NEWS RELEASE
For immediate release
California Resources Corporation Announces
Third Quarter 2015 Financial Results
LOS ANGELES, November 5, 2015 – California Resources Corporation (NYSE:CRC), an independent California-based oil and gas exploration and production company, today announced an adjusted net loss1 of $86 million or ($0.22) per diluted share for the third quarter of 2015, compared with adjusted net income of $188 million or $0.48 per diluted share for the third quarter of 2014. The adjusted net loss for the first nine months of 2015 was $234 million or ($0.61) per diluted share, compared with an adjusted net income of $657 million or $1.69 per diluted share for the same period in 2014. Adjusted EBITDAX2 for the third quarter of 2015 was $212 million, compared with $662 million for the third quarter of 2014. Adjusted EBITDAX for the first nine months of 2015 was $680 million, compared with $2.1 billion for the first nine months of 2014.
Highlights Include:
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| • | Quarterly crude oil production of 103,000 barrels per day |
| |
| • | Quarterly total production of 158,000 BOE per day |
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| • | Third quarter 2015 Adjusted EBITDAX of $212 million |
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| • | Operating cash flow of $180 million in the third quarter of 2015 |
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| • | Capital investment of $95 million in the third quarter of 2015 |
Todd Stevens, President and Chief Executive Officer, said, "The strength of CRC's world class resource base and our workforce's unwavering focus on both protecting our base production and defending our margins have been displayed again in the third quarter. We held crude oil production essentially flat sequentially and decreased our debt balance by over $100 million by remaining cash flow positive and investing in projects that exceed our VCI threshold of 1.3."
1 See reconciliation on Attachment 2.
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.
Mr. Stevens continued, "We continue to focus significant attention on deleveraging our balance sheet. In conjunction with our recent cost saving actions and the current environment, we felt it was prudent to suspend our dividend. At this point, we have narrowed down the opportunities, as well as the number of possible partners for each opportunity, to a handful. As I have said before, we have been very diligent and selective in our approach to execute on transactions we believe will maximize the value to our shareholders, as opposed to rushing into any deal. This, inevitably, has led to a longer process but we are working to announce at least one asset monetization transaction this year.
Our new credit agreement amendment provides additional liquidity and flexibility as we continue our deleveraging plan. The amendment provides full availability of our $2 billion revolver, subject to our covenant restrictions, and the flexibility to manage through CRC’s deleveraging opportunities including our midstream monetizations and upstream joint venture initiatives or through capital market alternatives. Under our transition to a secured facility governed by a borrowing base, we believe that our borrowing base will exceed the level of our borrowings. In our opinion, our continued dialogue and transparency with our lending group lead to positive outcomes and increased credibility.”
Third Quarter Results
The adjusted net loss was $86 million or ($0.22) per diluted share for the third quarter of 2015, compared with adjusted net income of $188 million or $0.48 per diluted share for the same period of 2014. The 2015 quarter reflected higher oil volumes, and lower production costs, depreciation, depletion and amortization expense (DD&A), adjusted general and administrative expense, exploration expense and ad valorem tax expense, offset by significantly lower realized oil, NGL and gas prices and higher interest expense resulting from our current capital structure as an independent company. The net loss for the current quarter was $104 million or ($0.27) per diluted share, compared with a net income of $188 million or $0.48 per diluted share for the same period of 2014. The third quarter 2015 adjusted net loss excludes the effects of a pre-tax $62 million charge for our voluntary retirement program and employee reductions described below, non-cash hedge income of $53 million and other charges and the related tax effects of $9 million. Adjusted EBITDAX for the third quarter of 2015 was $212 million.
In light of the prevailing low commodity price environment, CRC took additional steps in the third quarter of 2015 to better align its workforce with a longer term moderate price environment, including a voluntary retirement program and limited layoffs. These actions resulted in a total pre-tax charge of $62 million in the third quarter of 2015. A significant majority of these costs will be paid to the affected employees over a period of up to 18 months. CRC expects total annual pre-tax savings of approximately $50 million resulting from these actions, the majority of which will affect production costs and general and administrative expenses. At year-end 2015, we expect to have approximately 1,700 employees, a 15% reduction from our employment at year-end 2014.
