Oneok Inc (OKE) — Q2 2015 Earnings Call Transcript

Thank you and welcome to ONEOK and ONEOK Partners’ second quarter 2015 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 thank you for joining today and for your continued interest in ONEOK and ONEOK Partners. On this conference call is Walt Hulse, Executive Vice President of Strategic Planning and Corporate Affairs; Derek Reiners, our Chief Financial Officer; Wes Christensen, Senior Vice President, Operations; Sheridan Swords, Senior Vice President, Natural Gas Liquids; Kevin Burdick, Vice President, Natural Gas Gathering and Processing; and Phil May, Vice President, Natural Gas Pipelines. As noted in our second quarter earnings results release yesterday afternoon, key financial and operational information discussed during our first quarter earnings call has been updated in a short presentation and is posted on ONEOK’s and ONEOK Partners’ website. Please refer to this presentation and to the earnings releases for various explanations and key metrics. With the information that has already been provided, I intend to keep my remarks brief today and focus on a few key areas. We’ll spend the majority of our time answering your questions. To begin, even in this continued weak commodity price environment, we expect that both ONEOK and ONEOK Partners will end the year within our 2015 financial guidance ranges. And as we exit 2015, we expect 2016 to continue to benefit from the completed and soon to be completed capital growth projects in the natural gas liquids, natural gas pipelines and natural gas gathering and processing segments. We are seeing volume growth through the first half of the year as anticipated, particularly regarding natural gas liquids gathered and fractionated and natural gas gathered and processed. We expect these volume increases to continue into 2016. Overall, the Partnership’s year-to-date performance positions us to achieve our natural gas gathering volume and financial objectives for the year. I will now turn the call over to Derek for a brief discussion of ONEOK Partners’ and ONEOK’s financials. Derek?

Thank you, Terry. Starting on partnership, 2015 EBITDA contribution continues to ramp up as strong volume growth is shaking up as we anticipated. We expect to grow our EBITDA in the second half of 2015 and be within our 2015 financial guidance EBITDA range of $1.51 billion to $1.73 billion. Our EBITDA growth follows the volume growth. Even in this lower commodity price environment, the Partnership’s year-to-date EBITDA of $712 million is only $40 million less than in the same period in 2014, which was a record in an environment with much higher commodity prices. Our coverage ratio has improved to a 0.88 times coverage in the second quarter of 2015 and we expect continued improvement in our coverage the balance of the year. The partnership has a solid balance sheet and ample liquidity to support our current capital program including access to our commercial paper program and credit facility. As of June 30, ONEOK Partners had an adjusted debt-to-EBITDA ratio of 4.5 times. As we said, investment grade credit ratings of ONEOK Partners remain very important to us. Through the first half of 2015 our ATM program was a very effective tool for issuing equity and we continue to evaluate the overnight equity markets and other sources of capital. We will continue to take a balanced approach and remain disciplined when issuing debt and equity. Additional equity is needed to continue to support our capital projects. We continue to remain confident in our ability to raise necessary capital to fund our capital projects at ONEOK Partners. At ONEOK our liquidity remains strong with $150 million in cash and an undrawn $300 million credit facility, and a debt-to-EBITDA ratio of 2 times at June 30. We continue to retain cash at ONEOK as we navigate these uncertain times. Terry, that concludes my remarks.

