California Resources Corporation — Q3 2015 Form 10-Q
Reporting period: Quarter and nine months ended September 30, 2015. CRC is a California-only oil and natural gas exploration and production company. The 2014 comparative results are not fully like-for-like: they reflect the California business under Occidental before the November 30, 2014 spin-off, while 2015 reflects CRC as a standalone company.
Key financial and operating metrics
| Metric | Q3 2015 | Q3 2014 | Nine months 2015 | Nine months 2014 |
|---|---|---|---|---|
| Total revenue | $626 million | $1.092 billion | $1.837 billion | $3.353 billion |
| Net income (loss) | $(104) million | $188 million | $(272) million | $657 million |
| Diluted EPS | $(0.27) | $0.48 | $(0.71) | $1.69 |
| Adjusted EBITDAX | $212 million | $662 million | $680 million | $2.094 billion |
| Operating cash flow | Not presented for quarter | Not presented for quarter | $412 million | $1.867 billion |
| Capital investments | Not presented for quarter | Not presented for quarter | $323 million | $1.569 billion |
Balance sheet at September 30: Cash was $4 million; total assets $11.913 billion; total debt $6.481 billion, including $481 million drawn on the revolver and $75 million current maturities; and equity $2.355 billion. Long-term debt, net of financing costs, was $6.345 billion. Cash and operating cash flow were substantially lower than the prior comparative period.
Production and realized prices: Q3 daily production averaged 158,000 BOE, versus 160,000 BOE a year earlier; oil production rose 3% to 103,000 barrels per day. For the first nine months, production averaged 161,000 BOE per day, up from 157,000. Q3 realized oil price including hedges was $47.79 per barrel, down 50%; NGL price was $16.92 per barrel, down 64%; and natural gas was $2.83 per Mcf, down 33%. Nine-month realized prices also fell sharply: oil $50.28 per barrel, NGLs $19.64 per barrel and gas $2.72 per Mcf.
Production costs declined to $16.91 per BOE in Q3 from $18.35, and to $16.56 for the nine months from $18.78. DD&A was $253 million in Q3 and $757 million for the nine months. Interest and debt expense was $82 million and $244 million, respectively; the 2014 comparisons had no standalone debt expense.
Material changes and unusual items
- Oil and gas revenue fell sharply, chiefly from lower commodity prices; higher oil volumes and hedge gains only partly offset the decline. Q3 oil and gas sales were $596 million versus $1.051 billion; nine-month sales were $1.754 billion versus $3.238 billion.
- Q3 results included a $62 million pretax charge for voluntary retirement and workforce reductions; the nine-month charge was $72 million. CRC expects about $50 million in annual pretax savings from the actions, beginning in Q4, and expects no production impact. Headcount was expected to decline about 15% from spin-off levels to roughly 1,700 by year-end.
- Noncash hedge-related gains were $53 million in Q3 and $33 million for the nine months. CRC reported adjusted net losses of $86 million and $234 million, respectively; these are non-GAAP measures and exclude specified unusual items.
- CRC’s credit ratings were downgraded in Q3 to B1 by Moody’s and BB- by S&P. This triggered a borrowing base and first-lien security on oil and gas reserves. A November 2, 2015 credit amendment changed certain covenants. CRC said it was compliant with the covenants in effect at September 30.
- The Board suspended the $0.01 quarterly dividend beginning immediately after the reported period, as part of efforts to reduce costs and debt.
Liquidity, outlook and risks
For the first nine months, operating cash flow of $412 million was below investing cash outflow of $542 million. Financing provided $120 million, including net revolver borrowings; cash declined from $14 million at year-end 2014 to $4 million. Management expected operating cash flow to fund capital needs and other obligations for at least the next 12 months, while noting that low prices could lead to modestly lower future production and continued capital restraint.
The 2015 capital budget was reduced to $440 million from $2.1 billion in 2014, with spending focused largely on mature, lower-decline oil projects. Management was pursuing asset monetizations, joint ventures and other deleveraging options, particularly involving midstream and power assets, but gave no assurance that transactions would be completed. The amended facilities provided, on a September 30 pro forma basis, up to $1.523 billion of additional borrowing availability, subject to financial covenants; the borrowing base was scheduled for redetermination around January 15, 2016. A reduction could constrain borrowing or require repayment.
Management cited sustained low commodity prices as a risk to cash flows, reserves and capital capacity. CRC estimated that applying prices through October 1, 2015 to year-end 2014 reserves could imply a 10%–20% reduction, before considering subsequent production, additions, revisions and expected further cost savings. It did not then expect current commodity and strip prices to impair asset carrying values. Oil hedges covered portions of Q4 2015 and 2016 production; hedging was intended to support cash flow, investment plans and covenant compliance. Other stated risks include California operating and regulatory concentration, permitting, water and well-stimulation restrictions, reserve estimation, market access, operational disruptions and leverage. Legal and other claim reserves were not material, and management did not expect reasonably possible losses above reserves to be material.
Management reported more than 12% lower operating costs per BOE and drilling-cost reductions of about 10% for shallow wells and up to 20% for deeper wells, with further savings anticipated but not quantified. It also said refinery-related oil differentials had improved toward historical norms by Q3. These expectations are forward-looking and subject to commodity prices and other risks.
Most important facts for investors to verify
- How the spin-off affects comparability, especially the shift from related-party sales in 2014 to third-party sales in 2015.
- Whether operating cash flow, commodity prices and hedging support debt service and capital spending as planned.
- The terms and covenant headroom under the November 2 credit amendment, and the outcome of the borrowing-base redetermination.
- Whether planned asset monetizations or other deleveraging transactions close, and how proceeds are applied to debt.
- Actual reserve revisions, production trends, cost savings and capital spending versus management’s estimates and budget.
- The timing and conditions for any possible dividend resumption; the filing provides no firm date or commitment.