California Resources Corporation ("CRC" or the "Company") (NYSE:CRC), an independent California-based oil and gas exploration and production company, today announced an adjusted net loss1 of $100 million or ($0.26) per diluted share for the first quarter of 2016, compared with an adjusted net loss of $97 million or ($0.25) per diluted share for the first quarter of 2015. Adjusted EBITDAX2 for the first quarter of 2016 was $124 million, compared with $198 million for the first quarter of 2015.
Highlights Include:
- Crude oil production of 98,000 barrels per day
- Total production of 148,000 BOE per day
- First quarter 2016 Adjusted EBITDAX of $124 million
- Free cash flow1 (after capital) of $87 million
- Cash received from hedging program of $56 million ($6.31 per barrel of oil)
- 24% reduction in production costs year-over-year
Todd Stevens, President and Chief Executive Officer, said, "We continue to benefit from our high level of operational control as well as the resiliency of our diverse and rich asset base. In addition, the continued strong execution by our operations teams has helped reduce costs, protect our margins and manage our base production. We expect 2016 will be a year of blocking and tackling for our operations teams to continue their strong performance on all three of these key tenets while building inventory for the anticipated rebound in the commodity markets.
"Despite the lowest quarterly commodity prices realized by CRC to date, we generated the same amount of operating cash flow after working capital this quarter compared to the prior year period, allowing us to reduce our outstanding debt through free cash flow while maintaining sufficient liquidity to operate our business. Our plans to strengthen the balance sheet have continued to progress as the markets have begun to stabilize and we are assessing all options to improve our leverage."
1 See reconciliation on Attachment 3.
2 For
an explanation of how we calculate and use Adjusted EBITDAX (non-GAAP)
and reconciliations of net income / (loss) (GAAP) and net cash provided
by operating activities (GAAP) to Adjusted EBITDAX (non-GAAP), please
see Attachment 2.
First Quarter Results
For the first quarter of 2016, CRC reported an adjusted net loss of $100 million or ($0.26) per diluted share, compared with an adjusted net loss of $97 million or ($0.25) per diluted share for the same period of 2015. The 2016 quarter reflected lower production costs, adjusted general and administrative expense, ad valorem expense, depreciation, depletion and amortization expense (DD&A), exploration expense and interest expense, more than offset by lower oil, NGL and gas realized prices and volumes. The first quarter 2016 net loss was $50 million or ($0.13) per diluted share, compared with a net loss of $100 million or ($0.26) per diluted share for the same period of 2015. The first quarter 2016 adjusted net loss excluded an $89 million gain on the purchase of the company's notes, an $81 million non-cash hedge loss on outstanding hedges at March 31, 2016, a $63 million benefit from a deferred tax valuation allowance adjustment and net $21 million of other non-recurring charges. The first quarter 2015 adjusted net loss excluded $3 million of after-tax non-recurring adjustments. Adjusted EBITDAX for the first quarter of 2016 was $124 million, compared to $198 million in the prior year period.
Our year-over-year average oil production decreased by only 9 percent, or 10,000 barrels per day, to 98,000 barrels per day in the first quarter of 2016, compared to the same period of the prior year. NGL production decreased by 6 percent to 17,000 barrels per day and natural gas production decreased by 19 percent to 196 million cubic feet (MMcf) per day. Total daily production volumes averaged 148,000 barrels of oil equivalent (BOE) in the first quarter of 2016, compared with 166,000 BOE in the first quarter of 2015, an 11-percent decrease which is at the lower end of our corporate decline range. The first quarter 2016 production declines reflected reduced capital investments and selective deferral of workover and downhole maintenance activity based on our investment criteria and the effect of the planned power plant turnaround.
Realized crude oil prices decreased 22 percent to $36.39 per barrel, including the effect of realized hedges, in the first quarter of 2016 from $46.44 per barrel in the first quarter of 2015. First quarter hedges contributed $6.31 per barrel to the 2016 realized crude oil price compared with $0.06 for the first quarter of 2015. Realized NGL prices decreased 24 percent to $16.39 per barrel in the first quarter of 2016 from $21.55 per barrel in the first quarter of 2015. Realized natural gas prices decreased 28 percent to $2.05 per thousand cubic feet (Mcf) in the first quarter of 2016, compared with $2.84 per Mcf in the same period of 2015.
