| | For further information: Paula Waters, VP, Investor Relations 504/576-4380 pwater1@entergy.com |
INVESTOR NEWS
April 24, 2014
ENTERGY REPORTS FIRST QUARTER EARNINGS
Cold weather and Northeast infrastructure limitations drive revenue growth
NEW ORLEANS – Entergy Corporation (NYSE: ETR) today reported earnings per share of $2.24 on an as-reported basis and $2.29 on an operational basis for first quarter 2014, higher than the same quarter a year ago. See Table 1. More detail on quarterly results can be found beginning on page 2.
“The story for first quarter results was net revenue,” said Entergy Chairman and Chief Executive Officer Leo Denault. “The cold weather we experienced this past winter put stress on the power and gas systems, driving volatility and higher prices, and gave a glimpse of the longer term path these markets are on due to years of market design issues and regulatory intervention. The market prices realized this winter allowed us to capture significant value through our hedging strategy, and it highlighted the diversification value of our nuclear assets in that region.
“Utility revenue also benefitted from the cold weather,” he continued. “However, even on a weather-adjusted basis, sales growth was positive for residential, commercial and industrial customer classes and was consistent with our expectation for continued sales growth.”
| Table 1: Consolidated Earnings – Reconciliation of GAAP to Non-GAAP Measures |
| First Quarter 2014 vs. 2013 |
| (Per share in U.S. $) |
| | First Quarter |
| | 2014 | 2013 | Change |
| As-Reported Earnings | 2.24 | 0.90 | 1.34 |
| Less Special Items | (0.05) | (0.04) | (0.01) |
| Operational Earnings | 2.29 | 0.94 | 1.35 |
| Weather Impact | 0.18 | (0.10) | 0.28 |
| | | | |
Operational Earnings Highlights for First Quarter 2014
| · | EWC earnings increased, driven by higher net revenue; a lower effective income tax rate partially offset by higher depreciation also contributed. |
| · | Utility earnings were higher due primarily to higher net revenue driven by higher sales volume including weather and lower non-fuel O&M expense. |
| · | Parent & Other results were about the same as last year. |
Other business highlights for the quarter included the following:
| · | ETI filed a unanimous rate case settlement agreement and the ALJ approved interim rates; PUCT approval is pending. |
| · | APSC granted EAI’s rehearing request in its 2013 rate case. |
| · | IP2 returned to service after a 24-day scheduled refueling outage, the site’s shortest ever. |
| · | The Vermont PSB issued a certificate of public good for VY to operate through 2014. |
| · | The EPA named ENOI a 2014 ENERGY STAR Partner of the Year Award recipient for its Energy Smart energy efficiency program. |
A teleconference will be held at 10 a.m. CT on Thursday, April 24, 2014, to discuss Entergy’s first quarter 2014 earnings announcement and the company’s financial performance. The teleconference may be accessed by dialing (719) 325-2115, confirmation code 6761108, no more than 15 minutes prior to the start of the call or by visiting Entergy’s website at www.entergy.com. The presentation slides are also available on Entergy’s website concurrent with this release, which was issued before market open on the day of the call. A replay of the teleconference will be available by telephone and on Entergy’s website at www.entergy.com. The telephone replay will be available through noon CT on Thursday, May 1, 2014, by dialing (719) 457-0820, confirmation code 6761108.
Consolidated Earnings
Table 2 provides a comparative summary of consolidated earnings per share for first quarter 2014 versus 2013, including a reconciliation of GAAP as-reported earnings to non-GAAP operational earnings. A detailed discussion of the factors driving quarterly results at each business segment follows.
Table 2: Consolidated Earnings – Reconciliation of GAAP to Non-GAAP Measures First Quarter 2014 vs. 2013 (see Appendix D for definitions of certain measures) |
| (Per share in U.S. $) |
| | First Quarter |
| | 2014 | 2013 | Change |
| As-Reported | | | |
| Utility | 1.12 | 0.69 | 0.43 |
| Entergy Wholesale Commodities | 1.35 | 0.46 | 0.89 |
| Parent & Other | (0.23) | (0.25) | 0.02 |
| Consolidated As-Reported Earnings | 2.24 | 0.90 | 1.34 |
| | | | |
| Less Special Items | | | |
| Utility | (0.01) | (0.04) | 0.03 |
| Entergy Wholesale Commodities | (0.04) | - | (0.04) |
| Parent & Other | - | - | - |
| Consolidated Special Items | (0.05) | (0.04) | (0.01) |
| | | | |
| Operational | | | |
| Utility | 1.13 | 0.73 | 0.40 |
| Entergy Wholesale Commodities | 1.39 | 0.46 | 0.93 |
| Parent & Other | (0.23) | (0.25) | 0.02 |
| Consolidated Operational Earnings | 2.29 | 0.94 | 1.35 |
| Weather Impact | 0.18 | (0.10) | 0.28 |
| | | | |
Detailed earnings variance analyses are included in Appendix A-1 to this release. In addition, Appendix A-2 provides details of special items shown in Table 2 above.
Consolidated Operating Cash Flow
Entergy’s operating cash flow in first quarter 2014 was $767 million compared to $544 million in first quarter 2013. The overall quarterly increase was driven largely by higher cash flow from EWC and Utility net revenue. The increase in cash flow from Utility net revenue included the offsetting effect of decreased recovery of fuel costs. The increases were partially offset by higher pension funding.
Table 3 provides the components of operating cash flow contributed by each business with a current quarter comparison.
| Table 3: Consolidated Operating Cash Flow |
| First Quarter 2014 vs. 2013 |
| (U.S. $ in millions) |
| | First Quarter |
| | 2014 | 2013 | Change |
| Utility | 405 | 369 | 36 |
| Entergy Wholesale Commodities | 424 | 235 | 189 |
| Parent & Other | (62) | (60) | (2) |
| Total Operating Cash Flow | 767 | 544 | 223 |
| | | | |
In first quarter 2014, Utility earnings were $1.12 per share on an as-reported basis and $1.13 per share on an operational basis, compared to as-reported earnings per share of $0.69 and operational earnings per share of $0.73 in first quarter 2013. The quarter-over-quarter increase in operational earnings per share was due primarily to higher net revenue; lower non-fuel O&M expense also contributed. The decrease in non-fuel O&M was due partly to lower compensation and benefits expense.
Higher Utility net revenue was driven largely by colder-than-normal weather in the first quarter of the current year compared to unfavorable weather in the comparable period last year. Higher sales on a weather-adjusted basis also contributed to the increase in net revenue. These increases were partially offset by a quarter-over-quarter decrease in unbilled revenue.
Retail electric sales in billed gigawatt-hours by customer segment are summarized in Table 4. First quarter 2014 sales reflected the following:
| · | Residential sales, on a weather-adjusted basis, increased 1.9 percent compared to first quarter 2013. |
| · | Weather-adjusted commercial and governmental sales increased 2.0 percent quarter over quarter. |
| · | Industrial sales in the first quarter increased 2.5 percent compared to the same quarter of 2013. |
Billed retail sales increased 2.1 percent on a weather-adjusted basis. The increase was from residential, commercial and industrial customer classes and reflected growth in both the number of customers as well as usage per customer. Industrial sales growth was attributable to expansions, recovery of a major refining customer from an unplanned outage last year and continued moderate growth in the manufacturing sector both domestically and internationally.
