ONEOK, Inc. : ONEOK Partners Announces Higher First-quarter 2012 Financial Results; Reaffirms 2012 Earnings Guidance

ONEOK Partners Announces Higher First-quarter 2012 Financial Results; Reaffirms 2012 Earnings GuidanceNet Income Rises 58 Percent in the Quarter; Led by Significantly Higher Natural Gas Liquids Operating Results

TULSA, Okla., May 1, 2012 /PRNewswire via COMTEX/ --ONEOK Partners, L.P. (NYSE: OKS) today announced first-quarter 2012 earnings of $0.91per unit, compared with $0.58per unit on a split-adjusted basis for the first quarter 2011. Net income attributable to ONEOK Partners increased 58 percent for the first quarter 2012 to $238.8 million, compared with $150.9 millionfor the same period in 2011.

The partnership also reaffirmed its 2012 net income guidance range of $810 million to $870 millionand its distributable cash flow (DCF) range of $925 million to $985 million, provided on Feb. 20, 2012.

2012 earnings guidance includes a projected 2.5-cent-per-unit-per-quarter increase in unitholder distributions. Actual unitholder distribution declarations are subject to ONEOK Partners board approval.

"The partnership posted strong financial results during the first quarter," said John W. Gibson, chairman and chief executive officer of ONEOK Partners. "Our natural gas liquids business segment continued its exceptional performance, once again benefitting from favorable NGL price differentials and higher natural gas liquids volumes gathered and fractionated."

"The natural gas gathering and processing segment continued to experience higher natural gas volumes gathered and processed, driven primarily by the startup of our new Garden Creek natural gas processing plant in the WillistonBasin late last year," he said.

In the first quarter 2012, earnings before interest, taxes, depreciation and amortization (EBITDA) were $344.1 million, a 35-percent increase compared with $254.2 millionin the first quarter 2011.

DCF for the first quarter 2012 was $279.0 million, a 51-percent increase compared with $184.5 millionin the first quarter 2011.

First-quarter 2012 operating income was $256.0 million, a 44-percent increase compared with $177.6 millionfor the first quarter 2011.

The increase in first-quarter 2012 operating income reflects favorable natural gas liquids (NGL) price differentials, increased NGL fractionation and transportation capacity available for optimization activities and higher NGL volumes gathered and fractionated in the natural gas liquids segment. The natural gas gathering and processing segment benefited from higher natural gas volumes gathered and processed offset partially by lower natural gas and NGL product prices. The natural gas pipelines segment's results decreased due primarily to lower realized natural gas prices on its retained fuel position.

Operating costs were $115.9 millionin the first quarter of 2012, compared with $108.7 millionfor the same period last year. This increase was due primarily to the partnership's expanding operations from several growth projects placed in service.

Capital expenditures were $280.8 millionin the first quarter 2012, compared with $144.8 millionin the same period in 2011, due to increased investments in growth projects in the natural gas gathering and processing and natural gas liquids segments.

FIRST-QUARTER 2012 SUMMARY:

