歐尼克 (OKE) 2010 Q3 法說會逐字稿

Good day, ladies and gentlemen, welcome to the third quarter 2010 ONEOK and ONEOK Partners earnings conference call. At this time all participants are in a listen-only mode. Later we will conduct are a question-and-answer session and instructions will be given at that time. (Operator Instructions) As a reminder, today's call is being recorded.

At this time I would now like to turn the conference over to your host, Mr. Dan Harrison. Sir, you may begin.

Thank you. Good morning and thank you, everyone, for joining us. Any statements made during this call that might include ONEOK or ONEOK Partners' expectations and 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 defer 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. 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 many thanks for joining us today and for your continued investment and interest in ONEOK and ONEOK Partners. Joining me on the call today are Curtis Dinan, our Chief Financial Officer for both ONEOK and ONEOK Partners; Terry Spencer, our Chief Operating Officer of ONEOK Partners; and Rob Martinovich, Chief Operating Officer of ONEOK. We completed another successful quarter at both ONEOK and ONEOK Partners. At the partnership segment, both third quarter and nine-month results reflect higher NGL volumes and higher contracted natural gas transportation. In a few minutes, Terry will provide you with more detail on the partnership's activities. Our ONEOK Distribution segment continues to benefit from our new performance -based rates in Oklahoma, which reduced volumetric sensitivity and increased revenues in the warmer months. And, as expected, the Energy Services segment's third-quarter results were lower but remain on track to earn $126 million this year, and we continue to make progress on reducing our contracted storage and transportation capacity to mitigate annual earnings volatility.

In late September, we updated our 2010 earnings guidance for both ONEOK and ONEOK Partners and remain confident we will achieve those results. Also during the quarter, we announced additional growth projects at ONEOK Partners, another gas processing plan in the Bakken Shale and a new natural gas liquids pipeline that will transport NGLs out of the Bakken to the Mid-Continent, bringing our total to more than $1.5 billion of new projects announced this year.

These new projects, along with the $2 billion of projects we completed late last year, will benefit not only the partnership, but also ONEOK in the form of increased earnings and cash flow in the future. Our visibility into future potential earnings and cash flow growth give us the confidence to project 14% to 18% EBITDA growth over the next three years at the partnership, which will result in continued distribution growth during that period. We just recently increased the distribution by another $0.01, which results in a 40% increase since we became sole general partner four-and-a-half years ago. Over the next three years, we believe this growth at the partnership, along with the continued contributions from our other segments, will result in 8% to 10% annual net income growth at ONEOK, and 50% to 60% dividend and growth while generating $150 million to $250 million in free cash flow per year.

Our investments, along with the efficient and prudent use of cash, have been a significant part of our effort to create value for shareholders. As ONEOK has benefited from the partnership's many capital investment, we have continued to grow the dividends. Just two weeks ago the Board approved a 2% per share dividend increase, which is in addition to the two $0.02 per share increases we declared in January and July. At the same meeting, the Board also authorized a three-year $750 million stock repurchase program. Curtis will provide additional financial insight into ONEOK later in our call, but first he'll review ONEOK Partners' financials and then Terry will review the partnership's operating performance. So at this time, let me turn the call over to Curtis.

Thanks, John, and good morning, everyone. John has already provided a brief summary of the partnership's third-quarter results and Terry will provide additional detail in a moment. My remarks will focus on our financial results and outlook. In the third quarter, ONEOK Partners reported net income of $142 million, or $1.09 per unit, compared with last year's third-quarter net income of $122 million, or $1 per unit. Third quarter results included a $16 million gain related to the sale of a 49% interest in Overland Pass to Williams Partners. That gain had a $0.16 per unit impact on the partnership's third quarter results. On a prospective basis, Overland Pass has been deconsolidated in our financial statements and is now reflected as equity earnings from investments.

In the third quarter, we had 101.9 million units outstanding compared with 96.4 million units in the same period last year. Our equity offering in February, 2010, added approximately 5.5 million additional units. Distributable cash flow in the third quarter was $156 million, compared with $144 million in the third quarter 2009. While the coverage ratio for the first nine months of 2010 was slightly below one times, the coverage ratio for the third quarter was 1.09 times, and we expect the 2010 annual coverage ratio to be greater than one times. For the third quarter, the partnership increased the distribution $0.01 to $1.13 per unit, representing an annualized rate of $4.52 per unit. This is the 16th distribution increase since ONEOK became sole general partner in April 2006. Subject to Board approval, we plan to increase the distribution $0.01 per quarter through 2011 and 5% to 10%, annually in 2012 and 2013.