Table 4 also provides a comparative summary of Utility operational performance measures.
| Table 4: Utility Operational Performance Measures |
First Quarter 2014 vs. 2013 (see Appendix D for definitions of certain measures) |
| | | |
| | First Quarter |
| | 2014 | 2013 | % Change | % Weather Adjusted |
| GWh billed | | | | |
| Residential | 10,027 | 8,344 | 20.2% | 1.9% |
| Commercial and governmental | 7,384 | 7,005 | 5.4% | 2.0% |
| Industrial | 10,113 | 9,868 | 2.5% | 2.5% |
| Total Retail Sales | 27,524 | 25,217 | 9.2% | 2.1% |
| Wholesale | 2,234 | 630 | 254.6% | |
| Total Sales | 29,758 | 25,847 | 15.1% | |
| Non-fuel O&M per MWh (a) | $17.53 | $21.02 | (16.6)% | |
| Number of electric retail customers | | | | |
| Residential | 2,403,321 | 2,388,522 | 0.6% | |
| Commercial and governmental | 359,595 | 356,809 | 0.8% | |
| Industrial | 40,044 | 38,744 | 3.4% | |
| Total Retail Customers | 2,802,960 | 2,784,075 | 0.7% | |
| | | | | |
| (a) | First quarter 2013 excludes the special item associated with the proposed spin-merge of the transmission business; first quarter 2014 excludes the special item for HCM implementation expenses. |
Appendix B provides information on selected regulatory cases.
| III. | Entergy Wholesale Commodities |
EWC operational adjusted EBITDA was $455 million in first quarter 2014, compared to $194 million in the same period a year ago, as shown in Table 5.
| Table 5: Entergy Wholesale Commodities Operational Adjusted EBITDA – Reconciliation of GAAP to Non-GAAP Measures |
First Quarter 2014 vs. 2013 (see Appendix D for definitions of certain measures) |
| ($ in millions) |
| | First Quarter |
| | 2014 | 2013 | Change |
| Net income | 242 | 82 | 160 |
| Add back: interest expense | 5 | 3 | 2 |
| Add back: income tax expense | 119 | 57 | 62 |
| Add back: depreciation and amortization | 70 | 49 | 21 |
| Subtract: interest and investment income | 26 | 28 | (2) |
| Add back: decommissioning expense | 34 | 31 | 3 |
| Adjusted EBITDA | 444 | 194 | 250 |
| Add back: special item for HCM implementation expenses (pre-tax) | 1 | - | 1 |
| Add back: special item resulting from the decision to close VY | 10 | - | 10 |
| Operational adjusted EBITDA | 455 | 194 | 261 |
| | | | |
Totals may not foot due to rounding.
The quarter-over-quarter increase was driven by significantly higher realized wholesale energy prices. The realized price for EWC’s nuclear fleet was approximately $89 per MWh in the first quarter of this year – more than 50 percent higher than the $58 realized price from the comparable quarter a year ago. EWC’s hedging strategies routinely include financial instruments that manage operational and liquidity risk. These positions, in addition to a larger-than-normal unhedged position in 2014 due to VY being in its final year of operation, allowed EWC to benefit from increases in Northeast market power prices throughout the quarter. Net revenue also reflected mark-to-market activity, which was positive for the quarter.
Contribution to first quarter 2014 operational adjusted EBITDA from VY, scheduled to be closed later this year at the end of its current operating cycle, was approximately $110 million.
EWC as-reported earnings were $1.35 per share and operational earnings were $1.39 per share for first quarter 2014, compared to first quarter 2013 earnings of $0.46 per share on both an as-reported and an operational basis. The increase in operational earnings was driven by higher operational adjusted EBITDA. A lower effective income tax rate was another factor contributing to higher quarterly earnings. These items were partially offset by higher depreciation expense.
Table 6 provides a comparative summary of EWC operational performance measures.
| Table 6: Entergy Wholesale Commodities Operational Performance Measures |
First Quarter 2014 vs. 2013 (see Appendix D for definitions of certain measures) |
| |
| | First Quarter |
| | 2014 | 2013 | % Change |
| Owned capacity (MW) (b) | 6,068 | 6,612 | (8.2)% |
| GWh billed | 10,014 | 10,387 | (3.6)% |
| Net revenue ($ millions) | 748 | 493 | 51.7% |
| Average realized revenue per MWh | $90.68 | $58.66 | 54.6% |
| Non-fuel O&M per MWh (c) | $25.50 | $25.22 | 1.1% |
| | | | |
| EWC Nuclear Fleet | | | |
| Capacity factor | 82% | 83% | (1.2)% |
| GWh billed | 9,079 | 9,246 | (1.8)% |
| Average realized revenue per MWh | $88.86 | $57.82 | 53.7% |
| Production cost per MWh (c) | $26.72 | $25.94 | 3.0% |
| Refueling outage days | | | |
| IP2 | 24 | - | |
| IP3 | - | 28 | |
| Palisades | 56 | - | |
| VY | - | 22 | |
| | | | |
| (b) | First quarter 2014 was reduced due to the retirement of R.E. Ritchie Unit 2 (gas/oil) plant in November 2013 (544 MW). |
| (c) | First quarter 2014 excluded the effect of the special items for HCM implementation expenses and costs resulting from the decision to close VY. |
Table 7 provides information on current forward capacity and generation contracts for EWC’s fleet. Positions that are no longer classified as hedges are netted in the percent of planned generation under contract. It also provides total revenue projections using market prices as of March 31, 2014, adjusted for internal expectations for the new NYISO LHV capacity zone starting in May 2014. Since the new zone was put in production at the end of the first quarter, market quotes are not widely available beyond auctions held to date. EWC uses a combination of forward physical and financial contracts, including swaps, collars, put and/or call options to manage certain risks of that business including forward commodity price, operational and liquidity risks. Certain hedge volumes have price downside and upside relative to market price movements. The contracted minimum, current expected value and sensitivities are provided to show potential variations. The sensitivities may not reflect the total upside potential from higher market prices. Information contained in Table 7 represents projections at a point in time and will vary over time based on numerous factors, such as future market prices, contracting activities and generation.
| Table 7: Entergy Wholesale Commodities Capacity and Generation |
Second Quarter 2014 through 2018 (see Appendix D for definitions of certain measures) |
(Based on market prices as of March 31, 2014) (d) |
| | Balance of 2014 | 2015 | 2016 | 2017 | 2018 |
| EWC Nuclear Portfolio | | | | | |
| Energy | | | | | |
| Planned TWh of generation | 30 | 35 | 36 | 35 | 35 |
| Percent of planned generation under contract | | | | | |
| Unit-contingent | 25% | 17% | 16% | 14% | 14% |
| Unit-contingent with availability guarantees | 16% | 15% | 14% | 15% | 3% |
| Firm LD | 58% | 42% | 10% | - | - |
| Offsetting positions | (24)% | - | - | - | - |
| Total | 75% | 74% | 40% | 29% | 17% |
| Average revenue per MWh on contracted volumes | | | | | |
| Minimum | $44 | $43 | $47 | $51 | $56 |
| Expected based on current market prices | $48 | $53 | $50 | $53 | $56 |
| Sensitivity: -/+ $10 per MWh market price change | $45-$51 | $48-$58 | $48-$52 | $52-$54 | $56 |
| | | | | | |
| Capacity | | | | | |
| Planned net MW in operation | 5,011 | 4,406 | 4,406 | 4,406 | 4,406 |
| Percent of capacity sold forward | | | | | |
| Bundled capacity and energy contracts | 15% | 18% | 18% | 18% | 18% |
| Capacity contracts | 40% | 15% | 15% | 16% | 7% |
| Total | 55% | 33% | 33% | 34% | 25% |
Average revenue under contract per kW-month (applies to capacity contracts only) | $4.5 | $3.2 | $3.4 | $5.6 | $7.0 |
| | | | | | |
Total Nuclear Energy and Capacity Revenues (e) | | | | | |
| Expected sold and market total revenue per MWh | $54 | $53 | $51 | $52 | $52 |
| Sensitivity: -/+ $10 per MWh market price change | $49-$59 | $46-$59 | $44-$58 | $45-$59 | $44-$60 |
| | | | | | |
| EWC Non-Nuclear Portfolio | | | | | |
| Energy | | | | | |
| Planned TWh of generation | 5 | 5 | 6 | 6 | 6 |
| Percent of planned generation under contract | | | | | |
| Cost-based contracts | 43% | 38% | 36% | 33% | 34% |
| Firm LD | 8% | 7% | 7% | 6% | 7% |
| Total (f) | 51% | 45% | 43% | 39% | 41% |
| | | | | | |
| Capacity | | | | | |
| Planned net MW in operation | 1,052 | 1,052 | 1,052 | 977 | 977 |
| Percent of capacity sold forward | | | | | |
| Cost-based contracts | 24% | 24% | 24% | 26% | 26% |
| Bundled capacity and energy contracts | 8% | 8% | 8% | 8% | 8% |
| Capacity contracts | 52% | 53% | 53% | 56% | 24% |
| Total | 84% | 85% | 85% | 90% | 58% |
| | | | | | |
| Total Non-Nuclear Net Revenue | | | | | |
| Expected portfolio net revenue in $ millions | $66 | $92 | $99 | $120 | $133 |
| | | | | | |
| (d) | Assumes shutdown of VY in fourth quarter 2014 and uninterrupted normal operation at the remaining nuclear plants. NRC license renewal applications are in process for both Indian Point units; at midnight on 9/28/13, IP2 entered the period of extended operations under its current license and the current license for IP3 expires 12/12/15. |
| (e) | Includes current expectations for the new NYISO LHV capacity zone starting in May 2014. |
| (f) | The percentage sold assumes completion of the necessary transmission upgrades required for the approved transmission rights. |
Parent & Other reported a loss of $(0.23) per share on an as-reported and operational basis for first quarter 2014, compared to a first quarter 2013 as-reported and operational loss of $(0.25) per share. No item was individually significant.
