California Resources Corporation Announces Fourth Quarter 2017 and Year end Results

Source Press Release
Company California Resources Corporation 
Tags Production/Development, Hedging, Reserve Update, Upstream Activities, Financial & Operating Data
Date February 26, 2018

California Resources Corporation (NYSE:CRC) (the Company), an independent California-based oil and gas exploration and production company, today reported a net loss attributable to common stock (CRC net loss) of $138 million, or $3.23 per diluted share, for the fourth quarter of 2017. The adjusted net loss1 for the fourth quarter of 2017 was $14 million, or $0.33 per diluted share. For the full year of 2017, the CRC net loss was $266 million, or $6.26 per diluted share. The adjusted net loss1 for the full year of 2017 was $187 million, or $4.40 per diluted share.

Adjusted EBITDAX1 for the fourth quarter of 2017 was $222 million and $761 million for the full year of 2017. Cash provided by operating activities was $23 million for the fourth quarter of 2017 and $248 million for the full year of 2017. Capital investments for the fourth quarter of 2017 were $139 million and $371 million for the full year of 2017, of which $14 million was funded by CRC's joint venture (JV) partner Benefit Street Partners (BSP) in the fourth quarter and $96 million for the full year. For the full year of 2017, CRC was free cash flow1 neutral after working capital and excluding capital that was funded by BSP.

Quarterly Highlights Include:

  • Produced 126,000 BOE per day
  • Invested capital of $139 million, of which JV partner BSP funded $14 million
  • Drilled 37 wells with internally funded capital and 44 wells with BSP and Macquarie Infrastructure and Real Assets (MIRA) capital
  • Generated adjusted EBITDAX1 of $222 million, reflecting an adjusted EBITDAX margin1 of 39%

Full Year Highlights Include:

  • Proved reserves of 618 MMBOE, organically replacing 119% of reserves from the capital program, excluding price revisions
  • Organic F&D costs of $6.82 per BOE, excluding price revisions
  • Invested capital of $371 million, of which JV partner BSP funded $96 million
  • Drilled 110 wells with internally funded capital and 119 wells with BSP and MIRA funded capital
  • Generated adjusted EBITDAX1 of $761 million, reflecting an adjusted EBITDAX margin1 of 36%

1 See Attachment 2 for explanations of how CRC calculates and uses the non–GAAP measures of adjusted EBITDAX, adjusted EBITDAX margin, PV-10, adjusted general and administrative expenses, free cash flow, production costs (excluding the effects of production sharing-type contracts (PSC)) and adjusted net loss, and for reconciliations of the foregoing to their nearest GAAP measure as applicable. VCI is calculated by dividing the net present value of the project's expected pre-tax cash flow over its life by the net present value of the related investments, each using a 10 percent discount rate.

Todd Stevens, CRC's President and Chief Executive Officer, said, "In 2017, we followed a strategic plan to focus on projects that offered the best value creation, to live within cash flow and to emphasize disciplined growth, and I am pleased to report that we delivered on all fronts. We replaced 119% of our production, despite a limited capital program. We leveraged our portfolio flexibility through JV partnerships to accelerate and de-risk our actionable inventory. As we have done every year since our inception, we continued to live within our cash flow, investing approximately $240 million of CRC development capital in 2017 with a VCI1 of 1.7 or fully-burdened returns of 30%. In addition, we took steps to meaningfully strengthen our financial position with a new credit amendment that provides a clear runway and a path to further de-lever. In 2018, we expect to build upon this solid momentum as we extend our track record of disciplined execution into a mid-cycle commodity environment and capture the significant upside that lies ahead. By remaining dedicated to our strategy centered on optimizing CRC’s world-class resources, driving operational execution and strengthening our balance sheet, we expect to deliver meaningful value creation for our shareholders in 2018 and beyond."

