8-K

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d OF THE

SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported)

September 23, 2013

DYNEGY INC.

(Exact name of registrant as specified in its charter)

Delaware	001-33443	20-5653152
(State or Other Jurisdiction of Incorporation)	(Commission File Number)	(I.R.S. Employer Identification No.)

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

(713) 507-6400

(Registrant’s telephone number, including area code)

N.A.

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

oWritten communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

oSoliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

oPre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

oPre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 7.01Regulation FD Disclosure.

Dynegy Inc. (“Dynegy”) is participating in a series of meetings with analysts and investors beginning on September 23, 2013 at which Robert C. Flexon, Dynegy’s President and Chief Executive Officer, will be conducting presentations.

The presentation slides for use in conjunction with these meetings are being furnished pursuant to Regulation FD as Exhibit 99.1 to this Current Report on Form 8-K. The presentation slides include statements intended as “forward-looking statements,” which are subject to the cautionary statement about forward-looking statements set forth therein.

In accordance with SEC Release No. 33-8176, the information contained in the presentation slides furnished as an exhibit hereto shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, except as shall be expressly set forth by specific reference in such a filing.

Item 9.01Financial Statements and Exhibits.

(d)  Exhibits:

Exhibit No.	Document
99.1	Dynegy Inc. Investor Meetings Presentation.

2

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	DYNEGY INC.
	(Registrant)
Dated: September 23, 2013	By:	/s/ Catherine B. Callaway
	Name:	Catherine B. Callaway
	Title:	Executive Vice President, Chief Compliance Officer and General Counsel

3

EXHIBIT INDEX

Exhibit No.	Document
99.1	Dynegy Inc. Investor Meetings Presentation.

4

EX-99.1

Exhibit 99.1

Wolfe Trahan 2013 Utilities and Gas Conference September 24, 2013 Robert C. Flexon, President and CEO

Bank of America/Merrill Lynch Power and Gas Leaders Conference September 25, 2013 Robert C. Flexon, President and CEO

CRT Capital Group 2013 Investor Conference September 23, 2013 Robert C. Flexon, President and CEO

Houlihan Lokey 2013 Energy Conference October 1, 2013 Robert C. Flexon, President and CEO

Forward-Looking Statements Cautionary Statement Regarding Forward-Looking Statements This presentation contains statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward looking statements.” You can identify these statements by the fact that they do not relate strictly to historical or current facts. Management cautions that any or all of Dynegy’s forward-looking statements may turn out to be wrong. Please read Dynegy’s annual, quarterly and current reports filed under the Securities Exchange Act of 1934, including its 2012 Form 10-K and first and second quarter 2013 Forms 10-Q for additional information about the risks, uncertainties and other factors affecting these forward-looking statements and Dynegy generally. Dynegy’s actual future results may vary materially from those expressed or implied in any forward-looking statements. All of Dynegy’s forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking statements. In addition, Dynegy disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof. Non-GAAP Financial Measures This presentation contains non-GAAP financial measures including EBITDA, Adjusted EBITDA and Segment Adjusted EBITDA. Reconciliations of these measures to the most directly comparable GAAP financial measures to the extent available without unreasonable effort are contained herein. To the extent required, statements disclosing the definitions, utility and purposes of these measures are set forth in Item 2.02 to our current report on Form 8-K filed with the SEC on August 1, 2013, which is available on our website free of charge, www.dynegy.com. 5

Why invest in Dynegy? 6 Dynegy represents an attractive value-oriented investment opportunity with a compelling risk/reward profile Capital Allocation Opportunities Multiple Avenues for Substantial Earnings Upside Limited Downside Risk 1 2 3

7 Scale and diversity of business Dynegy’s diverse asset portfolio (1) Oakland 165 MW Moss Landing 1&2 1,020 MW Moss Landing 6&7 1,509 MW Morro Bay 650 MW 6,771 MW of generation with ~4,400 MW combined cycle capacity Fleet located across six states and five power markets Dispatch increases as natural gas prices decrease 2,980 MW baseload dispatch portfolio In all material respects, environmentally compliant with current EPA regulations All units burn ultra-low sulfur Powder River Basin coal Low cost structure as a result of favorable long-term rail agreements Baldwin 1,800 MW Havana 441 MW Wood River 446 MW Hennepin 293 MW Ontelaunee 580 MW Kendall 1,200 MW Independence 1,064 MW Black Mountain (2) 43 MW Casco Bay 540 MW Note: Net capacity shown based on winter capacity; (1) Pending completion of acquisition of Ameren Energy Resources ;(2) Dynegy owns 50% interest in Black Mountain (3) Net MW reflecting 80% interest in EEI, which owns Joppa Steam and MEPI Joppa 6B Duck Creek 410 MW Edwards 650 MW Joppa 949 MW (3) Coffeen 895 MW Newton 1,215 MW Gas Fleet IPH Assets (Pending) ~4,100 MW baseload dispatch portfolio In all material respects, environmentally compliant with current EPA regulations All units burn ultra-low sulfur Powder River Basin coal Favorable basis to Indy Hub Established retail business Coal Fleet

