歐尼克 (OKE) 2010 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the first 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, this conference is being recorded. I would now like to introduce your host for today's conference, Mr. Dan Harrison. Sir, you may begin the call.

Thank you. Good morning, and thanks to 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's President and CEO and ONEOK Partners' Chairman, President and CEO. John?

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

As our news release has stated, both ONEOK and ONEOK Partners turned in solid operating performances, with all of our businesses performing well. We also reaffirming the 2010 earnings guidance for both entities, reflecting our confidence in the continued strong performance of our businesses.

Energy Services performed in line with our expectations, benefiting from increased storage in marketing margins, net of hedging. We are on track with our efforts to reduce annual earnings volatility in this segment, by reducing our lease storage and transportation capacity. Our Distribution segment continues to benefit from its innovative rate strategy with improved operating performance and returns.

Rob will provide more detail on both these segments later in the call. ONEOK Partners reap the benefits of our recently completed $2 billion plus capital investment program, with higher NGL volumes gathered fractionated and transported. In the partnership, NGL segment, we experienced some short-term capacity bottlenecks during the quarter. As less fractionation and transportation capacity was available on our assets for optimization activities, resulting in lower optimization margins when compared with the first quarter of last year.

We expect to relieve the short-term capacity constraint in the coming quarters and our reaffirming guidance for this segment. Terry will provide additional information on this constraint in strength as well as why we see this as a short term issue. Overall, almost 73% of the partnerships' first quarter margins were fee-based, compared with approximately 65% in the same period last year, providing the partnership with repeatable and sustainable cash flow.

Our continued growth allows us to increase distributions to unit holders and dividends to shareholders. The partnership increases quarterly distribution another penny last week, representing a 40% increase since we became general partner four years ago this month.

Pending board approval, we expect to increase the ONEOK dividend by another $0.02 in July, which has grown by almost 60% in the last four years. These increases are driven primarily by our commitment too and our execution of growth at ONEOK Partners. ONEOK Partners continues to develop additional growth opportunities which will not only create value for the partnership unit holders but also for ONEOK as sole general partner and 43% owner.

Our announcement last week but more than $400 million of investments in the Bakken and Woodford Shale, demonstrates our ability and our commitment to develop projects that provide our producers and customers with nondiscretionary services, allowing them to deliver to market the natural gas and natural gas liquids they produce.

These projects also provide attractive returns generating EBITDA multiples of five to seven times. At this time, Curtis Dinan will provide a more detailed look at ONEOK Partners' financial highlights. And then Terry will review the partnerships' operating performance and industry trends. Curtis?

Thanks, John, and good morning, everyone. John has already provided a high-level summary of the drivers the partnerships' first quarter results. And Terry will provide additional detail in a moment. My remarks will focus on the financial results and our expectations.

In the first quarter, ONEOK Partners reported net income of $84 million or $0.57 per unit compared with last year's first quarter net income of $100 million or $0.85 per unit. Distributable cash flow in the first quarter was $122 million compared with $135 million in the first quarter 2009.

For the first quarter 2010, the partnership increased the distribution one penny to $1.11 per unit representing an annualized rate of $4.44 per unit. This is the 14th distribution increase since ONEOK 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 one penny per quarter for the remainder of the year. We reaffirm the partnerships 2010 guidance, and expect net income to be in the range of $450 million to $490 million for the year and estimate the partnerships 2010 distributable cash flow to be in the range of $580 million to $620 million. Based on the equity offering that we completed in February, we anticipate an average of 101.4 million units outstanding for 2010.

Capital expenditures for that partnership are expected to be approximately $362 million comprised of $278 million in growth capital and $84 million in maintenance capital. While growth capital expenditures were adjusted between the various business segments to accommodate the timing of certain projects associated with our recently announced expansion in the Bakken and Woodford Shale place. The total amount of capital expenditures remains unchanged. We have identified additional growth projects for 2010 that will likely resulted an increased in our projected capital expenditures during the year and we will provide an updated forecast when appropriate.

We have hedges in place to lock in margins on our expected equity volumes in the partnerships natural gas gathering and processing segment, which has the most sensitivity to the commodity price changes. For the remainder of 2010, we have hedged 70% of our expected NGL and condensate equity volumes at an average price of $1.22 per gallon and 81% of our expected natural gas equity volumes at $5.60 per MMBtu. For 2011, approximately 16% of our expected NGL and condensate equity volumes are hedged at an average price of $1.65 per gallon and 43% of our expected natural gas equity volumes are hedged at $6.29 per MMBtu. As is our practice, we continually monitor the commodity markets and will place additional hedges as conditions warrant to mitigate our overall risks.

