歐尼克 (OKE) 2010 Q2 法說會逐字稿

Good day ladies and gentlemen, and welcome to your second quarter 2010 ONEOK and ONEOK Partners earnings call. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session and instructions will follow at that time. (Operator Instructions) As a reminder today's conference call is being recorded. I would like to introduce your host for today's conference call, Mr Dan Harrison. You may begin, sir.

Thank you. Good morning and thanks everyone for joining us. Any 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. Please note that 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, let me turn the call over to John Gibson, ONEOK President and CEO, and ONEOK Partners Chairman, President and CEO. John.

Thanks, Dan. Good morning. Thanks for joining us and for your continued interest and investment in ONEOK and ONEOK Partners. Joining me on the call today are Curtis Dinan, Chief Financial Officer for both ONEOK and ONEOK Partners, Terry Spencer, Chief Operating Officer of ONEOK Partners, and Rob Martinovich, Chief Operating Officer of ONEOK.

ONEOK and ONEOK Partners again posted solid operating performances, with all of our business segments performing well. We are reaffirming our 2010 earnings guidance for both entities and increasing ONEOK Partners' 2010 capital expenditures to reflect our planned spending this year for the projects we have announced.

During the quarter, we continued to deliver on our commitments. ONEOK Partners is benefiting from the growth projects we completed last year, and we'll continue to grow and generate attractive returns from the investments we have just announced. Our distribution segments, operating income and returns are the result of a very deliberate and innovative approach to rate making that is paying off.

Energy services continues to make progress on reducing its contracted storage and transportation capacity, reducing annual earnings volatility, and with a renewed focus on its premium services customers, who are the linchpin of this very important business. ONEOK's and ONEOK Partners' financial position is solid with the structure and flexibility to fund growth either organically or through acquisitions. And, as Terry will discuss in a few minutes, we have taken the necessary steps to resolve the short-term NGL bottlenecks that have limited our ability to capture additional NGL optimization margins.

Now a lot has been written and concluded about Williams' decision to acquire 50% ownership of Overland Pass. As we have said many times over the past several years, we do not expect Williams' increased ownership and potential operatorship to affect Overland Pass' ability to add new volumes and grow. Had we believed otherwise, we would not have agreed to the option. Agreeing to the option with a recognized world-class pipeline operator and Company in exchange for barrels dedicated to Overland Pass was frankly a pretty good trade.

The ability for Williams to increase its ownership in, and potentially become operator of, Overland Pass was willingly negotiated four years ago. We believed then, as we do now, that it was important that NGL takeaway capacity from the Rockies be built, and that it be built to our NGL infrastructure in the mid-Continent.

Williams' willingness to be the anchor shipper on Overland Pass and to commit future barrels to the pipeline sealed the deal, and led to its construction and its continued success. Williams' decision to increase its Overland Pass ownership, I believe, reinforces its positive view, and the long-term viability of their upstream assets connected to the pipeline, and is a strong vote of confidence for Overland Pass' future growth.

Our announcement last week to expand Overland Pass to accommodate additional NGL volumes from our newly announced Bakken Pipeline is a testament to our strong partnership with Williams and our shared commitment to grow and how well aligned we are. And in a moment, Curtis will explain why the earnings impact is not significant.

So at this time, I'll turn it over to Curtis who will provide us with a financial highlight of ONEOK Partners, and then Terry will review the operating performance along with some industry dynamics. Curtis.

Thanks, John, and good morning everyone. John has already provided a brief summary of the Partnership's second quarter results, and Terry will provide additional detail in a moment. My remarks will focus on the financial results and our expectations.

In the second quarter, ONEOK Partners reported net income of $105 million or $0.75 per unit compared with last year's second quarter net income of $98 million or $0.81 per unit. In the second quarter, we had 101.9 million units outstanding compared with 91.4 million units in the same period last year. Our two equity offerings in July 2009 and February 2010 added approximately 11 million additional units.

Distributable cash flow in the second quarter was $140 million, compared with $131 million in the second quarter 2009. While the coverage ratio for the first six months was slightly below 1 times, we continue to expect the annual coverage ratio will be in our targeted range of 1.05 to 1.15 times.

As Terry will describe in more detail, we expect margins to improve in the second half of 2010, especially in the natural gas liquids segment where a significant frac-only contract expires in the third quarter. The expiration of that contract will free up capacity at our Mont Belvieu fractionator, which will be used to provide additional bundled services to our customers and will create additional optimization opportunities.

For the second quarter 2010, the partnership increased the distribution $0.01 to $1.12 per unit, representing an annualized rate of $4.48 per unit. This is the 15th distribution increase since ONEOK became sole general partner and it represents a cumulative 40% increase over that time. Pending Board approval, the partnership is on track to increase the distribution $0.01 per quarter for the remainder of the year.

We have reaffirmed the partnership's 2010 guidance and expect net income to be in the range of $450 million to $490 million for the year, taking into account Williams' decision to increase its ownership in Overland Pass Pipeline to 50%. Until the Overland Pass transaction with Williams closes, we will continue to record 99% of the earnings from Overland Pass. Once the transaction closes, we will deconsolidate ONEOK Partners in our financial statements and record future earnings as equity earnings from investments, similar to how we account for our 50% interest in Northern Border Pipeline.

As I mentioned, we have reaffirmed the Partnership's 2010 guidance, taking into account the Williams exercise. Although the effect of deconsolidating ONEOK Partners -- excuse me, Overland Pass, will change the individual line items in our guidance, the overall impact on net income is not significant. The impact of the reduction in the Partnership share of earnings from Overland Pass to 50% from 99% for the last three to four months of 2010, will be offset by lower interest expense from the receipt of $425 million, which will reduce short-term debt and eliminate a long-term debt offering that was planned for later this year. Sometime after we complete this transaction, we will update the various components of our 2010 guidance to reflect the deconsolidation of Overland Pass.

