歐尼克 (OKE) 2012 Q2 法說會逐字稿

Good day, and welcome to the ONEOK and ONEOK Partners' 2012 second-quarter earnings call. Today's conference is being recorded.

At this time, I would like to turn the conference over to Mr. Dan Harrison. Please go ahead, sir.

Thank you very much. Good morning and thanks to everyone for joining us. 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.

And now, John Gibson, Chairman and CEO of ONEOK and ONEOK Partners. John?

Thanks, Dan. Good morning, and many thanks for joining us today. As always, we appreciate your continued interest and investment in ONEOK and ONEOK Partners.

Joining me today are Rob Martinovich, our Chief Financial Officer, who will review our quarterly financial performance and discuss our updated earnings guidance; Pierce Norton, our Chief Operating Officer, who will review the operating performance of ONEOK and ONEOK Partners, and update you on the Partnership's growth projects, which I'm pleased to say are on-time, on-budget, and growing; and Terry Spencer, our President, who will update our NGL supply and demand outlook.

On this morning's call, we will review our second-quarter results; discuss our rationale for our updates to 2012 earnings guidance; reaffirm our ability to continue to grow ONEOK's dividend and ONEOK Partners' distribution over the next several years, even in a lower commodity price environment; and update our progress with our growth projects, including our contracting status for the Bakken Crude Express pipeline and the $1 billion of additional projects announced just last week.

Let's start with our second-quarter performance. ONEOK Partners turned in an exceptionally strong performance, driven by strong volume growth in the Natural Gas Liquids and Natural Gas Gathering and Processing businesses. Our Natural Gas Distribution segment turned in slightly higher results, performing as expected. And our Energy Services segment reported a loss because of the continuing challenges it faces in a low natural gas price environment with low price volatility. Pierce will provide more detail on each segment's operating performance in just a few minutes.

We updated our 2012 earnings guidance ranges, increasing the range for ONEOK Partners to reflect our expectation of the continued strength of the natural gas liquids business. We decreased slightly the ONEOK guidance range to reflect lower-than-expected earnings at Energy Services, and to a lesser extent, the Natural Gas Distribution segment, partially offset by the strong contribution from the ONEOK Partners segment.

As Rob will discuss in a few minutes, we remain confident in our ability to grow ONEOK's dividends and ONEOK Partners' distributions over the next several years, even with lower prices. The main driver of these increases will be the volume growth from ONEOK Partners' capital investments.

Since our last conference call, we've made a lot of progress contracting for our Bakken Crude Express Pipeline, which Pierce will discuss in a few minutes. Demand for the capacity is strong, and we may have opportunities to increase the pipeline's capacity.

Rob will now review ONEOK's financial highlights, and then Pierce will review ONEOK's operating performance. Rob?

Thanks, John, and good morning, everyone. ONEOK's second-quarter net income was $61 million compared with $55.1 million for the same period last year, driven primarily by the solid performance at ONEOK Partners, offset partially by continued challenges in the Energy Services segment.

We completed a 2-for-1 split of the Company's common stock on June 1, making our shares more accessible to a broader base of potential investors. Also in June, ONEOK executed a $150 million accelerated share repurchase agreement, funded by cash on-hand and short-term borrowings, part of a Board-approved $750 million share repurchase program through 2013, of which $300 million remains. Based on the repurchase of shares, we expect the average amount of diluted shares outstanding for 2012 to be approximately $211 million.

ONEOK's year-to-date 2012 stand-alone cash flow, before changes in working capital, exceeded capital expenditures and dividend payments by $82 million. In July, we declared a dividend of $0.33 per share on a split adjusted basis, an increase of 8% from the previous quarter. With the Partnership's equity offering and private placement in March 2012, ONEOK, as a General Partner and significant Limited Partner owner, is now expecting to receive $437 million in distributions from ONEOK Partners this year, a 31% increase over 2011.

We also updated 2012 guidance for ONEOK. Net income is expected to be in the range of $345 million to $375 million compared with its previous range of $360 million to $410 million. The updated guidance reflects lower expected earnings in the Energy Services and Natural Gas Distribution segments, offset partially by higher expected earnings in the ONEOK Partners segment. Pierce will discuss the specific segment guidance updates in a moment.

Our updated stand-alone cash flow before changes in working capital is expected to exceed capital expenditures and dividends by a range of $115 million to $145 million versus our previous guidance range of $155 million to $195 million. This change reflects our revised ONEOK earnings guidance. Today, we are also affirming our expectation to increase the dividend by approximately 40% between 2012 and 2014, as incremental cash from the growth at ONEOK Partners flows to ONEOK.

At our Investor Day in September, we'll present our updated three-year 2013 to 2015 projections that will include specific ranges for net income and dividend growth. We also expect to release 2013 financial guidance at that time.

ONEOK's liquidity position remains good. At the end of the second quarter, on a stand-alone basis, we had $571.9 million of commercial paper outstanding, $22.8 million of cash and cash equivalents, with $626.4 million available under our $1.2 billion credit facility. And our stand-alone total debt-to-capitalization ratio was 52%. ONEOK's cash flow and liquidity position continue to give us excellent financial flexibility.

