California Resources Corporation Announces Its Fourth Quarter and Full Year 2014 Financial Results


Thursday, February 19, 2015 1:01 pm PST



Public Company Information:

"Our fast actions underscore the operational flexibility of our asset base as we pursue our previously stated goals of delivering economic growth for shareholders while living within our cash flow."

LOS ANGELES--(BUSINESS WIRE)--California Resources Corporation (NYSE:CRC), the newly independent California-based oil and gas exploration and production company, today announced a core loss1 of $7 million ($0.02 per diluted share) for the fourth quarter of 2014, compared with core income of $212 million ($0.55 per diluted share) for the fourth quarter of 2013. Core income, excluding unusual and infrequent items, was $650 million ($1.67 per diluted share) for the full year 2014, compared with $869 million ($2.24 per diluted share) for the full year 2013.

Highlights Include:

  • Record quarterly total production of 165,000 BOE per day and crude oil production of 105,000 barrels per day
  • 4Q-2014 EBITDAX2 of $454 million
  • 4Q-2014 core loss of $7 million or ($0.02 per diluted share)
  • $2.1 billion after-tax non-cash charges, including GAAP required adjustments for commodity prices, spin-off related items and rig terminations
  • 203 percent preliminary proved reserve replacement from the Capital Program, ending 2014 with 768 million BOE proved reserves
  • Completed spin-off from Occidental Petroleum
  • Expected 2015 Capital Program of $400 to $450 million to keep annual production essentially flat

The reported net loss for the fourth quarter of 2014 was $2.1 billion ($5.47 per diluted share), compared with net income of $212 million ($0.55 per diluted share) for the fourth quarter of 2013. The fourth quarter loss was driven primarily by non-cash, after-tax impairment charges of $2.0 billion ($3.4 billion pre-tax), required under accounting rules to reflect the recent decline in commodity prices, as well as $64 million of other after-tax unusual and infrequent charges ($107 million pre-tax) including spin-off and transition related items.

Todd Stevens, President and Chief Executive Officer, said, "We successfully completed the spin-off from Occidental Petroleum on November 30, 2014 and became an independent California company trading on the NYSE with a vision to provide Californians with long-term, affordable and reliable energy exclusively from California resources. Reflecting the underlying quality of our world class asset base, our oil production set another quarterly record with a 12 percent increase from the fourth quarter of 2013 and a five percent increase from the third quarter of 2014. The industry is experiencing a challenging commodity price environment and we have adjusted rapidly by reducing our rig count from 27 in late November to six by year-end 2014 and three rigs currently. We have decreased our capital investment levels to live within our cash flows and will use this period of reduced activity to grow our inventory of available future projects. These steps will position CRC to capitalize on more favorable market fundamentals swiftly when prices improve. In the meantime, our low-decline and predictable asset base is capable of generating significant and sufficient cash flow in the current commodity price environment.”

Fourth Quarter Results

Core results were a loss of $7 million ($0.02 per diluted share) for the fourth quarter of 2014, compared with core income of $212 million ($0.55 per diluted share) for the fourth quarter of 2013. The 2014 quarter reflected higher oil volumes, higher realized gas prices and lower per unit production costs, more than offset by significantly lower realized oil and NGL prices and higher interest expense as a result of our capital structure as a newly independent-company. EBITDAX for the fourth quarter of 2014 was $454 million compared with $684 million for the fourth quarter of 2013.

Daily oil and gas production volumes averaged 165,000 barrels of oil equivalent (BOE) in the fourth quarter of 2014, a record level for our operations, compared with 157,000 BOE in the fourth quarter of 2013. Average oil production increased by 12 percent or 11,000 barrels per day, to a record 105,000 barrels per day in the fourth quarter of 2014, reflecting our focus on oil drilling. NGL and natural gas production decreased slightly by 1,000 barrels and 8 million cubic feet (MMcf) per day, respectively, in line with our planned shift in our capital investments toward higher margin oil projects.

