Earnings and Presentations

4th Quarter 2016 Earnings
Todd A. Stevens
Marshall D. Smith
February 16, 2017

Earnings Release Earnings Release
Historical Data Historical Data
Earnings Infographic Earnings Infographic
Earnings Transcript Complete Transcript
Supplementary Slides Supplementary Slides

3rd Quarter 2016 Earnings
Todd A. Stevens
Marshall D. Smith
November 3, 2016

Earnings Release Earnings Release
Historical Data Historical Data
Earnings Infographic Earnings Infographic
Earnings Transcript Complete Transcript
Supplementary Slides Supplementary Slides

2nd Quarter 2016 Earnings
Todd A. Stevens
Marshall D. Smith
August 4, 2016

Earnings Release Earnings Release
Historical Data Historical Data
Complete Transcript Complete Transcript
Supplementary Slides Supplementary Slides

1st Quarter 2016 Earnings
Todd A. Stevens
Marshall D. Smith
May 5, 2016

Earnings Release Earnings Release
Historical Data Historical Data
Complete Transcript Complete Transcript
Supplementary Slides Supplementary Slides

4th Quarter 2015 Earnings
Todd A. Stevens
Marshall D. Smith
February 29, 2016

Earnings Release Earnings Release
Historical Data Historical Data
Complete Transcript Complete Transcript
Supplementary Slides Supplementary Slides

CRC Analyst Day and Site Tours
Bakersfield and Long Beach, California
March 22-23, 2017

CRC Analyst Day and Site Tours Webcast
2017 CRC Analyst Day Presentation 2017 Analyst Day Presentation
2017 CRC Analyst Day Transcript 2017 Analyst Day Transcript

Raymond James & Associates’ 38th Annual Institutional Investors Conference
Mark Smith - Speaker
March 6-8, 2017

Raymond James & Associates’ 38th Annual Institutional Investors Conference Webcast
Raymond James & Associates’ 38th Annual Institutional Investors Conference Raymond James & Associates’ 38th Annual Institutional Investors Conference Presentation
Raymond James & Associates’ 38th Annual Institutional Investors Conference Transcript Raymond James & Associates’ 38th Annual Institutional Investors Conference Transcript

Goldman Sachs Global Energy Conference
Mark Smith - Speaker
January 5-6, 2017

Goldman Sachs Global Energy Conference Goldman Sachs Global Energy Conference Presentation

Wells Fargo 15th Annual Energy Symposium
Mark Smith - Speaker
December 7, 2016

Wells Fargo 15th Annual Energy Symposium Wells Fargo 15th Annual Energy Symposium Presentation

Cowen and Company Energy & Natural Resources Conference
Mark Smith - Speaker
December 6, 2016

Cowen and Company Energy & Natural Resources Conference Webcast
Cowen and Company Energy & Natural Resources Conference Cowen and Company Energy & Natural Resources Conference Presentation

Bank of America Merrill Lynch 2016 Global Energy Conference
Todd Stevens - Speaker
November 17, 2016

Bank of America Merrill Lynch 2016 Global Energy Conference Webcast
Bank of America Merrill Lynch 2016 Global Energy ConferencePresentation Bank of America Merrill Lynch 2016 Global Energy Conference Presentation

2016 Johnson Rice Energy Conference
September 22, 2016

2016 Johnson Rice Energy Conference Presentation 2016 Johnson Rice Energy Conference Presentation

Barclays CEO Energy-Power Conference
Todd Stevens - Speaker
September 6, 2016

Barclays CEO Energy-Power Conference Webcast
Barclays CEO Energy-Power Conference Presentation Barclays CEO Energy-Power Conference Presentation
Barclays CEO Energy-Power Conference Transcript Barclays CEO Energy-Power Conference Transcript

Supplemental Investor Information
August 1, 2016

Supplemental Investor Information Supplemental Investor Information

J.P. Morgan Inaugural Energy Equity Conference
June 28, 2016

J.P. Morgan Inaugural Energy Equity Conference J.P. Morgan Inaugural Energy Equity Conference Presentation