Production costs for the first quarter of 2016 were $184 million or $13.69 per BOE, compared with $242 million or $16.20 per BOE for the first quarter of 2015, a 24-percent reduction on an absolute dollar basis. The decrease was driven by cost reductions across the board, particularly in well servicing efficiency, field personnel, energy use and lower natural gas prices, as well as management's decision to selectively defer workovers and lower value downhole maintenance activity. The Company believes the majority of these cost reductions are sustainable over the long-term. Adjusted general and administrative expenses3 were $53 million or $3.95 per BOE for the first quarter of 2016, compared with $76 million or $5.09 per BOE for the first quarter of 2015, reflecting employee and contractor cost reduction initiatives, as well as the effect of lower stock prices on stock-based compensation. Exploration expenses of $5 million for the first quarter of 2016 were $12 million lower than the same period of 2015. Ad valorem taxes were $27 million for the first quarter of 2016 and $40 million for the same period of 2015.
Operating cash flow after working capital changes was $115 million for both the first quarter of 2016 and the first quarter of 2015.
3 See reconciliation on Attachment 4.
Operational Update
CRC did not have any drilling rigs running during the first quarter of 2016. This was consistent with CRC's significantly reduced 2016 capital program focused on investments designed to ensure safe and reliable long-term operations as well as the planned major turnaround on CRC's Elk Hills Power Plant during the quarter. For 2016, CRC has developed a dynamic capital program to align investments with operating cash flow. The Company will monitor prices and cash flow throughout the year and retain flexibility to increase investments in drilling and capital workovers, to the extent crude oil prices show sustained improvement, while abiding by its financial covenants. CRC anticipates that this capital program, without any adjustments during the year, could result in average production declines closer to the higher end of the Company's historical base decline range.
Spring Redetermination
CRC successfully executed its spring borrowing base redetermination for its credit agreement which was confirmed at $2.3 billion, the same as the February 2016 level.
Hedging Update
CRC continues to opportunistically add hedges to protect its cash flow, margins and capital program and to maintain liquidity. Currently, the Company has the following Brent crude oil hedges in place:
| 2Q 2016 | 3Q 2016 | 4Q 2016 | FY 2017 | FY 2018 | ||||||||||||||||
| Production | Strike | Production | Strike | Production | Strike | Production | Strike | Production | Strike | |||||||||||
| (Bbls/d) | (Wtd Avg) | (Bbls/d) | (Wtd Avg) | (Bbls/d) | (Wtd Avg) | (Bbls/d) | (Wtd Avg) | (Bbls/d) | (Wtd Avg) | |||||||||||
| Calls | 35,500 | $66.15 | 4,000 | $71.13 | 23,000 | $53.67 | 30,000 | $55.68 | 23,300 | $57.99 | ||||||||||
| Puts | 55,500 | $50.14 | 28,000 | $50.65 | 3,000 | $50.00 | ||||||||||||||
| Swaps | 1,000 | $61.25 | 25,000 | $49.10 | ||||||||||||||||
Reverse Stock Split
The Company’s stockholders approved a reverse stock split at the Company’s annual stockholders’ meeting on May 4, 2016. Following this approval, our board of directors authorized a reverse split using a ratio of one share of common stock for every ten shares currently outstanding. Our board set the reverse split to occur on May 31, 2016 with trading on a post-split basis to commence the following day. The reverse split will also proportionately decrease the number of authorized shares of common stock and preferred stock. Although the Company regained compliance with the New York Stock Exchange minimum listing requirements based on its increased stock price earlier in the first quarter, the reverse stock split is expected to facilitate continued compliance among other things.
Conference Call Details
To participate in today’s conference call, either dial (877) 328-5505 (International calls please dial +1 (412) 317-5421) or access via webcast at www.crc.com, fifteen minutes prior to the scheduled start time to register. Participants may also pre-register for the conference call at http://dpregister.com/10082716. 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 Investor Relations at www.crc.com.
About California Resources Corporation
California Resources Corporation is the largest oil and natural gas exploration and production company in California on a gross-operated basis. The Company operates its world class resource base exclusively within the State of California, applying integrated infrastructure to gather, process and market its production. Using advanced technology, California Resources Corporation focuses on safely and responsibly supplying affordable energy for California by Californians.
