道明尼資源 (D) 2015 Q1 法說會逐字稿

Good morning and welcome to the Dominion Resources and Dominion Midstream Partners first-quarter earnings conference call.

(Operator Instructions)

I would now like to turn the call over to Tom Hamlin, Vice President of Investor Relations and Financial Planning for the Safe Harbor statement.

Good morning and welcome to the first-quarter 2015 earnings conference call for Dominion Resources and Dominion Midstream Partners.

During this call, we will refer to certain schedules included in this morning's earnings releases and pages from our earnings release kit.

Schedules in the earnings release kit are intended to answer the more detailed questions pertaining to operating statistics and accounting.

Investor relations will be available after the call for any clarification of these schedules.

If you have not done so, I encourage you to visit the investor relations page on our website, register for email alerts, and view our first-quarter earnings documents.

Our website addresses are dom.com and dommidstream.com.

In addition to the earnings release kit, we have included a slide presentation on our website that will follow this morning's discussion.

And now for the usual cautionary language.

The earnings release and other matters that will be discussed on the call today may contain forward-looking statements and estimates that are subject to various risks and uncertainties.

Please refer to our SEC filings, including our most recent annual report on Form 10-K and our quarterly reports on Form 10-Q, for a discussion of factors that may cause results to differ from management's projections, forecasts, estimates, and expectations.

Also on this call, we will discuss the measures of our Company's performance that differ from those recognized by GAAP.

Those measures include our first-quarter operating earnings and our operating earnings guidance for the second quarter and full year 2015 as well as operating earnings before depreciation and amortization, interest, and taxes, commonly referred to as EBITDA.

Reconciliation of our non-GAAP measures to the most directly comparable GAAP financial measures we are able to calculate and report are contained in the earnings release kit and Dominion Midstream's press release.

Joining us on the call this morning are our CEO, Tom Farrell; our CFO, Mark McGettrick; and other members of our management team.

Mark will discuss our earnings results for the first quarter and our earnings guidance for the second quarter and full year 2015.

Tom will review our operating and regulatory activities and review the progress we have made on our growth plan.

I will now turn the call over to Mark McGettrick.

Good morning.

Dominion Resources recorded operating earnings of $0.99 per share for the first quarter of 2015, which was at the top of our guidance range of $0.85 to $1 per share.

Favorable weather conditions in our electric service area, particularly in February, added about $0.05 per share compared to normal.

Higher-than-expected earnings from our Marcellus farmout activities were $0.04 per share above guidance as we closed a new agreement on development rights for 11,000 acres and amended the terms of an existing agreement.

On the negative side, margins from our merchant power business were below expectations, largely due to lower power prices in New England.

GAAP earnings were $0.91 per share for the first quarter.

The principal difference between GAAP and operating earnings was a charge associated with Virginia legislation enacted in February that required the write-off of Virginia Power prior-period deferred fuel costs during the first quarter of 2015.

A reconciliation of operating earnings to reported earnings can be found on Schedule 2 of the earnings release kit.

Now moving to results by operating segment.

At Dominion Virginia Power, EBITDA for the first quarter was $402 million, which was at the top of its guidance range.

Kilowatt hour sales were above expectations due to colder than normal weather.

Excluding weather, sales growth for the quarter was about 1.5%, slightly higher than our full-year expectation of 1%.

Dominion Generation produced EBITDA of $676 million in the first quarter, which was in the middle of its guidance range.

Earnings from utility generation were above expectations due to colder than normal weather, while merchant generation was below expectations due to lower-than-expected power prices.

First-quarter EBITDA for Dominion Energy was $413 million, which was above the top of its guidance range.

The colder weather and higher earnings from farmout activities drove the strong results.

On a consolidated basis, interest expenses and income taxes were in line with our guidance.

Overall, we are pleased with our first-quarter operating results.

For the first quarter of 2015, Dominion Midstream Partners produced adjusted EBITDA of $11.8 million and distributable cash flow of $11.9 million, all consistent with management's expectations.

