Morgan Stanley MLP and Diversified Natural Gas Corporate Access Day New York City March 16, 2010
Forward-looking Statement Statements contained in this presentation that include company expectations or predictions should be considered forward-looking statements that are covered by the safe harbor provisions of the Securities Act of 1933 and the Securities and Exchange Act of 1934. It is important to note that the actual results of company earnings could differ materially from those projected in such forward-looking statements. For additional information, refer to ONEOK s and ONEOK Partners Securities and Exchange Commission filings. Page 2
Page 3 Overview
Key Investment Considerations A Premier Energy Company Value Creation Strategic Assets Proven Growth Financial Discipline Focused on creating value for customers, producers and investors Growth at ONEOK Partners benefits ONEOK Generate consistent free cash flow ONEOK Partners assets connect prolific supply basins to key market centers and provide primarily fee-based earnings Distribution segment provides stable cash flow Energy Services provides premium services to established customer base Dividends have increased 57% since January 2006 ONEOK distributions from OKS have increased 93% since 2006 Total return exceeds S&P 500 Index Investment-grade credit rating Target 50/50 debt-to-capitalization Experience Experienced and proven management team Talented workforce Page 4
ONEOK Today A Premier Energy Company Assets that fit and work together Proven ability to grow profitably Page 5
Our Vision A Premier Energy Company Creating exceptional value for all stakeholders by: Rebundling services across the value chain, primarily through vertical integration, to provide customers with premium services at lower costs Applying our capabilities as a gatherer, processor, transporter, marketer and distributor to natural gas and natural gas liquids Exploration & Production Midstream Natural Gas Midstream NGLs Distribution Marketing Markets Page 6
Our Key Strategies A Premier Energy Company Generate consistent growth and sustainable earnings Increase distributable cash flow at ONEOK Partners through a combination of strategic acquisitions and growth projects Grow operating income of ONEOK Distribution Companies through rate strategies and operating efficiencies Realign focus on our key markets at ONEOK Energy Services Execute strategic acquisitions Manage our balance sheet and maintain strong credit ratings at or above current level Operate in a safe, reliable and environmentally responsible manner Attract, develop and retain employees to support strategy execution Page 7
Business Environment 2010-2012 Moderate economic recovery in 2010 Improved credit markets for investment-grade issuers Federal legislative and regulatory environment is uncertain Anticipated consolidation of underperforming assets, particularly those with high commodity price exposure and/or high levels of debt Improving commodity price environment Narrower location differentials Page 8
Page 9 Diversified Assets
Business Segments Diversity Provides Stability and Opportunity Distribution Provides low-risk, stable cash flow Rate strategies have led to an increase in sustainable earnings and an improved return on equity Energy Services Provides premium services to customers through supply, transportation and storage contracts Renewed focus: more predictable, less volatile range of earnings ONEOK Partners ONEOK s primary growth engine: growth at OKS benefits ONEOK Primarily fee-based earnings Page 10
Page 11 Distribution
Distribution Key Points Eighth largest U.S. natural gas distributor Largest in Oklahoma and Kansas Third largest in Texas More than 2 million customers served Kansas Oklahoma Texas Customer Base Approximately 70% of state s natural gas customers Approximately 85% of state s natural gas customers Approximately 14% of state s natural gas customers Regulation Kansas Corporation Commission (three commissioners appointed by the governor to four-year staggered terms) Oklahoma Corporation Commission (three commissioners elected to six-year staggered terms) Home Rule with 10 jurisdictions (Texas Railroad Commission has appellate authority) Page 12
