Matt Zborowski
Assistant Editor
Nothing is more effective than a severe, prolonged downturn at stripping an industry of its excesses, especially in the US onshore upstream business. The combination of crude oil prices hovering around $100/bbl and the rich supply of oil and natural gas facilitated by the shale boom resulted in an undisciplined pursuit of growth by exploration and production firms from the mid-2000s to 2014.
As oil and gas prices fell to a fraction of their 2014 levels during 2015-16, cash flow shrank and options for raising capital "narrowed significantly," Jim Rice, managing partner of US corporate law firm Sidley Austin LLP's Houston office, told OGJ while summing up his observations on a topic he follows closely. His industry experience covers mergers, acquisitions, and divestitures; private equity investments; bank financings; structured financings; and debt restructurings.
Rice explained that opportunities to sell equity vanished save for Permian basin pure-play operators whose equity values "held up nicely." Large-cap firms were "loath to cut dividends," and companies whose stock prices were in large part a function of dividend yield only did so as a last resort. And, "there wasn't much of an appetite, even if there had been the credit available, to borrow more money." That left many firms with the asset sale route, which became "a preferred means of raising capital and bolstering liquidity to finance drilling in the basin and areas where companies thought they could get the best economic return," he said. But for many, the problem of too much debt and too few options to deal with their balance sheet problems resulted in Chapter 11 filings.
From January 2015 to Feb. 20, 2017, 119 North American oil and gas producers filed for bankruptcy, according to Haynes & Boone LLP's Oil Patch Bankruptcy monitor. One of those firms was Swift Energy Co., a Houston independent currently on the rebound with a sharpened focus on the Eagle Ford shale of South Texas, which itself has experienced a drilling and production resurgence in recent months. Its transformation is indicative of an industry-wide trend toward simplicity, conservatism, and a renewed emphasis on financial health.
Bankruptcy, restructuring blueprint
Taking a large role in overseeing a reinvented Swift Energy is Marc Rowland, who was appointed director and chairman of the firm on Sept. 26, 2016, just 5 months after it emerged from bankruptcy. Rowland concurrently serves as founder and senior managing director of Dallas-based upstream investment firm IOG Capital LP. His 40 years of industry experience includes his stint as executive vice-president and chief financial officer of Chesapeake Energy Corp., where he led the firm for 18 years from its initial public offering in 1993 to a more than $40-billion market cap oil and gas producer.
While speaking with OGJ in March, Rowland explained that Swift Energy's bankruptcy was caused by "the usual suspects" of lower commodity prices and "large investments with too much leverage," which he said is "kind of the common theme with all of these bankruptcies in the energy space." When gauging a firm's financial health, he first inspects its balance sheet for leverage and its ability to grow or at least maintain production or reserves with existing cash flow.
Rowland also noted, however, that beyond those two primary culprits for financial distress, bankruptcy is caused by a set of variables unique to each company. "Some people had way too much debt, assets that didn't perform that may have been noncash flowing, too much acreage investment, [or] pipeline obligations that led to uneconomic development," he cited as examples. In the case of Swift, it had foreign investments "that didn't work out," including as far away as New Zealand, in addition to those within the US. The firm did its best to cope by slashing its capital budget by 60%, renegotiating pipeline contracts, cutting its workforce, and renegotiating office leases. But it couldn't prevent the inevitable.
Swift Energy filed Chapter 11 on Dec. 31, 2015, with $1.35 billion in debt and $1 billion in assets. During that year's third quarter, the firm reported a net loss of $354.6 million-including a $321.5-million writedown of its oil and gas properties-compared with net income of $2.5 million in third-quarter 2014. Net cash used in operating activities for third-quarter 2015 was $1 million compared with $81.9 million in the same period a year earlier.
Rowland almost modestly describes the bankruptcy proceedings as "expeditious." The firm emerged fewer than 4 months after it filed having closed on its new $320-million senior secured credit facility and its $48.75-million sale to Texegy LLC of 75% of the firm's holdings in South Bearhead Creek and Burr Ferry fields of central Louisiana. The firm later sold the remaining 25% interest in the fields to an undisclosed buyer for $8 million, exiting Louisiana completely. Rowland said Swift Energy didn't believe those proved developed producing assets had growth potential and the offers surpassed the assets' values to the firm going forward.