| V. | 2014 Earnings Guidance |
Entergy affirmed its 2014 operational earnings guidance in the range of $5.55 to $6.75 per share. The guidance range, which was revised and widened on April 15, 2014, from $4.60 to $5.40 per share, is summarized in Table 8. The guidance range was widened to reflect increased volatility in the Northeast power markets year-to-date and the potential for that to continue through the rest of the year. The current range reflects strong first quarter 2014 results as well as other updates. Key assumptions on major drivers to the new guidance range versus original guidance are noted below. Because there is a range of possible outcomes associated with each earnings driver, a range is applied to the guidance midpoint to produce Entergy’s guidance range.
| Table 8: 2014 Operational Earnings Per Share Guidance |
| (Per share in U.S. $) – Updated April 2014 |
| Segment | Description of Drivers | Original 2014 Guidance Midpoint | Expected Change | Revised 2014 Guidance Midpoint | Revised 2014 Guidance Range |
| | | | | | |
| Utility | Original 2014 Operational EPS Guidance Midpoint | 5.20 | | | |
| | Net revenue, including first quarter 2014 weather | | 0.05 | | |
| | Non-fuel O&M/other | | (0.10) | | |
| | Higher effective income tax rate | | (0.15) | | |
| | Subtotal | 5.20 | (0.20) | 5.00 | |
| | | | | | |
| Entergy Wholesale Commodities | Original 2014 Operational EPS Guidance Midpoint | 0.85 | | | |
| Net revenue driven by higher price for nuclear assets | | 1.35 | | |
| Non-fuel O&M/other | | (0.10) | | |
| | Lower effective income tax rate | | 0.10 | | |
| | Subtotal | 0.85 | 1.35 | 2.20 | |
| | | | | | |
| Parent & Other | Original 2014 Operational EPS Guidance Midpoint | (1.05) | - | (1.05) | |
| | | | | | |
| Consolidated Operational | Revised 2014 Operational EPS Guidance Range | 5.00 | 1.15 | 6.15 | 5.55 – 6.75 |
| | | | | | |
Key assumptions on the revisions follow.
Utility
| · | Expected change in Utility net revenue includes favorable weather effect through first quarter 2014, partially offset by the effects of an unplanned negative variance to unbilled revenue, and rate case outcomes different than planned |
| · | Non-fuel O&M/other is higher due largely to consideration of opportunistic spending, net of lower-than-planned pension expense |
| · | Higher effective income tax rate driven by timing of tax benefits now expected to be realized in a later period |
Entergy Wholesale Commodities
| · | EWC net revenue driven by higher price for Northeast nuclear fleet |
| · | For the balance of the year, approximately $54/MWh average price for EWC-nuclear fleet’s total energy and capacity revenues, based on published market prices at the end of March 2014 |
| o | $49/MWh average market price on approximately 25 percent unsold energy volumes |
| o | $5.7/kW-month average capacity price on approximately 45 percent unsold capacity |
| · | Non-fuel O&M/other is attributable to EWC performance and consideration of opportunistic spending, net of lower-than-planned pension expense |
| · | Lower effective income tax rate due to first quarter 2014 tax benefit |
Other
| · | Overall consolidated effective income tax rate of 37 percent in 2014 |
Operational earnings guidance for 2014 should be considered in association with earnings sensitivities as shown in Table 9. These sensitivities illustrate the estimated change in operational earnings per share resulting from changes in various revenue and expense drivers. Traditionally, the most significant variables for earnings drivers are retail sales for the Utility and energy prices for EWC.
Estimated annual impacts shown in Table 9 are intended to be indicative rather than precise guidance.
| Table 9: 2014 Earnings Sensitivities |
| (Per share in U.S. $) – Updated April 2014 |
| Variable | 2014 Revised Guidance Assumption | Description of Change | Estimated Annual Impact |
| Utility | | | |
Retail sales growth Residential Commercial / Governmental Industrial | Around 1.9% retail sales growth on a weather adjusted basis, 0.6% excluding industrial expansions | 1% change in Residential MWh sold 1% change in Comm / Govt MWh sold 1% change in Industrial MWh sold | - / + 0.05 - / + 0.04 - / + 0.02 |
| Rate base | Growing rate base | $100 million change in rate base | - / + 0.03 |
| Return on equity | Authorized regulatory ROEs | 100 basis point change in allowed ROE | - / + 0.44 |
| Non-fuel O&M | Lower due to HCM and compensation and benefits costs, partially offset by other increases | 1% change in expense | + / - 0.08 |
Entergy Wholesale Commodities (g) | | |
| Nuclear capacity factor | 90% capacity factor | 1% change in capacity factor | - / + 0.06 |
| EWC revenue (energy) | $54/MWh nuclear revenue; Non-nuclear net revenue | $10/MWh market price change | (0.46) / + 0.51 (h) |
| EWC revenue (capacity) | $5.7/kW-month average capacity price on 45% unsold nuclear capacity (including VY) | $0.50/kW-month change in capacity price on nuclear capacity | - / + 0.03 (h) |
| Total non-fuel O&M | Lower due to HCM, compensation and benefits costs and the sale of District Energy, partially offset by other increases | 1% change in expense | + / - 0.04 |
| Nuclear Outage (lost revenue only) | 90% capacity factor, including refueling outages for three EWC nuclear units | 1,000 MW plant for 10 days at average portfolio energy price of $47/MWh for contracted volumes and $39/MWh for unsold volumes in 2014 (assuming no resupply option exercise) | (0.03) / n/a |
| Consolidated | | | |
| Interest expense | Higher debt outstanding balances | 1% change in interest rate on $1 billion debt | + / - 0.03 |
| Pension and other postretirement costs (expense portion only) | Discount rate of 4.36% | 0.25% change | - / + 0.07 |
| Effective income tax rate | 37% effective income tax rate | 1% change in overall effective income tax rate | + / - 0.10 |
| |
| (g) | Assumes shutdown of VY in fourth quarter 2014 and uninterrupted normal operation at the remaining nuclear plants. |
| (h) | Reflects price sensitivity for the second through fourth quarters of 2014. |
Five appendices are presented in this section as follows:
| · | Appendix A includes earnings per share variance analysis and detail on special items that relate to the current quarter results. |
| · | Appendix B provides information on selected Utility regulatory cases. |
| · | Appendix C provides financial metrics for both current and historical periods. In addition, historical financial and operating performance metrics are included for the trailing eight quarters. |
| · | Appendix D provides definitions of the operational performance measures, GAAP and non-GAAP financial measures and abbreviations or acronyms that are used in this release. |
| · | Appendix E provides a reconciliation of GAAP to non-GAAP financial measures used in this release. |
| A. | Variance Analysis and Special Items |
Appendix A-1 provides details of first quarter 2014 versus 2013 as-reported and operational earnings variance analysis for Utility, Entergy Wholesale Commodities, Parent & Other and Consolidated.