Distribution Successful Execution of Rate Strategy Synchronized rates and regulatory actions Capital and bad-debt recovery in all states Innovative rates (performance-based, decoupling) 2005 2009 Opportunities Solutions Oklahoma Kansas Texas * Oklahoma Kansas Texas * Earnings Lag Capital Recovery 36% Margin Protection Bad-Debt Recovery Customer Charge Increased Increased Increased Weather Protection 46% Innovative Rate Mechanisms Performance-based Rates, Cost of Service Adjustments, Decoupling *Percent of customers within the Texas jurisdictions Filed 60% Page 13
Distribution Earnings Growth to Close the Performance Gap Essentially closed the gap between actual and allowed returns 2010 return on equity Allowed: 10.7% Guidance: 10.4% Compared with 4.9% in 2005 Operating Income $117 $174 ($ In Millions) $189 Increased level of sustainable earnings Rate mechanisms reduce regulatory lag $8* $210 $215 2006 2007 2008 2009 2010 Guidance Page 14 *2010 operating income includes retail marketing moved from Energy Services **ROE calculations are consistent with utility ratemaking in each jurisdiction and not consistent with GAAP returns
Distribution On the Horizon - Regulatory Texas Austin rate case approved for $2.4 million in Feb. 2009 with new rates effective July 2009 Oklahoma Rate case approved for $54.5 million, with new rates effective Dec. 2009 Texas Filed for rate increase in El Paso service area for $7.3 million in Dec. 2009 with new rates effective May 2010 Oklahoma - Performance-based rate filing anticipated March 2011 with new rates to be effective July 2011, if applicable Texas Austin rate filing anticipated Nov. 2011 with new rates to be effective April 2012 2011 2009 2012 2010 Texas Rio Grande Valley rate case approved with new rates effective Sept. 2009 Kansas - Filed to become an Efficiency Kansas Loan Program utility partner contingent on approval of a revenuedecoupling mechanism. Decision to be made on or before Aug. 15, 2010 Texas North Texas rate filing anticipated Oct. 2010 with new rates to be effective April 2011 Kansas - Rate filing anticipated May 2012 with new rates to be effective Jan. 2013 Page 15
Distribution Oklahoma Natural Gas Largest customer base Approximately 85 percent of state s natural gas customers 834,500 customers Oklahoma Corporation Commission Three commissioners elected to sixyear staggered terms Rate activities Performance-based rate mechanism effective Jan. 2010 $54.5 million increase in base rates, $25.7 million net: $14 million operating income impact in 2010 Page 16
Distribution Kansas Gas Service Coldest territory Approximately 70 percent of state s natural gas customers 633,200 customers Kansas Corporation Commission Three commissioners appointed by the governor to four-year staggered terms Rate activities Filed Energy Efficiency application in Dec. 2009, contingent on approval of a revenue-decoupling mechanism Decision expected in 240 days Page 17
Distribution Texas Gas Service Third largest natural gas distributor in the state Approximately 14 percent of state s natural gas customers 604,800 customers Home Rule with 10 jurisdictions Texas Railroad Commission has appellate authority Rate activities Filed for rate increase in El Paso service area for $7.3 million in Dec. 2009 Page 18
Distribution Oklahoma Natural Gas Performance-based Rates Performance-based rate structure Shift from infrequent, larger rate increases to smaller annual rate changes Once new rates are set, annual filings occur Less volumetric sensitivity Minimizes exposure to effects of weather and conservation 150 basis point earnings band 75 bps 10.5 % 25 bps 75 bps If actual ROE is higher than band: 75% revenuesharing requirement 25% earnings incentive to ONEOK If actual ROE is more than 75 basis points below approved ROE: Rates increase to 25 basis points below approved ROE Page 19
Page 20 Energy Services
