歐尼克 (OKE) 2014 Q2 法說會逐字稿

Good day and welcome to the ONEOK and ONEOK Partners second-quarter 2014 earnings conference call. Today's conference is being recorded. At this time I would like to turn the conference over to T.D. Eureste. Please go ahead, sir.

Thank you, Shannon, and welcome to ONEOK and ONEOK Partners second-quarter 2014 earnings conference call. A reminder that statements made during this call that might include ONEOK or ONEOK Partners' expectations or predictions should be considered forward-looking statements and are covered by the Safe Harbor provisions of the Securities Acts of 1933 and 1934.

Actual results could differ materially from those projected in any forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings. Our first speaker is Terry Spencer, President and CEO of ONEOK and ONEOK Partners. Terry.

Thank you, T.D. Good morning and thanks for joining us today. On this conference call is Derek Reiners, our Chief Financial Officer, who will review our financial results. Also with me and available to answer your questions are Rob Martinovich, our Executive Vice President of Commercial; Sheridan Swords, our Senior Vice President of Natural Gas Liquids; and Wes Christensen, our Senior Vice President of Operations.

On this morning's call we will review our second-quarter 2014 financial and operating results. I will expand on sequential variances comparing first-quarter 2014 results, which were impacted by strong seasonal demand, with the second quarter 2014 at the partnership.

I will discuss our recently announced capital projects which increased our capital growth program to a range of $7 billion to $7.5 billion. I will expand on what I consider an incredible capital growth phase we are entering. And then we will discuss our commitment to reducing natural gas flaring in North Dakota plus an NGL market and Conway-to-Mont Belvieu price differential update.

Before we review our second-quarter performance I would like to briefly discuss our 2014 financial guidance. We remain confident that we will meet our 2014 financial guidance expectations and reaffirm guidance at both ONEOK and ONEOK Partners. We will continue to review our expected performance as the year progresses and make any adjustments as appropriate.

Now our second-quarter performance. Operating income from continuing operations attributable to ONEOK reflects higher natural gas volumes gathered, processed and sold and higher natural gas liquids volume sold in the natural gas gathering and processing segment as a result of recently completed capital growth projects.

Second-quarter 2014 results reflect the first quarter that ONEOK has operated as the pure play general partner of ONEOK Partners. We remain committed to providing management and resources to ONEOK Partners to execute its growth strategies.

Derek now will review ONEOK's and ONEOK Partners' financial highlights and then I will review our operating performance. Derek?

Thanks, Terry, and good morning. Second-quarter 2014 net income attributable to ONEOK was approximately $62 million or $0.29 per diluted share. Income from continuing operations attributable to ONEOK was approximately $70 million or $0.33 per diluted share compared with second-quarter 2013 income from continuing operations of approximately $75 million or $0.36 per diluted share.

ONEOK is benefiting from its pure play general partnership strategy, receiving $287 million in distributions from ONEOK Partners in the six months of 2014, a 9% increase from the same period last year. Cash flow available for dividends for the first six months was $341 million providing 1.45 times coverage.

We are reaffirming ONEOK's cash flow available for dividend guidance range of $560 million to $640 million. ONEOK increased its quarterly 2014 dividend $0.015 per share to $0.575 per share effective for the second quarter of 2014, resulting in an annualized cash dividend of $2.30 per share.

Moving on to ONEOK Partners. ONEOK Partners' second-quarter net income was approximately $214 million or $0.54 per unit compared with $202 million or $0.62 per unit in the second quarter of 2013. Distributable cash flow was $272 million for the second quarter, providing coverage of 1.02 times.

For the first six months of 2014 distributable cash flow was $570 million, providing 1.14 times coverage, compared with $445 million for the same period last year, providing coverage of 0.99 times. Our long-term annual coverage ratio target still remains at 1.05 times to 1.15 times.

We increased our second-quarter 2014 distribution to $0.76 per unit, an increase of approximately 6% from our second-quarter 2013 distribution of $0.72 per unit. We also reaffirmed ONEOK Partners' 2014 net income guidance range of $975 million to $1.075 billion, its adjusted EBITDA guidance range of $1.565 billion to $1.665 billion, and its DCF guidance range of $1.15 billion to $1.25 billion.

The partnership slightly increased its 2014 capital spending guidance by $85 million to $2.1 billion primarily as a result of our recently announced Demicks Lake and Knox capital growth projects.

In the gathering and processing segment we have updated the margin estimate web model that can be found on the ONEOK Partners website. This update improves the accuracy of estimating the net margin by adding an electric compression charge which has become more significant with our Canadian Valley plant coming online and our growth in the Williston basin.

In the news release you will notice changes in our hedge percentages reflecting expected ramp up of volumes in the second half of 2014. During the quarter we issued 1.9 million common units through our at-the-market equity program and a total of 3 million common units in the first six months of 2014 compared with 681,000 common units issued in all of last year through the program.

Additionally, in May we completed a public offering of 13.9 million common units which generated net proceeds of $730 million. We used the proceeds to repay commercial paper, fund our capital expenditures and for general partnership purposes. With this offering, and excluding any potential acquisitions at the partnership, we don't expect to return to the overnight equity market again this year based on our planned 2014 capital expenditure guidance.

We have ample liquidity to support the partnership's ongoing capital growth program including access to nearly $1.7 billion under our commercial paper program or a credit facility as of June 30.

At the end of the second quarter the partnership had $278 million in cash and cash equivalents, no commercial paper outstanding and no borrowings outstanding on our credit facility, a long-term debt to capitalization ratio of 51% and a debt to adjusted EBITDA ratio of 3.4 times. Terry, that concludes my remarks.