| Appendix A-1: As-Reported and Operational Earnings Per Share Variance Analysis |
| First Quarter 2014 vs. 2013 |
| (Per share in U.S. $, sorted in consolidated operational column, most to least favorable) |
| | | | | | | | |
| | Utility | | Entergy Wholesale Commodities | | Parent & Other | | Consolidated |
| | As- Reported | Opera- tional | | As- Reported | Opera- tional | | As- Reported | Opera- tional | | As- Reported | Opera- tional |
| 2013 earnings | 0.69 | 0.73 | | 0.46 | 0.46 | | (0.25) | (0.25) | | 0.90 | 0.94 |
| Net revenue | 0.39 | 0.39 | (i) | 0.88 | 0.88 | (j) | (0.01) | (0.01) | | 1.26 | 1.26 |
| Income taxes - other | - | - | | 0.13 | 0.13 | (k) | 0.02 | 0.02 | | 0.15 | 0.15 |
| Other O&M | 0.10 | 0.07 | (l) | (0.02) | 0.02 | | (0.01) | (0.01) | | 0.07 | 0.08 |
| Other income (deductions) - other | 0.01 | 0.01 | | (0.01) | (0.01) | | - | - | | - | - |
| Preferred dividend requirements | - | - | | - | - | | 0.01 | 0.01 | | 0.01 | 0.01 |
| Taxes other than income taxes | (0.01) | (0.01) | | - | - | | - | - | | (0.01) | (0.01) |
| Decommissioning expense | (0.01) | (0.01) | | (0.01) | (0.01) | | - | - | | (0.02) | (0.02) |
| Interest expense and other charges | (0.03) | (0.03) | | (0.01) | (0.01) | | 0.01 | 0.01 | | (0.03) | (0.03) |
| Depreciation / amortization expense | (0.02) | (0.02) | | (0.07) | (0.07) | (m) | - | - | | (0.09) | (0.09) |
| 2014 earnings | 1.12 | 1.13 | | 1.35 | 1.39 | | (0.23) | (0.23) | | 2.24 | 2.29 |
| | | | | | | | | | | | |
Utility Net Revenue Variance Analysis 2014 vs. 2013 ($ EPS) |
| | First Quarter |
| Weather | 0.28 |
| Sales growth / pricing | 0.07 |
| Other | 0.04 |
| Total | 0.39 |
| (i) | The quarter-over-quarter increase is due largely to favorable weather in the first quarter of 2014 compared to unfavorable weather in the comparable quarter last year. Higher sales on a weather-adjusted basis also contributed. These increases were partially offset by a quarter-over-quarter decrease in unbilled revenue. The net effect of pricing adjustments contributed to the net revenue increase, but were mostly for recovery of costs below net revenue. |
| (j) | The increase period-over-period was due largely to higher realized wholesale prices, mostly due to higher energy prices for EWC’s Northeast nuclear assets. The realized price also included the net effect of mark-to-market activity, which was positive in the current period including turnaround of negative mark-to-market in the fourth quarter of 2013. |
| (k) | The quarter-over-quarter increase was due primarily to a change in New York law which resulted in a reduction of deferred income taxes of approximately $21.5 million. |
| (l) | The increase compared to the first quarter last year is due largely to lower compensation and benefits expense which was attributable to several factors including fewer employees, higher pension discount rate effects and pension plan design changes. Fossil spending was also lower than the prior period due to lower outage expenses. A portion of the increase was partially offset by higher net revenue, including storm accruals and higher spending related to energy efficiency. New MISO RTO administration fees also provided a partial offset. The as-reported increase was driven by expenses in the prior period in connection with the planned spin-merge of the transmission business. |
| (m) | The quarter-over-quarter decrease is due primarily to the effects of a new depreciation study and an increase in depreciable plant. |
Appendix A-2 lists special items by business with quarter-to-quarter comparisons. Amounts are shown on both an earnings per share basis and a net income basis. Special items are those events that are not routine. Special items are included in as-reported earnings per share consistent with GAAP, but are excluded from operational earnings per share. As a result, operational earnings per share is considered a non-GAAP measure.
| Appendix A-2: Special Items (shown as positive / (negative) impact on earnings) |
| First Quarter 2014 vs. 2013 |
| (Per share in U.S. $) |
| | First Quarter |
| | 2014 | 2013 | Change |
| Utility | | | |
| Transmission business spin-merge expenses | - | (0.04) | 0.04 |
| HCM implementation expenses | (0.01) | - | (0.01) |
| Total Utility | (0.01) | (0.04) | 0.03 |
| | | | |
| Entergy Wholesale Commodities | | | |
| Decision to close VY | (0.03) | - | (0.03) |
| HCM implementation expenses | (0.01) | - | (0.01) |
| Total Entergy Wholesale Commodities | (0.04) | - | (0.04) |
| | | | |
| Parent & Other | - | - | - |
| | | | |
| Total Special Items | (0.05) | (0.04) | (0.01) |
| | | | |
| (U.S. $ in millions) | | | |
| | First Quarter |
| | 2014 | 2013 | Change |
| Utility | | | |
| Transmission business spin-merge expenses | - | (6.3) | 6.3 |
| HCM implementation expenses | (2.3) | - | (2.3) |
| Total Utility | (2.3) | (6.3) | 4.0 |
| | | | |
| Entergy Wholesale Commodities | | | |
| Decision to close VY | (5.9) | - | (5.9) |
| HCM implementation expenses | (0.7) | - | (0.7) |
| Total Entergy Wholesale Commodities | (6.6) | - | (6.6) |
| | | | |
| Parent & Other | - | - | - |
| | | | |
| Total Special Items | (8.9) | (6.3) | (2.6) |
| | | | |
Appendix B provides a summary of selected regulatory cases.
Appendix B: Regulatory Summary (see Appendix D for definitions of certain abbreviations or acronyms) |
| Company | Cases |
| Retail Regulation | |
Entergy Arkansas Authorized ROE: 9.3% Last filed rate base: $4.8 billion filed 1/9/14 based on 12/31/12 test year, with known and measureable changes through 12/31/13 | Recent Activity/Next Steps: On Feb. 26, 2014, the APSC granted rehearing for the purpose of considering additional evidence identified by EAI in its base rate case filed in March 2013 and established a procedural schedule for additional testimony, now complete. An APSC decision is pending. Background: In its original Dec. 30, 2013 order, the APSC approved a base rate increase of $81 million effective Dec. 31, 2013, including a 9.3% ROE. Approximately $64 million of the base rate increase was the reclassification of riders to base rates and ANO2 wholesale to retail with no effect on earnings. The base rate increase also included $13.6 million for storm reserve increases and $4 million for depreciation changes (reflecting a reduction in depreciation rates and an increase in plant in service). The MISO rider and the capacity cost rider proposed by EAI were approved. |
Entergy Gulf States Louisiana Authorized ROE range: 9.15 - 10.75% (electric); 9.45 - 10.45% (gas) Last filed rate base: $2.7 billion (electric) filed 2/15/13 based on 6/30/12 test year $0.05 billion (gas) filed 1/31/14 based on 9/30/13 test year | Recent Activity/Next Steps: A compliance FRP filing will be made on May 30, 2014. Background: On Dec. 16, 2013, the LPSC approved a settlement resolving EGSL’s 2013 electric rate case. The settlement results in no change to the base rider FRP revenue related to test year 2013, except recovery of the non-fuel related MISO costs, including the recovery of the deferred MISO implementation costs, and any capacity cost changes effective with the first billing cycle in December 2014. The settlement also provides for a three-year FRP for the 2014 through 2016 test years with a 9.95% ROE and a +/- 80 basis point bandwidth. Earnings outside the bandwidth are allocated prospectively, 60% to customers and 40% to EGSL. Other provisions of the settlement include recovery outside of the bandwidth for the Ninemile 6 new CCGT project and no cost of service increase for the 2014 test year. |
