Fortis Inc. (FTS) Q2 2013 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to ITC Holdings Corp., Second Quarter Conference Call and Webcast. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and answer-session and instructions will be given at that time. (Operator Instructions) As a remainder, today’s conference call is being recorded. I’d now like to turn the conference over to your host, Ms. Gretchen Holloway, Director of Investor Relations. Please go ahead.

Good morning, everyone, and thank you for joining us for ITC’s 2013 second quarter earnings conference call. Joining me on today’s call is Joseph L. Welch, Chairman, President and CEO of ITC, and Cameron M. Bready, our Executive Vice President and CFO. Last night, we issued a press release summarizing our results for the quarter and for the six-months ended June 30, 2013. We expect to file our Form 10-Q with the Securities and Exchange Commission today. Before we begin, I would like to remind everyone of the cautionary language contained in the Safe Harbor statement. Certain statements made during today’s call that are not historical facts such as those regarding our future plans, objectives and expected performance reflects forward-looking statements under Federal Securities Laws. While we believe these statements are reasonable, they are subject to various risks and uncertainties and actual results may differ materially from our projections and expectations. These risks and uncertainties are discussed in our reports filed with the SEC such as our periodic reports on Forms 10-Q and 10-K and our other SEC filings. You should consider these risk factors when evaluating our forward-looking statements. Our forward-looking statements represent our outlook only as of today and we disclaim any obligation to update these statements except as may be required by law. A reconciliation of the non-GAAP financial measures discussed on today’s call is available on the Investor Relations page of our website. In addition, ITC filled a registration statement on Form S-4 with the SEC to register shares of ITC common stock to be issued to shareholders of Entergy Corporation in connection with the proposed transaction with Entergy Corporation previously announced on December 1, 2011. This registration statement was to clear affected by the SEC on February 25, 2013. ITC expects to file a post effective amendment to this registration statement. Investors are urged to read the prospectus included in the ITC registration statement and the post effective amendment through the ITC registration statement when available as well as any other relevant documents because they contain important information about the transaction. Registration statements, perspectives and other documents relating to the proposed transaction can be obtained free of charge from the SEC website at www.sec.gov when they are available. These documents can also be obtained free of charge upon written request to ITC or Entergy. I will now turn the call over to Joe Welch.