Capital expenditure guidance for the partnership has been increased $115 million to $477 million, comprised of $394 million in growth capital and $83 million in maintenance capital. The increase in growth capital relates to our recently announced capital projects.

We have hedges in place to lock in margins, in our expected equity volumes in the Partnership's natural gas gathering and processing segment, which has the most sensitivity to commodity price changes. For the remainder of 2010, we have hedged 95% of our expected natural gas equity volumes at $5.55 per MMBtu and 63% of our expected NGL and condensate equity volumes at an average price of $1.24 per gallon.

For 2011, approximately 75% of our expected natural gas equity volumes are hedged at $5.72 per MMBtu, and 13% of our expected NGL and condensate equity volumes are hedged at an average price of $1.65 per gallon. As is our practice, we continually monitor the commodity markets and will place additional hedges as conditions warrant to mitigate our overall risk.

At the end of the second quarter, the Partnership had $680 million of debt outstanding, and $320 million available under its $1 billion revolving credit agreement. The Partnership's total debt-to-capital ratio was 52%, and its debt-to-EBITDA ratio has improved to 4.3 from 4.5 at December 31, 2009. Following the closing of the Overland Pass transaction with Williams, our debt-to-capital ratio will be less than 50% and our debt-to-EBITDA ratio is expected to be less than 3.75.

In June, the Partnership established a commercial paper program, providing for the issuance of up to $1 billion of unsecured commercial paper notes. Borrowings under the commercial paper program will reduce the borrowings available under the Partnership's revolver. In July, we repaid all amounts outstanding under the revolver through the issuance of commercial paper and effectively reduced our short-term borrowing costs by approximately 25 basis points.

During the second quarter, the Partnership repaid $250 million of maturing long-term debt with available cash and short-term borrowings. This repayment eliminated the ratings triggers that the Partnership had in its debt covenants. Our next long-term debt maturity is $225 million due in 2011. With the pending receipt of approximately $425 million from Williams, for its increased share of Overland Pass, the partnership does not anticipate any additional financing this year, but we will continue to monitor the capital markets and take advantage of opportunities that are presented.

Now Terry Spencer will provide you with an overview of the operating performance at the Partnership.

Thanks, Curtis, and good morning. The Partnership had a solid operating performance in the second quarter from all segments, driven primarily by volume increases in both the natural gas and natural gas liquids businesses from our recently completed $2 billion plus growth capital program. Similar to the first quarter, the benefit of these higher natural gas liquids volumes was offset by lower optimization margins in the natural gas liquid segment, as increasing NGL volumes from customers under fee-based contracts limited the fractionation and transportation capacity available for optimization activities.

We expect these margins to significantly improve in the near and long-term future for several reasons. First, there is a significant NGL legacy frac-only contract expiring in the third quarter of this year that will free up space at our Mont Belvieu fractionator and will be used to serve optimization and bundled service fee-based contracts.

Second, additional fractionation capacity from the 60,000 barrels per day fractionation services agreement with Targa will become available in the second quarter of next year. And thirdly, we announced last week a 15,000 barrel per day expansion of our Sterling I NGL distribution pipeline, which I will discuss in more detail later. We're well aware of the concerns relating to our tightening fractionation and transportation capacity and how it will impact our earnings. But the actions we're taking to free up capacity, allow us to maintain our natural gas liquids segment guidance for the year.

I will now briefly discuss the operating performance of ONEOK Partners' three segments. The gathering and processing segments second quarter financial results were approximately 7% higher compared with the same period last year, due primarily to higher net-realized commodity prices and higher processed natural gas volumes, offset somewhat by lower gather volumes primarily in the Powder River Basin in Wyoming.

Our process volumes continue to grow. In the second quarter, processed volumes were up 5%, compared with the second quarter of last year and up nearly 4% compared with the first quarter of this year. Processed volumes remain resilient due to our strong presence in the growing natural gas liquids-rich Bakken Shale in North Dakota and the Woodford Shale in Oklahoma.

Our gathered volumes were down in the second quarter of 2010 compared with the second quarter of 2009 due mainly to the lower Powder River volumes. However, these volumes were relatively flat compared with the first quarter of this year.

For the remainder of 2010, we expect our gathered volumes will be relatively flat to last year, due to our Grasslands plant in Williston Basin ramping up, as well as from incremental volumes as a result of the system expansions in the Woodford Shale which we announced in April, and will allow us to access available processing capacity by connecting our western Oklahoma gathering system to our existing Maidsville processing plant.

We are also maintaining our guidance for this segment, with continued growth expected in processed volumes and more than 63% of our NGLs and condensate, and 95% of our natural gas hedged for the remaining of 2010. We have placed additional hedges on for 2011, including 75% of our equity natural gas volumes and 13% of our NGLs and condensate.

Now moving to our natural gas pipeline segment. The segment had another solid quarter. Second quarter results were driven by increased contracted transportation capacity from two growth projects completed in the last half of 2009. The Midwestern gas transmission interconnection with the Rockies Express Pipeline and the Viking gas transmission Fargo lateral.

For the second quarter, our interstate and intrastate pipelines were approximately 84% subscribed under demand based rates, compared with 79% in the second quarter of 2009. Equity earnings from our 50% interest in Northern Border Pipeline for the second quarter were exceptional, doubling earnings from the second quarter in 2009 due to an increase in natural gas throughput. Northern Borders Pipelines' subscribed capacity increased in the second quarter due to strong Midwest market demand and is fully subscribed through October of this year.

