Attached files
| file | filename |
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| 8-K - 8-K - California Resources Corp | form8-kcrcearningsrelease2.htm |
NEWS RELEASE
For immediate release
California Resources Corporation Announces
Second Quarter 2015 Financial Results
LOS ANGELES, August 6, 2015 – California Resources Corporation (NYSE:CRC), the newly independent California-based oil and gas exploration and production company, today announced an adjusted net loss1 of $51 million or ($0.13) per diluted share for the second quarter of 2015, compared with adjusted net income of $246 million or $0.63 per diluted share for the second quarter of 2014. The adjusted net loss for the first six months of 2015 was $148 million or ($0.39) per diluted share, compared with an adjusted net income of $469 million or $1.21 per diluted share for the same period in 2014. Adjusted EBITDAX2 for the second quarter of 2015 was $270 million, compared with $727 million for the second quarter of 2014. Adjusted EBITDAX for the first six months of 2015 was $468 million, compared with $1.4 billion for the first six months of 2014.
Highlights Include:
• | Quarterly total production of 161,000 BOE per day and crude oil production of 104,000 barrels per day |
• | Second quarter 2015 Adjusted EBITDAX of $270 million |
• | Capital investment of $95 million in the second quarter of 2015 |
• | Operating cash flow of $117 million in the second quarter of 2015 |
Todd Stevens, President and Chief Executive Officer, said, "CRC is committed to living within our means and we have demonstrated this tenet again this quarter. We believe that the capital efficiency gains on our investments will allow for our debt levels to moderate slightly down through the remainder of the year. Even at the current reduced investment level, we have been able to increase our average crude oil production over last year, putting CRC on track for increased oil production for 2015.
"This has led to strong operational results in the face of a weak commodity market. We have not had a drilling rig running in our Elk Hills field since late November, yet have realized better than anticipated decline rates. Our operating teams continue to drive additional improvements, both by reducing operating costs and increasing capital efficiencies. I continue to believe CRC is well positioned with our low-decline portfolio to weather this cyclical downturn in prices. While we have an abundance of drilling opportunities above our investment threshold, we continue to build significant conventional and unconventional inventory for the future when prices improve. Potential joint venture partners are finding this
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inventory attractive in our deleveraging discussions. Deleveraging and bringing our balance sheet in line with the current commodity price environment remains our highest priority and we continue to hold discussions around opportunities across our entire portfolio."
Second Quarter Results
The adjusted net loss was $51 million or ($0.13) per diluted share for the second quarter of 2015, compared with adjusted net income of $246 million or $0.63 per diluted share for the second quarter of 2014. The 2015 quarter reflected higher production, in particular oil volumes, and lower production costs and depreciation, depletion and amortization expense (DD&A), offset by significantly lower realized oil, NGL and gas prices and higher interest expense as a result of our capital structure as an independent company.
Daily oil and gas production volumes averaged 161,000 barrels of oil equivalent (BOE) in the second quarter of 2015, compared with 156,000 BOE in the second quarter of 2014. Average oil production increased by 7 percent or 7,000 barrels per day to 104,000 barrels per day in the second quarter of 2015. NGL production remained the same and natural gas production decreased by approximately 4 percent to 234 million cubic feet (MMcf) per day.
Realized crude oil prices decreased 46 percent to $56.73 per barrel in the second quarter of 2015 from $104.50 per barrel in the second quarter of 2014. The decrease mainly reflected the drop in global oil prices, as well as wider differentials to Brent reflecting the residual effects of the market disruptions in California earlier in the year. Realized NGL prices decreased 58 percent to $20.47 per barrel in the second quarter of 2015 from $49.08 per barrel in the second quarter of 2014. Natural gas realized prices decreased 45 percent in the second quarter of 2015 to $2.49 per thousand cubic feet (Mcf), compared with $4.52 per Mcf in the second quarter of 2014.
