The Petroleum Truth Report

My goal is to offer clear and direct explanations of energy reality. These posts are data-driven interpretations of oil and gas topics that often challenge conventional thinking.
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Oil Prices Plunge To Where They Should Be

WTI oil prices plunged to almost $45 per barrel yesterday (Figure 1). That was a downward adjustment to where prices should be based supply, demand and inventory fundamentals.

Figure 1. Oil Prices Are Testing a $45 Floor. Source: EIA, CBOE, Bloomberg and Labyrinth Consulting Services, Inc.

Analysts invent narratives to explain why things happen after we already know the answer. In this case, oil prices fell supposedly because of falling confidence that the OPEC production cuts are working, fears of increasing U.S. shale output, and weakening demand from China.

None of those factors is new nor did they seem to affect the market a few weeks ago when prices were above $53 per barrel.

The real reason that oil prices have fallen is that they were too high and needed to adjust downward. Comparative inventory analysis (Bodell,2009) suggests that the correct price for WTI right now is about $45 per barrel (Figure 2).

Prices rose from that level in November 2016 to almost $55 (black arrows in Figure 2) following announcement of OPEC production cuts. Approximately $10 of “OPEC expectation premium” was included in those higher prices.

Figure 2. $45 Is The Right Price For WTI Based On Comparative Inventories. Source: EIA and Labyrinth Consulting Services, Inc.

In February and March, prices fell from more than $54 to $47 per barrel in the first deflation event shown in Figure 3. Prices then increased to more than $53 in the first half of April before falling to almost $45 per barrel this week during the April-May deflation.

Figure 3. Deflation of the OPEC Expectation Premium. Source EIA, Bloomberg and Labyrinth Consulting Services, Inc.

There is little doubt that the OPEC cuts are real and are working to reduce global inventories. Unrealistic expectations about how quickly markets might re-balance created an expectation premium that is now being deflated as prices adjust to where they should have been all along.

This market has been largely optimistic over the last year so it would not surprise me to see a return to $50 oil prices in the next week or so. At the same time, look for continued price volatility in the tug-of-war between revived expectation premiums and market fundamentals. Inventories will be the critical factor.

OPEC Production Cuts and The Long Road To Market Balance

Global oil inventories are falling because of OPEC and non-OPEC production cuts but the road to market balance will be long.

Production cuts have removed approximately 1.8 million barrels per day (mmb/d) of liquids from the world market since November 2016 (Figure 1).

Figure 1. OPEC-NOPEC Have Cut 1.8 mmb/d Liquids Since November 2016. Source: EIA April 2017 STEO, EIA International Data and Labyrinth Consulting Services, Inc.

Saudi Arabia has cut 619 kb/d (35% of total) and the Gulf States Cooperation Council—including Saudi Arabia—has cut 1,159 kb/d (65% of the total). Other significant contributors outside the GCC include Iraq (12%), Russia (12%) and Mexico (9%) (Table 1). Nigeria’s cuts are probably involuntary since it was exempted from the OPEC agreement. Iran and Libya–also exempted–and both increased production.

Table 1. Summary table of OPEC-Non OPEC production cuts, November 2016 through March 2017. Source: EIA April 2017 STEO, EIA International Data and Labyrinth Consulting Services, Inc.

Inventories and The Forward Curve

OECD inventories began falling in July 2016, four months before the OPEC production cuts were finalized. Stock levels have declined approximately 107 mmb according to recently revised EIA STEO data (Figure 2). That includes the January 2017 increase recently noted in the April IEA Oil Market Report.

Figure 2. OECD inventories have fallen more than 100 million barrels since July 2016. Source: EIA April 2017 STEO and Labyrinth Consulting Services, Inc.

Although this represents progress toward market balance, stocks must fall at least another 260 mmb to reach the 5-year average level to support oil prices in the $70 per barrel range.

Almost three-quarters (73%) of OECD decline was from non-U.S. inventories. Perhaps the intent of OPEC’s November cuts was to stimulate a decrease in U.S. inventories (about 45% of the OECD total). U.S. stocks and comparative inventories were increasing at the time of the cuts and did not start to fall until February 2017 (Figure 3). Since mid-February, U.S. stocks and comparative inventory have each declined 20%.

Figure 3. U.S. Comparative Inventories Have Fallen 20% Since Mid-February 2017. Source: EIA and Labyrinth Consulting Services, Inc.

