclear decommissioning trust	184,057		185,016
Other	260,015		238,777
Total Other Assets	1,195,384		1,178,022
TOTAL ASSETS	$	10,705,666	$	10,288,906
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of long-term debt of variable interest entities	$	28,309	$	27,933
Short-term debt	250,300		257,600
Accounts payable	220,969		219,351
Accrued dividends	49,829		44,971
Accrued taxes	83,773		74,356
Accrued interest	71,426		79,707
Regulatory liabilities	25,697		55,142
Other	106,632		90,571
Total Current Liabilities	836,935		849,631
LONG-TERM LIABILITIES:
Long-term debt, net	3,163,950		3,187,080
Long-term debt of variable interest entities, net	138,097		166,565
Deferred income taxes	1,591,430		1,445,851
Unamortized investment tax credits	209,763		211,040
Regulatory liabilities	267,114		288,343
Accrued employee benefits	462,304		532,622
Asset retirement obligations	275,285		230,668
Other	88,825		75,799
Total Long-Term Liabilities	6,196,768		6,137,968
COMMITMENTS AND CONTINGENCIES (See Notes 3, 13 and 15)
EQUITY:
Westar Energy, Inc. Shareholders’ Equity:
Common stock, par value $5 per share; authorized 275,000,000 shares; issued and outstanding 141,353,426 shares and 131,687,454 shares, respective to each date	706,767		658,437
Paid-in capital	2,004,124		1,781,120
Retained earnings	945,830		855,299
Total Westar Energy, Inc. Shareholders’ Equity	3,656,721		3,294,856
Noncontrolling Interests	15,242		6,451
Total Equity	3,671,963		3,301,307
TOTAL LIABILITIES AND EQUITY	$	10,705,666	$	10,288,906

The accompanying notes are an integral part of these consolidated financial statements.

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WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in Thousands, Except Per Share Amounts)



	Year Ended December 31,
	2015			2014			2013
REVENUES	$	2,459,164		$	2,601,703		$	2,370,654
OPERATING EXPENSES:
Fuel and purchased power	561,065			705,450			634,797
SPP network transmission costs	229,043			218,924			178,604
Operating and maintenance	330,289			367,188			359,060
Depreciation and amortization	310,591			286,442			272,593
Selling, general and administrative	250,278			250,439			224,133
Taxes other than income tax	156,901			140,302			122,282
Total Operating Expenses	1,838,167			1,968,745			1,791,469
INCOME FROM OPERATIONS	620,997			632,958			579,185
OTHER INCOME (EXPENSE):
Investment earnings	7,799			10,622			10,056
Other income	19,438			31,522			35,609
Other expense	(17,636		)	(18,389		)	(18,099		)
Total Other Income	9,601			23,755			27,566
Interest expense	176,802			183,118			182,167
INCOME BEFORE INCOME TAXES	453,796			473,595			424,584
Income tax expense	152,000			151,270			123,721
NET INCOME	301,796			322,325			300,863
Less: Net income attributable to noncontrolling interests	9,867			9,066			8,343
NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC.	$	291,929		$	313,259		$	292,520
BASIC AND DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY (see Note 2):
Basic earnings per common share	$	2.11		$	2.40		$	2.29
Diluted earnings per common share	$	2.09		$	2.35		$	2.27
AVERAGE EQUIVALENT COMMON SHARES OUTSTANDING	137,957,515			130,014,941			127,462,994
DIVIDENDS DECLARED PER COMMON SHARE	$	1.44		$	1.40		$	1.36

The accompanying notes are an integral part of these consolidated financial statements.

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WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)



	Year Ended December 31,
	2015			2014			2013
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES:
Net income	$	301,796		$	322,325		$	300,863
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	310,591			286,442			272,593
Amortization of nuclear fuel	26,974			26,051			22,690
Amortization of deferred regulatory gain from sale leaseback	(5,495		)	(5,495		)	(5,495		)
Amortization of corporate-owned life insurance	19,850			20,202			15,149
Non-cash compensation	8,345			7,280			8,188
Net deferred income taxes and credits	151,332			151,451			123,307
Stock-based compensation excess tax benefits	(1,307		)	(875		)	(576		)
Allowance for equity funds used during construction	(2,075		)	(17,029		)	(14,143		)
Changes in working capital items:
Accounts receivable	9,042			(17,291		)	(24,649		)
Fuel inventory and supplies	(53,263		)	(8,773		)	10,124
Prepaid expenses and other	(23,145		)	36,717			(12,316		)
Accounts payable	6,636			6,189			7,856
Accrued taxes	13,073			6,596			14,218
Other current liabilities	(80,396		)	(31,624		)	(52,829		)
Changes in other assets	2,199			6,378			(4,167		)
Changes in other liabilities	30,386			35,811			41,990
Cash Flows from Operating Activities	714,543			824,355			702,803
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES:
Additions to property, plant and equipment	(700,228		)	(852,052		)	(780,098		)
Purchase of securities - trusts	(37,557		)	(9,075		)	(66,668		)
Sale of securities - trusts	37,930			11,125			81,994
Investment in corporate-owned life insurance	(14,845		)	(16,250		)	(17,724		)
Proceeds from investment in corporate-owned life insurance	66,794			43,234			147,658
Proceeds from federal grant	—			—			876
Investment in affiliated company	(575		)	(8,000		)	(4,947		)
Other investing activities	(1,223		)	(7,730		)	(2,992		)
Cash Flows used in Investing Activities	(649,704		)	(838,748		)	(641,901		)
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES:
Short-term debt, net	(7,300		)	122,406			(205,241		)
Proceeds from long-term debt	543,881			417,943			492,347
Retirements of long-term debt	(635,891		)	(427,500		)	(100,000		)
Retirements of long-term debt of variable interest entities	(27,933		)	(27,479		)	(25,942		)
Repayment of capital leases	(2,591		)	(3,340		)	(2,995		)
Borrowings against cash surrender value of corporate-owned life insurance	59,431			59,766			59,565
Repayment of borrowings against cash surrender value of corporate-owned life insurance	(64,593		)	(41,249		)	(145,418		)
Stock-based compensation excess tax benefits	1,307			875			576
Issuance of common stock	257,998			87,669			32,906
Distributions to shareholders of noncontrolling interests	(1,076		)	(1,030		)	(2,419		)
Cash dividends paid	(186,120		)	(171,507		)	(162,904		)
Other financing activities	(3,277		)	(2,092		)	(2,719		)
Cash Flows (used in) from Financing Activities	(66,164		)	14,462			(62,244		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(1,325		)	69			(1,342		)
CASH AND CASH EQUIVALENTS:
Beginning of period	4,556			4,487			5,829
End of period	$	3,231		$	4,556		$	4,487

The accompanying notes are an integral part of these consolidated financial statements.

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WESTAR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Dollars in Thousands)



	Westar Energy, Inc. Shareholders
		Common stock shares	Common stock		Paid-in capital			Retained earnings			Non-controlling interests			Total equity
Balance as of December 31, 2012		126,503,748	$	632,519	$	1,656,972		$	606,649		$	14,115		$	2,910,255
Net income		—	—		—			292,520			8,343			300,863
Issuance of stock		1,256,391	6,282		26,624			—			—			32,906
Issuance of stock for compensation and reinvested dividends		494,090	2,470		7,171			—			—			9,641
Tax withholding related to stock compensation		—	—		(2,719		)	—			—			(2,719		)
Dividends declared on common stock ($1.36 per share)		—	—		—			(174,393		)	—			(174,393		)
Stock compensation expense		—	—		8,103			—			—			8,103
Tax benefit on stock compensation		—	—		576			—			—			576
Deconsolidation of noncontrolling interests		—	—		—			—			(14,282		)	(14,282		)
Distributions to shareholders of noncontrolling interests		—	—		—			—			(2,419		)	(2,419		)
Balance as of December 31, 2013		128,254,229	641,271		1,696,727			724,776			5,757			3,068,531
Net income		—	—		—			313,259			9,066			322,325
Issuance of stock		3,026,239	15,131		72,538			—			—			87,669
Issuance of stock for compensation and reinvested dividends		406,986	2,035		7,120			—			—			9,155
Tax withholding related to stock compensation		—	—		(2,092		)	—			—			(2,092		)
Dividends declared on common stock ($1.40 per share)		—	—		—			(182,736		)	—			(182,736		)
Stock compensation expense		—	—		7,193			—			—			7,193
Tax benefit on stock compensation		—	—		875			—			—			875
Deconsolidation of noncontrolling interests		—	—		—			—			(7,342		)	(7,342		)
Distributions to shareholders of noncontrolling interests		—	—		—			—			(1,030		)	(1,030		)
Other		—	—		(1,241		)	—			—			(1,241		)
Balance as of December 31, 2014		131,687,454	658,437		1,781,120			855,299			6,451			3,301,307
Net income		—	—		—			291,929			9,867			301,796
Issuance of stock		9,249,986	46,250		211,748			—			—			257,998
Issuance of stock for compensation and reinvested dividends		415,986	2,080		8,373			—			—			10,453
Tax withholding related to stock compensation		—	—		(3,277		)	—			—			(3,277		)
Dividends declared on common stock ($1.44 per share)		—	—		—			(201,398		)	—			(201,398		)
Stock compensation expense		—	—		8,250			—			—			8,250
Tax benefit on stock compensation		—	—		1,307			—			—			1,307
Distributions to shareholders of noncontrolling interests		—	—		—			—			(1,076		)	(1,076		)
Other		—	—		(3,397		)	—			—			(3,397		)
Balance as of December 31, 2015		141,353,426	$	706,767	$	2,004,124		$	945,830		$	15,242		$	3,671,963

The accompanying notes are an integral part of these consolidated financial statements.

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WESTAR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. DESCRIPTION OF BUSINESS

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

We prepare our consolidated financial statements in accordance with generally accepted accounting principles (GAAP) for the United States of America. Our consolidated financial statements include all operating divisions, majority owned subsidiaries and variable interest entities (VIEs) of which we maintain a controlling interest or are the primary beneficiary reported as a single reportable segment. Undivided interests in jointly-owned generation facilities are included on a proportionate basis. Intercompany accounts and transactions have been eliminated in consolidation.

Use of Management’s Estimates

When we prepare our consolidated financial statements, we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities, at the date of our consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an ongoing basis, including those related to depreciation, unbilled revenue, valuation of investments, forecasted fuel costs included in our retail energy cost adjustment billed to customers, income taxes, pension and post-retirement benefits, our asset retirement obligations (AROs) including the decommissioning of Wolf Creek Generating Station (Wolf Creek), environmental issues, VIEs, contingencies and litigation. Actual results may differ from those estimates under different assumptions or conditions.

Regulatory Accounting

We apply accounting standards that recognize the economic effects of rate regulation. Accordingly, we have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent. See Note 3, “Rate Matters and Regulation,” for additional information regarding our regulatory assets and liabilities.

Cash and Cash Equivalents

We consider investments that are highly liquid and have maturities of three months or less when purchased to be cash equivalents.

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Fuel Inventory and Supplies

We state fuel inventory and supplies at average cost. Following are the balances for fuel inventory and supplies stated separately.



	As of December 31,
	2015		2014
	(In Thousands)
Fuel inventory	$	113,438	$	70,416
Supplies	187,856		176,990
Fuel inventory and supplies	$	301,294	$	247,406

Property, Plant and Equipment

We record the value of property, plant and equipment, including that of VIEs, at cost. For plant, cost includes contracted services, direct labor and materials, indirect charges for engineering and supervision and an allowance for funds used during construction (AFUDC). AFUDC represents the allowed cost of capital used to finance utility construction activity. We compute AFUDC by applying a composite rate to qualified construction work in progress. We credit other income (for equity funds) and interest expense (for borrowed funds) for the amount of AFUDC capitalized as construction cost on the accompanying consolidated statements of income as follows:



	Year Ended December 31,
	2015			2014			2013
	(Dollars In Thousands)
Borrowed funds	$	3,505		12,044			11,706
Equity funds	2,075			17,029			14,143
Total	$	5,580		$	29,073		$	25,849
Average AFUDC Rates	2.7		%	6.7		%	4.8		%

We charge maintenance costs and replacements of minor items of property to expense as incurred, except for maintenance costs incurred for our planned refueling and maintenance outages at Wolf Creek. As authorized by regulators, we defer and amortize to expense ratably over the period between planned outages incremental maintenance costs incurred for such outages. When a unit of depreciable property is retired, we charge to accumulated depreciation the original cost less salvage value.

Depreciation

We depreciate utility plant using a straight-line method. The depreciation rates are based on an average annual composite basis using group rates that approximated 2.5% in 2015, 2.4% in 2014 and 2.5% in 2013.

Depreciable lives of property, plant and equipment are as follows.



	Years
Fossil fuel generating facilities	6	to	78
Nuclear fuel generating facility	55	to	71
Wind generating facilities	19	to	20
Transmission facilities	15	to	75
Distribution facilities	22	to	68
Other	5	to	30

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Nuclear Fuel

We record as property, plant and equipment our share of the cost of nuclear fuel used in the process of refinement, conversion, enrichment and fabrication. We reflect this at original cost and amortize such amounts to fuel expense based on the quantity of heat consumed during the generation of electricity as measured in millions of British thermal units (MMBtu). The accumulated amortization of nuclear fuel in the reactor was $59.1 million as of December 31, 2015, and $72.3 million as of December 31, 2014. The cost of nuclear fuel charged to fuel and purchased power expense was $27.3 million in 2015, $27.3 million in 2014 and $26.5 million in 2013.

Cash Surrender Value of Life Insurance

We recorded on our consolidated balance sheets in other long-term assets the following amounts related to corporate-owned life insurance (COLI) policies.



	As of December 31,
	2015			2014
	(In Thousands)
Cash surrender value of policies	$	1,299,408		$	1,306,777
Borrowings against policies	(1,168,794		)	(1,173,956		)
Corporate-owned life insurance, net	$	130,614		$	132,821

We record as income increases in cash surrender value and death benefits. We offset against policy income the interest expense that we incur on policy loans. Income from death benefits is highly variable from period to period.

Revenue Recognition

Allowance for Doubtful Accounts

We determine our allowance for doubtful accounts based on the age of our receivables. We charge receivables off when they are deemed uncollectible, which is based on a number of factors including specific facts surrounding an account and management’s judgment.

Income Taxes

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Sales Tax

We account for the collection and remittance of sales tax on a net basis. As a result, we do not reflect sales tax in our consolidated statements of income.

Earnings Per Share

We have participating securities in the form of unvested restricted share units (RSUs) with nonforfeitable rights to dividend equivalents that receive dividends on an equal basis with dividends declared on common shares. As a result, we apply the two-class method of computing basic and diluted earnings per share (EPS).

To compute basic EPS, we divide the earnings allocated to common stock by the weighted average number of common shares outstanding. Diluted EPS includes the effect of issuable common shares resulting from our forward sale agreements, if any, and RSUs with forfeitable rights to dividend equivalents. We compute the dilutive effect of potential issuances of common shares using the treasury stock method.

The following table reconciles our basic and diluted EPS from net income.



	Year Ended December 31,
	2015		2014		2013
	(Dollars In Thousands, Except Per Share Amounts)
Net income	$	301,796	$	322,325	$	300,863
Less: Net income attributable to noncontrolling interests	9,867		9,066		8,343
Net income attributable to Westar Energy, Inc.	291,929		313,259		292,520
Less: Net income allocated to RSUs	646		790		810
Net income allocated to common stock	$	291,283	$	312,469	$	291,710

Weighted average equivalent common shares outstanding – basic	137,957,515		130,014,941		127,462,994
Effect of dilutive securities:
RSUs	299,198		181,397		17,195
Forward sale agreements	1,021,510		2,628,187		818,505
Weighted average equivalent common shares outstanding – diluted (a)	139,278,223		132,824,525		128,298,694

Earnings per common share, basic	$	2.11	$	2.40	$	2.29
Earnings per common share, diluted	$	2.09	$	2.35	$	2.27

_______________


(a)	For the years ended December 31, 2015, 2014 and 2013, we had no antidilutive securities.

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Supplemental Cash Flow Information



	Year Ended December 31,
	2015			2014			2013
	(In Thousands)
CASH PAID FOR (RECEIVED FROM):
Interest on financing activities, net of amount capitalized	$	161,484		$	160,292		$	148,691
Interest on financing activities of VIEs	10,430			12,183			13,892
Income taxes, net of refunds	(410		)	458			(11		)
NON-CASH INVESTING TRANSACTIONS:
Property, plant and equipment additions	105,169			143,192			127,544
Property, plant and equipment of VIEs	—			(7,342		)	(14,282		)
NON-CASH FINANCING TRANSACTIONS:
Issuance of stock for compensation and reinvested dividends	10,453			9,155			9,641
Deconsolidation of VIEs	—			(7,342		)	(14,282		)
Assets acquired through capital leases	3,130			8,717			334

New Accounting Pronouncements

We prepare our consolidated financial statements in accordance with GAAP for the United States of America. To address current issues in accounting, the Financial Accounting Standards Board (FASB) issued the following new accounting pronouncements which may affect our accounting and/or disclosure.

Presentation of Financial Statements

In November 2015, the FASB issued Accounting Standard Update (ASU) No. 2015-17 to simplify the presentation of deferred income taxes. This guidance requires that deferred tax liabilities and assets be classified as long-term in a classified statement of position. The guidance is effective for fiscal years beginning after December 15, 2016, with early adoption permitted. We have elected to retrospectively adopt effective December 31, 2015, resulting in reducing long-term deferred income tax liabilities as of December 31, 2014, by $29.6 million previously presented as current deferred tax assets.

In April 2015, the FASB issued ASU No. 2015-03 to simplify the presentation of debt issuance costs. This guidance requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The guidance is effective for fiscal years beginning after December 15, 2015, with early adoption permitted. We have elected to adopt effective December 31, 2015, resulting in reducing long-term debt as of December 31, 2014, by $1.9 million previously presented in other current assets and $26.6 million previously presented in other long-term assets.

Extraordinary and Unusual Items

In January 2015, the FASB issued ASU No. 2015-01, which eliminates the accounting concept of extraordinary items. The objective of the new guidance is to reduce complexity in accounting standards while maintaining or improving the usefulness of information provided. The guidance is effective for fiscal years beginning after December 15, 2015, with early adoption permitted. We elected to adopt effective January 1, 2015, without an impact to our financial statements.

Revenue Recognition

In May 2014, the FASB issued ASU No. 2014-09, which addresses revenue from contracts with customers. The objective of the new guidance is to establish principles to report useful information to users of financial statements about the nature, amount, timing and uncertainty of revenue from contracts with customers. This guidance was effective for fiscal years beginning after December 15, 2016. However, in August 2015, the FASB deferred the effective date by one year. Early application of the standard is permitted for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective application or cumulative effect transition method. We have not yet selected a transition method or determined the impact on our consolidated financial statements but we do not expect it to be material.

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3. RATE MATTERS AND REGULATION

Regulatory Assets and Regulatory Liabilities

Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer prices. Regulatory liabilities represent probable future reductions in revenue or refunds to customers through the price setting process. Regulatory assets and liabilities reflected on our consolidated balance sheets are as follows.



	As of December 31,
	2015		2014
	(In Thousands)
Regulatory Assets:
Deferred employee benefit costs	$	353,785	$	435,590
Amounts due from customers for future income taxes, net	144,120		153,984
Debt reacquisition costs	121,631		61,079
Depreciation	65,797		68,422
Ad valorem tax	44,455		39,428
Asset retirement obligations	31,996		26,106
Treasury yield hedges	25,634		26,614
Wolf Creek outage	16,561		11,165
Disallowed plant costs	15,639		15,809
La Cygne environmental costs	15,446		—
Energy efficiency program costs	7,922		8,933
Other regulatory assets	17,932		12,648
Total regulatory assets	$	860,918	$	859,778

Regulatory Liabilities:
Deferred regulatory gain from sale leaseback	$	75,560	$	81,055
Removal costs	53,834		88,242
Jurisdictional allowance for funds used during construction	32,673		33,103
Pension and other post-retirement benefits costs	32,181		15,473
Nuclear decommissioning	30,659		43,641
La Cygne leasehold dismantling costs	25,330		22,918
Kansas tax credits	12,857		12,725
Retail energy cost adjustment	12,686		33,274
Purchase power agreement	9,972		4,377
Other regulatory liabilities	7,059		8,677
Total regulatory liabilities	$	292,811	$	343,485

Below we summarize the nature and period of recovery for each of the regulatory assets listed in the table above.

•

Deferred employee benefit costs: Includes $319.7 million for pension and post-retirement benefit obligations and $34.1 million for actual pension expense in excess of the amount of such expense recognized in setting our prices. The decrease from 2014 to 2015 is attributable primarily to an increase in the discount rates used to calculate our and Wolf Creek’s pension benefit obligations and the adoption of updated mortality tables. During 2016, we will amortize to expense approximately $26.0 million of the benefit obligations and approximately $6.8 million of the excess pension expense. We are amortizing the excess pension expense over a five-year period. We do not earn a return on this asset.

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•

Amounts due from customers for future income taxes, net: In accordance with various orders, we have reduced our prices to reflect the income tax benefits associated with certain income tax deductions, thereby passing on these benefits to customers at the time we receive them. We believe it is probable that the net future increases in income taxes payable will be recovered from customers when these temporary income tax benefits reverse in future periods. We have recorded a regulatory asset, net of the regulatory liability, for these amounts. We also have recorded a regulatory liability for our obligation to customers for income taxes recovered in earlier periods when corporate income tax rates were higher than current income tax rates. This benefit will be returned to customers as these temporary differences reverse in future periods. The income tax-related regulatory assets and liabilities as well as unamortized investment tax credits are also temporary differences for which deferred income taxes have been provided. These items are measured by the expected cash flows to be received or settled in future prices. We do not earn a return on this net asset.


•	Debt reacquisition costs: Includes costs incurred to reacquire and refinance debt. These costs are amortized over the term of the new debt. We do not earn a return on this asset.


