California Resources Corporation Announces First Quarter 2018 Results

Source Press Release
Company California Resources Corporation 
Tags Hedging, Production/Development, Upstream Activities, Strategy - Upstream, Strategy - Corporate, Financial & Operating Data
Date May 03, 2018

California Resources Corporation (NYSE:CRC), an independent California-based oil and gasexploration and production company, today reported a net loss attributable to common stock (CRC net loss) of $2 million, or $0.05 per diluted share, for the first quarter of 2018. Adjusted net income1 for the first quarter of 2018 was $8 million, or $0.18 per diluted share.

Adjusted EBITDAX1 for the first quarter of 2018 was $250 million and cash provided by operating activities was $200 million. Capital investments were $139 million.

Quarterly Highlights Include:

  • Produced 123,000 BOE per day, above the midpoint of the guidance range
  • Invested capital of $139 million
  • Drilled 44 wells with internally funded capital and 30 wells with joint venture (JV) capital
  • Generated adjusted EBITDAX1 of $250 million, reflecting an adjusted EBITDAX margin1 of 41%

2018 Outlook:

  • Increased 2018 capital budget to a range of $550 million to $600 million, with approximately $100 to $150 million funded by JV partners BSP and Macquarie
  • Incremental capital directed to drilling, workover and facilities projects in the San Joaquin, Los Angeles and Ventura basins
  • Second quarter of 2018 production guidance of 131,000 to 136,000 BOE per day, reflecting a 2,000 BOE per day negative impact due to production sharing contracts (PSC) effects utilizing first quarter of 2018 price levels
  • Second quarter of 2018 production forecast is flat with first quarter of 2018 production levels, adjusted for the PSC effect and excluding the Elk Hills acquisition production
  • Production from Elk Hills acquired interests for second quarter of 2018 projected at approximately 11,600 BOE per day, reflecting transition mechanics.
  • In the third quarter of 2018, the Company expects approximately 12,000 BOE per day contribution from acquired Elk Hills interests

Todd A. Stevens, CRC's President and Chief Executive Officer, said, "With our midstream joint venture and recent transaction to consolidate our interest in our flagship Elk Hills field, CRC is off to a strong start in 2018. Supported by increasing cash flow and a clear runway to execute, we are well-positioned for a mid-cycle commodity price environment. As our first quarter results and second quarter guidance show, we have confidence that we have arrested the decline in our production, excluding PSC impacts. We increased our capital program to target the next phase of development and further delineate growth areas. We will see associated production growth later this year and into 2019. Our top priorities remain centered on value-oriented growth and cash margin expansion, as we allocate capital to capture the full potential of our assets and deliver lasting value for our shareholders."

First Quarter 2018 Results

For the first quarter of 2018, the CRC net loss was $2 million, or $0.05 per diluted share, and adjusted net income1 was $8 million, or $0.18 per diluted share. Adjusted net income1 excluded $7 million of non-cash derivatives losses and a $2 million charge for severance costs.

Total daily production volumes averaged 123,000 barrels of oil equivalent (BOE) per day for the first quarter of 2018. Compared to the fourth quarter of 2017, first quarter production was reduced by 2,400 BOE per day due to PSC effects from higher prices. Excluding PSC effects, sequential production was essentially flat. For the first quarter of 2018, oil volumes averaged 77,000 barrels per day, NGL volumes averaged 16,000 barrels per day and gas volumes averaged 182,000 thousand cubic feet (MCF) per day. First quarter results reflect a residual 400 BOE per day negative impact due to the 2017 California wildfires and subsequent mudslides. The impact of PSC effect relative to guidance was a small negative amount.

Realized crude oil prices, including the effect of settled hedges, increased by $12.53 per barrel in the first quarter of 2018 to $62.77 per barrel from the prior year comparable period. Settled hedges decreased realized crude oil prices by $4.49 per barrel. Average realized NGL prices continued to be strong and registered $43.13 per barrel, reflecting a realized price that was 64% of Brent prices. Realized natural gas prices were $2.81 per MCF.

