CONOCOPHILLIPS quarterly report, Q3 FY2018

ConocoPhillips — Q3 2018 Form 10-Q Summary

Reporting period: Quarter and nine months ended September 30, 2018. The interim financial statements are unaudited. ConocoPhillips is a global exploration and production company operating in 17 countries.

Financial performance and position

Metric	Q3 2018	Q3 2017	Nine months 2018	Nine months 2017
Sales and other operating revenues	$9.449B	$6.688B	$26.751B	$20.987B
Total revenues and other income	$10.165B	$7.195B	$28.366B	$23.848B
Net income (loss) attributable to ConocoPhillips	$1.861B	$420M	$4.389B	$(2.434)B
Diluted earnings (loss) per share	$1.59	$0.34	$3.72	$(1.98)

Q3 net income margin was approximately 18.3% of total revenues and other income, calculated from reported figures; settlement proceeds and other items affected earnings.
Operating cash flow was $9.151B for the first nine months, versus $4.596B a year earlier. Capital expenditures and investments were $5.133B; dividends were $1.009B and share repurchases were $2.073B.
At September 30, cash and cash equivalents were $3.716B, short-term investments $875M, and cash, cash equivalents and restricted cash totaled $3.940B. Management reported approximately $4.8B including short-term investments.
Total debt was approximately $14.997B, down $4.706B from December 2017. Debt-to-capital was 32%, versus 39%. The company had $6.0B available under its revolving credit facility and no commercial paper outstanding.
Current assets were $14.723B and current liabilities $7.401B. The reported balance-sheet figures imply a current ratio of approximately 2.0.
Average Q3 production was 1,261 MBOED, including Libya; excluding Libya it was 1,224 MBOED. Total production rose 3% year over year, while nine-month production declined 11%, largely reflecting prior-year dispositions and field decline.

Material changes versus the prior comparable period

Q3 revenue increased 41% and attributable net income rose to $1.861B from $420M, driven mainly by higher realized commodity prices, higher crude oil sales volumes, and $325M after-tax from the PDVSA settlement. Lower DD&A also helped; higher operating costs partly offset gains.
For the first nine months, the company moved from a $2.434B loss to $4.389B of income. The comparison was heavily affected by 2017 impairments, including $2.384B for APLNG and substantial Lower 48 write-downs, as well as 2017 Canadian asset-sale gains and tax benefits.
Q3 average realized price was $57.71 per BOE, up 46% year over year. Brent averaged $75.27 per barrel, up 44%; WTI averaged $69.71, up 45%. Henry Hub gas averaged $2.91 per MMBTU, down 3%.
Operating cash flow more than doubled year over year, primarily reflecting higher realized prices. Debt fell by $4.7B as the company reached its $15B debt target ahead of schedule. Fitch and Moody’s upgraded the company’s long-term ratings.
Q3 dividends paid were $0.29 per share, compared with $0.27 a year earlier. The company announced an October increase to $0.305 per share.

Outlook, management commentary, risks and unusual items

Q4 2018 production guidance is 1,275–1,315 MBOED, excluding Libya and reflecting seasonal turnaround completion, project startups and ongoing unconventional development.
Full-year 2018 capital expenditures and investments are expected to be $6.6B. Capital expenditure guidance was raised to $6.1B from the original $5.5B budget; the stated guidance excludes $0.4B for the Alaska acquisition and $0.1B for additional Montney acreage.
The 2018 share-repurchase plan was increased to $3B, expected to be funded with operating cash flow. The board authorized an additional $9B, bringing total authorization to $15B. Management’s capital priorities include investment, dividends, debt reduction, repurchases and selective growth.
Management expects commodity prices to remain cyclical and notes that earnings and operating cash flows are highly dependent on oil, gas, LNG and NGL prices. Other risks include production interruptions, political instability, transportation constraints, regulatory and climate-related changes, litigation, and the ability to collect PDVSA settlement payments.
PDVSA agreed to pay approximately $2B, including initial payments of about $500M within 90 days and the balance quarterly over four and a half years. Q3 recognized $345M in cash and commodity inventory; substantially all of the inventory had been sold by the end of October. Collection of remaining amounts is not assured.
The company expects the BP Clair Field/Greater Kuparuk transactions to close simultaneously, subject to approvals; they are expected to be cash neutral, with a possible $0.5B–$1.0B noncash gain on the Clair sale. The Barnett sale for approximately $230M was expected to close by year-end. A planned $350M Greater Sunrise sale was subject to approvals and expected to close in early 2019.
Environmental remediation accruals were $170M. The filing describes ongoing legal and environmental matters, including climate-related lawsuits; management did not expect known contingencies to have a material adverse effect, but estimates may change.
Adoption of the new lease accounting standard was planned for January 1, 2019; management expected a material balance-sheet impact from recognizing operating-lease liabilities and right-of-use assets. No material changes to reported risk factors were disclosed.

Important facts for investors to verify

Progress and actual receipts under the PDVSA settlement, including timing and collectability of remaining installments.
Whether Q4 production and full-year capital spending meet guidance, and how commodity prices and operating interruptions affect cash generation.
Completion, final consideration and accounting effects of the BP, Barnett and Greater Sunrise transactions, including the potential Clair gain.
Debt reduction, share repurchases and dividend funding relative to operating cash flow and the company’s investment-grade objectives.
Potential effects of lease-standard adoption, environmental obligations, climate litigation and other contingencies.