California Resources Corporation Announces Third Quarter 2018 Results

Source Press Release
Company California Resources Corporation 
Tags Hedging, Exploration, Upstream Activities, Capital Spending, Financial & Operating Data, Strategy - Corporate
Date November 01, 2018

California Resources Corporation (NYSE:CRC), an independent California-based oil and gasexploration and production company, today reported net income attributable to common stock (CRC net income) of $66 million, or $1.32 per diluted share, for the third quarter of 2018. Adjusted net income1 for the third quarter of 2018 was $41 million, or $0.81 per diluted share.

Quarterly Highlights Include:

  • Generated core adjusted EBITDAX1 of $400 million, which excludes the impact of $79 million of cash settlement payments on commodity hedge contracts and $13 million of cash-settled stock-based compensation expense
  • Reported adjusted EBITDAX1 of $308 million, 26% higher than the prior quarter, and an adjusted EBITDAX margin1 of 38%
  • Produced 136,000 BOE per day, which reflects an increase of 6% over the prior year period and the midpoint of the previous guidance range
  • Invested $196 million of total capital of which internally funded capital was $158 million
  • Drilled 59 wells with internally funded capital and 36 wells with joint venture (JV) capital
  • Realized $34 million of annualized synergies after the Elk Hills acquisition, exceeding the initial $20 million target well ahead of anticipated pace
  • Increased 2018 capital budget to a range of $720 to $750 million, including approximately $100 million of JV funding, to sustain the increased level of activity through the fourth quarter
  • Issued fourth quarter of 2018 production guidance of 136,000 to 139,000 BOE per day reflecting continued production growth

Todd A. Stevens, CRC's President and Chief Executive Officer, said, "CRC‘s value-driven strategy continued to deliver strong results for the third quarter of 2018, showcasing operational excellence, strong Brent-based realizations, effective capital deployment and portfolio de-risking with the execution of two joint ventures. This resulted in the highest level of quarterly adjusted EBITDAX since 2014 and demonstrated our ability to deliver positive free cash flow before working capital on a year-to-date basis. We remain dedicated to capturing the full value of our conventional resources and driving production growth from our diverse portfolio of assets, while strengthening our financial position and furthering debt reduction efforts. Looking ahead, we are focused on a strong finish to 2018 and carrying that momentum into 2019."

Third Quarter 2018 Results

For the third quarter of 2018, CRC net income was $66 million, or $1.32 per diluted share, while adjusted net income1 was $41 million, or $0.81 per diluted share. Adjusted net income1 excluded $28 million of non-cash derivative gains, a $3 million gain on assetdivestitures, a net gain of $2 million on debt repurchases and a net $8 million charge related to other unusual and infrequent items. These results compared to a net loss of $133 million, or $3.11 per diluted share, and an adjusted net loss of $52 million, or $1.22 per diluted share, in the same prior year period. The 2018 results reflected higher production, significantly higher realized commodity prices and higher gas trading income, partially offset by higher production costs and general and administrative (G&A) expenses.

Total daily production volumes averaged 136,000 barrels of oil equivalent (BOE) per day for the third quarter of 2018, compared to 128,000 BOE per day for the same period in 2017, an increase of more than 6 percent over the prior year period, largely driven by the Elk Hills acquisition. This net increase included a 1,300 BOE per day negative effect on production volumes from production sharing contracts (PSC). For the third quarter of 2018 oil volumes averaged 84,000 barrels per day, NGL volumes averaged 17,000 barrels per day and gas volumes averaged 208,000 thousand cubic feet (MCF) per day.

Realized crude oil prices, including the effect of settled hedges, increased by $13.61 per barrel in the third quarter of 2018 to $63.63 per barrel from the comparable prior year period. Settled hedges decreased realized crude oil prices by $10.10 per barrel in the third quarter of 2018. Average realized NGL prices continued to be strong and registered $45.72 per barrel, reflecting a realized price that was 60 percent of Brent prices. Realized natural gas prices were $3.16 per MCF in the third quarter of 2018, $0.60 higher than in the same prior year period and $0.91 higher than in the second quarter of 2018. The increase in realized gas prices is largely due to higher price realizations resulting from limited third-party storage, pipeline constraints and seasonality trends.

