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 call is being recorded.
I would now like to introduce your host for today’s conference call, Mr. Dan Harrison. Sir, you may begin 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 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 are also reaffirming the 2010 earnings guidance for both entities reflecting our confidence in continued strong performance of our businesses. Energy services performed inline with our expectations.
Benefiting from increased storage and marketing margins net of hedging. We are on track with our efforts to reduce annual earnings volatility in this segment by reducing our least 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 million plus capital investment program. With higher NGL volumes gathered fractionated and transported.
In the partnerships NGLs 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 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 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 unitholders and dividends to shareholders. The partnership increases quarterly distribution another penny last week, representing a 40% increase since we became general partner four year 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 of ONEOK Partners. ONEOK Partners continues to develop additional growth opportunities, which will not only create value for the partnership unitholders, but also for ONEOK as sole general partner and 43% owner.
Our announcement last week of 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 EBTIDA 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 and 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 fourteenth distribution increase since ONEOK become 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 to $490 for the year and estimate that partnerships 2010 distributable cash flow to be in range of $580 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 expenditure for the 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 businesses segments to accommodate the timing of certain projects associated with our recently announced expansions in the Bakken and Woodford Shale plays. The total amount of capital expenditures remains unchanged. We have identified additional growth projects for 2010 that we likely resulted an increase 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 partnership’s natural gas gathering and processing segment, which has the most sensitivity to commodity price changes.
For the remainder of 2010, we have hedged 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 risk. 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 our $1 billion revolving credit agreement, and the partnerships total debt-to-capital ratio was 51%.
The partnership’s 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 used 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 as they 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 and processing segment's first quarter financial results were lower compared with the same period in 2009, due primarily to lower gathered volumes, primary in 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 coalbed 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, our 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 and 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 due to the natural gas liquids content and associated crude oil and condensate production.
We remain confident in this segment achieving this 2010 operating income guidance with continued growth in processing volumes and more than 70% of overall margin hedged. We’ve already placed some hedges for 2011 and we’ll continue to evaluate additional hedging opportunities as the year progresses.
I would like to add some additional color on 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 Shales. We are the largest independent operator of natural gas gathering and processing facilities in the Bakken shale.
We have seen significant increases in driven rig counts within for coal gathering area. Horizontal drilling and hydraulic fracturing techniques have resulted in new wells producing as much as 1500 barrels per day of oil and 1 million cubic per day NGL rich natural gas with NGL content in excess of 10 gallons per Mcf.
Current drilling economics in the Bakken are attractive and produces have plans to continue drilling for many years to come. We have large acreages 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 at capacity.
As a result, we will construct a new 100 million cubic feet per day gas processing facility, the Garden Creek plant and invest in expansions, upgrades additional compression and new well connects. The new plant 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 any rig counts remain at current levels, the new wells drilled and completed on acreage dedicated to us could exceed 2400 through 2016.
Now some highlights on Woodford Shale projects where the partnership will invest $55 million between now and 2011. Our western Oklahoma Systems are near capacity because of the increased drilling activity in the Cana Woodford Shale and the Colony Wash development, while 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 Cana Woodford which are horizontally drilled can produce as much as 8 million cubic feet per day with NGL contact of four to five gallons per Mcf. One of the projects will connect our western Oklahoma gathering system to our existing Maidsville 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 predominately fee-based segment had another exceptional quarter strong first quarter results were driven by the Guardian 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 margin.
For the first quarter of 2010 our interstate and intrastate pipelines were approximately 91% subscribed under demand based rates compared with 79% in the first quarter of 2009. The FERC recently announce its approval and authorization for TransCanada to construct the Bison pipeline that will connect to Northern Boarder pipeline.
Thereby connecting Rockies supply with upper Midwest markets and diversifying Northern Boarder pipelines to supply sources. Bison is expected to be in service in November of this year. We remain focused 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 Liquid 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 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 captured optimization opportunities which is being use 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 revolved as we move thorough the year, when more fractionation capacity becomes available to us primarily through the expiration of certain contracts. We remain committed to maximizing our bundle, first the full service gathering, fractionation and transportation capability, while reducing standalone fractionation only services. So at certain fractionation only agreements 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 inline with our expectations with continued growth expected throughout the year.
NGLs fractionated during the first quarter increased 492000 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 and investment in additional pump stations to increase its capacity over the next few years.