Forward-Looking Statements
This press release contains forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects. Such statements specifically include our expectations as to our future financial position, liquidity, cash flows, results of operations and business prospects, budgets, drilling program, maintenance capital, projected production, projected costs, future operations, hedging activities, future transactions, planned capital investments and other guidance included in this press release. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. For any such forward-looking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results, sometimes materially. Factors (but not necessarily all the factors) that could cause results to differ include: commodity price fluctuations; the ability of our lenders to limit our borrowing capacity; other liquidity constraints; the effect of our debt on our financial flexibility; limitations on our ability to enter efficient hedging transactions; insufficiency of our operating cash flow to fund planned capital expenditures; inability to implement our capital investment program; inability to replace reserves; inability to monetize selected assets; inability to obtain government permits and approvals; restrictions and changes in restrictions imposed by regulations including those related to our ability to obtain, use, manage or dispose of water or use advanced well stimulation techniques like hydraulic fracturing; risks of drilling; tax law changes; competition with larger, better funded competitors for and costs of oilfield equipment, services, qualified personnel and acquisitions; the subjective nature of estimates of proved reserves and related future net cash flows; risks related to our disposition and acquisition activities; restriction of operations to, and concentration of exposure to events such as industrial accidents, natural disasters and labor difficulties in, California; the recoverability of resources; concerns about climate change and air quality issues; lower-than-expected production from development projects or acquisitions; catastrophic events for which we may be uninsured or underinsured; the effects of litigation; cyber attacks; operational issues that restrict market access; and uncertainties related to the spin-off and the agreements related thereto.Material risks are further discussed in “Risk Factors” in our Annual Report on Form 10-K and Forms 10-Q available on our website at crc.com.Words such as "aim," "anticipate," "believe," "budget," "continue," "could," "effort," "estimate," "expect," "forecast," "goal," "guidance," "intend," "likely," "may," "might," "objective," "outlook," "plan," "potential," "predict," "project," "seek," "should," "target, "will" or "would" and similar expressions that reflect the prospective nature of events or outcomes typically identify forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.
| Attachment 1 | ||||||||
| SUMMARY OF RESULTS | ||||||||
| First Quarter | ||||||||
| ($ and shares in millions, except per share amounts) | 2016 | 2015 | ||||||
Statement of Operations Data: | ||||||||
| Revenues | ||||||||
| Oil and gas sales | $ | 304 | $ | 549 | ||||
| Other revenue | 18 | 28 | ||||||
| 322 | 577 | |||||||
| Costs and Other | ||||||||
| Production costs | 184 | 242 | ||||||
| General and administrative expenses | 67 | 76 | ||||||
| Depreciation, depletion and amortization | 147 | 253 | ||||||
| Taxes other than on income | 39 | 55 | ||||||
| Exploration expense | 5 | 17 | ||||||
| Interest and debt expense, net | 74 | 79 | ||||||
| Other (income) / expenses, net | (66 | ) | 24 | |||||
| 450 | 746 | |||||||
| Loss before income taxes | (128 | ) | (169 | ) | ||||
| Income tax benefit | 78 | 69 | ||||||
| Net loss | $ | (50 | ) | $ | (100 | ) | ||
| EPS - diluted | $ | (0.13 | ) | $ | (0.26 | ) | ||
| Adjusted net loss | $ | (100 | ) | $ | (97 | ) | ||
| Adjusted EPS - diluted | $ | (0.26 | ) | $ | (0.25 | ) | ||
