LOS ANGELES--(BUSINESS WIRE)--California Resources Corporation (NYSE:CRC), an independent California-based oil and gas exploration and production company, today announced net income of $546 million or $13.06 per diluted share for the third quarter of 2016, compared with a net loss of $104 million or $2.72 per diluted share for the same period in 2015. The adjusted net loss1 for the third quarter of 2016 was $71 million or $1.75 per diluted share, compared with an adjusted net loss of $86 million or $2.25 per diluted share for the same period of 2015. For the first nine months of 2016 net income was $356 million or $8.79 per diluted share, compared with a net loss of $272 million or $7.10 per diluted share for the same period of 2015. The adjusted net loss for the first nine months of 2016 was $243 million or $6.12 per diluted share, compared with an adjusted net loss of $234 million or $6.11 per diluted share for the same period of 2015. The adjusted net loss for the third quarter and first nine months of 2016 excluded gains resulting from debt repurchases and exchanges as well as other items. Adjusted EBITDAX2 for the third quarter and the first nine months of 2016 was $164 million and $448 million, respectively, compared with $212 million and $680 million for the third quarter and the first nine months of 2015. CRC completed its semi-annual borrowing base review which was reaffirmed at $2.3 billion as of November 1, 2016.
Quarterly Highlights Include:
- Total production of 138,000 BOE per day
- Crude oil production flat sequentially at 90,000 barrels per day
- 14% reduction in production costs year-over-year
- $625 million net debt reduction from a cash tender offer
- Operating cash flow of $101 million
- Free cash flow after capital1 of $88 million
Todd Stevens, President and Chief Executive Officer, said, "In the third quarter, we began to ramp up our field activities, while continuing to keep our investments within our cash flow. Importantly, our teams safely re-initiated our capital investment programs while maintaining our cost reductions and drilling efficiencies. We anticipate our increased drilling activity in the remainder of 2016 and 2017 has the potential to position CRC for an inflection point in our business.
"Our debt position was reduced by a net $625 million in the third quarter as a result of our tender for our unsecured bonds. This brings our total debt reduction to approximately $1.5 billion from peak levels after the spin. Based on the improving price outlook, we are building multi-year planning scenarios to develop our extensive inventory, supported by our low-decline base production, that we believe can further improve our leverage metrics organically. We continually evaluate options for additional deleveraging in this dynamic market to reach our target leverage goals."
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, please see
Attachment 3.
Third Quarter Results
For the third quarter of 2016, CRC reported net income of $546 million or $13.06 per diluted share, compared with a net loss of $104 million or $2.72 per diluted share for the same period of 2015. The 2016 quarter reflected the net gain from the Company's debt tender offer, as well as lower production costs, depreciation, depletion and amortization expense (DD&A), general and administrative expense (G&A), taxes other than on income, and exploration expense, partially offset by lower oil and natural gas realized prices and volumes. The third quarter 2016 adjusted net loss was $71 million or $1.75 per diluted share, compared with an adjusted net loss of $86 million or $2.25 per diluted share for the same period of 2015. The 2016 adjusted net loss excluded $660 million of net gains on the early extinguishment of the Company's notes resulting from the cash tender offer, $25 million of non-cash derivative losses on outstanding hedges, a $12 million interest charge for the write-off of deferred debt costs, and $6 million of other infrequent net charges. The 2015 adjusted net loss excluded $62 million of severance and early retirement costs, $53 million of non-cash derivative gains, and $9 million of other infrequent net charges and related tax adjustments.
Adjusted EBITDAX for the third quarter of 2016 was $164 million, compared to $212 million for the same period of 2015.