Now let's move to our natural gas liquids segment. As I discussed earlier, the natural gas liquids segment benefited from higher NGL volumes gathered, fractionated, marketed and transported, primarily as a result of the completion of the Arbuckle Pipeline and the lateral pipelines on Overland Pass.

NGLs fractionated during the second quarter increased to 524,000 barrels per day, 9% higher than last year's second quarter, and almost 7% higher than the first quarter, further emphasizing that fractionation capacity continues to be tight. NGLs transported on our gathering lines were up 32% to 480,000 barrels per day, compared with 364,000 barrels per day for the same period last year. NGLs transported on our distribution lines increased 5% to 482,000 barrels per day.

Overland Pass Pipeline volumes averaged almost 130,000 barrels per day during the quarter, nearing its current capacity of 140,000 barrels per day and necessitating continued expansions, such as those announced last week. Arbuckle volumes averaged nearly 72,000 barrels per day during the quarter, in line with our expectations and is well positioned to accommodate Rockies, mid-Continent and Barnett Shale production growth in particular, as we increase our access to more fractionation capacity in Mont Belvieu.

The average price differential for ethane between the Conway and Mont Belvieu market centers was $0.16 per gallon during the quarter, compared with $0.12 for the same period in 2009. A Midwest ethylene cracker down for maintenance impacted market dynamics, especially the Conway to Mont Belvieu ethane differentials.

Since June, ethane differentials had narrowed from a high of over $0.25 but we expect these differentials to remain relatively wide from a historical perspective for the rest of this year as petrochemical demand remains robust and NGL supplies continue to grow. As I mentioned earlier these wider differentials did not translate into higher optimization margins as capacity for optimization was limited. Again, we expect these capacity constraints to be resolved as we move throughout the year and next.

Now some additional color on the NGL markets. As a feedstock to the petrochemical industry, ethane is expected to continue to be economically attractive over the heavier oil-based fees such as NAFTA, driven primarily by wide crude oil to natural gas price ratios. Petchem demand remains strong, and coupled with the price advantage of ethane expected to continue, this creates a strong incentive for crackers to utilize ethane and continue their efforts to convert to NGL feedstocks.

We still believe there are more than 100,000 barrels per day of additional ethane demand related to the conversion of heavy-end crackers to ethane, and another 100,000 barrels per day of excess ethane cracking capacity available in Canada.

There's been a lot written about the potential for a glut of NGLs, specifically ethane. In our view, we believe that ethane supply and demand will remain relatively balanced over the next couple of years, especially when you consider that, first according to the production data we have studied, decline rates in many NGL-producing areas are much steeper, certainly in the double digits per year, and have been masked by the increase in production from shale development. We believe that the decline in existing production, combined with demand growth will absorb much of the new supplies coming online.

Secondly, petchems are stepping forward, not only in converting their crackers to lighter end fees, but are also seriously considering demothballing existing plants, thus creating incremental demand for NGL. Third, a large petrochemical company has noted that ethylene demand growth is occurring in South America as its economy improves. Canadian demand for ethane is also strengthening as projects are emerging that would enable US ethane suppliers to serve available fraccing capacity in Canada.

While NGL supply and demand will continue to be the subject of discussion and debate within our industry, we will remain focused on our customers, providing them with reliable and valuable non-discretionary fee-based services.

With increased natural gas and natural gas liquids production from the shale plays, more specifically in the Bakken Shale, there's an increased need for NGL takeaway capacity. Producers continue to aggressively develop NGL rich natural gas from crude oil producing wells in the Bakken and the Three Forks formation, which led us to announce several new projects. First the Bakken NGL Pipeline. A 600-mile pipeline with capacity to transport up to 60,000 barrels per day, of unfractionated NGLs from North Dakota to the Overland Pass Pipeline near Cheyenne, Wyoming. Supply commitments are anchored by NGL production from our own natural gas processing plants, including the Grasslands plant and the new Garden Creek processing facility is also well-positioned to serve new developments in the Niobrara shale emerging in eastern Wyoming and northern Colorado. We also plan to expand Overland Pass Pipeline to 255,000 barrels per day from 140,000 barrels per day and as well expand our NGL fractionation capacity in Bushton, Kansas to 210,000 barrels per day, from 150,000 barrels per day. We also announced plans to expand our existing Sterling I NGL distribution pipeline, increasing its capacity by 15,000 barrels a day, which will be supplied by the Partnership's mid-Continent NGL infrastructure, enabling us to transport additional NGL purity products for our customers under fee-based contracts, and increase the capacity available for our optimization activities.

The Sterling I expansion will begin later this year and is expected to be completed in the second half of 2011. We also continue to evaluate additional expansion of our mid-Continent to Gulf Coast NGL distribution pipeline capacity based upon demand for our services.

As Curtis discussed we have increased our capital expenditure guidance by $115 million to $477 million for 2010. As these newly announced projects progress and the material purchase schedules become finalized, as well as announcing additional new projects, we may adjust these estimates later in the year.

Finally, a few comments on Williams exercising its option to increase its ownership of Overland Pass pipeline to 50%. As John mentioned, we have a strong partnership with Williams, and we are both committed to growing Overland Pass. Upon closing the transaction and acquiring 50% ownership, Williams has the option to become operator and may very well elect to do so. That's okay with us. Williams, like ONEOK, is an excellent pipeline operator. John, that concludes my remarks.