• Operating income of $256.0 million, compared with $177.6 millionin the first quarter 2011;
• Natural gas gathering and processing segment operating income of $47.6 million, compared with $39.4 millionin the first quarter 2011;
• Natural gas pipelines segment operating income of $33.0 million, compared with $36.8 millionin the first quarter 2011;
• Natural gas liquids segment operating income of $174.5 million, compared with $100.7 millionin the first quarter 2011;
• Equity earnings from investments of $34.6 million, compared with $32.1 millionin the first quarter 2011;
• Capital expenditures of $280.8 million, compared with $144.8 millionin the first quarter 2011;
• In the natural gas pipelines segment, Midwestern Gas Transmission/Guardian Pipeline and ONEOK Gas Transportation earning 2011 American Gas Association (AGA) Safety Achievement Awards for their safety performance; and Viking Gas Transmission earning a 2011 Wisconsin Corporate Safety Award from the Wisconsin Safety Council and the Wisconsin Department of Workforce Development;
• Increasing its 2011-2015 growth program to a range of approximately $4.7 billion to $5.6 billionby:
  • Announcing in April plans to invest $1.5 billion to $1.8 billionbetween now and 2015 to build a 1,300-mile crude-oil pipeline - the Bakken Crude Express Pipeline - with the initial capacity to transport 200,000 barrels per day (bpd) of light-sweet crude oil from the Bakken Shale in the WillistonBasin in North Dakotato the Cushing, Okla., crude-oil market hub;
  • Announcing in April plans to invest approximately $340 million to $360 millionbetween now and the first quarter of 2014 to construct a new 200 million-cubic-feet-per-day (MMcf/d) natural gas processing facility - the Canadian Valley plant - in Canadian County, Okla., and related infrastructure in the Cana-Woodford Shale;
  • Announcing in April plans to invest $140 million to $160 millionto construct a 270-mile natural gas gathering system and related infrastructure in Divide County, N.D., that will supply the partnership's previously announced 100 MMcf/d Stateline II natural gas processing facility in western Williams County, N.D;
• Completing construction in April of approximately 230 miles of NGL pipelines expanding the partnership's existing Mid-Continent NGL gathering system in the Cana-Woodford and Granite Wash areas and completing the installation of additional pump stations on the Arbuckle Pipeline, increasing its capacity to 240,000 bpd;
• Completing in March 2012, a public offering of 8.0 million common units and a private placement with ONEOK, Inc. of 8.0 million common units, generating net proceeds of approximately $919.6 million;
• ONEOK Partners repaying in April $350 millionof senior notes;
• Having $746.7 millionof cash and cash equivalents and no commercial paper or borrowings outstanding as of March 31, 2012, under the partnership's $1.2 billionrevolving credit facility; and
• Increasing the quarterly cash distribution to 63.5 centsper unit from 61 centsper unit, an increase of 4 percent, payable on May 15, 2012, to unitholders of record as of April 30, 2012.

BUSINESS-UNIT RESULTS:

Natural Gas Gathering and Processing Segment

The natural gas gathering and processing segment reported first-quarter 2012 operating income of $47.6 million, compared with $39.4 millionfor the first quarter 2011.

First-quarter 2012 results reflect a $26.5 millionincrease from higher natural gas volumes gathered, processed and sold in the WillistonBasin, primarily from the completion of the Garden Creek natural gas processing plant, and in western Oklahoma. This increase was offset partially by a $5.3 milliondecrease from higher third-party processing costs in the WillistonBasin; a $5.2 milliondecrease from lower natural gas and NGL product prices, particularly ethane and propane, offset by higher condensate prices; and a $1.0 milliondecrease from lower natural gas volumes gathered as a result of continued production declines and reduced drilling activity in the Powder River Basin in Wyoming.

Operating costs in the first quarter 2012 were $40.2 million, compared with $38.1 millionin the same period last year. This increase was due primarily to higher property taxes and employee-related costs associated with the growth in this segment's operations, including the completion of the new Garden Creek natural gas processing plant in the WillistonBasin.

Depreciation and amortization expense was $20.5 millionfor the first quarter 2012, compared with $16.2 millionfor the same period in 2011. This increase was due to the completion of the Garden Creek plant, well connections and related infrastructure projects in the WillistonBasin.

Key Statistics: More detailed information is listed in the tables.

• Natural gas gathered totaled 1,045 billion British thermal units per day (BBtu/d) in the first quarter 2012, up 5 percent compared with the same period last year due to increased drilling activity in the WillistonBasin and in western Oklahoma, and the impact of weather-related outages in the first quarter 2011, offset partially by continued production declines and reduced drilling activity in the Powder River Basin in Wyoming; and down 1 percent compared with the fourth quarter 2011;
• Natural gas processed totaled 769 BBtu/d in the first quarter 2012, up 20 percent compared with the same period last year due to increased drilling activity in the WillistonBasin and western Oklahoma, the completion of the partnership's new Garden Creek plant in the WillistonBasin, and the impact of weather-related outages in the first quarter 2011; and up 1 percent compared with the fourth quarter 2011;
• The realized composite NGL net sales price was $1.09per gallon in the first quarter 2012, unchanged compared with the same period last year; however, ethane and propane prices declined in the first quarter, compared with the same period in 2011; and up 3 percent compared with the fourth quarter 2011;
• The realized condensate net sales price was $89.89per barrel in the first quarter 2012, up 18 percent compared with the same period last year; and up 5 percent compared with the fourth quarter 2011;
• The realized residue natural gas net sales price was $3.71per million British thermal units (MMBtu) in the first quarter 2012, down 39 percent compared with the same period last year; and down 27 percent compared with the fourth quarter 2011; and
• The realized gross processing spread was $8.59per MMBtu in the first quarter 2012, up 3 percent compared with the same period last year; and up 10 percent compared with the fourth quarter 2011.