Total daily production volumes averaged 138,000 barrels of oil equivalent (BOE) for the third quarter of 2016, compared with 158,000 BOE for the third quarter of 2015, a 13-percent decrease which is within CRC's stated base production decline range. This decrease includes PSC effects which were offset by production that was deferred from the second quarter due to third-party pipeline disruptions. The third quarter 2016 production decline continued to reflect management's decision to withhold development capital and to selectively defer workover and downhole maintenance activity in the early part of the year. Due to the improved commodity price environment, the Company began increasing its activity levels toward the end of the second quarter, resulting in lower declines quarter-over-quarter. Year-over-year average oil production decreased by 13 percent, or 13,000 barrels per day, to 90,000 barrels per day in the third 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 15 percent to 193 million cubic feet (MMcf) per day.
In the third quarter of 2016, realized crude oil prices, including the effect of cash received from settled hedges, decreased 10 percent to $43.03 per barrel from $47.79 per barrel in the third quarter of 2015. Third quarter 2016 hedges contributed $1.30 per barrel to the realized crude oil price, compared with $1.69 per barrel in the third quarter of 2015. Realized NGL prices increased 33 percent to $22.45 per barrel from $16.92 per barrel in the third quarter of 2015. Realized natural gas prices decreased 7 percent to $2.64 per thousand cubic feet (Mcf) compared with $2.83 per Mcf in the same period of 2015.
Production costs for the third quarter of 2016 were $211 million or $16.63 per BOE, compared with $246 million or $16.91 per BOE for the third quarter of 2015, a 14-percent reduction on an absolute dollar basis. The decrease was driven by cost reductions across nearly all of CRC's operations, particularly in well servicing efficiency, lower personnel costs, lower energy use and lower natural gas prices, which also reduced the cost of electricity. However, increasing workover and downhole maintenance activity combined with higher gas and seasonal energy prices resulted in higher production costs for the third quarter of 2016, compared to the prior quarter. G&A expenses were $58 million or $4.57 per BOE for the third quarter of 2016, compared with $129 million or $8.88 per BOE for the third quarter of 2015, reflecting continued employee and contractor cost-reduction initiatives since the middle of last year and greater severance and early retirement costs included in the prior year quarter. Adjusted G&A expenses for the third quarter of 2016 were $57 million or $4.49 per BOE, compared with $67 million or $4.61 per BOE for the third quarter of 2015. Adjusted G&A expenses for both quarters excluded severance and early retirement costs. Exploration expenses of $3 million for the third quarter of 2016 were $2 million lower than the same period of 2015. Taxes other than on income of $37 million for the third quarter of 2016 were $5 million lower than the same period of 2015.
Consistent with our operating tenet of living within cash flow, the Company generated $101 million of operating cash flow and free cash flow after working capital of $88 million in the third quarter of 2016.
Nine-Month Results
For the first nine months of 2016, CRC reported net income of $356 million or $8.79 per diluted share, compared with a net loss of $272 million or $7.10 per diluted share for the same period of 2015. The nine months ended 2016 reflected the net gains from the early extinguishment of the Company's notes and divestiture of assets, non-cash derivative losses on outstanding hedges, as well as lower production costs, DD&A expense, G&A expense, taxes other than on income, and exploration expense, partially offset by lower oil and natural gas prices and volumes. The first nine-month adjusted net loss was $243 million or $6.12 per diluted share, compared with an adjusted net loss of $234 million or $6.11 per diluted share for the same period of 2015. The 2016 adjusted net loss excluded $793 million of net gains on the early extinguishment of the Company's notes, $243 million of non-cash derivative losses on outstanding hedges, a $63 million benefit from a deferred tax valuation allowance adjustment, a $31 million gain from asset divestitures, a $12 million write-off of deferred financing costs related to the retirement of the Company's notes and $33 million of other infrequent charges. The 2015 adjusted net loss excluded $33 million of non-cash derivative gains, $72 million of severance and early retirement costs and $1 million of other infrequent net charges and related tax adjustments.
Adjusted EBITDAX for the first nine months of 2016 was $448 million, compared to $680 million in the prior-year period.