Thanks, [Rachel] and good morning. Since we last addressed the investment community in late April, there have been quite a number of developments related to our standalone business and the Entergy transaction that we will update you on today. First as this customary, I would like to begin by commenting on our operational performance and progress with respect to our capital investment plans. Overall, we remain on track to meet our capital investment expectations for the year, despite the fact that we are somewhat behind our plan for the first half of the year. Mother Nature continues to present multiple challenges to our plans. As we discussed in April, the long and volatile winter created some delays in capital development in the first quarter. This was followed by multiple severe weather events in the second quarter that marginally impacted our ITC Midwest System, including the snow and ice storm in April, late heavy snow storms in early May and severe thunderstorms, tornadoes and ongoing flooding in late May and June. All these events contributed to outages and damage to parts of the ITC Midwest System and have created a challenging environment in which to advance our capital projects. While we are off to a slower start than we had initially anticipated, we still expect to catch up in the second half of the year. Despite the fact that the weather has had on the timing of our capital investments relative to our plans, I am pleased with the overall progress that we have made. For the first six months of the year, we invested a record amount of capital for any six month period in our history, which is something that should not be overlooked and for which I’m quite proud of the team. This is particularly satisfying giving the fact that we have been advancing the Entergy transaction simultaneously. As we discussed in the past, our capital investments when coupled with our maintenance practices and protocols are critical in supporting our system performance. Our success on this front was recently demonstrated again through the SGS Statistical Services Transmission Reliability Benchmark Study for 2012 that was released during the second quarter of this year. For 2012, ITC Transmission and METC again ranked in the top decile for sustained outages per circuit, and ITC Midwest ranked in the second quartile for sustained outages per circuit. Well, ITC Michigan Systems continued their strong performance, ITC Midwest has experienced significant improvement from its fourth quartile performance in 2008, which was the first full-year of ITC owned the system. These results provide us further evidence that our independent business model with a sole focus on transmission yield significant benefits in terms of improved system performance that served to provide for a more reliable and economically efficient grid for the benefit of our customers. In addition to our strong system performance results, we are also pleased to report our safety benchmarking statistics for 2012, as ITC has ranked in the top decile for both recordable injuries and lost day work cases. This particular ranking is based on the Edison Electric Institute or EEI’s Annual Safety Survey which included 74 survey participants with a mix of transmission, distribution, generation and vertically integrated utilities. This is the second year on a row that ITC has achieved a top desk our performance in these very important safety measures. Fostering a safe work environment that ITC remains an absolutely, critically, imperative for us and I’m extremely proud of the fact that we have been able to achieve this level of safety even as we have been significantly expanding our capital investment programs. Turning now to the regulatory front, I would like to provide you with an update on the recent developments of the FERC. First of all, late last week FERC issued in order on Interstate Power and Lights 206 complaint against ITC Midwest Attachment FF policy, directing MISO on behalf of ITC Midwest to revise Attachment FF of the MISO tariff to confirm to MISO’s policy for reimbursing generator interconnection customers for network upgrade cost in the ITC Midwest zone. MISO’s current policy allows for customers to receive up to 10% reimbursement for those cost as supposed to Attachment FF, which allowed qualifying generators to receive up to 100% reimbursement. The order found that in the context of the MISO’s zonal rate structure and as a result of the MISO recent tariff changes that reduce the generator reimbursement to a maximum of 10% of cost. ITC’s Midwest Attachment FF interconnection reimbursement policy, results in an improper subsidy when the generators output is exported to another MISO pricing zone. It is worth noting that MISO employed a type of zonal rate structure when FERC approved the use of the Attachment FF for ITC Midwest in 2008. And MISO’s standard policy for generator interconnections differed from that of Attachment FF at that time as well. You will likely come to this no surprise that we strongly disagree with the order and the rational effectively over turning the use of Attachment FF by ITC Midwest going forward and believe the FERC is aired in its decision. Attachment FF is supported by the commission own policies in that the commission as up held 100% reimbursement policies as a means to increase competition of the bulk power markets and help insured reliability and just in reasonable prices. More specifically Attachment FF allows new resources to compete on a level playing filed with one over generating facilities owned by incumbent vertically integrated MISO members that included their interconnection cost in transmission rate and two old and new generating facilities outside of MISO that apply the order number 2003 policy of 100% reimbursement for network upgrade cost and three new generating facilities within the other MISO zones that apply the 100% network upgrade reimbursement policy. Further, Attachment FF has furthered Iowa’s economic development efforts and public policy agenda by supporting renewable development by encouraging investment in transmission. In a concurring statement commission in ours expressed his concern that the current MISO cost allocation might not adequately recognize the benefits that interconnection related network upgrades provides to all users. Consequently we are assessing our options with respect to next steps regarding this decision, which include but are not limited to potentially filing for rehearing of the decision and working with stakeholders to develop an alternative to our prior Attachment FF that addresses the concerns we have with respect to MISO standard policy. In May FERC also issued an order on the 206 complaint it had initiated over a year ago on MISO’s formula rate protocols. Within the order FERC found that current MISO formula rate protocols to be insufficient to assure just in reasonable rate. As a reminder, it is important to note that the protocols generally relate to the process by which the formula rates get posted and updated each year as well as the information sharing associated with such process. The protocols do not affect the rate, formula rates themselves. As a result of the order, FERC directed MISO to make certain revisions to these protocols to address three primary concerns. First, the protocols need to enable as efficiently broad scope of interested party to participate in transmission owners updates for their formula rates. Second, the protocols must provide interested parties with enhanced transparency related to the data inputs in the course of the annual updates and lastly the protocols must provide