Exhibit 99.1
Analyst & Investor Day Presentation October 31, 2014 0 |
Forward-Looking / Cautionary Statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact, included in this presentation that address activities, events or developments that California Resources Corporation (the “Company” or “CRC”) assumes, plans, expects, believes or anticipates will or may occur in the future are forward-looking statements. The words “believe,” “expect,” “may,” “estimate,” “will,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company’s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management’s expectations and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include, but are not limited to, compliance with regulations or changes in regulations and the ability to obtain government permits and approvals; commodity pricing; risks of drilling; regulatory initiatives relating to hydraulic fracturing and other well stimulation techniques; tax law changes; competition for and costs of oilfield equipment, services, qualified personnel and acquisitions; risks related to our acquisition activities; the subjective nature of estimates 1 of proved reserves and related future net cash flows; vulnerability to economic downturns and adverse developments in our business due to our debt; insufficiency of our operating cash flow to fund planned capital expenditures; inability to implement our capital investment program profitably or at all; concentration of operations in a single geographic area; any need to impair the value of our oil and natural gas properties; compliance with laws and regulations, including those pertaining to land use and environmental protection; restrictions on our ability to obtain, use, manage or dispose of water; inability to operate outside of California; inability to drill identified locations when planned or at all; concerns about climate change and air quality issues; catastrophic events for which we may be uninsured or underinsured; cyber attacks; operational issues that restrict production or market access; and uncertainties related to the spin-off, the agreements related thereto and the anticipated effects of restructuring or reorganizing our business. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. This presentation includes financial measures that are not in accordance with generally accepted accounting principles (“GAAP”), including EBITDAX. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For a reconciliation of EBITDAX to the nearest comparable measure in accordance with GAAP, please see the Appendix. |
Cautionary Statements Regarding Hydrocarbon Quantities CRC has provided internally generated estimates for proved reserves and aggregated proved, probable and possible reserves (“3P Reserves”) as of December 31, 2013 in this presentation, with each category of reserves estimated in accordance with SEC guidelines and definitions, though it has not reported all such estimates to the SEC. As used in this presentation: • Probable reserves. We use deterministic methods to estimate probable reserve quantities, and when deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. • Possible reserves. We use deterministic methods to estimate possible reserve quantities, and when deterministic methods are used to estimate possible reserve quantities, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. The SEC prohibits companies from aggregating proved, probable and possible reserves estimated using deterministic estimation methods in filings with the SEC due to the different levels of certainty associated with each reserve category. Actual quantities that may be ultimately recovered from CRC’s interests may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery include the scope of CRC’s ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, regulatory approvals, drilling and production costs, availability of drilling services and equipment, drilling results, 2 lease expirations, transportation constraints and other factors; actual drilling results, including geological and mechanical factors affecting recovery rates; and budgets based upon our future evaluation of risk, returns and the availability of capital. In this presentation, the Company may use the terms “oil-in-place” or descriptions of resource potential which the SEC guidelines restrict from being included in filings with the SEC. These have been estimated internally by the Company without review by independent engineers and include shales which are not considered in most older, publicly available estimates. The Company uses the term “oil-in-place” in this presentation to describe estimates of potentially recoverable hydrocarbons remaining in the applicable reservoir. Actual recovery of these resource potential volumes is inherently more speculative than recovery of estimated reserves and any such recovery will be dependent upon future design and implementation of a successful development plan. Management’s estimate of original hydrocarbons in place includes historical production plus estimates of proved, probable and possible reserves and a gross resource estimate that has not been reduced by appropriate factors for potential recovery and as a result differs significantly from estimates of hydrocarbons that can potentially be recovered. Ultimate recoveries will be dependent upon numerous factors including those noted above. In addition, the Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. |
Presenters Bill Albrecht • Executive Chairman Todd Stevens • President and Chief Executive Officer Shawn Kerns • EVP - Corporate Development Robert Barnes • EVP - Northern Operations 3 Frank Komin • EVP - Southern Operations Darren Williams • EVP - Exploration Charlie Weiss • EVP - Public Affairs Mark Smith • Senior EVP and Chief Financial Officer |
Agenda PAGE Executive Summary and Transaction Overview 5 Strategy and Investment Highlights 11 California Growth Potential 29 Northern Operations 45 Exploration Overview 68 Southern Operations 57 4 Regulatory and Community Involvement 80 Financial Overview 86 Management Biographies 101 Appendix 95 |
Separation Overview • Creates industry leading California-focused E&P • Allows CRC to reinvest substantially all cash flow after debt service to grow its business • Enables CRC’s management team to focus on and accelerate the development and execution of its business in its core areas of operation • Enables application of its technical expertise in specific, under-exploited and under-invested reservoirs and fields • Enhances CRC’s market recognition with investors because of its status as an industry leader in California Rationale • CRC will own and operate the California business as an independent publicly-traded company with the requisite technical expertise • OXY stockholders will receive at least 80.1% of CRC shares and keep their shares in OXY Structure 5 AUG SEP Bond financing closed 10/1 • OXY will retain approximately 19.9% of CRC common stock > Retained shares to be disposed of or distributed within 18 months • CRC ticker to trade on NYSE Process OCT NOV DEC Regular Way Trading 12/1 Record Date 11/17 When Issued Trading 11/13 Credit Agreement signed 9/24 |
Operating Independently • Ready for stand-alone operations, Transition Services Agreement provides access to advisory services, if needed • Transition services may include: > Administrative, payroll, human resources, data processing, environmental, health and safety, financial audit support, financial transaction support, marketing support and other support services, information technology systems and various other corporate services • Occidental systems and processes have been cloned to provide the basis for independent operations > Avoids business interruption introduced by changing systems • The CRC organizational structure is designed and substantially staffed • Competitive benefits, base salary and bonus, supplemented with substantial equity compensation Ready for Independence Transition Services Agreement 6 • CRC expects the agreement will provide for the provision of specified transition services, if needed, generally for a period of up to 12 months, with a possible extension of 6 months (an aggregate of 18 months), on a cost or a cost-plus basis • CRC has longstanding relationships with well-established service providers > Broad range of services and products such as cementing and drill-bits supplied by major OFS companies > Drill rigs and workover rigs sourced from specialized suppliers > Additional ancillary services and products such as pumps provided by smaller contractors Service Providers |
CRC’s Board of Directors (12/1/14) Name Position Experience Bill Albrecht Executive Chairman Former President OXY O&G Americas; President OXY Oil and Gas USA; VP California Operations OXY Todd Stevens Director, President and Chief Executive Officer Former VP Corporate Development OXY; VP California Operations OXY Justin Gannon Director Independent Consultant, private investor and former Managing Partner with Grant Thornton and audit partner with Arthur Andersen Ron Havner Director Current Chairman, President and CEO of Public Storage Harold Korell Director Former Chairman and CEO of Southwestern Energy Co. Richard Moncrief Director Founding principal and current President and Chairman of Moncrief Oil International Current Executive Vice President of Lowe Enterprises, Inc. and 7 Avedick Poladian Director Director of Occidental Petroleum Robert Sinnott Director Current President, CEO and Chief Investment Officer of Kayne Anderson Capital Advisors, L.P. |
Corporate Governance • 8 members; 6 that qualify as independent • Highly experienced executives and oil and gas professionals • Classified board until annual meeting in 2018 Board of Directors 8 Key Committees • Nominating and Governance • Audit • Compensation • Health, Safety and Environment |
Transaction Timeline October 2014 November 2014 December 2014 S M T W T F S S M T W T F S S M T W T F S 1 2 3 4 1 1 2 3 4 5 6 5 6 7 8 9 10 11 2 3 4 5 6 7 8 7 8 9 10 11 12 13 12 13 14 15 16 17 18 9 10 11 12 13 14 15 14 15 16 17 18 19 20 19 20 21 22 23 24 25 16 17 18 19 20 21 22 21 22 23 24 25 26 27 26 27 28 29 30 31 23 24 25 26 27 28 29 28 29 30 31 30 Market holiday Key event 9 Date Event October 31st Analyst Day November 13th When Issued Trading November 17th Ex-Distribution Date November 30th Distribution Date December 1st First Day Regular Way Trading Key events |