Thank you, Derek. At ONEOK Partners the natural gas gathering and processing segment's second-quarter 2014 operating income was up 19% compared with the second quarter 2013 due to higher natural gas volumes gathered, processed and sold and higher natural gas liquids volume sold as a result of recently completed capital growth projects and higher net realized commodity prices.

From a sequential quarter comparison, operating income for the second quarter 2014 compared with the first quarter 2014 was up 10% due to a $17 million increase due to natural gas volume growth in the Williston basin in Western Oklahoma, offset partially by a $9 million decrease in lower net realized prices and a $7 million decrease due to changes in contract mix.

The segment's operating cost decreased $6 million sequentially primarily due to the timing of materials and supplies costs. Volumes increased sequentially quarter over quarter. Natural gas gathered increased 10% and natural gas processed increased 14%.

We have continued to see a significant ramp-up in natural gas volumes across our system since February and we expect to see this strong growth continue in the second half of 2014, especially in the Williston basin as we connect more wells to our system and as we bring our Garden Creek 2 and 3 facilities into service.

The natural gas liquids segment's second-quarter 2014 income was up 11% compared with the second quarter 2013 due to higher margin volumes delivered from the Bakken NGL pipeline and from new plants connected in the Mid-Continent region.

From a sequential quarter comparison, operating income following strong seasonal demand of the first quarter was down 10% due to a $40 million decrease in optimization margins primarily from narrower Conway-to-Mont Belvieu propane location price differentials and a $15 million decrease in marketing margins due to lower propane margins, offset by a $34 million increase in exchange services margins, which resulted primarily from higher margin natural gas liquids volumes delivered from the Bakken NGL pipeline and increased volumes from new plants connected in the Mid-Continent region, a $16 million increase in isomerization volumes due to wider iso-to normal price differentials and a $7 million increase in operational measurement gain.

The segment's operating cost increased $11 million sequentially primarily due to outside services and property taxes due to capital growth projects. Volume growth increased sequentially quarter over quarter. Natural gas liquids gathered increased 9% and natural gas liquids fractionated increased 10%.

We expect natural gas liquids volumes to increase during the second half of the year as previously connected natural gas processing plants continue to ramp up. Also 6 of the 10 plus connections to new processing plants we planned for 2014 have been completed through July with the balance occurring by year end.

During the fourth quarter we expect to reach approximately 575,000 barrels per day both for natural gas liquids gathered and fractionated. The segment's natural gas liquids volume was impacted in the first quarter 2014 due to severe cold weather which reduced supply deliveries to our systems. Ethane rejection also continues to impact volumes. The lower volume impact to the exchange service's financial performance is partially offset by minimum volume commitments.

Additionally, our Bakken NGL pipeline is now gathering approximately 40,000 barrels per day and will increase as our Garden Creek 2 and 3 plants come online. The Bakken barrel is our highest margin volume on our entire NGL system.

The natural gas pipeline segment's second-quarter 2014 income was up 14% compared with the second quarter 2013 due to higher natural gas transportation revenues related to increased rates on intrastate pipelines and higher contracted capacity and natural gas volumes transported in the natural gas pipeline segment.

Sequentially quarter over quarter operating income following the strong seasonal demand of the first quarter was down 32% due to a $6 million decrease in short-term natural gas storage services from reduced weather driven demand in the second quarter of 2014; a $5 million decrease in park and loan services also as a result of reduced weather driven demand in the second quarter 2014; and a $9 million decrease related to lower net retained fuel, lower natural gas prices and lower contracted storage capacity.

Equity earnings decreased $8 million sequentially primarily due to decreased park and loan services on Northern Border Pipeline compared with the higher weather-related demand in the first quarter 2014.

On July 1, 2014 the North Dakota Industrial Commission, or NDIC, adopted an order drafted by the Department of Mineral Resources which revised the state's rules for natural gas flaring. Earlier in the year the NDIC also approved an industry goal to reduce natural gas flaring to 5% to 10% of total production by the fourth quarter 2020.

We remain committed to being part of the solution to reduce natural gas flaring in North Dakota as we continue to invest in critical natural gas and NGL infrastructure.

This commitment was demonstrated by last week's joint announcement with North Dakota governor, Jack Dalrymple, on the Demicks Lake natural gas processing facility and related infrastructure in North Dakota, which will bring the partnership's natural gas processing capacity in the Williston basin 21.1 billion cubic feet per day by the end of 2016, 10 times the natural gas processing capacity we had in the region compared with 2010.

Additionally, we expect to announce additional Williston basin natural gas processing capacity by the end of this year pending Board approval. We are accelerating our capital growth program in the region as improved completion techniques and increased density drilling continue to drive higher production forecasts.

We also recently announced the Knox natural gas processing plant and related infrastructure in the crude oil and NGL rich SCOOP play in South-Central Oklahoma. This 200 million cubic feet per day plant will accommodate increased production of NGL rich natural gas in the emerging SCOOP where we have substantial acreage dedications. This will increase our Oklahoma Natural Gas processing capacity to 900 million cubic feet per day by the end of 2016.

Now an update on our announced capital growth program. The Garden Creek 2 natural gas processing plant is mechanically complete and on budget and we expect Garden Creek 2 to be operational and full by the end of August.

