Illinois Power Generating Co - FORM 10-K

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EX-32.2 - CFO 906 CERT EXHIBIT - Illinois Power Generating Co	gen-201512x3110kex322.htm
EX-31.2 - CFO 302 CERT EXHIBIT - Illinois Power Generating Co	gen-201512x3110xkex312.htm
EX-32.1 - CEO 906 CERT EXHIBIT - Illinois Power Generating Co	gen-201512x3110xkex321.htm
EX-31.1 - CEO 302 CERT EXHIBIT - Illinois Power Generating Co	gen-201512x3110xkex311.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

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

For the transition period from ________ to ________

ILLINOIS POWER GENERATING COMPANY

(Exact name of registrant as specified in its charter)



Commission File Number	State of Incorporation	I.R.S. Employer Identification No.
333-56594	Delaware	37-1395586

601 Travis, Suite 1400
Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(713) 507-6400

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section12(b) of the Act: None.

Securities Registered Pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ý

No o

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 ¨ No x

As indicated above, the registrant is not required to file reports under the Securities Exchange Act of 1934. However, the registrant has filed all Exchange Act reports for the preceding 12 months.

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 (§232.405 of this chapter) 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. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer o		Accelerated filer o
Non-accelerated filer ý		Smaller reporting company o
(Do not check if a smaller reporting company)

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

As of June 30, 2015, all 2,000 shares of the registrant’s common stock were held by its parent, Illinois Power Resources, LLC, an indirect wholly-owned subsidiary of Dynegy Inc.

As of March 18, 2016, there were 2,000 outstanding shares of common stock, without par value, of the registrant, all of which were held by its parent, Illinois Power Resources, LLC, an indirect wholly-owned subsidiary of Dynegy Inc.

OMISSION OF CERTAIN INFORMATION

The registrant meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.

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TABLE OF CONTENTS



		Page

PART I
Definitions		1
Item 1.	Business	2
Item 1A.	Risk Factors	12
Item 1B.	Unresolved Staff Comments	17
Item 2.	Properties	17
Item 3.	Legal Proceedings	17
Item 4.	Mine Safety Disclosures	17

PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	18
Item 6.	Selected Financial Data	18
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	31
Item 8.	Consolidated Financial Statements and Supplementary Data	32
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	32
Item 9A.	Controls and Procedures	32
Item 9B.	Other Information	33

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	34
Item 11.	Executive Compensation	34
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	34
Item 13.	Certain Relationships and Related Transactions, and Director Independence	34
Item 14.	Principal Accountant Fees and Services	34

PART IV
Item 15.	Exhibits	35
SIGNATURES		38

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PART I

Definitions

Unless the context indicates otherwise, throughout this report, the terms “Genco,” “the Company,” “we,” “us,” “our,” and “ours” are used to refer to Illinois Power Generating Company and its direct and indirect subsidiaries. When appropriate, subsidiaries of Genco are named specifically as we discuss their various business activities. Further, as used in this Form 10-K, the abbreviations contained herein have the meanings set forth below.



AER Acquisition		December 2, 2013 acquisition of New AER and its subsidiaries by IPH, including EEI and Genco
CT		Combustion turbine electric facility used primarily for peaking capacity
DOE		Department of Energy
EGU		Electric Generating Units
ELG		Effluent Limitation Guidelines
EPA		Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
HAPs		Hazardous Air Pollutants, as defined by the Clean Air Act
IPCB		Illinois Pollution Control Board
IPH		IPH, LLC (formerly known as Illinois Power Holdings, LLC)
IRC		Internal Revenue Code
ISO		Independent System Operator
LMP		Locational Marginal Pricing
MATS		Mercury and Air Toxics Standards
MISO		Midcontinent Independent System Operator, Inc.
Moody’s		Moody’s Investors Service, Inc.
MW		Megawatts
MWh		Megawatt Hour
NERC		North American Electric Reliability Corporation
NM		Not meaningful
PJM		PJM Interconnection, LLC
PRIDE		Producing Results through Innovation by Dynegy Employees
PSA		Power Supply Agreement or Power Sales Agreement
RCRA		Resource Conservation and Recovery Act of 1976
RPM		Reliability Pricing Model
RTO		Regional Transmission Organization
S&P		Standard & Poor’s Ratings Services
SEC		Securities and Exchange Commission

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Item 1. Business

THE COMPANY

We are an electric generation subsidiary of Illinois Power Resources, LLC (“IPR”), which is an indirect wholly-owned subsidiary of Dynegy Inc. (“Dynegy”). We are headquartered in Houston, Texas and were incorporated in Illinois in March 2000. We own and operate a merchant generation business in Illinois. We have an 80 percent ownership interest in Electric Energy, Inc. (“EEI”), which we consolidate for financial reporting purposes. EEI operates merchant electric generation facilities in Illinois and FERC-regulated transmission facilities in Illinois and Kentucky. We also consolidate our wholly-owned subsidiary, Coffeen and Western Railroad Company, for financial reporting purposes.

Our revenues are determined by market conditions and contractual arrangements. As discussed below, we sell all of our power and capacity to Illinois Power Marketing Company (“IPM”) through PSAs. IPM attempts to optimize the value of our available generation capacity and energy and to mitigate risks through wholesale and bilateral sales of capacity and energy, retail sales in the non-rate-regulated Illinois market, participation in structured capacity market auctions in MISO and PJM and financial hedging transactions, including options and other derivatives. Please read Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7 and Note 11—Related Party Transactions for further discussion.

Genco has a PSA with IPM, a subsidiary of IPR, whereby IPM purchases all of the capacity and energy available from Genco’s generation fleet. IPM entered into a similar PSA with Illinois Power Resources Generating, LLC (“IPRG”). Under the PSAs, IPM revenues are allocated between Genco and IPRG based on reimbursable expenses and generation of each entity. The reimbursable expenses used in the calculation of revenues allocated under the Genco and IPRG PSAs include operation costs in addition to depreciation and interest on debt. Each PSA will continue through December 31, 2022, and from year to year thereafter. Either party to the respective PSA may elect to terminate the PSA by providing the other party with no less than six months advance written notice.

EEI has a PSA with IPM, whereby IPM purchases all of the capacity and energy available from EEI’s generation fleet. With limited exceptions, the price that IPM pays for capacity is the MISO Local Resources Zone 4 clearing price. IPM pays spot market prices for the associated energy. In addition, EEI will at times purchase energy from IPM to fulfill obligations to a non-affiliated party. The PSA will continue through December 31, 2022. Either party to the PSA may elect to terminate the PSA by providing the other party with no less than six months advance written notice. Please read Note 11—Related Party Transactions for further discussion on the power supply agreements.

We are organized into a ring-fenced group in order to maintain corporate separateness from Dynegy and its other legal entities, which include IPRG and IPM. We have an independent director whose consent is required for certain corporate actions, including material transactions with affiliates. We maintain separate books, records and bank accounts and separately appoint officers. Furthermore, we pay liabilities from our own funds, conduct business in our own name and have restrictions on pledging our assets for the benefit of certain other persons.

We file annual, quarterly and current reports, and other information with the SEC. You may read and copy any document we file at the SEC’s Public Reference Room at 100 F Street N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the SEC’s Public Reference Room. Our SEC filings are also available to the public at the SEC’s website at www.sec.gov. No information from such website is incorporated by reference herein. Our SEC filings are also available free of charge on Dynegy’s website at www.dynegy.com, as soon as reasonably practicable after those reports are filed with or furnished to the SEC. The contents of Dynegy’s website are not intended to be, and should not be considered to be, incorporated by reference into this Form 10-K.

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Our Power Generation Portfolio

Our generating facilities are as follows:



Facility	Total Net Generating Capacity (MW)(1)	Primary Fuel Type	Dispatch Type	Location	Region
Coffeen	915	Coal	Baseload	Coffeen, IL	MISO
Joppa/EEI (2)	802	Coal	Baseload	Joppa, IL	MISO
Joppa CT Units 1-3	165	Gas	Peaking	Joppa, IL	MISO
Joppa CT Units 4-5 (2)	56	Gas	Peaking	Joppa, IL	MISO
Newton	1,230	Coal	Baseload	Newton, IL	MISO
Total Fleet Capacity (3)	3,168

__________________________________________


(1)	Unit capabilities are based on winter capacity and are reflected at our net ownership interest. We have not included units that have been retired or are out of operation.


(2)	Co-owned with other generation companies.


(3)	We have transmission rights into PJM for certain of our plants and, therefore, also offer power and capacity into PJM.

Business Strategies

Our business strategy is to create value through the optimization of our generation facilities, cost structure and financial resources.

Customer Focus. Our commercial outreach, executed by IPM through our PSAs, focuses on the needs of the customers and constituents we serve, including the end-use and wholesale customer, our market channel partners and the government agencies and regulatory bodies that represent the public interest. The insight provided through these relationships will influence our decisions aimed at meeting customer needs while optimizing the value of our business.

We operate in a complex and highly-regulated environment with multiple federal, state and local stakeholders, such as legislators, government agencies, industry groups, consumers and environmental advocates. We work with these stakeholders to encourage reasonable regulations, constructive market designs and balanced environmental policies. Our regulatory strategy includes a continuous process of advocacy, visibility, education and engagement. The ultimate goal is to find solutions that provide a reasonable return on investment, while providing safe, reliable, cost-effective and environmentally-compliant generation for the communities we serve.

Continuous Improvement. We are committed to operating all of our facilities in a safe, reliable, cost-efficient and environmentally compliant manner and will continue to invest to maintain and improve the safety, reliability and efficiency of the fleet.

Capital Allocation. The power industry is a capital intensive, cyclical commodity business with significant commodity price volatility. Our ongoing capital allocation priorities, first and foremost, are to make the necessary capital investments to maintain the safety and reliability of our fleet and to comply with environmental rules and regulations.

Recent Developments

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MARKET DISCUSSION

Our fleet is comprised of three operating coal-fired power generation facilities located in Illinois with a total generating capacity of 3,168 MW. EEI operates its own balancing authority area and its own transmission facilities in southern Illinois and northern Kentucky. The EEI transmission system is directly connected to the transmission systems of MISO, the Tennessee Valley Authority (“TVA”) and Louisville Gas and Electric Company (“LGE”). Joppa, which is within the EEI control area, has the ability to sell power and capacity into MISO, TVA and LGE. Newton and Coffeen operate in MISO. We offer a portion of our generating capacity into the PJM market. Beginning on June 1, 2016, our Coffeen and Newton facilities will have 458 MW, or 15 percent of our capacity, that will be electrically tied and become baseload generation for PJM through pseudo-tie arrangements. We continue to expect that, over the longer-term, power and capacity pricing will improve as natural gas prices increase, marginal generating units retire, and more stringent environmental regulations force the retirement of power generation units that have not invested in environmental upgrades.

NERC Regions, RTOs and ISOs

Genco and EEI are members of SERC Reliability Corporation (“SERC”). SERC is responsible for the bulk electric power supply system in all or portions of Missouri, Illinois, Arkansas, Kentucky, Tennessee, North Carolina, South Carolina, Georgia, Mississippi, Alabama, Louisiana, Virginia, Florida, Oklahoma, Iowa and Texas. As a result of the Energy Policy Act of 2005, owners and operators of the bulk electric power system are subject to mandatory reliability standards promulgated by NERC and its regional entities, such as SERC, which are enforced by FERC. Genco and EEI must comply with these standards, which are in place to ensure the reliability of the bulk electric power system.

In discussing our business, we often refer to NERC regions. The NERC and its regional reliability entities were formed to ensure the reliability and security of the electricity system. The regional reliability entities set standards for reliable operation and maintenance of power generation facilities and transmission systems. For example, each NERC region establishes a minimum operating reserve requirement to ensure there is sufficient generating capacity to meet expected demand within its region. Each NERC region reports seasonally and annually on the status of generation and transmission in such region.

Separately, RTOs and ISOs administer the transmission infrastructure and markets across a regional footprint in most of the markets in which we operate. They are responsible for dispatching all generation facilities in their respective footprints and are responsible for both maximum utilization and reliable and efficient operation of the transmission system. RTOs and ISOs administer energy and ancillary service markets in the short term, usually day-ahead and real-time markets. Several RTOs and ISOs also ensure long-term planning reserves through monthly, semi-annual, annual and multi-year capacity markets. MISO and PJM, which oversee most of the wholesale power markets in which we operate, currently impose, and will likely continue to impose, both bid and price limits. They may also enforce caps and other mechanisms to guard against the exercise of market dominance in these markets. NERC regions and RTOs/ISOs often have different geographic footprints, and while there may be geographic overlap between NERC regions and RTOs/ISOs, their respective roles and responsibilities do not generally overlap.

In RTO and ISO regions with centrally dispatched market structures, all generators selling into the centralized market receive the same price for energy sold based on the bid price associated with the production of the last MWh that is needed to balance supply with demand within a designated zone or at a given location. Different zones or locations within the same RTO/ISO may produce different prices respective to other zones within the same RTO/ISO due to transmission losses and congestion. For example, a less efficient and/or less economical natural gas-fired unit may be needed in some hours to meet demand. If this unit’s production is required to meet demand on the margin, its bid price will set the market clearing price that will be paid for all dispatched generation in the same zone or location (although the price paid at other zones or locations may vary because of transmission losses and congestion), regardless of the price that any other unit may have offered into the market. In RTO and ISO regions with centrally dispatched market structures and location-based marginal price clearing structures (such as PJM and MISO), generators will receive the location-based marginal price for their output. The location-based marginal price, absent congestion, would be the marginal price of the most expensive unit needed to meet demand. In regions that are outside the footprint of RTOs/ISOs, prices are determined on a bilateral basis between buyers and sellers.

MISO. The MISO market includes all or parts of Iowa, Minnesota, North Dakota, Wisconsin, Michigan, Kentucky, Indiana, Illinois, Missouri, Arkansas, Mississippi, Texas, Louisiana, Montana, South Dakota and Manitoba, Canada.

The MISO energy market is designed to ensure that all market participants have open-access to the transmission system on a non-discriminatory basis. MISO, as an independent RTO, maintains functional control over the use of the transmission system to ensure transmission circuits do not exceed their secure operating limits and become overloaded. MISO operates day-ahead and real-time energy markets using a LMP system which calculates a price for every generator and load point within MISO. This market is transparent, allowing generators and load serving entities to see real-time price effects of transmission constraints and the impacts of congestion at each pricing point. An independent market monitor is responsible for evaluating the performance of

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the markets and identifying conduct by market participants or MISO that may compromise the efficiency or distort the outcome of the markets.

MISO’s tariff provisions provide for a full planning year capacity product (June 1 - May 31) and recognize zonal deliverability capacity requirements. We anticipate that the potential retirement of marginal MISO coal capacity due to poor economics or expected environmental mandates and confirmed future capacity exports from MISO to PJM will affect MISO capacity and energy pricing for future planning years.

We participate in MISO’s annual and monthly FTR auctions to manage the cost of our transmission congestion, as measured by the congestion of the LMP price differential between two points on the transmission grid across the market area.

In May 2015, three complaints were filed at FERC regarding the Zone 4 results for the 2015-2016 Planning Resource Auction (“PRA”) conducted by MISO. The Newton, Coffeen and Joppa facilities were offered into Zone 4 in the 2015-2016 PRA. The complainants, Public Citizen, Inc., the Illinois Attorney General, and Southwestern Electric Cooperative, Inc., have challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds and requested changes to the MISO PRA structure going forward. Complainants have also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the 2015-2016 PRA. The Independent Market Monitor for MISO (“MISO IMM”), which was responsible for monitoring the MISO 2015-2016 PRA, determined that all offers were competitive and that no physical or economic withholding occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the proposed remedies. Dynegy complied fully with the terms of the MISO Tariff in connection with the 2015-2016 PRA. In addition, the Illinois Industrial Energy Consumers filed a complaint at FERC against MISO on June 30, 2015 requesting prospective changes to the MISO tariff.

On October 1, 2015, FERC issued an order of non-public, formal investigation, stating that shortly after the conclusion of the 2015-2016 PRA, FERC’s Office of Enforcement began a non-public informal investigation into whether market manipulation or other potential violations of FERC orders, rules and regulations occurred before or during the PRA. The Order noted that the investigation is ongoing, and that the order converting the informal, non-public investigation to a formal, non-public investigation does not indicate that FERC has determined that any entity has engaged in market manipulation or otherwise violated any FERC order, rule, or regulation. Further, FERC held a Staff-led technical conference on October 20, 2015 to obtain further information concerning potential changes to the MISO PRA structure going forward, including proposals made by complainants. The technical conference did not address the ongoing Office of Enforcement investigation.

On December 31, 2015, FERC issued an order on the complaints requiring a number of prospective changes to the MISO Tariff provisions associated with calculating Initial Reference Levels and Local Clearing Requirements, effective as of the 2016-2017 PRA. Under the order, FERC found that the existing tariff provision which bases Initial Reference Levels for capacity supply offers on the estimated opportunity cost of exporting capacity to a neighboring region (for example, PJM) are no longer just and reasonable. Accordingly, FERC required MISO to set the Initial Reference Level for the capacity at $0 per MW-day for the 2016-2017 PRA. Capacity suppliers may also request a facility-specific reference level from the MISO IMM. The order did not address the other arguments of the complainants regarding the 2015-2016 Auction, and stated that those issues remain under consideration and will be addressed in a future order.

PJM. The PJM market includes all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.

PJM administers markets for wholesale electricity and provides transmission planning for the region, utilizing a similar LMP system as described in MISO above. PJM operates day-ahead and real-time markets into which generators can bid to provide energy and ancillary services. PJM also administers a forward capacity auction, the RPM, which establishes long-term markets for capacity. We have participated in RPM base residual auctions for years up to and including PJM’s Planning Year 2018-2019, which ends May 31, 2019. We also enter into bilateral capacity transactions. Beginning with Planning year 2016-2017, PJM has started to transition to Capacity Performance rules. Full transition of the capacity market to these new rules will occur by Planning Year 2020-2021. These rules are designed to improve system reliability and include penalties for underperforming units and rewards for overperforming units during shortage events. An independent market monitor continually monitors PJM markets to ensure a robust, competitive market and to identify any improper behavior by any entity.

PJM, like MISO, dispatches power plants to meet system energy and reliability needs, and settles physical power deliveries at LMPs. This value is determined by an ISO-administered auction process. The ISO-administered LMP energy markets consist of two separate and characteristically distinct settlement time frames, both of which are financially settled. The first is a day-ahead market and the second is a real-time dispatch and balancing market. Prices paid in these LMP energy markets, however, are affected by, among other things, (i) market mitigation measures, which can result in lower prices associated with certain generating units that are mitigated by shifting to a cost curve because they are deemed to have the potential to exercise locational market power, and (ii) the existing $1,000/MWh energy market price cap that is in place.

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Reserve Margins

RTOs and ISOs are required to meet NERC planning and resource adequacy standards. The reserve margin, which is the amount of generation resources in excess of peak load, is a measure of resource adequacy and is also used to assess the supply-demand balance of a region. RTOs and ISOs use various mechanisms to help market participants meet their planning reserve margin requirements. Mechanisms range from centralized capacity markets administered by the ISO to unstructured markets where entities fulfill their requirements through a combination of long and short-term bilateral contracts between individual counterparties and self-generation.

MISO. MISO has a Planning Reserve Margin of 15.2 percent and has forecasted reserve margins of 16.1 percent for Planning Year 2016-2017. MISO has forecasted reserve margins of 16.6 percent for Planning Year 2017-2018, 16.0 percent for Planning Year 2018-2019, 15.2 percent for Planning Year 2019-2020, and 14.7 percent for Planning Year 2020-2021.

PJM. The Planning Reserve Margin is reviewed by PJM on an annual basis and is 15.6 percent for Planning Year 2016-2017. PJM has forecasted reserve margins based on deliverable capacity of 20.2 percent for Planning Year 2015-2016, 21.1 percent for Planning Year 2016-2017, 19.7 percent for Planning Year 2017-2018 and 19.8 percent for Planning Year 2018-2019.

Contracted Capacity and Energy

MISO. We commercialize our assets through a combination of physical participation in the MISO markets (as described above), bilateral physical and financial power sales and fuel and capacity contracts. Capacity revenues consist of revenues billed to a third party at either the market or a negotiated contract price or through MISO from the PRA for making installed generation capacity available in order to satisfy system integrity and reliability requirements.

PJM. We commercialize a portion of our assets into the PJM markets (as described above) through bilateral physical and financial power sales and fuel and capacity contracts. Capacity revenues occur mainly through participation in the structured forward capacity market auctions.

Other

Market-Based Rates. Our ability to charge market-based rates for wholesale sales of electricity, as opposed to cost-based rates, is governed by FERC. Genco and EEI have been granted market-based rate authority for wholesale power sales.

Every three years, FERC conducts a review of our market-based rates and potential market power on a regional basis (known as the triennial market power review). In December 2015, we filed a market power update with FERC for our assets.

ENVIRONMENTAL MATTERS

Our business is subject to extensive federal, state and local laws and regulations concerning environmental matters, including the discharge of materials into the environment. We are committed to operating within these laws and regulations and to conducting our business in an environmentally responsible manner. The environmental, legal and regulatory landscape continues to change and has become more stringent over time. This may create unprofitable or unfavorable operating conditions or require significant capital and operating expenditures. Further, changing interpretations of existing regulations may subject historical maintenance, repair and replacement activities at our facilities to claims of noncompliance.

The following is a summary of (i) the material federal, state and local environmental laws and regulations applicable to us and (ii) certain pending judicial and administrative proceedings related thereto. Compliance with these environmental laws and regulations and resolution of these various proceedings may result in increased capital expenditures and other environmental compliance costs, impairments, increased operations and maintenance expenses, increased Asset Retirement Obligations (“AROs”), and the imposition of fines and penalties, any of which could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, if we are required to incur significant additional costs or expenses to comply with applicable environmental laws or to resolve a related proceeding, the incurrence of such costs or expenses may render continued operation of a plant uneconomical such that we may determine, subject to applicable laws and any applicable financing or other agreements, to reduce the plant’s operations to minimize such costs or expenses or cease to operate the plant completely to avoid such costs or expenses. Unless otherwise expressly noted in the following summary, we are not currently able to reasonably estimate the costs and expenses, or range of the costs and expenses, associated with complying with these environmental laws and regulations or with resolution of these judicial and administrative proceedings. For additional information regarding our pending environmental judicial and administrative proceedings, please read Note 13—Commitments and Contingencies for further discussion.

Our aggregate expenditures (both capitalized and those included in operating expense) for compliance with laws and regulations related to the protection of the environment were approximately $56 million in 2015 compared to approximately $23 million in 2014. We estimate that our total expenditures for environmental compliance in 2016 will be approximately $47 million,

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with approximately $28 million in capital expenditures and $19 million in operating expenses. Our capital budget is subject to revision as opportunities arise or circumstances change.

The Clean Air Act

The Clean Air Act (“CAA”) and comparable state laws and regulations relating to air emissions impose various responsibilities on owners and operators of sources of air emissions, which include requirements to obtain construction and operating permits, pay permit fees, monitor emissions, submit reports and compliance certifications, and keep records. The CAA requires that fossil-fueled electric generating plants meet certain pollutant emission standards and have sufficient emission allowances to cover sulfur dioxide (“SO₂”) emissions and in some regions nitrogen oxide (“NO_x”) emissions.