interested parties with the opportunities to challenge annual updates. Importantly in issuing the order the Commissioners reiterated their support for formula rates and the need to strike the appropriate balance between the benefits of avoiding ongoing rate cases with the need for customer confidence in rates. We believe that FERC’s actions serve to preserve and bolster the use of formula rates going forward by making the process more robust and enhancing stakeholder confidence in the accuracy of the data something which ITC is advocated for, for some time which is evidenced by the fact that FERC required revisions to the MISO protocols are fairly well aligned with ITC's current practices, as far as the next steps in the process FERC required MISO and MISO transmission owners to submit a compliance filing, implementing these prohibitions that is now due in mid September. While there has been a high degree of focus on FERC return levels, there have been no real new developments on this front since our last call. We have, however, seen the industry undertaken organized efforts to provide perspective on the issues with the release of a white paper on the top prepared by EEI, the white paper servers to highlight wide stable and adequate FERC returns on critical and supporting transmission infrastructure investment. The paper also supported the process by which FERC sets return levels in suggested in adjustments to the current methodology to medicate or eliminate elements of the process that naturally buy us numbers lower, especially in the artificially low interest rate environment in which we have been operating recently. We feel that EEI white paper serves to create more of the balanced discussion on returns and demonstrates the importance of stable and unpredictable rate regulation for the transmission industry as a whole in order to support transmission investment and FERC’s policy objectives. Other federal regulatory developments continue to be focused on order 1,000 compliance activities, which have been under way since late last year. Just last week FERC issued its order on SPP’s compliance plan for interregional planning and cost allocation, which accepted certain aspects of the filings, but also identified deficiencies and required future compliance filings to address the following issues. One, the process for identification of transmission need to driven by public policy requirements. Two, [Rolfer] related issues including the retention of [Rolfer] for certain projects and FPP’s proposal for the consideration of the state Rolfers and three additional detail or modification to the evaluation process to choose a transmission developer for projects where Rolfers were eliminated. FPP’s compliance filings to address these issues is due in 120 days from the order. In addition, MISO made its follow-up compliance filing earlier this week to address certain issues identified by FERC regarding MISO’s order 1000 interregional transmission planning in regional cost allocation methodology. While compliance filing for interregional activities are in the final stages, interregional compliance filings were just filed earlier this month with FERC. These interregional compliance plans are the first step in what will likely be a long process to promote interregional transmission development. However, ITC is encouraged that there is a systematic effort underway to address what has been a longstanding gap in the transmission planning process that we believe will eventually facilitate development of critical infrastructure among planning regions. Turning now to our transaction with Entergy Corporation, we have been very active with federal, state and local regulatory activities that made progress in advancing the required regulatory approvals. I think most interveners are now aware that on June 20, ITC and Entergy received approval from the FERC for the change of control of the Entergy transmission assets, which allows for the transfer of the transmission assets from Entergy to ITC. .: Certain other components of the formula rate is associated with 205 filings were set for hearing. Perhaps most importantly for shorter reaffirm the benefits of ITCs business model noting the benefits that stem from the independent ownership of transmission assets over and above benefits that will result for integration into MISO. In addition, the orders served to underpin the rate constructs in place at ITCs current operating companies and now these constructs serve to facilitate and support needed capital investment. This approval follows the FERC approval received in May by ITC and Entergy authorizing utility operating company financing associated with the transaction. At the state and local levels we are now in the heart of the procedural schedules in each jurisdiction. We continue to work constructively through these processes and are focus on achieving successful outcomes that allow us to move forward with the transaction on terms and conditions acceptable to us. In an effort to advance our discussion in each of the jurisdiction, we have made variety of commitment in connection with the transaction and have proposed certain rate mitigation plans to address concerns that had been raised by parties. Most recently ITC and Entergy have proposed a revised rate mitigation plan that serve to better align the modest rate impact associated with the transaction with the realization of the many of quantifiable benefits we expect customers to realize from the transaction and commits the companies to demonstrating the benefits, the transaction will bring to the Entergy region. We believe that this proposal represents an effective solution to the issues that have been raised by the parties to the proceedings at the state and local level, and provides these Commissions with the assurances that customers are protected from the risks of cost increases without the realization of quantifiable benefits. With respect to procedural schedules themselves, I will provide a brief update for each jurisdiction. First in Texas, the hearing was completed in May, and we now await the decision by the Texas Public Utilities Commission, which is required by August 18. We just completed the hearing process in Louisiana this week and are now preparing for upcoming hearings in Mississippi. New Orleans and Arkansas which are currently scheduled or anticipated to occur in the month of August and September, while the New Orleans and Arkansas hearings were originally scheduled to take place in July. They have now been rescheduled or anticipated for August and early September respectively, to provide interested parties with additional time to evaluate the transaction and the various issues of proposals raised in the applications and testimonies. The current schedules continue to allow for decisions from the State Commissions in full and position us to be able to close the transaction in 2013, assuming courts approvals are received. Lastly, it’s worth noting that in June, Entergy received a private letter ruling from the internal revenue service confirming according to the facts presented, the tax-free treatment of the transaction. It’s been quite a busy year for us, thus far and we feel that we have made good progress with both our base business and advancing the Entergy transaction through the regulatory approval process. We expect the second half of the year to be very active as well, as we strive to meet all of our standalone objectives for the year and bring the Entergy transaction to its successful close before at the end of the year. I will now turn the call over to Cameron for financial update.

