LOS ANGELES–(BUSINESS WIRE)–California Resources Corporation (NYSE: CRC), an independent California-based oil and gas exploration and production company, today reported net income attributable to common stock (CRC net income) of $346 million, or $7.00 per diluted share, for the fourth quarter of 2018. Adjusted net income1 for the fourth quarter of 2018 was $26 million, or $0.53 per diluted share. For the full year of 2018, CRC net income was $328 million, or $6.77 per diluted share. Adjusted net income1 for the full year of 2018 was $61 million, or $1.27 per diluted share.
Adjusted EBITDAX1 for the fourth quarter of 2018 was $314 million and $1,117 million for the full year of 2018. Cash provided by operating activities was $68 million for the fourth quarter of 2018 and $461 million for the full year of 2018, or an 86% increase over the full year $248 million in 2017.
- Produced an average of 136,000 barrels of oil equivalent (BOE) per day, an increase of 8% over the prior year period
- Produced an average of 86,000 barrels of oil per day, an increase of 8% over the prior year period
- Generated core adjusted EBITDAX1 of $352 million, which excludes $50 million of net settlement payments on commodity derivative contracts offset by $12 million related to cash-settled stock-based compensation
- Reported adjusted EBITDAX1 of $314 million and an adjusted EBITDAX margin1 of 41%
- Invested $197 million of total capital, including internally funded capital of $174 million with the remainder funded by joint venture (JV) partners
- Drilled 86 wells with internally funded capital and five wells with JV capital
Full Year Highlights
- Produced an average of 132,000 BOE per day, an increase of 2% over the prior year
- Generated core adjusted EBITDAX1 of $1,374 million, which excludes $228 million of net settlement payments on commodity derivative contracts and $29 million related to cash-settled stock-based compensation
- Reported adjusted EBITDAX1 of $1,117 million and an adjusted EBITDAX margin1 of 39%
- Invested $747 million of total capital, including internally funded capital of $641 million with the remainder funded by JV partners
- Drilled 237 wells with internally funded capital and 106 wells with JV capital
- Implemented $34 million of annualized synergies in the nine months following the Elk Hills acquisition, significantly exceeding the initial target of $20 million in a shorter time frame than expected
Todd A. Stevens, CRC’s President and Chief Executive Officer, said, “In 2018, our strategic approach focused on capturing the full value of our portfolio, driving operational excellence, efficiently and effectively allocating capital, and strengthening the balance sheet. We made good progress on each priority, increasing the impact of our investment program and delivering 8% growth in oil production from the fourth quarter of 2017 to the fourth quarter of 2018. We invested in value-driven activity to develop our core and growth areas with the support of strategic JV capital, in addition to successfully resuming our exploration program. We also harnessed our operating expertise to generate more synergies than expected around the consolidation of our flagship Elk Hills asset. We are entering 2019 with a internally funded capital program of $300 to $385 million, which we will adjust to align our financial and operating plans to market conditions. We are also in discussions to obtain additional investments from new and existing JV partners that could increase our capital program by $100-$150 million to support a total capital budget of approximately $500 million. This will allow us to maintain activity and efficiency gains, while retaining a high degree of operational flexibility. Supported by our diverse asset base, high level of operating control and dynamic business model, we expect to continue to deliver meaningful value for our shareholders in 2019 and beyond.”
Fourth Quarter 2018 Results
For the fourth quarter of 2018, CRC net income was $346 million, or $7.00 per diluted share, compared to a net loss attributable to common stock (CRC net loss) of $138 million, or $3.23 per diluted share for the same period of 2017. Adjusted net income1 for the fourth quarter of 2018 was $26 million, or $0.53 per diluted share, compared with an adjusted net loss1 of $14 million, or $0.33 per diluted share for the same prior year period. The 2018 results reflected increased production and higher realized commodity prices for oil and natural gas compared to 2017. The fourth quarter of 2018 adjusted net income1 excluded $295 million of non-cash derivative gains on commodity contracts, a $6 million non-cash derivative loss from interest-rate contracts and a net gain of $31 million on debt repurchases.