Fourth Quarter 2017 Results

For the fourth quarter of 2017, the CRC net loss was $138 million, or $3.23 per diluted share, and the adjusted net loss1 was $14 million or $0.33 per diluted share. The adjusted net loss1 excluded $116 million of non-cash derivatives losses and a net $8 million charge for other unusual and infrequent items.

Total daily production volumes averaged 126,000 barrels of oil equivalent (BOE) per day for the fourth quarter of 2017. Oil volumes averaged 80,000 barrels per day, NGL volumes averaged 16,000 barrels per day and gas volumes averaged 179,000 thousand cubic feet (MCF) per day. These results reflect approximately 1,300 BOE per day of negative PSC effects due to higher realized prices in the fourth quarter compared to expected prices, as well as a 700 BOE per day quarterly impact due to the California wildfires that occurred in December 2017.

Realized crude oil prices, including the effect of settled hedges, increased by $11.44 per barrel to $56.92 per barrel from the prior year comparable period. Settled hedges decreased realized crude oil prices by $2.95 per barrel. Average realized NGL prices registered $44.03 per barrel and realized natural gas prices were $2.77 per MCF.

Production costs for the fourth quarter of 2017 were $227 million, or $19.64 per BOE, compared to $17.50 per BOE in the prior year comparable period. 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 fourth quarter of 2017 would have been $18.31. The increase in unit based production costs was driven by an increase in energy costs, a ramp-up of downhole maintenance activity in line with stronger commodity prices and lower production volumes, but was partially offset by a more efficient use of energy. General and administrative (G&A) expenses were $68 million for the fourth quarter of 2017. Adjusted general and administrative expenses1 for the fourth quarter of 2017 were $67 million compared to $61 million in the prior year comparable period. The increase in adjusted G&A expenses1 was a result of the timing of grants coupled with the higher costs of performance-based bonus and incentive compensation plans due to better than expected results.

CRC reported taxes other than on income of $33 million and exploration expense of $5 million for the fourth quarter of 2017.

Capital investment in the fourth quarter of 2017 totaled $139 million, consisting of $125 million of internally funded capital and $14 million of BSP funded capital. Approximately $95 million was directed to drilling and capital workovers.

Cash provided by operating activities was $23 million.

Full Year 2017 Results

For the full year of 2017, the CRC net loss was $266 million, or $6.26 per diluted share. The adjusted net loss1 was $187 million, or $4.40 per diluted share, which excluded $78 million of non-cash derivative losses, $21 million of gains from asset divestitures, $4 million of net gains on early retirement of debt and a $26 million net charge from other unusual and infrequent items.

Total daily production volumes averaged 129,000 BOE per day for the full year of 2017. Oil volumes averaged 83,000 barrels per day, NGL volumes averaged 16,000 barrels per day, and gas volumes averaged 182,000 MCF per day.

Realized crude oil prices, including the effect of settled hedges, increased $9.23 per barrel to $51.24 per barrel from $42.01 per barrel in 2016. Settled hedges decreased 2017 realized crude oil prices by $0.23 per barrel compared with a $2.29 per barrel increase in 2016. Realized NGL prices increased 60% to $35.76 from $22.39 per barrel in 2016. Realized natural gas prices increased 17% to $2.67 per MCF compared with $2.28 per MCF in 2016.

Production costs for the full year of 2017 were $876 million, or $18.64 per BOE. Per unit production costs, excluding the effect of PSCs1, were $17.48 per BOE. The increase in production costs of $76 million from the prior year was driven by an increase in energy costs and a ramp-up of downhole and surface maintenance activity in line with stronger commodity prices, but were partially offset by a more efficient use of energy. While higher natural gas prices increase CRC's production costs for power and steam generation, they result in a net benefit due to higher revenue generated from natural gas sales. G&A expenses were $259 million for the full year of 2017. Adjusted G&A expenses1 for the full year of 2017 were $254 million compared to $228 million in 2016. The increase in adjusted G&A expenses1was a result of the timing of grants coupled with the higher costs of performance-based bonus and incentive compensation plans due to better than expected results.