Production costs for the third quarter of 2018 were $236 million compared to $222 million in the third quarter of 2017, an increase of $14 million primarily due to $12 million from the Elk Hills acquisition and increased equity compensation expense of $2 million primarily resulting from the Company's higher stock price. On a per unit basis, third quarter of 2018 production costs were $18.92 per BOE compared to $18.90 per BOE in the comparable prior year period. Third quarter of 2018 unit production costs were below the midpoint of previously disclosed guidance and would have been $18.68 per BOE excluding equity compensation expense of $0.24 per BOE. In line with industry practice for companies operating under PSCs, CRC reports gross field operating costs but only the Company's share of production volumes, which can result in higher production costs per barrel. Excluding this PSC effect, per unit production costs1 for the third quarter of 2018 would have been $17.55 per BOE. General and administrative expenses of $81 million for the third quarter of 2018 were $20 million higher than the comparable prior year period primarily related to higher equitycompensation expense of $9 million as a result of CRC's increased stock price and additional G&A of $3 million as a result of the Elk Hills acquisition. The remaining increase in G&A expenses was the result of a number of smaller increases in various cost categories.

CRC reported taxes other than on income of $45 million, $6 million higher than the same prior year period largely due to higher property taxes as a result of commodity price increases. Exploration expense was $4 million for the third quarter of 2018, $1 million lower than the comparable prior year period.

Capital investment in the third quarter of 2018 totaled $158 million, excluding JV capital. Approximately $136 million was directed todrilling and capital workovers.

Cash provided by operating activities was $159 million, which included interest payments of $69 million. CRC's free cash flow1, excluding BSP funded capital of $19 million, was $1 million in the third quarter of 2018.

Nine-Month Results

For the first nine months of 2018, CRC net loss was $18 million, or $0.38 per diluted share, compared to net loss of $128 million, or $3.01 per diluted share, for the same period of 2017. The 2018 results reflected significantly higher realized oil and NGL prices, partially offset by higher production costs and higher G&A expense. Adjusted net income1 for the first nine months of 2018 was $35 million, or $0.71 per diluted share, compared with an adjusted net loss of $173 million, or $4.07 per diluted share, for the same prior year period. The 2018 adjusted net income excluded $71 million of non-cash derivative losses, a net gain of $26 million on debtrepurchases, a $4 million gain on asset divestitures and a net $12 million charge related to other unusual and infrequent items. The 2017 adjusted net loss excluded $38 million of non-cash derivative gains, $21 million of gains from asset divestitures, a $4 million net gain on debt repurchases and an $18 million charge from other unusual and infrequent items.

Total daily production volumes averaged 131,000 BOE per day in the first nine months of 2018 compared with 130,000 BOE per day for the same period of 2017. This increase included a negative effect on production volumes from PSCs of 1,800 BOE per day. Excluding production from the Elk Hills acquisition and the effect of PSCs, the decline from the first nine months of 2017 to the first nine months of 2018 was 4 percent. This low decline reflects the gradual ramp up in capital investment beginning in late 2017.

In the first nine months of 2018, realized crude oil prices, including the effect of settled hedges, increased $14.11 per barrel to $63.53 per barrel from $49.42 per barrel for the same prior year period. Settled hedges reduced 2018 realized crude oil prices by $8.00 per barrel compared with an increase of $0.66 per barrel for the same period of 2017. Realized NGL prices increased 32 percent to $43.71 from $33.00 per barrel in the first nine months of 2017. Realized natural gas prices increased 3 percent to $2.73 per MCF compared with $2.64 per MCF for the comparable prior year period.

Production costs for the first nine months of 2018 were $679 million, or $18.98 per BOE, compared to $649 million, or $18.31 per BOE, for the same period in 2017. The Elk Hills acquisition added $24 million to the first nine months' production costs and the increase in equity compensation expense added $8 million, or $0.23 per BOE. Excluding these items, production costs were slightly lower in the current year compared to the prior year due to ongoing efficiency efforts. Per unit production costs, excluding the effect of PSC contracts, were $17.48 and $17.21 per BOE for the first nine months of 2018 and 2017, respectively. G&A expenses were $234 million and $183 million for the first nine months of 2018 and 2017, respectively, with the difference primarily related to increased equitycompensation expense resulting from the Company's higher stock price and additional G&A expense as a result of the Elk Hills acquisition.

Taxes other than on income of $120 million for the first nine months of 2018 were $17 million higher than the same period of 2017 primarily due to higher property taxes as a result of commodity price increases. Exploration expense of $18 million for the first nine months of 2018 was $1 million higher than the comparable year period of 2017.