Thanks, John and good morning everyone. I’ll start today by providing an overview of our financial results. As I'm sure most of you saw on our earnings release issued yesterday for the second quarter of 2013 ITC reported net income of $47.4 million or $0.90 per share as compared to $42.4 million or $0.81 per share for the second quarter of 2012. Reported net income for the six-months ended June 30, 2013 was $97.6 million or $1.85 per share compared to $88.4 million or $1.70 per share for the same period of last year. Our release also highlighted our operating earnings for both the second quarter year-to-date periods as we believe this better presents the true performance of the business. Operating earnings for the second quarter were $63.3 million or a $1.20 per share compared to the $54.8 million or $1.05 per share recorded for the second quarter of 2012. For the six-months ended June 30, 2013 operating earnings were $122.1 million or $2.32 per share compared to $103.5 million or $1.98 per share for the same period last year. Our operating earnings or non-GAAP measure that exclude the following items; first after-tax expenses associated with the Entergy transaction were approximately $15.9 million or $0.30 per share and $4.1 million or $0.08 per share for the second quarter of 2013 and 2012 respectively. These expenses totaled approximately $24.4 million or $0.46 per share and $6.6 million or $0.12 per share for the six-months ended June 30, 2013 and 2012, respectively. Secondly operating earnings exclude aftertax expenses associated with an estimate refund liability of approximately $0.1 million for both the second quarter and year-to-date 2013 periods and $8.4 million or $0.16 per share for the second quarter and year-to-date 2012 periods. This liability was recorded for certain acquisition accounting adjustments for ITC Midwest, ITCTransmission and METC, resulting from the FERC audit order on ITC Midwest issued in May 2012. Briefly, I would like to note that in early June, we received a letter order from FERC accepting the refund report and associated refund amounts filed for ITCTransmission and METC. We’ve previously received a similar order accepting the refund report and refund amount for ITC Midwest. This was the last regulatory step required in that process and with the payment of the refunds in 2014, this matter will be closed. Operating earnings are reported on the basis system with how we provided our earnings guidance for the year and exclude the aforementioned guidance that were not reflected in earnings guidance and do not impact to future earnings potential of the business. The year-over-year increases in operating earnings of approximately 17% for the year-to-date period was largely attributable to higher income associated with the increased rate base and AFUDC at all of our operating companies, resulting from the execution of our capital investment programs. Execution of our capital investment plans continues to be the primary driver of our financial performance for both the quarter and year-to-date periods. These investments support the system performance and operational excellence that we have realized that our operating companies will also providing significant benefits to our customers in the form of improved reliability and the economic efficiency of the grid, which contributes to the opportunities for the customers to realize a lower overall delivered cost of energy. For the six months ended June 30, 2013 our capital investments totaled $455.4 million across our four operating companies. This amount includes $120.8 million at ITC transmission, $81.8 million of METC, $178.8 million at ITC Midwest and $74 million at ITC Great Plains. While we have made good progress on our plans in the first half of the year, ongoing weather challenges along with some changes to project schedules have slowed the pace of our capital deployment relative to our plans for the year. Although we did gain some ground during the second quarter on a year-to-date basis we still remain slightly behind budget with respect to our capital investments for the year, but are poised to catch-up in the back half of the year and meet our overall annual expectations. As a result, we are today, reaffirming our aggregate standalone capital investment guidance for the year of $760 million to $860 million, which includes $200 million to $230 million at ITC Transmission, $160 million to $180 million at METC, $270 million to $300 million at ITC Midwest and $130 million to $150 million at ITC Great Plains. In addition, we’re also reaffirming our annual operating earnings guidance of $4.80 to $5 per share, which excludes any impact associated with Entergy transaction. Turning now to our financing and liquidity requirements, we have also had a very busy year with respect to our capital formation activities. Since the first quarter, we have continued to execute on our 2013 standalone financing plan, which includes addressing a number of debt maturities in the calendar year. On July 3, ITC Holdings successfully closed its first SEC registered bond offering by issuing $550 million of senior unsecured notes. The offering was comprised of a $250 million, 10 year tranche priced at 4.05%, the best pricing for bond issue in ITC Holdings history, and a $300 million 30 year tranche priced at 5.3%. Given the recent volatility experienced in the bond markets, we view this outcome as quite positive. The net proceeds from the offering were used to repay a significant portion of ITC Holdings 2013 debt maturities and for general corporate purposes. As we have discussed over the past couple of years, we have had an active interest rate hedging program in effect with respect to these planned issuances in order to mitigate a portion of the associated pricing risk through the ease of interest rates swaps. Concurrent with the debt issuance, we settle the swaps that were in place and recognizing net gain of approximately $11.2 million on our interest rates swaps, which will be amortized over the life of the new issuances thereby further reducing the overall average effective rate of the bonds. At the operating company level, we also entered into unsecured term agreements ITC Great Plains and ITCTransmission in May and July respectively. The term loan executed by ITC Great Plains was an 18 month facility in the amounts of $100 million, the proceeds which were used primarily to pay down its existing revolver balance and fund capital investments. ITCTransmission’s term loan is a 366 day facility, totaling $185 million, the proceeds of which were used to refinance maturing debt. By executing these term loans, ITC Great Plains and ITCTransmission were able to capitalize on attractive conditions in the lending market to meet their near-term needs. With our financing activities to-date, we have largely completed our 2013 financing plan and have positioned ourselves to be able to focus on the Entergy transaction related financings in the back half of the year. However, we will continue to seek to be opportunistic with respect to refinancing existing term loans in our portfolio with longer-term financing alternatives based on market conditions. As for our current liquidity position as of June 30, 2013 we had $63.8 million of cash on hand and $525.7 million of net undrawn revolver capacity, bringing our total liquidity position to $589.5 million. Our total capacity available under our revolving credit facilities is currently $725 million. For the six months ended June 30, 2013, we reported operating cash flows of approximately $185 million compared to approximately $134 million for the same period last year. This increase of approximately $51 million was largely attributable to an increase in operating revenues and lower cash taxes. Well on capitalization related matters, I wanted to spend a brief moment revisiting dividend policy as August is quickly approaching and that is typically when our Board considers our dividend and whether any adjustments are warranted given the outlook for the business. As we have stress, we remain committed to sustainable annual dividend growth whether on a standalone basis or for the pro forma business reflecting the addition of the Entergy transmission system while also recognizing and balancing our investment requirements. Our most recent guidance on dividend increases suggested that we believe we have additional flexibility with respective future increases and anticipate increases in the range of approximately 