Average oil production increased by 3 percent or 3,000 barrels per day to 103,000 barrels per day in the third quarter of 2015, compared to the same period of the prior year. NGL production decreased by 5 percent to 18,000 barrels per day and natural gas production decreased by 9 percent to 226 million cubic feet (MMcf) per day. Daily oil and gas production
volumes averaged 158,000 barrels of oil equivalent (BOE) in the third quarter of 2015, compared with 160,000 BOE in the third quarter of 2014.
Realized crude oil prices decreased 50 percent to $47.79 per barrel including the effect of realized hedges in the third quarter of 2015 from $96.27 per barrel in the third quarter of 2014. The realized crude oil price in the third quarter before the effect of hedges was $46.10 per barrel. The decrease, including the 2015 hedge effect, reflected the drop in global oil prices. Realized NGL prices decreased 64 percent to $16.92 per barrel in the third quarter of 2015 from $47.20 per barrel in the third quarter of 2014. Realized natural gas prices decreased 33 percent in the third quarter of 2015 to $2.83 per thousand cubic feet (Mcf), compared with $4.24 per Mcf in the same period of 2014.
Production costs for the third quarter of 2015 were $246 million or $16.91 per BOE, compared with $271 million or $18.35 per BOE for the third quarter of 2014, an 8-percent reduction on a BOE basis. The decrease was driven by cost reductions across the board, particularly in well servicing efficiency, surface operations and energy use, and was also aided by lower natural gas and power prices. Adjusted general and administrative expenses were $67 million or $4.61 per BOE for the third quarter of 2015, compared with $78 million or $5.28 per BOE for the third quarter of 2014. Exploration expenses for the third quarter of 2015 were $5 million and $25 million for the same period of 2014. Ad valorem taxes were $31 million for the third quarter of 2015 and $42 million for the same period of 2014.
Operating cash flow was $180 million for the third quarter of 2015, compared with $631 million for the third quarter of 2014.
Nine Month Results
The adjusted net loss for the first nine months of 2015 was $234 million or ($0.61) per diluted share, compared with an adjusted net income of $657 million or $1.69 per diluted share for the first nine months of 2014. The first nine months in 2015 reflected higher oil as well as total volumes, and lower production costs, DD&A, exploration expense and ad valorem tax expense, offset by significantly lower realized product prices in 2015 and higher interest expense. The net loss for the first nine months of 2015 was $272 million or ($0.71) per diluted share compared to a net income of $657 million or $1.69 per diluted share for the first nine months of 2014. The nine months 2015 adjusted net loss excludes the effects of pre-tax charges of $72 million for voluntary retirement and employee reductions mainly in the third quarter, non-cash hedge income of $33 million and other charges and the related tax effects of $1 million. Adjusted EBITDAX for the first nine months of 2015 was $680 million, compared with $2.1 billion for the first nine months of 2014.
For the first nine months of 2015 daily oil and natural gas production averaged 161,000 BOE, compared with 157,000 BOE in the first nine months of 2014. Average oil production increased 8,000 barrels per day, or by 8 percent, to 105,000 barrels per day in 2015. NGL production decreased by 5 percent to 18,000 barrels per day and natural gas production decreased by 5 percent to 234 MMcf per day.
Realized crude oil prices decreased 50 percent to $50.28 per barrel including the effect of realized hedges for the first nine months of 2015 from $100.94 per barrel for the first nine months of 2014. The realized crude oil price for the first nine months before the effect of hedges was $49.70 per barrel. Realized NGL prices decreased 62 percent to $19.64 per barrel in the first nine months of 2015 from $52.26 per barrel for the first nine months of 2014.
Realized natural gas prices decreased 40 percent to $2.72 per Mcf in the first nine months of 2015, compared with $4.53 per Mcf in the first nine months of 2014.
For the first nine months of 2015, production costs were $730 million or $16.56 per BOE, compared with $805 million or $18.78 per BOE for the first nine months of 2014, a 12-percent reduction on a BOE basis. The decrease was driven by the same factors discussed in the quarterly decline. Adjusted general and administrative expenses were $218 million or $4.95 per BOE for the first nine months of 2015, compared with $218 million or $5.09 per BOE for the first nine months of 2014. Exploration expenses for the first nine months of 2015 were $29 million and $71 million for the same period of 2014. Ad valorem taxes were $111 million for the first nine months of 2015 and $120 million for the same period of 2014.