Vision: To be the premier company providing Californians with long-term ample, affordable and reliable energy exclusively from California resources California Resources Corporation 10 Mission Statement: To maximize stockholder returns by safely and responsibly developing high-growth, high-return conventional and unconventional assets exclusively in California, while benefitting our workforce, communities and the state |
Key Investment Highlights World Class Resource Base • Interests in 4 of the 12 largest fields in the lower 48 states • 744 MMBoe proved reserves • Largest producer in California on a gross operated basis with significant exploration and development potential Portfolio of Lower-Risk, High-Growth Opportunities • Oil weighted reserves • Increased exploration and development program • 30%-100%+ rates of return on Shareholder Value Focus • Internally funded capital expenditure program • Optimized capital allocation • Unlocking under-exploited resource potential utilizing modern 11 California Heritage • Strong track record of operations since 1950s • Longstanding community and state relationships • Actively involved in communities with CRC operations Management Expertise • Successful operations exclusively in California • Assembled largest privately-held land position in California • Operator of choice in sensitive environments individual projects technology |
Disciplined Capital Allocation Focused Business Strategy • Grow NAV per share through exploration and development of under-exploited resources • Self-funding capital program eliminates reliance on external capital • Rigorously review projects to allocate capital most efficiently • Drive down costs to enhance project returns and ROE • Aggressively apply modern technologies to develop assets in a responsible manner Unlock Resource Potential Through 12 • Utilize legacy knowledge and data to accelerate successful exploration program • Capitalize on management team’s local expertise with assets Proactive and Collaborative Approach to Safety, Environmental Protection and Community Relations Increased Exploration and Development • Seek to benefit communities in which CRC operates • Maintain frequent, constructive dialogue with local, regional and state representatives • Be the operator of choice for California |
The State of California is a World Class Oil Province • Over 35 billion Boe produced since 18761 • Pico Canyon #4 was the first well with commercial production west of the Rockies and produced from 1876 to 1992 • Rich marine oil and gas source rocks • Underexplored with large undiscovered resources San Francisco Sacramento 2 billion Boe 19 billion Boe 13 1 Produced volumes: California Division of Oil, Gas & Geothermal Resources (“DOGGR”). • ~ 50 different active plays • We have operated in California since the 1950s • California's oil-in-place estimates have grown over many decades, and CRC will continue to expand its reserve base with the increasing application of proven, modern technologies Los Angeles Bakersfield CRC Fee/Lease CRC Fee/Lease 4 billion Boe 10 billion Boe |
Overview of California Resources Corporation California Pure-Play Net Resource Overview • CRC will be an independent E&P company focused on high-return assets in California • Largest privately-held acreage-holder with 2.3 million net acres • ~60% of total position is held in fee • Conventional and unconventional opportunities • Primary production • Waterfloods & gas injection • Steam / EOR Avg. net production by basin (YTD Q3’14) San Joaquin Basin 69% 68% PD Los Angeles Basin 21% 70% PD Ventura Basin 7% 64% PD Sacramento Basin 3% 100% PD San Joaquin Basin 71% 57% Oil Los Angeles Basin 18% 99% Oil Ventura Basin 5% 68% Oil Sacramento Basin 6% 0% Oil Total proved reserves by basin (12/31/2013) 744 MMBoe, 69% PD, 72% oil 155 MBoe/d, 62% oil 14 12,836 73% 1,537 9% 2,310 13% 1,008 5% San Joaquin Basin Los Angeles Basin Sacramento Basin Ventura Basin San Joaquin Basin Los Angeles Basin Sacramento Basin Ventura Basin 744, 68% 79% liquids 235, 21% 99% liquids 96, 9% 89% liquids 22, 2% 1% liquids • Substantial base of Proved Reserves (12/31/13) • 744 MMBoe (69% PD, 72% oil, 81% liquids) • PV-10 of $14 billion (SEC 5 year rule to PUDs) • 3P Reserves1 • 1,098 MMBoe (83% liquids) • PV-10 of $21 billion as of December 2013 1Refer to Endnote reference 1 in the Appendix for detail on 3P Reserves. 217,691 locations in known formations as of 12/31/13. Does not include 6,400 prospective resource locations. Total identified gross drilling locations by basin2 17,691 total gross locations2 Total 3P Reserves by basin (12/31/2013) 1,098 MMBoe; 83% liquids |
CRC is the Leading Operator in California • 85% of CA production from top 5 operators* Top California Producers in 2013* 188 166 147 38 25 - 20 40 60 80 100 120 140 160 180 200 CRC Chevron USA Aera Energy Freeport McMoRan LINN Energy Gross Operated MBoe/d Top 25 Companies MBoe/d % of CA CRC 188.0 29% Chevron 166.2 25% Aera 147.1 22% PXP/Freeport 38.5 6% Berry/Linn 25.4 4% MacPherson 11.3 2% Seneca 10.4 2% Venoco 7.0 1% E&B 6.6 1% Pacific Coast Enrg 6.4 1% Warren 3.8 0.6% Breitburn 3.8 0.6% 15 0 50 100 150 200 250 300 Gross Operated MBoe/d Growth of Top California Producers Aera Chevron CRC XOM 3.7 0.5% DCOR 3.3 0.5% Signal Hill 3.1 0.5% Greka 3.0 0.5% Crimson 2.7 0.4% ERG 2.2 0.3% Holmes 2.0 0.3% Termo 1.9 0.3% SJFM 1.6 0.2% TRC 1.5 0.2% Vaquero 1.3 0.2% Kern River Hldgs 1.3 0.2% JP Oil 1.1 0.2% Total – Top 25 642.8 97% Remaining 300 companies 22.2 3% *Gross operated production from DOGGR data for 2013 full year average. |
Acquisitions Over the Years 1,500,000 2,000,000 2,500,000 San Joaquin and Sacramento SJV North SJV and Sac SJV Central Kettleman North Dome Lost Hills ~40M acres Elk Hills and Kern Front 1.2MM acres Acquisition of Vintage and CA EOG assets 2.3MM acres Leading privately held acreage position in the state 1998 2009 2014 16 0 500,000 1,000,000 Acquisition Date Basin Minerals San Joaquin Minerals San Joaquin Basin Minerals and North Shafter Stockdale Huntington Beach Buena Vista Hills Elk Hills Vintage Merger Net Acres Tidelands Thums |
Stable Leasehold Position 160,000 180,000 Undeveloped acreage lease expirations, net San Joaquin Basin Los Angeles Basin Ventura Basin Sacramento Basin Total CRC Net acreage held in fee (000s) 943 13 212 195 1,363 % net acreage held in fee 63% 45% 83% 36% 60% Undeveloped acreage, net (000s) 1,110 10 196 288 1,604 Total acreage, net (000s) 1,485 30 257 533 2,305 % undeveloped 75% 32% 77% 54% 70% 17 41,757 67,556 130,102 937 579 6,471 9,626 13,701 16,225 0 20,000 40,000 60,000 80,000 100,000 120,000 140,000 2014 2015 2016 Net Acres San Joaquin Basin Ventura Basin Sacramento Basin Note: Los Angeles Basin has no net undeveloped acreage lease expirations through 2016. |
Substantial Opportunity and Resource Rich Asset Base Total California 2013 Reserves Net Proved Reserves (MMBoe) 744 % Liquids – Net Proved 81% Pre-Tax Proved PV-10 ($ millions)1 $14,018 Net 3P Reserves MMBoe 1,098 % Liquids – Net 3P 83% Pre-Tax 3P PV-10 ($ millions) $20,995 YTD Q3’14 Avg. Net Production (MBoe/d) 157 % Oil 62% Net Acreage (‘000 acres) 2,296 Identified Gross Locations 17,691 Additional Potential Locations 6,400 Sacramento Basin San Joaquin Basin Ventura Basin Los Angeles Basin 18 Note: Reserves as of 12/31/13. 1 PV-10 shown as of 12/31/13 based on SEC five-year rule applied to PUDs using SEC price deck of WTI at $97.97/Bbl and $3.66/Mcf. 2 Basin-level PV-10s include $180MM associated with fuel gas, which is excluded from PV-10 of $14,018MM disclosed in Form 10 filing. 3 Refer to Endnote reference 3 in the Appendix for further information. San Joaquin Basin Los Angeles Basin Ventura Basin Sacramento Basin Net Proved Reserves (MMBoe) 511 159 55 19 % Liquids – Net Proved 78% 98% 89% 0% Pre-Tax Proved PV-10 ($ million) 2 $10,130 $2,331 $1,631 $106 Net 3P Reserves MMBoe 3 744 235 96 22 % Liquids – Net 3P 3 79% 98% 89% 1% Pre-Tax 3P PV-10 ($ millions) 3 $14,983 $3,343 $2,556 $113 YTD Q3’14 Avg. Net Production (MBoe/d) 111 28 9 9 % Oil 57% 100% 67% 0% Net Acreage (‘000 acres) 1,485 21 257 533 Identified Gross Locations 12,836 1,537 2,310 1,008 |
Conventional Waterflood Steamflood Unconventional Total Conventional Waterflood Steamflood Unconventional 50%+ per pattern 50%+ per pattern 80%-100%+ per well 30%-50% per well Single Well/Pattern Economics by Drive Mechanism: Before Tax IRR1 Total California 2013 Reserves Robust Returns Across Multiple Drive Mechanisms 19 Net Proved Reserves (MMBoe) 112 238 178 216 744 % Liquids - Net Proved 68% 95% 100% 57% 81% Pre-Tax Proved PV-10 ($ millions) $959 $4,216 $4,917 $4,105 $14,1982 Net 3P Reserves (MMBoe)3 187 373 227 312 1,098 % Liquids - Net 3P3 77% 94% 100% 60% 83% Pre-Tax 3P PV-10 ($ millions)3 $2,719 $6,342 $5,906 $6,029 $20,995 YTD Q3’14 Avg. Net Production (MBoe/d) 33 37 30 57 157 % Oil 41% 94% 99% 34% 62% Identified Gross Locations 6,455 3,540 3,014 4,682 17,691 Additional Potential Locations - - - 6,400 6,400 Note: Reserves as of 12/31/13. PV-10 shown as of 12/31/13 using SEC price deck of WTI at $97.97/Bbl and $3.66/Mcf. 1Assumes $100/Bbl and $4.50/Mcf. 2 Drive-mechanism-level PV-10s include PV-10 of $180MM associated with fuel gas excluded from PV-10 of $14,018MM disclosed in Form 10 filing. 3 Refer to Endnote reference 4 in the Appendix for further information. |
155 1581 150 200 250 MBoe/d (Net) Oil NGLs Gas Upgrade to Current Technology to Drive High Margin Growth 20 CRC has a significant portfolio of conventional and unconventional opportunities to generate double-digit production growth over the longer-term - - 50 100 1H'14 2014 2015 2016 Longer-term 1 Based on 4Q’14 guidance for net production of 162 – 165 MBoe/d and 2014 capital budget of $2.1 billion, as disclosed in the Form 10, assuming commodity prices of $100/Bbl for crude oil and $4.50/Mcf for natural gas. |
Shale Geological Overview 0 GR 150 3,000 2,000 N A • Successful in upper Monterey using precise development approach • Expanding efforts into lower Monterey and other shales Play Depth (ft) Thickness (gross ft) Porosity (%) Permeability (mD) Total Organic Carbon (%) Upper Monterey1 3,500' – 12,000' 250' – 3,500' 5 – 30 <0.0001 – 2 1 – 12 Lower Monterey1 9,000' – 16,000' 200' – 500' 5 – 12 <0.001 – 0.05 2 – 18 Kreyenhagen1 8,000' – 16,000' 200' – 350' 5 – 15 <0.001 – 0.1 1 – 6 Moreno1 8,000' – 16,000' 200' – 300' 5 – 10 <0.001 – 0.1 2 – 6 Bakken 3,000' – 11,000' 6' – 145' 2 – 12 0.05 8 – 21 Barnett 5,400' – 9,500' 100' – 500' 4.0 – 9.6 <0.0001 – 0.1 4 – 8 Eagle Ford 5,000' – 12,000' 100' – 250' 3.4 – 14.6 0.13 2 – 9 21 Major U.S. Shale Plays California Unconventional Potential 0 GR 150 0 GR 150 0 GR 150 0 GR 150 0 GR 150 1,000 Kreyenhagen Productive interval Target interval Moreno Bakken Barnett Eagle Ford B C D PG CRC Current Production CRC Areas of Future Development 1Reservoir characteristics were internally generated based on regional 2D seismic data, 3D seismic data, open hole and mud log data, cores and other reservoir engineering data. |
