 EFH Corp. Q1 2013 Investor Call May 2, 2013 Exhibit 99.2 |
 1 Safe Harbor Statement Forward Looking Statements This presentation contains forward-looking statements, which are subject to various risks and uncertainties. A discussion of risks and uncertainties that could cause actual results to differ materially from management's current projections, forecasts, estimates and expectations is contained in EFH Corp.'s filings with the Securities and Exchange Commission (SEC). In addition to the risks and uncertainties set forth in EFH Corp.'s SEC filings, the forward-looking statements in this presentation regarding the company’s natural gas hedging program could be affected by, among other things: changes in the ERCOT electricity market, including a regulatory or legislative change, that results in wholesale electricity prices not generally moving with natural gas prices; any decrease in market heat rates as the program generally does not mitigate exposure to changes in market heat rates; the unwillingness or failure of any hedge counterparty to perform their respective obligations; or any other event that results in the inability to continue to use a first lien on TCEH’s assets to secure a substantial portion of the hedges under the program. Regulation G This presentation includes certain non-GAAP financial measures. A reconciliation of these measures to the most directly comparable GAAP measures is included in the appendix to this presentation. |
 2 Today’s Agenda Q&A Financial and Operational Overview Q1 2013 Review Paul Keglevic Executive Vice President & CFO |
 Consolidated: reconciliation of GAAP net loss to adjusted (non-GAAP) operating results Q1 12 vs. Q1 13 1 ; $ millions, after tax EFH Corp. Adjusted (Non-GAAP) Operating Results 3 1 Three months ended March 31. Factor Q1 12 Q1 13 Change EFH Corp. GAAP net loss (304) (569) (265) Items excluded from adjusted (non-GAAP) operating results (after tax) – noncash: Unrealized commodity-related mark-to-market net losses 98 314 216 Unrealized mark-to-market net gains on interest rate swaps (74) (98) (24) Effect of favorable resolution of income tax positions – Competitive business - (84) (84) Effect of favorable resolution of income tax positions – Oncor - (8) (8) EFH Corp. adjusted (non-GAAP) operating loss (280) (445) (165) |
 Consolidated key drivers of the change in (non-GAAP) operating results Q1 12 vs. Q1 13; $ millions, after tax EFH Corp. Adjusted (Non-GAAP) Operating Results Key Drivers (after tax) 1 Competitive business consists of Competitive Electric segment and Corp. & Other. 4 Description/Drivers Better (Worse) Than Q1 12 Competitive business¹: Lower net margin from asset management driven by lower natural gas hedge volumes and prices (139) Higher net fuel expense driven by lower lignite blend at coal plants (6) Higher net generation due to reduced unplanned outage days at coal plants 14 Lower amortization of intangibles arising from purchase accounting 2 Contribution margin (129) Higher net interest expense driven by higher average borrowings (24) Higher operating costs reflecting planned outages at coal and nuclear generation units (14) Higher depreciation reflecting accelerated depreciation primarily associated with asset retirements during planned outages at three coal units (9) Lower effective tax rate reflecting lower accrued interest 8 All other - net 1 Total change - Competitive business (167) Regulated business: Higher net revenues reflecting transmission tariff increases, automated meter surcharges, colder (more normal) weather, and growth in points of delivery 17 Higher revenues from transmission and other cost recovery (reconcilable rate) charges 5 Lower third party transmission fees 1 Higher depreciation and amortization reflecting infrastructure investment (10) Higher net interest expense driven by settlement of TCEH transition bond interest reimbursement agreement in 2012 (6) Higher operations and maintenance expense due to energy efficiency programs and advanced metering (2) All other – net (3) Change in Regulated business (~80% owned by EFH Corp.) 2 Total change in EFH Corp. adjusted (non-GAAP) operating results (165) |