ONEOK remains committed to providing sustainable value to our shareholders and solidifying our position as an attractive investment, whether it's by increasing our dividend, repurchasing ONEOK stock, and/or purchasing additional units of ONEOK Partners. We have used all of these options and don't view them as mutually exclusive, and are fortunate to have the financial capability to do one or more under favorable conditions.

Now, Pierce will update you on ONEOK's operating performance.

Thanks, Rob, and good morning. Starting with our Natural Gas Distribution segment, second-quarter 2012 earnings were up slightly, due to higher rates and surcharge recoveries, driven by regulatory activity in Texas and Kansas. The Distribution segment's operating income guidance for 2012 has been slightly decreased to $215 million, reflecting lower margins due to warmer-than-normal weather.

Now a brief regulatory update. Kansas Gas Service filed a request with the Kansas Corporation Commission to increase its overall annual revenues by $32.7 million. The request includes a $50.7 million increase in base rates and an $18 million reduction in amounts currently recovered through surcharges. If approved, we expect to implement new rates in January 2013. In July 2012, Oklahoma Natural Gas received approval to increase base rates by $9.5 million annually.

Our tariff was also modified, narrowing the range of allowed return on equity to between 10% and 11%, compared with the previously approved range of 9.75% to 11.25%. So far in 2012, we have received approval for increasing totals of $10.1 million annually in various Texas jurisdictions under rate cases, and capital recovery and cost of service mechanisms.

Now, a brief overview of Energy Services. Second-quarter 2012 earnings were reduced as a result of lower transportation margins compared with 2011, and lower premium services margins due to lower natural gas prices. As we have said on previous earnings calls, we are aligning or rightsizing the transportation and storage capacity to serve our premium service customers, which means we are turning back or renegotiating transportation and storage leases. We now expect our year-end 2012 natural gas storage position to be approximately 72 Bcf compared with our previous estimate of 65 Bcf.

We decreased guidance for the Energy Services segment to an operating loss of $60 million. This is primarily from the required $30 million non-cash reclassification of deferred losses to earnings on certain financial contracts related to our storage business, of which we have gains that will be recognized in earnings during 2012 and 2013's heating season, and the non-cash $10 million goodwill impairment charge. Both of these charges occurred in the first quarter 2012. This segment continues to be challenged by lower natural gas prices and volatility, and narrow seasonal and location natural gas price differentials.

John, that concludes my remarks for ONEOK.

Thanks, Pierce. Now, Rob will review ONEOK Partners' financial performance, and then Pierce will come back and review the Partnership's operating performance, as well as our growth projects.

Thanks, John. In the second quarter, ONEOK Partners' net income increased 21% compared with the second quarter of 2011, driven by higher Natural Gas Liquids operating results. ONEOK Partners reported net income of $206.5 million or $0.69 per unit, compared with last year's second-quarter net income of $171.1 million or $0.67 per unit.

There were 219.8 million units outstanding for the second quarter this year, compared with 203.8 million units outstanding for the same period in 2011. The equity offering and private placement in March 2012 included the issuance of 16 million additional units.

Quarterly distributable cash flow increased 16% compared with the second quarter last year, resulting in a coverage ratio of 1.29 times. At the same time, we are increasing distributions to our unitholders. We increased the distribution $0.025 per unit for the second quarter and, subject to Board approval, expect to increase it another $0.025 per unit per quarter for the remainder of 2012.

The most common question we are asked relates to the potential impact of sustained low commodity prices, specifically NGL prices, on our distribution growth rate. Based on a current forward-looking price deck developed by averaging PIRA and Wood Mackenzie prices for crude oil and natural gas, and applying NGL price relationships to crude oil from CMAI, our average annual distribution growth rate would be at the low end of the 15% to 20% range for 2013 and 2014, with a coverage ratio of 1.

Our long-term coverage ratio target remains at 1.05 to 1.15 times. However, if low commodity prices are sustained, our coverage ratios could be slightly below that. We'll provide more specific price assumptions with you at our Investor Day in September.

We've increased the Partnership's 2012 earnings guidance to a range of $860 million to $910 million, compared with the previous range of $810 million to $870 million, reflecting higher earnings in the Natural Gas Liquids segment, offset partially by lower expected earnings in the Natural Gas Gathering and Processing segment.

We now estimate the Partnership's 2012 distributable cash flow to be in the range of $975 million to $1.025 billion, compared with its previous range of $925 million to $985 million. We'll also present ONEOK Partner's updated three-year projections for 2013 to 2015 in September, that will include specific ranges for EBITDA and distribution growth. We also expect to release 2013 financial guidance at that time.

We hedge the commodities received for our services to lock in margins on our expected equity volumes in the Natural Gas Gathering and Processing segment. For the rest of 2012, 76% of our natural gas volumes are hedged, while 70% of our NGLs are hedged. Hedging information for 2013 is included in the news release.

At the end of the second quarter, the Partnership had $92.9 million in cash, $24 million of commercial paper outstanding, a debt-to-capitalization ratio of 44%, and a debt-to-EBITDA ratio of 2.3 times. We extended the maturity date of our $1.2 billion revolving credit agreement by one year to August 2017.