At the end of the first quarter, the partnership maintained a strong balance sheet with $310 million of debt outstanding and $558 million available under a $1 billion revolving credit agreement and the partnerships total debt to capital ratio was 51%. The partnerships next long-term debt maturities are very manageable $250 million due this June, which we expect to refinance with our short-term revolver and another $225 million due in 2011.

As I mentioned earlier, we completed an equity offering of approximately 5.5 million common units during the quarter generating net proceeds of approximately $323 million that was use to reduce the amount outstanding on our $1 billion revolving credit agreement. At this time, the partnership does not anticipate any additional financing needs 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 of the partnership.

Thank you, Curtis and good morning. The partnership had a solid operating performance in the first quarter driven primarily by volume increases in both the natural gas and natural gas liquids businesses from our recently completed $2 billion plus capital investment program. And accordingly the partnerships fee based margin has grown to 73% in the first quarter of 2010 from 60% in 2006.

The gathering in process and segments first quarter financial results were lower compared with the same period in 2009 due primarily to lower gathered volumes primarily, in the Powder River Basin in Wyoming. Offset, somewhat by higher natural gas volumes processed. We experienced a 6% decline in natural gas gathered in the first quarter of 2010 compared with the first quarter of 2009 due primarily to production declines by producers of dry natural gas from coal bed methane wells in the Powder River Basin. We continue to see a drop off in drilling and natural gas production in the Powder River Basin due to lower natural gas prices. As you may recall, Powder River natural gas production is generally not processed, since it does not contain natural gas liquids, and is some of our lowest margin throughput.

However, natural gas volumes processed increased nearly 2% for the quarter and remained resilient due to our presence in the growing natural gas liquids rich Bakken Shale in the Williston Basin in North Dakota and the Woodford Shale in Oklahoma, which I will discuss in more detail in a moment.

These areas continue to be very active development areas driven by favorable drilling economics in large part to the natural gas liquids content and associated crude oil and condensate production. We remain confident in this segment achieving its 2010 operating income guidance with continued growth in processing volumes and more than 70% of our margins hedged. We've already placed some hedges for 2011 and will continue to evaluate additional hedging opportunities as the year progresses.

I would like to add some additional color on our recently announced plans to invest approximately $405 million to $470 million between now and the end of 2011 in growth projects in the Bakken and Woodford Shale. We are the largest independent operator of natural gas gathering and processing facilities in the Bakken Shale.

We have seen significant increases in drilling rig counts within our core gathering area, horizontal drilling and hydraulic fracturing techniques has resulted in new wells producing as much as 1,500 barrels per day of oil and 1 million cubic feet per day of NGL rich natural gas with NGL content in excess of 10 gallons per Mcf.

Current drilling economics in the Bakken are attractive and producers have plans to continue drilling for many years to come. We have large acreage dedications in the most active development areas, which require additional gathering and processing capacity to handle these increasing volumes. By the end of the year, our Grasslands plant is expected to be add capacity.

As a result, we will construct a new 100 million cubic feet per day, gas processing facility, the Garden Creek plant and invest and expansions, upgrades, additional compression and new well connect. The new plan is expected to be completed in the fourth quarter of 2011. We expect to connect more than 300 wells in 2010 and more than 400 wells in 2011 in the Bakken Shale at a cost of approximately $90 million over this timeframe. If drilling rig counts remain at current levels, the new wells drilled and completed on acreage dedicated to us a could exceed 2400 through 2016.

Now, some highlights on the Woodford Shale projects where the partnership will invest $55 million between now and 2011. Our Western Oklahoma systems are at near capacity because of the increase drilling activity in the Cana Woodford Shale and the Colony Wash development. Well, more of the natural gas driven play, the natural gas produced in these areas does contain considerable natural gas liquids, which enhances drilling economic. Typical well completions in the Cana Woodford which are horizontally drilled can produce as much as 8 million cubic feet per day, with NGO content of 4 to 5 gallons per Mcf.

One of the projects will connect our Western Oklahoma gathering system to our existing Maysville processing plant, allowing us to optimize our processing capacity and accommodate this volume growth. We expect to complete this project by the end of this year. We also expect to spend approximately $20 million in well connects in 2010 and 2011 in this region.

Now, moving to our natural gas pipeline segment. This predominantly fee-based segment had another exceptional quarter. Strong first quarter results were driven by regarding pipeline expansion and extension that went into service in the first quarter of 2009, our new Midwestern Gas Transmission Interconnect with Rockies Express Pipeline as well as higher natural gas storage margins.

For the first quarter of 2010, our interstates and intrastate pipelines were approximately 91% subscribed under demand based rates, compared with 79% in the first quarter of 2009. The FERC recently announced its approval and authorization for TransCanada to construct the Bison Pipeline that will connect to Northern Broader Pipeline.