In order to ensure continued compliance with the CAA and related rules and regulations, we utilize various emission reduction technologies. These technologies include flue gas desulfurization (“FGD”) systems and activated carbon injection or mercury oxidation systems on select units and electrostatic precipitators, selective catalytic reduction (“SCR”) systems, low-NO_x burners and/or overfire air systems on all units. Additionally, our facilities mainly use low sulfur coal which, prior to combustion, goes through a refined coal process to further reduce NO_x and mercury emissions.

Cross-State Air Pollution Rule. The Cross-State Air Pollution Rule (“CSAPR”) to reduce emissions of SO₂ and NO_x from EGUs across the eastern U.S. took effect in 2015. The CSAPR imposes cap-and-trade programs within each affected state that limit emissions of SO₂ and NO_x at levels to help downwind states attain and maintain compliance with the 1997 ozone National Ambient Air Quality Standards (“NAAQS”) and the 1997 and 2006 fine particulate matter (“PM2.5”) NAAQS.

Under the CSAPR, our generating facilities are subject to cap-and-trade programs for ozone-season emissions of NO_x from May 1 through September 30 and for annual emissions of SO₂and NO_x. The CSAPR requirements applicable to SO₂ emissions from our affected EGUs will be implemented in two stages with fewer SO₂ emission allowances allocated in the second phase which will begin in 2017.

In July 2015, the U.S. Court of Appeals for the District of Columbia Circuit remanded to the EPA for reconsideration certain CSAPR emissions budgets for select states. The court rejected all other challenges to the CSAPR. In November 2015, the EPA issued a proposed CSAPR update rule to address the court’s remand decision regarding the CSAPR ozone-season NO_x emissions budgets and to reduce those budgets beginning in 2017 to attain and maintain compliance with the 2008 ozone NAAQS. Reduced ozone-season NO_x allowance allocations generally will require affected facilities to reduce NO_x emissions or acquire additional allowances. While the cost of our compliance with the proposed CSAPR update rule is uncertain at this time, the rule is anticipated to increase the compliance costs of our facilities.

Based on our current projections of emissions for 2016, we anticipate that our facilities will have an adequate number of SO₂ allowances, but will need to acquire a limited number of NO_x (ozone season and annual) allowances.

Mercury/HAPs. The EPA’s MATS rule for EGUs, which was issued in 2011, established numeric emission limits for mercury, non-mercury metals and acid gases as well as work practice standards for organic HAPs. Compliance with the MATS rule was required by April 16, 2015, unless an extension was granted in accordance with the CAA.

In June 2015, the U.S. Supreme Court found that the EPA failed to properly consider costs when it promulgated the MATS rule. The U.S. Court of Appeals for the District of Columbia Circuit then remanded the MATS rule to the EPA without vacating the rule. In December 2015, the EPA issued a proposed supplemental finding that the consideration of cost does not alter the Agency’s conclusion that it is appropriate and necessary to regulate coal- and oil-fired EGUs under CAA section 112. The EPA anticipates making a final finding regarding costs under the MATS rule by April 2016. We believe the EPA’s reconsideration of the MATS rule costs will have little or no bearing on the power markets, given that the majority of EGU retirement and investment decisions related to the MATS rule have already been made or are in process. Furthermore, EGUs are or will be subject to a number of other environmental regulations that also affect retirement and investment decisions, such as the Coal Combustion Residuals (“CCR”) rule, the CSAPR, the ELG rule and the Clean Power Plan.

We are in compliance with the MATS rule emission limits and continue to monitor the performance of our units and evaluate approaches to optimize compliance strategies.

The EPA revised the MATS rule in November 2014 to require use of extensive startup and shutdown monitoring instrumentation. Because installation of such instrumentation by April 2015 was not possible, we filed MATS extension requests regarding the startup and shutdown instrumentation requirements for each of our facilities. However, in January 2015, the EPA proposed to correct its November 2014 MATS rule revisions in a manner that, if adopted, would eliminate the need for our startup and shutdown instrumentation extension requests.

Illinois MPS. In 2007, our facilities elected to demonstrate compliance with the Illinois Multi-Pollutant Standards

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(“MPS”), which require compliance with NO_x, SO₂ and mercury emissions limits. We are in compliance with the MPS.

IPH Variance. The MPS SO₂ limits started in 2010 for our facilities and would have declined in 2014 and 2015 and required compliance with the final SO₂ limit beginning in 2017. However, the IPCB has granted IPH a variance which provides additional time for economic recovery and related power price improvements necessary to support the installation of FGD systems at the Newton facility such that the IPH coal-fired fleet can meet the MPS system-wide SO₂ limit. The IPCB approved the proposed plan to restrict the SO₂ emissions through 2014 to levels lower than those required by the MPS to offset any environmental impact from the variance. The IPCB’s order also included a schedule of milestones for completion of various aspects of the installation of the Newton FGD systems. The first milestone relating to the engineering design was completed by July 2015, while the last milestone relates to major equipment components being placed into final position on or before September 1, 2019. The variance also requires additional environmental protections in the form of enforceable commitments to cap IPH’s SO₂ emissions through December 31, 2020, retire IPRG’s Edwards Unit 1 as soon as permitted by the MISO, and, during the variance period, use only low sulfur coal at our Newton and Joppa facilities and IPRG’s Edward’s facility, and maintain operation of the existing FGD systems at our Coffeen facility and IPRG’s Duck Creek facility to achieve a 98 percent annual average SO₂ removal rate. In December 2015, the EPA approved the variance as part of the Illinois regional haze state implementation plan (“SIP”). In February 2016, we issued a notice to the third party contractor constructing the FGD systems directing them to temporarily suspend a portion of the work being performed. We will assess the results of the MISO Planning Year 2016-2017 capacity auction to be held in April 2016, at which time we will reevaluate our suspension notice to the third party contractor constructing the FGD systems.

Other Air Emission Initiatives

NAAQS. The CAA requires the EPA to regulate emissions of pollutants considered harmful to public health and the environment. The EPA has established NAAQS for six such pollutants, including ozone, SO₂ and PM2.5. Each state is responsible for developing a plan (a SIP) that will attain and maintain the NAAQS. These plans may result in the imposition of emission limits on our facilities.

The EPA will complete area designations for the 2010 one-hour SO₂ NAAQS in up to three additional rounds over the period July 2016 to December 31, 2020. The round of area designations due by July 2016 includes areas involving our Newton and Joppa facilities. In February 2016, the EPA provided notice of its intent to designate those areas as attainment.

The EPA issued a final rule in October 2015 lowering the ozone NAAQS from 75 to 70 parts per billion. The EPA anticipates designating attainment and nonattainment areas for the 2015 ozone NAAQS by October 2017. Various parties have filed lawsuits challenging the 2015 ozone NAAQS.

In May 2015, the EPA issued a final rule that eliminates existing exemptions in the SIPs of many states, including Illinois, for emissions during periods of startup, shutdown or malfunction (“SSM”). Affected states are required to submit corrective SIP revisions by November 2016. Various parties have filed lawsuits challenging the EPA’s SSM SIP rule.

The nature and scope of potential future requirements concerning the 2010 one-hour SO₂ NAAQS, 2015 ozone NAAQS and SSM SIP rule cannot be predicted with confidence at this time. A future requirement for additional emission reductions at any of our facilities may result in significantly increased compliance costs and could have a material adverse effect on our financial condition, results of operations and cash flows.

New Source Review and Clean Air Matters

New Source Review. Since 1999, the EPA has been engaged in a nationwide enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the New Source Review and New Source Performance Standard provisions under the CAA when the plants implemented modifications. The EPA’s initiative focuses on whether projects performed at power plants triggered various permitting requirements, including the need to install pollution control equipment.

In 2012, the EPA issued a Notice of Violation (“NOV”) alleging that projects performed in 1997, 2006 and 2007 at the Newton facility violated Prevention of Significant Deterioration (“PSD”), Title V permitting and other requirements. The NOV remains unresolved. We believe our defenses to the allegations described in the NOV are meritorious. A decision by the U.S. Court of Appeals for the Seventh Circuit in 2013 held that similar claims older than five years were barred by the statute of limitations. This decision may provide an additional defense to the allegations in the Newton facility NOV.

The Clean Water Act

The Clean Water Act (“CWA”) and analogous state laws regulate water withdrawals and wastewater discharges at our power generation facilities. Our facilities are authorized to discharge pollutants to waters of the United States by National Pollutant Discharge Elimination System (“NPDES”) permits, which contain discharge limits and monitoring, recordkeeping and reporting requirements. NPDES permits are limited to five years in duration but can be renewed.

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Cooling Water Intake Structures. Cooling water intake structures at our facilities are regulated under CWA Section 316(b). This provision generally requires that the location, design, construction and capacity of cooling water intake structures reflect best technology available (“BTA”) for minimizing adverse environmental impacts. Historically, the Illinois EPA has developed and implemented BTA standards through NPDES permits on a case-by-case basis using best professional judgment.

In 2014, the EPA issued a final rule for cooling water intake structures at existing facilities. The rule establishes seven BTA alternatives for reducing impingement mortality, including modified traveling screens, closed-cycle cooling, a numeric impingement standard, or a site-specific determination. For entrainment, the Illinois EPA is required to establish a case-by-case standard considering several factors, including social costs and benefits. Compliance with the rule’s entrainment and impingement mortality standards is required as soon as practicable, but will vary by site depending on several different factors, including determinations made by the Illinois EPA and the timing of renewal of a facility’s NPDES permit. Various environmental groups and industry groups filed petitions for judicial review of the EPA’s final rule.

At this time, we estimate the cost of our compliance with the cooling water intake structure rule will be approximately $5 million, with the majority of spend in the 2020-2023 timeframe. Our estimate could change materially depending upon a variety of factors, including site-specific determinations made by the Illinois EPA in implementing the rule, the results of impingement and entrainment studies required by the rule, the results of site-specific engineering studies, and the outcome of litigation concerning the rule.

Effluent Limitation Guidelines. In September 2015, the EPA issued a final rule revising the ELG for steam electric power generation units. The ELG final rule establishes new or additional requirements for wastewater streams associated with steam electric power generation processes and byproducts. For EGUs greater than 50 MW, the final rule establishes a zero discharge standard for bottom ash transport water, fly ash transport water and flue gas mercury control wastewater. The rule also establishes effluent limits for FGD wastewaters. Various industry and environmental groups have filed petitions for judicial review of the ELG final rule.

We have evaluated the ELG final rule and the CCR rule in light of our current management of CCR, including beneficial reuse. At this time, we estimate the cost of our compliance with the ELG rule to be approximately $66 million to $81 million. The majority of ELG compliance expenditures are expected to occur in the 2016-2023 timeframe.

NPDES Permits. We are currently appealing certain requirements in the renewal NPDES permits at our Newton and Joppa facilities.

Coal Combustion Residuals

The combustion of coal to generate electric power creates large quantities of ash and byproducts that are managed at power generation facilities in dry form in landfills and in wet form in surface impoundments. Each of our coal-fired plants has at least one CCR surface impoundment. At present, CCR is regulated by the states as solid waste.

EPA CCR Rule. The CCR rule, which took effect in October 2015, establishes requirements for existing and new CCR landfills and surface impoundments as well as inactive CCR surface impoundments. The requirements include location restrictions, structural integrity criteria, groundwater monitoring, operating criteria, liner design criteria, closure and post-closure care, recordkeeping and notification. The rule allows existing CCR surface impoundments to continue to operate for the remainder of their operating life, but generally would require closure if groundwater monitoring demonstrates that the CCR surface impoundment is responsible for exceedances of groundwater quality protection standards or the CCR surface impoundment does not meet location restrictions or structural integrity criteria. The deadlines for beginning and completing closure vary depending on several factors.

The EPA’s CCR rule establishes minimum federal criteria that owners or operators of regulated CCR units must meet without the engagement of a state or federal regulatory authority. Affected facilities are required to notify the state of actions taken to comply with requirements of the rule and to maintain a publicly accessible internet site that will document the facility’s compliance with the rule’s requirements. The rule regulates CCR as a non-hazardous waste under RCRA subtitle D, but defers a final determination on whether regulation of CCR as a hazardous waste is necessary until additional information is available. Several businesses, industry groups and environmental organizations filed petitions for judicial review of the CCR rule.

At this time, we estimate the cost of our compliance will be approximately $62 million to $76 million with the majority of the expenditures in the 2016-2023 timeframe. This estimate is reflected in our AROs. Pursuant to the CCR rule, we filed a notice of intent with the Illinois EPA in November 2015 to close an inactive surface impoundment located at our Coffeen facility.

Illinois CCR Rule. In 2013, the Illinois EPA filed a proposed rulemaking with the IPCB that would establish processes governing monitoring, corrective action and closure of CCR surface impoundments at power generating facilities. In 2015, the IPCB stayed the rulemaking proceeding to allow consideration of the EPA CCR rule, including the impact of legal and legislative actions concerning that rule. The stay has been extended to June 2016.

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Groundwater. Groundwater monitoring results indicate that the CCR surface impoundments at each of our facilities potentially impact onsite groundwater. In 2012, the Illinois EPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities’ CCR surface impoundments. In April 2015, we submitted an assessment monitoring report to the Illinois EPA concerning previously reported groundwater quality standard exceedances at the Newton facility’s active CCR landfill. The report identifies the Newton facility’s inactive unlined landfill as the likely source of the exceedances and recommends various measures to minimize the effects of that source on the groundwater monitoring results of the active landfill.

If remediation measures concerning groundwater are necessary at any of our facilities, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations and cash flows. At this time we cannot reasonably estimate the costs, or range of costs, of remediation, if any, that ultimately may be required.

Climate Change

For the last several years, there has been a robust public debate about climate change and the potential for regulations requiring lower emissions of greenhouse gas (“GHG”), primarily carbon dioxide (“CO₂”) and methane. Power generating facilities are a major source of GHG emissions. In 2015, our facilities emitted approximately 15 million tons of Equivalent Carbon Dioxide (“CO_2e”). The amounts of CO_2e emitted from our facilities during any time period will depend upon their dispatch rates during the period. We believe that the focus of any federal program attempting to address climate change should include three critical, interrelated elements: (i) the environment, (ii) the economy and (iii) energy security.

Federal Regulation of GHGs. The EPA has issued several rules concerning GHGs as directly relevant to our facilities since the U.S. Supreme Court’s 2007 decision in Massachusetts v. EPA, which held that GHGs meet the definition of a pollutant under the CAA and that regulation of GHG emissions is authorized by the CAA. We have implemented processes and procedures to report our GHG emissions. In 2010, the EPA issued PSD and Title V Permitting Guidance for Greenhouse Gases, which focuses on steam turbine and boiler efficiency improvements as a reasonable best available control technology (“BACT”) requirement for coal-fired EGUs. The EPA’s Tailoring Rule and Timing Rule phased in GHG emissions annual applicability thresholds for the PSD permit program and the Title V operating permit program beginning in 2011. Application of the PSD program to GHG emissions will require implementation of BACT for new and modified major sources of GHG.

In 2014, the U.S. Supreme Court decided Utility Air Regulatory Group v. EPA, holding that the EPA may not impose PSD or Title V permitting requirements on facilities based solely on emissions of GHGs. The Court also invalidated the EPA’s Tailoring Rule but concluded that the EPA may impose BACT requirements on GHG emissions if a facility is subject to BACT for other pollutants. The Court also determined that the EPA may establish a de minimis threshold below which BACT would not be required for GHG emissions, but left it open to the EPA to justify the appropriate threshold.

Paris Agreement. In December 2015, over 190 countries, including the U.S., reached an agreement ( the “Paris Agreement”) that establishes a global framework to reduce GHG emissions. The Paris Agreement seeks to keep warming below two degrees Celsius with a goal to limit increases in temperature to 1.5 degrees Celsius. The Paris Agreement directs all countries to prepare and communicate non-binding, nationally determined climate targets every five years starting in 2020.

Clean Power Plan. In August 2015, the EPA issued the Clean Power Plan to reduce carbon emissions from existing EGUs. The EPA also separately issued final rules establishing carbon standards for new, modified and reconstructed EGUs, which include emission standards for new fossil fuel-fired utility boilers based on the performance of a new efficient coal unit implementing partial carbon capture and storage.

The EPA expects that by 2030 when the Clean Power Plan is fully implemented, CO₂ emissions from EGUs will be 32 percent below 2005 levels. States are required to develop plans to achieve interim CO₂ emission rates reductions phased in over the period 2022 to 2029 and the final CO₂ rate for their state by 2030. The state-specific CO₂ emission performance rates reflect the EPA’s determination that the best system of emission reduction is comprised of three building blocks: increasing the operational efficiency of existing coal-fired EGUs, shifting electricity generation to natural gas-fired EGUs, and increasing electricity generation from renewable sources. Emission trading programs are permitted. States must submit final plans by September 6, 2016, unless a state makes certain demonstrations justifying a two-year extension for submittal of a final plan by September 2018.

Numerous states, industry associations and labor groups filed lawsuits challenging the EPA’s Clean Power Plan. In February 2016, the U.S. Supreme Court stayed the rule pending completion of judicial review. Judicial challenges also have been filed against the EPA’s final rules establishing carbon standards for new, modified and reconstructed EGUs.

Illinois has started efforts aimed at developing a plan to implement the Clean Power Plan. We are monitoring and, as appropriate, participating in those efforts. We also continue to analyze the EPA’s final rules to reduce EGU CO₂ emissions, the potential impacts on our power generation facilities, and how the rules intersect with electricity market design.

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The nature and scope of CO₂ emission reduction requirements that ultimately may be imposed on our facilities as a result of the EPA’s EGU CO₂ reduction rules are uncertain at this time, but may result in significantly increased compliance costs and could have a material adverse effect on our financial condition, results of operations and cash flows.

Remedial Laws

We are subject to environmental requirements relating to handling and disposal of toxic and hazardous materials, including provisions of the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and RCRA and similar state laws. CERCLA imposes strict liability for contributions to contaminated sites resulting from the release of “hazardous substances” into the environment. CERCLA or RCRA could impose remedial obligations with respect to a variety of our facilities and operations.

A number of our facilities contain quantities of asbestos-containing materials, lead-based paint and/or other regulated materials. Existing state and federal rules require the proper management and disposal of these materials. We have developed a plan that includes proper maintenance of existing non-friable asbestos installations and removal and abatement of asbestos-containing materials where necessary because of maintenance, repairs, replacement or damage to the asbestos itself.

COMPETITION

Demand for power may be met by generation capacity based on several competing generation technologies, such as natural gas-fired, coal-fired or nuclear generation, as well as power generating facilities fueled by alternative energy sources, including hydro power, synthetic fuels, solar, wind, wood, geothermal, waste heat and solid waste sources. The power generation business is a regional business that is diverse in terms of industry structure. Our power generation business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, other energy service companies, including retail power companies, and financial institutions in the regions in which we operate. We believe that our ability to compete effectively in the power generation business will be driven in large part by our ability to achieve and maintain a low cost of production, primarily by managing fuel costs and the reliability of our generating facilities. Our ability to compete effectively will also be impacted by various governmental and regulatory activities designed to reduce GHG emissions and to promote lower emitting generation. For example, regulatory requirements for load-serving entities to acquire a percentage of their energy from renewable-fueled facilities will potentially reduce the demand for energy from coal-fired facilities such as those we own and operate. In addition, the recent extension of federal renewable energy tax credit programs is expected to further expand renewable energy development.

SIGNIFICANT CUSTOMERS

Our revenues are primarily derived from the sales of our generation and capacity to IPM as described in Note 11—Related Party Transactions. Approximately 100 percent, 100 percent and 87 percent of our consolidated revenues were derived from sales to IPM for the years ended December 31, 2015, 2014 and 2013, respectively. No other customer represents greater than 10 percent of our consolidated revenues.

EMPLOYEES

At December 31, 2015, we had approximately 387 employees. We recently reached an agreement on new collective bargaining agreements with the two unions representing our Coffeen, Newton and Joppa facilities. These agreements cover approximately 297 represented employees located in Illinois and expire between 2018 and 2020. During 2015, the Company did not experience a labor stoppage or a labor dispute at any of its facilities.

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Item 1A. Risk Factors

FORWARD-LOOKING STATEMENTS

This Form 10-K includes statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements.” All statements included or incorporated by reference in this annual report, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These statements represent our reasonable judgment of the future based on various factors and using numerous assumptions and are subject to known and unknown risks, uncertainties and other factors that could cause our actual results and financial position to differ materially from those contemplated by the statements. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate,” “estimate,” “project,” “forecast,” “plan,” “may,” “will,” “should,” “expect” and other words of similar meaning. In particular, these include, but are not limited to, statements relating to the following:


•	beliefs and assumptions about weather and general economic conditions;


•	beliefs, assumptions and projections regarding the demand for power, generation volumes and commodity pricing, including natural gas prices and the timing of a recovery in natural gas prices, if any;


•	beliefs and assumptions about market competition, generation capacity and regional supply and demand characteristics of the wholesale and retail power markets, including the anticipation of plant retirements and higher market pricing over the longer term;


•	sufficiency of, access to and costs associated with coal inventories and transportation thereof;


•	the effects of, or changes to, MISO or PJM power and capacity procurement processes;


•	beliefs associated with impairments of our long-lived assets;

•

expectations regarding, or impacts of, environmental matters, including costs of compliance, availability and adequacy of emission credits and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts and other laws and regulations that we are, or could become, subject to, which could increase our costs, result in an impairment of our assets, cause us to limit or terminate the operation of certain of our facilities, or otherwise have a negative financial effect;


•	projected operating or financial results, including anticipated cash flows from operations, revenues and profitability;


•	expectations regarding our compliance with the unsecured notes indenture and any applicable financial ratios and other payments;


•	beliefs about the outcome of legal, administrative, legislative and regulatory matters;


•	our focus on safety and our ability to efficiently operate our assets so as to capture revenue generating opportunities and operating margins;


•	our ability to mitigate forced outage risk, including managing risk associated with Capacity Performance (“CP”) in PJM;


•	our ability to optimize our assets through targeted investment in cost effective technology enhancements;


•	the effectiveness of our strategies to capture opportunities presented by changes in commodity prices and to manage our exposure to energy price volatility;


•	our access to necessary capital, including short-term credit and liquidity;


•	our assessment of our liquidity, including liquidity concerns which have resulted in limited access to third-party financing sources and our ability to meet future obligations;


•	the inability of our counterparties and affiliates to meet their obligations with respect to contracts, credit agreements, and financial instruments;


•	efforts to identify opportunities to reduce congestion and improve busbar power prices;


•	expectations regarding performance standards and capital and maintenance expenditures; and


•	the timing and anticipated benefits to be achieved through our company-wide improvement programs, including our PRIDE initiative.

Any or all of our forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks, uncertainties and other factors, many of which are beyond our control, including those set forth below.

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FACTORS THAT MAY AFFECT FUTURE RESULTS

Risks Related to the Operation of Our Business

Because we receive variable prices under our PSAs, we are subject to significant volatility, and in turn, our revenue and profitability are subject to wide fluctuations.