NGL shrink, plant fuel and condensate shrink discussed in the table below refer to the Btus that are removed from natural gas through the gathering and processing operation; it does not include volumes from the partnership's equity investments. The following table contains operating information for the periods indicated:

		Three Months Ended
		March 31,
Operating Information (a)		2012		2011
Percent of proceeds
NGL sales (Bbl/d)		7,275		5,759
Residue gas sales (MMBtu/d)		59,405		41,207
Condensate sales(Bbl/d)		2,544		1,953
Percentage of total net margin		62%		58%
Fee-based
Wellhead volumes (MMBtu/d)		1,044,641		991,778
Average rate ($/MMBtu)		$ 0.36		$ 0.33
Percentage of total net margin		31%		33%
Keep-whole
NGL shrink (MMBtu/d) (b)		7,353		11,971
Plant fuel (MMBtu/d) (b)		864		1,347
Condensate shrink (MMBtu/d) (b)		1,297		1,336
Condensate sales (Bbl/d)		262		270
Percentage of total net margin		7%		9%
(a) - Includes volumes for consolidated entities only.
(b) - Refers to the Btus that are removed from natural gas through processing.

The natural gas gathering and processing segment is exposed to commodity-price risk as a result of receiving commodities in exchange for services. The following tables provide hedging information in the natural gas gathering and processing segment for the periods indicated:

			Nine Months Ending December 31, 2012
			Volumes Hedged	(a)	Average Price			Percentage Hedged
NGLs (Bbl/d)			9,094		$1.24	/ gallon		71%
Condensate (Bbl/d)			1,753		$2.43	/ gallon		73%
	Total (Bbl/d)		10,847		$1.43	/ gallon		72%
Natural gas(MMBtu/d)			48,145		$4.12	/ MMBtu		78%
(a) - Hedged with fixed-price swaps.
			Year Ending December 31, 2013
			Volumes Hedged	(a)	Average Price			Percentage Hedged
NGLs (Bbl/d)			367		$2.55	/ gallon		2%
Condensate (Bbl/d)			1,275		$2.53	/ gallon		47%
	Total (Bbl/d)		1,642		$2.54	/ gallon		7%
Natural gas(MMBtu/d)			50,137		$3.85	/ MMBtu		80%
(a) - Hedged with fixed-price swaps.

For 2012, the partnership estimates that in its natural gas gathering and processing segment, a 1-cent-per-gallon change in the composite price of NGLs would change annual net margin by approximately $2.1 million. A $1.00-per-barrel change in the price of crude oil would change annual net margin by approximately $1.2 million. Also, a 10-cent-per-MMBtu change in the price of natural gas would change annual net margin by approximately $2.2 million. All of these sensitivities exclude the effects of hedging and assume normal operating conditions.

Natural Gas Pipelines Segment

The natural gas pipelines segment reported first-quarter 2012 operating income of $33.0 million, compared with $36.8 millionfor the first quarter 2011.

First-quarter 2012 results reflect a $3.0 milliondecrease from lower realized natural gas prices on its retained fuel position and a $1.3 milliondecrease from lower natural gas storage margins primarily as a result of lower park-and-loan activity due to periods of lower heating and electric demand.

Operating costs were $26.2 millionin the first quarter 2012, compared with $27.0 millionin the same period last year.

Equity earnings from investments were $20.4 millionin the first quarter 2012, compared with $21.0 millionin the same period in 2011.

Key Statistics: More detailed information is listed in the tables.

