歐尼克 (OKE) 2013 Q2 法說會逐字稿

Good day, everyone, and welcome everyone to the second-quarter 2013 ONEOK and ONEOK Partners earnings conference call. Today's conference is being recorded. At this time, I would like to turn things over to Mr. Andrew Ziola. Please go ahead, sir.

Thank you, and good morning, everyone. And welcome to ONEOK and ONEOK Partners' second-quarter 2013 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 provision 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 John Gibson, Chairman and CEO of ONEOK and ONEOK Partners. John?

Thank you, Andrew. Good morning, and thanks for joining us today. As always, we appreciate your continued interest and investment in ONEOK and ONEOK Partners. Joining me on the conference call today are Derek Reiners, our Chief Financial Officer; and Terry Spencer, our President. Also on the call and available to answer questions are Pierce Norton, our Executive Vice President of Commercial; and Robert Martinovich, our Executive Vice President of Operations.

On this morning's call, we will review our second-quarter 2013 financial results; update our point of view on the magnitude and duration of ethane rejection, and explain why it should have no impact on our 2013 or our three-year earnings expectations; review our progress on our growth projects; and, to avoid any further confusion, we will reiterate the ONEOK dividend growth we expect once the -- once we separate our natural gas distribution business.

Let's start with our second-quarter performance. ONEOK's second-quarter performance was solid after adjusting for the non-cash charge related to the wind-down of our energy services segment. We had a robust volume growth in ONEOK Partners with volume increases in natural gas gathered and processed and natural gas liquids gathered, all as a result of the growth projects we completed.

In ONEOK Partners, our NGL exchange services margins continued to increase compared with the same period in 2012, as we execute on our strategy to convert capacity held for optimization activities to fee-based contracts. As a result, and as expected, our optimization margins declined as a result of this reduced capacity. And the expected tighter NGL price differentials were experienced between Mont Belvieu and Conway. As anticipated, ethane rejection had some impact on our second-quarter results. However, it was less than $15 million. Our natural gas distribution segment performed exceptionally well during the quarter, benefiting from new rates in all three of the states it serves and from higher sales and transportation volumes related to the colder than normal weather.

As Terry will discuss in a moment, we are revising our outlook for ethane rejection during 2014 and 2015, based on recent developments in the NGO market. We expect that current levels of ethane rejection, which are less than we originally forecasted in February, will continue into 2014 and into 2015, but at lower levels. We remain confident that we will meet our 2013 guidance expectations and our three-year earnings growth expectations, averaging an annual 15% to 20% EBITDA increase during that period. Even with ethane rejection continuing through 2014 and 2015, due primarily to additional volumes now expected that were not originally included in our three-year plan.

Derek will now review ONEOK's financial highlights, followed by Terry, who will review ONEOK's operating performance.

Thanks, John, and good morning. ONEOK's second-quarter earnings were approximately $1 million, or $0.00 per diluted share, including the non-cash after-tax charge related to the accelerated wind-down of the energy services segment. ONEOK's net income in the second quarter would've been approximately $72 million, or $0.34 per diluted share, excluding the non-cash charge compared with $61 million, or $0.29 per diluted share, for the same period last year. Improved second-quarter results reflect volume growth as a result of completed the growth projects at ONEOK Partners in the ONEOK Partners segment. The natural gas distribution segment posted higher results due to increased rates in Oklahoma, Kansas, and Texas, and colder weather in the service area compared with the same period last year.

As we announced in June, ONEOK will discontinue the energy services segment through an accelerated wind-down process. Energy services released a significant portion of its nonaffiliated third-party natural gas transportation and storage contracts to third parties in June, effective July 1, 2013, and recorded $114 million pre-tax non-cash charge. We also expect about $40 million of additional charges later this year or in the first quarter of 2014, related to the remaining capacity that we intend to release. We expect future cash expenditures associated with the released transportation and storage capacity from the wind-down to total approximately $100 million on an after-tax basis; with approximately $15 million paid in 2013, $35 million in 2014, $25 million in 2015, and $25 million over the period of 2016 through 2023.

As John mentioned, ONEOK also affirmed its 2013 net income guidance range of $235 million to $285 million, updated for the energy services current and expected future after-tax charges related to the wind-down provided in June. ONEOK also affirmed its three-year expectations of net income increasing by an average of 15% to 20% annually, comparing 2012 results with 2015, and excluding the impact of ONEOK's recently announced plans to separate its natural gas distribution business into a new stand-alone publicly traded company to be called ONE Gas.

In July, we declared a dividend of $0.38 per share, an increase of 6% from the previous quarter. As a reminder, ONEOK's 2013 guidance includes a projected $0.005 per-unit, per-quarter increase in unitholder distributions declared from ONEOK Partners, subject to ONEOK Partners' Board approval. ONEOK Partners has estimated an average annual distribution increase of 8% to 12% between 2012 and 2015, subject to ONEOK Partners' Board approval. For the six months ended -- for the six months of 2013, ONEOK received approximately $263 million in distributions from ONEOK Partners, a 32% increase from the same period last year. ONEOK's year-to-date 2013 stand-alone cash flow before changes in working capital exceeded capital expenditures and dividend payments by $129 million. Additionally, the midpoint of ONEOK's 2013 guidance for cash flow before changes in working capital has been updated to $787 million to reflect the wind-down, compared with its previous guidance of $835 million. Cash flow before changes in working capital is expected to exceed capital expenditures and dividends by a range of $145 million to $185 million, compared with its previous guidance range of $195 million to $235 million provided in February 2013.