Thank you, Derek. Now let's take a closer look at each of our business segments, starting with our natural gas liquids segment. The segment's 2015 year-to-date results were supported by solid second quarter performance. The segment's year-to-date operating income exceeds year-to-date 2014 operating income. This becomes a more useful statistic when you consider that first quarter 2014 results rightly benefited from a historically high demand for propane and that in 2015 the segment has experienced lower realized NGL product price differentials and narrower NGL location price differentials. So even though year-over-year the segment was competing with the 2014 propane benefit, operating income so far in 2015 has exceeded first half 2014 totals because of the continued strong growth of fee-based revenues and volumes. Our integrated NGL system continues to benefit from providing non-discretionary fee-based services to NGL producers by connecting growing natural gas liquids supply in the Rocky Mountain, Mid-Continent and Permian regions with key market centers. The natural gas liquids gathered volume on the Bakken NGL pipeline reached approximately 100,000 barrels per day in July and is expected to reach approximately 105,000 barrels per day in the fourth quarter of 2015. This is an increase of approximately 20,000 barrels per day from what we expected in the first quarter as a result of decreased ethane rejection in the Rocky Mountain region. We will talk more about the reduced ethane rejection in a moment. The average bundle gathering and fractionation rate on the Bakken NGL pipeline is more than $0.30 per gallon. Moving to our fractionated volume. In addition to the increased ethane fractionated due to the decreased ethane rejection, we also saw more than 20,000 barrels per day of incremental interruptible volumes on our system in the second quarter as we were able to utilize our fractionation assets to meet market demand. We expect to continue to see approximately that level of incremental interruptible volume from our system into the fourth quarter. As a reminder, we do not include interruptible volumes in our fractionation volume guidance. And finally, in recent weeks, we have seen Conway to Mont Belvieu ethane price differentials range from $0.02 to $0.03 per gallon and we expect this range to continue for the rest of this year. As you know our natural gas pipelines business is primarily fee-based with long-term firm demand charge contracts. We continue to develop new projects and opportunities to grow our fee-based earnings. Just last week we announced plans to expand our ONEOK WesTex Intrastate Natural Gas Pipeline System in the Texas Panhandle and Permian Basin. The expansion which will complement our previously announced Roadrunner Gas Transmission Pipeline joint venture is already 90% subscribed with 25 years firm demand charge agreements. These projects and the expansion of our Mid-Western Gas Transmission Pipeline System are continued examples of our commitment to stable long-term fee-based earnings growth. The natural gas gathering and processing segment's second quarter results were significantly improved over the first quarter. Earnings for this segment are still expected to be significantly weighted towards the second half of the year which is in line with the expected growth of our 2015 natural gas gathered and processed volumes. We have greater confidence in our Williston Basin volume projections with six months of operating performance under our belt and good visibility into the remainder of 2015. The segment is seeing the benefit of rigs concentrated in the most productive areas, new well connections, two compressor stations completed, and the current flared gas inventory. We expect Williston Basin volume in the third quarter to reach approximately 650 million cubic feet per day as we continue to bring on additional field infrastructure. Additionally, our new well connections continue to exceed our expectations as we completed nearly as many in the first half of 2015 as we did in the first half of 2014. We remain on track to fill our plans to approximately 685 million cubic feet per day in the fourth quarter as we complete gathering system and compression projects through the second half of the year. These new compressor stations will not only fill our existing plants but also will provide capacity to ramp up volumes at our Lonesome Creek plant, which is expected to be completed late in the fourth quarter of 2015. In the Mid-Continent our volumes increased quarter-over-quarter due to incremental interruptible gathering and processing services we provide to third parties from time to time as demand dictates. In addition, a key producer in the Cana-Woodford has started the process of completing wells drilled in the first half of the year. Our commercial team continues to make progress with customers on its recontracting efforts and has seen positive results in increasing our fee-based margin while providing enhanced services to our customers. Additionally, we reduced the level of ethane rejection in the Rocky Mountain region in June 2015 to maintain downstream NGL product quality specifications to ensure continued reliable delivery of high quality NGL products to meet the needs of our downstream markets. We expect the decreased level of ethane rejections to continue. Our producer customers are continuing to find ways to reduce drilling costs and are doing more with less. Said another way, our producer customers are increasing volume with fewer but more efficient rigs, and advanced completion technologies are increasing well production rates to levels the industry has never seen before. Our positive operating performance through the first half of the year, combined with what our producer customers are communicating to us, has given us greater confidence in our 2015 natural gas gathering and processing volumes and momentum into 2016. Much like 2015, our 2016 volume growth is expected to be led by growth in the Williston Basin. In the Williston, we connected more than 260 new wells in the second quarter of 2015, bringing our year-to-date total to more than 560 new well connections. We still expect to reach our 2015 new well connection goal of more than 700 wells and our 2016 goal of more than 600 new wells. There continues to be an inventory of flared gas in the Williston Basin, and we estimate approximately 145 million cubic feet per day is dedicated to the Partnership with the majority of the wells flaring already connected to our system. As I touched on earlier, our producer customers are doing more with less. There are approximately 40 rigs drilling in the most productive areas at any given time on our acreage dedication in Northeast McKenzie, North Dunn, and Southern Williams Counties. Additionally, wells in the high producing areas continue to exhibit significant performance improvements, producing two to three times more natural gas than lower producing areas. Additionally, more than 900 wells, which have been drilled but not completed, remain in the basin. The continued drilling flared natural gas inventory, improved well performance and significant backlog of uncompleted wells is expected to continue and help contribute to the Partnership reaching its 2016 natural gas gathered volume expectations. Our strong natural gas liquids and natural gas volume growth in the second quarter support the volume outlook we’ve been communicating and provide our stakeholders additional visibility to support our volume growth outlook for the second half of the year; and most importantly, our financial guidance expectations for 2015 and the momentum into 2016. As always, thank you for your continued support in ONEOK and ONEOK Partners and thank you to our dedicated employees for your hard work and continued commitment to our Company. Operator, we’re ready for the questions.