Total daily production volumes averaged 142,000 BOE in the first nine months of 2016, compared with 161,000 BOE in the first nine months of 2015, a 12-percent decrease which is within CRC's stated base production decline range. CRC's year-over-year average oil production decreased by only 11 percent, or 12,000 barrels per day, compared with the same period of the prior year to 93,000 barrels per day in the first nine months of 2016. NGL production decreased by 11 percent to 16,000 barrels per day and natural gas production decreased by 16 percent to 197 MMcf per day.
Realized crude oil prices, including the effect of cash received from settled hedges, decreased 19 percent to $40.91 per barrel in the first nine-months of 2016 from $50.28 per barrel in the comparable period of 2015. Hedges contributed $3.37 per barrel to realized crude oil prices in the first nine months of 2016, compared with $0.58 for the same period of 2015. Realized NGL prices increased 4 percent to $20.36 per barrel in the first nine months of 2016 from $19.64 per barrel in 2015. Realized natural gas prices decreased 22 percent to $2.11 per Mcf in the first nine months of 2016, compared with $2.72 per Mcf in the same period of 2015.
Production costs for the first nine months of 2016 were $583 million or $15.01 per BOE, compared with $730 million or $16.56 per BOE for the same period in 2015, a 20-percent reduction on an absolute dollar basis. The decrease reflected cost reductions across nearly all of CRC's operations, particularly in well servicing efficiency, lower personnel costs, lower energy use and lower natural gas prices, as well as management's decision to increase economic thresholds for capital investment and selectively defer lower value workovers and downhole maintenance activity during the early part of 2016. G&A expenses were $186 million or $4.79 per BOE for the first nine months of 2016, compared with $290 million or $6.58 per BOE for the same period of 2015, reflecting employee and contractor cost-reduction initiatives since the middle of last year and greater severance and early retirement costs included in the prior-year period. Adjusted G&A expenses were $167 million or $4.30 per BOE for the first nine months of 2016, compared with $218 million or $4.95 per BOE for the same period of 2015. Adjusted G&A expenses for both years excluded severance and early retirement. Exploration expenses of $13 million for the first nine months of 2016 were $16 million lower than the same period of 2015. Taxes other than on income were $118 million for the first nine months of 2016 and $150 million for the same period of 2015.
Consistent with our operating tenet of living within cash flow, the Company generated $145 million of operating cash flow and free cash flow after capital of $95 million for the first nine months of 2016.
Operational Update
During the third quarter, CRC deployed one drilling rig in the San Joaquin basin focused primarily on steamfloods and another rig in the Wilmington field in the Los Angeles basin, working on a half-time basis. We drilled and completed twenty-one wells. The deployment was consistent with CRC's decision to gradually increase capital investment in response to improvements in the commodity price environment. We began experiencing the positive impact of the increased capital activity toward the end of the third quarter and expect to see further related production benefit in the fourth quarter. The Company expects this activity to reduce the base production decline rate. The Company plans to further increase activity over the remainder of the year. As a result, we expect our capital investment for the year will be higher than originally planned, while still remaining within cash flow.
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 PG&E City Gate-based natural gas hedges in place:
Crude Oil
| 4Q 2016 | FY 2017 | FY 2018 | |||||||||
|
Production |
Strike |
Production |
Strike |
Production |
Strike |
||||||
| Calls | 25,000 | $53.62 | 15,500 | $54.17 | 21,500 | $58.21 | |||||
| Puts | 3,000 | $50.00 | 14,300 | $48.60 | |||||||
| Swaps | 39,000 | $49.71 | 20,000 | $53.98 | |||||||
Certain of the 2017 crude oil swaps grant the counterparty a quarterly option to increase volumes by up to 10,000 barrels per day for that quarter at a weighted-average Brent price of $55.46.