Arbuckle throughput is inline with our expectations at about 60,000 barrels per day and is well positioned to accommodate mid-continent and Barnett Shale production growth. We remain confident in achieving our 2010 operating income guidance for the Natural Gas Liquid segment. Although the first quarter was reflect of 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 our customers expect.
Now let’s discuss the NGL markets. On the demand side, petrochemical demand remains robust. The petrochemical chemical 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 a burn stock for motor gasoline as a denaturing for ethanol, a petrochemical feedstock and as diluent for Canadian oil essence.
Ethane demand is expected to reign relatively high within improving US demand picture and continued wide proved to natural gas ratios. We also believe there are more 100,000 barrels of additional ethane demand, related to the conversion of heavy-end crackers to ethane and another 100,000 barrels of per day of excess ethane cracking capacity available in Canada.
On the export front, vast majority of the US ethylene derivative demand comes from Canada, Mexico and South America. With about 10% to 20% of the export demand being consumed in Asian markets. While recent Asian demand has cooled a bit, double-digit demand growth per year is still expected.
The US Petrochemical industry is very competitive globally for the production of ethylene derivative due to the relatively low price of US NGLs. In addition our countries access to improve an ability to quickly develop natural gas and natural gas liquids research, at a relatively low cost keeps you and feed stock cost for US petrochemical 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 catch these opportunities and provide our customer 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 process plant currently under construction that will be completed by the end of this year. This will increase supply into our Arbuckle pipeline and our (inaudible) fractionation facility.
As we said before, as NGL growth continues we will carefully evaluate our NGL infrastructure growth opportunities with this new Shale plays becoming more prevalent and the need for NGL takeaway solutions. We continue to meet with NGL producers and customers particularly in the Bakken and Marcellus, whether an existing our new shale plays in project we develop will be the result of a disciplined approach that creates value for the customer in exchange, the customer who long-term supply could may be to us.
John that concludes my remarks.
Thank you, Terry, congratulations on great quarter. At this time Curtis will provide us some detailed look into ONEOK, its financial performance and then Rob Martinovich will follow; will provide a review ONEOKs’ 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 reframed 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 to $170 million due to higher than previously forecast, accelerated tax depreciation deductions, resulting and 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 estimate of $584 million. By virtue ONEOK’s general partners interest and significant ownership position, ONEOK received $73 million in distribution from the partnership during the first quarter, a 6% increase from 2009. At the partnerships estimated distribution level as detailed in the 2010 guidance. ONEOK expect to receive approximately $304 million in distribution 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 and storage. As natural gas was full from storage during the quarter ONEOK’s standalone debt-to-equity was reduced 39% from 46% and as 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, increased our investment in 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 remain committed to our targeted long-term dividend payout ratio of 60% to 70% of recurring earnings, due to the stability of earnings and 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’ll 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 costs and integrity management cost that were previously deferred but are now recovered in best rates. Some of the headlines of past heating stated this was year of a sudden winter seasons stated this was the year of the Southern winter. Much of our service territory in particular Oklahoma and Taxes experienced higher then normal snow fall, plus significantly higher heating degree days compared with 2009, and what is considered normal.
While our utility is experienced higher debt 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 couple 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 projects to install automated meters in 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 based rate structure, creating a win-win for customers and the company.
With that, I will briefly discuss the latest regulatory updates in our states beginning in Oklahoma. In late January we filed on application requesting recovery of the integrity management program cost deferred in 2009 of $15.7 million. The Oklahoma Corporation commission has anticipated to approve our application in hearing schedule June 17. As filed this will have no impact on earnings.
Moving to Kansas, in mid December Kansas get service filed an application with the Kansas Corporation commission to become in 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 continued upon the KCC approving a rate mechanism for revenue decoupling and allowing recovery 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 Counsel earlier this month. We’ll appeal this decision to Railroad Commission of Texas within the 30 day period, which expires on May 13. The railroad Commission will have a 185 days after RPL is filed to rendered decision. For 2010, we remain confident $223 million operating income guidance for our distribution segment.
Now let’s turned to Energy Services, we experienced the very good first quarter. Our results would driven primarily by increased storage margins, as a result of riders seasonal storage differentials because of hedges we put in place 2009. An 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 experience in our core regions. Offsetting these increases will decrease in premium services revenues. Although, the level of service under contract was similar, the piece we were able to collect was 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 25 Bcf, down from last year’s 46 Bcf. This decreases due primarily the colder than normal regional weather in the first quarter compared with the first quarter of 2009, plus the year-over-year reduction of a leased capacity.