CRC reported taxes other than on income of $136 million and exploration expense of $22 million for the full year of 2017.

Capital investment in 2017 totaled $371 million, consisting of $275 million of CRC internally funded capital and $96 million of BSP funded capital. Approximately $266 million was directed to drilling and capital workovers. The Company's MIRA joint venture funded an additional $58 million of investment.

Cash provided by operating activities for the full year of 2017 was $248 million. The Company was free cash flow1 neutral after working capital and excluding capital that was funded by BSP.

Operational Update

CRC operated an average of nine rigs during the fourth quarter of 2017 and drilled 81 wells, including those drilled with BSP and MIRA capital, which consisted of 75 development wells (36 steamflood, 25 waterflood, 13 primary and one unconventional) and six exploration wells (five steamflood and one primary). Most of the drilling activity was directed toward steamfloods and waterfloods, which have different production profiles and longer response times than typical conventional wells. As a result, the full production contribution is not typically experienced in the same year that the well is drilled. In the San Joaquin basin, CRC operated seven rigs and produced approximately 88 MBOE per day for the fourth quarter. The Los Angeles basin had one rig directed toward waterflood projects, and contributed 26 MBOE per day of production in the fourth quarter of 2017. The impact of the production sharing agreements in Long Beach decreased production by 1,300 BOE per day in the fourth quarter due to fewer cost-recovery barrels as a result of higher oil prices than initially expected. The Ventura basin activity included one rig focused on conventional projects and produced approximately 6,000 BOE per day for the fourth quarter. The California wildfires negatively impacted production by approximately 2,200 BOE per day in December 2017 and production remained affected by approximately 1,200 BOE per day in January 2018 due to third party power and access issues related to the fires and subsequent mudslides. First quarter of 2018 production guidance reflects a 400 BOE per day reduction primarily due to these issues, a 600 BOE per day impact for PSC effects, as well as other factors. CRC had no development drilling activity in the Sacramento basin and continues to focus on oil weighted projects.

Balance Sheet Strengthening Update

During February 2018, CRC entered into a midstream joint venture with an affiliate of Ares Management, L.P. For more details on the transaction, please see CRC's press release and Form 8-K dated February 7, 2018.

Year-End 2017 Reserves and PV-10 Value1

CRC's proved reserves totaled 618 MMBOE as of the end of 2017, up from 568 MMBOE at year-end 2016. Excluding positive price revisions, the Company organically replaced 119% of proved reserves. This strong reserve replacement ratio (RRR)** was achieved with a limited, well executed capital program for the year, in addition to positive performance revisions primarily in Huntington Beach and Buena Vista Area. A total of approximately 34 MMBOE of additions were related to extensions and discoveries in several CRC fieldsand another 22 MMBOE was added through positive performance revisions. All-in 2017 Finding and Development (F&D) costs were $3.94 per BOE in 2017, including price revisions. Organic F&D costs were $6.82 per BOE in 2017, which exclude price revisions.

Summary of Changes in Proved Reserves Based on the SEC Price Deck* (Million BOE)

       
Balance at December 31, 2016    568   
     
Revisions Related to Performance    22   
Extensions and Discoveries    34   
Sales    (8 
Revisions Related to Price    49   
Production    (47 
     
Balance at December 31, 2017    618   
     
2017 Organic Finding and Development Cost**    6.82   

*Calculated using the first-day-of-the-month twelve-month average Brent oil price of $54.42 per barrel and NYMEX natural gas price of $2.98 per Million British Thermal Units (MMBTU), before adjustments for gravity, quality and transportation costs, in accordance with Securities and Exchange Commission (SEC) rules and regulations.
** See calculation of RRR and F&D on Attachment 3.

The present value of CRC's proved reserves as of December 31, 2017 was approximately $4.5 billion on a pre-tax basis, discounted at 10% (PV-101).