Now, Pierce will review the Partnership's operating performance.

Thank you, Rob. As John said, the Partnership had a strong second quarter. Operating income increased 13%, driven primarily by higher margins in Natural Gas Liquids segment from favorable NGL price differentials between Conway and Mont Belvieu, increased transportation capacity available for optimization activities, and higher NGL volumes gathered.

Earnings also increased as a result of higher volumes in the Natural Gas Gathering and Processing segment, specifically in the Williston Basin from the start-up of the new Garden Creek 1 plant that went into service in late December. The Natural Gas Gathering and Processing segment's second-quarter financial results were relatively unchanged. Our natural gas volumes gathered and processed in the Williston Basin were offset by lower natural gas and NGL product prices on the unhedged equity portion of these commodities.

The new Garden Creek 1 plant continue to operate near its capacity of 100 million cubic feet per day. Operationally, the plant is exceeding our expectations, and we continue on a record-setting pace for new well connects in 2012. However, we reduced the segment's operating income guidance for 2012, primarily reflecting our expectation of lower net realized and expected commodity prices. We have provided those specific price assumptions in our earnings release.

We still expect process volumes to be up 24% over last year, and gathered volumes to be up 12% compared with last year. Low NGL prices did result in periods of ethane rejection in the midcontinent, but did not have a material impact of this segment's results.

The Natural Gas Pipelines segment's second-quarter results were higher, due primarily to increased natural gas storage and transportation margins. 2012 guidance for this segment remains unchanged.

Equity earnings from Northern Border Pipeline are relatively flat. Northern Border is substantially contracted through March 2013, and has been successful in capturing three-year or longer extensions as current contracts expire. It also has two-thirds contracted on its long-haul capacity through 2014.

Our Natural Gas Liquids segment continued to benefit from favorable NGL price differentials, and more transportation capacity available for optimization activities, and higher NGL volumes gathered. Our MB-1 fractionator was down for scheduled maintenance for 30 days in May, and experienced some temporary mechanical issues, preventing it from returning immediately to its 160,000 barrel-per-day capacity. As a result, our fractionation volumes were down 2% during the second quarter, with the midcontinent fractionators making up some of the volumes that would have been fractionated in the Gulf Coast, and increased volumes in the midcontinent.

The Partnership will realize margins from raw feed stored in the Gulf Coast as a result of the turnaround later in the year, as we have forward sales in place. NGLs transported on our gathered lines were up 21%, averaging 523,000 barrels-per-day during the quarter, as a result of the increased NGL volumes gathered from the expansions of Arbuckle Pipeline and the midcontinent NGL gathering system in Texas and Western Oklahoma. We expect NGL gathering volumes to be up 22% over last year and fractionation volumes to be up 11% compared with the same period.

We increased our operating income guidance for this segment to reflect higher-than-expected NGL optimization margins from increased NGL transportation capacity available for optimization activities and higher isomerization margins. For the last six months of 2012, we have assumed $0.28 per gallon Conway-to-Mont Belvieu average ethane in the ethane/propane mix price differential.

Now, an update on our projects. First, all of our previously announced internal growth projects are within the forecasted project cost and timeline ranges. Second, last week, we announced more internal growth projects, totaling approximately $1 billion, that now bring our 2011 to 2015 internal growth program from $5.7 billion to $6.6 billion.

Our contractual dedications in the Williston Basin have grown to 2.7 million acres, which is supporting the building of a new 100 million cubic feet per day natural gas processing facility, the Garden Creek 2 plant, and related infrastructure. Upon completion, our processing capability in the Williston Basin will be approximately 500 million cubic feet per day.

We will also be installing additional pump stations on the Bakken NGL pipeline to increase its capacity to 135,000 barrels-per-day from an initial 60,000 barrels-per-day to take away liquids generated by our plants.

We will be expanding our Gulf Coast fractionation capacity by constructing a new 75,000 barrel-per-day natural gas liquids fractionator, MB-3, and related infrastructure at Mont Belvieu, Texas, plus the installation of a 40,000 barrel-per-day ethane/propane splitter at our Mont Belvieu storage facility. These projects are backed by firm supply commitments and area dedications.

Third, an update of our plan to build the 1,300 mile Bakken Crude Express Pipeline. Discussions with crude oil producers indicate they project crude oil production to increase to well over 1 million barrels-per-day within the next five years, requiring additional crude oil takeaway capacity. At the moment, we are in advanced stages of negotiations with two large anchor shippers who represent a majority of the 200,000 barrel-per-day initial pipeline capacity.

We are also negotiating with multiple other producers for additional capacity. We expect to have committed in the near-term, well before construction, all the pipeline's capacity that's available for commitments. Final negotiations with the anchor tenants, as well as the open season results, could increase the current pipeline capacity beyond 200,000 barrels.

For obvious competitive reasons, we are not disclosing the proposed rates at this time. However, it will be advantageous to rail, with producers able to lock in rates for longer-term, compared with a contract for typical rail capacity.