Production costs for the second quarter of 2015 were $242 million or $16.59 per barrel, compared with $270 million or $19.03 per barrel for the second quarter of 2014, a 13 percent reduction on a per BOE basis. The decrease was driven by cost reductions across the board, particularly in surface operations, well servicing efficiency and energy use, and was also aided by lower natural gas and power prices. Adjusted general and administrative expenses were $75 million or $5.13 per barrel for the second quarter of 2015, compared with $71 million or $5.00 per barrel for the second quarter of 2014.
Operating cash flow was $117 million for the second quarter of 2015, compared with $496 million for the second quarter of 2014.
Six-Month Results
The adjusted net loss for the first six months of 2015 was $148 million or ($0.39) per diluted share, compared with an adjusted net income of $469 million or $1.21 per diluted share for the first six months of 2014. The first six months in 2015 reflected higher production, in particular oil volumes, and lower production costs, DD&A and exploration expense, offset by significantly lower realized product prices in 2015 and higher interest expense. Adjusted EBITDAX for the first six months of 2015 was $468 million, compared with $1.4 billion for the first six months of 2014.
For the first six months of 2015, daily oil and natural gas production averaged 163,000 BOE, compared with 155,000 in the first six months of 2014. Average oil production increased 10,000 barrels per day, or by 10 percent, to 106,000 barrels per day in 2015. NGL production
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remained the same and natural gas production decreased by approximately 2 percent to 238 MMcf per day.
Realized crude oil prices decreased 50 percent to $51.51 per barrel for the first six months of 2015 from $103.43 per barrel for the first six months of 2014. NGL prices decreased 62 percent to $21.00 per barrel in the first six months of 2015 from $54.86 per barrel for the first six months of 2014. Natural gas prices decreased 43 percent to $2.67 per Mcf in the first six months of 2015, compared with $4.67 per Mcf in the first six months of 2014.
For the first six months of 2015, production costs were $484 million or $16.39 per barrel, compared with $534 million or $19.02 per barrel for the first six months of 2014, a 14 percent reduction on a per BOE basis. The decrease was driven by the same factors discussed for the second quarter. Adjusted general and administrative expenses were $151 million or $5.11 per barrel for the first six months of 2015, compared with $140 million or $4.99 per barrel for the first six months of 2014.
Operating cash flow was $232 million for the first six months of 2015, compared with $1.2 billion for the first six months of 2014.
Second Quarter Operational Update
In the quarter, CRC continued to run three drilling rigs with two focused in the San Joaquin basin and one in the Los Angeles basin. In the San Joaquin basin, the rigs drilled 93 steamflood wells including 66 wells in the Lost Hills field, 16 in the Kern Front field and six in the Midway Sunset field. In the Los Angeles basin, CRC drilled 10 waterflood wells in the Wilmington field. As a result of capital efficiencies across the company, CRC has drilled eight more wells than its plan year-to-date. In addition during the second quarter, CRC completed 123 capital workovers and substantially completed a significant compression project in the San Joaquin basin.
Hedging Update
Since the last update, CRC extended the existing hedging program to protect our capital plan using a combination of swaps and options. For the fourth quarter of 2015, CRC hedged 10,000 incremental crude oil barrels per day with a $65 per barrel floor and an average of $75.38 per barrel ceiling. Additionally, CRC entered into a swap for 2,000 barrels per day of the full year 2016 oil production at $72.05 per barrel. For the second half of 2015, CRC entered into natural gas swaps at $3.01 per million British thermal unit (MMBtu) to protect 40,000 MMBtu per day and initiated a costless collar with a weighted average floor of $2.80 per MMBtu and ceiling of $3.17 per MMBtu for 20,000 MMBtu per day.
CRC Site Tour
We are pleased to announce that CRC is hosting a 2015 Site Tour in the Long Beach and Bakersfield areas in California on October 12-14. Due to the length of the event, logistical considerations and safety requirements space will be limited. We will be webcasting the presentations and post formal presentations to CRC's investor relations page on our website at www.crc.com. The event will be archived for play later on the day of the presentations.
1 See reconciliation on Attachment 2.
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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.