Gas
| 4Q 2016 | FY 2017 | FY 2018 | |||||||||
|
Production |
Strike |
Production |
Strike |
Production |
Strike |
||||||
| Swaps | 3,800 | $3.49 | — | — | — | — | |||||
| Forwards | — | — | 4,700 | $3.53 | — | — | |||||
Credit Facility Amendment, Debt Issuance and Tender Offer
As previously reported, in August 2016, CRC amended its bank credit facility to update the existing financial covenants until the end of the first quarter of 2018 and allow for the cash tender. Under this amendment, revolver commitments from the lenders were reduced from $1.6 billion to $1.4 billion. CRC's liquidity did not decrease as a result of this amendment. The Company also incurred $1 billion under a new first-lien, second-out term loan agreement during the third quarter of 2016. Proceeds were used to pay down a portion of its existing term loan and revolver. Additionally, CRC completed its oversubscribed tender offer for its notes, resulting in a reduction of outstanding debt by approximately $625 million net of transaction costs.
CRC completed its semi-annual borrowing base review which was reaffirmed at $2.3 billion as of November 1, 2016.
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/10091742. 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 and workover program, maintenance capital, projected 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 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; steeper than expected production declines; 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 | ||||||||||||||||
| Third Quarter | Nine 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 | $ | 424 | $ | 520 | $ | 1,157 | $ | 1,687 | ||||||||
| Net derivative gains (losses) | (14 | ) | 68 | (157 | ) | 50 | ||||||||||
| Other revenue | 46 | 38 | 95 | 100 | ||||||||||||
| Total revenues and other | 456 | 626 | 1,095 | 1,837 | ||||||||||||
| Costs and Other | ||||||||||||||||
| Production costs | 211 | 246 | 583 | 730 | ||||||||||||
| General and administrative expenses | 58 | 129 | 186 | 290 | ||||||||||||
| Depreciation, depletion and amortization | 137 | 253 | 422 | 757 | ||||||||||||
| Taxes other than on income | 37 | 42 | 118 | 150 | ||||||||||||
| Exploration expense | 3 | 5 | 13 | 29 | ||||||||||||
| Interest and debt expense, net | 95 | 82 | 243 | 244 | ||||||||||||
| Other expenses, net | 29 | 23 | 45 | 74 | ||||||||||||
| Total costs and other | 570 | 780 | 1,610 | 2,274 | ||||||||||||
| Net gain on early extinguishment of debt | 660 | — | 793 | — | ||||||||||||
| Income (loss) before income taxes | 546 | (154 | ) | 278 | (437 | ) | ||||||||||
| Income tax benefit | — | 50 | 78 | 165 | ||||||||||||
| Net income (loss) | $ | 546 | $ | (104 | ) | $ | 356 | $ | (272 | ) | ||||||
| EPS - diluted | $ | 13.06 | $ | (2.72 | ) | $ | 8.79 | $ | (7.10 | ) | ||||||
| Adjusted net loss | $ | (71 | ) | $ | (86 | ) | $ | (243 | ) | $ | (234 | ) | ||||
| Adjusted EPS - diluted | $ | (1.75 | ) | $ | (2.25 | ) | $ | (6.12 | ) | $ | (6.11 | ) | ||||
| Weighted average diluted shares outstanding | 41.8 | 38.3 | 40.5 | 38.3 | ||||||||||||
| Adjusted EBITDAX | $ | 164 | $ | 212 | $ | 448 | $ | 680 | ||||||||