We currently had 83 Bcf of storage capacity under lease, compared with 91 Bcf at the end of the first quarter of 2009. Our April 28, 2010 inventory balance is approximately 34 Bcf. As part of our ongoing realignment of stores and transportation capacity to meet the requirements of our premium services customers, we anticipate further storage capacity reductions, to 71 Bcf by the end of this year and 61 Bcf by the end of 2011.
We expect our long term transportation capacity to be at 1.3 Bcf per day by the end of 2010 and approximately 1 Bcf per day by the end of 2012, compared with our current long term transportation capacity of 1.4 Bcf per day. This capacity reduction targets those assets with lower than average unit margins. These actions were also help to reduce our year-over-year earnings volatility and working capital requirements.
Energy Services 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 lowed 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 narrower natural gas location differentials and limited optimization opportunities as result of reduced market volatility. For the fourth quarter we expect narrower seasonal differentials compared with 2009 and reduced premium services revenues as a result of falling commodity prices and reduced market volatility.
For the November and December withdrawal 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. As stated in our last conference call, we’ll complete our storage hedges for the year as we inject gas into storage or financially it's quite significantly widened. For transportation, we’ll continue to be opportunistic, if differentials widened in the summer, we’ll put additional hedges in place, if they don't we’ll optimize our position in the daily marketplace.
John, this concludes my remarks.
Thank you, Rob and also I’d like to acknowledge to have McDonie and Pierce Norton for obviously, two very strong quarters from two segments. Thank you very much. As you just heard, we had solid first quarter operating performance and we’re 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 foreign customer commitments in place.
Finally, as Curtis pointed out ONEOK’s balance sheet strength significant free cash and financial flexibility provide us, where with all 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 in ONEOK, who is 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.
(Operator Instructions) Our first question comes from Stephen Maresca of Morgan Stanley. Your line is open.
Stephen Maresca - Morgan Stanley
Just trying to understand on the OKS side, the less pipeline 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 an 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 at this way and then Terry can fill in some details and areas that I miss. If you think of it from a simple standpoint and if you could digitalize a pie chart, you’ve got one large area in that pie chart that whether explanation capacity or pipeline capacity is used for the purpose 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 it’s not consumed by or needed for that fee-based margin that so to speak, the exchange contracts.
What has occurred and the reason is short term normally is that as we looked at our contract portfolio inside the NGL segment. As Terry mention in this comments, we had a number of fractionation only type contracts. They were consuming space if you will in that fee-based area and also we had volume associated with the exchange contracts and that volumes has come our system that faster way than we anticipated.
As also Terry pointed out, we’re at new capacity already on Overland Pass Pipeline and so the amount of space in the smaller section of the part is available to optimize is strong royalty to year ago because we had more balls coming under the fee-based structure, now the auction like candidly was and could have been to back out our fee-based customers and utilize that space to optimize price product differentials and location differentials, but that’s not the way we do business.
So what happens is we work these contracts out that we’ve identified and have been identified for sometime and then that space returns for optimization, but clearly it’s quite simply and exchange or an opportunity cost issue relative to doing your fee-based business versus what’s available for optimization. Does that give you, I mean -- do you want, Terry to give you more detail.
Stephen Maresca - Morgan Stanley
No, that is very helpful. So I appreciate it and one follow-up in a little bit different area. Obviously, there are 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% volumes are made or 100% fee-based, if you can just share some light?
Sure, Steve. The contracts structures had evolved due to the hard demand. We’re seeing and gathering and processing business NGLs of minimum volume requirements. The producers are agreeable to commit to a minimum volume for an exchange for us building infrastructure and making capital investments. On the NGL side of the business, we’re seeing farm-to-fork contracts, as farm transportation contracts went historically in this business, such things did not exist. So you are seeing a level of farm becoming very prevalent in both this gathering and processing and in the NGL segment.
Stephen Maresca - Morgan Stanley
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?
Thank you. Our next question comes from Becca Followill - Tudor Pickering Holt
Becca Followill - Tudor Pickering Holt
Just one, quick one, on energy services, do you have expectations that in the second and third quarter as we could see losses there, just trying to model across the year?
Becca, this is John. We don’t give quarterly guidance -- this 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.
Our next question comes from Ted Durbin of Goldman Sachs. Your line is open.
Ted Durbin - Goldman Sachs
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're adding a 100 day and then the liquids as it comes out, where do the liquids find the home or did it have been going?