Thereby connecting Rocky supply with upper Midwest markets and diversifying Northern Broader Pipelines supply sources, by soon as expected to be in service in November of this year. We remained focus on the development of growth opportunities to deliver natural gas to new markets as well as pipeline expansions to serve new supply growth particularly in the areas of new Shale development.

Now let's move to our natural gas liquids segment. Net margin was relatively flat compared with the first quarter of 2009. We benefited from higher NGL volumes gathered, fractionated, marketed and transported primarily as a result of the completion of the Arbuckle Pipeline, Piceance lateral and the D-J Basin lateral projects. However, the benefit of these higher volumes was offset by lower optimization margins, due primarily to less fractionation and pipeline capacity available to capture optimization opportunities, which is being used to meet our fee-based contractual obligations.

These short-term capacity constraints limited our ability to capture additional optimization margins in the first quarter. We expect these capacity constraints to be resolved as we move through the year, when more fractionation capacity becomes available to us, primarily through the expiration of certain contracts.

We remain committed to maximizing our bundled first full service gathering fractionation and transportation capability, while reducing standalone fractionation only services. So as certain fractionation only agreement expire, more capacity will become available to serve our full service customers as well as our optimization activities.

The average price differential between the Conway and Mont Belvieu market centers for ethane was flat, compared with the same period in 2009. We do expect these differentials to widen the rest of this year as petrochemical demand remains robust and NGL supplies continue to grow.

NGL production from our recently completed growth projects is in line with our expectations, with continued growth expected throughout the year. NGLs fractionated during the first quarter increased to 492, 000 barrels per day or 6% higher. NGLs transported on our gathering lines were up 36% to 441,000 barrels per day and NGLs transported on our distribution lines increased 5% to 467,000 barrels per day. At this time Overland Pass Pipeline throughput is nearing its current capacity of a 140,000 barrels per day and we are evaluating an investment in additional pump stations to increase its capacity over the next few years.

Arbuckle throughput is in line with our expectation at about 60,000 barrels per day and is well positioned to accommodate Mid-continent and Barnett Shale production growth. We remained confident in achieving our 2010 operating income guidance for the natural gas liquid segment. Although the first quarter result reflect to the impact of some capacity constraints, we expect additional optimization opportunities during the year along with anticipated new NGL supplies, allowing us to provide the services to our customers expect.

Now let's discuss the NGL markets. On the demand side, petrochemical demand remains robust. The petrochemical industry is currently experiencing wide margins, which are expected to continue. NGL especially the lighter feeds such as ethane and propane remain economically attractive over some of the heavier oil based feeds, such as [NASA].

Natural Gasoline demand is also strengthening for years as the blend stock for motor gasoline as a denaturing for ethanol, a petrochemical feedstock and as a diluents for Canadian oil essence. Ethane demand is expected to reign relatively high with an improving US demand picture and continued wide proved to natural gas ratios.

We also believe there are more than a 100,000 barrels 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. On the export front a vast majority of the US ethylene derivative demand comes from Canada, Mexico and South America with about 10% to 20% of the export demand been consumed in Asian markets. Well, recent Asian demand has proved a bit double digit demand growth for year is still expected.

The US petrochemical industry is very competitive globally for the production of ethylene derivatives due to the relatively low price of US NGL's. In addition our countries access to improve inability to quickly develop natural gas and natural gas liquids reserves at relatively low cost who feeds fuel and feedstock cost for US petrochemicals as some of the lowest and most competitive in the world.

We do expect fractionation capacity to remain tight as additional NGL supplies continue to be developed. Our integrated NGL assets are well positioned to capture these opportunities and provide our customers with the flexible and bundled services they need. On the supply side the projects announced last week include an NGL project in the Woodford Shale that exchange our existing Oklahoma NGL gathering system to a new natural gas processing plant currently under construction that will be completed by the end of this year.

This will increase supply into our Arbuckle Pipeline and a Bayou the fractionating facility. As we said before, as NGL growth continues we will carefully evaluate our NGL infrastructure growth opportunities. With this new shale place becoming more prevalent and the need for NGL type away solutions. We continue to meet with NGL producers and customers particularly in the Bakken and Marcellus.

Whether in existing our new shale place, any projects we develop will be the result of a disciplined approach that creates value for the customer and exchange for the customers' long-term supply commitment to us. John, that concludes my remarks.

Thank you, Terry. Congratulations on a great quarter. At this time Curtis will provide us some more detailed look into ONEOK, its financial performance and then Rob Martinovich will provide the review of ONEOK's operating performance. Curtis?

Thanks, John. ONEOK's net income for the first quarter was $155 million or $1.44 per diluted share, compared with last year's first quarter net income of $122 million or $1.16 per diluted share. 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.

