Super independent Noble Energy Inc., whose vast U.S. portfolio extends across Texas and Colorado, plans to move cautiously through the year in the Lower 48 by shutting in wells and clawing back activity, while it works to build natural gas infrastructure overseas.
CEO David L. Stover helmed a conference call with his management team on Friday to discuss the efficiencies made in the first quarter and how the Houston-based operator has throttled down since the coronavirus took hold worldwide.
“The impacts from the Covid-19 pandemic and the resulting demand destruction has
created the most unpredictable marketplace that I’ve experienced in my 40 years in this
Industry,” Stover said. The supply response by international and U.S. producers has led to “rationing capital and adjusting production. However, the supply-demand imbalance is likely to remain in the near term.
“While we don’t know the duration of this pandemic or the ultimate slope of demand recovery, we will continue to be agile and respond appropriately.”
Noble as of Friday has reduced capital expenditures (capex) for 2020 three times since March, with spend down another $50 million to $750-850 million. The overall capex reduction is about 53% from the midpoint of original 2020 guidance. About 50% of the updated amount was spent in the first quarter.
The U.S. onshore has taken the brunt of the lower spending, as “current commodity prices do not justify new near-term investments in any basin,” Stover said. International projects, weighted to natural gas offshore Israel and Equatorial Guinea (EG), remain on track.
“At Noble Energy, we will not invest capital at less than acceptable returns, and we will preserve our resources for a better future,” the CEO said. “This will result in production declines in the second half of the year. We’re focused on value, not volume. This is further highlighted by our election to voluntarily curtail production in May and June.”
COO Brent Smolik during the call noted the first quarter was one of the best in terms of operational efficiencies and in reducing capital costs. Capital plans for the Lower 48 have been revised, however, with completion activities in the Denver-Julesburg (DJ) Basin of Colorado suspended and drilling activities reduced to one rig.
Noble has the option to complete the drilled but uncompleted (DUC) wells in the DJ in the final three months, but “we’ll hold that capital decision until late this year based on a variety of factors, including the extent of all price improvement,” Smolik said. DUCs could be carried into 2021, which would reduce overall 2020 spending.
Shut-ins are underway in the U.S. onshore too.
“Due to low crude oil realized pricing, we’ve also voluntarily curtailed net-net 5,000-10,000 b/d,” he said. “For June, we expect to curtail 30,000 to 40,000 b/d. We made these decisions on shut-ins in two tranches. The first bucket is lower productivity wells, which are not covering variable operating cost.
“We’re also deferring production from certain higher rate wells for better value in future
higher price environments. The exact amount and the duration of these curtailments is
uncertain and will depend on the recovery of all prices and economics.”
For the remainder of the year, executives have backed off providing guidance. However, Smolik offered some “directional trends.”
Absent the curtailments planned for the second quarter, U.S. onshore production is forecast to be “roughly equivalent” year/year. However, without any new turned-in-line wells from the DUC backlog, domestic output is likely to be 10-12% lower in the last half of this year.
[Want to see more earnings? See the full list of NGI’s 1Q2020 earnings season coverage.]
In the DJ, the average well cost fell to $5.4 million from $6.2 million, while costs in the Delaware formation of the Permian Basin declined to $6.8 million from $8 million. Expenses have also improved, with total U.S. onshore unit production cost more than 50 cents/boe below plan.
For the Eastern Mediterranean (Med) operations, which include the Leviathan gas project offshore Israel, the commissioning process delivered more than 92% facility runtime “and satisfied all of our domestic and export gas sales contracts,” Smolik noted. Platform commissioning also is “nearly complete, reliability is high, and we’ve delivered close to 100% runtime over the last month.”
Following the strong start to sales in January and February, however, the economic slowdown reared up in March across the Eastern Med region, which impacted power demand in gas consumption, Smolik noted.
In 1Q2020, total natural gas, liquids and oil volumes improved year/year to 35.46 million boe/d from 30.38 million boe/d. Gas volumes increased in the Lower 48, as well as from operations offshore Israel and EG to total 1.084 Bcf/d from 884 MMcf/d.
U.S. onshore volumes increased to 516 MMcf/d from 483, with Eastern Med output surging on the start-up of the offshore Leviathan field to 390 MMcf/d from 233. EG volumes were 178 MMcf/d from 168 MMcf/d a year ago.
Crude and condensate volumes also increased year/year, rising to 139,000 b/d from 127,000, with U.S. volumes at 117,000 b/d from 113,000. U.S. onshore natural gas liquids were higher at 66,000 b/d from 59,000 b/d.
For U.S. gas, realized prices fell to an average of $1.27/Mcf from year-ago prices of $2.49. Israel gas fetched an average of $5.36 from $5.57, while EG gas was flat at 27 cents/Mcf.
The average realized prices do not include gains or losses from hedging. Including hedges, the U.S. onshore gas price fetched a price of $1.23 versus $2.61 a year earlier. Domestic oil prices averaged $49.85/bbl from $54.59, while EG oil prices were $47.35 versus $58.22.
Noble in 1Q2020 finalized a liquefied natural gas (LNG) marketing agreement with a “large LNG trader” for offtake from the Alen project underway offshore EG. Pricing is indexed to European LNG, Smolik noted. “Considering the attractive liquefaction cost, the project’s anticipated to pay out is approximately two years.”
In the Eastern Med, however, “the pace of the economic recovery makes it a little more difficult to forecast sales volumes. The good news here, though, is that Israel and Jordan appear to be
several weeks ahead of the U.S. in terms of reopening their economies, which is encouraging for demand recovery this summer.”
Gas sales volumes in the second half of the year are forecast to increase in the Eastern Med region because of seasonal demand and increased quantities required in an Egypt supply contract for the offshore supply.
“With Leviathan fully installed, we now have a total of 2.3 Bcf of gross deliverability,” Smolik said. “This is a one-of-a-kind asset, with extremely low operating and development costs,” with more than “32 Tcf of gas to produce in the future…”
First quarter net losses totaled $4 billion (minus $8.27/share), which included a one-time impairment of $4.2 billion associated with writing down the value of proved and unproved properties in the Permian and Eagle Ford Shale. In 1Q2019, net losses totaled $289 million (minus 65 cents).
Revenue was nearly flat year/year at $1.02 billion, while operating net cash fell to $482 million from $528 million.
Capex in the first three months totaled $399 million, more than $75 million below the low end of guidance. For the majority owned U.S. onshore pipeline business, Noble Midstream Partners LP, about $196 million was spent in the first quarter, with $43 million budgeted to build out gathering systems in the DJ and Permian Delaware.
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