LOS ANGELES--(BUSINESS WIRE)--California Resources Corporation ("CRC" or the "Company") (NYSE:CRC), an independent California-based oil and gas exploration and production company, today announced a net loss of $140 million or $3.51 per diluted share for the second quarter of 2016, compared with a net loss of $68 million or $1.78 per diluted share for the same period in 2015. The adjusted net loss1 for the second quarter of 2016 was $72 million or $1.80 per diluted share, compared with an adjusted net loss of $51 million or $1.33 per diluted share for the same period in 2015. For the first six months of 2016, the net loss was $190 million or $4.85 per diluted share, compared with a net loss of $168 million or $4.40 per diluted share for the same period in 2015. The adjusted net loss for the first six months of 2016 was $172 million or $4.39 per diluted share, compared with an adjusted net loss of $148 million or $3.87 per diluted share for the same period of 2015. Adjusted EBITDAX2 for the second quarter and first six months of 2016 was $160 million and $284 million, respectively, compared with $270 million and $468 million for the second quarter and first six months of 2015.
Quarterly Highlights Include:
- Quarterly total production of 140,000 BOE per day
- 22% reduction in quarterly production costs year-over-year
- 28% reduction in quarterly general and administrative costs year-over-year
- $80 million debt reduction in exchange for common stock during the quarter
- Cash from settled hedges of $2.29 per barrel of oil for the quarter
Todd Stevens, President and Chief Executive Officer, said, "While the second quarter price improvements were welcome, we continued our commitment to executing on items within our control, remaining focused on our core financial and operating tenets. Over the past year we have reduced our debt by approximately $700 million from the post-spin peak reached in early 2015. The recently announced tender would take us another step closer to our long term goals, and we remain focused on continued deleveraging efforts."
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.
Second Quarter Results
For the second quarter of 2016, CRC reported a net loss of $140 million or $3.51 per diluted share, compared with a net loss of $68 million or $1.78 per diluted share for the same period of 2015. The 2016 quarter reflected lower production costs, general and administrative expense, ad valorem expense, depreciation, depletion and amortization expense (DD&A), exploration expense and interest expense, as well as gains on the retirement of notes and divestiture of assets, more than offset by lower oil and gas realized prices and lower oil, natural gas liquids (NGL) and gas volumes. The second quarter 2016 adjusted net loss was $72 million or $1.80 per diluted share, compared with an adjusted net loss of $51 million or $1.33 per diluted share for the same period of 2015. The 2016 adjusted net loss excluded $137 million of non-cash derivative losses on outstanding hedges at June 30, 2016, $44 million of gains on the retirement of the Company's unsecured notes, a $31 million gain from asset divestitures, and $6 million of other non-recurring charges. The 2015 adjusted net loss excluded $17 million of after-tax non-recurring adjustments.
Adjusted EBITDAX for the second quarter of 2016 was $160 million, compared to $270 million for the same period of 2015.
Total daily production volumes averaged 140,000 barrels of oil equivalent (BOE) in the second quarter of 2016, compared with 161,000 BOE in the second quarter of 2015, a 13-percent decrease which is within CRC's stated production decline range. The second quarter 2016 production decline reflected management's decision to withhold development capital and selective deferral of workover and downhole maintenance activity in the first half of the year. The Company began increasing its activity levels gradually towards the end of the second quarter. Additionally, temporary California pipeline disruptions negatively impacted CRC's ability to sell all of the oil the Company produced in the second quarter of 2016, some of which CRC held in inventory at the end of the quarter. As a result, the actual second quarter production was slightly higher than the reported volumes, which represent sales. The Company expects this inventory to be sold in the third quarter of 2016 and be reported as production at that time. Year-over-year average oil production decreased by 13 percent, or 14,000 barrels per day, to 90,000 barrels per day in the second quarter of 2016, compared to the same period of the prior year. NGL production decreased by 11 percent to 16,000 barrels per day and natural gas production decreased by 14 percent to 202 million cubic feet (MMcf) per day.
