Whiting Petroleum Corporation: a case study in the failure of shale oil economics
Frontispiece: That dog don’t hunt. Whiting Petroleum Corporation’s performance in the last decade is a poster child for how shale oil companies struggle to make returns for shareholders at intermediate oil prices, let alone bottom dollar prices as today. Instead, most have waged a destructive war on value, with no return to shareholders. How and why did this happen? Were management and the Board awake to the fundamental issues?
Whiting Petroleum Corporation filed for Chapter 11 on April 1st 2020 and represent the first major shale oil company bankruptcy of a number anticipated to result from the recent oil price crash. An examination of the company’s journey since 2007 reveals a poster child story of rising shale production and stock price during the shale “revolution” years of 2007 to 2014 followed by a crash in value with oil price and then steady decline as investors increasingly realized that billions of dollars of value had been destroyed in drilling wells only economic at higher prices. The technical reasons of this catastrophe relate to the failure to adjust business strategy to reflect deteriorating year-on-year well performance as sweet spots were drilled out and well spacing units became more and more densely packed. The search for underlying causes puts the spotlight squarely on the executive team motivated by an income share of the company’s production and on the Board that singularly failed to competently discharge its duties. The banks that now own Whiting should be wary of a repetition of this failed business model, and should avoid creating a zombie company by instead radically restructuring of the company, its board, strategy and business model.
Figure 1: The rise and fall of Whiting Petroleum Corporation. (Source: Data: EIA and Yahoo Finance; Graphic: Capriole Energy)
Poster child
Three weeks ago I posted an article about the five brutal facts that the US oil industry needed to confront before sorting out a real future for itself in a post-coronavirus world. The following day, Whiting Petroleum Corporation (Whiting or WLL), one of the shale companies (shalecos) that I had highlighted previously as even more distressed given the oil price crash in March, filed for Chapter 11 bankruptcy. In so doing the company brought to an end a typical example of a shale company story. A story of an early meteoric rise in production, reputation and share price during a period of rising oil prices, followed by a decline in value with declining price and the receding prospects for investors and banks getting their money back. Over the last decade, Whiting has made a net loss of over $3 billion, outspent operations cash by $5 billion and is now defaulting on $2 billion or more of debt. Some elements of the Chapter 11 petition alarmed a lot of people, not least the executives awarding themselves full bonuses for 2020 ahead of the request to re-structure. My post on the 5 brutal facts, annotated with a meme saying “That Dog Don’t Hunt”, attracted a lot of interest and comment, with the frequently asked question being why did investors, banks and indeed regulators tolerate this performance? I decided to examine their history to find out how Whiting changed from conventional field re-developer to shaleco star into a case for bankruptcy (Figure 1) and derive some reasoning about what caused this value destruction to occur and why it was allowed to happen.
Beginnings
Whiting went public in 2003, with James J. Volker as Chairman and CEO, armed with an acquire, exploit and explore strategy. By 2005, Whiting had built a diverse portfolio of acquired assets, with a core of CO2 enhanced oil recovery projects, with reserves growth potential. Although net income and free cash are highlighted in the annual reports up to 2007, the main focus is on reserves and production volume per share. By the end of 2006, Whiting had accrued reserves of 195.0 million barrels of oil (mbo) and 318.9 billion cubic feet gas (bcf) and had produced 9.8 mbo and 32.1 bcf in 2016. Whiting posted a net income of $156 million with a profit margin of 20%. Little or none of these earnings were returned to shareholders as cash and instead, Whiting’s end-2006 balance sheet showed retained earnings of $438 million, total assets $2,585.4 million, total debt of $995.4 million, and stockholders’ equity of $1,186.7 million, hence a gearing ratio of 45%.
One operated position was in the Williston Basin, and it appears that local knowledge plus some smart explorer connecting the dots between the Bakken shale and the Barnett shale “discovery” in north Texas, and a 1980s vintage horizontal well play in the upper Bakken, caused Whiting to launch into leasing and by 2007’s annual report, Volker was able to announce that they had amassed 118,348 gross acres (83,033 net acres) in the Sanish field in Mountrail County, ND, holding a total of 170 potential well locations based on drilling two wells per 1,280-acre spacing unit. The first three horizontal wells or laterals had been completed and the results were very encouraging. Whiting’s own shale boom had commenced.