Operating cash flow was $412 million for the first nine months of 2015, compared with $1.9 billion for the same period in 2014.
Third Quarter Operational Update
In the quarter, CRC continued to run three drilling rigs with 2 focused in the San Joaquin basin and 1 in the Los Angeles basin. In the San Joaquin basin, CRC drilled 65 steamflood wells including 38 wells in the Lost Hills field, 15 in the Kern Front field and 12 additional wells in the rest of the basin. In the Los Angeles basin, CRC drilled 8 waterflood wells in the Wilmington field. As a result of capital efficiencies across the company, CRC has drilled 21 more wells than its plan year-to-date. In addition, during the third quarter, CRC completed 19 capital workovers.
Credit Agreement Amendment
CRC recently amended its $3 billion credit facility, which includes a $2 billion senior revolver and $1 billion senior term loan, with our 20-bank syndication group. The key attributes include:
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| • | Facility transitions to a $3 billion secured facility from a senior unsecured credit facility. |
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| • | The initial borrowing base was confirmed at the $3 billion capacity, with the removal of the $750 million minimum liquidity requirement. |
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| • | The February credit agreement amendment covenants are removed and replaced with a leverage ratio (debt to EBITDAX) on our credit facility (first-lien) with a cap of 2.25x and an interest expense ratio (EBITDAX to interest expense) with a floor of 2.0x during the borrowing base period. |
As of September 30, our outstanding balance on our credit facility, including the term loan, was $1,481 million. Our ability to borrow under the $3 billion credit facility would be further subject to our financial covenants.
Dividend Suspended
CRC's Board of Directors has decided to suspend the payment of CRC's quarterly dividend of $0.01 per share, beginning immediately. This decision is consistent with the Company's broader initiatives to cut costs and reduce overall debt levels. In the longer term, CRC's Board will re-evaluate the payment of dividends as commodity prices normalize.
Hedging Update
Since the last earnings release, CRC extended its existing hedge program to protect the 2016 capital plan using primarily costless collars. Covering the first half of 2016, CRC has hedged 30,500 barrels of oil per day at a weighted average floor of $52.38 per barrel with 35,500 barrels per day with a weighted average ceiling of $66.15 per barrel. Additionally, CRC entered into collars for 3,000 barrels per day of second half 2016 production at a weighted average floor and ceiling of $50.00 and $74.42 per barrel, respectively, and in November, a 1,000 barrels per day swap at $61.25 per barrel.
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/10072663. 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. 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 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 subsequent 10Qs 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:
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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 | | | | | | | | | |