As mentioned in last week's announcement, the Garden Creek 3 natural gas processing plant is ahead of schedule and expected to be completed in the fourth quarter, 2014 versus the first quarter 2015. And by constructing additional field compression we will be able to take advantage of additional processing capacity at our existing and planned Garden Creek and State Line natural gas processing plants by a total of 100 million cubic feet per day by the fourth quarter 2015.

The Sterling I and II pipeline reconfiguration was completed in July. And finally, our MB-3 fractionators and the Sage Creek NGL pipeline infrastructure are expected to be completed in the fourth quarter 2014. The news release incorrectly stated the Sage Creek NGL pipeline infrastructure completion was fourth quarter 2015.

Our capital growth program is now at $7 billion to $7.5 billion and we are entering into another incredible capital growth phase at the partnership with the announcements of the Knox and Demicks Lake natural gas processing plants and related infrastructure and the expected announcement of additional processing capacity in the Williston basin pending Board approval.

Our announced capital growth program has approximately $3.2 billion to $3.7 billion remaining to spend between now and year-end 2016 and our backlog remains at $3 billion to $4 billion. We are well-positioned in the Bakken shale and Williston basin, the NGL rich area of the Niobrara shale and the Powder River basin with our Sage Creek acquisition which is progressing as planned and in the Cana-Woodford and SCOOP plays in the Mid-Continent.

Now a brief review of our outlook on the NGL markets and Conway-to-Mont Belvieu location price differential environment. Planned and unplanned ethylene plant outages plus expansion delays continue to constrain ethane cracking due to the decreased ethane demand and increased ethane rejection estimated to be approximately 300,000 barrels per day industry wide. Ethane inventories continue to build and could reach approximately 40 million barrels by the end of August.

As a result, we expect Conway-to-Mont Belvieu ethane location price differentials will be in the $0.03 to $0.05 per gallon range in favor of Mont Belvieu for the balance of the year.

Gulf Coast propane inventories are up approximately 24% over the five-year average and Midwest inventories are 8% under the five-year average. Propane exports continue to be strong and we are seeing more propane buying in Conway in preparation for the fall and winter. As a result we expect propane location price differentials between Conway and Mont Belvieu to be in the minus $0.02 to plus $0.02 per gallon range for the balance of the year.

Even in this narrow location price differential environment our integrated assets have performed well and we remain committed to our strategy of converting optimization margins to fee-based exchange services, which will continue to provide long-term value for our unit holders.

Normally I close by thanking all of the ONEOK employees whose professionalism and dedication allows us to create exceptional value for our investors and customers for which I am truly grateful. Today I would like to focus on my friend and one of ONEOK's most valued employees, Dan Harrison.

As most of you know, Dan passed away last week following a courageous and tough battle with cancer with his family by his side. Throughout his fight he was surrounded by his beloved wife and daughter, extended family, friends and his ONEOK and ONE Gas family. The outpouring of support for him and his family has been truly amazing.

His dedication and passion for ONEOK, its employees and its stakeholders cannot be put into words. His contributions to this Company and our employees are numerous. Dan led several functions for us among which were Communications and Investor Relations for which he had tremendous passion. How Dan was able to tell the ONEOK story to the investment community was truly best-in-class.

I remember when Dan joined ONEOK in 2005 he immediately recognized that our employees and integrated assets and their history of creating exceptional value he said, quote, made for a story that needed to be told, end quote.

So under Dan's guidance we traveled east and west and wherever he wanted to take us. Our stakeholders benefited from those efforts and this did not go unrecognized through our share and unit price. And by Dan's colleagues as he was named to Institutional Investor Relations magazines 2011 All American Executive Team.

Even as Dan was battling cancer he was instrumental in leading us through the separation from ONE Gas that we announced a little over a year ago. He provided me invaluable counsel and leadership, especially as I entered my new role as CEO.

I and the entire ONEOK family will be forever grateful for Dan's leadership, tenacity, kindness, professionalism, passion and dedication to this organization. Dan leaves behind a wonderful legacy and the way he was able to tell the ONEOK story to the investment community and we will always honor this and all of his many contributions.

Operator, we are ready for questions now.

(Operator Instructions). Ted Durbin, Goldman Sachs.

First of all, just on behalf of myself and Goldman Sachs, I want to pass on our condolences to you, to ONEOK and to Dan's family.

Thank you, Ted.

Maybe just starting off in the G&P business here and if you can just talk a little bit about the returns profile that we should be looking for. I guess if you look at kind of whether it is your guidance or where the numbers are coming for the first half of the year, at least when we do the math it looks like returns are not at the 5 to 7 times that you had been guiding us to.

So I guess the ramp as the capital is deployed, as the volumes ramp up, maybe just a little more help there in terms of how we should be thinking about that.

Sure, Ted. We still -- in our view still the economic returns on these projects are still within that 5 to 7 times in our view. Certainly you do have to think about the impact of commodity prices. Over the course of the last two or three years we have seen prices come down. That has impacted returns somewhat but we are still within that 5 to 7 range.

And is it -- should we expect that in a year or a couple years or what is the timing of when we think we hit the full run rate?

When we hit the full run rate?

Yes, for -- yes, exactly.

Ted, most of these plants when we turn them on, particularly Garden Creek 2, Garden Creek 3 and then the new process capacity that we've announced over the course of the last several months, we expect those to be full pretty darn quick. Almost as we start them up they will be essentially full day one.

Got it. Okay, great. And then if you can just talk about, again sticking with the G&P business, it looks like you had a little bit of a sequential drop if I look at second quarter versus first quarter in your equity NGL barrels. Is there anything behind that? What was the driver there?