ONEOK's liquidity position remains strong. At the end of the second quarter on a stand-alone basis, we had $405 million of commercial paper outstanding, $27 million of cash and cash equivalents, and $793 million available under our $1.2 billion revolving credit facility. Our stand-alone long-term debt to capital ratio was 45%.

Now Terry will update you on ONEOK's operating performance.

Thank you, Derek, and good morning. Let's start with our natural gas distribution segment. As you read in the news release, second-quarter 2013 earnings were higher, primarily reflecting higher rates in Oklahoma, Kansas, and Texas, and colder than normal weather in the second quarter 2013, compared with warmer than normal weather during the same period last year. Operating costs were slightly higher, compared with the second quarter 2012, primarily because of higher pension expenses and property taxes, which were mostly offset by lower share-based compensation expenses. The midpoint for the natural gas distribution segments operating income guidance for 2013 remains at $227 million. As Derek discussed, the energy services segment incurred a non-cash charge related to the released capacity in the second quarter. Excluding that charge, net margin decreased by approximately $14 million in the energy services segment, compared with the same period last year, primarily due to lower realized seasonal storage differentials and marketing margins net of hedging activities.

2013 guidance for the energy services segment is a loss of $210 million. That reflects the non-cash charges related to the accelerated wind-down unchanged from what we said in June.

John, that concludes my remarks for ONEOK.

Thank you, Terry. Now Derek will review ONEOK Partners' financial performance. And then Terry will come back and review the partnership's operating performance, growth projects, and discuss in a little more detail the reasoning behind the revised ethane rejection outlook.

Thanks, John. In the second quarter, ONEOK Partners' net income was $202 million, or $0.62 per unit, compared with $207 million, or $0.69 per unit, in the second quarter of 2012. Distributable cash flow was $252 million in the quarter, compared with $240 million in the second quarter of 2012, resulting in a coverage ratio of 1.17 times for the second quarter of 2013. By comparison, our coverage ratio was 1.29 times in the second quarter of 2012. Distributable cash flow was $445 million for the first six months of 2013, providing a 0.99 times coverage, compared with $519 million for the same period last year, providing coverage of 1.50 times. Our long-term annual coverage ratio target still remains at 1.05 to 1.15 times. However, as we've discussed in previous conference calls, we expect our full-year 2013 to be slightly above one times coverage.

ONEOK Partners affirmed its 2013 net income guidance range of $790 million announced in February of 2013. The partnership's DCF is expected to remain in the range of $910 million to $1 billion.

Operating income in the natural gas liquids segment is expected to increase, while operating income in the natural gas gathering and processing segment is expected to decrease from previous earnings guidance. Terry will give the specifics in a moment.

We affirmed EBITDA to increase by an average of 15% to 20% annually over a three-year period, comparing 2012 results with 2015. ONEOK Partners also affirmed that it still estimates an average annual distribution increase of 8% to 12% between 2012 and 2015, subject to ONEOK Partners' Board approval. Capital expenditures for 2013 are expected to be approximately $2.36 billion, comprised of $2.24 billion in growth capital and $120 million in maintenance capital. This update reflects the timing of capital dollars and the movement of some capital expenditures to 2014 from 2013. However, our growth projects continue to be on time and on budget. We still expect a $4.7 billion to $5.2 billion capital spend through 2015, in addition to having a $2 billion to $3 billion backlog of unannounced growth projects.

We increased the distribution declared by $0.005 per unit for the second quarter of 2013, an increase of 9% from the second quarter of 2012. Subject to Board approval, we expect to increase our distributions by $0.005 per unit per quarter for the remainder of 2013.

In the earnings release, you will note some updates in our hedging information as we continue to hedge commodity risk where appropriate. At the end of the second quarter, the partnership had $6 million in cash and cash equivalents, $429 million of commercial paper, and $771 million available under our $1.2 billion revolving credit facility. Our long-term debt-to-capitalization ratio was 52%, and our debt-to-adjusted-EBITDA ratio was 3.6 times.

From a financing perspective, we continue to have multiple sources of liquidity available to us, and we remain confident in our ability to raise the necessary capital to fund the growth at ONEOK Partners, which include access to our $1.2 billion credit facility with the option to increase -- to request an increase to $1.7 billion and access to our $300 million after-market program that allows the partnership to offer common units for the sale -- for sale in the market. These items enable us to be opportunistic from a timing perspective as we look to access public equity and debt markets.

And finally, I'd like to comment briefly on Standard & Poor's recent decision to affirm ONEOK Partners' credit rating but revise its outlook to negative due to its expectation that weak commodity prices, particularly natural gas liquids prices, could weigh on the Partners' -- on ONEOK Partners' credit profile in 2014. We remain committed to our investment-grade credit rating and will continue to take the necessary steps to remain investment-grade. Now, Terry will update you on the partnership's operating performance.

Thanks, Derek. The natural gas gathering and processing segments' second-quarter operating income was almost 20% higher, due primarily to higher natural gas volumes gathered and processed, offset partially by lower realized NGL prices and higher compression and operating costs due to the growth projects we placed in service over the last year. Natural gas volumes gathered and processed continue to grow, driven by increased well connections in the Williston Basin and western Oklahoma.