I just wanted to start with the reduced ethane in the Rockies. When you say to maintain downstream product quality specifications, are you talking about meeting natural gas pipeline specs?

No Christine we’re talking about natural liquids specifications….

So…Yes, more color would be helpful.

Sure, and Sheridan, I’ll let you talk about it.

The NGLs coming out of the Bakken have a high oxygen content, and as we fractionate that oxygen, it’s been driven into the propane, and the butane and to be able to get that by bringing more ethane on, we can drive it into the EP or we can treat it and we continue to make sure that the propane is on spec for delivery into the end-use market.

And then I guess a molecule from the Rockies. How much does that generate? I am assuming it's not the full $0.30 that we usually look at for Bakken.

We are close to that number, but there are some offsets due to the demand charges that the current shipper pays. So, this will affect the amount, and it will not amount to the full $0.30.

Okay, but not something for off '15?

It's close, yes.

Okay. I guess one of your competitors is in the process of connecting two of their NGL pipelines that would bring 50,000 barrels per day of propane from the Marcellus into the Midwest. Do you have any thoughts that you could share with us about what that level of supply could potentially use to the spread between Belvieu, Conway? Is that kind of supply going over along Conway or is that already enough excess capacity between Conway and Belvieu that it could easily go to Gulf Coast without any problems or does it just pretty prevent Conway from ever trading at a premium, again like it did last year? Any color would be helpful?

Christine what I would say is that obviously more volume into the Mid-Continent has nothing but improved spreads. We do think there is the ability to move some propane from Conway down to Mont Belvieu, especially if you displace out a product. So these are all back spot ones that you may move more propane than butane and more propane than the EP or ethane that you have. But we do think there is capacity to move incrementally more volume between the two. But I think it will normally have a widening effect on the spread and it will have a dampening effect on Conway ever trading over Belvieu, you are correct.

Okay. And then I guess last question from me. You guys have done a sizable amount of equity on the ATM year-to-date but like you said you are going to have to do more and because I think the market has somewhat of a wide range out there and what that number is, it kind of puts a bigger overhang on OKS. So that’s EBITDA you guys report is always different than what I calculate and I suspect it's because of the project credit that’s in there but how far does the credit rating agencies go in giving you that credit, is it year, 18 months, two years, any color on how they have used your balance sheet would be helpful?

Sure Christine, this is Derek. On an unadjusted basis, our debt-to-EBITDA is 5.1, while on an adjusted basis, it is 4.5, which you are correct about. The main difference is due to the material projects we have underway that receive some credit in our covenants. On a run rate basis, you might be looking at 1 or 2 basis points lower if you multiply the second quarter by four. I believe the credit rating agencies give us some credit for that, though I'm not exactly sure how much since they don’t share all their calculations with us. However, they do recognize that as we enter construction mode, we will be issuing equity and debt before we realize earnings from those projects. Therefore, I think there is some benefit for us in that aspect. Clearly, the agencies look ahead and consider the nature of those projects and the earnings they will generate as they assess our future leverage.

Thank you for the color.

You bet.

You bet. Thanks Christine.

