Business context and reporting period
National Fuel Gas Company’s unaudited fiscal first quarter ended December 31, 2020, compared with the three months ended December 31, 2019. The company operates in natural gas exploration and production, pipelines and storage, gathering, and utility distribution. Results are seasonal, particularly in the heating business.
Key financial metrics
| Metric | Q1 FY2021 | Q1 FY2020 |
|---|---|---|
| Operating revenues | $441.2 million | $444.2 million |
| Operating income | $143.5 million | $148.0 million |
| Net income available to common shareholders | $77.8 million | $86.6 million |
| Diluted EPS | $0.85 | $1.00 |
| Operating cash flow | $204.7 million | $167.7 million |
| Capital expenditures, cash-flow statement | $183.3 million | $198.5 million |
Revenue declined about 0.7%; net income declined about 10.2%. Operating margin was approximately 32.5%, versus 33.3%, and net margin approximately 17.6%, versus 19.5%. Earnings included a $76.2 million pre-tax ($55.2 million after-tax) non-cash oil and gas property impairment and a $51.1 million pre-tax ($37.0 million after-tax) gain on timber property sales.
At December 31, 2020, cash was $109.4 million; current assets were $453.4 million and current liabilities $906.2 million. Long-term debt, including its current portion, was $2.630 billion; bank notes and commercial paper added $25.0 million. The $500 million of 4.90% notes due December 2021 was classified as current debt. The current ratio was approximately 0.50.
Operating cash flow less cash capital expenditures was approximately $21.4 million. Investing cash outflow was $66.9 million, including $104.6 million net proceeds from the timber sale; financing cash outflow was $49.0 million, including $40.5 million of common dividends paid.
Material changes versus prior period
- Exploration and Production swung to a $29.6 million segment loss from $24.0 million of earnings, primarily reflecting the impairment. Appalachian gas production rose 21.3 Bcf, supported partly by the Shell asset acquisition, while lower hedged oil prices and lower oil production weighed on results.
- Pipeline and Storage earnings rose $6.1 million to $24.2 million, mainly from higher rates and new project demand charges. Gathering earnings rose $4.6 million to $20.6 million, mainly on higher volumes, including the acquired Tioga system.
- Utility earnings declined $3.5 million to $23.0 million, with higher operating and bad-debt expense and lower usage/margins contributing. Warmer-than-normal weather reduced throughput; New York’s weather normalization clause added approximately $1.6 million to earnings.
- All Other earnings increased to $37.6 million from $0.4 million, largely because of the timber sale gain. The sale completed a reverse like-kind exchange associated with the 2020 Shell acquisition.
- Cash from operations increased $37.0 million, while cash capital expenditures decreased $15.2 million year over year.
Outlook, commentary, risks and contingencies
- The filing gives no specific consolidated earnings guidance and cautions that the winter-quarter results should not be treated as a forecast for the full fiscal year.
- Management said cash on hand, operating cash flow, timber-sale proceeds and short-term borrowing are expected to meet fiscal 2021 financing needs. The company planned to issue debt during fiscal 2021 to refinance all or part of the $500 million December 2021 maturity.
- Following ceiling-test impairments in fiscal 2020 and Q1 FY2021, indenture covenants restrict incremental unsubordinated long-term debt issuance beginning January 2021, with the restriction expected to extend into the second half of fiscal 2021. Refinancing existing debt is permitted. The company reported a 0.54 debt-to-capitalization ratio under its revolving-credit agreements and $1.0 billion of committed revolving access. On February 3, 2021, it extended and increased its 364-day facility to $250 million, through December 30, 2022.
- The company expected to bring on a second Appalachian drilling rig, with production from its first associated pad expected in early fiscal 2022. The FM100 pipeline project, with a preliminary cost estimate of approximately $280 million and target in-service date of late calendar 2021, had $34.3 million capitalized at quarter-end. Project timing and costs remain exposed to construction, permitting and pandemic-related disruption.
- The Northern Access project remains subject to pending legal and regulatory proceedings over New York permits and water certification. The company remains committed to the project but said its preliminary $500 million cost estimate and timing would be updated when there is greater clarity.
- COVID-19 service termination restrictions, possible increases in customer non-payment and uncertain regulatory recovery of related costs present risks. The company had not experienced a significant payment-rate decline to date but anticipated possible higher non-payment as winter usage and bills increased.
- Commodity prices and full-cost ceiling tests create earnings and financing risk. Management’s sensitivity analysis showed that a further $0.25/MMBtu decline in gas prices could have resulted in $270.1 million of additional after-tax impairment; a $5/Bbl oil-price decline, $35.8 million; and both declines together, $305.9 million. These estimates exclude other changes in reserves and costs.
- Other exposures include climate and emissions regulation, environmental compliance, counterparty and credit risk, and pension funding. Estimated remaining cleanup costs for former manufactured gas plant sites were approximately $6.0 million; management expected recovery through rates over about two years. Other ordinary-course matters may affect earnings when resolved, but management did not expect a material adverse effect on financial condition.
Important facts for investors to verify
- Whether commodity prices, reserves and development costs lead to further ceiling-test impairment and continued limits on long-term debt issuance.
- How the company refinances the $500 million December 2021 maturity and maintains covenant compliance and liquidity.
- Progress, costs, permitting and in-service timing for FM100 and the legally contested Northern Access project.
- Whether utility customer arrears and uncollectible expense increase, and whether regulators allow recovery of pandemic-related costs.
- Whether Appalachian production growth and new pipeline capacity generate expected returns, and how hedging affects realized commodity prices.