• Natural gas transportation capacity contracted totaled 5,552 thousand dekatherms per day in the first quarter 2012, down 1 percent compared with the same period last year; and up 2 percent compared with the fourth quarter 2011;
• Natural gas transportation capacity subscribed was 86 percent in the first quarter 2012 compared with 87 percent in the same period last year; and up from 84 percent in the fourth quarter 2011; and
• The average natural gas price in the Mid-Continent region was $2.37per MMBtu in the first quarter 2012, down 42 percent compared with the same period last year; and down 26 percent compared with the fourth quarter 2011.

Natural Gas Liquids Segment

The natural gas liquids segment reported first-quarter 2012 operating income of $174.5 million, compared with $100.7 millionfor the first quarter 2011.

First-quarter 2012 results reflect:

• A $60.1 millionincrease in optimization margins due primarily to favorable NGL price differentials and increased NGL fractionation and transportation capacity available for optimization activities between the Mid-Continent and Gulf-Coast markets;
• An $18.0 millionincrease from higher NGL volumes gathered and fractionated, and favorable contract renegotiations associated with its exchange-services activities;
• A $6.3 millionincrease due to operational measurement gains in the first quarter 2012, compared with losses of approximately $5.6 millionin the same period last year;
• A $2.6 millionincrease due to higher storage margins as a result of favorable contract renegotiations; and
• A $3.5 milliondecrease in isomerization margins from narrower price differentials between normal butane and iso-butane, and lower isomerization volumes.

Beginning on Feb. 28, 2012, the partnership experienced an unexpected release of brine and propane from a storage well at its NGL fractionation facility in Medford, Okla., which caused a 10-day disruption to its operations. The well was capped successfully and will be taken out of service permanently. Without this disruption, the partnership estimates net margin in this segment would have been approximately $10 millionhigher.

Operating costs were $51.9 millionin the first quarter 2012, compared with $43.9 millionin the first quarter 2011. The increase was due primarily to higher expenses for materials, utilities, outside services and employee-related costs associated with scheduled maintenance and completed growth projects.

Equity earnings from investments were $5.7 millionin the first quarter 2012, compared with $4.8 millionin the same period in 2011.

Key Statistics: More detailed information is listed in the tables.

• NGLs fractionated totaled 585,000 bpd in the first quarter 2012, up 18 percent compared with the same period last year due primarily to increased throughput from existing supply connections in Texasand the Mid-Continent and Rocky Mountain regions, and new supply connections in the Mid-Continent and Rocky Mountain regions; and relatively unchanged compared with the fourth quarter 2011. In the second quarter 2011, additional Gulf Coast fractionation capacity became available through the partnership's 60,000 bpd fractionation-services agreement with a third party;
• NGLs transported on gathering lines totaled 498,000 bpd in the first quarter 2012, up 25 percent compared with the same period last year due primarily to increased production through existing supply connections in Texasand the Mid-Continent and Rocky Mountain regions, and new supply connections in the Mid-Continent and Rocky Mountain regions; and up 5 percent compared with the fourth quarter 2011;
• NGLs transported on distribution lines totaled 485,000 bpd in the first quarter 2012, up 5 percent compared with the same period last year due primarily to the completion of the Sterling I pipeline expansion project in the fourth quarter of 2011; and down 5 percent compared with the fourth quarter 2011; and
• The Conway-to-Mont Belvieuaverage price differential for ethane, based on Oil Price Information Service (OPIS) pricing, was 24 centsper gallon in the first quarter 2012, compared with 15 centsper gallon in the same period last year; and 49 centsper gallon in the fourth quarter 2011.