2018 Capital Budget

With stronger expected cash flows, CRC estimates its 2018 capital program will range from $425 million to $450 million, which includes approximately $100 to $150 million in JV capital. CRC's 2018 capital program may grow further through the use of cash on the balance sheet, additional tranches from existing JVs as well as potential new JVs. CRC’s direct investment level will be largely directed to waterflood and steamflood investments which will drive enhanced production into 2019.

Credit Facility Amendment

CRC entered into its seventh amendment of the 2014 Credit Facility in November 2017. This amendment received unanimous approval from all 29 lenders and financial institutions and became effective after the closing of a new $1.3 billion first lien secured term loan facility (“2017 Term Loan”). Net proceeds were used to pay the $559 million remaining balance of the 2014 Term Loan, reduce the balance of the 2014 Revolving Credit Facility and pay accrued interest. The amendment extended the maturity date of the 2014 Revolving Credit Facility to June 30, 2021 and modified some of its covenants. Subsequent to the amendment, CRC was able to eliminate the springing maturity features related to the 5% notes due January 15, 2020 and the 5 ½% notes due September 15, 2021 by buying back $65 million of principal of the 5% Notes and $35 million in principal of the 5 ½% Notes. For more details on the amendment, please see the Company's Form 8-K disclosure dated November 17, 2017.

Conference Call Details

To participate in today’s conference call scheduled for 5:00 P.M. Eastern Standard 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 
SUMMARY OF RESULTS                         
    Fourth Quarter      Twelve Months   
($ and shares in millions, except per share amounts)    2017      2016      2017      2016   
                         
Statement of Operations Data:                         
Revenues and Other                         
Oil and gas net sales    549      464      1,936      1,621   
Net derivative losses    (141    (49    (90    (206 
Other revenue    47      37      160      132   
Total revenues and other    455      452      2,006      1,547   
                         
Costs and Other                         
Production costs    227      217      876      800   
General and administrative expenses    68      62      259      248   
Depreciation, depletion and amortization    132      137      544      559   
Taxes other than on income    33      26      136      144   
Exploration expense        10      22      23   
Other expenses, net    30          106      79   
Total costs and other    495      455      1,943      1,853   
                         
Operating (Loss) Income    (40    (3    63      (306 
                         
Non-Operating (Loss) Income                         
Interest and debt expense, net    (91    (85    (343    (328 
Net gains on early extinguishment of debt    —      12          805   
(Losses) gains on asset divestitures    —      (1    21      30   
Other non-operating expense    (4    —      (7    —   
                         
(Loss) Income Before Income Taxes    (135    (77    (262    201   
Income tax benefit    —      —      —      78   
Net (Loss) Income    (135    (77    (262    279   
Net income attributable to noncontrolling interest    (3    —      (4    —   
Net (Loss) Income Attributable to Common Stock    (138    (77    (266    279   
                         
Net (loss) income attributable to common stock per share - basic and diluted    (3.23    (1.83    (6.26    6.76   
                         
Adjusted net loss    (14    (74    (187    (317 
Adjusted net loss per diluted share    (0.33    (1.76    (4.40    (7.85 
                         
Weighted-average common shares outstanding - diluted    42.7      42.1      42.5      40.4   
                         
Adjusted EBITDAX    222      168      761      616   
Effective tax rate          (39  )% 
                         
Cash Flow Data:                         
Net cash provided (used) by operating activities    23      (15    248      130   
Net cash used in investing activities    (139    (30    (313    (61 
Net cash provided (used) by financing activities    108      47      73      (69 
                         
Balance Sheet Data:    December 31,      December 31,               
    2017      2016               
Total current assets    483      425               
Total property, plant and equipment, net    5,696      5,885               
Current maturities of long-term debt    —      100               
Other current liabilities    732      626               
Long-term debt, principal amount    5,306      5,168               
Total equity    (720    (557             
                         