Capital investment in the first nine months of 2018 totaled $467 million, excluding JV capital, of which $363 million was directed todrilling and capital workovers.

Cash provided by operating activities for the first nine months of 2018 was $393 million and free cash flow, excluding BSP funded capital of $37 million, was $(74) million. Excluding changes in working capital, which predominantly relate to greenhouse gaspayments for prior years' activities, free cash flow would have been $17 million.

Operational Update

CRC operated an average of 10 drilling rigs during the third quarter of 2018 with two rigs focused on steamfloods, four on waterfloods, two on conventional primary production, one on unconventional production and one on exploration. CRC drilled 94 development wells and one exploration well with CRC and JV capital (43 steamflood, 25 waterflood, 18 primary and 9 unconventional). 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 period that the well is drilled. In the San Joaquin basin, CRC operated seven rigs and produced approximately 99,000 BOE per day in the third quarter of 2018. The Los Angeles basin operated three rigs directed toward waterflood projects and contributed 26,000 BOE per day of production in the third quarter of 2018. The Ventura basin produced 6,000 BOE per day and the Sacramento basin produced 5,000 BOE per day. Neither the Ventura nor Sacramento basin had active drilling programs in the third quarter of 2018.

2018 Capital Budget

CRC increased its 2018 capital program to a range of $720 million to $750 million, which includes approximately $100 million of JV capital. This increase from the previously stated range of $650 million to $700 million is intended to build on the momentum created in the first nine months of 2018. The updated program reflects management's strategy to align the capital program with stronger expected cash flows from commodity price improvements and increased production from the Elk Hills acquisition. The additional capital will sustain current workover and facility activity through the fourth quarter of 2018.

Debt Reduction Update

CRC continues to deliver on its commitment to strengthen the balance sheet. In the third quarter of 2018, CRC repurchased a total of $32 million in aggregate principal amount of the Company's outstanding debt for $30 million in cash. Through the first nine months of 2018, CRC repurchased a total of $177 million in aggregate principal amount of the Company's outstanding debt for $149 million in cash. The majority of CRC's debt repurchases focused on the Company's Second Lien Notes.

Borrowing Base Redetermination

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

Mid-Year Reserves

CRC's mid-year proved reserves totaled 731 MMBOE, up from 618 MMBOE at year-end 2017. Excluding positive price revisions and additions related to the Elk Hills acquisition, the Company organically replaced 96% of proved reserves. This strong organic reserve replacement ratio (RRR) was achieved with well executed capital programs in Buena Vista, South Valley, Huntington Beach and Long Beach. Approximately 23 MMBOE of additions were related to transfers, revisions, extensions and discoveries and improved recovery. The Elk Hills acquisition added 63 MMBOE of proved reserves, in line with the estimate stated at the time of acquisition.

Hedging Update

CRC continues to opportunistically seek hedging transactions to protect its cash flow, operating margins and capital program while maintaining adequate liquidity. For the first and second quarters of 2019, CRC has protected the downside price risk of approximately 47,000 and 42,000 barrels per day at approximately $65.35 Brent and $68.91 Brent per barrel, respectively. In the third and fourth quarters of 2019, the Company protected the downside price risk of approximately 42,000 and 37,000 barrels per day at approximately $72.18 and $74.56 Brent per barrel, respectively. Except for a small portion primarily in the first quarter of 2019, the 2019 hedges do not contain caps, thereby providing upside to oil price movements. 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, core adjusted EBITDAX, adjusted EBITDAX margin, free cash flow, production costs (excluding the effects of PSC-type contracts) 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 
SUMMARY OF RESULTS                 
    Third Quarter    Nine Months 
($ and shares in millions, except per share amounts)    2018    2017    2018    2017 
                 
Statement of Operations Data:                 
Revenues and Other                 
Oil and gas sales (a)    700      461      1,932      1,387   
Net derivative (loss) gain from commodity contracts    (54    (65    (259    51   
Other revenue (a)    182      49      313      113   
Total revenues and other    828      445      1,986      1,551   
                 
Costs and Other                 
Production costs    236      222      679      649   
General and administrative expenses    81      61      234      183   
Depreciation, depletion and amortization    128      134      372      412   
Taxes other than on income    45      39      120      103   
Exploration expense            18      17   
Other expenses, net (a)    149      29      259      76   
Total costs and other    643      490      1,682      1,440   
                 