| Weighted average diluted shares outstanding | 385.3 | 382.1 | ||||||
| Adjusted EBITDAX | $ | 124 | $ | 198 | ||||
| Effective tax rate | 61 | % | 41 | % | ||||
Cash Flow Data: | ||||||||
| Net cash provided by operating activities | $ | 115 | $ | 115 | ||||
| Net cash used by investing activities | $ | (29 | ) | $ | (313 | ) | ||
| Net cash (used) / provided by financing activities | $ | (88 | ) | $ | 212 | |||
Balance Sheet Data: | March 31, | December 31, | ||||||
| 2016 | 2015 | |||||||
| Total current assets | $ | 431 | $ | 497 | ||||
| Property, plant and equipment, net | $ | 6,214 | $ | 6,312 | ||||
| Total current liabilities | $ | 638 | $ | 605 | ||||
| Long-term debt, principal amount | $ | 5,872 | $ | 6,043 | ||||
| Total equity | $ | (952 | ) | $ | (916 | ) | ||
| Outstanding shares as of | 389.2 | 388.2 | ||||||
| Attachment 2 | ||||||||
| NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS | ||||||||
| We define adjusted EBITDAX consistent with our credit facilities as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; and certain other non-cash items as well as unusual or infrequent items. Our management believes adjusted EBITDAX provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry and investment community. The amounts included in the calculation of adjusted EBITDAX were computed in accordance with U.S. generally accepted accounting principles (GAAP). This measure is a material component of certain of our financial covenants under our credit facilities and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP. Certain items excluded from adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. Adjusted EBITDAX should be read in conjunction with the information contained in our financial statements prepared in accordance with GAAP. | ||||||||
| The following tables present a reconciliation of the GAAP financial measures of net income / (loss) and net cash provided by operating activities to the non-GAAP financial measure of adjusted EBITDAX: | ||||||||
| First Quarter | ||||||||
| ($ millions) | 2016 | 2015 | ||||||
| Net loss | $ | (50 | ) | $ | (100 | ) | ||
| Interest expense | 74 | 79 | ||||||
| Income tax benefit | (78 | ) | (69 | ) | ||||
| Depreciation, depletion and amortization | 147 | 253 | ||||||
| Exploration expense | 5 | 17 | ||||||
| Adjusted income items | 13 | 5 | ||||||
| Other non-cash items | 13 | 13 | ||||||
| Adjusted EBITDAX | $ | 124 | $ | 198 | ||||
| Net cash provided by operating activities | $ | 115 | $ | 115 | ||||
| Interest expense | 74 | 79 | ||||||
| Exploration expense | 5 | 11 | ||||||
| Changes in operating assets and liabilities | (98 | ) | 1 | |||||
| Non-cash gains / (losses) in income | 2 | (26 | ) | |||||
| Adjusted income items | 13 | 5 | ||||||
| Other non-cash items | 13 | 13 | ||||||
| Adjusted EBITDAX | $ | 124 | $ | 198 | ||||
| Attachment 3 | ||||||||
| NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS | ||||||||
| Our results of operations can include the effects of significant, unusual or infrequent transactions and events affecting earnings that vary widely and unpredictably in nature, timing, amount and frequency. Therefore, management uses a measure called "adjusted net income / (loss)" and a measure it calls "adjusted general and administration expense" which exclude those items. These non-GAAP measures are not meant to disassociate items from management's performance, but rather are meant to provide useful information to investors interested in comparing our performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted net income / (loss) and adjusted general and administrative expenses are not considered to be alternatives to net income / (loss) and general and administrative expenses reported in accordance with GAAP. | ||||||||
| The following table presents a reconciliation of the GAAP financial measure of net income / (loss) to the non-GAAP financial measure of adjusted net income / (loss): | ||||||||