•	Depreciation: Represents the difference between regulatory depreciation expense and depreciation expense we record for financial reporting purposes. We earn a return on this asset and amortize the difference over the life of the related plant.


•	Ad valorem tax: Represents actual costs incurred for property taxes in excess of amounts collected in our prices. We expect to recover these amounts in our prices over a one-year period. We do not earn a return on this asset.


•	Asset retirement obligations: Represents amounts associated with our AROs as discussed in Note 14, “Asset Retirement Obligations.” We recover these amounts over the life of the related plant. We do not earn a return on this asset.


•	Treasury yield hedges: Represents the effective portion of treasury yield hedge transactions. This amount will be amortized to interest expense over the term of the related debt. We do not earn a return on this asset.


•	Wolf Creek outage: We defer the expenses associated with Wolf Creek’s scheduled refueling and maintenance outages and amortize these expenses during the period between planned outages. We do not earn a return on this asset.

•

Disallowed plant costs: Originally there was a decision to disallow certain costs related to the Wolf Creek plant. Subsequently, in 1987, the Kansas Corporation Commission (KCC) revised its original conclusion and provided for recovery of an indirect disallowance with no return on investment. This regulatory asset represents the present value of the future expected revenues to be provided to recover these costs, net of the amounts amortized.

•

La Cygne environmental costs: Represents the deferral of depreciation and amortization expense and associated carrying charges related to the La Cygne Generating Station (La Cygne) environmental project from the in-service date until late October 2015, the effective date of our state general rate review. This amount will be amortized over the life of the related asset. We earn a return on this asset.


•	Energy efficiency program costs: We accumulate and defer for future recovery costs related to our various energy efficiency programs. We will amortize such costs over a one-year period. We do not earn a return on this asset.


•	Other regulatory assets: Includes various regulatory assets that individually are small in relation to the total regulatory asset balance. Other regulatory assets have various recovery periods. We do not earn a return on any of these assets.

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Below we summarize the nature and period of amortization for each of the regulatory liabilities listed in the table above.


•	Deferred regulatory gain from sale leaseback: Represents the gain KGE recorded on the 1987 sale and leaseback of its 50% interest in La Cygne unit 2. We amortize the gain over the lease term.


•	Removal costs: Represents amounts collected, but not yet spent, to dispose of plant assets that do not represent legal retirement obligations. This liability will be discharged as removal costs are incurred.


•	Jurisdictional allowance for funds used during construction: This item represents AFUDC that is accrued subsequent to the time the associated construction charges are included in our rates and prior to the time the related assets are placed in service. The AFUDC is amortized to depreciation expense over the useful life of the asset that is placed in service.


•	Pension and other post-retirement benefits costs: Represents amount of pension and other post-retirement benefits expense recognized in setting our prices in excess of actual pension and other post-retirement benefits expense. We amortize the amount over a five-year period.

•

Nuclear decommissioning: We have a legal obligation to decommission Wolf Creek at the end of its useful life. This amount represents the difference between the fair value of the assets held in a decommissioning trust and the amount recorded for the accumulated accretion and depreciation expense associated with our ARO. See Notes 4, 5 and 14, “Financial Instruments and Trading Securities,” “Financial Investments” and “Asset Retirement Obligations,” respectively, for information regarding our nuclear decommissioning trust (NDT) and our ARO.


•	La Cygne leasehold dismantling costs: We are contractually obligated to dismantle a portion of La Cygne unit 2. This item represents amounts collected but not yet spent to dismantle this unit and the obligation will be discharged as we dismantle the unit.


•	Kansas tax credits: This item represents Kansas tax credits on investments in utility plant. Amounts will be credited to customers subsequent to their realization over the remaining lives of the utility plant giving rise to the tax credits.

•

Retail energy cost adjustment: We are allowed to adjust our retail prices to reflect changes in the cost of fuel and purchased power needed to serve our customers. We bill customers based on our estimated costs. This item represents the amount we collected from customers that was in excess of our actual cost of fuel and purchased power. We will refund to customers this excess recovery over a one-year period.


•	Purchase power agreement: This item represents the amount included in retail electric rates from customers in excess of the costs incurred by us under the purchase power agreement with Westar Generating. We amortize the amount over a three-year period.


•	Other regulatory liabilities: Includes various regulatory liabilities that individually are relatively small in relation to the total regulatory liability balance. Other regulatory liabilities will be credited over various periods.

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KCC Proceedings

General and Abbreviated Rate Reviews

In September 2015, the KCC issued an order in our state general rate review allowing us to adjust our prices to include, among other things, additional investment in La Cygne environmental upgrades and investment to extend the life of Wolf Creek. The new prices were effective late October 2015 and are expected to increase our annual retail revenues by approximately $78.3 million. The KCC also approved our request to file an abbreviated rate review within 12 months of the effective date of this order to update our prices to include additional capital costs related to La Cygne environmental upgrades, investment to extend the life of Wolf Creek, costs related to programs to improve grid resiliency and costs associated with investments in other environmental projects during 2015.

In November 2013, the KCC issued an order in our state abbreviated rate review allowing us to adjust our prices to include additional investment in La Cygne environmental upgrades and to reflect cost reductions elsewhere. The new prices were expected to increase our annual retail revenues by approximately $30.7 million.

Environmental Costs

In October 2015, in connection with the state general rate review, we agreed to no longer make annual filings with the KCC to adjust our prices to include costs associated with investments in air quality equipment made during the prior year. The existing balance of costs associated with these investments were rolled into our base prices. In the future, we will need to seek approval from the KCC for individual projects. In the most recent three years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately:


•	$10.8 million effective in June 2015;


•	$11.0 million effective in June 2014; and


•	$27.3 million effective in June 2013.

Transmission Costs

We make annual filings with the KCC to adjust our prices to include updated transmission costs as reflected in our transmission formula rate (TFR) discussed below. In the most recent three years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately:


•	$7.2 million effective in April 2015;


•	$41.0 million effective in April 2014; and


•	$11.8 million effective in March 2013.

Property Tax Surcharge

We make annual filings with the KCC to adjust our prices to include the cost incurred for property taxes. In October 2015, in connection with the state general rate review, the existing balance of costs incurred for property taxes were rolled into our base prices. In the most recent four years, the KCC issued orders related to such filings allowing us to increase our annual retail revenues by approximately:


•	$5.0 million effective in January 2016;


•	$4.9 million effective in January 2015;


•	$12.7 million effective in January 2014; and


•	$15.2 million effective in January 2013.

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FERC Proceedings

In October of each year, we post an updated TFR that includes projected transmission capital expenditures and operating costs for the following year. This rate provides the basis for our annual request with the KCC to adjust our retail prices to include updated transmission costs as noted above. In the most recent four years, we posted our TFR which was expected to adjust our annual transmission revenues by approximately:


•	$21.6 million increase effective in January 2016;


•	$4.6 million decrease effective in January 2015;


•	$44.3 million increase effective in January 2014; and


•	$12.2 million increase effective in January 2013.

In August 2014, the KCC filed a complaint against us with the Federal Energy Regulatory Commission (FERC) under Section 206 of the Federal Power Act (FPA). The complaint sought to lower our base return on equity (ROE) used in determining our TFR, which would result in a refund obligation and reduce our future transmission revenues. In June 2015, we filed a settlement agreement with the FERC, which if approved, would result in an ROE of 10.3%, which consists of a 9.8% base ROE plus a 0.5% incentive ROE for participation in an RTO. In July 2015, FERC staff filed comments supporting the proposed settlement. As a result, for the year ended December 31, 2015, we recorded a liability of $13.8 million for our estimated refund obligation from the refund effective date of August 20, 2014 through December 31, 2015. In addition, we estimate our future transmission revenues would be reduced by approximately $11.0 million on an annualized basis as a result of the reduced ROE.

4. FINANCIAL INSTRUMENTS AND TRADING SECURITIES

Values of Financial Instruments

GAAP establishes a hierarchical framework for disclosing the transparency of the inputs utilized in measuring assets and liabilities at fair value. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the classification of assets and liabilities within the fair value hierarchy levels. The three levels of the hierarchy and examples are as follows:


•	Level 1 - Quoted prices are available in active markets for identical assets or liabilities. The types of assets and liabilities included in level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed on public exchanges.

•

Level 2 - Pricing inputs are not quoted prices in active markets, but are either directly or indirectly observable. The types of assets and liabilities included in level 2 are typically measured at net asset value, comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs.


•	Level 3 - Significant inputs to pricing have little or no transparency. The types of assets and liabilities included in level 3 are those with inputs requiring significant management judgment or estimation. Level 3 includes investments in private equity, real estate securities and other alternative investments, which are measured at net asset value.

We record cash and cash equivalents, short-term borrowings and variable rate debt on our consolidated balance sheets at cost, which approximates fair value. We measure the fair value of fixed rate debt, a level 2 measurement, based on quoted market prices for the same or similar issues or on the current rates offered for instruments of the same remaining maturities and redemption provisions. The recorded amount of accounts receivable and other current financial instruments approximates fair value.

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All of our level 2 investments are held in investment funds that are measured at fair value using daily net asset values. In addition, we maintain certain level 3 investments in private equity, alternative investments and real estate securities that are also measured at fair value using net asset value, but require significant unobservable market information to measure the fair value of the underlying investments. The underlying investments in private equity are measured at fair value utilizing both market- and income-based models, public company comparables, investment cost or the value derived from subsequent financings. Adjustments are made when actual performance differs from expected performance; when market, economic or company-specific conditions change; and when other news or events have a material impact on the security. The underlying alternative investments include collateralized debt obligations, mezzanine debt and a variety of other investments. The fair value of these investments is measured using a variety of primarily market-based models utilizing inputs such as security prices, maturity, call features, ratings and other developments related to specific securities. The underlying real estate investments are measured at fair value using a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity.

We measure fair value based on information available as of the measurement date. The following table provides the carrying values and measured fair values of our fixed-rate debt.



	As of December 31, 2015				As of December 31, 2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Fixed-rate debt	$	3,080,000	$	3,259,533	$	3,105,000	$	3,488,410
Fixed-rate debt of VIEs	166,271		179,030		194,204		213,579

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Recurring Fair Value Measurements

The following table provides the amounts and their corresponding level of hierarchy for our assets that are measured at fair value.



As of December 31, 2015	Level 1		Level 2		Level 3		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	50,872	$	6,050	$	56,922
International equity funds	—		33,595		—		33,595
Core bond fund	—		25,976		—		25,976
High-yield bond fund	—		15,288		—		15,288
Emerging market bond fund	—		13,584		—		13,584
Combination debt/equity/other funds	—		11,343		—		11,343
Alternative investment fund	—		—		16,439		16,439
Real estate securities fund	—		—		10,823		10,823
Cash equivalents	87		—		—		87
Total Nuclear Decommissioning Trust	87		150,658		33,312		184,057
Trading Securities:
Domestic equity funds	—		17,876		—		17,876
International equity fund	—		4,430		—		4,430
Core bond fund	—		11,423		—		11,423
Cash equivalents	159		—		—		159
Total Trading Securities	159		33,729		—		33,888
Total Assets Measured at Fair Value	$	246	$	184,387	$	33,312	$	217,945

As of December 31, 2014	Level 1		Level 2		Level 3		Total
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	—	$	54,925	$	6,047	$	60,972
International equity funds	—		30,791		—		30,791
Core bond fund	—		19,289		—		19,289
High-yield bond fund	—		13,198		—		13,198
Emerging market bond fund	—		10,988		—		10,988
Other fixed income fund	—		4,779		—		4,779
Combination debt/equity/other funds	—		18,141		—		18,141
Alternative investment fund	—		—		16,970		16,970
Real estate securities fund	—		—		9,548		9,548
Cash equivalents	340		—		—		340
Total Nuclear Decommissioning Trust	340		152,111		32,565		185,016
Trading Securities:
Domestic equity funds	—		18,698		—		18,698
International equity fund	—		4,252		—		4,252
Core bond fund	—		12,379		—		12,379
Cash equivalents	168		—		—		168
Total Trading Securities	168		35,329		—		35,497
Total Assets Measured at Fair Value	$	508	$	187,440	$	32,565	$	220,513

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The following table provides reconciliations of assets held in the NDT measured at fair value using significant level 3 inputs for the years ended December 31, 2015 and 2014.



	Domestic Equity Funds			Alternative Investment Fund			Real Estate Securities Fund			Net Balance
	(In Thousands)
Balance as of December 31, 2014	$	6,047		$	16,970		$	9,548		$	32,565
Total realized and unrealized gains and (losses) included in:
Regulatory liabilities	899			(531		)	1,275			1,643
Purchases	400			—			406			806
Sales	(1,296		)	—			(406		)	(1,702		)
Balance as of December 31, 2015	$	6,050		$	16,439		$	10,823		$	33,312

Balance as of December 31, 2013	$	5,817		$	15,675		$	8,511		$	30,003
Total realized and unrealized gains and (losses) included in:
Regulatory liabilities	391			1,295			1,037			2,723
Purchases	335			—			351			686
Sales	(496		)	—			(351		)	(847		)
Balance as of December 31, 2014	$	6,047		$	16,970		$	9,548		$	32,565

Portions of the gains and losses contributing to changes in net assets in the above table are unrealized. The following table summarizes the unrealized gains and losses we recorded to regulatory liabilities on our consolidated financial statements during the years ended December 31, 2015 and 2014, attributed to level 3 assets. See Note 3, “Rate Matters and Regulation,” for additional information regarding our regulatory assets and liabilities.



		Domestic Equity Funds			Alternative Investment Fund			Real Estate Securities Fund		Net Balance
	(In Thousands)
Total unrealized gains (losses):
Year ended December 31, 2015		$	(397	)	$	(531	)	$	869	$	(59	)
Year ended December 31, 2014		(105		)	1,296			685		1,876

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Some of our investments in the NDT and our trading securities portfolio are measured at net asset value and do not have readily determinable fair values. These investments are either with investment companies or companies that follow accounting guidance consistent with investment companies. In certain situations these investments may have redemption restrictions. The following table provides additional information on these investments.



	As of December 31, 2015				As of December 31, 2014				As of December 31, 2015
	Fair Value		Unfunded Commitments		Fair Value		Unfunded Commitments		Redemption Frequency	Length of Settlement
	(In Thousands)
Nuclear Decommissioning Trust:
Domestic equity funds	$	6,050	$	1,948	$	6,047	$	2,348	(a)	(a)
Alternative investment fund (b)	16,439		—		16,970		—		Quarterly	65 days
Real estate securities fund (c)	10,823		—		9,548		—		Quarterly	80 days
Total Nuclear Decommissioning Trust	$	33,312	$	1,948	$	32,565	$	2,348

Trading Securities:
Domestic equity funds	$	17,876	$	—	$	18,698	$	—	Upon Notice	1 day
International equity funds	4,430		—		4,252		—		Upon Notice	1 day
Core bond fund	11,423		—		12,379		—		Upon Notice	1 day
Total Trading Securities	33,729		—		35,329		—
Total	$	67,041	$	1,948	$	67,894	$	2,348

_______________

(a)

This investment is in three long-term private equity funds that do not permit early withdrawal. Our investments in these funds cannot be distributed until the underlying investments have been liquidated which may take years from the date of initial liquidation. Two funds have begun to make distributions. Our initial investment in the third fund occurred in the third quarter of 2013. This fund’s term is expected to be 15 years, subject to the general partner’s right to extend the term for up to three additional one-year periods.


(b)	There is a holdback on final redemptions.


(c)	In January 2016, we initiated a plan to sell this investment. We expect to receive proceeds in the amount of the investment’s fair value, determined as of March 31, 2016.

Derivative Instruments

Price Risk

We use various types of fuel, including coal, natural gas, uranium and diesel to operate our plants and also purchase power to meet customer demand. Our prices and consolidated financial results are exposed to market risks from commodity price changes for electricity and other energy-related products as well as from interest rates. Volatility in these markets impacts our costs of purchased power, costs of fuel for our generating plants and our participation in energy markets. We strive to manage our customers’ and our exposure to market risks through regulatory, operating and financing activities and, when we deem appropriate, we economically hedge a portion of these risks through the use of derivative financial instruments for non-trading purposes.

Interest Rate Risk

We have entered into numerous fixed and variable rate debt obligations. For details, see Note 9, “Long-Term Debt.” We manage our interest rate risk related to these debt obligations by limiting our exposure to variable interest rate debt, diversifying maturity dates and entering into treasury yield hedge transactions. We may also use other financial derivative instruments such as interest rate swaps.

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5. FINANCIAL INVESTMENTS

We report our investments in equity and debt securities at fair value and use the specific identification method to determine their realized gains and losses. We classify these investments as either trading securities or available-for-sale securities as described below.

Trading Securities

We hold equity and debt investments which we classify as trading securities in a trust used to fund certain retirement benefit obligations. These obligations totaled $27.4 million and $29.8 million as of December 31, 2015 and 2014, respectively. For additional information on our benefit obligations, see Note 11, “Employee Benefit Plans.”

As of December 31, 2015 and 2014, we measured the fair value of trust assets at $33.9 million and $35.5 million, respectively. We include unrealized gains or losses on these securities in investment earnings on our consolidated statements of income. For the years ended December 31, 2015, 2014 and 2013, we recorded unrealized gains of $0.4 million, $2.6 million and $6.7 million, respectively, on assets still held.

Available-for-Sale Securities

We hold investments in a trust for the purpose of funding the decommissioning of Wolf Creek. We have classified these investments as available-for-sale and have recorded all such investments at their fair market value as of December 31, 2015 and 2014.

Using the specific identification method to determine cost, we realized a loss on our available-for-sale securities of $0.9 million in 2015. In 2014 and 2013, we realized gains on our available-for-sale securities of $0.1 million and $5.3 million, respectively. We record net realized and unrealized gains and losses in regulatory liabilities on our consolidated balance sheets. This reporting is consistent with the method we use to account for the decommissioning costs we recover in our prices. Gains or losses on assets in the trust fund are recorded as increases or decreases, respectively, to regulatory liabilities and could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in the prices paid by our customers.

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The following table presents the cost, gross unrealized gains and losses, fair value and allocation of investments in the NDT fund as of December 31, 2015 and 2014.



			Gross Unrealized
Security Type	Cost		Gain		Loss			Fair Value		Allocation
	(Dollars In Thousands)
As of December 31, 2015:
Domestic equity funds	$	49,488	$	7,436	$	(2	)	$	56,922	32	%
International equity funds	33,458		1,372		(1,235		)	33,595		18	%
Core bond fund	26,397		—		(421		)	25,976		14	%
High-yield bond fund	17,047		—		(1,759		)	15,288		8	%
Emerging market bond fund	16,306		—		(2,722		)	13,584		7	%
Combination debt/equity/other funds	8,239		3,104		—			11,343		6	%
Alternative investment fund	15,000		1,439		—			16,439		9	%
Real estate securities fund	11,026		—		(203		)	10,823		6	%
Cash equivalents	87		—		—			87		<1%
Total	$	177,048	$	13,351	$	(6,342	)	$	184,057	100	%

As of December 31, 2014:
Domestic equity funds	$	46,126	$	14,853	$	(7	)	$	60,972	33	%
International equity funds	27,521		3,683		(413		)	30,791		17	%
Core bond fund	18,811		478		—			19,289		10	%
High-yield bond fund	13,342		—		(144		)	13,198		7	%
Emerging market bond fund	12,556		—		(1,568		)	10,988		6	%
Other fixed income fund	4,798		—		(19		)	4,779		3	%
Combination debt/equity/other funds	14,975		3,786		(620		)	18,141		10	%
Alternative investment fund	15,000		1,970		—			16,970		9	%
Real estate securities fund	10,619		—		(1,071		)	9,548		5	%
Cash equivalents	340		—		—			340		<1%
Total	$	164,088	$	24,770	$	(3,842	)	$	185,016	100	%

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The following table presents the fair value and the gross unrealized losses of the available-for-sale securities held in the NDT fund aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position as of December 31, 2015 and 2014.



	Less than 12 Months					12 Months or Greater					Total
	Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses			Fair Value		Gross Unrealized Losses
	(In Thousands)
As of December 31, 2015:
Domestic equity funds	$	—	$	—		$	668	$	(2	)	$	668	$	(2	)
International equity funds	—		—			6,717		(1,235		)	6,717		(1,235		)
Core bond funds	25,976		(421		)	—		—			25,976		(421		)
High-yield bond fund	15,288		(1,759		)	—		—			15,288		(1,759		)
Emerging market bond fund	—		—			13,584		(2,722		)	13,584		(2,722		)
Real estate securities fund	—		—			10,823		(203		)	10,823		(203		)
Total	$	41,264	$	(2,180	)	$	31,792	$	(4,162	)	$	73,056	$	(6,342	)

As of December 31, 2014:
Domestic equity funds	$	—	$	—		$	263	$	(7	)	$	263	$	(7	)
International equity funds	5,905		(413		)	—		—			5,905		(413		)
High-yield bond fund	13,198		(144		)	—		—			13,198		(144		)
Emerging market bond fund	—		—			10,988		(1,568		)	10,988		(1,568		)
Other fixed income fund	4,779		(19		)	—		—			4,779		(19		)
Combination debt/equity/other funds	—		—			5,892		(620		)	5,892		(620		)
Real estate securities fund	—		—			9,548		(1,071		)	9,548		(1,071		)
Total	$	23,882	$	(576	)	$	26,691	$	(3,266	)	$	50,573	$	(3,842	)

6. PROPERTY, PLANT AND EQUIPMENT

The following is a summary of our property, plant and equipment balance.



	As of December 31,
	2015			2014
	(In Thousands)
Electric plant in service	$	11,449,933		$	10,620,292
Electric plant acquisition adjustment	802,318			802,318
Accumulated depreciation	(4,178,885		)	(4,112,483		)
	8,073,366			7,310,127
Construction work in progress	349,402			773,144
Nuclear fuel, net	68,349			79,637
Plant to be retired, net (a)	33,785			—
Net property, plant and equipment	$	8,524,902		$	8,162,908

_______________

(a) Represents the retirement of analog meters prior to the end of their remaining useful lives due to modernization of meter technology.

