Noble Energy Inc., with its Lower 48 oil and gas projects humming along and coming closer to completion with the first phase of its world-class Leviathan natural gas project offshore Israel, is planning to slow things down spending-wise, with combined 2019 and 2020 capital spending slashed by nearly $1 billion.
The Houston-based super independent delivered its quarterly and full-year results on Tuesday, with CEO Dave Stover leading a conference call.
Noble reported a strong fourth quarter for the Lower 48 and overseas, with the first phase of the massive Leviathan project now 75% complete and sales agreements for 1 Bcfe/d-plus.
“Noble Energy made significant strides in 2018 as the company continued to preserve returns over volume growth across our global portfolio,” Stover said. “This was evidenced in the second half of the year as we moderated our U.S. onshore activity to protect margins, enhance capital efficiency and increase net cash flow generation.”
The three main Lower 48 production areas — the Denver-Julesburg (DJ) and Permian basins, and the Eagle Ford Shale — “have now transitioned…to row development, which is driving both cost and well productivity efficiencies.”
Still, “we were reminded in 2018 of the volatility of oil prices and how the impact of global markets, sanctions and other events can affect our business,” he said. “With that context, Noble Energy remains focused on aligning the business to drive sustainability through commodity cycles.”
Primarily, Noble is planning around a long-term West Texas Intermediate (WTI) price averaging $50-55/bbl. At that price, it expects to deliver 5-10% long-term annual growth, supplemented by additional growth as major projects come online.
“With the addition of Leviathan by the end of this year, Noble Energy will have over 30% of our asset base with minimal to no decline for up to a decade,” Stover said. “Our overall corporate decline improves into the low-20% range in 2020…This ensures that the capital dollars we deploy drive more incremental value as compared to just maintaining the base…
“We anticipate that we can hold our entire production base flat going forward at a capital level of around $1.6 billion/year…This is the amount of capital required to essentially replace our U.S. onshore production on an annual basis with our international assets needing minimal capital to stay flat.”
Stover spent a few minutes discussing Noble’s plans for 2020, which would include initial Leviathan output.
“Although too early to outline definitive plans, we anticipate that close to a $2.1 billion capital program would generate a 15-20% total company volume growth,” he said. “Production for 2020 models a full year’s impact from Leviathan, consistent with our previous communication of around 800 MMcf/d gross.”
The 2020 production guidance is 21% below previous estimates of 525,000 boe/d, implying sharply lower reinvestment in the U.S. onshore.
Noble’s capital range includes $1.6 billion for maintenance and $400-600 million for growth, split evenly between near-term U.S. onshore projects and longer-cycle exploration and development projects.
“Our plan reduces combined 2019 and 2020 capital by nearly $1 billion from our previous outlook,” Stover said. “This plan delivers a more moderate growth profile of 5-10% annually, supplemented by specific major project additions such as Leviathan’s first phase.”
U.S. onshore capex this year is set to capture the bulk of spend at $1.6-1.7 billion, generating estimated pro forma growth of 10% equivalent production and 13% oil production at the midpoint of guidance, COO Brent Smolik said. Smolik, previously chairman/CEO of EP Energy Corp., joined Noble last fall.
DJ, Delaware Taking 90% Of U.S. Capex
“The DJ and Delaware will be important contributors to 2019, and those assets will consume about 90% of the onshore capital spend this year and grow a combined 15-20% versus full year 2018,” Smolik said. “We’ve designed the U.S. onshore business to live within cash flow by the end of this year, which requires that we remain very diligent about improving capital efficiencies.
“Following the decrease in industry activity in the fourth quarter and the drop in oil prices, our teams have been very active in reducing cost across the onshore U.S. Since December, the combination of more efficient well designs, faster execution and service cost reductions is resulting in lower capital cost per well.”
Noble already has identified savings of $500,000 to $1 million per well, versus the second half of 2018, Smolik said. In the DJ the company plans to continue to operate one to two rigs, two to three fracture crews and bring online 95-100 wells this year.
There were issues in the Delaware, Smolik said, as “the industry battled several challenges in 2018, including rapid activity and production growth, the strained transportation service infrastructure that led to oil differential weakness, margin pressures and higher drilling, completion and facility costs.”
In the first half of 2018 Noble also had challenges from appraising some of its Permian acreage, with well interference when completing existing wells in its southwestern acreage. In addition, like some of its peers, it had “the growing pains of early phase development and rapid facility buildout.”
By the second half of 2018, however, most of the challenges had been mitigated, he said. Activity migrated away from the southwestern holdings, and a portion of the acreage was divested earlier this year.