Strong Returns Through the Commodity Cycle Oil Prices / Gas Prices • Invest in steam floods (above 5x Oil/Gas ratio) • Conventional, waterflood and unconventional oil opportunities • Gas used at the Elk Hills power plant (electricity) Oil Prices / Gas Prices • Gas price is a cost for steam floods. Invest in steam floods above 5x Oil/Gas ratio • Many projects commercial in CRC’s high-graded portfolio • Conventional and unconventional oil and gas opportunities 22 Oil Prices / Gas Prices • Invest in steam floods (above 5x Oil/Gas ratio) • Oil projects down to $25.60/barrel • Gas projects down to ~$2.10/Mcf Oil Prices / Gas Prices • Invest in steam floods (above 5x Oil/Gas ratio) • Invest in Sacramento gas projects, take advantage of dominant position in the basin • Oil projects down to $25.60/barrel |
CRC Achieves Premium Pricing and Recycle Ratio $49.66 $30.00 $40.00 $50.00 $60.00 $70.00 Cash Margins for FY 2013 ($/Boe) Recycle ratio: 2.4x 1 23 $0.00 $10.00 $20.00 A B C D CRC E F G H Source: Company 2013 SEC filings. Comparables consist of CLR, CXO, DNR, DVN, EOG, PXD, WLL and XEC. Note: Cash margin calculated as oil and gas revenue less operating expenses, general and administrative expenses and taxes other than on income. 1 Refer to Endnote reference 5 in the Appendix for detail on the calculation of cash margins and CRC’s recycle ratio. |
Captive Infrastructure Integral to Operations Gas Processing Transport • The Elk Hills 200 MMScf/d Cryogenic gas plant is part of the largest gas processing complex in California, with a combined capacity of 540 MMScf/d • CRC also owns and operates a system of gas processing facilities in the Ventura Basin that is capable of processing equity wellhead gas from the surrounding areas • The gas processing facilities are interconnected via pipelines to nearby third-party rail and trucking facilities, with access to certain North American NGL markets > CRC has truck loading facilities coupled with a battery of pressurized storage tanks at its Elk Hills gas processing facility for NGL sales to third parties • CRC sources all of its electricity needs for its Elk Hills operations, which run at 24 Electricity Gathering Pipelines about 120 megawatts, through the wholly-owned 550 megawatt combined-cycle power plant located adjacent to its Elk Hills processing facilities, and sells the excess to the state’s power grid • Within the Long Beach operations, CRC operates a 45 megawatt power generating facility that provides almost 40% of the Long Beach operation's electricity requirements, reducing operating costs • CRC owns an extensive network of over 20,000 miles of oil and gas gathering lines • Virtually all of CRCs natural gas production in California is connected via these facilities, which interconnect with the major third-party natural gas pipeline systems |
Proven Track Record in Sensitive Environments • Operator of choice in coastal environments • Proven coexistence with sensitive environmental receptors • Excellence in safety and mechanical integrity 25 |
Reversing California’s “Energy Trade Deficit” California imports ~885 MBoe/d via marine tankers and railcars • The source country or state reaps all the benefits • California communities bear the transportation risk • CRC already produces about 188,000 gross Boe/d CRC’s local production retains the value in California: • Employment 26 • Business activity • Technology development • Revenue from mineral interests • State and local taxes CRC’s natural gas supply is important to dependable California electric power |
CRC’s Strong, Highly Experienced Management Team Name Position Prior Experience Todd Stevens President and Chief Executive Officer VP Corporate Development OXY; VP California Operations OXY Bill Albrecht Executive Chairman President OXY O&G Americas; President OXY Oil and Gas USA; VP California Operations OXY Mark Smith Senior EVP - Chief Financial Officer Senior VP and CFO Ultra Petroleum; VP Upstream Business Development Constellation Energy Robert Barnes EVP - Northern Operations President and General Manager Elk Hills; General Manger Argentina; VP Operations Permian Shawn Kerns EVP - Corporate Development President and General Manager Vintage; President and General Manager Elk Hills Frank Komin EVP - Southern Operations President and General Manager Long Beach and LA Basin 27 Roy Pineci EVP - Finance VP and Controller; Senior VP of Finance OXY Michael Preston EVP - General Counsel VP and General Counsel of OXY Oil & Gas Darren Williams EVP - Exploration Africa Exploration Manager Marathon Oil; President, Marathon Upstream Gabon Limited Charlie Weiss EVP - Public Affairs VP Health, Environment, and Safety OXY; VP and General Counsel OXY Inc. Scott Espenshade VP - Investor Relations VP Investor Relations BHP Billiton; Director Corporate Development and Investor Relations Swift Energy • Investing in a highly experienced management team with a strong track record • Management team and technical staff have previous experience at OXY / CRC, and prior focus on California operations |
The CRC Opportunity World Class Resource Base Portfolio of Lower-Risk, High-Growth Opportunities Management Expertise 28 California Heritage Shareholder Value Focus |
California Resources Corporation 29 California Growth Potential |
Brief History of California Development • Oil has been an important part of California economy for over a century and remains so today • Large basins, vast deposits of rich source rock • 1876: First commercial production at Pico Canyon • 1900s: World class fields found in LA Basin, Ventura and Kern County • 1930s – 1960s: Exploration by Majors ending • 1960s – 1970s: Steamflooding technique in shallow zones • Mid 1980s: Majors leaving California as oil price collapses 30 • Shift in production to mostly shallow steam • 1990s: Broader use of 3D seismic • Recent: New completion technology, broader use of drilling techniques to target new unrecovered areas • Active in California since 1950s • Major step up with Elk Hills • Built a leading position; re-development, acquisitions, exploration • Applying new technology to recover resources from these great fields |
The Advancement of Oil Field Technology in California Majors In California Focus on Shallow Steam Fields left undeveloped CRC Growth Hand-drawn maps Cable Drilling Electric Logs Onshore Horizontal Geosteering Rig Drilling Dynamic Electric Logs Image Logs Computer-Aided 3D Geomodeling IOR / EOR Technologies Majors Pull Out of CA • Implementation • Improving deep drilling efficiency • Cost per well reductions 30%1 • High success rates in targets • Identification • Proprietary seismic interpretations 31 1930 1940 1950 1960 1970 1980 1990 1910 1920 2000 2010 2020 Open Hole Completions 3D Seismic and Microseismic Offshore Horizontal 2D Seismic Cased Hole Completions Frac and Acid Completions Advanced Technology Improves Old Fields • Improving understanding of rock physics and pay zone identification • Testing stimulation methods and response predictions • Basic industry techniques so far • Learning from other shale areas 1 Cost / well reductions for deeper unconventional drilling has decreased 30% since 2012. |
Production in All Four Basins • 130 Fields throughout California • Deep California knowledge • Both conventional and unconventional • Growing conventional plays • Field redevelopments of known resource • Increasing recoveries across mechanism types Production by Major Basin (YTD Q3’14) Ventura 5% Los Angeles 18% Sacramento 6% San Joaquin 71% 32 • Building unconventional success • Leveraging lessons learned • Accelerating timing to new field areas • Largest acreage position in California • 2.3 million net acres held; 60% in fee • Applying our experience in new plays Basin #Fields Orig in Place (Bn Boe) Current RF% San Joaquin 42 25 15% Los Angeles 10 10 33% Ventura 25 3.5 12% Sacramento 53 1.5 68% CRC Total 130 40 22% |
Reservoir Types • California basins have significant resource potential in stacked conventional and unconventional reservoirs • Conventional reservoirs: • Reservoirs that are capable of natural flow and will produce economic volumes of oil and gas without special recovery techniques • Reservoirs: Sands and shales with good porosity, permeability and/or fracture development • Development: Densely spaced vertical wells • Unconventional reservoirs: • Heavy oil trend • Conventional production • Excellent reservoir properties • High well productivity • Stacked sands, individual LOWER MONTEREY TEMBLOR UPPER MONTEREY ETCHEGOIN 500’ • 500 – 3,500’ thick • Stacked pay • Good reservoir quality • Productive at Elk Hills, Buena Vista and North Shafter • 250-500’ thick source rock • TOC 1-12% 33 • Reservoirs that cannot be produced at economic flow rates or that do not produce economic volumes of oil and gas without assistance from stimulation treatments or special recovery processes and technologies • Reservoirs: Sands and shales with low porosity, permeability and fractures • Technologies: Hydraulic fracturing and acid treatment • Development: Mostly vertical and horizontal wells Conventional Reservoirs Unconventional Reservoirs • 500 – 1,000’ thick source rock • TOC 2-18% • Productive in Kettleman North and Middle Dome reservoirs 100-500’+ • Productive at Elk Hills, Kettleman North Dome • 200 – 500’ thick source rock • TOC 1 – 6% KREYENHAGEN MORENO LODO • 200-500’ thick sands • Good reservoir quality Source: Information based on internal observed data and external published reports. |
Creating a Recovery Value Chain • Conventional fields in various stages of development • Base assets in place – advancing recovery with traditional means • Moving recoveries from primary through EOR • Primary (93 fields) • Production with natural energy of reservoir or gravity drainage • Waterflood (17 fields) 30 40 50 60 70 80 Recovery of Orig in Place; RF% Typical Recoveries by Mechanism Type 34 • Incremental recovery beyond primary with pressure support and displacement • Steam / EOR (12 fields) • Enhanced recovery from reservoirs using techniques such as steam, CO2, etc. 0 10 20 Primary Waterflood Steam Approximate current CRC RF% Development program is based on reservoir characteristics, reserves potential, and expected returns |