Swift Energy's prepackaged plan "kept the senior secured revolving bank line creditors whole," he explained. Noteholders behind the first lien creditors became "the vast majority of the shareholdings of the common units in exchange for the debt being canceled." Strategic Value Partners LLC and DW Partners LP, both of New York City, hold more than 50% of Swift and "basically directed the company through the bankruptcy process," he said.
Following the firm's emergence, then-Chief Executive Officer Terry Swift declared it was "a new era for Swift." Now, under the leadership of Sean Woolverton, who helped oversee the reorganization process at Samson Resources Corp., the firm is "all in" on South Texas. Rowland was previously familiar with Woolverton, who worked at Chesapeake from 2007 to 2013 and was well-acquainted with the Eagle Ford. Samson itself emerged from bankruptcy in March.
Swift Energy's net operational capital budget for 2017 is expected at $85-95 million. The firm plans to run one rig in the Eagle Ford to complete 12 wells, completing nine in its Fasken field in Webb County, drilling and completing two on its AWP field acreage in McMullen County, and drilling and completing its first well in Oro Grande in LaSalle County. All drilling activities will target the Lower Eagle Ford.
The budget largely targets acreage on which the firm has already drilled. The firm also maintains an active hedge program "to provide for predictable cash flows while still allowing for flexibility in capturing increases in prices." As of Jan. 20, the firm had hedges in place for more than 70% of expected gas and oil production at average weighted prices of $3.10/MMbtu and $48.10/bbl, respectively.
Rowland noted a recent private equity offering to existing shareholders of $40 million "was used to reduce [Swift Energy's reserve-based lending facility] and get it into a conforming status, so we have quite a bit of capital unutilized on the RBL. "We have operating cash flow this year" that will furnish a budget well above that of 2015 and 2016. "We hope to become relisted on the Stock Exchange and we hope to seek out opportunities that would be funded by a combination of cash flow and additional equity or debt issuance," he said. "No different from any other company that's trying to create value."
Changed lending environment
Rowland observes that bank financing in the US upstream industry "has changed dramatically" over the last couple of years. Banks are still lending, but "it's a much smaller pool" still active in the market. "You've got probably a universe that may have been 50 players that were active going into the bust sorted down to maybe 25 or so, and the 25 that remain are much more conservative either because that's the right thing to do or because the [Office of the Comptroller of the Currency (OCC)] has forced them to be more conservative."
Rice mentioned, however, that the "usual suspects are still quite active," namely the largest banks such as JPMorgan Chase & Co., Wells Fargo & Co., and Citigroup Inc., while a few of the regional banks "still have an appetite to lend even though it's been a tough couple of years for them." He noted, "Bank funding is available for the right kind of asset. It's really got to be a fully developed asset. They're just not in a position to lend for a nonproducing asset."
Gone are the days, Rowland said, of bank financing in unitranche situations, for example, where conventional proved developed producing (PDP) financing was combined with stretch financing, which was offered by banks such as Wells Fargo. That option had an element of debt and element of equity. It was largely focused on companies with undeveloped reserves, mostly proved, that could be developed with the excess capital and then rolled into a conventional borrowing base. "I can't remember the last time I saw a unitranche deal," Rowland said.
In the case of Swift Energy, "We've got either 11 or 13 banks in our bank group. Two of them are nonconventional lenders that came through the reorganization process. Several of the banks have gotten out of the business since they originally entered and don't want to continue on." Bank groups "are being reformed to attract the lenders that are still there, and there still is a handful of lenders that are coming in the business that weren't here a couple years ago as a result of just the normal cycling of opportunities."
Rowland noted, "East West Bank would be one of those. Two years ago I don't think they had any oil and gas lending experience or exposure and now they're pretty active in the business. An example going the other way would be Union Bank of California who I know has had a presence since the early '80s…and they're completely out of the business except for at the very top international investment grade companies. They've closed their office here in Dallas and have sold off most of their portfolio of noninvestment grade loans."