Yes, Ted, Rob will take that.

We started the Canadian Valley, started that process in April. So as you are going through the start-up there you are not running it at full efficiencies, quite frankly, as volumes are coming on and you are getting the plants lined up. So that was the primary factor.

Got it. And then last one for me. On the two new plants for Demicks Lake and Knox, I guess are these contracts going to be similar to the other ones you have had where we should consider them mostly acreage dedications? Or are you setting up any minimum volume commitments or any sort of other financial backstops on any of these projects?

They will be very similar to contracts in the past, acreage dedications, DLP percentage plus fee components.

Got it. Okay, I will leave it at that. Thanks.

Carl Kirst, BMO Capital.

Also certainly like to add my condolences to the ONEOK family and very sorry I can't be at the service this afternoon.

Thanks, Carl.

Maybe just to start, if I could, with the projects in the queue. You guys obviously continue to be active, continue to point to more projects coming in the Bakken. Yet you still are kind of looking at in this $3 billion to $4 billion of unannounced. So I assume new projects are kind of coming into sort of help backfill.

And what I wonder is has there been any shift in characteristic as you are adding new projects to that potential backlog, is the first question. Second, is as you look at that $3 billion to $4 billion, is it possible to break down from just a rough ZIP Code of percentage how much of that is coming from either processing or commodity exposed infrastructure versus more fee-based infrastructure?

Well, Carl, I will take part of this question and then I could let Rob follow up with it. But, yes, the characterization of the projects that are coming into the backlog, as we continue to announce, are really no different than in the past. It is all gathering and processing, it is liquids rated infrastructure and it is in of course our core regions, the Bakken. We have expectations for the Niobrara or the Powder River basin as well. So really it is more of the same.

I think the mix of the projects too from a spending standpoint have been pretty well in the past, they have been pretty well 50-50 gathering and processing in NGLs. And I will let Rob speak to kind of going forward -- his assessment.

Sure. Carl, stepping back, the only thing I would add to what Terry said is certainly what we are seeing in the Bakken in the Mid-Continent shale similar to other shales is the newer wells are stronger than probably they were a few years ago.

And so, with that kind of as an overall backdrop, certainly what we are seeing is the opportunity for additional gathering and processing infrastructure in the areas be it the Bakken, the Niobrara, Oklahoma as we've demonstrated and then going forward to continuing in the Bakken.

And then from an NGL infrastructure to support those liquids. So I would say it is going to be, at the end of the day, maybe a little bit tilted toward the gathering and processing initially, but I think over time it will work its way down to that 50-50.

Okay, that is helpful, thank you. And then also if I could ask a question on the NGL volumes, and this may be more sort of geared towards the distribution lines, but noting that second quarter was relatively flat with first quarter despite Sterling III having come online.

And so, I just want to get a better sense of the nuance there. Is that from more the fact of just kind of the narrowed differential or was Sterling I and II, for all intents and purposes, down for the count for second quarter as it was finishing its reconfiguration work?

Carl, I am going to let Sheridan handle that question. But the only comment I will make, my contribution is that our business is a very complicated business in terms of the way we operate it. And when Sheridan gets done talking to you about that you will have an even better appreciation of the complexity. Sheridan, take it away, please.

Carl, you kind of hit it on the narrow spread differential as overall that is what is driving it. As we see spreads or prices are more in favor of the Conway market we are moving more of the barrels up through our system to Conway which has taken barrels away from the Sterling system than we had seen in the previous quarter.

So that is really overall what is driving our system -- driving the flatness in the two quarters of that piece is that more is just going north to the higher (multiple speakers) formation.

Excellent. And then last question if I could, and this is really more on the NGL volumes gathered. And Terry, correct me if I am wrong, I think you indicated that you guys were targeting a fourth-quarter run rate in the 575,000 barrel range, did I have the correct?

That is correct.

And so, that number seems to be a little bit lower than what we were looking for initially back last December. And I just wanted to make sure I knew exactly what was driving that delta, if it was primarily just a timing of gas plants coming on.

But also I wanted to ask, to the extent that you have any contract renewals at the tailgate of any of these plants, do you see any headwinds of any of those plants going a different direction and is there basically a volume at risk that we should be aware of?

Well, Carl, I'm going to take the last part of that question, I will let Sheridan handle the first part. But the last part of that question, no, we don't have concerns. But we do remain very sensitive to the market and extremely aware of our competition out there. And so, we've been very successful competing in our area and really don't see any vulnerabilities.

The one a contract that you have heard us talk about a number of times in past calls is we had a contract at the beginning of the year that we terminated. And that was a below market, very, very low margin contract that had been in place for a number of years. And so we terminated that contract and that of course has impacted our year-over-year volumes. If we haven't forgotten the question already I think Sheridan will handle the first part of it.

As we -- Carl, as we look into the fourth quarter of this year and why we have changed our volume it kind of comes down to a couple things. And one is we are seeing more ethane rejection across our system. And so, that is having an impact on it as well. We're also seeing as plants ramp-up they are not ramping up quite as fast as we thought they would in certain parts of our system.

But also we are seeing some -- the volume that is not coming on is more weighted towards our lower margin volume and the volume that is coming on is more of a higher margin volume. So that is a little bit fortunate for us that we are kind of having that mix that our higher margin volumes are doing well if not exceeding our expectations.

Okay, that is very helpful. Appreciate the color.

Michael Blum, Wells Fargo.

My condolences as well to the entire ONEOK family. A couple of questions. Just kind of -- maybe this is somewhat big picture, but just trying to think about fractionation utilization across your system both in Mont Belvieu and in the Mid-Con.