In the second quarter of 2016, realized crude oil prices including the effect of cash received from settled hedges decreased 23 percent to $43.70 per barrel from $56.73 per barrel in the second quarter of 2015. Second quarter 2016 hedges contributed an additional $2.29 per barrel to the realized crude oil price, compared with no effect in the second quarter of 2015. Realized NGL prices increased 10 percent to $22.54 per barrel in the second quarter of 2016 from $20.47 per barrel in the second quarter of 2015. Realized natural gas prices decreased 33 percent to $1.66 per thousand cubic feet (Mcf) in the second quarter of 2016, compared with $2.49 per Mcf in the same period of 2015.
Production costs for the second quarter of 2016 were $188 million or $14.76 per BOE, compared with $242 million or $16.59 per BOE for the second quarter of 2015, a 22-percent reduction on an absolute dollar basis. The decrease was driven by cost reductions across CRC's operations, particularly in well servicing efficiency, field personnel and lower natural gas prices, as well as management's decision to selectively defer lower value workovers and downhole maintenance activity. General and administrative (G&A) expenses were $61 million or $4.80 per BOE for the second quarter of 2016, compared with $85 million or $5.82 per BOE for the second quarter of 2015, reflecting employee and contractor cost-reduction initiatives. Adjusted G&A expenses for the second quarter of 2016 were $57 million or $4.49 per BOE, compared with $75 million or $5.13 per BOE for the second quarter of 2015. Adjusted G&A expenses for both quarters excluded severance and other employee-related costs. Exploration expenses of $5 million for the second quarter of 2016 were $2 million lower than the same period of 2015. Ad valorem taxes of $26 million for the second quarter of 2016 were $14 million lower than the same period of 2015.
Six-Month Results
For the first six months of 2016, CRC reported a net loss of $190 million of $4.85 per diluted share, compared with a net loss of $168 million or $4.40 per diluted share for the same period of 2015. The 2016 results reflected lower production costs, general and administrative expense, ad valorem expense, DD&A expense, exploration expense and interest expense, as well as gains on the retirement of notes and divestiture of assets, more than offset by lower oil, NGL and gas realized prices and volumes. The first six-month adjusted net loss was $172 million or $4.39 per diluted share, compared with an adjusted net loss of $148 million or $3.87 per diluted share for the same period of 2015. The 2016 adjusted net loss excluded $218 million of non-cash derivative losses on outstanding hedges at June 30, 2016, $133 million of gains on the retirement of the company's notes, a $31 million gain from asset divestitures, a $63 million benefit from a deferred tax valuation allowance adjustment and $27 million of other non-recurring charges. The 2015 adjusted net loss excluded $20 million of after-tax non-recurring adjustments.
Adjusted EBITDAX for the first six months of 2016 was $284 million, compared to $468 million in the prior year period.
Total daily production volumes averaged 144,000 BOE in the first six months of 2016, compared with 163,000 BOE in the first six months of 2015, a 12-percent decrease which is within CRC's stated production decline range. The production decline in the first six months of 2016 reflected management's decision to withhold development capital and selective deferral of workover and downhole maintenance activity in the first half of the year. CRC's year-over-year average oil production decreased by only 11 percent, or 12,000 barrels per day, to 94,000 barrels per day in the first six months of 2016, compared with 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 16 percent to 199 MMcf per day.
Realized crude oil prices including the effect of cash received from settled hedges decreased 23 percent to $39.90 per barrel in the first half of 2016 from $51.51 per barrel in the first half of 2015. Hedges contributed $4.38 per barrel to the 2016 realized crude oil price compared with $0.03 for 2015. Realized NGL prices decreased 8 percent to $19.35 per barrel in the first half of 2016 from $21.00 per barrel in the first half of 2015. Realized natural gas prices decreased 31 percent to $1.85 per Mcf in the first half of 2016, compared with $2.67 per Mcf in the same period of 2015.