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	As of December 31,
	2015			2014
	(In Thousands)
Electric plant of VIEs	$	497,999		$	497,999
Accumulated depreciation of VIEs	(229,760		)	(219,426		)
Net property, plant and equipment of VIEs	$	268,239		$	278,573

We recorded depreciation expense on property, plant and equipment of $287.9 million in 2015, $263.8 million in 2014 and $249.9 million in 2013. Approximately $9.6 million, $9.7 million and $9.7 million of depreciation expense in 2015, 2014 and 2013, respectively, was attributable to property, plant and equipment of VIEs.

7. JOINT OWNERSHIP OF UTILITY PLANTS

Under joint ownership agreements with other utilities, we have undivided ownership interests in four electric generating stations. Energy generated and operating expenses are divided on the same basis as ownership with each owner reflecting its respective costs in its statements of income and each owner responsible for its own financing. Information relative to our ownership interests in these facilities as of December 31, 2015, is shown in the table below.



Plant	In-Service Dates	Investment		Accumulated Depreciation		Construction Work in Progress		Net MW	Ownership Percentage
		(Dollars in Thousands)
La Cygne unit 1 (a)	June 1973	$	602,599	$	152,737	$	22,461	368	50
JEC unit 1 (a)	July 1978	816,051		188,649		800		670	92
JEC unit 2 (a)	May 1980	546,955		200,286		10,112		651	92
JEC unit 3 (a)	May 1983	715,624		325,599		18,959		654	92
Wolf Creek (b)	Sept. 1985	1,880,243		817,353		72,864		551	47
State Line (c)	June 2001	111,451		57,828		263		196	40
Total		$	4,672,923	$	1,742,452	$	125,459	3,090

_______________


(a)	Jointly owned with Kansas City Power & Light Company (KCPL). Our 8% leasehold interest in Jeffrey Energy Center (JEC) that is consolidated as a VIE is reflected in the net megawatts (MW) and ownership percentage provided above, but not in the other amounts in the table.


(b)	Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.

We include in operating expenses on our consolidated statements of income our share of operating expenses of the above plants. Our share of fuel expense for the above plants is generally based on the amount of power we take from the respective plants. Our share of other transactions associated with the plants is included in the appropriate classification on our consolidated financial statements.

In addition, we also consolidate a VIE that holds our 50% leasehold interest in La Cygne unit 2, which represents 331 MW of net capacity. The VIE’s investment in the 50% interest was $392.1 million and accumulated depreciation was $201.6 million as of December 31, 2015. We include these amounts in property, plant and equipment of VIEs, net on our consolidated balance sheets. See Note 17, “Variable Interest Entities,” for additional information about VIEs.

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8. SHORT-TERM DEBT

In September 2015, Westar Energy extended the term of its $730.0 million revolving credit facility to terminate in September 2019, $20.7 million of which will expire in September 2017. As long as there is no default under the facility, Westar Energy may extend the facility up to an additional year and may increase the aggregate amount of borrowings under the facility to $1.0 billion, both subject to lender participation. All borrowings under the facility are secured by KGE first mortgage bonds. As of December 31, 2015, no amounts had been borrowed and $19.2 million of letters of credit had been issued under this revolving credit facility. As of December 31, 2014, no amounts had been borrowed and $15.6 million of letters of credit had been issued under this revolving credit facility.

In February 2014, Westar Energy extended the term of the $270.0 million revolving credit facility to February 2017, of which $20.0 million of this facility was scheduled to terminate in February 2016. In April 2015, the $20.0 million was extended to also terminate in February 2017. So long as there is no default under the facility, Westar Energy may increase the aggregate amount of borrowings under the facility to $400.0 million, subject to lender participation. All borrowings under the facility are secured by KGE first mortgage bonds. As of December 31, 2015 and 2014, Westar Energy had no borrowed amounts or letters of credit outstanding under this revolving credit facility.

Westar Energy maintains a commercial paper program pursuant to which it may issue commercial paper up to a maximum aggregate amount outstanding at any one time of $1.0 billion. This program is supported by Westar Energy’s revolving credit facilities. Maturities of commercial paper issuances may not exceed 365 days from the date of issuance and proceeds from such issuances will be used to temporarily fund capital expenditures, to redeem debt on an interim basis, for working capital and/or for other general corporate purposes. Westar Energy had $250.3 million and $257.6 million of commercial paper issued and outstanding as of December 31, 2015 and 2014, respectively.

In addition, total combined borrowings under Westar Energy’s commercial paper program and revolving credit facilities may not exceed $1.0 billion at any given time. The weighted average interest rate on short-term borrowings outstanding as of December 31, 2015 and 2014, was 0.77% and 0.52%, respectively. Additional information regarding our short-term debt is as follows.



	Year Ended December 31,
	2015			2014
	(Dollars in Thousands)
Weighted average short-term debt outstanding	$	350,380		$	232,336
Weighted daily average interest rates, excluding fees	0.48		%	0.30		%

Our interest expense on short-term debt was $3.0 million in 2015, $2.0 million in 2014 and $2.4 million in 2013.

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9. LONG-TERM DEBT

Outstanding Debt

The following table summarizes our long-term debt outstanding.



	As of December 31,
	2015			2014
	(In Thousands)
Westar Energy
First mortgage bond series:
5.15% due 2017	$	125,000		$	125,000
8.625% due 2018	—			300,000
5.10% due 2020	250,000			250,000
3.25% due 2025	250,000			—
5.95% due 2035	—			125,000
5.875% due 2036	—			150,000
4.125% due 2042	550,000			550,000
4.10% due 2043	430,000			430,000
4.625% due 2043	250,000			250,000
4.25% due 2045	300,000			—
	2,155,000			2,180,000
Pollution control bond series:
Variable due 2032, 0.02% as of December 31, 2015; 0.06% as of December 31, 2014	45,000			45,000
Variable due 2032, 0.02% as of December 31, 2015; 0.08% as of December 31, 2014	30,500			30,500
	75,500			75,500

KGE
First mortgage bond series:
6.70% due 2019	300,000			300,000
6.15% due 2023	50,000			50,000
6.53% due 2037	175,000			175,000
6.64% due 2038	100,000			100,000
4.30% due 2044	250,000			250,000
	875,000			875,000
Pollution control bond series:
Variable due 2027, 0.02% as of December 31, 2015; 0.08% as of December 31, 2014	21,940			21,940
4.85% due 2031 (c)	50,000			50,000
Variable due 2032, 0.02% as of December 31, 2015; 0.08% as of December 31, 2014	14,500			14,500
Variable due 2032, 0.02% as of December 31, 2015; 0.08% as of December 31, 2014	10,000			10,000
	96,440			96,440

Total long-term debt	3,201,940			3,226,940
Unamortized debt discount (a)	(10,374		)	(11,401		)
Unamortized debt issuance expense (a)	(27,616		)	(28,459		)
Long-term debt, net	$	3,163,950		$	3,187,080

Variable Interest Entities
5.92% due 2019 (b)	$	4,223		$	8,413
5.647% due 2021 (b)	162,048			185,791
Total long-term debt of variable interest entities	166,271			194,204
Unamortized debt premium (a)	135			294
Long-term debt of variable interest entities due within one year	(28,309		)	(27,933		)
Long-term debt of variable interest entities, net	$	138,097		$	166,565

_______________

(a) We amortize debt discounts and issuance expense to interest expense over the term of the respective issues.

(b) Portions of our payments related to this debt reduce the principal balances each year until maturity.

The Westar Energy and KGE mortgages each contain provisions restricting the amount of first mortgage bonds that could be issued by each entity. We must comply with such restrictions prior to the issuance of additional first mortgage bonds or other secured indebtedness.

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The amount of Westar Energy first mortgage bonds authorized by its Mortgage and Deed of Trust, dated July 1, 1939, as supplemented, is subject to certain limitations as described below. The amount of KGE first mortgage bonds authorized by the KGE Mortgage and Deed of Trust, dated April 1, 1940, as supplemented and amended, is limited to a maximum of $3.5 billion, unless amended further. First mortgage bonds are secured by utility assets. Amounts of additional bonds that may be issued are subject to property, earnings and certain restrictive provisions, except in connection with certain refundings, of each mortgage. As of December 31, 2015, approximately $851.0 million principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in Westar Energy’s mortgage. As of December 31, 2015, approximately $1.5 billion principal amount of additional KGE first mortgage bonds could be issued under the most restrictive provisions in KGE’s mortgage.

In February 2016, KGE, as lessee to the La Cygne sale-leaseback, effected a refunding of $162.1 million in outstanding bonds held by the trustee of the lease maturing March 2021. The stated interest rate of the bonds was reduced from 5.647% to 2.398%. See Note 17, “Variable Interest Entities,” for additional information regarding our La Cygne sale-leaseback.

In August 2015, Westar Energy redeemed $150.0 million in principal amount of first mortgage bonds bearing stated interest at 5.875% and maturing July 2036.

In January 2015, Westar Energy redeemed $125.0 million in principal amount of first mortgage bonds bearing stated interest at 5.95% and maturing January 2035.

In July 2014, KGE issued $250.0 million in principal amount of first mortgage bonds bearing stated interest at 4.30% and maturing July 2044, the proceeds of which were used to retire Westar Energy first mortgage bonds in a principal amount of $250.0 million with a stated interest of 6.00% maturing in July 2014.

In June 2014, KGE redeemed $177.5 million in principal amount of pollution control bonds bearing stated interest rates between 5.00% and 5.30%.

In May 2014, Westar Energy issued $180.0 million in principal amount of first mortgage bonds bearing stated interest at 4.10% and maturing April 2043. These bonds constitute a further issuance of a series of bonds initially issued in March 2013 in a principal amount of $250.0 million.

Proceeds from issuances were used to repay short-term debt, which was used to purchase capital equipment, to redeem bonds and for working capital and general corporate purposes.

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Maturities

The principal amounts of our long-term debt maturities as of December 31, 2015, are as follows.



Year	Long-term debt		Long-term debt of VIEs
	(In Thousands)
2016	$	—	$	28,309
2017	125,000		26,842
2018	—		28,538
2019	300,000		31,485
2020	250,000		32,254
Thereafter	2,526,940		18,843
Total maturities	$	3,201,940	$	166,271

Interest expense on long-term debt, net of debt AFUDC, was $152.7 million in 2015, $158.8 million in 2014 and $154.9 million in 2013. Interest expense on long-term debt of VIEs was $9.8 million in 2015, $11.4 million in 2014 and $13.0 million in 2013.

10. TAXES

Income tax expense is comprised of the following components.



	Year Ended December 31,
	2015			2014			2013
	(In Thousands)
Income Tax Expense (Benefit):
Current income taxes:
Federal	$	327		$	416		$	135
State	341			(597		)	279
Deferred income taxes:
Federal	124,891			124,923			102,030
State	29,484			29,657			24,443
Investment tax credit amortization	(3,043		)	(3,129		)	(3,166		)
Income tax expense	$	152,000		$	151,270		$	123,721

The tax effect of the temporary differences and carryforwards that comprise our deferred tax assets and deferred tax liabilities are summarized in the following table.

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	As of December 31,
	2015		2014
	(In Thousands)
Deferred tax assets:
Tax credit carryforward (a)	$	266,963	$	257,827
Net operating loss carryforward (b)	129,232		179,285
Deferred employee benefit costs	122,757		158,102
Deferred state income taxes	67,307		66,557
Deferred regulatory gain on sale-leaseback	33,287		35,706
Deferred compensation	27,266		29,315
Alternative minimum tax carryforward (c)	26,725		24,114
Accrued liabilities	21,115		23,048
Disallowed costs	10,211		10,829
LaCygne dismantling cost	10,018		9,064
Capital loss carryforward (d)	1,668		1,981
Other	41,319		27,689
Total gross deferred tax assets	757,868		823,517
Less: Valuation allowance (e)	1,668		1,981
Deferred tax assets	$	756,200	$	821,536

Deferred tax liabilities:
Accelerated depreciation	$	1,787,457	$	1,664,367
Acquisition premium	155,881		163,894
Amounts due from customers for future income taxes, net	144,120		153,984
Deferred employee benefit costs	122,757		158,102
Deferred state income taxes	59,787		59,170
Debt reacquisition costs	42,314		20,102
Pension expense tracker	12,051		14,187
Storm costs	—		15,713
Other	23,263		17,868
Total deferred tax liabilities	$	2,347,630	$	2,267,387

Net deferred income tax liabilities	$	1,591,430	$	1,445,851

_______________

(a)

Based on filed tax returns and amounts expected to be reported in current year tax returns (December 31, 2015), we had available federal general business tax credits of $80.9 million and state investment tax credits of $186.1 million. The federal general business tax credits were primarily generated from production tax credits. These tax credits expire beginning in 2020 and ending in 2035. The state investment tax credits expire beginning in 2017 and ending in 2031.


(b)	As of December 31, 2015, we had a federal net operating loss carryforward of $326.5 million, which is available to offset federal taxable income. The net operating losses will expire beginning in 2031 and ending in 2034.


(c)	As of December 31, 2015, we had available an alternative minimum tax credit carryforward of $26.7 million, which has an unlimited carryforward period.


(d)	As of December 31, 2015, we had an unused capital loss carryforward of $4.2 million that is available to offset future capital gains. The capital losses will expire in 2016.


(e)	As we do not expect to realize any significant capital gains in the future, we have established a valuation allowance of $1.7 million. The total valuation allowance related to the deferred tax assets was $1.7 million as of December 31, 2015, and $2.0 million as of December 31, 2014.

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In accordance with various orders, we have reduced our prices to reflect the income tax benefits associated with certain accelerated income tax deductions. We believe it is probable that the net future increases in income taxes payable will be recovered from customers when these temporary income tax benefits reverse. We have recorded a regulatory asset for these amounts. We also have recorded a regulatory liability for our obligation to reduce the prices charged to customers for deferred income taxes recovered from customers at corporate income tax rates higher than current income tax rates. The price reduction will occur as the temporary differences resulting in the excess deferred income tax liabilities reverse. The income tax-related regulatory assets and liabilities as well as unamortized investment tax credits are also temporary differences for which deferred income taxes have been provided. The net deferred income tax liability related to these temporary differences is classified above as amounts due from customers for future income taxes, net.

Our effective income tax rates are computed by dividing total federal and state income taxes by the sum of such taxes and net income. The difference between the effective income tax rates and the federal statutory income tax rates are as follows.



	Year Ended December 31,
	2015		2014		2013
Statutory federal income tax rate	35.0	%	35.0	%	35.0	%
Effect of:
COLI policies	(4.4	)	(4.0	)	(5.4	)
State income taxes	4.3		4.0		3.8
Flow through depreciation for plant-related differences	2.6		2.0		2.2
Production tax credits	(2.1	)	(2.1	)	(2.3	)
Amortization of federal investment tax credits	(0.7	)	(0.7	)	(0.7	)
AFUDC equity	(0.2	)	(1.3	)	(1.2	)
Capital loss utilization carryforward	(0.1	)	(0.3	)	(1.1	)
Liability for unrecognized income tax benefits	—		(0.2	)	0.1
Other	(0.9	)	(0.5	)	(1.3	)
Effective income tax rate	33.5	%	31.9	%	29.1	%

We file income tax returns in the U.S. federal jurisdiction as well as various state jurisdictions. The income tax returns we file will likely be audited by the Internal Revenue Service or other tax authorities. With few exceptions, the statute of limitations with respect to U.S. federal or state and local income tax examinations by tax authorities remains open for tax year 2012 and forward.

The unrecognized income tax benefits decreased from $3.2 million at December 31, 2014, to $2.9 million at December 31, 2015. The decrease for unrecognized income tax benefits was largely attributable to tax positions expected to be taken with respect to potential deductions related to an environmental settlement agreement in a tax period for which the statute of limitations has closed. We do not expect significant changes in the unrecognized income tax benefits in the next 12 months. A reconciliation of the beginning and ending amounts of unrecognized income tax benefits is as follows:



	2015			2014			2013
	(In Thousands)
Unrecognized income tax benefits as of January 1	$	3,188		$	1,703		$	1,219
Additions based on tax positions related to the current year	410			872			224
Additions for tax positions of prior years	—			813			325
Reductions for tax positions of prior years	(86		)	(200		)	(65		)
Lapse of statute of limitations	(611		)	—			—
Settlements	—			—			—
Unrecognized income tax benefits as of December 31	$	2,901		$	3,188		$	1,703

The amounts of unrecognized income tax benefits that, if recognized, would favorably impact our effective income tax rate, were $2.9 million, $3.2 million and $2.4 million (net of tax) as of December 31, 2015, 2014 and 2013, respectively.

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Interest related to income tax uncertainties is classified as interest expense and accrued interest liability. As of December 31, 2015 and 2014, we had no amounts accrued for interest related to unrecognized income tax benefits. We accrued no penalties at either December 31, 2015 or 2014.

As of December 31, 2015 and 2014, we had recorded $1.5 million for probable assessments of taxes other than income taxes.

11. EMPLOYEE BENEFIT PLANS

Pension and Post-Retirement Benefit Plans

We maintain a qualified non-contributory defined benefit pension plan covering substantially all of our employees. For the majority of our employees, pension benefits are based on years of service and an employee’s compensation during the 60 highest paid consecutive months out of 120 before retirement. Non-union employees hired after December 31, 2001, and union employees hired after December 31, 2011, are covered by the same defined benefit pension plan; however, their benefits are derived from a cash balance account formula. We also maintain a non-qualified Executive Salary Continuation Plan for the benefit of certain retired executive officers. We have discontinued accruing any future benefits under this non-qualified plan.

The amount we contribute to our pension plan for future periods is not yet known, however, we expect to fund our pension plan each year at least to a level equal to current year pension expense. We must also meet minimum funding requirements under the Employee Retirement Income Security Act, as amended by the Pension Protection Act. We may contribute additional amounts from time to time as deemed appropriate.

In addition to providing pension benefits, we provide certain post-retirement health care and life insurance benefits for substantially all retired employees. We accrue and recover in our prices the costs of post-retirement benefits during an employee’s years of service. In 2014 and prior years, our retirees were covered under a health insurance policy. In January 2015, we began giving our retirees a fixed annual allowance, which provides them the flexibility to obtain health coverage in the marketplace that is tailored to their needs.

As a co-owner of Wolf Creek, KGE is indirectly responsible for 47% of the liabilities and expenses associated with the Wolf Creek pension and post-retirement benefit plans. See Note 12, “Wolf Creek Employee Benefit Plans,” for information about Wolf Creek’s benefit plans.

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The following tables summarize the status of our pension and post-retirement benefit plans.



	Pension Benefits						Post-retirement Benefits
As of December 31,	2015			2014			2015			2014
	(In Thousands)
Change in Benefit Obligation:
Benefit obligation, beginning of year	$	1,030,645		$	823,780		$	141,516		$	133,061
Service cost	21,392			16,218			1,443			1,381
Interest cost	43,014			41,600			5,691			6,351
Plan participants’ contributions	—			—			582			4,232
Benefits paid	(44,945		)	(39,225		)	(6,549		)	(12,184		)
Actuarial (gains) losses	(90,644		)	188,272			(16,399		)	16,509
Amendments	5,731			—			—			(7,834		)
Benefit obligation, end of year (a)	$	965,193		$	1,030,645		$	126,284		$	141,516

Change in Plan Assets:
Fair value of plan assets, beginning of year	$	661,141		$	609,817		$	121,349		$	121,766
Actual return on plan assets	(6,948		)	61,291			(208		)	7,189
Employer contributions	41,000			26,400			—			—
Plan participants’ contributions	—			—			534			4,074
Benefits paid	(41,248		)	(36,367		)	(6,259		)	(11,680		)
Fair value of plan assets, end of year	$	653,945		$	661,141		$	115,416		$	121,349

Funded status, end of year	$	(311,248	)	$	(369,504	)	$	(10,868	)	$	(20,167	)

Amounts Recognized in the Balance Sheets Consist of:
Current liability	$	(2,745	)	$	(2,716	)	$	(344	)	$	(246	)
Noncurrent liability	(308,503		)	(366,788		)	(10,524		)	(19,921		)
Net amount recognized	$	(311,248	)	$	(369,504	)	$	(10,868	)	$	(20,167	)

Amounts Recognized in Regulatory Assets Consist of:
Net actuarial loss (gain)	$	254,085		$	329,572		$	(12,208	)	$	(2,253	)
Prior service cost	8,078			2,867			3,130			3,585
Net amount recognized	$	262,163		$	332,439		$	(9,078	)	$	1,332

_______________

(a) As of December 31, 2015 and 2014, pension benefits include non-qualified benefit obligations of $27.4 million and $29.8 million, respectively, which are funded by a trust containing assets of $33.9 million and $35.5 million, respectively, classified as trading securities. The assets in the aforementioned trust are not included in the table above. See Notes 4 and 5, “Financial Instruments and Trading Securities” and “Financial Investments,” respectively, for additional information regarding these amounts.



	Pension Benefits						Post-retirement Benefits
As of December 31,	2015			2014			2015			2014
	(Dollars in Thousands)
Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:
Projected benefit obligation	$	965,193		$	1,030,645		$	—		$	—
Fair value of plan assets	653,945			661,141			—			—

Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:
Accumulated benefit obligation	$	864,263		$	914,800		—			—
Fair value of plan assets	653,945			661,141			—			—

Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:
Accumulated post-retirement benefit obligation	—			—			$	126,284		$	141,516
Fair value of plan assets	—			—			115,416			121,349

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:
Discount rate	4.60		%	4.17		%	4.51		%	4.10		%
Compensation rate increase	4.00		%	4.00		%	—			—

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We use a measurement date of December 31 for our pension and post-retirement benefit plans. The discount rate used to determine the current year pension obligation and the following year’s pension expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality, non-callable corporate bonds that generate sufficient cash flow to provide for the projected benefit payments of the plan. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan’s projected benefit payments discounted at this rate with the market value of the bonds selected. The increase in the discount rates used as of December 31, 2015, decreased the pension and post-retirement benefit obligations by approximately $59.6 million and $5.8 million, respectively.

