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California Resources Adds Ninth Rig in Q3; Drills 28 Wells

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   |    Friday,December 08,2017

[Summary: California Resources reported its Q3 2017 results. Highlights include:

  • Q3 Production: 128,000 BOEPD
  • Drilled 28 new wells in Q3
  • Ninth Rig Added: The Company averaged eight rigs in the third quarter of 2017 and is currently operating nine rigs. Activity has primarily been focused in the San Joaquin Basin on steamfloods and waterfloods.]

ORIGINAL RELEASE:

California Resources Corporation (NYSE:CRC), an independent California-based oil and gas exploration and production company, today reported a net loss attributable to common stock (CRC net loss) of $133 million, or $3.11 per diluted share, for the third quarter of 2017, compared with net income attributable to common stock (CRC net income) of $546 million, or $13.04 per diluted share, for the third quarter of 2016. The adjusted net loss1 for the third quarter of 2017 was $52 million, or $1.22 per diluted share, compared with an adjusted net loss1 of $71 million, or $1.74 per diluted share, for the third quarter of 2016. For the first nine months of 2017, the CRC net loss was $128 million, or $3.01 per diluted share, compared with CRC net income of $356 million, or $8.79 per diluted share, for the same period in 2016. The adjusted net loss1 for the first nine months of 2017 was $173 million, or $4.07 per diluted share, compared with an adjusted net loss1 of $243 million, or $6.12 per diluted share, for the same period in 2016.

Adjusted EBITDAX1 for the third quarter of 2017 was $181 million compared with $164 million for the third quarter of 2016. Adjusted EBITDAX1 for the first nine months of 2017 was $539 million compared with $448 million for the same period in 2016. Cash provided by operations was $225 million for the first nine months of 2017. Capital investments for the third quarter of 2017 were $100 million and $232 million for the first nine months of 2017, of which $30 million was funded by CRC's joint venture (JV) partner Benefit Street Partners (BSP) in the third quarter and $82 million in the first nine months. After excluding the capital that was funded by BSP, CRC generated free cash flow1 of $101 million for the first nine months of 2017.

Quarterly Highlights Include:

  • Produced approximately 128,000 BOE per day
  • Invested capital of $100 million, of which JV partner BSP funded $30 million
  • Drilled 28 wells with internally funded capital and 49 wells with JV capital
  • Received approval for a bank amendment, subject to certain conditions being met, which would extend the maturity of our credit facility and relax financial covenants, among other changes
  • Borrowing Base reaffirmed at $2.3 billion
  • Generated adjusted EBITDAX1 of $181 million, reflecting an adjusted EBITDAX margin1 of 35%

See Attachment 2 for explanations of how we calculate and use the non–GAAP measures of Adjusted EBITDAX, Adjusted EBITDAX margin, Free Cash Flow and Adjusted Net Loss, and for reconciliations of the foregoing to their nearest GAAP measure as applicable.

Todd Stevens, President and Chief Executive Officer, said, "We have been very pleased with our team's execution as we nearly doubled the drilling activity in the third quarter of 2017 compared to the prior quarter. Our corporate strategy has always been to focus on value. One way we have delivered this is through our drilling efficiencies. Furthermore, we are particularly excited about the strong successes from the Buena Vista Nose area and our redevelopment wells in the Los Angeles Basin. We believe we will exit this year at a level of activity supported by capital from cash flows and JV partners. As the industry moves toward our long-standing philosophy of living within cash flow and not chasing production at all costs, we continue to execute against our operational and financial goals with this core principle in mind. We are also pleased to be moving forward with an amendment to address our bank credit facility maturity and covenants."

Third Quarter Results

For the third quarter of 2017, the CRC net loss was $133 million, or $3.11 per diluted share, compared with CRC net income of $546 million, or $13.04 per diluted share, for the same period of 2016. Operational results were stronger year over year due to higher oil and gas sales partially offset by higher production costs from increased downhole maintenance activity. Non-operating income reflected a gain in the third quarter of 2016 from debt-reduction actions. The third quarter 2017 adjusted net loss2 was $52 million, or $1.22 per diluted share, compared with an adjusted net loss2 of $71 million, or $1.74 per diluted share, for the same period of 2016. The third quarter 2017 adjusted net loss2 excluded $72 million of non-cash derivatives losses and a net $9 million charge for other unusual and infrequent items. The third quarter 2016 adjusted net loss2 excluded $660 million of gains related to repurchases of the Company's notes, $25 million of non-cash derivatives losses, a $12 million interest charge for the write-off of deferred debt costs, and a $6 million charge for other unusual and infrequent items.