Christina Kitchens, East West's managing director, established the bank's national energy finance department. Her division serves upstream, midstream, and downstream middle-market firms with annual revenues of $2.5-750 million, including private or public, sponsored or non-sponsored firms; domestic, onshore producers; and diversified royalty portfolio companies.
"East West Bank launched its energy platform in January 2016 after working towards the specialty finance addition for a number of years," Kitchens explained to OGJ. "In the downturn, the bank saw the opportunity to be a meaningful entry in both the scale of its balance sheet vs. those banks exiting-or slowing down-and its ability to attract talented energy bankers. The bank prepared for what it was sure would be a recovery due to the vital nature of the industry."
East West's leadership continued to hire and invest in the platform despite the continued drop in commodity prices and a slowing of acquisition and divestiture (A&D) activity. "The bank began actively lending when A&D escalated and was readied for rapid growth into yearend," she said. "So far in 2017, this momentum has continued and the bank is pleased with the strategy. Also, growth in the energy platform has been concentrated on well-equitized acquisitions or project expansions led by private equity investments into well-defined play's core areas and with excellent management teams. The bank primarily does reserve-based lending for upstream firms and finances midstream projects."
Kitchens also noted that "a good many" of East West's peers are more conservative these days, and she's observed "many banks being cautious or pacing themselves in reentering the market." She said, "In some part, this conservativism is not only a product of the downturn but also due to regulatory guidance in underwriting led by both the [OCC] and the Federal Reserve Bank, two material US bank regulators."
She added, "Further, a number of the community banks have exited and will likely not return to the space in the near term." Many of those that have exited did so "questioning their fit to the business," including, "scale match, especially to shale deals; ability to be competitive; specialty lending coverage capacity; and bank capital wherewithal to weather industry's cyclicality."
Kitchens describes the regulatory impact as "profound," having "narrowed debt available to firms in RBL structures amongst additional standardization in banks' cash-flow testing and other impacts." She said, "The primary effect is that leverage profiles of E&P firms are narrowed when accessing regulated debt or else they have to fund through unregulated and more costly sources."
As for other trends, Kitchens noted, "Certain conventions that are popular in downturns remain in reserve-based lending, inclusive of commodity price hedge contracts on material volumes and in longer durations. Further, anticash hoarding clauses are still commonly included along with deposit account control agreements. Advances and risk factors remain conservative on proved-undeveloped categories and sometimes on proved developed nonproducing categories where there is not a definitive drilling or recompletion program under way or sufficient liquidity to support."
She said, "Moreover, bank debt underwriting is focused on liquidity and exploration companies largely living within their cash flow. [Capital expenditure] funding is expected to be supported with a narrower debt amount than before the downturn, to be instead largely supported from reinvestment of cash flow or equity investment. This means that the pace of capex growth, and therefore the industry recovery, may be limited to only as much as a firm's cash flow-equity interest supports it. Project economics must support attracting equity investments in this new era or at a minimum produce favorable enough return to balance the current equity return expectations and a higher cost of noncommercial debt."
Kitchens believes, however, that a rebound among the banks is taking place. "We are active and we are seeing an uptick with other banks as well. We see A&D continuing to escalate with smaller deals lifting the volume, all requiring more debt financing although more conservatively done than before the downturn," she said, adding, "Further, there has been little refinancing so far in this recovery but we believe that refinancing will also begin to expand. Many debt facilities are nearing their maturities that launched prior to the downturn and the borrower's financial situations have improved to support refinancing whether through a formal process or not. Most could refinance with minimal other resource needs-more equity, asset sales, added hedges, etc.-in today's environment. As public markets improve there are additional resources in mending a firm's balance sheet alongside refinancing and asset sales."