Scotia Howard Weil 2016 Energy Conference
Todd Stevens - Speaker
March 23, 2016

Scotia Howard Weil 2016 Energy Conference Scotia Howard Weil 2016 Energy Conference
Scotia Howard Weil 2016 Energy Conference Edited Transcript Scotia Howard Weil 2016 Energy Conference Edited Transcript

Goldman Sachs Energy Conference
Mark Smith - Speaker
January 6, 2016

Goldman Sachs Energy Conference Goldman Sachs Energy Conference Presentation

2015 Analyst Day 2
October 14, 2015

2015 Analyst Day 2 Webcast Webcast
2015 Analyst Day 2 2015 Analyst Day 2 Presentation
2015 Analyst Day 2 Transcript 2015 Analyst Day 2 Transcript

2015 Analyst Day 1
October 13, 2015

2015 Analyst Day 1 Webcast Webcast
2015 Analyst Day 1 2015 Analyst Day 1 Presentation
2015 Analyst Day 1 Transcript 2015 Analyst Day 1 Transcript

OGIS San Francisco
Scott Espenshade - Speaker
October 5, 2015

OGIS San Francisco Conference OGIS San Francisco Presentation

Johnson Rice Energy Conference
Mark Smith - Speaker
September 30, 2015

Johnson Rice Energy Conference Johnson Rice Energy Conference Presentation

Raymond James North American Conference
Todd Stevens - Speaker
September 22, 2015

Raymond James North American Conference Raymond James North American Conference Presentation

Barclays CEO Energy & Power Conference
Todd Stevens - Speaker
September 10, 2015

Webcast Webcast
Barclays CEO Energy & Power Conference Barclays CEO Energy & Power Conference Presentation
Barclays CEO Energy & Power Conference Transcript Barclays CEO Energy & Power Conference Transcript

Investor Presentation
July 2015

July Investor Presentation July Investor Presentation

Wolfe Research – Interview with Paul Sankey
Todd Stevens - Speaker
July 13, 2015

Wolfe Research – Interview with Paul Sankey Wolfe Research – Interview with Paul Sankey Presentation
Wolfe Research – Interview with Paul Sankey Transcript Wolfe Research – Interview with Paul Sankey Edited Transcript

Tudor Pickering Holt CEO Luncheon Series
Todd Stevens - Speaker
June 30, 2015

Tudor Pickering Holt CEO Luncheon Series Tudor Pickering Holt CEO Luncheon Series Presentation

GHS 100 Energy Conference
Scott Espenshade - Speaker
June 24, 2015

GHS 100 Energy Conference GHS 100 Energy Conference Presentation

TPH 2015 Hotter ‘N Hell Conference
Mark Smith - Executive Representation
June 17, 2015

Bank of America Merrill Lynch Global Energy and Power Leveraged Finance Conference TPH 2015 Hotter ‘N Hell Conference Presentation

Bank of America Merrill Lynch Global Energy and Power Leveraged Finance Conference
Mark Smith - Speaker
June 3, 2015

Bank of America Merrill Lynch Global Energy and Power Leveraged Finance Conference Bank of America Merrill Lynch Global Energy and Power Leveraged Finance Conference Presentation

UBS Global Oil and Gas Conference
Todd Stevens - Speaker
May 19, 2015

UBS Global Oil and Gas Conference Webcast
UBS Global Oil and Gas Conference UBS Global Oil and Gas Conference Presentation

Citi 2015 Global Energy and Utilities Conference
Todd Stevens - Speaker
May 12-13, 2015

Citi 2015 Global Energy and Utilities Conference Webcast
Citi 2015 Global Energy and Utilities Conference Citi 2015 Global Energy and Utilities Conference Presentation

Independent Petroleum Association of America, Oil and Gas Investment Symposia
Todd Stevens - Speaker
April 21, 2015

Independent Petroleum Association of America, Oil and Gas Investment Symposia Webcast
Independent Petroleum Association of America, Oil and Gas Investment Symposia Independent Petroleum Association of America, Oil and Gas Investment Symposia Presentation

