Dan Harrison – VP, IR and Public Affairs John Gibson – Vice Chairman, President and CEO Rob Martinovich – SVP, CFO and Treasurer Terry Spencer – COO, ONEOK Partners Pierce Norton – COO

Stephen Maresca – Morgan Stanley Craig Shere – Calyon Securities Ted Durbin – Goldman Sachs John Tysseland – Citigroup Michael Blum – Wells Fargo Yves Siegel – Credit Suisse Monroe Helm – Barrow Hanley Helen Ryoo – Barclays Capital Andrew Gundlach – First Eagle Bernie Colson – Oppenheimer Rick Gross – Barclays Capital

Good day ladies and gentlemen and thank you for your patience. You joined the first quarter 2011 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 be given at that time. (Operator Instructions) As a reminder, this conference call may be recorded. I would now like to turn the call over to your host, Mr. Dan Harrison. Sir, you may begin.

Thank you. Good morning and thank you everyone for joining us. A reminder that 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’s Vice Chairman, President and CEO and ONEOK Partners’ Chairman, President and CEO. John?

Thanks Dan. Good morning and thank you all for joining us. We appreciate your continued interested and investment in ONEOK and ONEOK Partners. Joining me today are Rob Martinovich, Chief Financial Officer of both ONEOK and ONEOK Partners; Terry Spencer, ONEOK Partners’ Chief Operating Officer; and Pierce Norton, ONEOK’s Chief Operating Officer. Before we begin, I would like to make a few comments about our announcement two days ago to build a new NGL pipeline and fractionator. Then, I will briefly review our first quarter performance, discuss our 2011 earnings guidance, turn things over to Rob, Terry and Pierce to review our financial and operating results in more detail, and then make a few final comments before taking your questions. Our decision to build a new pipeline between Medford, Oklahoma and Mont Belvieu, Texas and a new fractionators at Mont Belvieu was driven by a market demand, in particular from producers, processors and petrochemical companies. This new pipeline project will alleviate the infrastructure constraints that currently exists for producers and processors in the Mid-Continent and limit the ability of NGLs to get from the Mid-Continent to the Gulf Coast. We will also build additional fractionation capacity on the Gulf Coast to serve the growing NGL feedstock needs of petrochemical companies. Both projects are yet another extension of our NGL infrastructure and will provide producers, processors, and customers with the critical services needed to monetize their respective investments and meet their customers’ needs. Terry will provide additional information about these new NGL investments and we will answer your questions later in the call. Now, let’s talk about our first quarter results. We had a successful quarter at ONEOK and ONEOK Partners, while continuing to meet some challenges in the marketplace. ONEOK Partners first quarter performance was exceptional, posting an 80% earnings increase from last year’s first quarter. These strong results were led by our natural gas liquids business, which benefited from favorable natural gas liquids price differentials and having more fractionation and transportation capacity available to use for optimization activities. In spite of extremely cold weather and record snowfalls as well as some NGL market disruptions caused by fire at a competitor’s facility, our assets and people performed extremely well. The partnership continues to benefit from the new assets built during our $2 billion growth program that was completed in 2009. And we are executing on the next tranche of growth projects that Terry will discuss later. Our ONEOK Distribution segment performed as expected, but was adversely impacted by higher operating costs, primarily due to higher share-based compensation expenses in the quarter that Rob will explain in a few minutes. Energy services had a good quarter in a very difficult industry environment. Seasonal storage and location price differentials remained extremely narrow and were mitigated somewhat by our ability to place hedges. As we stated in our news release, we are reaffirming our financial guidance for the year at ONEOK and at ONEOK Partners. We believe the continued strong performance at ONEOK Partners will offset lower expected results and energy services. Due to current and projected market conditions, we now expect energy services 2011 operating income to be at the low end of the earnings range of $75 million to $125 million, which is the range we announced in 2009 with our plan to reduce our contracted storage and transportation capacity. Seasonal storage and location differentials are not where we expected them to be, and with the continued oversupply of natural gas, we don’t expect them to improve significantly during the rest of the year, absent of course a weather-related event. Pierce will explain energy services performance and outlook in more detail. Rob will now review ONEOK Partners’ financial highlights, and then we will ask Terry to review the partnership’s operating performance. Rob?

Thanks John and good morning to everyone. In the first quarter ONEOK Partners reported net income of $151 million or $1.16 per unit compared with last year’s first quarter net income of $84 million of $0.57 per unit, an 80% year-over-year increase. Distributable cash flow in the first quarter was $185 million, a 51% increase compared with first quarter 2010, resulted in a coverage ratio of 1.30 times. We reaffirmed the partnership’s 2011 net income guidance in the range of $525 million to $575 million, with distributable cash flow in the range of $625 million to $675 million. We expect the partnership’s interest expense to be approximately $12 million higher compared with what we announced in January. This amount will be offset by a projected $12 million increase in equity earnings for Overland Pass Pipeline. This line item shift reflects financing of Overland Pass Pipeline at the ONEOK Partners level versus at the joint venture level that we assumed in our initial 2011 financial guidance Pending Board approval, the partnership anticipates increasing the distribution of $0.01 per quarter for the remainder of 2011, building on the first quarter of 2011 distribution increase to $1.15 per unit to be paid this month, which marks the 18th distribution increase since ONEOK became sole general partner five years ago, a 44% increase. We have hedges in place to lock in margins on our expected equity volumes in the naturals gas gathering and processing segment, which is the most sensitive to commodity price changes. For the remainder of 2011, we have hedged 68% of our expected NGL and condensate equity volumes at an average of $1.40 per gallon and 78% of our expected natural gas equity volumes at $5.60 per MMBtu. For 2012, approximately 52% of our expected NGL and condensate equity volumes are hedged at an average price of $1.82 per gallon. For 2013, we have hedged approximately 5% of our expected NGL and condensate equity volumes at an average price of $2.55 per gallon. In January, we completed an offering of $1.3 billion of senior notes consisting of $650 million of five-year senior notes at a coupon of 3.25% and $650 million of 30-year senior notes at a coupon of 6.125%, generating net proceeds of approximately $1.28 billion. As a result of the debt offering, we repaid all of our outstanding commercial paper and the $225 million senior notes that were due in March 2011 and we will use the remaining funds for general partnership purposes, including our 2011 capital spending program. At the end of the first quarter, we had $617 million [ph] in cash and no commercial paper for borrowings outstanding under the $1 billion revolving credit agreement that expires in 2012. On March 31st, the partnership had a debt-to-capital ratio of 54% and debt-to-EBITDA ratio of 4.2. The majority of the Sterling III and Mont Belvieu-2 projects estimated capital expenditures will be in 2012 and 2013, with a minimal amount in 2011. Therefore, we do not anticipate any additional financing this year, but we will continue to monitor the capital markets and be prepared to take advantage of any opportunities. Now, Terry will review the partnership’s operating performance.