On April 22, Dominion Midstream's Board of Directors declared a distribution of $0.175 per unit, payable on May 15 to unitholders of record on May 5.

On April 1, Dominion Midstream acquired Dominion Carolina Gas Transmission from Dominion Resources for a combination of debt and units, valued at approximately $495 million.

The acquisition is supportive of management's plan to grow limited partner distributions at a 22% compound annual rate through the end of the decade.

We do not expect to drop anymore assets into the Partnership this year to reach our projected fourth-quarter annualized distribution rate of $0.85 per unit.

Moving to cash flow and treasury activities at Dominion, funds from operations were $1.1 billion for the first 3 months of the year.

Commercial paper and letters of credit outstanding at the end of the quarter were $3.25 billion.

We had $4.5 billion of credit facilities at the end of the first quarter.

And taking into account cash and short-term investments, we ended the quarter with liquidity of $1.4 billion.

For statements of cash flow and liquidity, please see pages 14 and 25 of the earnings release kit.

Finally, in the financing area, we began an at-the-market program earlier this year to raise $500 million of common equity.

Through the first week of April, we had raised $264 million and expect to complete our equity issuance by year end.

Now moving to earnings guidance.

Our operating earnings guidance for the second quarter of 2015 is $0.65 to $0.75 per share compared to operating earnings of $0.62 per share for the second quarter of 2014.

Positive earning drivers for the quarter compared to last year are a return to normal weather, higher revenues from rider projects, the absence of a refueling outage at Millstone.

Negative earning drivers for the quarter were higher operating expenses.

Our operating earnings guidance for the year remains $3.50 to $3.85 per share.

As to hedging, you can find our hedge positions on page 27 of the earnings release kit.

As of mid-April, we have hedged 88% of our expected 2015 production at Millstone and 60% of our expected 2016 production.

So let me summarize my financial review.

Operating earnings were $0.99 per share for the first quarter of 2015, at the top of our guidance range.

Favorable weather and higher earnings for more farmout activities were the principal factors in the strong performance.

Operating results for Dominion Midstream Partners were in line with management's expectations and the Dominion Carolina Gas Transmission business was dropped into the Partnership effective April 1. And finally, our operating earnings guidance for the second quarter of 2015 is $0.65 to $0.75 per share.

Our operating earnings guidance for the full year remains $3.50 to $3.85 per share.

I will now turn the call over to Tom Farrell.

Good morning.

Our business units delivered strong operational and safety performance in the first quarter.

Year-to-date OSHA recordables for all units are consistent with their respective targets for the year.

Dominion ranked first in safety in the Southeast Exchange in the fourth quarter of 2014.

Our nuclear plate continues to operate well.

The net capacity factor of our 6 units was 97.7% for the first 3 months of the year.

Our power generation group also performed well during the quarter, with record production from our combined cycle and large coal plates and a first ever six-month breaker-to-breaker run for the Virginia City Hybrid Energy Center.

Virginia Power experienced a new record peak demand of 21,651 megawatts on February 20, exceeding the previous winter peak by 9% and the previous record summer peak by 8%.

Our natural gas transportation storage and delivery businesses also operated well during the recent winter.

Despite the cold, DTI had no interruption to firm service customers.

The system experienced a record storage turn of 67.4 billion cubic feet for the month of February and set a record throughput of 7.24 Bcf on February 15.

Our natural gas distribution companies also met the higher demands brought on by the cold weather safely and efficiently.

Before I discuss the progress we are making on our growth projects, I want to update you on a number of regulatory and legislative issues affecting the Company.

As many of you are aware, the Virginia General Assembly passed legislation in the recent session, modifying the base rate review process for the next several years.

The changes were advanced because of the uncertainties and potential impact to the state for the proposed clean power plant being formulated by the Environmental Protection Agency.

In its current form, this plan would impose some of the strictest CO2 emission standards in the eastern US on the Commonwealth of Virginia and could result in substantial costs for our customers and have a negative impact on our economy.