And you continue to add a lot of processing capacity in and around your system, of course a lot of it up in the Bakken. And I'm just wondering, does that -- should we expect that at some point you will need to add another fractionator to handle all that incremental volume coming off of all those plants?

Okay, Michael, I am going to give you the short answer and then Sheridan may give you a much longer answer. But the short answer is, yes. Do you have anything to add to that, Sheridan?

Michael, you hit it. As we bring more of these plants on, not just from our own plants but from other plants, we are looking forward to having more fractionation capacity coming on line, trying to make sure we understand where the right place to put it in our system is to maximize utilization of the capacity that we have now and in the future on both our pipelines and our existing fracs. So, yes, you will see -- if everything continues to progress you will see more fracs come out.

Michael, one other tidbit of information that I think may be helpful is that when we look at frac utilization in an ethane rejection environment like we are in right now, you may see the total utilization percentage be well below 100% and I am talking about anybody that operates fracs here in the industry.

It is a little bit misleading because what is not being utilized in an ethane rejection scenario is the front end of the frac. The back end of the frac may be very full, okay. And so, that is one little phenomenon or characteristic that you need to be aware of that I think will be helpful to you, particularly as we are in this ethane rejection environment.

Okay, no, that is helpful. I appreciate it. And then back on the Sterling pipeline, just so -- if you don't mind going over it again. So now that you have got I and II configured and III up and running, I mean what is the best way for us to think about what is [contracting] (technical difficulty) versus what is available for optimization? Is III fully contracted, are you now using I and II for optimization or -- just trying to get a feel for how those three lines now are going to interact or --?

Michael, I think the first thing, you have got to look at those three lines as working as one system. And so you have three different capacities that you can put the right mix of product on those lines. And with how we've configured today, we are also going to use one of those lines for raw feed to move raw feed between the Mid-Continent and Mont Belvieu.

So like when we are in certain situations where we had an ethane rejection, we don't have as much EEP coming out of the Mid-Continent, we could put that on a smaller line and use one of the other lines for purity products or raw feed if that is what it dictates.

So we will be able to move product in between those lines to maximize capacities that we have going from Conway to Belvieu. So you've kind of got to think of them as a complete system, not as individual pipelines.

Okay. My last question just any updated thoughts you have on establishing a bigger footprint in the crude markets, obviously we have seen one Bakken crude line get project get announced. Just not necessarily asking about that particular project but just generally your thoughts in terms of getting into the crude side of the business more?

Yes, Michael, we still are engaged in that process and still would like to establish a footprint where it makes good sense and where it makes economic sense. The Bakken continues to be an area that we are continually prospecting for opportunity. The fact of the matter is though as you look at the crude oil landscape, not many people want to sell or divest of their crude oil assets. So those are very valuable, they are very valuable assets to most midstream companies.

So we have continued though to look for logistical opportunities, storage, terminalling, pipelines, that type of thing. But of course we again have to continue to weigh those investments against our alternative investments in our core areas like our Bakken gathering and processing, our Mid-Continent gathering and processing, our Mont Belvieu, Gulf Coast NGL position. So we want to be in the crude business. We are very aggressively looking for those opportunities but certainly we are not going to do them at the expense of economic discipline and in particular at the expense of investments we are making in our core areas.

Great, thank you.

John Edwards, Credit Suisse.

And also my condolences to Dan's and the entire ONEOK family.

Thank you, John.

Just wanted to make sure I understood -- you mentioned about reducing flaring in the Bakken down to I think you said the 5% or maybe 5% to 10% level by 2020. And I am just curious, your thoughts on how much capital do you think will be required to accomplish that up in the Williston basin there?

Well, certainly it is going to take a lot of capital, as you can see. We have already announced our Demicks Lake processing plant and now we are telling you that we are going to announce yet more capacity between now and the end of the year pending Board approval.

Every time we announce these plants they are now much larger plants than we've built in the past, they are in that 200 million a day capacity range. And now we've announced two of them in the last several months and you have got -- from that you've got a pretty good sense of what the capital is and the frequency associated there with.

We don't know exactly when the capacity is going to stop. That is what is happening that is making this challenging for us is that the increased density, the increased number of wells per spacing unit is increasing dramatically, seemingly quarter by quarter.

And when you look at current density levels being at about 14 -- roughly 14 wells per spacing unit as compared to maybe 3, 4, 5 or 6 several months ago that has a tremendous impact on your volume forecast, makes it difficult to figure out where the top side of this thing can be.

We have also heard increased density to as many as 30 plus wells per spacing unit, although we have not assumed that in our economics. And certainly we have a very large acreage dedication inventory, if you will, that is we have got a lot of acres under dedication there, they're continuing to grow. So it makes that really challenging, John.

I wish I could tell you an exact figure of what it is going to take to get to that point because it may take more. If I gave you a number I might determine three months from now it is going to take a lot more. And certainly that is a good problem to have for a midstream company.

So it sounds like you are capturing a very large share in this regard. I mean would it -- and you have just announced these recent projects, yet you -- and this to Carl's question -- you have not expanded your backlog under consideration, the $3 billion to $4 billion at all. But it sounds like potentially there is upward pressure on that. Is that the right way to think about it?

Absolutely.

Okay, that is really helpful. So I guess would it be safe to say this whole flaring issue, you are talking many billions of dollars? And is it fair to say you expect to get maybe half of that business? Or just if you can give us an idea share wise how you think about it.

At least half.

