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[Editor's note: A version of this story appears in the January 2020 edition of Oil and Gas Investor. Subscribe to the magazine here.]
It comes as little surprise that capital markets for energy barely have a pulse. Discipline is the order of the day, and capital constraints are enforced on E&Ps by market pressure. A market mandate asks E&Ps to pursue multiple goals at once: keeping capex within cash flow, while pushing production higher at a sustainable rate, offering a rising dividend, buying back stock, rolling over debt, etc.
No easy task for what was once recognized to be a “capital-heavy” industry. And, for public E&Ps, life is made no simpler by an apparent assumption that the cadence of capital outlays and increases in output will tend to neatly match one another. Yes, capital efficiency may tend to move forward based on those factors, but capital projects do not always progress at a uniform pace each quarter.
So, if the spigot for sourcing capital is down to a dribble, how are E&Ps coping with capital constraints?
It’s not as if the energy industry has lacked resourcefulness in adjusting to varying levels of capital or finding new capital sources. If capital is tight, dropping rigs and crews is obviously an option. Less drastic are moves to sell noncore acreage and nonoperated assets. Then there are less frequently used moves, such as the sale of overriding royalty interests (ORRI) or volumetric production payments.
Of late, E&Ps have also focused on substantial investments in water infrastructure that can be partly or wholly monetized to boost sources of capital. Likewise, interests in gathering and processing facilities may also be put up for sale. Such sales, however, are likely to come with a measurable move higher in lease operating expenses. A third option is spinning off at least part of an E&P’s mineral interests.
“The key is to limit our capital in infrastructure projects so we can generate incremental free cash.”
—Rich Dealy, Pioneer Natural Resources Co.
Levers to pull
Pioneer Natural Resources Co. has several levers it can pull—and the luxury of not having to use any of them.
Pioneer in some ways offers a textbook example of moves to enhance its self-funding. These include asset sales, a possible further sale of gathering and processing assets, and an evaluation of strategic alternatives for its water infrastructure. However, with a pristine balance sheet—debt is only 0.7x trailing EBITDA—the timing to push forward along any of these avenues is largely at its discretion.
Last summer, Pioneer made a sale in the Permian of some 3,300 net acres in Martin County, Texas. The position traded hands at about $20,000 per acre in two transactions with the same buyer. Subsequently, Pioneer also considered a possible sale of acreage farther south. However, due to deteriorating acquisitions and divestitures market conditions, an outright sale was dropped in favor of a Drillco.
“We would have considered a monetization, but we didn’t think we would get the right value for the property,” Rich Dealy, Pioneer’s CFO, told Oil and Gas Investor. “The A&D market has virtually dried up. We thought the Drillco was probably a better outcome for us rather than trying to sell the acreage outright at this point in time. A Drillco is in essence a wellbore deal; it doesn’t involve any acreage.”
While Pioneer could easily have drilled the acreage itself, given its “great balance sheet,” bringing in a partner in a Drillco “is a way for us to accelerate the value of some of our long-dated inventory,” said Dealy. “Given the tremendous inventory that we have, these projects can be farther out or at the tail end of that inventory. Some of it has drilling obligations associated with it.”
Drillco ‘in process stage’
Drillcos are typically structured so the economics heavily favor the joint-venture (JV) partner until the latter has earned a hurdle rate, “typically in a 12% to 15% range,” at which point much of the economics revert to Pioneer, said Dealy. A key variable is how long it takes the partner to reach the hurdle. “That could be forecast to be, say, three to five years. But if commodity prices dip, it could be seven or eight years.”
Any initiative on a possible Drillco is “in the process stage,” stated Pioneer in its third-quarter report.
In its gathering and processing JV with Targa Resources Corp., Pioneer is “in the process of trying to sell our 27% interest,” said Dealy. “It’s something we would like to monetize. The key is to limit our capital in infrastructure projects so we can generate incremental free cash flow [FCF]. We’ll improve our FCF yield by not investing in plants that have a lower rate of return than we achieve with our drilling investments.”
Pioneer estimated its 27% interest in the Targa asset was throwing off some $50- to $60 million of EBITDA, although this was earlier in 2019 when NGL prices were higher, according to Dealy. Midstream deals have historically traded at an 8 to 10 multiple of EBITDA, but the multiple may be somewhat lower today, he said. “NGL prices have declined over the course of the year.”
On water infrastructure, Pioneer’s situation differs from many other projects in that the buildout is designed to source water used for hydraulic fracking of wells rather than for the disposal of produced water. Pioneer currently has access to 120,000 barrels per day (bbl/d) of effluent water from the city of Odessa, and it is building a water treatment plant with the city of Midland from which it will take 240,000 bbl/d.