Energy Services Contracted Capacity Enable us to Provide Premium Services to Customers Deliver natural gas, together with bundled, reliable, premium products and services Peaking services Primarily to LDCs Access to prolific supply and high-demand areas Industry knowledge and customer relationships Leased Pipeline Leased Storage Storage Transportation 82.8 Bcf of capacity 2.3 Bcf/d of withdrawal rights 1.4 Bcf/d of injection rights 1.5 Bcf/d of long-term firm capacity *As of December 31, 2009 Page 21
Energy Services Current Efforts Continued focus on customer-specific premium delivery services Realign contracted storage and transportation capacity with premium-service requirements Storage capacity to 71.3 Bcf by year-end 2010 Storage capacity to 65 Bcf by year-end 2011 Transportation capacity to 1 Bcf/d in 2012 1.5 Bcf/d in 2009 1.3 Bcf/d by year-end 2010 Reduction in working capital requirements Reduce volatility in earnings Minimizes downside, limits upside 2010 hedged positions 62% of transportation 75% of storage Page 22 Exploration & Production Midstream Natural Gas Midstream NGLs Distribution Marketing Markets
Energy Services Financial Profile Thousands except $/MMBtu Baseline* 2009 Actual 2010 Guidance* Premium service fees $85,000 $81,625 $68,000 Year-end storage capacity (Bcf) 65.0 82.8 71.3 Assumed winter/summer spread NYMEX ($/MMBtu) $1.30 $1.01 $1.36 Storage costs (lease, variable, hedging and other) ($/MMBtu) $1.24 $1.10 $1.17 Net storage margin ($/MMBtu) $0.06 $(0.09) $0.19 Net storage margin $4,200 $(7,290) $13,220 Long-term transportation capacity (MMBtu/d) 1,000 1,466 1,303 Transportation gross margin ($/MMBtu) $0.32 $0.35 $0.30 Transportation costs ($/MMBtu) $0.26 $0.22 $0.22 Transportation net margin ($/MMBtu) $0.06 $0.13 $0.08 Net transportation margin $19,500 $67,804 $42,554 Optimization $13,300 $14,371 $13,226 Financial Trading - 3,138 - Wholesale margin subtotal $122,000 $159,648 $137,000 Wholesale general and administrative expense $30,500 $35,312 $30,000 Total Operating income $91,500 $124,336 $107,000 Page 23 * Reflects moving retail business to Distribution segment
Page 24 Financial Strength
Earnings Growth Delivering Consistent Growth and Stable Earnings Distribution segment provides stable cash flow Energy Services margin hedged in 2010: 62% of transportation 75% of storage ONEOK Partners 2010 margin: 67% fee based 75% of commodity exposure hedged $535 Stand-alone Operating Income Plus Equity Earnings ($ in Millions) $524 $591 $609 $597 $607 $274 $223 $107 ONEOK Partners Distribution* Energy Services 2005 2006 2007 2008 2009 2010G* *Distribution segment includes $8 million in retail marketing Page 25
ONEOK Financial Guidance 2010 2 cents per share dividend increase semi annually 2010 capital expenditures include $31 million to install automated meters in selected Oklahoma residential communities $895 $958 $306 $318 $175 $241 Net Income Operating Income Capital Expenditures 2009 Actual 2010 Guidance Midpoint ($ In Millions) Page 26
ONEOK Earnings Growth 2010 Drivers Operating Income and Equity Earnings Drivers $ Millions $1,100 $1,000 $900 $800 $967 2009 Actual ONEOK Partners $86 * Full-year impact of 2009 completed growth projects * Higher NGL throughput * Higher gas processing volumes *Narrower NGL product price differentials Distribution $13 * Oklahoma performancebased rates * Retail marketing moved from Energy Services * Rate strategies * El Paso rate filing * Operational efficiencies Energy Services ($28) * Higher seasonal storage differentials * Retail marketing moved to Distribution *Narrower transportation basis differentials * Lower premium-service fees $1,038 2010 Guidance $700 * Primarily fee-based revenues $600 Page 27
Strong Cash Flow Provides Financial Flexibility $135-$170 million free cash flow available for: Acquisitions Investment in OKS Dividend increase Share repurchase $205 $182 $135 $150 Free Cash Flow* ($ in Millions) $170 $223 $163 $173 $152 $191 $175 $174 $219 $175 $241 2006 2007 2008 2009 2010G Capital Expenditures Dividends Surplus *Stand-alone cash flow, excluding acquisitions Page 28