We receive variable prices under our PSAs. Consequently, there can be no assurance that we will be able to sell any or all of the electric energy, capacity or ancillary services from those facilities at commercially attractive rates or that our facilities will be able to operate profitably. We depend, in large part, upon prevailing market prices for power, capacity and fuel. Given the volatility of commodity prices, our revenues and profitability will be subject to volatility, and our financial condition, results of operations and cash flows could be materially adversely affected.

We may not have access to sufficient capital in the amounts and at the times needed.

Under the provisions of our indenture, we may not borrow additional funds from external, third-party sources if our interest coverage ratio is less than a specified minimum or if our leverage ratio is greater than a specified maximum. Throughout the year 2015, our interest coverage ratio was less than the specified minimum level required for external borrowings. As a result, our ability to borrow additional funds from external, third-party sources is restricted. The inability to raise debt or equity capital on favorable terms, or at all, could negatively affect our ability to maintain our current business operations, our ability to make principal payments on existing debt as it becomes due, as well as our ability to make any required capital investments. Any adverse change in our credit ratings may further reduce access to capital and may cause requests for additional collateral postings and prepayments.

Our costs of compliance with existing environmental requirements are significant, and costs of compliance with new environmental requirements or factors could materially adversely affect our financial condition, results of operations and cash flows.

Our business is subject to extensive and frequently changing environmental regulation by federal, state and local authorities. Such environmental regulation imposes, among other things, capital and operating expenditures, restrictions, liabilities and obligations in connection with the generation, handling, use, transportation, treatment, storage and disposal of certain substances and wastes, including CCR, and in connection with spills, releases and emissions of various substances (including carbon emissions) into the environment, as well as environmental impacts associated with cooling water intake structures. Existing environmental laws and regulations may be revised or reinterpreted, new laws and regulations may be adopted or may become applicable to us or our facilities, and litigation or enforcement proceedings could be commenced against us. Proposals being considered by federal and state authorities (including proposals regarding cooling water intake structures and carbon) could, if and when adopted or enacted, require us to make substantial capital and operating expenditures, impair assets, or limit or terminate operation of certain of our facilities. If any of these events occur, our financial condition, results of operations and cash flows could be materially adversely affected.

Many environmental laws require approvals or permits from governmental authorities before construction, modification or operation of a power generation facility may commence. Certain environmental permits must be renewed periodically in order for us to continue operating our facilities. The process of obtaining and renewing necessary permits can be lengthy and complex and can sometimes result in the establishment of permit conditions that make the project or activity for which the permit was sought unprofitable or otherwise unattractive. Even where permits are not required, compliance with environmental laws and regulations can require significant capital and operating expenditures. We are required to comply with numerous environmental laws and regulations, and to obtain numerous governmental permits when we modify and operate our facilities. If there is a delay in obtaining any required environmental regulatory approvals or permits, if we fail to obtain any required approval or permit, or if we are unable to comply with the terms of such approvals or permits, the operation of our facilities may be interrupted or become subject to additional costs and/or legal challenges. Further, changed interpretations of existing regulations may subject historical maintenance, repair and replacement activities at our facilities to claims of noncompliance. With the continuing trend toward stricter environmental standards and more extensive regulatory and permitting requirements, our capital and operating environmental expenditures are likely to be substantial and may significantly increase in the future. As a result, our financial condition, results of operations and cash flows could be materially adversely affected.

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Our business is subject to complex government regulation. Changes in these regulations or in their implementation may affect costs of operating our facilities or our ability to operate our facilities, or increase competition, any of which would negatively impact our results of operations.

We are subject to extensive federal, state and local laws and regulations governing the generation and sale of energy commodities in each of the jurisdictions in which we have operations. Compliance with these ever-changing laws and regulations requires expenses (including legal representation) and monitoring, capital and operating expenditures. Potential changes in laws and regulations that could have a material impact on our business include: the introduction, or reintroduction, of rate caps or pricing constraints; state regulatory initiatives; increased credit standards, collateral costs or margin requirements, as well as reduced market liquidity, as a result of potential market regulation; or a variation of these. Furthermore, these and other market-based rules and regulations are subject to change at any time, and we cannot predict what changes may occur in the future or how such changes might affect any facet of our business.

The costs and burdens associated with complying with the increased number of regulations may have a material adverse effect on us if we fail to comply with the laws and regulations governing our business or if we fail to maintain or obtain advantageous regulatory authorizations and exemptions. Failure to comply with such requirements could result in the shutdown of any non-compliant facility, the imposition of liens or fines, or civil or criminal liability. Moreover, increased competition within the sector resulting from potential legislative changes, regulatory changes or other factors may create greater risks to the stability of our power generation earnings and cash flows generally.

Regulators, politicians, non-governmental organizations and other private parties have expressed concern about greenhouse gas, or GHG, emissions and the potential risks associated with climate change and are taking actions which could materially adversely affect our financial condition, results of operations and cash flows.

For the last several years, there has been a robust public debate about climate change and the potential for regulations requiring lower emissions of GHG, primarily CO₂ and methane. As discussed in Item 1. Business-Environmental Matters, at the federal and state levels, rules are in effect and policies are under development to regulate GHG emissions, thereby effectively putting a cost on such emissions in order to create financial incentives to reduce them. Power generating facilities are a major source of GHG emissions. We cannot confidently predict the final outcome of the current debate on climate change nor can we predict with confidence the ultimate requirements of proposed or anticipated federal and state legislation and regulations intended to address climate change. These activities, and the highly politicized nature of climate change, suggest a trend toward increased regulation of GHG that could result in a material adverse effect on our financial condition, results of operations and cash flows. Existing and anticipated federal and state regulations intended to address climate change may significantly increase the cost of providing electric power, resulting in far-reaching and significant impacts on us and others in the power generation industry over time. It is possible that federal and state actions intended to address climate change could result in costs assigned to GHG emissions that we would not be able to fully recover through market pricing or otherwise. If capital and/or operating costs related to compliance with regulations intended to address climate change become great enough to render the operations of certain plants uneconomical, we could, at our option and subject to any applicable agreements or other obligations, reduce operations or cease to operate such plants and forego such capital and/or operating costs. Though we consider our largest risk related to climate change to be legislative and regulatory changes, we are subject to physical risks inherent in industrial operations including severe weather events such as hurricanes and tornadoes. To the extent that changes in climate effect changes in weather patterns (such as more severe weather events), we could be adversely affected.

Competition in wholesale power markets, together with the age of certain of our generation facilities, may have a material adverse effect on our financial condition, results of operations and cash flows.

Our power generation business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, other energy service companies and financial institutions in the sale of electric energy, capacity and ancillary services, as well as in the procurement of fuel, transmission and transportation services. Moreover, aggregate demand for power may be met by generation capacity based on several competing technologies, as well as power generating facilities fueled by alternative or renewable energy sources, including hydroelectric power, synthetic fuels, solar, wind, wood, geothermal, waste heat and solid waste sources. Regulatory initiatives designed to enhance and/or subsidize renewable generation increase competition from these types of facilities.

We also compete against other energy merchants on the basis of our relative operating characteristics, financial position and access to credit sources. Electric energy customers, wholesale energy suppliers and transporters often seek financial guarantees, credit support such as letters of credit and other assurances that their energy contracts will be satisfied. Companies with which we compete may have greater resources in these areas. In addition, certain of our current facilities are relatively old. Newer plants owned by competitors may be more efficient than some of our plants, which may put these plants at a competitive disadvantage. Over time, some of our plants may become unable to compete because of the construction of new plants, and such new plants could have a number of advantages including: more efficient equipment, newer technology that could result in fewer emissions,

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or more advantageous locations on the electric transmission system. Additionally, these competitors may be able to respond more quickly to new laws and regulations because of the newer technology utilized in their facilities or the additional resources derived from owning more efficient facilities. Taken as a whole, the potential disadvantages of our aging fleet could result in lower run-times or even early asset retirement.

Other factors may contribute to increased competition in wholesale power markets. New forms of capital and competitors have entered the industry, including financial investors who perceive that asset values are at levels below their true replacement value. As a result, a number of generation facilities in the United States are now owned by lenders and investment companies. Furthermore, mergers and asset reallocations in the industry could create powerful new competitors. Under any scenario, we anticipate that we will face competition from numerous companies in the industry.

We are exposed to the risk of fuel and fuel transportation cost increases and interruptions in fuel supplies.

Profitable operation of our coal-fired generation facilities is highly dependent on coal prices and coal transportation rates. We mitigate our price exposure to coal and related transportation by entering into short and long-term contracts. Transportation of coal can also be affected by rail equipment availability, extreme weather or natural disasters, each of which may slow or stop the delivery from the mine to the facility. In addition, certain of our coal suppliers have filed for bankruptcy protection, which could negatively impact our coal supply.

Further, any changes in the costs of PRB coal or transportation rates and changes in the relationship between such costs and the market prices of power will affect our financial results. If we are unable to procure fuel for physical delivery at prices we consider favorable, our financial condition, results of operations and cash flows could be materially adversely affected.

The concentration of our business in the MISO market increases the effects of any adverse conditions in MISO.

A substantial portion of our business is conducted in MISO. Natural disasters in Illinois and changes in economic conditions in MISO, including changing demographics, congestion, or oversupply of or reduced demand for power, could have a material adverse effect on our financial condition, results of operations and cash flows.

Generally, we do not own or control transmission facilities required to deliver wholesale power from our generation facilities. If transmission services are inadequate, our ability to sell and deliver wholesale power may be materially adversely affected. Furthermore, RTOs and ISOs administer the transmission infrastructure and market, which are subject to changes in structure and operation and impose various pricing limitations. These changes and pricing limitations may affect our ability to deliver power to the market that would, in turn, adversely affect the profitability of our generation facilities.

With the exception of EEI, which owns and controls transmission lines interconnecting the Joppa facility in EEI’s control area to MISO, TVA and LGE, we do not own or control the transmission facilities required to deliver the wholesale power from our generation facilities. If transmission services from these facilities is unavailable or disrupted, or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver wholesale power may be materially adversely affected, which could result in reduced profitability, or with respect to capacity performance in PJM, significant penalties. RTOs and ISOs provide transmission services, administer transparent and competitive power markets and maintain system reliability. Many of these RTOs and ISOs operate in the real-time and day-ahead markets in which we sell energy. The RTOs and ISOs that oversee most of the wholesale power markets impose price limitations, offer caps, capacity performance requirements, penalties and other mechanisms to guard against the potential exercise of market power in these markets. Price limitations and other regulatory mechanisms may adversely affect the profitability of our generation facilities that sell energy and capacity into the wholesale power markets. Problems or delays that may arise in the formation and operation of maturing RTOs and similar market structures, or changes in geographic scope, rules or market operations of existing RTOs, may also affect our ability to sell, the prices we receive or the cost to transmit power produced by our generating facilities. Market design as well as rules governing the various regional power markets may also change from time to time, which could materially adversely affect our financial condition, results of operations and cash flows.

Operation of power generation facilities involves significant risks customary to the power industry that could have a material adverse effect on our financial condition, results of operations and cash flows.

The ongoing operation of our facilities involves risks customary to the power industry that include the breakdown or failure of equipment or processes, operational and safety performance below expected levels and the inability to transport our product to customers in an efficient manner due to a lack of transmission capacity. Unplanned outages of generating units, including extensions of scheduled outages due to mechanical failures or other problems, occur from time to time and are an inherent risk of our business. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures, could result in reduced profitability, or with respect to capacity performance, penalties. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer MW or require us to incur significant costs as a result of running one of our higher cost units or obtaining replacement power from third parties in the

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open market to satisfy our forward power sales obligations. If we are unsuccessful in operating our facilities efficiently, such inefficiency could have a material adverse effect on our results of operations, financial condition and cash flows.

If our long-lived assets become impaired, we may be required to record a significant charge to earnings.

We have long-lived assets recorded on our balance sheet. In accordance with the Generally Accepted Accounting Principles of the United States of America (“GAAP”), we review our long-lived assets for impairment when events or changes in circumstances indicate the carrying value of the asset may not be recoverable. Factors that may be considered include a decline in future cash flows and slower growth rates in the energy industry.

We performed asset impairment tests of all of our facilities in 2015 which indicated that the carrying value of our Coffeen facility was not recoverable; therefore, we recorded an impairment charge of $855 million during the third quarter of 2015. Please read Note 3—Impairments for further details.

Our risk management policies cannot fully eliminate the risk associated with fuel procurement and pricing risk.

Our asset-based power position as well as our power marketing and fuel procurement expose us to risks of commodity price movements. We attempt to manage this exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. Even when our policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations may be diminished if the judgments and assumptions underlying those decisions prove to be incorrect. Factors, such as future prices and demand for power and other energy-related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, we cannot fully predict the impact that our risk management decisions may have on our business and/or financial condition, results of operations and cash flows.

Availability and cost of emission allowances could materially impact our costs of operations.

We are required to maintain, either through allocation or purchase, sufficient emission allowances to support our operations in the ordinary course of operating our power generation facilities. These allowances are used to meet our obligations imposed by various applicable environmental laws, and the trend toward more stringent regulations (including regulations regarding GHG emissions) will likely require us to obtain new or additional emission allowances. If our operational needs require more than our allocated quantity of emission allowances, we may be forced to purchase such allowances on the open market, which could be costly. If we are unable to maintain sufficient emission allowances to match our operational needs, we may have to curtail our operations so as not to exceed our available emission allowances, or install costly new emissions controls. As we use the emissions allowances that we have purchased on the open market, costs associated with such purchases will be recognized as an operating expense. If such allowances are available for purchase, but only at significantly higher prices, their purchase could materially increase our costs of operations in the affected markets and materially adversely affect our financial condition, results of operations and cash flows.

A decline in market liquidity and our ability to manage our counterparty credit risk could adversely affect us.

Our supplier counterparties may experience deteriorating credit. These conditions could cause counterparties in the coal, natural gas and power markets to withdraw from participation in those markets. If multiple parties withdraw from those markets, market liquidity may be threatened, which in turn could adversely impact our business. Additionally, these conditions may cause our counterparties to seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of the Bankruptcy Code. Our credit risk may be exacerbated to the extent collateral held by us cannot be realized or is liquidated at prices not sufficient to recover the full amount due to us. There can be no assurance that any such losses or impairments to the carrying value of our financial assets would not materially and adversely affect our financial condition, results of operations and cash flows.

Furthermore, we have obligations to other IPH companies and other IPH companies have obligations to us, as a result of transactions involving energy, coal, other commodities and services and as a result of hedging transactions. If one of these other IPH companies fails to perform under any of these arrangements, we might incur losses. Our financial condition, results of operations and cash flows could be adversely affected, resulting in our inability to meet our obligations, including to unrelated third parties.

Strikes, work stoppages or an inability to negotiate future collective bargaining agreements on commercially reasonable terms could have a material adverse effect on our financial condition, results of operations and cash flows.

A majority of the employees at our facilities are subject to collective bargaining agreements with various unions. If union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strike or disruption, we could experience reduced power generation or outages if replacement labor is not procured. The ability to procure such replacement

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labor is uncertain. Strikes, work stoppages or an inability to negotiate future collective bargaining agreements on commercially reasonable terms could have a material adverse effect on our financial condition, results of operations and cash flows.

Terrorist attacks and/or cyber-attacks may result in our inability to operate and fulfill our obligations, and could result in material repair costs.

As a power generator, we face heightened risk of terrorism, including cyber terrorism, either by a direct act against one or more of our generating facilities or an act against the transmission and distribution infrastructure that is used to transport our power. We rely on information technology networks and systems, including third party cloud systems, to operate our generating facilities, engage in asset management activities, and process, transmit and store electronic information. Security breaches of this information technology infrastructure, including cyber-attacks and cyber terrorism, could lead to system disruptions, generating facility shutdowns or unauthorized disclosure of confidential information related to our employees, vendors and counterparties.

Systemic damage to one or more of our generating facilities and/or to the transmission and distribution infrastructure could result in our inability to operate in one or all of the markets we serve for an extended period of time. If our generating facilities are shut down, we would be unable to respond to the ISOs and RTOs or fulfill our obligations under various energy and/or capacity arrangements, resulting in lost revenues and potential fines, penalties and other liabilities. Pervasive cyber-attacks across our industry could affect the ability of ISOs and RTOs to function in some regions. The cost to restore our generating facilities after such an occurrence could be material.

Item 1B. Unresolved Staff Comments

Not applicable.

Item 2. Properties

We have included descriptions of the location and general character of our principal physical operating properties in “Item 1. Business,” which is incorporated herein by reference.

With only a few exceptions, we have fee title to all principal facilities and other units of property material to the operation of our business, and to the real property on which such facilities are located (subject to certain permitted liens and judgment liens).

Item 3. Legal Proceedings

Please read Note 13—Commitments and Contingencies—Legal Proceedings for a description of our material legal proceedings, which is 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, Related Stockholder Matters and Issuer Purchases of Equity Securities

There is no established trading market for our common stock. As of March 18, 2016, all outstanding shares of the registrant were held by our parent, IPR, an indirect wholly-owned subsidiary of Dynegy Inc.

Item 6. Selected Financial Data



	Year Ended December 31,
(in millions)	2015			2014			2013			2012			2011
Statements of Operations Data:
Revenues	$	534		$	648		$	811		$	790		$	1,067
Depreciation and amortization expense	$	(86	)	$	(100	)	$	(80	)	$	(85	)	$	(96	)
Impairment	$	(855	)	$	—		$	(199	)	$	(70	)	$	(35	)
Operating income (loss)	$	(902	)	$	(57	)	$	(213	)	$	(17	)	$	139
Interest expense	$	(39	)	$	(40	)	$	(42	)	$	(52	)	$	(63	)
Income tax benefit (expense)	$	378		$	49		$	65		$	29		$	(32	)
Net income (loss)	$	(563	)	$	(48	)	$	(189	)	$	(40	)	$	45
Net income (loss) attributable to Illinois Power Generating Company	$	(562	)	$	(50	)	$	(188	)	$	(33	)	$	44
Cash Flow Data:
Net cash provided by (used in) operating activities	$	(7	)	$	(16	)	$	51		$	139		$	215
Net cash provided by (used in) investing activities	$	(58	)	$	(48	)	$	110		$	(122	)	$	(141	)
Net cash provided by (used in) financing activities	$	—		$	—		$	4		$	—		$	(72	)
Capital expenditures	$	(58	)	$	(48	)	$	(55	)	$	(175	)	$	(141	)

	December 31,
(in millions)	2015			2014			2013			2012			2011
Balance Sheet Data:
Current assets	$	263		$	326		$	363		$	619		$	325
Current liabilities	$	73		$	83		$	94		$	140		$	142
Property, plant and equipment, net	$	937		$	1,871		$	1,873		$	1,887		$	2,231
Total assets	$	1,230		$	2,221		$	2,264		$	2,532		$	2,572
Long-term debt	$	824		$	824		$	824		$	824		$	824
Total Illinois Power Generating Company stockholder’s equity	$	136		$	690		$	756		$	1,020		$	1,018

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read together with the consolidated financial statements and the notes thereto included in this report.

OVERVIEW

We own and operate a merchant generation business in Illinois. We have an 80 percent ownership interest in, and consolidate for financial reporting purposes, EEI. EEI operates merchant electric generation facilities in Illinois and FERC-regulated transmission facilities in Illinois and Kentucky.

On December 2, 2013, we were acquired by IPH, an indirect wholly owned subsidiary of Dynegy. In connection with the AER Acquisition, Ameren retained certain historical obligations of AER and its subsidiaries, including certain historical environmental and tax liabilities. We did not apply “push-down accounting” as a result of the AER Acquisition which would require the adjustment of assets and liabilities to fair value recognized by Dynegy to be shown in our consolidated financial statements. Our approximately $825 million in aggregate principal amount of long-term notes remain outstanding as an obligation of Genco. We are organized into a ring-fenced group in order to maintain corporate separateness from Dynegy and its other legal entities, which include IPRG and IPM. Further, IPH and its direct and indirect subsidiaries present themselves to the public as separate entities.

Genco has a PSA with IPM, whereby IPM purchases all of the capacity and energy available from Genco’s generation fleet. IPM entered into a similar PSA with IPRG, a related party. Under the PSAs, revenues allocated between Genco and IPRG are based on reimbursable expenses and generation of each entity. The reimbursable expenses used in the calculation of revenues allocated under the Genco and IPRG PSAs include operation costs in addition to depreciation and interest on debt.

EEI also has a PSA with IPM, whereby IPM purchases all of the capacity and energy available from EEI’s generation fleet. With limited exceptions, the price that IPM pays for capacity is the MISO Local Resource Zone 4 clearing price. IPM pays spot market prices for the associated energy. In addition, EEI will at times purchase energy from IPM to fulfill obligations to a nonaffiliated party.

Business Discussion

The following is a list of key factors that have affected, and are expected to continue to affect, our earnings and cash flows.


•	prices for power, coal and natural gas, which in turn are largely driven by supply and demand. Demand for power can vary due to weather and general economic conditions, among other things. Power supplies similarly vary by region and are impacted significantly by available generating capacity, transmission capacity and federal and state regulation;


•	the relationship between electricity prices and prices for coal and natural gas, commonly referred to as the “dark spread” and “spark spread,” respectively, which impacts the margin we earn on the electricity we generate;


•	our ability to control capital expenditures, which primarily include maintenance, safety, environmental and reliability projects, and to control operating expenses through disciplined management;


•	our ability to optimize our assets by maintaining a high in-market availability, reliable run-time and safe, low-cost operations;


•	our ability to optimize our assets through targeted investment in cost effective technology enhancements or efficiency and reliability improvements;


•	our ability to operate and deliver energy from our facilities during periods of planned/unplanned electric transmission outages;


•	our ability to post the collateral necessary to execute our commercial strategy;


•	the cost of compliance with existing and future environmental requirements that are likely to be more stringent and more comprehensive. Please read Item 1. Business—Environmental Matters for further discussion;


•	our ability to maintain sufficient coal inventories, which is dependent upon the continued performance of the mines and railroads for deliveries of coal in a consistent and timely manner, and its impact on our ability to serve the critical winter and summer on-peak loads;


•	market supply conditions resulting from federal and regional renewable power mandates and initiatives;


•	costs of transportation related to coal deliveries;


•	changes in MISO and PJM market design or associated rules, including the resulting effect on future capacity revenues from changes in the existing bilateral MISO capacity markets;


•	the potential for more competition in generation, supply and distribution, including new technologies; and

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•	the availability of qualified labor and material, and rising costs.

Please read “Item 1A. Risk Factors” for additional factors that could affect our future operating results, financial condition and cash flows.

LIQUIDITY AND CAPITAL RESOURCES

Overview

In this section, we describe our liquidity and capital requirements including our sources and uses of liquidity and capital resources. Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements, contractual obligations, capital expenditures (including required environmental expenditures) and working capital needs. Examples of working capital needs include purchases and sales of commodities and associated margin and collateral requirements, facility maintenance costs and other costs such as payroll. Our primary sources of liquidity are cash flows from operations and cash on hand. Please refer to Outlook for further discussion on the MISO capacity auction results.