10% to 15% in the near term with the goal of preserving a pay out ratio in the mid to high 30% range as we continue to grow earnings. We believe this dividend policy strikes the proper balance between the need to reinvest in the business and providing current returns to shareholders. Not to any future increases in dividend remains at the discretion of our Board of Directors. Before turning to the Entergy transaction, I would like to briefly touch on our standalone capital investment plans. All the key projects included within the plan remain on track both from a budget and timing perspective. The Michigan Thumb Loop Project and Kansas V‐Plan are currently well into construction. On the Thumb Loop Project, we’re in the process of completing work on the first segment, which we estimate will be placed into service before year-end and work also continues on the second segment, which we still expected place in the service in 2015. For the Kansas V‐Plan, we have ordered a majority of substation construction contracts and work on the transmission line construction continues. We remain on target for a late 2014 in service date for this project. Likewise, we’re also making good progress in advancing MVP projects number three and four to the very exciting processes. And we’re also continuing to work through ownership structure for MVP projects number five and seven. In addition to providing updates on key projects in the plan, I also wanted to address the recent FERC order regarding ITC Midwest Attachment FF policy and the potential impacts of the order to our long-term plan. Although, the order relates with ITC Midwest use of the Attachment FF, our Michigan operating companies also use Attachment FF or recovery of certain network upgrade to support new generator interconnection and we will need to evaluate the continued use of this policy of these entities. Given that we just received the order last week, we are still in the process of analyzing the specific implications as well as our options for next steps. However, directionally, it is worth noting that we have just $9 million of expected investments in our 2012 to 2016 long-term plan categorize it network system upgrades for new generator interconnections. This amount includes approximately $510 million of investment associate with the Michigan Thumb Loop project, which is an MVP project as oppose to an Attachment FF project, and therefore it’s not impacted by any future potential elimination of Attachment FF. Of the remaining amount, some of this capital has already been invested by our operating companies over the course of 2012 and the first half of 2013, prior to the issuance of the order by FERC. In addition, the order issued by FERC on this matter has perspective application for any non-executed or non-filed generator interconnections agreements. This essentially means that the in process generator in interconnections would still fall under our historical Attachment FF treatment. Lastly, as we’ve previously indicated, we will need to further evaluate future projects included in this category, and some of projects may still be necessary to support system requirements, regardless of whether or not the associated generator in interconnected in the future. Consequently, we cannot provide definitive guidance today, with respect to the future impact of the potential elimination of our Attachment FF generator interconnection policy. However, given the aforementioned factors, we do not currently anticipate that any elimination of this policy would have a material effect on our future anticipated capital investment plans. Turning now to the Entergy transaction, as Joe noted in his comments, we’re continuing to work through the regulatory approval processes in each of the jurisdictions, and have recently proposed a rate mitigation plan that we believe when coupled with the other commitments that we’ve made will serve to address many of the concerns that have been raised and in the state and local regulatory proceedings. The overall sphere in which the rate mitigation plan was provided, is to one better align the rate impacts to customers of the transactions associated with the change in waited average cost of capital under ITC’s ownership with the realization of all the benefits that we expect materialize from the transaction. And two, and for the customers realize quantifiable and tangible benefits of the transaction prior to experiencing such cost increases. More specifically, ITC and Entergy have committed to a rate mitigation plan that if accepted would effectively eliminate the retail rate impact, the result from the change in weighted average cost of capital for the first five years following the close of the transaction. At the end of the five year period and analysis or test would be performed by an independent third-party that measures the annual reliability economic and other benefits provided by ITC’s ownership of the transmission system and resulting improvements that have been realized. If these annual benefits exceed the annual impact of ITC’s higher weighted average cost of capital and the test is met and rate mitigation within. If the test is not met, rate mitigation will continue for the percentage of the impact of ITC’s weighted average cost of capital, they have not been offset by benefits as for the benefit test. If the rate mitigation continues beyond the five year period, additional benefit test would be conducted in the future and rate mitigation will continue until such time as it could be demonstrated as the benefit of ITC ownership exceed the impacts of ITC’s weighted average cost of capital on retail rates. Under the proposed rate mitigation plan, the Company were committing to rate mitigation for the first five years post closing of the transaction at a minimum. Beyond that, future rate mitigation if any depends on the result of the benefit analysis as I discussed. While the merger agreement between ITC and Entergy calls rate 50/50 split of any rate concession. ITC and Entergy have agreed to a different approach in light of this new rate mitigation proposal. Under this agreement for the first five years of rate mitigation, Entergy will bare a greater proposition of the cost associated with rate mitigation than ITC. If rate mitigation is required beyond the first five years ITC and Entergy will share in those costs on a 50-50 basis through year 10. If after year 10 rate mitigation is still required Entergy’s contribution to this will be based on a fixed amount and ITC will be responsible for any shortfall relative to the size of required rate mitigation if any. Entergy’s obligation to provide contributions to the rate mitigation plan which sees after year 20 if rate mitigation were still required beyond that point of time. More specifics on this revised split will be provided at a later day as we’re gaining clarity as to whether or not this plan will be accepted and how will be implemented in the various jurisdictions. The rational for pursuing this rate mitigation proposal is clear and we believe it will be an important tool and addressing concerns raised with respect to rate effects and the realization of benefits. From our perspective, we believe this rate mitigation plan allows us to control our own destiny. And provided us the opportunity to put our money where our mouth is so to speak. As our history suggest we have a long track record of improving transmission system performance and delivering significant benefits to customer and we have a great deal of confidence in our ability to do so. Essentially this rate mitigation plan commits us to do the same here and by doing so will allow us to end rate mitigation relatively quickly. When given the opportunity we’re always going to bet on ourselves and we are confident and that we will be able to realize the same benefits for customers in the Entergy region that we have been able to achieve in our other service territories. We are pleased with our overall performance for the first six months of this year and we remain committed to continuing to effectively execute on our standalone plans and also advancing the Entergy transaction through the complex set of regulatory approval processes while preparing for a smooth integration of this business. We remain of the view that the combination of these two provides the best value creation opportunity for our investors in the future. At this time, I would like to open up the call to answer questions from the investment community.