Okay.

Okay. When you look at our footprint, within our footprint we have got 5 billion to 6 million acres that are asset footprint touches. We've got 3 million acres under dedication. When you look at kind of our share of the field within our reach, 50% is a pretty good number right now. And as we continue to put these larger processing plants in, that percentage will likely grow.

Okay, that is really helpful. All right and then switching gears. I wanted to make sure I understood your comment about what the optimization margin expectation is now. I think back at your Analyst Day I think you were protecting for 2014 I think it was something like $0.07.

That is correct. That is correct.

And what is the expectation now?

Well, for the balance of the year about $0.03 to $0.05 a gallon on the ethane differential. As we look out further into the 2015-2016 time frame we are thinking $0.05 to $0.06. So we are tempering our thoughts on that a bit.

Okay.

So, does that help you?

Yes, that -- no, that is really helpful. And then just lastly, you are speaking -- and again I think this was to Carl's question. But as far as I guess kind of the ramp on your volumes offset by margin, how -- in terms of the return on those -- on your projects given how I think you said you are getting more at the heavy end of the barrel where the margin is higher. So is your overall return relatively unchanged? How should we think about that?

Well, as I said earlier in the earlier question, our returns are still within that 5 to 7 times. Commodity prices have affected that particularly with these POP contracts to some extent. But they're still within that -- they are still comfortably within that range.

What is happening -- what affects returns as well as margin is volume, okay. And the volumes continue to perform, we continue to build incremental gathering facilities in addition to these plants at lower cost. So, yes, I mean I think to some extent we have offset some of that impact from commodity pricing, lower commodity pricing.

Okay. So you are -- just because the volumes are ramping a little slower because of the mix you are not really seeing significant return erosion, you are still within your normal parameters?

We are still within that range. I think the other thing -- the other comment I will make, John, is when we look at the returns on these gathering and processing investments in the Bakken you have got to remember too that we are bringing NGLs down -- our NGL infrastructure, okay.

And what happens is sometimes it requires incremental capital to get those NGLs to market and sometimes for some periods of time it won't. So the returns that you earn collectively when you combine the gathering and processing operation with the NGL investment you get great returns.

Okay.

You follow me?

Yes. No, that is really helpful. All right, thank you very much. That is all I have.

Chris Sighinolfi, Jeffries.

I wanted to follow-up on some of the volumetric questions you made during prepared remarks. Carl asked about the fourth-quarter expectation on the frac side. I wanted to touch base real quickly on your hedge percentages for NGLs came down in the last update with no real change to the absolute hedge position.

So obviously implying some higher numbers in the back half. Just wondering how that sort of details with the full-year guidance that you gave for gathering and process volumes. Did you take those -- did I miss it or did those figures go up?

Chris, I am going to let Rob take that question.

Hey, Chris. Yes, we are expecting at this point a stronger second half than we had a couple months ago. We expect to, from a processing volume standpoint, beat our guidance at this point in time. And so as a result you did see the percentage hedged reduce.

Got it, okay.

And Chris of course we will -- obviously that percent hedged is now in that 57% range on the NGLs. We will look for opportunities to hedge as we move through the back half of the year.

Exactly.

Well, that also brings me to the next question, Terry, which is how do you guys think, given the NGL market today across all the products, clearly taking into account what you guys have said about the light end products in the past?

But how do you think about sort of the window into 2015 or even beginning to look into 2016 on any of that hedging behavior? Is that -- are you finding any opportunities that are attractive at this moment in time or is it just going to be sort of real-time opportunistic behavior?

It will be -- Chris, it will be opportunistic. We don't have anything right now at this 10 seconds. But certainly we are looking at it every day, hard.

Okay. And so historically, Terry, thinking about how much you guys were hedging, is the general goal on a go-forward is still sort of get up to those levels as we enter any given period of time? Or are you comfortable running a little bit less hedge now given your internal view of the market?

Well, we'd actually -- as you move into the later part of the year we get a little more comfortable with our volumes. And so, as we move into the year our tendency -- or as we move through the year our tendency will be to get more hedged, okay.

But we are -- the market today has limited opportunities for us and, like I said, we'll -- but it can change in a hurry. And we will continue to use this opportunistic strategy, which gravitates around a 75% hedged across the board strategy, okay. And that is not real prescriptive and hard and fast. We have at times gotten about the 75%, like I say, as we move later into the year and get more confident in our volumes. So I hope that helps.

Yes, it does, it does. I want to switch gears real quickly, Terry, a lot of questions on infrastructure opportunities. And obviously we have seen additional build outs in the Bakken, you alluded to some more potentially coming with Board approval by the end of the year.

And so, I am just curious how we think about NGL take away capacity from the base. I mean clearly you have the NGL line today and you are doing expansion on it. But as we think out beyond that, just remind me, does that system have the capacity to be expanded further or would we -- would additional take away above this expansion entail an entirely new system?

Chris, the short answer is, yes. It is expandable, we have done some expansion and some expansion projects are underway. And if necessary more to come. I will let Sheridan talk -- give you a little bit more color on how we would expand those facilities.

Basically the last expansion that we did -- let me back up. The first expansion you saw we put intermediate pump stations in. The next expansion we started loops on the pipeline. So any further expansions of the pipeline will continue to extend a loop, meaning that we are laying a line right next to the original line and tying it in. If we need more capacity we will continue to extend those loops to be able to get the right amount of capacity out of the Bakken pipeline.

Okay. So those adds (inaudible) could be smaller in size, just more incremental?