Ted, to answer your first question, we’re installing $100 million a day process in plan, that's going to effectively double our current throughput and production. So we have an existing plan at there, its $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 rates continue and they’re actually continue to trend up or it could be a possibility of even further expansion; so on a gas front very strong.
On the NGL front, most of liquids there -- actually all the liquids there they serve the local markets, so as well as they railed out to other market areas. So there is no pipeline, it serves that region and clearly we’re looking at that opportunity as well and talking to other processors and producers in that region for possible commitments.
Ted Durbin - Goldman Sachs
I guess would you consider building the pipe itself or would you start parties or how are you thinking about that?
We’d build that ourselves.
Ted Durbin - Goldman Sachs
Just one the natural gas liquid segment, these gives you just have these measurement adjustments? Should we considered those as recurring or more onetime the $7 million there?
No they’re one time.
Ted Durbin - Goldman Sachs
Then second is about the distribution it looks like the OpEx was up pretty big year-over-year, but you're going to get most of that recovered to your rates, I mean just walk us through the changes there?
Would you like to take that?
Yes, John I will; forgot my protocol. Ted, we got $3.1 million related to a condition of previously differed 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 the delta that you are looking at of income year-over-year, I think that goes down to just higher employee related costs and I’m sure what that is.
(Operator Instructions) Our next question comes from Michael Blum of Wells Fargo; your line is open.
Michael Blum - Wells Fargo
Just back to the NGL to pipeline and the bottle necks, just I guess I’m still little 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 the thought process and doing so and quantify that delta anyway you can?
Not always true, that is not always true statement. In another way, which are another high level way of understanding what this segment is incurring as if you use the analogy of trunk transport versus interruptible transport. You enter into contracts which provide you a farm obligation to deliver and that space is not being utilized by those farm customers, you’re able to optimize or use under interruptible basis.
As we look forward to this year, we did not expect as higher level of throughput for both pipeline and fractionation capacity. We have found that our customers under firm transport if you have used more other space than we anticipated. In anticipation of that build in throughput, we had already identified certain contracts that needed to be terminated. Because of the build up, 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 depended upon the market is 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 in the same thing is true here, we entered into these fee-based firm contracts and because of the volume has picked up little faster than we anticipated and we put our plan together that has diminished our ability to optimize. So let me ask Terry to put his slant on this.
Michael I think, the only thing I could add to John's comment are that in reiterate, is that the contracts that we’re talking about that are expiring, our contracts that occur in Gulf Coast and those are legacy contracts that we entered into many years ago back when the frac market war oversupplied that is there was more frac capacity that there was a need. So the rates at that time were very low under those contracts. So it’s not a bad thing that those things expire.
So and were frac-only contracts, so there are no other services bundled, they want the tax too or connected with other services or pipeline and gathering services that we provide. So their standalone frac contracts, those customers will move on and obtain those services from others; and we’ll be better prepared to not only optimize that capacity or use it in our optimization, but continue to serve our long-term for service customers.
In the phenomena of these legacy contracts is not a reflection on the previous owner, it’s a reflection of the market much like what you see today with type fractionation capacity, completely different market then when these contracts were entered into. So these are just contracts that have to work away out by our system, because the market is stronger. Sot one of the reasons the market stronger is, because throughputs 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 is to facile those obligations to our firm customers. Stay with us until you clear.
Michael Blum - Wells Fargo
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 a result of the North System, which is included in that number, so the North System we had there record high volumes in the fourth quarter. So that decrease you saw was primarily the result of that.
Michael Blum - Wells Fargo
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 been under the barrel?
You’re talking about the natural gas gathering and processing business.
You’re talking about 2010?
Michael Blum - Wells Fargo
Yes and '11.
Yes, there was some ethane in those hedges.
Thank you. Our next question comes from Jonathan Lefebvre of Wells Fargo.
Jonathan Lefebvre - Wells Fargo
Just a one quick question following up on Becca’s 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’d see the largest up ticks in the first and fourth quarters?
Yes, Jonathan when you stopped think about it and we've made this comment as many of our conferences and have made the 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, and other utilities they tend to make most of their earnings in the first quarter and the fourth quarter and in many cases 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.
Jonathan Lefebvre - Wells Fargo
I guess, so if we could see an up tick 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. I'm just wonder if that would follow kind of a similar pattern in this year or if it would essentially be flat to maybe slightly down going forward?
