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 $66 million, or $1.32 per diluted share, for the third quarter of 2018. Adjusted net income1 for the third quarter of 2018 was $41 million, or $0.81 per diluted share.
Quarterly Highlights Include:
- Generated core adjusted EBITDAX1 of $400 million, which excludes the impact of $79 million of cash settlement payments on commodity hedge contracts and $13 million of cash-settled stock-based compensation expense
- Reported adjusted EBITDAX1 of $308 million, 26% higher than the prior quarter, and an adjusted EBITDAX margin1 of 38%
- Produced 136,000 BOE per day, which reflects an increase of 6% over the prior year period and the midpoint of the previous guidance range
- Invested $196 million of total capital of which internally funded capital was $158 million
- Drilled 59 wells with internally funded capital and 36 wells with joint venture (JV) capital
- Realized $34 million of annualized synergies after the Elk Hills acquisition, exceeding the initial $20 million target well ahead of anticipated pace
- Increased 2018 capital budget to a range of $720 to $750 million, including approximately $100 million of JV funding, to sustain the increased level of activity through the fourth quarter
- Issued fourth quarter of 2018 production guidance of 136,000 to 139,000 BOE per day reflecting continued production growth
Todd A. Stevens, CRC’s President and Chief Executive Officer, said, “CRC‘s value-driven strategy continued to deliver strong results for the third quarter of 2018, showcasing operational excellence, strong Brent-based realizations, effective capital deployment and portfolio de-risking with the execution of two joint ventures. This resulted in the highest level of quarterly adjusted EBITDAX since 2014 and demonstrated our ability to deliver positive free cash flow before working capital on a year-to-date basis. We remain dedicated to capturing the full value of our conventional resources and driving production growth from our diverse portfolio of assets, while strengthening our financial position and furthering debt reduction efforts. Looking ahead, we are focused on a strong finish to 2018 and carrying that momentum into 2019.”
Third Quarter 2018 Results
For the third quarter of 2018, CRC net income was $66 million, or $1.32 per diluted share, while adjusted net income1 was $41 million, or $0.81 per diluted share. Adjusted net income1 excluded $28 million of non-cash derivative gains, a $3 million gain on asset divestitures, a net gain of $2 million on debt repurchases and a net $8 million charge related to other unusual and infrequent items. These results compared to a net loss of $133 million, or $3.11 per diluted share, and an adjusted net loss of $52 million, or $1.22 per diluted share, in the same prior year period. The 2018 results reflected higher production, significantly higher realized commodity prices and higher gas trading income, partially offset by higher production costs and general and administrative (G&A) expenses.
Total daily production volumes averaged 136,000 barrels of oil equivalent (BOE) per day for the third quarter of 2018, compared to 128,000 BOE per day for the same period in 2017, an increase of more than 6 percent over the prior year period, largely driven by the Elk Hills acquisition. This net increase included a 1,300 BOE per day negative effect on production volumes from production sharing contracts (PSC). For the third quarter of 2018 oil volumes averaged 84,000 barrels per day, NGL volumes averaged 17,000 barrels per day and gas volumes averaged 208,000 thousand cubic feet (MCF) per day.
Realized crude oil prices, including the effect of settled hedges, increased by $13.61 per barrel in the third quarter of 2018 to $63.63 per barrel from the comparable prior year period. Settled hedges decreased realized crude oil prices by $10.10 per barrel in the third quarter of 2018. Average realized NGL prices continued to be strong and registered $45.72 per barrel, reflecting a realized price that was 60 percent of Brent prices. Realized natural gas prices were $3.16 per MCF in the third quarter of 2018, $0.60 higher than in the same prior year period and $0.91 higher than in the second quarter of 2018. The increase in realized gas prices is largely due to higher price realizations resulting from limited third-party storage, pipeline constraints and seasonality trends.