We utilize actuarial assumptions about mortality to calculate the pension and post-retirement benefit obligations. In 2015, a revised mortality table was issued reflecting updated future projections of life expectancies based on additional years of actual mortality experience. We adopted a modified version of the revised mortality table as of December 31, 2015, resulting in a decrease to the pension and post-retirement benefit obligations by approximately $27.3 million and $1.8 million, respectively.

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We amortize prior service cost on a straight-line basis over the average future service of the active employees (plan participants) benefiting under the plan at the time of the amendment. We amortize the net actuarial gain or loss on a straight-line basis over the average future service of active plan participants benefiting under the plan without application of an amortization corridor. The KCC allows us to record a regulatory asset or liability to track the cumulative difference between current year pension and post-retirement benefits expense and the amount of such expense recognized in setting our prices. We accumulate such regulatory asset or liability between general rate reviews and amortize the accumulated amount as part of resetting our base prices. Following is additional information regarding our pension and post-retirement benefit plans.



	Pension Benefits									Post-retirement Benefits
Year Ended December 31,	2015			2014			2013			2015			2014			2013
	(Dollars in Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	21,392		$	16,218		$	21,420		$	1,443		$	1,381		$	2,028
Interest cost	43,014			41,600			38,520			5,691			6,351			6,007
Expected return on plan assets	(40,236		)	(36,438		)	(33,405		)	(6,614		)	(6,576		)	(6,691		)
Amortization of unrecognized:
Transition obligation, net	—			—			—			—			—			325
Prior service costs	520			526			601			455			2,524			2,524
Actuarial loss (gain), net	32,131			19,362			33,914			379			(742		)	1,125
Net periodic cost before regulatory adjustment	56,821			41,268			61,050			1,354			2,938			5,318
Regulatory adjustment (a)	6,886			15,479			3,693			4,096			4,499			2,922
Net periodic cost	$	63,707		$	56,747		$	64,743		$	5,450		$	7,437		$	8,240

Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:
Current year actuarial (gain) loss	$	(43,459	)	$	162,569		$	(163,086	)	$	(9,576	)	$	15,896		$	(30,201	)
Amortization of actuarial (loss) gain	(32,379		)	(19,362		)	(33,914		)	(379		)	742			(1,125		)
Current year prior service cost	5,730			—			—			—			(7,834		)	—
Amortization of prior service costs	(520		)	(526		)	(601		)	(455		)	(2,524		)	(2,525		)
Amortization of transition obligation	—			—			—			—			—			(325		)
Other adjustments	352			—			—			—			—			—
Total recognized in regulatory assets	$	(70,276	)	$	142,681		$	(197,601	)	$	(10,410	)	$	6,280		$	(34,176	)

Total recognized in net periodic cost and regulatory assets	$	(6,569	)	$	199,428		$	(132,858	)	$	(4,960	)	$	13,717		$	(25,936	)

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost (Benefit):
Discount rate	4.17		%	5.07		%	4.13		%	4.10		%	4.88		%	3.99		%
Expected long-term return on plan assets	6.50		%	6.50		%	6.50		%	6.00		%	6.00		%	6.00		%
Compensation rate increase	4.00		%	4.00		%	4.00		%	4.00		%	4.00		%	4.00		%

_______________


(a)	The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices.

We estimate that we will amortize the following amounts from regulatory assets and regulatory liabilities into net periodic cost in 2016.



	Pension Benefits		Post-retirement Benefits
	(In Thousands)
Actuarial loss (gain)	$	20,559	$	(1,118	)
Prior service cost	987		455
Total	$	21,546	$	(663	)

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We base the expected long-term rate of return on plan assets on historical and projected rates of return for current and planned asset classes in the plans’ investment portfolios. We select assumed projected rates of return for each asset class after analyzing long-term historical experience and future expectations of the volatility of the various asset classes. Based on target asset allocations for each asset class, we develop an overall expected rate of return for the portfolios, adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets.

Plan Assets

We believe we manage pension and post-retirement benefit plan assets in a prudent manner with regard to preserving principal while providing reasonable returns. We have adopted a long-term investment horizon such that the chances and duration of investment losses are weighed against the long-term potential for appreciation of assets. Part of our strategy includes managing interest rate sensitivity of plan assets relative to the associated liabilities. The primary objective of the pension plan is to provide a source of retirement income for its participants and beneficiaries, and the primary financial objective of the plan is to improve its funded status. The primary objective of the post-retirement benefit plan is growth in assets and preservation of principal, while minimizing interim volatility, to meet anticipated claims of plan participants. We delegate the management of our pension and post-retirement benefit plan assets to independent investment advisors who hire and dismiss investment managers based upon various factors. The investment advisors are instructed to diversify investments across asset classes, sectors and manager styles to minimize the risk of large losses, based upon objectives and risk tolerance specified by management, which include allowable and/or prohibited investment types. We measure and monitor investment risk on an ongoing basis through quarterly investment portfolio reviews and annual liability measurements.

We have established certain prohibited investments for our pension and post-retirement benefit plans. Such prohibited investments include loans to the company or its officers and directors as well as investments in the company’s debt or equity securities, except as may occur indirectly through investments in diversified mutual funds. In addition, to reduce concentration of risk, the pension plan will not invest in any fund that holds more than 25% of its total assets to be invested in the securities of one or more issuers conducting their principal business activities in the same industry. This restriction does not apply to investments in securities issued or guaranteed by the U.S. government or its agencies.

Target allocations for our pension plan assets are approximately 39% to debt securities, 39% to equity securities, 12% to alternative investments such as real estate securities, hedge funds and private equity investments, and the remaining 10% to a fund which provides tactical portfolio overlay by investing in debt and equity securities. Our investments in equity include investment funds with underlying investments in domestic and foreign large-, mid- and small-cap companies, derivatives related to such holdings, private equity investments including late-stage venture investments and other investments. Our investments in debt include core and high-yield bonds. Core bonds are comprised of investment funds with underlying investments in investment grade debt securities of corporate entities, obligations of U.S. and foreign governments and their agencies and other debt securities. High-yield bonds include investment funds with underlying investments in non-investment grade debt securities of corporate entities, obligations of foreign governments and their agencies, private debt securities and other debt securities. Real estate securities consist primarily of funds invested in core real estate throughout the U.S. while alternative funds invest in wide ranging investments including equity and debt securities of domestic and foreign corporations, debt securities issued by U.S. and foreign governments and their agencies, structured debt, warrants, exchange-traded funds, derivative instruments, private investment funds and other investments.

Target allocations for our post-retirement benefit plan assets are 65% to equity securities and 35% to debt securities. Our investments in equity securities include investment funds with underlying investments primarily in domestic and foreign large-, mid- and small-cap companies. Our investments in debt securities include a core bond fund with underlying investments in investment grade debt securities of domestic and foreign corporate entities, obligations of U.S. and foreign governments and their agencies, private placement securities and other investments.

Similar to other assets measured at fair value, GAAP establishes a hierarchal framework for disclosing the transparency of the inputs utilized in measuring pension and post-retirement benefit plan assets at fair value. From time to time, the pension and post-retirement benefits trusts may buy and sell investments resulting in changes within the hierarchy. See Note 4, “Financial Instruments and Trading Securities,” for a description of the hierarchal framework.

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All level 2 pension investments are held in investment funds that are measured at fair value using daily net asset values as reported by the trustee, invested directly in long-term U.S. Treasury securities. We also maintain certain level 3 investments in private equity, alternative investments and real estate securities that are also measured at fair value using net asset value, but require significant unobservable market information to measure the fair value of the underlying investments. The underlying investments in private equity are measured at fair value utilizing both market- and income-based models, public company comparables, investment cost or the value derived from subsequent financings. Adjustments are made when actual performance differs from expected performance; when market, economic or company-specific conditions change; and when other news or events have a material impact on the security. The underlying alternative investments include collateralized debt obligations, mezzanine debt and a variety of other investments. The fair value of these investments is measured using a variety of primarily market-based models utilizing inputs such as security prices, maturity, call features, ratings and other developments related to specific securities. The underlying real estate investments are measured at fair value using a combination of market- and income-based models utilizing market discount rates, projected cash flows and the estimated value into perpetuity.

The following table provides the fair value of our pension plan assets and the corresponding level of hierarchy as of December 31, 2015 and 2014.



As of December 31, 2015	Level 1		Level 2		Level 3		Total
	(In Thousands)
Assets:
Domestic equity funds	$	—	$	165,506	$	25,277	$	190,783
International equity fund	—		75,453		—		75,453
Emerging market equity fund	—		20,798		—		20,798
Domestic bond fund	—		105,279		—		105,279
Core bond funds	—		99,726		—		99,726
High-yield bond fund	—		28,288		—		28,288
Emerging market bond fund	—		23,019		—		23,019
Combination debt/equity/other fund	—		36,151		—		36,151
Alternative investment funds	—		—		39,557		39,557
Real estate securities fund	—		—		30,173		30,173
Cash equivalents	—		4,718		—		4,718
Total Assets Measured at Fair Value	$	—	$	558,938	$	95,007	$	653,945

As of December 31, 2014	Level 1		Level 2		Level 3		Total
Assets:	(In Thousands)
Domestic equity funds	$	—	$	160,574	$	23,996	$	184,570
International equity fund	—		82,604		—		82,604
Core bond funds	—		224,740		—		224,740
High-yield bond fund	—		20,412		—		20,412
Emerging market bond fund	—		14,685		—		14,685
Combination debt/equity/other fund	—		61,632		—		61,632
Alternative investment funds	—		—		41,141		41,141
Real estate securities fund	—		—		26,439		26,439
Cash equivalents	—		4,918		—		4,918
Total Assets Measured at Fair Value	$	—	$	569,565	$	91,576	$	661,141

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The following table provides a reconciliation of pension plan assets measured at fair value using significant level 3 inputs for the years ended December 31, 2015 and 2014.



	Domestic Equity Funds			Alternative Investment Funds			Real Estate Securities Fund			Total
	(In Thousands)
Balance as of December 31, 2014	$	23,996		$	41,141		$	26,439		$	91,576
Actual gain (loss) on plan assets:
Relating to assets still held at the reporting date	934			(1,584		)	3,944			3,294
Relating to assets sold during the period	2,755			—			60			2,815
Purchases, issuances and settlements, net	(2,408		)	—			(270		)	(2,678		)
Balance as of December 31, 2015	$	25,277		$	39,557		$	30,173		$	95,007

Balance as of December 31, 2013	$	22,488		$	39,171		$	24,022		$	85,681
Actual gain (loss) on plan assets:
Relating to assets still held at the reporting date	(154		)	1,970			2,630			4,446
Relating to assets sold during the period	1,365			—			29			1,394
Purchases, issuances and settlements, net	297			—			(242		)	55
Balance as of December 31, 2014	$	23,996		$	41,141		$	26,439		$	91,576

The following table provides the fair value of our post-retirement benefit plan assets and the corresponding level of hierarchy as of December 31, 2015 and 2014.



As of December 31, 2015	Level 1		Level 2		Level 3		Total
	(In Thousands)
Assets:
Domestic equity funds	$	—	$	59,946	$	—	$	59,946
International equity fund	—		14,419		—		14,419
Core bond funds	—		40,475		—		40,475
Cash equivalents	—		576		—		576
Total Assets Measured at Fair Value	$	—	$	115,416	$	—	$	115,416

As of December 31, 2014	Level 1		Level 2		Level 3		Total
	(In Thousands)
Assets:
Domestic equity funds	$	—	$	63,600	$	—	$	63,600
International equity fund	—		14,783		—		14,783
Core bond funds	—		42,390		—		42,390
Cash equivalents	—		576		—		576
Total Assets Measured at Fair Value	$	—	$	121,349	$	—	$	121,349

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Cash Flows

The following table shows the expected cash flows for our pension and post-retirement benefit plans for future years.



	Pension Benefits						Post-retirement Benefits
	To/(From) Trust			(From) Company Assets			To/(From) Trust			(From) Company Assets
	(In Millions)
Expected contributions:
2016	$	28.0					$	—

Expected benefit payments:
2016	$	(54.0	)	$	(2.8	)	$	(7.4	)	$	(0.4	)
2017	(55.0		)	(2.8		)	(7.7		)	(0.3		)
2018	(57.4		)	(2.7		)	(7.9		)	(0.3		)
2019	(59.3		)	(2.7		)	(8.1		)	(0.3		)
2020	(61.4		)	(2.7		)	(8.3		)	(0.3		)
2021-2025	(318.3		)	(12.6		)	(41.2		)	(1.1		)

Savings Plans

We maintain a qualified 401(k) savings plan in which most of our employees participate. We match employees’ contributions in cash up to specified maximum limits. Our contributions to the plan are deposited with a trustee and invested at the direction of plan participants into one or more of the investment alternatives we provide under the plan. Our contributions totaled $7.7 million in 2015, $7.0 million in 2014 and $6.9 million in 2013.

Stock-Based Compensation Plans

We have a long-term incentive and share award plan (LTISA Plan), which is a stock-based compensation plan in which employees and directors are eligible for awards. The LTISA Plan was implemented as a means to attract, retain and motivate employees and directors. Under the LTISA Plan, we may grant awards in the form of stock options, dividend equivalents, share appreciation rights, RSUs, performance shares and performance share units to plan participants. Up to 8.25 million shares of common stock may be granted under the LTISA Plan. As of December 31, 2015, awards of approximately 5.0 million shares of common stock had been made under the plan.

All stock-based compensation is measured at the grant date based on the fair value of the award and is recognized as an expense in the consolidated statement of income over the requisite service period. The requisite service periods range from one to ten years. The table below shows compensation expense and income tax benefits related to stock-based compensation arrangements that are included in our net income.



	Year Ended December 31,
	2015		2014		2013
	(In Thousands)
Compensation expense	$	8,250	$	7,193	$	8,121
Income tax benefits related to stock-based compensation arrangements	3,263		2,845		3,212

We use RSU awards for our stock-based compensation awards. RSU awards are grants that entitle the holder to receive shares of common stock as the awards vest. These RSU awards are defined as nonvested shares and do not include restrictions once the awards have vested.

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RSU awards with only service requirements vest solely upon the passage of time. We measure the fair value of these RSU awards based on the market price of the underlying common stock as of the grant date. RSU awards with only service conditions that have a graded vesting schedule are recognized as an expense in the consolidated statement of income on a straight-line basis over the requisite service period for the entire award. Nonforfeitable dividend equivalents, or the rights to receive cash equal to the value of dividends paid on Westar Energy’s common stock, are paid on these RSUs during the vesting period.

RSU awards with performance measures vest upon expiration of the award term. The number of shares of common stock awarded upon vesting will vary from 0% to 200% of the RSU award, with performance tied to our total shareholder return relative to the total shareholder return of our peer group. We measure the fair value of these RSU awards using a Monte Carlo simulation technique that uses the closing stock price at the valuation date and incorporates assumptions for inputs of the expected volatility and risk-free interest rates. Expected volatility is based on historical volatility over three years using daily stock price observations. The risk-free interest rate is based on treasury constant maturity yields as reported by the Federal Reserve and the length of the performance period. For the 2015 valuation, inputs for expected volatility ranged from 14.6% to 19.1% and the risk-free interest rate was approximately 1.0%. For the 2014 valuation, inputs for expected volatility ranged from 15.2% to 23.3% and the risk-free interest rate was approximately 0.3%. For these RSU awards, dividend equivalents accumulate over the vesting period and are paid in cash based on the number of shares of common stock awarded upon vesting.

During the years ended December 31, 2015, 2014 and 2013, our RSU activity for awards with only service requirements was as follows.



	As of December 31,
	2015				2014				2013
	Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Grant Date Fair Value
	(Shares In Thousands)
Nonvested balance, beginning of year	342.2		$	31.38	352.5		$	28.38	351.1		$	25.47
Granted	115.7		39.50		131.5		34.53		139.6		31.06
Vested	(115.4	)	28.77		(118.2	)	26.19		(125.5	)	23.22
Forfeited	(32.6	)	33.07		(23.6	)	30.00		(12.7	)	28.35
Nonvested balance, end of year	309.9		35.21		342.2		31.38		352.5		28.38

Total unrecognized compensation cost related to RSU awards with only service requirements was $4.5 million and $4.4 million as of December 31, 2015 and 2014, respectively. We expect to recognize these costs over a remaining weighted-average period of 1.7 years. The total fair value of RSUs with only service requirements that vested during the years ended December 31, 2015, 2014 and 2013, was $4.7 million, $3.9 million and $3.7 million, respectively.

During the years ended December 31, 2015, 2014 and 2013, our RSU activity for awards with performance measures was as follows.



	As of December 31,
	2015				2014				2013
	Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Grant Date Fair Value
	(Shares In Thousands)
Nonvested balance, beginning of year	345.1		$	32.31	350.1		$	30.35	340.1		$	29.20
Granted	94.8		40.26		126.1		35.97		134.4		31.54
Vested	(109.0	)	28.99		(108.2	)	30.56		(112.5	)	28.29
Forfeited	(31.8	)	34.03		(22.9	)	30.70		(11.9	)	30.45
Nonvested balance, end of year	299.1		36.00		345.1		32.31		350.1		30.35

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As of December 31, 2015 and 2014, total unrecognized compensation cost related to RSU awards with performance measures was $4.0 million and $3.8 million, respectively. We expect to recognize these costs over a remaining weighted-average period of 1.7 years. The total fair value of RSUs with performance measures that vested during the years ended December 31, 2015, 2014 and 2013, was $3.1 million, $0.5 million and $2.3 million, respectively.

Another component of the LTISA Plan is the Executive Stock for Compensation program under which, in the past, eligible employees were entitled to receive deferred common stock in lieu of current cash compensation. Although this plan was discontinued in 2001, dividends will continue to be paid to plan participants on their outstanding plan balance until distribution. Plan participants were awarded 296 shares of common stock for dividends in 2015, 403 shares in 2014 and 551 shares in 2013. Participants received common stock distributions of 2,024 shares in 2015, 1,944 shares in 2014 and 3,456 shares in 2013.

Income tax benefits resulting from income tax deductions in excess of the related compensation cost recognized in the financial statements is classified as cash flows from financing activities in the consolidated statements of cash flows.

12. WOLF CREEK EMPLOYEE BENEFIT PLANS

Pension and Post-retirement Benefit Plans

As a co-owner of Wolf Creek, KGE is indirectly responsible for 47% of the liabilities and expenses associated with the Wolf Creek pension and post-retirement benefit plans. KGE accrues its 47% share of Wolf Creek’s cost of pension and post-retirement benefits during the years an employee provides service. The following tables summarize the status of KGE’s 47% share of the Wolf Creek pension and post-retirement benefit plans.



	Pension Benefits						Post-retirement Benefits
As of December 31,	2015			2014			2015			2014
	(In Thousands)
Change in Benefit Obligation:
Benefit obligation, beginning of year	$	210,320		$	162,820		$	8,240		$	10,010
Service cost	7,595			5,695			138			173
Interest cost	9,016			8,469			314			464
Plan participants’ contributions	—			—			934			766
Benefits paid	(6,217		)	(5,039		)	(1,622		)	(1,292		)
Actuarial (gains) losses	(14,296		)	38,375			(211		)	(1,881		)
Benefit obligation, end of year	$	206,418		$	210,320		$	7,793		$	8,240

Change in Plan Assets:
Fair value of plan assets, beginning of year	$	124,660		$	114,734		$	6		$	17
Actual return on plan assets	(2,879		)	7,626			—			—
Employer contributions	5,805			7,089			787			515
Plan participants’ contributions	—			—			934			766
Benefits paid	(5,964		)	(4,789		)	(1,622		)	(1,292		)
Fair value of plan assets, end of year	$	121,622		$	124,660		$	105		$	6

Funded status, end of year	$	(84,796	)	$	(85,660	)	$	(7,688	)	$	(8,234	)

Amounts Recognized in the Balance Sheets Consist of:
Current liability	$	(247	)	$	(247	)	$	(597	)	$	(575	)
Noncurrent liability	(84,549		)	(85,413		)	(7,091		)	(7,659		)
Net amount recognized	$	(84,796	)	$	(85,660	)	$	(7,688	)	$	(8,234	)

Amounts Recognized in Regulatory Assets Consist of:
Net actuarial loss (gain)	$	56,747		$	65,049		$	(184	)	$	29
Prior service cost	501			559			—			—
Net amount recognized	$	57,248		$	65,608		$	(184	)	$	29

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	Pension Benefits						Post-retirement Benefits
As of December 31,	2015			2014			2015			2014
	(Dollars in Thousands)
Pension Plans With a Projected Benefit Obligation In Excess of Plan Assets:
Projected benefit obligation	$	206,418		$	210,320		$	—		$	—
Fair value of plan assets	121,622			124,660			—			—

Pension Plans With an Accumulated Benefit Obligation In Excess of Plan Assets:
Accumulated benefit obligation	$	180,718		$	179,228		$	—		$	—
Fair value of plan assets	121,622			124,660			—			—

Post-retirement Plans With an Accumulated Post-retirement Benefit Obligation In Excess of Plan Assets:
Accumulated post-retirement benefit obligation	$	—		$	—		$	7,793		$	8,240
Fair value of plan assets	—			—			105			6

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Benefit Obligation:
Discount rate	4.61		%	4.20		%	4.27		%	3.89		%
Compensation rate increase	4.00		%	4.00		%	—			—

Wolf Creek uses a measurement date of December 31 for its pension and post-retirement benefit plans. The discount rate used to determine the current year pension obligation and the following year’s pension expense is based on a bond selection-settlement portfolio approach. This approach develops a discount rate by selecting a portfolio of high quality, non-callable corporate bonds that generate sufficient cash flow to provide for the projected benefit payments of the plan. After the bond portfolio is selected, a single interest rate is determined that equates the present value of the plan’s projected benefit payments discounted at this rate with the market value of the bonds selected. The increase in the discount rates used as of December 31, 2015, decreased Wolf Creek’s pension and post-retirement benefit obligations by approximately $12.4 million and $0.3 million, respectively.