“Going forward, we plan to further block up our acreage position in the Delaware, just as we’ve done in the DJ,” Smolik said. “In 2019, we expect to average four drilling rigs and two completion crews in the Permian. We plan to focus over 95% of our 2019 program on row development drilling, and we anticipate bringing a total of 50-55 wells online with an average lateral length of over 8,700 feet.”
Through drilling completion and facility design changes, as well as lower service costs, “we’ve already identified $1-1.5 million of well cost reductions versus the second half of 2018” in the Delaware, Smolik said. The plan is to remain focused on the Wolfcamp A and Third Bone Spring, with most of the completions near five central gathering facilities.
Total liquids sales volumes in 4Q2018, comprising 60% of output, averaged 205,000 b/d. The U.S. onshore produced 72% of liquids sales, while Equatorial Guinea (EG) represented 17% and Israel comprised 11%. For 2018, volumes climbed by 11% year/year to 353,000 boe/d, with U.S. onshore oil output up 26%.
In the legacy DJ, production during 4Q2018 averaged 138,000 boe/d, a 9% sequential increase, driven by continued strong well performance from the Mustang area and 22 wells turned online in Wells Ranch.
Noble also received regulatory approval during the quarter for the first large-scale comprehensive drilling plan (CDP) in Colorado, naming it as sole operator across a 100 square-mile position in the Mustang development. The company has permits for more than 400 locations across the Mustang, most for six years.
“This CDP is one-of-a-kind in Colorado, providing a clear line of sight to our long-term execution in the DJ Basin,” Stover said. Last November 57% of Colorado voters rejected a ballot initiative that would have increased well site setbacks to 2,500 feet from 500 feet for residences and workplaces.
“Following the industry’s extensive engagement with stakeholders across Colorado, voters rejected a ballot initiative that would have set the state back for many years,” Stover said. “Moving forward, we will continue to support reasonable regulatory solutions that provide more certainty for safe and sustainable operations in the state.”
Meanwhile, sales volumes from the Delaware totaled 60,000 boe/d, up 4% sequentially and 57% year/year. However, Eagle Ford volumes were down 4% sequentially to 55,000 boe/d.
“In the Delaware Basin, in spite of a tough first half, we more than doubled production volumes last year while slowing completion activity in the second half of the year to protect returns and prepare for row development,” said the CEO. “This sets the company up to take advantage of the development mode benefits that we saw in the DJ and Eagle Ford, driving capital efficiency through productivity improvements and lower costs.”
Noble also added “necessary infrastructure and secured long-haul pipeline agreements to the Gulf Coast, providing transportation reliability and access to a higher priced market.”
Across the U.S. onshore portfolio, the company drilled 50 wells in the fourth quarter, while completing and turning online 40 wells.
“Adding to our future potential, last year we captured over 100,000 acres of low-cost material exploration inventory in the onshore U.S. and a 40% interest in operatorship of two million acres offshore in a new venture country,” Stover told analysts. “We expect to drill both onshore and offshore opportunities in 2020 as we begin to test nearly 1 billion boe of net risked exploration inventory.”
Net losses in 4Q2018 totaled $824 million (minus $1.72/share), versus year-ago profits of $494 million ($1.01). Revenue was nearly flat year/year at about $1.197 billion from $1.201 billion. During 4Q2018 Noble incurred one-time charges of $802 million from derivatives impacts, gains/losses on asset sales (including the Gulf of Mexico portfolio). It recorded an impairment of $1.3 billion associated with the Texas assets, primarily from the drop in WTI forward strip pricing at the end of 2018.
Removing the one-time charges, adjusted net income in 4Q2018 totaled $56 million (12 cents/share). Operating cash was $622 million.
For 2018, Noble lost $66 million net (minus 14 cents/share), versus a 2017 loss of $1.12 billion (minus $2.38). Revenue for the year increased to $4.986 billion from $4.256 billion.
Total proved reserves at the end of 2018 were 1.93 billion boe. Removing the impact of asset divestments, reserves were up 5% from the end of 2017. U.S. onshore reserve replacement was 214% at a cost of $11.86/boe. DJ reserves climbed 21%, while Delaware reserves were up 8% year/year. The company booked more than 300 Bcfe of gross reserve additions in Israel.
The results for Noble Midstream Partners LP, in which the producer holds a 55% stake, included an additional $37 million in capex with revenue of $29 million for the quarter. The midstream unit averaged record quarterly volumes of 284,000 boe/d.
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