Realized crude oil prices decreased 31 percent to $68.54 per barrel for the fourth quarter of 2014 from $99.32 per barrel for the fourth quarter of 2013. The decrease reflects the drop in global oil prices during this period and our widening differentials to Brent. Realized NGL prices decreased 40 percent to $34.41 per barrel in the fourth quarter of 2014 from $57.73 per barrel in the fourth quarter of 2013. Natural gas realized prices increased nine percent in the fourth quarter of 2014 to $4.00 per thousand cubic feet (Mcf), compared with $3.68 per Mcf in the fourth quarter of 2013.

Full Year 2014 Results

Core income for the full year 2014 was $650 million ($1.67 per diluted share) compared with $869 million ($2.24 per diluted share) for the same period of 2013. Higher oil production and higher realized natural gas prices in 2014 were more than offset by lower realized oil prices in 2014 and higher production costs, depreciation rates, property taxes, selling, general and administrative costs and interest expense. Production costs increased mainly due to higher natural gas and other energy costs. EBITDAX for the twelve months of 2014 was $2.5 billion, compared with $2.7 billion for the twelve months of 2013. 2

The 2014 daily oil and gas production volumes averaged 159,000 BOE, compared with 154,000 BOE in 2013. Average oil production increased 9,000 barrels per day, or by 10 percent, to 99,000 barrels per day in 2014. NGL and natural gas production decreased by 1,000 barrels and 14MMcf per day, respectively.

Realized crude oil prices decreased 11 percent to $92.30 per barrel for the full year 2014, compared with $104.16 per barrel for the twelve months of 2013. NGL prices decreased five percent to $47.84 per barrel for the twelve months of 2014 from $50.43 per barrel for the twelve months of 2013. Natural gas prices increased 18 percent in the twelve months of 2014 to $4.39 per Mcf, compared with $3.73 per Mcf in the twelve months of 2013.

With respect to the impairment charges being reported, accounting rules require the company to evaluate its properties in light of, among other factors, the year-end forward price curve and projects it has determined not to pursue in the current environment. The company continues to expect to develop these properties as energy prices recover to more sustainable levels.

The other non-core pre-tax charges included $52 million for rig idling and other price-related charges, and $55 million for spin-off and transition related items.

2014 Operational Activity

CRC drilled 1,048 wells in 2014, of which 73 wells were drilled for primary production, 259 wells were drilled in our waterflood fields, 532 were focused on steamfloods and 184 were focused on unconventional reservoirs.

In our exploration program, we had notable success in our conventional reservoir drilling results in proven play trends offsetting the Pleito Ranch Field in the San Joaquin Basin and the Bardsdale Field in the Ventura Basin.

Current Market Conditions

The oil and gas industry experienced a steep decline in commodity prices, particularly in oil, beginning in the second half of 2014. CRC rapidly adjusted by reducing capital investments, and by reducing its rig count to six in December 2014 from 27 rigs at the end of November. The Company also has identified significant cost reductions, some of which were already implemented by year-end 2014.

Based on preliminary discussions with the Board and subject to their final approval next week, CRC plans for its capital program in 2015 to be in the range of $400 million to $450 million with a focus on steamflood and waterflood activities. CRC’s average crude oil production in 2015 is expected to be higher than the 2014 average, and natural gas and NGL production are expected to be lower. The Company expects its total average daily 2015 production to be relatively flat compared to 2014.

Mr. Stevens added, “Our fast actions underscore the operational flexibility of our asset base as we pursue our previously stated goals of delivering economic growth for shareholders while living within our cash flow.”


The Company’s proved oil and gas reserves as of December 31, 2014 increased to 768 million BOE from 744 BOE at December 31, 2013. CRC’s 2014 capital program of $2.1 billion added 118 million barrels of proved reserves for a 203 percent proved reserve replacement rate for the year. This resulted in an organic finding and development cost from the capital program of $17.68 per BOE. Acquisitions added an additional 6 million barrels of proved reserves. Partially offsetting these additions were negative revisions of 42 million BOE. The negative revisions were mainly the result of performance related adjustments to certain legacy projects concentrated in the San Joaquin Basin, primarily at Elk Hills. Production for the year was approximately 58 million BOE.