Thank you, Rob and good morning. The partnership had an exceptional first quarter. Operating income increased almost 50% compared with the first quarter of 2010, driven primarily by higher optimization margins in the natural gas liquids segment due to higher NGL price differentials between Conway and Mont Belvieu and increased fractionation and transportation capacity available for NGL optimization activities as a result of a large frac-only contract that expired in September of last year. Earnings also increased as a result of contract renegotiations for our exchange service activities in our NGL business as well as higher commodity prices in the natural gas gathering and processing segment. I will briefly discuss the operating performance for the three segments, followed by a review of the current NGL market environment and close with a status report on our growth projects. The natural gas gathering and processing segment’s first quarter financial results were higher than the same period in 2010 due primarily to higher net realized commodity prices and changes in contract terms. Processed volumes were down slightly due primarily to adjustments to drilling schedules by Western Oklahoma producer and weather-related outages offset partially by increased drilling activity in the Bakken Shale. Gathered volumes were lower due to continued production declines in the Powder River Basin in Wyoming, adjustments to drilling schedules by adjustments to drilling schedules by a Western Oklahoma producer and weather-related outages, offset partially by increased drilling activity in the Bakken Shale. Although natural gas gathered and processed volumes were down in the quarter, we still expect to achieve the volume estimates we communicated to you at the beginning of the year, processed volumes to be up 11% and gathered volumes to be up 5%, with growth in the Cana-Woodford Shale more than offsetting declines in the Powder River Basin at Wyoming. Now, moving to our natural gas pipeline segment. First quarter results were slightly lower. Transportation margins were down approximately 4% due to decreased contracted activity on Mid-Western and less interruptible volumes due to narrower regional natural gas price differentials. As a reminder, approximately 84% of our pipeline’s subscribed capacity directly serves end users such as natural gas distribution companies and electric generators that need gas to operate their businesses regardless of regional price differentials. And approximately 90% of our pipeline and storage capacity is contracted under long-term firm contracts. Northern Border’s earnings were up almost 40% due to an increase in contracted capacity from continued strong Mid-West market demand, with most if not all of Northern Border’s capacity contracted through March of 2012. Now, let’s move to our natural gas liquids segment. The segment benefited from more available fractionation and transportation capacity for optimization activities and favorable NGL price differentials. Contract renegotiations associated with our exchange service activities also helped earnings. The first quarter Conway-to-Mont Belvieu ethane price differential was $0.15 per gallon compared with $0.08 for the same period in 2010. We fractionated approximately 488,000 net barrels per day, almost 90% of capacity, further evidence of how tight frac capacity. We expect it to remain tight, but gradually improve as new frac capacity comes online over the next couple of years. Fractionated volumes were relatively flat in the quarter due primarily to weather-related outages in the Mid-Continent and an unplanned outage at Mont Belvieu. NGLs transported on our gathering lines were 397,000 barrels per day and reflect the exclusion of Overland Pass volumes because of its deconsolidation last September. If you back out the Overland Pass barrels for the comparable quarter last year, volumes were up as a result of increased volumes gathered on the Arbuckle Pipeline and in the Mid-Continent. Arbuckle volumes have increased over 150,000 barrels per day. Current Arbuckle capacity is approximately 180,000 barrels per day, increasing to 240,000 barrels per day in 2012. The pipeline remains well positioned to accommodate NGL volume growth from Rockies, Mid-Continent and Barnett Shale production growth for the rest of the year, helped by more fractionation capacity in Mont Belvieu when the fractionation service agreement with Targa gives us access to 60,000 barrels per day of additional fractionation capacity. Arbuckle Pipeline has emerged as a key connector of Mid-Continent NGL production to Gulf Coast NGL fractionation. Accordingly, Arbuckle has expanded our Mid-Continent to Gulf Coast optimization capability and allowed us to capture more location class differential opportunities. However, Arbuckle capacity is primarily earmarked for NGL supply growth from new natural gas processing plant development in the Oklahoma and Texas Panhandle unconventional resource plays. We will talk more about Mid-Continent to Gulf Coast capacity needs in a moment. Now, a brief summary of the NGL market. On the demand side, the petrochemical industry continues to find ways to consume more ethane due to its strong price advantage oil-based feedstocks. Accordingly, we see strong ethane demand from the petrochemical as the ethane to crude ratio remains relatively low and regional processing and NGL infrastructure expansions will continue to be needed. The recent announcements of petrochemical plant restarts expansions and development of new world-class petrochemical plants is further evidence of the growing need over the next three to five years for price advantaged light end NGLs such as ethane and propane for feedstocks. On the supply, producers continued focus on liquids-rich plays such as the Bakken, Cana-Woodford, Granite Wash, and the Eagle Ford Shales. While NGL growth continues at a rapid pace, much of the growth and volumes offsets the inherent natural decline rate of the base natural gas production, which exceeds 20% per year and getting steeper according to some experts. Now, a few comments on the sale of several growth projects. On Monday, we announced we are building a new NGL pipeline and fractionators. These projects, the 570-mile Sterling III Pipeline and the Mont Belvieu-2 fractionators will provide greatly needed infrastructure will alleviate capacity constraints between Conway and Mont Belvieu as well as provide capacity to serve Mid-Continent NGL supply growth. The new Sterling III pipeline doubles our current NGL capacity between Medford, Oklahoma and the Mont Belvieu markets. In conjunction with the reconfiguration of the existing Sterling I and II pipelines, the new pipeline will enhance our ability to transport unfractionated NGLs and products by providing us the flexibility to move multiple products through either of the Sterling Pipelines. Given our view of the new NGL supply development in the Mid-Continent and elsewhere, we are confident in our ability to fill the pipeline and our fractionator, which would come online in 2013. Now, an update on our previously announced projects. As we execute on another major capital spending program, we remain focused on applying the lessons learned from our last series of projects to ensure better cost and schedule management. While our contractors are important to the overall success of these projects, it’s our employees who are the difference makers during the construction phase, and we plan to have more of our employees on the ground this time around. We have also applied our lessons learnt to the regulatory and route planning process. We have used fixed price turnkey construction contracts on all three processing plants, have already purchased the steel pipe for the Bakken NGL pipeline, minimized winter construction periods and have a more favorable construction labor environment, which helps keep costs down. That does not mean we won’t face potential challenges with weather and construction labor housing and other issues that inevitably surface during construction. Accordingly, we have included contingency costs in our estimates. In aggregate, we plan to invest approximately $1.5 billion to $1.8 billion in Bakken Shale related projects to build midstream infrastructure, allowing producers who have dedicated their volumes to our systems to fully monetize their oil and natural gas reserves. Acreage dedicated to our systems under long-term gas supply contracts has grown steadily to approximately 1.7 million acres today. Our gathering and processing growth projects include three 100 million cubic feet per day of natural gas processing plants, the Garden Creek plant and related infrastructure and the Stateline I and II plants, which will quadruple our processing capacity in the region to nearly 400 million cubic per day. We are full steam ahead constructing the Garden Creek plant and are progressing through the permitting process for the Stateline I and II plants. And we are currently on schedule and within our proved capital budget. Our NGL infrastructure projects related to the Bakken growth which include the 500-plus miles 60,000 barrels per day Bakken Pipeline are in various stages of development, engineering, design, procurement and write-away acquisition, and all are progressing within our expected timelines and capital budgets. In addition to growth projects we have already announced, we are continuing to evaluate a lengthy backlog of natural gas and NGL-related infrastructure projects including investments in natural gas pipelines and NGL storage facilities. John, that concludes my remarks.