Total daily production volumes averaged 136,000 BOE per day for the fourth quarter of 2018, compared to 126,000 BOE per day for the fourth quarter of 2017, an increase of 8%, largely driven by the Elk Hills acquisition in the second quarter of 2018. For the fourth quarter of 2018, oil volumes averaged 86,000 barrels per day, NGL volumes averaged 16,000 barrels per day and gas volumes averaged 204,000 thousand cubic feet (MCF) per day. Organically, oil production grew over 1,000 barrels per day from the third quarter of 2018 to the fourth quarter of 2018, excluding the effects of production sharing-type contracts (PSCs) and acquisitions.
Realized crude oil prices, including the effect of settled hedges, increased by $3.05 per barrel for the fourth quarter of 2018 to $59.97 per barrel from the same prior year period. Settled hedges decreased realized crude oil prices by $6.15 per barrel for the fourth quarter of 2018. Average realized NGL prices registered $43.56 per barrel, reflecting a realized price that was 64% of Brent prices. Realized natural gas prices were $3.77 per MCF for the fourth quarter of 2018, $1.00 higher than the same prior year period. The increase in realized gas prices resulted from the effects of limited third-party storage and pipeline constraints.
Production costs for the fourth quarter of 2018 were $233 million, or $18.61 per BOE, compared to $227 million, or $19.64 per BOE, for the fourth quarter of 2017. In line with industry practice for reporting PSCs, CRC reports gross field operating costs, but only CRC’s share of production volumes, which results in higher production costs per barrel. Excluding this PSC effect, per unit production costs1 for the fourth quarter of 2018 would have been $17.44 per BOE compared to $18.31 for the same prior year period. The decrease in production costs per BOE was primarily driven by higher production between comparative periods, largely related to the Elk Hills acquisition. Elk Hills’ production costs are lower than the average CRC-wide production cost per barrel. As a result, the Elk Hills acquisition had a favorable effect on production cost per barrel. General and administrative expenses (G&A) were $65 million for the fourth quarter of 2018 compared to $66 million for the prior year period.
CRC reported taxes other than on income of $29 million for the fourth quarter of 2018 compared to $33 million for the same prior year period. Exploration expense was $16 million for the fourth quarter of 2018, $11 million higher than the same prior year period due to exploration dry holes.
CRC’s internally funded capital investment for the fourth quarter of 2018 totaled $174 million, of which $119 million was directed to drilling and capital workovers. CRC’s JV partner Benefit Street Partners LLC (BSP) funded $12 million, which is included in CRC’s consolidated results, while JV partner Macquarie Infrastructure and Real Assets Inc. (MIRA) funded an additional $11 million of investment, which is excluded from our consolidated results.
Cash provided by operating activities was $68 million for the fourth quarter of 2018, which included interest payments of $157 million.
Full Year 2018 Results
For the full year of 2018, CRC net income was $328 million, or $6.77 per diluted share, compared to a CRC net loss of $266 million, or $6.26 per diluted share, for the full year of 2017. Adjusted net income1 for 2018 was $61 million, or $1.27 per diluted share, compared with an adjusted net loss1 of $187 million, or $4.40 per diluted share, for 2017. The 2018 results reflected significantly higher realized prices and higher production, partially offset by increased production costs, as well as higher G&A and interest expense. The 2018 adjusted net income1 excluded $224 million of non-cash derivative gains on commodity contracts, a net gain of $57 million on debt repurchases, a $6 million non-cash derivative loss from interest rate contracts, a $5 million gain on asset divestitures and a net $13 million charge related to other unusual and infrequent items. The 2017 adjusted net loss1 excluded $78 million of non-cash derivative losses, $21 million of gains from asset divestitures, a $4 million net gain on debt repurchases and a $26 million net charge from other unusual and infrequent items.