Strong Balance Sheet Demonstrated Financial Discipline Strong credit rating S&P: BBB Moody s: Baa2 Capital structure Goal: 50/50 capitalization Reduced debt by $1.2 billion in 2009 by: Lower working capital requirements Cash from operations Cash on-hand $1.1 billion available at Feb. 28 under its $1.2 billion revolving credit facility Total Debt 41% Equity 59% Stand alone Capitalization February 28, 2010 Page 29
Dividend Growth Creating Exceptional Value for Shareholders 8 dividend increases since January 2006 Target long-term dividend payout of 60%-70% of recurring earnings 2010 guidance includes dividend increases of 2 cents per share semi annually Total return exceeds S&P 500 Index Dividends Per Share Total Return at Feb. 26, 2010 57% Increase ** 500% $1.22 $1.40 $1.56 $1.68 $1.80 400% 300% 200% 100% 0% 2006 2007 2008 2009 2010G* *ONEOK, Inc. board approval required ** Since January 2006-100% 10-year Total Return 5-year Total Return 3-year Total Return ONEOK, Inc. S&P 500 Utilities S&P 500 Index Page 30
Page 31 ONEOK Partners
ONEOK Partners Overview Participates in natural gas and natural gas liquids value chains Strategic assets connected to prolific supply basins with access to key markets Provides non-discretionary services to producers and customers Generates stable cash flows from predominantly fee-based income Aligned interests: ONEOK: General Partner ONEOK: 42.8 percent owner Natural Gas Gathering & Processing Natural Gas Pipelines Natural Gas Liquids Gathering Pipeline Natural Gas Liquids Distribution Pipelines Page 32
ONEOK Partners Strong Asset Position Strategic assets connected to prolific supply basins with access to key markets Provides non-discretionary services to natural gas producers and various customers Natural Gas Two businesses Gathering & Processing Pipelines Diversified supply basins, producers and contracts mitigate earnings volatility Earnings on pipelines are predominantly fee based Natural Gas Liquids One integrated business: Includes gathering, fractionation, storage and pipelines Links key NGL market centers at Conway and Mont Belvieu Earnings are predominantly fee based Page 33
Natural Gas What We Do Connect raw natural gas production from the wellhead to markets through: Gathering and compression via extensive pipeline systems Processing and treating to remove contaminants and extract natural gas liquids Storage services using underground caverns Transportation of residue natural gas via extensive pipeline systems, both intraand inter-state Supply Gathering & Processing Storage & Transportation --------------------------Markets----------------------- Distribution Marketing Power / Industrial Page 34
Natural Gas Diverse Asset Base Two businesses: Gathering & Processing Pipelines Diversified supply basins, producers and contracts mitigate earnings volatility Earnings on pipelines are predominantly fee based Natural Gas Gathering Pipeline Natural Gas Interstate Pipeline Natural Gas Intrastate Pipeline Northern Border Pipeline (50% interest) Natural Gas Processing Plant Natural Gas Storage Page 35
Natural Gas Gathering & Processing Key Points Provides non-discretionary services to producers Gathering, compression, treating and processing Natural gas supplies from five basins Wind River equity investment Diverse contract portfolio More than 2,000 contracts Minimal exposure to keepwhole spread Gathering Processing Production Year ended 2009 Wind River Gathering Pipeline Processing Plant 15,000 miles of pipe 13 active plants 769 MMcf/d capacity 1,123 BBtu/d gathered 658 BBtu/d processed 291 BBtu/d residue sold 43 MBpd NGLs sold Powder River Hugoton Williston Kansas Uplift Anadarko Page 36
Natural Gas Gathering & Processing Volumes by Basin Williston Basin produces high NGL content gas Produced with crude oil Powder River Basin produces dry gas Does not require processing Oklahoma and Kansas regions produce moderately wet gas Requires processing Gathered Volumes by Basin* Hugoton 20% 3-4 GPM Central Kansas Uplift 12% 2-4 GPM Anadarko 38% 3-5 GPM Powder River 21% 0 GPM Williston 9% GPM = gallons of NGLs per Mcf of natural gas * 2010 guidance Page 37
