CO 2. Tim Bradley & Jim Wuerth. President CO 2 Group

Transcription

1 CO 2 Tim Bradley & Jim Wuerth President CO 2 Group

2 Kinder Morgan CO 2 Asset Map 2

3 History of CO 2 Group and Looking Forward Track Record Consistently very close to budget despite inherent volatility Shell CO 2 formed in 1998, KM share 20% Acquired remaining 80% in April 2000 Acquired SACROC interests June 2000 Acquired Yates interests in 2001 and 2003 Ramped up developments at SACROC Constructed Centerline pipeline in 2003 Constructed power plant in 2005 Increased oil production 3X+ Acquired Wink pipeline in 2004 Acquired Katz field 2006 Increased SW Colorado CO 2 capacity 30% 2008 Katz CO 2 project: CO 2 injection commenced Dec-2010 Doe Canyon expansion announced 2012 DCF ($MM) (a) Our assets, resources and technologies provide us with growth opportunities Strong growth in CO 2 demand new developments are underway Continued developments at SACROC, Yates, and Katz Emerging oil and gas opportunities (a) CO 2 Sales and Transportation includes Yates Oil Gathering System (YOGS), CO 2 sales profit on own use has not been eliminated 3

4 2012 Performance Recap Beat plan operationally; NGL prices hurt 2012 DCF: $1,365MM plan $1,315MM actual -$59 MM price impact SACROC (a) DCF $706MM vs. $747MM plan Oil: 28,968 Bbl/d vs. 27,868 Bbl/d NGLs: 18,825 Bbl/d vs. 17,361 Bbl/d NGL Price 22% below plan: $59 MM impact CO 2 Source and Transportation DCF $358MM vs. $350MM plan CO 2 Production: 1212 MMCF/d vs 1264 MMCF/d Yates DCF $240MM vs. $240MM plan 20,839 Bbl/d vs. 20,986 Bbl/d Katz DCF $9.87MM vs $27.6 MM plan 1,722 Bbl/d vs 2,267 Bbl/d Capex Capex $443MM actual vs. $437MM plan CO 2 Purchases slightly higher (a) Including SACROC Services and remaining oil and gas assets 4

5 2012 and 2013 DCF by Asset Group (a) 2012 DCF = $1,315 MM 2013 DCF = $1,380 MM Katz 1% S&T 27% SACROC Complex 54% Yates 18% (a) Segments shown without elimination 5

6 2013 Expansion Capital Budget - $632 Million Staff overhead and CO 2 purchases aggregated CO 2 purchases and staff overhead allocated to assets Note: ES refers to Eastern Shelf properties including Katz field development and Residual Oil Zone (ROZ) development. 6

7 2013 Executive Summary Capex Program $632 MM (a) CO 2 S&T $241 MM Drill 6 new wells, 6 Re-Completion and Seismic Order Additional Compression (70,000 horsepower) Produce 1,275 MMcf/d St Johns Unit and Lobos PL Pre-Development Increase Oil Transportation Capacity to 145 BOPD SACROC Complex $170 MM (b,c) Activate 24 patterns Continue Infill, Harvest and Beyond Tertiary Efforts Initiate work for Platform 3 North Purchase 120 MMcf/d CO 2, Produce 30.7 MBbl/d oil, 19.2 MBbl/d NGL Yates $21 MM (c) Drill 30 wells (15 East, 15 West) Add 10 CO 2 injectors Purchase 115 MMcf/d CO 2, Produce 20.2 MBbl/d oil Eastern Shelf $32 MM (c) Activate 22 patterns Purchase 89 MMcf/d CO 2, Produce 2,850 Bbl/d oil $379MM DCF $743MM DCF $236 MM DCF $22MM DCF Total 464 MM capex (exc overhead / CO 2 purchases) (a) Total $1,380MM DCF (a) Included in $632 million total capex program are overhead and CO 2 purchases, in the aggregate, of approximately $168 million (b) Includes minor properties, unallocated costs (c) Includes secondary objectives 7