| Effective tax rate | 0 % | 32 | % | (28) % | 38 | % | ||||||||||
|
Cash Flow Data: |
||||||||||||||||
| Net cash provided by operating activities | $ | 101 | $ | 180 | $ | 145 | $ | 412 | ||||||||
| Net cash used by investing activities | $ | (13 | ) | $ | (102 | ) | $ | (31 | ) | $ | (542 | ) | ||||
| Net cash (used) provided by financing activities | $ | (80 | ) | $ | (111 | ) | $ | (116 | ) | $ | 120 | |||||
|
Balance Sheet Data: |
September 30, | December 31, | ||||||||||||||
| 2016 | 2015 | |||||||||||||||
| Total current assets | $ | 356 | $ | 438 | ||||||||||||
| Property, plant and equipment, net | $ | 5,953 | $ | 6,312 | ||||||||||||
| Total current liabilities | $ | 658 | $ | 605 | ||||||||||||
| Long-term debt, principal amount | $ | 5,173 | $ | 6,043 | ||||||||||||
| Total equity | $ | (493 | ) | $ | (916 | ) | ||||||||||
| Outstanding shares as of | 41.2 | 38.8 | ||||||||||||||
| Attachment 2 | ||||||||||||||||
| 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): | ||||||||||||||||
| Third Quarter | Nine Months | |||||||||||||||
| ($ millions, except per share amounts) | 2016 | 2015 | 2016 | 2015 | ||||||||||||
| Net income (loss) | $ | 546 | $ | (104 | ) | $ | 356 | $ | (272 | ) | ||||||
| Non-cash, unusual and infrequent items: | ||||||||||||||||
| Non-cash derivative losses (gains) | 25 | (53 | ) | 243 | (33 | ) | ||||||||||
| Severance and early retirement costs | 1 | 62 | 19 | 72 | ||||||||||||
| Plant turnaround, outage and other costs | 5 | 3 | 14 | 6 | ||||||||||||
| Net gain on early extinguishment of debt | (660 | ) | — | (793 | ) | — | ||||||||||
| Gain from asset divestitures | — | — | (31 | ) | — | |||||||||||
| Adjusted income items before interest and taxes | (629 | ) | 12 | (548 | ) | 45 | ||||||||||
| Deferred debt issuance costs write-off | 12 | — | 12 | — | ||||||||||||
| Valuation allowance for deferred tax assets (a) | — | — | (63 | ) | — | |||||||||||
| Tax effects of these items and related adjustments | — | 6 | — | (7 | ) | |||||||||||
| Total | $ | (617 | ) | $ | 18 | $ | (599 | ) | $ | 38 | ||||||
| Adjusted net loss | $ | (71 | ) | $ | (86 | ) | $ | (243 | ) | $ | (234 | ) | ||||
| Net income (loss) per diluted share | $ | 13.06 | $ | (2.72 | ) | $ | 8.79 | $ | 7.10 | |||||||
| Adjusted net loss per diluted share | $ | (1.75 | ) | $ | (2.25 | ) | $ | (6.12 | ) | $ | (6.11 | ) | ||||
| (a) Amount represents the out-of-period portion of the valuation allowance reversal. | ||||||||||||||||
| DERIVATIVES GAINS AND LOSSES | ||||||||||||||||
| Third Quarter | Nine Months | |||||||||||||||
| ($ millions) | 2016 | 2015 | 2016 | 2015 | ||||||||||||
| Non-cash derivative losses (gains) | $ | 25 | $ | (53 | ) | $ | 243 | $ | (33 | ) | ||||||
| Proceeds from settled derivatives | (11 | ) | (15 | ) | (86 | ) | (17 | ) | ||||||||
| Net derivative losses (gains) | $ | 14 | $ | (68 | ) | $ | 157 | $ | (50 | ) | ||||||
| FREE CASH FLOW | ||||||||||||||||
| Third Quarter | Nine Months | |||||||||||||||
| ($ millions) | 2016 | 2015 | 2016 | 2015 | ||||||||||||
| Operating cash flow | $ | 101 | $ | 180 | $ | 145 | $ | 412 | ||||||||