Wolf Creek utilizes actuarial assumptions about mortality to calculate the pension and post-retirement benefit obligations. In 2015, a revised mortality table was issued reflecting updated future projections of life expectancies based on additional years of actual mortality experience. Wolf Creek adopted a modified version of the revised mortality table as of December 31, 2015, resulting in a decrease to the pension benefit obligation by approximately $4.8 million.

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The prior service cost (benefit) is amortized on a straight-line basis over the average future service of the active employees (plan participants) benefiting under the plan at the time of the amendment. The net actuarial gain or loss is amortized on a straight-line basis over the average future service of active plan participants benefiting under the plan without application of an amortization corridor. Following is additional information regarding KGE’s 47% share of the Wolf Creek pension and other post-retirement benefit plans.



	Pension Benefits									Post-retirement Benefits
Year Ended December 31,	2015			2014			2013			2015			2014			2013
	(Dollars in Thousands)
Components of Net Periodic Cost (Benefit):
Service cost	$	7,595		$	5,695		$	6,835		$	138		$	173		$	206
Interest cost	9,016			8,469			7,562			314			464			413
Expected return on plan assets	(9,044		)	(8,084		)	(7,373		)	—			—			—
Amortization of unrecognized:
Prior service costs	57			58			58			—			—			—
Actuarial loss, net	5,930			2,987			5,421			3			165			265
Net periodic cost before regulatory adjustment	13,554			9,125			12,503			455			802			884
Regulatory adjustment (a)	(1,485		)	2,328			(641		)	—			—			—
Net periodic cost	$	12,069		$	11,453		$	11,862		$	455		$	802		$	884

Other Changes in Plan Assets and Benefit Obligations Recognized in Regulatory Assets:
Current year actuarial (gain) loss	$	(2,373	)	$	38,833		$	(29,911	)	$	(211	)	$	(1,881	)	$	(1,303	)
Amortization of actuarial gain	(5,930		)	(2,987		)	(5,421		)	(3		)	(165		)	(265		)
Amortization of prior service cost	(57		)	(58		)	(58		)	—			—			—
Total recognized in regulatory assets	$	(8,360	)	$	35,788		$	(35,390	)	$	(214	)	$	(2,046	)	$	(1,568	)

Total recognized in net periodic cost and regulatory assets	$	3,709		$	47,241		$	(23,528	)	$	241		$	(1,244	)	$	(684	)

Weighted-Average Actuarial Assumptions used to Determine Net Periodic Cost:
Discount rate	4.20		%	5.11		%	4.16		%	3.89		%	4.70		%	3.78		%
Expected long-term return on plan assets	7.50		%	7.50		%	7.50		%	—			—			—
Compensation rate increase	4.00		%	4.00		%	4.00		%	—			—			—

_______________


(a)	The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices.

We estimate that we will amortize the following amounts from regulatory assets and regulatory liabilities into net periodic cost in 2016.



	Pension Benefits		Post-retirement Benefits
	(In Thousands)
Actuarial loss (gain)	$	4,357	$	(14	)
Prior service cost	55		—
Total	$	4,412	$	(14	)

The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the plans’ investment portfolios. Assumed projected rates of return for each asset class were selected after analyzing long-term historical experience and future expectations of the volatility of the various asset classes. Based on target asset allocations for each asset class, the overall expected rate of return for the portfolios was developed, adjusted for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets.

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For measurement purposes, the assumed annual health care cost growth rates were as follows.



	As of December 31,
	2015		2014
Health care cost trend rate assumed for next year	7.0	%	7.0	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.0	%	5.0	%

Year that the rate reaches the ultimate trend rate	2020		2019

The health care cost trend rate affects the projected benefit obligation. A 1% change in assumed health care cost growth rates would have effects shown in the following table.



	One-Percentage- Point Increase			One-Percentage- Point Decrease
	(In Thousands)
Effect on total of service and interest cost	$	(8	)	$	8
Effect on post-retirement benefit obligation	(95		)	97

Plan Assets

Wolf Creek’s pension and post-retirement plan investment strategy is to manage assets in a prudent manner with regard to preserving principal while providing reasonable returns. It has adopted a long-term investment horizon such that the chances and duration of investment losses are weighed against the long-term potential for appreciation of assets. Part of its strategy includes managing interest rate sensitivity of plan assets relative to the associated liabilities. The primary objective of the pension plan is to provide a source of retirement income for its participants and beneficiaries, and the primary financial objective of the plan is to improve its funded status. The primary objective of the post-retirement benefit plan is growth in assets and preservation of principal, while minimizing interim volatility, to meet anticipated claims of plan participants. Wolf Creek delegates the management of its pension and post-retirement benefit plan assets to independent investment advisors who hire and dismiss investment managers based upon various factors. The investment advisors are instructed to diversify investments across asset classes, sectors and manager styles to minimize the risk of large losses, based upon objectives and risk tolerance specified by Wolf Creek, which include allowable and/or prohibited investment types. It measures and monitors investment risk on an ongoing basis through quarterly investment portfolio reviews and annual liability measurements.

The target allocations for Wolf Creek’s pension plan assets are 31% to international equity securities, 25% to domestic equity securities, 25% to debt securities, 10% to real estate securities, 5% to commodity investments and 4% to other investments. The investments in both international and domestic equity include investments in large-, mid- and small-cap companies, private equity funds and investment funds with underlying investments similar to those previously mentioned. The investments in debt include core and high-yield bonds. Core bonds include funds invested in investment grade debt securities of corporate entities, obligations of U.S. and foreign governments and their agencies and private debt securities. High-yield bonds include a fund with underlying investments in non-investment grade debt securities of corporate entities, private placements and bank debt. Real estate securities include funds invested in commercial and residential real estate properties while commodity investments include funds invested in commodity-related instruments.

All of Wolf Creek’s pension plan assets are recorded at fair value using daily net asset values as reported by the trustee. However, level 3 investments in real estate funds and alternative funds are invested in underlying investments that are illiquid and require significant judgment when measuring them at fair value using market- and income-based models. Significant unobservable inputs for underlying real estate investments include estimated market discount rates, projected cash flows and estimated value into perpetuity. Alternative funds invest in a wide range of investments typically with low correlations to traditional investments.

Similar to other assets measured at fair value, GAAP establishes a hierarchal framework for disclosing the transparency of the inputs utilized in measuring pension and post-retirement benefit plan assets at fair value. From time to time, the Wolf Creek pension trust may buy and sell investments resulting in changes within the hierarchy. See Note 4, “Financial Instruments and Trading Securities,” for a description of the hierarchal framework.

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The following table provides the fair value of KGE’s 47% share of Wolf Creek’s pension plan assets and the corresponding level of hierarchy as of December 31, 2015 and 2014.



As of December 31, 2015	Level 1		Level 2		Level 3		Total
	(In Thousands)
Assets:
Domestic equity funds	$	—	$	30,503	$	—	$	30,503
International equity funds	—		37,682		—		37,682
Core bond funds	—		30,287		—		30,287
Real estate securities fund	—		6,123		6,434		12,557
Commodities fund	—		5,811		—		5,811
Alternative investment fund	—		—		4,258		4,258
Cash equivalents	—		524		—		524
Total Assets Measured at Fair Value	$	—	$	110,930	$	10,692	$	121,622

As of December 31, 2014	Level 1		Level 2		Level 3		Total
	(In Thousands)
Assets:
Domestic equity funds	$	—	$	31,580	$	—	$	31,580
International equity funds	—		38,624		—		38,624
Core bond funds	—		31,854		—		31,854
Real estate securities fund	—		6,313		5,649		11,962
Commodities fund	—		5,887		—		5,887
Alternative investment fund	—		—		4,309		4,309
Cash equivalents	—		444		—		444
Total Assets Measured at Fair Value	$	—	$	114,702	$	9,958	$	124,660

The following table provides a reconciliation of KGE’s 47% share of Wolf Creek’s pension plan assets measured at fair value using significant level 3 inputs for the years ended December 31, 2015 and 2014.



	Real Estate Securities Fund		Alternative Investment Fund			Total
	(In Thousands)
Balance as of December 31, 2014	$	5,649	$	4,309		$	9,958
Actual gain (loss) on plan assets:
Relating to assets still held at the reporting date	785		(51		)	734
Balance as of December 31, 2015	$	6,434	$	4,258		$	10,692

Balance as of December 31, 2013	$	5,094	$	4,147		$	9,241
Actual gain on plan assets:
Relating to assets still held at the reporting date	555		162			717
Balance as of December 31, 2014	$	5,649	$	4,309		$	9,958

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Cash Flows

The following table shows our expected cash flows for KGE’s 47% share of Wolf Creek’s pension and post-retirement benefit plans for future years.



Expected Cash Flows	Pension Benefits						Post-retirement Benefits
	To/(From) Trust			(From) Company Assets			To/(From) Trust			(From) Company Assets
	(In Millions)
Expected contributions:
2016	$	8.0					$	0.6

Expected benefit payments:
2016	$	(6.0	)	$	(0.3	)	$	(1.8	)	$	—
2017	(6.9		)	(0.3		)	(2.0		)	—
2018	(7.8		)	(0.3		)	(2.3		)	—
2019	(8.7		)	(0.3		)	(2.6		)	—
2020	(9.6		)	(0.3		)	(2.9		)	—
2021 - 2025	(61.3		)	(1.3		)	(18.2		)	—

Savings Plan

Wolf Creek maintains a qualified 401(k) savings plan in which most of its employees participate. Wolf Creek matches employees’ contributions in cash up to specified maximum limits. Wolf Creek’s contributions to the plan are deposited with a trustee and invested at the direction of plan participants into one or more of the investment alternatives provided under the plan. KGE’s portion of the expense associated with Wolf Creek’s matching contributions was $1.6 million in 2015, $1.4 million in 2014 and $1.4 million in 2013.

13. COMMITMENTS AND CONTINGENCIES

Purchase Orders and Contracts

As part of our ongoing operations and capital expenditure program, we have purchase orders and contracts, excluding fuel and transmission, which are discussed below under “—Fuel, Purchased Power and Transmission Commitments.” These commitments relate to purchase obligations issued and outstanding at year-end.

The yearly detail of the aggregate amount of required payments as of December 31, 2015, was as follows.



	Committed Amount
	(In Thousands)
2016 (a)	$	757,250
2017	13,199
2018	48,744
Thereafter	31,720
Total amount committed	$	850,913

_______________

(a) Significant portion related to construction commitments.

Environmental Matters

Federal Clean Air Act

We must comply with the federal Clean Air Act (CAA), state laws and implementing federal and state regulations that impose, among other things, limitations on emissions generated from our operations, including sulfur dioxide (SO₂), particulate matter (PM), nitrogen oxides (NOx), carbon monoxide (CO), mercury and acid gases.

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Emissions from our generating facilities, including PM, SO₂ and NOx, have been determined by regulation to reduce visibility by causing or contributing to regional haze. Under federal laws, such as the Clean Air Visibility Rule, and pursuant to an agreement with the Kansas Department of Health and Environment (KDHE) and the Environmental Protection Agency (EPA), we are required to install, operate and maintain controls to reduce emissions found to cause or contribute to regional haze.

Sulfur Dioxide and Nitrogen Oxide

Through the combustion of fossil fuels at our generating facilities, we emit SO₂ and NOx. Federal and state laws and regulations, including those noted above, and permits issued to us limit the amount of these substances we can emit. If we exceed these limits, we could be subject to fines and penalties. In order to meet SO₂ and NOx regulations applicable to our generating facilities, we use low-sulfur coal and natural gas and have equipped the majority of our fossil fuel generating facilities with equipment to control such emissions.

We are subject to the SO₂ allowance and trading program under the federal Clean Air Act Acid Rain Program. Under this program, each unit must have enough allowances to cover its SO₂ emissions for that year. In 2015, we had adequate SO₂ allowances to meet generation and we expect to have enough to cover emissions under this program in 2016.

Cross-State Air Pollution Rule

In November 2015, the EPA proposed the Cross-State Air Pollution Update Rule. The proposed rule addresses interstate transport of NOx emissions in 23 states including Kansas, Missouri and Oklahoma during the ozone season and the impact from the formation of ozone on downwind states with respect to the 2008 ozone National Ambient Air Quality Standards (NAAQS). Starting with the 2017 ozone season, the proposed rule will revise the existing ozone season allowance budgets for Missouri and Oklahoma and will establish an ozone season budget for Kansas. We are currently evaluating the impact of the proposed rule on our operations, and it could have a material impact on our operations and consolidated financial results.

National Ambient Air Quality Standards

Under the federal CAA, the EPA sets NAAQS for certain emissions considered harmful to public health and the environment, including two classes of PM, ozone, NOx (a precursor to ozone), CO and SO₂, which result from fossil fuel combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals.

In October 2015, the EPA strengthened the ozone NAAQS by lowering the standards from 75 parts per billion (ppb) to 70 ppb. As a result of this change, the EPA is required to make attainment/nonattainment designations for the revised standards by October 2017. We are currently reviewing this final rule and cannot at this time predict the impact it may have on our operations. Nonattainment designations in or surrounding our areas of operations could have a material impact on our consolidated financial results.

In December 2012, the EPA strengthened an existing NAAQS for one class of PM. In December 2014, the EPA designated the entire state of Kansas as unclassifiable/in attainment with the standard. We cannot at this time predict the impact this designation may have on our operations or consolidated financial results, but it could be material.

In 2010, the EPA revised the NAAQS for SO₂. In March 2015, a federal court approved a consent decree between the EPA and environmental groups. The decree includes specific SO₂ emissions criteria for certain electric generating plants that, if met, requires the EPA to promulgate attainment/nonattainment designations for areas surrounding these plants by July 2016. Tecumseh Energy Center is our only generating station that meets this criteria. We are working with KDHE to determine the appropriate designation for the areas surrounding the facility. In addition, we continue to communicate with our regulatory agencies regarding these standards and evaluate what impact the revised NAAQS could have on our operations and consolidated financial results. If areas surrounding our facilities are designated as nonattainment and/or we are required to install additional equipment to control emissions at our facilities, it could have a material impact on our operations and consolidated financial results.

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Greenhouse Gases

Byproducts of burning coal and other fossil fuels include carbon dioxide (CO₂) and other gases referred to as greenhouse gases (GHG), which are believed by many to contribute to climate change. Various regulations under the federal CAA limit CO₂ and other GHG emissions, and other measures are being imposed or offered by individual states, municipalities and regional agreements with the goal of reducing GHG emissions.

In October 2015, the EPA published a rule establishing new source performance standards that limit CO₂ emissions for new, modified and reconstructed coal and natural gas fueled electric generating units to various levels per Megawatt hour (MWh) depending on various characteristics of the units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate CO₂ emissions from existing power plants. The standards for existing plants are known as the Clean Power Plan (CPP). Under the CPP, interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates must be achieved by 2030. Legal challenges to the CPP were filed by groups of states and industry members, including our company, in the U.S. Court of Appeals for the D.C. Circuit beginning in October 2015, and more challenges are expected. In January 2016, the U.S. Court of Appeals for the D.C. Circuit denied a request to stay the CPP pending review. However, the U.S. Court of Appeals for the D.C. Circuit placed the case on an expedited review schedule with oral arguments scheduled for June 2016. Based on the U.S. Court of Appeals for the D.C. Circuit denial of the petition for stay, state and industry groups petitioned the U.S. Supreme Court for a stay. In February 2016, the U.S. Supreme Court granted the stay request. Due to the future uncertainty of the CPP, we cannot at this time determine the impact on our operations or consolidated financial results, but we believe the costs to comply could be material.

Mercury and Air Toxics Standards

In 2012, the Mercury and Air Toxics Standards (MATS) rule became effective. Under the MATS rule the EPA regulates the emissions of mercury, non-mercury metals, acid gases and organics. MATS required compliance to begin in April 2015, three years after the effective date. Sources could petition their state air regulatory agency to ask for an additional year to prepare for compliance. We petitioned the KDHE and our petition request was granted. Our current compliance date is April 2016 for all of our MATS affected units.

In June 2015, the U.S. Supreme Court reversed and remanded a decision by the U.S. Court of Appeals for the District of Columbia Circuit regarding the need for the EPA to consider costs during the initial phase of MATS development. In December 2015, the U.S. Court of Appeals for the District of Columbia Circuit issued an order leaving MATS in effect while EPA develops a final cost determination. The Court anticipates this final determination to be completed prior to the MATS compliance deadline in April 2016. Based on the final MATS rule, we do not expect there to be a material impact on our operations or consolidated financial results.

Water

We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants. Revised rules governing such discharges from coal-fired power plants were issued in November 2015. The final rule establishes limitations or forces the elimination of wastewater associated with coal combustion residual handling. Implementation timelines for these requirements will vary from 2019 to 2023. We are evaluating the final rule at this time and cannot predict the resulting impact on our operations or consolidated financial results, but believe costs to comply could be material.

In October 2014, the EPA’s final standards for cooling intake structures at power plants to protect aquatic life took effect. The standards, based on Section 316(b) of the federal Clean Water Act (CWA), require subject facilities to choose among seven best available technology options to reduce fish impingement. In addition, some facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. Our current analysis indicates this rule will not have a significant impact on our coal plants that employ cooling towers. Biological monitoring may be required for La Cygne and Wolf Creek. We are currently evaluating the rule’s impact on those two plants and cannot predict the resulting impact on our operations or consolidated financial results, but we do not expect it to be material.

In June 2015, the EPA along with the U.S. Army Corps of Engineers issued a final rule, effective August 2015, defining the Waters of the United States for purposes of the CWA. This rulemaking has the potential to impact all programs under the CWA. Expansion of regulated waterways is possible under the rule depending on regulating authority interpretation, which could impact several permitting programs. Various states have filed lawsuits challenging the rule and, in October 2015,

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the U.S. Court of Appeals for the Sixth Circuit issued an order that temporarily stays implementation of the rule nationwide pending the outcome of the various legal challenges. We are currently evaluating the final rule. The resulting impact of the rule could have a material impact on our operations or consolidated financial results.

Regulation of Coal Combustion Byproducts

In the course of operating our coal generation plants, we produce coal combustion byproducts (CCBs), including fly ash, gypsum and bottom ash. We recycle some of our ash production, principally by selling to the aggregate industry. The EPA published a rule to regulate CCBs in April 2015, which we believe will require additional CCB handling, processing and storage equipment and closure of certain ash disposal areas. While we cannot at this time estimate the full impact and costs associated with future regulations of CCBs, we have recorded an increase of approximately $34.4 million to our ARO and property, plant and equipment to recognize estimated future costs associated with closure and post-closure of disposal sites. We believe further impact on our operations or consolidated financial results could be material. See Note 14, “Asset Retirement Obligations,” for additional information.

SPP Revenue Crediting

We are a member of the Southwest Power Pool, Inc. (SPP) Regional Transmission Organization, which coordinates the operation of a multistate interconnected transmission system. The SPP has been engaged in a process whereby it is seeking to allocate revenue credits under its Open Access Transmission Tariff to sponsors of certain transmission system upgrades. Qualifying upgrades are those that are not financed through general rates paid by all customers and that result in additional revenue to the SPP. The SPP is also evaluating whether sponsors are entitled to revenue credits for previously completed upgrades, and whether members will be obligated to pay for revenue credits attributable to these historical upgrades.

We believe it is reasonably possible that we will be required to pay sponsors for revenue credits attributable to historical upgrades. However, due to the complexity of the process, including the large number of transmission service requests associated with the upgrades at issue, the number of years included in the process and complexity surrounding the manner in which revenue credits are allocated, we are unable to estimate an amount, or a range of amounts, we may owe, or the impact on our consolidated financial results.

Renewable Energy Standard

In May 2015, Kansas repealed a state mandate to maintain a minimum amount of renewable energy sources, effective January 1, 2016.

Nuclear Decommissioning

Nuclear decommissioning is a nuclear industry term for the permanent shutdown of a nuclear power plant and the removal of radioactive components in accordance with Nuclear Regulatory Commission (NRC) requirements. The NRC will terminate a plant’s license and release the property for unrestricted use when a company has reduced the residual radioactivity of a nuclear plant to a level mandated by the NRC. The NRC requires companies with nuclear plants to prepare formal financial plans to fund nuclear decommissioning. These plans are designed so that sufficient funds required for nuclear decommissioning will be accumulated prior to the expiration of the license of the related nuclear power plant. Wolf Creek files a nuclear decommissioning site study with the KCC every three years.

The KCC reviews nuclear decommissioning plans in two phases. Phase one is the approval of the updated nuclear decommissioning study including the estimated costs to decommission the plant. Phase two involves the review and approval of a funding schedule prepared by the owner of the plant detailing how it plans to fund the future-year dollar amount of its pro rata share of the decommissioning costs.

In 2014, Wolf Creek updated the nuclear decommissioning cost study. Based on the study, our share of decommissioning costs, including decontamination, dismantling and site restoration, is estimated to be approximately $360.0 million. This amount compares to the prior site study estimate of $296.2 million. The site study cost estimate represents the estimate to decommission Wolf Creek as of the site study year. The actual nuclear decommissioning costs may vary from the estimates because of changes in regulations and technologies as well as changes in costs for labor, materials and equipment.

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We are allowed to recover nuclear decommissioning costs in our prices over a period equal to the operating license of Wolf Creek, which is through 2045. The NRC requires that funds sufficient to meet nuclear decommissioning obligations be held in a trust. We believe that the KCC approved funding level will also be sufficient to meet the NRC requirement. Our consolidated financial results would be materially affected if we were not allowed to recover in our prices the full amount of the funding requirement.

We recovered in our prices and deposited in an external trust fund for nuclear decommissioning approximately $2.8 million in 2015, $2.8 million in 2014 and $2.9 million in 2013. We record our investment in the NDT fund at fair value, which approximated $184.1 million and $185.0 million as of December 31, 2015 and 2014, respectively.