GROWTH ACTIVITIES:

The partnership has announced approximately $4.7 billion to $5.6 billionin growth projects, including:

• Approximately $1.5 billion to $1.8 billionto construct a 1,300-mile crude-oil pipeline with the initial capacity to transport 200,000 bpd. The Bakken Crude Express Pipeline will transport light-sweet crude oil from the Bakken Shale in the WillistonBasin in North Dakotato the Cushing, Okla., crude-oil market hub. Following receipt of all necessary permits and compliance with customary regulatory requirements, construction is expected to begin in late 2013 or early 2014 and be completed by early 2015.
• Approximately $1.8 billion to $2.2 billionfor natural gas liquids projects including:
  • Approximately $610 million to $810 millionfor the construction of a 570-plus-mile, 16-inch NGL pipeline - the Sterling III Pipeline - expected to be completed in late 2013, to transport either unfractionated NGLs or NGL purity products from the Mid-Continent region to the Texas Gulf Coast with the initial capacity of 193,000 bpd and the ability to expand to 250,000 bpd; and the reconfiguration of its existing Sterling I and II NGL distribution pipelines to transport either unfractionated NGLs or NGL purity products;
  • Approximately $300 million to $390 millionfor the construction of a new 75,000 bpd natural gas liquids fractionator, MB-2, at Mont Belvieu, Texas, that is expected to be completed in mid-2013;
  • Approximately $450 million to $550 millionfor the construction of a 525- to 615-mile NGL pipeline - the Bakken NGL Pipeline - to transport unfractionated NGLs produced from the Bakken Shale in the WillistonBasin to the Overland Pass Pipeline, a 760-mile NGL pipeline extending from southern Wyomingto Conway, Kan.The Bakken NGL Pipeline is expected to be in service during the first half of 2013, with the initial capacity of 60,000 bpd and can be expanded to 110,000 bpd with additional pump stations;
  • Approximately $35 million to $40 millionon the partnership's 50-percent-owned Overland Pass Pipeline for a 60,000-bpd capacity expansion to transport the additional unfractionated NGL volumes from the new Bakken NGL Pipeline;
  • Approximately $110 million to $140 millionfor a 60,000-bpd expansion of the partnership's fractionation capacity at Bushton, Kan., which is expected to be in service during the fourth quarter of 2012, to accommodate volumes from the Bakken Shale in the WillistonBasin;
  • Approximately $210 million to $230 millionto construct more than 230 miles of 10- and 12-inch diameter NGL pipelines that will expand the partnership's existing Mid-Continent NGL gathering system in the Cana-Woodford and Granite Wash areas, which is expected to add approximately 75,000 to 80,000 bpd of raw, unfractionated NGLs to the partnership's existing NGL gathering systems in the Mid-Continent and the Arbuckle Pipeline. Construction of the NGL pipelines was completed early in the second quarter 2012 and connected three new third-party natural gas processing facilities and three existing third-party natural gas processing facilities that have been expanded to the partnership's NGL gathering system. In addition, the installation of additional pump stations on the Arbuckle Pipeline was completed, increasing its capacity to 240,000 bpd; and
  • At the end of 2011, the partnership completed the installation of seven additional pump stations along its existing Sterling I NGL distribution pipeline, which cost approximately $30 million; the additional pump stations increased the pipeline's capacity by 15,000 bpd.
• Approximately $1.4 billion to $1.6 billionfor natural gas gathering and processing projects including:
  • Approximately $360 millionfor the Garden Creek plant, a new 100-MMcf/d natural gas processing facility in the Bakken Shale in the WillistonBasin in North Dakotathat was placed in service at the end of 2011, and related expansions; and for new well connections, expansions and upgrades to the existing natural gas gathering system infrastructure;
  • Approximately $300 million to $355 millionto construct the Stateline I plant, a new 100-MMcf/d natural gas processing facility in the Bakken Shale in the WillistonBasin in North Dakota, which is expected to be in service in the third quarter of 2012, and related NGL infrastructure; expansions and upgrades to the existing gathering and compression infrastructure; and new well connections;
  • Approximately $260 million to $305 millionto construct the Stateline II plant, a new 100-MMcf/d natural gas processing facility in the Bakken Shale in the WillistonBasin in North Dakota, which is expected to be in service in the first half of 2013; expansions and upgrades to the existing gathering and compression infrastructure; and new well connections;
  • Approximately $140 million to $160 millionto construct a 270-mile natural gas gathering system and related infrastructure in Divide County, N.D. This system, which is expected to be in service in the second half of 2013, will gather and deliver natural gas from producers in the Bakken Shale in the WillistonBasin to the partnership's previously announced 100 MMcf/d Stateline II natural gas processing facility in western Williams County, N.D.; and
  • Approximately $340 million to $360 millionto construct the Canadian Valley plant, a new 200-MMcf/d natural gas processing facility in the Cana-Woodford Shale in Oklahoma, which is expected to be in service in the first quarter 2014; and expansions and upgrades to the existing gathering and compression infrastructure.