| Capital investment | (19 | ) | (95 | ) | (45 | ) | (323 | ) | ||||||||
| Changes in capital accruals | 6 | 1 | (5 | ) | (202 | ) | ||||||||||
| Free cash flow (after working capital) | $ | 88 | $ | 86 | $ | 95 | $ | (113 | ) | |||||||
| ADJUSTED GENERAL AND ADMINISTRATIVE EXPENSES | ||||||||||||||||
| Third Quarter | Nine Months | |||||||||||||||
| ($ millions) | 2016 | 2015 | 2016 | 2015 | ||||||||||||
| General and administrative expenses | $ | 58 | $ | 129 | $ | 186 | $ | 290 | ||||||||
| Severance and early retirement costs | (1 | ) | (62 | ) | (19 | ) | (72 | ) | ||||||||
| Adjusted general and administrative expenses | $ | 57 | $ | 67 | $ | 167 | $ | 218 | ||||||||
| Attachment 3 | ||||||||||||||||
| NON-GAAP FINANCIAL MEASURES AND RECONCILIATIONS | ||||||||||||||||
| We define adjusted EBITDAX consistent with our first lien, first out 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 first lien, first out 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: | ||||||||||||||||
| Third Quarter | Nine Months | |||||||||||||||
| ($ millions) | 2016 | 2015 | 2016 | 2015 | ||||||||||||
| Net income (loss) | $ | 546 | $ | (104 | ) | $ | 356 | $ | (272 | ) | ||||||
| Interest and debt expense | 95 | 82 | 243 | 244 | ||||||||||||
| Income tax benefit | — | (50 | ) | (78 | ) | (165 | ) | |||||||||
| Depreciation, depletion and amortization | 137 | 253 | 422 | 757 | ||||||||||||
| Exploration expense | 3 | 5 | 13 | 29 | ||||||||||||
| Adjusted income items before interest and taxes(a) | (629 | ) | 12 | (548 | ) | 45 | ||||||||||
| Other non-cash items | 12 | 14 | 40 | 42 | ||||||||||||
| Adjusted EBITDAX | $ | 164 | $ | 212 | $ | 448 | $ | 680 | ||||||||
| Net cash (used) provided by operating activities | $ | 101 | $ | 180 | $ | 145 | $ | 412 | ||||||||
| Cash Interest | 64 | 99 | 244 | 248 | ||||||||||||
| Exploration expenditures | 3 | 3 | 13 | 20 | ||||||||||||
| Other changes in operating assets and liabilities | (9 | ) | (73 | ) | 32 | (6 | ) | |||||||||
| Plant turnaround, outage and other costs | 5 | 3 | 14 | 6 | ||||||||||||
| Adjusted EBITDAX | $ | 164 | $ | 212 | $ | 448 | $ | 680 | ||||||||
| (a) See Attachment 2. | ||||||||||||||||
| Attachment 4 | ||||
| ADJUSTED NET INCOME / (LOSS) VARIANCE ANALYSIS | ||||
| ($ millions) | ||||
| 2015 3rd Quarter Adjusted Net Loss | $ | (86 | ) | |
| Price - Oil | (45 | ) | ||
| Price - NGLs | 9 | |||
| Price - Natural Gas | (3 | ) | ||
| Volume | (33 | ) | ||
| Production cost rate | 26 | |||
| DD&A rate | 98 | |||
| Exploration expense | 2 | |||
| Interest expense | (1 | ) | ||
| Adjusted general & administrative expenses | 10 | |||
| Income tax | (56 | ) | ||
| All Others | 8 | |||
| 2016 3rd Quarter Adjusted Net Loss | $ | (71 | ) | |
| 2015 Nine Month Adjusted Net Loss | $ | (234 | ) | |
| Price - Oil | (277 | ) | ||
| Price - NGLs | 4 | |||
| Price - Natural Gas | (39 | ) | ||
| Volume | (70 | ) | ||
| Production cost rate | 125 | |||
| DD&A rate | 282 | |||
| Exploration expense | 16 | |||
| Interest expense | 13 | |||
| Adjusted general & administrative expenses | 51 | |||
| Income tax | (143 | ) | ||
| All Others | 29 | |||