Thank you, Terry, and congratulations on another good quarter. Now, Curtis will review ONEOK's financial performance, and then turn it over to Rob who will then review ONEOK's operating performance. Curtis.

Thanks, John. ONEOK's net income for the second quarter was $41.7 million or $0.39 per diluted share, unchanged from second quarter 2009. Consistent with our guidance, ONEOK increased the dividend $0.02 to $0.46 per share for the second quarter 2010. This is the ninth dividend increase since January 2006, and it represents a cumulative 64% increase over that time. We remain committed to our targeted long-term dividend payout ratio of 60% to 70% of recurring earnings.

We have reaffirmed our 2010 financial guidance, and continue to expect net income to be in the range of $300 million to $335 million for the year. Rob will provide more details on the drivers of this financial performance in a few minutes.

We currently estimate standalone cash flow before changes in working capital to exceed capital expenditures and dividends by $215 million to $250 million. By virtue of ONEOK's general partner interest and significant ownership position, ONEOK received $76 million in distributions from the partnership during the second quarter, a 10% increase from the second quarter of 2009. At the Partnership's estimated distribution level, as detailed in the 2010 guidance, ONEOK expects to receive approximately $304 million in distributions for 2010, a 9% increase over 2009.

At the end of the second quarter and on a standalone basis, ONEOK had no short-term debt outstanding, $1.2 billion available on our credit facility, $100 million in cash and cash equivalents, and approximately $340 million of natural gas in storage. ONEOK's standalone debt-to-equity remains 39%, below our 50-50 debt to equity target. We currently project short-term borrowings to remain below $300 million for the remainder of the year. Our next scheduled debt maturity is not until 2011, when $400 million comes due. ONEOK's significant free cash flow and financial flexibility provide us with opportunities to make acquisitions, increase our investment in ONEOK Partners, increase future dividends or repurchase shares.

Now Rob Martinovich will provide an update on ONEOK's operating performance.

Thanks, Curtis, and good morning, everyone. Let's start with our distribution segment.

Second quarter results were significantly higher compared with the second quarter of 2009. Improved margins were driven primarily by increased revenues and a new rate structure approved in our 2009 Oklahoma rate case. By design this new rate structure reduces volumetric sensitivity by increasing fixed fees, which increases revenues in the warmer months.

Successful rate activity in all three states generated additional revenues. Expenses decreased due to lower employee-related costs, but were mostly offset by previously deferred integrity management costs that are now recovered in base rates. We continue our efforts to grow our rate base by efficiently investing capital in projects that provide benefits to our customers and shareholders. To that end, our largest efficiency project is progressing well.

We're about 50% complete on our $31 million automated meter instillation program for our residential customers in Tulsa and Oklahoma City, with completion expected during the fourth quarter. These meters will enable quicker, safer, and more efficient meter reading and provide a net reduction in expenses, while allowing us to earn a return on these investments under our new performance-based rate structure, creating a win-win for customers and the Company.

With that, I'll discuss the latest regulatory updates in our states, beginning in Oklahoma. In late January, we filed an application requesting recovery of $15.7 million in integrity management program costs that were deferred in 2009, and in May filed supplemental testimony increasing this amount to $16.7 million. On June 30, the Oklahoma Corporation Commission approved our application and billing of the new rates began July 1. The recovery of these integrity management program costs will have no impact on earnings as they are fully offset by increased revenues.

In May, Kansas Gas Service withdrew its application with the Kansas Corporation Commission to become an efficiency Kansas utility partner, due to a wide discrepancy between all parties involved, as well as a lack of participation in the program that's designed to promote energy conservation. We continue a dialogue with the commission seeking a resolution that works for all parties.

In Texas, we filed an appeal with the Railroad Commission of Texas on May 12, to increase rates by $5.3 million in our El Paso service area, after the El Paso city council denied our rate request. Hearings begin in late August, and the commission has until mid-November to make a decision. Any new rates would likely go into effect within 20 days of receiving the new rate order if a motion for rehearing is not filed.

Eight cost of service adjustments were filed throughout our Texas jurisdictions with an expected total annual impact to earnings of approximately $1.7 million. The 2010 impact was previously incorporated into our guidance.

Finally, there has been active interest by the Railroad Commission of Texas to initiate a rule-making procedure proposing the replacement of steel natural gas service lines. We agree that replacing aging infrastructure is important but believe that replacing bare steel service lines as opposed to coated steel service lines should be the focus. A small percentage of Texas gas services service lines are bare steel pipe. This proposal is still in the development stages by the Railroad Commission of Texas and any capital expenditure impact associated with replacing lines would be recovered through the regulatory process.

For 2010, we remain confident in our $223 million operating income guidance for our distribution segment.

Now let's turn to energy services. Our second quarter results were as expected, driven primarily by lower transportation margins due to tighter mid-Continent to Gulf Coast location differentials and lower realized seasonal storage differentials and marketing margins. In addition, energy services had a decrease in premium services revenues. While the volumetric level of contracted premium services was about the same as last year, revenues were lower due to flat forward commodity prices and reduced market volatility.

Our natural gas in storage at the end of the second quarter was about 50 BCF, down from last year's 69 BCF due primarily to the year-over-year reduction of lease storage capacity. We currently have 75 BCF of storage capacity under lease, compared with 83 BCF at the end of the second quarter of 2009. On July 30 2010, we had approximately 55 BCF of gas in storage.