Production costs for the first quarter of 2018 were $212 million, essentially flat with the $211 million in the first quarter of 2017. On a per unit basis, first quarter production costs of $19.08 per BOE were higher than the comparable prior year period of $17.70 per BOE, due to lower production. First quarter unit production costs were lower than previously disclosed guidance levels, reflecting continued cost reductions and efficiency, as well as timing of activities, across most cost categories. The industry practice for reporting PSCs can result in higher production costs per barrel as gross field operating costs are matched with net production. Excluding the PSC effects, per unit production costs1 for the first quarter of 2018 would have been $17.47. General and administrative (G&A) expenses were $63 million for the first quarter of 2018, compared to $66 million in the fourth quarter of 2017 and consistent with the prior year comparable period. These costs were also lower than the guidance range for the period due to the timing of certain corporate expenses.

CRC reported taxes other than on income of $38 million, $5 million higher than the prior year period primarily due to the increase in market prices for greenhouse gas allowances, among other factors. Exploration expense of $8 million for the first quarter of 2018increased $2 million from the prior year comparable period, demonstrating the Company's commitment to the exploration opportunities within its large asset portfolio.

Capital investment in the first quarter of 2018 totaled $139 million, excluding JV capital. Approximately $94 million was directed to drilling and capital workovers.

Cash provided by operating activities was $200 million. CRC generated free cash flow1 of $61 million in the first quarter of 2018.

Operational Update

CRC operated an average of nine rigs during the first quarter of 2018 and drilled 74 wells with CRC and JV capital, consisting of 72 development wells (55 steamflood, 10 waterflood, one primary and six unconventional) and two exploration wells. Steamfloods and waterfloods have different production profiles and longer response times than typical conventional wells and, as a result, the full production contribution may not be experienced in the same year that the well is drilled. In the San Joaquin basin, CRC operated seven rigs and produced approximately 87,000 BOE per day for the first quarter. The Los Angeles basin had one rig directed toward waterflood projects, and contributed 24,000 BOE per day of production in the first quarter of 2018. Ventura basin activity included one rig focused on conventional projects and produced approximately 6,000 BOE per day for the first quarter of 2018. The California wildfires in December 2017 and subsequent mudslides negatively impacted Ventura basin production by approximately 400 BOE per day in the first quarter of 2018, in line with expectations incorporated into the Company's previous guidance. The related production effects have been resolved and should not affect second quarter production. CRC continues to focus on oil weighted projects, with no development drilling activity in the Sacramento basin at this time.

Elk Hills Transaction

As previously announced, on April 9, 2018 CRC consolidated its interest in the 47,000-acre Elk Hills field by acquiring the remaining working, surface and mineral interests from its long-time partner Chevron. CRC paid cash consideration of $460 million and issued 2.85 million of common shares for the assets. The effective date of the transaction was April 1, 2018. The acquisition includes Chevron's non-operated working interests ranging between 20% and 22% in different producing horizons. In the fourth quarter of 2017, the acquired interests produced an average of 12,700 BOE per day with 46% oil and 9% natural gas liquids. CRC expects to realize the full incremental production in the third quarter of 2018 after the effect of the initial transitional mechanics abate. The Company estimates these additional interests would have added approximately 64 million BOE of proved reserves at year-end 2017 of which approximately 75% are considered proved developed. Over the next two years, CRC estimates up to $20 million of annualized savings as it streamlines production facilities, operations and processes, and leverages Elk Hills' substantial infrastructure.

2018 Capital Budget

In conjunction with improved commodity prices and additional cash flow expected from the acquisition of the Elk Hills interests and synergies, CRC increased its 2018 capital program to a range from $550 million to $600 million, which includes approximately $100 to $150 million in JV capital. This is an increase from its previously stated budget range of $500 million to $550 million. The incremental investment should increase second half 2018 production over first half 2018 levels with a more meaningful effect in 2019. The additional capital will primarily be deployed to drilling, workover and facilities in the San Joaquin, Los Angeles and Ventura basins. Further, CRC expects funding of a third tranche of the BSP capital in the second quarter of 2018.