| | | Third Quarter | | Nine Months | |
| ($ and shares in millions, except per share amounts) | | 2015 | | 2014 | | 2015 | | 2014 | |
| | | | | | | | | | |
| Statement of Operations Data: | | | | | | | | | |
| Revenues | | | | | | | | | |
| Oil and gas sales | | $ | 596 |
| | $ | 1,051 |
| | $ | 1,754 |
| | $ | 3,238 |
| |
| Other revenue | | 30 |
| | 41 |
| | 83 |
| | 115 |
| |
| | | 626 |
| | 1,092 |
| | 1,837 |
| | 3,353 |
| |
| Costs and other deductions | | | | | | | | | |
| Production costs | | 246 |
| | 271 |
| | 730 |
| | 805 |
| |
| General and administrative expenses | | 129 |
| | 78 |
| | 290 |
| | 218 |
| |
| Depreciation, depletion and amortization | | 253 |
| | 304 |
| | 757 |
| | 886 |
| |
| Taxes other than on income | | 42 |
| | 56 |
| | 150 |
| | 163 |
| |
| Exploration expense | | 5 |
| | 25 |
| | 29 |
| | 71 |
| |
| Interest and debt expense, net | | 82 |
| | — |
| | 244 |
| | — |
| |
| Other expenses | | 23 |
| | 39 |
| | 74 |
| | 109 |
| |
| | | 780 |
| | 773 |
| | 2,274 |
| | 2,252 |
| |
| Income / (loss) before income taxes | | (154 | ) | | 319 |
| | (437 | ) | | 1,101 |
| |
| Income tax (expense) / benefit | | 50 |
| | (131 | ) | | 165 |
| | (444 | ) | |
| Net income / (loss) | | $ | (104 | ) | | $ | 188 |
| | $ | (272 | ) | | $ | 657 |
| |
| | | | | | | | | | |
| EPS - diluted | | $ | (0.27 | ) | | $ | 0.48 |
| | $ | (0.71 | ) | | $ | 1.69 |
| |
| | | | | | | | | | |
| Adjusted net income / (loss) | | $ | (86 | ) | | $ | 188 |
| | $ | (234 | ) | | $ | 657 |
| |
| Adjusted EPS - diluted | | $ | (0.22 | ) | | $ | 0.48 |
| | $ | (0.61 | ) | | $ | 1.69 |
| |
| | | | | | | | | | |
Weighted average diluted shares outstanding (a) | | 383.1 |
| | 381.8 |
| | 382.7 |
| | 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 | | $ | 212 |
| | $ | 662 |
| | $ | 680 |
| | $ | 2,094 |
| |
| Effective tax rate | | 32 | % | | 41 | % | | 38 | % | | 40 | % | |
| | | | | | | | | | |
| Cash Flow Data: | | | | | | | | | |
| Net cash provided by operating activities | | $ | 180 |
| | $ | 631 |
| | $ | 412 |
| | $ | 1,867 |
| |
| Net cash used by investing activities | | $ | (102 | ) | | $ | (575 | ) | | $ | (542 | ) | | $ | (1,614 | ) | |
| Net cash provided (used) by financing activities | | $ | (111 | ) | | $ | 49 |
| | $ | 120 |
| | $ | (148 | ) | |
| | | | | | | | | | |
| Balance Sheet Data: | | September 30, | | December 31, | | | | | |
| | | 2015 | | 2014 | | | | | |
| Total current assets | | $ | 602 |
| | $ | 701 |
| | | | | |
| Property, plant and equipment, net | | $ | 11,257 |
| | $ | 11,685 |
| | | | | |
| Total current liabilities | | $ | 748 |
| | $ | 922 |
| | | | | |
| Long-term debt, net | | $ | 6,345 |
| | $ | 6,292 |
| | | | | |
| Total equity | | $ | 2,355 |
| | $ | 2,611 |
| | | | | |
| | | | | | | | | | |
| Outstanding shares | | 387.8 |
| | 385.6 |
| | | | | |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | |
| 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: |
| | | | | | | | |
| | | Third Quarter | | Nine Months | |
| ($ millions) | | 2015 | | 2014 | | 2015 | | 2014 | |
| Net income / (loss) | | $ | (104 | ) | | $ | 188 |
| | $ | (272 | ) | | $ | 657 |
| |
| Interest expense | | 82 |
| | — |
| | 244 |
| | — |
| |
| Income tax expense / (benefit) | | (50 | ) | | 131 |