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/10068497. 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, drilling program, 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 effect of our debt on our financial flexibility; sufficiency of our operating cash flow to fund planned capital expenditures; the ability to obtain government permits and approvals; effectiveness our capital investments; our ability to monetize selected assets; 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; restriction of operations to, and concentration of exposure to events such as industrial accidents, natural disasters and labor difficulties in, California; limitations on our ability to enter efficient hedging transactions; 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
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restrict market access; and uncertainties related to the spin-off, the agreements related thereto and the anticipated effects of restructuring or reorganizing our business. Material risks are further discussed in “Risk Factors” in our Annual Report on Form 10-K 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" or similar expressions that convey the prospective nature of events or outcomes generally indicate forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made and CRC 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.
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Contacts:
Scott Espenshade (Investor Relations) 818 661-6010 Scott.Espenshade@crc.com | Margita Thompson (Media) 818 661-6005 Margita.Thompson@crc.com |
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Attachment 1 | |||||||||||||||||
SUMMARY OF RESULTS | |||||||||||||||||
Second Quarter | Six Months | ||||||||||||||||
($ and shares in millions) | 2015 | 2014 | 2015 | 2014 | |||||||||||||
Statement of Operations Data: | |||||||||||||||||
Revenues | |||||||||||||||||
Oil and gas sales | $ | 609 | $ | 1,107 | $ | 1,158 | $ | 2,187 | |||||||||
Other revenue | 25 | 33 | 53 | 74 | |||||||||||||
634 | 1,140 | 1,211 | 2,261 | ||||||||||||||
Costs and other deductions | |||||||||||||||||
Production costs | 242 | 270 | 484 | 534 | |||||||||||||
General and administrative expenses | 85 | 71 | 161 | 140 | |||||||||||||
Depreciation, depletion and amortization | 251 | 293 | 504 | 582 | |||||||||||||
Taxes other than on income | 53 | 55 | 108 | 107 | |||||||||||||
Exploration expense | 7 | 15 | 24 | 46 | |||||||||||||
Interest and debt expense, net | 83 | — | 162 | — | |||||||||||||
Other expenses | 27 | 28 | 51 | 70 | |||||||||||||
748 | 732 | 1,494 | 1,479 | ||||||||||||||
Income / (loss) before income taxes | (114 | ) | 408 | (283 | ) | 782 | |||||||||||
Income tax (expense) / benefit | 46 | (162 | ) | 115 | (313 | ) | |||||||||||
Net income / (loss) | $ | (68 | ) | $ | 246 | $ | (168 | ) | $ | 469 | |||||||
EPS - diluted | $ | (0.18 | ) | $ | 0.63 | $ | (0.44 | ) | $ | 1.21 | |||||||
Adjusted net income / (loss) | $ | (51 | ) | $ | 246 | $ | (148 | ) | $ | 469 | |||||||
Adjusted EPS - diluted | $ | (0.13 | ) | $ | 0.63 | $ | (0.39 | ) | $ | 1.21 | |||||||
Weighted average diluted shares outstanding (a) | 382.7 | 381.8 | 382.4 | 381.8 | |||||||||||||
(a) On November 30, 2014, the Spin-off date from Occidental Petroleum Corporation, we issued 381.4 million shares of our common stock. Additional shares were distributed to our employees and vested in December. For comparative purposes, and to provide a more meaningful calculation of weighted-average shares outstanding, we have assumed these amounts to be outstanding for each period prior to the Spin-off. | |||||||||||||||||