A study by the Virginia State Corporation Commission estimated total compliance costs of $5 billion to $6 billion, excluding up to $2 billion for the cost of potentially retiring much of our existing fleet of coal fire-generating plants.

The recently enacted legislation suspends the biannual review process during the early years of the compliance period for the new CO2 standards.

During this time, the Company will file its integrated resource plan annually with the Commission to include various compliance strategies and has committed to seek a solution to the new rules, which will allow the continuing use of coal as an energy resource in our state.

We will file our integrated resource plan with the Commission on July 1 of this year.

We filed our review of earnings for 2013 and 2014 on March 31, showing an earned return of 10.13%, which was below the top of the allowed range of 10.7%.

We expect the Commission order and this review by the end of November.

The biannual review process will resume in 2022, covering earnings for the calendar years 2020 and 2021.

Now for an update on our growth plans.

Construction of the 1,358 megawatt combined cycle facility in Brunswick County was about 60% complete through the end of the first quarter.

There are approximately 1,140 workers on site.

The turbine building construction is in progress and all field-erected tanks are in various stages of construction or hydro testing.

Construction of the air-cooled condenser is approximately 75% complete.

The facility is on budget and on time for a mid-2016 commercial operation date.

Dominion announced that Greensville County will be the site for the next three-on-one gas-fired combined cycle facility to be constructed in Virginia.

We expect to file a request with Virginia State Corporation Commission for a CPCN and rate rider for this project in July.

If approved, this 1,600 megawatt station is scheduled for commercial operation in late 2018.

During the first quarter, the Company announced plans to invest $700 million to build several utility-scale solar projects in Virginia, totaling up to 400 megawatts.

Legislation enacted by the General Assembly states that the development of 500 megawatts of large-scale solar by utilities within the Commonwealth is in the public interest.

Also during the first quarter, Dominion announced the development of a 20-megawatt solar facility at our Remington power station and filed for an A-6 rider and CPCN in January.

If approved, the facility would be in service by late 2016.

Construction is also on schedule for 5 merchant solar plants totaling 132 megawatts scheduled for service this year.

The largest of these projects is our 50-megawatt Pavant project in Utah, which is currently under construction.

Two projects in California totaling 42 megawatts should be in service by the end of this quarter.

We also recently announced the acquisitions of the Richland solar project for a 20-megawatt facility in Georgia and the Alamo solar project, a 20-megawatt facility located in California.

Both projects will be operational later this year and bring our merchant solar portfolio to 384 megawatts.

Our plan is to grow this portfolio to 450 megawatts by the end of this year and to 625 megawatts by the end of next year.

At Dominion Virginia Power, we have a number of electric transmission projects at various stages of regulatory approval and construction.

During the first quarter, $199 million of transmission assets were placed into service.

Electric transmissions capital budget for growth projects, including NERC, RTEP, maintenance, as well as security-related investments will average over $700 million per year through at least the remainder of this decade.

Progress on our growth plan for Dominion Energy continues as well.

At our February 9 meeting for analysts and investors, we highlighted a number of producer outlet and market access projects underway at Dominion Energy.

Five of the nine producer outlet projects, which are designed to relieve congestion and move Marcellus gas out of the basin, are in service, while the remaining four are all on time and on budget for completion over the next two years.

Similarly, all four market access projects, which are customer-driven expansions, are on time and on budget for completion in 2016 and 2017.

On March 31, Dominion East Ohio filed an application with the Public Utility Commission of Ohio for an expansion of the PIR program.

If approved, DEO's annual capital investment would increase from $160 million to $200 million by 2018 and by 3% per year for the following 3 years.

In West Virginia, legislation was passed authorizing the West Virginia PSC to approve expedited cost recovery of natural gas utility infrastructure projects.

Dominion Hope plans to file an application later this year for this replacement and expansion program.

During the first quarter, we closed on a new farmout agreement and adjusted the terms of another.

In March, DTI closed on an agreement to convey approximately 11,000 acres of Marcellus shale development rights underneath one of its storage fields.