Thank you, Terry and congratulations to you and Sheridan and Curtis for an outstanding quarter. At this time, we will ask Rob to review the financial performance of ONEOK and then we will pass it to Pierce for him to review the operating performance of ONEOK. Rob?

Thanks John. ONEOK’s first quarter net income was $130 million or $1.19 per diluted share compared with $155 million or $1.44 per diluted share in the same period last year. Operating costs were higher primarily due to increased share-based compensation costs as well as increased employee benefit costs and higher property taxes in the ONEOK Partners segment. Share-based compensation costs include stocks issued to employees and Directors under the company’s long-term incentive plans and our employee stock award program that awards one share of stock each time ONEOK stock closes at or above a new $1 benchmark. The program began in 2004 to reward employees for their contributions to the company’s success. Since then, we have awarded 44 shares of stock and in the first quarter, we awarded 11 shares of stock at a cost of $5 million. ONEOK’s first quarter 2011 standalone free cash flow before changes in working capital exceeded capital expenditures and dividend payments by $117 million. This includes the benefit of bonus depreciation we recorded as a result of federal income tax legislation. Bonus depreciation will continue to benefit us throughout 2011. As general partner and significant limited partner owner, ONEOK received $80 million in distributions from the partnership for the first quarter of 2011, a 10% increase from the same period last year. At the partnership’s planned 2011 distribution level, ONEOK will receive approximately $328 million in distribution this year, an 8% increase over 2010. ONEOK’s income tax is on the distributions from the LP units it owns are deferred, contributing to ONEOK’s strong free cash flow. ONEOK’s liquidity position is excellent. At the end of the first quarter, on a standalone basis, we had no short-term debt, $1.2 billion available on our existing credit facilities, $253 million of cash and cash equivalents and $174 million of natural gas and storage. In April 2011, we repaid $400 million of maturing senior notes of available cash and borrowings from our commercial paper program. And last month, we completed a new five-year $1.2 billion unsecured senior revolving credit facility replacing one that was to expire in June. Our standalone long-term and total debt-to-capitalization ratios at March were 38%. ONEOK’s significant free cash flow and excellent liquidity position give us tremendous financial flexibility. As you know, the Board authorized a $750 million share repurchase program for 2013 with an annual maximum of $300 million. To date, we have not purchased any shares, but continued to evaluate the opportunity to do so. This authorization is another option to return value to shareholders. However, we also have other alternatives such as acquisitions, increasing our investment in ONEOK Partners or further increasing dividends. Our 2011 guidance anticipates dividend increases of $0.04 per share twice a year during 2011. We increased the dividend in January and the Board will consider another one in July. This is consistent with our forecasted 50% to 60% dividend increase between 2011 and 2013. We are reaffirming ONEOK’s 2011 net income guidance in the range of $325 million to $360 million. We expect higher earnings in the ONEOK Partners segment that will offset the lower expected earnings in the energy services segment that John mentioned earlier. Our financial guidance reflects standalone free cash flow of $235 million to $275 million, which includes the benefit from the bonus depreciation I mentioned earlier. This range does not include any share repurchases. So, obviously, if we were to repurchase shares under our authorized program, free cash flow would be reduced. Now, Pierce will update you on ONEOK’s operating performance.