Production costs for the first half of 2016 were $372 million or $14.21 per BOE, compared with $484 million or $16.39 per BOE for the same period in 2015, a 23-percent reduction on an absolute dollar basis. The decrease was driven by cost reductions across CRC's operations, particularly in well servicing efficiency, field personnel, energy use and lower natural gas prices, as well as management's decision to increase economic thresholds and selectively defer lower value workovers and downhole maintenance activity. G&A expenses were $128 million or $4.90 per BOE for the first half of 2016, compared with $161 million or $5.45 per BOE for the same period in 2015, reflecting employee and contractor cost-reduction initiatives as well as lower 2016 stock-based compensation costs due to the lower stock price. Adjusted G&A expenses were $110 million or $4.20 per BOE for the first half of 2016, compared with $151 million or $5.11 per BOE for the same period of 2015. Adjusted G&A expenses for both years excluded severance and other employee-related costs. Exploration expenses of $10 million for the first half of 2016 were $14 million lower than the same period of 2015. Ad valorem taxes were $53 million for the first half of 2016 and $80 million for the same period of 2015.
Operating cash flow after working capital changes was $44 million for the first six months of 2016 and $232 million for the first six months of 2015. In addition to the increase in net loss, the first half of 2016 reflected higher interest payments, largely due to the timing of the payment due dates.
Operational Update
CRC did not have any drilling rigs running during the second quarter of 2016. This was consistent with CRC's significantly reduced 2016 capital program which focused on investments designed to maintain the mechanical integrity of its facilities and systems and operate them safely. The Company significantly slowed second quarter capital investment in response to low commodity prices. Management's decision to withhold development capital and defer well maintenance activity in the first half of the year reduced its production levels, particularly in the second quarter. The Company is increasing the level of its capital and well maintenance activity in the second half of the year to a pace that will bring the full-year investment to a level consistent with its plans. CRC expects that this higher activity level will reduce its production decline rate in the second half of the year to bring the full-year decline to a range consistent with its stated decline range. For 2016, CRC developed a dynamic capital program to align investments with projected 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.
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-based crude oil and NYMEX-based natural gas hedges in place:
|
Crude Oil |
||||||||||||||||||||||
| 3Q 2016 | 4Q 2016 | FY 2017 | FY 2018 | |||||||||||||||||||
|
Production |
Strike |
Production |
Strike |
Production |
Strike |
Production |
Strike |
|||||||||||||||
| Calls | 19,000 | $55.08 | 25,000 | $53.62 | 10,500 | $56.07 | 21,479 | $58.21 | ||||||||||||||
| Puts | 28,000 | $50.65 | 3,000 | $50.00 | 4,300 | $50.00 | — | — | ||||||||||||||
| Swaps | 1,000 | $61.25 | 29,000 | $49.43 | — | — | — | — | ||||||||||||||
|
Gas |
||||||||||||||||||||||||
| 3Q 2016 | 4Q 2016 | FY 2017 | FY 2018 | |||||||||||||||||||||
|
Production |
Strike |
Production |
Strike |
Production |
Strike |
Production |
Strike |
|||||||||||||||||
| Swaps | 330 | $3.13 | 5,500 | $3.50 | — |
— |
— | — | ||||||||||||||||
| Forwards | — | — | — | — | 6,200 |
$3.53 |
— | — | ||||||||||||||||
CRC Tender Offer for Outstanding Notes
As previously announced, CRC has made a cash tender of up to $525 million for its outstanding notes subject to certain conditions. For further details, please see the press release dated August 1, 2016 on CRC’s website.