For the second quarter, natural gas lines gathered increased 23%, and natural gas volumes processed increased 28%, compared with the same period last year, driven by the new Garden Creek and Stateline I and II natural gas processing plants and related infrastructure projects completed in 2012 and in 2013. The second-quarter throughput was lower than expected, due to wet weather conditions that temporarily delayed gathering system construction and producers' well completion efforts. Despite those challenges, we still connected 350 wells in the quarter and 600 year to date, compared with 450 wells last year through June. While we expect to connect more than 1000 wells to our Williston Basin and the mid-continent gathering systems in 2013, we reduced this segment's 2013 operating income guidance to $209 million, reflecting lower natural gas volumes gathered and processed experienced in the second quarter of 2013, compared with previous estimates. Specific volume expectations and updated 2013 price assumptions are provided in our earnings release.

The natural gas pipeline segment second-quarter financial results were slightly lower, compared with the same period in 2012. Equity earnings from Northern Border Pipeline were lower in the second quarter, due to reduced transportation rates on Northern Border Pipeline due to a rate settlement with its shippers that took effect in January, offset partially by higher transportation volumes. Substantially, all of Northern Border Pipeline's long-haul transportation capacity has now been contracted through March 2015. 2013 operating income guidance for the natural gas pipeline segment has been updated to $149 million, compared with the previous midpoint of $153 million, reflecting weaker than expected electric power demand, due to milder weather in 2013 compared with 2012. Offsetting this decrease are higher expected equity earnings.

Our natural gas liquids segment second-quarter results were only 4% lower, despite significantly narrower Conway-to-Mont Belvieu NGL price differentials and the impact of ethane rejection. As expected, NGL exchange services margins continued to grow, while NGL optimization margins decreased, compared with the same period last year as a result of ONEOK Partners' strategy to convert NGL optimization capacity to fee-based exchange services capacity. To put this narrow NGL location price differential impact into perspective, the second-quarter 2013 Conway-to-Mont Belvieu ethane price differential was $0.06 per gallon, down 74%, compared with $0.23 per gallon in the second quarter of 2012 and $0.01 per gallon in the first quarter 2013.

From a volume perspective, NGLs transported on gathering lines were 554,000 barrels per day in the second quarter of 2013, up 6% compared with the same period last year and up 11% compared with the first quarter 2013. These volume increases were due primarily to the completed Bakken NGL Pipeline, volume ramp-ups from third-party plant connections or expansions, and capacity increases made available through the partnership's Cana-Woodford Shale and Granite Wash system expansions that were placed in service in April 2012. Partially offsetting these volume increases was the impact of ethane rejection.

We increased our 2013 operating income guidance for the NGL segment to $575 million compared with the previous guidance of $545 million. This updated 2013 guidance reflects additional capacity available for optimization activities as a result of ethane rejection, more favorable NGL and product differentials, higher expected isomerization margins, and new revenue growth from commercial activities. Ethane rejection did result in NGL pipeline capacity typically utilized for exchange services business becoming available for optimization activities, allowing us the ability to benefit from the NGL price differentials between the midcontinent and Gulf Coast market centers. Offsetting this increase are lower-than-expected earnings from Overland Pass Pipeline due mainly to ethane rejection. In our 2013 financial guidance, we have assumed the ethane and EP differentials between Conway and Mont Belvieu will average $0.06 per gallon for the second half of 2013.

Specific NGL gathering and fractionation volume expectations are provided in our earnings release. The lower NGL volume forecasts for 2013 are primarily the result of lower-than-expected volume increases from third-party natural gas processes during the first half of 2013, and projected ethane rejection at many natural gas processing plants connected to the partnership's NGL system for the remainder of 2013. The financial impact of these volumes decreases -- is mitigated by minimum volume operations and the ability to utilize the available transportation capacity for optimization activities.

Now an update on our projects. We have a couple of significant projects expected to be completed this year. The MB-2 NGL fractionator at Mont Belvieu is progressing very well and is expected to be completed in the third quarter. And the Sterling III pipeline is expected to be completed by the end of 2013 with the flexibility to transport either unfractionated NGLs or NGL purity products from the midcontinent region to the Texas Gulf Coast.

Now to commodity prices. We have decreased our second-half 2013 equity NGL composite price assumption for the natural gas gathering and processing segment to $0.62 per gallon. Our 2013 equity NGL composite price is weighted more to Conway due to contractual commitments. To be clear, this price is at the market hubs before transportation and fractionation fee deduction. The $0.62 per gallon is calculated on a full ethane recovery basis. By comparison, with reduced ethane recovery in 2013, our realized NGL composite prices are expected to be $0.84 per gallon.

Our three-year commodity price outlook has been revised downward to reflect the latest point of view of the commodity markets. I'm going to provide these price assumptions to you by commodity, by year for the full year 2013, 2014, and 2015.

Okay, here we go. Mont Belvieu ethane prices are assumed to be an average of $0.25 per gallon for 2013, $0.33 per gallon for 2014, and $0.40 per gallon for 2015. Mont Belvieu propane is assumed to average $0.91 for 2013, $1.05 for 2014, and $1.18 per gallon for 2015. Nymex natural gas prices are assumed at $3.60 for 2013, $4.25 for 2014, and $4.60 per MMBtu for 2015. NYMEX crude oil prices are assumed at $98 for 2013, $94 for 2014, and $96 per barrel for 2015. The composite equity NGL prices, assuming ethane rejection, are $0.84 for the full-year 2013, $1.04 for 2014, and $1.14 per gallon for 2015. The 2014 and 2015 NGL composite prices are primarily on a Mont Belvieu basis.