| First Quarter | ||||||||
| ($ millions, except per share amounts) | 2016 | 2015 | ||||||
| Net Loss | $ | (50 | ) | $ | (100 | ) | ||
| Unusual and infrequent items: | ||||||||
| Non-cash loss on outstanding hedges | 81 | 3 | ||||||
| Severance and other employee-related costs | 14 | — | ||||||
| Plant turnaround costs | 7 | 2 | ||||||
| Gain on debt repurchases | (89 | ) | — | |||||
| Valuation allowance for deferred tax assets (a) | (63 | ) | — | |||||
| Tax effects of these items | — | (2 | ) | |||||
| Adjusted net loss | $ | (100 | ) | $ | (97 | ) | ||
| Adjusted EPS - diluted | $ | (0.26 | ) | $ | (0.25 | ) | ||
| (a) Amount represents the out-of-period portion of the valuation allowance reversal. | ||||||||
| FREE CASH FLOW | ||||||||
| First Quarter | ||||||||
| ($ millions) | 2016 | 2015 | ||||||
| Operating cash flow (b) | $ | 115 | $ | 115 | ||||
| Capital investment | (21 | ) | (133 | ) | ||||
| Changes in capital accruals | (7 | ) | (173 | ) | ||||
| Free cash flow | $ | 87 | $ | (191 | ) | |||
| (b) 2016 operating cash flow includes $98 million of positive working capital changes. | ||||||||
| ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES | ||||||||
| First Quarter | ||||||||
| ($ millions) | 2016 | 2015 | ||||||
General and administrative expenses per statements of operations | $ | 67 | $ | 76 | ||||
| Severance and other employee-related costs | (14 | ) | — | |||||
| Adjusted general and administrative expenses | $ | 53 | $ | 76 | ||||
| Attachment 4 | ||||
| ADJUSTED NET INCOME / (LOSS) VARIANCE ANALYSIS | ||||
| ($ millions) | ||||
| 2015 1st Quarter Adjusted Net Loss | $ | (97 | ) | |
| Price - Oil and NGLs | (111 | ) | ||
| Price - Natural Gas | (17 | ) | ||
| Volume | (11 | ) | ||
| Production cost rate | 52 | |||
| DD&A rate | 91 | |||
| Exploration expense | 12 | |||
| Interest expense | 5 | |||
| Adjusted general & administrative expenses | 23 | |||
| Income tax | (52 | ) | ||
| All Others | 5 | |||
| 2016 1st Quarter Adjusted Net Loss | $ | (100 | ) | |
| Attachment 5 | ||||||
| CAPITAL INVESTMENTS | ||||||
| First Quarter | ||||||
| ($ millions) | 2016 | 2015 | ||||
| Capital Investments: | ||||||
| Conventional | $ | 1 | $ | 102 | ||
| Unconventional | 1 | 17 | ||||
| Exploration | — | 10 | ||||
| Other (a) | 19 | 4 | ||||
| $ | 21 | $ | 133 | |||
| (a) Includes $18 million of capital incurred for the planned turnaround at the Elk Hills Power Plant, of which payment of $14 million was deferred to future periods. | ||||||
| Attachment 6 | ||||
| PRODUCTION STATISTICS | ||||
| First Quarter | ||||
| Net Oil, NGLs and Natural Gas Production Per Day | 2016 | 2015 | ||
| Oil (MBbl/d) | ||||
| San Joaquin Basin | 60 | 67 | ||
| Los Angeles Basin | 32 | 34 | ||
| Ventura Basin | 6 | 7 | ||
| Sacramento Basin | — | — | ||
| Total | 98 | 108 | ||
| NGLs (MBbl/d) | ||||
| San Joaquin Basin | 16 | 17 | ||
| Los Angeles Basin | — | — | ||
| Ventura Basin | 1 | 1 | ||
| Sacramento Basin | — | — | ||
| Total | 17 | 18 | ||
| Natural Gas (MMcf/d) | ||||
| San Joaquin Basin | 147 | 179 | ||
| Los Angeles Basin | 3 | 2 | ||
| Ventura Basin | 8 | 12 | ||
| Sacramento Basin | 38 | 49 | ||
| Total | 196 | 242 | ||
Total Barrels of Oil Equivalent (MBoe/d) (a) | 148 | 166 | ||
| (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. The price of natural gas on a barrel of oil equivalent basis is currently substantially lower than the corresponding price for oil and has been similarly lower for a number of years. For example, in the first quarter of 2016, the average prices of Brent oil and NYMEX natural gas were $35.08 per Bbl and $2.07 per Mcf, respectively, resulting in an oil-to-gas price ratio of approximately 17 to 1. | ||||
| Attachment 7 | ||||||||
| PRICE STATISTICS | ||||||||
| First Quarter | ||||||||
| 2016 | 2015 | |||||||
| Realized Prices | ||||||||
| Oil with hedge ($/Bbl) | $ | 36.39 | $ | 46.44 | ||||
| Oil without hedge ($/Bbl) | $ | 30.08 | $ | 46.38 | ||||