Storage of Spent Nuclear Fuel

Under the Nuclear Waste Policy Act of 1982, the Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel. Wolf Creek paid into a federal Nuclear Waste Fund administered by the DOE a quarterly fee for the future disposal of spent nuclear fuel. In November 2013, a federal court of appeals ruled that the DOE must stop collecting this fee effective May 2014. Our share of the fee, calculated as one tenth of a cent for each kilowatt-hour of net nuclear generation delivered to customers, was $0.8 million in 2014 and $3.0 million in 2013. We included these costs in fuel and purchased power expense on our consolidated statements of income.

In 2010, the DOE filed a motion with the NRC to withdraw its then pending application to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada. An NRC board denied the DOE’s motion to withdraw its application and the DOE appealed that decision to the full NRC. In 2011, the NRC issued an evenly split decision on the appeal and also ordered the licensing board to close out its work on the DOE’s application by the end of 2011 due to a lack of funding. These agency actions prompted the states of Washington and South Carolina, and a county in South Carolina, to file a lawsuit in a federal Court of Appeals asking the court to compel the NRC to resume its license review and to issue a decision on the license application. In August 2013, the court ordered the NRC to resume its review of the DOE’s application. The NRC has not yet issued its decision.

Wolf Creek is currently evaluating alternatives for expanding its existing on-site spent nuclear fuel storage to provide additional capacity prior to 2025. We cannot predict when, or if, an off-site storage site or alternative disposal site will be available to receive Wolf Creek’s spent nuclear fuel and will continue to monitor this activity.

Nuclear Insurance

We maintain nuclear liability, property and business interruption insurance for Wolf Creek. These policies contain certain industry standard terms, conditions and exclusions, including, but not limited to, ordinary wear and tear and war. An industry aggregate limit of $3.2 billion plus any reinsurance, indemnity or any other source recoverable by Nuclear Electric Insurance Limited (NEIL), our property and business interruption insurance provider, exists for acts of terrorism affecting Wolf Creek or any other NEIL insured plant within 12 months from the date of the first act. In addition, we are required to participate in industry-wide retrospective assessment programs as discussed below.

Nuclear Liability Insurance

Pursuant to the Price-Anderson Act, which has been reauthorized through December 2025 by the Energy Policy Act of 2005, we are required to insure against public liability claims resulting from nuclear incidents to the current limit of public liability, which is approximately $13.5 billion. This limit of liability consists of the maximum available commercial insurance of $375.0 million and the remaining $13.1 billion is provided through mandatory participation in an industry-wide retrospective assessment program. In addition, Congress could impose additional revenue-raising measures to pay claims. Under this retrospective assessment program, the owners of Wolf Creek are jointly and severally subject to an assessment of up to $127.3 million (our share is $59.8 million), payable at no more than $19.0 million (our share is $8.9 million) per incident per year per reactor. Both the total and yearly assessment is subject to an inflationary adjustment every five years with the next adjustment in 2018.

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Nuclear Property and Business Interruption Insurance

The owners of Wolf Creek carry decontamination liability, premature nuclear decommissioning liability and property damage insurance for Wolf Creek totaling approximately $2.8 billion. In the event of an accident, insurance proceeds must first be used for reactor stabilization and site decontamination in accordance with a plan mandated by the NRC. Our share of any remaining proceeds can be used to pay for property damage or, if certain requirements are met, including decommissioning the plant, toward a shortfall in the NDT fund. The owners also carry additional insurance with NEIL to cover costs of replacement power and other extra expenses incurred during a prolonged outage resulting from accidental property damage at Wolf Creek. If significant losses were incurred at any of the nuclear plants insured under the NEIL policies, we may be subject to retrospective assessments under the current policies of approximately $42.0 million (our share is $19.7 million).

Accidental Nuclear Outage Insurance

Although we maintain various insurance policies to provide coverage for potential losses and liabilities resulting from an accident or an extended outage, our insurance coverage may not be adequate to cover the costs that could result from a catastrophic accident or extended outage at Wolf Creek. Any substantial losses not covered by insurance, to the extent not recoverable in our prices, would have a material effect on our consolidated financial results.

Fuel, Purchased Power and Transmission Commitments

To supply a portion of the fuel requirements for our power plants, the owners of Wolf Creek have entered into various contracts to obtain nuclear fuel and we have entered into various contracts to obtain coal and natural gas. Some of these contracts contain provisions for price escalation and minimum purchase commitments. As of December 31, 2015, our share of Wolf Creek’s nuclear fuel commitments was approximately $16.7 million for uranium concentrates expiring in 2017, $2.5 million for conversion expiring in 2017, $94.6 million for enrichment expiring in 2027 and $33.2 million for fabrication expiring in 2025.

As of December 31, 2015, our coal and coal transportation contract commitments under the remaining terms of the contracts were approximately $827.8 million. The contracts are for plants that we operate and expire at various times through 2020.

As of December 31, 2015, our natural gas transportation contract commitments under the remaining terms of the contracts were approximately $109.6 million. The natural gas transportation contracts provide firm service to several of our natural gas burning facilities and expire at various times through 2030.

We have power purchase agreements with the owners of nine separate wind generation facilities with installed design capabilities of approximately 1,314 MW expiring in 2028 through 2036. Of the approximately 1,314 MW under contract, approximately 400 MW are associated with agreements pursuant to which generation providers are scheduled to deliver power beginning by early 2017. Each of the agreements provide for our receipt and purchase of energy produced at a fixed price per unit of output. We estimate that our annual cost of energy purchased from these wind generation facilities will be approximately $104.8 million in 2016 and approximately $145.0 million for the next several years thereafter.

We have acquired rights to transmit a total of 206 MW. These agreements providing transmission capacity for 206 MW expire in 2016. As of December 31, 2015, we are committed to spend approximately $7.1 million over the remaining terms of these agreements.

FERC Proceedings

See Note 3, “Rate Matters and Regulation - FERC Proceedings,” for information regarding a pending settlement of a complaint that was filed by the KCC against us with the FERC under Section 206 of the FPA.

14. ASSET RETIREMENT OBLIGATIONS

Legal Liability

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statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or an offset to a regulatory liability.

We initially recorded AROs at fair value for the estimated cost to decommission Wolf Creek (KGE’s 47% share), retire our wind generation facilities, dispose of asbestos insulating material at our power plants, remediate ash disposal ponds and dispose of polychlorinated biphenyl (PCB)-contaminated oil.

The following table summarizes our legal AROs included on our consolidated balance sheets in long-term liabilities.



	As of December 31,
	2015			2014
	(In Thousands)
Beginning ARO	$	230,668		$	160,682
Increase in nuclear decommissioning ARO liability	—			50,683
Increase in other ARO liabilities	34,440			9,580
Liabilities settled	(1,553		)	(593		)
Accretion expense	12,964			10,316
Revisions in estimated cash flows	(1,234		)	—
Ending ARO	$	275,285		$	230,668

In 2015, we recorded an approximately $34.4 million increase in our ARO in response to the EPA’s published rule to regulate CCBs. The increase is to recognize costs associated with closure and post-closure of disposal sites to be compliant. See Note 13, “Commitments and Contingencies - Regulation of Coal Combustion Byproducts,” for additional information.

Wolf Creek filed a nuclear decommissioning cost study with the KCC in 2014. As a result of the study, we recorded in 2014 a $50.7 million increase in our ARO to reflect revisions to the estimated costs to decommission Wolf Creek.

Conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. We determined that our conditional AROs include the retirement of our wind generation facilities, disposal of asbestos insulating material at our power plants, the remediation of ash disposal ponds and the disposal of PCB-contaminated oil.

We have an obligation to retire our wind generation facilities and remove the foundations. The ARO related to our owned wind generation facilities was determined based upon the date each wind generation facility was placed into service.

The amount of the retirement obligation related to asbestos disposal was recorded as of 1990, the date when the EPA published the “National Emission Standards for Hazardous Air Pollutants: Asbestos NESHAP Revision; Final Rule.”

We operate, as permitted by the state of Kansas, ash landfills at several of our power plants. The retirement obligation for the ash landfills was determined based upon the date each landfill was originally placed in service.

PCB-contaminated oil is contained within company electrical equipment, primarily transformers. The PCB retirement obligation was determined based upon the PCB regulations that originally became effective in 1978.

Non-Legal Liability - Cost of Removal

We collect in our prices the costs to dispose of plant assets that do not represent legal retirement obligations. As of December 31, 2015 and 2014, we had $53.8 million and $88.2 million, respectively, in amounts collected, but not yet spent, for removal costs classified as a regulatory liability.

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15. LEGAL PROCEEDINGS

We and our subsidiaries are involved in various legal, environmental and regulatory proceedings. We believe that adequate provisions have been made and accordingly believe that the ultimate disposition of such matters will not have a material effect on our consolidated financial results. See Notes 3 and 13, “Rate Matters and Regulation” and “Commitments and Contingencies,” for additional information.

16. COMMON STOCK

General

Westar Energy’s Restated Articles of Incorporation, as amended, provide for 275.0 million authorized shares of common stock. As of December 31, 2015 and 2014, Westar Energy had issued 141.4 million shares and 131.7 million shares, respectively.

Westar Energy has a direct stock purchase plan (DSPP). Shares of common stock sold pursuant to the DSPP may be either original issue shares or shares purchased in the open market. During 2015 and 2014, Westar Energy issued 0.5 million shares and 0.5 million shares, respectively, through the DSPP and other stock-based plans operated under the LTISA Plan. As of December 31, 2015 and 2014, a total of 1.2 million shares and 1.6 million shares, respectively, were available under the DSPP registration statement.

Issuances

In March 2013, Westar Energy entered into a three-year sales agency financing agreement and master forward sale agreement with a bank. The maximum amount that Westar Energy may offer and sell under the March 2013 master agreements is the lesser of an aggregate of $500.0 million or approximately 25.0 million shares, subject to adjustment for share splits, share combinations and share dividends. Under the terms of the sales agency financing agreement, Westar Energy may offer and sell shares of its common stock from time to time. In addition, under the terms of the sales agency financing agreement and master forward sale confirmation, Westar Energy may from time to time enter into one or more forward sale transactions with the bank, as forward purchaser and the bank will borrow shares of Westar Energy’s common stock from third parties and sell them through its agent. The agent receives a commission equal to 1% of the sales price of all shares sold under the agreements.

In April 2010, Westar Energy entered into a three-year sales agency financing agreement and master forward sale agreement with a bank that was terminated in March 2013. The maximum amount that Westar Energy could offer and sell under the agreements was the lesser of an aggregate of $500.0 million or approximately 22.0 million shares, subject to adjustment for share splits, share combinations and share dividends. Terms under these agreements were generally similar to the March 2013 agreements described above.

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The following table summarizes our common stock activity pursuant to the three forward sale agreements.



	Year Ended December 31,
	2015	2014	2013
Shares that could be settled at beginning of year	9,160,500	12,052,976	1,753,415
Transactions entered	—	—	11,367,673
Transactions settled (a)	9,160,500	2,892,476	1,068,112
Shares that could be settled at end of year	—	9,160,500	12,052,976
_______________
(a) The shares settled during the years ended December 31, 2015, 2014 and 2013, were settled with a physical settlement amount of approximately $254.6 million, $82.9 million and $27.0 million, respectively.

17. VARIABLE INTEREST ENTITIES

In determining the primary beneficiary of a VIE, we assess the entity’s purpose and design, including the nature of the entity’s activities and the risks that the entity was designed to create and pass through to its variable interest holders. A reporting enterprise is deemed to be the primary beneficiary of a VIE if it has (a) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses or right to receive benefits from the VIE that could potentially be significant to the VIE. The primary beneficiary of a VIE is required to consolidate the VIE. The trusts holding our 8% interest in JEC and our 50% interest in La Cygne unit 2 are VIEs of which we are the primary beneficiary.

We assess all entities with which we become involved to determine whether such entities are VIEs and, if so, whether or not we are the primary beneficiary of the entities. We also continuously assess whether we are the primary beneficiary of the VIEs with which we are involved. Prospective changes in facts and circumstances may cause us to reconsider our determination as it relates to the identification of the primary beneficiary.

8% Interest in Jeffrey Energy Center

Under an agreement that expires in January 2019, we lease an 8% interest in JEC from a trust. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the 8% interest in JEC and lease it to a third party, and does not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trust. In determining the primary beneficiary of the trust, we concluded that the activities of the trust that most significantly impact its economic performance and that we have the power to direct include (1) the operation and maintenance of the 8% interest in JEC, (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount and (3) our option to require refinancing of the trust’s debt. We have the potential to receive benefits from the trust that could potentially be significant if the fair value of the 8% interest in JEC at the end of the agreement is greater than the fixed amount. The possibility of lower interest rates upon refinancing the debt also creates the potential for us to receive significant benefits.

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50% Interest in La Cygne Unit 2

Under an agreement that expires in September 2029, KGE entered into a sale-leaseback transaction with a trust under which the trust purchased KGE’s 50% interest in La Cygne unit 2 and subsequently leased it back to KGE. The trust was financed with an equity contribution from an owner participant and debt issued by the trust. The trust was created specifically to purchase the 50% interest in La Cygne unit 2 and lease it back to KGE, and does not hold any other assets. We meet the requirements to be considered the primary beneficiary of the trust. In determining the primary beneficiary of the trust, we concluded that the activities of the trust that most significantly impact its economic performance and that we have the power to direct include (1) the operation and maintenance of the 50% interest in La Cygne unit 2 and (2) our ability to exercise a purchase option at the end of the agreement at the lesser of fair value or a fixed amount. We have the potential to receive benefits from the trust that could potentially be significant if the fair value of the 50% interest in La Cygne unit 2 at the end of the agreement is greater than the fixed amount. In February 2016, KGE effected a refunding of the $162.1 million in outstanding bonds maturing March 2021. See Note 9, “Long-term Debt,” for additional information.

Railcars

Under two separate agreements, we leased railcars from unrelated trusts to transport coal to some of our power plants. We consolidated the trusts as VIEs until the agreements expired in November 2014 and May 2013. As a result of deconsolidating the trusts, property, plant and equipment of VIEs, net and noncontrolling interests decreased $7.3 million in 2014 and $14.3 million in 2013.

Financial Statement Impact

We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIEs described above.



	As of December 31,
	2015		2014
	(In Thousands)
Assets:
Property, plant and equipment of variable interest entities, net	$	268,239	$	278,573
Regulatory assets (a)	9,088		7,882

Liabilities:
Current maturities of long-term debt of variable interest entities	$	28,309	$	27,933
Accrued interest (b)	2,457		2,961
Long-term debt of variable interest entities, net	138,097		166,565

_______________

(a) Included in long-term regulatory assets on our consolidated balance sheets.

(b) Included in accrued interest on our consolidated balance sheets.

All of the liabilities noted in the table above relate to the purchase of the property, plant and equipment. The assets of the VIEs can be used only to settle obligations of the VIEs and the VIEs’ debt holders have no recourse to our general credit. We have not provided financial or other support to the VIEs and are not required to provide such support. We did not record any gain or loss upon initial consolidation of the VIEs.

18. LEASES

Operating Leases

We lease office buildings, computer equipment, vehicles, railcars and other property and equipment. In determining lease expense, we recognize the effects of scheduled rent increases on a straight-line basis over the minimum lease term.

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Rental expense and estimated future commitments under operating leases are as follows.



Year Ended December 31,	Total Operating Leases
	(In Thousands)
Rental expense:
2013	$	16,484
2014	14,143
2015	14,035

Future commitments:
2016	$	13,550
2017	11,646
2018	10,216
2019	8,815
2020	5,988
Thereafter	8,917
Total future commitments	$	59,132

Capital Leases

We identify capital leases based on defined criteria. For both vehicles and computer equipment, new leases are signed each month based on the terms of master lease agreements.

Assets recorded under capital leases are listed below.



	As of December 31,
	2015			2014
	(In Thousands)
Vehicles	$	17,345		$	18,820
Computer equipment	1,204			1,504
Generation plant	40,048			40,048
Accumulated amortization	(13,477		)	(11,741		)
Total capital leases	$	45,120		$	48,631

Capital leases are treated as operating leases for rate making purposes. Minimum annual rental payments, excluding administrative costs such as property taxes, insurance and maintenance, under capital leases are listed below.



Year Ended December 31,	Total Capital Leases
	(In Thousands)
2016	$	5,812
2017	5,386
2018	5,233
2019	4,645
2020	4,007
Thereafter	56,050
	81,133
Amounts representing imputed interest	(32,271		)
Present value of net minimum lease payments under capital leases	48,862
Less: Current portion	3,815
Total long-term obligation under capital leases	$	45,047

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19. QUARTERLY RESULTS (UNAUDITED)

Our business is seasonal in nature and, in our opinion, comparisons between the quarters of a year do not give a true indication of overall trends and changes in operations.



2015	First		Second		Third		Fourth
	(In Thousands, Except Per Share Amounts)

Revenues (a)	$	590,807	$	589,563	$	732,829	$	545,965
Net income (a)	53,163		66,243		140,564		41,826
Net income attributable to Westar Energy, Inc. (a)	50,980		63,710		138,003		39,235

Per Share Data (a):

Basic:
Earnings available	$	0.38	$	0.47	$	0.97	$	0.28

Diluted:
Earnings available	$	0.38	$	0.46	$	0.97	$	0.28

Cash dividend declared per common share	$	0.36	$	0.36	$	0.36	$	0.36
Market price per common share:
High	$	44.03	$	39.65	$	40.22	$	43.56
Low	$	36.58	$	33.88	$	34.17	$	37.55

_______________


(a)	Items are computed independently for each of the periods presented and the sum of the quarterly amounts may not equal the total for the year.

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2014	First		Second		Third		Fourth
	(In Thousands, Except Per Share Amounts)

Revenues (a)	$	628,556	$	612,668	$	764,040	$	596,439
Net income (a)	70,970		55,822		149,760		45,773
Net income attributable to Westar Energy, Inc. (a)	68,955		53,473		147,382		43,449

Per Share Data (a):

Basic:
Earnings available	$	0.53	$	0.41	$	1.13	$	0.33

Diluted:
Earnings available	$	0.52	$	0.40	$	1.10	$	0.32

Cash dividend declared per common share	$	0.35	$	0.35	$	0.35	$	0.35
Market price per common share:
High	$	35.33	$	38.24	$	38.23	$	43.15
Low	$	31.67	$	34.51	$	33.76	$	33.73

_______________


(a)	Items are computed independently for each of the periods presented and the sum of the quarterly amounts may not equal the total for the year.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

We maintain a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act), is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports under the Exchange Act is accumulated and communicated to management, including the chief executive officer and the chief financial officer, allowing timely decisions regarding required disclosure. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of management, including the chief executive officer and the chief financial officer, of the effectiveness of our disclosure controls and procedures, the chief executive officer and the chief financial officer have concluded that our disclosure controls and procedures were effective.

There were no changes in our internal control over financial reporting during the three months ended December 31, 2015, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

See “Item 8. Financial Statements and Supplementary Data” for Management’s Report On Internal Control Over Financial Reporting and the Independent Registered Public Accounting Firm’s report with respect to the effectiveness of internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION

Investors should note that we announce material financial information in SEC filings, press releases and public conference calls. In accordance with SEC guidance, we may also use the Investor Relations section of our website (http://www.WestarEnergy.com, under “Investors”) to communicate with investors about our company. It is possible that the financial and other information we post there could be deemed to be material information. The information on our website is not part of this document.

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PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information concerning directors required by Item 401 of Regulation S-K will be included under the caption Election of Directors in our definitive Proxy Statement for our 2016 Annual Meeting of Shareholders to be filed pursuant to Regulation 14A (2016 Proxy Statement), and that information is incorporated by reference in this Form 10-K. Information concerning executive officers required by Item 401 of Regulation S-K is located under Part I, Item 1 of this Form 10-K. The information required by Item 405 of Regulation S-K concerning compliance with Section 16(a) of the Exchange Act will be included under the caption Additional Information - Section 16(a) Beneficial Ownership Reporting Compliance in our 2016 Proxy Statement, and that information is incorporated by reference in this Form 10-K. The information required by Item 406, 407(c)(3), (d)(4) and (d)(5) of Regulation S-K will be included under the captions Election of Directors - Corporate Governance Matters and - Board Meetings and Committees of the Board of Directors in our 2016 Proxy Statement, and that information is incorporated by reference in this Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

The information required by Item 11 will be set forth in our 2016 Proxy Statement under the captions Compensation Discussion and Analysis, Compensation Committee Report, Compensation of Executive Officers, Director Compensation and Compensation Committee Interlocks and Insider Participation, and that information is incorporated by reference in this Form 10-K.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required by Item 12 will be set forth in our 2016 Proxy Statement under the captions Beneficial Ownership of Voting Securities and Equity Compensation Plan Information, and that information is incorporated by reference in this Form 10-K.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by Item 13 will be set forth in our 2016 Proxy Statement under the caption Election of Directors - Corporate Governance Matters, and that information is incorporated by reference in this Form 10-K.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by Item 14 will be set forth in our 2016 Proxy Statement under the caption of Ratification and Confirmation of Deloitte and Touche LLP as Our Independent Registered Public Accounting Firm for 2016 and its subsections captioned Independent Registered Accounting Firm Fees and Audit Committee Pre-Approval Policies and Procedures, and that information is incorporated by reference in this Form 10-K.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

FINANCIAL STATEMENTS INCLUDED HEREIN

Westar Energy, Inc.

Management’s Report on Internal Control Over Financial Reporting

Reports of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of December 31, 2015 and 2014

Consolidated Statements of Income for the years ended December 31, 2015, 2014 and 2013

Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013

Consolidated Statements of Changes in Equity for the years ended December 31, 2015, 2014 and 2013

Notes to Consolidated Financial Statements

SCHEDULES

Schedule II - Valuation and Qualifying Accounts

Schedules omitted as not applicable or not required under the Rules of Regulation S-X: I, III, IV and V.

EXHIBIT INDEX

All exhibits marked “I” are incorporated herein by reference. All exhibits marked with “*” are management contracts or compensatory plans or arrangements required to be identified by Item 15(a)(3) of Form 10-K. All exhibits marked “#” are filed with this Form 10-K.