EARNINGS CONFERENCE CALL AND WEBCAST:

ONEOK Partners and ONEOK management will conduct a joint conference call on Wednesday, May 2, 2012, at 11 a.m. Eastern Daylight Time(10 a.m. Central Daylight Time). The call will also be carried live on ONEOK Partners' and ONEOK's websites.

To participate in the telephone conference call, dial 877-795-3613, pass code 2482979, or log on to http://www.oneokpartners.com/ or http://www.oneok.com/.

If you are unable to participate in the conference call or the webcast, the replay will be available on ONEOK Partners' website, http://www.oneokpartners.com/, and ONEOK's website, http://www.oneok.com/, for 30 days. A recording will be available by phone for seven days. The playback call may be accessed at 888-203-1112, pass code 2482979.

NON-GAAP (GENERALLY ACCEPTED ACCOUNTING PRINCIPLES) FINANCIAL MEASURES

ONEOK Partners has disclosed in this news release anticipated EBITDA and DCF levels that are non-GAAP financial measures. EBITDA and DCF are used as measures of the partnership's financial performance. EBITDA is defined as net income adjusted for interest expense, depreciation and amortization, income taxes and allowance for equity funds used during construction. DCF is defined as EBITDA, computed as described above, less interest expense, maintenance capital expenditures and equity earnings from investments, adjusted for distributions received and certain other items.

The partnership believes the non-GAAP financial measures described above are useful to investors because these measurements are used by many companies in its industry as a measurement of financial performance and are commonly employed by financial analysts and others to evaluate the financial performance of the partnership and to compare the financial performance of the partnership with the performance of other publicly traded partnerships within its industry.

EBITDA and DCF should not be considered alternatives to net income, earnings per unit or any other measure of financial performance presented in accordance with GAAP.

These non-GAAP financial measures exclude some, but not all, items that affect net income. Additionally, these calculations may not be comparable with similarly titled measures of other companies. Furthermore, these non-GAAP measures should not be viewed as indicative of the actual amount of cash that is available for distributions or that is planned to be distributed for a given period nor do they equate to available cash as defined in the partnership agreement.

ONEOK Partners, L.P. (NYSE: OKS) is one of the largest publicly traded master limited partnerships, and is a leader in the gathering, processing, storage and transportation of natural gas in the U.S. and owns one of the nation's premier natural gas liquids (NGL) systems, connecting NGL supply in the Mid-Continent and Rocky Mountain regions with key market centers. Its general partner is a wholly owned subsidiary of ONEOK, Inc. (NYSE: OKE), a diversified energy company, which owns 43.4 percent of the overall partnership interest. ONEOK is one of the largest natural gas distributors in the United States, and its energy services operation focuses primarily on marketing natural gas and related services throughout the U.S.

For the latest news about ONEOK Partners, follow us on Twitter @ONEOKPartners.

Some of the statements contained and incorporated in this news release are forward-looking statements within the meaning of Section 27A of the Securities Act, as amended, and Section 21E of the Exchange Act, as amended. The forward-looking statements relate to our anticipated financial performance, liquidity, management's plans and objectives for our future operations, our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of our operations and other statements contained or incorporated in this news release identified by words such as "anticipate," "estimate," "expect," "project," "intend," "plan," "believe," "should," "goal," "forecast," "guidance," "could," "may," "continue," "might," "potential," "scheduled" and other words and terms of similar meaning.