The agreement provides for an upfront payment of $27 million plus on ongoing overriding royalty interest in gas produced from the acreage.

Also in March, DTI and a natural gas producer amended the terms of its December 2013 agreement, covering 79,000 acres of Marcellus shale development rights for payments over a nine-year period.

That amendment resulted in an immediate conveyance of approximately 9,000 acres or 11% of the overall development rights and a two-year extension of the term of the original agreement.

We are continuing to work toward the commencement of construction on the Atlantic Coast Pipeline and the related supply header project.

We began the FERC filing process last November and expect to make the formal filing in September.

On February 27, FERC issued a notice of intent to prepare an environmental impact statement for both projects.

During March, FERC held 10 scoping meetings at locations along the pipeline route.

We have been continuing our public outreach efforts.

11 open houses for the Atlantic Coast Pipeline and 2 open houses for the supply header were held in January.

3 additional open houses were held in March for proposed reroutes.

Surveying is about 72% complete and engineering is about 42% complete.

We were awarded the pipe manufacturing contract in January to Dura-Bond Industries of Pennsylvania and expect to award the pipeline construction contracts this summer.

We should begin construction in the fourth quarter of next year and begin operations in November 2018.

Dominion completed the acquisition of Carolina Gas Transmission from Scana in January and sold it to Dominion Midstream Partners in April.

This transaction is illustrative of the kind of third-party acquisitions we will be seeking to supplement Dominion's already large inventory of MLP eligible assets that support our growth targets for Dominion Midstream.

Now an update on our Cove Point liquefaction project.

Construction is continuing at the site and is on time and on budget.

The first foundations have been poured and the first structural steel has been erected.

Engineering is nearly 80% complete and approximately 85% of the engineered equipment has been procured as of the end of the first quarter.

So to summarize, our businesses delivered strong operating and safety performance in the first quarter.

The Brunswick County construction project is proceeding on time and on budget.

We continue to work toward a formal filing with FERC for the Atlantic Coast Pipeline in September.

And construction of the Cove Point liquefaction project is continuing on time and on budget.

Thank you and we are ready for your questions.

(Operator Instructions) Greg Gordon, Evercore Group.

Pretty thorough presentation.

I really have only one question.

I know that you have been given a lot more runway in Virginia to run the business, given the flexibility of the new legislation and the uncertain, but there is also a lot of uncertainty that goes with that.

It doesn't look like the -- weather normalized sales were moved one way or the other that dramatically versus last year.

Can you talk about whether or not you are still running behind your longer-term growth expectation for kilowatt hour sales in your market?

And what your base case assumptions are over the next several years for growth?

We actually were quite happy with the first quarter weather normalized sales, where we were up slightly more than 1.5%.

If you recall, we guided everybody this year to 1% sales growth annually, 2015 over 2014.

And then as we talked on February 9, we look for growth beyond that 1.5% next year and then a more normal 2% range for us 2017 through the end of the decade.

But for the first quarter, residential sales came in strong.

And what we are very pleased about is commercial sales came in strong, excluding data centers, which we already knew were going to be very strong.

Commercial sales are where we lagged in the last couple years due to sequestration, particularly in Northern Virginia and Eastern Virginia, so we will see how that trend continues the rest of the year.

But with just three months' worth of data, we think we are off to a strong stale start.

The only -- it looks like even industrial -- it looks like across the board, everything was pretty strong.

Maybe industrial was a little bit weaker -- delivers --.

Excuse me, Greg.

Industrial was weak.

You're right.

But it is very deceiving, because most of the industrial weakness was due to low curtailment activities in the first quarter based on weather.

Fabulous.

Good answer.

Thank you; have a good day.

(Operator Instructions) Michael Weinstein, UBS.

Julian here.

Good morning.

Turning to the farmouts and just broadly the volumetric outlook on the Dominion Energy side, can you talk to just hitting the targets you laid out at the analyst day as you think about subsequent execution of farmout deals?

And also the royalty payments, given the oil price environment?

And then subsequently, the Blue Racer impacts from where we stand today.