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/10086916. 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, 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 | ||||||||||||||||||||||
| Second Quarter | Six Months | |||||||||||||||||||||
| ($ and shares in millions, except per share amounts) | 2016 | 2015 | 2016 | 2015 | ||||||||||||||||||
|
Statement of Operations Data: |
||||||||||||||||||||||
| Revenues and Other | ||||||||||||||||||||||
| Oil and natural gas net sales | $ | 404 | $ | 621 | $ | 733 | $ | 1,167 | ||||||||||||||
| Net derivative losses | (118 | ) | (17 | ) | (143 | ) | (18 | ) | ||||||||||||||
| Other revenue | 31 | 30 | 49 | 62 | ||||||||||||||||||
| Total revenues and other | 317 | 634 | 639 | 1,211 | ||||||||||||||||||
| Costs and Other | ||||||||||||||||||||||
| Production costs | 188 | 242 | 372 | 484 | ||||||||||||||||||
| General and administrative expenses | 61 | 85 | 128 | 161 | ||||||||||||||||||
| Depreciation, depletion and amortization | 138 | 251 | 285 | 504 | ||||||||||||||||||
| Taxes other than on income | 42 | 53 | 81 | 108 | ||||||||||||||||||
| Exploration expense | 5 | 7 | 10 | 24 | ||||||||||||||||||
| Interest and debt expense, net | 74 | 83 | 148 | 162 | ||||||||||||||||||
| Other (income) expenses, net | (51 | ) | 27 | (117 | ) | 51 | ||||||||||||||||
| Total costs and other | 457 | 748 | 907 | 1,494 | ||||||||||||||||||
| Loss before income taxes | (140 | ) | (114 | ) | (268 | ) | (283 | ) | ||||||||||||||
| Income tax benefit | — | 46 | 78 | 115 | ||||||||||||||||||
| Net loss | $ | (140 | ) | $ | (68 | ) | $ | (190 | ) | $ | (168 | ) | ||||||||||
| EPS - diluted | $ | (3.51 | ) | $ | (1.78 | ) | $ | (4.85 | ) | $ | (4.40 | ) | ||||||||||
| Adjusted net loss | $ | (72 | ) | $ | (51 | ) | $ | (172 | ) | $ | (148 | ) | ||||||||||
| Adjusted EPS - diluted | $ | (1.80 | ) | $ | (1.33 | ) | $ | (4.39 | ) | $ | (3.87 | ) | ||||||||||
| Weighted average diluted shares outstanding | 39.9 | 38.3 | 39.2 | 38.2 | ||||||||||||||||||
| Adjusted EBITDAX | $ | 160 | $ | 270 | $ | 284 | $ | 468 | ||||||||||||||
| Effective tax rate | 0 | % | 40 | % | 29 | % | 41 | % | ||||||||||||||
|
Cash Flow Data: |
||||||||||||||||||||||
| Net cash (used) provided by operating activities | $ | (71 | ) | $ | 117 | $ | 44 | $ | 232 | |||||||||||||
| Net cash provided (used) by investing activities | $ | 11 | $ | (127 | ) | $ | (18 | ) | $ | (440 | ) | |||||||||||
| Net cash provided (used) by financing activities | $ | 52 | $ | 19 | $ | (36 | ) | $ | 231 | |||||||||||||
|
Balance Sheet Data: |
June 30, | December 31, | ||||||||||||||||||||
| 2016 | 2015 | |||||||||||||||||||||
| Total current assets | $ | 386 | $ | 497 | ||||||||||||||||||
| Property, plant and equipment, net | $ | 6,073 | $ | 6,312 | ||||||||||||||||||
| Total current liabilities | $ | 592 | $ | 605 | ||||||||||||||||||
| Long-term debt, principal amount | $ | 5,843 | $ | 6,043 | ||||||||||||||||||
| Total equity | $ | (1,045 | ) | $ | (916 | ) | ||||||||||||||||
| Outstanding shares as of | 41.1 | 38.8 | ||||||||||||||||||||
| 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 other non-cash, unusual and 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: | ||||||||||||||||||||
| Second Quarter | Six Months | |||||||||||||||||||