Conventional – Primary Projects • 90+ fields with conventional opportunities • Over 8 Bn Boe original in place • Over 6,400 identified / 200 proven locations • Typical completed cost $1.5 MM/well • Depths vary 1,500’ – 15,000’ Ventura Basin LA Basin Primary Conventional Type Curve1 35 0 50 100 150 200 250 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57 59 61 Gross Boe/d IP Months Pleito T Ranch EH Shallow PC SM Torrey Sac • Range of $0.5 – $6.0 MM / well • IPs range from 20 to 225 Boe/d • EURs range from 50 to 500 MBoe/well Many conventional projects ready for future waterfloods or EOR processes Various Type Curves depending on play type Curve 1 Type curves include average production by post-completion month for all wells drilled from 2010 to 2013. |
Conventional Primary Example • Field discovered in 1950s by a major oil company • Multiple stacked producing zones 9,000 – 14,500’ • 250 MMBoe in place at 4% RF • Acquired property in 2005 • Geologic re-characterization • Recent redevelopment in progress • Gross production has increased 5-fold • Producing 2,500 Boe/d (95% oil) as of Q3’14 • 100+ potential locations CRC Acquired Major Producer Pleito Ranch Historical Production 36 Economic Sensitivity Type Curve Economics EUR (Gross) MBoe Oil Prices (WTI $ / Bbl) 380 440 570 680 795 $100 31% 38% 55% 75% 96% $90 23% 29% 42% 57% 74% $80 19% 24% 35% 47% 60% Well cost ($MM) $5.5 % Oil 100% DPI 10 2.19 Payback (years) 1.8 Net F&D ($ / Boe)1 $9.70 Red outline indicates base case for type curve economics. 1 Refer to Endnote reference 2 in the Appendix for detail on the calculation of F&D costs. DPI – Discounted Profitability Index is a ratio of the net present value of the project over capital investment, used for ranking investments in our portfolio of assets. EUR – Estimated Ultimate Recovery. |
Conventional – Waterflood Projects Waterflood Recovery Areas • 17+ fields with waterflood opportunities • Over 22 Bn Boe original in place • Over 3,500 identified / 669 proven locations • Typical completed cost $1.7 MM/well • Depths vary 2,000’ – 6,000’ • Range of $0.7 – $4.2 MM/well Ventura Basin LA Basin 37 • IPs range from 30 to 130 Boe/d • EURs from 50 to 200 MBoe/well A Waterflood Type Curve1 Many waterflood fields are suited for future EOR processes 0 20 40 60 80 100 -6 0 6 12 18 24 2012 2013 2014 Type Curve Average Curve Months Injection BOPD 1 Type curve represents example of Mt. Poso Program from 2012 to 2014 and includes average production by post-completion month for all wells drilled. The graph illustrates injection to production response. |
Conventional Waterflood Example • Field discovered in 1920s by a major oil company • Multiple stacked zones 1,200’ – 2,000’ • 150 MMBoe in place at 6% RF • Acquired property in 2009 • Geologic re-characterization • Analog field experience • Gross production has nearly tripled • Producing 2,700 Boe/d (100% oil) as of Q3’14 • 200+ potential locations CRC Acquired Ownership by Other Companies Mount Poso 38 ROR Sensitivity Type Curve Economics WF EUR (Gross) MBoe Oil Prices (WTI $ / Bbl) risk 43 65 87 109 131 $100 102% 169% 238% 311% 388% $90 89% 147% 208% 272% 337% $80 75% 125% 178% 233% 289% Average Pattern cost ($MM) $0.6 % Oil 100% DPI 10 4.85 Payback (years) 0.9 Net F&D ($ / Boe)1 $9.18 Red outline indicates base case for type curve economic. 1 Refer to Endnote reference 2 in the Appendix for detail on the calculation of F&D costs. DPI – Discounted Profitability Index is a ratio of the net present value of the project over capital investment, used for ranking investments in our portfolio of assets. EUR – Estimated Ultimate Recovery. |
Conventional – Steamflood Projects Steamflood Recovery Areas • 12+ fields with steamflood opportunities • Nearly 2 Bn Boe original in place • Low risk projects with proven technology • Over 3,000 identified / 994 proven locations • Typical completed cost $0.4 MM/well • Depths down to 3,000’ • Range of $0.2 – $0.8 MM/well Oxnard Field – Ventura 39 • IPs range from 8 to 20 Boe/d • EURs can vary significantly depending on stage of steamflood Example of Steamflood Programs – Kern Front1 Field 2013 Q3 (Net Boe/d) 2014 Q3 (Net Boe/d) YoY% Growth Kern Front 8,250 12,000 45% Lost Hills 3,710 6,100 64% Other 4,900 5,000 2% Total 16,860 23,100 37% 1 Type curves represent example of Kern Front Program from 2008 to 2014 and includes average production by post-completion month of all wells drilled. |
40,000 50,000 60,000 70,000 80,000 90,000 100,000 110,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 Jan- 13 Feb- 13 Mar- 13 Apr- 13 May- 13 Jun- 13 Jul- 13 Aug- 13 Sep- 13 Oct-13 Nov- 13 Dec- 13 Jan- 14 Feb- 14 Mar- 14 Apr- 14 May- 14 Jun- 14 Jul- 14 Aug- 14 Sep- 14 Oct-14 Nov- 14 Dec- 14 BSPD Net BOPD Year to Year Performance Net Oil (bopd) Steam (bspd) 2013 2014 9,000 bopd 68,000 bspd 12,000 bopd 100,000 bspd Conventional Steamflood Example • Eastern San Joaquin Valley Steamflood • Two major intervals 1,500’ – 2,500’ • 500 MMBoe in place at 35% RF • Field extension • Geologic re-characterization • Facilities expansion in 2013 • Production growing at 45% / annum in 2014 to date • Producing 12,000 Boe/d as of Q3’14 • 740 potential locations (~110 patterns) Year to Year Performance 40 Oct Oct EUR (Gross) MBoe Oil Prices (WTI $ / Bbl) 165 187 205 228 250 $100 44% 53% 62% 71% 80% $90 35% 44% 52% 60% 68% $80 26% 34% 42% 49% 56% 9 Spot Inv Pattern cost ($MM) $1.8 % Oil 100% DPI 10 2.4 Payback (years) 3 Net F&D ($ / Boe)1 $10.50 ROR Sensitivity Type Curve Economics DPI – Discounted Profitability Index is a ratio of the net present value of the project over capital investment, used for ranking investments in our portfolio of assets. EUR – Estimated Ultimate Recovery. Red outline indicates base case for type curve economics. 1 Refer to Endnote reference 2 in the Appendix for detail on the calculation of F&D costs. |
California Unconventional Projects • Unconventional reservoirs have produced in California for many years • California shale expertise • Steady, commercial growth • Over 50,000 Boe/d from upper Monterey • Confidence in our processes 41 • Deepening our play experience • Many within existing core fields • Moving to new areas around San Joaquin basin • Historically focused in core field with existing operations CRC Fee/Lease |
Unconventional – Primary Project Unconventional Recovery Areas • Leading unconventional position in California • Over 9 Bn Boe in place • Unconventional targets in over 70 fields • Locations • 4,600+ identified / 278 proven locations • Typical completed cost $3 MM/well • Depths vary 2,500’ – 12,000’ • Range of $2 – $4.5 MM/well 42 0 100 200 300 400 500 600 1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52 55 58 61 Gross BOEPD Months Rose EH Deep ASP RRG BV EH Stv BVH • IPs range from 80 to 500 Boe/d • EUR range 75 – 400 MBoe • Over 1 million additional prospective acres • Lease expirations minimal • Lease costs low Unconventional Type Curves1 Programs ongoing across 8 unique fields Various Type Curves depending on play type 1 Type curves include average production by post-completion month for all wells drilled from 2010 to 2013. |
Unconventional Example • Discovered in 1950s by a major oil company • Multiple stacked producing zones 4,000’ – 7,500’ • 3 Bn Boe original in place at 2% oil RF • Consolidation of field ownership since 2009 • Geologic re-characterization • Analog experience from Elk Hills • Recent redevelopment in progress • Production has already doubled since acquisition • Producing 3,800 Boe/d net as of Q3’14 0 50 100 150 200 250 300 0 1000 2000 3000 4000 5000 6000 7000 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 # Wells BOPD BOPD # Wells Other Owner Other Owner CRC Acquired 100%WI Buena Vista Historical Net Production 43 Economic Sensitivity EUR (Gross) MBoe Oil Prices (WTI $ / Bbl) 268 303 338 373 408 $100 13% 18% 22% 26% 30% $90 11% 15% 19% 23% 27% $80 10% 13% 17% 21% 24% Well cost ($MM) $3.0 % Liquids 33% DPI 10 1.3 Payback (years) 4.4 Net F&D ($ / Boe)1 $9.10 Red outline indicates base case for type curve economics. 1 Refer to Endnote reference 2 in the Appendix for detail on the calculation of F&D costs. DPI – Discounted Profitability Index is a ratio of the net present value of the project over capital investment, used for ranking investments in our portfolio of assets. EUR – Estimated Ultimate Recovery. • 250 potential locations Type Curve Economics |
Large in Place Volumes with Significant Upside Recovery Factors for Discovered Fields¹ 25 30 35 40 45 Billion Boe • Leading asset position to exploit • In place volumes of ~40 Bn Boe at low recovery factor (22%) to date • Conventional “value chain” approach to life of field development • Unconventional success with great 44 9 40 0 5 10 15 20 Cum Recovered to Date Remaining 3P + Contingent RF + 10% RF + 15% RF + 20% Original in Place 1 Does not include undiscovered unconventional resource potential. upside positioning • Untapped opportunities to apply technology advances to California • Good return projects that can withstand alternative price environments |
California Resources Corporation 45 Asset Overview Northern Operations |
Sacramento Basin • Exploration started in 1918 and focused on seeps and topographic highs. In the 1970s the use of multifold 2D seismic led to largest discoveries • Cretaceous Starkey, Winters, Forbes, Kione, and the Eocene Domengine sands • Most current production is less than 10,000 feet • 3D seismic surveys in mid 1990s helped define trapping mechanisms and reservoir geometries Overview Basin Map 46 • CRC has 53 active fields (consolidated into 35 operating areas where we have facilities) • YTD Q3’14 average net production of 9 MBoe/d (100% dry gas) • Produce 85% of basin gas with synergies of scale • Price and volume opportunity Key Assets |
San Joaquin Basin • CRC has 53 active fields (consolidated into 35 operating areas where we have facilities) • Oil and gas discovered in the late 1800s • Currently accounts for ~70% of CRC production • 25 billion barrels OOIP in CRC fields • Cretaceous to Pleistocene sedimentary section (>25,000 feet) • Source rocks are organic rich shales from Overview Basin Map Kettleman Lost Hills Mt Poso 47 Moreno, Kreyenhagen, Tumey, and Monterey Formations • Thermal techniques applied since 1960s • YTD Q3’14 avg. of 111 MBoe/d (57% oil) • Elk Hills is the flagship asset (~57% of CRC San Joaquin production) • Two core steamfloods - Kern Front and Lost Hills • Early stage waterfloods at Buena Vista and Mount Poso Key Assets -Legend- Oxy Land Oil Fields Gas Fields Buena Vista Pleito Ranch Elk Hills CRC Land Kern Front |
Patterns are the Fundamental Building Blocks Injection Production well 2011 2013 2012 Steamfloods: Pattern Developments over Multiple Years 48 well Displacement Project • Common start-date • Contiguous patterns Field Development • Several projects • Multi-year drilling 5-spot Pattern • Typical 5 acres |