(Operator Instructions) Our first question comes from Julien Dumoulin-Smith of UBS, please go ahead. Julien Dumoulin-Smith – UBS Securities, LLC: Hi, good morning.

Good morning

Good morning Julien. Julien Dumoulin-Smith – UBS Securities, LLC: So first question on Attachment FF, just wanted to get a sense here, as you think about reviewing projects out there, what kind of timeline is that going to be for the non-ITC Midwest projects that you contemplated? And just to be clear, even ahead of that review, you still feel confident that net of all those offsetting factors, it doesn’t materially impact your current CapEx outlook through 2016.

Yeah Julien, it’s Cameron. Let me, may be answer the second part of your question first. What you’ve stated is a true statement. Given all of the offsetting factors that I described in my comments, we don’t believe that any potential elimination of FF would have a material impact on our future capital investment plans through 2016. Obviously the vast majority of the capital investments that we had year marked for network upgrade to support generated interconnection associated with the Thumb Loop Project here in Michigan which is not actually an Attachment FF project as I mentioned. And projects that we have already actually completed so the balance again we do not believe if some of that opportunity will last that it would have a material impact on our future capital investment plans. To the earlier part of your comments, I think as we said, we’re still evaluating what our next steps will be. And as Joe highlighted we are considering whether or not it’s appropriate to seek rehearing on the order given that we do disagree with the conclusion. But we’re also considering in light of some of the commentary in the order itself, whether or not we ought to pursue a different cost allocation proposal in consultation with other stake holders in the region that we believe will serve to address concerns that we have with regard to MISO’s standard policy. And by background MISO standard policy again is the generator is responsible for 90% of the costs. And the generator is eligible for up to 10%, only 10% reimbursement of those costs. We don't feel that that provides the level playing field for new generators in the marketplace and have concerns about that MISO’s standard policy. At a minimum, we think that modification should be made that allow for the creation of more competitive marketplace even if we’re not successful in advocating for 100% reimbursement policy. So at this time, we’re still evaluating what next steps we’ll take and those next steps we’ll largely dictate again what we think the ultimate exposure is with respect to capital investment channel in our business. Julien Dumoulin-Smith – UBS Securities, LLC: And perhaps just a quick follow up directly to that I mean obviously there were some concurring Commissioner Norris and others alluding to perhaps alternative middle ways if you will. Could you perhaps talk to what he was alluding to more directly? And then also some perspective on FF, I mean what do all the markets currently pursue? I understand that is somewhat different as well. And would you contemplate proposing some of those before MISO exposed as they compromise or something?

Well, the first fact is, is that if you go back, I don’t know what directly Commissioner Norris is referring to I mean I think he has a thought in his mind. But if you go back a little bit of history MISO had a 50/50 policy instead of what we would look at as the 90/10 policy in other words, and that was actually what was in place when Attachment FF was found to be just unreasonable. So at that point in time the generator was eligible to receive 50% of reimbursement for the network upgrades that we had to make and when MISO changed their rate protocols to get to the MVP projects and to get that approved they also changed a generator interconnection policy at that time. I kind of find it candidly amazing that they found FF to be just in unreasonable with a 50/50 policy and now they have reversed themselves with a 90/10 policy, but I believe that if I read between the lines Commissioner Norris is looking to go back tomorrow to that 50/50 policy, because if you look at in some of these rural areas and specifically Iowa to be just to call it out, the system there when we bought it candidly was in deplorable condition number one and it was a very weak system and you would virtually could not get anybody to interconnect out there any kind of generation of which that generation is brought – that has been brought online brought huge benefits to the region and so I think that we need to go back in and make a good demonstration of what those benefits to the region were, but I think that if I again read that I think he’s looking for more regional cost allocation process similar to the MVPs. Julien Dumoulin-Smith – UBS Securities, LLC: Great. Well thank you very much.

Yep, thanks Julien.

Our next question comes from Jonathan Arnold of Deutsche Bank. Please go ahead. Jonathan Arnold – Deutsche Bank: Good morning guys.

Good morning Jonathan. Jonathan Arnold – Deutsche Bank: Just a quick one, Cameron on FF, just can you give us any indication of how much of the 380 million inside that’s already been spent or grandfather. I mean you have that bullet, but it feels like it could have a number attached to it.

Yeah, rough number Jonathan, I don’t have specific on how much is in the queue that we view as being grandfathered, I have some estimates they are fairy rough at this stage. So directionally what I would tell you in aggregate between what we have already invested between 2012 and first half of 2013 and what we view as being likely of advancing under the old attachment FF that’s probably in the neighborhood of call it close to $200 million. Jonathan Arnold – Deutsche Bank: Okay so it’s about a half.

Yeah it would be close to half and it would leave the other half either at risk for perhaps only 10% of the balance or potentially something different to the extent that we are successful in either seeking a rehearing on FF and having that reinstated or creating an alternative solution in consultation with stakeholders that would yield something higher than 10%. Jonathan Arnold – Deutsche Bank: The 380 was fairly linear basically through the five year plan, is probably though?

Probably, that’s not a reasonable expectation, they are somewhat lumpy depending on the timing of particular generators coming, but by and large it’s not too heavily weighted one way or the other. Jonathan Arnold – Deutsche Bank: Okay, thank you. Can I also ask on the mitigation proposal, just to make sure we have this right, because we were struggling to keep up with you. So the first five years entities share is a larger proportion of the total of that undisclosed exactly what the split is and then you go to 50:50 after year five if you have to continue.

Correct, that’s correct so in the first half excuse me in the first five years, we’re still finalizing some of the numbers but Entergy share would approximate probably 65% to 70% of the total. And we would be responsible for the remaining 30% to 35% rough numbers. Jonathan Arnold – Deutsche Bank: Okay.

Sorry go ahead. Jonathan Arnold – Deutsche Bank: So then as a shortfall you would then cover that 50:50?

No in the first five years it’s fixed. Jonathan Arnold – Deutsche Bank: Right. But if after five years…

Yeah. After five years that would be shared 50:50. Jonathan Arnold – Deutsche Bank: Okay.

Correct. Jonathan Arnold – Deutsche Bank: And then how what’s the mechanism for that would you go to year five and then you haven’t delivered the savings promised would you then kind of seek to deliver them over each year or over a five year period or is that…

Yeah it’s a good question, we would have the opportunity to do an additional benefit test at our discretion. So we can do presumably another benefit test after year six and demonstrate after year six that the benefits of ITC’s ownership are in excess of the retail rate effects resulting from the weighted average cost of capital. So beyond year five the benefit test can be conducted at our discretion. So we really are in control when we feel like we have met it then we can bring forward the benefit test and have it conducted. Jonathan Arnold – Deutsche Bank: Okay can you give us any insights into how they are going to – this is being received, we will see some of the State filings with following. Some of them you file and update but they don't even acknowledge that there is a new number out there.