Total daily production volumes averaged 128,000 barrels of oil equivalent (BOE) per day for the third quarter of 2017, a decrease of 7 percent from 138,000 BOE per day for the third quarter of 2016. Total daily production decreased 1,000 BOE per day, or less than 1 percent, from the second quarter of 2017.

In the third quarter of 2017, realized crude oil prices, including the effect of settled hedges, increased $6.99 per barrel to $50.02 per barrel from $43.03 per barrel in the prior year comparable quarter. Settled hedges increased realized crude oil prices by $1.12 per barrel in the third quarter of 2017 compared with $1.30 per barrel in the prior year comparable quarter. Realized NGL prices increased 54 percent to $34.63 per barrel from $22.45 per barrel in the third quarter of 2016 due to higher exports and low inventories. Realized natural gas prices decreased 3 percent to $2.56 per thousand cubic feet (Mcf), compared with $2.64 per Mcf in the same period of 2016.

Production costs for the third quarter of 2017 were $222 million, or $18.90 per BOE, compared with $211 million, or $16.63 per BOE, for the third quarter of 2016. The industry practice for reporting production sharing-type contracts (PSCs) can result in higher production costs per barrel as gross field operating costs are matched with net production. Excluding the PSC effects, per unit production costs would have been $17.81 and $15.63 for the third quarter of 2017 and 2016, respectively. The increase in production costs was driven by the ramp-up of downhole maintenance activity in line with stronger commodity prices. Adjusted general and administrative (G&A) expenses for the third quarter of 2017 were $62 million, compared with $57 million for the third quarter of 2016. The increase in adjusted G&A expenses was a result of higher costs of performance-based bonus and incentive compensation plans due to better than expected results.

Taxes other than on income of $39 million for the third quarter of 2017 were $2 million higher than the same period of 2016. Exploration expense of $5 million for the third quarter of 2017 was also $2 million higher than the same period of 2016.

Capital investment in the third quarter of 2017 totaled $100 million, consisting of $70 million of CRC internally funded capital and $30 million of BSP capital. Approximately $81 million was directed to drilling and capital workovers.

Cash provided by operations for the quarter of 2017 was $105 million and free cash flow2 was $35 million after excluding capital funded by BSP.

2 See Attachment 2 for explanations of how we calculate and use the non-GAAP measures of Adjusted Net Loss and Free Cash Flow, and for reconciliations to the nearest GAAP measurement, as applicable.

Nine-Month Results

For the first nine months of 2017, the CRC net loss was $128 million, or $3.01 per diluted share, compared with CRC net income of $356 million, or $8.79 per diluted share, for the same period of 2016. Operational results were stronger year over year due to higher revenue partially offset by an increase in production costs resulting from increased activity and higher gas and electricity costs. The first nine months of 2016 reflected a gain from our debt-reduction actions. The adjusted net loss2 for the first nine months of 2017 was $173 million, or $4.07 per diluted share, compared with an adjusted net loss2 of $243 million, or $6.12 per diluted share, for the same period of 2016. The 2017 adjusted net loss2 excluded $38 million of non-cash derivative losses, $21 million of gains from asset divestitures, $4 million of gains related to retirements of the Company's notes and a net $18 million charge from other unusual and infrequent items. The 2016 adjusted net loss2 excluded $793 million of gains related to retirements of the Company's notes, $243 million of non-cash derivatives losses, a $31 million gain from asset divestitures, a $63 million tax benefit from a partial reversal of valuation allowances against CRC's deferred tax assets, a $12 million interest charge for the write-off of deferred debt issuance costs and a net $33 million charge for other unusual and infrequent items.

Total daily production volumes averaged 130,000 BOE per day in the first nine months of 2017, compared with 142,000 BOE per day for the same period in 2016, a decrease of 8 percent.