Outstanding shares as of    42.9      42.5         

The following table presents a reconciliation of the GAAP financial measure of net income (loss) attributable to common stock to the non-GAAP financialmeasure of adjusted net loss: 
    Fourth Quarter    Twelve Months 
($ millions, except per share amounts)    2017    2016    2017    2016 
Net (loss) income attributable to common stock    (138    (77    (266    279   
Unusual and infrequent items:                 
Non-cash derivative losses (gains), excluding noncontrolling interest    116      40      78      283   
Early retirement, severance and other costs                20   
Losses (gains) on asset divestitures    —          (21    (30 
Net gains on early extinguishment of debt    —      (12    (4    (805 
Other        (27    21      (13 
Total unusual and infrequent items    124          79      (545 
                 
Deferred debt issuance costs write-off    —      —      —      12   
Reversal of valuation allowance for deferred tax assets (a)    —      —      —      (63 
Adjusted net loss    (14    (74    (187    (317 
                 
Net (loss) income attributable to common stock per diluted share    (3.23    (1.83    (6.26    6.76   
Adjusted net loss per diluted share    (0.33    (1.76    (4.40    (7.85 
   
(a) Amount represents the out-of-period portion of the valuation allowance reversal. 
           
DERIVATIVES GAINS AND LOSSES           
    Fourth Quarter    Twelve Months 
($ millions)    2017    2016    2017    2016 
Non-cash derivative losses, excluding noncontrolling interest    (116    (40    (78    (283 
Non-cash derivative losses for noncontrolling interest    (3    —      (5    —   
Cash (payments) proceeds from settled derivatives    (22    (9    (7    77   
Net derivative losses    (141    (49    (90    (206 
                 
                 
FREE CASH FLOW           
    Fourth Quarter    Twelve Months 
($ millions)    2017    2016    2017    2016 
                 
Net cash provided (used) by operating activities    23      (15    248      130   
Capital investment    (139    (31    (371    (75 
Changes in capital accruals        (1    27      (6 
Free cash flow, after working capital    (115    (47    (96    49   
BSP funded capital investment    14      —      96      —   
Free cash flow, excluding BSP funded capital    (101    (47    —      49   
                 
         
ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES           
    Fourth Quarter    Twelve Months 
($ millions)    2017    2016    2017    2016 
                 
General and administrative expenses    68      62      259      248   
Early retirement and severance costs    (1    (1    (5    (20 
Adjusted general and administrative expenses    67      61      254      228   
                 
ADJUSTED EBITDAX           
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: 
             
    Fourth Quarter    Twelve Months 
($ millions)    2017    2016    2017    2016 
Net (loss) income attributable to common stock    (138    (77    (266    279   
Interest and debt expense, net    91      85      343      328   
Income tax benefit    —      —      —      (78 
Depreciation, depletion and amortization, excluding noncontrolling interest    129      137      535      559   
Exploration expense        10      22      23   
Unusual and infrequent items (c)    124          79      (545 
Other non-cash items    11      10      48      50   
Adjusted EBITDAX (A)    222      168      761      616   
                 
Net cash provided (used) by operating activities    23      (15    248      130   
Cash interest    145      140      396      384   
Exploration expenditures            20      20   
Changes in operating assets and liabilities    43      63      76      95   
Other, net        (27    21      (13 
Adjusted EBITDAX (A)    222      168      761      616   
                 
(c) See Adjusted Net Loss reconciliation. 
                 