Production costs for the third quarter of 2018 were $236 million compared to $222 million in the third quarter of 2017, an increase of $14 million primarily due to $12 million from the Elk Hills acquisition and increased equity compensation expense of $2 million primarily resulting from the Company’s higher stock price. On a per unit basis, third quarter of 2018 production costs were $18.92 per BOE compared to $18.90 per BOE in the comparable prior year period. Third quarter of 2018 unit production costs were below the midpoint of previously disclosed guidance and would have been $18.68 per BOE excluding equity compensation expense of $0.24 per BOE. In line with industry practice for companies operating under PSCs, CRC reports gross field operating costs but only the Company’s share of production volumes, which can result in higher production costs per barrel. Excluding this PSC effect, per unit production costs1 for the third quarter of 2018 would have been $17.55 per BOE. General and administrative expenses of $81 million for the third quarter of 2018 were $20 million higher than the comparable prior year period primarily related to higher equity compensation expense of $9 million as a result of CRC’s increased stock price and additional G&A of $3 million as a result of the Elk Hills acquisition. The remaining increase in G&A expenses was the result of a number of smaller increases in various cost categories.
CRC reported taxes other than on income of $45 million, $6 million higher than the same prior year period largely due to higher property taxes as a result of commodity price increases. Exploration expense was $4 million for the third quarter of 2018, $1 million lower than the comparable prior year period.
Capital investment in the third quarter of 2018 totaled $158 million, excluding JV capital. Approximately $136 million was directed to drilling and capital workovers.
Cash provided by operating activities was $159 million, which included interest payments of $69 million. CRC’s free cash flow1, excluding BSP funded capital of $19 million, was $1 million in the third quarter of 2018.
For the first nine months of 2018, CRC net loss was $18 million, or $0.38 per diluted share, compared to net loss of $128 million, or $3.01 per diluted share, for the same period of 2017. The 2018 results reflected significantly higher realized oil and NGL prices, partially offset by higher production costs and higher G&A expense. Adjusted net income1 for the first nine months of 2018 was $35 million, or $0.71 per diluted share, compared with an adjusted net loss of $173 million, or $4.07 per diluted share, for the same prior year period. The 2018 adjusted net income excluded $71 million of non-cash derivative losses, a net gain of $26 million on debt repurchases, a $4 million gain on asset divestitures and a net $12 million charge related to other unusual and infrequent items. The 2017 adjusted net loss excluded $38 million of non-cash derivative gains, $21 million of gains from asset divestitures, a $4 million net gain on debt repurchases and an $18 million charge from other unusual and infrequent items.
Total daily production volumes averaged 131,000 BOE per day in the first nine months of 2018 compared with 130,000 BOE per day for the same period of 2017. This increase included a negative effect on production volumes from PSCs of 1,800 BOE per day. Excluding production from the Elk Hills acquisition and the effect of PSCs, the decline from the first nine months of 2017 to the first nine months of 2018 was 4 percent. This low decline reflects the gradual ramp up in capital investment beginning in late 2017.
In the first nine months of 2018, realized crude oil prices, including the effect of settled hedges, increased $14.11 per barrel to $63.53 per barrel from $49.42 per barrel for the same prior year period. Settled hedges reduced 2018 realized crude oil prices by $8.00 per barrel compared with an increase of $0.66 per barrel for the same period of 2017. Realized NGL prices increased 32 percent to $43.71 from $33.00 per barrel in the first nine months of 2017. Realized natural gas prices increased 3 percent to $2.73 per MCF compared with $2.64 per MCF for the comparable prior year period.
Production costs for the first nine months of 2018 were $679 million, or $18.98 per BOE, compared to $649 million, or $18.31 per BOE, for the same period in 2017. The Elk Hills acquisition added $24 million to the first nine months’ production costs and the increase in equity compensation expense added $8 million, or $0.23 per BOE. Excluding these items, production costs were slightly lower in the current year compared to the prior year due to ongoing efficiency efforts. Per unit production costs, excluding the effect of PSC contracts, were $17.48 and $17.21 per BOE for the first nine months of 2018 and 2017, respectively. G&A expenses were $234 million and $183 million for the first nine months of 2018 and 2017, respectively, with the difference primarily related to increased equity compensation expense resulting from the Company’s higher stock price and additional G&A expense as a result of the Elk Hills acquisition.