“We’re evaluating it,” said Dealy. “The board will likely make a late-2020 decision. One reason is we need to complete the Midland water treatment facility. We want to evaluate what the right structure is. We’re not going to just trade dollars. Getting money upfront, and then having higher well costs, doesn’t make a lot of sense if you’re just paying it back over time.”
Options for Pioneer range from “keeping it 100%” to “monetizing it 100%,” as well as a multitude of opportunities in-between, according to Dealy. These may include selling volumes to third parties when the pipeline system has spare capacity, which is expected as the Midland facility comes online and as Pioneer increases the company’s recycling of its produced water.
Capex for water and gathering and processing facilities was budgeted at $250 million for 2019. With the water pipeline buildout over its peak expenditure period, and a likely resolution of a Targa asset sale, Pioneer expects capex for the two sectors in 2020 to be “substantially less,” said Dealy.
Casting a wide net
Parsley Energy Inc. has got its sights on monetizing parts of its water infrastructure and its minerals interests, but has indicated it is prioritizing water, with a transaction that could be finalized by year-end 2019. A monetization of minerals is “something on the docket to explore in 2020, but the near-term focus is on water,” according to Ryan Dalton, CFO of Austin, Texas-based Parsley.
In the interim, of course, the major event happening at Parsley is its combination with Jagged Peak Energy Inc. With Parsley already FCF positive, the merger plans call for Jagged Peak to drop one of its five rigs in 2020 so internally generated cash flow covers its capex. In broad terms, this “makes Jagged Peak FCF positive and makes the acquisition accretive to Parsley on FCF,” said Dalton.
The timing of any water monetization may prove fortuitous for financing the Jagged Peak acquisition.
Incremental debt assumed with the Jagged Peak purchase is “manageable” and could be paid down over time, said Dalton. “But the timing of events could line up perfectly such that if the water transaction closes by the end of 2019 and the Jagged Peak transaction closes in the first quarter of 2020, then we could take part of the proceeds from the water transaction and use it to pay down the revolver balance.”
As for a monetizing part of its water assets, Parsley “cast a wide net” in examining potential strategies.
In the end, according to Dalton, “it was important to management and the board that we maintain operational control. It’s important to us that, if a saltwater disposal well runs into a mechanical issue during the night, one of our guys is going to get the alarm and we know the problem is going to be addressed. For operational continuity, it’s important we keep control.”
This led to Parsley working on a minority sale of less than 50% of its water assets to an unnamed party. Parsley termed the process as involving “exclusive negotiations” with a single party, which it describes as a “true financial party” as opposed to a well-known water infrastructure company. “This is more an entity that is going to invest some cash and let us run the business,” commented Dalton.
An option down the road
The prospect of a divestment of minerals in some form “is still an option for us down the road,” said the Parsley CFO. “Our mineral ownership is concentrated more in the Delaware Basin, primarily in the old Trees Ranch area. We have minerals on a good portion of our Delaware acreage; approximately three quarters or more of our minerals are on the Delaware side.”
Another tool used by Parsley to pursue strategic options in a capital-constrained setting is commodity hedging. In the past, Parsley has had “a high utilization of hedges,” noted Dalton, and the hedging of a growing portion of production has gained importance as the company has emphasized a policy of being FCF positive and delivering a dividend.
“I view hedging as even more critical now, because we can’t go backward,” observed Dalton. “We’ve committed to be FCF positive to ourselves and to the market. We want to be one of the companies that grows its dividend over time. We can speculate as to what may happen in 2020 and beyond. But for us to sleep at night, we must know we can pay our dividend, and so hedging is going to be a very critical component.”
Parsley has hedged 65% to 70% of its oil production for 2020, pro forma for the Jagged Peak acquisition, based on guidance given at the time of its third-quarter earnings release.
As for availability of credit under reserve-based lending (RBL), Parsley has now gone to an annual redetermination, so it did not go through a fall redetermination. However, it has heard that some of the major commercial banks are lowering their price decks, which coupled with an increase in discount rates has led to meaningful cuts in some E&P borrowing base amounts.
Temporarily slowing down
Steve Struna, CEO of Bayswater Exploration & Production LLC, has worked hard to gain an advantage from financial strategies amidst largely moribund capital markets. Strategies it has used or explored include: marketing nonop interests; selectively selling down working interests in company-operated projects; and selling future crude production via volumetric production payments, among others.
However, current tightness in credit and capital markets also offers attractive opportunities, in his view, and privately held Bayswater has raised a series of energy funds chiefly from college endowments, pension funds, foundations and other institutions.
Struna sees the pace of industry activity moderating, but not likely decelerating into a steep decline.
“We’re seeing a decrease in activity. I would characterize it as people are temporarily slowing down. How long ‘temporary’ ends up being is hard to say. The industry is in a slowdown for a while in which players likely defer some activity, let cash flows come in, and consider other sources of debt and equity. But slowing down is key in the first instance, so that you have options in the future.”