Ramp-up Mature Peak Thermal Process: Pattern Life Cycle 49 Stable oil decline Injection reduction Facilities established Maximize injection 6 months – 2+ yrs Steam Injection Rate Maximum oil rate Steam breakthrough |
-200 -150 -100 -50 0 50 100 150 200 0 15 30 45 60 75 90 105 120 Cash Flow Capital and Operating Costs OPEX Steam Drilling Facilities Cash Flow Positive Cash Pattern Profit Delivery ($MM) ($MM) 50 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Years • Up-front investment • Strong margins • Stable/long-lived declines • Strong backside cash flow Thermal Performance Thermal Business * * * *Based on estimates. Representative example; based on CRC estimates. |
Elk Hills Field – Overview • CRC’s flagship asset, a 103-year old field with exploration opportunities1 • Large fee property with multiple stacked reservoirs • Light oil from conventional and unconventional production • Largest gas and NGL producing field in CA, one of the largest fields in the continental U.S.1, >3,000 producing wells • 7.8 billion barrels OOIP and cumulative production of 1.6 billion Boe1 • In 2013, produced 68 MBoe/d (44% of total production), including 46 MBoe/d of unconventional Overview Field Map Elk Hills Buena Vista RR Gap GS 51 0 20 40 60 80 100 120 140 1998 2000 2002 2004 2006 2008 2010 2012 2014 Net MBoe/d production from the upper Monterey Shale • 540 MMScf/d processing capacity • 2 CO2 removal plants • Over 4,200 miles of gathering lines • 3 gas plants (including California’s largest) • 45 MW cogeneration plant • 550 MW power plant Comprehensive Infrastructure Production History 1DOGGR data and U.S. Energy Information Administration. |
Elk Hills at a Glance 3,627 active wells • 3,244 producers • 383 injection/disposal wells • 89% production by beam pump Infrastructure • Consolidated control facility • 3 gas plants (CGP1, LTS1, LTS2) • 540 MMcf/d processing capacity • 131 units; 300K HP compression 52 Gross Operating Data – Q3 2014 • 36 MBbl/d oil • 21 MBoe/d NGL • 192 MMcf/d gas sales • 89 MBoe/d total production • 525 MBbl/d water Consolidated Control Facility • 3 major fluid processing facilities • Produced water treatment and injection • 45 MW cogeneration plant • 550 MW Elk Hills Power Plant • 2 CO2 removal plants (GTU2 and 14Z Amine) • 117 tank settings • Over 4,200 miles of gathering lines 9 drilling rigs 35 workover/well servicing rigs |
Elk Hills – Field Development Activities 72% of wellbores have been drilled after field was purchased in 1998 50% 60% 70% 80% 90% 100% 200 250 300 350 Wells Drilled CUM % of Total Wells 53 0% 10% 20% 30% 40% 0 50 100 150 1919 1923 1933 1943 1947 1951 1955 1961 1965 1969 1974 1978 1982 1986 1990 1994 1998 2002 2006 2010 2014 |
Elk Hills Field – Stacked Pay Zones 987-25R 1978 Carneros Zone 1941 Stevens Zone 1941 Shallow Oil Zone 1919 Dry Gas Zone 1910 2512’ TD 6700’ TD Age PLEISTOCENE PLIOCENE MIOCENE Producing Formations Tulare Dry Gas Zone Shallow Oil Zone Antelope / Stevens 934-29R 1988 954-4G 1977 1610’ TD Deep Exploratory Wells Discovery Well 2009 54 EOCENE CRETACEOUS Carneros Basement Point of Rocks Oceanic Santos / Wygal OLIGOCENE 12,850’ TD 18,270’ TD 18,761’ TD 24,426 TD 11,460’ TD TD denotes total depth. |
Elk Hills Field – Identified Projects Monterey and Carneros Formations Shallow Oil Zone 55 Primary 29R Waterflood 31S Waterflood Gas Injection Mid Flank Water Injection Crestal Waterflood Expansion Tianshan Area Goliath Area Lower Carneros Waterflood Waterflood Steamflood Submulinia Steamflood Light Oil Steamflood Alkaline Surfactant Polymer Flood CO2 Flood - 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 90.0 100.0 2009 2010 2011 2012 2013 2014E MBoe/d Shale Waterf lood/Gas injection Primary/Conventional Net Production C4D Shale Asphalto, Railroad Gap, & N. Midway-Sunset Opal CT Compression Expansion |
56 Prior Kr Wells 2014 Kr Well Rio Lobo seismic survey KNDU Field Boundary Kettleman North Dome – “Elk Hills Analog” Kreyenhagen Estimates Area (acres) 12,800 Depth (ft) 9,500 OOIP (MMBbl) 800 Cum. Prod (MMBbl) 0.36 Recovery Factor 0.05% # of Completions to Date 9 • OOIP of 3 Bn Bbls • 1,000’s of feet of stacked pay • API >= 36° • WI = 100% and NRI = 80.3% • Shooting 3D in preparation of development • Modern formation evaluation, new wells, and WOs • Advancing the understanding and development potential • Temblor waterflood • Moreno • Vaqueros • Kreyenhagen shale Source: Information based on CRC internal estimates and DOGGR. |
California Resources Corporation 57 Asset Overview Southern Operations |
Ventura Basin • Estimated ~3.5 billion barrels OOIP in CRC fields1 • Operate 25 fields (about 40% of basin) • 257,500 net acres • Multiple source rocks: Miocene (Monterey and Rincon Formations), Eocene (Anita and Cozy Dell Formations) • YTD Q3’14 average net production of 9 Overview Key Assets Basin Map San Miguelito Saticoy South Shiells Canyon Rincon Ventura 58 MBoe/d • In 2013, shot 10 mi2 of 3D Seismic > First 3D seismic acquired by any company in the basin • CRC has four early stage waterfloods • Ventura Avenue Field analog has >30% RF • CRC fields have 3.5 Bn Boe in place at 14% RF Waterflood Potential2 Oxnard Mountain CRC Waterflood Fields Aera Waterflood CRC Primary Production Fields 1 Information based on CRC internal estimates. 2 Source: USGS. |
Los Angeles Basin • Large, world class basin with thick deposits • Kitchen is the entire basin, hydrocarbons did not migrate laterally; basin depth (>30,000 ft) • 10 billion barrels OOIP in CRC fields • Most significant discoveries date to the 1920s – past exploration focused on seeps & surface expressions • Very few deep wells (> 10,000 ft) ever drilled • Focus on urban, mature waterfloods, with generally Overview Basin Map 59 low technical risk and proven repeatable technology across huge OOIP fields • YTD Q3’14 avg. net production of 28 MBoe/d • Over 20,000 net acres • Active coastal development program underway – seven rigs and 143 wells drilled year to date • Major properties are world class coastal developments of Wilmington and Huntington Beach Key Assets |
Wilmington Field – Overview Overview Field Map • CRC’s flagship coastal asset: acquired in 2000 • Field discovered in 1932; 3rd largest field in the U.S. • Over 7 billion barrels OOIP (34% recovered to date)1 • Depths 2,000’ – 10,000’ (TVDSS) • Q3’14 avg. production of 36.8 MBoe/d (gross) • Over 8,000 wells drilled to date • PSC (Working Interest and NRI vary by contract) • CRC partnering with State and City of Long Beach 60 - 50 100 150 200 250 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 MMBoe Net Proved Reserves Production to Date Proved Reserves & Cumulative Production Structure Map & Acquisition History * *Proved reserves prior to 2009 represent previously effective SEC methodology. Proved reserves for 2009 – 2013 are based on current SEC reserve methodology and SEC pricing. Tidelands Acquired: 2006 Belmont Offshore Acquired: 2003 Long Beach Unit Acquired: 2000 Pico Properties Acquired: 2008 |
Wilmington Field – Geology Stratigraphic Column Bathymetric Contours Submarine Canyon Levee Upper Fan (overbank) Shelf Slope 0 10 Kilometers Upper Fan Middle Fan Lower Fan Shallow Gas reservoirs Upper Fan Middle Fan Middle Fan Lower Fan Ranger reservoirs Terminal reservoirs 61 Beaubouef et al, 1999 San Clemente, CA 237 Zone reservoirs Deep marine Siliclastics UP-Ford reservoirs |
Wilmington Field – Geosteering Technology 62 Well complexity • State of the art, proprietary directional drilling technology • Over 8,000 wellbores since 1930s • Small surface footprint, reach far out into reservoirs • Well placement critical to maximizing value |
Wilmington Field – Production Sharing Contracts • Over 90% of CRC’s Long Beach production is covered under Production Sharing Contracts (PSCs) with the State and City of Long Beach • CRC’s net production decreases when prices rise and increases when prices decline • “Base” rate/profit are defined in LBU PSC - 10,000 20,000 30,000 40,000 50,000 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 Boe/d Base Incremental Base Profit Split: 4% CRC / 96% State Incremental profit split: 49% CRC / 51% State 6/30/14 63 contracts • State/City receive most of base profit • CRC receives remainder • “Incremental” rate/profit is everything greater than base Tidelands PSC - 2,000 4,000 6,000 8,000 10,000 2006 2008 2010 2012 2014 Boe/d Base Incremental Base Profit Split: 4% CRC / 96% State (average) 49% CRC / 51% State & City First of 3 new PSCs executed 6/30/14 |
Wilmington Field – Future Drilling Opportunities • Over 1,000 future drilling locations identified • 80% of 2014 wells drilled are PUD locations aimed at rate growth • Remaining P2 and P3 locations strategically located for optimal drilling 64 Boundaries LBU West Wilmington PICO Belmont Faults Production Area Drilling Pads |
Production (MBoe/d) Summary Wilmington Field – Summary • Waterflood development • Majority of production covered by Production Sharing Contracts • Infill drilling targeting unswept intervals, attic oil, and fault plays • Injectors for waterflood support and - 5 10 15 20 25 2010 2011 2012 2013 2014E Base Growth 65 surface subsidence management • Potential for additional well stimulation • Longstanding record of environmental and safety achievement |
Proven Track Record in Sensitive Environments • Operator of choice in coastal environments • Proven coexistence with sensitive environmental receptors • Excellence in mechanical integrity is essential 66 |
Overview Production (MBoe/d) Huntington Beach Field – “Wilmington Analog” • Waterflood redevelopment • 2.25 Bn Boe OOIP • Oil gravity: 13-30 API; Depths 1,800’ – 4,800’ (TVDSS) • We acquired in 2011, followed by adjacent acquisition in 2013 • Initiated first significant development drilling program in over 25 years - 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 2010 2011 2012 2013 2014E Base Growth 67 Circa 1930s Current |
California Resources Corporation 68 Exploration Overview |