So basically kind of a GNP, are you on track to hit the targets?

Farmout royalties and just generally GNP.

Sure.

Paul Koonce is going to handle the farmouts first.

And then I will talk generally about Blue Racer versus what we showed in February.

Yes.

We still remain very much engaged with producers on Utica acreage.

We have had a lot of success with the farmouts in the Marcellus.

We are now moving into the Utica, which is really the dry Utica, which right now seems to be where a lot of producers are putting forth their interest.

So if you go back to the chart that Tom showed us, February 9 of $450 million to $500 million between 2015, 2020, we really haven't seen anything change that.

We have been quite encouraged, frankly.

So that is kind of where we stand.

We are in negotiations right now and we will continue that.

Julian, on Blue Racer, if you will note in the script, there were two areas that we didn't talk about, mainly because we gave such a comprehensive update in February.

And one of them was Blue Racer.

And what I want to mention on Blue Racer is it that we need to bound Blue Racer, because we get lots of questions on it.

We get lots of questions on the basin, but Blue Racer's contribution at $85 million to $95 million, which we showed on February 9, is less than 2% of the total contribution to Dominion's overall earnings.

The other area that we will update only on significant changes are unregulated gas retail business, which, again, the reason we stopped including that in our script is because it is 1% of our total overall earnings.

So I just want to give that backdrop.

And in terms of Blue Racer, in the first half of this year, we feel real good with the processing volumes that are out there.

We have -- they have three processing units up and running.

The frac addition that was scheduled for the second quarter is in commissioning.

So I think we feel real good with Blue Racer.

I think the question I think will be with Blue Racer and others is later this year, do we continue to see the tie-ins that we expect -- expected before?

And we will have to wait to see what producers do.

But permits continue to grow in Ohio and in Pennsylvania.

And we are optimistic, but we will wait and see what the fourth quarter brings.

Great.

And then subsequently, just in terms of the 22% CAGR and thinking about subsequent dropdowns, vis-a-via M&A, how are you thinking about more drops?

Is there still the potential to have acquisitions at the MLP?

Or is generally the thought process at this point in time to warehouse those assets, whatever you may be targeting, at Dominion until a subsequent period in time to smooth out the growth rate, if you will.

Julian, I think it could happen a number of different ways.

Most of the assets that are in the market right now are liquid sensitive assets, which we would not be interested in.

But there are some that have fairly stable regulated earnings -- more pipeline-type assets.

If they were accretive and supportive of our growth rate at DM, we could do it at DM.

We could do it at D and house those until we wanted to drop them in the future.

So we have tremendous flexibility.

That is why we like the model of D and DM focusing on these assets together.

And it may well be a straight unit buy at DM or it might be a buy at D with a dropdown very similar to Carolina Gas Transmission.

So lots of flexibility, but I can assure you, we are not going to buy anything unless it adds value to both DM and D.

Great.

And then lastly, just on the -- speaking of housing, any developments on finding a YOKO partner?

May be too early.

For solar?

Yes.

We are pretty far down the road on how we want to structure that, Julian.

We have had a lot of inbound from all kinds of people that would be interested and partnering with an ultimate selldown.

I think the structure is going to be very similar to what we have talked about publicly before.

And that is a partial selldown into a joint venture and then an ultimate absolute sale in the future after certain tax restrictions are released.

So look for more on that, probably late summer or fall, but that process is well underway.

But a cash sale to get -- to bind to the JV up front.

And that is where you will get the premium for effectively having this transaction.

I think the way it will work is that we will get a cash sale for the interest that we sell initially into the JV.

And then we will get a cash sale when we ultimately selldown the remaining interest at a future period.

Neel Mitra, Tudor, Pickering.

First question was on Carolina Gas Transmission.

Could you discuss in a little bit more detail the growth projects that kind of get you from the 10% CAGR in EBITDA from 2015 to 2018?

And then also if there was any synergies between CGT and Atlantic Coast?

I will ask Paul Koonce to answer the first part of that.