Figure 2: Financial performance from 2007 to 2019. (Source: Data: Yahoo Finance; Graphic Capriole Energy)
Big spender
Figure 2 illustrates the bottom-line performance of Whiting from 2007 onwards. Supported for the most part (except late 2008 to early 2009) by high oil prices (> $60/bo, Figure 1), the ramp-up of Bakken drilling led to continued growth in both EBIDTA and net income. However, offset by the depreciation of capex in the company’s income statement obscures a deficit that steadily grew the drilling program, both in Mountrail County and elsewhere in the Williston Basin. Whiting serially outspent operations cash flow by spending more on capital investment (Figure 3).
Figure 3: Cash flow 2007-2019. (Source: Data: Yahoo Finance; Graphic: Capriole Energy)
The increasing rate of capital expenditure in 2010 to 2014 outpaced operations cash generation so much that net income margin was eroded by increasing cash costs but particularly DD&A from the depreciation of increasing amounts of capital deployed in the business and depletion of the hydrocarbon resource (Figures 2 and 3). Why did Whiting continue on this course for 5 years, and not even pull back until 2016, a good 2 years after the 2014 price crash?
Figure 4: Balance sheet fundamentals for Whiting, 2007-2019. (Source: Data: Yahoo Finane; Graphic: Capriole Energy)
The first reason must be Whiting’s strategic fixation on production and reserve volume as a metaphor for Net Asset Value (NAV) and that shareholders were similarly fixated on stock value. In the period 2009 to 2014, Whiting’s NAV increased year-on-year because rising long-term debt was outpaced by rising asset value, which was in part a function of robust and increasing oil prices as well as a reserve replacement greater than production. For investors, the assumption must have been that they were more likely ultimately to have been “traders” and intended to sell their stock at a profit at an optimum moment, than “owners” patiently waiting for the day that capital and asset value would be returned as a cash dividend, share buybacks or sale at a premium to another peer. And of course, every investment model that involves a commodity such as oil, there is also an assumption (and hence risk) that the oil price will stay the same or increase. From 2009 to 2014, it appears that both Whiting and their investors shared those mental models and Whiting (like other shalecos) kept drilling.
However, there was another, deeper problem with Whiting’s business that was partially but not wholly obscured by oil price robustness during the period from 2009 to 2014. Look again at Figure 3 and take note of how the ratio of cash generated from operations relative to capex decreases through the period from 74% in the period of rising oil price 2009 to 61% in 2014 (Figure 1). This is partially explained by a commensurate 12% rise in cash costs per barrel product, but that doesn’t account for the 21% decline in cash generation efficiency. To understand what else was happening, we need to look at well performance.
Figure 5: Year by year drilling out of Sanish area acreage and resulting type curve well performance in Mountrail County, ND. (Source: map and data from DrillingInfo; Graphic: Capriole Energy)
Bellwether asset
Whiting’s bellwether position in the Bakken is the Sanish field in Mountrail County in North Dakota (Figure 5). In 2008, despite an oil price crash related to the financial crisis of that year, Whiting steamed ahead with their Sanish development as well as other operated and working interest wells elsewhere in the basin. Encouraged by the results of the 2 wells drilled in 2007 and one completed in January 2008, I can imagine that in that world, with shale oil science and engineering still in its infancy, it would have been tough not to get carried away with onshore wells with initial production (IP) rates averaging more than 1,800 boe (6:1) per day with the most recent well, the Liffrig 11-27H, coming in at 2,530 boe per day, a record at the time for the county. CEO Volker indicated that the proved reserves associated with these wells are estimated to be “in the range of 500,000 boe to 700,000 boe.” As can be seen from Figure 5 (which represents associated gas at a 20:1 mscf:oil ratio), that has turned out to be a good, perhaps conservative forecast, with 25 operated wells in the area headed towards 700,000 boe (20:1) after more than 12 years of production. I don’t know whether the Whiting team looked at well breakeven economics at the time (there’s no record in the annual reports), although it would be surprising if they didn’t use this standard oil industry practice. Nevertheless, and admitting to the benefits of hindsight, it’s interesting to test the economics of the wells (Figure 6).