Adjusted EBITDAX | $ | 270 | $ | 727 | $ | 468 | $ | 1,432 | |||||||||
Effective tax rate | 40 | % | 40 | % | 41 | % | 40 | % | |||||||||
Cash Flow Data: | |||||||||||||||||
Net cash provided by operating activities | $ | 117 | $ | 496 | $ | 232 | $ | 1,236 | |||||||||
Net cash used by investing activities | $ | (127 | ) | $ | (538 | ) | $ | (440 | ) | $ | (1,039 | ) | |||||
Net cash provided (used) by financing activities | $ | 19 | $ | 42 | $ | 231 | $ | (197 | ) | ||||||||
Balance Sheet Data: | June 30, | December 31, | |||||||||||||||
2015 | 2014 | ||||||||||||||||
Total current assets | $ | 656 | $ | 701 | |||||||||||||
Property, plant and equipment, net | $ | 11,410 | $ | 11,685 | |||||||||||||
Total current liabilities | $ | 685 | $ | 922 | |||||||||||||
Long-term debt, net | $ | 6,476 | $ | 6,292 | |||||||||||||
Total equity | $ | 2,455 | $ | 2,611 | |||||||||||||
Outstanding shares | 386.4 | 385.6 | |||||||||||||||
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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 measure of net income / (loss) to the non-GAAP financial measure of adjusted EBITDAX: | |||||||||||||||||
Second Quarter | Six Months | ||||||||||||||||
($ millions) | 2015 | 2014 | 2015 | 2014 | |||||||||||||
Net income / (loss) | $ | (68 | ) | $ | 246 | $ | (168 | ) | $ | 469 | |||||||
Interest expense | 83 | — | 162 | — | |||||||||||||
Income tax expense / (benefit) | (46 | ) | 162 | (115 | ) | 313 | |||||||||||
Depreciation, depletion and amortization | 251 | 293 | 504 | 582 | |||||||||||||
Exploration expense | 7 | 15 | 24 | 46 | |||||||||||||
Other | 43 | 11 | 61 | 22 | |||||||||||||
Adjusted EBITDAX | $ | 270 | $ | 727 | $ | 468 | $ | 1,432 | |||||||||
Net cash provided by operating activities | $ | 117 | $ | 496 | $ | 232 | $ | 1,236 | |||||||||
Interest expense | 83 | — | 162 | — | |||||||||||||
Cash income taxes | — | 135 | — | 135 | |||||||||||||
Cash exploration expense | 6 | 7 | 17 | 13 | |||||||||||||
Changes in operating assets and liabilities | 49 | 118 | 50 | 47 | |||||||||||||
Other, net | 15 | (29 | ) | 7 | 1 | ||||||||||||
Adjusted EBITDAX | $ | 270 | $ | 727 | $ | 468 | $ | 1,432 | |||||||||
California Resources Corporation's 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) ," which excludes those items. This non-GAAP measure is not meant to disassociate items from management's performance, but rather is meant to provide useful information to investors interested in comparing California Resources Corporation's earnings performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted net income / (loss) is not considered to be an alternative to net income / (loss) 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): | |||||||||||||||||
Second Quarter | Six Months | ||||||||||||||||
($ millions) | 2015 | 2014 | 2015 | 2014 | |||||||||||||
Net income / (loss) | $ | (68 | ) | $ | 246 | $ | (168 | ) | $ | 469 | |||||||
Hedge related activity | 17 | — | 20 | — | |||||||||||||
Early retirement and severance costs | 10 | — | 10 | — | |||||||||||||
Rig terminations and others | 1 | — | 3 | — | |||||||||||||
Tax effect of pre-tax adjustments | (11 | ) | — | (13 | ) | — | |||||||||||