Hedging Update

As previously reported, the Company purchased put options in the fourth quarter of 2014 with a $50 per barrel Brent strike price (based on a monthly average). CRC’s initial program covered almost all of its oil production for the first six months of 2015. More recently, CRC put into place additional hedging instruments to protect the pricing for almost two-thirds of its expected third quarter 2015 oil production. For this program, the Company chose a combination of Brent-based collars with strike prices between $55 and $72 per barrel for 30,000 barrels per day for July through September, as well as put options at $50 per barrel Brent for 40,000 barrels per day combined with a $75 per barrel Brent call for 30,000 barrels per day of oil production in March through June of 2015.

1 See reconciliation on Attachment 2.
2 For an explanation of how we calculate and use EBITDAX (non-GAAP) and a reconciliation of net income (GAAP) to EBITDAX (non-GAAP), please see Attachment 2.

Conference Call Details

To participate in today’s conference call, either dial (866) 777-2509 (International calls please dial +1 (412) 317-5413) or access via webcast at, fifteen minutes prior to the scheduled start time to register. Participants may also pre-register for the conference call at

A digital replay of the conference call will be archived for approximately 30 days and available online in Investor Relations at

About California Resources Corporation

California Resources Corporation is an independent oil and natural gas exploration and production company and the largest combined oil and natural gas producer in California on a gross-operated basis. The Company operates its world class resource base exclusively within the State of California. Using advanced technology, California Resources Corporation focuses on safely and responsibly supplying affordable energy for California by Californians.

Forward-Looking Statements

Portions of this press release contain forward-looking statements and involve risks and uncertainties that could materially affect expected results of operations, liquidity, cash flows and business prospects. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. Factors that could cause results to differ include, but are not limited to: commodity pricing fluctuations; supply and demand considerations for California Resources Corporation's products; access to capital markets; higher-than-expected costs; the regulatory approval environment; negative developments arising from the spin-off of California Resources Corporation; not successfully completing, or any material delay of, field developments, expansion projects, capital investments, efficiency projects, acquisitions or dispositions; lower-than-expected production from development projects or acquisitions; exploration risks; general economic slowdowns; liability under environmental regulations including remedial actions; litigation; disruption or interruption of production, processing or marketing or facility damage due to accidents, labor unrest, weather, natural disasters or cyber attacks; changes in law or regulations; or changes in tax rates. Words such as “estimate,” “project,” “predict,” “will,” “would,” “should,” “could,” “may,” “might,” “anticipate,” “plan,” “intend,” “believe,” “expect,” “aim,” “goal,” “target,” “objective,” “likely” or similar expressions that convey the prospective nature of events or outcomes generally indicate forward-looking statements. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this release. Unless legally required, California Resources Corporation does not undertake any obligation to update any forward-looking statements, as a result of new information, future events or otherwise. Material risks that may affect California Resources Corporation's results of operations and financial position appear in “Risk Factors” in our Form 10.

Attachment 1
   Fourth Quarter     Twelve Months
($ and shares in millions)  2014  2013     2014  2013

Income Statement Data:

Oil and gas sales to related parties  $57   $1,027      $2,617   $4,054 
Oil and gas sales to third parties   728    22       1,406    85 
Other revenue   35    30       150    145 
    820    1,079       4,173    4,284 
Costs and other deductions               
Production costs   243    243       1,023    960 
Selling, general and administrative expenses   93    80       336    292 
Depreciation, depletion and amortization   312    291       1,198    1,144 
Asset impairments   3,402    -       3,402    - 
Taxes other than on income   54    44       217    185 
Exploration expense   68    35       139    116 
Interest expense   72    -       72    - 
Other expenses   98    34       207    140 
    4,342    727       6,594    2,837 
Income (loss) before income taxes   (3,522)   352       (2,421)   1,447 
(Provision) benefit for income taxes   1,431    (140)      987    (578)
Net income (loss)  $(2,091)  $212      $(1,434)  $869 
EPS - diluted  $(5.47)  $0.55      $(3.75)  $2.24 
Core income (loss)  $(7)  $212      $650   $869 
Core EPS - diluted  $(0.02)  $0.55      $1.67   $2.24 
Weighted average basic shares outstanding (a)   381.9    381.8       381.9    381.8 
Weighted average diluted shares outstanding (a)   381.9    381.8       381.9    381.8 