As part of our ongoing realignment of storage and transportation capacity to meet the requirements of our premium services customers, we're on track to reduce our storage capacity to 71 BCF by the end of this year, and to 65 BCF by the end of 2011. We expect our long-term transportation capacity to be at 1.3 BCF per day by the end of 2010, and approximately 1 BCF per day by the end of 2012, compared with our current long-term transportation capacity of 1.4 BCF per day. This capacity reduction effort targets those assets with lower unit margins.

Our 2010 earnings pattern is returning to a more normal pattern of higher first and fourth quarter earnings, driven by the sale of natural gas related to winter weather, which follows the load profile of our core customers, the LDCs. Looking at the second half of the year, we continue to expect the balance of the summer to be challenging, with tighter natural gas location differentials and limited optimization opportunities as a result of reduced market volatility. For the fourth quarter, we expect tighter seasonal storage differentials compared with 2009, and reduced premium services revenues as a result of flat forward commodity prices and reduced market volatility.

Seasonal storage differentials have tightened over the past few months as a result of the extreme heat that is limiting storage injections due to the increased natural gas demand for cooling. Storage balances will be more than adequate to meet winter demand, but storage has not filled up as quickly as anticipated, thus limiting downward pressure on summer prices, which has resulted in the tightening of the seasonal differential. The heat has kept summer prices strong, while winter prices have fallen as the marketplace has become comfortable that the combined capabilities of gas and storage and flowing gas will cover winter load requirements.

For the November and December withdrawal period, approximately 86% of our storage margins are hedged. In addition, approximately 78% of our transportation margins are hedged for the balance of the year. We'll complete our storage hedges for 2010 as we inject gas into storage or financially, as spreads significantly widen.

For transportation, we'll continue to be opportunistic. If differentials widen in the remaining summer months, we will put additional hedges in place. If they don't, we will optimize our position in the daily marketplace. For 2011, we have hedged approximately 30% of our transportation margins for the year, and approximately 71% of our storage margins for the first quarter. We expect energy services to achieve its 2010 earnings guidance of $107 million in operating income. John, this concludes my remarks.

Thank you, Rob. Congratulations to you and Pierce, Chuck, Pat on a good quarter. Obviously, we're very optimistic about our future. Not only have we delivered on our past promises, we've also developed new and exciting growth projects. Earlier in the year, our $300 million to $500 million annual growth spending lacked specificity, at least publicly. At mid-year, our $1.1 billion in announced projects are well-developed, well-funded and backed by commitments from key customers.

We also continue to be active on the mergers and acquisitions front. If you know our history, you know that almost all of our growth between 1999 and 2005 was the result of acquiring assets, allowing us to develop the capability to acquire, integrate and operate those assets. Along with the discipline to not overpay for them while taking into account the embedded and sometimes unseen growth potential that many acquisitions present.

While we have not completed any transactions lately, we remain active, evaluating most of the access to come to market, and many that don't, looking for the right ones that will create long-term value for our customers, our investors and our employees.

And finally, on that point, I'd like to thank our more than 4,700 employees who continued contributions create value for our investors and our customers. And I'd like to thank all of them for their commitment, their continued dedication and hard work. And with that, Operator, we're now ready to answer any questions.

(Operator Instructions)

Our first question comes from John Tyson with Citi.

Good morning, gentlemen.

Good morning, John.

Terry, I guess this question is for you.

In the NGL segment at OKS, volumes on-- for fractionation have continued to be strong steadily growing over the last few quarters. However, if you look at NGL sales and NGLs transported over distribution lines, out of this segment-- out of the NGL segment-- they've been a little more variable where they were strong in the fourth quarter, came down in the first quarter, and then made a rebound back up in the second quarter.

Can you just give us some color as to what's going on there? And what's driving those-- that variability?

Sure, John.

You know, we have our mid-Continent infrastructure connected to these distribution pipelines, like our Sterling pipeline system, for example. And then we have our-- what we call our north system pipes, where products will move into the Conway market area, through those pipes. Through our Sterling pipelines we'll move product into the Mont Belvieu area.

But we have another pipe called our north system, which is the pipeline system we acquired from Kinder Morgan a couple years back, where we moved products to the Midwest; and we moved normal butanes, and we moved propanes. And so that pipeline is creating some of that variability that you're seeing.

When you look at NGL sales out of this segment, what is-- because it's pretty clear on the gathering and processing side what NGL sales are related to, but I guess in this system it's a little bit different-- can you describe what you're actually doing for NGL sales?

Is that more related to the optimization or the basis differentials, that you're able to take advantage of mid-Continent to Mont Belvieu, or is that strictly just selling NGLs into petrochemical companies?

It's actually a combination of both. The primary-- the lion's share of that volume is from our well-- our plant tailgate purchases, if you will, from our-- the processing plants that are connected to our supply infrastructure. We'll purchase those barrels on an index basis, if you will, or an opus basis less a fee. That's -- and then we-- then in turn sell those barrels after we purchase them.

So, you'll see those-- you'll see that volume fluctuate from time to time as the production moves up and down.

Will that go up and down if you're putting NGLs into storage and taking them out of storage? Will that have an impact at all?

Yes, it could have some impact. I mean, you have to-- when we do and calculate our supply WACOG, we will factor in barrels that we withdraw. It will be valued at a WACOG; and that does affect our cost of goods sold, and obviously affect what we reflect in terms of sales.

And then, lastly, when your-- when this legacy fractionation contract rolls off in the third quarter, would we expect both NGL sales and NGL fractionated volumes to go up, or just mainly NGL sales?

Well, since it's not our-- it is not NGL fractionated capacity that we operate, you-- that will not be reflected as an increase in fractionation volume. Where you'll see the impact, you'll see it in the sales, and you'll see it in the gathering or transportation throughput. You'll see an increase there. As we-- what we intend to do is move more barrels down our Arbuckle Pipeline to fill this capacity. So, you'll see that increase in volume reflected there.