Adjusted net income / (loss) | $ | (51 | ) | $ | 246 | $ | (148 | ) | $ | 469 | |||||||
Adjusted EPS - diluted | $ | (0.13 | ) | $ | 0.63 | $ | (0.39 | ) | $ | 1.21 | |||||||
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Attachment 3 | |||||||||||||||||
ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES | |||||||||||||||||
Second Quarter | Six Months | ||||||||||||||||
($ millions) | 2015 | 2014 | 2015 | 2014 | |||||||||||||
General and administrative expenses per statements | |||||||||||||||||
of operations | $ | 85 | $ | 71 | $ | 161 | $ | 140 | |||||||||
Early retirement and severance costs | (10 | ) | — | (10 | ) | — | |||||||||||
Adjusted general and administrative expenses | $ | 75 | $ | 71 | $ | 151 | $ | 140 | |||||||||
ADJUSTED NET INCOME / (LOSS) VARIANCE ANALYSIS | |||||||||||||||||
($ millions) | |||||||||||||||||
2014 2nd Quarter Adjusted Net Income | $ | 246 | |||||||||||||||
Price - Oil and NGLs | (495 | ) | |||||||||||||||
Price - Natural Gas | (43 | ) | |||||||||||||||
Volume | 55 | ||||||||||||||||
Production cost rate | 30 | ||||||||||||||||
DD&A rate | 50 | ||||||||||||||||
Exploration expense | 8 | ||||||||||||||||
Interest expense | (83 | ) | |||||||||||||||
Income tax | 197 | ||||||||||||||||
All Others | (16 | ) | |||||||||||||||
2015 2nd Quarter Adjusted Net Loss | $ | (51 | ) | ||||||||||||||
2014 Six Month Adjusted Net Income | $ | 469 | |||||||||||||||
Price - Oil and NGLs | (1,099 | ) | |||||||||||||||
Price - Natural Gas | (86 | ) | |||||||||||||||
Volume | 149 | ||||||||||||||||
Production cost rate | 57 | ||||||||||||||||
DD&A rate | 106 | ||||||||||||||||
Exploration expense | 22 | ||||||||||||||||
Interest expense | (162 | ) | |||||||||||||||
Income tax | 415 | ||||||||||||||||
All Others | (19 | ) | |||||||||||||||
2015 Six Month Adjusted Net Loss | $ | (148 | ) | ||||||||||||||
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Attachment 4 | |||||||||||||||||
CAPITAL INVESTMENTS | |||||||||||||||||
Second Quarter | Six Months | ||||||||||||||||
($ millions) | 2015 | 2014 | 2015 | 2014 | |||||||||||||
Capital Investments: | |||||||||||||||||
Conventional | $ | 78 | $ | 344 | $ | 180 | $ | 674 | |||||||||
Unconventional | — | 147 | 17 | 272 | |||||||||||||
Exploration | 3 | 37 | 13 | 57 | |||||||||||||
Corporate and Other | 14 | — | 18 | — | |||||||||||||
$ | 95 | $ | 528 | $ | 228 | $ | 1,003 | ||||||||||
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Attachment 5 | |||||||||||||
PRODUCTION STATISTICS | |||||||||||||
Second Quarter | Six Months | ||||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||||
Net Oil, NGLs and Natural Gas Production Per Day | |||||||||||||
Oil (MBbl/d) | |||||||||||||
San Joaquin Basin | 67 | 62 | 67 | 62 | |||||||||
Los Angeles Basin | 31 | 29 | 33 | 28 | |||||||||
Ventura Basin | 6 | 6 | 6 | 6 | |||||||||
Sacramento Basin | — | — | — | — | |||||||||
Total | 104 | 97 | 106 | 96 | |||||||||
NGLs (MBbl/d) | |||||||||||||
San Joaquin Basin | 17 | 17 | 17 | 17 | |||||||||
Los Angeles Basin | — | — | — | — | |||||||||
Ventura Basin | 1 | 1 | 1 | 1 | |||||||||
Sacramento Basin | — | — | — | — | |||||||||
Total | 18 | 18 | 18 | 18 | |||||||||
Natural Gas (MMcf/d) | |||||||||||||
San Joaquin Basin | 175 | 182 | 177 | 177 | |||||||||
Los Angeles Basin | 2 | — | 2 | — | |||||||||
Ventura Basin | 11 | 12 | 12 | 12 | |||||||||
Sacramento Basin | 46 | 49 | 47 | 54 | |||||||||
Total | 234 | 243 | 238 | 243 | |||||||||