The assumed ethane NDP price differential between Conway and Mont Belvieu is approximately $0.10 per gallon for 2014 and 2015. This updated pricing will also be available on a future investor presentation.

The change to Mont Belvieu pricing in 2014 and 2015 reflects the expected completion of our Sterling III pipeline in late 2013, providing our customers with more access to the Mont Belvieu market.

Now let's discuss the impact of ethane rejection in 2013, 2014, and 2015 earnings expectations. We are revising our outlook for ethane rejection during 2014 and 2015 based on some recent developments in the NGL markets that I'll discuss in a moment. We believe that ethane rejection by natural gas processing plants connected to our NGL system will continue at current levels throughout much of 2014, and through 2015 but primarily in the Rockies. However, in spite of the continued ethane rejection affecting the partnership, we remain confident that we can still increase EBITDA by an average of 15% to 20% annually over a three-year period. New commercial opportunities, new supply projects, and increased optimization capacity made available due to ethane rejection -- all made possible because of our integrated NGL system -- are expected to offset the impact of ethane rejection in 2014 and 2015.

Here's the current situation. Natural gas processing plants, our own and third parties, that supply our natural gas liquids assets excluding the Williston Basin are currently rejecting between 55,000 and 65,000 barrels per day of ethane. As we communicated in previous conference calls, we currently are rejecting ethane in the Williston Basin, which is consistent with our expectations. These current levels of ethane rejection are significantly lower than the 90,000 barrels per day, excluding the Williston, we experienced earlier this year and previously expected for all of 2013. This reduced ethane rejection has occurred because natural gas processors in the midcontinent and Rockies, excluding the Williston Basin, that were previously rejecting ethane began to experience less propane recovery, which caused them to begin recovering ethane so they could increase their recovery of propane.

Here's what we expect in 2014 and 2015. In 2014, we expect that ethane rejection levels from existing midcontinent and Rockies plants outside the Williston Basin will continue in the range of 55,000 to 60,000 barrels per day. We do not expect to recover ethane from our Williston Basin plants in 2014 and 2015 as originally planned, which will reduce our planned throughput on the Bakken NGL Pipeline by approximately 30,000 barrels per day in 2014 and by approximately 40,000 barrels per day in 2015. We expect Rockies plants outside the Williston Basin supplying our systems to reject 10,000 to 15,000 barrels per day of ethane in 2015. As a result, we expect to reject about 90,000 barrels per day of ethane in total during 2014 and about 50,000 to 55,000 barrels per day of ethane in total during 2015. We estimate the financial impact of this level of ethane rejection in 2014 to be approximately $83 million in operating income after deducting ship-or-pay offsets.

The recent developments in the marketplace resulting in our revision of the 2014 and 2015 ethane rejection outlook include higher inventories that persist for longer period of time. Recent industry forecasts indicate that historically high ethane inventories will likely persist for a much longer period than originally expected due to the extended petrochemical turnaround season, and several major unplanned outages including the unfortunate incident at Williams' Geismar, Louisiana, petrochemical facility. Which not only curtailed the consumption of ethane for an indefinite period of time but also postponed a planned capacity expansion that was scheduled to come online later this year.

Spot purchases of ethane are down. For the first time this year, a number of our petrochemical customers reduced their purchases of ethane on the spot market in favor of drawing down inventories from their proprietary ethane storage. Proprietary ethane storage figures are typically not reported to the EIA. Non-ethane feedstocks are improving co-product yields. Petrochemical customers are consuming more normal butane as a feedstock instead of switching from propane feed to ethane feed due to better co-product yield.

And Mont Belvieu pricing has weakened. Mont Belvieu ethane and propane prices have not maintained the strong pricing trajectory experienced mid-spring of this year, as inventory overhangs and propane exports have not yet been sufficient to cause a substantial switching by the petchems to ethane feed from propane feed. However, as I stated earlier, new commercial opportunities, new supply projects, and increased optimization capacity made available due to ethane rejection are expected to offset the expected impact of ethane rejection during 2014 and 2015. While we recognize the continued near-term challenges facing ethane producers, the partnership remains well-positioned through its integrated network of assets in NGL-rich basins to provide essential services to its customers for the long-term.

John, that concludes my remarks.

Thank you, Terry. Appreciate that. It was very good.

Before we take your questions about the quarter, I'd like to take this time to reiterate our expectations regarding the dividend growth ONEOK anticipates following the completion of its plan to separate the natural gas distribution business. What we stated in last week's news release on page 3, and in the slides on page 9 provided in advance of the conference call, is correct. In all the toing-and-froing during the Q&A portion of the conference call, there appears to have been some confusion about what our intent is. So let me reiterate our post-separation dividend growth expectations so that there is no additional misunderstanding.

When the separation is complete, post-spin, ONEOK intends to increase its dividend to a level competitive with its pure-play GP peers. That means the dividend growth rate is expected to be greater than the current pre-spend three-year dividend growth rate ONEOK estimates, which is 55% to 65% during the 2012 to 2015 period. This post-spin ONEOK dividend growth expectation excludes the dividend that ONE Gas would pay its shareholders, which we expect would also be competitive with its natural gas utility peers.

Said another way, ONEOK dividend growth, post-spin, is exclusive of the ONE Gas dividend. The ONEOK dividend growth expectation, post-spin, comes entirely from ONEOK. As usual, in closing, I'd like to again thank our 5000 employees whose commitment, dedication, skills, and experience allow us to operate our assets safely, reliably, and environmentally responsibly every day; and to create exceptional value for our investors and our customers.