8 Impact of Oil Price / Volume Variance on 2013 DCF 2013 Budget: $1,380MM Volume +/ 1,000 Bbl/d SACROC / Katz Yates CO 2 Volume +/ 50 MMCF/d Oil Price +/ $1/Bbl WTI NGL $2.1MM CO 2 $2.0MM Crude $1.8MM NGL Price +/- $1/Bbl $26.4MM $13.8MM $9.8MM $5.9MM $3.9 MM Notes: Unhedged WTI price presumed to average $91.67/b; WTI-WTS spread = $1.42/Bbl / Midland-Cushing spread = $2.70 (total spread for WTS = $4.12) NGL price presumed to be $47.67 (52% WTI) 8

9 CO 2 S&T Growth Opportunities Demand is strong and continues to increase Domestic EOR Projected CO 2 Demand (a) We have a simple plan: 1. Sign Contracts securing the demand 2. Develop the supply to meet those contracts Options: MMcf/d for $1-2 Billion (a) Source: AEO 2011 Forecast 9

10 CO 2 Source & Transportation Growing Business Opportunities Permian Basin CO 2 Deliveries Permian Basin 2012 supplies were at capacity, customers were being pro-rated Permian Basin demand is growing via new projects, extensions of existing projects, and ROZ projects Domestic CO 2 Deliveries Domestic EOR Industry CO 2 EOR activity is increasing Naturally occurring sources are being expanded to ultimate capacity Several regions have potential Gulf Coast, California, Mid-continent, Canada Sources: KM estimates, Oil and Gas Journal, EIA, XOM, Dakota Gasification, DRI 10

11 CO 2 Entitlement Volumes Produced and Sold to our Customers CO 2 KM-share Significant growth since 2005: CAGR: volumes +5.2%, price +13.1% 2013 vs 2012: volumes +5.2%, price +3.1% And, just to be clear: Although our customer deliveries often have and will exceed our entitlement, sales revenues are based on our working interest entitlement and not deliveries KM share of EOR demand consumes ~37% of our entitled production in 2013 Elimination: consolidation results in eliminating profit on sales to ourselves, however we view our S&T and O&G businesses independently, and price sales to ourselves at market prices 11

12 Demand Growth and Regeneration 5-year Contracted CO 2 Volumes CO 2 Daily Contract Quantities 1, MMcf/d Year High oil prices have increased long-term demand for CO 2 Total contract quantities signed in represents 3.4 times our entitled production during that period Weighted average contract life with 3rd parties is 10.3 years Contract Terms Improvement (a) Percent Increase High CO 2 demand has improved contract terms Higher floor prices Increased upside to oil price Higher take-or-pay (T.O.P.) requirements Floor Price % WTI % T.O.P. (a) relative to

13 Doe Canyon Field Expansion $255 MM, 65 MMcf/d CO 2 increase Projected Production Forecast, MMcf/d 170 MMcf/d (from 105 MMcf/d) Adds 750 Bcf reserves Timing : 2nd Quarter 2014 Drilling underway Parallel Compression Q MMCFD YE Booster Compression Q New Booster Building New Recip. Building 2040 Project delivers attractive returns based on contracts recently executed and currently being negotiated Existing Facility 13

14 McElmo Dome Field Expansion Yellow Jacket Area 1.23Bcf/d CO 2 Targeted McElmo Production Project Incremental Production, MMcf/d Target Rate of 1.23 Bcf/d Extended for ~2 yrs Add 1.7 TCF reserves Timing : 4th Quarter Project Costs $243 MM Compression $141 MM Facilities $68 MM SWD Wells $15 MM 2013 Drilling $19 MM Proposed to Partners in 4 th Qtr Project delivers attractive returns based on contracts recently executed and currently being negotiated 14