Total Barrels of Oil Equivalent (MBoe/d) | 161 | 156 | 163 | 155 | |||||||||
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Attachment 6 | |||||||||||||||||
PRICE STATISTICS | |||||||||||||||||
Second Quarter | Six Months | ||||||||||||||||
2015 | 2014 | 2015 | 2014 | ||||||||||||||
Realized Prices | |||||||||||||||||
Oil ($/Bbl) | $ | 56.73 | $ | 104.50 | $ | 51.51 | $ | 103.43 | |||||||||
NGLs ($/Bbl) | $ | 20.47 | $ | 49.08 | $ | 21.00 | $ | 54.86 | |||||||||
Natural gas ($/Mcf) | $ | 2.49 | $ | 4.52 | $ | 2.67 | $ | 4.67 | |||||||||
Index Prices | |||||||||||||||||
Brent oil ($/Bbl) | $ | 63.50 | $ | 109.77 | $ | 59.33 | $ | 108.83 | |||||||||
WTI oil ($/Bbl) | $ | 57.94 | $ | 102.99 | $ | 53.29 | $ | 100.84 | |||||||||
NYMEX gas ($/MMBtu) | $ | 2.74 | $ | 4.55 | $ | 2.90 | $ | 4.60 | |||||||||
Realized Prices as Percentage of Index Prices | |||||||||||||||||
Oil as a percentage of Brent | 89 | % | 95 | % | 87 | % | 95 | % | |||||||||
Oil as a percentage of WTI | 98 | % | 101 | % | 97 | % | 103 | % | |||||||||
NGLs as a percentage of Brent | 32 | % | 45 | % | 35 | % | 50 | % | |||||||||
NGLs as a percentage of WTI | 35 | % | 48 | % | 39 | % | 54 | % | |||||||||
Natural gas as a percentage of NYMEX | 91 | % | 99 | % | 92 | % | 102 | % | |||||||||
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Attachment 7 | |||
2015 THIRD QUARTER GUIDANCE | |||
Anticipated Realizations Against the Prevailing Index Prices for Q3 2015 | |||
Oil | 87% to 91% of Brent | ||
NGLs | 31% to 35% of Brent | ||
Natural Gas | 96% to 100% of NYMEX | ||
2015 Third Quarter Production, Capital and Income Statement Guidance | |||
Production | 153 to 159 Mboe per day | ||
Capital | $105 million to $115 million | ||
Production costs | $17.25 to $17.75 per boe | ||
General and administrative expenses | $5.10 to $5.30 per boe | ||
Depreciation, depletion and amortization | $17.25 to $17.45 per boe | ||
Taxes other than on income | $40 million to $44 million | ||
Exploration expense | $9 million to $13 million | ||
Interest expense | $82 million to $84 million | ||
Income tax expense rate | 40% | ||
Cash tax rate | 0% | ||
Pre-tax Quarterly Price Sensitivities | On Income (a) | On Cash (a) | |
$1 change in Brent index | $7 million | $7 million | |
$1 change in NGLs | $0.5 million | $0.5 million | |
$0.50 change in NYMEX gas | $4 million | $4 million | |
Quarterly Volumes Sensitivities | |||
$1 change in the Brent index (a) | 300 Boe/d | ||
(a) Reflects the effect of production sharing type contracts in our Wilmington field operations. | |||
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Attachment 8 | ||||||||||
SECOND QUARTER DRILLING ACTIVITY | ||||||||||
San Joaquin | Los Angeles | Ventura | Sacramento | |||||||
Wells Drilled (Gross) | Basin | Basin | Basin | Basin | Total | |||||
Development Wells | ||||||||||
Primary | — | — | — | — | — | |||||
Waterflood | 6 | 10 | — | — | 16 | |||||
Steamflood | 93 | — | — | — | 93 | |||||
Unconventional | — | — | — | — | — | |||||
Total | 99 | 10 | — | — | 109 | |||||
Exploration Wells | ||||||||||
Primary | — | — | — | — | — | |||||
Waterflood | — | — | — | — | — | |||||
Steamflood | — | — | — | — | — | |||||
Unconventional | — | — | — | — | — | |||||
Total | — | — | — | — | — | |||||
Total Wells | 99 | 10 | — | — | 109 | |||||
Development Drilling Capital ($ millions) | $20 | $15 | — | — | $35 | |||||
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