In the first nine months of 2017, realized crude oil prices, including the effect of settled hedges, increased $8.51 per barrel to $49.42 per barrel from $40.91 per barrel for the same period in 2016. Settled hedges increased 2017 realized crude oil prices by $0.66 per barrel, compared with $3.37 per barrel for the same period in 2016. Realized NGL prices increased 62 percent to $33.00 from $20.36 per barrel in the first nine months of 2016. Realized natural gas prices increased 25 percent to $2.64 per thousand cubic feet (Mcf), compared with $2.11 per Mcf for the same period in 2016.

Production costs for the first nine months of 2017 were $649 million, or $18.31 per BOE, compared with $583 million, or $15.01 per BOE, for the same period in 2016. Per unit production costs, excluding the effect of PSC contracts, were $17.21 and $14.18 per BOE for the first nine months of 2017 and 2016, respectively. The increase in production costs was driven by higher natural gas and power prices and the ramp-up of downhole and surface maintenance activity in line with stronger commodity prices. While higher natural gas prices increase CRC's production costs for power and steam generation, they result in a net benefit to the Company due to higher revenue generated from natural gas sales. Adjusted general and administrative expenses for the first nine months of 2017 were $187 million, compared with $167 million for the first nine months of 2016. The increase in adjusted G&A expenses was a result of higher employee-related costs due to the resumption of employee benefits and higher costs of performance-based bonus and incentive compensation plans due to better than expected results.

Taxes other than on income of $103 million for the first nine months of 2017 were $15 million lower than the same period of 2016. Exploration expense of $17 million for the first nine months of 2017 was $4 million higher than the same period of 2016.

Capital investment in the first nine months of 2017 totaled $232 million, consisting of $150 million of CRC internally funded capital and $82 million of BSP capital. Approximately $170 million was directed to drilling and capital workovers.

Cash provided by operations for the first nine months of 2017 was $225 million and free cash flow3 was $101 million after excluding capital that was funded by BSP.

See Attachment 2 for explanations of how we calculate and use the non-GAAP measures of Adjusted Net Loss and Free Cash Flow, and for reconciliations to the nearest GAAP measure, as applicable.

Hedging Update

CRC continues to opportunistically seek hedging transactions to protect its cash flow, operating margins and capital program and to maintain liquidity. During the third quarter of 2017, CRC hedged 2018 volumes of 19,000 barrels of oil per day at approximately $60.00 Brent for 2018. See attachment 8 for more details.

Operational Update and 2017 Capital Investment Plan

CRC remains on track for its full year total capital plan, which is inclusive of BSP and MIRA JV capital, of $400 million. The Company averaged eight rigs in the third quarter of 2017 and is currently operating nine rigs. Activity has primarily been focused in the San Joaquin Basin on steamfloods and waterfloods. Within the basin, CRC has two rigs on steamfloods, three rigs on conventional, one on waterfloods, and two on unconventional. Additionally, the Company has one part-time rig drilling waterflood projects in the Los Angeles Basin.

For the fourth quarter of 2017, CRC remains focused on waterflood and steamflood opportunities primarily in the San Joaquin Basin. The Company expects to continue deploying JV capital toward its focus areas and anticipates spudding several exploratory opportunities.

Credit Facility Amendment

We are working with our lender group to amend our 2014 Credit Facility. The proposed amendment has received approval from each member of the lender group, subject to federally mandated flood insurance review. The proposed amendment, if completed, would become effective upon the satisfaction of certain conditions, including the closing of a new term loan with minimum proceeds of at least $900 million and minimum liquidity at closing of $500 million. The proceeds of the new term loan would be used to repay a portion of the borrowings under the 2014 Credit Facility. The proposed amendment would, among other things, (i) extend the maturity date of the 2014 Credit Facility until 2021 (subject to a potential earlier springing maturity date consistent with our 2014 Credit Facility), (ii) permit the repurchase of up to $100 million of junior indebtedness, (iii) provide financial covenant relief and (iv) reduce commitments under the 2014 revolving facility to $1 billion and the 2014 term loan to $200 million. We can provide no assurances that the amendment will be signed or will become effective, whether as a result of flood insurance review or otherwise.


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