Entergy Louisiana Authorized ROE range: 9.15 - 10.75% Last filed rate base: $4.5 billion filed 2/15/13 based on 6/30/12 test year | Recent Activity/Next Steps: A compliance FRP filing will be made on May 15, 2014. Background: On Dec. 16, 2013, the LPSC approved a settlement resolving ELL’s 2013 rate case. The settlement provides for a $10 million cost of service increase and recovery of the non-fuel related MISO costs, including the recovery of the deferred MISO implementation costs, and any capacity cost changes effective with the first billing cycle in December 2014. The settlement also provides for a three-year FRP for the 2014 through 2016 test years with a 9.95% ROE and a +/- 80 basis point bandwidth. Earnings outside the bandwidth are allocated prospectively, 60% to customers and 40% to ELL. Other provisions of the settlement include recovery outside of the bandwidth for the Ninemile 6 new CCGT project and a cumulative $30 million cap on cost of service increases over the three-year FRP cycle, exclusive of items outside of the sharing mechanism but inclusive of the initial $10 million base rate increase in December 2014. |
Entergy Mississippi Authorized ROE range: 9.76 - 11.83% (per 4/30/13 filing based on 12/31/12 test year) Last filed rate base: $1.7 billion filed 4/30/13 based on 12/31/12 test year | Recent Activity/Next Steps: On March 14, 2014, EMI made its FRP information-only submittal for the 2013 test year to the MPUS reporting an earned return which is within the FRP bandwidth. EMI is preparing a general rate case that could be filed next month pending discussions with the MPSC. No final decision has been made to file a rate case at this time. Background: On Jan. 7, 2014, the MPSC suspended EMI’s 2013 test year FRP filing and requested EMI to make an abbreviated, information-only filing. EMI’s FRP includes an annual redetermination of the benchmark ROE based on a formula tied to interest rates and equity risk premiums, with an adjustment based upon performance ratings. Returns inside the bandwidth result in no change in rates while returns outside the bandwidth reset rates prospectively to or within the bandwidth depending on performance, subject to a 4% revenue limit. The annual filing occurs each March with rates effective in June (if no hearing) or July (if hearing). EMI’s FRP does not have an expiration date. On Aug. 13, 2013, the MPSC approved a stipulation resolving EMI’s 2012 test year FRP. Without agreeing to any specific disallowances, the stipulation provided for a rate increase of approximately $22.3 million, which brings EMI up to the equity “point of adjustment” of 10.59% from an 8.96% earned ROE for 2012. The annualized change was effective with September 2013 bills. |
Entergy New Orleans Authorized ROE range: 10.7 - 11.5% (electric) and 10.25 - 11.25% (gas) Last filed rate base: $0.3 billion (electric) and $0.09 billion (gas) filed 5/12 based on 12/31/11 test year | Recent Activity/Next Steps: The new Ninemile 6 CCGT project is expected to be complete by the first part of 2015 and is currently ahead of schedule. Although ENOI’s FRP expired with the 2011 test year, ENOI expects to recover the costs associated with its 20% participation in the resource through a rider until new base rates are established in the next base rate proceeding. The timing of ENOI’s next base rate case filing is currently under consideration and is expected to be determined in the coming months. |
Entergy Texas Authorized ROE: 9.8% Last filed rate base: $1.6 billion filed 9/25/13 based on 3/31/13 adjusted test year Baselines for riders for future use: Transmission $93.6M Distribution: $155.7M Purchased power: $252.6M | Recent Activity/Next Steps: On April 4, 2014, ETI and other parties filed a unanimous “black box” settlement in the 2013 rate case, providing for an ROE of 9.8%, an $18.5 million base rate change effective April 1, 2014 and approval of riders for rate case expenses and RPCE payments. Other stipulated terms include approval of the as-filed $1.63 billion rate base and storm reserve accruals of $8.54 million per year. All remaining MISO transition expenses are deemed included in the agreed rate base, and there were no changes to depreciation rates and River Bend decommissioning funding. No special circumstances recovery of purchased power costs was allowed. Baselines were established for the transmission, distribution and capacity riders for future potential use. Interim rates reflecting this settlement went in effect April 1, subject to refund. A decision by the PUCT is expected in May. Background: On Sept. 25, 2013, ETI filed a rate case requesting a $38.6 million base rate increase and a 10.4% ROE based on a test year period ending March 31, 2013. ETI also requested rider recovery of rate case expenses and RPCE payments. Special circumstances recovery as fuel of approximately $22 million of historical purchased power capacity costs was reflected in the fuel reconciliation. On Jan. 17, 2014, the PUCT Staff filed direct testimony, recommending a retail rate reduction of $(0.3) million and a 9.2% ROE. |
| Wholesale Regulation |
System Energy Resources ROE and rate base, next column | Recent Activity: None. Authorized ROE: 10.94%; Last calculated rate base: $1.3 billion for 3/31/14 monthly cost of service |
| C. | Financial and Historical Performance Measures |
Appendix C-1 provides comparative financial performance measures for the current quarter. Appendix C-2 provides historical financial and operating performance measures for the trailing eight quarters. Financial performance measures in both tables include those calculated and presented in accordance with GAAP, as well as those that are considered non-GAAP measures.
As-reported measures are computed in accordance with GAAP as they include all components of net income, including special items. Operational measures are non-GAAP measures as they are calculated using operational net income, which excludes the impact of special items. A reconciliation of operational measures to as-reported measures is provided in Appendix E.
| Appendix C-1: GAAP and Non-GAAP Financial Performance Measures |
First Quarter 2014 vs. 2013 (see Appendix D for definitions of certain measures) |
| | |
| For 12 months ending March 31 | 2014 | 2013 | | Change |
| GAAP Measures | | | | |
| Return on average invested capital – as-reported | 5.7% | 6.9% | | (1.2%) |
| Return on average common equity – as-reported | 9.9% | 12.8% | | (2.9%) |
| Cash flow interest coverage | 6.6 | 5.9 | | 0.7 |
| Book value per share | $55.53 | $51.73 | | $3.80 |
| End of period shares outstanding (millions) | 179.1 | 178.1 | | 1.0 |
| | | | | |
| Non-GAAP Measures | | | | |
| Return on average invested capital – operational | 6.8% | 7.0% | | (0.2%) |
| Return on average common equity – operational | 12.5% | 13.2% | | (0.7%) |
| | | | | |
| As of March 31 ($ in millions) | 2014 | 2013 | | Change |
| GAAP Measures | | | | |
| Cash and cash equivalents | 908 | 263 | | 645 |
| Revolver capacity | 4,077 | 3,542 | | 535 |
| Commercial paper outstanding | 1,059 | 883 | | 176 |
| Total debt | 13,860 | 13,471 | | 389 |
| Securitization debt | 861 | 952 | | (91) |
| Debt to capital ratio | 57.5% | 58.7% | | (1.2%) |
| Off-balance sheet liabilities: | | | | |
| Debt of joint ventures – Entergy’s share | 86 | 90 | | (4) |
| Leases – Entergy’s share | 456 | 505 | | (49) |
| Total off-balance sheet liabilities | 542 | 595 | | (53) |
| | | | | |
| Non-GAAP Measures | | | | |
| Debt to capital ratio, excluding securitization debt | 55.9% | 56.9% | | (1.0%) |
| Gross liquidity | 4,985 | 3,805 | | 1,180 |
| Net debt to net capital ratio, excluding securitization debt | 54.1% | 56.3% | | (2.2%) |
| Net debt to net capital ratio including off-balance sheet liabilities, excluding securitization debt | 55.2% | 57.5% | | (2.3%) |
| | | | | |
Appendix C-2: Historical Performance Measures (see Appendix D for definitions of certain measures) |
| | | | 2Q12 | 3Q12 | 4Q12 | 1Q13 | 2Q13 | 3Q13 | 4Q13 | 1Q14 | 14YTD | 13YTD |
| Financial | | | | | | | | | | |