| NGLs ($/Bbl) | $ | 16.39 | $ | 21.55 | ||||
| Natural gas ($/Mcf) | $ | 2.05 | $ | 2.84 | ||||
| Index Prices | ||||||||
| Brent oil ($/Bbl) | $ | 35.08 | $ | 55.17 | ||||
| WTI oil ($/Bbl) | $ | 33.45 | $ | 48.63 | ||||
| NYMEX gas ($/MMBtu) | $ | 2.07 | $ | 3.06 | ||||
| Realized Prices as Percentage of Index Prices | ||||||||
| Oil with hedge as a percentage of Brent | 104 | % | 84 | % | ||||
| Oil without hedge as a percentage of Brent | 86 | % | 84 | % | ||||
| Oil with hedge as a percentage of WTI | 109 | % | 95 | % | ||||
| Oil without hedge as a percentage of WTI | 90 | % | 95 | % | ||||
| NGLs as a percentage of Brent | 47 | % | 39 | % | ||||
| NGLs as a percentage of WTI | 49 | % | 44 | % | ||||
| Natural gas as a percentage of NYMEX | 99 | % | 93 | % | ||||
| Attachment 8 | ||||
| 2016 SECOND QUARTER GUIDANCE | ||||
| Anticipated Realizations Against the Prevailing Index Prices for Q2 2016 (a) | ||||
| Oil | 85% to 89% of Brent | |||
| NGLs | 43% to 47% of Brent | |||
| Natural Gas | 81% to 85% of NYMEX | |||
| 2016 Second Quarter Production, Capital and Income Statement Guidance | ||||
| Production | 138 to 143 Mboe per day | |||
| Capital | $8 million to $12 million | |||
| Production costs | $15.75 to $16.25 per BOE | |||
| General and administrative expenses | $4.15 to $4.45 per BOE | |||
| Depreciation, depletion and amortization | $11.10 to $11.30 per BOE | |||
| Taxes other than on income | $38 million to $42 million | |||
| Exploration expense | $4 million to $8 million | |||
| Interest expense (b) | $74 million to $78 million | |||
| Cash Interest (b) | $130 million to $134 million | |||
| Income tax expense rate (c) | 0% | |||
| Cash tax rate | 0% | |||
| Second Quarter Pre-tax Price Sensitivities | On Income (d) | On Cash (d) | ||
| $1 change in Brent index - Oil | $3.0 million | $3.0 million | ||
| $1 change in Brent index - NGLs | $0.5 million | $0.5 million | ||
| $0.50 change in NYMEX - Gas | $2.0 million | $2.0 million | ||
| Second Quarter Pre-tax Hedge Price Sensitivities | ||||
| $1 change in Brent index at above $50.00 - Oil | $4.5 million | $4.5 million | ||
| Quarterly Volumes Sensitivities | ||||
| $1 change in the Brent index (e) | 300 BOE/d | |||
| (a) Realizations exclude hedge effects. | ||||
| (b) Interest expense includes the amortization of the deferred gain that resulted from the December 2015 debt exchange. Cash interest for the quarter is higher than interest expense due to the timing of interest payments. | ||||
| (c) No tax benefit anticipated as all deferred tax amounts are fully reserved through valuation allowances. | ||||
| (d) All amounts exclude hedge effects and reflect the effect of production sharing type contracts in our Wilmington field operations. | ||||
| (e) Reflects the effect of production sharing type contracts in our Wilmington field operations. | ||||
| Attachment 9 | ||||||||||
| FIRST QUARTER DRILLING ACTIVITY | ||||||||||
| San Joaquin | Los Angeles | Ventura | Sacramento | |||||||
| Wells Drilled (Net) | Basin | Basin | Basin | Basin | Total | |||||
| Development Wells | ||||||||||
| Primary | — | — | — | — | — | |||||
| Waterflood | — | 1 | — | — | 1 | |||||
| Steamflood | — | — | — | — | — | |||||
| Unconventional | — | — | — | — | — | |||||
| Total | — | 1 | — | — | 1 | |||||
| Exploration Wells | ||||||||||
| Primary | — | — | — | — | — | |||||
| Waterflood | — | — | — | — | — | |||||
| Steamflood | — | — | — | — | — | |||||
| Unconventional | — | — | — | — | — | |||||
| Total | — | — | — | — | — | |||||
| Total Wells | — | 1 | — | — | 1 | |||||
Development Drilling Capital ($ millions) | $— | $— | — | — | $— | |||||
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Contacts:
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Relations)
818 661-6010
Scott.Espenshade@crc.com
or
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Thompson (Media)
818 661-6005
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