Yes, the investment will be smaller in size than building a brand-new system. Now eventually as you extend loops you will have a new system when you finish them all, but you do it incrementally a little bit at a time.

Got it.

And Chris, just from a number standpoint, the pumps that Sheridan talked about gives us up to 135,000 barrels a day and that initial looping is up to 160,000.

Right, right. Okay, and then a final question, Sheridan, you had talked about the reconfiguration of the Sterling systems. And I just wanted to confirm, I think it was my belief Sterling I was the only one capable of going south to north. Is that accurate?

That is correct.

Okay. All right. Thanks a lot for the time, guys.

Jeremy Tonet, JPMorgan.

And our sincere condolences to ONEOK and Dan's family as well. Just looking at your guidance for the year, there seems to be a strong ramp up in second-half 2014 EBITDA. And I was wondering if you could provide just a bit more granularity on what is driving the ramp on an asset basis, if that is possible, which projects. And what the shape of that ramp could look like between 3Q and 4Q?

Well, Jeremy, I'm going to just tell you the short answer, it is all about volume. And Rob will give you a whole lot more color than that, I am sure.

Hey, Jeremy. Let's start I guess from a pipe standpoint and just kind of go segment by segment. I mean obviously had a great first quarter with regards to the maximizing our assets during a severe winter with regards to park and loan as did our equity interest in Northern Border. And so, we've been able to keep that and that segment has continued to perform well as noted in the second quarter and we expect that to continue going forward the balance of the year. So we certainly expect to keep those gains.

While G&P as well as the rest of the industry got stung a little bit on the opposite side of that severe weather from a volumetric standpoint, again we are emphasizing what we said earlier.

The second half of the year with those facilities coming on with the continued strong volumes that we are seeing in the Mid-Continent, that facilities coming on earlier in the Bakken, that is giving us pretty strong indications that overall volumes for the year are going to be stronger than what we guided to. And as a result that is where we are going to see the benefits in the second half of the year. And as -- so that is the G&P. So obviously expecting both those to continue to perform strongly for the year.

From an NGL standpoint, while volumes are down where we thought we would be at the beginning of the year, certainly we don't want anyone to lose sight of the great first quarter with regards to, again, maximizing our assets to get propane to the Midwest market.

And other opportunities have continued to come along -- isomerization spreads certainly were strong this quarter. The guys are doing all the, as Terry alluded, very complicated business, but they're doing a lot of things maximizing our system, again, to take us the opportunity where spreads are.

So while volumes overall are down we do have some thinner margins that are accounted for in that volume being off as well as some additional volumes are mitigated with take or pay or ship or pay contracts as well. So net-net that is kind of where we see the three segments with G&P and types being up. And then NGL being slightly down. But overall that is the reason that Terry commented that we are reaffirming guidance for the year.

That is helpful. Thank you. Thanks for the color. When thinking about future growth CapEx potential, I was wondering how much of your opportunities set resides kind of in your existing footprint, in particular the Bakken and the Mid-Con where you keep having lots of nice projects materializing.

And how much of a focus is there on expanding the platform to new basins or growing your position there such as the Niobrara or entering the Permian? Just wondering if you could share your thoughts on that trade-off?

As we said before, we are continually looking for opportunity to expand our footprint where it makes sense and where we can utilize, in particular, our existing assets to enhance any competitive advantage getting into those areas.

So, yes, we continue to look, the Permian certainly, as I have said many times in the past, is an area of focus for us, it is a target rich environment in terms of production. And it is underserved in some areas.

So, yes, we're going to continue to expand or at least look to expand outside our footprint. The Niobrara of course is one that you mentioned, one that where things are going very well for us, we continue to contract more and more acreage dedications and enhance our contractual footprint there. And the capital spending is coming.

So that is kind of how we look at it. Yes, we really would like to have another platform like whether it is for crude oil, as I mentioned before, or perhaps it is gathering and processing and NGLs in another region, perhaps the Permian, certainly that would be very attractive to us.

That is helpful. Thank you very much.

Craig Shere, Tuohy Brothers.

We are also very sorry to hear about Dan, he will be very missed.

Thank you, Craig.

So piggybacking a little on Carl's initial growth CapEx question and a number of the others, despite the $1.1 billion of incremental growth CapEx announced in recent weeks and the implicit increase on unannounced backlog, you are not getting much respect this morning at OKS in the market. Can you give some color around the pace of the timing of this $3 billion to $4 billion of incremental announcements besides the Bakken processing that will likely be disclosed by year-end?

Sure, I mean I think what we can tell you as far as that capital backlog, we haven't provided specific timing associated with it. But generally speaking it takes a couple years to build these -- most of these projects, these plants and these pipelines.

So I think if I were trying to make a swag at it in terms of the timing associated with that capital, certainly most of it would be spent over the next couple years.

Okay, so you think most of that $3 billion to $4 billion would be announced in the next six to nine months?

Yes, it would actually be announced -- well, yes. If it is going to -- if you are going to spend -- at the spend rate is a couple years, it takes you a couple years to spend it, you are probably going to announce most of these projects in the next 12 months or so. But, yes, I think that is fair.

Okay, that is very helpful. And, Terry, expanding on your ethane commentary and John's optimization question, the roughly nickel spread and outlook for 2015 and 2016 seems much more sober than I think what you all were talking about just last quarter. I don't know if Sheridan wants to respond to this more.

But while delays in downstream projects like Geismar are obviously having a near-term impact, what exactly are the catalysts you are seeing out one to two years that are making it a little more sober?