| | | EPS – as-reported ($) | 2.06 | 1.89 | 1.66 | 0.90 | 0.92 | 1.34 | 0.82 | 2.24 | 2.24 | 0.90 |
| | | Less – special items ($) | (0.05) | (0.06) | (0.06) | (0.04) | (0.09) | (1.07) | (0.18) | (0.05) | (0.05) | (0.04) |
| | | EPS – operational ($) | 2.11 | 1.95 | 1.72 | 0.94 | 1.01 | 2.41 | 1.00 | 2.29 | 2.29 | 0.94 |
| | Trailing twelve months | | | | | | | | | | |
| | | ROIC – as-reported (%) | 6.2 | 4.8 | 5.5 | 6.9 | 5.9 | 5.5 | 4.7 | 5.7 | | |
| | | ROIC – operational (%) | 7.4 | 6.0 | 6.6 | 7.0 | 6.1 | 6.4 | 5.8 | 6.8 | | |
| | | ROE – as-reported (%) | 11.3 | 7.8 | 9.3 | 12.8 | 10.5 | 9.3 | 7.6 | 9.9 | | |
| | | ROE – operational (%) | 14.2 | 10.7 | 12.2 | 13.2 | 10.9 | 11.7 | 10.2 | 12.5 | | |
| | | Cash flow interest coverage | 7.2 | 6.8 | 6.1 | 5.9 | 5.8 | 5.9 | 6.2 | 6.6 | | |
| | | Debt to capital ratio (%) | 57.4 | 57.7 | 58.7 | 58.7 | 59.0 | 58.4 | 57.9 | 57.5 | | |
| | | Debt to capital ratio, excluding securitization debt (%) | 55.3 | 55.7 | 56.9 | 56.9 | 57.3 | 56.7 | 56.3 | 55.9 | | |
| | | Net debt to net capital ratio, excluding securitization debt (%) | 54.7 | 54.1 | 55.8 | 56.3 | 56.7 | 56.0 | 54.8 | 54.1 | | |
| Utility |
| | | GWh billed | | | | | | | | | | |
| | | Residential | 7,940 | 11,605 | 7,360 | 8,344 | 7,377 | 11,359 | 8,089 | 10,027 | 10,027 | 8,344 |
| | | Commercial & Governmental | 7,753 | 9,101 | 7,313 | 7,005 | 7,267 | 9,041 | 7,647 | 7,384 | 7,384 | 7,005 |
| | | Industrial | 10,408 | 10,748 | 10,067 | 9,868 | 10,357 | 11,038 | 10,389 | 10,113 | 10,113 | 9,868 |
| | | Wholesale | 836 | 833 | 798 | 630 | 590 | 667 | 1,133 | 2,234 | 2,234 | 630 |
| | | Non-fuel O&M per MWh (n) | $19.94 | $16.66 | $22.19 | $21.02 | $23.44 | $18.15 | $21.99 | $17.53 | $17.53 | $21.02 |
| Entergy Wholesale Commodities |
| | | Owned Capacity in MW (o) | 6,612 | 6,612 | 6,612 | 6,612 | 6,612 | 6,612 | 6,068 | 6,068 | 6,068 | 6,612 |
| | | GWh billed | 11,674 | 12,002 | 11,221 | 10,387 | 11,172 | 11,630 | 11,938 | 10,014 | 10,014 | 10,387 |
| | | Net revenue ($ millions) | 444 | 495 | 463 | 493 | 383 | 494 | 432 | 748 | 748 | 493 |
| | | Operational adjusted EBITDA ($ millions) | 127 | 185 | 161 | 194 | 61 | 165 | 133 | 455 | 455 | 194 |
| | | Avg realized revenue per MWh | $48.27 | $51.88 | $50.56 | $58.66 | $47.36 | $53.22 | $45.05 | $90.68 | $90.68 | $58.66 |
| | | Non-fuel O&M per MWh (n) | $24.07 | $23.15 | $23.52 | $25.22 | $25.69 | $25.28 | $25.10 | $25.50 | $25.50 | $25.22 |
| | | EWC Nuclear Operational Measures |
| | | Capacity factor (%) | 85 | 90 | 90 | 83 | 82 | 94 | 97 | 82 | 82 | 83 |
| | | GWh billed | 10,426 | 10,480 | 10,298 | 9,246 | 9,789 | 10,274 | 10,858 | 9,079 | 9,079 | 9,246 |
| | | Avg realized revenue per MWh | $48.67 | $52.27 | $49.88 | $57.82 | $46.40 | $53.16 | $44.15 | $88.86 | $88.86 | $57.82 |
| | | Production cost per MWh (n) | $26.61 | $26.14 | $26.18 | $25.94 | $29.16 | $25.32 | $25.37 | $26.72 | $26.72 | $25.94 |
| | | | | | | | | | | | | |
| (n) | Excludes effect of special items: the proposed spin-merge of the transmission business at Utility (2012 and 2013 quarterly periods and 2013 year-to-date), HCM implementation expenses at Utility and EWC (2013 second, third and fourth quarters; 2014 first quarter and year-to-date) and expenses resulting from the decision to close VY at EWC (2013 third and fourth quarters; 2014 first quarter and year-to-date). |
| (o) | Fourth quarter 2013 and first quarter and year-to-date 2014 were reduced due to the retirement of R.E. Ritchie Unit 2 (gas/oil) plant in November 2013 (544 MWs). |
Appendix D provides definitions of certain operational performance measures, as well as GAAP and non-GAAP financial measures, all of which are referenced in this release. Non-GAAP measures are included in this release to provide metrics that remove the effect of financial events that are not routine, from commonly used financial metrics.
| Appendix D: Definitions of Operational Performance Measures, GAAP and Non-GAAP Financial Measures and Abbreviations or Acronyms |
| Utility Operational Performance Measures |
| GWh billed | Total number of GWh billed to all retail and wholesale customers |
| Non-fuel O&M per MWh | Operation, maintenance and refueling expenses per MWh of billed sales, excluding fuel, fuel-related expenses and purchased power |
| Number of retail customers | Number of customers at end of period |
| Entergy Wholesale Commodities Operational Performance Measures |
| Net revenue | Operating revenue less fuel, fuel related expenses and purchased power |
| Owned capacity | Installed capacity owned and operated by EWC, including investments in wind generation accounted for under the equity method of accounting; in November 2013, R.E. Ritchie Unit 2 (gas/oil) plant was retired (544 MWs) |
| GWh billed | Total number of GWh billed to customers, excluding investments in wind generation accounted for under the equity method of accounting and financially-settled instruments |
| Average realized revenue per MWh | As-reported revenue per MWh billed, excluding revenue from the amortization of the Palisades below-market PPA and/or investments in wind generation accounted for under the equity method of accounting |
| Non-fuel O&M per MWh | Operation, maintenance and refueling expenses per MWh billed, excluding fuel, fuel-related expenses and purchased power and investments in wind generation accounted for under the equity method of accounting |
| Capacity factor | Normalized percentage of the period that the nuclear plants generate power |
| Production cost per MWh | Fuel and non-fuel O&M expenses according to accounting standards that directly relate to the production of electricity per MWh (based on net generation) |
| Refueling outage days | Number of days lost for scheduled refueling outage during the period |
| Planned TWh of generation | Amount of output expected to be generated by EWC resources considering plant operating characteristics, outage schedules and expected market conditions which impact dispatch, assuming shutdown of VY in fourth quarter 2014, uninterrupted normal operation at the remaining nuclear plants and timely renewal of plant operating licenses; non-nuclear also includes purchases from affiliated and non-affiliated counterparties under long-term contracts and excludes energy and capacity from EWC’s wind investment accounted for under the equity method of accounting |
| Percent of planned generation under contract | Percent of planned generation output sold or purchased forward under contracts, forward physical contracts, forward financial contracts or options that mitigate price uncertainty that may or may not require regulatory approval or approval of transmission rights, or other conditions precedent; positions that are no longer classified as hedges are netted in the planned generation under contract |
| Unit-contingent | Transaction under which power is supplied from a specific generation asset; if the asset is not operating, seller is generally not liable to buyer for any damages |
| Unit-contingent with availability guarantees | Transaction under which power is supplied from a specific generation asset; if the asset is not operating, seller is generally not liable to buyer for any damages, unless the actual availability over a specified period of time is below an availability threshold specified in the contract |
| Firm LD | Transaction that requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset) or settles financially on notional quantities; if a party fails to deliver or receive energy, defaulting party must compensate the other party as specified in the contract; a portion of which may be capped through the use of risk management products |
| Offsetting positions | Transactions for the purchase of energy, generally to offset a Firm LD transaction |