Debt Reduction Update

CRC continues to show its commitment to strengthening the balance sheet. In April, CRC repurchased a total of $95 million in aggregate principal amount of the Company's second lien notes for $79 million in cash.

Borrowing Base Redetermination

Effective May 1, 2018, CRC's borrowing base under its 2014 Credit Agreement was reaffirmed at $2.3 billion.

Hedging Update

CRC continues to opportunistically seek hedging transactions to protect its cash flow, operating margins and capital program while maintaining adequate liquidity. In the first and second quarters of 2019, CRC hedged approximately 35,000 and 20,000 barrels per day, respectively. The hedges generally form an effective floor at around $63 Brent with a portion of the hedge volumes continuing to provide CRC upside at prices above $67. For the third quarter of 2019, the Company has hedged 10,000 barrels per day providing an effective floor at $65 Brent or Brent plus $15 at prices below $50 Brent. At prices above $65 Brent, CRC continues to receive Brent pricing. See Attachment 8 for more details.

1 See Attachment 3 for explanations of how CRC calculates and uses the non-GAAP measures of adjusted EBITDAX, adjusted EBITDAX margin, PV-10, free cash flow, production costs (excluding the effects of production sharing-type contracts (PSC)) and adjusted net income (loss), and for reconciliations of the foregoing to their nearest GAAP measure as applicable. 

Conference Call Details

To participate in today’s conference call scheduled for 5:00 P.M. Eastern Daylight Time, either dial (877) 328-5505 (International calls please dial +1 (412) 317-5421) 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 supplemental slides for the conference call will be available online in the Investor Relations section of 

Attachment 1 
    First Quarter 
($ and shares in millions, except per share amounts)    2018    2017 
Statement of Operations Data:         
Revenues and Other         
Oil and gas sales    575      487   
Net derivative (losses) gains      (38      73   
Other revenue      72        30   
Total revenues and other (a)      609        590   
Costs and Other         
Production costs      212        211   
General and administrative expenses      63        63   
Depreciation, depletion and amortization      119        140   
Taxes other than on income      38        33   
Exploration expense             
Other expenses, net (a)      61        22   
Total costs and other      501        475   
Operating Income      108        115   
Non-Operating (Loss) Income         
Interest and debt expense, net      (92      (84 
Net gains on early extinguishment of debt      —         
Gains on asset divestitures      —        21   
Other non-operating expenses      (7      (4 
Income Before Income Taxes            52   
Income tax benefit      —        —   
Net Income            52   
Net (income) loss attributable to noncontrolling interest      (11       
Net (Loss) Income Attributable to Common Stock    (2    53   
Net (loss) income attributable to common stock per share - basic    (0.05    1.23   
Net (loss) income attributable to common stock per share - diluted    (0.05    1.22   
Adjusted net income (loss)        (43 
Adjusted net income (loss) per diluted share    0.18      (1.02 
Weighted-average common shares outstanding - basic      44.2        42.3   
Weighted-average common shares outstanding - diluted      44.2        42.6   
Adjusted EBITDAX    250      200   
Effective tax rate         
(a) We adopted the new revenue recognition standard on January 1, 2018 which required certain sales related costs to be reported as expense as opposed to being netted against revenue. The adoption of this standard does not affect net income. Results for reporting periods beginning after January 1, 2018 are presented under the new accounting standard while prior periods are not adjusted and continue to be reported under accounting standards in effect for the prior period. The increase in total revenues and other for the three months ended March 31, 2018 was $42 million. Under prior accounting standards total revenues and other would have been $567 million and other expenses, net would have been $19 million. 
Cash Flow Data:         
Net cash provided by operating activities    200      133   
Net cash used in investing activities    (138    —   
Net cash provided (used) by financing activities    412      (95 
Balance Sheet Data:    March 31,    December 31, 
    2018    2017 
Cash and cash equivalents    494      20   
Total current assets    949      483   
Total property, plant and equipment, net    5,714      5,696   
Current maturities of long-term debt    —      —   
Total current liabilities    806      732   
Long-term debt, principal amount    4,941      5,306   
Mezzanine equity    724      —   
Total equity    (654    (720 
Outstanding shares as of      45.3        42.9   