With our announcement last week, all of our employees are facing change. But the approximately 600 employees in our shared service organizations are forced -- facing more changes and uncertainty because they do not know if they will remain with ONEOK or move to ONE Gas. Removing that uncertainty is a high priority for my leadership team during the next 60 to 90 days. Our entire management team appreciates all of our employees' efforts to make our Company successful.

Operator, we're now ready for your questions.

(operator instructions). Christine Cho, Barclays.

Nice quarter. If I do some quick back-of-the-envelope math, it seems that your optimization margin was much higher than what some of us were probably expecting and better than what we've seen in the past two quarters. Would it be fair to say that year to date you guys are tracking higher than what you would have expected? And how much of your increase in guidance for the NGL segment reflects what you've already generated in the past two quarters versus what you hope to see in the next two quarters?

Terry?

Yes. Well actually, the impact from ethane from optimization -- the revenue impact for 2013 is approximately -- let me make sure I get your question right. Christine, could you say the first part of your question again?

You know, it seems that your optimization margin for this quarter was much higher than what some of us were probably expecting and better than what we've seen in the past two quarters. So would it be fair to say that year to date you guys are tracking higher than what you would've expected six months ago? And how much of your increase in guidance for the NGL segment reflects what you've, call it, already have in the bag versus what you hope to generate in the next two quarters?

The answer -- yes, it is tracking higher. Terry, is there anything you'd want to add?

The thing I'd add though, Christine, you can see that we averaged $0.01 on the spread in the first quarter and $0.06 in the second quarter, averaging $0.04 for the first half. We do expect that to be higher in the second half as well as the optimization of volumes to be higher as well. So it is a little more back-end weighted.

I see. Okay, that answers it. And then when ethane spreads were very wide last year and the year before, most of your optimization capacity was used for ethane. For talking purposes, let's say it was 100,000 barrels per day for all ethane. If we were to instead use all propane or all of butane, am I correct in thinking that this number moves lower because the other liquids are heavier and they take longer to move?

No, I don't think so.

Okay. And then, just my last question, it sounds like with the export projects and propane inventories being relatively low, we might see some strength in propane prices, especially if we get a normal winter. I'm assuming this dynamic is what's driving your lower expectation for ethane rejection if the older plants are losing their propane recoveries with the ethane rejection?

Yes, I think that's right.

Okay. Thank you.

Carl Kirst, BMO Capital.

Also, nice quarter. Maybe just cueing off of Christine's question and perhaps asked another way. On the NGL guidance, if you think about it from a full year, the segment guidance is going up $30 million. Is it possible to segregate since we have this situation where the fractionation of the transport volumes are being reduced lower but have some protection by some shipper pay? Is it possible to segregate what the negative impact of the reduced volumes -- what that impact is versus the uplift from the optimization that gives this net $30 million uplift?

Carl, there is actually kind of more to it than that. You are hitting on the optimization piece. You hit on the minimum volume requirement piece. There's three other factors here that really play into this that aren't volume related. The first one is, we have more isomer volumes available to us to process through our isomerization unit. We have higher spreads on that volume as well. The next piece is, we are experiencing more commercial marketing opportunities because of assets that have been freed up by putting the Bakken line into service. For instance, we've got more truck and rail activity that used to be dedicated to the Bakken barrels. Now we're getting third-party business through that, and then we also have the propane export opportunities. And the final thing is, there are incremental volumes that are actually coming on, but they are not enough to offset the reduction in some of the gathered volumes. So all that combination of things with the optimization volumes, the minimum volume preps, is actually making up that $30 million.

Great. Appreciate the extra color. And then just a second question on the gathering and processing. You know, it looks like with the guidance reduction that's going on there for that particular segment, we may have -- on the gathered process, perhaps volume is being down 2% to 4% relative to prior guidance, maybe a little bit more so on the implied equity production. But I guess my question is, it sounds like that's all timing related with respect to well connects in the second quarter. Is that something where you feel like by the end of the year you will have caught up to your prior expectations? Meaning, even though we haven't seen granular guidance for 2014; and sort of what you guys are looking at, you're not really expecting much of a change from the volume? Or does this push out the entire curve, where we might expect lower volumes both in 2014 and 2015 because we've been backed up by a quarter, if that makes sense?

It makes good sense. It just backs the curve out.

It just slides the curve.

Excellent. Thanks guys.

Ted Durbin, Goldman Sachs.

I guess my first question here is on the exchange service activities. And I'm assuming there is sort of a layer of contracts you signed here on the minimum volume. So I'm wondering what the vintage of those is and how we should think about the change in the contract pricing. You've signed up for the shippers on there. I'm assuming as the spreads here, between say Conway and Belvieu, have come in, you've probably signed those contracts up at higher rates that maybe roll forward. But maybe I'm thinking about that wrong.

You're thinking about it right. We're just not going to be willing to tell you the specifics; I mean for competitive reasons, right?

Okay. That's fair. And then second one for me was just, you kind of [worry] on hedging for NGLs. It looks like you're still leaving 2014 fairly open. Is that just because you don't like the price? You kind of walked through your ethane price and propane price forecasts. Is that kind of the big driver there of where the hedges are?

I think that's right, Ted. When you look at ethane and you look in the out months from a hedging standpoint, you have to take a pretty significant haircut in pricing. And what we've tended to do over time, as it -- particularly as it related to ethane prices, generally moved back toward us. So we're just going to continue to look, and look for the opportunities to hedge more ethane as we go into the future.