Thanks Rob and good morning everyone. Let’s start with our distribution segment. First quarter 2011 earnings were lower primarily because of higher operating costs. As Rob mentioned in his comments, operating expenses were higher this quarter due to share-based compensation costs. Because the distribution segment has most of ONEOK’s employees, it experienced the largest portion of the share-based compensation cost, which accounted for $4.6 million of the quarter-over-quarter operating expense difference. Depreciation expense was higher due to our investment in automated meter reading devices in Oklahoma last year. We also had higher regulatory amortization expense because of various revenue writer recovery mechanisms, net margin was relatively unchanged compared with the same period last year. Natural gas volumes were lower in the first quarter due to warmer weather compared with the same period in 2010, however, this decrease was moderated by weather normalization mechanism. Now, a brief regulatory update. In February, Oklahoma Natural Gas submitted its first annual performance-based rate filing. The application does not seek any modifications to customer rates that were put in place in January 2010, since Oklahoma Natural Gas’ return on equity is within the range approved by the Oklahoma Corporation Commission. Texas Gas Service made its annual gas reliability infrastructure program filing in the city of Austin and surrounding communities for approximately $1.6 million. If approved, the new rates will become effective in June. We continue our efforts to grow our rate base by investing in projects that provide benefits to our customers and our shareholders. We expect to invest $25 million this year to continue installing automated meters. To date, we have completed 31% of this year’s planned installations in areas of Oklahoma and Texas that will result in the quickest recovery of expenses and return on capital as well as reduce expenses. Our 2010 investment of $31 million to install automated meters in Tulsa and Oklahoma City resulted in approximately 57% of Oklahoma Natural’s residential customers having automated meters. These meters are safer, more accurate and more efficient, while allowing us to earn a return on these investments, creating a win-win for the customers and the company. Now, let’s turn to energy services. As expected our first quarter results were lower compared with the same quarter in 2010. This was driven primarily by lower realized seasonal storage natural gas price differentials, a decrease in transportation margins net of hedging, predominantly due to narrower Mid-Continent to Gulf Coast price differentials and a reduction in premium service margins. Let me provide you some perspective on the market this year versus last year. We experienced wider seasonal storage price differentials in the first quarter last year compared with the first quarter this year. We also were able to place more hedges on locational differentials affecting our transportation positions for last year’s first quarter. Because there was ample liquidity in the marketplace in 2008, in early 2009 with these hedges in place for 2010. Since then, liquidity and volatility have been extremely limited and it has been difficult to place forward hedges. This year’s business environment is extremely challenging. The increase in transportation top line capacity in recent years combined with an oversupply of situation from shale plays has narrowed significantly location and seasonal differentials from where they have been in the past years. As John mentioned earlier, we expect our 2011 operating income to be towards the low end of the $75 million to $125 million range we announced when we began our transportation and storage capacity realignment effort in 2009. For the remainder of 2011, we have hedged approximately 47% of our transportation margins and 54% of our storage margins. We plan to execute additional transportation and storage hedges based on the forward view of the market and the availability of market liquidity. We have a plan to deliver earnings despite the flat forward gas price curves and low volatility. We plan to maintain our existing premium service customers while adding new ones, maximize earnings through effective optimization activities, grow our market share over the electric generation customers and work for producers to nuclear supply in constrained areas. We continue to make progress on realignment of our storage and transportation capacities to meet the requirements of our premium service customers. As of April 30th, we currently have 72.6 Bcf of storage capacity under lease close to our goal of 65 Bcf by the end of 2012. And 1 Bcf per day of long-term transportation capacity with a goal of 1.1, 1.0 Bcf [ph] per day by the end of 2012. A quick update on pipeline safety. At the beginning of this year, the Pipeline and Hazardous Materials Safety Administration issued an advisory bulletin about the establishment of maximum allowable operating pressure or MAOP for regulated pipelines. This advisory required pipeline operators to rely on design construction, inspection, testing and other related historic data to determine MAOPs to verify and validate the accuracy and completeness of these records. All of ONEOK and ONEOK Partners business segments recently initiated their reviews for pipeline data and documentation used to establish our pipeline MAOPs. And we will be validating that information as we go forward with this process. John, that concludes my remarks.

Thank you, Pierce and congratulations to you also on a great quarter as well as Caron and Patrick, all doing the right things in a difficult market environment. Now, a couple of final comments before we take your questions. We are confident of our 2011 financial guidance ranges for both ONEOK and ONEOK Partners. We expect ONEOK Partners’ strong performance in the first quarter with expected volume growth to continue throughout the year and offset lower anticipated results in energy services. As Pierce mentioned, energy services has a path forward in a very difficult market consisting of tighter seasonal storage and basis spreads and lower price volatility, all due to the oversupply of natural gas because of the emergence of shale plays. However, the shale plays have benefited ONEOK Partners, affording us the opportunity to invest capital to build critical gathering and processing and natural gas liquids infrastructure, to serve natural gas producers, processors and customers. The abundance of natural gas has also brought price stability to consumers making natural gas a preferred and environmentally attractive fuel for home heating, electric power generation and in certain applications, transportation. Lower natural gas prices also make the NGLs coming from these shale plays very attractive feedstocks for the petrochemical industry. As illustrated by the expansions Terry just mentioned, that’s good for us, but more importantly, it’s good for the country. And the overall global competitiveness of the U.S. petrochemical industry and why we are so enthusiastic about natural gas liquids supply and demand. We are on track, both cost and timing with our projects. As Terry mentioned, we have applied the lessons learned from our first set of projects, which will benefit from our overall project execution. In all of our projects which now total almost $3 billion with the new ones we announced this week are consistent with our vision to create value for our customers and investors, enabling us to grow earnings and provide our owners with attractive returns. And of course, finally, I would like to thank our employees across more than a dozen states for their dedication and commitment, which create value everyday for our investors and customers. I appreciate their efforts and know that our success as a company depends on their contributions. At this time, we are now ready to take your questions.

(Operator instructions) Our first question comes from Stephen Maresca of Morgan Stanley. Please go ahead. Stephen Maresca – Morgan Stanley: Thanks and good morning everybody.

Hi Steve. Stephen Maresca – Morgan Stanley: My first question is on the petrochemical demand side and if you could provide some color as to, how sustainable you think this shift is with lot of the announcements coming out of (inaudible) and Lyondell. Do you see any shift in behavior where they are maybe willing to buy off-take under long-term agreements, and what is ethane prices hovering near 90% due into that view?

I will let Terry answer that in a more detail, but clearly, with the recent announcements, Dow and others, it’s a clear indication that just by the size of the investments that they foresee competitive, they see ethane prices favorably priced relative to alternative feedstocks, which obviously provided us a lot of confidence to move forward with our recently announced project. Terry, do you have any specifics, you would like to add?