Natural Gas Gathering & Processing Gathered Volumes Wells connected 2010: 400 plus 2009: 304 2008: 476 2007: 352 Approximately $32 million in annual growth capital for new well connections in 2010 2009 gathered volumes decreased 4% from 2008 2010 gathered volumes flat to 2009 2009/2010 volume declines primarily related to Powder River Basin Lowest margin throughput Natural Gas Gathered (BBtu/d) 1,171 1,164 1,123 1,131 800 798 782 799 371 366 341 332 2007 2008 2009 2010G Rocky Mountain Mid-Continent Page 38
Natural Gas Gathering & Processing Processed Volumes Active drilling in the Woodford Shale and Bakken Shale 2009 processed volumes increased 3% from 2008 2010 processed volumes expected to increase 6% from 2009 Natural Gas Processed (BBtu/d) 696 658 621 641 571 525 539 545 96 102 113 125 2007 2008 2009 2010G Rocky Mountain Mid-Continent Page 39
Natural Gas Gathering & Processing Contract Portfolio Contract restructuring is a core capability Increases fee-based business and reduces commodity price sensitivity Conditioning language is on 84% of keep-whole contracts and reduces spread risk Comfortable with current contract mix Contract Mix by Volume Contract Mix by Margin 3% 3% 15% 10% 6% 8% 7% 4% 3% 6% 1% 1% 1% 31% 34% 27% 30% 34% 32% 35% 13% 12% 13% 13% 3% 2% 2% 2% 55% 56% 50% 62% 5% 1% 60% 51% 53% 61% 61% 58% 63% 62% 29% 30% 23% 35% 34% 2004 2005 2006 2007 2008 2009 2010G 2006 2007 2008 2009 2010G Page 40 Fee Based Percent of Proceeds Keep Whole Keep Whole w/ Conditioning
Natural Gas Gathering & Processing Risk Mitigation Contract restructuring reduced commodity price and keep-whole spread sensitivity Long NGL, condensate and natural gas positions 2010 hedged positions* NGLs: 75% at $1.03/gallon Condensate: 75% at $1.80/gallon Natural Gas: 75% at $5.55/MMBtu 2011 hedged positions* NGLs: 13% at $1.34/gallon Condensate: 25% at $2.12/gallon Natural Gas: 43% at $6.29/MMBtu Commodity Price Sensitivity Before Hedging Margin Impact ($ Millions) $4.8 $4.5 $3.8 $2.1 $1.7 $1.1 $1.3 $1.0 $1.2 $1.1 $1.1 $0.4 $0.5 $1.0 $1.0 $1.0 -$0.1 $0.3 $0.6 $1.1 $1.2 -$1.6 -$2.7 -$3.5 2003 2004 2005 2006 2007 2008 Commodity Natural Gas Liquids Crude Oil Natural Gas Sensitivity 2009 2010 1 cent/gallon increase $1/barrel increase 10 cent/mmbtu increase *As of Feb. 26, 2010 Page 41
Natural Gas Pipelines Key Points Connected to diverse supply basins and markets Predominantly fee-based income Approximately 90 percent of transportation capacity contracted under demand-based rates Storage provides valuable services Northern Border Pipeline Viking Gas Transmission Midwestern Gas Transmission Guardian Pipeline Pipelines Storage Equity Investment 7,000 miles, 6.5 Bcf/d peak capacity 52.4 Bcf active working capacity 50% Northern Border Pipeline Natural Gas Interstate Pipeline Natural Gas Intrastate Pipeline Natural Gas Storage Northern Border Pipeline (50% interest) Page 42
Northern Border Pipeline 50 Percent Equity Investment Links natural gas supply from western Canada to Midwest Potential new supply from emerging shale development in northeast British Columbia Bison Pipeline project Connecting Rockies supply to Northern Border Pipeline with access to upper Midwest markets Estimated in-service date late 2010 302 miles of 30 pipeline from Gillette, Wyo. Capacity of 477 MMcf/d Sold project to TransCanada in Sept. 2008 Northern Border Pipeline Proposed Bison Pipeline Northern Border Pipeline Pipeline 1,249 miles Capacity 2.4 Bcf/d Page 43
Natural Gas Liquids What We Do Connect raw-blended NGL production from natural gas processing plants to markets through: Gathering via extensive pipeline systems Fractionating to convert raw-blended NGLs to purity products Storage services using underground caverns Marketing NGL products to end-users Distributing NGL products to markets Gathering & Fractionation Storage Distribution -------------------------Markets-------------------------- Petrochemical Heating Refining Page 44