ONEOK's first quarter 2010 standalone free-cash flow before changes in working capital exceeded capital expenditures and dividend payments by $204 million. We currently estimate standalone free-cash flow before changes in working capital to exceed capital expenditures and dividends by $200 million to $235 million. This is higher than our original forecast of $135 million $170 million due to higher than previously forecast accelerated tax depreciation deduction resulting in lower income tax payments in 2010.

The midpoint of our standalone cash flow before changes in working capital is $650 million compared with our previous estimates of $584 million. By virtue of ONEOK's general partner interest and significant ownership position, ONEOK received $73 million and distributions from the partnership during the first quarter, a 6% increase from 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 first quarter and on a standalone basis, we had no commercial paper outstanding, $1.2 billion available on our credit facility, $162 million in cash and cash equivalents and $178 million of natural gas in storage. As natural gas was pulled from storage during the quarter, ONEOK's standalone debt to equity was reduced to 39% from 46% and is below our 50, 50 debt-to-equity target. We currently project short term borrowings to remain below $400 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 strategic acquisitions, increase our investment at ONEOK Partners, increase future dividends or repurchase shares.

Pending board approval, ONEOK is on track to increase the dividend $0.02 per share semi annually during the year. Building on the first quarter dividend of $0.44 per share. We remained committed to our targeted long-term dividend payout ratio of 60% to 70% of recurring earnings due to the stability of earnings in cash flows from all of our business segments. Now Rob Martinovich will provide an update on ONEOK's operating performance.

Thanks, Curtis, and good morning. Terry already discussed ONEOK Partners, so I will start with our Distribution segment. First quarter results were slightly lower down 2%, compared with the first quarter of 2009. Improved margins were driven by successful rate activity and colder than normal weather that resulted in higher sales and transport margins in all three states.

Expenses increased due to higher employee related cost and integrity management cost that were previously deferred that are now recovered in best rates. Some of the headlines these past heating seasons stated this was the year of the southern winter. Much of our service territory in particular Oklahoma and Taxes experienced higher the normal snowfall, plus significantly higher heating degree days compared with 2009 and what is considered normal.

While our utility is experienced higher gas sales. You may recall that we have weather normalization mechanisms in place to mitigate the earnings' impact of colder or warmer than normal weather as well as the coupled rates for 75% of our residential customers in Oklahoma.

We continue our efforts to grow our rate base by efficiently investing capital and projects that provide benefits to our customers and our shareholders. We are on schedule with approximately 12% complete with our 2010 project to install automated meters Tulsa and Oklahoma City, for a total capital investment of $31 million.

By the end of the year, almost half of ONGs residential customers will have automated meters installed. 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 base rate structure creating a win-win for customers and the Company.

With that I'll briefly discus the latest regulatory updates in our states beginning in Oklahoma. In late January, we filed an application requesting recovery of the integrity management program cost differed in 2009 of $15.7 million. The Oklahoma Corporation Commission is anticipated to approve our application in a hearing schedule June 17, as filed this will have no impact on earnings.

Moving to Kansas, in mid December, Kansas Gas Service filed an application with the Kansas Corporation Commission to become an efficiency Kansas utility partner. This program is designed to promote energy conservation and is funded by federal economic stimulus dollars. As filed the company's participation in this program is contingent upon the KCC approving a rate mechanism for revenue decoupling and allowing recover of all program cost. The KCC staff is examining the rate mechanism and public hearings have been schedule for mid May. The KCC is expected to issue its order by mid August.

Finally, our Texas rate activity. In early December, Texas Gas Service filed for a $7.3 million rate increase in its El Paso service area, which was denied by the El Paso City Council earlier this month. We'll appeal this decision to the Railroad Commission of Texas within the 30 day period, which expires on May 13th. The Railroad Commission will have 185 days after our appeal is filed to render a decision. For 2010, we remained confident in our $223 million operating income guidance for our distribution segment. Now, let's turn to Energy services.

We experienced a very good first quarter. Our results were driven primarily by increased storage margins as a result of wider seasonal storage differentials because of hedges we put in place in 2009 and increased Rockies to mid-continent transportation differentials due to hedges we put in place during 2008 and early 2009. We also were able to take advantage of increased optimization opportunities due to the cold weather experienced in our cold regions.

Offsetting these increases was a decrease in premium services revenues. Although the level of service under contract was similar, the fees we're able to collect were lower due to the decrease in commodity prices and market volatility. Our natural gas and storage at the end of the first quarter was about 25Bcf down from last year's 46Bcf. This decreases due primarily to colder than normal regional weather in the first quarter compared with first quarter of 2009 plus the year-over-year reduction of leased capacity. We currently have 83Bcf of storage capacity under lease compared with 91Bcf at the end of first quarter of 2009. Our April 28, 2010 inventory balance is approximately 34Bcf.