In terms of Atlantic Coast, we are only focused on the existing project we have at Atlantic Coast and moving that process through the approval and construction period.

We don't, at this point in time, see any other project but what has been announced on ACP.

Yes.

Just on CGT growth, there are three projects in particular that have already been executed with the counterparty, the counterparty in this case being South Carolina Electric and Gas.

So the growth is in place.

The contracts have been signed.

The permitting process is well underway.

So we really don't see anything there that would really cause any question or concern.

Great.

My second question was on generation.

So in the past, you've said your CCGT projects were used to kind of catch up with retirements and Greensville County is going to be used to serve the additional load in your territory.

After Greensville County, are you set for generation for a while?

Or are there other needs within your service territory that would require additional builds, whether it is gas or other forms of generation?

Of course we have Brunswick.

We just finished Warren.

Brunswick is 60% complete.

Greensville County we will be filing for.

We also announced the 400 megawatts of solar and it is -- I am highly confident that we will need more generation construction in Virginia, post-Greensville County as a result of the carbon rule, the so-called clean power plant.

How much and what it will look like, we will have to see how the final rule comes out.

There is issues around the interim target and how rigorous that will be, whether it is a cliff-like target in 2020 or whether it be some kind of phasing in over the first few years of the compliance period, ultimately getting to 2030.

But I don't think there is -- I think there is very little chance we won't need to construct significant more generation in Virginia over the next 10 to 15 years.

Got it.

And then just as far as the approval for Greensville County, can you give us a timeline for that?

And then the RFP process for looking at merchant generators was that any different than Brunswick or Warren or was that pretty standard?

We ran the typical RFP process.

It is all done completely at arms' length.

It was reviewed by independent parties and you will see all that supported in the filing when it comes.

We should have the approval on Greensville County early next year and then get under construction.

Daniel Eggers, Credit Suisse.

Please stand by for streaming text.

Tom, I know it is not a big amount of capital, but can you maybe give your thoughts on the kind of the takeaways from the artificial island process and decision?

And maybe how that might affect some of the transmission investment decisions you guys might be looking at going forward?

Well, Daniel, it was interesting results.

Obviously after a very long drawn out process.

I am not sure, to be honest with you, what it portends to or the future.

We have our new FERC Chairman is there.

We'll have to see what emphasis there is on these kind of projects.

We'll continue to look at them and if we think it makes sense for us to participate, we will.

And it is hard for me to -- I wouldn't want to try to judge much about the future off that one data point.

But we are going to -- I can understand why you would ask.

We are all going to continue to watch it.

Okay.

And I guess just on the stayout in Virginia with the legislation in place.

Are there any major things you guys need to change operationally to be able to manage earning your ROE for such a long period without the review process or something we should be watching change in strategy-wise out of the business?

Well, there will be -- just to make sure there is not a big deal, but there is nuance in this.

There is a ROE reset in 2018.

There is not in this biannual.

And at that will apply to the riders going forward.

There is no earnings test.

But there is a ROE review.

We are just -- Dan, I would just say that we will focus very carefully on how we manage the business.

And we expect to be able to balance the needs of our customers and our other constituency -- constituents as we go through the next five years.

Okay.

And I guess just on the FERC pipeline investments, you guys have done a good job of finding opportunities in the last year or so.

Are you seeing things popping up right now or bubbling out that were opportunities going to existing here forward?

Or do you think the market is at a spot we are going to have to absorb what is in process before the next wave of announcements comes?

Well, we have a lot in process, but Paul Koonce spends a lot of time day to day on this, so I'll let him answer the question.

What is interesting is that as people sort of look closely at the clean power plant, we are starting to see a lot of our business development efforts shift toward providing supplies to combined cycles.

So we are seeing it off the Dominion East Ohio system up in Ohio.

And of course, we are seeing it along the DTI system, along the East -- Maryland and Eastern Pennsylvania and those areas.

So I think as we go forward in time, you will hear us talking about combined cycle gas supplies for a combined cycle.