Dynegy’s portfolio generates free cash flow in both high and low gas environments 8 Environmentally Compliant Coal Fleet If gas prices stay low If gas prices rise Benefits from rising capacity payments and “heat rates” due to increased retirements Significant upside leverage in a rising natural gas environment Benefits from increased capacity factors and rising capacity payments due to increased retirements Benefits from spark spread expansion as energy prices rise If gas prices stay low If gas prices rise CoalCo/IPH GasCo Efficient Combined-Cycle Gas Fleet Retail (pending) Benefits from margin expansion as a result of lower costs to procure supply Benefits from increasing sales volume in higher demand periods Natural Hedge for Generation Assets

Ascribing all value to GasCo Total GasCo MW 6,771 GasCo Valuation $407/kW Leaves “no” value for CoalCo or IPH Total CoalCo/IPH MW 7,099 CoalCo/IPH Valuation $0/kW The market effectively assigns zero value to CoalCo and the pending IPH transaction 9 Enterprise Valuation as of 7/26/2013(1) $ millions Total Debt $1,296 Equity Value: Stock 1,963 Less: Cash (500) Firm Value $2,759 Implied Segment Valuations $/kW (1) See Appendix, Slide 28, for detailed calculations; (2) 2012 Asset level transactions for CCGTs and coal-fired generation assets, Source: SNL, company filings and Wall Street research (3) Includes debt of $825MM and cash of $266MM at Ameren Energy Resources at closing Valuation Comparables(2) $/kW A $240/kw valuation for CoalCo/IPH (3) would equal ~$11 per share

10 Dynegy Shareholder Value Drivers All drivers point towards higher power and capacity prices MATS results in over 30GWs of retirements in MISO and PJM Prolonged low commodity price environment driving additional coal and nuclear generation retirements (Kewaunee, Yankee) Retirements Natural Gas Higher natural gas demand for electric generation adding to natural gas demand for LNG exports, exports to Mexico, industrial demand and transportation sector Reserve Margins Tighter reserve margins, particularly in MISO, are projected as minimal new build projects are in the queue to replace retiring coal and nuclear assets Clearing Prices Marginal clearing prices in MISO and PJM will be set by higher heat rate gas facilities

Adjusted EBITDA sensitivities to changing market conditions demonstrate significant upside opportunities (1) Assumes an unhedged porfolio. Heat rate sensitivities based on power price changes and full-year estimates; Assumes constant natural gas price of $3.46/MMBtu and heat rate changes are for a full year. Natural gas sensitivities based on full-year estimates and assume natural gas price change occurs for the entire year and entire portfolio; power prices are adjusted by holding the spark spread constant for a 7,000 Btu/KWh heat rate. (2) Assumes 22M MWh annually 11 Dynegy Coal Portfolio ($mm) ~$100 $64 ~$85 Impact of $1/MMBtu Increase in Cost of Natural Gas (net of .6 heat rate contraction)(1) 1 2 Impact of $2/kw-month Increase in Capacity payments within MISO 3 Impact of ATC power clearing price increasing by $4/MWh within MISO(2) Dynegy Coal and IPH Portfolio ($mm) IPH effectively doubles the impact of increasing commodity and capacity prices in MISO

A total of 10.3 GW of retirements assumed: 4.7 GW of retirements assumed in 2015 Additional 5.6 GW of retirements slated for 2016 Most of the retirements are coal and older steam units Conservative projections continue to show reduced MISO reserve margins due to MATS and economic retirements Retirement Outlook 12 1.5 GW of new gas CCGT to be added by 2018 .5 GW of wind additions by 2018 Wind additions to slow with renewable tax credit expiration Projected 2013-2018 demand CAGR of 0.7% Supply & Demand Outlook 2015/16 installed capacity falls to within 1.5 GW of the vertical demand curve reserve margin of 14%, using moderate import activity MATS retirements will force installed capacity to drop below its reserve margin target between 2016-18 until new resources become available Reserve Margin Outlook Projected MISO Reserve Margin