15 St. John s CO 2 Source Opportunity Assessment drilling and testing ongoing St Johns McElmo Dome 16 Pipeline 216 Miles Cortez PL Sheep Mountain Bravo Dome Denver City Evaluating pipeline & field development options 200 MMCFD ~$0.6 B 450 MMCFD ~$1.3 B Drilled/Recompleted 14 wells Established good deliverability in Granite Wash Deliverability in Amos Wash is being evaluated Testing completion strategies Core analysis, log evaluation, geological/reservoir characterization and mapping is ongoing Target in service date

16 Oil and Gas Segment Production and DCF Net Hydrocarbon Production (Mboe/d) Original oil in place (billion Bbls) SACROC 2.8 Yates 5.0 ES 0.23 DCF ($MM) Gross production (Bbl/d) (b) SACROC oil 28,998 30,726 SGP NGLs 18,825 19,233 Yates 20,839 20,212 ES 1,722 2,846 DCF (b) ($MM, without Elimination) SACROC Group (a,b) Yates (b) ES (b) Notes: Yates DCF does not include contribution from MKM Boe: Oil and NGL =1:1, Residue gas sales = 6:1 Gas Processing includes net Boe attributable to our plant interests and processing agreements but excluded from reserve report (a) Includes other minor oil and gas properties near SACROC (b) Includes Secondary Objectives 16

17 Oil & Gas Margins and Cost Structure Oil & Gas All-in Cost Structure (a) ($/Net Boe) O&G cost structure has strong correlation to energy prices Power is tied to gas prices High activity levels have increased staffing and other service costs Well-work and rig contracts now being tied to oil prices Purchased CO 2 and TOTI (b) are strongly correlated to oil prices (a) Costs and Revenue per net Boe, including hedges where applicable; includes acquisition and all development costs (b) Taxes other than income taxes 17

18 Oil and Gas Segment Over past 5 years, capex 6% below plan, oil production 0.5% below plan Capex ($MM) Net Oil Production (MBbl/d) Budget Actual Note: Capex includes CO2 purchases and capitalized overhead 18

19 SACROC Production & Operations Highlights Oil Production (MBbl/d) Sub-pump Improvements 2012 Review Oil production 3.9% above plan Harvest better than expected Good results from infill program Platform 2 meeting oil expectations GOR under control Sub Pump and Compressor performance on target Costs above plan Opex/sustaining capex: $6MM above plan Increased power congestion charges Expansion capex: $14.5MM above plan Harvest project capital and opex (well count) 2013 Focus Evaluate additional harvest opportunities Continue infill / Green Zone lateral program Evaluate Cisco / Wolfcamp / Cline opportunities Add Platform 2 and Platform 3 patterns at the right pace manage gas volumes 19