Operating Income (Loss)    185      (45    304      111   
                 
Non-Operating (Loss) Income                 
Interest and debt expense, net    (95    (85    (281    (252 
Net gain on early extinguishment of debt        —      26       
Gain on asset divestitures        —          21   
Other non-operating expenses    (4    (2    (16    (11 
                 
Income (Loss) Before Income Taxes    91      (132    37      (127 
Income tax    —      —      —      —   
Net Income (Loss)    91      (132    37      (127 
Net income attributable to noncontrolling interests    (25    (1    (55    (1 
Net Income (Loss) Attributable to Common Stock    66      (133    (18    (128 
                 
Net income (loss) attributable to common stock per share - basic    1.34      (3.11    (0.38    (3.01 
Net income (loss) attributable to common stock per share - diluted    1.32      (3.11    (0.38    (3.01 
                 
Adjusted net income (loss)    41      (52    35      (173 
Adjusted net income (loss) per share - basic    0.82      (1.22    0.72      (4.07 
Adjusted net income (loss) per share - diluted    0.81      (1.22    0.71      (4.07 
                 
Weighted-average common shares outstanding - basic    48.5      42.7      47.0      42.5   
Weighted-average common shares outstanding - diluted    49.1      42.7      47.0 (b)    42.5   
                 
Adjusted EBITDAX    308      187      803      548   
Effective tax rate    0%    0%    0%    0% 
                 

(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 periods. Under prior accounting standards, for the three and nine months ended September 30, 2018, oil and gas sales would have been $695 million and $1,915 million, respectively, other revenue would have been $177 million and $242 million, respectively, and other expenses, net would have been $139 million and $171 million, respectively. 
 
(b) Weighted-average common shares outstanding for adjusted net income (loss) per share - diluted were 47.6 million. 
 

    Third Quarter    Nine Months 
($ and shares in millions)    2018    2017    2018    2017 
                 
Cash Flow Data:                 
Net cash provided by operating activities    159      105      393      225   
Net cash used in investing activities    (158    (100    (965    (174 
Net cash (used) provided by financing activities    (12    14      583      (35 
                 
Balance Sheet Data:    September 30,    December 31,         
    2018    2017         
Total current assets    546      483           
Total property, plant and equipment, net    6,386      5,696           
Total current liabilities    871      732           
Long-term debt    5,108      5,306           
Mezzanine equity    745      —           
Equity    (605    (720         
                 
Outstanding shares as of    48.6      42.9           

 
STOCK-BASED COMPENSATION   
   
Our stock price increased $38.07 or over 364% from $10.46 as of September 30, 2017 to $48.53 as of September 30, 2018. Due to our stock price increase, we recognized a significant increase in stock-based compensation expense that is included in both general and administrative expenses and production costs as shown in the following table: 

    Third Quarter    Nine Months 
($ in millions, except per BOE amounts)    2018    2017    2018    2017 
                 
General and administrative expenses                 
Cash-settled awards    11          33     
Equity-settled awards            10      10 
Total stock-based compensation in G&A    13          43      13 
Total stock-based compensation in G&A per Boe    1.04      0.43      1.20      0.37 
                 
Production costs                 
Cash-settled awards        —          — 
Equity-settled awards               
Total stock-based compensation in production costs            11     
Total stock-based compensation in production costs per Boe    0.24      0.09      0.31      0.08 
                 
Total company stock-based compensation    16          54      16 
Total company stock-based compensation per Boe    1.28      0.52      1.51      0.45 
                               

                 
            Attachment 2 
PRODUCTION STATISTICS                 
         
    Third Quarter    Nine Months 
Net Oil, NGLs and Natural Gas Production Per Day    2018    2017    2018    2017 
                 
Oil (MBbl/d)                 
San Joaquin Basin    54      51      52      52 
Los Angeles Basin    26      27      25      27 
Ventura Basin               
Sacramento Basin    —      —      —      — 
Total    84      82      81      84 
                 
NGLs (MBbl/d)                 
San Joaquin Basin    16      15      16      15 
Los Angeles Basin    —      —      —      — 
Ventura Basin               
Sacramento Basin    —      —      —      — 
Total    17      16      17      16 
                 
Natural Gas (MMcf/d)                 
San Joaquin Basin    172      139      162      140 
Los Angeles Basin               
Ventura Basin               
Sacramento Basin    29      33      30      32 
Total    208      182      200      181 
                 