| ($ millions) | 2016 | 2015 | 2016 | 2015 | ||||||||||||||||
| Net loss | $ | (140 | ) | $ | (68 | ) | $ | (190 | ) | $ | (168 | ) | ||||||||
| Interest and debt expense | 74 | 83 | 148 | 162 | ||||||||||||||||
| Income tax benefit | — | (46 | ) | (78 | ) | (115 | ) | |||||||||||||
| Depreciation, depletion and amortization | 138 | 251 | 285 | 504 | ||||||||||||||||
| Exploration expense | 5 | 7 | 10 | 24 | ||||||||||||||||
| Adjusted income items(a) | 68 | 28 | 81 | 33 | ||||||||||||||||
| Other non-cash items | 15 | 15 | 28 | 28 | ||||||||||||||||
| Adjusted EBITDAX | $ | 160 | $ | 270 | $ | 284 | $ | 468 | ||||||||||||
| Net cash (used) provided by operating activities | $ | (71 | ) | $ | 117 | $ | 44 | $ | 232 | |||||||||||
| Cash Interest | 132 | 95 | 180 | 149 | ||||||||||||||||
| Exploration expenditures | 5 | 6 | 10 | 17 | ||||||||||||||||
| Other changes in operating assets and liabilities | 92 | 51 | 41 | 67 | ||||||||||||||||
| Plant turnaround and other costs | 2 | 1 | 9 | 3 | ||||||||||||||||
| Adjusted EBITDAX | $ | 160 | $ | 270 | $ | 284 | $ | 468 | ||||||||||||
|
(a) For 2016, includes non-cash losses on outstanding hedges, severance and other employee-related costs, plant turnaround costs, gain on retirement of notes and gain from the sale of assets. For 2015, includes non-cash losses on outstanding hedges, severance and other employee-related costs and rig termination costs. |
||||||||||||||||||||
|
Attachment 3 |
||||||||||||||||||||
| NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS | ||||||||||||||||||||
|
Our results of operations can include the effects of non-cash, unusual and 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 administrative 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): | ||||||||||||||||||||
| Second Quarter | Six Months | |||||||||||||||||||
| ($ millions, except per share amounts) | 2016 | 2015 | 2016 | 2015 | ||||||||||||||||
| Net Loss | $ | (140 | ) | $ | (68 | ) | $ | (190 | ) | $ | (168 | ) | ||||||||
| Non-cash, unusual and infrequent items: | ||||||||||||||||||||
| Non-cash derivative losses | 137 | 17 | 218 | 20 | ||||||||||||||||
| Severance and other employee-related costs | 4 | 10 | 18 | 10 | ||||||||||||||||
| Plant turnaround and other costs | 2 | 1 | 9 | 3 | ||||||||||||||||
| Gain on retirement of notes | (44 | ) | — | (133 | ) | — | ||||||||||||||
| Gain from asset divestitures | (31 | ) | — | (31 | ) | — | ||||||||||||||
| Valuation allowance for deferred tax assets (a) | — | — | (63 | ) | — | |||||||||||||||
| Tax effects of these items | — | (11 | ) | — | (13 | ) | ||||||||||||||
| Adjusted net loss | $ | (72 | ) | $ | (51 | ) | $ | (172 | ) | $ | (148 | ) | ||||||||
| Adjusted EPS - diluted | $ | (1.80 | ) | $ | (1.33 | ) | $ | (4.39 | ) | $ | (3.87 | ) | ||||||||
| (a) Amount represents the out-of-period portion of the valuation allowance reversal. | ||||||||||||||||||||
|
DERIVATIVES GAINS AND LOSSES |
||||||||||||||||||||
| Second Quarter | Six Months | |||||||||||||||||||
| ($ millions) | 2016 | 2015 | 2016 | 2015 | ||||||||||||||||
| Non-cash derivative losses | $ | 137 | $ | 17 | $ | 218 | $ | 20 | ||||||||||||
| Proceeds from settled derivatives | (19) | - | (75 | ) | (2 | ) | ||||||||||||||