Hey good morning Terry.

Hey good morning Chris.

Thanks for the added color this morning also thanks to Walt and T. D. for the slide presentation and the added disclosure, it's very helpful to us. So I just want to say thanks.

You are quite welcome.

Couple of questions, I guess the follow on with where the screen going originally, the slide 4 where you have the volumetric data since the April update, clearly the Bakken NGL volumes are up materially from April end of July and you expected peak rates for the fourth quarter. You mentioned Terry the effects of reduced ethane rejection and interruptible volumes on 2Q and the guidance. But the wondering sort of those factors 2Q with an upside price for you on those fronts. So what are you seeing in the Bakken and I guess what gives you confidence with the forecast and could we see further upside from the products that you mentioned as we move into the back half?

Well Chris I mean we have increased confidence because our producers are performing and we continue to have lots of discussions to get a better understanding of where they are and what their plans are, and they are executing those plans and as we said they are continuing to improve their cost structure and improve their technology and really significantly outperformed even in the midst of slight rig reductions in some cases. So we've got good visibility into the quarter and that's the reason why we feel so confident about the volumes. That plays right into the natural gas liquids segment particularly as we produced more natural gas liquids out of the Rockies and we produced more natural gas liquids out of the Mid-Continent that benefits the NGL segment. So it's about visibility, it's about continued communication with these producers.

And so on the, I guess the downstream spec element, the Sheridan’s comments. Is there further upside on that element, what you saw in Q2 and thus far in 3Q? Or are we fairly comfortable with their specs look like given base level and production volumes on is different?

Well, one thing I would say is that in 2Q we discovered that we stated the ethane recovery or decreased ethane rejection in June, so you would have a full three months in the third quarter and full three months in the fourth quarter. So we think the level of ethane, or close to the level of ethane that we were extracting today, is enough to bring these products into the spec and we can handle and get into the end use market.

Sticking with that slide, slide number four, for a moment, it seems like the steepest projected ramp in July volumes to year end is on the West Texas system. So I just had a couple of questions there. First, what is driving the ramp? Two, it looks also like the blended tariff rate on the system maybe came up a penny from the April update. I'm wondering if that was due to any recontracting if I am over-reading or reading too much and it’s something like there is something else going on. And then three, Terry you had mentioned when you bought that asset the potential to fractionate barrels coming off gathering Permian volumes. So just wondering when we might expect to see the approach of that effort or if you could give us something on it?

The first thing I’d say is July is down a little bit, the 2 15 is down a little bit from the fact that we had some outages on the system that caused the volume to be down. Also the reason the $0.04 we’ve gone from $0.03 to $0.04 just because we have increased the tariff rates on the pipeline closer to market than from what it was. So you’re seeing an increase in rates on the existing volume there. We continue to think that we’ll have ramp up there as we talk to more producers out there and we think there is opportunity for that to grow. As you point out that the West Texas pipeline has the lowest margin on our system, so it doesn’t have the biggest impact.

And then on the fractionation side of it longer-term, just give an update on where we stand.

We continue to talk to producers and processors out in the Permian who are looking for a bundled service, not just transportation to fractionation and delivery into the end-use market. So as we stated when we bought this pipeline, we think the ability to bring that bundled service to customers of the West Texas pipeline greatly enhance our ability to bring product to the line. And so we are in negotiations with various people on the line to be able to do that.

Sheridan, anything to talk about?

No, I didn’t have anything to add, Chris.

I guess one final thing on the asset side, it looks like the Stateline de-ethanizer was moved out a little bit. Given the comments around reduced ethane rejection, I'm just wondering what drove that and any that that movement in time would have on cost or return.

The de-ethanizer was delayed due to design details and two main factors. First, while working with our contractor, some long lead time equipment arrived late, pushing the timeline back. Second, when we adjusted the dates for winter construction and evaluated our efficiency during winter project execution, this added some additional time. However, I don’t believe it will have a significant impact on our expectations for 2016.

One final thing for me, just, Derek, the 4.5 times debt to EBITDA leverage metric that you quoted, that is consistent with how we interpret the covenants on the credit facilities, is that right?

Yes, that’s correct. It is exactly the way that we file with our banks for covenant compliance.