We are organized into a ring-fenced group in order to maintain corporate separateness from Dynegy and its other legal entities. We have an independent director, whose consent is required for certain corporate actions, including material transactions with affiliates. We maintain separate books, records and bank accounts and separately appoint officers. Furthermore, we pay liabilities from our own funds, conduct business in our own name and have restrictions on pledging our assets for the benefit of certain other persons. These provisions restrict the ability to move cash out of Genco without meeting certain requirements as set forth in the governing documents.

As of December 31, 2015, our liquidity consisted of $61 million of cash on hand. Based on current projections as of December 31, 2015, we expect operating cash flows and daily working capital needs to be sufficiently covered by our cash on hand in 2016.

On March 14, 2013, we exercised our option under the amended put option agreement with Medina Valley and received an initial payment of $100 million for the sale of our Gas-Fired Facilities to Medina Valley, an affiliate of Ameren. On October 11, 2013, we completed the sale of our Gas-Fired Facilities to Medina Valley and received an additional payment of $38 million. Medina Valley entered into the Rockland Agreement to sell the Gas-Fired Facilities to Rockland Capital. The sale of the Gas-Fired Facilities to an affiliate of Rockland Capital closed on January 31, 2014. Under the Put Option, Medina Valley is obligated to pay us after-tax proceeds realized on the sale of the Gas-Fired Facilities in excess of $138 million within two years of January 31, 2014. The excess proceeds have been placed in escrow and we expect to receive approximately $14 million of excess proceeds from the sale in the first quarter 2016.

We are a party to a services agreement (the “Services Agreement”) with Dynegy and certain of its subsidiaries for the provision of certain support services. Effective December 31, 2015, we amended the Services Agreement to provide that payments to Dynegy for services incurred may be deferred based on the liquidity of certain IPH subsidiaries as of the current month’s end. Any deferred payments, and associated interest, will be reflected as an affiliate payable to be settled at the discretion of Dynegy or us. The amendment will be in place through 2016 and will be evaluated for extension in the fourth quarter of 2016. Please read Note 11—Related Party Transactions for further details.

Under the provisions of our indenture, we may not borrow additional funds from external, third-party sources if our interest coverage ratio is less than a specified minimum or if our leverage ratio is greater than a specified maximum. Please read Note 10—Debt for further discussion on our indenture provisions. Throughout the year 2015, our interest coverage ratio was less than the specified minimum level required for external borrowings. As a result, our ability to borrow additional funds from external, third-party sources has been restricted. Our required ratios under the indenture may be disregarded if both Moody’s and S&P reaffirm the ratings in place at the time of the debt incurrence after considering the additional indebtedness.

Our indenture provides that dividends cannot be paid unless the actual interest coverage ratio for our most recently ended four fiscal quarters and the interest coverage ratios projected by management for each of the subsequent four six-month periods are greater than a specified minimum level. Based on December 31, 2015 calculations, our interest coverage ratios are less than the minimum ratios required to pay dividends and borrow additional funds from external, third-party sources. As a result, we were restricted from paying dividends as of December 31, 2015. Please read Note 10—Debt for further discussion on indenture provisions. We paid no dividends in 2015, 2014 or 2013.

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The following table presents net cash from operating, investing and financing activities for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
(amounts in millions)	2015			2014			2013
Net cash provided by (used in) operating activities	$	(7	)	$	(16	)	$	51
Net cash provided by (used in) investing activities	$	(58	)	$	(48	)	$	110
Net cash provided by financing activities	$	—		$	—		$	4

Operating Activities

Historical Operating Cash Flows. Cash used in operations totaled $7 million for the year ended December 31, 2015. During the period, our power generation business provided cash of $90 million primarily due to the operation of our power generation facilities, offset by $59 million in interest payments and approximately $38 million of cash used related to changes in working capital and general and administrative expenses.

Cash used in operations totaled $16 million for the year ended December 31, 2014. During the period, our power generation business provided cash of $80 million primarily due to the operation of our power generation facilities, offset by $39 million in interest payments and approximately $57 million of cash used related to changes in working capital and other, including general and administrative expenses.

Cash provided by operations totaled $51 million for the year ended December 31, 2013. During the period, our power generation business provided cash of $57 million primarily due to the operation of our power generation facilities, $1 million in negative changes due to decreased net deferred tax liabilities and $5 million in positive changes in working capital.

Future Operating Cash Flows. Our future operating cash flows will vary based on a number of factors, many of which are beyond our control, including the price of power, the prices of coal and their correlation to power prices, collateral requirements, the value of capacity and ancillary services, the run time of our generating facilities, the effectiveness of our commercial strategy and legal, environmental and regulatory requirements.

Collateral Postings. We use a portion of our capital resources in the form of cash to satisfy counterparty collateral demands. Our collateral postings to third parties consisted of approximately $8 million and $5 million of cash at December 31, 2015 and 2014, respectively. Collateral postings increased from December 31, 2014 to December 31, 2015 due to the expiration of an agreement with Ameren Corporation (“Ameren”) as described below.

On February 26, 2014, Genco entered into a collateral agreement, with a total limit not to exceed $22.5 million, with IPM pursuant to which Genco may provide collateral to IPM to secure obligations of IPM applicable to Genco’s assets. We have provided no amounts to IPM under this agreement as of December 31, 2015.

Additional collateral support for agreements entered into prior to December 2, 2013 was provided by Ameren through December 2, 2015. On December 2, 2015, we directly posted $4 million of collateral support and IPM posted an additional amount of cash collateral related to these contracts on our behalf, which will reduce the future cash receipts on our PSA for the same amount.

Investing Activities

Capital Expenditures. We had capital expenditures of approximately $58 million, $48 million and $55 million during the years ended December 31, 2015, 2014 and 2013, respectively. These amounts included capitalized interest of $22 million, $20 million and $18 million for the years ended December 31, 2015, 2014 and 2013, respectively. Capital expenditures principally consisted of facility upgrades to comply with environmental regulations. In 2015, 2014 and 2013, we spent $41 million, $42 million, and $38 million, respectively, primarily related to a FGD system project at our Newton facility. Other capital expenditures were made principally to fund various facility upgrades.

We expect capital expenditures for 2016 to be approximately $59 million. The capital budget is subject to revision as opportunities arise or circumstances change. Capital expenditures are typically funded through the use of cash flows from operations and available cash on hand.

Other Investing Activities. During the years ended December 31, 2015 and 2014, we had no other investing activities.

During the year ended December 31, 2013, there was a $138 million cash inflow primarily from the sale of the Gas-Fired Facilities to Medina Valley and a $27 million cash inflow primarily due to proceeds from repayment of net money pool advances related to the AER Acquisition.

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Financing Activities

Historical Cash Flow from Financing Activities. During the years ended December 31, 2015 and 2014, we had no cash flow from financing activities.

Cash provided by financing activities totaled $4 million during the year ended December 31, 2013, primarily due to a capital contribution received from AER.

Financing Trigger Events. Certain of our financial obligations and all of our senior notes include provisions which, if not met, could require early payment, additional collateral support or similar actions. The trigger events include the violation of covenants, defaults on scheduled principal or interest payments, including any indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions, insolvency events and acceleration of other financial obligations. We do not have any trigger events tied to specified credit ratings or stock price in our debt instruments and are not party to any contracts that require us to issue equity based on credit ratings or other trigger events.

Long-term Debt and Equity

For the years ended December 31, 2015 and 2014, there were no issuances of common stock, and no issuances, redemptions, repurchases or maturities of long-term debt. Please read Note 10—Debt for further discussion.

Summarized Debt

The following table depicts our third party debt obligations:



	Year Ended December 31,
(amounts in millions)	2015			2014
Unsecured obligations	$	825		$	825
Unamortized discount	(1		)	(1		)
Total long-term debt	$	824		$	824

Indebtedness Provisions and Other Covenants

Please read Note 10—Debt for further discussion of covenants and provisions contained in our indenture and “Dividends” below for further discussion of restrictions on dividends.

At December 31, 2015, we were in compliance with the provisions and covenants contained within our indenture. Our indenture includes provisions that require us to maintain certain interest coverage and debt-to-capital ratios in order for us to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans or investments in affiliates, or to incur additional external, third-party indebtedness. The following table summarizes these required ratios as of and for the year ended December 31, 2015:



	Required Ratio	Actual Ratio
Restricted payment interest coverage ratio (1)	≥1.75	1.05
Additional indebtedness interest coverage ratio (2)	≥2.50	1.05
Additional indebtedness debt-to-capital ratio (2)	≤60%	86	%

_______________________________________


(1)	As of the date of the restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods.


(2)	Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Other borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests.

Based on our actual ratios noted above, as of December 31, 2015 we are prohibited from incurring additional third-party indebtedness. Our required ratios under the indenture may be disregarded if both Moody’s and S&P reaffirm the ratings in place at the time of the debt incurrence after considering the additional indebtedness.

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Dividends

Our indenture provides that dividends cannot be paid unless the actual interest coverage ratio for our most recently ended four fiscal quarters and the interest coverage ratios projected by management for each of the subsequent four six-month periods are greater than a specified minimum level. Based on December 31, 2015 calculations, our interest coverage ratios are less than the minimum ratios required to pay dividends. As a result, we were restricted from paying dividends as of December 31, 2015. Please read Note 10—Debt for further discussion on indenture provisions. We paid no dividends in 2015, 2014 or 2013.

Credit Ratings

In carrying out our commercial business strategy, our current non-investment grade credit ratings have resulted and will likely continue to result in requirements that we either prepay obligations or post significant amounts of collateral to support our business.

The following table presents the principal credit ratings by Moody’s and S&P effective on the date of this report:



	Moody’s	S&P
Issuer/corporate credit rating	Caa3	CCC+
Senior unsecured debt	Caa3	CCC+

Disclosure of Contractual Obligations

We have incurred various contractual obligations and financial commitments in the normal course of our operations and financing activities. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities.

The following table summarizes the contractual obligations of the Company and its consolidated subsidiaries as of December 31, 2015. Cash obligations reflected are not discounted and do not include accretion. Obligations which are not under existing contractual arrangements are not included.



	Expiration by Period
(amounts in millions)	Total		Less than 1 Year		1 - 3 Years		3 - 5 Years		More than 5 Years
Long-term debt	$	825	$	—	$	300	$	250	$	275
Interest payments on debt	491		59		112		77		243
Coal transportation	407		38		65		82		222
Coal purchase commitments	369		145		126		98		—
Environmental compliance obligations	186		9		115		62		—
Pension funding obligations	28		—		4		6		18
Other obligations	4		—		1		—		3
Total contractual obligations	$	2,310	$	251	$	723	$	575	$	761

Long-Term Debt. Amounts do not include unamortized discounts. Please read Note 10—Debt for further discussion.

Interest Payments on Debt. Interest payments on debt represent estimated periodic interest payment obligations. Please read Note 10—Debt for further discussion.

Coal Transportation. At December 31, 2015, we had long-term coal transportation contracts in place. We also had long-term rail car leases in place. The amounts included in Coal transportation reflect our minimum purchase obligations based on the terms of the contracts.

Coal Purchase Commitments. At December 31, 2015, we had contracts in place to purchase coal for various generation facilities. The amounts in the table reflect our minimum purchase obligations. To the extent forecasted volumes have not been priced but are subject to a price collar structure, the obligations have been calculated using the minimum purchase price of the collar.

Environmental Compliance Obligations. The table above includes estimated costs under a third party contract, excluding capitalized interest, for the completion of scheduled milestones related to the installation of the Newton FGD systems, such that the fleet will comply with certain SO₂ emission limits approved in the variance granted by the IPCB in November 2013. Please

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read Business—Environmental Matters—IPH Variance for further discussion and for our discussion of all our environmental compliance obligations. The first milestone relating to engineering design was completed by July 2015, while the last milestone requires major equipment components being placed into final position on or before September 1, 2019. We are currently scheduled to complete the Newton FGD system project by the end of 2019 with minimal costs anticipated in 2020. Either party can terminate this contract based on certain events as specified in the contract. In February 2016, we issued a notice to the third party contractor constructing the FGD systems directing them to temporarily suspend a portion of the work being performed. We will assess the results of the MISO Planning Year 2016-2017 capacity auction to be held in April 2016, at which time we will reevaluate our suspension notice to the third party contractor constructing the FGD systems.

Pension Funding Obligations. Amounts include our minimum required contributions to our defined benefit pension plans through 2025 as determined by our actuary and are subject to change based on actual results of the plan. We may elect to make voluntary contributions in 2016 which would decrease future funding obligations. Please read Note 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion.

Other Obligations. Other obligations include obligations under a facilities service agreement to maintain transmission system stability in connection with our Coffeen facility and other miscellaneous items which are individually insignificant.

Commitments and Contingencies

Please read Note 13—Commitments and Contingencies, which is incorporated herein by reference, for further discussion of our material commitments and contingencies.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements at December 31, 2015.

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RESULTS OF OPERATIONS

Overview

In this section, we discuss our results of operations for the years ended December 31, 2015, 2014 and 2013. Our results of operations and financial position are affected by many factors. Weather, economic conditions and the actions of key customers or competitors can significantly affect the demand for our services. At the end of this section, we have included our business outlook.

Genco has a PSA with IPM, a subsidiary of IPR, whereby it agreed to sell and IPM agreed to purchase all of the capacity and energy available from its generation fleet. IPM entered into a similar PSA with IPRG. Under the PSAs, IPM revenues are allocated between Genco and IPRG based on reimbursable expenses and generation of each entity. The reimbursable expenses used in the calculation of revenues allocated under the Genco and IPRG PSAs include operation costs in addition to depreciation and interest on debt. Additionally, the revenues allocated include settled values of derivative instruments entered into by IPM to hedge commodity exposure related to Genco and IPRG generation.

EEI has a PSA with IPM, whereby EEI agreed to sell and IPM agreed to purchase all of the capacity and energy available from EEI’s generation fleet. With limited exceptions, the price that IPM pays for capacity is the MISO Local Resource Zone 4 clearing price. IPM pays spot market prices for the associated energy. In addition, EEI will at times purchase energy from IPM to fulfill obligations to a non-affiliated party.

Ultimately, our sales are subject to market conditions for power. We principally use coal and limited amounts of natural gas for fuel in our operations. The prices for these commodities can fluctuate significantly due to the global economic and political environment, weather, supply, demand and many other factors. We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. As discussed above, IPM may hedge exposures related to our generation through derivative contracts and the settled value under those contracts are allocated to us through the PSAs. The reliability of our facilities, operations and maintenance costs and capital expenditures are key factors that we seek to control and to optimize our results of operations, financial position and liquidity.

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Consolidated Summary Financial Information — Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

The following table provides summary financial data regarding our consolidated results of operations for the years ended December 31, 2015 and 2014, respectively:



	Year Ended December 31,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
(dollars in millions, except for price data)	2015			2014			Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
Revenues	$	534		$	648		$	(114	)	(18	)%
Cost of sales, excluding depreciation expense	(333		)	(447		)	114			26	%
Gross margin	201			201			—			—	%
Operating and maintenance expense	(162		)	(158		)	(4		)	(3	)%
Impairment	(855		)	—			(855		)	(100	)%
Depreciation and amortization expense	(86		)	(100		)	14			14	%
Operating loss	(902		)	(57		)	(845		)	NM
Interest expense	(39		)	(40		)	1			3	%
Loss before income taxes	(941		)	(97		)	(844		)	NM
Income tax benefit	378			49			329			NM
Net loss	(563		)	(48		)	(515		)	NM
Less: Net income (loss) attributable to noncontrolling interest	(1		)	2			(3		)	NM
Net loss attributable to Illinois Power Generating Company	$	(562	)	$	(50	)	$	(512	)	NM

Million Megawatt Hours Generated	14.4			19.2			(4.8		)	(25	)%
In Market Availability for Genco Facilities (1)	92		%	91		%
Average Capacity Factor for Genco Facilities (2)	52		%	70		%
Average Quoted Market Power Prices ($/MWh) (3)
On-Peak: Indiana (Indy Hub)	33.50			48.28			$	(14.78	)	(31	)%
Off-Peak: Indiana (Indy Hub)	24.56			32.52			$	(7.96	)	(24	)%

________________________________________


(1)	In Market Availability is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. This calculation excludes certain events outside of management control such as weather related issues.


(2)	Reflects actual production as a percentage of available capacity.


(3)	Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.

Discussion of Consolidated Results of Operations

Revenues. Revenues decreased by $114 million from $648 million for the year ended December 31, 2014 to $534 million for the year ended December 31, 2015. The decrease was primarily due to $146 million in lower revenues allocated to us through the PSAs as the result of decreased generation due to milder weather in 2015, planned outages at our EEI and Newton facilities and lower reimbursed costs due to lower depreciation on our assets as a result of an impairment in 2015, offset by $33 million of increased capacity revenue received through the PSAs from higher capacity clearing prices for the year ended December 31, 2015 compared to the year ended December 31, 2014.

Cost of Sales. Cost of sales decreased by $114 million from $447 million for the year ended December 31, 2014 to $333 million for the year ended December 31, 2015. The decrease was primarily due to $114 million in lower coal costs due to decreased generation as a result of milder weather and planned outages during the year ended December 31, 2015 compared to the year ended December 31, 2014.

Operating and Maintenance Expense. Operating and maintenance expense increased by $4 million from $158 million for the year ended December 31, 2014 to $162 million for the year ended December 31, 2015. The increase was primarily a $6 million increase in accretion expense caused by an upward revision in ARO liability at the end of 2014 and increased planned

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outage expenses of $7 million at our EEI and Newton facilities, offset by a $10 million decrease in the services agreement fee due to a lower allocation rate.

Impairment. Impairment charges were $855 million for the year ended December 31, 2015 due to an impairment charge during the third quarter of 2015 of our Coffeen generation facility. Please read Note 3—Impairments for further discussion. There were no such charges during the year ended December 31, 2014.

Depreciation and Amortization Expense. Depreciation and amortization expense decreased by $14 million from $100 million for the year ended December 31, 2014 to $86 million for the year ended December 31, 2015. The decrease was primarily due to a reduction in the depreciable asset base as a result of the impairment of assets during the year ended December 31, 2015.

Income Tax Benefit. We reported an income tax benefit from continuing operations of $378 million and $49 million for the years ended December 31, 2015 and December 31, 2014, respectively. The increase in the benefit is primarily related to the increase in our pretax loss when comparing the two periods, mainly attributable to the impairment charge during the year ended December 31, 2015.

Consolidated Summary Financial Information — Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

The following table provides summary financial data regarding our consolidated results of operations for the years ended December 31, 2014 and 2013, respectively:



	Year Ended December 31,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
(dollars in millions, except for price data)	2014			2013			Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
Revenues	$	648		$	811		$	(163	)	(20	)%
Cost of sales, excluding depreciation expense	(447		)	(607		)	160			26	%
Gross margin	201			204			(3		)	(1	)%
Operating and maintenance expense	(158		)	(138		)	(20		)	(14	)%
Impairment	—			(199		)	199			100	%
Depreciation and amortization expense	(100		)	(80		)	(20		)	(25	)%
Operating loss	(57		)	(213		)	156			73	%
Interest expense	(40		)	(42		)	2			5	%
Other income and expense, net	—			1			(1		)	(100	)%
Loss before income taxes	(97		)	(254		)	157			62	%
Income tax benefit	49			65			(16		)	(25	)%
Net loss	(48		)	(189		)	141			75	%
Less: Net loss attributable to noncontrolling interest	2			(1		)	3			NM
Net loss attributable to Illinois Power Generating Company	$	(50	)	$	(188	)	$	138		73	%

Million Megawatt Hours Generated	19.2			18.8			0.4			2	%
In Market Availability for Genco Facilities (1) (3)	91		%	—		%
Average Capacity Factor for Genco Facilities (2) (3)	70		%	—		%
Average Quoted Market Power Prices ($/MWh) (4)
On-Peak: Indiana (Indy Hub)	48.28			38.01			$	10.27		27	%
Off-Peak: Indiana (Indy Hub)	32.52			27.49			$	5.03		18	%

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________________________________________


(1)	In Market Availability is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. This calculation excludes certain events outside of management control such as weather related issues.


(2)	Reflects actual production as a percentage of available capacity.


(3)	In Market Availability and Average Capacity Factor are not available as the Genco assets were acquired by Dynegy on December 2, 2013.


(4)	Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.

Discussion of Consolidated Results of Operations

Revenues. Revenues decreased by $163 million from $811 million for the year ended December 31, 2013 to $648 million for the year ended December 31, 2014. The decrease was primarily due to $144 million of power sales to the DOE during the year ended December 31, 2013, $7 million in lower revenues received through the PSA as the result of a lower price per MWh and a $7 million decrease in mark-to-market gains for 2014 .

Cost of Sales. Cost of sales decreased by $160 million from $607 million for the year ended December 31, 2013 to $447 million for the year ended December 31, 2014. The decrease is primarily due to $142 million of power purchases to supply the DOE contract, $14 million in lower average fuel price per MWh generated, offset by an increase in fuel expense of $1 million as a result of higher generation volumes.

Operating and Maintenance Expense. Operating and maintenance expense increased by $20 million from $138 million for the year ended December 31, 2013 to $158 million for the year ended December 31, 2014. The increase is primarily related to a curtailment gain associated with EEI postretirement benefits of $26 million and a gain on the sale of the Meredosia facility in 2013 with no such activity in 2014. The increase was offset by lower maintenance costs related to extensive boiler repairs at our Coffeen and Newton facilities in 2013 that were not present in 2014 and the absence of expenses related to the Gas-Fired Facilities, which were sold in October 2013.

Impairment. Impairment charges were $199 million for the year ended December 31, 2013, which was due to a pretax charge to earnings to reflect the impairment of the Gas-Fired Facilities, which were held for sale during the period. There were no such charges during the year ended December 31, 2014 as the Gas-Fired Facilities were sold in October 2013.

Depreciation and Amortization Expense. Depreciation and amortization expense increased by $20 million from $80 million for the year ended December 31, 2013 to $100 million for the year ended December 31, 2014. The increase is primarily due to $28 million as a result of change in the depreciable lives of the Genco assets at the Acquisition Date, partially offset by a decrease of $10 million as a result of the removal of the Gas-Fired Facilities in 2013 due to held for sale accounting.

Income Tax Benefit. We reported an income tax benefit from continuing operations of $49 million and $65 million for the years ended December 31, 2014 and December 31, 2013, respectively. The decrease in the benefit was related to the decrease in our pretax loss when comparing the two periods and recognizing a property, plant, and equipment benefit of $9 million in the year ended December 31, 2014, which previously was not expected to be realized in 2013 due to the limits imposed by IRC Section 382.

Outlook

Through IPM, we sell our capacity through five main channels to market: bilateral sales, wholesale transactions, retail sales, PJM exports and the MISO capacity auction. The MISO capacity auction is typically our final opportunity to market the remaining capacity in MISO. The next MISO capacity auction, for Planning Year 2016-2017, will conclude April 14, 2016. We intend to offer our uncommitted volume in the auction at our economic cost. If significant portions of our capacity do not clear the auction, we may suspend operations for that generation which is not recovering its cost. For Planning Year 2013-2014, Local Resource Zone 4 cleared at $1.05 per MW-day. For Planning Year 2014-2015, Local Resource Zone 4 cleared at $16.75 per MW-day. For Planning Year 2015-2016, Local Resource Zone 4 cleared at $150 per MW-day with 1,403 MW sold, including 996 MW that are expected to cover obligations which are realized through the PSAs, leaving 407 MW that will receive the $150 per MW-day clearing price.