| | (165 | ) | | 444 |
| |
| Depreciation, depletion and amortization | | 253 |
| | 304 |
| | 757 |
| | 886 |
| |
| Exploration expense | | 5 |
| | 25 |
| | 29 |
| | 71 |
| |
| Other | | 26 |
| | 14 |
| | 87 |
| | 36 |
| |
| Adjusted EBITDAX | | $ | 212 |
| | $ | 662 |
| | $ | 680 |
| | $ | 2,094 |
| |
| | | | | | | | | | |
| Net cash provided by operating activities | | $ | 180 |
| | $ | 631 |
| | $ | 412 |
| | $ | 1,867 |
| |
| Interest expense | | 82 |
| | — |
| | 244 |
| | — |
| |
| Cash income taxes | | — |
| | 47 |
| | — |
| | 182 |
| |
| Cash exploration expense | | 3 |
| | 6 |
| | 20 |
| | 19 |
| |
| Changes in operating assets and liabilities | | (7 | ) | | (35 | ) | | 43 |
| | 12 |
| |
| Other, net | | (46 | ) | | 13 |
| | (39 | ) | | 14 |
| |
| Adjusted EBITDAX | | $ | 212 |
| | $ | 662 |
| | $ | 680 |
| | $ | 2,094 |
| |
| | | | | | | | | | |
| 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): |
| | | Third Quarter | | Nine Months | |
| ($ millions, except per share amounts) | | 2015 | | 2014 | | 2015 | | 2014 | |
| Net income / (loss) | | $ | (104 | ) | | $ | 188 |
| | $ | (272 | ) | | $ | 657 |
| |
| Hedge related gains | | (53 | ) | | — |
| | (33 | ) | | — |
| |
| Early retirement and severance costs | | 62 |
| | — |
| | 72 |
| | — |
| |
| Rig terminations and other costs | | 3 |
| | — |
| | 6 |
| | — |
| |
| Tax related adjustments | | 6 |
| | — |
| | (7 | ) | | — |
| |
| Adjusted net income / (loss) | | $ | (86 | ) | | $ | 188 |
| | $ | (234 | ) | | $ | 657 |
| |
| | | | | | | | | | |
| Adjusted EPS - diluted | | $ | (0.22 | ) | | $ | 0.48 |
| | $ | (0.61 | ) | | $ | 1.69 |
| |
|
| | | | | | | | | | | | | | | | | |
| Attachment 3 |
| ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES | | | |
| | | Third Quarter | | Nine Months | |
| ($ millions) | | 2015 | | 2014 | | 2015 | | 2014 | |
| General and administrative expenses per statements | | | | | | | | | |
| of operations | | $ | 129 |
| | $ | 78 |
| | $ | 290 |
| | $ | 218 |
| |
| Early retirement and severance costs | | (62 | ) | | — |
| | (72 | ) | | — |
| |
| Adjusted general and administrative expenses | | $ | 67 |
| | $ | 78 |
| | $ | 218 |
| | $ | 218 |
| |
| | | | | | | | | | |
| | | | | | | | | | |
| |
| ADJUSTED NET INCOME / (LOSS) VARIANCE ANALYSIS |
| ($ millions) | | | | | | | | | |
| | | | | | | | | | |
| 2014 3rd Quarter Adjusted Net Income | | $ | 188 |
| | | | | | | |
| | | | | | | | | | |
| Price - Oil and NGLs | | (504 | ) | | | | | | | |
| Price - Natural Gas | | (29 | ) | | | | | | | |
| Volume | | 14 |
| | | | | | | |
| Production cost rate | | 24 |
| | | | | | | |
| DD&A rate | | 45 |
| | | | | | | |
| Exploration expense | | 20 |
| | | | | | | |
| Interest expense | | (82 | ) | | | | | | | |
| Income tax | | 187 |
| | | | | | | |
| All Others | | 51 |
| | | | | | | |
| | | | | | | | | | |
| 2015 3rd Quarter Adjusted Net Loss | | $ | (86 | ) | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| 2014 Nine Month Adjusted Net Income | | $ | 657 |
| | | | | | | |
| | | | | | | | | | |
| Price - Oil and NGLs | | (1,599 | ) | | | | | | | |
| Price - Natural Gas | | (114 | ) | | | | | | | |
| Volume | | 146 |
| | | | | | | |
| Production cost rate | | 81 |
| | | | | | | |
| DD&A rate | | 150 |