Description




1(a)	Sales Agency Financing Agreement, dated March 21, 2013, with BNY Mellon Capital Markets, LLC and The Bank of New York Mellon (filed as Exhibit 1.1 to the Form 8-K filed on March 22, 2013)	I
3(a)	By-laws of Westar Energy, Inc., as amended April 28, 2004 (filed as Exhibit 3(a) to the Form 10-Q for the period ended June 30, 2004 filed on August 4, 2004)	I
3(b)	Restated Articles of Incorporation of Westar Energy, Inc., as amended through May 25, 1988 (filed as Exhibit 4 to the Form S-8 Registration Statement, SEC File No. 33-23022 filed on July 15, 1988)	I
3(c)	Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibit 3 to the Form 10-K405 for the period ended December 31, 1998 filed on April 14, 1999)	I
3(d)	Certificate of Correction to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibit 3(b) to the Form 10-K for the period ended December 31, 1991 filed on March 30, 1992)	I
3(e)	Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibit 3(c) to the Form 10-K for the period ended December 31, 1994 filed on March 30, 1995)	I
3(f)	Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibit 3 to the Form 10-Q for the period ended June 30, 1994 filed on August 11, 1994)	I
3(g)	Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibit 3(a) to the Form 10-Q for the period ended June 30, 1996 filed on August 14, 1996)	I
3(h)	Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibit 3 to the Form 10-Q for the period ended March 31, 1998 filed on May 12, 1998)	I
3(i)	Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibit 3(l) to the Form 10-K for the period ended December 31, 2002 filed on April 11, 2003)	I
3(j)	Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibit 3(m) to the Form 10-K for the period ended December 31, 2002 filed on April 11, 2003)	I

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3(k)	Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibit 3(m) to the Form S-3 Registration Statement No. 333-125828 filed on June 15, 2005)	I
3(l)	Certificate of Amendment to Restated Articles of Incorporation of Westar Energy, Inc. (filed as Exhibit 3(m) to the Form 10-K for the period ended December 31, 2011 filed on February 23, 2012)	I
4(a)	Mortgage and Deed of Trust dated July 1, 1939 between Westar Energy, Inc. and Harris Trust and Savings Bank, Trustee (filed as Exhibit 4(a) to Registration Statement No. 33-21739)	I
4(b)	First and Second Supplemental Indentures dated July 1, 1939 and April 1, 1949, respectively (filed as Exhibit 4(b) to Registration Statement No. 33-21739)	I
4(c)	Sixth Supplemental Indenture dated October 4, 1951 (filed as Exhibit 4(b) to Registration Statement No. 33-21739)	I
4(d)	Fourteenth Supplemental Indenture dated May 1, 1976 (filed as Exhibit 4(b) to Registration Statement No. 33-21739)	I
4(e)	Twenty-Eighth Supplemental Indenture dated July 1, 1992 (filed as Exhibit 4(o) to the Form 10-K for the period ended December 31, 1992 filed on March 30, 1993)	I
4(f)	Twenty-Ninth Supplemental Indenture dated August 20, 1992 (filed as Exhibit 4(p) to the Form 10-K for the period ended December 31, 1992 filed on March 30, 1993)	I
4(g)	Thirtieth Supplemental Indenture dated February 1, 1993 (filed as Exhibit 4(q) to the Form 10-K for the period ended December 31, 1992 filed on March 30, 1993)	I
4(h)	Thirty-First Supplemental Indenture dated April 15, 1993 (filed as Exhibit 4(r) to the Form S-3 Registration Statement No. 33-50069 filed on August 24, 1993)	I
4(i)	Thirty-Second Supplemental Indenture dated April 15, 1994 (filed as Exhibit 4(s) to the Form 10-K for the period ended December 31, 1994 filed on March 30, 1995)	I
4(j)	Senior Indenture dated August 1, 1998 (filed as Exhibit 4.1 to the Form 10-Q for the period ended June 30, 1998 filed on August 12, 1998)	I
4(k)	Form of Senior Note (included in Exhibit 4(j))	I
4(l)	Thirty-Fourth Supplemental Indenture dated June 28, 2000 (filed as Exhibit 4(v) to the Form 10-K for the period ended December 31, 2000 filed on April 2, 2001)	I
4(m)	Thirty-Fifth Supplemental Indenture dated May 10, 2002 between Westar Energy, Inc. and BNY Midwest Trust Company, as Trustee (filed as Exhibit 4.1 to the Form 10-Q for the period ended March 31, 2002 filed on May 15, 2002)	I
4(n)	Thirty-Sixth Supplemental Indenture dated as of June 1, 2004, between Westar Energy, Inc. and BNY Midwest Trust Company (as successor to Harris Trust and Savings Bank), to its Mortgage and Deed of Trust dated July 1, 1939 (filed as Exhibit 4.1 to the Form 8-K filed on January 18, 2005)	I
4(o)	Thirty-Seventh Supplemental Indenture, dated as of June 17, 2004, between Westar Energy, Inc. and BNY Midwest Trust Company (as successor to Harris Trust and Savings Bank), to its Mortgage and Deed of Trust dated July 1, 1939 (filed as Exhibit 4.2 to the Form 8-K filed on January 18, 2005)	I
4(p)	Thirty-Eighth Supplemental Indenture, dated as of January 18, 2005, between Westar Energy, Inc. and BNY Midwest Trust Company (as successor to Harris Trust and Savings Bank), to its Mortgage and Deed of Trust dated July 1, 1939 (filed as Exhibit 4.3 to the Form 8-K filed on January 18, 2005)	I
4(q)	Thirty-Ninth Supplemental Indenture dated June 30, 2005 between Westar Energy, Inc. and BNY Midwest Trust Company (as successor to Harris Trust and Savings Bank) to its Mortgage and Deed of Trust dated July 1, 1939 (filed as Exhibit 4.1 to the Form 8-K filed on July 1, 2005)	I
4(r)	Form of Forty-Second Supplemental Indenture, dated as of March 1, 2012 by and among Westar Energy, Inc., The Bank of New York Mellon Trust Company, N.A. and Judith L. Bartolini (filed as Exhibit 4.1 to the Form 8-K filed on February 29, 2012)	I
4(s)	Form of Forty-Second Supplemental (Reopening) Indenture, dated as of May 17, 2012 by and among Westar Energy, Inc., The Bank of New York Mellon Trust Company, N.A. and Judith L. Bartolini (filed as Exhibit 4.1 to the Form 8-K filed on May 16, 2012)	I
4(t)	Form of Forty-Third Supplemental Indenture, dated as of March 28, 2013, by and among Westar Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as successor trustee to Harris Trust and Savings Bank (filed as Exhibit 4.1 to the Form 8-K filed on March 22, 2013)	I
4(u)	Form of Forty-Fourth Supplemental Indenture, dated as of August 19, 2013, by and among Westar Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as successor trustee to Harris Trust and Savings Bank (filed as Exhibit 4.1 to the Form 8-K filed on August 14, 2013)	I
4(v)	Form of Forty-Fifth Supplemental Indenture, dated as of November 13, 2015, by and among Westar Energy, Inc. and The Bank of New York Mellon Trust Company, N.A., as successor to Harris Trust and Savings Bank (filed as Exhibit 4.1 to the Form 8-K filed on November 6, 2015)	I

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	Instruments defining the rights of holders of other long-term debt not required to be filed as Exhibits will be furnished to the Commission upon request.

10(a)	Executive Salary Continuation Plan of Western Resources, Inc., as revised, effective September 22, 1995 (filed as Exhibit 10(j) to the Form 10-K for the period ended December 31, 1995 filed on March 27, 1996)*	I
10(b)	Amended and Restated Long-Term Incentive and Share Award Plan (filed as Exhibit 10 to the Form 8-K filed on May 6, 2011)*	I
10(c)	Westar Energy, Inc. Form of Restricted Share Units Award (filed as Exhibit 10(f) to the Form 10-K for the period ended December 31, 2014 filed on February 25, 2015)*	I
10(d)	Westar Energy, Inc. Form of Performance Based Restricted Share Units Award (filed as Exhibit 10(g) to the Form 10-K for the period ended December 31, 2014 filed on February 25, 2015)*	I
10(e)	Westar Energy, Inc. Non-Employee Director Deferred Compensation Plan, as amended and restated, dated as of October 20, 2004 (filed as Exhibit 10.1 to the Form 8-K filed on October 21, 2004)*	I
10(f)	Summary of Westar Energy, Inc. Non-Employee Director Compensation*	#
10(g)	Form of Amended and Restated Change in Control Agreement with Officers of Westar Energy, Inc.*	#
10(h)	Westar Energy, Inc. Retirement Benefit Restoration Plan (filed as Exhibit 10.1 to the Form 8-K filed on April 2, 2010)*	I
10(i)	Westar Energy, Inc. 401(k) Benefit Restoration Plan (filed as Exhibit 10(l) to the Form 10-K for the period ended December 31, 2014 filed on February 25, 2015)*	I
10(j)	Credit Agreement dated as of February 18, 2011, among Westar Energy, Inc. and several banks and other financial institutions or entities from time to time parties to the Agreement (filed as Exhibit 10.1 to the Form 8-K filed on February 22, 2011)	I
10(k)	First Extension Agreement dated as of February 12, 2013, among Westar Energy, Inc. and several banks and other financial institutions party thereto (filed as Exhibit 10.1 to the Form 8-K filed on February 15, 2013)	I
10(l)	Second Extension Agreement dated as of February 14, 2014, among Westar Energy, Inc. and several banks and other financial institutions or entities from time to time parties to the Agreement (filed as Exhibit 10(v) to the Form 10-K for the period ended December 31, 2013 filed on February 26, 2014)	I
10(m)	Fourth Amended and Restated Credit Agreement dated as of September 29, 2011, among Westar Energy, Inc. and several banks and other financial institutions or entities from time to time parties to the Agreement (filed as Exhibit 10.1 to the Form 8-K filed on September 29, 2011)	I
10(n)	First Extension Agreement dated as of July 19, 2013, among Westar Energy, Inc. and several banks and other financial institutions or entities from time to time parties to the Agreement (filed as Exhibit 10(a) to the Form 10-Q for the period ended September 30, 2014 filed on November 5, 2014)	I
10(o)	Second Extension Agreement dated as of September 18, 2014, among Westar Energy, Inc. and several banks and other financial institutions or entities from time to time parties to the Agreement (filed as Exhibit 10(b) to the Form 10-Q for the period ended September 30, 2014 filed on November 5, 2014)	I
10(p)	Third Extension Agreement dated as of September 17, 2015, among Westar Energy, Inc. and several banks and other financial institutions or entities from time to time parties to the Agreement (filed as Exhibit 10 to the Form 10-Q for the period ended September 30, 2015 filed on November 3, 2015)	I
10(q)	Master Confirmation for Forward Stock Sale Transactions, dated March 21, 2013, between Westar Energy, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Form 8-K filed on March 22, 2013)	I
10(r)	Confirmation of Forward Sale Transaction, dated September 24, 2013, between JPMorgan Chase Bank, National Association, London Branch and Westar Energy, Inc. (filed as Exhibit 10.1 to the Form 8-K filed on September 27, 2013)	I
10(s)	Confirmation of Forward Sale Transaction, dated September 24, 2013, between Wells Fargo Bank, National Association and Westar Energy, Inc. (filed as Exhibit 10.2 to the Form 8-K filed on September 27, 2013)	I
10(t)	Confirmation of Additional Forward Stock Sale Transaction, dated October 16, 2013, between JPMorgan Chase Bank, National Association, London Branch and Westar Energy, Inc. (filed as Exhibit 10.1 to the Form 8-K filed on October 17, 2013)	I
10(u)	Confirmation of Additional Forward Stock Sale Transaction, dated October 16, 2013, between Wells Fargo Bank, National Association and Westar Energy, Inc. (filed as Exhibit 10.2 to the Form 8-K filed on October 17, 2013)	I
12	Computations of Ratio of Consolidated Earnings to Fixed Charges	#
21	Subsidiaries of the Registrant	#
23	Consent of Independent Registered Public Accounting Firm, Deloitte & Touche LLP	#

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31(a)	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	#
31(b)	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	#
32	Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished and not to be considered filed as part of the Form 10-K)	#
101.INS	XBRL Instance Document	#
101.SCH	XBRL Taxonomy Extension Schema Document	#
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document	#
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document	#
101.LAB	XBRL Taxonomy Extension Label Linkbase Document	#
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document	#

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WESTAR ENERGY, INC.

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS



Description	Balance at Beginning of Period		Charged to Costs and Expenses		Deductions (a)			Balance at End of Period
	(In Thousands)
Year ended December 31, 2013
Allowances deducted from assets for doubtful accounts	$	4,916	$	7,039	$	(7,359	)	$	4,596

Year ended December 31, 2014
Allowances deducted from assets for doubtful accounts	$	4,596	$	9,752	$	(9,039	)	$	5,309

Year ended December 31, 2015
Allowances deducted from assets for doubtful accounts	$	5,309	$	8,614	$	(8,629	)	$	5,294

_______________


(a)	Result from write-offs of accounts receivable.

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SIGNATURE

Pursuant to the requirements of Sections 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



		WESTAR ENERGY, INC.

Date:	February 24, 2016	By:	/s/ ANTHONY D. SOMMA
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.



Signature	Title	Date
/S/ MARK A. RUELLE	Director, President and Chief Executive Officer (Principal Executive Officer)	February 24, 2016
(Mark A. Ruelle)

/S/ ANTHONY D. SOMMA	Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer)	February 24, 2016
(Anthony D. Somma)

/S/ CHARLES Q. CHANDLER IV	Chairman of the Board	February 24, 2016
(Charles Q. Chandler IV)

/S/ MOLLIE H. CARTER	Director	February 24, 2016
(Mollie H. Carter)

/S/ R. A. EDWARDS III	Director	February 24, 2016
(R. A. Edwards III)

/S/ JERRY B. FARLEY	Director	February 24, 2016
(Jerry B. Farley)

/S/ RICHARD L. HAWLEY	Director	February 24, 2016
(Richard L. Hawley)

/S/ B. ANTHONY ISAAC	Director	February 24, 2016
(B. Anthony Isaac)

/S/ SANDRA A. J. LAWRENCE	Director	February 24, 2016
(Sandra A. J. Lawrence)

/S/ S. CARL SODERSTROM JR.	Director	February 24, 2016
(S. Carl Soderstrom Jr.)

119

Exhibit

Exhibit 10(f)

Westar Energy, Inc.

Non-Employee Director Compensation Program

Effective January 1, 2016



Item	Amount
Board Fees
Annual Retainer	$70,000
Meeting Fees	None
Committee Fees
Audit
Chair Retainer	$20,000
Member Retainer	$10,000
Meeting Fees	None
Compensation
Chair Retainer	$16,500
Member Retainer	$8,000
Meeting Fees	None
Nominating & Governance
Chair Retainer	$13,500
Member Retainer	$6,000
Meeting Fees	None
Finance
Chair Retainer	$13,500
Member Retainer	$6,000
Meeting Fees	None
Annual Stock Award	$85,000
Additional Non-Executive Chair	$100,000 ($40,000 cash) ($60,000 stock)

Stock awards are issued pursuant to the Westar Energy, Inc. Long Term Incentive and Share Award Plan, as amended from time to time.

A non-employee director may elect to have all or a portion of any cash fees paid in stock rather than cash in accordance with the Westar Energy, Inc. Long Term Incentive and Share Award Plan, as amended from time to time.

A non-employee director may elect to defer payment of cash fees or stock in accordance with the provisions of the Non-Employee Director Deferred Compensation Plan.

A non-employee director is entitled to be reimbursed for (i) travel and other out-of-pocket expenses incidental to attending meetings and (ii) reasonable expenses relating to ongoing director education.

Westar Energy, Inc. provides liability insurance to its directors under its directors and officers insurance policies.

Exhibit

Exhibit 10(g)

[Date]

[Employee Name]

_________________

Dear [First Name]:

You are presently the [Title], of Westar Energy, Inc., a Kansas corporation (the “Company”). The Company considers the establishment and maintenance of a sound and vital management team to be essential to protecting and enhancing the best interests of the Company and its shareholders. In this regard, the Company recognizes that, as is the case for many publicly-held corporations, the possibility of a Change in Control may arise and that such possibility and the uncertainty and questions which it may raise among management may result in the departure or distraction of management personnel to the detriment of the Company and its shareholders.

Accordingly, the Board has determined that appropriate steps should be taken to minimize the risk that the Company’s management will depart prior to a Change in Control, thereby leaving the Company without adequate management personnel during such a critical period, and that appropriate steps also be taken to reinforce and encourage the continued attention and dedication of members of the Company’s management to their assigned duties without distraction in circumstances arising from the possibility of a Change in Control. In particular, the Board believes it important, should the Company or its shareholders receive a proposal for transfer of control, that you be able to continue your management responsibilities without being influenced by the uncertainties of your own personal situation.

The Board recognizes that continuance of your position with the Company involves a substantial commitment to the Company in terms of your personal life and professional career and the possibility of foregoing present and future career opportunities, for which the Company receives substantial benefits. Therefore, to induce you to remain in the employ of the Company, this Agreement, which has been approved by the Board, sets forth the benefits that the Company agrees will be provided to you in the event your employment with the Company is terminated in connection with a Change in Control under the circumstances described below.

The following terms will have the meaning set forth below unless the context clearly requires otherwise. Terms defined elsewhere in this Agreement will have the same meaning throughout this Agreement.

Article I

Definitions

1.“Affiliate” means (i) any corporation at least a majority of whose outstanding securities ordinarily having the right to vote at elections of directors is owned directly or indirectly by the Company or (ii) any other form of business entity in which the Company, by virtue of a direct or indirect ownership interest, has the right to elect a majority of the members of such entity’s governing body.

2.“Agreement” means this letter agreement, as amended, extended or renewed from time to time in accordance with its terms.

3.“Annual RSU Grant” means the number of restricted share units granted to you in your most recent annual grant of restricted share units, which shall be equal to the sum of the number of time-based restricted share units and the target number of performance-based restricted share units.

4.“Board” means the board of directors of the Company duly qualified and acting at the time in question. On and after the date of a Change in Control, any duty of the Board in connection with this Agreement is non-delegable and any attempt by the Board to delegate any such duty is ineffective.

[Employee Name]

[Date]

Page 2 of 9

5.“Cause” means your conviction of a felony or crime involving moral turpitude, your commission of a willful act of fraud or dishonesty with respect to the Company, your willful and repeated failure to perform substantially your material duties with the Company, your engaging in significant activity that is materially harmful to the reputation of the Company, or your breach of your fiduciary responsibilities to the Company or its shareholders.

6.“Change in Control” means any of the following:

a.the sale, lease, exchange or other transfer, directly or indirectly, of all or substantially all of the assets of the Company in one transaction or in a series of related transactions, to any Person;

b.except in the case of the liquidation or dissolution of the Company in connection with the bankruptcy or insolvency of the Company or similar arrangement for the benefit of the Company’s creditors, the approval by the shareholders of the Company of any plan or proposal for the liquidation or dissolution of the Company, as the case may be;

c.any Person is or becomes the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of 20 percent or more of the combined voting power of the outstanding securities of the Company ordinarily having the right to vote at elections of directors;

d.a merger or consolidation to which the Company is a party if the shareholders of the Company immediately prior to the effective date of such merger or consolidation have, solely on account of ownership of securities of the Company at such time, “beneficial ownership” (as defined in Rule 13d-3 under the Exchange Act) immediately following the effective date of such merger or consolidation of securities of the surviving corporation representing less than 50 percent of the combined voting power of the surviving corporation’s then outstanding securities ordinarily having the right to vote at elections of directors (regardless of any approval by the continuing directors);

e.the continuing directors cease for any reason to constitute at least a majority of the Board; or

f.a change in control of a nature that is determined by outside legal counsel to the Company, in a written opinion specifically referencing this provision of the Agreement, to be required to be reported (assuming such event has not been “previously reported”) pursuant to section 13 or 15(d) of the Exchange Act, whether or not the Company is then subject to such reporting requirement, as of the effective date of such Change in Control.

For purposes of this Section 6, a “continuing director”‘ means any individual who is a member of the Board on January 20, 2006 while he or she is a member of the Board, and any individual who subsequently becomes a member of the Board whose election or nomination for election by the Company’s shareholders was approved by a vote of at least a majority of the directors who are continuing directors (either by a specific vote or by approval of the proxy statement of the Company in which such individual is named as a nominee for director without objection to such nomination).

Notwithstanding the preceding provisions of this Section 6, a Change in Control shall not be deemed to have occurred if the Person described in the preceding provisions of this Section 6 is (1) an underwriter or underwriting syndicate that has acquired the ownership of any of the Company’s then outstanding voting securities solely in connection with a public offering of the Company’s securities, (2) the Company or any subsidiary of the Company or (3) an employee stock ownership plan or other employee benefit plan maintained by the Company (or any of its affiliated companies) that is qualified under the provisions of the Code. In addition, notwithstanding the preceding provisions of this Section, a Change in Control shall not be deemed to have occurred if the Person described in the preceding provisions of this Section becomes a beneficial owner of more than the permitted amount of outstanding securities as a result of the acquisition of voting securities by the Company which, by reducing the number of voting securities outstanding, increases the proportional number of shares beneficially owned by such

[Employee Name]

[Date]

Page 3 of 9

Person, provided, that if a Change in Control would occur but for the operation of this sentence and such Person becomes the beneficial owner of any additional voting securities (other than through the exercise of options granted under any stock option plan of the Company or through a stock dividend or stock split), then a Change in Control shall occur.

7.“Code” means the Internal Revenue Code of 1986, as amended. Any reference to a specific provision of the Code includes a reference to such provision as it may be amended from time to time and to any successor provision.

8.“Company” means Westar Energy, Inc., a Kansas corporation.