Total daily production volumes averaged 132,000 BOE per day for the full year of 2018 compared with 129,000 BOE per day for 2017. This net increase included a 1,300 barrel per day negative PSC effect on production volumes due to higher realized prices for 2018. Oil volumes averaged 82,000 barrels per day, NGL volumes averaged 16,000 barrels per day and gas volumes averaged 202,000 MCF per day.
Realized crude oil prices, including the effect of settled hedges, increased $11.36 per barrel to $62.60 per barrel for the full year 2018 from $51.24 per barrel for 2017. Settled hedges reduced 2018 realized crude oil prices by $7.51 per barrel compared with a $0.23 decrease per barrel for 2017. Realized NGL prices increased 22% to $43.67 per barrel for 2018 from $35.76 per barrel for 2017. Realized natural gas prices increased 12% to $3.00 per MCF for 2018 compared with $2.67 per MCF for 2017.
Production costs for the full year of 2018 were $912 million, or $18.88 per BOE, compared to $876 million, or $18.64 per BOE, for 2017. The Elk Hills acquisition and cash-settled stock-based compensation added $38 million and $4 million to full year production costs for 2018, respectively. Synergies captured from the Elk Hills consolidation reduced production costs by $17 million, partially offset by an increase in energy costs. Per unit production costs, excluding the effect of PSC contracts1, were $17.47 and $17.48 per BOE for the full year of 2018 and 2017, respectively. G&A expenses were $299 million and $249 million for the full year of 2018 and 2017, respectively, with the difference primarily related to increased equity compensation expense resulting from CRC’s higher stock price, as well as additional G&A expense as a result of lower cost recovery following the Elk Hills acquisition.
Taxes other than on income of $149 million for 2018 were $13 million higher than 2017, primarily due to higher greenhouse gas (GHG) costs related to annual price increases, in addition to a reduction in the number of allowances granted to CRC between periods. CRC reported exploration expenses of $34 million for the full year of 2018, or $12 million higher than 2017, due to exploration dry holes.
CRC’s internally funded capital investment for 2018 totaled $641 million, of which $445 million was directed to drilling and capital workovers. CRC’s JV partner BSP funded an additional $49 million, which is included in CRC’s consolidated results, while JV partner MIRA funded an additional $57 million of investment, which is excluded from our consolidated results.
Cash provided by operating activities for the full year of 2018 was $461 million, which included interest payments of $441 million and $98 million of GHG payments related to prior years’ allowances.
CRC operated an average of 10 drilling rigs during the fourth quarter of 2018 with five rigs focused on waterfloods, three on conventional primary production, one on steamfloods and one on unconventional production. CRC drilled 90 development wells and one exploration well with CRC and JV capital (33 steamflood, 38 waterflood, 13 primary and 7 unconventional). Steamfloods and waterfloods have different production profiles and longer response times than typical conventional wells and, as a result, the full production contribution may not be experienced in the same period that the well is drilled. In the San Joaquin basin, CRC produced approximately 99,000 BOE per day and operated six rigs during the fourth quarter of 2018. The Los Angeles basin contributed 26,000 BOE per day of production and operated three rigs directed toward waterflood projects during the fourth quarter of 2018. The Ventura basin produced 6,000 BOE per day and operated one rig directed toward waterflood projects during the fourth quarter of 2018. The Sacramento basin produced 5,000 BOE per day and had no active drilling program during the fourth quarter of 2018.
2019 Capital Budget
With current oil prices slightly above $60 per barrel Brent, CRC estimates its 2019 internally funded capital program will range from $300 million to $385 million, which may be adjusted during the course of the year depending on commodity prices. CRC is also in discussion to obtain additional investments from new and existing JVs that could increase the 2019 capital program by $100 to $150 million, to support a total capital budget of approximately $500 million. CRC’s internally funded investments will be largely directed to quick payback projects, such as primary drilling and capital workovers, and low-risk projects including waterflood and steamflood investments that maintain base production.
Balance Sheet Strengthening Update
For the fourth quarter of 2018, CRC repurchased a total of $55 million in aggregate principal amount of CRC’s outstanding debt for $50 million. In 2018, CRC repurchased a total of $232 million in aggregate principal amount of CRC’s outstanding debt for $199 million. The majority of CRC’s debt repurchases focused on CRC’s Second Lien Notes.