0 5 10 15 20 25 30 35 40 0.0 1.0 2.0 3.0 4.0 1860 1870 1880 1890 1900 1910 1920 1930 1940 1950 1960 1970 1980 1990 2000 2010 Annual Discoveries Bn Boe Cum. Discoveries Bn Boe Exploration History of California • Multiple 1 Bn Boe+ discoveries from 1880s to 1940s based upon surface information • Established California as a world class hydrocarbon province • Little exploration or discoveries since 1970s California Exploration History Drill Oil and Gas Seeps Drill Surface Features 2D Seismic Small Discoveries Since mid 1970s • Little exploration activity • Few discoveries Why? • Super major focus? • Shift to EOR? • Limited potential? • Too little exploration? 69 Discovery Year • Industry focused on development and EOR • Late 2000s CRC reestablished focused exploration program • Portfolio of high-graded exploration opportunities delivering renewed success 35 35 36 36 37 37 0 50 100 150 200 250 1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010 Annual Discoveries MMBoe Discovery Year Cum. Discoveries Bn Boe CRC Renewed California Exploration Success CRC Discoveries Source : California Division of Oil, Gas & Geothermal Resources. • Re-setting expectations • Encouraging recent exploration success |
Exploration Program Sacramento Basin Dry gas & shale San Joaquin Basin Heavy oil, light oil, dry gas & shale • Prioritized and balanced portfolio approach: • High-return, lower-risk near field exploration program in proven play trends • Impact exploration program in highgraded shale plays for longer-term growth 70 Ventura Basin Heavy oil, light oil, dry gas & shale LA Basin Heavy oil, light oil & shale • Maximize competitive advantage leveraging extensive land position, and proprietary knowledge, data, technology and expertise • Diverse, multi-basin portfolio provides optionality in different price environments |
Successful Exploration Program Driving Growth Chance of Encountering Hydrocarbons • Activity: 118 wells • Investment: $682 MM • Discovered 3P Reserves: 187 MMBoe • Finding cost: $3.65 / Boe • 2014 production: ~18,000 Boe/d • Key discoveries: Gunslinger, Buena Vista and Pleito Ranch extensions 2007 – 2013 Performance 71 Geologic Success Rate Drivers for Success • Rigorous portfolio management • Proven technical expertise and proprietary geologic models • Integration of technology • Extensive land position • Running room • Continuous lessons learned unlocking new plays and resource |
72 Successful Exploration Through Application of Technology Producing oil well No reservoir Oil reservoir No reservoir • Largest seismic data owner in California • 4,250 square miles of 3D seismic, ~90% of 3D available in state • 47% of all CRC leasehold covered • Detailed seismic analysis and integration of seismic attributes identifies hydrocarbon accumulations • Proprietary geologic models integrating well, seismic, outcrop and analog data to identify accumulations missed by previous operators -Legend- CRC 3D SURVEYS CRC Land Oil Fields Gas Fields |
San Joaquin Conventional San Joaquin Unconventional Sacramento Basin Conventional Ventura Basin Conventional Exploration Portfolio San Joaquin Conventional San Joaquin Unconventional Sacramento Basin Conventional Ventura Basin Conventional 1.5 Bn Boe Net Unrisked Resource 5,117 Net Drilling Locations Near Field Exploration in Proven Play Trends 73 Prospective Shale Plays Lower Monterey Kreyenhagen Moreno 2.0 Bn Boe Net Unrisked Prospective Resources Lower Monterey Kreyenhagen Moreno 5,300 Net Drilling Locations |
San Joaquin Basin Exploration • Cenozoic age basin with >19 Bn Boe produced to date • Multiple, stacked conventional and unconventional reservoirs in structural and stratigraphic plays • Significant portfolio of near field exploration prospects in proven play trends • Additional upside in shale plays • Heavy oil trend • Elk Hills •Semitropic •Midway-Sunset •Elk Hills •Mount Poso •Kettleman North Dome •Elk Hills •Buena Vista •Rose-North Shafter Fields 74 • Extensive seismic coverage and proprietary geologic understanding Elk Hills Buena Vista Monument Junction Shale Plays Jerry Slough North Shafter /Rose Mount Poso Conventional Reservoirs Unconventional Reservoirs •Kettleman North Dome • Kettleman North Dome • Coalinga Source: Information based on CRC internal estimates. |
San Joaquin Basin: Near Field Exploration • High-return, lower-risk growth program in proven play trends • Multiple, stacked conventional and unconventional reservoirs in structural and stratigraphic traps • 100 – 500’+ individual reservoir thickness • 10 – 30% porosity • Good quality sands, tight sands, cherts and fractured shales MONTEREY CARNEROS > 5,000’ GROSS RESERVOIR POTENTIAL 75 • Exploration portfolio • ~1MM+ gross acres within exploration play trends • 125+ prospects and leads • 4,000 net drilling locations • 10 – 40 acre vertical development well spacing POINT OF ROCKS OCEANIC PHACOIDES Producing Reservoir Source: Information based on CRC internal estimates. |
San Joaquin Basin: Shale Play Exploration • Multiple organic-rich shale reservoirs in structural and basinal settings • Exploration targets in Lower Monterey, Kreyenhagen and Moreno shales • Individual shale reservoirs range in thickness from 200 to 750’+ • Depths to targets from 9,000 – 16,000’ primarily within oil fairway • TOC ranging from 1 – 18%, source rocks for LOWER MONTEREY UPPER MONTEREY 6,000’ - 4,000’ 2,500’ EXPLORATION SHALE RESERVOIR POTENTIAL 8,000’ - 4,000’ 10,000’ 76 main fields • Multiple potential target intervals in each shale reservoir • Exploration portfolio • ~650,000 acre gross play trend with stacked targets • 5,300+ net prospective drill locations • Potential 80 acre horizontal development well spacing WHEPLEY KREYENHAGEN MORENO 8,000’ Producing Shale Exploration - 4,000’ 12,000’ - 4,000’ 14,000’ Source: Information based on CRC internal estimates. |
Ventura Basin Exploration Assets • >6 Bn Boe OOIP, 2.2 Bn Boe produced to date1 • Multiple, stacked conventional reservoirs in structural play trends, deep reservoirs are underexplored • Predominantly light oil at shallow depths concentrated along major fault trends • Exploration portfolio Overview Basin Map 77 • 40+ prospects and leads • 700 net drilling locations • 10 – 40 acre vertical development well spacing • Seismic data provides competitive advantage • Acquired first 3D seismic in basin • Regional 2D Source: Tanya Atwater – UCSB 1 DOGGR data. |
Sacramento and LA Basin Exploration Sacramento Basin Overview Basin Map • Dry gas basin with multiple, stacked conventional reservoirs in proven play trends • Deep reservoirs are underexplored with only 4% of wells in the basin drilled deeper than 10,000’ • Cretaceous age source rock, potential unconventional shale target • Extensive seismic data control 78 LA Basin Overview • Highly prospective, world class hydrocarbon basin • > 25 Bn Boe OOIP, 8.7 Bn Boe produced to date1 • Multiple, stacked conventional reservoirs in proven play trends • Deep reservoirs within existing fields are underexplored; very few wells drilled deeper than 10,000’ Basin Map 1 DOGGR data. |
Exploration Summary Sacramento Basin Dry gas & shale San Joaquin Basin Heavy oil, light oil, dry gas & shale • Outstanding exploration portfolio in underexplored, world class hydrocarbon province • Proven track record of exploration success • Balanced portfolio approach 79 Ventura Basin Heavy oil, light oil, dry gas & shale LA Basin Heavy oil, light oil & shale • Significant competitive advantage • Optionality in different pricing environments |
California Resources Corporation 80 Regulatory and Community Involvement |
CRC’s Regulatory Program • Demonstrate CRC’s strong commitment to safety and environmental responsibility • Proactively engage in transparent and constructive dialogue with communities and regulators • Serve as an active community partner to build mutually beneficial relationships 81 • Senior CRC leaders and dedicated teams collaborate with regulatory agencies and community organizations |
Safeguarding People and the Environment Safety Performance • California operations achieved record safety performance in 2013 using a key OSHA metric1, with continuing improvement through Q3 2014 • The Elk Hills Field received the National Safety Achievement Award from the National Safety Council in September 2014 Environmental Performance • Net supplier of water to agriculture, due to 82 1 The employees and contractors of CRC’s operations had a combined OSHA Injury and Illness Incidence Rate of 0.54 in 2013. CRC’s recycling of produced water and reduced fresh water use • Leader in habitat preservation, managing over 8,000 acres of certified conservation lands • Open communication with agencies and neighbors to address issues cooperatively |
Delivering Economic Benefits to California Stakeholders Direct economic contributions • $2.6 billion spent on 2,000 vendors for California operations in 2013 Revenues to California governments of ~$600 MM • $300 MM generated by CRC for the State Lands Commission 83 • ~$300 MM in California state, local and payroll taxes and fees |
Experienced in California’s Permitting Process CRC participates actively with federal, state and local agencies that oversee our operations through: • Education and advocacy • Coalition building • Regulatory development 84 • Community input • Permitting • Compliance assurance |
CRC’s Unique Regulatory Flexibility Long and distinguished regulatory track record Leading acreage position and diversity of opportunities • Core operations in longstanding oil & gas fields • Primary production, IOR and EOR • All grades of oil, NGLs and natural gas • Government-operated fields and private land • Coastal / inland and urban / rural 85 Extensive network of production assets, gas plants, pipelines and utilities • Reliable supplier of in-state energy resources (62% of oil and 90% of natural gas in California is imported) • Net supplier of water to agriculture |
California Resources Corporation 86 Financial Overview |
Marketing – Oil California Refining Capacity •San Francisco = 0.8 MM BPD •Bakersfield = 0.1MM BPD •Los Angeles = 1.1 MM BPD Source: IIR • Oil prices strongly linked to international price benchmarks due to reliance on imports • California refineries source ~50% of crude supplies from non-US imports, 38% of crude supplies from California production and the rest from Alaska • In August 2014, California refinery imports (885 MBbl/d) were from • Saudi Arabia (225 MBbl/d) • Colombia (41 MBbl/d) • Ecuador (252 MBbl/d) • Iraq (171 MBbl/d) 87 Chevron Pipe Line Shell Pipeline Plains All American Pipeline Crimson Pipeline • Canada (34 Mbbl/d) • All others (163 MBbl/d) • Continue to expect Brent-linked prices for the foreseeable future • Transport capacity for crude from other U.S. basins is limited • Despite new crude rail offload facilities planned for California, the state is expected to remain net short of domestic crude • Will continue to support a premium to WTI index |