We expect asset retirements and confirmed future capacity exports from MISO to PJM to continue shrinking the supply of generation in the MISO market. MISO has a Planning Reserve Margin of 15.2 percent and has forecasted reserve margins of 16.1 percent for Planning Year 2016-2017, 16.6 percent for Planning Year 2017-2018, 16.0 percent for Planning Year 2018-2019, 15.2 percent for Planning Year 2019-2020 and 14.7 percent for Planning Year 2020-2021.

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Through IPM, we also sell a portion of our capacity into the PJM control area. Beginning on June 1, 2016, our Coffeen and Newton facilities will have 458 MW, or 15 percent of our capacity, that is electrically tied and become baseload generation for PJM through pseudo-tie arrangements. PJM’s capacity market construct is more favorable than MISO’s due to (i) a 3 year forward auction versus a prompt year auction in MISO, (ii) a sloped demand curve versus the vertical demand curve in MISO, and (iii) minimum offer price rule in PJM versus vertically integrated utilities offering in at a zero price in MISO.

PJM has begun the transition of the PJM capacity market to the CP product. On August 26-27, 2015, PJM held a transitional auction to convert up to 60 percent of PJM’s capacity needs for Planning Year 2016-2017 from legacy capacity to CP. On September 3-4, 2015, PJM held a transitional auction to convert 70 percent of PJM’s capacity needs for Planning Year 2017-2018 from legacy capacity to CP. On August 10-14, 2015, PJM held the BRA to procure CP for 80 percent and Base for 20 percent of PJM’s capacity needs for Planning Year 2018-2019. PJM will procure 100 percent CP for all resources beginning with Planning Year 2020-2021.

In PJM, we cleared no volume in the Planning Year 2014-2015 Base Residual Auction (“BRA”) and 150 MW in the Planning Year 2015-2016 BRA. In the Planning Year 2016-2017 Transitional Auction, Genco converted its previously committed 425 MW of legacy capacity to 434 MW of CP. In the Planning Year 2017-2018 Transitional Auction, Genco converted 260 MW of its 416 MW legacy capacity to CP retaining 156 MW as legacy capacity. CP increased previous BRA prices from $59 per MW-day to $134 per MW-day for Planning Year 2016-2017; and $120 per MW-day to $152 per MW-day for Planning Year 2017-2018. CP for Planning Year 2018-2019 cleared $165 per MW-day. We have also secured one segment of the transmission path required to offer an additional 240 MW of capacity and energy into PJM.

As of February 8, 2016, our expected remaining 2016 coal requirements are 89 percent contracted and 72 percent priced. Our forecasted coal requirements for 2017 are 43 percent contracted and 26 percent priced. We look to procure and price additional fuel opportunistically. Our coal transportation requirements are fully contracted for 2016 and 2017. Our coal transportation requirements are approximately 65 percent contracted for 2018 to 2020. In addition, we recently entered into a new long-term transportation agreement for the Joppa facility. The new Joppa transport contract will begin in 2018 and is at a lower rate than the 2017 rate.

In May 2015, three complaints were filed at FERC regarding the Zone 4 results for the 2015-2016 PRA conducted by MISO. The Newton, Coffeen and Joppa facilities were offered into Zone 4 in the 2015-2016 PRA. The complainants, Public Citizen, Inc., the Illinois Attorney General, and Southwestern Electric Cooperative, Inc., have challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds and requested changes to the MISO PRA structure going forward. Complainants have also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the 2015-2016 PRA. The MISO IMM, which was responsible for monitoring the MISO 2015-2016 PRA, determined that all offers were competitive and that no physical or economic withholding occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the proposed remedies. Dynegy complied fully with the terms of the MISO Tariff in connection with the 2015-2016 PRA. In addition, the Illinois Industrial Energy Consumers filed a complaint at FERC against MISO on June 30, 2015 requesting prospective changes to the MISO tariff.

On October 1, 2015, FERC issued an order of non-public, formal investigation, stating that shortly after the conclusion of the 2015-2016 PRA, FERC’s Office of Enforcement began a non-public informal investigation into whether market manipulation or other potential violations of FERC orders, rules and regulations occurred before or during the PRA. The Order noted that the investigation is ongoing, and that the order converting the informal, non-public investigation to a formal, non-public investigation does not indicate that FERC has determined that any entity has engaged in market manipulation or otherwise violated any FERC order, rule or regulation. Further, FERC held a Staff-led technical conference on October 20, 2015 to obtain further information concerning potential changes to the MISO PRA structure going forward, including on proposals made by complainants. The technical conference did not address the ongoing Office of Enforcement investigation.

On December 31, 2015, FERC issued an order on the complaints requiring a number of prospective changes to the MISO Tariff provisions associated with calculating Initial Reference Levels and Local Clearing Requirements, effective as of the 2016-2017 PRA. Under the order, FERC found that the existing tariff provision which bases Initial Reference Levels for capacity supply offers on the estimated opportunity cost of exporting capacity to a neighboring region (for example, PJM) are no longer just and reasonable. Accordingly, FERC required MISO to set the Initial Reference Level for capacity at $0 per MW-day for the 2016-2017 PRA. Capacity suppliers may also request a facility-specific reference level from the MISO IMM. The order did not address the other arguments of the complainants regarding the 2015-2016 Auction, and stated that those issues remain under consideration and will be addressed in a future order.

Other Market Developments

On January 25, 2016, the U.S. Supreme Court overturned the decision of the U.S. Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”) and affirmed FERC’s jurisdiction over compensation to Demand Response providers in wholesale competitive markets and the compensation method as proscribed in FERC Order No. 745. The decision effectively maintains the

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status-quo with respect to Demand Response participation in the wholesale markets, because the ISOs/RTOs refrained from making changes to market design while the case was pending.

SEASONALITY

Our revenues and operating income are subject to fluctuations during the year, primarily due to the impact seasonal factors have on sales volumes and the prices of power and natural gas. Power marketing operations and generating facilities have higher volatility and demand in the summer cooling months and winter heating season.

CRITICAL ACCOUNTING POLICIES

Our Accounting Department is responsible for the development and application of accounting policy and control procedures. This department conducts these activities independent of any active management of our risk exposures and reports to the Chief Financial Officer (“CFO”).

The process of preparing financial statements in accordance with GAAP requires our management to make estimates and judgments. It is possible that materially different amounts could be recorded if these estimates and judgments change or if actual results differ from these estimates and judgments. We have identified the following critical accounting policies that require a significant amount of estimation and judgment and are considered important to the portrayal of our financial position and results of operations.

Impairment of Long-Lived Assets

ASC 360 - Property, Plant, and Equipment requires an entity to assess whether the recorded values of PP&E and finite-lived intangible assets have become impaired when certain indicators of impairment exist. Examples of these indicators include, but are not limited to:


•	A significant decrease in the market price of a long-lived asset (asset group);


•	A significant adverse change in the extent or manner in which a long-lived asset (asset group) is being used, or in its physical condition;


•	A significant adverse change in legal factors or in the business climate that could affect the value of a long-lived asset (asset group), including an adverse action or assessment by a regulator;


•	An accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset (asset group);


•	A current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset (asset group); and,


•	A current expectation that it is more likely than not, a long-lived asset (asset group) will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

If we determine that an asset may have become impaired, then we will perform step one of the impairment analysis, which requires us to determine if the asset’s value is recoverable using forecasted undiscounted cash flows. If it is determined that the asset’s value is not recoverable, then we will perform step two of the impairment analysis and fair value the asset using a discounted cash flow model and record an impairment charge to reduce the value of the asset to its fair value. The assumptions and estimates used by management to assess whether the asset may have become impaired, whether the asset’s value is recoverable, and to determine the fair value of the estimate are significant and may vary materially from the assumptions used by our peers. Some examples of the assumptions and estimates used include:


•	Determination of decreases in the market price of an asset being a short-term or long-term, fundamental change;


•	The highest and best use of the asset;


•	Forecasted environmental and regulatory costs;


•	Management’s fundamental view of the long-term pricing environment for energy and capacity;


•	Management’s forecast of gross margin, capital expenditures, and operations and maintenance costs;


•	Remaining useful life of our assets;


•	Salvage value;


•	Discount rates; and,


•	Inflation rates.

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Changes in any of management’s assumptions and estimates could result in significantly different results than what we have reported herein.

We performed asset impairment tests of all of our facilities in 2015 which determined that the carrying value of our Coffeen facility was not recoverable; therefore, we recorded an impairment charge of $855 million during the third quarter of 2015. Please read Note 3—Impairments for further discussion.

Accounting for Income Taxes

We use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant differences.

As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing tax and accounting treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are included within our consolidated balance sheet. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

Accounting for uncertainty in income taxes requires that we determine whether it is more-likely-than-not that a tax position we have taken will be sustained upon examination. If we determine that it is more likely than not that the position will be sustained, we recognize the largest amount of the benefit that is greater than 50 percent likely of being realized upon settlement. There is a significant amount of judgment involved in assessing the likelihood that a tax position will be sustained upon examination and in determining the amount of the benefit that will ultimately be realized.

Please read Note 12—Income Taxes for further discussion of our accounting for income taxes, uncertain tax positions and changes in our valuation allowance.

RECENT ACCOUNTING PRONOUNCEMENTS

Please read Note 2—Summary of Significant Accounting Policies for further discussion of accounting principles adopted and accounting principles not yet adopted.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of changes in value of a physical asset or a financial instrument, derivative or nonderivative, caused by fluctuations in market variables such as interest rates, commodity prices and equity security prices. A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset or index. The following discussion of our risk management activities includes forward-looking statements that involve risks and uncertainties. Actual results could differ materially from those projected in the forward-looking statements. We handle market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, we also face risks that are either nonfinancial or nonquantifiable. Such risks, principally business, legal, and operational risks, are not part of the following discussion.

Our risk management objective is to optimize our physical generating assets and to pursue market opportunities within prudent risk parameters. Our risk management policies have been approved by our Board of Directors and are monitored by the Commodity Risk Control Group.

Credit Risk. Credit risk represents the loss that would be recognized if counterparties should fail to perform as contracted. Exchange-traded contracts are supported by the financial and credit quality of the clearing members of the respective exchanges and have nominal credit risk. In all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction.

Commodity Price Risk. We limit our coal price exposure for generation by entering into term purchase agreements for PRB coal. Profitable operation of our coal-fired generation facilities is highly dependent on coal prices and coal transportation rates. We intend to secure a reliable coal supply while reducing exposure to commodity price volatility. Transportation of PRB coal can be affected by extreme weather, rail maintenance, and accidents, slowing or stopping the delivery from the mine to the facility.

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The following table shows the percentage of our coal and coal transportation requirements that have been contracted for the five-year period 2016 through 2020:



	2016		2017		2018 - 2020
Coal	89	%	43	%	31	%
Coal transportation	100	%	100	%	65	%

We are exposed to changes in market prices for power and the risk of fuel and fuel transportation cost increases and interruptions in fuel supplies. On a completely unhedged basis for 2016, if power prices were to decrease by one percent on economic generation, power revenues would decrease by $5 million. If delivered coal costs were to increase by one percent, our coal delivery expenses would increase by $3 million for the five-year period 2016 through 2020.

Item 8. Financial Statements and Supplementary Data

The report of our independent registered public accounting firm and our Consolidated Financial Statements are filed pursuant to this Item 8 and are included later in this report. See Index to Consolidated Financial Statements on page F-1.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A. Controls and Procedures

Genco was required to comply with Section 404 of the Sarbanes-Oxley Act of 2002 and related SEC regulations as to management’s assessment of internal control over financial reporting for the 2015 fiscal year.

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of management, including our Chief Executive Officer (“CEO”) and our CFO, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). This evaluation included consideration of the various processes carried out under the direction of our disclosure committee. Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2015.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Our internal control over financial reporting includes those policies and procedures that:


(i)	pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;


(ii)	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 our company are being made only in accordance with authorizations of our management and directors; and


(iii)	provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our 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. Also, 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. Under the supervision and with the participation of our management, including the CEO and CFO, 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 issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Based on the results of this assessment and on those criteria, we concluded that our internal control over financial reporting was effective as of December 31, 2015.

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Changes in Internal Controls Over Financial Reporting

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

Item 9B. Other Information

Not applicable.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

This item is omitted in reliance on General Instruction (I)(2)(c) of Form 10-K.

Item 11. Executive Compensation

This item is omitted in reliance on General Instruction (I)(2)(c) of Form 10-K.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

This item is omitted in reliance on General Instruction (I)(2)(c) of Form 10-K.

Item 13. Certain Relationships and Related Transactions, and Director Independence

This item is omitted in reliance on General Instruction (I)(2)(c) of Form 10-K.

Item 14. Principal Accountant Fees and Services

Information required by this Item of Form 10-K is identical to the information included in Dynegy’s definitive proxy statement for Dynegy’s 2016 annual meeting of stockholders under the heading “Independent Registered Public Auditors—Principal Accountant Fees and Services,” which information will be incorporated herein by reference; such proxy statement will be filed with the SEC not later than 120 days after December 31, 2015. However, if such proxy statement is not filed within such 120-day period, information with respect to the principal accountant fees and services will be filed as part of an amendment to this Form 10-K not later than the end of the 120-day period.

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PART IV

Item 15. Exhibits

(a) The following documents, which we have filed with the SEC pursuant to the Securities Exchange Act of 1934, as amended, are by this reference incorporated in and made a part of this report:

1. Financial Statements—Our consolidated financial statements are incorporated under Item 8. of this report.

2. Exhibits—The following instruments and documents are included as exhibits to this report.



Exhibit Number		Description
2.1		Transaction Agreement by and between Ameren Corporation and Illinois Power Holdings, LLC, dated as of March 14, 2013 (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 15, 2013, File No. 001-33443).
2.2		Asset Purchase Agreement by and between AmerenEnergy Medina Valley Cogen, L.L.C. and Illinois Power Generating Company, dated as of March 14, 2013 (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K of Ameren Corporation filed on March 19, 2013, File No. 001-14756).
2.3		Letter Agreement by and between Ameren Corporation and Illinois Power Holdings, LLC, dated as of December 2, 2013, amending the Transaction Agreement dated as of March 14, 2013 (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K of Dynegy Inc. filed on December 4, 2013, File No. 001-33443).
3.1		Articles of Incorporation of Illinois Power Generating Company filed March 9, 2000 (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-4 filed on March 6, 2001, File No. 333-56594).
3.2		Amendment to Articles of Incorporation of Illinois Power Generating Company filed April 19, 2000 (incorporated by reference to Exhibit 3.2 to the Registration Statement on Form S-4 filed on March 6, 2001, File No. 333-56594).
3.3		Amendment to Articles of Incorporation of Illinois Power Generating Company, filed on December 2, 2013 (incorporated by reference to Exhibit 3.3 to the Annual Report on Form 10-K for the year ended December 31, 2013, File No 333-56594).
3.4		Amended and Restated Bylaws of Illinois Power Generating Company as amended December 2, 2013 (incorporated by reference to Exhibit 3.4 to the Annual Report on Form 10-K for the year ended December 31, 2013, File No 333-56594).
4.1		Indenture dated as of November 1, 2000, from Illinois Power Generating Company to The Bank of New York Mellon Trust Company, N.A., as successor trustee (Genco Indenture) (incorporated by reference to Exhibit 4.1 to the Registration Statement on Form S-4 filed March 6, 2001, File No. 333-56594).
4.2		Third Supplemental Indenture dated as of June 1, 2002, to Genco Indenture, relating to the 7.95% Senior Notes, Series E due 2032 (incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 333-56594).
4.3		Fourth Supplemental Indenture dated as of January 15, 2003, to Genco Indenture, relating to the 7.95% Senior Notes, Series F due 2032 (incorporated by reference to Exhibit 4.5 to the Annual Report on Form 10-K for the year ended December 31, 2002, File No. 333-56594).
4.4		Fifth Supplemental Indenture dated as of April 1, 2008, to Genco Indenture, relating to the 7.00% Senior Notes, Series G due 2018 (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed April 9, 2008, File No. 333-56594).
4.5		Sixth Supplemental Indenture, dated as of July 7, 2008, to Genco Indenture, relating to the 7.00% Senior Notes, Series H due 2018 (incorporated by reference to Exhibit No. 4.55 to the Registration Statement on Form S-3 filed November 17, 2008, File No. 333-56594).
4.6		Seventh Supplemental Indenture, dated as of November 1, 2009, to Genco Indenture, relating to the 6.30% Senior Notes, Series l due 2020 (incorporated by reference to Exhibit 4.8 to the Current Report on Form 8-K filed November 17, 2009, File No. 333-56594).
4.7		Registration Rights Agreement, dated June 6, 2002 among Illinois Power Generating Company and the Initial Purchasers relating to the Illinois Power Generating Company 7.95% Senior Notes, Series E due 2032 (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 333-56594).
4.8		Registration Rights Agreement, dated April 9, 2008 among Illinois Power Generating Company and the Initial Purchasers relating to the Illinois Power Generating Company 7.00% Senior Notes, Series G due 2018 (incorporated by reference to Exhibit 4.8 to the Registration Statement on Form S-4 Filed May 19, 2008, File No. 333-56594).

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10.1		Amended and Restated Power Supply Agreement, dated March 28, 2008, between Illinois Power Marketing Company and Illinois Power Generating Company (incorporated by reference to Exhibit 10.1 to the Annual Report on Form 10-K for the year ended December 31, 2014, File No 333-56594).
10.2		First Amendment dated January 1, 2010, to Amended and Restated Power Supply Agreement dated March 28, 2008, between Illinois Power Marketing Company and Illinois Power Generating Company (incorporated by reference to Exhibit 10.2 to the Annual Report on Form 10-K for the year ended December 31, 2014, File No 333-56594).
10.3		Amended and Restated Power Sales Agreement, dated July 31, 2009, between Illinois Power Marketing Company and Electric Energy, Inc. (incorporated by reference to Exhibit 10.3 to the Annual Report on Form 10-K for the year ended December 31, 2014, File No 333-56594).
10.4		First Amendment dated September 1, 2014, to Amended and Restated Power Sales Agreement dated July 31, 2009, between Illinois Power Marketing Company and Electric Energy, Inc. (incorporated by reference to Exhibit 10.4 to the Annual Report on Form 10-K for the year ended December 31, 2014, File No 333-56594).
10.5		Second Amendment dated June 29, 2015, to Amended and Restated Power Sales Agreement dated July 31, 2009, between Illinois Power Marketing Company and Electric Energy, Inc. (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2015, File No. 333-56594).
10.6		Put Option Agreement, dated as of March 28, 2012, between Illinois Power Generating Company and Ameren Energy Resources Generating Company (incorporated by reference to Exhibit 10.1, to the Current Report on Form 8-K of Ameren Corporation filed March 28, 2012, File No. 001-14756).
10.7		Guaranty, dated as of March 28, 2012, made by Ameren Corporation in favor of Illinois Power Generating Company (incorporated by reference to Exhibit 10.2, to the Current Report on Form 8-K of Ameren Corporation filed on March 28, 2012, File No. 001-14756).
10.8		Novation and Amendment of Put Option Agreement, dated as of March 14, 2013, by and among AmerenEnergy Medina Valley Cogen. L.L.C., Ameren Energy Resources Generating Company, Illinois Power Generating Company and Ameren Corporation (incorporated by reference to Exhibit 10.3, to the Current Report on Form 8-K of Ameren Corporation filed March 19, 2013, File No. 001-14756).
10.9		Guaranty Agreement, dated as of December 2, 2013, by Illinois Power Generating Company in favor of Ameren Corporation (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed December 5, 2013, File No. 333-56594).
10.10		Revolving Promissory Note, dated as of December 2, 2013, by and between Dynegy Inc., as Lender, and Illinois Power Resources, LLC, as Borrower` (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed December 4, 2013, File No. 001-33443).
10.11		Letter of Credit and Reimbursement Agreement, dated as of January 29, 2014, between Illinois Power Marketing Company and Union Bank, N.A. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed February 4, 2014, File No. 333-56594).
10.12		Waiver and Amendment No. 1 to Letter of Credit and Reimbursement Agreement by and between Illinois Power Marketing Company and Union Bank, N.A. (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2014 of Dynegy Inc., File No. 001-33443).
10.13		Amendment No. 2 to Letter of Credit and Reimbursement Agreement by and between Illinois Power Marketing Company and Union Bank, N.A. (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarter ended September 30, 2015 of Dynegy Inc., File No. 001-33443).
10.14		Dynegy Inc. Severance Plan (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on October 30, 2015 File No. 001-33443).††
10.15		Dynegy Inc. 2009 Phantom Stock Plan (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on March 10, 2009, File No. 001-33443).††
10.16		First Amendment to the Dynegy Inc. 2009 Phantom Stock Plan, dated as of July 8, 2011 (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2011 of Dynegy Inc., File No. 001- 33443).††
10.17		Dynegy Inc. Incentive Compensation Plan, as amended and restated effective May 21, 2010 (incorporated by reference to Exhibit 10.34 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2010, File No. 001-33443).††
10.18		2012 Long Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on October 4, 2012, File No. 001-33443).††
14.1		Dynegy Inc. Code of Ethics for Senior Financial Professionals, as amended on July 23, 2013 (incorporated by reference to Exhibit 14.1 to the Annual Report on Form 10-K of Dynegy Inc. for the year ended December 31, 2013, File No. 001-33443).

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16.1		Letter of PricewaterhouseCoopers LLP dated May 15, 2014 (incorporated by reference to Exhibit 16.1 to the Current Report on Form 8-K, filed May 15, 2014, File No. 333-56594).
**31.1		Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**31.2		Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**32.1		Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
**32.2		Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101.INS		XBRL Instance Document
*101.SCH		XBRL Taxonomy Extension Schema Document
*101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
*101.LAB		XBRL Taxonomy Extension Label Linkbase Document
*101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document
*101.DEF		XBRL Taxonomy Extension Definition Document

__________________________________________


††	Compensatory plan or arrangement.

Attached as Exhibit 101 to this report is the following financial information for Genco's Annual Report on Form 10-K for the year ended December 31, 2015, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Operations and Comprehensive Income (Loss) for the years ended December 31, 2015, 2014 and 2013, (ii) the Consolidated Balance Sheets at December 31, 2015 and December 31, 2014, (iii) the Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013, (iv) the Consolidated Statements of Changes in Stockholder’s Equity for the years ended December 31, 2015, 2014 and 2013, and (v) the Combined Notes to the Financial Statements for the year ended December 31, 2015. These exhibits are deemed furnished and not filed pursuant to Rule 406T of Regulation S-T.


**	Filed herewith.

Genco hereby undertakes to furnish to the SEC upon request a copy of any long-term debt instrument not listed above that Genco has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.

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SIGNATURES

Pursuant to the requirements of Section 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.



		ILLINOIS POWER GENERATING COMPANY (registrant)

Date:	March 28, 2016	By	/s/ ROBERT C. FLEXON
			Robert C. Flexon
			President and Chief Executive Officer

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 date indicated.