Which is the reason you pointed out it's a frac-only contract. There's no transportation or gathering associated with those barrels currently.

That's correct.

Got it. That helps. Thanks, guys.

Let me make sure-- let me just clarify one thing. When this contract-- I just want to make sure I'm clear on this. When this contract expires, what you-- you will not see a net increase in fractionation volume, because we're basically replacing it. So, you'll see it in these other places that I indicated earlier. Just wanted to make sure we're all clear on that.

No. That's clear.

Got it. Thank you.

Our next question comes from Ted Durbin with Goldman Sachs.

Hi, guys.

Hi, Ted.

Just want to turn to the Bakken projects. Can you give us a little sense of the counter parties, what kind of contracts you have there? Can you talk about what the volumes are like now, where you see them going?

We've heard about another pipeline that's proposed to take the liquids to the north. Is there enough volume to fill both?

I think Terry is in the best position to really address both of those questions.

Well, I think clearly, the potential is there to fill both pipelines, and relatively quickly. And when I say quickly, I'm talking over the next two, three, four years. It's very possible these two pipelines could be built.

When we look at our contracts, and the type-- the nature of the parties that we're dealing with, we're dealing with a mix. A lot of them are independents. Some of them are large independents. Some of them have a very extensive position-- acreage position in the Bakken for many, many years. Some of them are new entrants into the play.

So, we've got a mix-- there are actually some what I would classify major independents are in there as well.

Our contracts are primarily a percent of proceeds contracts. They are on dedicated acreage to us, and we have a very sizeable dedication position. That's what's making all this possible for us. The contracts will be a mix of term. Some will be long-term beyond-- well beyond ten years. Some will be shorter term depending upon what fits the producer. So-- but they will be predominantly percent of proceeds contracts less fees.

A lot of the Bakken throughput will be from our own facilities.

Yes, in excess of 50% of the throughput we've indicated. That 60,000 barrels a day will be from our own partnership control facilities.

Got you.

Or operated facilities.

Got you. That's really helpful. Thank you. And then if I could just ask one more question in terms of-- you talked about the chemical demand in some of the ethylene crack outages. I mean, where do you see the industry able to run in terms of utilization rates? How hard can they run as we see all this extra supply coming on from the extra liquids drilling?

You know, today-- if you look through 2010 year-to-date, you're averaging about 88%. That's your petrochemical utilization rates. We've been periods of time well above 95%; not for very long periods of time.

The question is whether that's sustainable. So, you can see significant demand coming just from increased utilization.

I think the other places, as I indicated in our comments, where we're really seeing a potential pop, are in-- Canada and South America, which are markets that we have an advantage, or at least that our petrochemical businesses have an advantage of serving. We see-- as you see that project that was indicated earlier out of the Bakken that could-- that goes north to serve petrochemical facilities in Canada is a great example of petrochemical facilities needing more products and willing to step up and make commitments necessary to do that.

Okay. Thanks a lot. Those are my questions.

Our next question comes from Andrew Dunlap with ASV.

Good morning. These are all impressive projects, and I'm just curious if you can comment, John, on what you think the rate of return on the $730 million at the higher end might achieve?

Andrew we've seen these, as we've indicated in our release as being in the five to seven times EBITDA.

Okay.

Typical and consistent with some of our past projects as well.

And then, with respect to the Sterling and your comments on the potential difficulties to your optimization business, is there pressure to close the Mont Belvieu Conway gap in the sense that if you don't do it quickly enough, a competitor will do it, and make your strategic and business life a little bit more challenging?

Always. You know, that's an indication of a wide -- consistently wide basis, an indication that infrastructure needs to be built, service needs to be provided. So that's -- if you look at every pipeline we've built, particularly as it relates to the NGL piece that's exactly what we've done and why we've done it.

So not only are we looking at expanding -- have we announced that we're expanding Sterling, but we continue to look at our existing infrastructure between those two points and opportunities to expand, because we are the best situated to provide that expansion in industry.

I would agree with that, and that's why I found Sterling to be small relatively to the potential market. I mean, I guess you could even imagine 50,000 or even 100,000 type of expansion. I don't -- I guess the question here is how much -- if we look over the next three to five years, how much capacity is needed to narrow that differential to a more normal -- to a level that's acceptable from the producers?

Right. So part of this -- part of the answer gets to point Terry was making about, you know, this NGL glut, this perception of an NGL glut and not taking into account the decline rates that we're seeing, but Terry probably can provide a bit more color to that.

Well, you know, the 15,000 barrels a day is just one of the low-hanging fruit projects that we have to create more capacity. If you look at Arbuckle, when we built Arbuckle and it's a 160,000 barrels a day pipeline and we're moving about 70,000 to 72,000 barrels a day down it right now, it in effect is a north south pipe. It's just moving raw feed as opposed to purity products so we have a considerable amount of capacity that we've not been able to utilize in Arbuckle because we've been limited in terms of frac capacity at Mont Belvieu. So, you follow me?

Yes I do, so that will change -- that problem will take care of itself.

That problem is set up to take care of itself with a contract expiration and the 60,000 barrel a day contract with targe and we will also take care of part of that problem when we expand the Bushton fractionators. So the unique position is of course having the gathering, the fractionation and the transportation, whether it be on raw or whether it's on finished product, and balancing all those pieces together.

That's what gives us the advantage of finding the most economical way to expand the system to provide the best service at the lowest cost to the producer.