Okay, perfect. Thanks a lot for the added color today, guys, and congrats on a great quarter.

You bet. Thanks Chris.

Can you elaborate on your leverage levels? I remember you mentioned this in response to previous questions, but I would like to know more about what your expectations are in terms of the rating agencies' requirements for maintaining an investment-grade rating at year-end. How does this impact the use of the ATM or possibly a block, especially considering the current trading levels of different currencies?

The agencies I think have put out some guidance for us in their most recent updates. I think Moody's talks about a 4.5 times and S&P talks about 4.25 to be in those ranges. So certainly we think about that as we consider our equity needs during the year. We’ve said many times the ATM has been a good tool for us and certainly would expect to continue to use that in the future. But again, we have to kind of balance the balance sheet needs, the leverage with the issuing equity at a higher yield certainly than we would like to see. And of course as to additional you pay distributions on those units and so that impacts your coverage. So it's a balance and certainly we have regular communications with the agencies and let them know what our plans are.

And then bigger picture, I know we often talk about the desire to move more from POP to fee-based and to kind to get the business and at some in time you said you guys have sustained like the one-time coverage just off fee-based. I know you mentioned, again say in the press release but can we talk about progress that's been made there and time frame to that actually occurring in your mind?

I want to make a general comment. Everything is progressing well. Producers are actively engaging with us, and we have achieved some success with contracts. We are moving towards a fee-based structure rather than continuing with the pay-on-performance model. This shift is allowing us to increase the fee-based component while reducing the part tied to commodity prices, and it's going smoothly. Producers are looking for additional services and features in their contracts with us, and we are collaborating with them on those requests. When considering the regions we operate in, especially the Williston Basin, we are not dealing with a large number of contracts, just a few key producers. Therefore, we anticipate achieving more success as we move forward and expect to see results relatively soon.

And so when we think about that, is it like a '16, '17, '18, how just roughly frame enough maybe?

Yes, it's going to be more of 2016 benefit to us.

Perfect. Thanks guys. That was it from me today.

You bet. Thank you.

Good morning and congratulations.

Thanks Craig.

So when you were discussing the 2016 benefit and some of the shift to more fee-based from POP processing and contracting, does that imply that the majority, if not all, of the distribution could be covered by fee-based by then, or is that a longer-term outlook?

That would be a longer term proposition for us. I think it's a practical goal, and it makes more sense than trying to target a percentage of fee and commodity exposure, but it is definitely a longer term goal.

Okay. And Derek expressed the balance between topping ATM and keeping in mind the practical yields these units are trading at in the public market. Even with today's gains I think we are at stair step of lower price point than what you got on the ATM issuances in the second quarter. Is there a point at which you are just not interested in public issuances and at which without considering major structural changes that the OKE free cash flow and balance sheet strength could be used to bridge funding needs for few quarters?

Yes, Craig, this is Derek. That's a good point. OKE has additional cash on its balance sheet and has the ability to raise capital at more attractive yields now. It's important to consider the underlying assets of the Partnership and the types of projects we have; even at these higher yields, those projects still make sense. We often think about this, and we could also look into other types of securities besides just a common unit. OKE might consider participating in some way to address that need as well.

And Terry, as we think about bottlenecks in infrastructure in terms of actually filling out the Bakken Express Pipeline, I know that right now at the $45 oil that's not what people are thinking about. But thinking overtime, filling up that pipeline at $0.30 plus pricing that’s bundled pricing including all downstream infrastructure. Is the bottleneck there fractionation that would need to be added and how we should think about how much more fractionation is needed to fill up that pipe in terms of the full issue of ethane rejection?

Well Craig it's a combination of both pipe and fractionation capacity. We are certainly not anywhere near to that point yet but if you think about it very broadly and longer term, if we need to get to that kind of next stair step level of production assuming the prices stabilize and rebound, when we think about expanding that whole infrastructure it's got to be pipes, it's a combination of lubs, it's pumps and it's fractionation capacity you got potentially in the Mid-Continent and Gulf Coast. So you have to think about it broadly, I wouldn’t characterize it as just one particular component.

Can you provide an estimate regarding the billions of dollars of infrastructure we are discussing?