Got it, that's great. Then last one for me, just on the balance sheet at OKS. I think I heard you say it was -- you're 3.6 times on debt to EBITDA. I just want to make sure is that on a trailing 12 months? I'm coming to a higher number. I'm just kind of thinking about where you are in your credit metrics and then how you're thinking about financing the CapEx for those -- kind of where you are.

Derek?

Yes. That's correct, although the 3.6 is adjusted for some EBITDA on our capital projects that we get credit for in our covenants.

Got it. So you're getting some forward EBITDA, I guess, credit for things that are coming on?

That's correct.

We are allowed to do that by our agreement.

Yes. And then how are you thinking about sort of financing the CapEx for the next 6 to 12 months, let's say?

Well, I think -- you know, as we've said before, we do have equity and debt needs. And the timing of that, we'll just have to determine based on the market conditions.

Okay. That's it for me. Thanks.

John Tysseland, Citi.

Hi guys. Thanks for the call. Can you just describe the mechanics and maybe provide an example of your exchange services operations? And then kind of what the difference is of that versus maybe optimization? And then also where geographically you see the most opportunities in today's kind of market? Is that -- in that business is it Bakken or midcontinent?

Well, first off, when we look at discussing same services, that's all fee-based. That's all fee-based business, okay? Transportation, frac services for a fee, gathering, fractionation. If we look at optimization, of course that's spread. The Conway-to-Belvieu pricing differentials for ethane is what we talk about. The other part of your question is where do we see the opportunities? And we continue to see a lot of opportunities in the NGL-rich plays within our footprint. The Bakken, of course, continues to yield a lot of opportunity. The Niobrara down in the Powder River Basin is yielding some opportunity for us. The Mississippian Lime down in Oklahoma and the Cana-Woodford play are all plays that are still very active, and new processing plants are being developed.

That's helpful. Can you just help describe the mechanics of how that contract with customers actually works in the exchange services business? I mean, what does the producer -- what is the contract with the producer or the downstream customer really have with ONEOK?

Basically, how the exchange services contract works -- as I said before, it's a fee-based contract. We take the barrels and exchange raw feed for purity products at the market hub. So -- and we do that for a fee. So that in a nutshell, how it works. The transportation or gathering and fractionation fees are typically bundled, okay? So you get all that for a flat fee. So, that's basically how it works.

So to put numbers to it, just using one commodity, we take the wide grade, we take the raw, right? We take title to it, say, in the Bakken. And then we provide a price, and then we charge the producer based on the finished product at the market hub, like Terry said, less a fee.

Got it. That's very helpful.

So in other words, we do the gathering. We do the -- all the transportation. We do the fractionation. We distribute the products to the market hubs. And then give them, in essence, market price, less a fee, for doing all of that. All those fees, we don't -- we've got one fee. So that's why we call it a fee-based business.

That makes a lot of sense. I appreciate the clarification. And then final follow-up on that same kind of line of questioning. When the Bakken pipeline actually came online, is it fair to say that your exchange services business and opportunities there expanded pretty greatly during the quarter?

That would be right.

Thank you.

Craig Shere, Tuohy Brothers.

Congratulations on a good quarter. Look forward to seeing you guys next week. And thank you, and congratulations again, John, to you and the team, Terry, and everybody on -- well just all the what's built-up the last few years that led to the market movement when you decided to separate the business.

Thank you.

Just a couple of follow-up questions on the optimization. It seems like the ability to have some optimization fill in for lost capacity utilization amidst ethane rejection is suggesting that there is a lot more opportunity other than the historical Conway-to-Belvieu ethane spreads. And I think, on Christine's questioning, the answer was that this year's optimization, even though there were some pretty healthy results this quarter, were more back-end loaded towards the second half. Could you comment about the various opportunities for optimization and sustainability of that into 2014 and beyond, as I think rejection continues, albeit at a lower rate?

You know, Craig, we don't provide the specifics as far as volume for our optimization activities. But the opportunities for optimization expand across a number of products, not just ethane. Propane, normal butane, etcetera. So we optimize more than just ethane. We're going to continue to see a need for products in Mont Belvieu. We're going to continue to see growth in supply in midcontinent based on what we're seeing in terms of development in NGL rich plays. So I think the opportunities for optimization of the viable portion of our business are going to continue, although they are going to be a much smaller percentage of our margin versus what we had seen over the last couple of years. Does that help you?

Well, sure. You were knocking the lights out a year ago. But I think what we're seeing now is definitely better than the market was expecting, at least the financial markets.

One of the things I would add to that, knocking it out of the ballpark, is remember that the -- it's the optionality of the asset that allows us to capture the optimization margin, regardless of what the margin is. We don't create the margin. It's the ability to capture it, whether it's a penny or whether it's $0.40. It's the optionality embedded in those assets and our ability to bundle all those services together relative to our competitors. It gives us an advantage to participate in optimization. That's an important piece.

Understood. And that's a nice segueway for my follow-up. Obviously, over time the desire is to convert more and more towards fee-based exchange service activities. And I think you all had alluded in prior commentary to expectations that you could contract out multi-year agreements on Conway-to-Belvieu spreads, a capacity close to a dime. In light of some of your more recent commentary around the ethane markets, could you give any color as to the markets' appetite for multi-year agreements, fee-based, that you would be comfortable with? Or is that not available in the short run?