20 WS2 WS1 WS WS A-22A ST A-3 12A A-9 12A A A-21 12A A-2 12A A-1 12A A-9 17A-12 17A-11A A A-3 17A-4 17A A ST A A 24-5A A A A A 26-3A A A A 28-1A 28-2A A _ST A A A A 28-6A A _ST 38-3A A A A A A A A 36-A1 40-3A 33-2A B2 36-C3 36-D B2A 36-C3A36-D4A A A 37-3A A A A _ST A A 62-3A A A A A A ST A A 58-2A A A A _ST _ST _ST _ST 56-1A A A _ST A A 56-6A 56-6_ST A A A 56-20A _ST_No A 50-2_ST_No A A 56-5A A 46-2B A A A A A A A A ST_ A A A_ST_2 60-3A _ST A A A _Sidetrack A A A A A _ST _ST A A B-2A _ST A _ST 69-1A A ST_ A B ST_2 73-5_Sidetrack _ST _ST _ST 89-1A 74-WW-1 73-WW A A 69-4A A A _ST 73-WW A A A B BW2BW 77-1_ST WW _ST A A WW _ST _ST A A-3 104A A A _ST Side 1 72A A-7 104B A-4 104A _Sidetrack _ST _ST ST _ST A A A ST 129-4A _ST WW _ST _ST A _ST A A _ST A 159-4A ST A A A A A A A A A _ST _ST 142-1_ST_ _ST_ A B A A A _ST _ST _ST B _ST 126A A-3 161A B 161-1B A A A A A A _ST A A _ST 210-4_ST A ST _ST ST A 239-2A _ST _ST A A A A-8 251A _ST A 221-1_ST A A A A A A-5 251A A _ST A A A A 263-1A A A A A A A-2A A A A A A A A A A A-7 206A A A-8A 262A-1A A A A A A A 283-1A A A 277-2A A A A A A A A A A B-1 286A WS1 WS1 WS1 WS1 WS1 WS1A WS1A WS1 WS2 2A 3 WS1 WSW WS1 WS1 WS WS A A A-3 327A ,335 4,670 7,005 FEET WELL SYMBOLS Location Only Oil Well Shut-In Producer Injection Well Pre CO2 Injector CO2-Water Injector Shut-In CO2-Water Well Water Injection Well Shut-In Water Injector Temporarily Abandoned P&A'ed Producer Plugged and Abandoned P&A'ed CO2-Water Well P&A'ed Water Injector H2O Injection or Observation Well TA Disposal Well Plugged Disposal Well Sidetracked Original Borehole Service Well Dry Hole Brackish Water Supply Well P&A Brackish Water Supply Well Brine Supply Well Fresh Water Well September 28, 2010 SACROC Unit Harvest Project: 3,000 b/d of incremental oil and ~40MMCF of additional recycled CO 2 to inject Harvest Production older projects Pump upsizes and reactivations CR 1 and CR2 Primary Areas of Wellwork _ST A A A A 56-10A A SACROC Unit Area Teams Project Phases By: Brian Bernal 20

21 SACROC Unit -- Emerging Opportunities Big Fields get Bigger Canyon Reef (SACROC Unit) Horizontal producing and injection wells West end development Middle Canyon re-development Infill Drilling pinchouts and mounds Other Horizons (20,000+ acres of base leases) Currently testing Cisco Sands 2 wells recompleted to date Analyzing cores cut in the Wolfcamp/Cline shales Noodle Creek test A.E. Dennis #6 (92-6) Horizontal well proposed for Cisco Sand Evaluating seismic for deep opportunities Plan includes 470 bopd 21

22 Yates Production Steady 2012 Production (MBbl/d) 25,000 20,000 15,000 10,000 5,000 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Plan Actual Yates oil slightly below plan in 2012 (0.7%) Oil column thinned at half rate (0.8 ) of previous year. Stable production Renewed East Side drilling Deeper/polymer gel to control gas West Side Horizontals waning, fewer in 2013 Waterflooding West Side to augment Horizontals Yates East Side Horizontals (Cum Oil, Bbls) 35,000 30,000 25,000 20,000 15,000 10,000 5, AFE Oil Cum Days Actual Oil Cum Strategies to add long-term reserves include: Continuing to raise reservoir pressure to increase CO 2 solubility: this will increase swelling and reduce oil viscosity Expand use of CO 2 injectors to increase CO 2 / Oil contact Expand East Side deep drilling 22

23 Katz CO 2 Project The Second Year Investment $202MM project total, $158MM thru 2012 Oil Response Oil Rate up from 1104 to 1806 Bbl/d (Dec to Dec) 2012 plan 2,267 vs. Actual 1,722 Bbl/d Phase 1 Underperforming Effect was 417 Bbl/d (77% of short fall) Bbl/d Recent Operation Challenges Asphaltene, Scale, Pump failures Effect was 84 Bbl/d (15% of short fall) 2013 Expected Production 2,850 Bbl/d Phase 2 & 3 response on track Increase pattern activations by 96% (23-45) Increase CO 2 purchases by 44% (62-89 MMcf/d) Budget Budget Actuals 0 1/1/2011 1/1/2012 1/1/2013 1/1/2014 1/1/