Figure 6: Simplied well economics for the 2008 type curve, Sanish Field, Mountrail County. Wellhead costs includes $5.5m Capex and $6000/month opex (Whiting’s average Lease Operating Expenses (LOE) per bo in 2008). Fully loaded cost adds $4.5m additional capital for upfront costs (e.g leasing) and surface facilities and is approximated from Whiting’s total Capex versus the number of wells completed) and $10,000 per month opex which adds $4000 per month for G&A, interest, exploration and other expenses. (Source: Data: DrillingInfo, WLL Annual Reports; Graphic: Capriole Energy).
These 2008 wells look really good, even when fully loaded with costs. Wellhead cost breakevens (tagged at 15% IRR) at less than $20/bo realized price, while full cost load takes the 15% IIR breakeven to a realized breakeven of about $32/bo. With respect to the rest of this story, the important observation about these wells is that except for 3 of them, they are initial Bakken development wells drilled one for each 1280 acre spacing unit. CEO Volker indicated in the 2008 annual report that the results of the first two infill wells supported going to two 10,000 foot laterals per unit, or a 640 spacing. Comparing the performance of one of the first infill wells completed in late 2008 with its initial development neighbor, completed 12 months earlier, already shows production deviation from the initial production period and this deviation enhances with time (Figure 7).
Figure 7: Performance comparison of parent development well Liffrig 11-27H with neighboring child infill well McNammarra 42-16H, completed 12 months later.
In 2009 Whiting pursued their Sanish development mainly through new development wells north and west of the 2008 completions, and therefore were not exposed to the parent-child performance relationships depicted in Figure 7. However, the wells drilled in 2009 were significantly poorer performers than the 2008 batch (Figure 5) and this should have been apparent to the Whiting team, for example by comparing Initial Production (IP) and first 6 months production data (Figure 8).
Figure 8: Early performance data for 2007-2009 Whiting operated wells in Mountrail County. (Source: Data: DrillingInfo; Graphic: Capriole Energy).
Figure 9: Revised economics in Figure 6 using same cost assumptions, but 2009 type curve.
Well economics with fully loaded costs for the 2009 type curve are now look significantly less attractive than the 2008 type curve, with breakeven oil price about $45/bo (Figure 9). Whiting realized an average oil price (excluding hedging) of $52.51/bo implying that the lowest performing wells in the 2009 batch were sub-economic when they were drilled. There is no mention of this in the 2009 annual report, which instead focuses on production and reserves growth, and explanation of the net loss due to volatile oil prices, and an account of the farming down activities to manage debt.
Figure 10: Comparing type curve well performance, completion count and relative production contribution of the three Whiting reservoir targets in Mountrail County. (Source: Data: DrillingInfo; Graphics: Capriole Energy)
After a brief improvement in the performance of the wells drilled in 2010, overall performance deteriorated much more in 2011 to 2014, with project Estimated Ultimate Recoveries (EURs) projected to be below 350,00 boe (Figure 5). The explanation for this deteriorated performance rests with a greater proportion of laterals completed in the Three Forks, together with a deterioration of the Bakken infill wells (Figure 10). Drilling so many Three Forks wells in this period is particularly alarming with projected breakevens of $80/bo for the fully loaded cost model of the Three Forks type curve (Figure 11). This is the fundamental reason for the deterioration of Whiting’s business fundamentals of net profit margin, net income, capital efficiency, and long term debt burden on the balance sheet offset by price-dependent NAV.
Figure 11: Well economics for the Three Forks type curve, using same cost data as Figure 6.
The same pattern of poorer performance in the Williston Basin
Zooming out from a focus on the Sanish area, the same pattern of deteriorating performance is reflected elsewhere in the Williston Basin (Figure 12) and hence in Whiting as a whole with the Bakken so important to its resource base. Whiting’s annual reports for 2013 and 2014 don’t mention anything about declining well performance. Instead, there is much to do about continued growth, acquisition of more resource play acreage, and in 2014 the merger with Kodiac Oil and Gas in a stock deal including Kodiac’s $2.5 billion of debt. The 2014 report also acknowledges the “pullback” in oil prices during that year and describes a 2015 capital budget of $2.0 billion to reflect “a disciplined approach to maintaining our financial strength while preserving our long-term growth plans”. The 2015 plan held reducing the number of active rigs to half of 2014 level and a focus on the “highest rate-of-return properties”.
Figure 12: Whiting type well performance by year in the Williston Basin. Note that the 2008 cumulative type curve, whether expressed as 6:1 or 20:1 MScf:boe for gas, has never been bettered, nor likely never will by subsequent years. (Source: Data: DrillingInfo; Graphic: Capriole Energy).