One should not place undue reliance on forward-looking statements, which are applicable only as of the date of this news release. Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:

• the effects of weather and other natural phenomena, including climate change, on our operations, demand for our services and energy prices;
• competition from other United Statesand foreign energy suppliers and transporters, as well as alternative forms of energy, including, but not limited to, solar power, wind power, geothermal energy and biofuels such as ethanol and biodiesel;
• the capital intensive nature of our businesses;
• the profitability of assets or businesses acquired or constructed by us;
• our ability to make cost-saving changes in operations;
• risks of marketing, trading and hedging activities, including the risks of changes in energy prices or the financial condition of our counterparties;
• the uncertainty of estimates, including accruals and costs of environmental remediation;
• the timing and extent of changes in energy commodity prices;
• the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, pipeline safety, environmental compliance, climate change initiatives and authorized rates of recovery of natural gas and natural gas transportation costs;
• the impact on drilling and production by factors beyond our control, including the demand for natural gas and crude oil; producers' desire and ability to obtain necessary permits; reserve performance; and capacity constraints on the pipelines that transport crude oil, natural gas and NGLs from producing areas and our facilities;
• difficulties or delays experienced by trucks or pipelines in delivering products to or from our terminals or pipelines;
• changes in demand for the use of natural gas because of market conditions caused by concerns about global warming;
• conflicts of interest between us, our general partner, ONEOK Partners GP, and related parties of ONEOK Partners GP;
• the impact of unforeseen changes in interest rates, equity markets, inflation rates, economic recession and other external factors over which we have no control;
• our indebtedness could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantages compared with our competitors that have less debt or have other adverse consequences;
• actions by rating agencies concerning the credit ratings of us or the parent of our general partner;
• the results of administrative proceedings and litigation, regulatory actions, rule changes and receipt of expected clearances involving the Oklahoma Corporation Commission (OCC), Kansas Corporation Commission (KCC), Texasregulatory authorities or any other local, state or federal regulatory body, including the Federal Energy Regulatory Commission (FERC), the National Transportation Safety Board (NTSB), the Pipeline and Hazardous Materials Safety Administration (PHMSA), the Environmental Protection Agency (EPA) and the Commodity Futures Trading Commission (CFTC);
• our ability to access capital at competitive rates or on terms acceptable to us;
• risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines that outpace new drilling;
• the risk that material weaknesses or significant deficiencies in our internal control over financial reporting could emerge or that minor problems could become significant;
• the impact and outcome of pending and future litigation;
• the ability to market pipeline capacity on favorable terms, including the effects of:
  • future demand for and prices of natural gas and NGLs;
  • competitive conditions in the overall energy market;
  • availability of supplies of Canadian and United Statesnatural gas; and
  • availability of additional storage capacity;
• performance of contractual obligations by our customers, service providers, contractors and shippers;
• the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory clearances;
• our ability to acquire all necessary permits, consents and other approvals in a timely manner, to promptly obtain all necessary materials and supplies required for construction, and to construct gathering, processing, storage, fractionation and transportation facilities without labor or contractor problems;
• the mechanical integrity of facilities operated;
• demand for our services in the proximity of our facilities;
• our ability to control operating costs;
• acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers' or shippers' facilities;
• economic climate and growth in the geographic areas in which we do business;
• the risk of a prolonged slowdown in growth or decline in the United Statesor international economies, including liquidity risks in United Statesor foreign credit markets;
• the impact of recently issued and future accounting updates and other changes in accounting policies;
• the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political conditions in the Middle Eastand elsewhere;
• the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;
• risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions;
• the impact of uncontracted capacity in our assets being greater or less than expected;
• the ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our state and FERC-regulated rates;
• the composition and quality of the natural gas and NGLs we gather and process in our plants and transport on our pipelines;
• the efficiency of our plants in processing natural gas and extracting and fractionating NGLs;
• the impact of potential impairment charges;
• the risk inherent in the use of information systems in our respective businesses, implementation of new software and hardware, and the impact on the timeliness of information for financial reporting;
• our ability to control construction costs and completion schedules of our pipelines and other projects; and
• the risk factors listed in the reports we have filed and may file with the Securities and Exchange Commission (SEC), which are incorporated by reference.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also have material adverse effects on our future results. These and other risks are described in greater detail in Part I, Item 1A, Risk Factors, in the Annual Report. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.

Analyst Contact:	Andrew Ziola
	918-588-7163
Media Contact:	Brad Borror
	918-588-7582

SOURCE ONEOK Partners, L.P.

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