(a) - On December 1, 2014, the Spin-off date from Occidental Petroleum Corporation, 381.4 million shares of our common stock were distributed to Occidental shareholders. Additional shares were distributed to our employees and vested in December. For comparative purposes, and to provide a more meaningful calculation of weighted-average shares outstanding, we have assumed these amounts to be outstanding for each period prior to the Spin-off.

EBITDAX  $454   $684      $2,548   $2,733 
Effective tax rate   41%   40%      41%   40%

Cash Flow Data:

Net cash provided by operating activities  $480   $574      $2,371   $2,476 
Net cash used by investing activities  $(674)  $(499)     $(2,312)  $(1,713)
Net cash provided (used) by financing activities  $103   $(75)     $(45)  $(763)

Balance Sheet Data:

   December 31,     December 31,      
   2014     2013      
Total current assets  $701      $254      
Property, plant and equipment, net  $11,685      $14,008      
Total current liabilities  $906      $689      
Total debt  $6,360      $-      
Total equity / net investment  $2,611      $9,989      
Outstanding shares   385.6       -      
Attachment 2

We define EBITDAX consistently with our credit facilities as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; and certain other non-cash and unusual, infrequent charges. Our management believes EBITDAX provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry and investment community. The amounts included in the calculation of EBITDAX were computed in accordance with generally accepted accounting principles (GAAP). This measure is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP.


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

   Fourth Quarter  Twelve Months
($ millions)  2014  2013  2014  2013
Net income (loss)  $(2,091)  $212   $(1,434)  $869 
Interest expense   72    -    72    - 
Provision (benefit) for income taxes   (1,431)   140    (987)   578 
Depreciation, depletion and amortization   312    291    1,198    1,144 
Exploration expense   68    35    139    116 
Asset impairment   3,402    -    3,402    - 
Other (a)   122    6    158    26 
EBITDAX  $454   $684   $2,548   $2,733 
Net cash provided by operating activities  $480   $574   $2,371   $2,476 
Interest expense   72    -    72    - 
Cash income taxes   -    121    165    318 
Cash exploration expenses   19    14    38    44 
Changes in operating assets and liabilities   (131)   -    (143)   (103)
Other, net   14    (25)   45    (2)
EBITDAX  $454   $684   $2,548   $2,733 
(a) Includes non-cash and unusual, infrequent charges.

California Resources Corporation's results of operations can include the effects of significant, unusual and infrequent transactions and events affecting earnings that vary widely and unpredictably in nature, timing, amount and frequency. Therefore management uses a measure called "core income," which excludes those items. This non-GAAP measure is not meant to disassociate items from management's performance, but rather is meant to provide useful information to investors interested in comparing California Resources Corporation's earnings performance between periods. Reported earnings are considered representative of management's performance over the long term. Core income is not considered to be an alternative to income reported in accordance with GAAP.


The following table presents a reconciliation of the non-GAAP financial measure of core income to the GAAP financial measure of net income:

   Fourth Quarter  Twelve Months
($ millions)  2014  2013  2014  2013
Net income (loss)  $(2,091)  $212  $(1,434)  $869
Asset impairments   3,402    -   3,402    -
Rig terminations and other price-related costs   52    -   52    -
Spin-off and transition related costs   55    -   55    -
Tax effect of pre-tax adjustments   (1,425)   -   (1,425)   -
Core income (loss)  $(7)  $212  $650   $869
Core EPS - diluted  $(0.02)  $0.55  $1.67   $2.24
Attachment 3
($ millions)   
2013 4th Quarter Core Income  $212 
Price - Oil and NGLs   (308)
Price - Natural Gas   9 
Volume   25 
Production cost rate   11 
DD&A rate   (11)
Exploration expense   (12)
Interest expense   (72)
Income tax   146 
All Others   (7)
2014 4th Quarter Core Income (Loss)  $(7)
2013 Twelve Month Core Income  $869 
Price - Oil and NGLs   (394)
Price - Natural Gas   61 
Volume   168 
Production cost rate   (29)
DD&A rate   (32)
SG&A expense   (34)
Taxes other than on income   (32)
Interest expense   (72)
Income tax   140 
All Others   5 
2014 Twelve Month Core Income  $650 
Attachment 4
   Fourth Quarter  Twelve Months
($ millions)  2014  2013  2014   2013
Capital Investments: (a)             
Conventional  $335  $321  $ 1,376   $ 1,121
Unconventional   163   142    606     457
Exploration   21   26    100     91
Corporate and Other   1   -    7     -
   $520  $489  $ 2,089   $ 1,669
(a) The capital investments reported above include the cash outlays of each period and period-over-period accruals.
Attachment 5
   Fourth Quarter    Twelve Months
   2014  2013    2014  2013
Net Oil, Gas and Liquids Production Per Day              
Oil (MBbl/d)              
San Joaquin Basin  66  60    64  58
Los Angeles Basin  32  28    29  26
Ventura Basin  7  6    6  6
Sacramento Basin  -  -    -  -
Total  105  94    99  90
NGLs (MBbl/d)              
San Joaquin Basin  18  19    18  19
Los Angeles Basin  -  -    -  -
Ventura Basin  1  1    1  1
Sacramento Basin  -  -    -  -
Total  19  20    19  20
Natural Gas (MMcf/d)              
San Joaquin Basin  184  178    180  182
Los Angeles Basin  2  2    1  2
Ventura Basin  10  11    11  11
Sacramento Basin  52  65    54  65
Total  248  256    246  260
Total Barrels of Oil Equivalent (MBoe/d)  165  157    159  154
Attachment 6
   Fourth Quarter  Twelve Months
   2014  2013  2014  2013
Realized Prices            
Oil ($/Bbl)  68.54   99.32   92.30   104.16 
NGLs ($/Bbl)  34.41   57.73   47.84   50.43 
Natural gas ($/Mcf)  4.00   3.68   4.39   3.73 
Index Prices            
WTI oil ($/Bbl)  73.15   97.46   93.00   97.97 
Brent oil ($/Bbl)  76.98   109.35   99.51   108.76 
NYMEX gas ($/Mcf)  3.99   3.64   4.34   3.66 
Realized Prices as Percentage of Index Prices            
Oil as a percentage of WTI  94%  102%  99%  106%
Oil as a percentage of Brent  89%  91%  93%  96%
NGLs as a percentage of WTI  47%  59%  51%  51%
NGLs as a percentage of Brent  45%  53%  48%  46%
Natural gas as a percentage of NYMEX  100%  101%  101%  102%

Attachment 7


Anticipated Realizations Against the Prevailing Index Prices for Q1 2015
Oil   85% to 90% of Brent
NGLs   38% to 42% of Brent
Natural Gas   95% to 100 % of NYMEX
2015 First Quarter Production, Capital and Income Statement Guidance
Production   160 to 165 Mboe per day
Capital   $135 million to $150 million
Production costs   $17.00 to $17.50 per boe
Selling, general and administrative expenses   

$5.30 to $5.45 per boe

Depreciation, depletion and amortization   

$17.60 to $17.80 per boe

Taxes other than on income   

$55 million to $58 million

Exploration expense   

$21 million to $24 million

Interest expense   

$81 million to $84 million

Income tax expense rate   41%
Cash tax rate   0%
Pre-tax Quarterly Price Sensitivities   On Income (a)    On Cash (a)
$1 change in Brent index   $8 million    $8 million
$1 change in NGLs   $1 million    $1 million
$.50 change in NYMEX gas   

$5 million


$5 million

Quarterly Volumes Sensitivities         
$1 change in the Brent index (a)   125 Boe/d     

(a) Reflects the effect of production sharing type contracts in our Long Beach operations.