In late September, we updated the partnership's 2010 earnings guidance in the range of $450 million to $470 million to reflect higher-than-anticipated earnings in the natural gas pipeline segment, offset by lower expected earnings in the natural gas gathering and processing segment and the natural gas liquids segment. We also updated our 2010 capital expenditure guidance to $464 million, comprised of $394 million in growth capital and $70 million in maintenance capital. We used the $424 million we received from the Overland Pass transaction to reduce our short-term debt and fund a portion of our capital expenditures, effectively eliminating a long-term debt offering that had been planned for this year. We don't anticipate any additional financing this year, but we will continue to monitor the capital markets and take advantage of opportunities that are presented. The partnership's next scheduled long-term debt maturity is not until March 2011 when $225 million comes due. We have chosen not to call any of our long-term debt early and refinance the debt in today's low interest rate environment, as the make-whole provisions included in our debt agreements are too expensive.

At the end of the third quarter we had $326 million outstanding in commercial paper and $674 million available under our $1 billion regret he -- revolving credit facility. The partnership's total debt-to-capital ratio was 49% and its debt-to-EBITDA ratio has improved to 3.8 from 4.5 at December 31, 2009. 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 hedges on 99% of our expected natural gas equity volumes at $5.55 per MMBTu and 65% of our expected NGL and condensate equity volumes at an average price of $1.25 per gallon. For 2011, approximately 74% of our expected natural gas equity volumes are hedged at $5.72 per MMBTu and 18% of our expected NGL and condensate equity volumes are hedged at an average price of $1.37 per gallon. As is our practice, we continually monitor the commodity markets and will place additional hedges as conditions warrant to mitigate our overall risk. Now, Terry Spencer will provide you with an overview of the operating performance at the partnership.

Thanks, Curtis and good morning. The partnership had a solid operating performance in the third quarter from all segments, driven primarily by volume increases in both the natural gas and natural gas liquid businesses from our $2 billion-plus plus growth capital program we completed last year, and from recording the gain on the sale of the 49% ownership interest in Overland Pass Pipeline to Williams Partners. Similar to the second quarter, the benefit of these higher natural gas liquids volumes was offset by lower optimization margins in the natural gas liquids segment due to limited fractionation and transportation capacity available for optimization activities and narrower NGL product price differentials between Conway, Kansas, and Mont Belvieu, Texas, NGL market centers.

As I discussed in our second quarter call, we expect margins to significantly improve in the near- and long-term future for several reasons. First, on September 1, an significant NGL legacy contract expired, freeing up space at our Mont Belvieu fractionator that is now being used to serve bundled service fee-based contracts and for optimization activities. Second, additional fractionation capacity from the 60,000-barrel-per-day fractionation services agreement with Targa will become available in the second quarter of next year. Third, we announced a few months ago a 50,000-barrel-per-day of our Sterling 1 NGL distribution pipeline that will allow us to move more NGL purity products from the Mid-Continent to the Texas Gulf Coast.

I will now briefly discuss the operating performance of ONEOK partners segment, the gathering and processing segment's third quarter financial results were slightly lower compared with the same period last year, due primarily to lower net realized commodity prices and lower gathered volumes, primarily in the Powder River Basin in Wyoming. The declines in the Powder River Basin are due to reduced drilling activities since natural gas produced in the Powder is dry gas, giving producers less economic incentive to drill. We have also seen lower gathered volumes in some conventional basins in Kansas and western Oklahoma due to brief periods of ethane rejection and operational-related outage. For 2010, we expect our gathered volumes will be down 1% to 2% compared with last year from the impact of reduced drilling in the Powder River. Offset somewhat by volume growth at our Grasslands natural gas processing plant in Williston Basin, which we expect to be full by the end of this year, as well as from incremental volumes from the Woodford Shale system expansions we announced in April.

Process lines for the third quarter were slightly higher compared with last year. Our strong presence in the growing natural gas liquids-rich Bakken Shale in North Dakota, the Woodford Shale and the Granite Wash regions have offset other declined. For the year, we will expect our processing volumes to be approximately 4% higher than in 2009. We updated our operating income guidance for 2010 in late September to $155 million from $172 million, reflecting lower-than-expected processing volumes and lower commodity prices for the balance of the year, compared with our original plan we completed in late 2009. The impact from lower commodity prices has been mitigated through our hedging activities that Curtis mentioned earlier.

Now, moving to our natural gas pipeline segment. Third quarter results, including our 50% interest in Northern Border Pipeline, were outstanding. Earnings from Northern Border nearly doubled when compared with the same period last year due mainly to an increase in contracted capacity and as a result of strong Midwest market demand. TransCanada announced on their conference call last week that the Bison Pipeline project, targeted to come online in November, has been delayed until December, and that a significant amount of Northern Border's capacity has been successfully contracted into April of next year. Our increased guidance of $165 million for this segment reflects higher earnings from increased demand for park and loan transportation services on our pipeline.