Right, that can’t be disappointing as you imagine, but I think in reality the information is getting on the record as it needs to. And will be available to the decision-makers as we work through the process. So we strongly believe that this newest proposal that we have made really turns a lot of the argument that have been made on their head. The concerns that have been raised with respect to the timing of realization of the benefits relative to the timing of the realization of rate effects, I mean this very much at addresses that and concerns that have been raised with respect to customers being at risk for the realization of benefits I mean those arguments really don't have a lot of merit any more, because the proposal we have put forward really addresses those two overarching issues that we’ve heard kind of time-and-time again. So we think that when the decision-makers are confronted with the fact in the case the commitments that we are prepared to make and this new rate mitigation proposal that we have provided that they will find that those address the issues that have been raised by interveners and we’ll find that the transaction is in the public interest.

I think one other item that I would add to Cameron is actually just if you will a sub note is that constantly through cross examination. I have been repeatedly asked what guarantees do we have that you will do this work notwithstanding the fact that our history is just absolutely stellar and that we do this work and that's what we are about this proposal that the team put together is very good and that it absolutely put to us in right smacked up where we want to be in that as Cameron said in his prepared remarks. It really puts us betting on ourselves that we will deliver those benefits to customers and if we don’t then we’ll be paying for it with cash. So, it’s what we like and I think that it commits us to getting the work done and the improvement of the grid that I believe the Entergy grid shortly needs. Jonathan Arnold – Deutsche Bank: Can I Cameron just also ask how would this mitigation be accounted for from your perspective?

It’s too early to say definitively Jonathan, as we still are working through kind of the mechanics of a structure itself. As you know in the ITC Midwest situation it was just simply a – essentially a rate rebate, that is the, is an impact earnings in each year in which the rate rebate is provided. That sort of the default case from an earnings perspective, but we haven’t yet specifically structured it and so I cant give you right specific answer with regards to the exact accounting treatments if number one, the rate mitigation plan is accepted and two the transaction progresses, but we’ll able to provide those details as we get all further into the year. Jonathan Arnold – Deutsche Bank: Thank you, for all the color.

Sure, thanks.

Our next question comes from Kevin Cole of Credit Suisse. Please go ahead. Kevin Cole – Credit Suisse: Good morning.

Good morning.

Good morning, Kevin. Kevin Cole – Credit Suisse: Just a quick follow-up on the rate mitigation plan. So, should we view the effect of this on your cash flow and earnings, income statements basically is essentially you’re realizing an ROE we somewhere between the midpoint of Entergy’s current mid 10s and the MISO [12.38] given that sharing with the Entergy?

I really wouldn’t put it that way. I think what we are trying to do is look at the overall weighted average cost of capital effects that result from moving to our model from the existing to state regulatory constructed Entergy operates under. So the way I characterize the rate mitigation and again because Entergy is bearing a larger proportion of it in the trump part of the plan in the period that is put more is “guarantee”. I really view it is not in similar to what we agree to in connection with the ITC Midwest transaction, where we are willing to provide some rate relief to customers in the early years, while we are working towards making the investments that will improve the performance of the system and allow for customers to realize the economic benefits from that improved performance of the system. The difference between the ITC Midwest cases as we had a longer period of fixed-rate mitigation. In this case we have the ability to exit it earlier than what we are experiencing in the ITC Midwest situation subject to the realization of the benefits that we strongly believe we can provide. So, I would characterize in more is just our willingness to provide rate rebates or rate relief to customers for a period of time. And again as Joe highlighted and I’ve mentioned in my remarks, it provides us with a greater level control in our ability to end that early, by delivering on the benefits that we expect customers to realize. Kevin Cole – Credit Suisse: And then just so I am clear is this a rate refund or rate deferral specifically ITC Midwest is more of a deferral?

ITC Midwest is not a deferral, we’ll say rate rebate Kevin Cole – Credit Suisse: Okay.

And this is designed to be a rate rebate, not a deferral. Kevin Cole – Credit Suisse: Okay. So and then..

Relatively consistent with the overall approach in Midwest, but for as I mentioned before the benefits as replaces arguably some period of time of fixed rate mitigation. Kevin Cole – Credit Suisse: Okay. And I guess and then given the uniqueness of Reverse Morris Trust, does this rate mitigation plan complicate that at all.

No, it doesn’t. What really dictates the ability to utilize reverse more stress in the tax free nature of the transaction is the ownership structure at closing. And this doesn’t change that ownership structure at closing. So it would not have an impact on the requirements of the reverse more stress. Kevin Cole – Credit Suisse: Okay. One last question, I guess given that the Texas approval could come for the next earnings call. If the worst case scenario would happen in Texas for to another transaction, can this transaction still move forward?

Right, I don’t want to really speculate on that as we sit here today. What I would tell you is consistent with our prior comments the transaction structure top is very sensitive to receiving the approvals in all the jurisdictions. So we need really the entire transmission business have Entergy to make the reverse more stress structure work. But obviously whatever result we get in, in Texas we’re obviously expecting a favorable result. If it’s not favorable, then we will step back and assess what our next steps are at that stage. But obviously the transaction structure as you all know is very sensitive due to realization of all the regulatory approvals. Kevin Cole – Credit Suisse: Great. Thank you very much.

Thanks, Kevin.

Our next question comes from Charles Fishman of Morningstar. Please go ahead. Charles Fishman – Morningstar: Thank you. Just one quick one, the $0.30 per share associated or attributable to the Entergy transaction costs in the second quarter? Did you say that is the peak in your transaction spending rate?