I understand. Let me just make sure I do understand this. So that 60 that will be available of additional fractionation capacity will be, in effect, volumes that you back out of Conway, use Arbuckle to take down to the Gulf Coast, and that will then free up Bushton plus the Sterling expansion, in the sense that there's some double counting, so to speak? Am I understanding it correctly?

Well, I think, you know --

We can do it offline if you want.

What it obviously does is allows us to frac more barrels in Belvieu than we're currently fraccing in Conway, which puts more finished product at Belvieu than at Conway, which should reduce the basis.

I understand. I understand. And how long do you think it takes before that gets to a more normal level? Two years?

Well, I mean, historically we've actually seen it move pretty quick, in months. Okay. My guess is that I would say that it would take some time, probably six months to a year probably to see that -- for that impact in the marketplace to settle out. So yes, six to 12 months, but you could see some impact immediately.

Yes. I guess, my estimation would be, once the infrastructure is in place, and you can rest assured we're doing everything we can to get it in place as quickly as we can, I think it will narrow or it will tighten, I don't know what the right word is, sooner rather than later.

I'd agree.

Great. Thanks for the comments.

Our next question comes from Xin Liu with JPMorgan.

Morning guys.

Hi, Xin. How are you?

Good. So for the frac contract that's going off, what is the capacity we're talking about?

I would not release that and we don't intend to .

Okay. And you mentioned that you were doing some incremental margins on bundled services and option for optimization. Can you break down what percent you think you will get from bundles services versus optimization?

You know, we've not disclosed that information either. What I can say is that at least initially most of that capacity will be optimization. But over the long-term, it will move toward a mix of optimization and the bundle fee-based service contracts.

Okay. And just a question. Overland Pass, when I look at your guidance, it sold 50% and the earnings impact is just offsetting the interest expense. It looks -- the earnings looks rather low. Can you comment on that?

I guess if you're saying the earnings on Overland Pass are low?

Yes. You sold 50%, and that lost earnings is just off --

Right. Let's think back to my comments about wanting to make sure those incremental barrels in the Rockies came to our structure in the mid-Continent. So it should not -- and the reason we wanted that is, those are our own -- 100% owned assets. So yes, the money we make off of Overland Pass is less than the money we make off of our fractionation gathering and transportation.

Okay. That's helpful. Thanks.

Thank you.

Our next question comes from Mark Brightman with Madison Williams.

Good morning. Most of my questions have been answered. But with respect to ONEOK Partners, I think Terry alluded to some of the sources of a stronger second half, but I was wondering, could you just reconcile net income for the first six months with, say, the low end or midpoint of your full-year 2010 net income guidance, just highlighting the sources of the positive changes ?

Curtis.

Mark, there's several things going in. One of the bigger items is what Terry's comments and what my comments were focused on, which is the additional capacity that we'll have at Mont Belvieu from this frac-only contract that is expiring. That will give us the opportunity to capture some of these wider differentials that we've seen between Conway and Belvieu, which we call our optimization activities. And then further down the line, as Terry was describing, we'll see more bundle type of services between our pipeline, such as Arbuckle, and then volumes going through that frac plant -- through that frac at a more current market rate associated with those volumes.

As we described last quarter, this contract was an old legacy contract that was put in place several years ago and was out of market with rates that we're seeing today.

Yes, Curtis. I think the only thing I would add to that, which I think you really kind of already touched on, is in our gathering and processing segment for our volumes, particularly in the Bakken Shale and in the Woodford Shale in Oklahoma, those volumes continue to ramp up. So we have an expectation to realize some significant volume growth in the second half.

Okay. And most of the positive impact, I guess, from the expiring contracts will be in the fourth quarter. Is that right?

A ballpark.

Okay, great. Thank you very much.

Yes, sir.

Our next question comes from Michael Blum of Wells Fargo.

Hey, good morning, everyone.

Good morning.

Another question on the NGL. Can you just help me think about on all these NGL expansion projects, the Overland Pass, the Bushton fractioner, the Sterling expansion, how should I think about what percent of that new capacity that you'll have will you use for your own account, for lack of a better word, versus leasing that to third parties?

Well, I think a vast majority of it will be used for our own account.

It starts -- think of it this way. It starts with the answer about on the Bakken Pipeline, more than 50% of those barrels headed to Overland Pass are going to be barrels that come out of our own 100% owned processing plants.

Okay. And then as I think about the capacity that you're going to gain. So you're going to gain this initial capacity in the -- sometime in the third quarter, and then there will be another kind of step change in capacity beginning the third quarter of '11? Is that the right way to think about it?

No, we've not announced anything with respect to frac -- building a frac or expanding a frac next year.

Okay. I'm sorry. What I meant was.

Hang on a second. Other than Targa.

Right. That's what I was referring to, Targa.

That's right. That's in the second of 2011.

Okay. Okay, got it. And then just to your comments, Terry, about supply and demand for ethane. When your Bushton fractionator expansion comes on, where will those -- what's the end market for those? Where do those find a home, the ethane and the propane et cetera?

Well, I mean, it's going to go into a number of places. Let me just start at the top of the list. Obviously some barrels will go into the Conway marketplace and be consumed. Some barrels will wind up in the upper Midwest through our north system.

And then some of the barrels will wind up going through our purity products pipelines after they're fractionated down to the Gulf Coast, and then some of the barrels, then again, will move down the raw feed. Some of it will move in raw feed down our Arbuckle pipeline to access the Gulf Coast. So it's going to be placed in a number of places, not any one particular spot.

Okay. And then last question, just switching over to natural gas. You mentioned in the Powder River Basin, you're still seeing basically pretty weak environment. Can you just give a little more details in terms of what type of drilling activity you're seeing there, where the magnitude of the declines are, et cetera ?

