California Resources Corporation — Q2 2017 Form 10-Q
Business and period: Independent oil and natural gas exploration and production company operating in California. This unaudited report covers the three and six months ended June 30, 2017; comparisons are with the corresponding 2016 periods unless stated otherwise. Figures are in millions of dollars except per-share, production and price data.
Financial and operating performance
| Metric | Q2 2017 | Q2 2016 | Six months 2017 | Six months 2016 |
|---|---|---|---|---|
| Oil and gas net sales | $439 | $404 | $926 | $733 |
| Total revenues and other, including derivative results | $516 | $317 | $1,106 | $639 |
| Operating income (loss) | $39 | $(141) | $150 | $(284) |
| Net income (loss) attributable to common stock | $(48) | $(140) | $5 | $(190) |
| Diluted EPS | $(1.13) | $(3.51) | $0.12 | $(4.85) |
| Adjusted EBITDAX (non-GAAP) | $158 | $160 | $358 | $284 |
| Adjusted net loss (non-GAAP) | $(78) | $(72) | $(121) | $(172) |
- Cash flow, six months: Operating cash flow was $120, versus $44 in 2016; investing cash outflow was $74, versus $18; financing cash outflow was $49, versus $36. Capital investments were $132 gross, or approximately $106 net of capital-related accrual changes. Ending cash was $9, down from $12 at year-end 2016.
- Balance sheet and liquidity: June 30 total assets were $6,154; current assets $387 and current liabilities $607. Total debt principal was $5,169, including $100 of current maturities; equity was negative $491. Available borrowing capacity was approximately $437, subject to a $250 minimum monthly liquidity requirement.
- Costs and production: Q2 production averaged 129,000 Boe/day versus 140,000; six-month production averaged 131,000 versus 144,000. Q2 oil production was 83,000 barrels/day, NGLs 16,000 barrels/day and natural gas 182 MMcf/day. Q2 production cost was $18.34/Boe versus $14.76; excluding the reported PSC-contract effect, it was $17.18 versus $13.88.
- Prices: Q2 realized oil price including hedges was $47.98/barrel versus $43.70; NGLs $30.08 versus $22.54; natural gas $2.47/Mcf versus $1.66. Six-month realized oil price including hedges was $49.12/barrel versus $39.90.
- Debt costs: Interest and debt expense was $83 in Q2 and $167 for six months, up from $74 and $148, respectively. Management attributed the increase mainly to higher blended interest rates following the 2016 second-out credit agreement, partly offset by lower debt balances.
Material changes versus prior periods
- Higher commodity prices, improved oil differentials and derivative results lifted reported revenue and operating results. Net derivative gains were $43 in Q2 versus losses of $118 a year earlier, and $116 for six months versus losses of $143. The filing notes that non-cash mark-to-market changes were a major driver.
- Despite improved GAAP results, Q2 adjusted net loss widened to $78 from $72; adjusted EBITDAX was nearly unchanged at $158 versus $160. Six-month adjusted net loss narrowed to $121 from $172, while adjusted EBITDAX increased to $358 from $284.
- Production declined year over year, which management linked primarily to reduced investment in 2016. Higher activity and energy prices raised production costs; Q2 costs increased 15% in total and per-Boe costs rose.
- Total debt principal decreased by $99 from December 31, 2016, primarily reflecting term-loan payments and debt repurchases. Cash remained limited, and total equity remained negative.
Outlook, risks and unusual items
- Management expected production growth in the second half of 2017 and into 2018 as the increased capital program took effect, while cautioning that growth was not assured. The 2017 capital program was approximately $400, including joint-venture funding; the initial company base budget was about $300. In a prolonged period around $40 Brent, management said it would reduce internally funded second-half capital to remain within cash flow.
- CRC had seven rigs operating at quarter-end and expected eight by year-end. Management expected joint ventures to support at least a six-rig program for the remainder of the year.
- The BSP development joint venture could invest up to $250; it had contributed $50 in Q1 and another $50 in July. The MIRA venture could invest up to $300, with an initial $160 commitment over two years; $8 had been contributed in Q2. These arrangements support development but involve partner interests in production or properties.
- At June 30, CRC reported compliance with its credit covenants and expected compliance through 2017. Management warned that, if mid-July forward prices materialized, CRC might not meet the tighter leverage and interest-coverage tests beginning in Q1 2018 and might need a lender amendment or waiver. Failure to obtain relief could materially harm liquidity and could permit acceleration of debt and foreclosure on collateral.
- Commodity-price weakness could reduce operating cash flow, production, reserves and the borrowing base. Other stated risks include cost inflation, execution and production declines, regulatory and permitting constraints, California concentration, and limited access to capital. Hedges may not adequately protect cash flows; some sold puts can require payments below their strike prices.
- CRC recorded no income-tax provision or benefit in 2017 and maintained a full valuation allowance against net deferred tax assets; it did not expect a release within 12 months. The IRS was examining post-spin-off 2014 and 2015 federal returns, with no significant issues raised to date.
- Routine litigation and claims reserves were not material. A California air-quality regulator alleged past permit exceedances at a Huntington Beach facility; the company expected monetary sanctions above $100,000 but not material to its financial statements.
Important facts for investors to verify
- Whether operating cash flow and joint-venture funding can sustain the planned capital program and reverse production declines.
- The November 2017 borrowing-base redetermination, actual liquidity headroom, and progress toward the tighter 2018 covenant thresholds or any lender amendments.
- Debt maturities and refinancing constraints, including the facility maturity provisions tied to the 2020 and 2021 notes.
- The composition and cash-settlement impact of derivative gains, subsequent hedging activity, counterparty options and sold-put exposure.
- Joint-venture funding actually received, partner return thresholds, and the resulting economic share of future production.
- Production-cost trends, realized California pricing and any material developments in the air-quality matter or tax examinations.