And we continue to develop and evaluate a lengthy backlog of natural gas and NGL-related infrastructure projects, including investments in processing plants, natural gas pipelines, NGL fractionation, and storage facilities. Even with the recently announced projects totaling $1 billion, this backlog still totals more than $2 billion. As we have done in the past, we will announce the projects when we have sufficient producer and/or customer commitments to make them economically viable.

John, that concludes my remarks.

Thank you, Pierce. Terry will now give you an update on our view of the current and the long-term NGL market dynamics.

Thanks, John, and good morning, everyone. Today, I'll provide a brief outlook of the NGL markets.

Over the past several months, there certainly has been some downward pressure on NGL prices, primarily as a result of the following -- an overall softening in the crude oil markets; many of the petrochemical facilities were down for major scheduled and unscheduled maintenance; increased production growth in NGL-rich shale areas; and higher propane inventory levels, due to a warmer-than-normal winter.

With the major planned outages behind them, the petchems have begun to consume the excess ethane inventory that has built up, and accordingly, ethane inventories are expected to decline throughout the remainder of the year. The petchems expect to be operating at high utilization rates well in excess of 90%, with ethane as their primary feedstock. Ethane continues to be the preferred petrochemical feedstock versus oil-based feeds, due to ethane's continued price advantage, driven by the continued low ethane to crude oil price ratio, which is now well below 20%.

With near-record ethane consumption of well over 1 million barrels-per-day, we expect US ethane inventories, in terms of days of supply, to be back to within normal ranges as early as year-end. We expect the price of ethane, particularly at Mont Belvieu, to continue to strengthen in the near and longer-term, as it has recently. In particular, US Gulf Coast petchem demand for purity ethane feed continues to grow, and supplies of the traditional ethane/propane mix continue to grow as well.

This, in our view, is creating, across our system, an imbalance of excess ethane/propane mix and not enough purity ethane to serve the petchems' needs. Accordingly, the price relationship of ethane/propane mix versus the premium-priced purity ethane has periodically widened to historical levels.

To meet the growing petrochemical demand for purity ethane, we plan to construct a new facility in Mont Belvieu to split purity ethane out of the traditional ethane/propane mix. The new facility, which is simply a specialized fractionator, designed to fractionate an 80/20 ethane/propane mix into purity, will allow us to better serve our petrochemical customers, as well as compete more effectively for new markets and supplies.

A quick comment on propane. Due to the higher propane inventories, resulting primarily from the past mild winter, and its reduced price relative to crude oil-based feeds, we have seen some petchems crack more propane compared with previous years. However, with the petchems resuming normal operations following the major turnarounds, we are seeing some petrochemical facilities reduce their propane feed in favor of ethane. We do expect the propane surplus to decline as additional export capacity is developed over the next 12 months, with propane exports being maximized, due to the continued pricing incentive for international propane buyers to purchase US Gulf Coast propane.

We also expect NGL fractionation capacity to remain in short supply, but gradually increase as new fractionators, including our own, come online over the next few years. Fractionation capacity, especially in the Gulf Coast, is at a premium, as growing unfractionated NGL supplies from the prolific shale developments continue to seek the premium-priced Gulf Coast NGL markets.

Accordingly, new pipeline capacity between Conway and Mont Belvieu is being built to accommodate NGL growth from the shales. We continue to believe the NGL price differential between the market hubs will narrow to the cost-to-build range of $0.08 to $0.10 per gallon over the next couple of years.

In spite of the volatile and challenging commodity markets, we continue to focus on helping our supply and market-connected customers get the products to where they need to be. Our recently announced growth projects, the new MB-3 fractionator and the E/P splitter in Mont Belvieu, and the expansion of the Bakken NGL pipeline, are being built so we can continue to provide reliable services to our customers through our integrated NGL asset base.

On the supply side, as you know, many rigs have moved away from dry gas regions, and producers are focusing specifically on crude oil and liquids-rich plays, such as the Bakken, Cana-Woodford, Woodford, Granite Wash, Niobrara, Mississippian Lime, and the Eagle Ford Shales. Fortunately for us, our assets are well positioned in all but one of these areas. While overall rig counts have decreased, rig counts in the Bakken and the Cana-Woodford, especially in the core areas where we operate, are increasing.

As NGL growth continues at a rapid pace, we believe that over the next couple of years, there will be some periodic oversupplies of ethane, as new NGL production and infrastructure brings additional NGLs to market. As we approach and move through the 2015 to 2017 time frame, we do believe there will be sufficient demand for NGLs as new petrochemical expansions come online, and from growing Gulf Coast export activity.

John, that concludes my remarks.

Thank you, Terry. Before we take your questions, I'd like to add to what Rob said about our confidence in our dividend and distribution growth projections. Prices, especially lower ones, will affect ONEOK Partner's earnings through our percent of proceeds contracts, particularly in our Natural Gas Gathering and Processing business.