That, I think, is going to be the next wave of growth.

And Paul, you see that being newbuild generation or rerouting to existing plans?

No.

I think we are seeing a combination of both, but newbuild is certainly one area where we have seen a lot of activity.

So our pipeline team is really spending a lot of time looking at the flexible services that generators need.

So for example, we have typically designed pipe to provide ratably over 24 hours.

If you need to supply all of that in an 8-hour period, it is a little bit different design spec.

So those are the things that we are looking at.

It is not just repowering; it is newbuild as well.

Steve Fleischmann, Wolfe Research.

On the farmout, was this something that was in your rough guidance expectation for the year or was this kind of a new thing?

One of them was in our guidance for the year.

The other one was an agreement that we had with a producer that was not in this year's guidance.

And so that was $0.04 of the $0.07 difference, but that is kind of the breakdown.

Okay.

Thank you.

And then on the Atlantic Coast Pipeline, I think could just generally -- not just this, but other pipelines -- are just starting to see maybe a little bit more noise in terms of citing these pipelines and I guess some pressure at FERC.

Is this -- do you think this is like a big change?

Or is this more just the nature of the fact that there is just a lot of building going on and so it is not really a big change?

I actually think it is a little bit of both.

There is a lot of activity going on and I think the nature of the conversation has gotten louder.

But when you back up and look at it, we have already surveyed nearly 80% of the right-of-way for the Atlantic Coast Pipeline.

We have bled out this field making the steel.

We are going to -- we're doing -- looking on the construction projects now.

FERC -- this is what they do.

They are very professional about this.

They recognize their role and I just think it is -- the world has changed some, for sure.

But we will see how it all goes on from here.

But I think it is -- there is going to be more noise around all pipelines.

Okay.

Maybe just one last question, just the overall environment for the Dominion Midstream in terms of both GNP and new pipeline growth.

Obviously, we have oil collapse.

Now it has stabilized some.

Things keep changing, but would you say your overall market perspective is still the same as it was three months, six months ago?

Has anything changed meaningfully?

Steve, I don't think anything has changed measurably.

We had the drop off in the oils down into the mid-$40s there at [prop mod].

But the strip is back in the low $60s for 2015, mid-$60s for 2016, 2017.

So I think if oil continues to stabilize and recover, we have a growing confidence that a lot of the producers will start tying in a lot of these wells and continue to grow, at least in the regions that we are operating in.

But that is why I mentioned earlier -- we are just going to have to wait and see until the fourth quarter or so as they work through the wells already been drilled in that production.

But I guess what makes us feel pretty good, if you look at the permitting in Ohio and Pennsylvania, West Virginia, you continue to add every month new permits and new growth.

And so it is just going to come down to producer confidence on how quick they are going to tie in and what basins they are going to shift resources to.

But it certainly looks like more Marcellus and Utica are still the two prime regions to drill for gas, oil, and liquids, if you are going to investor capital.

So we will see where we go between fourth quarter and next year in terms of volumes.

Shahriar Pourreza, Guggenheim Partners.

Just broadly speaking, can you maybe just provide a little bit of color on what you are seeing as far as muni and electric co-op opportunities?

I think there is at least maybe one muni or electric co-op within the state that has helped public hearings is as far as a potential sale.

A little bit of color there would be good.

I think that is Bristol you are referring to, which is in the far southwest part of the state, which is outside of our service territory.

We have -- I think there are 14 electric co-ops that are in our service territory.

It is like that.

It is about 10.

They are all -- we work very cooperatively with them.

We are their transmission providers.

We have a -- they have a collective group that buys generation on the market, some from us.

They own some plants.

They own part of North Ana with us.

And part of Clover.

But I haven't heard any notion of that from any of the other co-ops, other than -- or munis, for that matter, other than Bristol.

Got it.

It is a little bit preliminary, but just on Atlantic Coast, if you are seeing any potential opportunities to upsize that pipe to a little over 2 Bcfs per day.

And then maybe just touch on some of the comments that came out of those potential reroutes of the pipeline.