Well, certainly, just at a high level what I can tell you is supply growth continues to be very strong and it is coming at you from a lot of different areas like the Eagle Ford and the Marcellus and then of course in our core areas supply continues to grow. And I will let Sheridan provide you perhaps a bit more color, at least his thoughts on that.

The other thing that you have is 2015 and 2016, you get in the end of 2016 and 2017 is when the new big crackers come online. So you are kind of in this -- we think you are kind of in the situation year to day through those next two months -- next two years.

Obviously Geismar and some other plants that have been down longer than anticipated for both planned and unplanned outages have built ethane inventories higher than we anticipated at this time and we think that is going to have a little bit of a drag into the next two years.

Craig, too, the other comments that I will make is there's been a lot of talk about ethane export facilities. And so -- but the timing associated with those is not immediate. So they're still a year plus away.

I think the other thing that you have working against you is the view of many that natural gas prices are going to stay fairly weak over this time frame as well. So that will kind of have a drag down effect on your ethane prices.

Okay, that makes some sense. And, Rob, I think you mentioned how the isomerization volumes were pretty good in the quarter. Obviously in the press release there was a nice uptick in that margin. Do you see this as a seasonal optimization benefit or something that is really kind of a sustainable trend that we can see each year?

I mean, historically you would call it seasonal, Craig, I think there is some things as far as where that supply was coming from this year versus in past years where it has been more focused on a Mid-Continent supply, so that is where we have gotten the benefit from that standpoint.

Sheridan, you got anything?

Yes, we are seeing a little bit more demand this year through the what we call the driving season in the unleaded market that is continuing on a period of time that we haven't seen in the past. Our customers are demanding more from us out of the Mid-Continent than they have in the past. And that could continue to go forward, but we don't -- it is still a seasonal spread opportunity asset.

Fair enough. And last question, I don't know if this is just beating Bakken growth into the ground, but the implicit guidance on well connects, I think is like [710] in the second half versus [590] in the first half and [560] last year for the second half if I am doing my math right.

Do you see -- I mean, when you talk to your producer customers, if you are able to stay ahead of their activity, do you see this growth trend continuing without any interruption? Is there a steady state at some point in terms of total number per quarter that we should think about?

Craig, I guess certainly we are into the period now where from an overall construction and specifically well connects July and August have historically been our and the industry's high water marks. I mean, you are making a lot of hay now from that perspective. So those typically peak and as you get into the fourth quarter and early into the first quarter depending on weather that tends to slow you down.

So again, similar to the overall volume standpoint with the first-quarter severe weather that put you a little bit behind where you thought where you thought you might be. But at the end of the day our well connects aren't really ratable over the year because of just the seasons that we have. But overall from a growth standpoint when you again step back from a growth to support those volumes they are going to be continued number of connects.

Now obviously as we go to the multi-well pads you are laying one well in and, as Terry said, as those number of wells per spacing unit continue to increase you are going to benefit from that. But at the end of the day the number of wells ultimately that you're able to handle is going to continue to grow because that is supporting this ultimate volume growth that you've seen from third parties that is just continuing to ramp up to the right pretty strong.

Okay, appreciate all the color.

Helen Ryoo, Barclays.

And I would also like to share my condolences to Dan and ONEOK family.

Thank you, Helen.

A couple of questions. Starting with the new Bakken project. It looks like the cost is -- like 80% of the plant is 80% higher than the Knox plant, although the related infrastructure cost is pretty much consistent. And just wondering, the higher construction cost for the plant, does this reflect maybe cost inflation in that area?

And then a follow-up to that is if it is more expensive to build a GMP system up in Bakken versus other regions, are midstream operators in general able to charge more to compensate for sort of the high costs up there?

Helen, I am going to let Wes Christensen answer that question.

We have seen some upward pressure for costs for building plants and infrastructure in the Bakken area. It is primarily related to labor costs that have escalated in the area. As far as it goes with the equipment and supplies associated with it, we are not seeing upward pressure as much on that but we are seeing some schedule impacts.

And then, Helen, from a standpoint of margin, I mean margins in the Bakken are stronger than the Mid-Continent. I don't want to say that that is necessarily a reason for the costs that you charge more, but historically they have been stronger.

I guess the one thing I will add to this, Wes -- you could add to it if you don't hear -- if you don't agree with what I am saying. If you look at a plant, you built a 200 million a day plant in the Bakken versus a 200 million a day plant in Oklahoma, those are not the same plants. The processing plant in the Bakken is designed to operate in extremely hostile conditions. So a lot of measures have to be taken in the design of that plant.

So that is a factor in the difference to some of these costs. And, of course, the richness of the gas is hugely significant in the design of these plants. It is basically the NGL content sets the size of many of these towers that are used in the processing facilities, and the size of the liquid pumps and what have you.

So, Wes, do you have anything to add to that?

That's true, Terry, and they are also -- there is additional infrastructure related to stabilizers and handling the inlet condensate because of the richness as well.

Very good, thank you, Wes.

Ladies and gentlemen, it appears that does conclude today's question-and-answer session. I would like to turn the conference over back to Mr. Eureste for closing remarks.

Thank you for joining us. Our quiet period for the third quarter starts when we close our books in early October and extends until earnings are released after the market closes on November 4, followed by our conference call on November 5. We will provide details on the conference call at a later date.

I will be available throughout the day to answer your follow-up questions. Thank you for joining us and have a great day.

Ladies and gentlemen, that does conclude today's conference. We do thank you for your participation. You may now disconnect. Have a great rest of your day.