This commodity price risk will always be present in the Gathering and Processing business, which is why we have historically pursued hedging opportunities. However, as we continue to grow ONEOK Partners, the volume growth in our Natural Gas Liquids and crude oil pipeline business will generate additional income that is fee-based, and contracted on a ship-or-pay or frac-or-pay basis, significantly reducing future earnings risk.

I'd also, at this time, like to thank our more than 4,800 employees whose dedication and commitment allow us to operate our assets safely, reliably, and environmentally responsibly every day, and create exceptional value for our investors and customers. Our entire management team appreciates their efforts to make our Company successful.

And finally, I'd like to take this opportunity to recognize David Roth, our Senior Vice President of Administrative Services, who will retire September 30. In his role, he is responsible for IT, HR, and Corporate Services. During his 33 years, he has made countless contributions and many positive changes to our employee benefits; enhanced our IT capability dramatically; and advanced our employee development efforts. Through his leadership, he has made ONEOK a much better place to work.

During my 12 years at ONEOK, David has been a trusted and faithful colleague; but more importantly to me, over those years, one of my closest friends. With Dan assuming David's responsibilities, I am confident the Company will stay the course, but we will miss David Roth. So, on behalf of all ONEOK employees, we thank David for his contributions and wish him the best in his retirement years.

Operator, we're now ready to take questions.

(Operator Instructions).

All right, and we're off.

Steve Maresca, Morgan Stanley.

You won't get off that easy. (laughter) Good morning and thanks, as always, for all the details. My first question is on the NGL movements out of Kansas and Oklahoma.

Can you talk a little bit about, first, what is Arbuckle running at right now in terms of flows? And then Sterling III comes online late next year. How long do you think that will take to get up to the initial capacity that you talk about, 193,000 barrels? (multiple speakers)

Yes, I'll ask Pierce to provide you as much detail as he's comfortable doing. But as you'll recall in our many, many conversations where you ask very similar questions, we don't disclose a whole lot of information about that. But whatever you feel comfortable saying, Pierce.

Oh, as far as Arbuckle goes, Steve, I guess the way I would say that, it's near capacity.

Okay.

That's all you're going to say.

Okay. And then how long does something typically, like a new line like Sterling, like, take, would you say, to ramp to what a capacity nameplate that you're talking?

You know, one of the points of reference I'd give to you is that when we built Arbuckle, we anticipated that it would have a slow increase -- I can't remember what we -- Terry, do you remember what we anticipated? Maybe as much as a year to get --?

Right, John. I think we were expecting it would take roughly a year to get to about 160,000 barrels-per-day. And of course, we've moved through that pretty quickly.

Yes. So, sort of, it depends upon the ability of the producer and/or the customer shipper to either complete the plants or have the supply available. It can go -- once the pipeline's built, it's just a matter of the supply being accessible.

Okay. And then with your July announcements on the Garden Creek gas processing and MB-3, can you discuss any agreements that you have surrounding those projects?

Steve, this is Pierce. The way I would answer that one is that, if you remembered my script notes, we have 2.7 million acres under dedication there. And when you look at the projected volumes, it will more than fill up that plant. So we actually have all of that contracted for, under existing area dedications.

And as far as MB-3 goes, there is a very high level -- way more barrels available there than even the capacity. So we believe that that will fill up really quickly and be committed as well.

Okay. Final one on the Bakken Crude line. What are the permits or regulatory hurdles that are needed?

It really is not -- it's the same ones pretty much that you go through on the NGL side. We'll get core permits; if you cross any kind of state lands, you get the state land permits. You go through the standard negotiation process in the beginning, and then you have an open season.

And then, basically, you're ready to go and construct and build, once you get the necessary regulatory permits. So nothing out of the ordinary when you compare it to the NGL side.

Okay, thanks, everybody.

Carl Kirst, BMO Capital.

Actually, Pierce, just following up on that, and I'm not sure if, given the stage of negotiations, it's possible to say, but you had made the reference of near-term, I believe. And so, is a binding open season something that you still expect to happen this year? Or is that something that could potentially be a 2013 event?

We still expect that to happen this year, Carl.

Okay. And then if I could, and you know, Rob, I know you're going to lay all this out at the Analyst Day, but just -- you mentioned sort of the forward deck that you're using being an average of PIRA, Wood Mac, et cetera. Do you actually happen to have those absolute numbers, even if it's kind of a 30,000 high-level oil and even composite NGL relationship, just to dead reckon?

I mean, Carl, we do. And I guess one of the reasons that we wanted to cite that was, that's been past practice as -- so you can get a feel as far as how those things are moving around. But really where those kind of end up from, at least from a crude standpoint, you're kind of mid-90s; gas around $4; and then on the composite barrels, kind of in that $0.80 to $0.90 range.

Okay. Fair enough. And then last question if I could, just -- I just wanted to make sure I understood on energy marketing at OKE, this reclassification. Was that basically something that was previously a LOCOM, and is now sort of a mark-to-market loss and maybe we'll get some of that money back? And whether it's the end of this year or 2013? Or is that just more sort of an outright loss?

Yes, Carl, when we talked about that the first quarter, we said similar to an LCM, that you may be familiar with on inventory. However, this related to losses on purchase [ahead] contracts. And, as we indicated in the first quarter, and as Pierce said, now we expect to get some deferred gains back in this heating season. And so, we do expect to claw back a little bit of that this year. And that's included in the guidance.