Now, let's go to our national gas liquids segment. As I discussed earlier, the natural gas liquids segment benefited from higher NGL volumes gathered, fractionated, marketed and transported, primarily as a result of the completion of the Arbuckle Pipeline and the lateral pipelines on Overland Pass and the gain on the sale of the 49% ownership interest in Overland Pass Pipeline to Williams Partners. NGL volumes fractionated during the third quarter were approximately 500,000 barrels per day, more than 91% of capacity, further emphasizing that fractionation capacity continues to be tight.

Our operating statistics in the news release, NGLs transported on our gathering lines reflect Overland Pass be deconsolidated as of early September. NGLs transported on our gathering lines were up 13% to 436,000 barrels per day compared with 385,000 barrels per day for the same period last year. NGLs transported on our distribution lines increase 2% to 455,000 barrels per day. Overland Pass Pipeline volumes are currently averaging approximate 120,000 to 130,000 barrels per day, approaching the Pipeline's current capacity of 140,000. These increases are necessitating continued expansion, such as those announced in July, and we expect the capacity to increase to 255,000 barrels per day during 2013.

Arbuckle averaged almost 93,000 barrels per day during the quarter and is currently averaging approximate 120,000 barrels per day, in line with our expectations, and is well-positioned to accommodate additional volumes from Rockies, Mid-Continent and Barnett Shale production growth, as our access to more fractionation capacity in Mont Belvieu increases. Current Arbuckle capacity is 160,000 barrels per day with plans to expand the capacity to 240,000 barrels per day in 2012. The average price differential for ethane between the Conway and Mont Belvieu market centers was $0.10 per gallon during the quarter, compared with $0.15 during the same period last year. A few notable items that may have impacted the Conway to Mont Belvieu differentials during the quarter include a number of maintenance outages at Gulf Coast Petrochemical crackers, as well as increasing NGL volumes being transported via Arbuckle into Mont Belvieu.

We reduced earnings guidance for this segment in September to $267 million, primarily due to lower-than-expected NGL volumes gathered and transported as a result of the timing of certain supply commitments, as well as the lower optimization margins for the first nine months of this year and narrower expected NGL product price differentials anticipated for the rest of the year.

Now, some additional color on the NGL markets. The petrochemical industry continues to find ways to crack more ethane due to its continued strong price advantage through retooling and potential restarts of idle crackers. Export demand for ethylene derivatives continues to be robust, so

over the next couple of years, we see ethylene demand remaining strong as the ethane-to-crude ratio remains relatively low. Additionally, low natural-gas-to-crude ratios will continue to be a key driver in keeping ethane a highly attractive petrochemical feedstock. NGL infrastructure and fractionation capacity remains tight, but will gradually improve as the new frac capacity comes online over the next couple of years. Looking at the NGL supply picture, we see producers very focused on liquid-rich plays such as the Bakken, Caney/Woodford, Granite Wash and the Eagle Ford shales.

While NGL growth continues at a rapid pace, much of the growth in volumes is being offset by the inherent natural decline of the base natural gas production, which, by some experts, exceeds 20% per year and it is getting steeper each year with more shale gas. This assumes 20% decline rate, and if applied to roughly two million barrels per day of NGLs produced from US natural gas processing plans results in a 400,000-barrel-per-day hole that has to be filled just to remain flat compared with the previous year. We and others believe that NGL demand will be sufficient over the next few years, and that regional processing and NGL infrastructure expansions will, in fact, continue to be needed.

As I touched on earlier, NGL demand continues to be robust as the petchems continue to demand more NGLs, particularly ethane, due to its price advantage. Our discussion with industry experts indicate that petrochemical demand from heavy to light feed convergence could create another 100,000 barrels per day of demand. Exports of NGL should also further help demand keep pace with supply, with increased propane export demand, as well as growing ethane demand in Canada due to it declining ethane supply.

Now, a few comments on our the recent growth projects. In aggregate this year, we have announced plans to invest approximately $1.5 billion in Barnett Shale related-projects. In the Williston Basin, the Bakken and the underlying Three Forks formations are oil plays, which also produce NGL-rich associated natural gas. Attractive crude oil economics and new technology are pushing rig counts higher, and the midstream infrastructure must be built to allow producers to fully monetize their oil and natural gas reserves.

Our gathering and processing segment has a very large and well-established gathering and processing footprint overlaying the Bakken and Three Forks development. Our long-standing relationships with producers, extensive contracted acreage dedications and operating history are the keys to our future growth, and clearly provide us with an advantage as we compete for new supplies. We have announced approximately $700 million in gathering and processing growth projects in the Bakken Shale, which includes two 100 million cubic feet per day natural gas processing plants, the Garden Creek plant and related infrastructure and the Stateline I plant and related infrastructure, which will triple our processing capacity in the region to nearly 300 million cubic feet per day. We are also evaluating the installation of another new plant, Stateline II as volumes continue to grow.