Well it's coalbed methane gas, which once it gets established -- once you get in the out years, it goes relatively flat but until you get to that point in time, you'll see some fairly steep declines early. Drilling activity have been very mild, and it's primarily the gas net back, after you net back all the costs, you're below a level that producers feel comfortable drilling in, in that region. There's no BTU bump up. There's no processing. The gas is actually -- some of it is below a thousand BTU per cubic foot so there's not a whole lot of extra juice like we have in these NGL-rich shale plays.

Okay. Thank you very much.

Thank you, Michael.

Our next question comes from Helen Ryoo with Barclays Capital.

Yes. Good morning. My first question is related to the Sterling expansion. The 15,000 barrels per day addition, what does that represent in terms of existing capacity addition expansion on the Sterling one and two? Is it roughly about 10% expansion?

Helen, we've not disclosed that, the capacities on the pipes. We're not -- can't do it now.

Okay. Then, could you say whether the 1 and 2 both lines are just product lines or one if them is a wide great line?

Both 1 and 2 are both purity products in the pipeline.

Okay. Got it. Thank you. And then another question. Just a clarification on the Bakken Pipeline, the NGL takeaway pipeline. You said less than 50% of the volume will come from third party, but do you need to secure third party commitment before you start the construction, or is this something you can do without a secure commitment?

I would say -- Helen, I would say that we're in various stages of negotiations with these third parties. I would say we do not have to get all of them secured in order to move forward with the project.

Okay. And then the two years ago. It's going to come online first quarter of -- I guess first half 2013, so it's about two plus years of construction and permitting process. Is it --does the -- how long does the construction itself take place?

The construction itself will take place in less than a year.

Okay.

The part that takes the longest is the permitting.

Okay.

This particular pipeline relative to some of the other pipelines we built, I think, from a regulatory perspective, it's going to be in pretty good shape. We'll be dealing mostly with wildlife departments. We won't have to deal with the bureau of land management like we did on our Overland Pass Pipeline, which can -- which will help us from a timing standpoint.

Just a point of clarification, Helen, on your first question. From and economic standpoint, we can't proceed based on our own. We have as a company not made a decision whether to take -- to do that or not. We still want to see what other shippers are willing to do.

Right. And I guess finally you're selling your Bakken production -- Bakken NGL locally. And if so, going forward, would you say once this line is built, you will be taking all your barrels out, on this pipeline, or you would still be selling some locally?

Helen, we would continue to sell barrels locally. The market is saturated. The local market is relatively saturated. So we certainly have to move the excess barrels out of there. But we expect for the local sales to continue.

Okay. Great. Thank you very much.

Thank you, Helen.

Our next question comes from Tim Snider with Citigroup.

Hi, guys. A quick question on the distribution business. So, I think the rate case -- the net rate case in Oklahoma that was approved in December, you guys said it was $26 million was going to be the net impact for the whole year, right? So how much -- that $17.2 million that showed up in quarter two, how should we think about the remainder of the year? Is that $17.2 million out of that $26 million showed up in quarter two and the rest shows up in quarter three and quarter four?

That's correct. Maybe just a quick correction. The $17 million excluded any of the integrity management cost that you'd net off of that, so the $25 would include -- is a net number.

Okay. And do you know what those costs were?

Well, I do, yes, but what we released publicly is we'll be right around $26 million. And so for practical purposes, you can assume a similar amount in the third quarter.

Okay. Got it. And then how much did the fixed fee per customer go up?

It varied depending on the class of customer. For our smaller customers, plan A, it went up $2.20, and for our plan B customers, it went up about just a little bit under $7.

Okay. Thank you. That was it.

Our next question comes from Louis Shamie from Zimmer Lucas.

Hi. Great quarter. I had a couple of questions. First off just go to the housekeeping. What was the volume mix between your different contracts and the G&P segment for this quarter?

Oh, it will be in the at-a-glance table. Does anybody have that close by ?

It's going to be around 60% to 64% sea-based and 32% [pop] and the balance [people].

Okay, great.

Louis, it's on a volume basis.

You're right, yes. That's what I was asking. And then in terms of the optimization business, how should we look at it? With this frac-only contract throwing off, will that bring you back to kind of the same capacity for that business as you had, let's say in 2009, or how should we look at this?

You capacity mean for optimizations?

Yes. I mean, the same ability to capture that basis spread.

That absolutely will enhance it considerably.

Oh, okay.

Because we'll be using that Arbuckle project as an optimization pipe.

Right.

Now, if you recall that Arbuckle pipe (inaudible) --

So currently that raw feed that you aren't able to move down Arbuckle because of the lack of frac capacity, where is that going? Is that being fractionated in the mid-Continent on your system, or --

It's being fractionated and there are also volumes yet to come. That are volumes connected to our system in the interim period.

Great.

Supply growth and volumes that are being fractionated in the mid-Continent.

Perfect. Thank you very much, guys.

Thank you. Okay. Well, thank you all this concludes the ONEOK and ONEOK Partners call.

As a reminder, our required period for the third quarter will start when we close our books in early October, and will extend until earnings are released after the market closes on November 2. Our third quarter conference call is scheduled for November 3, and we'll provide additional third quarter conference call information at a later date.

The annual ONEOK, ONEOK Partners investor day is scheduled for Tuesday October 5 in New York. A save-the-date notice went out last week and will be following up with additional information, times and meeting locations in the next month or so.

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

Ladies and gentlemen, this does conclude today's presentation. You may now disconnect.