 EFH Corp. Adjusted EBITDA (Non-GAAP) EFH Corp. Adjusted EBITDA (non-GAAP) 1 Q1 12 vs. Q1 13; $ millions Q1 13 Q1 12 1,051 1,230 638 834 415 386 TCEH Oncor Q1 13 performance was largely driven by the same key drivers impacting adjusted (non- GAAP) operating results. 8% 1 See Appendix for Regulation G reconciliations and definition. Includes $10 million and $(2) million of Corp. & Other Adjusted EBITDA in Q1 12 and Q1 13, respectively. 5 24% 15% |
 Luminant Operational Results 6 Q1 2013 Nuclear Plant Results Solid safety performance 2 fewer generation days in Q1 2013 Top decile industry performance for reliability and cost Q1 2013 Coal-Fueled Plant Results Higher generation due to improved reliability - fewer unplanned outages Higher planned outage days due to maintenance ~4.3 TWh of available generation was uneconomic resulting in seasonal operations and backdown of higher cost units |
  Q1 2013 Results Sales volumes declined 4% driven by business volumes Residential attrition rates improved over 25% compared to Q1 2012. Q1 2013 attrition was 1.0% vs. 1.4% in Q1 2012 Lower SMB 1 and LCI 2 volumes reflect competitive intensity and a focus on margin discipline TXU Energy Operational Results Total residential customers3 End of period, thousands Retail electricity sales volumes by customer class; GWh 1 SMB – small business. 2 LCI – large commercial and industrial. 3 Includes December 2012 acquisition of customers. 4 Last twelve months. 7 |
 8 Oncor Operational Results Electric energy billed volumes 3 ; GWh 1 SMB – small business; LCI – large commercial and industrial. 2 CREZ – Competitive Renewable Energy Zone. 3 On average, billed volumes are on an approximate 17-day calendar lag; therefore, amounts shown reflect partial impacts from prior quarters. 4 Last twelve months. Electricity distribution points of delivery End of period, thousands of meters Q1 2013 Results Higher residential volumes principally due to more normal weather and premise growth Higher SMB & LCI 1 energy volumes due to economic growth $1.6 billion spent on CREZ 2 through March 31, 2013; $167 million spent in 2013 |
 EFH Corp. Liquidity Management As of March 31, 2013 9 Cash and Equivalents TCEH Letter of Credit Facility¹ TCEH Revolving Credit Facility EFH Corp. and TCEH continue to monitor capital market conditions for opportunities to ensure liquidity needs are met and to improve financial flexibility. EFH Corp. (excluding Oncor) available liquidity As of 3/31/13; $ millions 1 At March 31, 2013, restricted cash totaled $947 million, after reduction for a $115 million letter of credit drawn in 2009 related to a building financing. The restricted cash supports letters of credit, of which $735 million are outstanding, leaving $212 million available. |
 10 10 10 Commodity Prices Commodity Units Q1 13 Actual Q1 12 Actual FY 12 1 Actual 13E 1 NYMEX gas price 2 $/MMBtu 3.48 2.46 2.75 4.12 HSC gas price 2 $/MMBtu 3.43 2.41 2.71 4.08 7x24 market heat rate (HSC) 3 MMBtu/MWh 7.69 10.00 9.53 10.16 North Hub 7x24 power price $/MWh 26.45 23.46 25.17 41.47 TCEH weighted avg. hedge price 4 $/MMBtu 6.89 7.46 7.36 6.89 Gulf Coast ultra-low sulfur diesel $/gallon 3.09 3.17 3.05 2.99 PRB 8400 coal $/ton 9.17 8.28 7.57 9.62 LIBOR interest rate 5 percent 0.47% 0.76% 0.69% 0.59% Commodity prices Q1 13, Q1 12, FY 12 and 13E; mixed measures 1 FY 2012: Year ended December 31, 2012; 13E: 2013 estimate based on average of monthly commodity prices as of March 28, 2013 for April 2013 through December 2013. 2 The actual prices are computed based on settled Gas Daily prices for Henry Hub or Houston Ship Channel (HSC) respectively. 3 Based on ERCOT Nodal market clearing price for North Hub. 4 Weighted average prices in the TCEH natural gas hedging program. Based on NYMEX Henry Hub prices of forward natural gas sales positions in the hedging program (excluding the impact of offsetting purchases for rebalancing and pricing point basis transactions). 5 The index for the settled value is a 6-month LIBOR rate. LIBOR interest rate for 13E is based on 9 month LIBOR rate. |