We also have more than 700 million in NGL infrastructure projects related to the Bakken growth, which includes the 500-plus-mile, 60,000 barrels-per-day raw NGL pipeline, referred to as the Bakken Pipeline, that will connect with Overland Pass. This new pipeline, scheduled to be complete in 2013, will receive raw NGLs from our plant in the Williston, as well as from third party processing plants. Included in that project are expansions of Overland Pass Pipeline, and our Bushton, Kansas, fractionation capacity by 60,000 barrels per day to accommodate those additional volumes. Also on the NGL side, we are expanding our Sterling I NGL distribution pipeline by 15,000 barrels per day, enabling us to transport to Mont Belvieu additional NGL purity products out of the Mid-Continent for our customers under fee-based contracts and to increase the capacity available for our optimization activities. The expansion will begin later this year and is expected to be completed in the second half of 2011.

In addition to the $1.6 billion of growth projects we have already announced, we are continuing to evaluate a lengthy backlog of natural gas- and NGL-related infrastructure projects, some of which we have already briefed you on, including another gas processing plant in the Bakken Shale, the Stateline II plant and the NGL pipeline capacity expansions by adding additional pump stations. We are also considering investments in our natural gas pipeline segments, fractionator expansions or a new fractionator, NGL storage facilities and additional pipeline capacities, both for raw NGL and purity NGL products. John, that concludes my remarks.

Thank you, Terry. Obviously, with that detailed explanation of all of the projects in the Bakken, when you were remarking about your $1.5 billion, it wasn't in the Barnett, it was in the Bakken. Just to clarify that. But I also want to take this opportunity to recognize you and your employees for continued successful progress in the area of safety and reliability. We do not make any money unless our people are safe, unless our assets are operating well. Also, completing the projects, as well as the tremendous ability you all have to originate these new projects to meet our customer needs. Very much appreciated. So at this time we will ask Curtis to jump back in and review financial -- ONEOK's financial performance, and then Rob will step in and review the ONEOK operating performance. So, Curtis?

Thanks, John. ONEOK's net income for the third quarter was $55 million, or $0.51 per diluted share, compared with last year's third quarter net income of $48 million or $0.45 per diluted share. ONEOK Partners' gain on the sale of a 49% interest in Overland Pass impacted ONEOK's third quarter diluted earnings per share by $0.04. Rob will provide more details on the drivers of ONEOK's financial performance in a few minutes.

We increased the dividend $0.02 to $0.48 per share for the third quarter 2010. This dividend increase, our third this year, reflects our continued confidence in the Company and is the 10th dividend increase since January 2006, representing a 70% increase over that time period. As John mentioned, over the next three years, we plan to execute a more aggressive dividend growth rate of approximately 50% to 60%, while maintaining our targeted payout ratio of 60% to 70% of recurring earnings. In September, we updated our 2010 earnings guidance and expect net income to be in the range of $320 million to $335 million for the year.

We currently estimate 2010 stand-alone cash flow, before changes in working capital, to exceed capital expenditures and dividends by $250 million to $300 million, which is higher than originally forecast and reflects the positive impact from the implementation of recent tax legislation that extended the 50% bonus depreciation provisions for 2010. This increases our deferred taxes and cash flow for 2010, but is not indicative of our future cash flow expectations. We anticipate stand-alone cash flow to exceed capital expenditures and dividends by a range of $150 million to $200 million per year over the next three years. Embedded within that expectation are the more aggressive dividend growth and the targeted payout ratio that I previously mentioned. Last month the ONEOK Board approved the ability of the Company to execute, at its option, up to $750 million of share repurchases over a three-year period, with a limitation of $300 million of share repurchase in any one calendar year. We continue to evaluate both the method and timing of any potential repurchases.

Our three-year cash flow projections include the impact of that share repurchase program. By virtue of ONEOK's general partner interest and significant ownership position, ONEOK received $77 million in distributions from the partnership during the third quarter, a 10% increase from the third quarter last year. At the partnership's estimated distribution level, included in the updated 2010 guidance, ONEOK should receive approximately $304 million in distributions during 2010, a 9% increase over 2009. In effect, the partnership's distribution increases have funded the dividend increases at ONEOK, further demonstrating the alignment between the two entities.

At the end of the third quarter, on a stand-alone basis, ONEOK had no short-term debt outstanding, $46 million in cash and cash equivalents and approximately $440 million of natural gas in storage. ONEOK's stand-alone debt to equity remains 39%, below our 50/50 debt to equity target. We currently project short-term borrowings to remain below $100 million for the remainder of the year. ONEOK's next scheduled debt maturity is not until April 2011 when $400 million comes due.

Finally, a few comments about the Dodd-Frank financial reform act. While the actual regulations are still being written, we do not expect them to significantly impact our ability to hedge commodity price and interest rate risk. However, the cost of doing so may increase and liquidity in the marketplace could become more constrained. Additionally, we may incur higher administrative costs associated with compliance and additional reporting and disclosure obligations. Now, Rob Martinovich will provide an update on ONEOK's operating performance.