Scotia Howard Weil 43rd Annual Energy Conference
Todd Stevens - Speaker
March 25, 2015

Scotia Howard Weil 43rd Annual Energy Conference Scotia Howard Weil 43rd Annual Energy Conference Presentation

Raymond James 36th Annual Institutional Investors Conference
Mark Smith – Speaker
March 4, 2015

Raymond James 36th Annual Institutional Investors Conference Webcast Webcast
Raymond James 36th Annual Institutional Investors Conference Presentation Raymond James 36th Annual Institutional Investors Conference Presentation

Goldman Sachs Global Energy Conference 2015
January 7-8, 2015

Goldman Sachs Global Energy Conference Presentation Goldman Sachs Global Energy Conference Presentation

Investor Presentation
December 2014

2014 CRC December Investor Presentation December Investor Presentation

2014 Wells Fargo Energy Symposium
Mark Smith – Speaker
December 10, 2014

2014 Wells Fargo Energy Symposium Presentation CRC 2014 Wells Fargo Energy Symposium Presentation

Bank of America Merrill Lynch 2014 Leveraged Finance Conference
Mark Smith – Speaker
December 2, 2014

Bank of America Merrill Lynch 2014 Leveraged Finance Conference Webcast
Bank of America Merrill Lynch 2014 Leveraged Finance Conference Presentation Bank of America Merrill Lynch 2014 Leveraged Finance Conference Presentation

Bank of America Merrill Lynch 2014 Energy Conference
Todd A. Stevens – Speaker
November 14, 2014

Bank of America Merrill Lynch 2014 Energy Conference Webcast
Bank of America Merrill Lynch 2014 Energy Conference Presentation Bank of America Merrill Lynch 2014 Energy Conference Presentation

Analyst Day
October 31, 2014

2014 Analyst Day Webcast
2014 Analyst Day Presentation 2014 Analyst Day Presentation
2014 Analyst and Investor Day Transcript 2014 Analyst and Investor Day Transcript

Investor Presentation
October 2014

pdf October Investor Presentation

Important Additional Disclosures and GAAP Reconciliations


3P Reserves and Other Hydrocarbon Resource Quantities
We provide internally generated estimates for proved reserves and aggregated proved, probable and possible reserves (“3P Reserves”) as of December 31, 2016, with each category of reserves estimated in accordance with SEC guidelines and definitions, though we have not reported all such estimates to the SEC. As used:

  • 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.

We use the terms “hydrocarbons in place,” “potential recovery,” “original hydrocarbons in place, “resource potential,” “expected ultimate recovery (EUR)” and “inventory” to describe estimates of potentially recoverable hydrocarbons remaining in the applicable reservoir. These resources are not proved reserves in accordance with SEC regulations and SEC guidelines restrict us from including these measures in filings with the SEC. These have been estimated internally without review by independent engineers and may include shale resources which are not considered in most older, publicly available estimates. Actual recovery of these potential resource volumes is inherently more speculative than recovery of estimated reserves. Factors affecting ultimate recovery include the scope of our ongoing drilling and workover 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, lease expirations, transportation constraints and other factors; actual drilling results, which may be affected by geological, mechanical and other factors that determine recovery rates; and budgets based upon our future evaluation of risk, returns and the availability of capital. 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. Unproved inventory comprises risked probable and possible reserves and may include contingent and prospective resources. Contingent and prospective resources consist of volumes identified through life-of-field planning efforts that may not have been risked by reference to analogy or other methods used to estimate the chance of success from drilling. Ultimate recoveries will be dependent upon numerous factors including those noted above.

Drilling Locations

Determination of Identified Drilling Locations

Proven Drilling Locations
Based on our reserves report as of December 31, 2016, we have approximately 2,350 gross (2,150 net) drilling locations attributable to our proved undeveloped reserves. We use production data and experience gained from our development programs to identify and prioritize this proven drilling inventory. These drilling locations are included in our inventory only after we have adopted a development plan to drill them within a five-year time frame. As a result of rigorous technical evaluation of geologic and engineering data, we can estimate with reasonable certainty that reserves from these locations will be commercially recoverable in accordance with SEC guidelines. Management considers the availability of local infrastructure, drilling support assets, state and local regulations and other factors it deems relevant in determining such locations.