/s/ ROBERT C. FLEXON	President and Chief Executive Officer (Principal Executive Officer)	March 28, 2016
Robert C. Flexon

/s/ CLINT C. FREELAND	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	March 28, 2016
Clint C. Freeland

/s/ J. CLINTON WALDEN	Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 28, 2016
J. Clinton Walden

/s/ KEVIN HOWELL	Chairman	March 28, 2016
Kevin Howell

/s/ MARIO ALONSO	Director	March 28, 2016
Mario Alonso

/s/ MARJORIE BOWEN	Director	March 28, 2016
Marjorie Bowen

/s/ CAROLYN J. BURKE	Director	March 28, 2016
Carolyn J. Burke

/s/ JULIUS COX	Director	March 28, 2016
Julius Cox

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ILLINOIS POWER GENERATING COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



		Page
Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm		F-2
Report of Independent Registered Public Accounting Firm		F-3
Consolidated Balance Sheets:
December 31, 2015 and 2014		F-4
Consolidated Statements of Operations:
For the years ended December 31, 2015, 2014 and 2013		F-5
Consolidated Statements of Comprehensive Income (Loss):
For the years ended December 31, 2015, 2014 and 2013		F-6
Consolidated Statements of Cash Flows:
For the years ended December 31, 2015, 2014 and 2013		F-7
Consolidated Statements of Changes in Stockholder’s Equity:
For the years ended December 31, 2015, 2014 and 2013		F-8
Notes to Consolidated Financial Statements		F-9

F-1

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholder

Illinois Power Generating Company:

We have audited the accompanying consolidated balance sheets of Illinois Power Generating Company (the Company) as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income (loss), changes in stockholder’s equity and cash flows for each of the two years in the period ended December 31, 2015. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements 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. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Illinois Power Generating Company at December 31, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the two years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Houston, Texas

March 28, 2016

F-2

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder

of Illinois Power Generating Company:

In our opinion, the consolidated statement of operations, comprehensive income (loss), changes in shareholder’s equity and cash flows for the year ended December 31, 2013 present fairly, in all material respects, the results of operations and cash flows of Illinois Power Generating Company and its subsidiaries for the year ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 28, 2014

F-3

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Item 1—FINANCIAL STATEMENTS

ILLINOIS POWER GENERATING COMPANY CONSOLIDATED BALANCE SHEETS (in millions, except share data)

	December 31,
	2015			2014
ASSETS
Current Assets
Cash	$	61		$	126
Accounts receivable, affiliates	54			88
Accounts receivable	8			14
Inventory	133			82
Deferred income taxes	—			5
Prepayments and other current assets	7			11
Total Current Assets	263			326

Property, Plant and Equipment	1,750			3,016
Accumulated depreciation	(813		)	(1,145		)
Property, Plant and Equipment, Net	937			1,871
Other Assets	30			24
Total Assets	$	1,230		$	2,221
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	26		$	39
Accounts payable, affiliates	18			13
Taxes accrued	10			11
Accrued interest	10			10
Accrued liabilities and other current liabilities	9			10
Total Current Liabilities	73			83
Long-term debt	824			824
Other Liabilities
Deferred income taxes, net	119			498
Asset retirement obligations	49			90
Other long-term liabilities	24			30
Total Liabilities	1,089			1,525
Commitments and Contingencies (Note 13)

Stockholder’s Equity
Common stock, no par value, 10,000 shares authorized 2,000 shares outstanding	—			—
Additional paid-in capital	542			540
Accumulated other comprehensive loss, net of tax	(10		)	(16		)
Retained earnings	(396		)	166
Total Illinois Power Generating Company Stockholder’s Equity	136			690
Noncontrolling interest	5			6
Total Equity	141			696
Total Liabilities and Equity	$	1,230		$	2,221

See the notes to consolidated financial statements.

F-4

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ILLINOIS POWER GENERATING COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions)



	Year Ended December 31,
	2015			2014			2013
Revenues	$	534		$	648		$	811
Cost of sales, excluding depreciation expense	(333		)	(447		)	(607		)
Gross margin	201			201			204
Operating and maintenance expense	(162		)	(158		)	(138		)
Impairment	(855		)	—			(199		)
Depreciation and amortization expense	(86		)	(100		)	(80		)
Operating loss	(902		)	(57		)	(213		)
Interest expense	(39		)	(40		)	(42		)
Other income and expense, net	—			—			1
Loss before income taxes	(941		)	(97		)	(254		)
Income tax benefit	378			49			65
Net loss	(563		)	(48		)	(189		)
Less: Net income (loss) attributable to noncontrolling interest	(1		)	2			(1		)
Net loss attributable to Illinois Power Generating Company	$	(562	)	$	(50	)	$	(188	)

See the notes to consolidated financial statements.

F-5

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ILLINOIS POWER GENERATING COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in millions)



	Year Ended December 31,
	2015			2014			2013
Net loss	$	(563	)	$	(48	)	$	(189	)
Other comprehensive income (loss) before reclassifications:
Actuarial gain (loss) due to pension plan remeasurement (net of tax benefit (expense) of $3, ($10) and ($26), respectively)	6			(11		)	15
AER Acquisition (net of tax expense of zero, zero and $20 respectively)	—			—			28
Amounts reclassified from accumulated other comprehensive income (loss):
Reclassification of mark-to-market losses to earnings on interest rate swaps designated as cash flow hedges (net of tax benefit of zero, zero and zero, respectively)	1			1			1
Settlement loss on pension plan (net of tax benefit of zero, zero and zero, respectively)	—			2			—
Reclassification of curtailment gain included in net loss (net of tax benefit of zero, zero and $10, respectively)	—			—			(16		)
Amortization of unrecognized prior service credit and actuarial gain (loss) (net of tax expense of zero, $1 and $2, respectively)	(1		)	—			1
Other comprehensive income (loss), net of tax	6			(8		)	29
Comprehensive loss	(557		)	(56		)	(160		)
Less: Comprehensive loss attributable to noncontrolling interest	—			(1		)	(1		)
Total comprehensive loss attributable to Illinois Power Generating Company	$	(557	)	$	(55	)	$	(159	)

See the notes to consolidated financial statements.

F-6

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ILLINOIS POWER GENERATING COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)



	Year Ended December 31,
	2015			2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(563	)	$	(48	)	$	(189	)
Adjustments to reconcile net loss to net cash flows from operating activities:
Impairment	855			—			199
Curtailment gain on pension and postretirement benefits	—			—			(26		)
Risk management activities	—			—			(7		)
Depreciation and amortization expense	86			100			80
Deferred income taxes and investment tax credits, net	(378		)	(48		)	(1		)
Other	10			6			—
Changes in working capital:
Accounts receivable, net	40			(27		)	6
Inventory	(51		)	(1		)	15
Accounts payable and accrued liabilities	(7		)	8			(14		)
Other	1			(6		)	(12		)
Net cash provided by (used in) operating activities	(7		)	(16		)	51
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(58		)	(48		)	(55		)
Proceeds from sales of properties	—			—			138
Money pool advances, net	—			—			27
Net cash provided by (used in) investing activities	(58		)	(48		)	110
CASH FLOWS FROM FINANCING ACTIVITIES:
Capital contribution from parent	—			—			4
Net cash provided by financing activities	—			—			4
Net increase (decrease) in cash	(65		)	(64		)	165
Cash, beginning of period	126			190			25
Cash, end of period	$	61		$	126		$	190

See the notes to consolidated financial statements.

F-7

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ILLINOIS POWER GENERATING COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER’S EQUITY

(in millions)



	Common Stock		Additional Paid-In Capital			Retained Earnings			AOCI (Loss)			Total Controlling Interests			Non-controlling Interest			Total
December 31, 2012	$	—	$	656		$	404		$	(40	)	$	1,020		$	8		$	1,028
Capital contribution from former parent	—		76			—			—			76			—			76
Adjustments to tax NOLs and other attributes from acquisition	—		(178		)	—			—			(178		)	—			(178		)
Other paid-in capital	—		(3		)	—			—			(3		)	—			(3		)
Net loss	—		—			(188		)	—			(188		)	(1		)	(189		)
Other comprehensive income, net of tax	—		—			—			29			29			—			29
December 31, 2013	—		551			216			(11		)	756			7			763
Adjustments to tax NOLs and other attributes from acquisition	—		(6		)	—			—			(6		)	—			(6		)
Amounts due to parent under tax sharing agreement	—		(5		)	—			—			(5		)	—			(5		)
Net income (loss)	—		—			(50		)	—			(50		)	2			(48		)
Other comprehensive loss, net of tax	—		—			—			(5		)	(5		)	(3		)	(8		)
December 31, 2014	—		540			166			(16		)	690			6			696
Amounts due to parent under tax sharing agreement	—		2			—			—			2			—			2
Net loss	—		—			(562		)	—			(561		)	(1		)	(563		)
Other comprehensive income, net of tax	—		—			—			6			6			—			6
December 31, 2015	$	—	$	542		$	(396	)	$	(10	)	$	137		$	5		$	141

See the notes to consolidated financial statements.

F-8

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ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Operations

We are an electric generation subsidiary of Illinois Power Resources, LLC (“IPR”), which is an indirect wholly-owned subsidiary of Dynegy Inc. (“Dynegy”). Unless the context indicates otherwise, throughout this report, the terms “Genco,” “the Company,” “we,” “us,” “our,” and “ours” are used to refer to Illinois Power Generating Company and its direct and indirect subsidiaries. We are headquartered in Houston, Texas and were incorporated in Illinois in March 2000. We own and operate a merchant generation business in Illinois and have an 80 percent ownership interest in Electric Energy, Inc. (“EEI”). EEI operates merchant electric generation facilities and FERC-regulated transmission facilities in Illinois and Kentucky. We also consolidate our wholly-owned subsidiary, Coffeen and Western Railroad Company, for financial reporting purposes.

On December 2, 2013 (the “Acquisition Date”), we were acquired indirectly by IPH, an indirect wholly-owned subsidiary of Dynegy. On the Acquisition Date, pursuant to the terms of the definitive agreement dated as of March 14, 2013 and as amended on the Acquisition Date (the “AER Transaction Agreement”) by and between IPH and Ameren Corporation (“Ameren”), IPH completed its acquisition from Ameren of 100 percent of the equity interests of New Ameren Energy Resources, LLC (“New AER”) and its subsidiaries (the “AER Acquisition”). “Push-down accounting” was not applied as a result of the AER Acquisition, which would require the adjustment of the assets and liabilities to fair value recognized by Dynegy to be shown in our consolidated financial statements.

Note 2—Summary of Significant Accounting Policies

Principles of Consolidation and Basis of Presentation. The accompanying consolidated financial statements include our accounts and the accounts of our majority-owned or controlled subsidiaries. Intercompany accounts and transactions have been eliminated. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. Certain prior period amounts in our consolidated statements of operations have been reclassified to conform to current year presentation. Accounting policies for all of our operations are in accordance with accounting principles generally accepted in the United States of America.

Noncontrolling Interest. Noncontrolling interest is comprised of the 20 percent of EEI we do not own. This noncontrolling interest is classified as a component of equity separate from our equity in our consolidated balance sheets.

Use of Estimates. The preparation of consolidated financial statements in conformity with Generally Accepted Accounting Principles (“GAAP”) requires management to make informed estimates and judgments that affect our reported financial position and results of operations based on currently available information. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (i) developing fair value assumptions, including estimates of future cash flows and discount rates, (ii) analyzing tangible assets for possible impairment, (iii) estimating the useful lives of our assets and Asset Retirement Obligations (“AROs”), (iv) assessing future tax exposure and the realization of deferred tax assets, (v) determining amounts to accrue for contingencies, guarantees and indemnifications and (vi) estimating various factors used to value our pension assets and liabilities. Actual results could differ materially from our estimates.

Inventory. Our commodity and materials and supplies inventories are carried at the lower of weighted average cost and net realizable value (“NRV”).

Property, Plant and Equipment. Property, plant and equipment, which consist principally of power generating facilities, including capitalized interest, is generally recorded at historical cost. Expenditures for major installations, replacements, and improvements or betterments are capitalized and depreciated over the expected life cycle. Expenditures for maintenance, repairs and minor renewals to maintain the operating condition of our assets are expensed. Depreciation is provided using the straight-line method over the estimated economic service lives of the assets, ranging from 2 to 30 years.

F-9

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The estimated economic service lives of our asset groups are as follows:



Asset Group		Range of Years
Power generation		3 to 30
Buildings and improvements		2 to 30
Office and other equipment		3 to 20

Impairment of Long-lived Assets. We evaluate long-lived assets classified as held and used for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we recognize an impairment charge equal to the amount of the carrying value that exceeds the estimated fair value of the assets. In the period in which we determine an asset meets held for sale criteria, we record an impairment charge to the extent the carrying value exceeds its fair value less cost to sell. Please read Note 3—Impairments for further discussion.

Asset Retirement Obligations. We record the present value of our legal obligations to retire tangible, long-lived assets on our balance sheets as liabilities when the liability is incurred. Our AROs relate to activities such as Coal Combustion Residuals (“CCR”) surface impoundment and landfill closure, dismantlement of power generation facilities, future removal of asbestos containing material from certain power generation facilities, closure and post-closure costs, environmental testing, remediation, monitoring and land obligations. In subsequent periods, we make upward or downward revisions to AROs in accordance with GAAP. Corresponding increases in asset book values are depreciated over the remaining useful life of the related asset. Uncertainties as to the probability, timing, or amount of cash flows associated with AROs affect our estimates of fair value. Accretion expense is included in Operating and maintenance expense on our consolidated statements of operations.

The following table provides a reconciliation of the beginning and ending carrying amounts of AROs for the year ended December 31, 2015:



(amounts in millions)
Balance at December 31, 2013	$	43
Accretion expense	3
Revision of previous estimate (1)	44
Balance at December 31, 2014	90
Accretion expense	9
Revision of previous estimate (2)	(50		)
Balance at December 31, 2015	$	49

__________________________________________


(1)	During 2014, we revised our ARO upward by $44 million based on observed trends in Illinois primarily related to CCR surface impoundment closures, groundwater monitoring and updated cost estimates for asbestos in accordance with the standards used in the industry.


(2)	During 2015, we revised our ARO downward by $50 million based on management’s review and assessment of CCR compliance timing and site specific analysis.

F-10

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Contingencies, Commitments, Guarantees and Indemnifications. We are involved in numerous lawsuits, claims, proceedings and tax-related audits in the normal course of our operations. We record a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We review our loss contingencies on an ongoing basis to ensure that we have appropriate reserves recorded on our consolidated balance sheets. These reserves are based on estimates and judgments made by management with respect to the likely outcome of these matters, including any applicable insurance coverage for litigation matters, and are adjusted as circumstances warrant. Liabilities for environmental contingencies are recorded when an environmental assessment indicates that remedial efforts are probable and the costs can be reasonably estimated. Measurement of liabilities is based, in part, on relevant past experience, currently enacted laws and regulations, existing technology, site-specific costs and cost-sharing arrangements. Recognition of any joint and several liability is based upon our best estimate of our final pro-rata share of such liability.

Operating Revenue. Revenue is earned from the facilities based on generation for the sale of energy and the sale of capacity. Operating revenue for electric service is recorded based on net generation in accordance with our PSAs with Illinois Power Marketing Company (“IPM”). Revenue is recognized when the product or service is delivered to a customer, unless they meet the definition of a derivative.

Fair Value Measurements. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Our estimate of fair value reflects the impact of credit risk. We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs are classified as readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the classification of the inputs used to calculate the fair value of a transaction. The inputs used to measure fair value have been placed in a hierarchy based on priority.

The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

•

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.

•

Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using industry-standards models or other valuation methodologies, in which substantially all assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over the counter forwards, options and swaps.

•

Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to our needs. At each balance sheet date, we perform an analysis of all instruments and include in Level 3 all of those whose fair value is based on significant unobservable inputs.

The determination of fair value incorporates various factors. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities. Valuation adjustments are generally based on capital market implied ratings evidence when assessing the credit standing of our counterparties and when applicable, adjusted based on management’s estimates of assumptions market participants would use in determining fair value.

Income Taxes. Upon the AER Acquisition, we were acquired in a transaction that resulted in an “ownership change,” as defined under IRC Section 382. Prior to the AER Acquisition, we were included in the consolidated federal and state income tax returns of Ameren Corporation. Genco and Ameren Corporation were parties to a tax sharing agreement that provided that the amount of tax recognized is similar to that which would have been owed had we been separately subject to tax.

Upon the closing of the AER Acquisition, we are included in the consolidated federal and state returns of Dynegy. Genco and Dynegy entered into a tax sharing agreement effective December 2, 2013, which was amended and restated as of December 31, 2014. Under the terms of the new tax sharing agreement, we recognize taxes based on a separate company income tax return basis and settle taxes with Dynegy at the discretion of either Dynegy’s or Genco’s management, as defined in the agreement.

F-11

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As a result of the AER Acquisition, we are under IRC Section 382, and are subject to a limitation in the amount of net operating losses (“NOLs”) that could be used in any one year following this ownership change. Further, we are subject to a worthless stock loss deduction equal to Ameren’s tax basis in our stock prior to the AER Acquisition. Accordingly, we determined that our pre-acquisition NOLs are unlikely to be used against future taxable income and the estimated benefits therefrom have been written down to zero. Please read Note 12—Income Taxes for further discussion.

We use an asset and liability approach for our financial accounting and reporting of income taxes, in accordance with authoritative accounting guidance. Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and income tax return purposes. These deferred tax assets and liabilities are based on statutory tax rates.

Employee Separation and Other Charges. Employee separation programs were initiated as a result of the AER Acquisition to reduce positions under terms and benefits consistent with our former parent Ameren’s standard management separation program. We recorded pretax charges related to these programs of less than $1 million, and $3 million for the years ended December 31, 2014 and 2013, respectively. These charges were recorded in Operating and maintenance expense on the consolidated statements of operations. There were no charges incurred in 2015, and we do not expect to pay out severance benefits in 2016.

Accounting Standards Adopted

Income Taxes. In November 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-17-Income Taxes (Topic 740). The amendment in this ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations will be required to classify all deferred tax assets and liabilities as noncurrent. The guidance in this ASU is effective for public entities for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted for all entities as of the beginning of an interim or annual reporting period. The ASU may be applied prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We adopted ASU 2015-17 as of December 31, 2015 and applied the guidance prospectively with no change to prior period amounts disclosed in our consolidated balance sheets and related notes to the consolidated financial statements. Please read Note 12—Income Taxes for further details.

Derivatives. In August 2015, the FASB issued Accounting Standards Update ASU 2015-13-Derivatives and Hedging (Topic 815). The amendments in this ASU specify that the use of locational marginal pricing by an ISO does not constitute net settlement of a contract for the purchase or sale of electricity on a forward basis and, therefore, does not cause that contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. If the physical delivery criterion is met, along with all of the other criteria of the normal purchases and normal sales scope exception, an entity may elect to designate that contract as a normal purchase or normal sale. The amendments in this ASU are effective upon issuance and should be applied prospectively. The adoption of this ASU did not have a material impact on our consolidated financial statements.

Inventory. In July 2015, the FASB issued ASU 2015-11-Inventory (Topic 330). The amendments in this ASU require that inventory is measured at the lower of cost and NRV, with the latter defined as the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. This ASU eliminates the need to determine market or replacement cost and evaluate whether it is above the ceiling at NRV or below the floor (NRV less a normal profit margin). The guidance in this ASU is effective prospectively for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We adopted ASU 2015-11 as of July 1, 2015. The adoption of this ASU did not have a material impact on our consolidated financial statements.

Retirement Benefits. In April 2015, the FASB issued ASU 2015-04-Compensation-Retirement Benefits (Topic 715). For an entity that has a significant event in an interim period that calls for a remeasurement of defined benefit plan or post retirement plan assets and obligations, the amendments in this Update provide a practical expedient that permits the entity to remeasure the plan assets and obligations using the month-end that is closest to the date of the significant event. The month-end remeasurement of defined benefit plan assets and obligations that is closest to the date of the significant event should be adjusted for any effects of the significant event that may or may not be captured in the month-end measurement. An entity is required to disclose the accounting policy election and the date used to measure defined benefit plan assets and obligations in accordance with the amendments in this Update. The amendments in this Update are effective for public business entities for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption allowed. The amendments in this Update should be applied prospectively. We adopted the guidance in this ASU on July 1, 2015. The adoption of this ASU did not have a material impact on our consolidated financial statements.

Reporting Discontinued Operations and Asset Disposals. In April 2014, the FASB issued ASU 2014-08-Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosure of Disposals of Components of an Entity. The amendments in this ASU change the requirements for reporting

F-12

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

discontinued operations in Subtopic 205-20. An entity is required to report within discontinued operations on the statement of operations the results of a component or group of components of an entity if the disposal represents a strategic shift that has, or will have, a major effect on an entity’s operations and financial results. Additionally, the associated assets and liabilities are required to be presented separately from other assets and liabilities on the balance sheet for all comparative periods. The ASU includes updated guidance regarding what meets the definition of a component of an entity. The new financial statement presentation provisions relating to this ASU are prospective and effective for interim and annual periods beginning after December 15, 2014, with early adoption permitted. We adopted the guidance in this ASU on January 1, 2015. The adoption of this ASU did not have a material impact on our financial statements or disclosures.

Accounting Standards Not Yet Adopted

Leases. In February 2016, the FASB issued ASU 2016-02-Leases (Topic 842). The amendments in this ASU will mainly require lessees to recognize lease assets and lease liabilities, for those leases classified as operating leases under GAAP, in their balance sheet. The lease assets recognized in the balance sheet will represent a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The lease liability recognized in the balance sheet will represent the lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our consolidated financial statements.

Debt Issuance Costs. In April 2015, the FASB issued ASU 2015-03-Interest-Imputation of Interest (Subtopic 835-30). The amendments in this ASU require 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 recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update.

In August 2015, the FASB issued ASU 2015-15-Interest-Imputation of Interest (Subtopic 835-30). The amendments in this ASU further clarify the guidance provided in ASU 2015-03 to include the presentation of debt issuance costs in relation to line-of-credit arrangements. The amendments state these costs may be presented as an asset and subsequently amortized ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement.

The guidance in these ASUs is effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted. The adoption of these ASUs should be applied on a retrospective basis, affecting all balance sheet periods presented. We do not anticipate the adoption of these ASUs will have a material impact on our consolidated balance sheets.

Extraordinary and Unusual Items. In January 2015, the FASB issued ASU 2015-01-Income Statement-Extraordinary and Unusual Items (Subtopic 225-20). The amendments in this ASU eliminate from GAAP the concept of extraordinary items and will no longer require separate classification of these items within the statement of operations. Presentation and disclosure guidance for items that are unusual in nature or occur infrequently will be retained and will be expanded to include items that are both unusual in nature and infrequently occurring. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Reporting entities may elect to apply the amendments prospectively only, or retrospectively for all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. We do not anticipate the adoption of this ASU will have a material impact on our consolidated financial statements.