Today, MISO reserve margin is tighter than it appears Taking into account the IMM’s recommended adjustments regarding wind, imports, demand response, retirements and exports, a potential 8GW shortfall for 2016 MISO Reserve Margin Estimates(1) The market monitor also stated MISO’s capacity market construct does not send adequate price signals for new investment and recommended: Replacing the vertical demand curve with a sloped demand curve Evaluate capacity credits assigned to wind and DR to increase their accuracy Removal of barriers to capacity trading with adjacent areas MISO reserve margins have potential to reach 6% by 2016 (1) Source: Potomac Economics, 2012 State of the Market Report for the MISO Electricity Markets, June 2013; MISO 2013 Summer Resource Assessment; Dynegy Fundamentals. See Slide 29 in Appendix for links to referenced material. MISO’s independent market monitor (IMM) noted the 2013 reserve margin is actually lower after adjusting for non-firm imports and “realistic” wind and demand response 13 MISO 2013 Planning Reserve Margin

Although capacity markets are MISO-wide, confirmed exports to PJM further tighten available capacity in Zone 4 in 2016 14 MISO Zone 4 (Illinois)(1) MISO 2013 Planning Reserve Margin With approximately 850 MW of Zone 4 capacity leaving MISO for PJM, reserve margins could reach 12% in the region by 2016 (1) Source: Potomac Economics, 2012 State of the Market Report for the MISO Electricity Markets, June 2013; MISO 2013 Summer Resource Assessment; Dynegy Fundamentals; Ventyx. See Slide 29 in Appendix for links to referenced material. (2) 2013 reserve margin calculations exclude 930MWs of exports currently identified by MISO

AER’s coal generation and retail marketing business is a natural fit with CoalCo Portfolio Overview ~4,100 MW of environmentally compliant, baseload coal generation in MISO and PJM ~900 MW in PJM by 2016 Ameren Energy Marketing and Homefield Energy – established retail and commercial energy providers 15 15 MISO Kendall Hennepin Wood River Baldwin Havana Edwards Coffeen Newton Duck Creek Joppa DYN Transaction Summary Dynegy’s newly created, non-recourse subsidiary(1), Illinois Power Holdings, acquires AER equity for no cash consideration At closing, AER and its subsidiaries will have $226 million in cash, $160 million in working capital and 2 years of collateral support from Ameren Synergy run-rate in 2014, targeted to exceed ~$75 million; further synergy run-rate increases for 2015 Accretive to Adj. EBITDA in 2014 and Free Cash Flow by 2015(2) Regulatory approvals include FERC, FCC and Illinois Pollution Control Board Estimated close during 4th quarter 2013 (1) Excluding a $25 million Dynegy guarantee to Ameren Corp. (2) Definitions of Adjusted EBITDA and Free Cash Flow are set forth in Item 2.02 to our current report on Form 8-K filed with the SEC on March 14, 2013 PJM AER

AER Acquisition Update – Q4 targeted closing 16 Pending approvals: Integration Update – Annual Synergies Filed 4/16/2013 FERC issued information request on 7/26/2013 Illinois Pollution Control Board (IPCB) IPH filed variance request on 7/22/2013 Anticipate ruling on or before 11/21/2013 FERC Synergies comprised of three primary categories: Procurement and delivered coal costs Operating costs G&A allocation from Ameren Corporate Substantially all synergies targeted to be implemented by end of Q1 2014

 Refinancing / Liquidity ($ in millions) June 30 July 26 Cash & Cash Equivalents 461 500 Revolver Capacity 475 475 Posted LC’s (190) (188) Total Liquidity $746 $787 Liquidity Summary Refinancing Summary Refinanced expensive CoalCo/GasCo Term Loans with Dynegy Inc Term Loan and High Yield Note Weighted average interest rate of 4.72% Freed up $335MM of previously restricted cash Covenant-lite term loan and high-yield note with investment-grade covenants provide substantial flexibility for growth and capital management $475MM revolver reduces the cash intensity of DYN’s liquidity program Collateral outstanding continues to decline – currently below $250MM Lowest collateral level since July 2006 17 Streamlined debt structure, robust liquidity, and lower collateral requirements Facility Revolving Credit Term Loan B High Yield Note Size $475 MM $800 MM $500 MM Interest Rate L + 275 bps L + 300 bps 5.88% LIBOR floor No floor 1% n/a OID NA 99.5 100 Tenor 5 years 7 years 10 years