Thanks, Curtis, and good morning, everyone. Let's start with our Distribution segments. Third quarter results will higher compared with the third quarter of 2009. Improved margins, similar to those experienced in the second quarter, were driven primarily by increased revenues and a new rate structure approved in our 2009 Oklahoma rate case. By design this new rate structure reduces volumetric sensitivity by increasing fixed fees which increase revenues in the warmer months. Approximately two-thirds of our total margin comes from our residential customers, with 73% fixed and 27% volume sensitive. A significant amount of our volumetric sensitive margin is mitigated by normal usage patterns and weather normalization mechanisms. Third quarter expenses increased over last year, due primarily to the recognition of previously-deferred integrity management program costs in Oklahoma that are now recovered in base rates. We remain confident in our updated operating income guidance of $232 million, which was increased in late September due primarily to lower operating expenses compared with our original guidance.

We continue our efforts to grow our rate base by efficiently and vesting our capital in projects that provide benefits to our customers and our shareholders. We are Approximately 96% complete with the installation of automated meters in Tulsa and Oklahoma City. As a result, by the end of the year, almost half of Oklahoma Natural's residential customers will have automated meters. These meters provide quicker, safer and more efficient meter reading and a net reduction in expenses, while allowing us to earn a return on these investments, creating a win/win for customers and the Company.

Now a brief regulatory update beginning in Oklahoma. In September, Oklahoma Natural Gas filed an application with the Oklahoma Corporation Commission to recover costs and receive performance incentives as a partner in numerous proposed energy efficiency programs. Our procedural schedule is currently being developed and a hearing is expected to take place in February 2011. In Texas, we filed an appeal with the Railroad Commission of Texas on May 12 to increase rates by $5.3 million in our El Paso service area after the El Paso City Council denied our rate request. Subsequently, rate case expenses were placed into a separate docket, which, effectively, reduced the requested increase to $4.4 million. A decision on the appeal is required by December 16, and any new rates would likely go into effect within 20 days of a decision, if a motion for rehearing is not filed. In the third quarter, eight cost of service adjustments were approved throughout our Texas jurisdictions, with a total annual impact to earnings of approximately $1.6 million, which was incorporated into our guidance.

There continues to be interest by the Railroad Commission of Texas to initiate a rulemaking procedure proposing the replacement of steel natural gas service lines. The Railroad Commission recently voted through a first draft of a steel service line replacement rule. Numerous Texas gas facilities, including Texas Gas Service, have provided written comments in response, which the Commission is taking under consideration. The commissioners may vote on a final rule as early as November 30 and any capital expenditure impact associated with replacing lines would be recovered through the regulatory process.

Now, let's turn to energy services. Our third quarter results were lower, as expected, driven primarily by narrower realized seasonal storage differentials and lower transportation margins due to narrower Mid-Continent to Gulf Coast location differentials. In addition, premium service revenues decreased, while the volumetric levels of contracted premium services was about the same as last year, revenues were lower due to low natural gas prices and reduced market volatility. These market factors affect the value we receive for providing these premium services.

Our natural gas in storage at the end of the third quarter was about 65 Bcf, down from last year's 79 Bcf, due primarily to the year-over-year reduction of leased storage capacity. We currently have 73.6 Bcf of capacity under lease compared with 83 Bcf at the end of the third quarter of 2009. On October 31, we had approximately, 70.5 Bcf of gas in storage. As part of our ongoing realignment of storage and transportation capacity to meet the requirements of our premium services customers, we are on track to reduce our storage capacity to 71 Bcf by the end of this year and to 65 Bcf by the end of 2011. We expect our long-term transportation capacity to be at 1.2 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 unit margins and that are not required to provide premium services to our customers.

Energy services operating income guidance for 2010 was updated in late September to $126 million. Our strong 2010 storage margin performance was a result of hedges put in place in 2009, which enabled us to capture wider seasonal storage differentials and our ability to capture incremental margins as a result of the cold weather in the first quarter of this year and hotter than normal weather in the summer.

The current business environment is, in a word, challenging. It includes narrow locational and season storage differentials, which impact the value realized on our transportation and storage positions. These narrow location differentials are primarily a result of low natural gas prices and increased pipeline capacity. Low natural gas prices, coupled with a flat forward price curve have reduced seasonal storage differentials. High gas storage levels persist in spite of a cold first quarter and a hot summer due to reduced demand as a result of a slow economy and supply growth. For the November and December withdrawal period, approximately 98% of our storage margins are hedged. In addition, approximately 67% of our transportation margins are hedged for the balance of 2010. For 2011, we have hedged approximately 32% of our transportation margins for the year, and approximately 73% of the storage margins for the first quarter. Our general strategy is to execute hedges on both transportation and storage based on our forward view of the market and market liquidity.