I see. Okay. All right, thank you very much.

Ted Durbin, Goldman Sachs.

Just following-up on the question on the new Garden Creek plant. So, you've got the acreage dedications, but the volumes that actually move through, will those be percentage-of-proceeds type contracts?

Yes, they will.

Okay. And then, talking about just the Conway- Belvieu spread assumptions, and you talk about $0.08 to $0.10 long-term; you're now in the high 20s for this year. I guess I'm trying to bridge for 2013 how you're thinking about '13. You're going to be bringing 60,000 barrels-a-day of Bakken and gels into Conway, so that will probably make that spread a little wider. I'm just wondering if you can talk a little bit more about that?

Well, Ted, this is Terry. We provided you the $0.28 for ethane for the second half of 2012. As we look to 2013, if you'll recall, we've actually brought some capacity on between the midcontinent and the Gulf Coast. In particular, our Sterling I, 15,000 barrel-a-day expansion, and our Arbuckle expansion of about 60,000 barrels-per-day here in 2012.

So we brought some capacity on. And so, as a result, our view is that the spreads will tighten somewhat as we move into 2013. So you're going to see spreads, in our view, somewhere in that $0.15 to $0.20 range for 2013. And then you'll move into the 2014 time frame and get into that $0.08 to $0.10 realm, which is primarily the cost to build.

Sure. That's very helpful. Thanks, Terry.

And then last one for me, just coming back to the Bakken Crude Pipeline. You talked about the two anchor shippers. I guess if you got just those two contracts signed where you're thinking, would you be hitting your sort of 5 to 7 times EBITDA target? Or do you need to get a few more people signed up to hit your target?

No, we -- if we could get those two anchor shippers, then we'll be within that range. But we do expect there to be even more interest than just those two anchor shippers.

Got it. And that would cause you then to potentially upsize the pipe?

That's correct.

Got it. Okay. That's it for me. Thanks, guys.

Thanks, Ted.

John Edwards, Credit Suisse.

Just curious, you were making some comments about your distribution growth outlook in relation to coverage. And so I'm just curious, would you be more inclined to slow that growth just a bit to keep your coverage within your 1.05 to 1.15 target? Or would you be more inclined to maintain the low end of the 15% to 20% range and take your coverage down a bit?

Well, there's no answer to give to you at this point in time. That's a Board issue; but we have had that discussion with the Board, and it's management's view that we probably would focus more on the coverage ratio than we would accelerating the distribution.

But again, it all depends on where the market is at that particular point in time. I think the more important thing is that we don't necessarily see ourselves in that position.

Rob, is there anything you want to add to that?

Yes, I think just to amplify it, John, much like when we had periods of time, John, where we knew we had unsustainable optimization levels, and we had coverage ratios well exceeding that target rate, there are going to be periods of times we're down below. So, I think it's -- you have to look at it there from a sustainability standpoint before you make a final decision.

Okay, great. And then, with regards to the ethane supply/demand balance outlook, there were some comments made indicating there'd be some periods of oversupply, and that although 2015 to '17, the expectation was it would be in relative balance. And I was just wondering if you had any more thoughts regarding the 2013 to '15 time frame, with respect to what kind of -- where you think the supply/demand balance might be at that point in that time frame?

Well, John, really, I think probably the only thing I could add to the previous comments I made in my remarks is that the curve is going to be kind of lumpy. It's not going to be perfectly smooth. And certainly, we will have these periods of time where we'll have excess ethane.

When many of the analysts analyze this ethane supply and demand balance, they make the assumption that every one of these fractionators that are coming on are going to be full day one -- or at least get full at some point in time. That may not happen in every case. And as a result, it's going to make it -- it is going to make it kind of difficult to predict those supply and demand balances during that time frame.

And so, it really is going to look kind of lumpy. And we'll have periods where the crackers will need everything we can give them, and they will consume everything we can give them; and then other times where they don't.

So, we'll have to weather that; it will be volatile. We're well positioned through that volatile time frame. And by the time we make it to 2015, 2017, we'll be in really good shape.

Okay, great. Thank you very much.

Thanks, John.

Michael Blum, Wells Fargo.

A couple of questions for me. One on the E/P Splitter, will that produce international grade propane? And if so, would that potentially find an export market?

No. It will be primarily consumed domestically.

Okay. Then kind of a dumb question for me, and I apologize but, why is MB-3, the cost-to-build it, so much greater than MB-2?

Well, I mean, basically, you've got some escalation of costs that occurs in the labor market and with the materials. So, that's driving it more than anything. And frankly, when you start to build that many fractionators down in that area, you get a lot of demand for construction services, both construction management services and the materials and labor, and it just drives the cost up.

Okay. So how does that impact the return you'll get on MB-3 versus MB-2?

Well, we still expect our returns to be solid and within those guidelines of multiples that we provided earlier.

Okay. All right, thank you.

Elvira Scotto, RBC Capital Markets.