ADJUSTED EBITDAX MARGIN           
    Fourth Quarter    Twelve Months 
($ millions)    2017    2016    2017    2016 
Total Revenues    455      452      2,006      1,547   
Non-cash derivative losses    119      40      83      283   
Adjusted revenues (B)    574      492      2,089      1,830   
Adjusted EBITDAX Margin (A)/(B)    39    34    36    34 
                         
                         
PRODUCTION COSTS PER BOE                   
      Fourth Quarter    Twelve Months 
($ per BOE)      2017    2016    2017    2016 
Production Costs    19.64      17.50      18.64      15.61   
Costs attributable to PSC type contracts      (1.33    (1.21    (1.16    (0.92 
Production Costs, excluding the effects of PSC type contracts    18.31      16.29      17.48      14.69   
                                 

         
PV-10 AND STANDARDIZED MEASURE         
The following table presents a reconciliation of the GAAP financial measure of standardized measure of discounted future net cash flows to the non-GAAP financial measure of PV-10: 
         
($ millions)        2017 
Standardized measure of discounted future net cash flows    3,765 
Present value of future income taxes discounted at 10%    780 
PV-10 of proved reserves (1)        4,545 
         
 
 
Attachment 3 
   
Organic Reserve Replacement Ratio (1)    2017   
Organic proved reserves added - MMBOE         
Extensions and discoveries    34     
Revisions related to performance    22     
Total (A)    56     
         
Production in 2017 - MMBOE (B)    47     
Organic reserve replacement ratio (A)/(B)    119   
         
(1) The organic reserve replacement ratio is calculated for a specified period using the proved oil-equivalent additions from extensions and discoveries and performance-related revisions, divided by oil-equivalent production. There is no guarantee that historical sources of reserves additions will continue as many factors fully or partially outside management's control, including commodity prices, availability of capital and the underlying geology, affect reserves additions. Management uses this measure to gauge the results of its capital program. Other oil and gas producers may use different methods to calculate replacement ratios, which may affect comparability. 
         
         
Finding and Development Costs(2)    2017   
Costs incurred - in millions (A)    382     
         
Organic proved reserves added - MMBOE (B)    56     
Organic finding and development costs - $/BOE (A)/(B)    6.82    (3) 
         
Proved reserves added including price related revisions, net - MMBOE (C)    97     
All in finding and development costs - $/BOE (A)/(C)    3.94    (4) 
         

.

Attachment 4 
ADJUSTED NET INCOME / (LOSS) VARIANCE ANALYSIS 
($ millions)     
     
2016 4th Quarter Adjusted Net Loss    (74 
     
Price - Oil    93   
Price - NGLs    21   
Price - Natural Gas    —   
Volume    (31 
Production cost    (10 
DD&A    (3 
Exploration expense     
Interest expense    (6 
Adjusted general & administrative expenses    (6 
All others    (3 
     
2017 4th Quarter Adjusted Net Loss    (14 
     
     
2016 Twelve-Month Adjusted Net Loss    (317 
     
Price - Oil    308   
Price - NGLs    78   
Price - Natural Gas    29   
Volume    (136 
Production cost    (76 
DD&A    (30 
Exploration expense     
Interest expense    (27 
Adjusted general & administrative expenses    (26 
Income tax    (15 
All others    24   
     
2017 Twelve-Month Adjusted Net Loss    (187 
         

 
Attachment 5 
CAPITAL INVESTMENTS                 
    Fourth Quarter    Twelve Months 
($ millions)    2017    2016    2017    2016 
                 
Internally Funded Capital Investments    125      31      275      75 
                 
BSP Funded Capital    14      —      96      — 
                 
Consolidated Reported Capital    139      31      371      75 
                 
MIRA Funded Capital    20      —      58      — 
                 
Total Capital Program    159      31      429      75 
                               

                 
                Attachment 6 
PRODUCTION STATISTICS                 
         
    Fourth Quarter    Twelve Months 
Net Oil, NGLs and Natural Gas Production Per Day    2017    2016    2017    2016 
                 
Oil (MBbl/d)                 
San Joaquin Basin    50      55      52      57 
Los Angeles Basin    26      27      27      29 
Ventura Basin               
Sacramento Basin    —      —      —      — 
Total    80      87      83      91 
                 