| Cost-based contracts | Contracts priced in accordance with cost-based rates, a ratemaking concept used for the design and development of rate schedules to ensure that the filed rate schedules recover only the cost of providing the service; these contracts are on owned EWC resources located within Entergy’s utility service territory and were executed prior to EWC receiving market-based authority under MISO |
| Planned net MW in operation | Amount of installed capacity to generate power and/or sell capacity; non-nuclear also includes purchases from affiliated and non-affiliated counterparties under long-term contracts and excludes energy and capacity from EWC’s wind investment accounted for under the equity method of accounting |
| Percent of capacity sold forward | Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions |
| Bundled capacity and energy contracts | A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold |
| Capacity contracts | A contract for the sale of the installed capacity product in regional markets managed by ISO-NE, the NYISO and MISO |
| | |
| Appendix D: Definitions of Operational Performance Measures, GAAP and Non-GAAP Financial Measures and Abbreviations or Acronyms (continued) |
| Entergy Wholesale Commodities Operational Performance Measures (continued) |
| Average revenue per MWh on contracted volumes | Revenue on a per unit basis at which generation output reflected in contracts is expected to be sold to third parties (including offsetting positions) at the minimum contract prices and at forward market prices at a point in time, given existing contract or option exercise prices based on expected dispatch or capacity, excluding the revenue associated with the amortization of the below-market PPA for Palisades; revenue will fluctuate due to factors including market price changes affecting revenue received on puts, collars and call options, positive or negative basis differentials, option premiums and market prices at the time of option expiration, costs to convert firm LD to unit-contingent and other risk management costs; also, excludes payments owed under the value sharing agreements, if any |
| Average revenue under contract per kW per month (applies to capacity contracts only) | Revenue on a per unit basis at which capacity is expected to be sold to third parties, given existing contract prices and/or auction awards |
| Expected sold and market total revenue per MWh | Total energy and capacity revenue on a per unit basis at which total planned generation output and capacity is expected to be sold given contract terms and market prices at a point in time, including estimates for market price changes affecting revenue received on puts, collars and call options, positive or negative basis differentials, option premiums and market prices at time of option expiration, costs to convert Firm LD to unit-contingent and other risk management costs, divided by total planned MWh of generation, excluding the revenue associated with the amortization of the Palisades below-market PPA; also excludes payments owed under value sharing agreements, if any |
| | |
| Financial Measures – GAAP |
| Return on average invested capital – as-reported | 12-months rolling net income attributable to Entergy Corporation (Net Income) adjusted to include preferred dividends and tax-effected interest expense divided by average invested capital |
| Return on average common equity – as-reported | 12-months rolling Net Income divided by average common equity |
| Cash flow interest coverage | 12-months cash flow from operating activities plus 12-months rolling interest paid, divided by interest expense |
| Book value per share | Common equity divided by end of period shares outstanding |
| Revolver capacity | Amount of undrawn capacity remaining on corporate and subsidiary revolvers |
| Total debt | Sum of short-term and long-term debt, notes payable and commercial paper and capital leases on the balance sheet |
| Debt of joint ventures - Entergy’s share | Debt issued by business joint ventures at EWC |
| Leases - Entergy’s share | Operating leases held by subsidiaries capitalized at implicit interest rate |
| Debt to capital ratio | Total debt divided by total capitalization |
| Securitization debt | Debt associated with securitization bonds issued to recover storm costs from hurricanes Rita, Ike and Gustav at ETI; the 2009 ice storm at EAI and investment recovery of costs associated with the cancelled Little Gypsy repowering project at ELL |
| Financial Measures – Non-GAAP |
| Operational earnings | As-reported Net Income adjusted to exclude the impact of special items |
| Adjusted EBITDA | Earnings before interest, income taxes, depreciation and amortization and interest and investment income excluding decommissioning expense and other than temporary impairment losses on decommissioning trust fund assets |
| Operational adjusted EBITDA | Adjusted EBITDA excluding effects of special items |
| Return on average invested capital – operational | 12-months rolling operational Net Income adjusted to include preferred dividends and tax-effected interest expense divided by average invested capital |
| Return on average common equity – operational | 12-months rolling operational Net Income divided by average common equity |
| Gross liquidity | Sum of cash and revolver capacity |
| Debt to capital ratio, excluding securitization debt | Total debt divided by total capitalization, excluding securitization debt |
| Net debt to net capital ratio, excluding securitization debt | Total debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents, excluding securitization debt |
| Net debt to net capital ratio, including off-balance sheet liabilities, excluding securitization debt | Sum of total debt and off-balance sheet debt less cash and cash equivalents divided by sum of total capitalization and off-balance sheet debt less cash and cash equivalents, excluding securitization debt |
| | |
| Appendix D: Definitions of Operational Performance Measures, GAAP and Non-GAAP Financial Measures and Abbreviations or Acronyms (continued) |
| Abbreviations or Acronyms |
| ALJ | Administrative law judge |
| ANO2 | Unit 2 of Arkansas Nuclear One (nuclear) |
| APSC | Arkansas Public Service Commission |
| CCGT | Combined cycle gas turbine |
| EAI | Entergy Arkansas, Inc. |
| EGSL | Entergy Gulf States Louisiana, L.L.C. |
| ELL | Entergy Louisiana, LLC |
| EMI | Entergy Mississippi, Inc. |
| ENOI | Entergy New Orleans, Inc. |
| EPA | U.S. Environmental Protection Agency |
| ETI | Entergy Texas, Inc. |
| EWC | Entergy Wholesale Commodities |
| FRP | Formula rate plan |
| GAAP | Generally accepted accounting principles |
| HCM | Human Capital Management program |
| IP2 | Indian Point Energy Center Unit 2 (nuclear) |
| IP3 | Indian Point Energy Center Unit 3 (nuclear) |
| ISO | Independent system operator |
| ISO-NE | ISO New England |
| LHV | Lower Hudson Valley |
| LPSC | Louisiana Public Service Commission |
| MISO | Midcontinent Independent System Operator, Inc. |
| MPSC | Mississippi Public Service Commission |
| MPUS | Mississippi Public Utilities Staff |
| MWh | Megawatt hour |
| NRC | Nuclear Regulatory Commission |
| NYISO | New York Independent System Operator, Inc. |
| NYPA | New York Power Authority |
| O&M | Operation and maintenance expense |
| Palisades | Palisades Power Plant (nuclear) |
| PPA | Power purchase agreement |
| PSB | Public Service Board |
| PUCT | Public Utility Commission of Texas |
| ROE | Return on equity |
| ROIC | Return on invested capital |
| RPCE | Rough production cost equalization |
| RTO | Regional transmission organization |
| VY | Vermont Yankee Nuclear Power Station (nuclear) |
| | |
| E. | GAAP to Non-GAAP Reconciliations |
Appendix E-1, Appendix E-2 and Appendix E-3 provide reconciliations of various non-GAAP financial measures disclosed in this release to their most comparable GAAP measure.