9.“Confidential Information” means information which is proprietary to the Company or proprietary to others and entrusted to the Company, whether or not trade secrets. It includes information relating to business plans and to business as conducted or anticipated to be conducted, and to past or current or anticipated products or services. It also includes, without limitation, information concerning research, development, purchasing, accounting, marketing and selling. All information which you have a reasonable basis to consider confidential is Confidential Information, whether or not originated by you and without regard to the manner in which you obtain access to that and any other proprietary information.

10.“Date of Termination” following a Change in Control (or prior to a Change in Control if your termination was either a condition of the Change in Control or was at the request or insistence of any Person related to the Change in Control) means:

a.if your employment is to be terminated for Disability, 30 days after Notice of Termination is given (provided that you have not returned to the performance of your duties on a full-time basis during such 30-day period);

b.if your employment is to be terminated by the Company for Cause or by you for Good Reason, the date specified in the Notice of Termination, which date may not be less than 30 days or more than 60 days after the date on which the Notice of Termination is given unless you and the Company otherwise expressly agree;

c.if your employment is to be terminated by the Company for any reason other than Cause, Disability, death or Retirement, the date specified in the Notice of Termination, which in no event may be a date earlier than 30 days after the date on which a Notice of Termination is given, unless an earlier date has been expressly agreed to by you in writing either in advance of, or after receiving, such Notice of Termination; or

d.if your employment is terminated by reason of death or Retirement, the date of death of Retirement, respectively.

In the case of termination by the Company of your employment for Cause, if you have not previously expressly agreed in writing to the termination, then within 30 days after receipt by you of the Notice of Termination with respect thereto, you may notify the Company that a dispute exists concerning the termination, in which event the Date of Termination will be the date set either by mutual written agreement of the parties or by the judge or arbitrators in a proceeding as provided in Article IV, Section 6 of this Agreement. During the pendency of any such dispute, you will continue to make yourself available to provide services to the Company and the Company will continue to pay you your full compensation and benefits in effect immediately prior to the date on which the Notice of Termination is given (without regard to any changes to such compensation or benefits which constitute Good Reason) and until the dispute is resolved in accordance with Article IV, Section 6 of this Agreement. You will be entitled to retain the full amount of any such compensation and benefits without regard to the resolution of the dispute unless the judge or arbitrators decide(s) that your claim of a dispute was frivolous or advanced by you in bad faith.

11.“Disability” means a permanent and total disability as defined in section 22(e)(3) of the Code.

[Employee Name]

[Date]

Page 4 of 9

12.“Exchange Act” means the Securities Exchange Act of 1934, as amended. Any reference to a specific provision of the Exchange Act or to any rule or regulation thereunder includes a reference to such provision as it may be amended from time to time and to any successor provision.

13.“Good Reason” means (1) any change in your status as an officer of the Company, (2) a reduction by the Company in your total annual compensation, as in effect immediately prior to the Change in Control or as the same may be increased from time to time thereafter, including a reduction in your base salary, a reduction in your Annual RSU Grant value (calculated based on your Annual RSU Grant and the price per share for the Company’s common stock used in determining your most recent Annual RSU Grant) and the elimination of dividend equivalents on the Annual RSU Grant, provided that a reduction in total annual compensation resulting from a change by the Company in the indicated annual dividend paid on the Company’s common stock shall not be deemed “Good Reason,” (3) any requirement of the Company that you be required to relocate more than 80 miles from your principal office location immediately prior to the Change in Control provided that your new principal office is located outside the Company’s Kansas service territory on the date hereof, (4) the taking of any action by the Company which would materially and adversely affect your participation in or reduce your benefits under any Plan, unless you are permitted to participate in other plans providing you with substantially equivalent benefits at no greater cost to you, (5) any purported termination by the Company of your employment which is not properly effected pursuant to a Notice of Termination and pursuant to any other requirements of this Agreement, or (6) the failure of the Company to obtain the assumption agreement contemplated in Article IV, Section 2.

14.“Notice of Termination” means a written notice given on or after the date of a Change in Control (unless your termination before the date of the Change in Control was either a condition of the Change in Control or was at the request or insistence of any Person related to the Change in Control) which indicates the specific termination provision in this Agreement pursuant to which the notice is given. Any purported termination by the Company or by you for Good Reason on or after the date of a Change in Control (or before the date of a Change in Control if your termination was either a condition of the Change in Control or was at the request or insistence of any Person related to the Change in Control) must be communicated by a written Notice of Termination to be effective; provided, that a Notice of Termination by you for Good Reason must be delivered to the Company not later than 90 calendar days after your knowledge of the event serving as the basis for your termination for Good Reason.

15.“Person” means any individual, corporation, partnership, group, association or other “person,” as such term is used in section 14(d) of the Exchange Act, other than the Company, or any Affiliate or any employee benefit plan(s) sponsored by the Company or an Affiliate.

16.“Plan” means any employee benefit plan, welfare benefit plan or fringe benefit plan in which you are participating immediately prior to a Change in Control or, if more favorable to you, which may be available from time to time thereafter to you or other comparable executives of the Company.

17.“Qualifying Termination” means the termination of your employment within three years following a Change in Control (a) by the Company or the Company’s Successor without Cause or (b) by you for Good Reason. A Qualifying Termination shall not include a termination of your employment by reason of your death, Disability or Retirement.

18.“Retirement” means termination of your employment on or after your normal retirement date under the terms of the Westar Energy, Inc. Retirement Plan, as in effect immediately prior to your termination or a Change in Control, whichever is earlier.

19.“Separation from Service” means your termination of employment with the Company.

20.“Successor” means any Person that succeeds to, or has the practical ability to control (either immediately or solely with the passage of time), the Company’s business directly, by merger, consolidation or other form of business combination, or indirectly, by purchase of the Company’s outstanding securities ordinarily having the right to vote at the election of directors or, all or substantially all of its assets or otherwise.

[Employee Name]

[Date]

Page 5 of 9

ARTICLE II

TERM OF AGREEMENT

This Agreement is effective immediately and will continue in effect until the earliest of (a) your termination of this Agreement, (b) the Company’s termination of this Agreement by providing you with written notice of such termination at least 180 calendar days prior to the proposed termination date, provided that such termination notice shall be deemed to be null and void if prior to such proposed termination date a Change in Control occurs or another event occurs that would result in a Change in Control, or (c) the third anniversary of a Change in Control.

ARTICLE III

CHANGE IN CONTROL BENEFITS

1.Benefits payable following Separation from Service following a Qualifying Termination. If you have a Separation from Service with the Company following a Qualifying Termination, then the Company will provide you the payments and benefits described in clauses (a) and (b) of this Section 1 of Article III, subject to the limitations described in clause (c) of this Section 1 of Article III.

a.Cash Payment. On the first business day following the six month anniversary of your Separation from Service with the Company following a Qualifying Termination, the Company will make a lump-sum cash payment to you in an amount equal to the sum of:

i.two times your annual base salary in effect on the date of the Change in Control or, if higher, your annual base salary in effect on the Date of Termination;

ii.two times (x) your Annual RSU Grant multiplied by (y) the average of the high and low selling price per share for the Company’s common stock on the date of the Change in Control or, if higher, the Date of Termination (or, if either such date was not a trading day, on the next preceding day when shares were traded) as reported by the New York Stock Exchange, provided that if the restricted share units related to the Annual RSU Grant are converted into restricted share units related to securities of the Company’s Successor in connection with the Change in Control, the amount payable pursuant to this clause (ii) will be based on the number of securities into which such restricted share units are converted and the average of the high and low selling price per share of such securities;

iii.two times (x) your Annual RSU Grant multiplied by (y) the indicated annual dividend on the Company’s common stock in effect on the date of the Change in Control or, if higher, the Date of Termination, provided that if the restricted share units related to the Annual RSU Grant are converted into restricted share units related to securities of the Company’s Successor in connection with the Change in Control, the amount payable pursuant to this clause (iii) will be based on the number of securities into which such restricted share units are converted and the indicated annual dividend on such securities;

iv.the excess of (x) the present value (determined as of the Date of Termination) of the lump-sum actuarial equivalent of the benefit you would have received, giving you credit for two additional years of age and service under the Company’s pension plans in which you participate, utilizing actuarial assumptions (including the discount rate used in the present value calculation) no less favorable to you than those in effect under the pension plan immediately prior to the Change in Control, over (y) the present value (determined as of the Date of Termination) of the lump-sum actuarial equivalent of your actual benefits accrued as of the Date of Termination, if any, under the pension plans, and utilizing the same actuarial assumptions as used above;

[Employee Name]

[Date]

Page 6 of 9

v.the product of (x) your annual base salary in effect on the Date of Termination divided by 2080, and (y) the number of hours of unused vacation you were eligible to receive in the year of your termination; and

vi.the product of (x) your annual base salary in effect on the Date of Termination divided by 2080, and (y) the number of hours of unused sick leave you have earned, up to a maximum of 240 hours.

b.Welfare Plans. The Company will maintain in full force and effect, for the continued benefit of you and your dependents for a period terminating on the earlier of (x) the second anniversary of the Date of Termination and (y) the date you begin receiving equivalent benefits from a new employer (including coverage for any pre-existing conditions), all insured and self-insured employee benefit and welfare benefit Plans (including, without limitation, medical, life, dental, vision and disability plans) in which you were eligible to participate at any time during the 90-day period immediately preceding the Change in Control, provided that your continued participation is possible under the general terms and provisions of such Plans and without regard to any discretionary amendments to such Plans by the Company following the Change in Control (or prior to the Change in Control if amended as a condition of or at the request or insistence of a Person (other than the Company) related to the Change in Control) and provided that you continue to pay an amount equal to your regular contribution under such Plans for such participation (based upon your level of benefits and employment status most favorable to you at any time during the 90-day period immediately preceding the Change in Control). The continuation period under federal and state continuation laws, to the extent applicable, will begin to run from the date on which coverage pursuant to this clause (b) ends. If, at the end of the two year period, you have not previously received or are not then receiving equivalent benefits from a new employer (including coverage for any pre-existing conditions), the Company, pursuant to federal and state law, will provide, for a period of eighteen months (the “COBRA Period”), a continuation of your and your dependents’ coverage under such Plans (the “COBRA Coverage”), provided that you will be required to pay for such benefits during the COBRA Period, should you elect to receive COBRA Coverage.

c.Limitation on Payments and Benefits. Notwithstanding anything in this Agreement to the contrary, if any of the payments or benefits to be made or provided in connection with this Agreement, together with any other payments, benefits or awards which you have the right to receive from the Company, or any corporation which is a member of an “affiliated group” (as defined in section 1504(a) of the Code without regard to section 1504(b) of the Code), of which the Company is a member, constitute an “excess parachute payment” (as defined in section 280G(b) of the Code), such payments, benefits or awards will be reduced by the minimum amount the Company deems necessary so that none of the payments or benefits under the Agreement are excess parachute payments. The calculations to determine such reduction must be made in good faith by legal counsel or a certified public accountant selected by the Company, and such determination will be conclusive and binding upon you and the Company.

ARTICLE IV

OTHER PROVISIONS

1.Binding Agreement. This Agreement inures to the benefit of, and is enforceable by, you, your personal and legal representatives, executors, administrators, successors, heirs, distributes, devisees and legatees. If you die while any amount would still be payable to you under this Agreement if you had continued to live, all such amounts, unless otherwise provided in this Agreement, will be paid in accordance with the terms of this Agreement to your devisee, legatee or other designee or, if there be no such designee, to your estate.

2.Successors. This Agreement shall not be terminated by any sale, merger or other business combination involving the Company or its business. In the event of any such sale, merger or other business combination, the provisions of this Agreement shall be binding upon the Company’s Successor. The Company agrees that in connection with any sale, merger or other business combination, it will cause the Company’s Successor (x) unconditionally to assume by written instrument delivered to you, all of the obligations of the Company hereunder, and (y) maintain directors and officers liability insurance for five years following your termination that provides coverage for you as a former officer of the Company or its Successor substantially the same as the coverage provided to current officers of the Company or its Successor.

[Employee Name]

[Date]

Page 7 of 9

3.Confidential Information. During the term and for three years following the Date of Termination, you will not, directly or indirectly, disclose or use any of the Company’s Confidential Information, other than in the proper performance of the duties contemplated herein or as required by law or by a court of competent jurisdiction or other administrative or legislative body. You agree to return all confidential information to the Company at any time upon request of the Company and upon the termination of your employment for any reason.

4.Taxes. All payments and benefits to be made or provided to you in connection with this Agreement will be subject to required withholding of federal, state and local income, excise and employment-related taxes.

5.Notices. For the purposes of this Agreement, notices and all other communications provided for in, or required under, this Agreement must be in writing and will be deemed to have been duly given when personally delivered or when mailed by United States registered or certified mail, return receipt requested, postage prepaid and addressed to each party’s respective address set forth on the first page of this Agreement (provided that all notices to the Company must be directed to the attention of the General Counsel), or to such other address as either party may have furnished to the other in writing in accordance with these provisions, except that notice of change of address will be effective only upon receipt.

6.Disputes. Any dispute, controversy or claim arising under or in connection with this Agreement will be settled exclusively by binding arbitration administered by the American Arbitration Association in Topeka, Kansas in accordance with the Commercial Arbitration Rules of the American Arbitration Association then in effect. Judgment may be entered on the arbitrator’s award in any court having jurisdiction. If any dispute shall arise involving your right to benefits hereunder, the Company will reimburse you on a current basis for all legal fees and expenses incurred in connection with such dispute regardless of the result thereof, provided that if the arbitrators determine that the Company properly terminated your employment for Cause, you will be obligated to repay to the Company any such reimbursement made by the Company.

7.Related Agreements. To the extent that any provision of any other Plan or agreement between the Company and you limits, qualifies or is inconsistent with any provision of this Agreement, then for purposes of this Agreement, while such other Plan or agreement remains in force, the provision of this Agreement will control and such provision of such other Plan or agreement will be deemed to have been superseded, and to be of no force or effect, as if such other agreement had been formally amended to the extent necessary to accomplish such purpose. Nothing in this Agreement prevents or limits your continuing or future participation in any Plan provided by the Company and for which you may qualify, and nothing in this Agreement limits or otherwise affects the rights you may have under any Plans or other agreements with the Company. Amounts which are vested benefits or which you are otherwise entitled to receive under any Plan or other agreement with the Company at or subsequent to the Date of Termination will be payable in accordance with such Plan or other agreement.

8.No Employment or Service Contract. Nothing in this Agreement is intended to provide you with any right to continue in the employ of the Company for any period of specific duration or interfere with or otherwise restrict in any way your rights or the rights of the Company, which rights are hereby expressly reserved by each, to terminate your employment at any time for any reason or no reason whatsoever, with or without Cause.

9.Funding and Payment. Benefits payable under this Agreement will be paid only from the general assets of the Company. No person has any right to or interest in any specific assets of the Company by reason of this Agreement. To the extent benefits under this Agreement are not paid when due to any individual, he or she is a general unsecured creditor of the Company with respect to any amounts due.

10.Survival. The respective obligations of, and benefits afforded to, the Company and you which by their express terms or clear intent survive termination of your employment with the Company or termination of this Agreement, as the case may be, including without limitation the provisions of Article III, will survive termination of your employment with the Company or termination of this Agreement, as the case may be, and will remain in full force and effect according to their terms.

[Employee Name]

[Date]

Page 8 of 9

ARTICLE V

MISCELLANEOUS

1.Modification and Waiver. No provision of this Agreement may be modified, waived or discharged unless such modification, waiver or discharge is agreed to in a writing signed by you and the Company. No waiver by any party to this Agreement at any time of any breach by another party to this Agreement of, or of compliance with, any condition or provision of this Agreement to be performed by such party will be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time.

2.Entire Agreement. No agreements or representations, oral or otherwise, express or implied, with respect to the subject matter to this Agreement have been made by any party which is not expressly set forth in this Agreement.

3.Governing Law. This Agreement and the legal relations among the parties as to all matters, including, without limitation, matters of validity, interpretation, construction, performance and remedies, will be governed by and construed exclusively in accordance with the internal laws of the State of Kansas (without regard to the conflict of laws principles of any jurisdiction).

4.Headings. Headings are for purposes of convenience only and do not constitute a part of this Agreement.

5.Further Acts. The parties to this Agreement agree to perform, or cause to be performed, such further acts and deeds and to execute and deliver or cause to be executed and delivered, such additional or supplemental documents or instruments as may be reasonably required by the other party to carry into effect the intent and purpose of this Agreement.

6.Severability. The invalidity or unenforceability of all or any part of any provision of this Agreement will not affect the validity or enforceability of the remainder of such provision or of any other provision of this Agreement, which will remain in full force and effect.

7.Counterparts. This Agreement may be executed in several counterparts, each of which will be deemed to be an original, but all of which together will constitute one and the same instrument.

8.Compliance With Section 409A. It is the intent of the parties that the provisions of this Agreement comply with Code Section 409A and the Treasury regulations and guidance issued thereunder (“Section 409A”) and that this Agreement be interpreted and operated consistent with such requirements of Section 409A in order to avoid the application of additive income taxes under Section 409A (“409A Penalties”). To the extent that a payment, or the settlement or deferral thereof, is subject to Section 409A, except as you and the Board otherwise determine in writing, the payment shall be paid, settled or deferred in a manner that will meet the requirements of Section 409A, such that the payment, settlement, or deferral shall not be subject to the 409A Penalties.

[Signatures on following page]

[Employee Name]

[Date]

Page 9 of 9

If this letter correctly sets forth our agreement on the subject matter discussed above, kindly sign and return to the Company the enclosed copy of this letter, which will then constitute our agreement on this subject.

WESTAR ENERGY, INC.

____________________________________

Name:

Title:

ACCEPTED AND AGREED:

_____________________________________

Date: [Date]

Exhibit



							Exhibit 12
WESTAR ENERGY, INC.
Computations of Ratio of Earnings to Fixed Charges and
Computations of Ratio of Earnings to Combined Fixed Charges
and Preferred Dividend Requirements
(Dollars in Thousands)

	Year Ended December 31,
	2015		2014		2013		2012		2011

Earnings from continuing operations (a)	$	446,192	$	465,538	$	421,449	$	406,638	$	339,274

Fixed Charges:
Interest (expensed and capitalized)	180,307		195,162		193,873		186,736		178,049
Interest on corporate-owned life insurance borrowings	58,178		58,344		57,767		63,518		66,326
Interest applicable to rentals	4,678		4,714		5,495		4,675		4,528
Total Fixed Charges (b)	243,163		258,220		257,135		254,929		248,903

Distributed income of equity investees	3,000		—		—		—		—

Preferred Dividend Requirements:
Preferred dividends	—		—		—		1,616		970
Income tax required	—		—		—		723		424

Total Preferred Dividend Requirements (c)	—		—		—		2,339		1,394

Total Fixed Charges and Preferred Dividend Requirements	243,163		258,220		257,135		257,268		250,297

Earnings (d)	$	692,355	$	723,758	$	678,584	$	661,567	$	588,177

Ratio of Earnings to Fixed Charges	2.85		2.80		2.64		2.60		2.36

Ratio of Earnings to Combined Fixed Charges and Preferred Dividend Requirements	2.85		2.80		2.64		2.57		2.35

_______________

(a) Earnings from continuing operations consist of income from continuing operations before income taxes, cumulative effects of accounting changes and preferred dividends adjusted for undistributed earnings from equity investees.

(b) Fixed charges consist of all interest on indebtedness, interest on uncertain tax positions, interest on corporate-owned life insurance policies, amortization of debt discount and expense, and the portion of rental expense that represents an interest factor.

(c) Preferred dividend requirements consist of an amount equal to the pre-tax earnings that would be required to meet dividend requirements on preferred stock.

(d) Earnings are deemed to consist of earnings from continuing operations, fixed charges and distributed income of equity investees.

Exhibit

Exhibit 21

WESTAR ENERGY, INC.

Subsidiaries of the Registrant



Subsidiary	State of Incorporation	Date Incorporated

1) Kansas Gas and Electric Company (a)	Kansas	October 9, 1990
_______________
(a) Kansas Gas and Electric Company does business as Westar Energy.

Exhibit

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-187398 on Form S-3, and Registration Statement Nos. 333-175293, 333-70891 and 333-151104 on Form S-8 of our reports dated February 24, 2016, relating to the consolidated financial statements and financial statement schedule of Westar Energy, Inc. and subsidiaries, and the effectiveness of Westar Energy, Inc. and subsidiaries' internal control over financial reporting, appearing in this Annual Report on Form 10-K of Westar Energy, Inc. for the year ended December 31, 2015.

/s/ Deloitte & Touche LLP

Kansas City, Missouri

February 24, 2016

Exhibit

Exhibit 31(a)

WESTAR ENERGY, INC.

CHIEF EXECUTIVE OFFICER

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Mark A. Ruelle, certify that:


1.	I have reviewed this annual report on Form 10-K for the period ended December 31, 2015, of Westar Energy, Inc.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c.	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d.	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



Date:	February 24, 2016	By:	/s/ Mark A. Ruelle
			Mark A. Ruelle
			President and Chief Executive Officer
			Westar Energy, Inc.

Exhibit

Exhibit 31(b)

WESTAR ENERGY, INC.

CHIEF FINANCIAL OFFICER

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Anthony D. Somma, certify that:


1.	I have reviewed this annual report on Form 10-K for the period ended December 31, 2015, of Westar Energy, Inc.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c.	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d.	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.	The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):


a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



Date:	February 24, 2016	By:	/s/ Anthony D. Somma
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer
			Westar Energy, Inc.

Exhibit

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Westar Energy, Inc. (the Company) on Form 10-K for the year ended December 31, 2015, (the Report), which this certification accompanies, Mark A. Ruelle, in my capacity as Director, President and Chief Executive Officer of the Company, and Anthony D. Somma, in my capacity as Senior Vice President, Chief Financial Officer and Treasurer of the Company, certify that the Report fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934 and that information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



Date:	February 24, 2016	By:	/s/ Mark A. Ruelle
			Mark A. Ruelle
			President and Chief Executive Officer



Date:	February 24, 2016	By:	/s/ Anthony D. Somma
			Anthony D. Somma
			Senior Vice President, Chief Financial Officer and Treasurer