“By working with our service company partners, we have been able to improve margins and cash flow. In 2015, we lowered operated well costs approximately 25% in the Williston Basin. To increase returns and recoveries, we are using new completion techniques that involve larger sand volumes. Our Bakken productivity continued to increase throughout the year. Our fourth quarter 30-day average rates came in 22% higher than third quarter results. As a result of this new technology and associated productivity gains, our Bakken type curve has moved up 17% to over 700,000 barrels of oil equivalent.”
The reckoning
2015 turned into a disaster for Whiting (Figures 1 to 4). A net loss of more than $2 billion wiped out all the profits of the prior 8 years. They outspent ops cash with Capex by a massive $2.5 billion, drilling wells that only were marginally better than 2011 to 2014 batches (Figures 12, 13). With oil price controlling proven reserves and NAV, Whiting’s share price sank to below post-IPO levels in 2003. While the numbers are plain to see in the 2015 Whiting annual report, the narrative tells a different story of successful production and reserves growth, balance sheet liquidity with new debt and some asset sales. The most interesting revelation is contained in the quote above with the declaration that the “Bakken type curve moved up 17% to over 700,000 boe”.
This exposes several technical issues that obscure the real economics of the business. Firstly the use of a 6:1, Mscf:boe ratio to express hydrocarbon reserves overstates the value of the reserves by a factor of 3 or more. It is generally accepted that a 20:1 ratio or more needs to be used instead to properly represent the lower value of the associated gas. The optical effects of this can be seen in Figure 12. The upper chart shows the type curves for the decade of Whiting’s drilling using a 6:1 ratio, while the lower chart uses 20:1, illustrating the optical illusion of overstated value using 6:1.
Figure 13. The story of a parent and two children. The upper panel shows the production history of well drilled and completed in Mountrail County in 2008, while the lower two panels show wells drilled between 400 and 600’ from the first well in 2013 and 2014. The infill or child wells have proportionately greater gas production, diminishing oil recovery compared to the parent. Moreover, the parent’s gas:oil ratio also goes up because of the enhanced pressure depletion affected by the children. (Source: Data: DrillingInfo; Graphic: Capriole Energy)
The second issue, of course, is more critical and would have been apparent to Whiting on a basin-wide basin by early 2016 or earlier by looking at well performance in specific spacing units (Figure 13). The batch of wells drilled in the Sanish area in 2008, initial development wells, continued to be the best yearly group of wells drilling by Whiting in the basin, with subsequent years until 2016 itself not even getting close (Figure 12). This in spite of apparently improving completion techniques. As will be discussed further below, even the additionally enhanced completions of the last 3 or so years will get close to 700,000 boe (6:1, Figure 12). Thus the expectation that a play/reservoir type curve should get better in oil (or real value) terms should get better year-on-year is likely to be confounded for two reasons.
The first is that in any development, be it a smaller conventional pool or a huge unconventional shale development like the Bakken, geoscientists and reservoir engineers are typically able to predict the best parts of the reservoir or the “sweet spots”. That means rock that can produce the most oil and lease condensate. If anybody is going to be a winner in a shale play, they need to be early acquirers (at a reasonable price and terms) of the acreage in those sweet spots. In the Bakken, there is generally a rim of oiler production around a deeper kernel of more gas-prone rocks.
Figure 14: Production for the Bakken play (all operators) in the Williston Basin and the escalation of gas production in 2014. (Source: Data: DrillingInfo; Graphic: Capriole Energy).
The second reason concerns the density of drilling. In 2008, the original development wells were drilled on a 1280 acre spacing. That soon changed to 640 (2 wells per 1280 unit), then 320, and onwards to the spacing illustrated in Figure 13, which is in the range of 80 to 180 acres. Even a reservoir like the Bakken has a physical limit on the fluid that is moveable as production, no matter how dense the network of wellbores and associated artificial fractures. A related and more profound problem with over-drilling a reservoir concerns reservoir pressure which if overdrawn or depleted below its bubble point causes a break-out of associated gas which would otherwise remain in solution in the oil at reservoir conditions. Gas is relatively more permeable than oil in a reservoir and its preferential flow to the well reduces the effectiveness of oil recovery (Figure 13). Art Berman, who like others has been writing and presenting about the failings of shale for many years, pointed out these problems for the whole of the Bakken play in 2017, but it’s clear that operating companies like Whiting should have been awake to these issues by 2014 if not sooner (Figures 12, 13 and 14). Instead, the ability to down space was taken with glee and the value of Whiting’s leases was inferred to be enhanced by the multiplication of drilling locations.
