The breakeven prices for many unconventional plays has been falling rapidly.
"The overall lower unit costs can be used to estimate the breakeven price for wells drilled in 2015, assuming a 1% reduction in price equals a 1% reduction in the breakeven price. Figure 3 shows the breakeven prices for the main plays and how they have developed from 2011 to 2015. Historical values are calculated looking at decline curves, production mix and well cost for each year, and the 2015 values estimated, assuming a 23% decrease in prices.
Source: Oil And Gas Financial Journal Article Written By Per Magnus Nysveen and Leslie Wei July 15, 2015
On average, breakeven prices for the main oil plays have decreased ~50% since 2011. This is because operators are able to produce more as they find sweet spots, and rigs are able to drill more as rig companies better understand shale characteristics. This year, the Bakken, the Eagle Ford, the Permian Delaware and the Niobrara are all expected to have average prices less than 50 $/bbl, where the best areas are even lower. The current breakeven price of shale and the steady trend proves that shale is a very competitive source of production, and going forward, when prices recover, operators will increase rig counts just as quickly as they dropped them."
As shown above, prices have dropped from as high as $140 per barrel of oil to roughly the $40 range per barrel of oil at the time of this article. The breakeven is still continuing to drop as well design and other operational improvements continue to decrease costs per BOE.
Back in the good old days when I went to school, the college professor used to tell us to calculate breakeven by dividing the total costs for the period by the production to get a breakeven cost per unit. In the case of Whiting Petroleum (NYSE:WLL) the total first quarter costs 2016, of $529 million and a tax benefit of $65 million yielded a breakeven cost of $34.72 per barrel when divided by 13.4 million BOE for the quarter of production. The cost is $39.60 BOE without the tax benefit. Reported as a cost reduction is another $6.41 BOE of gains from the extinguishment of debt and net derivative losses. Without that net gain, the breakeven would be $46.01 BOE before tax effects and $41.13 BOE with tax effects. Those costs roughly fit the trend of the above article. At that point, the professor really ended the lecture and went on to the next topic because the breakeven topic was fully covered.
Unfortunately the good old days are probably gone forever. Things are just not as simple as they used to be.
Source: Whiting Petroleum June, 2016 Corporate Presentation
As shown above, the company has been busy working on increasing reserves and flow rates. In fact, during the conference call, management stated that the 900 MBOE figure was going to be rising this year. Management also anticipated more improvements on the way. Then it was time to discuss well costs.
While the rest of the industry has reported lower well costs, Whiting Petroleum Management is maintaining the well costs at $6.8 million for a Bakken well.
"Sure. The diverter agents really are the - the technology has been around for a while. It's using polylactic acid. And the service companies each have their own mix of that, but the idea here is that when you go in to stimulate a well, what you're trying to do is maximize the number of entry points. So, within given stage of the well, you can have up to six different perforation clusters. The problem has always been trying to make sure that the frac job gets distributed among all six of those. In the past, maybe only one or two of those was actually receiving any of the frac.
By pumping a diverter, what you do is, you give it a certain amount of time to go into those first one or two stages, then you pump the diverter, and it temporarily plugs up those stages, and the pressure goes up, and another perforation cluster will break. And so, it essentially doubles, in some cases, triples the number of effective perforation clusters within each stage. So, you just access a lot more of the reservoir that way, and so we're - it's turning out to be a great add-on. It's older technology, but it's just the way we're applying it now with our new completions that's making the difference."
Management is using the lower cost to add clusters per stage which increases reservoir contact and then is adding more sand to the mixture plus using this old technology to get the proppant where it always should have been in the first place. Because management now has a far more effective way to establish a lot more well contact, the above slides show a huge improvement with more improvements projected. Management now reported that the wells have about 40 stages. Some competitors are far higher than that, but management wants to be sure of increased results that justify the cost of the stages before they increase the stages or change anything else. In any event the cost progress and operational improvements are going to drop future breakeven costs for the company.
But the breakeven per BOE listed for the first quarter financial reports above were for a mixture of wells, most of those wells have antiquated designs and obsolete production curves. They are not representative of the company's costs going forward. When the company management shows as much production change in the first two slides as is shown above, then everything from lease operating expenses to depreciation will change in the future. They will probably change for the far better. Historical costs (some would say hysterical costs in a situation like this) have very little meaning and definitely cannot be used for analysis purposes.