Natural Gas Liquids Extensive Asset Base Gathering, fractionation & storage Capacity in Mid-Continent and Gulf Coast NGL Pipelines From key supply areas Distribution to key markets Connected to approximately 90% of the Mid-Continent processing plants and a growing share in the Rockies and Barnett Shale Earnings are predominantly fee based NGL Gathering Pipelines NGL Distribution Pipelines NGL Market Hub NGL Fractionator NGL Storage Page 45
Natural Gas Liquids Key Points Provides non-discretionary and fee-based services to various customers Gathering, fractionation, storage, transportation and marketing Extensive raw NGL gathering system Access to 98 natural gas processing plants in the Mid-Continent, Barnett Shale and Rocky Mountain regions Links key NGL market centers at Conway and Mont Belvieu North System supplies Midwest refineries Fractionation 549,000 Bbl/d capacity Isomerization 9,000 Bbl/d capacity Storage 27.4 MMBbl capacity Distribution 3,500 miles of pipe with 691,000 Bbl/d capacity Gathering Raw Feed 4,200 miles of pipe with 800,000 Bbl/d capacity NGL Gathering Pipelines NGL Distribution Pipelines NGL Market Hub NGL Fractionator NGL Storage Page 46
Natural Gas Liquids NGL Supply Significant volume growth in the Mid-Continent from 21 new processing plant connections and growth from existing plant connections Rockies, Barnett Shale and Woodford Shale provide additional growth Gathering Volume (MBbl/d) 80% Growth Fractionation Volume (MBbl/d) 69% Growth 372 407 481 529 226 248 260 313 356 389 2006 2007 2008 2009 2010G 2006 2007 2008 2009 2010G Page 47
Natural Gas Liquids Fractionation Capacity ONEOK Partners: 549,000 Bbl/d, net ownership Increasing our fractionation capacity 60,000 Bbl/d of fractionation services from Targa in early 2011 Continuing to evaluate expansion and new fractionator opportunities Conway Bushton 27% Hutchinson 2% 9% Medford 38% Mont Belvieu 24% Page 48 * Does not include Targa capacity Fractionation Capacity*
Natural Gas Liquids Fractionation Capacity Agreement with Targa Page 49 Signed a definitive 10-year fractionation services agreement for additional capacity at Targa s Cedar Bayou facility in Mont Belvieu, Texas Expected to be operational during second quarter 2011 Rationale Relatively short construction period Cost effective Provides 60,000 barrels per day of additional capacity to accommodate continued new supply growth NGL Distribution Pipeline Arbuckle Pipeline Targa Expansion NGL Market Hub NGL Fractionator
Natural Gas Liquids Margins Fee-based Earnings with Optimization Opportunities Exchange & Storage Services Gather, fractionate, transport and store NGLs and deliver to market hubs Primarily fee based 2010* 2009 2008 65% 59% 56% Transportation Transporting raw NGL feed from supply basins and NGL products to market centers Fee based 2010* 2009 2008 14% 12% 9% Marketing Purchase for resale approximately 60% of system supply in the Mid- Continent on an index-related basis Differential based 2010* 2009 2008 6% 6% 9% Optimization Obtain highest product price by directing product movement between market hubs Differential based 2010* 2009 2008 13% 17% 25% Isomerization Convert normal butane to iso-butane Differential based 2010* 2009 2% 3% 2008 4% Page 50 *Guidance
Natural Gas Liquids Supply Growth - Rocky Mountains Overland Pass and Laterals Supply Supply commitments secured to reach throughput of more than 200,000 Bbl/d over the next three to five years Capacity (MBbl/d) 110 140 Expandable to 255 Nov. 2008 Oct. 2009 2010-2015 Page 51
Natural Gas Liquids Arbuckle Pipeline Cost Arbuckle Pipeline $490 Million NGL Gathering Pipeline NGL Distribution Pipeline NGL Arbuckle Pipeline NGL Storage NGL Fractionator NGL Market Hub Length Completion Date 440 miles In service August 2009 Capacity (MBbl/d) 160 Expandable to 240 2009 2010-2015 Supply Supply commitments secured to reach throughput of more than 210,000 Bbl/d over the next three to five years Page 52