It’s a good difference and again we have publicly stated our intention is reducing the volatility, annual earnings in the segment. So certainly $100 million a quarter does not mean $400 million a year; and I’ve explained our pattern going forward as it has been in the past is going to be higher one and four than in two and three, but what is different going forward is also as we have said many times before, as we’ve hedged a higher percentage of our margins relative to storage and transport that we have in the past.
A couple of years ago, while we were executing the strategy, we went into the winter and we typically in Energy Services this is went into the winter, which is the fourth quarter with over 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 doesn’t always happen, which we learned a couple of year ago.
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 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 for ’10. If we see those opportunities in ’10 for ’11 and ‘11 and ’12 et cetera, et cetera, we’re going to take advantage of those and remove that opportunity for earnings volatility.
So it’s fair to say fourth quarter is going to be higher than second and third, but I would not to say that it’s going to be the same or relatively close to be the same, because of the fact that we’ve hedge such a high percentage of our Energy Services business, which is why we are reaffirming the segment’s earnings at 107.
Thank you. Our next question comes from Eve Segal of Credit Suisse.
Eve Segal - Credit Suisse
If I could just three quick clarifications: one is again on the optimization side. So going forward, once you’ve complete de-bottlenecking 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 gathering and processing business and that we serve to and we’re successful on reducing our people exposure, because of our point of view on gas prices, royalty accrue one might argue that we might miss 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 option that exists in our assets. We will keep that open until the market no longer until the market values the fee-based arrangement to such an extent the opportunity cost to driving that incremental space go the economic work in that favor.
Eve Segal - Credit Suisse
No, it doesn’t, I was just debating whether I should ask part A and B related to what you just said and I think…?
I mean if you didn’t would be other character.
Eve Segal - Credit Suisse
Alright, 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 is, what's the appropriate returns that would suggest well, it just doesn't make sense we’re getting a 18% returns, or with just from everything up and not hold back anything?
I mean very hesitant to disclose those comments percentages because, there are other people who will listen this phone call then 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 depended upon the value we can create with that space relative to our next alternative, which is to do the exchange service bundled service.
Let's go through and identify how much we’re willing to keep it. I mean that's a lot of competitive information. I think that’s the best thing that I suggest you do with 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 capacity driven as much as it is by what the market gives you.
Eve Segal - Credit Suisse
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 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?
Eve, the way we’re installing this particular plant the site that we’ve selected will have 20 acreages to install another one, this is a skid mounted facility as single train, 100 million of that 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.
Eve Segal - Credit Suisse
So, there is not a whole lot of cost savings to go from 100 million to 200 million then?
Not really I mean, you’ll have to build another plant and you have multiple train the benefit of having multiple trains is when you finally hopefully doesn’t happen we’re soon when you finally go the other direction as you start setting train down, it’s better to have multiple trains, because the plants run more efficiently as you set the individual trains down.
Eve Segal - Credit Suisse
Then the last question and I might have misheard to that word. In terms of the CapEx for 2010, did you just say that you did not increase it, but you just sort of [regiggled] it and if that's the case, does that mean that some projects fell out in 2010?
No, it not. 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 will be back in front of our board for additional capital, but we don’t anything on the horizon that would cost us to have to issue equity worked at to fund any of these potential project. So let’s see how this develops and then we’ll be back in front of our Board.
Our next question comes from Jeremy Tonet of UBS; your line is open.
Jeremy Tonet - UBS
Sorry, I don't mean to beat 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 were there any other factor in place if you look at it in sequential quarters?
Yes, I think that’s the biggest impact would be reduced volumes on the note system. I mean and sequentially, some impact from an optimization perspective as well.
Jeremy Tonet - UBS
Then as far as the bottlenecks improving throughout 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 lumpier, it is not ratable, it is lumpier and the quantities we’re talking about are fairly large.
One another thing I like to one comment about optimization today there is an opportunity to make dollars and more not making them because this opportunity cost issue but optimization is not always in the money. So it is optimization it’s an option that exist, it’s in embedded option that exist in asset. So want to be clear that’s why this, if you look historically at the percent or margin it comes from this bucket that’s why sometimes it’s in, and sometimes it’s out.
Well, this concludes the ONEOK and ONEOK Partners conference call. As a reminder, our quiet 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 close as on August 3. Our second quarter conference call is scheduled for the following day August 4 and we’ll provide additional conference call information at a later date. Andrew Ziola and I will be available throughout the day for any follow-up questions. Thank you for joining us.
Ladies and gentlemen, thank you for participating in today’s conference. This does conclude the program. You may now disconnect.
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