Yes, Steve, specifically with respect to the change in behavior, clearly the pet chems are wanting to talk about longer-term types of arrangements. Those arrangements can come in a number of different forms. They can address pricing, they can address dedication. Those are the kinds of conversations we have not had with them historically. They typically have been a short-term buyer of ethane. Given these large capital investments, it absolutely takes a long-term view. They have to have a long-term point of view in order to make these investments work. And they clearly are getting more and more comfortable with supply. I think that some of this talk about longer term contracts may be a bit overblown. I think they have and are getting more confident in the supply picture, so they don’t absolutely have to have long-term supply contracts for ethane to make these things work. I think they are kind of sort of realizing that. They are getting more confident as the NGL infrastructure like these projects we recently announced continue to get built. That is the endorsement of the supply, that’s what’s providing them with some comfort. So, clearly they are thinking differently than they have in the past that’s of course beneficial to us. Stephen Maresca – Morgan Stanley: Okay, thanks for that. And then secondly, on the supply side, how much more fractionation do you think is needed above and beyond what’s been announced, and as a subset to that, is there ethane or raw NGL that are just waiting to be fracked right now in certain areas or are we needing to produce to actually continue to ramp up to meet all of this new fractionation capacity that’s coming online?

Steve, I will answer that in reverse, because I probably already forgot the first question. Stephen Maresca – Morgan Stanley: Okay, sorry.

There is ethane laying in the weeds if you will from plants that want to upgrade and take deep extraction. There are plants that we are having or producers of NGLs that we are having discussions with as we speak that have very sizeable conversions where they could extract more ethane. So, you don’t necessarily have to depend on a ramp-up in order to get some pretty sizeable chunks of ethane. There is going to be a ramp-up. We are talking to at least 17 potential processing plants and plant expansions across the Mid-Continent and that’s driving a lot of this infrastructure need. So, there is going to be ample supply of ethane to meet this petrochemical companies’ needs. And what was the first question? Stephen Maresca – Morgan Stanley: I was just, if you had an estimate of above what’s been announced in Mont Belvieu and your guess is over the next three years, what is the additional fractionation capacity needs?

Well, this can kind of give you a benchmark. Our point of view is that in the U.S., we expect at least 200,000 barrels a day of incremental ethane demand. When you put that on an NGL, you make an assumption about a 50% ethane content, that’s 400,000 barrels a day. You are going to need some frac capacity in order to meet that need. So, that gives you some indication. When you look at, you can do the math, you can look at enterprises announcements, you look at our announcement, I think you could argue, we are still going to be a bit short. So, there is likely going to have to be more capacity built to meet the needs. Stephen Maresca – Morgan Stanley: Okay.

Steve, the only thing I would add to that is, and Terry test on it, don’t lose side of the fact of the decline that we face. And then the second thing is I believe his conversations with 17 different plants is probably just an estimate. Stephen Maresca – Morgan Stanley: Okay. We won’t print that. All right. Thanks a lot everybody.

Thank you. Our next question comes from Craig Shere. Your line is open. Craig Shere – Calyon Securities: Hi, couple of questions, on energy services, could we speak to, whether the $59 million or $60 million in premium service revenue for the year is now a little high and what the prospects are looking forward on that as we think about new customers going forward? And couple of other questions right after that.

Okay. Pierce, you want to handle that?

Yes, Craig, we still think that, that is actually in our range, that the stress that we are kind of coming off on really is more the locational spread stuff which is affecting the transportation side of the business and the seasonal spread which is the storage side, but we are still hanging in there with our premium service business. Craig Shere – Calyon Securities: Okay, great. Thank you. And on the tax situation, I just want to make sure I understand, are you all saying that the OKS LP and GP distributions to OKE are completely tax deferred for the LP distribution but of course the GP distribution would be taxed to your top marginal rate?

That’s correct. Craig Shere – Calyon Securities: Okay, so that’s pretty good. Your basis must not be too low on OKS. And one more question regarding OKS NGL and ethane equity volumes moving forward, if I understand, excluding the optimization capacity you have, you got PLP benefit or exposure in your growth projects of Stateline I and II and Garden Creek plants, but beyond that, what motto would be driving equity volumes? Would there be a point at which there is more ethane extraction on the associated gas from the Bakken, could you talk that through?

And hopefully this answers your question. When we justified these projects, we justified them based upon extraction of propane plus, that is actually no ethane extraction, okay. And it really has been until we approved Bakken NGL pipeline that we considered extracting ethane. So now, with the Bakken pipeline at and anticipate extracting ethane at those plants and we are also looking at the possibility of taking ethane up into Canada, okay. Now, when you look at the equity makeup or the waiting of commodity risk on these projects versus fee, what you are going to see is we are going to increase our commodity exposure, because these are percent of proceeds contracts, and we are going to be, these projects are going to be about 75% NGL-driven revenues with the balance being fee-based. The Bakken pipeline itself will be fee-based. So, hopefully that at least answered part of your question. Craig Shere – Calyon Securities: Yes. So, I guess fee-based is driving increases or leverage or synergy with the percent of proceeds businesses and so as your fee base goes up, you are going to see some drivers in terms of commodity exposure. Are you looking at currently in the Bakken, is it similar to the Marcellus in the wet gas area where people are just blending as much as possible because obviously the ethane is worth less up there, and what is the point of no return where that option for producers runs up?

It’s significantly different than the Marcellus, and what’s happening in the Bakken, that gas is so rich, it’s not even possible to blend that raw gas because it’s 1,500 Btu gas, it contains 13 GPM, the natural gas liquids. You can’t even consider blending it. What’s happening is the gas is being flared at the well hedge by the producers until all this infrastructure gets built. So, their considerable volumes being flared and obviously that’s a strong economic driver for the producers to get these wells connected and get their gas committed to processor as soon as possible. Craig Shere – Calyon Securities: Great, thank you.

Thank you. Our next question comes from Ted Durbin of Goldman Sachs. Please go ahead. Ted Durbin – Goldman Sachs: Thank you. You had really good results in your natural gas liquids segment. I am just wondering if you can, first of call, quantify how much of that $0.15 basis differential helped in the quarter? And then just thinking about the new Sterling Pipeline that you are going to build, do you expect that basis to really narrow significantly? Would you keep some of that capacity opening for yourself to optimize or would you contract it all out?

The answer to your last two questions is yes. So, the basis will come in and we are going to have capacity for other, okay. As far as the optimization contribution, in the earnings release, we talked about and quantified approximately how much of that was spread-driven. So, it’s there even in the earnings release for optimization.

I think it was about $55 million – Ted Durbin – Goldman Sachs: $55 million, developed just on basis, if there was other, anything else going on in there?

A majority of that is on basis. Ted Durbin – Goldman Sachs: It’s on basis, okay. Okay, that’s great. So, you would expect the basis sort of $0.05 or $0.10 kind of where you can still be in 2013, once the new pipe is built or –?