Natural Gas Liquids U.S. NGL Supply Sources and End Uses Five-year Averages NGL Supply Sources Gas Processing 73% of U.S Supply NGLs Supplied 1 Ethane - 39% Propane - 29% Normal Butane - 7% Iso-butane - 10% Natural Gasoline - 15% NGL End Uses Primary Petrochemicals 50% of NGLs Supplied Space Heating & Other Fuel Uses 27% of NGLs Supplied Crude Oil Refining 16% of U.S. Supply Overland & Waterborne Imports 11% of U.S. Supply Ethane - 3% Propane - 62% Mixed Butanes - 36% (summer) Propane - 65% Mixed Butanes - 24% Pentane Plus - 11% Motor Gasoline & Blend Stocks 19% of NGLs Supplied Ethanol Denaturing <1% of NGLs Supplied Fuel Exports 3% of NGLs Supplied Page 53 1 Percentage represents the composition of NGL mix from primary sources Source: EIA, En*Vantage
ONEOK Partners Growth More than $2 Billion of Growth Projects Completed 2010 is first full year of all projects contributing EBITDA Grasslands plant expansion Fort Union Gas Gathering Expansion Guardian II Expansion Piceance Lateral Overland Pass Pipeline North System Acquisition D-J Lateral NGL Upgrade Projects Woodford Extension Midwestern Extension Natural Gas Gathering & Processing Natural Gas Pipelines Natural Gas Liquids Gathering Pipelines Natural Gas Liquids Distribution Pipelines Growth Projects Arbuckle Pipeline Page 54
Future Growth Projects 2010-2015 Potential Capital Investments Natural Gas Segment Category Cost Ranges (millions) Gathering & Processing Well-connects and routine growth $60-90 / year New plant facilities $200-$250 Plant consolidation $10-$20 Plant expansions, upgrades $140-$180 Pipelines New pipelines $300-$350 Expansions $5-$10 Storage $30-$50 New market connections $80-$120 Natural Gas Liquids Segment Category Cost Ranges (millions) Fractionation & Storage Fractionator expansions $120-$160 New fractionator $400-$500 Rail / truck racks $10-$20 Storage $10-$30 Pipelines New pipelines $800-$1,100 New market connections $50-80 Expansions $25-$50 Estimate $1,100-$1,500 Estimate $1,400-$1,900 Project Timing Depends on Market Needs Page 55
Growth Capital Future Investments Potential Natural Gas Liquids Projects - Fractionator expansions - New fractionator - Rail / truck racks - Storage - New pipelines - New market connections - Expansions Potential Natural Gas Gathering & Processing Projects - Well-connects - New plant facilities - Plant consolidation - Plant expansion, upgrades Natural Gas Gathering & Processing Natural Gas Pipelines Natural Gas Liquids Gathering Pipelines Natural Gas Liquids Pipelines Potential Natural Gas Pipelines Projects - New pipelines - Expansion - Storage - New market connections 2010-2015 Potential Growth Projects: $300-$500 million/year plus acquisitions Page 56
ONEOK Partners Shale Play Opportunities Active in numerous shale plays Evaluating new shale plays Producer supply commitments required Western Canadian Sedimentary Basin Natural Gas Basins Natural Gas Shale Plays OKS Basins Shale Plays Montana Thrust Belt Big Horn Basin Greater Green River Basin Pardox Basin San Juan Basin Uinta Piceance Basin Williston Basin Bakken Shale Denver Basin Forest City Basin Cherokee Platform Michigan Basin Illinois Basin Anadarko Raton Basin Basin Woodford-Caney Arkoma Fayetteville Woodford Shale Basin Black Warrior Permian Basin Basin Barnett Shale Haynesville Shale East Texas Basin Ft. Worth Basin Utica Shale Appalachian Basin Marcellus Shale Page 57 Source: EIA Eagle Ford
Financial Strength Financial Strength Page 58
Strong Balance Sheet Liquidity Strong credit rating S&P: BBB Moody s: Baa2 Capital structure Goal: 50/50 capitalization Reflects Feb. 2010 equity offering of $323 million, 5.5 million units $1 billion revolving credit facility $260 million outstanding at Feb. 28, 2010 Expires in 2012 Strong general partner Total Debt 50% Capitalization February 28, 2010 Equity 50% Page 59
Earnings Growth Investments Provide Earnings Growth Diverse asset base provides significant feebased income through non-discretionary services 2009 operating income compared with 2008 includes less favorable: Commodity pricing in gathering & processing Location differentials in NGL $257 $396 Operating Income 16% CAGR $645 $447 $547 $172 $156 $297 2005 2006* 2007 2008 2009 2010G *Millions of dollars, excluding gain/loss on sale of assets $625 Gathering and Processing Natural Gas Pipelines Natural Gas Liquids Page 60