24 1/1/11 7/4/11 1/4/12 7/6/12 1/6/13 7/9/13 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 Katz CO 2 Project Solid oil response but Phase 1 Stalled ,500 1, ,000 Oil production by Development Phase Phase 1 Oil rate Curr View BOPD Phase Phase 1 Poor Performance in 6 Wells Near wellbore cleanouts had mixed results, Moving to fracture stimulate Total Phase Productivity 43% Low 0 1,000 Phase 3 Good Indicators Petrophysics, oil cut, pressure and containment continue to encourage Sub-pump redesign has improved failure rate Flow and gas assist more wells Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 24

25 Oil and Gas Segment Production Forecasts Production expectations tend to grow over time Evolution of Forecasted 2013 Production (a) over Time (MBbl/d, 8/8ths) We have replaced 105% of our Hydrocarbon production (net Boe) with new proved reserves for the past 3 years We expect production to exceed our reserve report over the long-term Higher recoveries and additional targets added to inventory at SACROC and Katz Proved Reserves Production Forecast (a) (MBbl/d, 8/8ths) Current challenge: slow the decline More efficient operations New opportunities (a) Forecasts based on independent consultant NSAI Reserve Report. Excludes minor properties 25

26 Oil & Gas, and Business Unit IRR 35% 30% 25% 20% 15% 10% 5% 0% 10-K + Reserve Report Gas Processing P2's, Development Costs S&T All-in O&G IRR ( ) ~22.7% Required disclosures in 10-K plus proved reserves cash flows: 15.6% With unhedged prices, IRR would have been 40.2% Adding in Gas Processing excluded from disclosures increases IRR to 16.8% Adding in reserves discounted to P2 by NSAI, and using planned development costs increases return to 22.7% Total business IRR ( ) ~30% Includes S&T assuming volumes increase with higher capacity, valued at market prices As of 12/31/12, CO 2 Segment cumulative free cash flow is $2.6B+ (net of cumulative invested capital) As of 12/31/13 expect cumulative FCF of $3.4B Note: Segments shown without elimination 26

27 KM CO 2 Current Outlook Development Plans SACROC Group Forecast 55 MMBoe net (a), $1,210MM KM-share capex ($258MM Capitalized CO 2 ) 5 Year Capex $606MM Continue platform development plan; production forecast is based on existing recovery expectations Forecast assumes deteriorating inlet gas quality impacting NGL production volumes DCF ($MM) (b) 2. Yates Base Case 29 MMBoe net (a), $335MM KM-share capex ($85MM Capitalized CO 2 ) 5 Year Capex $97MM Continue HDH programs and gravity drainage depletion plan; no upside potential included from infill or surfactant 3. Eastern Shelf / Other 30MMBoe net (a), $870MM KM-share capex ($538MM Capitalized CO 2 ) 5 Year Capex $228MM Continue development plans at Katz Claytonville CO 2 project not included 4. CO 2 S&T $1,842MM KM-share capex, 1.84 Bcf/d capacity 5 Year Capex $1,446MM Maintain aggressive CO 2 sales program and increase facilities capacity (production sustained by in-fill drilling and inlet compression (a) Net Boe = Net Crude plus NGLs plus Residue Gas sold divided by 6. (b) 2013 = Budget, at $95/Bbl; cost metrics based on 2012 run rate; development plans may change in different price scenarios (c) CO 2 profits not eliminated from S&T 27

28 Historical Long-term Outlook The best is yet to come Historical DCF Projections ($MM) CO 2 segment outlook has continued to grow over past 5 years Oil prices have decreased from $100 to $95/Bbl Increased costs but also opportunities Higher CO 2 volumes and prices Increased demand, improved contract terms Higher ultimate recoveries being achieved Improved operating practices, new areas to exploit 28