| 2016 Nine Month Adjusted Net Loss | $ | (243 | ) | |
| Attachment 5 | ||||||||||||||||
| CAPITAL INVESTMENTS | ||||||||||||||||
| Third Quarter | Nine Months | |||||||||||||||
| ($ millions) | 2016 | 2015 | 2016 | 2015 | ||||||||||||
| Capital Investments: | ||||||||||||||||
| Conventional | $ | 14 | $ | 86 | $ | 19 | $ | 266 | ||||||||
| Unconventional | 5 | — | 6 | 17 | ||||||||||||
| Exploration | — | 4 | — | 17 | ||||||||||||
| Other (a) | — | 5 | 20 | 23 | ||||||||||||
| $ | 19 | $ | 95 | $ | 45 | $ | 323 | |||||||||
| (a) Nine months of 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 | |||||||||||
| Third Quarter | Nine Months | ||||||||||
| Net Oil, NGLs and Natural Gas Production Per Day | 2016 | 2015 | 2016 | 2015 | |||||||
| Oil (MBbl/d) | |||||||||||
| San Joaquin Basin | 56 | 64 | 58 | 65 | |||||||
| Los Angeles Basin | 29 | 32 | 30 | 33 | |||||||
| Ventura Basin | 5 | 7 | 5 | 7 | |||||||
| Sacramento Basin | — | — | — | — | |||||||
| Total | 90 | 103 | 93 | 105 | |||||||
| NGLs (MBbl/d) | |||||||||||
| San Joaquin Basin | 15 | 17 | 15 | 17 | |||||||
| Los Angeles Basin | — | — | — | — | |||||||
| Ventura Basin | 1 | 1 | 1 | 1 | |||||||
| Sacramento Basin | — | — | — | — | |||||||
| Total | 16 | 18 | 16 | 18 | |||||||
| Natural Gas (MMcf/d) | |||||||||||
| San Joaquin Basin | 149 | 172 | 150 | 175 | |||||||
| Los Angeles Basin | 2 | 1 | 3 | 3 | |||||||
| Ventura Basin | 8 | 11 | 8 | 11 | |||||||
| Sacramento Basin | 34 | 42 | 36 | 45 | |||||||
| Total | 193 | 226 | 197 | 234 | |||||||
| Total Barrels of Oil Equivalent (MBoe/d) (a) | 138 | 158 | 142 | 161 | |||||||
| (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 nine months ended September 30, 2016, the average prices of Brent oil and NYMEX natural gas were $43.01 per Bbl and $2.24 per Mcf, respectively, resulting in an oil-to-gas price ratio of approximately 19 to 1. | |||||||||||
|
Attachment 7 |
||||||||||||||||
| PRICE STATISTICS | ||||||||||||||||
| Third Quarter | Nine Months | |||||||||||||||
| 2016 | 2015 | 2016 | 2015 | |||||||||||||
| Realized Prices | ||||||||||||||||
| Oil with hedge ($/Bbl) | $ | 43.03 | $ | 47.79 | $ | 40.91 | $ | 50.28 | ||||||||
| Oil without hedge ($/Bbl) | $ | 41.73 | $ | 46.10 | $ | 37.54 | $ | 49.70 | ||||||||
| NGLs ($/Bbl) | $ | 22.45 | $ | 16.92 | $ | 20.36 | $ | 19.64 | ||||||||
| Natural gas ($/Mcf) | $ | 2.64 | $ | 2.83 | $ | 2.11 | $ | 2.72 | ||||||||
| Index Prices | ||||||||||||||||
| Brent oil ($/Bbl) | $ | 46.98 | $ | 51.17 | $ | 43.01 | $ | 56.61 | ||||||||
| WTI oil ($/Bbl) | $ | 44.94 | $ | 46.43 | $ | 41.33 | $ | 51.00 | ||||||||
| NYMEX gas ($/MMBtu) | $ | 2.70 | $ | 2.78 | $ | 2.24 | $ | 2.86 | ||||||||
| Realized Prices as Percentage of Index Prices | ||||||||||||||||
| Oil with hedge as a percentage of Brent | 92 | % | 93 | % | 95 | % | 89 | % | ||||||||
| Oil without hedge as a percentage of Brent | 89 | % | 90 | % | 87 | % | 88 | % | ||||||||
| Oil with hedge as a percentage of WTI | 96 | % | 103 | % | 99 | % | 99 | % | ||||||||
| Oil without hedge as a percentage of WTI | 93 | % | 99 | % | 91 | % | 97 | % | ||||||||
| NGLs as a percentage of Brent | 48 | % | 33 | % | 47 | % | 35 | % | ||||||||