| Net derivative losses | $ | 118 | $ | 17 | $ | 143 | $ | 18 | ||||||||||||
|
FREE CASH FLOW |
||||||||||||||||||||
| Second Quarter | Six Months | |||||||||||||||||||
| ($ millions) | 2016 | 2015 | 2016 | 2015 | ||||||||||||||||
| Operating cash flow | $ | (71 | ) | $ | 117 | $ | 44 | $ | 232 | |||||||||||
| Capital investment | (5 | ) | (95 | ) | (26 | ) | (228 | ) | ||||||||||||
| Changes in capital accruals | (4 | ) | (30 | ) | (11 | ) | (203 | ) | ||||||||||||
| Free cash flow (after working capital) | $ | (80 | ) | (b) | $ | (8 | ) | $ | 7 | $ | (199 | ) | ||||||||
| (b) Second quarter 2016 operating cash flow reflects $132 million and $56 million of interest and property tax payments, respectively. | ||||||||||||||||||||
| Second Quarter | Six Months | |||||||||||||||||||
| ($ millions) | 2016 | 2015 | 2016 | 2015 | ||||||||||||||||
| EBITDAX | $ | 160 | $ | 270 | $ | 284 | $ | 468 | ||||||||||||
| Cash interest at normalized run rate | (91 | ) | (83 | ) | (182 | ) | (162 | ) | ||||||||||||
| Capital investments | (5 | ) | (95 | ) | (26 | ) | (228 | ) | ||||||||||||
| Free cash flow (before working capital) | $ | 64 | $ | 92 | $ | 76 | $ | 78 | ||||||||||||
|
ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES |
||||||||||||||||||||
| Second Quarter | Six Months | |||||||||||||||||||
| ($ millions) | 2016 | 2015 | 2016 | 2015 | ||||||||||||||||
|
General and administrative expenses per statements of operations |
||||||||||||||||||||
| $ | 61 | $ | 85 | $ | 128 | $ | 161 | |||||||||||||
| Severance and other employee-related costs | (4 | ) | (10 | ) | (18 | ) | (10 | ) | ||||||||||||
| Adjusted general and administrative expenses | $ | 57 | $ | 75 | $ | 110 | $ | 151 | ||||||||||||
| Attachment 4 | |||||||
|
ADJUSTED NET INCOME / (LOSS) VARIANCE ANALYSIS |
|||||||
| ($ millions) | |||||||
| 2015 2nd Quarter Adjusted Net Loss | $ | (51 | ) | ||||
| Price - Oil and NGLs | (121 | ) | |||||
| Price - Natural Gas | (18 | ) | |||||
| Volume | (30 | ) | |||||
| Production cost rate | 47 | ||||||
| DD&A rate | 93 | ||||||
| Exploration expense | 2 | ||||||
| Interest expense | 9 | ||||||
| Adjusted general & administrative expenses | 18 | ||||||
| Income tax | (35 | ) | |||||
| All Others | 14 | ||||||
| 2016 2nd Quarter Adjusted Net Loss | $ | (72 | ) | ||||
| 2015 Six Month Adjusted Net Loss | $ | (148 | ) | ||||
| Price - Oil and NGLs | (236 | ) | |||||
| Price - Natural Gas | (35 | ) | |||||
| Volume | (38 | ) | |||||
| Production cost rate | 99 | ||||||
| DD&A rate | 184 | ||||||
| Exploration expense | 14 | ||||||
| Interest expense | 14 | ||||||
| Adjusted general & administrative expenses | 41 | ||||||
| Income tax | (87 | ) | |||||
| All Others | 20 | ||||||
| 2016 Six Month Adjusted Net Loss | $ | (172 | ) | ||||
| Attachment 5 | |||||||||||||||||||||||
| CAPITAL INVESTMENTS | |||||||||||||||||||||||
| Second Quarter | Six Months | ||||||||||||||||||||||
| ($ millions) | 2016 | 2015 | 2016 | 2015 | |||||||||||||||||||
| Capital Investments: | |||||||||||||||||||||||
| Conventional | $ | 4 | $ | 78 | $ | 5 | $ | 180 | |||||||||||||||
| Unconventional | — | — | 1 | 17 | |||||||||||||||||||
| Exploration | — | 3 | — | 13 | |||||||||||||||||||
| Other (a) | 1 | 14 | 20 | 18 | |||||||||||||||||||