ONEOK Partners Financial Guidance 2010 75% of equity volumes hedged 1 cent per unit per quarter increase in distribution Average units outstanding 101.4 million units $547 $625 $434 $470 $558 $600 $616 $557 $362 $278 Growth $59 $84 Maintenance Operating Income Net Income Distributable Cash Flow Capital Expenditures Page 61 2009 Actual 2010 Guidance Midpoint ($ Millions)
ONEOK Partners Earnings Growth 2010 Drivers Operating Income and Equity Earnings Drivers 2009 Guidance vs. 2010 Guidance $ Millions $725 $625 $525 $425 $619 2009 Actual G & P $5 * Higher processing volumes * Favorable pricing * Flat gathering volumes NGP $17 * Full-year impact of 2009 completed growth projects * Higher Northern Border Pipeline equity earnings * Higher storage fees NGL $65 * Full-year impact of 2009 completed growth projects * Higher throughput on Overland Pass, D-J, Piceance and Arbuckle pipelines * Supply growth in Mid- Continent * Narrower NGL product price differentials Other ($1) $705 2010 Guidance $325 Page 62
Distribution Coverage Financial Discipline Target coverage ratio of 1.05x to 1.15x Considerations Fund growth projects Commodity prices Capital market conditions Overland Pass option 2010: 1 cent per unit per quarter increase in distribution $4.50 annual distribution $3.71 $3.20 $3.78 $4.48 $4.025 1.16 1.19 1.22 $4.92 $4.26 $4.35 1.45 $6.17 $4.91 $4.50 1.13 1.05 2005 2006 2007 2008 2009 2010 Guidance* Distributions Declared Per Unit Distributable Cash Flow Per Unit Coverage Ratio *ONEOK Partners board approval required Page 63
Value Creation Delivering Consistent Growth and Stable Earnings Distribution growth: 13 increases with ONEOK as sole general partner Total return exceeds S&P 500 Index $0.80 $0.88 $0.95 $0.97 $0.98 $0.99 Distributions Per Unit 8% CAGR $1.00 $1.01 $1.025 $1.04 $1.06 $1.08 $1.08 $1.08 $1.09 $1.10 $1.11 $1.12 $1.13 $1.14 2010 Guidance 500% 400% 300% 200% 100% Total Return at Feb. 26, 2010 0% 1Q06 3Q06 1Q07 3Q07 1Q08 3Q08 1Q09 3Q09 1Q10* 3Q10* *2010 distribution guidance; ONEOK Partners board approval required -100% 10-year Total Return 5-year Total Return 3-year Total Return ONEOK Partners Alerian MLP Index S&P 500 Index Page 64
ONEOK Partners Growth at ONEOK Partners benefits ONEOK Distributions to ONEOK have increased significantly in the past three years: General partner distributions have more than doubled Limited partner distributions have grown more than 70% Internally generated growth projects will enable distribution growth 2010 guidance includes 1 cent per quarter increase in distributions $ Millions $300 $250 $200 $150 $100 $50 $- $146 $108 $38 Distributions to ONEOK* 18% CAGR $207 $149 $58 * Declared $181 $184 $86 $98 2006 2007 2008 2009 GP interest $267 LP units owned $282 Page 65
Aligned Interests Growth at ONEOK Partners Benefits ONEOK As ONEOK Partners grows, ONEOK grows Two-thirds of every incremental EBITDA dollar flows to ONEOK Distribution growth: Penny a quarter increase adds $5.8 million to ONEOK s annual cash flow Capital Investment EBITDA Growth Higher Distributions IDR and Equity Income Net Income Dividends Unit Price Appreciation Share Price Appreciation Page 66
ONEOK Partners Managing Risk Capital projects provide earnings growth Predominantly fee-based Natural gas gathering and processing segment commodity risk is significantly hedged Volume risk Mitigated by supply diversity Demand-based contracts on natural gas pipelines $844 Million $896 Million 12% 13% 28% 27% 60% 60% Sources of Margin $1.1 Billion $1.1 Billion 20% 18% 28% 52% 18% $1.2 Billion 12% 21% 64% 67% 2006 2007 2008 2009 2010 Guidance Fee Commodity Spread Page 67
Capital Expenditures Capital Expenditures 2007-2015 2010 capital expenditure guidance $278 million in growth $84 million in maintenance Identified $300 - $500 million per year in growth projects between 2010-2015 Growth Capital Expenditures $1,172 $ In Millions $650 $462 $188 $808 $364 $555 $278 $423 $168 $132 $192 $300+ per year 2007 2008 2009 2010G 2010-2015 Page 68 Natural Gas Liquids Natural Gas