What I would mention, Craig, is that fracs are not limited to a specific basin. Our system allows us to adjust the movement of Y grade. If we increase our volume from the Bakken, we may need to add more fracs. As we observe a rise in volume from the Scoop, Stack, and other areas, that increase can fill our current frac capacity. However, we believe we currently have sufficient frac capacity for the volume coming from the Bakken, even as it grows with C3 plus rejected volume. We also see significant potential in Central Oklahoma with the Stack and ongoing developments in the Scoop, and we anticipate building more fracs in the future.

On a separate note, I was a bit surprised the optimization margins weren't more robust in the quarter, because propane spreads actually got pretty decent even though ethane was pretty anemic still. Can you update us on your ability to capture specific propane differentials even amidst the anemic ethane margins?

The key aspect to consider is the propane differential during the second quarter. If you're looking at the LONESTAR facility, which experienced the highest spread, there are limitations on access to that facility. Much of what we captured was between Conway and the non-TET or enterprise mark, which was down a few cents per gallon. On the propane side, we are continuing to convert much of our optimization capacity to fee-based arrangements. This transition reduces our ability to achieve wider margins on the volume we ship there since we need to ship increasing amounts for our third-party customers who have access to Belvieu.

And just one more, the Bakken gathered NGL volumes are only forecast to rise 5% from July to the fourth quarter. But gathered volumes are guided to rise 14% from 2Q to 4Q. Can you elaborate on that?

The reason that gathered volumes are continuing to go up, it is definitely a growth out of our Bakken, but we also see growth coming out of the Mid-Continent as we continue to go forward on that. So I think that may be where you are seeing some of that growth happen.

I apologize, the first figure pertained to the NGL volumes, and the second referred to the gas gathered volumes from Bakken.

Okay.

Craig, this is Kevin. On the gathered volumes when you look at the information we provided in the quarter, that is not necessarily a quarterly average that’s saying we will reach that capacity at some point. So, if you just do that math, that’s not saying that there is a, what your number was that’s the average growth, quarter-over-quarter, that just taking look at kind of a peak volume in the third quarter and a peak volume in the fourth quarter.

So the numbers are a bit apples and oranges. That helps. Thank you very much.

This is Chris speaking on behalf of Jeremy. I appreciate the additional details in the slide presentation. Regarding the volume outlook for the latter half of 2015, you mentioned that captured flare gas is a significant factor, and there's an inventory of approximately 145 million cubic feet per day in ONEOK's dedicated area. We were curious whether this would be more focused on the second half of 2015 or how much of it would extend into 2016.

Well, yes, there is a considerable amount in the second half, but it certainly gives you considerable momentum going into 2016. So, it is going to carry you well into 2016 along with the newly completed wells and the backlog of uncompleted wells. So it is all kind of working together. Kevin, you got anything to add to that?

No, I would just share one statistic that I think is very interesting to highlight the improved performance. From January to May, oil production increased by around 10,000 barrels a day. In contrast, gas production was mostly flat with maybe a 1% increase, but it actually rose by about 150 million cubic feet a day during the same period. This shows that while oil production stayed steady, the improved gas-to-oil ratios have driven gas volumes to continue increasing.

Thanks, that's helpful. I guess moving to West Texas LPG, your JV partner there noted some pretty big expectations in terms of increased pipeline distributions. And so we’re wondering, relative to your plans with that at the time of the acquisition, how are things trending? And with the recent tariff developments and your expectations for I guess returns going forward?

Everything is going very well. With the tariff increases and the volume prospects we are developing, we have high expectations for the pipeline. It aligns perfectly with our existing infrastructure and places us in the prime basin we have aimed for, setting us up for continued growth. Financially, we expect significant improvements from these tariff increases, and as volumes keep rising, it will be a major contributor to the segment's profit.

So relative to your planned into time of the acquisition, would you say that's higher or?

I believe we are making steady progress toward the expectations we had at the time of the acquisition.

Thanks, it's helpful. And then I guess lastly from me. On the re-contracting front in terms of your percentage of proceed contracts. For 2016, would you expect any kind of lower returns from those contract negotiations or what kind of give and take do you have with producer customers in that regard? Anything there would be helpful?