As part of our own going realignment of storage and transportation capacity, to meet the requirements of our premium services customers, we anticipate further storage capacity reductions to 71Bcf by the end of this year and to 65Bcf by the end of 2011. We expect our long-term transportation capacity to be at 1.3Bcf today by the end of 2010. And approximately 1Bcf per day by the end of 2012, compared with our current long-term transportation capacity of 1.4Bcf per day. This capacity reduction targets those assets with lower than average unit margins. These actions will also help to reduce our year-over-year earnings volatility and working capital requirements.

Energy service is on track to achieve its 2010 earnings guidance of $107 million in operating income. Our 2010 earnings pattern is returning to the more normal pattern of higher first and fourth quarter earnings driven by the sale of natural gas related to winter weather.

This logically follows the load profile of our core customers the LDCs. Looking at the balance of the year; we expect to have a challenging summer due to lower transportation margins from narrow natural gas location differentials and limited optimization opportunities as a result of reduced market volatility.

So the fourth quarter we expect narrow seasonal differentials compared with 2009 and reduced premium services revenues as result of following commodity prices and reduced market volatility. For the November and December with all period approximately 88% of our storage margins are hedged.

In addition approximately 62% of our transportation margins are hedged for the balance of the year. I have stated in our last conference call we'll complete our storage hedges for the year as we get gas into storage or financially its spread significantly widen. The transportation will continue to be opportunistic, if differentials widen in the summer, we will put additional hedges in place, if they don't, we'll optimize our positions in the daily market place. John, this concludes my remarks.

Thank you, Rob. And also I'd like to acknowledge Pat McDonie and Pierce Norton for obviously two very strong quarters, a strong quarter from two segments some like that. Thank you very much.

As you've just heard, we have solid first quarter operating performance and we are on track to deliver another strong year. We will continue to focus on growth opportunities, not just the ones that we recently announced, but others that find themselves in various stages of development. And as we've done in the past, we'll announce those projects when we have the firm customer commitments in place.

Finally, as Curtis pointed out, ONEOK's balance sheet strength, significant free-cash flow and financial flexibility, provide us with the wherewithal to continue to make strategic investments that will and do create value for our investors.

So, at this time, I'd like to thank our more than 4700 employees here at ONEOK, whose daily commitment and contributions make it possible for us to create value for our investors and for our customers. So many thanks to all of them for their dedication and continued hard work. At this point, we are ready to answer any questions that you might have.

Thank you.

(Operator Instructions)

Our first question comes from Stephen Maresca of Morgan Stanley. Your line is open.

Good morning, everyone.

Hi, Stephen.

Just trying to understand on the OKS side, the less tighten FERC capacity available for optimization. How much on a percentages, if you can quantify that you used for optimization and how is this compared to last quarter and this is mean going forward? You mentioned the fee-based to be in over 70% this quarter. Does that mean we'll move away from that a little bit as you used more optimization?

Let me try to explain it this way and then Terry can fill in some details and areas that I met. If you think a bit from a simple standpoint and if you could visualized a pie chart.

Yes.

You've got one large area in that pie chart that whether its fractionation capacity or pipeline capacity, it's used for the purposes that providing fee-based exchange services to our customers. And then you have another piece of that pie chart that is available for optimization. Its capacity that is not consumed by or needed for that fee-based margin.

All right.

That [will see] the exchange contracts. What has occurred in the region, it's a short-term anomaly is that, as we look at our contract portfolio inside the NGL segment. As Terry mentioned in his comments we had a number of fractionation only type contracts, that we're consuming space if you will and that's fee-based area. And also we had volume associated with the exchange contracts and that volume has come to our system at a faster rate than we anticipated. As also Terry pointed out were at near capacity already on Overland Pass Pipeline.

And so the amount of space in the smaller section of the [part] that's available to optimize, has royalty to a year ago because we have had more barrels coming under the fee-based structure, now the option like candidly was it could have been to back out our fee-based customers, and utilize that space to optimize price product differentials and location differences, but that's not the way we do business.

So what happened is, we work these contracts out that we have identified and have been identified for some time and when that space returns for optimization, but clearly is quite simply and exchange for an opportunity cost issue relative to doing your fee-based business versus what's available for optimization.

Okay.

That give you -- I will let Terry to give you more detail.

No, that's very helpful. So I appreciate it. And one follow-up in little bit different area. Obviously, there is a lot of needs because of the rich gas content, the Bakken, the Woodford and you talked about it. Maybe, Terry, or you can talk about. How are the contracts changing as producers need to have seemingly significantly increased in these areas. It seems like midstream operators like itself have a lot of leverage in these areas.

What sort of terms are now available given the demand and is it much more beneficial to you in terms of rate charge, or it being 100% volume committed or 100% fee based, if you can just shed some light?