Finally, I would like to make a few comments about our pipeline integrity efforts and both ONEOK and ONEOK Partners. We operate an extensive array of gas gathering, transmission, distribution and liquid pipelines in 16 states. Our pipeline control center helps to monitor these pipelines 24 hours a day to ensure the safety of employers, contractors and communities newar these lines. Our pipeline controllers monitor variances in operating pressures, alarm system indications, third-party calls, weather-related issues and storage levels. Any observed operational anomalies are reported promptly to field operations for review and response. We use a number of inspection methods and processes to detect and mitigate pipeline corrosion, third-party damage and other outside exposures that may affect our pipelines.

Federal and state regulations require us to develop, implement and maintain formal integrity management programs for transmission and liquid pipelines that cross high-consequence areas, or HCAs. HCAs include areas with large population, navigable waterways and sensitive environmental areas. These regulations require assessments on covered natural gas pipelines at least once every seven years, while assessments on covered natural gas liquids pipelines are required every five years. For our natural gas liquids pipelines, all assessments were required to be completed by March 2008, and they were. Natural gas pipeline assessments, which includes our gas distribution and gas transmission pipelines, must be completed before December 17, 2012.

All of our gas pipeline assessments are scheduled to be completed within their required inspection timeframe. As a final point, the integrity assessment program is not limited to only those pipelines in HCAs. Monitoring and testing are done on all parts of our pipelines, as appropriate, to verify the safety of our operations. John, this concludes my remarks. Thank you, Rob, and congratulations to you and your team on another successful quarter. I would be remiss in not recognizing your leadership and that of your people in regards to leading our effort as it relates to our both integrity and safety, pipeline -- well beyond pipeline, also, our other assets, as well. So very much appreciated.

I made a remark at our recent investor day about our desire to execute a transforming transaction, which has led to many questions about what I meant, what it is, timing, structure, and how the recently announced Board authorization of the three-year stock repurchase program might impact our ability to execute such a transaction. To me, a transforming transaction is one that significantly expands our current line of business or allows us to enter into a new line of business within the energy value chain. In this case, a review of our history may be the best predictor of our future.

Our purchase of three separate packages of natural gas gathering and processing assets in 1999 and 2000 transformed us from primarily a utility to a diversified natural gas Company, with a significant midstream presence. Our acquisition of the Mid-Continent natural gas liquids business in 2005 clearly transformed us into a preeminent NGL player, and paved the way for additional growth that more than doubled the business in less than five years. Our becoming sole general partner and selling $3 billion of assets to what is now ONEOK Partners transformed the partnership and ONEOK into growth-oriented organizations that perform better than their peer on any number of financial measures.

We are looking for an opportunity that will not only continue to grow the partnership, but at the same time, could grow ONEOK's Distribution segment and provide additional opportunities for our Energy Services segment. We are also looking outside our current value chain for businesses where we can confidently utilize our capabilities into create more value for our customers, much like we did when we acquired the NGL business. As far as timing goes, we will continue to be very diligent on the acquisition front, evaluating assets that come on the market and seeking out those that might make sense, all the while exercising the financial discipline that has become our hallmark, not paying too much or buying just for the sake of buying. Given our continued backlog of growth opportunities at the partnership, executing a transforming transaction is not an urgent need, but rather an opportunistic option that we will continue to consider.

Our structure also provides us with a tremendous flexibility on completing such a transaction, allowing us to buy assets or whole companies at either the ONEOK or ONEOK Partners levels. If we were to transact at the ONEOK level, depending on the assets, we could hold them there, or sell them all at once or over time to ONEOK Partners. And finally, our recently announced share repurchase program does not affect our ability to make a transforming transaction if the right asset at the right price comes along.

And finally, and probably most importantly, I would like to thank our more than our 4700 employees who create value every day for our investors and for our customers through their hard work, their dedication and continued commitment. Operator, we are now ready to answer questions.

Excellent, sir. (Operator Instructions) Our first question comes from Steve Maresca with Morgan Stanley.

Good morning, everybody.

Hello, Steve.

Two questions, really. One on the business, you talked about the narrow basis differentials between Conway and Mont Belvieu and infrastructure being built. Do you think we are in an area where this is permanently a lower basis differential and with the NGL frac capacity coming on September 1, do you expect the fourth quarter to be a bit better from an optimization standpoint?

Terry?

Steve, I think -- let me get your first question, longer-term, as we look at differential particulars going into 2011, I think we're still going to be historical levels, that's our view. Our proxy for our North-South optimization, of course, is the ethane spread. So we are looking at $0.09 to $0.10 for 2011, so still well above historical -- the old historical $0.03 to $0.05 a gallon. The second question was--

With the frac capacity coming new on September 1 at Mont Belvieu, the contract expiration. So is fourth quarter, or first quarter going to be better before the Targa thing becomes in the second quarter of 2011?