What I will tell you is, is that the market is indicating to us and I am not going to tell you what that is, but the market is indicating to us the long-term value of that capacity, okay. And that long-term value of that capacity is lower, significantly lower than the spread that’s currently printing in the market today.

That’s the trade-off for us. I mean, we are in the business providing services to producers, processors and are downstream customers are pet chem. So, we will exchange, we will create this capacity which will reduce the spreads, but in exchange to that, we will have fee-based business and make our business much more stable going forward. Ted Durbin – Goldman Sachs: Sure. Okay. If I can just have on hedging, you had a lot of NGL hedges in 2012, are you directionally worried about where prices are going or are you just kind of wondered locks the margin since it’s now you have a lot more CapEx coming to you on a stabilized cash flow? Sorry to hear about the hedging that you just did.

I think that is true. We looked at those prices in 2012 relative to our point of view. Some of the literature, the people are a lot smarter than us, put out there, and we deemed that those were good prices and thought we should take them off the table. And yes, we anticipated these project announcements, the need for some certainty as to locking down future earnings that also influenced us. Ted Durbin – Goldman Sachs: Okay. And then if I could ask just one more just on the share buyback at the OKE level. You are going to be having a lot of accretion from all, being partners and projects. I am assuming you will fund them all at that level. So, presumably you are going to have a lot more free cash flow even more coming up to the OKE level. I am just wondering when do you kind of, we haven’t gone forward yet with the buyback, but what would you need to see to have the visibility actually go forward with?

It’s not so much what we need to see as much as – and of course, I surely can’t give you specific information, as much as the alternatives for those, for that cash. And it can’t be too specific about what we wanted to do with it, but that’s the trade-off. And so, we continue to look at that almost daily relative to the other opportunities we have for either acquisitions or increasing dividends, but I probably can’t go much beyond that. Ted Durbin – Goldman Sachs: Okay. Those are my questions. Thanks.

Yes, thank you, Ted.

Thank you. Our next question comes from John Tysseland of Citigroup. Please go ahead. John Tysseland – Citigroup: Hi guys, good morning.

Hello John. John Tysseland – Citigroup: OKS has now posted I guess two strong quarters following the legacy contracts that rolled over in the third quarter. Now, for the second quarter, you will have new frac capacity available to you in the Gulf Coast through the Cedar Bayou expansion. How do you think about this new capacity? Do you expect to fill it pretty almost immediately and does that increase your optimization opportunities?

John, yes. We do expect to fill it immediately. We actually already delivering barrels as we speak into the frac, not at full capacity, but they are still in the process, are still in the process of starting that fractionators. And yes, that we anticipate filling that 60,000 barrels a day capacity and it will in fact help our optimization activity. John Tysseland – Citigroup: So, then, how do you think about, you kind of spoke to this a little bit in a question before, but how do you think of that existing optimization opportunities and balancing your kind of long-term contract business, is there a preferred mix that you kind of want to stick with over the next couple of years as we go through this buildout process?

John, not really. We have not targeted a specific percentage. I think historically we have run in that 12% to 13% range of course with this spread environment, it’s stepped to the 25% range of our gross margin. Probably something in that range is going to be fine with us. One of the things that will of course factor into whether we optimize more or less of course is what the market and i.e., the producers are willing to pay for that ability to take their Conway barrels to Mont Belvieu. We get comfortable with the particular rate, then we are going to give up that capacity and give up that optimization upside. We will always have, I believe a tranche of capacity that we will reserve for optimization opportunity. John Tysseland – Citigroup: That’s helpful. And then, lastly I guess, you look at the first quarter guidance, you look at the second quarter and kind of where ethane margins are and spreads are continuing to be pretty strong, new optimization capacity coming online, I guess why are you keeping your guidance of what I would think would be conservative for the rest of the year? Do you think more capacity comes in and kind of expect things to flatten out maybe towards the end of the year or do you think you are staying a little conservative?

Yes, conservative? We, every year, go through the same process where after the first quarter, we know a little bit more about our performance relative to our expectations. After the second quarter, we will know a whole lot more and every quarter, if you look at our history, we have tightened the bands, moved the midpoint and I would anticipate we would continue to do the same. What we are saying is that we are probably going to be on the high end at OKS, as we see the business today, but those, let’s say, around this table have been in this business long enough to know that it can change quickly. And we have three more quarters to go. John Tysseland – Citigroup: Fair enough. I appreciate your comments, thank you.

Yes, sir.

Thank you. Our next question comes from Michael Blum. Please go ahead. Michael Blum – Wells Fargo: Thanks, good morning. Couple of questions on the Sterling and frac announcement expansion, perhaps it is a naïve question, but in terms of you sort of say that you could either use the new lines plus the existing lines to transport raw NGLs, do you batch that or do you have to make a decision on the specific line and that as low line versus a purity line, can you just walk through how that works?

Michael, that’s a great question. That Sterling III pipeline, we will be able to actually batch raw feed and purity, so that’s contrary to what some people believe that are not in the NGL industry, you can hedge raw products and purity products. Michael Blum – Wells Fargo: And for Sterling I and II, my understanding is those are purity lines today, is there something you have to do in terms of investment otherwise to be able to batch on those lines?

Actually, what we like to be able to do is move raw products across either of those pipelines as operational needs and market needs dictate. What will have to happen with the Sterling, the existing Sterling pipelines is some work on the pump motors in order to get them hands up where they can handle raw products at a very small cost will need to be done.

The other thing is all three of those lines will be reversible.

We will have reversible capability which we have had for some time. You won’t need to reverse all three pipelines at the same time. Very rarely will we ever have to do that, okay. But we will have reversible, reversing capability on Sterling III as well as with our existing Sterling pipes. Michael Blum – Wells Fargo: Okay. And then the other part to the question is, and this would apply both to new pipeline and the new frac you announced at Mont Belvieu, what percent of those assets are going to be locked under long-term contracts with third-party customers and what would be the duration of those contracts?

At this point in time, we would anticipate that nearly all of the barrels should be locked up under some form of long-term contract. The terms would typically be anywhere from 5 to 15 years, preferably 10 plus. Michael Blum – Wells Fargo: Okay. Great, thank you very much.