Total Production (MBoe/d) (a)    136      128      131      130 
                       

Third Quarter    Nine Months 
($ millions, except per share amounts)    2018    2017    2018    2017 
Net income (loss)    91      (132    37      (127 
Net income attributable to noncontrolling interests    (25    (1    (55    (1 
Net income (loss) attributable to common stock    66      (133    (18    (128 
Unusual, infrequent and other items:                 
Non-cash derivative (gain) loss, excluding noncontrolling interest    (28    72      71      (38 
Early retirement and severance costs    —               
Gain on asset divestitures    (3    —      (4    (21 
Net gain on early extinguishment of debt    (2    —      (26    (4 
Other, net                14   
Total unusual, infrequent and other items    (25    81      53      (45 
                 
Adjusted net income (loss)    41      (52    35      (173 
                 
Net income (loss) attributable to common stock per share - diluted    1.32      (3.11    (0.38    (3.01 
Adjusted net income (loss) per share - diluted    0.81      (1.22    0.71      (4.07 
                 
         
DERIVATIVE GAINS AND LOSSES         
    Third Quarter    Nine Months 
($ millions)    2018    2017    2018    2017 
Non-cash derivative gain (loss), excluding noncontrolling interest    28      (72    (71    38   
Non-cash derivative loss included in noncontrolling interest    (3    (1    (10    (2 
Net (payments) proceeds on settled commodity derivatives    (79        (178    15   
Net derivative (loss) gain from commodity contracts    (54    (65    (259    51   
                 
                 
                 
                 
FREE CASH FLOW                 
    Third Quarter    Nine Months 
($ millions)    2018    2017    2018    2017 
                 
Net cash provided by operating activities    159      105      393      225   
Capital investment    (177    (100    (504    (232 
Free cash flow    (18        (111    (7 
BSP funded capital investment    19      30      37      82   
Free cash flow excluding BSP funded capital        35      (74    75   
                 
DISCRETIONARY CASH FLOW                 
    Third Quarter    Nine Months 
($ millions)    2018    2017    2018    2017 
Adjusted EBITDAX    308      187      803      548   
                 
Cash Interest    (69    (56    (284    (251 
Distributions to noncontrolling interest holders:                 
BSP joint venture    (18    (5    (35    (6 
Ares joint venture    (21    —      (45    —   
                 
Discretionary Cash Flow    200      126      439      291   

 
ADJUSTED EBITDAX AND CORE ADJUSTED EBITDAX 
The following tables present a reconciliation of the GAAP financial measures of net income (loss) and net cash provided (used) by operating activities to the non-GAAP financial measures of adjusted and core adjusted EBITDAX. 

    Third Quarter    Nine Months 
($ millions)    2018    2017    2018    2017 
Net income (loss)    91      (132    37      (127 
Interest and debt expense, net    95      85      281      252   
Interest income    —      —      (1    —   
Depreciation, depletion and amortization    128      134      372      412   
Exploration expense            18      17   
Unusual, infrequent and other items (a)    (25    81      53      (45 
Other non-cash items    15      14      43      39   
Adjusted EBITDAX (A)    308      187      803      548   
Net payments (proceeds) on settled commodity derivatives    79      (8    178      (15 
Cash-settled stock-based compensation    13          41       
Core Adjusted EBITDAX    400      181      1,022      536   
                 
Net cash provided (used) by operating activities    159      105      393      225   
Cash interest    69      56      284      251   
Exploration expenditures            14      16   
Changes in operating assets and liabilities    76      13      113      42   
Other, net    —          (1    14   
Adjusted EBITDAX (A)    308      187      803      548   
Net payments (proceeds) on settled commodity derivatives    79      (8    178      (15 
Cash-settled stock-based compensation    13          41       
Core Adjusted EBITDAX    400      181      1,022      536   
                 
(a) See Adjusted Net Income (Loss) reconciliation.                 
                 