I would like to think it is Charles. Couple of things happened in the second quarter. We entered into the actual hearing process in the jurisdictions and that is a favorably costly exercise. I won’t despair as lawyers, but it is heavily lawyer intensive, I would say that for the benefit of our lawyers in the room, but it’s a fairly extensive proposition, so naturally we did see a bit of a ramp up in cost in the second quarter associated with being in hearings in taxes and preparing for hearings in the other jurisdictions. And then secondly in the second quarter we did have a payment due to our financial advisors that was contingent upon us receiving shareholder approval for the transaction and that was a relatively large component of it as well. So I do think there are a couple of items driving that second quarter number that do make it a bit of a peak, as we work through rest of the hearing process we will still see reasonable expenses associated with advancing the transaction, but I would expect that Q2 number to be somewhat of a peak. Charles Fishman – Morningstar: That’s it, thanks.

Thank you.

Our next question comes from Michael Bates with D.A. Davidson. Please go ahead. Michael Bates – D.A. Davidson & Co: Hey good morning guys. Most of my questions has been asked and answered, but I did want to follow-up on the comment about the impact adverse whether it’s had so far in the first half. I believe Joe you made the comment in the first quarter that there had been a $40 million or $50 million delta between the expected and actual CapEx levels. Where are you now, are you able to quantify that?

Sure. Michael its Cameron, I’ll touch on that, because I think it was comments I made in the first quarter regarding that. So at the end of the Q1 we were about $50 million behind our internal plan with respect to capital investments for the year, we are now about $30 million behind. So we did catch a little bit in the second quarter as I mentioned in my prepared comments, so Q2 was a little better than expected, but we didn’t catch all of the sort of the key one shortfall the best way to look at it. And the important thing that I would like to remind everyone is that when you are in a business like ours where earnings are based on a 13 month average rate base, or 13 month average CWIP balance for AFUDC, when you miss getting projects into service or miss making investments, those are really missed earnings for the year, because it’s hard to catch back up. Once you’ve missed one of your 13 months and particularly if it’s early in the year, it’s going to have a higher weighting and it’s harder to catch back up in the back half of the year from an earnings perspective. So although we are positioned and as we sit here today and believe that we will meet out overall capital investment expectations for the full year, you know the fact that we’re behind our internal plans relative to the timing of that deployment will continue to impact our earnings through the balance of the year. And that’s just the way the math works when using the 13 month average rate base as we do in the business. So it is an important I think thing to remember as you’re thinking about sort of the back half of the year. Michael Bates – D.A. Davidson & Co: Fine, that’s very helpful. Thank you.

Thanks Michael.

In the interest of time, our final question comes from Jonathan Reeder of Wells Fargo. Please go ahead. Jonathan Reeder – Wells Fargo: Good morning with some of the nuclear units and potentially incremental coal being at risk or even coming offline in the region, you know the kind of for economic regions. How does that potentially impact transmission needs over the next five years and could this provide a meaningful opportunity for you guys?

Hey good morning Jonathan I think we have said historically, that we do view the potential for either new units coming online, or units coming offline to change obviously that dynamics of the transmission system which do create potentially opportunity to invest in transmission to ensure a system stability and reliability as you’re changing the flow of power on the transmission grid. And we have indicated also that our view might has been little slow in I think addressing and planning for the potential future retirements that could be impacting the system as a result of the change in generation mix whether it would be just older units retiring or environmental pressures causing units to become uneconomic in retiring. Naturally generators aren’t terribly forthcoming all the time with their plans, so it’s little hard to make transmission plants to address future potential requirements of exiting generators, but long story short we do view that as having potential upside as we look forward in time. The magnitude of that upside is really going be dependent entirely on what exact generators ultimately de list and exit the marketplace and obviously what that means from a transmission or excuse me from a power flow perceptive and what specific transmission investments are required to ensure system stability. So it’s hard to put specific numbers on it. But we do view it as just directionally a positive relative to do the need for transmission investment over the coming years. Jonathan Reeder – Wells Fargo: And directionally I mean I guess increase your confidence with some of the announcements recently that there could be some potential upside to the current. I guess base business forecast?

I think the announcement that we’ve seen lately are really just re-enforcing a view we’ve had for sometime which is you’re going to see a change in the generation mix in MISO and in particular. And that will yield future transmission investment opportunities. So I wouldn’t want to suggest the recent announcements give us or cause us to feel like there is incremental upside relative to what we’ve been talking about. I think it reinforces our view that that upside exist and there will be investments that are required over the course of time.

And I would like to just add one sidebar comment to what Cameron made as we see the generation mix changing and that will inevitably happen. We are also going to see more people entering into the wholesale market and as more and more people get away from their native generation and go on to the wholesale market to get their power, then the realization of congestion in the wholesale market will become more and more visible to people, as they are buying and selling out of that wholesale market and as a result of that you are going to see more people putting pressure on getting more transmission built to relieve the higher LMP costs. And I think there is an article in the Wall Street Journal that just deals with little bit of this going on in Texas as they change generation mix, but as that happens those wholesale prices become more relevant to the retail customer and then that puts more pressure on getting transmission built to get that LMP price become more rationalized across the system. So I think you're going to see a lot of changes overtime, but I don't think any of these occurring in the next couple of years, because it’s just a planning cycle doesn't allow that to happen. Jonathan Reeder – Wells Fargo: Okay, thanks for the comments.

Thank you.

I would now like to turn the conference back over to Gretchen Holloway.