Thanks Michael.

Thank you. Our next question comes from Yves Siegel of Credit Suisse. Yves Siegel – Credit Suisse: Good morning.

Hello Beverly [ph]. Yves Siegel – Credit Suisse: We will take that offline. Just, Terry, on your comments, you spoke about looking at natural gas pipeline opportunities and storage projects, NGL storage projects, could you speak of maybe just elaborate on that, and also, as you think about that, you are expanding capacity so much, I am a little surprised that you haven’t already announced some expansion of the NGL storage?

Clearly, NGL storage is something that in order to be effective at bringing these kinds of volumes down into in the Belvieu, we got to be able to do a good job handling those volumes, and we are looking and have for sometime looked at expansions of our existing storage capability at Belvieu. So, what I will tell you is, is that we are working on that very feverishly. As far as the natural gas pipelines go, we are looking at a number of projects to supply natural gas to potential co-plant conversions and new industrial loads. So, we are very active, very busy there. Yves Siegel – Credit Suisse: So, that thing is primarily intrastate or –?

A large portion of it is going to be intrastate, but we have got a lot of incremental load activity on our interstates as well and in particular as it relates to conversions of coal plants to natural gas. Also, we continue to look at new processing plant opportunities in our gathering and processing segment in these hot shale plays. Yves Siegel – Credit Suisse: So, is it possible, so I am sure the answer is yes. Would you sort of put a number around the backlog that you are looking at?

You know, we have always said $300 million to $500 million per year and it’s still in that order of magnitude. Yves Siegel – Credit Suisse: Okay. And then could you – yes.

I was just going to say, we still got several foreseeable future, I don’t know how you define that, but we still got a backlog. Yves Siegel – Credit Suisse: Above and beyond the $3 billion that you just announced?

Yes sir. Yves Siegel – Credit Suisse: And then when you spoke about ethane to Canada, how would you accomplish that?

If you are probably familiar with the pipeline project called the Vantage Pipeline company, named Mistral has developed in concert with NOVA Chemicals. That’s an opportunity for us and we are evaluating it and looking at its merit. Of course, we have got now with the Bakken Pipeline, we have got a couple of ways we can go with our incremental ethane. So, we are continuing to evaluate that. Yves Siegel – Credit Suisse: And then, two other quick ones, are you also looking at other geographic areas and perhaps if you are, what kind of criteria are you think about?

I think John has made this comment in the past, when everybody was looking at Marcellus, we were working fast and feverishly on the Bakken and we announced the Bakken. We still have a lot of opportunities right underneath our noses in our fairway, and we have talked about the Niobrara, we have talked about the Woodford, lot of things going on in those areas. So, I mean, our plate is well.

I think another way to think about it is, when we make those decisions, we look at the competitive landscape, make sure we have got some value that we can bring to the producer, to the processor and customers, and for us, just by virtue of where our infrastructure exists, it continues to be right down from Canada down to Mont Belvieu. So, if we were to move to the east or to the west, it would be, if we saw opportunities to our model of vertical integration. So, we are not going to find ourselves in California in trying to give into some business we know nothing about. Yves Siegel – Credit Suisse: Okay. I guess my last question/observation, it would seem to me that the bulk of the spending seems to be on fee-based businesses. So, is it accurate to think that the model still is moving more and more of the income mix towards fee-based?

It is, the exception to that would be, for example, in the Bakken, the producers don’t want the fee-based arrangement behind processing things, they want a percentage of proceeds. So, we have to meet the needs of the producers. So, to the extent the market allows us to, we will move towards fee-based arrangements, but to the extent the market doesn’t want to be there, we have to be competitive. Yves Siegel – Credit Suisse: Thank you.

Yes, sir.

Thanks Yves.

Thank you. Our next question comes from Monroe Helm of Barrow Hanley. Please go ahead. Monroe Helm – Barrow Hanley: Thanks a lot, but my questions have been answered.

Thank you very much for your call.

Thank you. Our next question comes from Helen Ryoo of Barclays Capital. Helen Ryoo – Barclays Capital: Good morning. Thank you. A clarification regarding your comments on the NGL decline, did you say on average, you are seeing about 20% decline on the NGL production?

Helen, that was referring to the base natural gas production. Helen Ryoo – Barclays Capital: Okay, I see. Would you be able to provide a sense of what kind of NGL decline you are seeing?

It’s going to be, that base NGL production decline is going to be comparable, it may not be quite as steep because obviously they are richer, these shale plays are richer in NGL content than the typical and historical NGL content of a lot of our basin. So, it may be a bit shallower, but it’s going to be in the same order of magnitude in our view.

Helen, we put that in thousands of barrels a day.

Actually, we produced a slide. The slide itself was natural gas, not NGLs. But then we equated it and did the math and came up with the 400,000 barrel per day of total that you need to fill –

That’s what I was remembering, 400,000 barrels a day. Helen Ryoo – Barclays Capital: 400,000 barrels a day. Okay.

Helen, that’s still pretty much our view that we got to fill that hole each and every year in order to stay flat. Helen Ryoo – Barclays Capital: Sure, okay. And then another question just regarding your recent expectation of five to seven times on these projects, is that or are you expecting to reach this level of return maybe a year or two after the projects are completed?

Helen, most of our projects have been kind of a ramp-up type. The development doesn’t all happen day one, so it’s going to happen overtime, but your return is going to be in that five to seven times range pretty consistently.

And getting there within probably one to two years time.

Correct. Helen Ryoo – Barclays Capital: Okay, great, thank you very much.

Thanks Helen.

Thank you. Our next question comes from Andrew Gundlach of First Eagle. Please go ahead. Andrew Gundlach – First Eagle: Hi, good morning. Thanks for taking the questions.

Good morning, Iron Man. Andrew Gundlach – First Eagle: The 992 and 641 numbers specifically in the gathering and processing in terms of the gathered per day Btu and process per day Btu, do you have the backup in terms of what was Mid-Continent and what was Rockies? And the Oklahoma driller that you referred to, is that now a stable situation where you can flat line it? The reason I asked the question is because I didn’t expect it to go down so much quarter-over-quarter, obviously the Rockies expect to go down, but not Mid-Continent.