CVO 260 P66 120 TSO 165 VLO 170 Shell 165 SF Bay Area Refineries Kern 25 SJR 15 SJ Valley Refineries • California is heavily reliant on imported sources of energy • 62% of oil consumed during 2013 was imported from outside the state, mostly from foreign locations • CRC sells almost all of its crude oil into the California refining Marketing – Oil 88 CVX 290 TSO 265 TSO 100 P66 140 VLO 135 XOM 155 LA Area Refineries 55M 10M 40M San Pablo 180 KLM 90 Unocap 120 N-bound Pipelines Line 63/2000 130 XOM 100 S-bound Pipelines Crimson 50 Ventura LA Pipelines CRC crude markets, which are among the most favorable in the U.S. • CRC generally does not transport, refine or process the crude oil it produces and does not have any long-term crude oil transportation arrangements in place Volumes are Mbod |
Marketing – Gas 30/d 35/d CRC PG&E Utility 3rd Parties California Gas Delivery Overview • California consumes 6.7 Bcf/d of natural gas (11 Bcf/d peak Winter) • California produces 0.65 Bcf/d • Remaining supply comes from the Permian, San Juan, Canada and Rockies • Because California imports ~90% of the natural gas consumed in the state, CRC does not have any significant interstate natural gas transportation commitments • Higher shale production in the Midwest and East has resulted in lower NYMEX prices and higher California basis prices • SoCal Border basis is ~+$0.15 / MMBtu, PG&E Citygate basis is ~$0.45 / MMBtu 89 PG&E Volumes are MMcfd Fuel for CRC Thermal 180/d (55/d) 15/d 2/d Kern River/ Mojave CRC CRC EHP SoCalGas Utility CRC Long Beach Utility • California basis is among the strongest in the U.S. • Low storage inventories in California are expected to support shortterm basis • Increasing Mexican exports are expected to reduce the available capacity from the Permian and add upward pressure on SoCal basis • CRC has intrastate transportation capacity where necessary to access markets • Contracts are required to facilitate deliveries • CRC sells virtually all of its natural gas production under individually negotiated contracts using market-based pricing on a monthly or shorter basis |
Marketing – NGLs Rail SF Bay Area • Largest NGL producer in CA at ~20,000 Boe/d • CRC processes substantially all of its NGLs through its processing plants, which facilitate access to third-party delivery points near the Elk Hills field • ~80% of the propane is sold to Mexican distribution companies (OPIS Mont Belvieu index). Remaining volumes sold to local San Joaquin Valley market at local posting price • Normal and iso-butane sold to LA and San Francisco markets on a WTI basis. Balance is sold to local crude 90 LTS CGP1 Truck Rail Crestwood Rogas Crestwood/ Inergy Plains Shafter Truck LA Calexico Propane Tijuana Butane Butane Nat Gasoline Canada blenders in the San Joaquin Valley • Value as % of crude: • Propane – 40% • Butane – 55% • Natural gasoline – 75% • CRC does not have long-term or long-haul interstate NGL transportation agreements |
Financial Strength Provides Flexibility to Drive Growth • Capital program: Invest within cash flow • Growth strategy based on re-investment in opportunity rich portfolio of projects and disciplined allocation of capital • Maintain strong liquidity profile • Target debt / EBITDAX of 2.2x or less • Funds from operations / debt: 30% - 40% • Selective commodity hedging to support capital Capitalization as of 10/1/14 ($MM) $2.0Bn Senior Unsecured RCF1 $65 Senior Unsecured Term Loan 1,000 Senior Unsecured Notes 5,000 Total Debt $6,065 Equity 4,869 Total Capitalization $10,934 Credit Statistics: Total Debt / Capitalization 55% Total Debt / LTM EBITDAX 2.2x Asset Coverage: 91 program or M&A • Opportunistic M&A to increase asset base where attractive • Corporate family and senior unsecured credit ratings of Ba1 and BB+ from Moody’s and S&P, respectively PV-102 / Total Debt 2.3x Total Debt / Proved Reserves ($/Boe) $8.15 Total Debt / PD Reserves ($/Boe) $11.80 1 CRC expects to borrow an additional $300 – 350 million, including (i) $200 million to repay a short-term loan from OXY used to fund the acquisition of oil and gas properties and (ii) $100 – 150 million concurrently with, or shortly after, the Spin-Off to fund working capital requirements as a stand-alone company. 2 PV-10 shown as of 12/31/13 based on SEC five-year rule applied to PUDs using SEC price deck. |
CRC ($400) $0 $400 $800 $10.00 $20.00 $30.00 $40.00 $50.00 $60.00 Significant Free Cash Flow ($ in millions) LTM 6/30/14 Free Cash Flow (1) • Positive free cash flow gives opportunity to accelerate growth without impairing credit metrics • Cash margin on par with or exceeds peer group 92 ($1,200) ($800) Note: Market data as of 10/1/14 and SEC filings. Comparables consist of CLR, CXO, DNR, DVN, EOG, PXD, WLL and XEC. (1) Refer to Endnote reference 6 in the Appendix for detail on the calculation of free cash flow. Devon Energy excludes the acquisition of GeoSouthern Energy Corp. and Whiting Petroleum Corp. excludes pending acquisition of Kodiak Oil & Gas Corp. (2) Source: 2014E analyst estimates from BMO, KLR Group, Stephens, SunTrust Robinson Humphrey, Wells Fargo Securities and Wunderlich Securities; CRC 2014E. (3) Refer to Endnote reference 5 in the Appendix for detail on the calculation of cash margins. For CRC shown as 2013A. 2014E Cash Margins ($/Boe ex-hedges)(2)(3) • Disciplined capital program provides ability to withstand commodity price volatility |
Drilling ~$1,390 ~66% Dev. Facility ~$280 ~13% Workover ~$200 ~9% Exploration ~$95 ~5% Other ~$145 ~7% Self-Funded Capital Investment Program Commentary 2014 Total Capital Budget • 2014 capital budget of $2.1 billion is an increase of 24% from 2013 • CRC plans to reinvest excess free cash flow that prior to spin was sent to Occidental 1 93 2014 Drilling Capital Budget – By Basin 2014 Capital Budget – By Drive San Joaquin $942 68% Los Angeles $384 28% Ventura $56 4% Sacramento $8 1% Total: $2.1 billion Total: $1,390 million Primary $342 16% Unconventional $543 26% Waterflood $787 37% Steamflood $343 16% Exploration $95 5% 1Other includes land, seismic, infrastructure and other investments. |
Key Investment Highlights World Class Resource Base • Interests in 4 of the 12 largest fields in the lower 48 states • 744 MMBoe proved reserves • Largest producer in California on a gross operated basis with significant exploration and development potential Portfolio of Lower-Risk, High-Growth Opportunities • Oil weighted reserves • Increased exploration and development program • 30%-100%+ rates of return on Shareholder Value Focus • Internally funded capital expenditure program • Optimized capital allocation • Unlocking under-exploited resource potential utilizing modern 94 California Heritage • Strong track record of operations since 1950s • Longstanding community and state relationships • Actively involved in communities with CRC operations Management Expertise • Successful operations exclusively in California • Assembled largest privately-held land position in California • Operator of choice in sensitive environments individual projects technology |
California Resources Corporation 95 Appendix |
Historical Financials – Income Statement For the Three Months Ended September 30, For the Nine Months Ended September 30, For the Year Ended December 31, ($ in millions) 2014 2013 2014 2013 2013 2012 Revenues Oil and gas net sales to related parties $421 $1,040 $2,560 $3,027 $4,054 $3,878 Oil and gas net sales to third parties 630 20 678 63 85 89 Other revenue 41 47 115 115 145 106 Total revenue $1,092 $1,107 $3,353 $3,205 $4,284 $4,073 Costs and other deductions Production costs (262) (244) (780) (717) (927) (1,219) Selling, general and administrative expenses (87) (73) (243) (212) (293) (276) 96 Depreciation, depletion and amortization (304) (288) (886) (853) (1,144) (926) Asset impairments and related items - - - - - (41) Taxes other than on income (56) (32) (163) (141) (185) (167) Exploration expense (25) (41) (71) (81) (116) (148) Other expenses (39) (37) (109) (106) (172) (115) Total costs and other deductions (773) (715) (2,252) (2,110) (2,837) (2,892) Income before income taxes 319 392 1,101 1,095 1,447 1,181 Provision for income taxes (131) (157) (444) (438) (578) (482) Net income $188 $235 $657 $657 $869 $699 Note: March 31 and September 30, 2014 statements are unaudited. |
Historical Financials – Balance Sheet ($ in millions) September 30, 2014 December 31, 2013 December 31, 2012 Current assets Cash and cash equivalents $105 - - Trade receivables, net 441 30 22 Inventories 72 75 81 Other current assets 279 149 142 Total current assets 897 254 245 Property, plant and equipment 22,580 20,972 19,324 Accumulated depreciation, depletion and amortization (7,855) (6,964) (5,825) Net property, plant and equipment 14,725 14,008 13,499 Other assets 35 35 20 Total non-current assets 14,760 14,043 13,519 Total assets $15,657 $14,297 $13,764 97 Current liabilities Accounts payable 584 448 371 Accrued liabilities 268 241 180 Total current liabilities 852 689 551 Deferred income taxes 3,404 3,122 2,842 Other long-term liabilities 532 497 511 Total non-current liabilities 3,936 3,619 3,353 Net investment Accumulated other comprehensive income (22) (24) (47) Net parent company investment 10,891 10,013 9,907 Total net investment 10,869 9,989 9,860 Total liabilities and net investment $15,657 $14,297 $13,764 Note: March 31 and September 30, 2014 statements are unaudited. |
Historical Financials – Cash Flow Statement For the Nine Months Ended September 30, For the Year Ended December 31, ($ in millions) 2014 2013 2013 2012 Cash flow from operating activities Net Income $657 $657 $869 $699 Adjustments to reconcile net income to net cash provided by operating activities Depreciation, depletion and amortization of assets 886 853 1,144 926 Deferred income tax provision 262 197 260 603 Other non-cash charges to income 22 42 29 28 Asset impairments and related items - - - 41 Dry hole expenses 52 51 72 128 Changes in operating assets and liabilities, net 12 103 102 (202) Net cash provided by operating activities $1,891 $1,903 $2,476 $2,223 98 Cash flow from investing activities Capital expenditures (1,569) (1,180) (1,669) (2,331) Payments for purchases of assets and businesses, and other, net (69) (35) (44) (424) Net cash provided (used) by investment activities ($1,638) ($1,215) ($1,713) ($2,755) Cash flow from financing activities Contributions from (distributions to) parent company (148) (688) (763) 532 Net cash provided (used) by financing activities ($148) ($688) ($763) $532 Increase (decrease) in cash and cash equivalents 105 - - - Cash and cash equivalents – beginning of period - - - - Cash and cash equivalents – end of period $105 - - - Note: September 30, 2014 statements are unaudited. |