Going Concern. In August 2014, the FASB issued ASU 2014-15-Presentation of Financial Statements - Going Concern (Subtopic 205-40). The amendments in this ASU requires management, in connection with preparing financial statements for each annual and interim reporting period, to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued (or within one year after the date that the financial statements are available to be issued when applicable). Currently, there is no guidance in GAAP about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern or to provide related footnote disclosures. The amendments in this ASU provide that guidance. In doing so, the amendments should reduce diversity in the timing and content of footnote disclosures. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We currently do not anticipate the adoption of this ASU will have a material impact on our consolidated financial statements.

Revenue from Contracts with Customers. In May 2014, the FASB and International Accounting Standards Board jointly issued ASU 2014-09-Revenue from Contracts with Customers (Topic 606). This ASU was further updated through the issuance of ASU 2015-14 in August 2015. The amendments in this ASU develop a common revenue standard for GAAP and International Financial Reporting Standards by removing inconsistencies and weaknesses in revenue requirements, providing a more robust framework for addressing revenue issues, improving comparability of revenue recognition practices, providing more useful

F-13

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

information to users of financial statements and simplifying the preparation of financial statements. The guidance in this ASU is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted for interim and annual periods beginning after December 15, 2016. We are currently assessing this ASU; however, we do not anticipate the adoption of this ASU will have a material impact on our consolidated financial statements.

Note 3—Impairments

2015 Coffeen Impairment

During the third quarter of 2015, several environmental regulations were adopted which will have an impact on our coal-fired power generation facilities. As a result of these regulations, we performed a strategic review of our assets which incorporated the costs of these regulations, and incorporated a reduced long-term market outlook, caused by MISO’s poorly designed wholesale capacity market. The analysis indicated that the book value of the Coffeen facility was not recoverable, requiring the facility to be impaired. We conducted a held and used discounted cash flow model of the facility to determine its fair value. For the model, gross margin was based on publicly available forward market quotes for the first two years and internally developed prices thereafter, operations and maintenance expenses and capital expenditures were based on current forecasts and used a plant-specific discount rate of approximately 15%. The model resulted in a fair value of zero for the plant, requiring us to record an impairment charge of $855 million during the third quarter of 2015.

2013 Gas-fired Facilities Impairment

In October 2013, we divested our Elgin, Gibson City and Grand Tower gas-fired facilities (the “Gas-Fired Facilities”) to Ameren Energy Medina Valley Cogen LLC (“Medina Valley”), an affiliate of Ameren Energy Resources Company, LLC (“AER”) that IPH did not acquire in the AER Acquisition, under a put option agreement that was assumed by Medina Valley and exercised by us in March 2013 (the “Put Option”). We recorded a pretax charge to earnings of $199 million for 2013, to reflect the impairment of the Gas-Fired Facilities under the held for sale model. Fair value was based on the actual sales price of $138 million realized upon sale of the Gas-Fired Facilities to Medina Valley in October 2013.

The 2013 impairment recorded was primarily related to the Gibson City and Grand Tower Gas-Fired Facilities as the Elgin facility was previously impaired during the year ended December 31, 2012. The impairment charges were recorded in Impairment on our consolidated statements of operations for the year ended December 31, 2013. The impairment charges did not result in a violation of our debt covenants or counterparty agreements. These assets and liabilities held for sale were measured at fair value on a nonrecurring basis, based on the cash proceeds of $138 million, which is an input classified as Level 3 within the fair value hierarchy.

Key assumptions used in the determination of estimated undiscounted cash flows of our long-lived assets tested for impairment under a held and used model included forward price projections for energy and fuel costs, the expected life or duration of ownership of the long-lived assets, environmental compliance costs and strategies and operating costs. These assumptions are subject to a high degree of judgment and complexity. In comparison, impairment analysis under the held for sale model involves only comparison of the carrying cost of the asset group to the asset group’s estimated fair value less cost to sell and recording an impairment charge for any excess of that carrying value over the estimated fair value less cost to sell. We assess impairment at the lowest level of identifiable cash flows.

Note 4—Derivative Financial Instruments

There are no derivative instruments as of December 31, 2015 and 2014.

Impact of Derivatives on the Consolidated Statements of Operations

The cumulative amount of pretax net losses on interest rate derivative instruments in accumulated other comprehensive income (“AOCI”) was $4 million, $5 million and $6 million as of December 31, 2015, 2014 and 2013, respectively. These interest rate swaps were executed in 2007 and designated as a cash flow hedge of interest rate risks associated with our April 2008 debt issuance. The loss on the interest rate swaps is being amortized over a 10-year period that began in April 2008, $1.4 million of which was amortized in 2015.

Financial Instruments Not Designated as Hedges. There was no material impact of mark-to-market gains (losses) on our consolidated statements of operations for the years ended December 31, 2015 and 2014. Revenues on our consolidated statements of operations for the year ended December 31, 2013 included mark-to-market gains of $7 million related to commodity derivatives.

F-14

Note 5—Fair Value Measurements

Non-recurring Measurements. We recorded impairment charges in our 2015 and 2013 statements of operations of $855 million and $199 million, respectively, related to long-lived assets using fair value techniques. Please read Note 3—Impairments for further details. The valuation methods used to determine the impairment charges were classified as Level 3 within the fair value hierarchy levels.

Fair Value of Financial Instruments. We have determined estimated fair value amounts using available market information and selected valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies could have a material effect on the estimated fair value amounts.

The carrying values of financial assets and liabilities (cash, accounts receivable, restricted cash and accounts payable) not presented in the table below approximate fair values due to the short-term maturities of these instruments. Unless otherwise noted, the fair value of debt as reflected in the table has been calculated based on the average of certain available broker quotes as of December 31, 2015 and 2014, respectively. All fair values presented below are classified within Level 2 of the fair value hierarchy.



	December 31, 2015				December 31, 2014
(amounts in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
7.00% Senior Notes Series H, due 2018	$	300	$	204	$	300	$	264
6.30% Senior Notes Series I, due 2020	$	250	$	148	$	250	$	208
7.95% Senior Notes Series F, due 2032 (1)	$	274	$	162	$	274	$	241

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(1)	Carrying amount includes unamortized discount of $1 million as of December 31, 2015 and 2014. Please read Note 10—Debt for further discussion.

Note 6—Accumulated Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive income (loss), net of tax, by component are as follows:



	Year Ended December 31,
(amounts in millions)	2015			2014			2013
Beginning of period	$	(16	)	$	(11	)	$	(40	)
Other comprehensive income (loss) before reclassifications:
Actuarial gain (loss) and plan amendments (net of tax benefit (expense) of $3, $4, and ($8), respectively)	6			(8		)	12
Amounts reclassified from accumulated other comprehensive income (loss):
Reclassification of mark-to-market losses to earnings on interest rate swaps designated as cash flow hedges, net (net of tax benefit of zero, zero and zero, respectively) (1)	1			1			1
Settlement loss on pension plan (net of tax benefit of zero, zero and zero, respectively) (2)	—			2			—
Amortization of unrecognized prior service credit and actuarial loss (net of tax expense of zero, zero, and $1, respectively) (3)	(1		)	—			1
Reclassification of curtailment gain included in net loss (net of tax benefit of zero, zero, and $9, respectively) (4)	—			—			(13		)
Net current period other comprehensive income (loss), net of tax	6			(5		)	1
AER Acquisition (net of tax expense of zero, zero, and $20, respectively) (5)	—			—			28
End of period	$	(10	)	$	(16	)	$	(11	)

__________________________________________


(1)	Amount related to the reclassification of mark-to-market loss on cash flow hedging activities, net and was recorded in Interest expense on our consolidated statements of operations. Please read Note 4—Derivative Financial Instruments for further discussion.


(2)	Amount related to the settlement loss on the EEI pension plan and is included in the computation of total benefit cost (gain). Please read Note 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion.

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ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


(3)	Amounts are associated with our defined benefit pension and other post-retirement benefit plans and are included in the computation of net periodic benefit cost (gain). Please read Note 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion.


(4)	Amount related to the EEI curtailment gain on pension and postretirement benefit plans and was recorded in Operating and maintenance expense in our consolidated statements of operations. Please read Note 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion.


(5)	Amount related to the transfer of certain defined benefit pension and other postretirement benefit plans as a part of the AER Acquisition. Please read Note 14—Savings and Pension and Other Post-Retirement Benefit Plans for further discussion.

Note 7—Cash Flow Information

Following are supplemental disclosures of cash flow and non-cash investing and financing information:



	Year Ended December 31,
(amounts in millions)	2015		2014		2013
Interest paid (net of amount capitalized)	$	37	$	39	$	41
Income taxes, net	$	—	$	—	$	(65	)
Other non-cash investing and financing activity:
Non-cash capital expenditures (1)	$	—	$	3	$	3
Capital contributions from parent	$	—	$	—	$	72

__________________________________________


(1)	These expenditures are primarily for changes in our accruals of capital expenditures for all years presented.

Note 8—Inventory

A summary of our inventories is as follows:



	December 31,
(amounts in millions)	2015		2014
Materials and supplies	$	30	$	30
Coal	102		51
Fuel oil	1		1
Total	$	133	$	82

Note 9—Property, Plant and Equipment

A summary of our property, plant and equipment is as follows:



	December 31,
(amounts in millions)	2015			2014
Power generation	$	1,511		$	2,710
Building and improvements	212			276
Office and other equipment	27			30
Property, plant and equipment	$	1,750		$	3,016
Less: Accumulated depreciation and amortization	(813		)	(1,145		)
Property, plant and equipment, net	$	937		$	1,871

During the third quarter of 2015, we recorded an impairment charge to our Coffeen facility of $855 million. For more information see Note 3—Impairments.

The following table summarizes total interest costs incurred and interest capitalized related to costs of construction projects in process:

F-16

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)



	Year Ended December 31,
(amounts in millions)	2015		2014		2013
Total interest costs incurred	$	59	$	59	$	60
Capitalized interest	$	22	$	20	$	18

Note 10—Debt

A summary of our long-term debt is as follows:



	December 31,
(amounts in millions)	2015			2014
Unsecured notes:
7.00% Senior Notes Series H, due 2018	$	300		$	300
6.30% Senior Notes Series I, due 2020	250			250
7.95% Senior Notes Series F, due 2032	275			275
	825			825
Unamortized discount	(1		)	(1		)
Total long-term debt	$	824		$	824

Aggregate maturities of the principal amounts of all long-term indebtedness, excluding unamortized discounts, as of December 31, 2015 are as follows: 2016—zero, 2017—zero, 2018—$300 million, 2019—zero, 2020—$250 million and thereafter—$275 million.

Indenture Provisions and Other Covenants

Certain of our financial obligations and all of our senior notes include provisions which, if not met, could require early payment, additional collateral support or similar actions. The trigger events include the violation of covenants, defaults on scheduled principal or interest payments, including any indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions, insolvency events and acceleration of other financial obligations. At December 31, 2015, we were in compliance with the provisions and covenants contained within our indenture. Our indenture also includes provisions that require us to maintain certain interest coverage and debt-to-capital ratios in order for us to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third-party indebtedness. The following table summarizes these required ratios:



		Required Ratio
Restricted payment interest coverage ratio (1)		≥1.75
Additional indebtedness interest coverage ratio (2)		≥2.50
Additional indebtedness debt-to-capital ratio (2)		≤60%

_______________________________________


(1)	As of the date of the restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods.


(2)	Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Other borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests.

As of December 31, 2015, we did not meet our debt incurrence-related ratios and therefore we are prohibited from incurring additional third-party indebtedness. Our required ratios under the indenture may be disregarded if both Moody’s and S&P reaffirm the ratings in place at the time of the debt incurrence after considering the additional indebtedness.

Our indenture provides that dividends cannot be paid unless the actual interest coverage ratio for our most recently ended four fiscal quarters and the interest coverage ratios projected by management for each of the subsequent four six-month periods are greater than a specified minimum level. Based on December 31, 2015 calculations, our interest coverage ratios are less than the minimum ratios required to pay dividends . As a result, we were restricted from paying dividends as of December 31, 2015.

In order for us to issue securities in the future, we will have to comply with all applicable requirements in effect at the time of any such issuances.

F-17

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 11—Related Party Transactions

We have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of power purchases and sales, services received or rendered, and borrowings and lendings. Below are the material related party agreements.

The following table summarizes the affiliate accounts receivable and payable on our consolidated balance sheets.



	December 31, 2015				December 31, 2014
(amounts in millions)	Accounts Receivable, Affiliates		Accounts Payable, Affiliates		Accounts Receivable, Affiliates		Accounts Payable, Affiliates
Power supply agreements	$	54	$	—	$	88	$	—
Services agreement	—		5		—		1
Tax sharing agreement	—		3		—		5
Other (1)	—		10		—		7
Total	$	54	$	18	$	88	$	13

__________________________________________


(1)	As of December 31, 2015, approximately $10 million of the accounts payable, affiliate balance is comprised of reimbursable employee benefits paid by a Dynegy subsidiary on behalf of Genco.

The following table presents the impact of related party transactions on our consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013.



		Year Ended December 31,
(amounts in millions)	Income Statement Line Item	2015		2014		2013
Power supply agreements	Revenues	$	530	$	646	$	709
Services provided to AER affiliates	Revenues	$	—	$	—	$	6
Ameren Missouri gas transportation agreement	Cost of sales	$	—	$	—	$	1
EEI power supply agreement	Cost of sales	$	—	$	—	$	66
Services agreement	Operating and maintenance expense	$	34	$	43	$	13

Power Supply Agreements

Genco has a PSA with Illinois Power Marketing Company (“IPM”), a subsidiary of IPR, whereby IPM purchases all of the capacity and energy available from Genco’s generation fleet. IPM entered into a similar PSA with Illinois Power Resources Generating, LLC (“IPRG”). Under the PSAs, IPM revenues are allocated between Genco and IPRG based on reimbursable expenses and generation of each entity. The reimbursable expenses used in the calculation of revenues allocated under the Genco and IPRG PSAs include operation costs in addition to depreciation and interest on debt. Each PSA will continue through December 31, 2022, and from year to year thereafter. Either party to the respective PSA may elect to terminate the PSA by providing the other party with no less than six months advance written notice.

Collateral Agreement

Genco has a collateral agreement with IPM pursuant to which IPM may require Genco to provide collateral to IPM to secure obligations of IPM applicable to Genco’s assets. The initial collateral limit for Genco is $15 million and IPM can demand an additional $7.5 million for a total limit not to exceed $22.5 million. There have been no amounts provided under this agreement to date.

F-18

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Services Agreements

Dynegy and certain of its subsidiaries (collectively, the “Providers”) provide certain services (the “Services”) to IPH, and certain of its consolidated subsidiaries (collectively, the “Recipients”), which includes us and EEI.

The Providers act as agents for the Recipients for the limited purpose of providing the Services set forth in the Services Agreements. Prior to the beginning of each fiscal year in which Services are to be provided pursuant to the Service Agreements, the Providers and the Recipients agree on a budget for the Services, outlining, among other items, the contemplated scope of the Services to be provided in the following fiscal year and the cost of providing the Services. The Recipients will pay the Providers an annual management fee as agreed in the budget. We believe this is a reasonable method of allocating the costs of the Services to us and provides an appropriate reflection of the costs we would have incurred if we operated as an unaffiliated entity.

Effective December 31, 2015, we amended the Services Agreement to provide payments to Dynegy for services incurred which may be deferred based on the liquidity of certain of IPH’s subsidiaries as of the current month’s end. Any deferred payments, and associated interest, will be reflected as an affiliate payable to be settled at the discretion of Dynegy or us. The amendment will be in place through 2016 and will be evaluated for extension in the fourth quarter of 2016.

Tax Sharing Agreement

We are included in the consolidated tax returns of Dynegy. Under U.S. federal income tax law, Dynegy files consolidated income tax returns for itself and its subsidiaries. Dynegy is responsible for the federal tax liabilities of its subsidiaries which include the income and business activities of the ring-fenced entities and Dynegy’s other affiliates. Genco and Dynegy entered into a tax sharing agreement on December 2, 2013 that provides that we recognize taxes based on a separate company income tax return basis, as defined in the agreement. The tax sharing arrangement was amended as of December 31, 2014 and provides that accumulated taxes payable to Dynegy, and any associated interest, be settled at the discretion of Dynegy or us.

Note 12—Income Taxes

Income Tax Benefit. We are subject to U.S. federal and state income taxes on our operations. Our loss before income taxes was $941 million, $97 million and $254 million for the years ended December 31, 2015, 2014 and 2013, respectively. The following table presents the principal reasons why the effective income tax rate differed from the statutory federal income tax rate:



	Year Ended December 31,
	2015		2014		2013
Statutory federal income tax rate:	35	%	35	%	35	%
Increases (decreases) from:
State tax	5		6		6
Acquisition adjustment (1)	—		9		(15	)
Effective income tax rate	40	%	50	%	26	%

_________________________________________


(1)	Acquisition adjustments relating to the impacts of the change in ownership under IRC Section 382 and other tax attribute reductions.

The following table presents the components of income tax benefit:



	Year Ended December 31,
(amounts in millions)	2015		2014		2013
Current taxes:
Federal	$	—	$	1	$	50
State	—		—		14
Deferred taxes:
Federal	305		39		(6		)
State	73		9		6
Deferred investment tax credits, amortization	—		—		1
Total income tax benefit	$	378	$	49	$	65

F-19

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The Illinois corporate income tax rate decreased from 9.5 percent to 7.75 percent in 2015, and it is scheduled to return to 7.3 percent in 2025.

The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary differences:



	December 31,
(amounts in millions)	2015			2014
Accumulated deferred income taxes, net liability (asset):
Plant related	$	167		$	551
Deferred employee benefit costs	(1		)	(6		)
ARO	(15		)	(36		)
NOLs	(25		)	(7		)
Other	(7		)	(9		)
Total net accumulated deferred income tax liabilities	$	119		$	493

Uncertain Tax Positions. A reconciliation of the change in the unrecognized tax benefit balance is as follows:



	Year Ended December 31,
(amounts in millions)	2015		2014		2013
Unrecognized tax benefits - beginning of year	$	—	$	—	$	6
Increases based on tax positions prior to current year	—		—		2
Decreases based on tax positions prior to current year	—		—		(3		)
Decreases based on tax positions related to current year	—		—		(1		)
Adjustment of balance due to change in ownership	—		—		(3		)
Decreases related to the lapse of statute of limitations	—		—		(1		)
Unrecognized tax benefits - end of year	$	—	$	—	$	—
Total unrecognized tax benefits (detriments) that, if recognized, would affect the effective tax rates	$	—	$	—	$	—

Interest charges (income) and penalties accrued on tax liabilities on a pretax basis are recognized as interest charges (income) or miscellaneous expense, respectively, in our consolidated statements of operations.

A reconciliation of the change in the liability for interest on unrecognized tax benefits is as follows:



	Year Ended December 31,
(amounts in millions)	2015		2014		2013
Liability for interest - beginning of year	$	—	$	—	$	1
Adjustment of balance due to change in ownership	—		—		(1		)
Liability for interest - end of year	$	—	$	—	$	—

As of December 31, 2015, 2014 and 2013, we accrued no amount for penalties with respect to unrecognized tax benefits.

Upon the closing of the AER Acquisition, we are included in the consolidated federal and state tax returns of Dynegy. Genco and Dynegy entered into a tax sharing agreement effective December 2, 2013, which was amended and restated as of December 31, 2014. Under the terms of the new tax sharing agreement, we recognize taxes based on a separate company income tax return basis and settle taxes with Dynegy at the discretion of either Dynegy’s or Genco’s management, as defined in the agreement. Genco’s tax payable of $3 million and $5 million for the years ended 2015 and 2014, respectively, has been recorded at the total amount due to Dynegy under its tax sharing agreement for all of its subsidiaries in accordance with ASC 740. The changes in Genco’s tax payable resulted in positive adjustment of $2 million and charge of $5 million to equity for the years ended 2015 and 2014, respectively.

As a result of the AER Acquisition, we are under IRC Section 382 and are subject to a limitation in the amount of NOLs that could be used in any one year following the ownership change. Further, we are subject to a worthless stock loss deduction equal to Ameren’s tax basis in our stock prior to the AER Acquisition. Accordingly, we determined that our pre-acquisition NOLs are unlikely to be used against future taxable income, and the estimated benefits therefrom have been written down to zero. We

F-20

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

have also recorded the effects of a reduction of other tax basis, totaling $425 million. The adjustments to our NOLs and tax attributes resulted in a charge to paid-in capital at the Acquisition Date of $6 million and $178 million for the years ended December 31, 2014 and 2013, respectively. We also increased our income tax benefit by $9 million for the year ended December 31, 2014 and reduced our income tax benefit by $39 million for the year ended December 31, 2013.

As of December 31, 2015, we had approximately $62 million of state NOLs and $62 million federal NOLs on a separate return basis that expire in 2034 and 2035. We are currently under federal audit for the 2014 tax period. State income tax returns are generally subject to examination for a period of three years after filing of the return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. As a result of the AER Acquisition, we are indemnified by Ameren for any federal or state tax adjustment for tax periods prior to December 2, 2013.

Note 13—Commitments and Contingencies

Legal Proceedings

Set forth below is a summary of our material ongoing legal proceedings. We record accruals for estimated losses from contingencies when available information indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, we disclose matters for which management believes a material loss is reasonably possible. In all instances, management has assessed the matters below based on current information and made judgments concerning their potential outcome, giving consideration to the nature of the claim, the amount, if any, and nature of damages sought and the probability of success. Management regularly reviews all new information with respect to such contingencies and adjusts its assessments and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties including unfavorable rulings or developments, it is possible that the ultimate resolution of our legal proceedings could involve amounts that are different from our currently recorded accruals and that such differences could be material.

In addition to the matters discussed below, we are party to other routine proceedings arising in the ordinary course of business. Any accruals or estimated losses related to these matters are not material. In management’s judgment, the ultimate resolution of these matters will not have a material effect on our financial condition, results of operations or cash flows.

Contingencies

MISO 2015-2016 Planning Resource Auction. In May 2015, three complaints were filed at FERC regarding the Zone 4 results for the 2015-2016 Planning Resource Auction (“PRA”) conducted by MISO. The Newton, Coffeen and Joppa facilities were offered into Zone 4 in the 2015-2016 PRA. The complainants, Public Citizen, Inc., the Illinois Attorney General, and Southwestern Electric Cooperative, Inc., have challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds and requested changes to the MISO PRA structure going forward. Complainants have also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the 2015-2016 PRA. The Independent Market Monitor for MISO (“MISO IMM”), which was responsible for monitoring the MISO 2015-2016 PRA, determined that all offers were competitive and that no physical or economic withholding occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the proposed remedies. Dynegy disputes the allegations and will defend its actions vigorously. Dynegy filed its Answer to these complaints. In addition, the Illinois Industrial Energy Consumers filed a complaint at FERC against MISO on June 30, 2015 requesting prospective changes to the MISO tariff. Dynegy also responded to this complaint.

On October 1, 2015, FERC issued an order of non-public, formal investigation, stating that shortly after the conclusion of the 2015-2016 PRA, FERC’s Office of Enforcement began a non-public informal investigation into whether market manipulation or other potential violations of FERC orders, rules and regulations occurred before or during the PRA (the “Order”). The Order noted that the investigation is ongoing, and that the order converting the informal, non-public investigation to a formal, non-public investigation does not indicate that FERC has determined that any entity has engaged in market manipulation or otherwise violated any FERC order, rule or regulation. Further, FERC held a Staff-led technical conference on October 20, 2015 to obtain further information concerning potential changes to the MISO PRA structure going forward, including on proposals made by complainants. The technical conference did not address the ongoing Office of Enforcement investigation.