                 
ADJUSTED EBITDAX MARGIN         
    Third Quarter    Nine Months 
($ millions)    2018    2017    2018    2017 
Total revenues and other    828      445      1,986      1,551   
Non-cash derivative loss (gain)    (25    73      81      (36 
Adjusted revenues (B)    803      518      2,067      1,515   
Adjusted EBITDAX Margin (A)/(B)    38    36    39    36 

                 
PRODUCTION COSTS PER BOE                 
    Third Quarter    Nine Months 
($ per Boe)    2018    2017    2018    2017 
Production costs    18.92      18.90      18.98      18.31   
Costs attributable to PSC-type contracts    (1.37    (1.09    (1.50    (1.10 
Production costs, excluding effects of PSC-type contracts    17.55      17.81      17.48      17.21   

 
Attachment 4 
ADJUSTED NET LOSS VARIANCE ANALYSIS 
($ millions)       
       
2017 3rd Quarter Adjusted Net Loss    (52   
       
Price - Oil    100    (a) 
Price - NGLs    15     
Price - Natural Gas       
Volume    21     
Production cost    (14   
Taxes other than on income    (6   
DD&A rate    13     
Interest expense    (10   
Adjusted general & administrative expenses    (20   
Net income attributable to noncontrolling interests    (24   
All others       
       
2018 3rd Quarter Adjusted Net Income    41     
       
       
2017 Nine-Month Adjusted Net Loss    (173   
       
Price - Oil    325    (a) 
Price - NGLs    46     
Price - Natural Gas       
Volume    (27   
Production cost    (30   
Taxes other than on income    (17   
DD&A rate    43     
Interest expense    (29   
Adjusted general & administrative expenses    (46   
Net income attributable to noncontrolling interests    (54   
All others    (8   
       
2018 Nine-Month Adjusted Net Income    35     
       
(a) Includes cash settlement payments on commodity derivatives. 
 

Attachment 5 
CAPITAL INVESTMENTS                 
    Third Quarter    Nine Months 
($ millions)    2018    2017    2018    2017 
                 
Internally Funded Capital    158      70      467      150 
                 
BSP Funded Capital    19      30      37      82 
                 
Consolidated Reported Capital Investments    177      100      504      232 
                 
MIRA Funded Capital    19      30      46      38 
                 
Total Capital Program    196      130      550      270 
                               

                Attachment 6 
PRICE STATISTICS                 
    Third Quarter    Nine Months 
    2018    2017    2018    2017 
Realized Prices                 
Oil with hedge ($/Bbl)    63.63      50.02      63.53      49.42   
Oil without hedge ($/Bbl)    73.73      48.90      71.53      48.76   
                 
NGLs ($/Bbl)    45.72      34.63      43.71      33.00   
                 
Natural gas ($/Mcf) (a)    3.16      2.56      2.73      2.64   
                 
Index Prices                 
Brent oil ($/Bbl)    75.97      52.18      72.68      52.59   
WTI oil ($/Bbl)    69.50      48.21      66.75      49.47   
NYMEX gas ($/MMBtu)    2.88      2.95      2.83      3.12   
                 
Realized Prices as Percentage of Index Prices                 
Oil with hedge as a percentage of Brent    84    96    87    94 
Oil without hedge as a percentage of Brent    97    94    98    93 
                 
Oil with hedge as a percentage of WTI    92    104    95    100 
Oil without hedge as a percentage of WTI    106    101    107    99 
                 
NGLs as a percentage of Brent    60    66    60    63 
NGLs as a percentage of WTI    66    72    65    67 
                 
Natural gas as a percentage of NYMEX (a)    110    87    96    85 
                         

(a) See Note (a) on Attachment 1 related to our adoption of the new accounting standard regarding the reporting of certain sales related costs. For the three months and nine months ended September 30, 2018, the realized gas price would have been $2.98 per Mcf and $2.52 per Mcf, respectively, and the realized gas price as a percentage of NYMEX would have been 103% and 89%, respectively. 
 

                    Attachment 7 
THIRD QUARTER DRILLING ACTIVITY                     
    San Joaquin    Los Angeles    Ventura    Sacramento     
Wells Drilled (Gross)    Basin    Basin    Basin    Basin    Total 
                     
Development Wells                     
Primary    17    —    —    —    17 
Waterflood      16    —    —    25 
Steamflood    43    —    —    —    43 
Unconventional      —    —    —   
Total    78    16    —    —    94 
                     
Exploration Wells                     
Primary      —    —    —   
Waterflood    —    —    —    —    — 
Steamflood    —    —    —    —    — 
Unconventional    —    —    —    —    — 
Total      —    —    —   
                     