Okay, Terry.

Sure Steve. The contract structures have evolved due to the high demand we're seeing in the gathering and processing business in MVA or minimum volume requirements and producers are agreeable to commit to a minimum volume for in exchange for us building infrastructure and making capital investments.

On the NGL side of the business, we're seeing firm frac contracts. Firm transportation contracts, when historically in this business such things did not exist. So, you are seeing a level of firm becoming very prevalent in both in gathering and processing and in the NGL segment.

And just quickly, is that what you are undertaking like with the new Bakken projects that you just talked about the $470 million or so, is that fair to apply those types of contracts for that?

Absolutely.

Okay, thanks a lot.

Thank you. Our next question comes from Rebecca Followill of Tudor Pickering & Co. Your line is open.

Hi, guys. Just one, quick one. On energy services, do you have expectations that in the second and third quarters we could see losses there, just trying to model across the year.

Well, Rebecca, this is John. You know, we don't quarterly guidance nor have at least to my knowledge. Obviously if where we are today and we affirm where we are going to be at the end of the year, over the next three quarters, we're going to have pluses and minuses that don't add up to a big number, so, yes.

Okay. Thank you.

Thank you. Our next question comes from Ted Durbin of Goldman Sachs. Your line is open.

Yeah. Hey, guys. In terms of the Bakken projects, do you just talk a little bit about how much you see in natural gas production grow in there. You know, you're adding a 100 million day and then the liquids as it comes out, where the liquid find the home or did it have been going?

Terry?

Well, Ted. That's your first question. You know, we see - we're installing a 100 million a day processing plant that's going to effectively double our current throughput in production. So, we have an existing plant there, that's a 100 million a day. So, that can give you a pretty good indication of where we see production growth going. We could conceivably if current drilling rights continue and they're actually continuing to trend upward that could be a possibility of even further expansion. So, on the gas front, very strong. On the NGL front, most of the liquids there - actually all of the liquids there are -- they served the local market. So, as well as they're railed out to other market areas. So, there is no pipeline that serves that region and you know, clearly we're looking at that opportunity as well. We're talking to other processors and producers in that region for possible commitments.

And may just would you consider building the pipe itself or would you start parties or how are you thinking about that?

We built it ourselves.

Okay. Okay. And just one the natural gas liquid segment, that gives you just have these measurement adjustments? Should we considered those as recurring or more onetime the $7 million there?

No, that one time.

Okay. That's great. And then second is about the distribution it looks like the OpEx was up pretty big year-over-year, but you're going to get more - you are going to get most of that recovered to your rates, I mean just walk us through the changes there?

Right.

Rob, would you like to take that?

Yes, John I will, you've got my protocol. Said, we've got the $3.1 million related to recondition of previously deferred integrity management program cost and so that's offset on the revenue line in the same quarter. So, that's coming back and so really that the delta that you are looking at off income year-over-year essentially brought down to just hire employee related cost. That's how, what that is.

Okay. Thanks, it's helpful guys, I appreciate it.

Thank you.

(Operator Instructions)

Our next question comes from Michael Blum of Wells Fargo. Your line is open.

Thanks and good morning everyone.

Good morning, Michael.

Just back to the NGL, the pipeline and the bottom mix. Just I guess and still and I am confused, sorry. So, if I don't understand correctly, your contracting fee based capacity at a rate, which is below what you could achieve the optimization. So, I guess is that correct and if it is to walk to that process and doing so and quantify that delta anyway you can?

Not always true, that is not always a true statement. In another way try another high level way of understanding what the segment is incurring, if you use the analogy of firm transport versus an interruptible transport, you enter into contracts which provide you a firm obligation to deliver and that's space is not been utilized by those firm customers you're able to optimize or use under an interruptible basis.

As we look forward to this year, we do not expect as higher level of throughput for both pipeline and fractionation capacity. We didn't have -- we have found that our customers under firm transport if you will, have used more of their space than we anticipated. And in anticipation of that build in throughput we had already identified certain contracts that needed to be terminated. Because of the buildup we just have less space available to optimize.

Now, not always is the optimization margin going to be greater than the margin we collect on our exchange services, that all is dependent upon the market. It's just like in our gathering and processing business. We've hedged our gas prices and our liquids prices. One could argue that we shouldn't have hedged our liquids prices but we have. And the same thing is true here, we entered into these fee-based firm contracts and because the volume has picked up a little faster than we anticipated when we put our plan together, that has diminished our ability to optimize. So, let me ask Terry to put his snap on this.