F-21

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

not address the arguments of the complainants regarding the 2015-2016 Auction, and stated that those issues remain under consideration and will be addressed in a future order.

New Source Review and Clean Air Act Matters

New Source Review. Since 1999, the EPA has been engaged in a nationwide enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the New Source Review and New Source Performance Standard provisions under the Clean Air Act (“CAA”) when the plants implemented modifications. The EPA’s initiative focuses on whether projects performed at power plants triggered various permitting requirements, including the need to install pollution control equipment.

CAA Section 114 Information Requests. Commencing in 2005, we received a series of information requests from the EPA pursuant to Section 114(a) of the CAA. The requests sought detailed operating and maintenance history data with respect to the Coffeen, Newton and Joppa facilities. In August 2012, the EPA issued a Notice of Violation (“NOV”) alleging that projects performed in 1997, 2006 and 2007 at the Newton facility violated Prevention of Significant Deterioration, Title V permitting and other requirements. The NOV remains unresolved. We believe our defenses to the allegations described in the NOV are meritorious. A decision by the U.S. Court of Appeals for the Seventh Circuit in 2013 held that similar claims older than five years were barred by the statute of limitations. This decision may provide an additional defense to the allegations in the NOV.

Ultimate resolution of any of these CAA matters could have a material adverse impact on our future financial condition, results of operations and cash flows. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties. At this time we are unable to make a reasonable estimate of the possible costs, or range of costs, that might be incurred to resolve these matters.

Groundwater. Groundwater monitoring results indicate that the CCR surface impoundments at the Newton, Coffeen and Joppa facilities potentially impact onsite groundwater. In 2012, the Illinois EPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities’ CCR surface impoundments. In April 2015, we submitted an assessment monitoring report to the Illinois EPA concerning previously reported groundwater quality standard exceedances at the Newton facility’s active CCR landfill. The report identifies the Newton facility’s inactive unlined landfill as the likely source of the exceedances and recommends various measures to minimize the effects of that source on the groundwater monitoring results of the active landfill.

Commitments

In conducting our operations, we have routinely entered into long-term commodity purchase and sale commitments, as well as agreements that commit future cash flow to the lease or acquisition of assets used in our businesses. These commitments have been typically associated with commodity supply arrangements, capital projects, reservation charges associated with firm transmission, transportation, storage and leases for office space, equipment, design and construction, plant sites and power generation assets. The following describes the more significant commitments outstanding at December 31, 2015.

Coal Purchase Commitments. At December 31, 2015, we had contracts in place to purchase coal for our generation facilities with aggregate minimum commitments of $369 million. To the extent forecasted volumes have not been priced but are subject to a price collar structure, the obligations have been calculated using the minimum purchase price of the collar.

Coal Transportation. At December 31, 2015, we had coal transportation contracts and rail car leases in place for our generation facilities with aggregate minimum commitments of $407 million.

Environmental Compliance Obligations. We estimate costs, excluding capitalized interest, of approximately $186 million for the completion of scheduled milestones related to the installation of the Newton flue gas desulfurization (“FGD”) systems, such that the IPH fleet will comply with certain SO₂ emission limits approved in the variance granted by the IPCB in November 2013. Please read Business-Environmental Matters-IPH Variance for further details. The first milestone relating to engineering design was completed by July 2015, while the last milestone requires major equipment components being placed into final position on or before September 1, 2019. We are currently scheduled to complete the Newton FGD system project by the end of 2019 with minimal costs anticipated in 2020. Either party can terminate this contract based on certain events as specified in the contract. In February 2016, we issued a notice to the third party contractor constructing the FGD systems directing them to temporarily suspend a portion of the work being performed. We will assess the results of the MISO Planning Year 2016-2017 capacity auction to be held in April 2016, at which time we will reevaluate our suspension notice to the third party contractor constructing the FGD systems.

F-22

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Other Obligations. We have a facilities service agreement obligation of $4 million to maintain transmission system stability in connection with our Coffeen facility through 2039 and other miscellaneous items which are individually insignificant.

Indemnifications and Guarantees

In the ordinary course of business, we routinely enter into contractual agreements that contain various representations, warranties, indemnifications and guarantees. Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, asset sales agreements, and procurement and construction contracts. Some agreements contain indemnities that cover the other party’s negligence or limit the other party’s liability with respect to third party claims, in which event we will effectively be indemnifying the other party. Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false. While there is always the possibility of a loss related to such representations, warranties, indemnifications and guarantees in our contractual agreements, and such loss could be significant, management considers the probability of loss to be remote.

Guaranty Agreement. Genco has provided an uncapped Guaranty Agreement of certain credit support obligations and tax and environmental indemnification obligations of IPH under a transaction agreement with Ameren Corporation. Certain of the guaranteed obligations under the Guaranty Agreement will survive indefinitely.

Note 14—Savings and Pension and Other Post-Retirement Benefit Plans

Savings Plans

Effective December 2, 2013, our employees, excluding the EEI employees, participate in the Dynegy Inc. 401(k) Plan. The Ameren 401(k) plan covered all eligible employees, including our employees, prior to December 2, 2013, the date of the AER Acquisition. Prior to December 31, 2013, the EEI Bargaining Unit 401(k) Plan covered all eligible EEI union employees and the EEI Management 401(k) Plan covered all eligible EEI management employees. Effective January 1, 2014, these plan benefits were frozen and contributions stopped as of that date and EEI participants became eligible to participate in the Dynegy Inc. 401(k) Plan. These plan benefits were merged into the Dynegy Inc. 401(k) Plan on June 26, 2014. These 401(k) plans allowed employees to contribute a portion of their compensation in accordance with specific guidelines. The plan sponsor matched a percentage of the employee contributions up to certain limits. Our portion of the matching contribution to the Dynegy Inc. 401(k) Plan was $1 million, $1 million and zero for the years ended December 31, 2015, 2014 and the period from December 2, 2013 through December 31, 2013, respectively. Our portion of the matching contribution to the Ameren 401(k) plan was $1 million for the period from January 1 through December 1, 2013. The matching contribution to the EEI 401(k) plans was less than $1 million for the years ended December 31, 2015, 2014 and 2013.

Pension and Other Post-Employment Benefits

We offer defined benefit pension and postretirement benefit plans covering our employees. Effective December 2, 2013, our employees and retirees, excluding EEI employees and retirees, participate in Dynegy’s single-employer pension and other postretirement plans. Our employees and retirees, excluding EEI employees and retirees, participated in Ameren’s single-employer pension and other postretirement plans through December 1, 2013, prior to the AER Acquisition. Separately, our EEI employees and retirees participate in EEI’s single-employer pension and other postretirement plans. We consolidate EEI, and therefore, EEI’s plans are reflected in our pension and postretirement balances and disclosures. We use a measurement date of December 31 for our pension and postretirement benefit plans.

As a result of the AER Acquisition, Ameren retained the pension obligations associated with the current and former employees of Genco and the postretirement benefit obligations associated with the employees of Genco who were eligible to retire at December 2, 2013 with respect to such employees’ participation in Ameren’s single-employer pension and postretirement plans. Effective with the AER Acquisition, Dynegy assumed the postretirement benefit obligation for active union employees of New AER and its subsidiaries not eligible to retire based on the assumption of the collective bargaining agreements in place. Genco retained the pension and other postretirement benefit obligations associated with EEI’s current and former employees. As a result of the AER Acquisition, certain EEI employees were terminated which resulted in a curtailment gain of $26 million which was recorded in Operating and maintenance expense in our consolidated statements of operations.

In August 2015, we finalized certain new collective bargaining agreements that resulted in amendments to certain post-employment benefit plans. As a result of these amendments, we remeasured our benefit obligations and the funded status of the affected plans during the third quarter of 2015.

For our disclosures below, unless otherwise noted, we have reflected the obligations, plan assets and costs associated with EEI’s pension and postretirement plans. Also reflected is an allocation of our share of obligations, plan assets, and costs associated with our participation in Dynegy’s single-employer pension and postretirement plans on December 2, 2013 and thereafter

F-23

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

and Ameren’s single-employer pension and postretirement plans through December 1, 2013. The allocation of obligations, plan assets and costs from our participation in Dynegy’s and Ameren’s single-employer pension plan was based on our employees’ share of total pensionable salaries. The allocation of obligations, plan assets and costs from our participation in Dynegy’s and Ameren’s single-employer postretirement plans was based on the number of our employees.

Obligations and Funded Status. The following tables contain information about the obligations, plan assets and funded status of our pension and postretirement benefit plans as of December 31, 2015 and 2014. These amounts include the funded status of EEI’s pension and postretirement plans as well as an allocation of our share of obligation and plan assets associated with our participation in Dynegy’s and Ameren’s single-employer pension and postretirement plans.



	Pension Benefits						Other Benefits
	Year Ended December 31,						Year Ended December 31,
(amounts in millions)	2015			2014			2015			2014
Benefit obligation, beginning of the year	$	89		$	89		$	60		$	50
Service cost	3			3			1			1
Interest cost	3			4			2			2
Actuarial (gain) loss	(3		)	7			(6		)	11
Benefits paid	(8		)	(5		)	(3		)	(4		)
Plan change	—			—			(8		)	—
Settlements	—			(9		)	(1		)	—
Benefit obligation, end of the year	$	84		$	89		$	45		$	60
Fair value of plan assets, beginning of the year	$	70		$	75		$	68		$	67
Actual return on plan assets	(1		)	6			2			5
Employer contributions	4			3			—			—
Benefits paid	(8		)	(5		)	(3		)	(4		)
Settlements	—			(9		)	—			—
Fair value of plan assets, end of the year	$	65		$	70		$	67		$	68
Funded status	$	(19	)	$	(19	)	$	22		$	8

Our accumulated benefit obligation related to pension plans was $84 million and $89 million as of December 31, 2015 and 2014, respectively. Our accumulated benefit obligation related to other post-employment plans was $45 million and $60 million as of December 31, 2015 and 2014, respectively.

Amounts recognized in the consolidated balance sheets consist of:



	Pension Benefits						Other Benefits
	Year Ended December 31,						Year Ended December 31,
(amounts in millions)	2015			2014			2015			2014
Noncurrent asset (1)	$	—		$	—		$	23		$	15
Noncurrent liability	(19		)	(19		)	(1		)	(7		)
Net amount recognized	$	(19	)	$	(19	)	$	22		$	8

_________________________________________


(1)	The EEI union postretirement plan was over-funded as of December 31, 2015 and 2014 which was included in our balance sheets in “Other assets.”

Pre-tax amounts recognized in AOCI consist of:



	Pension Benefits						Other Benefits
	Year Ended December 31,						Year Ended December 31,
(amounts in millions)	2015			2014			2015			2014
Prior service credit	$	(2	)	$	(3	)	$	(42	)	$	(39	)
Actuarial loss (gain)	21			20			42			50
Net loss recognized	$	19		$	17		$	—		$	11

F-24

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The estimated amounts that will be amortized from accumulated OCI into net periodic benefit cost in 2016 are as follows:



(amounts in millions)	Pension Benefits (1)		Other Benefits (1)
Prior service credit	$	—	$	(5	)
Net actuarial loss (gain)	1		3
Total	$	1	$	(2	)

_________________________________________


(1)	Includes only amounts for EEI’s plans.

The amortization of prior service cost is determined using a straight line amortization of the cost over the average remaining service period of employees expected to receive benefits under the Plan.

Components of Net Periodic Benefit Cost (Gain). The following tables present the components of our net periodic benefit cost (gain) of the EEI pension and postretirement benefit plans and an allocation of net periodic benefit costs from our participation in Dynegy’s and Ameren’s pension and postretirement benefit plans:



	Pension Benefits
	Year Ended December 31,
(amounts in millions)	2015			2014			2013
Service cost	$	3		$	3		$	5
Interest cost	3			4			10
Expected return on plan assets	(4		)	(5		)	(13		)
Amortization of:
Prior service credit	—			—			(1		)
Actuarial loss	1			1			6
Net periodic benefit cost	3			3			7
Settlements	—			2			1
Total benefit cost	$	3		$	5		$	8



	Other Benefits
	Year Ended December 31,
(amounts in millions)	2015			2014			2013
Service cost	$	1		$	1		$	2
Interest cost	2			2			3
Expected return on plan assets	(3		)	(3		)	(5		)
Amortization of:
Prior service credit	(5		)	(4		)	(8		)
Actuarial loss	3			3			5
Net periodic benefit cost (gain)	(2		)	(1		)	(3		)
Curtailment gain (1)	—			—			(26		)
Total benefit cost (gain)	$	(2	)	$	(1	)	$	(29	)

_________________________________________


(1)	Represents EEI’s management postretirement benefit plans’ curtailment gain recognized due to a reduction of employees as a result of the AER Acquisition.

In addition to the above net periodic benefit cost for pension benefits, we were allocated $1 million in net periodic benefit costs from Ameren Services employees doing work on our behalf during the period from January 1, 2013 through December 1, 2013. We were also allocated less than $1 million in net periodic benefit costs for postretirement benefits from Ameren Services employees doing work on our behalf during the period from January 1, 2013 through December 1, 2013.

F-25

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Assumptions. The following table presents the assumptions used to determine our benefit obligations:



	Pension Benefits				Other Benefits
	Year Ended December 31,				Year Ended December 31,
	2015		2014		2015		2014
Discount rate (1)	4.35	%	4.00	%	4.35	%	4.00	%
Rate of compensation increase (1)	3.50	%	3.50	%	3.50	%	3.50	%

_________________________________________


(1)	A weighted average rate of EEI’s and Dynegy’s pension and postretirement plans at December 31, 2015 and 2014.

The following table presents the assumptions used to determine net periodic benefit cost:



	Pension Benefits						Other Benefits
	Year Ended December 31,						Year Ended December 31,
	2015		2014		2013		2015		2014		2013
Discount rate (1)	4.35	%	4.00	%	(2)		4.35	%	4.00	%	(3)
Expected return on plan assets (1)	5.82	%	6.16	%	7.65	%	5.86	%	6.26	%	7.59	%
Rate of compensation increase (1)	3.50	%	3.50	%	(4)		3.50	%	3.50	%	(5)

_________________________________________


(1)	A weighted average rate of EEI’s and Dynegy’s pension and postretirement plans for the years ended December 31, 2015 and 2014. A weighted average rate of EEI’s and Ameren’s pension and postretirement plans for the year ended December 31, 2013.


(2)	The discount rate used for EEI’s pension plan was 4.00 percent and 4.67 percent for the period from January 1, 2013 through December 1, 2013 and the period from December 2, 2013 through December 31, 2013, respectively. The discount rate used for Ameren’s pension plans was 4.00 percent for the period from January 1, 2013 through December 1, 2013.

(3)

The discount rate used for EEI’s postretirement plans was 4.00 percent for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 4.00 percent for EEI union employees and 4.75 percent for EEI management employees for the period from December 2, 2013 through December 31, 2013, respectively. The discount rate used for Ameren’s postretirement plans was 4.00 percent for the period from January 1, 2013 through December 1, 2013.


(4)	The average rate of compensation increase used for EEI’s pension plan was 5.97 percent and 3.50 percent for the period from January 1, 2013 through December 1, 2013 and the period from December 2, 2013 through December 31, 2013, respectively. The average rate of compensation increase used for Ameren’s pension plans was 3.50 percent for the period from January 1, 2013 through December 1, 2013.

(5)

The average rate of compensation increase used for EEI’s postretirement plans was 6.35 percent for EEI union employees and 3.81 percent for EEI management employees for the period from January 1, 2013 through December 1, 2013 and 6.35 percent for EEI union employees and 3.50 percent for EEI management employees for the period from December 2, 2013 through December 31, 2013, respectively. The average rate of compensation increase used for Ameren’s postretirement plans was 3.50 percent for the period from January 1, 2013 through December 1, 2013.

Our expected long-term rate of return on Dynegy’s pension plan assets and EEI’s pension plan assets is 5.60 percent and 5.90 percent, respectively, for the year ended December 31, 2016. Our expected long-term rate of return on EEI’s other post-employment plan assets is 6.30 percent for EEI union employees and 5.75 percent for EEI salaried employees for the year ended December 31, 2016. This figure begins with a blend of asset class-level returns developed under a theoretical global capital asset pricing model methodology conducted by an outside consultant. In development of this figure, the historical relationships between equities and fixed income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long term. Current market factors such as inflation and interest rates are also incorporated in the assumptions. This figure gives consideration towards the plan’s use of active management and favorable past experience. It is also net of plan expenses.

F-26

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The following summarizes our assumed health care cost trend rates:



	Other Benefits
	Year Ended December 31,
	2015		2014		2013
Dynegy - Health care cost trend rate assumed for next year	7.00	%	7.25	%	N/A
Dynegy - Ultimate trend rate	4.50	%	4.50	%	N/A
Dynegy - Year that the rate reaches the ultimate trend rate	2023		2023		N/A
Ameren - Health care cost trend rate assumed for next year	N/A		N/A		5.00	%
Ameren - Ultimate trend rate	N/A		N/A		5.00	%
Ameren - Year that the rate reaches the ultimate trend rate	N/A		N/A		2013
EEI - Health care cost trend rate assumed for next year	7.00	%	7.25	%	(1)
EEI - Ultimate trend rate	4.50	%	4.50	%	4.50	%
EEI - Year that the rate reaches the ultimate trend rate	2023		2023		(2)

_________________________________________


(1)	The health care trend rate assumed for next year used for EEI’s postretirement plans was 7.96 percent for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 7.96 percent for EEI union employees and 7.75 percent for EEI management employees for the period from December 2, 2013 through December 31, 2013, respectively.


(2)	The year that the rate reaches the ultimate trend rate used for EEI’s postretirement plans was 2027 for both EEI union and management employees for the period from January 1, 2013 through December 1, 2013 and 2027 for EEI union employees and 2023 for EEI management employees for the period from December 2, 2013 through December 31, 2013, respectively.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The impact of a one percent increase/decrease in assumed health care cost trend rates is as follows:



(amounts in millions)	Increase		Decrease
Aggregate impact on service cost and interest cost (1)	$	—	$	—
Impact on accumulated post-employment benefit obligation (1)	$	6	$	(5	)

_________________________________________


(1)	Includes amounts only for EEI’s plans.

Plan Assets. We employ a total return investment approach whereby a mix of equity and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. The intent of this strategy is to minimize plan expenses by outperforming plan liabilities over the long run. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks as well as growth, value, and small and large capitalizations. The target asset mix for EEI’s plan assets as of December 31, 2015 was approximately 60 percent to equity investments and approximately 40 percent to fixed income investments. EEI’s plan assets are routinely monitored and rebalanced as circumstances warrant.

Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying investment. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, periodic asset/liability studies and annual liability measurements.

F-27

ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As described above, a portion of Dynegy’s pension and postretirement plan assets is allocated to us as of December 31, 2015 and 2014. The amount of Dynegy pension plan assets allocated to us for financial reporting purposes as of December 31, 2015 and 2014 was $2 million and $2 million, respectively, based on pensionable salaries. None of the Dynegy postretirement plan assets were allocated to us for financial reporting purposes as of December 31, 2015 and 2014 based on the number of our non-EEI employees. The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value related to our EEI pension and other post-employment plans. These assets are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.



	Fair Value as of December 31, 2015
(amounts in millions)	Quoted Prices in Active Markets for Identified Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Cash and cash equivalents	$	1	$	—	$	—	$	1
Equity securities:
U.S. companies (1)	32		33		—		65
International (3)	7		5		—		12
Fixed income securities (4)	14		38		—		52
Total	$	54	$	76	$	—	$	130



	Fair Value as of December 31, 2014
(amounts in millions)	Quoted Prices in Active Markets for Identified Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Cash and cash equivalents	$	2	$	—	$	—	$	2
Equity securities:
U.S. companies (1)	6		62		—		68
Non-U.S. companies (2)	—		—		—		—
International (3)	2		10		—		12
Fixed income securities (4)	3		51		—		54
Total	$	13	$	123	$	—	$	136

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(1)	This category comprises a domestic common collective trust not actively managed that tracks the Dow Jones total U.S. stock market.


(2)	This category comprises a common collective trust not actively managed that tracks the MSCI All Country World Ex-U.S. Index.


(3)	This category comprises actively managed common collective trusts that hold U.S. and foreign equities. These trusts track the MSCI World Index.


(4)	This category includes a mutual fund and a trust that invest primarily in investment grade corporate bonds.

Contributions and Payments. We were required to make contributions of $4 million and $3 million to EEI's pension plan during the years ended December 31, 2015 and 2014, respectively. We are not required to make any contributions to our pension plans during 2016.

The following table presents the cash contributions made to our pension benefit plans:



	Pension Benefits
	Year Ended December 31,
(amounts in millions)	2015		2014		2013
Allocation (1)	$	—	$	—	$	5
EEI	4		3		10
Total	$	4	$	3	$	15

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ILLINOIS POWER GENERATING COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

_________________________________________


(1)	Represents an allocation of our share of cash contributions associated with our participation in Ameren’s pension plan for the year ended December 31, 2013. There was no allocation of our share of cash contributions associated with our participation in Dynegy’s pension plan for the years ended December 31, 2015 and 2014.

Our current funding policies are to forego further contributions to their postretirement benefit plans, except as necessary to fund benefit payments. There were no employer contributions to our postretirement plans for the years ended December 31, 2015, 2014 and 2013.

The expected pension and postretirement benefit payments for expected future service, as of December 31, 2015, are as follows:



(amounts in millions)	Pension Benefits (1)		Other Benefits (1)
2016	$	8	$	2
2017	$	7	$	2
2018	$	7	$	2
2019	$	7	$	2
2020	$	6	$	2
2021 - 2025	$	30	$	12

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(1)	Includes only amounts for EEI’s plans.

Note 15—Quarterly Financial Information

The following is a summary of our unaudited quarterly financial information:



	Quarter Ended
(amounts in millions)	March 31			June 30			September 30			December 31
2015
Revenues	$	143		$	131		$	146		$	114
Operating loss (1)	$	(17	)	$	(24	)	$	(855	)	$	(6	)
Net loss	$	(16	)	$	(19	)	$	(517	)	$	(11	)
Net loss attributable to Illinois Power Generating Company	$	(15	)	$	(17	)	$	(519	)	$	(11	)



	Quarter Ended
(amounts in millions)	March 31			June 30			September 30			December 31
2014
Revenues	$	180		$	138		$	165		$	165
Operating income (loss)	$	3		$	(35	)	$	(18	)	$	(7	)
Net loss	$	(4	)	$	(27	)	$	(17	)	$	—
Net loss attributable to Illinois Power Generating Company	$	(6	)	$	(27	)	$	(17	)	$	—

__________________________________________


(1)	The results for the three months ended September 30, 2015, include an impairment charge of $855 million. See Note 3—Impairments for more information.

F-29

Illinois Power Generating Co - FORM 10-K - March 28, 2016

Attached files

Illinois Power Generating Co Reports