| NGLs as a percentage of WTI | 50 | % | 36 | % | 49 | % | 39 | % | ||||||||
| Natural gas as a percentage of NYMEX | 98 | % | 102 | % | 94 | % | 95 | % | ||||||||
| Attachment 8 | |||
| 2016 FOURTH QUARTER GUIDANCE | |||
| Anticipated Realizations Against the Prevailing Index Prices for Q4 2016 (a) | |||
| Oil | 88% to 92% of Brent | ||
| NGLs | 45% to 49% of Brent | ||
| Natural Gas | 92% to 96% of NYMEX | ||
| 2016 Fourth Quarter Production, Capital and Income Statement Guidance | |||
| Production | 132 to 137 MBOE per day | ||
| Capital | $30 million to $35 million | ||
| Production costs | $17.10 to $17.60 per BOE | ||
| Adjusted general and administrative expenses | $4.60 to $4.90 per BOE | ||
| Depreciation, depletion and amortization | $10.80 to $11.00 per BOE | ||
| Taxes other than on income | $30 million to $34 million | ||
| Exploration expense | $8 million to $12 million | ||
| Interest expense (b) | $83 million to $87 million | ||
| Cash Interest (b) | $137 million to $141 million | ||
| Income tax expense rate (c) | 0% | ||
| Cash tax rate | 0% | ||
| Pre-tax Fourth Quarter Price Sensitivities | On Income (d) | On Cash (d) | |
| $1 change in Brent index - Oil | $2.5 million | $2.5 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 Fourth Quarter Hedge Price Sensitivities | |||
| $1 change in Brent index below $50.00 - Oil | $3.9 million | $3.9 million | |
| $1 change in Brent index between $50.00 and $53.62 - Oil | ($3.6 million) | ($3.6 million) | |
| $1 change in Brent index above $53.62 - Oil | ($5.9 million) | ($5.9 million) | |
| Fourth Quarter Volumes Sensitivities | |||
| $1 change in the Brent index (e) |
300 Bbl/d |
||
| (a) Realizations exclude hedge effects. | |||
| (b) Interest expense includes the amortization of the deferred gain that resulted from the December 2015 debt exchange. Cash interest for the quarter is higher than interest expense due to the timing of interest payments. | |||
| (c) The 2016 tax benefit will be limited to amounts that can be recognized as deferred tax assets. | |||
| (d) All amounts exclude hedge effects and reflect the effect of production sharing type contracts in our Wilmington field operations. | |||
| (e) Reflects the effect of production sharing type contracts in our Wilmington field operations. | |||
| Attachment 9 | ||||||||||
| THIRD QUARTER DRILLING ACTIVITY | ||||||||||
| San Joaquin | Los Angeles | Ventura | Sacramento | |||||||
| Wells Drilled (Net) | Basin | Basin | Basin | Basin | Total | |||||
| Development Wells | ||||||||||
| Primary | — | — | — | — | — | |||||
| Waterflood | 3 | 1 | — | — | 4 | |||||
| Steamflood | 17 | — | — | — | 17 | |||||
| Unconventional | — | — | — | — | — | |||||
| Total | 20 | 1 | — | — | 21 | |||||
| Exploration Wells | ||||||||||
| Primary | — | — | — | — | — | |||||
| Waterflood | — | — | — | — | — | |||||
| Steamflood | — | — | — | — | — | |||||
| Unconventional | — | — | — | — | — | |||||
| Total | — | — | — | — | — | |||||
| Total Wells | 20 | 1 | — | — | 21 | |||||
|
Development Drilling Capital
($ millions) |
$4 | $2 | $— | $— | $6 | |||||