Yes, it will be better. Margins will be better and, as we sit today, we are actually really seeing spreads moving wider, just particularly over the course over the last few days. That is a bit above our expectation in terms of where we thought spreads would be today.

Of course, one of the things that makes this business, in particular, complicated is are looking not only at differentials between Conway and Mont Belvieu but you're looking at differentials on five or six different products. But one of the things that sometimes gets lost is as this fractionation capacity becomes available in Belvieu, what we are in essence doing is bringing raw feed down to have it fracked and we are putting the finished product in Belvieu that way as opposed to shipping it through a finished product line between Conway and Belvieu. So I think we cannot lose sight of the fact that building Arbuckle and putting more raw barrels into Arbuckle is going to have nothing but a helpful benefit to the shipper, and should also provide -- put more pressure to shrink that spread over time.

Okay, so if I can, just one final one. Thanks a lot for the color, John, on your results and acquisitions. Is there a reason you seem to be, at least in our own humble opinion, a little more aggressive in talking about wanting to do something? Are you seeing things that are available now that were not several quarters ago that are enticing you more that you think are attainable?

I think there is a couple of reasons. One is, yes, there has been a bit more traffic flow from the investment bankers, is one thing. I think the other thing is that if you look back three years ago, this Management team was focused on executing $2 billion worth of growth projects in the partnership. Constantly, in the back of our minds, the challenge has always been, how do we grow -- continue to grow this company? And part of it is coming through that effort with confidence that we can not only continue to execute on internal growth products, but we can look beyond that and see other opportunities to grow our Company. We have yet to find the willing seller at the right price, but we -- you could -- I guess the way to characterize it is that an acquisition has moved its way up the priority list just from the standpoint of the confidence of the Management team as well as the balance sheet of the Company.

Okay. Thanks a lot, gentlemen.

You bet, Steve.

Our next question comes from John Tysseland with Citi.

Hi. Thank you for the overview. Just a follow-up on the Arbuckle discussion. Do you expect Arbuckle to run at better rates, I guess, closer to your capacity of 160,000 barrels per day in the fourth quarter, or do you think that is more of a first quarter once you're fractionation capacity comes down in Belvieu?

We are actually -- we're running about 120,000 barrels per day, right now. And our view is that that is going to continue. And we see it growing and moving closer to that 160,000-barrel-a-day level as we move into 2011.

Okay. Terry, I thought you had mentioned in your comments that the Arbuckle expansion to Belvieu to 240,000 barrels a day was expected to come online in 2012. My recollection was, at your investor day, that was that the Sterling expansion was expected to -- was going forward but the Arbuckle expansion was not yet contracted and still a potential project. Has there been some developments recently where you are now more confident on that expansion?

Well, I think as we move through time, we get more and more confident. I think with the supply growth we are seeing, the potential for new processing plants in the Mid-Continent and the Rockies, our confidence level is increasing monthly.

So, at this point, you are comfortable with a 2012-type expansion on that? Is that an online date or is that something where you will start spending capital?

We are actually in the process of spending some capital on some pumps as we speak. I think that as we move forward in time, we will announce further expansions. But right now we are moving in installments, if you will. As our volumes grow, we are putting pump facilities in.

Incrementally in pace with the supply.

Got you. Is that something where you are going to try and look for long-term contracts before, or are you confident enough in the supplies that you might do it without the contract?

We are going to contract as much as we possibly can under long-term contracts. If what you are saying is, are we specifically entering into firm contracts on just that pipe, the answer that question is no. What we are doing is developing the supply around our infrastructure. I think the key thing to note about Arbuckle, to John's point, Arbuckle effectively becomes an optimization pipe. It is also -- it links all of our fractionation facilities together. All of our raw products coming in from the Mid-Continent and Rockies can also access the Gulf Coast. So really what we are doing is increasing the supply on our raw system through long-term contracts -- long-term supply contracts or exchange contracts that, ultimately, fill Arbuckle.

Got it. That is very helpful. Thank you guys.

Part of these investment dollars is providing the flexibility to optimize our assets.

Our next question comes from Andrew Gunlich with ASB.

Good morning.

Good morning, Andrew.

A couple of just really quick questions. On the natural gas gathering and processing business, when do you expect the gathered volumes to start going back up, that trend to revers over the last seven or eight quarters or so with the new well connects?

Well, we are seeing this decline, okay? And we've indicated the Powder River Basin being the contributor to that. We actually even in this low gas price environment, we are starting to see some of that decline arrest a bit. It is still fairly steep, but it's not as steep, okay? As we move into -- going from 2010 to 2011, our -- overall, we see our volumes been pretty flat, but then as we move from 2011 into 2012, we will start seeing that significant uptick.

Okay. And then the process volume is a percentage of gathered should also -- that percentage should also start to trend up, is that not right?

We are actually seeing that trending up as we speak.