 11 Factor Measure 2013 2014 Total 12/31/12 Natural gas hedges mm MMBtu ~211 ~146 ~357 Wtd. avg. hedge price¹ $/MMBtu ~$6.89 ~$7.80 Natural gas prices $/MMBtu ~$3.54 ~4.03 Cum. MtM gain at 12/31/12² $ billions ~$1.0 ~$0.6 ~$1.6 03/31/13 Natural gas hedges³ mm MMBtu ~163 ~146 ~309 Wtd. avg. hedge price¹ $/MMBtu ~$6.89 ~$7.80 Natural gas prices 4 $/MMBtu ~$4.12 ~$4.23 Cum. MtM gain at 03/31/13² $ billions ~$0.7 ~$0.5 ~$1.2 Q1 13 MtM (loss) gain $ billions ~(0.3) ~(0.1) ~(0.4) 11 Unrealized Mark-To-Market Impact Of Hedging Unrealized mark-to-market impact of hedging program 03/31/13 vs. 12/31/12; mixed measures, pre-tax Hedge program decrease is due to settlement of Q1 position, as well as rising gas prices. 1 Weighted average prices are based on forward natural gas sales positions in the natural gas hedging program (excluding the impact of offsetting purchases for rebalancing and pricing point basis transactions). Where collars are reflected, sales price represents the approximate collar floor price. December 31, 2012 prices for 2013 represent January 1, 2013 through December 31, 2013 values and March 31, 2013 prices for 2013 represent April 1, 2013 through December 31, 2013 values. 2 MtM values include the effects of all transactions in the natural gas hedging program including offsetting purchases (for re-balancing) and natural gas basis deals. 3 As of March 31, 2013. 2013 represents April 1, 2013 through December 31, 2013 volumes. Where collars are reflected, the volumes are estimated based on the notional position of the derivatives to provide protection against downward price movements. The notional volumes for collars are approximately 150 million MMBtu, which correspond to a delta position of approximately 146 million MMBtu in 2014. 4 2013 represents the average of monthly forward prices for April 1, 2013 though December 31, 2013. |
 12 12 TCEH Natural Gas Exposure TCEH Natural Gas Position 13-15¹; million MMBtu Hedges Backed by Asset First Lien Open Position Factor Measure 2013 2014 2015 Natural gas hedging program million MMBtu ~152 ~146 0 TXUE and LUME net positions million MMBtu ~166 ~51 ~16 Overall estimated percent of total NG position hedged percent ~94% ~43% ~3% TXUE and Luminant Net Positions2 TCEH has hedged approximately 94% of its estimated natural gas price exposure for 2013 1 As of March 31, 2013. Balance of 2013 is from May 1, 2013 to December 31, 2013. Assumes conversion of electricity positions based on a ~8.5 heat rate with natural gas generally being on the margin ~70-90% of the time (i.e. when other technologies are forecast to be on the margin, no natural gas position is assumed to be generated). 2 Includes estimated forward net wholesale and retail sales. Excludes any transactions associated with proprietary trading positions. 3 The 2014 position includes notional volume of approximately 150 million MMBtu costless collar with strikes of ~$7.80/MMBtu and ~$11.75/MMBtu for puts and calls, respectively. The delta equivalent short position is ~146 million MMBtu. 3 |
 2013 estimate based on commodity positions as of March 31, 2013 and reflects the existing regulatory environment under the Clean Air Interstate Rule, net of natural gas hedges and net wholesale and retail sales. Excludes gains and losses incurred prior to March 31, 2013. Simplified representation of heat rate position in a single TWh position. Heat rate impacts are typically differentiated across plants and respective pricing periods: nuclear and coal-fueled plants generation (linked primarily to changes in North Hub 7x24), natural gas plants (primarily North Hub 5x16) and wind (primarily West Hub7x8). Assumes conversion of electricity positions based on a ~8.5 market heat rate with natural gas generally being on the margin ~70-90% of the time (i.e., when coal is forecast to be on the margin, no natural gas position is assumed to be generated). Includes positions related to fuel surcharge on rail transportation. Excludes fuel surcharge on rail transportation. 