As we've said about the -- right now, it is a 1.5 Bcf pipe.

It can be expanded to 2 Bcf a day with just adding some compression to it.

It is almost 100% sold out at the 1.5 Bcf.

And we are going to just sit there for now until we get through this permitting process.

There have been -- and the second question was on the comments?

Right.

Sorry.

[Comments] reroute.

This is -- we look -- this happens with every pipeline, whether it is 10 miles or 500 miles.

We have already done over 100 small reroutes along the line.

It is one of the reasons why you go survey is to be able to meet with the landowners and they can express concerns about a particular -- where you are touching their property, if you can figure out a way to change it, to make it work for everybody, that is what we do.

And then we are looking at 10 -- we have already adopted 10 major reroutes and looked at others.

So this is all part of the process.

This is why you go through the prefiling process: to make sure everybody gets a chance to be heard on it and you can figure out what is the best approach.

We have had -- there have been -- almost 30 open houses and scoping meetings on this project so far, 7,500 people attending.

And that is the natural outcome as to every routes.

Chris Turnure, JPMorgan.

Tom, did I hear you say that the legislation that was passed back in February, I think, allows for gas reserves by you guys?

No.

No.

I didn't touch on that at all.

That is an interesting idea and we will have to -- we will talk to our staff about the -- the staff at the State Corporation Commission -- the Utility Commission staff to see what interest level they have in it.

It is the kind of thing we would want to have a sort of stakeholder process to go through and see if people really wanted us to do that or not.

But the legislation did not touch on that.

Okay.

Do you think that you have the ability to do that without legislative approval if you wanted to proceed?

Possibly.

But it is not something that I would think about with us right now.

Okay.

Then my second question is on equity issuance.

You mentioned in addition to the outstanding ATM that you are going to exhaust this year and the, I think, converts that you have coming due in the next couple years, you are potentially going to need $500 million to $1 billion of incremental equity through 2017 or 2018.

Is there any update that you can provide us on that number or the timing there or the method by which you would want to issue them?

No, there is no additional update other than what we talked about at the analyst meeting.

And you are exactly right.

We said after we do the at-the-market, we could have potentially an equity need of $500 million to $1 billion over the next 3 years.

But what we are watching closely, in terms of influencing this, is what is going to happen with bonus depreciation.

If bonus depreciation were to be extended a year or two, we would be a very large beneficiary of that because we have some very large projects underway.

That could well have a significant impact on any equity needs that will be remaining over the next three years.

So stay tuned on that later this year and see what happens in Washington.

And then we will be able to give some more clarity from 2016 and 2017.

Paul Patterson, Glenrock Associates.

Back on the farmouts, what is the expectation for a run rate on them for this year and next?

Paul, we said at the analyst meetings that we saw about $500 million worth of earnings for farmouts over the planned period that we talked about.

Right.

I think it is going to be a little lumpy, depending on what region you are in.

We have done most of our Marcellus farmouts already, so we are focused on that 180,000 acres of Utica.

We have had some strong interest in acreage there.

But I think if you want to model it, I would model $100 million a year or so as you go through.

But just knowing that depending on the timing of producers' interest, it could move around.

So that is $100 million pre-tax?

Pre-tax.

Okay.

And then on the ISO New England, the new zones, I know you guys filed a protest or a complaint because of the process.

But I was wondering if there was anything that you saw in those zones that the economic impact, if any, that you might be seeing as a result of the zones for the next capacity auction?

Paul, Dave Christian will go ahead and answer that for you.

Yes, we filed comments mostly regarding the process.

And we thought that there should have been additional opportunity for some stakeholder input.

So the way they went about it was a little unusual, in our view.

But our most sensitive unit up there, Millstone, stays in the Connecticut zone and we don't see any meaningful changes there.

The rest of it, we are still evaluating and it would be too early to say if there is anything substantial.

But I am not seeing anything meaningful at this point in time.

Thank you.

This does conclude this morning teleconference.

You may now disconnect your line and enjoy your day.

Thank you.