| | | | | | | |
| Exploration expense | | 42 |
| | | | | | | |
| Interest expense | | (244 | ) | | | | | | | |
| Income tax | | 602 |
| | | | | | | |
| All Others | | 45 |
| | | | | | | |
| | | | | | | | | | |
| 2015 Nine Month Adjusted Net Loss | | $ | (234 | ) | | | | | | | |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | Attachment 4 |
| CAPITAL INVESTMENTS | | | | | | | | | |
| | | Third Quarter | | Nine Months | |
| ($ millions) | | 2015 | | 2014 | | 2015 | | 2014 | |
| Capital Investments: | | | | | | | | | |
| Conventional | | $ | 86 |
| | $ | 367 |
| | $ | 266 |
| | $ | 1,041 |
| |
| Unconventional | | — |
| | 171 |
| | 17 |
| | 443 |
| |
| Exploration | | 4 |
| | 21 |
| | 17 |
| | 79 |
| |
| Corporate and Other | | 5 |
| | 7 |
| | 23 |
| | 6 |
| |
| | | $ | 95 |
| | $ | 566 |
| | $ | 323 |
| | $ | 1,569 |
| |
| | | | | | | | | | |
| |
|
| | | | | | | | | | | | | |
| | | | | | | | | Attachment 5 |
| PRODUCTION STATISTICS | | | | | | | | | |
| | | | | | |
| | | Third Quarter | | Nine Months | |
| Net Oil, NGLs and Natural Gas Production Per Day | | 2015 | | 2014 | | 2015 | | 2014 | |
| | | | | | | | | | |
| Oil (MBbl/d) | | | | | | | | | |
| San Joaquin Basin | | 64 |
| | 65 |
| | 65 |
| | 63 |
| |
| Los Angeles Basin | | 32 |
| | 29 |
| | 33 |
| | 28 |
| |
| Ventura Basin | | 7 |
| | 6 |
| | 7 |
| | 6 |
| |
| Sacramento Basin | | — |
| | — |
| | — |
| | — |
| |
| Total | | 103 |
| | 100 |
| | 105 |
| | 97 |
| |
| | | | | | | | | | |
| NGLs (MBbl/d) | | | | | | | | | |
| San Joaquin Basin | | 17 |
| | 18 |
| | 17 |
| | 18 |
| |
| Los Angeles Basin | | — |
| | — |
| | — |
| | — |
| |
| Ventura Basin | | 1 |
| | 1 |
| | 1 |
| | 1 |
| |
| Sacramento Basin | | — |
| | — |
| | — |
| | — |
| |
| Total | | 18 |
| | 19 |
| | 18 |
| | 19 |
| |
| | | | | | | | | | |
| Natural Gas (MMcf/d) | | | | | | | | | |
| San Joaquin Basin | | 172 |
| | 182 |
| | 175 |
| | 179 |
| |
| Los Angeles Basin | | 1 |
| | 2 |
| | 3 |
| | 1 |
| |
| Ventura Basin | | 11 |
| | 9 |
| | 11 |
| | 11 |
| |
| Sacramento Basin | | 42 |
| | 56 |
| | 45 |
| | 55 |
| |
| Total | | 226 |
| | 249 |
| | 234 |
| | 246 |
| |
| | | | | | | | | | |
| Total Barrels of Oil Equivalent (MBoe/d) | | 158 |
| | 160 |
| | 161 |
| | 157 |
| |
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | Attachment 6 |
| PRICE STATISTICS | | | | | | | | | |
| | | Third Quarter | | Nine Months | |
| | | 2015 | | 2014 | | 2015 | | 2014 | |
| Realized Prices | | | | | | | | | |
| Oil with hedge ($/Bbl) | | $ | 47.79 |
| | $ | 96.27 |
| | $ | 50.28 |
| | $ | 100.94 |
| |
| Oil without hedge ($/Bbl) | | $ | 46.10 |
| | $ | 96.27 |
| | $ | 49.70 |
| | $ | 100.94 |
| |
| NGLs ($/Bbl) | | $ | 16.92 |
| | $ | 47.20 |
| | $ | 19.64 |
| | $ | 52.26 |
| |
| Natural gas ($/Mcf) | | $ | 2.83 |
| | $ | 4.24 |
| | $ | 2.72 |
| | $ | 4.53 |
| |
| | | | | | | | | | |
| Index Prices | | | | | | | | | |
| Brent oil ($/Bbl) | | $ | 51.17 |
| | $ | 103.39 |
| | $ | 56.61 |
| | $ | 107.02 |
| |
| WTI oil ($/Bbl) | | $ | 46.43 |
| | $ | 97.17 |
| | $ | 51.00 |
| | $ | 99.61 |
| |
| NYMEX gas ($/MMBtu) | | $ | 2.78 |
| | $ | 4.17 |
| | $ | 2.86 |
| | $ | 4.46 |
| |
| | | | | | | | | | |
| Realized Prices as Percentage of Index Prices |
| Oil with hedge as a percentage of Brent | | 93 | % | | 93 | % | | 89 | % | | 94 | % | |