Taxes other than on income of $120 million for the first nine months of 2018 were $17 million higher than the same period of 2017 primarily due to higher property taxes as a result of commodity price increases. Exploration expense of $18 million for the first nine months of 2018 was $1 million higher than the comparable year period of 2017.
Capital investment in the first nine months of 2018 totaled $467 million, excluding JV capital, of which $363 million was directed to drilling and capital workovers.
Cash provided by operating activities for the first nine months of 2018 was $393 million and free cash flow, excluding BSP funded capital of $37 million, was $(74) million. Excluding changes in working capital, which predominantly relate to greenhouse gas payments for prior years’ activities, free cash flow would have been $17 million.
CRC operated an average of 10 drilling rigs during the third quarter of 2018 with two rigs focused on steamfloods, four on waterfloods, two on conventional primary production, one on unconventional production and one on exploration. CRC drilled 94 development wells and one exploration well with CRC and JV capital (43 steamflood, 25 waterflood, 18 primary and 9 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 operated seven rigs and produced approximately 99,000 BOE per day in the third quarter of 2018. The Los Angeles basin operated three rigs directed toward waterflood projects and contributed 26,000 BOE per day of production in the third quarter of 2018. The Ventura basin produced 6,000 BOE per day and the Sacramento basin produced 5,000 BOE per day. Neither the Ventura nor Sacramento basin had active drilling programs in the third quarter of 2018.
2018 Capital Budget
CRC increased its 2018 capital program to a range of $720 million to $750 million, which includes approximately $100 million of JV capital. This increase from the previously stated range of $650 million to $700 million is intended to build on the momentum created in the first nine months of 2018. The updated program reflects management’s strategy to align the capital program with stronger expected cash flows from commodity price improvements and increased production from the Elk Hills acquisition. The additional capital will sustain current workover and facility activity through the fourth quarter of 2018.
Debt Reduction Update
CRC continues to deliver on its commitment to strengthen the balance sheet. In the third quarter of 2018, CRC repurchased a total of $32 million in aggregate principal amount of the Company’s outstanding debt for $30 million in cash. Through the first nine months of 2018, CRC repurchased a total of $177 million in aggregate principal amount of the Company’s outstanding debt for $149 million in cash. The majority of CRC’s debt repurchases focused on the Company’s Second Lien Notes.
Borrowing Base Redetermination
Effective October 2018, CRC’s borrowing base under its 2014 Credit Agreement was reaffirmed at $2.3 billion.
CRC’s mid-year proved reserves totaled 731 MMBOE, up from 618 MMBOE at year-end 2017. Excluding positive price revisions and additions related to the Elk Hills acquisition, the Company organically replaced 96% of proved reserves. This strong organic reserve replacement ratio (RRR) was achieved with well executed capital programs in Buena Vista, South Valley, Huntington Beach and Long Beach. Approximately 23 MMBOE of additions were related to transfers, revisions, extensions and discoveries and improved recovery. The Elk Hills acquisition added 63 MMBOE of proved reserves, in line with the estimate stated at the time of acquisition.
CRC continues to opportunistically seek hedging transactions 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 47,000 and 42,000 barrels per day at approximately $65.35 Brent and $68.91 Brent per barrel, respectively. In the third and fourth quarters of 2019, the Company protected the downside price risk of approximately 42,000 and 37,000 barrels per day at approximately $72.18 and $74.56 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 8 for more details.