Year-End 2018 Reserves
CRC’s proved reserves totaled 712 million barrels of oil equivalent (MMBOE), an increase from 618 MMBOE in 2017. Excluding positive price revisions, proved undeveloped reserves downgraded at management’s discretion and acquisitions, CRC organically replaced 127% of proved reserves. CRC achieved this strong organic reserve replacement ratio through well-executed capital programs in its Buena Vista, South Valley, Huntington Beach and Long Beach areas of operations. In 2018, total additions to proved reserves from all sources were 142 MMBOE, resulting in an all-in reserve replacement ratio of 296%.
CRC continues to opportunistically implement a hedging program to protect its cash flow, operating margins and capital program, while maintaining adequate liquidity. For the first and second quarters of 2019, CRC has protected the downside price risk of approximately 45,000 and 40,000 barrels per day at approximately $66 Brent and $70 Brent per barrel, respectively. For the third and fourth quarters of 2019, CRC has protected the downside price risk of approximately 40,000 and 35,000 barrels per day at approximately $73 Brent and $76 Brent per barrel, respectively. Except for a small portion primarily in the first quarter of 2019, the 2019 hedges do not contain caps, thereby providing upside to oil price movements. See Attachment 10 for more details.
1 See Attachment 3 for how CRC calculates and uses the non-GAAP measures of adjusted EBITDAX, core adjusted EBITDAX, adjusted EBITDAX margin, free cash flow, production costs (excluding the effects of PSC-type contracts) and adjusted net income (loss), and for reconciliations of the foregoing to their nearest GAAP measure.
Conference Call Details
To participate in today’s conference call scheduled for 5:00 P.M. Eastern Standard Time, 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/10127347. 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 the Investor Relations section of 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. CRC operates its world-class resource base exclusively within the State of California, applying complementary and 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.
This presentation contains forward-looking statements that involve risks and uncertainties that could materially affect CRC’s expected results of operations, liquidity, cash flows and business prospects. Such statements include those regarding CRC’s expectations as to its future:
- financial position, liquidity, cash flows and results of operations
- business prospects
- transactions and projects
- operating costs
- Value Creation Index (VCI) metrics, which are based on certain estimates including future production rates, costs and commodity prices
- operations and operational results including production, hedging and capital investment
- budgets and maintenance capital requirements
- type curves
- expected synergies from acquisitions and joint ventures
Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. While CRC believes assumptions or bases underlying its expectations are reasonable and make them in good faith, they almost always vary from actual results, sometimes materially. CRC also believes third-party statements it cites are accurate, but has not independently verified them and does not warrant their accuracy or completeness. Factors (but not necessarily all the factors) that could cause results to differ include:
- commodity price changes
- debt limitations on CRC’s financial flexibility
- insufficient cash flow to fund planned investments, debt repurchases or changes to CRC’s capital plan
- inability to enter desirable transactions, including acquisitions, asset sales and joint ventures
- legislative or regulatory changes, including those related to drilling, completion, well stimulation, operation, maintenance or abandonment of wells or facilities, managing energy, water, land, greenhouse gases or other emissions, protection of health, safety and the environment, or transportation, marketing and sale of our products
- joint ventures and acquisitions and CRC’s ability to achieve expected synergies
- the recoverability of resources and unexpected geologic conditions
- incorrect estimates of reserves and related future cash flows and the inability to replace reserves
- changes in business strategy
- PSC effects on production and unit production costs
- effect of stock price on costs associated with incentive compensation
- insufficient capital, including as a result of lender restrictions, unavailability of capital markets or inability to attract potential investors
- effects of hedging transactions
- equipment, service or labor price inflation or unavailability
- availability or timing of, or conditions imposed on, permits and approvals
- lower-than-expected production, reserves or resources from development projects, joint ventures or acquisitions, or higher-than-expected decline rates
- disruptions due to accidents, mechanical failures, transportation or storage constraints, natural disasters, labor difficulties, cyber attacks or other catastrophic events
- factors discussed in “Risk Factors” in CRC’s Annual Report on Form 10-K available on its website at crc.com.