Private equity's role
The one source of funding that has been plentiful over the past year has been private equity, which has swept in to provide cash by way of asset acquisitions as well as in the form of partnerships with operators. Rice believes "private equity is absolutely critical to everything we've seen over the last 18-24 months and probably will continue to be so" in terms of companies' ability to raise capital in asset sales and companies streamlining their operations. During a typical divestiture process where Sidley Austin is representing a seller, if his client gets "100 confidentially agreements or nondisclosure agreements signed up, then 80-85 will be from private equity or private equity portfolio companies," Rice said.
SM Energy Co. has made a few deals with private equity-both as buyer and seller-in its quest to narrow its focus on the Permian. The firm in 2016 spent about $2.5 billion in separate acquisitions from Riverstone Holdings LLC and EnCap Investments LP to boost its position in the Midland basin. Those moves were, in part, funded by asset divestitures, including its sale of 55,000 net acres in the Williston basin to Oasis Petroleum Inc. for $785 million. SM Energy then began this year by selling its nonoperated Eagle Ford assets to Venado Oil & Gas LLC, an Austin-based affiliate of KKR & Co. LP. SM plans to use the proceeds of the Eagle Ford sale for its $875 million capital program in 2017, general debt reduction, and general corporate purposes.
SM Energy now has 87,600 net acres in the Midland basin, by far its largest position. The vast majority of its capital spending for the year will go toward the Permian, where it's slated to drill 100 wells and complete 80. Last year, just 32% of the firm's $687 million in capital spending was allocated to the Permian, with 37% going toward the Eagle Ford and 31% to the Bakken-Three Forks and Powder River basin.
"Last year, many strategists seemed to be saying 'let's be a core-basin operation,' taking the approach that they should put more resources and capital in fewer basins," Rice said during a Sidley Austin roundtable discussion in Houston earlier this year. "The trend is toward specializing your operations and presenting yourself as, say, a Permian basin story plus one or two other basins." He said that some firms want to focus the bulk of their intellectual and financial capital on a single basin-that is to say, leverage the expertise they've gained over years of working in an area-"and present that story to Wall Street."
Given its reserves quality and prospectivity for drilling longer laterals, "everybody seems to say the Permian works quite well from an economic perspective at $50/bbl [West Texas Intermediate], maybe even a bit lower than that, when other basins don't work so well." That's why "the pure-play Permian guys have had no trouble raising as much capital as they want and their equity values have just gone up" as of late. Rowland said, "Right now the flavor of the month is to invest in these multistratigraphic traps in the Permian and have 30-36 wells/section, and the concept of net acreage equivalent is the justification for paying $40-50,000/acre."
Rice noted that even at oil prices around $50/bbl, companies need additional capital resources. There's "still some reticence to look at the equity market," and borrowing money at the moment "is still a sore spot" given all of the recent bankruptcies. Meanwhile, "there's still a lot of private equity capital out there waiting and anxious to be deployed," representing "a ready and able supply side" for capital.
Operator-investor partnerships
Examples of newly established operator-investor partnerships include last summer's formation of a Fort Worth-based, Delaware basin-focused Jetta Permian LP by Blackstone Energy Partners LP and an affiliate of Jetta Operating Co. Inc. With $1 billion committed in capital, Jetta's strategy includes pursuing asset and leasehold acquisition opportunities, farm-in deals, and partnerships or joint ventures with existing operators and landowners.
Blackstone at the time also teamed with Jay Still, a former senior executive for Pioneer Natural Resources Co. and Laredo Petroleum Inc., to create Dallas-based, Midland basin-focused Guidon Energy. Together, they acquired 16,000 net acres in the core of Martin County, Tex. Blackstone and affiliated funds committed $500 million of capital to Guidon, "with the potential to commit significantly more" in future acquisitions. The firm plans to "develop its leasehold through manufacturing styled horizontal well development."
Rowland noted, "A lot of people think private equity is the mainstay of capital in this business, and I think for larger fundings, private equity at $250 million and above is still the most frequently used." If "you get a good project with a good equity partner and a well-known operator, the money is not only available but it's incredibly cheap relative to what I think the risks are."