Well the strategy is to enhance our returns and obviously these contracts have been affected by the lower commodity price environment and certainly at these price levels and the resulting margins it makes it difficult to realize an acceptable return. So we are not going to sacrifice return and as we continue to work with these producers and provide enhanced services and we have demonstrated that we have been able to put contracts together that make sense and get our returns to an acceptable level.

Thanks. Appreciate the color.

You bet.

Yes, good morning everybody and congrats on a nice quarter. Just coming back to the financing questions, you have indicated you are open to alternative approaches here. So I take it that you would also include things like subordinating yields, take units, perhaps even cash injections from OKE using OKE equity. Would that be fair?

Yes, that would be fair. We continue to evaluate all of those levers.

And then I am just curious on the projects that have been suspended Terry, kind of what's the thoughts behind those perhaps any color on when you think you would be able to bring those back into say execution mode?

No specific dates at this time, but we are continually evaluating the current market situation, which remains very volatile and uncertain. We will reactivate those projects when the market conditions are favorable and when there is demand from producers for that capacity. Currently, we are in a wait-and-see mode regarding the suspended projects.

Okay and then just any thoughts regarding your plans with all the recent increases in M&A activity?

Our plans will remain consistent. We will continue to focus on organic growth, but we are also open to strategic acquisitions, particularly those that align with our assets, like our West Texas pipeline in the Permian. We will actively seek out opportunities in M&A. However, we recognize that the dynamics of the M&A market are beyond our control. Our priority is to remain focused, manage risks effectively, and provide excellent service to our customers.

Okay. Great. That's it from me. Thanks.

Yes.

Hi, thanks, so two quick ones. Just one more question on the West Texas LPG pipeline. When you acquired the asset you laid out a plan to spend a significant amount of capital over the next few years and expand the capacity of the line, obviously you have executed on increasing rate already. Has anything changed there or is that still all kind of on plan?

Hi Michael this is Sheridan. Yes, we have been talking to quite a few producers out there that will backstop expansion. So we are progressing as planned on that and we are very hopeful hear pretty soon that we will be able to come out and announce expansion of the pipeline. So the Permian has still been resilient. We are still seeing growth and we are getting most people call on us about trying to get on this platform, as we still think with the assets that we have we can be extremely competitive versus the marketplace out there.

And then just I apologize if I missed this but could you quantify the reduction in ethane rejection you saw this quarter?

In the Bakken is about 20,000 barrels a day in June. So that's 20,000 barrels a day in June, so you can put over about 7,000 barrels a day on average for the quarter.

If this has already been asked, just let me know to go listen to or check the transcripts. Regarding the ethane rejection, why is it happening now? What has changed that requires us to add more ethane to support the spec?

Well, Becca, I think the short answer, and I will let Sheridan follow-up, but I think the short answer is just the volume growth, significant volume growth that we kind of broke over to a point where the NGL production has gotten so big to the point where now this issue emerging is something significant.

Yes, I would say you are exactly right. It is fundamentally that we’ve had end-use people call us and say that the propane is off spec and we need to clean it up.

So, it is just you reached a tipping point?

Yes, that's right.

And then going forward, as you continue to produce volumes and you will have to produce more ethane in order to keep it in balance, is that correct?

It will be. We are working on a long-term plan that we can clean this up at our fractionators so that we do not have to continue to extract this ethane. But that is going to take some time to construct and get in place. But we are working, our engineers are working on a long-term solution.

And the only thing I will add is that is not done for free.

So your shippers will have to pay for that?

Likely so.

I wanted to revisit the percentage of proceeds that are fee-based. Your fee-based rate increased to $0.39 from the mid-30s this quarter. Is this change connected to your efforts to focus more on fee-based revenue?

I think the short answer is yes.

And I guess as I was looking at it last night, is the strategy then to move towards more of a fee-based cut or a hybrid contract structure where maybe if commodity prices are low you get an extra fee payment? Because your equity volumes for NGLs and for residue gas actually ticked up a bit relative to the overall production levels. And I would have thought if that was moving towards fee-based that that would have been down or flat. So, I was just curious to whether this is more of a hybrid move or whether this is a pure conversion.