2016’s annual report only increases the perception that for Whiting profit and returns to shareholders didn’t really matter so long as they making oil. The bottom line of a $1.3 billion net loss was ignored in the annual report propaganda of “resurgence”, big frac jobs and balance sheet liquidity. Asset sales, with Whiting’s original EOR fields now divested, covered off the $2.5 billion debt bought with Kodiac acquisition in 2014. In doing so, Whiting was now doubled down on shale, specifically the Bakken.
Despite the repayments, there was still $3.5 billion long term debt on the balance sheet, most of which was covered by a credit facility of $2.5 billion with covenants based on the EBIDTA/Debt ratio amongst other ratios. I have held the view for some time that these EBIDTA/Ratios are one of the forcing mechanisms that cause shalecos to keep drilling even when prices are low and well economics make no sense. In Whiting’s case, negative EBITDA in 2015, 2016 and 2017 must have led to some interesting conversations with the lending banks.
Meanwhile, the 2016 annual report again contains more claims about improving production output from new wells and type curves make their first appearance, at least in the form of EUR estimates and a first 24 cumulative type curve (boe, 6:1) of two different completion types. One claimed to deliver 900 mboe (6:1) corresponds to an “enhanced” completion with 5+ million pounds of sand, the other is a “super-completion”, with 10+ million pounds of sand, seeking to deliver 1500 mboe of reserves. These assertions would have looked less optimistic if they had been backed up by historical data and/or some support from engineering models, but Figures 5 and 12 show us that these EURs represent step change into previously unattained heights.
Figure 15: Comparison of costs/boe (6:1) of 2008 and 2016 financial performance (Source: Data: Annual reports: Graphic: Capriole Energy).
Changing of the guard
2016 was to be James Volker’s last full year in charge and in November 2017 Bradley J Holly took over. Volker had certainly transformed Whiting in terms of production, but the company in terms of bottom-line economics was little better than 2008 when the strategic pivot from the exploitation of conventional properties to development of the Bakken shale commenced. The economies of scale of production and perhaps the operating cost intensity of enhanced oil projects compared to shale shine through in an improvement in cash costs per boe. Unfortunately, that improvement is offset by an increase in DD&A per boe, reflecting the continued depreciation of the enormous amounts of capital deployed in the business from 2011 to 2015 (Figure 4).
Figure 16: Comparison of well productivity year by year for Whiting operated wells. (Source: Data: DrillingInfo; Graphic: Capriole Energy).
During the last three years until end 2019 Whiting has had a much more sober approach to production, broadly staying within the same levels, but with an increasing proportion of natural gas. The escalating scale of frac jobs and expected productivity improvements has continued apace. Unfortunately, attempts to bludgeon more oil out of already highly drilled acreage has not increased oil productivity since 2016 when the first big fracs were completed, and has accelerated the gas breakout discussed above (Figures 12, 16 and 17).
Figure 17: Whiting’s gross operated production in the Williston Basin (Source: Data: DrillingInfo; Graphic: Capriole Energy).
After a narrow profit in 2018, Whiting returned to a loss making in 2019. Keeping Capex under $1 billion applied to the mega-fracs has kept the company’s production relatively steady over the last three years, but with an increasing amount of associated gas in the mix.
Figure 18: Per boe financial performance in 2019. (Source; Data: WLL Annual Report; Graphic: Capriole Energy).
The new executive team has done a reasonable job in reducing cash costs, and DD&A is also reducing as the excessive capital of prior years is depreciated. Whiting also realized (excluding hedging) $50.06/bo for their oil, 12% less than WTI for the year. Nevertheless, the increased proportion of less valuable gas, the price of which was also deteriorating, made average revenue per boe come in at $34.33/boe (Figure 18). In addition to the net loss, EBITDA also fell of course and Whiting’s debt vulnerability was in the spotlight again with the Debt/EBITDA ratio more than 3. Whiting also outspent ops cash with capex again, so further supporting the opinion that the company is unable to both sustain production and return cash to shareholders at “normal” ($50/bo) oil prices. During 2019 WLL continued its downward slide as investors continued to bail out on Whiting and its peers in the sector. Whiting’s fate was clear prior to the price crash in March.