13 13 13 EFH Corp. Adjusted EBITDA Sensitivities Commodity Percent Hedged at March 31, 2013 Change BOY 13E Impact $ millions 7X24 market heat rate (MMBtu/MWh)2 ~85 0.1 MMBtu/MWh ~4 NYMEX gas price ($/MMBtu) ~94 $1/MMBtu ~20 Diesel ($/gallon)3 ~80 $1/gallon ~6 Base coal ($/ton) 4 ~92 $2/ton ~2 Generation operations Nuclear- and coal / lignite-fueled generation (TWh) N/A 1 TWh ~15 Retail operations BOY 2013 Residential contribution margin ($/MWh) 17 TWh $1/MWh ~17 Residential consumption 17 TWh 1% ~5 Business markets consumption 12 TWh 1% ~1 Impact on EFH Corp. Adjusted EBITDA 13E¹; mixed measures The majority of 2013 commodity-related risks are significantly mitigated 1 2 3 4 |
 Estimate as of March 31, 2013; $ billions EFH / EFIH TCEH 1 1st Lien $0.02 $0.41 2 2nd Lien $0.23 $1.88 3 Total $0.25 $2.29 Estimated Secured Debt Capacity at EFH / EFIH and TCEH 1 14 1 The debt capacity numbers presented above are for informational purposes only and should not be relied upon in connection with any investment decision regarding the securities of EFH Corp. or its subsidiaries. All of these amounts are estimates based on EFH Corp.'s current interpretation of the covenants set forth in its and its subsidiaries' applicable debt agreements and do not take into account exceptions in the agreements that may allow for the incurrence of additional secured debt, including, but not limited to, acquisition debt, coverage ratio debt, refinancing debt, capital leases and hedging obligations. Moreover, such amounts could change from time to time as a result of, among other things, the termination of any debt agreement (or specific terms therein) or a change in the debt agreement that results from negotiations with new or existing lenders. In addition, covenants included in agreements governing additional, future debt may impose greater or lesser restrictions on the incurrence of secured debt by EFH Corp. and its subsidiaries. Consequently, the actual amount of senior secured debt that EFH Corp. and its subsidiaries are permitted to incur under their respective debt agreements could be materially different than the amounts provided above. EFH Corp. encourages you to review, in consultation with your own advisors, its and its subsidiaries’ various debt agreements, which are on file with the SEC, in order to assess the ability and capacity of EFH Corp. and its subsidiaries to incur additional debt (secured and unsecured) in the future. 2 Of this amount, $1.0B is permitted to be issued for cash (entire amount is permitted to be issued for exchanges). 3 TCEH is permitted to issue an unlimited amount of additional first-priority debt in order to refinance the first-priority debt outstanding under the TCEH Senior Secured Facilities. |
 15 Today’s Agenda Q&A Financial and Operational Overview Q1 2013 Review John Young President & CEO |
 Forward Natural Gas Prices and Heat Rates Forward gas prices have shown some indications of stabilizing, Heat rate markets continue to show volatility. 1 Calendar 2013 represents market price for the balance of the year. For example, as of March 31, 2013, the market price is for April to December 2013. 2 2015 is not considered liquid. The heat rate represents indicative pricing from limited brokers. 16 |
 17 1 ERCOT Capacity, Demand and Reserve (CDR) Summary, December 2012. 2 ERCOT Capacity, Demand and Reserve (CDR) Summary, May 2013. ERCOT reserve margin 2013E-2018E; percent December 2012 CDR 1 May 2013 CDR 2 Resource Adequacy in ERCOT 13.75% target reserve margin – – – – 13.2 13.8 11.6 10.4 10.5 9.4 '13 '14 '15 '16 '17 '18 ERCOT Loss of Load Probability (LOLP) study results indicate a higher target reserve margin is likely (i.e., 15%-16%); final decision pending at ERCOT Stakeholders and PUCT continue reviewing inputs to the ERCOT reserve margin methodology (CDR) PUCT considering additional market design changes, such as an operating reserve demand curve Yesterday ERCOT issued the May 2013 CDR, which increased the 2014 planning reserve margin to 13.8 percent versus 10.9 in the December 2012 CDR. The increase is primarily driven by higher expected generation resources Recent and pending PUCT/ERCOT actions and potential deliberations: |