Just a point of clarification for me. For the increase in the guidance in the NGL segment, where the press release states that part of that increase is due to higher optimization margin, resulting from additional transportation capacity for optimization, is that -- can you elaborate a little bit more on that, and how that trends the rest of the year?

Is that just because you had some pipeline come on a little sooner, and you're just waiting for some laterals to connect before third-parties contract? Or has there been a change in how you're thinking about contracting?

Elvira, this is -- it's really all of the construction and the expansions that we've done so far. And then it's a matter of how volumes match up with new plants that are coming online. If, for some reason, they're a little bit slower, then that provides us the ability to take those -- that spare capacity and use it for optimization volumes. So, it's really -- it's opportunistic.

But there's really no change in the way that we're contracting. We're still moving toward more of the fee-based and, as Terry has indicated, more of the cost-to-build in the outer years, you know, 2014.

Okay. And then just to follow-up on a previous question, on the Bakken NGL pipeline, the expansion -- do you expect that to be full on day one?

Actually, it's -- the way that you add the capacity to that pipe, which is through pumps, the way the engineering works is that the capacity actually elevates up to 135,000 per day. We do expect it to be substantially full, but we also run into a limitation when we get to Overland Pass Pipeline. So, we won't be able to immediately go to the 135,000 without doing some things on the Overland Pass Pipeline, but it will be substantially full, early.

I'm sorry. But was Elvira asking about the NGL pipeline or the Crude Oil Pipeline?

The NGL (multiple speakers) --

Yes, the NGL pipeline.

Sorry.

Okay. And then if you wanted to expand that pipeline further, could you? Or I guess, as you said, you'd have to make some modifications to Overland Pass?

Right. That's probably going to be more the driving factor than the NGL Bakken line. And -- I mean, you can always expand them by looping lines and adding pumps. So the simple answer is yes, you can expand it, but there's other things you have to expand as well.

And then just my final question -- so if you have these additional NGLs coming into Conway, I'm just trying to understand, looking out into 2014, why we're thinking the Conway-to-Belvieu spread is going to be at $0.08 to $0.10 as opposed to higher, if you're having -- if you have more NGLs?

Certainly, Elvira. I could see where you might think that. The reality, though, is that there's quite a bit of capacity that's going to be built, not just by ONEOK but by others. DCP has their project, and Enterprise has their Texas Express project. So those will be coming online in 2013 and then 2014. So those are going to pressure the spreads.

You know, we -- we're pretty confident they will come in, because when you just do the math, and you look at the incremental capacity that's going to be added, you just add it up, it's significant. So our view was, is that the floor, so to speak, on that margin between Conway and Belvieu, will naturally gravitate toward this cost-to-build. So it may be conservative, but we feel pretty confident that's where it's going to wind up.

Okay, great. Thanks. That's all I had.

Craig Shere, Tuohy Brothers.

Thanks for the call and also for the mid-June midcontinent field trip. I thought that was very helpful.

Good. I'm glad you enjoyed it, Craig. It was a little hot, wasn't it?

Yes. Especially in those overalls.

(laughter) Yes, I'm sure that's true, but we've got to keep you safe.

That must be why you only sent us home with the hardhats.

That's right. Those dang things are expensive. Hardhats, we'll give you.

So a couple follow-ups here. Terry, do you have a firm idea of just how much exactly petrochem capacity has increased to handle lighter feedstocks, coming out of the most recent maintenance cycle? And do you have a better feel for whether the proportional amount of fuel switching capacity between propane and ethane has increased or decreased coming out of that cycle?

Well, what I can tell you is, is that the increased demand coming out of the petrochemical space is about 80,000 to 100,000 barrels a day, just based upon the information we've been able to pick up, not just from the experts, but those within the industry themselves.

As it relates to propane, we have seen a significant amount of switching. Our marketing people are talking to the petchems every day, and we are seeing some switching -- as much as 100,000 barrels a day away from propane back to ethane. Okay.

So, pretty significant. And expect that -- we expect that to continue throughout the year, and in particular, as propane prices strengthen with the pressure from the increased demand on the export side.

Okay, but you wouldn't attribute that to a decreased flexibility in the system, depending on how they tweaked things when they were in the maintenance downcycle?

No.

Okay. And there's been some questions about distribution coverage, given the prepared comments. One thing I'd note -- and the comment was made, well, we're going to -- it's seasonal, right? You know, sometimes we're going to be significantly over the target range for coverage, and sometimes a little under, and it will be because of market events that are transitory that we're not reacting to.

But it was nice before when you had a whole slew of growth CapEx projects that were highly accretive, and you happened to have a lot of extra cash flow. Now that you're thinking about maybe a 1-times coverage, and you just announced a week ago another $1 billion of CapEx, could you speak to thoughts about how that might be financed?

I'm not suggesting that your question is insinuating we've changed our practice, because we haven't. I think what we were trying to do in our comments was to say that, with sustained low pricing, and keeping our distribution growth, we could see a 1-times coverage. We're not saying that we are shifting from 1.05 to 1.15 and we're now going to set it at 1.