Total Wells (a)    79    16    —    —    95 
                     
CRC Wells Drilled    47    12    —    —    59 
                     
BSP Wells Drilled        —    —   
                     
MIRA Wells Drilled    29    —    —    —    29 
                     
(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                           
                           
      4Q    1Q    2Q    3Q    4Q    Q1 
      2018    2019    2019    2019    2019    2020 
Crude Oil                           
Sold Calls:                           
Barrels per day      15,000    15,000    5,000    —    —    — 
Weighted-average Brent price per barrel      $58.83    $66.15    $68.45    $—    $—    $— 
                           
Purchased Calls:                           
Barrels per day      —    2,000    —    —    —    — 
Weighted-average Brent price per barrel      $—    $71.00    $—    $—    $—    $— 
                           
Purchased Puts:                           
Barrels per day      —    38,000    40,000    40,000    35,000    10,000 
Weighted-average Brent price per barrel      $—    $65.66    $69.75    $73.13    $75.71    $75.00 
                           
Sold Puts:                           
Barrels per day      19,000    40,000    35,000    40,000    35,000    10,000 
Weighted-average Brent price per barrel      $45.00    $51.88    $55.71    $57.50    $60.00    $60.00 
                           
Swaps:                           
Barrels per day      48,000    7,000 (1)    —    —    —    — 
Weighted-average Brent price per barrel      $60.35    $67.71    $—    $—    $—    $— 
                           

(1) Certain of our counterparties have options to increase swap volumes by up to 5,000 barrels per day at a weighted-average Brent price of $70.00 for the first quarter of 2019.

The BSP JV entered into crude oil derivatives that are included in our consolidated results but not in the above table. The hedges entered into by the BSP JV could affect the timing of the redemption of the JV interest. The BSP JV sold calls for up to approximately 1,000 barrels per day at a weighted-average price per barrel of $60.00 per barrel for 2018 through 2020. The BSP JV purchased puts for up to approximately 2,000 barrels per day at a weighted-average price per barrel of approximately $50.00 for 2018 through 2021. The BSP JV also entered into natural gas swaps for insignificant volumes for periods through May 2021. 
 
In May 2018 we entered into derivative contracts that limit our interest rate exposure with respect to $1.3 billion of our variable-rate indebtedness. The interest rate contracts reset monthly and require the counterparties to pay any excess interest owed on such amount in the event the one-month LIBOR exceeds 2.75% for any monthly period prior to May 4, 2021. 
 

Attachment 9 
2018 FOURTH QUARTER GUIDANCE     
     
Anticipated Realizations Against the Prevailing Index Prices for Q4 2018 (a) 
Oil    93% to 98% of Brent 
NGLs    55% to 60% of Brent 
Natural Gas    100% to 110% of NYMEX 
     
2018 Fourth Quarter Production, Capital and Income Statement Guidance 
Production (b) & (c)    136 to 139 MBOE per day 
Capital    $170 million to $200 million 
Production costs (b) & (c)    $17.75 to $19.25 per BOE 
Adjusted general and administrative expenses (b) & (d)    $6.30 to $6.70 per BOE 
Depreciation, depletion and amortization (b)    $10.10 to $10.40 per BOE 
Taxes other than on income    $41 million to $45 million 
Exploration expense    $10 million to $15 million 
Interest expense (e)    $96 million to $100 million 
Cash interest (e)    $150 million to $155 million 
Income tax expense rate    0% 
Cash tax rate    0% 
     
     
Pre-tax 2018 Fourth Quarter Price Sensitivities (f)     
$1 change in Brent index - Oil (g)    $1.2 million 
$1 change in Brent index - NGLs    $1.0 million 
$0.50 change in NYMEX - Gas    $4.9 million 
     

(a) Realizations exclude hedge effects. 
 
(b) Based on an average assumed Q4 2018 Brent price of $75 per barrel. 
 
(c) Based on an average assumed Brent price of $70 per barrel, Q4 2018 production would be 137 to 140 MBOE per day and production costs would be $17.65 to $19.15 per BOE. Based on an average assumed Brent price of $80 per barrel, Q4 2018 production would be 135 to 138 MBOE per day and production costs would be $17.85 to $19.35 per BOE. 
 
(d) Our long-term incentive compensation programs for non-executive employees are stock based but payable in cash. Accounting rules require that we adjust the cumulative liability for all vested but 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 could include this cumulative adjustment depending on movement in our stock price. Our stock price at September 30, 2018 was $48.53 per share, which was used for fourth quarter guidance. 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. 
 
(e) 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. 
 
(f) Due to our tax position there is no difference between the impact on our income and cash flows. 
 
(g) 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® ©2019 EvaluateEnergy Ltd