However, Rowland, whose IOG Capital partners with companies on projects smaller than most of those involving private equity, mentioned that some longstanding independents struggle with the added outside influence of a private equity firm. "The private equity boards that I have been on in the past, sometimes at the request of the private equity sponsor, show that basically all the decisions have to be made at the private equity level." He noted that the partnership "takes an element of control out" for the operator, with management being "told what to do" from essentially an outside source, "and that isn't terribly attractive."
Rowland founded IOG in 2014 and has since funded eight investments and more than 260 wells in the Midland basin, STACK, Eagle Ford and Austin Chalk, Arkoma Woodford, Bakken, and Marcellus. Projects tend to range $50-100 million. Mike Arnold, IOG vice-president and chief compliance officer, explained that his firm partners with experienced operators that specialize in a particular basin.
"Generally these operators have a good amount of drilling inventory and require additional capital to develop their assets," Arnold said. "These operators are not in distress and have the ability and willingness to invest capital alongside IOG. Being that we have a substantial network in the industry, we generally have awareness of the reputation of the operator throughout respective networks." He added that IOG's partners have avoided "using a large amount of leverage to retain control of their business," meaning they've avoided mezzanine debt and corporate investment via private equity.
An example of these reversionary interest deals includes IOG's development agreement with Seneca Resources Corp., which was made in late 2015 and revised in summer 2016. Under the revised agreement, Seneca and IOG agreed to jointly participate in a program developing up to 75 Marcellus wells on 10,500 acres in the Clermont-Rich Valley area of Pennsylvania. IOG is expected to fund $325 million of the program while holding 80% working interest in the wells, with Seneca holding the remaining 20%. When IOG reports a 15% internal rate of return, a predetermined reversion takes effect and Seneca's working interest increases to 85% and IOG's interest drops to 15%, allowing Seneca to retain long-term economics.
Rowland describes IOG as "sort of the antiprivate equity model." The firm doesn't make decisions for the operator-it's "truly an oil and gas partner" and "people who've been in the business a while like those kinds of relationships," he said.
"We can function as a money partner but [also] as an oil and gas guy that will exit when it's right for them to exit." Perhaps most importantly, Rowland reiterates that IOG isn't debt. "If it doesn't work out, the risk is on us. There's no obligation at the end of the day, so it doesn't cloud [the operator's] balance sheet otherwise, and a lot of people are still risk averse as they probably should be in this business, particularly with regard to drilling."
Operator-investor in one
Serving as something of a private equity fund and operator in one, Houston-based EnerVest Ltd., founded in 1992, specializes in buying onshore properties with proved reserves, building up those assets, and then selling them. "There's only four of us that do that, and we're by far largest," said EnerVest Chief Executive Officer John B. Walker, who himself has experience on both the financial and operational sides of the industry. EnerVest as well as the separate, publicly traded EV Energy Partners LP, founded in 2006 and where Walker also serves as executive chairman, say they're "extremely particular" in their acquisitions, and would "rather lose a bid than buy foolishly," according to their web sites.
The combined strategy includes finding assets that are long-lived producing oil and gas properties with low decline rates, predictable production profiles, and low-risk development opportunities; leveraging their own operating and technical knowledge to control operational costs and increase asset value and cash flow stability; maintaining conservative levels of indebtedness to reduce risk and facilitate acquisition opportunities; and reducing cash flow volatility and exposure to commodity price and interest rate risk through derivatives.
Early in his career, Walker spent 11 years as an energy analyst on Wall Street, where he was named "All American" energy analyst 6 years in a row by Institutional Investor. "I thought that I knew everything you could possibly know about oil and gas until I started my own company." He made lots of mistakes at the beginning, but realized "that's the way we learn." EnerVest was the first general partner for GE Capital, and the two entities collaborated on eight funds before EnerVest began raising multi-institutional funds, which grew from around $100 million in equity to start to $2.4 billion. The firm currently operates 33,000 wells in 15 states and produces just under 1 bcfd of gas equivalent.
EnerVest started building concentrations in specific regions in 2003. "The whole purpose of concentration is that you can be efficient-you can be the most cost-effective operator in the area." Ohio was the first region to garner the firm's attention. "Over an 8-year period, we bought out four of the top five producers, and we accumulated 9,000 Clinton wells because we thought we were getting what's called the Knox formation for free…but we didn't know we were getting the Utica for free also." At the time, "we didn't think the Utica would produce."