Eric, this is Kevin. It's a combination. We're focusing on transitioning to a more fee-based margin, and there are several ways to achieve this. One is by increasing fees and raising the POP percentages, among other strategies. Our objective, as Terry has previously mentioned, is to recognize that each of our customers is unique and requires different services. These varying services may necessitate distinct strategies to find the optimal mix. However, in all cases, this approach leads to a higher fee; it may not be a fee-based margin but doesn't necessarily imply a decrease in equity volume.

And, Kevin, the only thing I would add to that is that when you think about our business as a whole, we’re keenly focused on bringing new fee-based opportunities and fee-based projects to the table. And in Phil's business segment, as we mentioned in the remarks, the Roadrunner pipeline and its OWT expansion are important. And on the OWT expansion, in particular, is a good example of the additional projects that have spun off as a result of this Roadrunner project in establishing a conduit to those markets in Mexico. So we’ll be very focused and remain very focused on fee-based opportunities and that will help bring that fee-based percentage up as we go forward.

So is it fair to say then that that $0.39, at least, probably while commodity prices remain low, is probably fairly sticky at this point? And then perhaps as commodity prices recover maybe that falls back a little bit to where it should have been, but it doesn't matter because you have retained the upside in these contracts?

No, I don't think so, Eric. I think that as we continue to renegotiate that fee should go up. So, yes, I don't think that that rate is going to be driven much by or affected much by a move in commodity prices.

I have a couple of quick questions to clarify some of the numbers you provided on the last quarter's conference call, which I believe you repeated. I just want to confirm. There are approximately 900 drilled uncompleted wells in the Bakken right now, and I think you mentioned that around 50% of those are on your acreage. Is that still accurate?

That is correct, roughly 50%.

And I think you said last quarter that there were 50 rigs drilling on your acreage. I was curious; did you give a number for that today?

Yes, we did.

Okay, what was that? I'm sorry. I missed that.

We’re in the 40 range right now.

40 range….

Yes, and again that moves up and down. But all of that has been in line with our expectations.

Okay.

The only thing I would add to that is keep in mind that these IP rates is the average initial production rates on these wells just continue to skyrocket. And I was just reading some materials the other day from some of our customers or some of our producers rather, and it's really remarkable the improvement that we are seeing. So even if you see rig reductions we are seeing these increased IP rates that are more than offsetting some of those reductions.

I think that's fair. In some cases, we've observed that it takes about 24 days to drill a well, but we've also heard that for some, it might have fallen to around 16 days. So, I would say that this is not as definitive as it once was.

Yes.

I also just wanted to ask real quick. Of the 900 drilling completed wells in the basin what you view is sort of being an equilibrium number for that? I mean there's always going to be some number of uncompleted wells and I was just curious overall for the basin what do you think is normal?

That's a tough one to answer. Especially as producers have shifted almost entirely to multi-well pads where they set a rig in one spot and drill several wells, there's an artificial working inventory of uncompleted wells. From discussions with others in North Dakota, there seems to be a consistent inventory in the range of 300 to 400 wells, which will likely remain as long as the rig count stays consistent. However, this number can fluctuate as rigs move around and depending on where and how they are drilling.

Okay. Well, thank you very much. That's all I had.

Thank you.

Hi. I just wanted to make sure I understood what you said at the beginning of the call properly that you had ample of liquidity particularly given how credit metrics are calculated by your borrowers that there is no need to issue okay equity at these FX valuations?

Well I don’t know that I have said that. We have been pretty clear that we expect to continue to issue equity as we balance our credit metrics with issuing at this price.

Okay. But you said you're going at least avoid the disruptive overnight offering given the ATM program?

Well I mean we talk about the overnight markets all the time and we certainly continue to look at that option. As we said many times the ATM program has worked pretty well for us. We were able to get quite a bit done in the second quarter, so to avoid that overnight market issue, but I can't rule that out for you.

Okay. Thank you.

Thank you. Our quiet period for the third quarter starts when we close our books early October and extensive earnings are released after the market closes on November 3rd, followed by our conference call on November 4. Thank you for joining us and have a good day.