Chapter 11
Whiting’s filing for Chapter 11 restructuring on April 1st, 2020 was not seen as a fool’s surprise by anyone although there was a fair amount of alarm and disdain expressed when it was revealed that the Whiting executive team has made early payment of their bonuses (subject to some clawback options) part of the package. The deal with the banks to be presented to the court is for the debt burden to be written off by an exchange for 97% of the equity of the restructured company. I suppose that this means that the executive team believes that there is a viable business on the other side of restructuring and that the banks believe that this is their best chance to get (some of) their money back. I will return to these assumptions later, but will first share some thoughts about the possible causes of Whiting’s rise and fall story of the destruction of billions of dollars of value.
Figure 19: Whiting Board and Executive Remuneration, and the proportion of the latter expressed as a percentage proportion of the company’s General & Administrative (G&A) overhead. (Source: Annual Reports and Proxy Statements; Graphic: Capriole Energy).
Underlying causes
It only takes a glance at the Whiting proxy statements ahead of annual general meetings to understand what was driving the execs to drive production (and reserves) ahead of returns and value. Since its inception until 2014, Whiting employees and executives more so have all benefited from a Production Participation Plan (PPP) in which they receive a share of the revenue from Whiting wells and from assets sold. This plan obviously grew in value with growing company production so by 2013 Volker’s total remuneration was $10,097,657, including a PPP four times his base salary (Figure 19). In 2014 the PPP was terminated after shareholders, represented by their proxy advisors, kicked up a fuss over the lack of transparency of the plan. By 2015 it had been replaced with a “more traditional” executive compensation plan, still heavily weighted to production:
Production Growth 30%
Reserve Growth 20%
Finding and Development Costs 20%
Safety 5%
However, the damage had already been done. Whiting’s at any cost production growth “phenomenon” was a result of executive incentives misaligned with bottom-line financial performance and value growth. Not only was there no return to shareholders from the production growth, but the company was left in a debt-laden position highly vulnerable to oil price. Since 2017, the targets for the executive compensation plan have swung away from production and reserves to include more cost measures including a drilling rate of return which I take as a belated attempt to ensure that new wells make sense to drill and making the cash returns contribution required for the business to prosper.
The role of the Board
It’s fairly easy to imagine that during the period from 2007 to 2014, there weren’t many employees of Whiting, entirely incentivized to production and reserves growth, that would have had much listening if they pointed out that the return efficiency of the wells being drilled was declining, that the business was being over-capitalized, and that was showing up in net profit margin, debt burden and increasing vulnerability to the risk of an oil price crash. In short a failing business strategy. If anybody should be watching for these factors, it should have been the Board, which in principle is duty-bound to shareholders to:
Approve the corporate strategy
Test business model and identify key performance measures
Identify risk areas and oversee risk management
Plan for and select new executives
Design executive compensation packages
Ensure the integrity of published financial statements
Approve major asset purchases
Protect company assets and reputation
Represent the interest of shareholders
Ensure the company complies with laws and codes
It appears that Whiting’s board was ineffective in most if not all of these duties. I think there are several possible reasons for this. Firstly, having the combined role of Chair and CEO can be problematic at the best of times, and when a CEO is singularly driven by one or two incentive metrics, not having an independent chair to exact some control can be a big problem. Secondly, it’s noticeable that no other company executive is on the Whiting Board. Normally it’s a good idea for the CFO to also be a director so that the board gets a line of sight on the numbers and the CFO gets to act strategically as part of the Board. Thirdly, for the most part, the pre-2014 Whiting Board was made up of men from smaller company backgrounds, with little or no apparent experience of successful executive roles in multi-billion dollar enterprises. It appears reasonable to conclude that this board could very well have been unaware of financial problems brewing under the CEO’s production and reserves drive, and perhaps didn’t have the nouse to ask the penetrating questions to uncover the truth.
After 2017, there has been a noticeable change in both the annual reports and proxy statements including further minor change of the makeup of the Board, pivots in strategy, and alterations to the remuneration policies and targets. Having said that, Bradley Holly still holds both Chair and CEO roles, and at the time of writing there is still no other executive such as the newly recruited CFO on the Board.