Attachment 2 
    First Quarter 
Net Oil, NGLs and Natural Gas Production Per Day    2018    2017 
Oil (MBbl/d)         
San Joaquin Basin    49    54 
Los Angeles Basin    24    27 
Ventura Basin     
Sacramento Basin    —    — 
Total    77    86 
NGLs (MBbl/d)         
San Joaquin Basin    15    15 
Los Angeles Basin    —    — 
Ventura Basin     
Sacramento Basin    —    — 
Total    16    16 
Natural Gas (MMcf/d)         
San Joaquin Basin    143    141 
Los Angeles Basin     
Ventura Basin     
Sacramento Basin    31    31 
Total    182    181 
Total Production (MBoe/d) (a)    123    132 
(a) Natural gas volumes have been converted to BOE based on the equivalence of energy content between six Mcf of natural gas and one Bbl of oil. Barrels of oil equivalence does not necessarily result in price equivalence. 

Attachment 3 
Our results of operations can include the effects of unusual, out-of-period and infrequent transactions and events affecting earnings that vary widely and unpredictably (in particular certain non-cash items such as derivatives gains and losses) in nature, timing, amount and frequency. Therefore, management uses a measure called adjusted net income (loss) which excludes those items. This measure is not meant to disassociate items from management's performance, but rather is 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) is not considered to be an alternative to net income (loss) reported in accordance with U.S. generally accepted accounting principles (GAAP). 
We define adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; other unusual, out-of-period and infrequent items and other non-cash items. We believe 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. A version of this measure is a material component of certain of our financial covenants under our 2014 revolving credit facility 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 table presents a reconciliation of the GAAP financial measure of net income (loss) attributable to common stock to the non-GAAP financial measure of Adjusted net income (loss): 
    First Quarter 
($ millions, except per share amounts)      2018        2017   
Net (loss) income attributable to common stock    (2    53   
Unusual, infrequent and other items:         
Non-cash derivative losses (gains), excluding noncontrolling interest            (75 
Early retirement and severance costs             
Gains on asset divestitures      —        (21 
Net gains on early extinguishment of debt      —        (4 
Other, net             
Total unusual and infrequent items      10        (96 
Adjusted net income (loss)        (43 
Net (loss) income attributable to common stock per share - basic    (0.05    1.23   
Net (loss) income attributable to common stock per share - diluted    (0.05    1.22   
Adjusted net income (loss) per diluted share    0.18      (1.02 
    First Quarter 
($ millions)      2018        2017   
Non-cash derivative (losses) gains, excluding noncontrolling interest    (7    75   
Non-cash derivative losses for noncontrolling interest      —        (1 
Net payments on settled derivatives      (31      (1 
Net derivative (losses) gains    (38    73   
    First Quarter 
($ millions)      2018        2017   
Net cash provided by operating activities    200      133   
Capital investment      (139      (50 
Free cash flow      61        83   
Changes in capital accruals            17   
Capitalized interest      (1      —   
Free cash flow, after working capital      65        100   
BSP funded capital investment      —        15   
Free cash flow, after working capital excluding BSP funded capital    65      115   
The following tables present a reconciliation of the GAAP financial measures of net income (loss) attributable to common stock and net cash provided (used) by operating activities to the non-GAAP financial measure of adjusted EBITDAX. 
    First Quarter 
($ millions)      2018        2017   
Net income        52   
Interest and debt expense, net      92        84   
Depreciation, depletion and amortization      119        140   
Exploration expense             
Unusual, infrequent and other items (b)      10        (96 
Other non-cash items      12        14   
Adjusted EBITDAX (A)    250      200   
Net cash provided by operating activities    200      133   
Cash interest      61        44   
Exploration expenditures             
Changes in operating assets and liabilities      (18      17   
Other, net             
Adjusted EBITDAX (A)    250      200   
(b) See Adjusted Net Income (Loss) reconciliation. 
    First Quarter 
($ millions)      2018        2017   
Total Revenues    609      590   
Non-cash derivative losses (gains)            (74 
Adjusted revenues (B)    616      516   
Adjusted EBITDAX Margin (A)/(B) (c)      41      39 
(c) See Note (a) on Attachment 1 related to our adoption of the new accounting standard related to the reporting of certain sales related costs. Under prior accounting standards our adjusted EBITDAX margin would have been 44% in the first quarter of 2018. 
    First Quarter 
($ per Boe)      2018        2017   
Production Costs    19.08      17.70   
Costs attributable to PSC type contracts      (1.61      (1.04 
Production Costs, excluding the effects of PSC type contracts    17.47      16.66   