| $ | 5 | $ | 95 | $ | 26 | $ | 228 | ||||||||||||||||
| (a) Six months 2016 includes $18 million of capital incurred for the planned turnaround at the Elk Hills Power Plant, of which payment of $14 million is deferred to future periods. | |||||||||||||||||||||||
| Attachment 6 | |||||||||||||||||
| PRODUCTION STATISTICS | |||||||||||||||||
| Second Quarter | Six Months | ||||||||||||||||
| Net Oil, NGLs and Natural Gas Production Per Day | 2016 | 2015 | 2016 | 2015 | |||||||||||||
| Oil (MBbl/d) | |||||||||||||||||
| San Joaquin Basin | 56 | 67 | 58 | 67 | |||||||||||||
| Los Angeles Basin | 29 | 31 | 31 | 33 | |||||||||||||
| Ventura Basin | 5 | 6 | 5 | 6 | |||||||||||||
| Sacramento Basin | — | — | — | — | |||||||||||||
| Total | 90 | 104 | 94 | 106 | |||||||||||||
| NGLs (MBbl/d) | |||||||||||||||||
| San Joaquin Basin | 15 | 17 | 16 | 17 | |||||||||||||
| Los Angeles Basin | — | — | — | — | |||||||||||||
| Ventura Basin | 1 | 1 | 1 | 1 | |||||||||||||
| Sacramento Basin | — | — | — | — | |||||||||||||
| Total | 16 | 18 | 17 | 18 | |||||||||||||
| Natural Gas (MMcf/d) | |||||||||||||||||
| San Joaquin Basin | 152 | 175 | 149 | 177 | |||||||||||||
| Los Angeles Basin | 4 | 2 | 3 | 2 | |||||||||||||
| Ventura Basin | 9 | 11 | 9 | 12 | |||||||||||||
| Sacramento Basin | 37 | 46 | 38 | 47 | |||||||||||||
| Total | 202 | 234 | 199 | 238 | |||||||||||||
| Total Barrels of Oil Equivalent (MBoe/d) (a) | 140 | 161 | 144 | 163 | |||||||||||||
| (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, for the six months ended June 30, 2016, the average prices of Brent oil and NYMEX natural gas were $41.03 per Bbl and $2.02 per Mcf, respectively, resulting in an oil-to-gas price ratio of approximately 20 to 1. | |||||||||||||||||
| Attachment 7 | ||||||||||||||||||||||
| PRICE STATISTICS | ||||||||||||||||||||||
| Second Quarter | Six Months | |||||||||||||||||||||
| 2016 | 2015 | 2016 | 2015 | |||||||||||||||||||
| Realized Prices | ||||||||||||||||||||||
| Oil with hedge ($/Bbl) | $ | 43.70 | $ | 56.73 | $ | 39.90 | $ | 51.51 | ||||||||||||||
| Oil without hedge ($/Bbl) | $ | 41.41 | $ | 56.73 | $ | 35.52 | $ | 51.48 |
|
|||||||||||||
| NGLs ($/Bbl) | $ | 22.54 | $ | 20.47 | $ | 19.35 | $ | 21.00 | ||||||||||||||
| Natural gas ($/Mcf) | $ | 1.66 | $ | 2.49 | $ | 1.85 | $ | 2.67 | ||||||||||||||
| Index Prices | ||||||||||||||||||||||
| Brent oil ($/Bbl) | $ | 46.97 | $ | 63.50 | $ | 41.03 | $ | 59.33 | ||||||||||||||
| WTI oil ($/Bbl) | $ | 45.59 | $ | 57.94 | $ | 39.52 | $ | 53.29 | ||||||||||||||
| NYMEX gas ($/MMBtu) | $ | 1.97 | $ | 2.74 | $ | 2.02 | $ | 2.90 | ||||||||||||||
| Realized Prices as Percentage of Index Prices | ||||||||||||||||||||||
| Oil with hedge as a percentage of Brent | 93 | % | 89 | % | 97 | % | 87 | % | ||||||||||||||
| Oil without hedge as a percentage of Brent | 88 | % | 89 | % | 87 | % | 87 | % | ||||||||||||||
| Oil with hedge as a percentage of WTI | 96 | % | 98 | % | 101 | % | 97 | % | ||||||||||||||
| Oil without hedge as a percentage of WTI | 91 | % | 98 | % | 90 | % | 97 | % | ||||||||||||||
| NGLs as a percentage of Brent | 48 | % | 32 | % | 47 | % | 35 | % | ||||||||||||||
| NGLs as a percentage of WTI | 49 | % | 35 | % | 49 | % | 39 | % | ||||||||||||||