Attachment 8
   San Joaquin  Los Angeles  Ventura  Sacramento   

(As of December 31, 2014)

  Basin  Basin  Basin  Basin  Total
Oil Reserves (in millions of barrels)               
Proved Developed Reserves  229   


   34    -   


Proved Undeveloped Reserves  111   


   14    -   


Total  340   163   48    -   551
NGLs Reserves (in millions of barrels)               
Proved Developed Reserves  62   -   2    -   64
Proved Undeveloped Reserves  20   -   1    -   21
Total  82   -   3    -   85
Natural Gas Reserves (in billions of cubic feet)               
Proved Developed Reserves  458   11   28    110   607
Proved Undeveloped Reserves  163   5   9    6   183
Total  621   16   37    116   790
Total Reserves (in millions of barrels of oil equivalent)               
Proved Developed Reserves  367   126   41    18   552
Proved Undeveloped Reserves  158   40   17    1   216
Total  525   166   58    19   768

(For year ended December 31, 2014)

  Oil  NGLs  Gas  Total   
Reserves Replacement (in millions of BOE)               
Balance at December 31, 2013  532   71   141    744    
Improved recovery  85   13   19    117    
Extensions and discoveries  1   -   -    1    
Replacement from the capital program  86   13   19    118    
Purchases of proved reserves  6   -   -    6    
Revisions of previous estimates  (37)  8   (13)   (42)   
Net reserve additions from all sources  55   21   6    82    
Production  (36)  (7)  (15)   (58)   
Balance at December 31, 2014  551   85   132    768    
Cost Incurred from the Capital Program ($ millions)        $2,086    
Finding and Development Costs - Capital Program ($/BOE) (1)        $17.68    
Reserve Replacement Ratio from the Capital Program (2)         203%   

PV-10 and Standardized Measure

PV-10 of Proved Reserves (3)           $16.1 billion   
Standardized Measure           $10.8 billion   
(1)  Finding and Development costs for the capital program are calculated by dividing the costs incurred from the capital program (development and exploration costs) by the amount of proved reserves added in the same year from improved recovery and extensions and discoveries (excluding acquisitions and revisions). Our management believes that reporting our finding and development costs can aid evaluation of our ability to add proved reserves at a reasonable cost and is not a substitute for our 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. Our calculations of finding and development costs may not be comparable to similar measures provided by other companies.
(2)  The reserves replacement ratio is calculated for a specified period using the applicable proved oil-equivalent additions divided by oil-equivalent production. 76% of the additions are proved undeveloped. There is no guarantee that historical sources of reserves additions will continue as many factors fully or partially outside management's control, including the underlying geology, commodity prices and availability of capital, affect reserves additions. Management uses this measure to gauge results of its capital allocation. The measure is limited in that reserves may be added and produced based on costs incurred in separate periods and other oil and gas producers may use different replacement ratios affecting comparability.
(3)  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 reserve bases and the reserve 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.
Attachment 9
DRILLING ACTIVITY               
   San Joaquin  Los Angeles  Ventura  Sacramento   
Wells Drilled (Gross)  Basin  Basin  Basin  Basin  Total
Producer Wells               
Primary   67   -   -   3   70
Waterflood   53   123   1   -   177
Steamflood   419   -   20   -   439
Unconventional   183   -   -   -   183
Total   722   123   21   3   869
Injector Wells               
Primary   3   -   -   -   3
Waterflood   28   54   -   -   82
Steamflood   93   -   -   -   93
Unconventional   1   -   -   -   1
Total   125   54   -   -   179
Total Wells   847   177   21   3   1,048
Development Drilling Capital ($ millions)  $909  $338  $43  $7  $1,297



California Resources Corporation
Scott Espenshade (Investor Relations)
Margita Thompson (Media)