To get an idea of the company's future breakeven costs and the breakeven costs for new wells, one would have to look at the cash costs. The cash costs to produce oil, gas, and liquids appear to be about $13.85 BOE from the operations (and guidance for the year) and another $5.00 BOE for interest expense. The finding and development costs could easily be less than half of the current depreciation or about $11 BOE going forward. While all of this is a very rough estimation, the forward looking new well breakeven costs for the company appear to be about $30 BOE for any new wells drilled. So no matter what the company is reporting, at current commodity pricing, new wells drilled appear to be above breakeven.
The other major point to look at is the cash cost to drill those wells with the lower. The company needs lower cost wells to make money in the latest commodity price environment. The historical pricing of $90 and up for a barrel of oil is probably gone for the foreseeable future. But the cash flow needed to transition to the new lower cost commodity pricing environment could easily add $10-$20 BOE to the breakeven. But the company need not rely solely on cash flow from operations to get the money needs for the new wells.
Indeed management stated that with the recent price rally the company expects cash flow of more than $200 million in the second quarter. This is up considerably from a pittance in the first quarter when commodity prices were a lot lower. The commodity price rally gave the company breathing room that it needs. Now the finances and operations quickly need an overhaul before the next downturn. The company had about $5.3 billion in long term debt at the end of the first quarter. When that is divided by the annualized second quarter cash flow figure of $200 million, the ratio is 6.6:1. This is an extremely tight and unsatisfactory figure. So the company may not be able to transition to the lower cost wells over time with that increased cash flow.
The additional cash can some from several sources. The company can sell stock, it can borrow more (not recommended), it can wait for higher commodity prices, it can joint venture or it can sell non-core assets. Each of the above has its advantages and disadvantages. Management began to tackle this issue by forcing (click on May 10 press release for details)the conversion of $477 million of debt to equity in May. Management has continued by forcing the conversion (click on June 22, press release) of $1 billion in notes by the end of July, 2016. While both of these conversions started with an exchange offer, the company is effectively moving its debt to equity. Not only does this increase current cash flow by saving interest but it also increases future cash flow by eliminating the debt maturity payments in the future.
The new ratio of long term debt to annualized projected cash flow is now $3.8 billion long term debt-to-$800 million cash flow. That new figure is nearly 5:1. While that is still tight, it is far better than the figure before the debt conversions. These debt conversions also decreased the breakeven amounts above by $1 BOE (very roughly) to $33.72 BOE after taxes. Still the company needs more cash to transition to a lower cost structure.
The company also announced a joint venture that has allowed management to increase the exit production rate and decrease the amount of production decline throughout the year. A partner provides the money and the company provides the expertise and execution. All of this will affect the forward looking breakeven of the company. Especially since joint ventures allow management to spread overhead amounts over more activity.
The company has more than $1 billion in liquidity from its bank credit line that was recently redetermined. So any debt maturities in the next couple years can be handled either by paying the debt when due, or paying the debt through the open credit line. The company also has the credit rating to issue more notes or bonds. However, management may choose to improve the key ratios (to get a better interest rate) before issuing more notes.
With management appearing extremely flexible and using several of the above options at once, it should be clear to the investor that the company has the capability to drill new lower cost wells to lower the company breakeven going forward. Maybe an individual investor cannot tell how significantly the quarterly breakeven will change, but the investor can clearly see that the breakeven will decrease for the foreseeable future.
If operational improvements slow down (a lot) or cease, and service costs stabilize, then depreciation and other costs would eventually represent the forward looking costs. But currently none of those conditions are visible on the horizon. Therefore using reported costs to forecast future costs is definitely not recommended at this time. In short there are current breakeven costs, company breakeven costs, individual well (or project) breakeven costs, and the costs to get to various possibilities. One statement about breakeven with no parameters or context can be very misleading and ambiguous.