Michael, I think the only thing I could add to John's comment are that, and reiterate is that the contracts that we're talking about, that are expiring, our contracts that occur in the Gulf Coast. And those are legacy contracts that we've entered into many years ago, back when the frac market was over supplied that is there was more frac capacity than there was a need. So the rates at that time it was very low under those contracts. So, it's not a bad thing that those things expired.

So, and they were frac only contracts, so there are no other services bundled, they don't --they were in attach to or connected with other services or pipeline and gathering services that we provide. So they are standalone frac contracts. Those customers will move on and obtain those services from others. And will be better prepared to not only optimize that capacity or use it in our optimization, but continue to serve our long term full-service customers.

And the phenomena of these legacy contracts is not a reflection on the previous owners. It's a reflection of the market, much like what you see today with tight fractionation capacity, completely different market than when these contracts were entered into. So, these are just contracts that have to work their way out of our system because the market is stronger. But one of the reasons the market is stronger is because throughput is going up, and the throughput, we make a lot of money, serving our customers under fee-based contracts, and that's where this optimization volume by our choice is being used. It's to fulfill those obligations to our firm customers.

Okay.

I mean, let's stay with us until you're clear.

No, that's helpful. Thank you. Two quick follow- ups. One, (inaudible) staying in the NGL pipeline, if your firm volumes are higher than what you thought they would be going into the year. How come NGL transported volumes were down sequentially from the fourth quarter?

Michael, that was primarily -- as result of the North System, which is included in that number. So the North System we had record high volumes in the fourth quarter. So that decrease you saw it was primarily the result of that.

Okay. Final one for me, just on the hedging, on the NGL piece, is that mostly at the heavy end, in other words have you hedged any ethane, or is it mostly have it under the barrel?

Now you are talking about the natural gas gathered and process in business.

When you are talking -- that you are talking about 2010?

Yes and '11.

Yes, there would some ethane in those hedges.

Okay. Thank you.

Yes, sir.

Thank you. Our next question comes from Jonathan Lefebvre of Wells Fargo. Your line is open.

Thanks guys. Just a one quick question following up on that as previous question on the energy services, did I understand correctly that the pattern of earnings in this segment should follow kind of the utility pattern where we see the largest upticks in the first and fourth quarters?

Yes, Jonathan, when you stop to think about it and we have made this comment at many of our conferences and have made this same remark over the last several years. Our energy services business is primarily focused on serving utilities therefore our earning pattern at energy services has and will follow the earnings pattern of the utility. And if you look at our utilities, they tend to in other utilities, they tend to make most of their earnings in the first quarter and the fourth quarter and in many cases you lose money in the second and third. So, because our customers are utilities, predominantly, that segment is going to follow that earnings pattern, which is the comment Rob was alluding to.

That's helpful. I guess, so, we could an uptake in the fourth quarter. I mean, it seems like historically you did about 55% of the earnings in the first quarter and then about 40 or so, in the fourth of 2009. And I'm just wonder if that would follow kind of similar pattern in this year or it would essentially be flat to maybe slightly down going forward?

Well, the difference, and again, we have publicly stated our intention of reducing the volatility of annual earnings in this segment, so certainly $100 million a quarter does not mean $400 million a year. And as I have explained our pattern going forward is, as it has been in the past is going to be hiring one in four than in two and three. But what is different going forward is also, as we have said many times before is we've hedged higher percentage of our margins relative to storage and transport than we have in the past. Couple of years ago while we were executing the strategy we went in the winter and we typically in energy services went into the winter, which is the fourth quarter with lower hedges on our natural gas volumes in other people's storage field. Because we felt that gas prices were going to increase during the winter months and that was a pretty safe opportunity.

The reality is that, that doesn't always happen, which we learned a couple of years ago. And so what you're seeing this year is going to be more typical to what you're going to see in the future and that is, this is front end loaded. And as Rob pointed out in his remarks, when we see opportunities to do exactly the same thing we did in '09, '10, if we see those opportunities in ten for eleven and eleven and twelve et cetera , et cetera, we're going to take advantage of those and remove that opportunity before earnings volatility.

So, it's not even. It's fair to say fourth quarter is going to be higher. Excuse me, fourth quarter is going to be higher than second and third quarter, but it is. It would not be correct to say that it's going to be the same or you know, relatively closed to being the same. Because of the fact that we've hedged such a high percentage of our energy services business, which is why, we are reaffirming the segments earnings at a $107

Okay. I appreciate it. Thanks.

You're welcome.

Thank you. Our next question comes from [Eve Segal] of Credit Suisse. Your line is open.

Hey, thanks. Good morning everybody.

Good morning.

If I could just -- just three quick classifications. One is on the, again on the optimization side. So, going for once you've complete the borrowing I think if you will -- would you consider holding back capacity or would you end up leasing all of the available capacity?