Its second concentration was established in the Austin Chalk of South Texas, where it accumulated more than 800,000 acres and 1,700 wellbores, buying from large producers such as Anadarko Petroleum Corp., Chesapeake Energy Corp., ExxonMobil Corp., and Marathon Oil Corp. EnerVest's other concentrations have been built in the Barnett, the Midcontinent, and in Virginia, where the firm in 2015 acquired Nora field from units of Range Resources Corp. for $876 million.
Its Nora position comprises 365,000 net acres, of which 220,000 acres include all mineral rights, and "we're sending the gas through a pipeline into southern Virginia and North Carolina where we're getting a premium to Henry Hub, which is kind of unique in the US right now to get a premium on gas." That concentration is "really cost efficient," Walker said. In Karnes County, Tex., encompassed by the Austin Chalk and the Eagle Ford, EnerVest previously made three acquisitions all next to each other and "we're just having tremendous success there." Since November, he said the firm has completed around 22 wells there and increased its output to almost 40,000 b/d from 8,000 b/d.
EnerVest, however, struggled through the downturn like everyone else. When a giant like ExxonMobil loses its AAA credit rating that it held since 1949, "you can imagine what happened to everybody lesser than Exxon," Walker said. "We have a couple of our institutional funds that have their loans classified, and we're working with the banks to get them into total compliance," he explained. "And I believe that we will have those reclassified by sometime this summer."
Walker believes companies have to take the extra measures to be cost efficient. For example, if a midstream company contends there's no way to reduce costs on its gathering system, and a producer is a major customer on that system, the producer can just shut all of its wells and the gathering system "is worth nothing," he said. "We've had to do some things that I don't particularly like to do, but all of us are in the same boat and all of us have to work together to make sure we've got production at least breaking even."
EnerVest was fortunate enough to sell about $1 billion in assets as the downturn struck, but it was merely good timing for the company. "I would like to tell you that, being an old analyst, I knew that the price of oil would go from $107[/bbl] to $26[/bbl]…but I don't remember anyone saying it would drift lower than the $70s," he said. At the time, "We did have hedges in place, but those hedges weren't out to '17. We got hurt and we continue to hedge. But the fortunate thing was in 2012 we bought some Midland assets from Chesapeake for $321 million, and we sold those in spring 2014 for $950 million. And then we sold the non-op position we had in the Bakken that we bought for a little over $100 million-we sold that for $200 million. So we sold about $1.2 billion of assets…But it was part of our model-not that we were smart."
While Nora field is "a great gas field with good margins," the firm has spent most of its money, roughly $1.5 billion, in Karnes County within the last year. Karnes is the most prolific oil-producing counties in Texas-even larger than any county in the Permian-and has contributed to raising the firm's share of oil production to 15% with 65% gas and 20% liquids. "We're trying to get oilier and we'd love to be in the Permian basin more than we are," he said, but the premiums being paid at the moment there will make it difficult for recent buyers "to get a good rate of return." For that reason, EnerVest won't join the Permian rush.
"We've always been to a certain extent contrarians," Walker said. "We were buying in Ohio when no one even thought about the Appalachian basin, and we were able to buy in Karnes County when people focused on the Permian and wanted to move out [of the Eagle Ford] to a certain extent…We're drilling wells in Karnes Country cheaper than in the Permian basin, and we're getting higher EURs and higher IPs. I mean, it's just a better area…Now, we don't have seven zones that we can drill, but we do have three-because it's the Lower Eagle Ford, the Upper Eagle Ford, and the Austin Chalk," the latter of which contains "the best wells that we have there."
When it comes to how the average midsize or larger firm is funding its operations these days, "if you're a private equity-based firm and you're in the SCOOP, STACK, or Permian, you're in pretty good shape. If you're not, you're struggling." Public companies in those three areas are "getting incredible [price-earnings] multiples, but we'll see if they justify it."