Exactly.

And that's going to continue at a pretty significant clip. And as we move into 2011, it is going to increase even at a higher rate.

So what should we think about as an end game, 75%, 80%?

I don't understand.

In other words, what percentage of gathered gas will you be processing when the building --

Oh, I see. Yes, I have not actually done that calculation in my head, but I think that sounds about right. The relationship -- what you're talking about is the relationship of processed gas to gathered gas?

Right.

Actually, that will probably increase.

It should increase because of what is going on in the Bakken.

Exactly, but to what level? 75%, 80%?

Like I said, I have not actually done that calculation in my head, or on paper.

Okay, well we can do it later. Just two other quick questions then. This is probably for Curtis and John. As you think about -- Curtis, you mentioned that the growth in IDRs and limited partnership distributions has in effect funded the OKE dividend increases. Mentally, even though all the cash is fundable, but mentally, is that how we should continue to think about the OKE dividends? In other words, as the IDRs and the LPs increase, then the OKE dividends will increase and the potential for significant share repurchases is really a function of the balance sheet being slightly less "optimized?"

I don't think -- I'll make a comment and then Curtis can jump in. I don't think I would not make that direct correlation. We have made that statement if, for any reason, then to try to once again articulate how aligned ONEOK and ONEOK Partners are. So it is another way of continuing to talk to the investment community about the benefits of ONEOK Partners to ONEOK, and the way we have chosen to throw that little tidbit out is the fact that when you think about it, and you make a good point, cash is cash, it's all fundable. A way to think about it is when we have had those increases in the past, they, in effect, have flown through and taken care. It's just a way of trying to draw the conclusion or help to draw a conclusion. I don't think I would make a correlation as far as -- as deep as you are going. It is certainly beneficial. Curtis?

I completely agree with that and just to reiterate the comment that I made, the dividend itself, Andrew, is driven by the targeted payout ratio, the 60% to 70%. And so the dividend growth guidance that we have given, the 50% to 60% over the next three years, that directly relates to that payout ratio.

I understand. That helps. Okay. And then, I guess this is somewhat related to the dig deals potential, the fractionation capacity and operating businesses in this country, it is really quite a consolidated industry, and I am curious if you would think the government would allow further consolidation, or when you think big deals are you thinking outside of that circle of competence you already have?

Well, on fractionation in and of itself, it is more of a supply and demand phenomenon in that supply is outpacing fractionation capacity. And so the challenge for those that currently own fractionation is making sure you do not overbuild. Because when you overbuild, it can have a detrimental effect on all of your capacity. So that, I would not characterize as part of a transformational transaction. I see that more as an unique opportunity within the NGL business. That is why we have been very careful about where we have added NGL fractionation capacity, as have others who own NGL fractionation capacity. Our deal is probably more aligned -- or opportunities just across the entire value chain, not just specific just to fractionation.

That makes sense. But do you think there is potential for further consolidation of the NGL fractionation base? So there is one less competitor to worry about in terms of overbuilding?

I don't think so. I think the NGL fractionation market -- another way of saying it is pretty tight right now, and I think all of the players, and there are several in the fractionation game, are looking very carefully and many -- all of us, I would say, have added incremental fractionation. But as I say, that it is a very measured action.

Thanks for taking the questions.

You bet, Andrew. Take care.

(Operator Instructions) Our next question comes from Mike Cerasoli with Goldman Sachs.

Thanks. Just on your 3Q NGL results, how much of that benefited from your ability to capture more optimization opportunities versus other drivers?

Well, we really don't break that out separately, but it was significant. That is about all I will tell you in terms of the numbers.

Okay. And then I am sorry if I missed your answer here from earlier, but does ONEOK have the capacity to execute a transformational transaction and a stock repurchase program at the same time?

I did make that comment. It all depends on the size of the transaction. I think when giving those examples of transforming transactions, I did not go into and provide the value, the relative -- for example, the acquisition dollars, because they are all over the board. You can spend a little bit of money and make a transforming transaction, you can spend a lot of money. I think the take away is that a transaction could be significant from the standpoint of dollars, and the share repurchase is not a commitment on our part to buy $750 million worth of our stock back over three years, it's an option.

If we have an opportunity where we can deploy the Company's assets in a transaction, we will do that and not buy the shares back, or vice versa. It is an optionality. It is an option that exists for us. So until you've got the turkey leg in front of you, you just don't know how big it is.

All right. Thank you.

Okay. Well, thank you. This concludes the ONEOK and ONEOK Partners conference call. As a reminder, our quiet period for the fourth quarter will start when we close our books in early January and will extend until earnings are released in February. We will provide the exact date and time of the release of our fourth-quarter earnings in details on the conference call at a later date. Andrew Ziola and I are available throughout the day to answer your follow-up questions. Thanks again, for joining us.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the program. You may now disconnect. Everyone have a great day.