Unproven Drilling Locations
We have also identified a multi-year inventory of 16,450 gross (15,050 net) drilling locations that are not associated with proved undeveloped reserves but are specifically identified on a field-by-field basis considering the applicable geologic, engineering and production data. We analyze past field development practices and identify analogous drilling opportunities taking into consideration historical production performance, estimated drilling and completion costs, spacing and other performance factors. These drilling locations primarily include (i) infill drilling locations, (ii) additional locations due to field extensions or (iii) potential improved oil recovery and enhanced oil recovery project expansions, some of which are currently in the pilot phase across our properties, but have yet to be moved to the proven category. We believe the assumptions and data used to estimate these drilling locations are consistent with established industry practices with well spacing selected based on the type of recovery process we are using.

Exploration Drilling Locations
Our portfolio of prospective drilling locations contains approximately 12,100 gross (5,650 net) unrisked exploration drilling locations in proven reservoirs, the majority of which are located near existing producing fields. We use internally generated information and proprietary geologic models consisting of data from analog plays, 3D seismic data, open hole and mud log data, cores, and reservoir engineering data to help define the extent of the targeted intervals and the potential ability of such intervals to produce commercial quantities of hydrocarbons. Information used to identify exploration locations includes both our own proprietary data, as well as industry data available in the public domain. After defining the potential areal extent of an exploration prospect, we identify our exploration drilling locations within the prospect by applying the well spacing historically utilized for the applicable type of recovery process used in analogous fields.

Prospective Resource Drilling Locations
In addition, we have approximately 6,400 gross (5,300 net) unrisked prospective resource drilling locations identified in the lower Monterey, Kreyenhagen and Moreno unconventional reservoirs based on screening criteria that include geologic and economic considerations and limited production information. Prospective play areas are defined by geologic data consisting of well cuttings, hydrocarbon shows, open-hole well logs, geochemical data, available 3D or 2D seismic data and formation pressure data, where available. Information used to identify our prospective locations includes both our own proprietary data, as well as industry data available in the public domain. We identify our prospective resource drilling locations based on an assumption of 80-acre spacing per well throughout the prospective area for each resource play.

Well Spacing Determination
Our well spacing determinations in the above categories of identified well locations are based on actual operational spacing within our existing producing fields, which we believe are reasonable for the particular recovery process employed (i.e., primary, waterflood or EOR). Due to the significant vertical thickness and multiple stacked reservoirs usually encountered by our drilling wells, typical well spacing is generally less than 20 acres and often 10 acres or less in the majority of our fields unless specified differently above. These parameters also meet the general well spacing restrictions imposed on certain oil and gas fields in California.

Drilling Schedule
Our identified drilling locations have been scheduled as part of our current multi-year drilling schedule or are expected to be scheduled in the future. However, we may not drill our identified sites at the times scheduled or at all. We view the risk profile for our exploration drilling locations and our prospective resource drilling locations as being higher than for our other drilling locations due to relatively less available geologic and production data and drilling history, in particular with respect to our prospective resource locations, which are in unproven geologic plays. We make assumptions about the consistency and accuracy of data when we identify these locations that may prove inaccurate.

Our ability to profitably drill and develop our identified drilling locations depends on a number of variables, including crude oil and natural gas prices, capital availability, costs, drilling results, regulatory approvals, available transportation capacity and other factors. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling or development of these projects. A small portion of the unproven drilling locations may be uneconomic at current prices. For a discussion of the risks associated with our drilling program, see "Risk Factors—Risks Related to Our Business and Industry" in our Form 10-K for 2016.

The table below sets forth our total gross identified drilling locations as of December 31, 2016, excluding our prospective drilling locations from new resource plays.