NGLs (MBbl/d)                 
San Joaquin Basin    15      14      15      15 
Los Angeles Basin    —      —      —      — 
Ventura Basin               
Sacramento Basin    —      —      —      — 
Total    16      15      16      16 
                 
Natural Gas (MMcf/d)                 
San Joaquin Basin    138      152      140      150 
Los Angeles Basin               
Ventura Basin               
Sacramento Basin    33      34      33      36 
Total    179      195      182      197 
                 
Total Production (MBoe/d) (a)    126      135      129      140 
                 
                 
(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 7 
PRICE STATISTICS                 
    Fourth Quarter    Twelve Months 
    2017    2016    2017    2016 
Realized Prices                 
Oil with hedge ($/Bbl)    56.92      45.48      51.24      42.01   
Oil without hedge ($/Bbl)    59.87      46.60      51.47      39.72   
                 
NGLs ($/Bbl)    44.03      28.99      35.76      22.39   
                 
Natural gas ($/Mcf)    2.77      2.79      2.67      2.28   
                 
Index Prices                 
Brent oil ($/Bbl)    61.54      51.13      54.82      45.04   
WTI oil ($/Bbl)    55.40      49.29      50.95      43.32   
NYMEX gas ($/MMBtu)    3.00      2.95      3.09      2.42   
                 
Realized Prices as Percentage of Index Prices 
Oil with hedge as a percentage of Brent    92    89    93    93 
Oil without hedge as a percentage of Brent    97    91    94    88 
                 
Oil with hedge as a percentage of WTI    103    92    101    97 
Oil without hedge as a percentage of WTI    108    95    101    92 
                 
NGLs as a percentage of Brent    72    57    65    50 
NGLs as a percentage of WTI    79    59    70    52 
                 
Natural gas as a percentage of NYMEX    92    95    86    94 
                         

                     
                    Attachment 8 
FOURTH QUARTER DRILLING ACTIVITY                     
    San Joaquin    Los Angeles    Ventura    Sacramento     
Wells Drilled (Gross)    Basin    Basin    Basin    Basin    Total 
                     
Development Wells                     
Primary    11    —      —    13 
Waterflood    20      —    —    25 
Steamflood    36    —    —    —    36 
Unconventional      —    —    —   
Total    68        —    75 
                     
Exploration Wells                     
Primary    —    —    —     
Waterflood    —    —    —    —    — 
Steamflood      —    —    —   
Unconventional    —    —    —    —    — 
Total      —    —     
                     
Total Wells    73          81 
                     
CRC Wells Drilled (a)    29          37 
                     
BSP Wells Drilled (a)    20    —    —    —    20 
                     
MIRA Wells Drilled    24    —    —    —    24 
                     
(a) Includes steam injectors and drilled but uncompleted wells, which would not be included in the SEC definition of wells drilled. 
 

                     
                    Attachment 9 
FULL YEAR DRILLING ACTIVITY                     
    San Joaquin    Los Angeles    Ventura    Sacramento     
Wells Drilled (Gross)    Basin    Basin    Basin    Basin    Total 
                     
Development Wells                     
Primary    28    —      —    30 
Waterflood    50    16    —    —    66 
Steamflood    115    —    —    —    115 
Unconventional    12    —    —    —    12 
Total    205    16      —    223 
                     
Exploration Wells                     
Primary    —    —    —     
Waterflood    —    —    —    —    — 
Steamflood      —    —    —   
Unconventional    —    —    —    —    — 
Total      —    —     
                     
Total Wells    210    16        229 
                     
CRC Wells Drilled (a)    91    16        110 
                     
BSP Wells Drilled (a)    45    —    —    —    45 
                     
MIRA Wells Drilled    74    —    —    —    74 
                     
(a) Includes steam injectors, water injectors and drilled but uncompleted wells, which would not be included in the SEC definition of wells drilled. 
 