 18 Today’s Agenda Q&A Financial and Operational Overview Q1 2013 Review EFH Corp. Senior Executive Team |
 19 Questions & Answers |
 20 Appendix – Additional Slides and Regulation G Reconciliations Appendix |
 Financial Definitions Measure Definition Adjusted (non-GAAP) Operating Results Net income (loss) adjusted for items representing income or losses that are not reflective of underlying operating results. These items include unrealized mark-to-market gains and losses, noncash impairment charges and other charges, credits or gains that are unusual or nonrecurring. EFH Corp. uses adjusted (non-GAAP) operating results as a measure of performance and believes that analysis of its business by external users is enhanced by visibility to both net income (loss) prepared in accordance with GAAP and adjusted (non-GAAP) operating earnings (losses). Adjusted EBITDA (non-GAAP) EBITDA adjusted to exclude interest income, noncash items, unusual items, results of discontinued operations and other adjustments. Adjusted EBITDA is not intended to be an alternative to GAAP results as a measure of operating performance or an alternative to cash flows from operating activities as a measure of liquidity or an alternative to any other measure of financial performance presented in accordance with GAAP, nor is it intended to be used as a measure of free cash flow available for EFH Corp.’s discretionary use, as the measure excludes certain cash requirements such as interest payments, tax payments and other debt service requirements. Because not all companies use identical calculations, Adjusted EBITDA may not be comparable to similarly titled measures of other companies. See EFH Corp.’s filings with the SEC for a detailed reconciliation of EFH Corp.’s net income prepared in accordance with GAAP to Adjusted EBITDA. Competitive Business Results Refers to the combined results of the Competitive Electric segment and Corporate & Other. Competitive Electric segment refers to the EFH Corp. business segment that consists principally of TCEH. Contribution Margin (non- GAAP) Operating revenues less fuel, purchased power costs, and delivery fees, plus or minus net gain (loss) from commodity hedging and trading activities, which on an adjusted (non-GAAP) basis, exclude unrealized gains and losses. EBITDA (non-GAAP) Net income (loss) before interest expense and related charges, income tax expense (benefit) and depreciation and amortization. GAAP Generally accepted accounting principles. Purchase Accounting The purchase method of accounting for a business combination as prescribed by GAAP, whereby the purchase price of a business combination is allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill. Depreciation and amortization due to purchase accounting represents the net increase in such noncash expenses due to recording the fair market values of property, plant and equipment, debt and other assets and liabilities, including intangible assets such as emission allowances, customer relationships and sales and purchase contracts with pricing favorable to market prices at the date of the Merger. Amortization is reflected in revenues, fuel, purchased power costs and delivery fees, depreciation and amortization and interest expense in the income statement. Regulated Business Results Refers to the results of the Regulated Delivery segment, which consists largely of EFH Corp.’s investment in Oncor. 21 |