Well, our strategy has been to long-term contract that optimization capacity under fee-based exchange services. So as we look at the marketplace and our customers, they want that long-term capacity. In fact, that optimization spread or the Conway development spread have been very volatile and basically nonexistent in the first quarter. Has not phased our customers one bit. They still want that capacity. They want to contract for it long-term, and they are willing to pay an attractive rate -- a fair rate to do that.

Well, I guess, let me rephrase instead of specific pricing like a dime. We saw a nice uptick even toward $0.07 plus, until that unfortunate olefins plant accident. Then we gave back a penny or two. Do you see your customers looking past the near-term issues towards multi-year -- the desire, as you say, to lock in multi-year spreads at sustainable levels comfortably above what we're seeing now, which is more like a nickel?

You know, I don't -- here's just my opinion. These customers are not focused on the spread. What they're focused on is getting their barrels to where they think the best markets are. So they haven't really been fixated on the spreads, and they don't come back to us and say, well we think the spread is going to be X; as a result, we think your rate should be Y. They recognize the cost it takes to build infrastructure down to the Gulf Coast. They want to be in that liquid market because they believe that's the place to be. So that's where we are taking them. But we don't really get into that issue with the producers -- arguing over what the view of the spread is.

Is a part of it that you simply don't get in this argument because you provide so much bundled services, that's simply one part of the total?

I think that's definitely key. That we are able to provide that full menu of services relative to others in the industry. I think that's very important.

I think it probably is the key. That's what differentiates us from others.

Great. I really appreciate the answers, guys.

Jason Agnew, Robert W. Baird.

With plenty available revolver capacity and potential to increase that base, are you guys solely focused on directing that capital towards your backlog of organic projects? Or any M&A opportunities, I guess, outside of your current fairway that you're evaluating?

Terry, do you want to take that?

I'll take it. The answer is yes. And we will continue to look at M&A activities, and then we will look for an opportunity to finance those M&A activities, as I've said many times before. We have and will continue to look at opportunities to grow through acquisitions. But as I've also said many times before, it's a lot more economical use of our capital to build at this point in time than to buy. And we measure these opportunities against our mixed alternatives.

Got it. And then more of a housekeeping item, but maintenance CapEx seems to be weighted a little more towards the back half of the year. Is that something we should expect kind of going forward into 2014 and 2015?

Yes.

Yes. Just as you would imagine with more assets coming on stream, you're going to have smaller incremental amounts of maintenance capital.

Got it. That's all for me. Thanks.

Matt Niblack, HITE.

Not to add confusion to the distribution growth question, but just wanted to clarify. When you talk about that growth rate being higher than it was before, exclusively for the remaining ONEOK, is that based on a baseline of the current combined distribution? Or is that based on a new baseline of the distribution as it will be after the separation?

Okay. Let me come back and repeat what I talked about earlier. When we talk about -- when the separation is complete after the spin of the gas utility, ONEOK intends to increase its dividend to a level competitive with its pure-play GP peers. If you look at the pure-play GP peers and measure that against where ONEOK is today, the pure-play GPs are -- show a greater increase. Okay? So that's what we're seeing. Does that help you?

Right. A greater growth rate, right?

Yes.

So when we think of that greater growth rate (multiple speakers).

Whoa whoa whoa whoa! I'm sorry to interrupt you, but also what I said was ONEOK intends to increase its dividend to a level competitive with its pure-play GP peers. Now, that's what I said. And those words, to me, mean that ONEOK intends to increase its dividend.

Right. Right. The remaining ONEOK will increase its dividend versus current levels in absolute terms.

That's correct.

Chris Sighinolfi, Jefferies.

Terry, thanks for the call and added color. I just have one question remaining, and that's pertaining to the NGL sales for the quarter. Obviously, they jumped quite significantly. You mentioned that in your prepared commentary. Just wanted to better understand the drivers behind that. Obviously, you had the ethane header at Belvieu and some other things. But I'm just, I guess, curious -- was inventory sales a contributor to that jump at all? And if so, roughly how much?

Yes, it's definitely related to inventory. The reason why that sales number is increased is we're loading our storage down there at Belvieu with raw feed to get positioned and ready to start up the MB-2 fractionator. So, in all, the accounting associated with that and protecting the price risk associated with that storage, it inflates our sales numbers. So that's what you're seeing. It's not really related to any sort of contractual change or anything like that.

Okay. So with that facility slated to come on here in 3Q, can you quantify at all like how much that impact might've been in the quarter in 2Q?

Related to that inventory?

Yes.

Probably that delta -- the delta Q over Q was probably all attributable to that raw feed bill.

Okay great. Just trying to figure out on my run rates later on. Thanks a lot.

John Edwards, Credit Suisse.

Good morning, everybody. If we could come back to the ethane rejection versus optimization and the exchange services issues. This first on exchange services -- kind of a follow-up to John's question. So the margin, does that vary with respect to, you know, market prices and volumes involved in the exchange? And if so, can you give us any kind of idea how that would work?

Think of it this way. Optimization is going to be the relative value between two market points, Conway and Belvieu, less whatever costs might be incurred to move the product between the two points. Now, to avoid the cost, you could buy a product at one point and sell it at another, etcetera. But optimization is all about just taking advantage of whatever, if you will, spread is the word Terry uses that exists between a relative -- a component of the NGL barrels between two locations at any particular point in time. And that is just -- so what -- and you compare that to an exchange service fee. And as Terry mentioned earlier, when we work with our producers, it -- the optimization piece is not part of the puzzle. The fee represents a fair exchange of cost, or revenue in our case. Cost, in the case of the producer, for us to gather the NGL barrel, bring it to our fractionation facility, fractionate it, distribute the finished products to a market center, and then monetize that product for the producer in the form of a price, less a fee. And so there is no spread component in the exchange services agreement.

