California Resources Corporation — Q3 2017 Form 10-Q
Business context and reporting period. California Resources Corporation is an independent oil and natural gas exploration and production company operating in California. This unaudited filing covers the quarter and nine months ended September 30, 2017; balance-sheet comparisons are with December 31, 2016. Amounts are in U.S. dollars, millions unless stated otherwise.
Financial performance and position
| Metric | Q3 2017 | Q3 2016 | Nine months 2017 | Nine months 2016 |
|---|---|---|---|---|
| Oil and gas net sales | $461 | $424 | $1,387 | $1,157 |
| Total revenues and other, including derivatives | $445 | $456 | $1,551 | $1,095 |
| Operating income (loss) | $(47) | $(19) | $103 | $(303) |
| Net income (loss) attributable to common stock | $(133) | $546 | $(128) | $356 |
| Adjusted net loss (non-GAAP) | $(52) | $(71) | $(173) | $(243) |
| Adjusted EBITDAX (non-GAAP) | $181 | $164 | $539 | $448 |
| Operating cash flow | Not separately stated | Not separately stated | $225 | $145 |
Q3 oil and gas sales rose with higher realized oil and NGL prices, but total revenue was lower because derivative results were a $65 million loss versus a $14 million loss in Q3 2016. Nine-month net income comparisons were heavily affected by debt-extinguishment gains: $793 million in 2016 versus $4 million in 2017. Q3 2016 included a $660 million gain; therefore, reported earnings are not directly indicative of underlying operating trends. No current or deferred income tax benefit was recorded for 2017 periods; CRC maintained a full valuation allowance against net deferred tax assets.
For the nine months, cash used in investing activities was $174 million and cash used in financing was $35 million. Capital investments were $232 million; operating cash flow was $225 million. Cash at September 30 was $28 million, including $17 million restricted for JV capital investment. Total debt principal was $5.139 billion, down from $5.268 billion at year-end 2016; $100 million was classified as current. Equity was negative $574 million. Available borrowing capacity under the 2014 revolver was approximately $431 million, subject to the minimum-liquidity requirement.
Average production fell year over year: total production was 128,000 Boe/d in Q3 versus 138,000 Boe/d, and 130,000 Boe/d for the nine months versus 142,000 Boe/d. Q3 oil production was 82,000 Bbl/d, down 9%; natural gas production was 182 MMcf/d, down 6%. For the nine months, realized oil price including hedges was $49.42/Bbl versus $40.91; NGL price was $33.00/Bbl versus $20.36. Production costs increased to $18.90/Boe in Q3 from $16.63, and to $18.31/Boe for the nine months from $15.01.
Material changes, outlook and risks
- Management said higher commodity prices and increased activity supported improved sales and Adjusted EBITDAX, while lower production volumes constrained results. Higher maintenance activity and gas and electricity costs increased production costs.
- Management expected the 2017 internally funded capital program to be approximately $240 million, within a total program of approximately $400 million, including JV-funded activity. Nine-month capital investments were $232 million, including $82 million funded by BSP. CRC expected to operate eight rigs at year-end and said increased 2017 investment had slowed production declines, while cautioning that growth was not assured.
- At September 30, CRC was in compliance with debt covenants, but management expected it would not meet the existing minimum interest-coverage and maximum-leverage tests when they tightened in March 2018 at prevailing prices. A lender-approved, but not yet executed or effective, proposed amendment required, among other conditions, a new term loan with at least $900 million of proceeds and $500 million of liquidity at closing. The amendment would extend facility maturity and reset covenants; failure to complete it or obtain other relief could materially harm liquidity and could trigger acceleration and foreclosure rights.
- CRC reported $5.139 billion of debt principal, including $2.25 billion of 8% second-lien notes and a $1 billion 2016 term loan bearing floating interest at LIBOR plus 10.375% (subject to a floor). Debt service, covenant compliance, borrowing-base changes, and commodity prices are key risks. The borrowing base was reaffirmed at $2.3 billion effective November 1, 2017.
- CRC uses commodity derivatives to manage cash-flow exposure; Q3 derivative losses included substantial non-cash mark-to-market losses. Hedge positions can limit upside or create payment obligations, including sold puts. Additional 2018 hedges were entered into after quarter-end.
- Development JVs provide external capital but share economics: BSP had contributed approximately $100 million gross by September 30, while MIRA had contributed $38 million toward drilling and holds a 90% working interest initially in covered properties.
- Legal and regulatory matters included Chevron’s disputed audit claims alleging approximately $200 million of NGL underallocation and $50 million of power overcharges at Elk Hills; CRC disputes the claims and says it believes amounts may instead be owed to it. An air-quality notice concerned alleged permit exceedances; monetary sanctions above $100,000 were expected but not considered material. Recorded reserves for other claims were not material.
- Management cited commodity-price volatility, production declines, capital access, regulatory and environmental requirements, operating disruptions, and the proposed refinancing as important risks. CRC said it expected to fund operations and its capital budget at then-current prices, but sustained lower prices could require capital reductions and harm production, reserves, cash flow, and borrowing capacity.
Most important facts for investors to verify
- Whether the proposed credit-facility amendment and required new term loan closed, and whether all effectiveness conditions were met.
- Subsequent covenant headroom, available liquidity, borrowing-base determinations, and scheduled debt maturities or springing-maturity triggers.
- Actual production and cost trends versus management’s expected benefit from the 2017 capital program and JV-funded drilling.
- Cash settlement effects and exposure from derivatives, including post-quarter-end hedges and downside obligations under sold puts.
- Resolution or financial impact of Chevron’s audit dispute, air-quality matters, and any changes in tax valuation allowances.