Non-GAAP Reconciliation for EBITDAX For the Year Ended December 31, 9 Months Ended, Last Twelve Months Ended, ($ in millions) 2012 2013 9/30/2013 9/30/2014 9/30/2014 Net Income $699 $869 $657 $657 $869 Interest Expense - - - - - Provision for income taxes 482 578 438 444 584 Depreciation, depletion and amortization 926 1,144 853 886 1,177 Exploration expense 148 116 81 71 106 EBITDAX $2,255 $2,707 $2,029 $2,058 $2,736 Net cash provided by operating activities $2,223 $2,476 $1,903 $1,891 $2,464 99 Interest expense - - - - - Cash income taxes (121) 318 241 182 259 Cash exploration expenses 20 44 30 19 33 Changes in operating assets and liabilities 202 (102) (103) (12) (11) Asset impairments and related items (41) - - - - Other, net (28) (29) (42) (22) (9) EBITDAX $2,255 $2,707 $2,029 $2,058 $2,736 |
Endnotes 1) As of 12/31/13, CRC’s probable reserves were 218 MMBoe (87% liquids) with a PV-10 of $4 billion and possible reserves were 136 MMBoe (83% liquids) with a PV-10 of $3 billion, each based on SEC pricing. 2) CRC's recycle ratio is equal to cash margin per barrel divided by F&D costs. CRC's cash margin per barrel is calculated as revenue less operating expenses, general and administrative expenses and taxes other than on income for 2013 divided by PDP and PDNP volumes additions for 2013 after adding back production for the period. Includes all drilling and completion costs but excludes land and acquisition costs. CRC's F&D costs are calculated as total exploration, development and acquisition costs for the period divided by total reserves additions for the period from all sources, including acquisitions. CRC's F&D costs were $20.60 / Boe for 2013. F&D costs may not include all the costs associated with exploration and development related to reserves added for the period, or may include costs related to reserves added or to be added in other periods, and may differ from calculations used by other companies. 3) As of 12/31/13, CRC’s probable reserves in the San Joaquin, Los Angeles, Ventura and Sacramento basins were 124 MMBoe (82% liquids), 65 MMBoe (95% liquids), 28 MMBoe (89% liquids) and 1 MMBoe (0% liquids), respectively, with a PV-10 of $2.5 billion, $0.9 billion, $0.6 billion and $0.0 billion, respectively, and CRC’s possible reserves were 109 MMBoe (82% liquids), 12 MMBoe (100% liquids), 14 MMBoe (86% liquids) and 1 MMBoe (0% liquids), respectively, with 100 a PV-10 of $2.4 billion, $0.1 billion, $0.4 billion and $0.0 billion, respectively, each based on SEC pricing. 4) As of 12/31/13, CRC’s probable reserves associated with conventional, waterflood, steamflood and unconventional drive mechanisms were 32 MMBoe (91% liquids), 101 MMBoe (94% liquids), 41 MMBoe (100% liquids) and 44 MMBoe (59% liquids), respectively, with a PV-10 of $0.8 billion, $1.6 billion, $0.9 billion and $0.6 billion, respectively, and CRC’s possible reserves were 42 MMBoe (90% liquids), 35 MMBoe (86% liquids), 8 MMBoe (100% liquids) and 51 MMBoe (75% liquids), respectively, with a PV-10 of $0.9 billion, $0.5 billion, $0.1 billion and $1.3 billion, respectively, each based on SEC pricing. 5) Cash margin per barrel for each producer is calculated as revenue less operating expenses, general and administrative expenses and taxes other than on income for 2013 divided by production for 2013 and derived from publicly available information. CRC’s recycle ratio is equal to CRC’s cash margin per barrel divided by F&D costs. 6) Free cash flow is calculated as cash flows from operations minus capital expenditures, excluding corporate transactions. |
California Resources Corporation 101 Management Biographies |
Management Biographies William (Bill) Albrecht, Executive Chairman of the Board Mr. Albrecht joined Occidental in 2007 as Vice President, California Operations, and became the President of Oxy Oil & Gas USA in 2008. In 2011, he was named President, Oxy Oil & Gas Americas. Prior to joining Oxy, Mr. Albrecht served as Vice President, Acquisitions and Engineering for EOG Resources, and Vice President, Engineering and Production for Kelley Oil & Gas Corporation. Mr. Albrecht earned a master of science degree in systems management from the University of Southern California and a bachelor of science degree in general engineering from the U.S. Military Academy, West Point Todd Stevens, President and Chief Executive Officer Mr. Stevens is a 19-year veteran of the company, and most recently served as Vice President, Corporate Development of Occidental Petroleum Corporation from August 2012 to July 2014. He served as Vice President, California Operations of Oxy Oil & Gas from April 2008 to September 2012, and as Vice President, 102 Acquisitions and Corporate Finance of Occidental Petroleum Corporation from October 2004 to August 2012. Mr. Stevens holds a master of business administration degree from the University of Southern California and a bachelor of science degree in engineering management from the United States Military Academy, West Point Scott Espenshade, Vice President – Investor Relations Mr. Espenshade joined the company in 2014, and has over 20 years of industry experience, including serving as Vice President, Investor Relations – Americas for BHP Billiton, and Director, Corporate Development and Investor Relations for Swift Energy Company in Houston. Mr. Espenshade also worked at the Independent Petroleum Association of America in Washington, D.C., serving as Vice President, Economics. Mr. Espenshade holds a master of business administration degree from Texas A&M University and a bachelor of science degree in Mineral Economics from Pennsylvania State University |
Management Biographies Shawn Kerns, Executive Vice President – Corporate Development Mr. Kerns’ career with Oxy spans over 20 years in operations, development and engineering. He most recently served as President and General Manager of Vintage Production California in Bakersfield from December 2013 to July 2014. Prior to that, Mr. Kerns was President and General Manager of California Heavy Oil, and President and General Manager of Occidental of Elk Hills in Bakersfield, after returning from five years in Doha with Oxy Qatar from November 2003 to October 2008 in planning, reservoir management, and operations leadership roles. Mr. Kerns holds a bachelor of science degree in electrical and communications engineering from the University of Oklahoma Robert (Bob) Barnes, Executive Vice President – Northern Operations Mr. Barnes is a 36-year veteran of the company, and most recently served as President and General Manager 103 of Occidental of Elk Hills from December 2012 to July 2014. He served as Operations Manager for Oxy Permian CO2 from May 2011 to November 2012, as Deputy General Manager and Senior Vice President, Operations of Occidental Argentina from June 2010 to April 2011, and as Vice President, Operations of Occidental Argentina from August 2007 to June 2010. Mr. Barnes also held Production Operations Manager and Operations Team Leader roles at Occidental of Elk Hills from 1998 to 2007. Mr. Barnes holds a bachelor of business administration degree from New Mexico State University |
Frank Komin, Executive Vice President – Southern Operations Mr. Komin has over 36 years of domestic oil and gas industry experience, with more than 14 years at Oxy. Mr. Komin most recently served as President and General Manager of Oxy Long Beach from January 2010 to July 2014, and held the position of President and General Manager of Oxy THUMS from February 2001 to December 2009. Before joining Oxy THUMS in 2000 as Manager, Production & Development, Mr. Komin worked for 22 years at ARCO, including as Manager, Production & Development, at ARCO THUMS, and Reservoir Engineering Manager and Operations Superintendent, Kuparuk in Alaska. Mr. Komin holds a bachelor of science degree in petroleum engineering from the University of Kansas Management Biographies Darren Williams, Executive Vice President – Exploration Mr. Williams has 20 years of experience in the oil and gas industry, working 17 of those years for Marathon Oil 104 in London, Houston and Oklahoma City. Mr. Williams has broad experience and proven track record in both conventional and unconventional exploration programs. Mr. Williams served as Africa Exploration Manager and President of Marathon Upstream Gabon Limited from May 2013 to September 2014. From September 2010 to May 2013 he served as Oklahoma Subsurface Manager where he managed the Woodford shale development program and established Marathon’s Oklahoma Resource Basin growth strategy. From 2008 to 2010, Mr. Williams served as Gulf of Mexico Exploration and Appraisal Manager overseeing participation in the Gunflint and Shenandoah discoveries; and from 2004 to 2008, he managed teams responsible for discovery of the Droshky field and rebuilding Marathon’s deepwater Gulf of Mexico inventory. From 1997 to 2004, Mr. Williams held various roles exploring assets in Europe, Africa and the Gulf of Mexico. Mr. Williams holds a master of science degree from Royal Holloway, University of London, UK, and a bachelor of science degree from the University of Leicester, UK |
Management Biographies Marshall (Mark) Smith, Senior Executive Vice President and Chief Financial Officer Mr. Smith has extensive experience in both the energy industry and in finance. Prior to joining the company in Charles (Charlie) Weiss, Executive Vice President – Public Affairs Mr. Weiss is an 18-year veteran of Occidental Petroleum Corporation, and most recently served as Vice President, Health, Environment and Safety of Oxy from October 2007 to July 2014. Mr. Weiss joined Oxy as Senior Counsel in Los Angeles in May 1996, and moved to Dallas to head the Litigation Group as Chief Counsel in July 2000. Mr. Weiss subsequently served as Vice President and General Counsel of Oxy Inc. Prior to joining Oxy, Mr. Weiss was a partner at Latham & Watkins in Los Angeles. He received a bachelor of science in engineering degree in chemical engineering from Princeton University and a juris doctorate degree from the University of Michigan Law School 105 August, he served as Senior Vice President and CFO of Ultra Petroleum Corporation in Houston, Texas, where he had worked since 2005. Mr. Smith has held Vice President and Business Development positions with Constellation Energy Investments and J.M. Huber Energy, and served as CFO of Gulf Liquids Inc. in Houston. He also served as Managing Director, Investment Banking at Nesbitt Burns Securities Inc. (now known as BMO Capital Markets Corporation). Mr. Smith began his career in production and reservoir engineering. He holds a master of business administration degree from Oklahoma City University and a bachelor of science degree in petroleum engineering from the University of Oklahoma |