| Appendix E-1: Reconciliation of GAAP to Non-GAAP Financial Measures – ROE, ROIC Metrics |
| ($ in millions) | | | | | | | | |
| | 2Q12 | 3Q12 | 4Q12 | 1Q13 | 2Q13 | 3Q13 | 4Q13 | 1Q14 |
| As-reported net income-rolling 12 months (A) | 996 | 705 | 847 | 1,160 | 958 | 861 | 712 | 952 |
| Preferred dividends | 21 | 22 | 22 | 22 | 21 | 20 | 19 | 18 |
| Tax effected interest expense | 329 | 342 | 350 | 356 | 363 | 365 | 371 | 376 |
| As-reported net income, rolling 12 months including preferred dividends and tax effected interest expense (B) | 1,346 | 1,069 | 1,219 | 1,538 | 1,342 | 1,246 | 1,102 | 1,346 |
| | | | | | | | | |
| Special items in prior quarters | (244) | (253) | (251) | (31) | (28) | (33) | (212) | (239) |
| | | | | | | | | |
| Special items in current quarter | | | | | | | | |
| Decision to close VY | - | - | - | - | - | (173) | (32) | (6) |
| Transmission business spin-merge expenses | (9) | (11) | (11) | (6) | (12) | (10) | 25 | - |
| HCM implementation expenses | - | - | - | - | (4) | (7) | (26) | (3) |
| Total special items (C) | (253) | (264) | (262) | (37) | (44) | (224) | (245) | (248) |
| | | | | | | | | |
| Operational earnings, rolling 12 months including preferred dividends and tax effected interest expense (B-C) | 1,599 | 1,333 | 1,481 | 1,575 | 1,386 | 1,470 | 1,347 | 1,594 |
| | | | | | | | | |
| Operational earnings, rolling 12 months (A-C) | 1,249 | 969 | 1,109 | 1,197 | 1,002 | 1,085 | 957 | 1,200 |
| | | | | | | | | |
| Average invested capital (D) | 21,556 | 22,065 | 22,290 | 22,389 | 22,573 | 22,857 | 23,283 | 23,539 |
| | | | | | | | | |
| Average common equity (E) | 8,814 | 9,078 | 9,079 | 9,064 | 9,152 | 9,299 | 9,415 | 9,581 |
| | | | | | | | | |
| ROIC – as-reported % (B/D) | 6.2 | 4.8 | 5.5 | 6.9 | 5.9 | 5.5 | 4.7 | 5.7 |
| | | | | | | | | |
| ROIC – operational % ((B-C)/D) | 7.4 | 6.0 | 6.6 | 7.0 | 6.1 | 6.4 | 5.8 | 6.8 |
| | | | | | | | | |
| ROE – as-reported % (A/E) | 11.3 | 7.8 | 9.3 | 12.8 | 10.5 | 9.3 | 7.6 | 9.9 |
| | | | | | | | | |
| ROE – operational % ((A-C)/E) | 14.2 | 10.7 | 12.2 | 13.2 | 10.9 | 11.7 | 10.2 | 12.5 |
| | | | | | | | | |
| Appendix E-2: Reconciliation of GAAP to Non-GAAP Financial Measures – Credit and Liquidity Metrics |
| ($ in millions) | | | | | | | | |
| | 2Q12 | 3Q12 | 4Q12 | 1Q13 | 2Q13 | 3Q13 | 4Q13 | 1Q14 |
| Total debt (A) | 12,533 | 12,931 | 13,473 | 13,471 | 13,747 | 13,623 | 13,678 | 13,860 |
| Less securitization debt (B) | 1,020 | 1,003 | 973 | 952 | 927 | 910 | 883 | 861 |
| Total debt, excluding securitization debt (C) | 11,513 | 11,928 | 12,500 | 12,519 | 12,820 | 12,713 | 12,795 | 12,999 |
| Less cash and cash equivalents (D) | 283 | 750 | 533 | 263 | 311 | 365 | 739 | 908 |
| Net debt, excluding securitization debt (E) | 11,230 | 11,178 | 11,967 | 12,256 | 12,509 | 12,348 | 12,056 | 12,091 |
| | | | | | | | | |
| Total capitalization (F) | 21,844 | 22,402 | 22,951 | 22,965 | 23,302 | 23,312 | 23,615 | 24,113 |
| Less securitization debt (B) | 1,020 | 1,003 | 973 | 952 | 927 | 910 | 883 | 861 |
| Total capitalization, excluding securitization debt (G) | 20,824 | 21,399 | 21,978 | 22,013 | 22,375 | 22,402 | 22,732 | 23,252 |
| Less cash and cash equivalents (D) | 283 | 750 | 533 | 263 | 311 | 365 | 739 | 908 |
| Net capital, excluding securitization debt (H) | 20,541 | 20,649 | 21,445 | 21,750 | 22,064 | 22,037 | 21,993 | 22,344 |
| | | | | | | | | |
| Debt to capital ratio % (A/F) | 57.4 | 57.7 | 58.7 | 58.7 | 59.0 | 58.4 | 57.9 | 57.5 |
| | | | | | | | | |
| Debt to capital ratio, excluding securitization debt % (C/G) | 55.3 | 55.7 | 56.9 | 56.9 | 57.3 | 56.7 | 56.3 | 55.9 |
| | | | | | | | | |
| Net debt to net capital ratio, excluding securitization debt % (E/H) | 54.7 | 54.1 | 55.8 | 56.3 | 56.7 | 56.0 | 54.8 | 54.1 |
| | | | | | | | | |
| Off-balance sheet liabilities (I) | 600 | 599 | 595 | 595 | 594 | 592 | 542 | 542 |
| | | | | | | | | |
| Net debt to net capital ratio including off-balance sheet liabilities, excluding securitization debt % ((E+I)/(H+I)) | 56.0 | 55.4 | 57.0 | 57.5 | 57.8 | 57.2 | 55.9 | 55.2 |
| | | | | | | | | |
| Revolver capacity (J) | 2,762 | 2,917 | 3,462 | 3,542 | 3,819 | 4,129 | 3,977 | 4,077 |
| | | | | | | | | |
| Gross liquidity (D+J) | 3,045 | 3,667 | 3,995 | 3,805 | 4,130 | 4,494 | 4,716 | 4,985 |
| | | | | | | | | |
| Appendix E-3: Reconciliation of GAAP to Non-GAAP Financial Measures – Entergy Wholesale Commodities Operational Adjusted EBITDA |
| ($ in millions) | | | | | | | | |
| | 2Q12 | 3Q12 | 4Q12 | 1Q13 | 2Q13 | 3Q13 | 4Q13 | 1Q14 |
| Net income | 71 | 87 | 59 | 82 | 12 | (93) | 42 | 242 |
| Add back: interest expense | 5 | 3 | 3 | 3 | 4 | 4 | 5 | 5 |
| Add back: income tax expense | 47 | 57 | 50 | 57 | (15) | (107) | (12) | 119 |
| Add back: depreciation and amortization | 48 | 29 | 47 | 49 | 50 | 55 | 61 | 70 |
| Subtract: interest and investment income | 27 | 20 | 28 | 28 | 22 | 21 | 66 | 26 |
| Add back: decommissioning expense | (17) | 29 | 30 | 31 | 30 | 32 | 33 | 34 |
| Adjusted EBITDA | 127 | 185 | 161 | 194 | 59 | (130) | 63 | 444 |
| Add back: special item for HCM implementation expenses (pre-tax) | - | - | - | - | 2 | 3 | 19 | 1 |
| Add back: special item resulting from the decision to close VY (pre-tax) | - | - | - | - | - | 292 | 52 | 10 |
| Operational adjusted EBITDA | 127 | 185 | 161 | 194 | 61 | 165 | 133 | 455 |
Totals may not foot due to rounding
Entergy Corporation’s common stock is listed on the New York and Chicago exchanges under the symbol “ETR.”
Additional investor information can be accessed online at
www.entergy.com/investor_relations
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In this news release, and from time to time, Entergy Corporation makes certain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Except to the extent required by the federal securities laws, Entergy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
Forward-looking statements involve a number of risks and uncertainties. There are factors that could cause actual results to differ materially from those expressed or implied in the forward-looking statements, including (a) those factors discussed in this news release and in: (i) Entergy’s most recent Annual Report on Form 10-K, any subsequent Quarterly Reports on Form 10-Q and (ii) Entergy’s other reports and filings made under the Securities Exchange Act of 1934; (b) uncertainties associated with rate proceedings, formula rate plans and other cost recovery mechanisms; (c) uncertainties associated with efforts to remediate the effects of major storms and recover related restoration costs; (d) nuclear plant relicensing, operating and regulatory risks, including any changes resulting from the nuclear crisis in Japan following its catastrophic earthquake and tsunami;
(e) legislative and regulatory actions and risks and uncertainties associated with claims or litigation by or against Entergy and its subsidiaries; and (f) economic conditions and conditions in commodity and capital markets during the periods covered by the forward-looking statements, in addition to other factors described elsewhere in this release and subsequent securities filings.
| VII. | Financial Statements |