Let me give you this number, maybe this will give you order of magnitude. The Rockies volume that we are talking about is about 150,000 MMBtu per day of that 992. So, maybe that helps you, the rest of it is going to be Mid-Continent, Kansas, Oklahoma. As far as the situation with that particular producer, it is stable, but that producer like any producer is going to optimize for landholding purposes, for geologic reasons, they are going to optimize and change and adjust their drilling schedules from time-to-time and there was a pretty significant adjustment with this particular producer. They are still very high on their prospects and we still have a very, very strong and bullish long-term view on this particular producer. Andrew Gundlach – First Eagle: What’s the specific play there?

It’s primarily the Cana-Woodford play. Andrew Gundlach – First Eagle: So, dry gas from the Cana?

You got dry gas in the Cana and you got rich gas in the Cana produced or stepped in and out of those particular plays as conditions warrant. Andrew Gundlach – First Eagle: Okay. And then, I guess the other question in the section is that, in this reporting section is that the margins were very strong despite the volume drop-off, but not as strong as I would have expected, and I guess is there a mix shift going on already between POP and (inaudible) that in other words, in the fourth quarter, it was about 12% of margin and today they announced about 9%. And is that small percentage change big enough to affect the overall profitability?

Yes, it can from quarter-to-quarter. That shift that you are talking about, we have an ongoing effort, and still it’s a strategy that we still employ to reduce the segment’s volatility and risk as it relates to commodity prices. So, we are still converting from time-to-time people contracts to percent of proceed/fee-based type contracts. So, that’s some of what you are seeing there. Andrew Gundlach – First Eagle: Understood. When you go back to the big picture, just one more question for John, it follows up to Yves questions, on Canada, I think you have an unique opportunity there, but it sometimes complicated getting money across the border and back without having the governments take a lot of it, and I am just curious how you see yourself being able to take advantage of Canada, does that mean you have to kind of create a standalone entity up there relative somewhat to what Williams is doing or how do you see that in the big picture?

We see it as you describe it. Agree with what you have, we have actually exposure to Canada through our energy services business in the past. So, we know what you say is true. Because what you say is true, it’s probably not the most favorable environment, but it’s something that we think about very carefully before we would head in that direction. Andrew Gundlach – First Eagle: Okay. And then, last question, talking about use of proceeds and this great untapped credit line that you have now been given for a long time of five years or so, I guess one of the shortfalls of the MLP model is that there is a lot of pressure on doing projects that pay off really quickly, you don’t have to have that negative carry with respect to distribution payments, but a company like ONEOK with OKE as the parent can afford a much longer-term perspective that a weaker MLP would not be able to take or they have to attract private equity, which is very, very expensive partner, but OKE, charges are a lot less than private equity. And I am just curious how you see that and whether you can use that advantage into some of the plays that you are talking about, the Niobrara, Woodford you mentioned earlier on, answering Yves question. I mean, isn’t that the best opportunity for OKE?

Well said. Andrew Gundlach – First Eagle: You are a man of few words, that’s why I like you so much, John.

I don’t know, I guess I could take everybody else’s time and repeat what you said, but it’s clearly one of the things we look at, at ONEOK is to where our money goes and where we think it can create the most value for our shareholder and clearly that still remains a great investment, so does buying back shares, so does increasing the dividend. But I will say also, so does buying earnings. And you know, as hard as we work at ONEOK Partners on developing these internal projects, you may rest assured we are working just as hard for opportunities to grow at ONEOK, they are just more difficult and not quite as a parent. Andrew Gundlach – First Eagle: Right. But more of a step function in earnings as opposed to a linear path.

Much, very well said, again. Andrew Gundlach – First Eagle: Thanks very much, John.

You bet, Andrew. Thank you.

Thank you. Our next question comes from Bernie Colson of Oppenheimer. Your line is open. Bernie Colson – Oppenheimer: Yes, thanks. Actually, questions have been answered.

Thanks, Bernie.

Thank you. Our final question comes from Rick Gross of Barclays Capital, after which we will turn the call back over to Mr. Harrison for any closing remarks.

The maestro, he dropped off. Rick Gross – Barclays Capital: Just under the wire. Good morning.

Hello, there you are. Rick Gross – Barclays Capital: I just wanted to ask what you could tell us about your two cryptic comments about changing the nature of the contracts. You have made a little bit more money in gathering and processing, and then you said you migrated your exchange services contract in a way that helped out without obviously great detail. Can you give us an idea of what the intent of all of this and why it might be better the way it now is than it was?

Rick, is your question directed toward NGLs or is it directed towards gathering and processing? Rick Gross – Barclays Capital: It’s both. You had uplift that you alluded to because of contract renegotiation, we will call it restructuring in exchange services and also in gathering and processing, and I would like to kind of understand with as much as you will give me, what’s going on in each of those areas and why you would be getting uplifts and whether this is something that continues on, helps, that kind of thing? How this works and benefits you?

I am with you now, Rick. Particularly in our NGL business, capacity has been tight. Fractionation capacity, the infrastructure capacity across the board has been tight because the demand for that capacity has gone up. And so, every year we have a tranche of contracts that come up for renewal, and we have benefited from the market, the market value for this capacity increasing. So, that’s hit our bottom line and in particular in certain areas in our gathering and processing segment, we see that opportunity and realize those opportunities as well. Rick Gross – Barclays Capital: Okay. Is this something as simple as you used to charge a $0.01 for frac and you can now charge more etcetera or is there something – I got the impression in the language if there was something actually in the way the contracts were structured, particularly in exchange services that gives you more flexibility to optimize?

Not particularly, there’s not a significant change. I think if there is a change to structure, it’s probably more around the fact that some of these producers, NGL producers are willing to enter into frac or pay types of arrangements. And we are doing a number of those. Rick Gross – Barclays Capital: Okay. Thank you.

Thanks, Rick.

Okay. Thank you all for participating. This concludes our conference call. As a reminder, the quiet period for the second quarter will start when we close our books in early July, and we will extend until we release second quarter earnings on August 2nd with the conference call schedule a day later. We will give you additional details on that August 3rd conference call at a later date. Just a reminder, Andrew Ziola and I will be available throughout the day to answer your follow-up questions you might have. Thank you for joining us.

Thank you, sir. Thank you, ladies and gentlemen, for your participation. That does conclude your program. You may disconnect your lines at this time. Have a great day.