Proven Drilling Locations Total Identified Drilling Locations
Oil and Natural Gas Wells Injection Wells Oil and Natural Gas Wells Injection Wells
San Joaquin Basin
Primary Conventional 200 - 9,000 -
Steamflood 1,050 250 7,550 450
Waterflood 100 50 2,100 1,050
Unconventional 250 - 3,750 -
San Joaquin Basin subtotal 1,600 300 22,400 1,500
Los Angeles Basin
Primary Conventional - - - -
Steamflood - - - -
Waterflood 250 100 1,600 550
Unconventional - - - -
Los Angeles Basin subtotal 250 100 1,600 550
Ventura Basin
Primary Conventional - - 1,600 -
Steamflood - - 350 -
Waterflood 50 50 750 250
Unconventional - - - -
Ventura Basin subtotal 50 50 2,700 250
Sacramento Basin
Primary Conventional - - 1,900 -
Sacramento Basin subtotal - - 1,900 -
Total Identified Drilling Locations 1,900 450 28,600 2,300

Non-GAAP Financial Measures and Reconciliations

Some disclosures may include financial measures that are not in accordance with United States generally accepted accounting principles (“GAAP”), including PV-10, Adjusted EBITDAX and Adjusted G&A. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures presented in accordance with GAAP. For a reconciliation of such measures to the nearest comparable measure in accordance with GAAP, please see below.

Non-GAAP Reconciliation for Adjusted EBITDAX

We define Adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; and other unusual and infrequent items. Our management believes Adjusted EBITDAX provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry, the investment community and our lenders. While Adjusted EBITDAX is a non-GAAP measure, the amounts included in the calculation of Adjusted EBITDAX were computed in accordance with GAAP. This measure is a material component of certain of our financial covenants under our first-lien, first-out credit facilities and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing our financial performance, such as our cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. Adjusted EBITDAX should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP.

The following tables present a reconciliation of the GAAP financial measures of net (loss) / income and net cash (used) / provided by operating activities to the non-GAAP financial measure of Adjusted EBITDAX:

($ millions) 2016
Net (loss) income $ 279
Interest and debt expense 328
Income tax benefit (78)
Depreciation, depletion and amortization 559
Exploration expense 23
Adjusted income items before interest and taxes(a) (545)
Other items 50
Adjusted EBITDAX $ 616
Net cash (used) provided by operating activities $ 130
Cash Interest 384
Exploration expenditures 20
Other changes in operating assets and liabilities 95
Refunds, plant turnaround charges and other (13)
Adjusted EBITDAX $ 616
(a) See reconciliation of adjusted net loss below.

Non-GAAP Reconciliation for Adjusted Net Loss and Adjusted G&A
Our results of operations can include the effects of unusual and infrequent transactions and events affecting earnings that vary widely and unpredictably in nature, timing, amount and frequency. Therefore, management uses measures called "Adjusted Net Income / (Loss)" and "Adjusted General and Administrative Expenses" which exclude those items. These non-GAAP measures are not meant to disassociate items from management's performance, but rather are meant to provide useful information to investors interested in comparing our performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted Net Income / (Loss) and Adjusted General and Administrative Expenses are not considered to be alternatives to net income / (loss) and general and administrative expenses reported in accordance with GAAP.

Adjusted Net Loss

($ millions, except per share amounts) 2016
Net (loss) income $ 279
Unusual and infrequent items:
Asset impairments -
Write-down of certain assets -
Non-cash derivative losses (gains) 283
Severance, early retirement and other costs 20
Refunds, plant turnaround charges and other (13)
Net gains on early extinguishment of debt (805)
Debt issuance costs -
Loss (gain) from asset divestitures (30)
Adjusted income items before interest and taxes (545)
Deferred debt issuance costs write-off 12
Adjustments for valuation allowance on deferred(a) (63)
Tax effects of these items and related adjustments -
Total $ (596)
Adjusted net loss $ (317)
Net (loss) income per diluted share $ 6.76
Adjusted net loss per diluted share $ (7.85)
(a) Amount represents the out-of-period portion of the valuation allowance