 
Attachment 10 
HEDGES - CURRENT                             
                             
    1Q    2Q    3Q    4Q    1Q    2Q - 4Q    FY 
    2018    2018    2018    2018    2019    2019    2020 
Crude Oil                             
Sold Calls:                             
Barrels per day      9,000      6,200      16,100      16,100      1,100      1,000      500 
Weighted-average Brent price per barrel    59.58    60.24    58.91    58.91    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      1,200      1,200      6,100      1,100      14,100      1,000      500 
Weighted-average Brent price per barrel    45.82    45.83    61.48    45.85    58.93    45.85    43.91 
                             
Sold Puts:                             
Barrels per day      29,000      29,000      24,000      19,000      10,000      —      — 
Weighted-average Brent price per barrel    45.00    45.00    46.04    45.00    47.50    —    — 
                             
Swaps:                             
Barrels per day      38,300      34,000      19,000      19,000      7,000      —      — 
Weighted-average Brent price per barrel    60.03    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 some of the 2019 and all of the 2020 positions. The BSP JV also entered into natural gas swaps for insignificant volumes for the period of February 2018 to July 2020. 
 
 
Certain of our counterparties have options to increase swap volumes by up to: 
 
- 19,000 barrels per day at a weighted-average Brent price of $60.00 for the second quarter of 2018; 
- 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 11 
RESERVES                     
    San Joaquin    Los Angeles    Ventura    Sacramento     
As of December 31, 2017    Basin    Basin    Basin    Basin    Total 
Oil Reserves (in millions of barrels)                     
Proved Developed Reserves    176    104    24    —    304 
Proved Undeveloped Reserves    89    39    10    —    138 
Total    265    143    34    —    442 
                     
NGLs Reserves (in millions of barrels)                     
Proved Developed Reserves    43    —      —    45 
Proved Undeveloped Reserves    13    —    —    —    13 
Total    56    —      —    58 
                     
Natural Gas Reserves (in billions of cubic feet)                     
Proved Developed Reserves    447      20    70    543 
Proved Undeveloped Reserves    138        15    163 
Total    585    10    26    85    706 
                     
Total Reserves (in millions of barrels of oil equivalent)*                     
Proved Developed Reserves    294    105    29    12    440 
Proved Undeveloped Reserves    125    40    11      178 
Total    419    145    40    14    618 
                     
                     
*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 12 
2018 FIRST QUARTER GUIDANCE       
       
Anticipated Realizations Against the Prevailing Index Prices for Q1 2018 (a) 
Oil    92% to 96% of Brent   
NGLs    62% to 66% of Brent   
Natural Gas    88% to 92% of NYMEX   
       
2018 First Quarter Production, Capital and Income Statement Guidance 
Production    120 to 125 MBOE per day   
Capital    $115 million to $135 million   
Production costs    $19.25 to $20.75 per BOE   
Adjusted general and administrative expenses    $6.05 to $6.35 per BOE   
Depreciation, depletion and amortization    $10.50 to $10.80 per BOE   
Taxes other than on income    $36 million to $40 million   
Exploration expense    $6 million to $10 million   
Interest expense (b)    $89 million to $93 million   
Cash Interest (b)    $58 million to $62 million   
Income tax expense rate    0%   
Cash tax rate    0%   
       
       
Pre-tax 2018 First Quarter Price Sensitivities (c)       
$1 change in Brent index - Oil (d)    $1.7 million   
$1 change in Brent index - NGLs    $0.8 million   
$0.50 change in NYMEX - Gas    $3.5 million   
       
       
2018 First Quarter Production Sensitivities (e)       
    Production  Production Costs 
Brent at $75.00    119 to 124 MBOE per day  $19.50 to $21.00 per BOE 
Brent at $65.00    120 to 125 MBOE per day  $19.25 to $20.75 per BOE 
Brent at $55.00    123 to 128 MBOE per day  $19.00 to $20.50 per BOE 

Source: EvaluateEnergy® ©2019 EvaluateEnergy Ltd