Attachment 4 
($ millions) 
2017 1st Quarter Adjusted Net Loss    (43 
Price - Oil      100   
Price - NGLs      13   
Price - Natural Gas      (1 
Volume      (45 
Production cost      (1 
DD&A rate      14   
Exploration expense      (2 
Interest expense      (8 
All others      (19 
2018 1st Quarter Adjusted Net Income     

Attachment 5 
    First Quarter 
($ millions)    2018    2017 
Internally Funded Capital Investments    139    35 
BSP Funded Capital      —      15 
Consolidated Reported Capital    139    50 
MIRA Funded Capital      22      — 
Total Capital Program    161    50 
    First Quarter 
($ millions)    2018    2017 
Distributions to noncontrolling interest         
BSP Joint Venture    13    — 
Ares Joint Venture          — 
Total    18    — 

Attachment 6 
    First Quarter 
      2018        2017   
Realized Prices         
Oil with hedge ($/Bbl)    62.77      50.24   
Oil without hedge ($/Bbl)    67.26      50.40   
NGLs ($/Bbl)    43.13      34.33   
Natural gas ($/Mcf) (a)    2.81      2.90   
Index Prices         
Brent oil ($/Bbl)    67.18      54.66   
WTI oil ($/Bbl)    62.87      51.91   
NYMEX gas ($/MMBtu)    2.87      3.26   
Realized Prices as Percentage of Index Prices     
Oil with hedge as a percentage of Brent      93      92 
Oil without hedge as a percentage of Brent      100      92 
Oil with hedge as a percentage of WTI      100      97 
Oil without hedge as a percentage of WTI      107      97 
NGLs as a percentage of Brent      64      63 
NGLs as a percentage of WTI      69      66 
Natural gas as a percentage of NYMEX (a)      98      89 
(a) See Note (a) on Attachment 1 related to our adoption of the new accounting standard related to the reporting of certain sales related costs. Under prior accounting standards our natural gas realized price would have been $2.53 per Mcf and our realized price as a percentage of NYMEX would have been 88% in the first quarter of 2018. 

Attachment 7 
    San Joaquin    Los Angeles    Ventura    Sacramento     
Wells Drilled (Gross)    Basin    Basin    Basin    Basin    Total 
Development Wells                     
Primary      —    —    —   
Waterflood        —    —    10 
Steamflood    55    —    —    —    55 
Unconventional      —    —    —   
Total    67      —    —    72 
Exploration Wells                     
Primary      —      —   
Waterflood    —    —    —    —    — 
Steamflood    —    —    —    —    — 
Unconventional    —    —    —    —    — 
Total      —      —   
Total Wells (a)    68        —    74 
CRC Wells Drilled    38        —    44 
MIRA Wells Drilled    30    —    —    —    30 
(a) Includes steam injectors and drilled but uncompleted wells, which would not be included in the SEC definition of wells drilled. 