Institutional investors and banks
While institutional investors together have held a significant proportion of Whiting’s outstanding stock, individually they are typically less than 10% and spread across the sector. It seems that their strategy is sector-wide, and they spend less time allocating interest between companies in the sector. From that “peanut butter “ approach I wonder if there is much if any specific attention placed on detailed performance metrics of individual companies. Thus shale oil investment economics boiled down in 2008 to 2014 period to a single large bet on the oil price. To be fair, it was proxy advisors who stepped in during 2014 to steer investors to vote against the continued Production Participation Plan for Whiting’s executives, but by then it was too late with the gaping vulnerability of Whiting’s position to oil price already a severe risk.
Similarly, it seems the level of risk management by the banks lending money to Whiting (and other shalecos) seems to be fairly blind to the risks of diminishing well economics and increasing vulnerability to oil price in the reserves used for collateral.
Some people view investors and banks as much culpable for the shale disaster that is now unfolding at an accelerated pace as the companies themselves. The role of private equity, sponsoring portfolio companies with a strategy to acquire acreage, drill wells to prove productivity and then flip to the highest bidder, is also now highly questionable. As the initial “gold rush” from 2008 to 2014 in the earlier shale plays took off, a lot of private equity firms did very well. But the crash in 2014/15 and subsequent “lower for longer” prices acted against the private equity model to work on maturing plays and perhaps only the Permian provided any continuing success for the model.
Figure 20: A very simple financial model for the future depletion of Whiting’s production and reserves with no further capital deployment, for three oil price sensitivities.
The future of Whiting
So what next for the re-structured company that emerges from Whiting’s Chapter 11 process? I am assuming that depends on what the banks who now own Whiting want and what the bankruptcy judge determines as wise and pragmatic. The banks will want as much of their loans back as possible and in the face of the reasons and underlying causes for the failure it seems to be that a very disciplined re-basing of the cost structure of any costs that eat away at the revenue stream. There is a catch 22 at play because, without significant recycling of ops cash as capital, the revenue stream appears to be subject to a very rapid decline. In the very simple models presented in Figure 20, I have assumed (probably too optimistically) a 15% annual decline in Whiting’s existing production, with negligible capital expenditure. The models underscore the central problem of the business: the wells need higher oil prices to generate significant free cash at all and the choice to reduce the decline requires ops cash to be recycled as capital and exposes the business to the price risk problem again.
This leads me to the conclusion that perhaps the best thing for the banks to do is to create a very lean holding company to deplete these and other bankrupt assets. Any new capital or recycling of ops cash into capital would be done only if the projects had bottom-cycle price breakevens. The fund would also have to allow for well and other facility abandonment obligations, perhaps equivalent to a residual value associated with a thousand or more wells producing 10 bod or less. If such a holding company has a number of companies consolidated into the new business, perhaps there will be an increased number of better capital options to reduce the decline from which to choose.
Who’s foolin’ who?
I will finish this essay with a note about the current Whiting executive team. When I saw the reports and comments about Whiting’s Chapter 11, like a lot of people I was pretty vexed by the deal to pay themselves 100% of their bonuses. I was aware of the value destruction that Whiting (and other shalecos) had waged in the last decade, but hadn’t analyzed the company’s history to the level of detail presented in this article. I now feel a little sorry for the current Whiting execs, who from 2017 took on a business that was already failing and under duress. They have tried pretty valiantly to save the business and make it return free cash. Ultimately, however, a dog is a dog, and this one don’t hunt.
Nevertheless, while firing the execs and getting some new ones might have proven more expensive to the banks than paying the bonuses, I still think the execs negotiating the deal in this way as poor judgment and if I were the owner I’d be strongly considering a revamp of the executive team. If the current execs continue I suggest their remuneration is revamped to the new strategy and value delivery goals of the restructured company including a no profit no bonus minimum hurdle. At the very least, the Board of the new company needs to reconstituted both in terms of personnel, purpose, and process, starting with splitting the Chair and CEO roles. If the new company ends up being a consolidation of several bankrupt entities, then there is an opportunity to high-grade personnel on the consolidated Board.
Above all else, a post-restructuring return to business as usual by Whiting must be avoided. I’ve noticed people using the term zombie company which I take to describe a post-Chapter 11 firm that is trying to perform in the same way as it did previously and hence wanders aimlessly until the next price event put it out of its misery. That shouldn’t be allowed to happen. Indeed as the first major bankruptcy, Whiting ironically represents an opportunity to be a role model of shale oil’s future.