It's a little bit, like our gathered in processing business in that we scrolled to and we're successful in reducing our people exposure because of our point of view, on our on gas prices relative to grew one might part that we missed that one. But anyway, we will always keep some portion of our fractionation in pipeline system available for optimization. I mean, I think that is one of the embedded options that exist in our assets. And we will keep that open until the market no longer and then tell the market values that fee based arrangement to such an extent the opportunity cost upgrading that incremental space go to the economic work in that favor, did I make sense?

No, it doesn't, I was just debating whether I should ask for [AMB] related to what you just said and I think--?

I think, that should, I mean if you didn't that would be out of character.

All right. I will stay in character. So, what percentage do you think is appropriate to hold back and then in the second aspect of that follow on question. What's the appropriate return that would suggest well, it just doesn't make sense with getting a 18% returns, so with just from everything up and not hold back anything?

Well, it's interesting, that's -- there is now -- I mean, very ahead of into disclose those kind of percentages because there are other people that listen to this phone call than you. So, I think it's fair to say that your Part A and Part B are the right questions and the amount that we withhold is dependent upon the value we can create with that space relative to our next alternative, which is to do the exchange service, bundled service. But to go through and identify how much we're willing to keep it -- that's a lot of competitive information. I think the best I'd suggest you do is, is look at that one slide we present every time we go out, where we do the breakdown of margins. You can see how much of our margin comes from optimization. It's not volume driven as much as it is by what capacity driven, as much it is by what the market gives you.

Okay. And then the other two would be, in terms of the processing new build plant, a 100 million cubic feet. How scalable is that, so that if you -- if there is an opportunity to go from 100 million to 150 million or 100 million to 200 million? How do you think about that and what's the incremental cost to do that?

Terry.

Eve, the way we're installing this particular plant, the site that we've selected will have plenty acreage to install another one. This is a skid-mounted facility, a single train, 100 million a day they train. If we need additional capacity we'll install a twin and we'll have a good template for doing that if we need to.

Okay. So, there is not a whole lot of cost savings to go from 100 million to 200 million then?

Well, I mean, not really. I mean, you'll have to build another plan.

Okay.

You have multiple -- the benefit of having multiple trains is when you finally, hopefully doesn't happen real soon, but when you finally go the other direction as you start shutting [trains]down, it's better to have multiple trains because the plants run more efficiently as you shut the individual trains down.

Okay, got it. Thanks. And then the last question and I might have misheard, if that's the word. In terms of the CapEx for 2010, did you just say that you did not increase it but you just sort of re-jiggled it and if that's the case, does that mean that some projects fell out in 2010?

No, it's not.

Okay.

No, all we're saying is that, we can fund all identified and disclosed projects with our approved capital budget. As those future opportunities develop, based on when they develop, we'll be back in front of our board for additional capital. But we don't see anything on the horizon that would cause us to have to issue equity or debt to fund any of these potential projects. So, we'll wait and see how this develops and then we'll be back in front of our board.

Got it. Thanks guys.

(Operator Instructions)

Our next question comes from Jeremy Tonet of UBS. Your line is open.

Hi Jeremy.

Hi, good morning.

How are you?

Good. Sorry, I don't mean to be a dead horse here. But on the Natural Gas Liquid segment, if you look at the operating income sequentially, fourth quarter versus first quarter of this year. Would you describe the delta being solely to the optimization in the measurement adjustment or was there any other factor in place if you look at it in sequential quarters?

Terry.

Yeah. I think the biggest impact would be reduced volumes on North System and sequentially some impact from an optimization perspective as well.

Okay. Great. And then as far as the (inaudible) improving across the year allowing more optimization opportunities, do you see that improving kind of ratably throughout the year or is that kind of lumpy? If you could give any color on that, that be helpful.

Jeremy, it's more lumpy. It is not ratable, it is more lumpy and the quantities we're talking about are fairly large.

One other thing I like to, one comment about optimization just so we're clear. Optimization today there is an opportunity to make dollars and we're now making them because there is opportunity cost issue but optimization is not always in the money. So, I mean, it is optimization, it's an option that exists; it's an embedded option that exist in assets. So want to be clear that -- that's why this, if you look historically at the percent our margin it comes from this bucket, that's why, sometimes it's in and sometimes it's out.

Okay, great. That's very helpful. Thank you.

You bet, Jeremy.

Okay. Well, this concludes the ONEOK and ONEOK Partners conference call. As a reminder, our quite period for the second quarter will start when we close our books in early July and will extend until earnings are released after the market closes on August 3rd. Our second quarter conference call is scheduled for the following day, August 4th, and we'll provide additional conference call information at a later date. Andrew Ziola and I will be available throughout the day for follow-up questions. Thanks for joining us.

Ladies and gentlemen, thank you for attending today's conference. This does conclude the program. You may now disconnect.