Words such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “goal,” “intend,” “likely,” “may,” “might,” “plan,” “potential,” “project,” “seek,” “should,” “target, “will” or “would” and similar words 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 CRC 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.
|SUMMARY OF RESULTS|
|Fourth Quarter||Twelve Months|
|($ and shares in millions, except per share amounts)||2018||2017||2018||2017|
|Statement of Operations Data:|
|Revenues and Other|
|Oil and gas sales (a)||$||658||$||549||$||2,590||$||1,936|
|Net derivative gain (loss) from commodity contracts||260||(141||)||1||(90||)|
|Other revenue (a)||160||47||473||160|
|Total revenues and other||1,078||455||3,064||2,006|
|Costs and Other|
|General and administrative expenses||65||66||299||249|
|Depreciation, depletion and amortization||130||132||502||544|
|Taxes other than on income||29||33||149||136|
|Other expenses, net (a)||140||30||399||106|
|Total costs and other||613||493||2,295||1,933|
|Operating Income (Loss)||465||(38||)||769||73|
|Non-Operating (Loss) Income|
|Interest and debt expense, net||(98||)||(91||)||(379||)||(343||)|
|Net gain on early extinguishment of debt||31||—||57||4|
|Gain on asset divestitures||1||—||5||21|
|Other non-operating expenses||(7||)||(6||)||(23||)||(17||)|
|Income (Loss) Before Income Taxes||392||(135||)||429||(262||)|
|Net Income (Loss)||392||(135||)||429||(262||)|
|Net income attributable to noncontrolling interests||(46||)||(3||)||(101||)||(4||)|
|Net Income (Loss) Attributable to Common Stock||$||346||$||(138||)||$||328||$||(266||)|
|Net income (loss) attributable to common stock per share – basic (b)||$||7.00||$||(3.23||)||$||6.77||$||(6.26||)|
|Net income (loss) attributable to common stock per share – diluted||$||7.00||$||(3.23||)||$||6.77||$||(6.26||)|
|Adjusted net income (loss)||$||26||$||(14||)||$||61||$||(187||)|
|Adjusted net income (loss) per share – basic (b)||$||0.53||$||(0.33||)||$||1.27||$||(4.40||)|
|Adjusted net income (loss) per share – diluted||$||0.53||$||(0.33||)||$||1.27||$||(4.40||)|
|Weighted-average common shares outstanding – basic||$||48.6||$||42.7||$||47.4||$||42.5|
|Weighted-average common shares outstanding – diluted||$||48.6||$||42.7||$||47.4||$||42.5|
|Effective tax rate||0||%||0||%||0||%||0||%|
|(a) We adopted a new revenue recognition standard on January 1, 2018 which required certain sales-related costs to be reported as expense as opposed to being netted against revenue. The adoption of this standard does not affect net income. Results for reporting periods beginning January 1, 2018 are presented under the new accounting standard while prior periods are not adjusted and continue to be reported under accounting standards in effect for the applicable period. Under prior accounting standards, for the three and twelve months ended December 31, 2018, oil and gas sales would have been $653 million and $2,568 million, respectively, other revenue would have been $150 million and $392 million, respectively, and other expenses, net would have been $125 million and $296 million, respectively.|
|(b) In calculating Net income (loss) attributable to common stock per share – basic, income of $6 million and $7 million for the three and twelve months ended December 31, 2108, respectively, was allocated to unvested participating securities with the balance of undistributed earnings allocated to common shares. In calculating Adjusted net income (loss) per share – basic, none and $1 million for the three and twelve months ended December 31, 2018, respectively, was allocated to unvested participating securities with the balance of undistributed earnings allocated to common shares. For periods of losses no allocation is made to participating securities.|
Scott Espenshade (Investor Relations)
Margita Thompson (Media)