Okay. That's helpful. Just and then adding to that, is that the fixed that you're talking about? You know, you provide all those services. Or does that fee itself also vary depending upon volume that you're doing it for and the market price? Or how does that vary?

It varies by the quantity, the relative terms that the producer wants. Obviously, a producer that has more barrels is probably in a better position in negotiating with us than one that has fewer. But that's an example. But each of those contracts, although there is a fee, also has sometimes the ability for that fee to change based on increased quantities, or actually reductions in quantity. And then it also will include things like consumer price index, power price indexes, things of that nature that the two parties agree to to adjust the fees so that neither party suffers relative to increased or decreased costs. And all those things are negotiated in these exchange service agreements. And that's how we are able to get the term, is by reducing the amount of exposure to both parties and finding that good middle ground.

And that fee, that it's -- is it basically -- I realize there's a lot of services here. Is it -- the form, is it on a per-barrel basis?

I think it's on a per-gallon, but --.

It can be on a per-barrel or gallon basis. Whatever you choose to do.

Okay. And then just to help us for modeling purposes, is there kind of a range that we should be thinking about? Or is that something you can't talk about?

Really can't talk about that.

I would say this, though. The piece in the marketplace that's transparent is the optimization spread. That's out there every day. Exchange with the producer is providing all the services and getting them, in essence, finished barrel -- finished product pricing, less the fee, agreed to to make all that happen for them. So if you pick Belvieu as the point in which the pricing under the contract is agreed to, it's going to be Belvieu pricing, less a fee, on the exchange service agreement. For simplicity sake. And that is -- the producer's net back will be reduced by the fee that they pay ONEOK. And that fee can be adjusted, and we talked about some of those adjustments.

Now what's happened is, as ethane has come off the system because of ethane rejection, it has created additional space in all of those pieces of pipe, whether it's gathering, whether it's fractionation, whether it's distributed pipelines, right? What ONEOK has been able to do for its own account is to either buy barrels at Conway -- or sell barrels at Conway or buy barrels at Belvieu, or move them back and forth paying -- covering those costs and making money with that space that's been created by the fact that ethane is no longer being produced by that gas processor. So the ethane play on spread play is for our book. I mean, for the most part, that's the way to think about it. And then the other part is just an exchange of service with the producer for the services that we provide them. And it removes -- to a very large degree, removes any price risk. For this.

That's really helpful. Now that actually is a good segueway, then, to the question I was trying to understand a little better. That interaction between the ethane rejection and uplift from optimization. In the guidance that you gave, you went from $5.45 to $5.75 for the NGL segment. You were citing the optimization versus ethane rejection. Is there any way to sort of break that out? How much was the downshift from ethane rejection, and how much was the uplift from optimization? Or the net $30 million; how much was uplift from optimization, and how much was lower from ethane rejection, I guess?

Let me try this. As I indicated to you before, we don't provide optimization volumes. But if you look at our guidance for 2013, and we're rejecting -- we've got ethane rejection in that guidance. Okay? We are offsetting a considerable portion of that ethane rejection with the optimization activity. If you look at optimization activity to provide some relativity for you, if you look at the optimization margin that we expect to generate in our 2013 guidance, it's going to be in the range of what we have indicated we're going to be running -- 15% to 20% of our margin, okay, will be from rejection. The rest of these things -- minimum volume obligations; additional Bakken volumes; significantly higher [isome] margins; various term transactions and commercial transactions in our marketing. Those are all things that are going to contribute to that guidance. And optimization is that -- is in that -- is not an unusually large percentage.

So when confronted with the fact that ethane comes off the pipe, if you will, or comes out of the fractionator, you got this empty space. What are you going to do with it? Well, as I alluded to earlier, the optionality that the assets give you is to go out because you have these -- all these interconnected assets, the gathering, the fractionation, the distribution, the storage, you go out and you make the most out of all those assets and take place of what the -- take advantage or capture what the market gives you. And that's the optimization. The alternative is to let all these other things happen that Terry is talking about. The isomerization activity, the increased volumes that we've gotten from the new supply connections, etcetera. New pipeline out of the Bakken. You take all those things. And those are all great things, and they all added to -- and have added to and will add to our bottom line. But in addition to that, instead of just letting the space go empty, we've taken advantage of the optionality that the assets provide and captured some value for that. And as Terry is alluding to, that's not -- you know, we throw these millions of dollars around like they are nothing. But it's a decent amount of money. But it didn't turn the whole tide. It's not what's put us where we are today. The other stuff. Did that help you?

That's helpful. Maybe I'll follow-up a little bit further off-line, but thank you very much.

Okay John.

That does conclude our question-and-answer session. I'll turn the conference back over to our speakers for any additional or closing remarks.

Thank you for joining us, everybody. 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 5, followed by our conference call at 11 AM Eastern time, 10 AM Central on November 6. We'll provide details on the conference call at a later date. TD, your [SD&I], will be available throughout the day to answer your follow-up questions. Thank you for joining us and have a great day.

Again ladies and gentlemen, that does conclude today's conference. We do thank you all for joining.