| Natural gas as a percentage of NYMEX | 84 | % | 91 | % | 92 | % | 92 | % | ||||||||||||||
| Attachment 8 | |||||||||||
| 2016 THIRD QUARTER GUIDANCE | |||||||||||
| Anticipated Realizations Against the Prevailing Index Prices for Q3 2016 (a) | |||||||||||
| Oil | 85% to 90% of Brent | ||||||||||
| NGLs | 48% to 54% of Brent | ||||||||||
| Natural Gas | 94% to 98% of NYMEX | ||||||||||
| 2016 Third Quarter Production, Capital and Income Statement Guidance | |||||||||||
| Production | 134 to 139 MBOE per day | ||||||||||
| Capital | $10 million to $20 million | ||||||||||
| Production costs | $16.75 to $17.25 per BOE | ||||||||||
| Adjusted general and administrative expenses | $4.75 to $5.05 per BOE | ||||||||||
| Depreciation, depletion and amortization | $10.90 to $11.10 per BOE | ||||||||||
| Taxes other than on income | $37 million to $41 million | ||||||||||
| Exploration expense | $3 million to $7 million | ||||||||||
| Interest expense (b) | $74 million to $78 million | ||||||||||
| Cash Interest (b) | $48 million to $52 million | ||||||||||
| Income tax expense rate (c) | 0% | ||||||||||
| Cash tax rate | 0% | ||||||||||
| Pre-tax Third Quarter Price Sensitivities | On Income (d) | On Cash (d) | |||||||||
| $1 change in Brent index - Oil | $4.0 million | $4.0 million | |||||||||
| $1 change in Brent index - NGLs | $0.7 million | $0.7 million | |||||||||
| $0.50 change in NYMEX - Gas | $4.0 million | $4.0 million | |||||||||
| Pre-tax Third Quarter Hedge Price Sensitivities | |||||||||||
| $1 change in Brent index at below $55.00 - Oil | $2.2 million | $2.2 million | |||||||||
| Third Quarter Volumes Sensitivities | |||||||||||
| $1 change in the Brent index (e) | 275 Bbl/d | ||||||||||
| (a) Realizations exclude hedge effects. | |||||||||||
| (b) Interest expense includes the amortization of the deferred gain that resulted from the December 2015 debt exchange. Cash interest for the quarter is lower than interest expense due to the timing of interest payments. These amounts exclude any effects of the proposed tender offer or the proposed syndicated loan facility. | |||||||||||
| (c) The 2016 tax benefit will be limited to amounts that can be recognized as deferred tax assets. | |||||||||||
| (d) All amounts exclude hedge effects and reflect the effect of production sharing type contracts in our Wilmington field operations. | |||||||||||
| (e) Reflects the effect of production sharing type contracts in our Wilmington field operations. | |||||||||||
| Attachment 9 | |||||||||||
| SECOND QUARTER DRILLING ACTIVITY | |||||||||||
| San Joaquin | Los Angeles | Ventura | Sacramento | ||||||||
| Wells Drilled (Net) | Basin | Basin | Basin | Basin | Total | ||||||
| Development Wells | |||||||||||
| Primary | — | — | — | — | — | ||||||
| Waterflood | — | — | — | — | — | ||||||
| Steamflood | — | — | — | — | — | ||||||
| Unconventional | — | — | — |
— |
— | ||||||
| Total | — | — | — | — | — | ||||||
| Exploration Wells | |||||||||||
| Primary | — | — | — | — | — | ||||||
| Waterflood | — | — | — | — | — | ||||||
| Steamflood | — | — | — | — | — | ||||||
| Unconventional | — | — | — | — | — | ||||||
| Total | — | — | — | — | — | ||||||
| Total Wells | — | — | — | — | — | ||||||
|
Development Drilling Capital
($ millions) |
$— | $— | $— | $— | $— | ||||||