 Table 1: EFH Corp. Adjusted EBITDA Reconciliation Three Months Ended March 31, 2012 and 2013 $ millions Factor Q1 12 Q1 13 Net loss (304) (569) Income tax benefit (180) (475) Interest expense and related charges 785 784 Depreciation and amortization 337 351 EBITDA 638 91 Adjustments to EBITDA (pre-tax): Oncor Holdings distributions of earnings 36 31 Interest income (2) - Amortization of nuclear fuel 42 39 Purchase accounting adjustments 1 21 5 Impairment and write-down of assets 1 - Equity in earnings of unconsolidated subsidiary (net of tax) (57) (67) Unrealized net loss resulting from commodity hedging and trading transactions 152 487 Noncash compensation expense 2 4 3 Transition and business optimization costs 3 9 6 Transaction and merger expenses 4 10 10 Restructuring and other 5 - 16 Expenses incurred to upgrade or expand a generation station 6 26 46 Subtotal 880 667 Add Oncor Adjusted EBITDA (reduced by Oncor Holdings distributions) 350 384 EFH Corp. Adjusted EBITDA per Restricted Payments Covenant 1,230 1,051 1 Includes amortization of the intangible net asset value of retail and wholesale power sales agreements, environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped-up value of nuclear fuel. Also includes certain credits and gains on asset sales not recognized in net income due to purchase accounting. 2 Represents amounts recorded under stock-based compensation accounting standards and excludes capitalized amounts. 3 Includes certain incentive compensation expenses as well as professional fees and other costs related to generation plant reliability and supply chain efficiency initiatives. 4 Primarily represents Sponsor Group management fees. 5 Includes costs associated with liability management program. 6 Represents noncapital outage costs. 22 |
 Table 2: TCEH Adjusted EBITDA Reconciliation Three Months Ended March 31, 2012 and 2013 $ millions Factor Q1 12 Q1 13 Net loss (238) (524) Income tax benefit (115) (378) Interest expense and related charges 622 586 Depreciation and amortization 330 344 EBITDA 599 28 Adjustments to EBITDA (pre-tax): Interest income (17) (4) Amortization of nuclear fuel 42 39 Purchase accounting adjustments 1 9 5 Unrealized net loss resulting from commodity hedging and trading transactions 152 487 EBITDA amount attributable to consolidated unrestricted subsidiaries (2) - Corporate depreciation, interest and income tax expenses included in SG&A expense 4 4 Noncash compensation expense 2 3 2 Transition and business optimization costs 3 9 5 Transaction and merger expenses 4 10 10 Restructuring and other 5 (1) 16 Expenses incurred to upgrade or expand a generation station 6 26 46 TCEH Adjusted EBITDA per Incurrence Covenant 834 638 Expenses related to unplanned generation station outages 26 10 TCEH Adjusted EBITDA per Maintenance Covenant 860 648 23 1 2 3 4 5 6 Includes amortization of the intangible net asset value of retail and wholesale power sales agreements, environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel. Also includes certain credits and gains on asset sales not recognized in net income due to purchase accounting. Includes expenses recorded under stock-based compensation accounting standards and excludes capitalized amounts. Includes certain incentive compensation expenses as well as professional fees and other costs related to generation plant reliability and supply chain efficiency initiatives. Primarily represents Sponsor Group management fees. Includes costs associated with liability management program. Represents noncapital outage costs. |
 Table 3: Oncor Adjusted EBITDA Reconciliation Three Months Ended March 31, 2012 and 2013 $ millions Factor Q1 12 Q1 13 Net income 75 87 Income tax expense 49 39 Interest expense and related charges 91 94 Depreciation and amortization 184 199 EBITDA 399 419 Interest income (8) (1) Purchase accounting adjustments1 (6) (5) Noncash compensation expense 1 1 Settlement of management incentive pay plan - 1 Oncor Adjusted EBITDA 386 415 1 Purchase accounting adjustments consist of amounts related to the accretion of an adjustment (discount) to regulatory assets. 24 |