| Oil without hedge as a percentage of Brent | | 90 | % | | 93 | % | | 88 | % | | 94 | % | |
| Oil with hedge as a percentage of WTI | | 103 | % | | 99 | % | | 99 | % | | 101 | % | |
| Oil without hedge as a percentage of WTI | | 99 | % | | 99 | % | | 97 | % | | 101 | % | |
| NGLs as a percentage of Brent | | 33 | % | | 46 | % | | 35 | % | | 49 | % | |
| NGLs as a percentage of WTI | | 36 | % | | 49 | % | | 39 | % | | 52 | % | |
| Natural gas as a percentage of NYMEX | | 102 | % | | 102 | % | | 95 | % | | 102 | % | |
|
| | | |
| | | | Attachment 7 |
| 2015 FOURTH QUARTER GUIDANCE | | | |
| | | | |
Anticipated Realizations Against the Prevailing Index Prices for Q4 2015 (a) | |
| Oil | 86% to 90% of Brent | | |
| NGLs | 36% to 40% of Brent | | |
| Natural Gas | 93% to 97% of NYMEX | | |
| | | | |
| 2015 Fourth Quarter Production, Capital and Income Statement Guidance | |
| Production | 151 to 156 Mboe per day | | |
| Capital | $90 million to $100 million | | |
| Production costs | $16.75 to $17.25 per boe | | |
| General and administrative expenses | $4.85 to $5.05 per boe | | |
| Depreciation, depletion and amortization | $17.40 to $17.60 per boe | | |
| Taxes other than on income | $38 million to $42 million | | |
| Exploration expense | $6 million to $10 million | | |
| Interest expense | $82 million to $84 million | | |
| Income tax expense rate | 40% | | |
| Cash tax rate | 0% | | |
| | | | |
| Pre-tax Quarterly Price Sensitivities | On Income (b) | On Cash (b) | |
| $1 change in Brent index - Oil | $7.5 million | $7.5 million | |
| $1 change in Brent index - NGLs | $0.5 million | $0.5 million | |
| $0.50 change in NYMEX - Gas | $4.5 million | $4.5 million | |
| | | | |
| Quarterly Volumes Sensitivities | | | |
$1 change in the Brent index (c) | 350 Boe/d | | |
| | | | |
| (a) Realizations exclude hedge effects. |
| (b) All amounts exclude hedge effects and reflect the effect of production sharing type contracts in our Wilmington field operations. |
| (c) Reflects the effect of production sharing type contracts in our Wilmington field operations. |
|
| | | | | | | | | | |
| | | | | | | | | | | Attachment 8 |
| THIRD QUARTER DRILLING ACTIVITY | | | | | | | | | | |
| | | San Joaquin | | Los Angeles | | Ventura | | Sacramento | | |
| Wells Drilled (Gross) | | Basin | | Basin | | Basin | | Basin | | Total |
| | | | | | | | | | | |
| Development Wells | | | | | | | | | | |
| Primary | | — | | — | | — | | — | | — |
Waterflood a | | — | | 8 | | — | | — | | 8 |
Steamflood b | | 61 | | — | | — | | — | | 61 |
| Unconventional | | — | | — | | — | | — | | — |
| Total | | 61 | | 8 | | — | | — | | 69 |
| | | | | | | | | | | |
| Exploration Wells | | | | | | | | | | |
| Primary | | — | | — | | — | | — | | — |
| Waterflood | | — | | — | | — | | — | | — |
| Steamflood | | 4 | | — | | — | | — | | 4 |
| Unconventional | | — | | — | | — | | — | | — |
| Total | | 4 | | — | | — | | — | | 4 |
| Total Wells | | 65 | | 8 | | — | | — | | 73 |
| | | | | | | | | | | |
Development Drilling Capital ($ millions) | | $11 | | $12 | | — | | — | | $23 |
| | | | | | | | | | | |
| (a) Waterflood wells include 1 injector well. | | |
| (b) Steamflood wells include 10 injector and disposal wells. | | |