Attachment 8 
HEDGES - CURRENT                                 
    2Q    3Q    4Q    1Q    2Q    3Q    4Q    FY 
    2018    2018    2018    2019    2019    2019    2019    2020 
Crude Oil                                 
Sold Calls:                                 
Barrels per day    6,168    6,127    16,086    16,057    6,023    991    961    503 
Weighted-average Brent price per barrel    $60.24    $60.24    $58.91    $65.75    $67.01    $60.00    $60.00    $60.00 
Purchased Calls:                                 
Barrels per day    —    —    —    2,000    —    —    —    — 
Weighted-average Brent price per barrel    $—    $—    $—    $71.00    $—    $—    $—    $— 
Purchased Puts:                                 
Barrels per day    1,168    6,127    1,086    29,057    21,023    10,991    961    503 
Weighted-average Brent price per barrel    $45.83    $61.47    $45.85    $60.86    $62.40    $63.27    $45.85    $43.91 
Sold Puts:                                 
Barrels per day    29,000    24,000    19,000    30,000    15,000    10,000    —    — 
Weighted-average Brent price per barrel    $45.00    $46.04    $45.00    $49.17    $50.00    $50.00    $—    $— 
Barrels per day    44,350    19,000    19,000    7,000    —    —    —    — 
Weighted-average Brent price per barrel    $60.00    $60.13    $60.13    $67.71    $—    $—    $—    $— 
A small portion of the derivatives in the table above were entered into by the BSP JV, including all of the 2020 positions. The BSP JV also entered into natural gas swaps for insignificant volumes for periods through July 2020. 
Certain of our counterparties have options to increase swap volumes by up to: 
- 29,000 barrels per day at a weighted-average Brent price of $60.50 for the second half of 2018 and 
- 5,000 barrels per day at a weighted-average Brent price of $70.00 for the first quarter of 2019. 

Attachment 9 
Anticipated Realizations Against the Prevailing Index Prices for Q2 2018 (a) 
Oil    94% to 98% of Brent 
NGLs    52% to 56% of Brent 
Natural Gas    81% to 85% of NYMEX 
2018 Second Quarter Production, Capital and Income Statement Guidance 
Production at current prices (b)    131 to 136 MBOE per day 
Production at average Q1 2018 Brent of $67    133 to 138 MBOE per day 
Capital    $165 million to $185 million 
Production costs at current prices (b)    $18.10 to $19.60 per BOE 
Production costs at average Q1 2018 Brent of $67    $17.90 to $19.40 per BOE 
Adjusted general and administrative expenses (b) & (c)    $6.45 to $6.75 per BOE 
Depreciation, depletion and amortization (b)    $10.30 to $10.60 per BOE 
Taxes other than on income    $34 million to $38 million 
Exploration expense    $7 million to $11 million 
Interest expense (d)    $91 million to $95 million 
Cash Interest (d)    $150 million to $154 million 
Income tax expense rate    0% 
Cash tax rate    0% 
Pre-tax 2018 Second Quarter Price Sensitivities (e)     
$1 change in Brent index - Oil (f)    $2.2 million 
$1 change in Brent index - NGLs    $0.8 million 
$0.50 change in NYMEX - Gas    $4.3 million 
(a) Realizations exclude hedge effects. 
(b) Based on assumed average Q2 2018 Brent price of $74. 
(c) Our long-term incentive compensation program for non-executive employees are stock based but payable in cash. Accounting rules require that we adjust the cumulative liability for all vested but yet unpaid awards under these programs to the amount that would be paid using our stock price as of the end of each quarter. Therefore, in addition to the normal pro-rata vesting expense associated with these programs, our quarterly G&A expense includes this cumulative adjustment. Our stock price at March 31, 2018 was $17.15 per share. Our guidance reflects what the effect of such cumulative adjustment will be assuming that our current stock price of approximately $25 per share will prevail at the end of the second quarter. Only about 1/3 of such cumulative adjustment would result in a cash liability in the same year as the adjustment because of the pro-rata three year vesting of our incentive compensation programs. 
(d) Interest expense includes cash interest, original issue discount and amortization of deferred financing costs as well as the deferred gain that resulted from the December 2015 debt exchange. Cash interest for the quarter is higher than interest expense due to the timing of interest payments. 
(e) Due to our tax position there is no difference between the impact on our income and cash flows. 
(f) Amount reflects the sensitivity with respect to unhedged barrels at a Brent index price exceeding $60.00 per barrel and includes the effect of production sharing type contracts at our Wilmington field operations in Long Beach. 


Source: EvaluateEnergy® ©2020 EvaluateEnergy Ltd