The above slide is already (click on the June, 2016, presentation) obsolete. The company has already decreased interest expense by at least $1BOE. As cash is freed up from the lower debt, and the company's capacity to borrow increases, the company may elect to accelerate its activity levels beyond its cash flow and exceed its production guidance. The company has a significant inventory of drilled but uncompleted wells. Should management complete that inventory of wells, the production guidance for the year would change. The lease operating expense in the first quarter was $8.56 BOE. With the decreasing industry costs, management should have the goal of beating its guidance every single quarter. In fact, management should update the guidance to reflect the latest industry conditions.
Probably the best figures on the slide are the oil and gas price differential and the taxes. There are projects underway to increase the ability to get produced product to market better than in previous years. Pipeline capacity is being added to reduce transportation costs and reduce the price differential. But this will take some time for the solutions to become effective. In any even this company is not only decreasing its costs rapidly, but there are projects that will increase the sales price significantly even if commodity prices do not increase. Increasing sales prices will help profitability even if those prices do not affect breakeven.
So the future of this company looks quite bright. Management needs to decide if the debt level will be comfortable enough by relying on joint ventures and commodity price increases to increase cash flow. Or does management need to consider a sale of common stock, property sales, or a debt issue. This would not be the first company to convert debt to equity and then issue more debt. Management has stated that if the price of oil remains near $50 and forecast are confident of it remaining at $50 then management will review the options available to increase production. The company has a significant inventory of drilled but not completed wells. These wells have the potential, as do completely new wells to lower the breakeven point of the company. Given the cost cutting progress, a year or two of new wells factored into the mix of wells could significantly increase cash flow as the new lower cost production replaces the higher cost production from the older wells.
Therefore the company breakeven cost in the future would be based upon the specific company strategy for getting to that future. Debt issuance would raise the breakeven costs whereas equity and property sales have the potential to lower that costs. The activity level of new production replacing the natural decline of older wells will also lower breakeven. Breakeven is now a moving target for a lot of reasons, and not that easily pinned down to a general statement. Management is transitioning towards a breakeven of about $30 BOE with plans to drive that BOE lower in the future. While timing is uncertain, management is clearly focused on the goal of lower costs. That is just what investors in a commodity company want to know. In the near future, this company will make money even if commodity prices drop considerably from current levels. The hedging program could help the profitability by stabilizing the cash flow.
Whiting Petroleum has a bright future. The debt has been and will be reduced significantly. Management has several viable ways to increase cash flow, show operating improvements, and drill newer low cost wells. The path chosen will determine the riskiness of investing in the company in the future. Options include, converting more debt to equity and then issuing more debt, selling shares, joint ventures, and selling non-core assets. Management has done all of these and the company has made considerable progress. The company has access to the debt markets if management chooses that path. The CEO and Chairman control a significant amount of stock. Their experience and investment in the company probably decrease the risk of an investment in this company. Plus the oil and gas industry is probably near its bottom, so there is a lot of pessimism priced into the stock and not much faith in the leadership abilities of management to navigate the company into the next industry recovery.
The recent stock dilution has made the company much safer. While that dilution may have reduced the future returns, those returns will become a little more certain and less variable. The company has some of the prime Bakken acreage and some of the lowest costs and superior production results from that acreage. This industry leader may be a speculative pick now, but expect management to improve the risk-reward ratio as the future unfolds. Infrastructure improvements are underway that will improve the selling price which will also boost cash flow. The stock, which is trading at about 27% (at the close of the market on June 24, 2016) of its 52 week high should reward investors handsomely as management improves cash flow considerably and returns the stock to its former highs. This management built the company from scratch and should not be underestimated.
Investors should expect to see the cash flow increase over the next reporting periods. The depreciation and other allocated costs from the higher cost history will cause some smaller than expected profits until enough new lower cost production has been established to dominate the costs. The investor needs to remember that those older wells are sunk costs and will probably never achieve the original projected profitability. The cost ceiling writeoffs will help to correct the future reporting but will not push all the losses those older wells now cause into the past. So it may be a year before the company reports profits (and several years more before allocated costs reflect the new lower costs), but cash flow should grow significantly as long as the commodity prices do not drop substantially and sustain that drop.
Disclaimer: I am not an investment advisor and this article is not meant to be a recommendation of the purchase or sale of stock. Investors are advised to review all company documents, and press releases to see if the company fits their own investment qualifications.
Disclosure: I/we have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours.
I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.