So I just want to be clear that that was not the intention of our comments. Our comments were -- there is a lot of concern in a low-price environment as to whether or not people are going to maintain their coverage ratio and grow their distribution. We believe in worst case that we may face, if prices continue to remain low, that we might be near that 1. We might fall below that 1.05, but we are not re-basing the Company to a 1-times coverage ratio.

So, I just want to be clear that we have not changed and we remain focused. I know there was a question earlier about which gives. And our management team believes that what you would do is probably slow down your distribution growth in periods of extremely low-price environment, and maintain your coverage ratio.

And then, of course, is your follow-on question about equity offering or additional financing. Of course, even if we had those dates, we wouldn't share them with you.

So I think you look at the balance sheet, although there's a lot of great things to be said about it, clearly, at OKS we need to raise some additional capital and some debt. And we've got a great general partner and a company that likes to invest in ONEOK Partners, so we see the capital markets being receptive to any demands we might put out there.

Understood. And last question. And it may just be coincidence -- I know you've had a lot of nice transitions with the management team, various people taking on new responsibilities lately, and some people taking a well-deserved rest. Does the changing of the guard at Energy Services amid the very tough operational environment indicate any kind of reconsideration of the business plan over time there?

Not one bit.

Okay. Great. Thank you very much.

Helen Ryoo, Barclays.

First question on the optimization capacity, it seems like you'll be using much less optimization capacity in second-half versus first-half. And I'm just wondering if that capacity has already been contracted out to third parties? And if so, what is the term of the contract?

Helen, you are correct in the amount of optimization capacity available to us is going to go directionally downward toward the end of the year. That is a contractual basis. But as I mentioned before, part of that is dependent on whether or not they actually -- what volume is under those contracts actually shows up.

So, we've assumed that most of that volume will show up. It may or may not. And if it doesn't, then we'll have a little more for capacity. We actually don't disclose what that amount is.

Okay, yes, I understand you don't disclose the amount, but just wondering the length of these contracts that you're signing with third-parties, is it more of five-year, 10-year, what?

They are long-term contracts.

Okay. Okay. And then is it your expectation to bring down your optimization capacity down even more in 2013, versus the second-half of the year? Or are you -- will you be comfortable with maintaining the sort of the second-half optimization capacity level going forward?

Well, I think if I said that and then the volumes, whatever those volumes materialized to be, I'd be kind of sending a message as to what that is. So, we're going to have -- we will always have a certain amount of volume available for our optimization, I guess is the best way I can answer that.

Okay. And then just out of curiosity, on your E/P Splitter project, I know it's a small project, but would that be a spread business for you? Or is that a fee-based business?

It actually is a little bit of both. You know, we have enough E/P mix to put in that splitter and capture that upside of purity ethane to the E/P price. It also factors into a competitive advantage point of view that we have of being able to offer our customers a purity ethane price, which rolls into long-term fee-based contracts out of the midcontinent.

Okay. And then, just lastly, I think regarding the MB-3 project, I think the MB-2 fractionator was expandable from like 75,000 to 125,000, if I'm not mistaken. So just wondering, your decision to build MB-3 instead of expanding the existing MB-2, what are the factors that affected that?

Helen, this is Terry. I do recall that that's what we indicated. I think it's quite simply in terms of -- we will have built a 75,000 barrel-a-day fractionator, then we'll have done that. It will be easier and more efficient, and we'll get more bang for our buck building a twin, basically, to MB-2. So it's simply that.

Okay. And even if you expanded the MB-2 rather than MB-3, I mean, the cost side, it may -- it would not really have changed too much on the cost side?

I didn't follow that.

I didn't --?

So, you know, just -- I mean, there was an earlier discussion about MB-3 costs getting a bit much higher than MB-2 because of all those inflationary factors you mentioned. But just wondering if you expanded the existing frac rather than build a new one, would those factors still have contributed to higher costs?

Helen, there is one other piece I think that I need to mention here, is that there are also infrastructure costs that are in the MB-3 cost. So there's some line looping, some pumps and some other stuff out in the field that actually also is going to be attributing to that, not only the escalation in costs. So I think that's probably one of the big points I want to make.

Okay. Thank you so much.

Ross Payne, Wells Fargo.

Thank you. My questions have been answered. Thank you.

Thank you, Ross.

Carl Kirst, BMO Capital.

Thanks, my question, my follow-up, was hit too. Thank you.

Okay, well, thank you, all. This concludes our call.

A couple of announcements. The annual ONEOK/ONEOK Partners Investor Day is scheduled for Tuesday, September 25 in New York. A save-the-date notice was sent out to you earlier this week, and we'll be following up with additional information, including times, meeting room locations, in the next several weeks. At that meeting, you'll have the opportunity to meet T.D. Eureste, who is joining our Investor Relations team from Treasury, and will be part of Andrew's team.

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 October 30, followed by our conference call at 11 Eastern, 10 Central on October 31. We'll provide details on the conference call at a later date.

Andrew and I will be available throughout the day to answer your follow-up questions, so we'll see you in September, if not before. Thanks for joining us.

Again, that does conclude today's conference. We thank you for your participation.