Adjusted General and Administrative Expenses

Twelve Months
($millions) 2016 2015
General and administrative expenses $ 248 $ 354
Severance, early retirement and other costs (20) (67)
Adjusted general and administrative expenses $ 228 $ 287

Additional Non-GAAP Reconciliations


Free Cash Flow

Twelve Months
($millions) 2016 2015
Operating cash flow $ 130 $ 403
Capital investment (75) (401)
Changes in capital accruals (6) (205)
Free cash flow (after working capital) $ 49 $ (203)

Organic Recycle Ratio

($/BOE) 2016
Oil and gas revenues $ 33.17
Production Costs (15.61)
Taxes other than on income (Oil and Gas Operations) (2.36)
Total CRC general and administrative expenses (4.84)
Margin $ 10.36
Organic Finding and Development $ 3.42
Organic Recycle Ratio 3.0x

Organic Reserve Replacement Ratio
The organic reserves replacement ratio is calculated for a specified period using the proved oil-equivalent additions from extensions and discoveries, improved recovery, and performance-related provisions, divided by oil-equivalent production. Approximately 89% of the additions for 2016 are proved undeveloped. There is no guarantee that historical sources of reserves additions will continue as many factors could cause unforeseen results, including geology, government regulations and permits, commodity prices, the availability of capital, the effectiveness of development plans. Management uses this measure to gauge results of its capital allocation.

2016
Proved reserves added - MMBOE
Extensions and Discovery 20
Improved Recovery 3
Revisions related to performance 13
Total (A) 36
Production in 2016 - MMBOE (B) 51
Organic Reserves Replacement Ratio (A)/(B) 71%

Organic Finding and Development Costs
We calculate organic finding and development costs by dividing the costs incurred for the year from the capital program (including development (including asset retirement obligations), and exploration costs, but excluding acquisitions) by the amount of oil-equivalent proved reserves added in the same year from improved recovery, extensions and discoveries and performance-related revisions (excluding acquisitions and price-related revisions). We believe that reporting our finding and development costs can aid investors in their evaluation of our ability to add proved reserves at a reasonable cost but is not a substitute for GAAP disclosures. Various factors, including timing differences and effects of commodity price changes, can cause finding and development costs to reflect costs associated with particular reserves imprecisely. For example, we will need to make more investments in order to develop the proved undeveloped reserves added during the year and any future revisions may change the actual measure from that presented above. In addition, part of the 2016 costs were incurred to convert proved undeveloped reserves from prior years to proved developed reserves. We have not estimated future costs expected for the reserves added or removed costs related to reserves added in prior periods. Our calculations of finding and development costs may not be comparable to similar measures provided by other companies.

2016
Organic costs incurred - in millions (A) $ 123(1)
Proved Reserves Added - MMBOE (B) 36(2)
Organic Finding and Development Costs - $/BOE (A)/(B) $ 3.42

(1) Includes development and exploration costs, as well as asset retirement obligations.
(2) Includes performance revisions.

PV-10
PV-10 is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC prescribed pricing assumptions for the period. PV-10 differs from Standardized Measure because Standardized Measure includes the effects of future income taxes on future net cash flows. Neither PV-10 nor Standardized Measure should be construed as the fair value of our oil and natural gas reserves. PV-10 and Standardized Measure are used by the industry and by our management as an asset value measure to compare against our past reserves bases and the reserves bases of other business entities because the pricing, cost environment and discount assumptions are prescribed by the SEC and are comparable. PV-10 further facilitates the comparisons to other companies as it is not dependent on the tax paying status of the entity.

The following table presents a reconciliation of the non-GAAP financial measure of PV-10 to the GAAP financial measure of standardized measure of discounted future net cash flows:

PV-10 and Standardized Measure ($ millions) 2016
PV-10 of proved reserves $ 2,848
Present value of future income taxes discounted at 10% (181)
Standardized measure of discounted future net cash flows $ 2,667

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