Bayswater’s track record and its conservative capital structure gives it perhaps greater flexibility than some industry players have in setting strategy. Its first two institutional funds have been realized, with returns to investors “near what we projected,” said Struna. Its third fund, which closed in early 2017, diversified from mainly the Denver-Julesburg Basin to include investments in the Midland and Delaware sections of the Permian Basin.
An initial investment in the Midland Basin was in Howard County, Texas, where SM Energy Co., Diamondback Energy Inc. and Callon Petroleum Co., among others, have enjoyed considerable success. After acquiring leases on what then was thought to be Tier 2 acreage, Bayswater was “very encouraged” by its initial well results and went on to drill 10 wells, and it is now considering a 30-well program for 2020. Bayswater currently holds some 20,000 net acres in the play.
Bayswater also continued investing in minerals in the core of the Delaware portion of the Permian Basin.
For funds, a longer hold period due to the thin A&D market has increased financing needs, said Struna.
“Our fundamental model has been ‘acquire, develop and exit.’ But given the change in the market, our hold time is now much longer, requiring more capital and a greater percentage of development of the assets,” he observed. “Maybe ‘full development’ is now our new model. And with that in mind, expanding the use of our RBL through the semiannual redetermination process has been one option for us.”
The price deck used for redetermining its RBL remains below the strip, commented Struna, but commodity price assumptions for Bayswater “have not changed as dramatically as we’ve heard for others.” In large part, he explained, this may reflect that “we’ve got some built-in constraints on borrowing inside our funds that leaves us relatively underlevered compared to our peers.”
Helping capital go further
Meanwhile, Bayswater has turned to several financial instruments in hopes of helping capital go further.
These measures have included selling down working interests in company-operated projects in a farm-out or Drillco-like transaction, as well as marketing a package of nonoperated interests that have drawn interest, said Struna. “If our hold is longer, we have to stretch our capital. A farm-out or Drillco-like transaction is one where a joint development partner puts up a portion of the initial capital and, in return, we get a reversionary interest down the road.” Bayswater recently entered into a joint development agreement with Houston-based Millennial Energy Partners covering the drilling and completion of six multiwell pads in the Denver-Julesburg Basin’s Wattenberg Field.
Even with alternative sources of capital, Struna sees a need for a reopening of traditional capital markets.
“The capital markets have to come back in our industry. The question is when,” observed Struna. “There are some solid opportunities. We all have attractive, high-return projects in front of us.”
“We’re very confident that first lien financing will be available. Whether people will take advantage of it, we don’t know for certain.”
—Tim Perry, Credit Suisse
Tim Perry, who serves as global co-head of oil and gas investment banking at Credit Suisse, pointed to a number of instruments that E&Ps may turn to for financing. These included a new format for asset-backed financing by Raisa Energy LLC (see article on p. 97), a sale of overriding royalty interests—a choice employed by Range Resources Corp.—and first lien financing as a possible further avenue.
On the topic of first liens, Perry recalled its use in the downturns four years ago and again in 2009 through 2010, and he expressed confidence that it would be available—and quite likely used—if current conditions in the industry “continued to deteriorate, which might happen. We’re very confident that first lien financing will be available. Whether people will take advantage of it, we don’t know for certain.”
First lien financing is “more expensive than bank financing, but not hugely so,” according to Perry. As compared to RBL funding from a bank at 4.5% to 5.5%, a first lien loan would be priced in a range of 6% to 8%, depending on individual circumstances, he said. “It’s not really a revolver,” he commented, “but you can raise capital that way on a secured basis.”
First lien financing is typically issued with a term of five to eight years.
Reducing revolver ‘dollar for dollar’
A first lien financing may be attractive to E&Ps that have a “highly utilized revolver,” which could then be paid down in part or in full “so they can significantly reduce a banking facility,” said Perry. “It may be a way of eliminating it or just making it a lot smaller. It will reduce the revolver dollar for dollar.”
As an example, a significant $500 million RBL credit could be replaced by a $300 million first lien and a $200 million revolver, or paid off entirely by a $500 million first lien. In the former case, the RBL and first lien financing would be considered pari passu, allowing each of them an equal claim on the prorated assets, according to Perry.
While borrowing bases are “still pretty large,” bearish commodity forecasts may spark greater use of first liens “if the borrowing bases start to shrink,” said Perry. “If the commodity strip is right, we’re in a backwardated curve for both oil and natural gas. The fact of the matter is that a lot of the hedges for E&Ps start rolling off in 2021 or 2022, and mostly in 2021.”
First tier financing has historically been “extremely well-secured,” with minimal losses even at times of challenging commodity prices, according to Perry. For first tier financing, he said, “I think there’s a lot of capacity out there.”
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