AER Acquisition Dynegy Investment Thesis Dynegy’s Fundamental Investment Thesis 18 Capital Allocation Opportunities Multiple Avenues for Substantial Upside Limited Downside Risk Increasing shareholder value while protecting and preserving Dynegy’s balance sheet Minimal financial exposure with downside risk to be ring-fenced Scale and market recovery benefits Preserves future capital allocation opportunities Debt Refinancing Further reduces downside risk to low natural gas prices Established capital structure to enhance ability to capture market opportunities As a result of refinancing, excess liquidity available for future allocation

Appendix 19

20 Dynegy Generation Facilities Portfolio/Facility(1) Location Net Capacity(2) Primary Fuel Dispatch Type Market Region Coal Baldwin Baldwin, IL 1,800 Coal Baseload MISO Havana Havana, IL 441 Coal Baseload MISO Hennepin Hennepin, IL 293 Coal Baseload MISO Wood River Units 4-5 Alton, IL 446 Coal Baseload MISO Coal Segment Total 2,980 Gas Casco Bay Veazie, ME 540 Gas - CCGT Intermediate ISO-NE Independence Scriba, NY 1,064 Gas - CCGT Intermediate NYISO Kendall Minooka, IL 1,200 Gas - CCGT Intermediate PJM Ontelaunee Ontelaunee Township, PA 580 Gas - CCGT Intermediate PJM Moss Landing Monterey County, CA Units 1-2 1,020 Gas - CCGT Intermediate CAISO Units 6-7 1,509 Gas Peaking CAISO Morro Bay Morro Bay, CA 650 Gas Peaking CAISO Oakland Oakland, CA 165 Oil Peaking CAISO Black Mountain Las Vegas, NV 43 Gas Baseload WECC Gas Segment Total 6,771 TOTAL GENERATION 9,751 NOTES: Dynegy owns 100% of each unit listed, except that it owns a 50% interest in the Black Mountain facility. Total Net Capacity set forth in this table for Black Mountain includes only Dynegy’s proportionate share of such unit’s gross generating capacity. The list also does not include several facilities that are retired or in agreement to be sold. Those facilities include Havana 1-5 and Wood River 1-3 which are retired and out of operation; Morro Bay 1-2 which are in mothball status and out of operation; and Danskammer and Roseton, which were deconsolidated effective October 1, 2012 and are under agreement to be sold. Unit capabilities are based on winter capacity. 1) 2)

21 Gas Segment: Tolling, Capacity and Other Tolling Agreements Plant Contract Type Size (MW) Tenor Moss Landing 6&7 Tolling Agreement 1,509 Through 2013 Oakland RMR 165 Through Dec-2013 Independence Steam & Energy 44 Through Jan-2017 Kendall Tolling Agreement 50-85 Through Sep-2017 Capacity / Resource Adequacy Plant Contract Type Clearing Price (1) Size (MW) Tenor Casco Bay ISO-NE Capacity Auction $2.34/kw-Mo 488 Jun-2013 to May-2014 $3.21/kw-Mo 435 Jun-2014 to May-2015 $3.43/kw-Mo 445 Jun-2015 to May-2016 $3.15/kw-Mo 425 Jun-2016 to May 2017 Kendall PJM Capacity Auction $27.73/MW-day 1,044 Jun-2013 to May-2014 $125.99/MW-day 1,016 Jun-2014 to May-2015 $136.00/MW-day 1,033 Jun-2015 to May 2016 $59.37/MW-day 1,021 Jun-2016 to May 2017 Ontelaunee PJM Capacity Auction $226.15/MW-day 519 Jun-2013 to May-2014 $136.50/MW-day 492 Jun-2014 to May-2015 $167.46/MW-day 503 Jun -2015 to May 2016 $119.13/MW-day 503 Jun-2016 to May 2017 Moss Landing 1&2 RA Capacity 1,007 Avg Bilateral Sold Q3 2013 593 Avg Bilateral Sold Q3 2014 200 Avg Bilateral Sold Q3 2015 Morro Bay 3&4 RA Capacity 542 Avg Bilateral Sold Q3 2013 Independence ICAP - Con Ed 740 Through Oct-2014 (1) Publicly disclosed clearing prices have been added where applicable