1 See Attachment 3 for explanations of 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 as applicable.
Conference Call Details
To participate in today’s conference call scheduled for 5:00 P.M. Eastern Daylight 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/10124828. 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. The Company 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 our expected results of operations, liquidity, cash flows and business prospects. Such statements include those regarding our expectations as to our 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 we believe assumptions or bases underlying our expectations are reasonable and make them in good faith, they almost always vary from actual results, sometimes materially. We also believe third-party statements we cite are accurate but have not independently verified them and do 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 our financial flexibility
- insufficient cash flow to fund planned investments, debt repurchases or changes to our 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 our 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 our Annual Report on Form 10-K available on our 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 we undertake 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|
|Third Quarter||Nine 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)||$||700||$||461||$||1,932||$||1,387|
|Net derivative (loss) gain from commodity contracts||(54||)||(65||)||(259||)||51|
|Other revenue (a)||182||49||313||113|
|Total revenues and other||828||445||1,986||1,551|
|Costs and Other|
|General and administrative expenses||81||61||234||183|
|Depreciation, depletion and amortization||128||134||372||412|
|Taxes other than on income||45||39||120||103|
|Other expenses, net (a)||149||29||259||76|
|Total costs and other||643||490||1,682||1,440|
|Operating Income (Loss)||185||(45||)||304||111|
|Non-Operating (Loss) Income|
|Interest and debt expense, net||(95||)||(85||)||(281||)||(252||)|
|Net gain on early extinguishment of debt||2||—||26||4|
|Gain on asset divestitures||3||—||4||21|
|Other non-operating expenses||(4||)||(2||)||(16||)||(11||)|
|Income (Loss) Before Income Taxes||91||(132||)||37||(127||)|
|Net Income (Loss)||91||(132||)||37||(127||)|
|Net income attributable to noncontrolling interests||(25||)||(1||)||(55||)||(1||)|
|Net Income (Loss) Attributable to Common Stock||$||66||$||(133||)||$||(18||)||$||(128||)|
|Net income (loss) attributable to common stock per share – basic||$||1.34||$||(3.11||)||$||(0.38||)||$||(3.01||)|
|Net income (loss) attributable to common stock per share – diluted||$||1.32||$||(3.11||)||$||(0.38||)||$||(3.01||)|
|Adjusted net income (loss)||$||41||$||(52||)||$||35||$||(173||)|
|Adjusted net income (loss) per share – basic||$||0.82||$||(1.22||)||$||0.72||$||(4.07||)|
|Adjusted net income (loss) per share – diluted||$||0.81||$||(1.22||)||$||0.71||$||(4.07||)|
|Weighted-average common shares outstanding – basic||48.5||42.7||47.0||42.5|
|Weighted-average common shares outstanding – diluted||49.1||42.7||47.0 (b)||42.5|
|Effective tax rate||0%||0%||0%||0%|
|(a) We adopted the 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 after 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 prior periods. Under prior accounting standards, for the three and nine months ended September 30, 2018, oil and gas sales would have been $695 million and $1,915 million, respectively, other revenue would have been $177 million and $242 million, respectively, and other expenses, net would have been $139 million and $171 million, respectively.|
|(b) Weighted-average common shares outstanding for adjusted net income (loss) per share – diluted were 47.6 million.|
|Third Quarter||Nine Months|
|($ and shares in millions)||2018||2017||2018||2017|
|Cash Flow Data:|
|Net cash provided by operating activities||$||159||$||105||$||393||$||225|
|Net cash used in investing activities||$||(158||)||$||(100||)||$||(965||)||$||(174||)|
|Net cash (used) provided by financing activities||$||(12||)||$||14||$||583||$||(35||)|
|Balance Sheet Data:||September 30,||December 31,|
|Total current assets||$||546||$||483|
|Total property, plant and equipment, net||$||6,386||$||5,696|
|Total current liabilities||$||871||$||732|
|Outstanding shares as of||48.6||42.9|
|Our stock price increased $38.07 or over 364% from $10.46 as of September 30, 2017 to $48.53 as of September 30, 2018. Due to our stock price increase, we recognized a significant increase in stock-based compensation expense that is included in both general and administrative expenses and production costs as shown in the following table:|
|Third Quarter||Nine Months|
|($ in millions, except per BOE amounts)||2018||2017||2018||2017|
|General and administrative expenses|
|Total stock-based compensation in G&A||$||13||$||5||$||43||$||13|
|Total stock-based compensation in G&A per Boe||$||1.04||$||0.43||$||1.20||$||0.37|
|Total stock-based compensation in production costs||$||3||$||1||$||11||$||3|
|Total stock-based compensation in production costs per Boe||$||0.24||$||0.09||$||0.31||$||0.08|
|Total company stock-based compensation||$||16||$||6||$||54||$||16|
|Total company stock-based compensation per Boe||$||1.28||$||0.52||$||1.51||$||0.45|