Adjusted EBITDA Sensitivities based on pricing as of 1/2/2013 22 Gas Coal +/- 500 HR(1) $30 $ 39 +/- $1 Gas(2) $(4) $153 +/- $1/MWh increase in basis $22 $ mm Market Implied Heat Rate Movement (Btu/KWh) Change in Cost of Natural Gas ($/MMBtu) Sensitivities based on power price changes and full-year estimates; Assumes constant natural gas price of $3.46/MMBtu and heat rate changes are for a full year (2) Sensitivities based on full-year estimates and assume natural gas price change occurs for the entire year and entire portfolio; power prices are adjusted by holding the spark spread constant for a 7,000 Btu/KWh heat rate Shows impact of a change in market implied heat rates on earnings, holding gas prices and expected generation levels constant Shows impact of a change in gas prices on earnings, where power prices are adjusted by holding spark spreads constant for a 7,000 Btu/kWh heat rate and expected generation levels are held constant Unhedged Year

Utilizing Adjusted EBITDA Sensitivities 23 Coal Unhedged Year ($mm) +/- $1 Gas +/-$153 +/- 500 HR +/-$39 Market Implied Heat Rate Movement (Btu/KWh) Change in Cost of Natural Gas ($/MMBtu) Due to relationship between natural gas and power prices, gas and heat rate sensitivities need to be considered jointly to estimate changes to Adjusted EBITDA: Forward Market Analysis ($mm) + $1 Gas $153 - 600 HR ($47) Change in Adjusted EBITDA (assumes constant basis) ~$100 Using Dynegy sensitivities yield same results as analysis of forward markets

Decreased correlation between Coal segment and INDY Hub 24 Historical hedging activity/INDY Hub correlation Correlations between Dynegy Coal units and INDY Hub have eroded over time Reducing correlation exposure at INDY Hub ($4.29) ($4.54) ($5.80) ($7.86) Basis Increased use of FTRs and busbar sales as correlations decreased

Multiple unscheduled line outages near Indy Hub and Dynegy Coal units Generation on Indiana border not running Mt. Vernon Outage Ended Dynegy’s Coal segment LMP versus INDY Hub pricing Causes for variation between Coal units’ LMP and INDY Hub Line outages near INDY Hub or Coal units Unit outages near INDY Hub Prairie State operations 25 (1) Excludes Hennepin LMP pricing during planned outage period in the quarter (2) As provided in original 2013 guidance projections, January 2013 Mt. Vernon Outage Average ATC Gen-Weighted Basis 2Q2013 1H 2013 Actual ($8.99) ($7.86) Planned(2) ($4.25) ($4.47) Planned Basis: ($4.36) ($/MWh) Drought induced unit outages during high demand Mt. Vernon Outage

A changing market requires a change in hedging strategy for Coal segment Captured FTRs in annual and monthly MISO auctions Executed INDY Hub to MISO fleet busbar financial basis swaps to perfect hedges Minimized unperfected on-peak hedges at INDY Hub Increasing open position at plant busbar 26 Mid to long-term basis risk management Pursue busbar to Indy Hub financial basis swaps Implement origination strategy Optimize sourcing of energy for AEM’s retail portfolio post-closing Hedging activity for 2013/2014(1) Near-term strategies implemented to reduce exposure to INDY Hub correlation (1) Coal segment generation volumes hedged as of 7/26/2013

Midwest Congestion and PJM Capacity Market Access Congestion cost mitigation measures: Quanta Resources study identified 19 flowgates that had greatest impact on facility LMP’s due to congestion in 2012 Only 2 identified constraints are not mitigated by MTEP work already planned Remaining 2 constraints addressed by Dynegy Transformer upgrade and transmission line upgrades in the Baldwin plant area Constraint near Indiana border area created as a result of completion of the Illinois River Project PJM Capacity Market Access: Transmission service request to MISO and PJM to identify available transmission capacity to PJM and associated cost Generator interconnect request to assess cost of direct connection of Baldwin to PJM Future transmission projects positively impact congestion at Dynegy and AEM facilities Multiple initiatives to mitigate congestion, improve LMP pricing and increase access to higher valued capacity markets 27

Enterprise Valuation Enterprise Valuation as of 7/26/2013 ($ MM) Total Debt $1,296 Equity Value: Stock (1) 1,963 Less: Cash (500) Firm Value $2,759 Total Capacity (mws) (3) 9,751 $/kw $283 28 (1) Based on 9/19/13 price of $19.63 * 100MM shares (2) As of 7/26/2013. (3) Excludes Stallings/Oglesby , DNE and mws that will be acquired through the Ameren transaction

Links to referenced material 29 MISO 2013 Summer Assessment: https://www.midwestiso.org/Library/Repository/Study/Seasonal%20Assessments/2013%20Summer%20Resource%20Assessment.pdf Potomac Economics/Independent Market Monitor, 2012 State of the Market Report: https://www.midwestiso.org/Library/Repository/Report/IMM/2012%20State%20of%20the%20Market%20Report.pdf