Still, U.S. inventories must fall another ~150 mmb to reach the 5-year average (Figure 4).

Figure 4. U.S. Crude Inventories Must Fall ~150 Million Barrels to Reach the 5-Year Average and Higher Oil Prices. Source: EIA and Labyrinth Consulting Services, Inc.

The immediate results of the OPEC cuts were an increase in oil prices and an important change in the term structure of crude oil futures contracts. Before the cuts were announced, the term structure of the WTI oil futures curve was in contango (prices are higher in the near-future). That favored storing rather than selling oil and contributed to growing inventory levels (Figure 5).

Figure 5. The Term Structure of WTI Futures Contracts Changed From Contango To Backwardation After the OPEC Production Cut in Late November 2016. Source: CME and Labyrinth Consulting Services, Inc.

In early March 2017, however, oil prices fell as investors lost confidence that the cuts were working. Forward curves moved into weak backwardation (prices are lower in the near-future). Now, prices have increased with outages in Canada and Libya, and the forward curve has moved into stronger backwardation. That favors selling rather than storing crude oil and contributes to decreasing inventory levels.

Market Balance, Supply and Demand

The latest IEA  Oil Market Report stated, “It can be argued confidently that the market is already very close to balance.” What does that mean?

Market balance means that production and consumption are approximately equal. That is an important first step for a market in which production has exceeded consumption for most of the last 3 years but it hardly means that $70 oil prices are around the corner.

Market balance must be expanded to be useful:  production is not the same as supply, and consumption is not the same as demand. Supply is production plus inventory. Demand is the quantity of oil the market is willing to buy at a certain price–it may be either more or less than production.

Oil prices collapsed in 2014 because demand wasn’t great enough at $100 per barrel to absorb the output from the 2010-2014 production bubble. Prices collapsed to $30 per barrel before a transformed market began a weak and uneven recovery, and production surpluses began to decrease slowly (Figure 6).

Figure 6. Critical Supply & Demand Are In Approximate Balance. Source: EIA April 2017 STEO, IEA OMR, OPEC MOMR and Labyrinth Consulting Services, Inc.

Demand did not increase enough until July 2016 to require critical supply withdrawals from inventory–a small subset of total supply. U.S. inventories did not begin to decline until after the OPEC cuts took effect in February 2017.

In the real world, the 5-year average inventory level represents a dynamic proxy for market balance. Comparative inventory is the measure of how far the present market must rise or fall to reach that level. IEA data indicates that inventories are 330 mmb above the 5-year average although revised EIA data suggests that levels are closer to 260 mmb higher than that important benchmark. In either case, it will take 6 months to a year to approach the 5-year average.

Demand Growth

Weakening demand growth is the potential barrier to continued inventory reduction and price recovery assuming that OPEC production cuts hold and are extended. Annual demand growth has declined to 1.25 mmb/d from the comparatively robust 2 mmb/d growth in 2015 and 1.62 mmb/d in 2016 (Figure 7). IEA forecasts continued weak demand growth for 2017.

Figure 7. 2017 Demand Growth Has Fallen To 1.25 mmb/d. Source: EIA April 2017 STEO, IEA OMR, OPEC MOMR and Labyrinth Consulting Services, Inc.

The problem, of course, is that demand is highly price-sensitive in a global economy that is burdened by unmanageable debt. Demand lags price and demand growth reflects the full spectrum of economic headwinds.  In early 2016, oil prices reached the lowest level in a decade-and-a-half. After that, year-over-year demand and oil prices increased through November 2016 and yet, demand growth in 2016 was lower than in 2015. Since then, $45 to $55 per barrel prices appear to have depressed demand growth to annual levels of about 1.25 mmb/d.

The OPEC cuts are accelerating the reduction of global inventories but continued progress toward the 5-year average will push oil prices higher. Higher prices may collide with weak demand growth in a stagnant economy that simply needs less oil. The long road to market balance may be slower and less predictable than bullish analysts predict.

 

Low Break-Even Prices Are For Everyone–Not Just Shale Companies

Shale companies have pushed break-even oil prices below $40 per barrel—but so have major oil companies.

Analysts commonly portray cost reduction as something unique to the tight oil companies. Data from annual reports filed with the U.S. SEC (Securities and Exchange Commission) suggests otherwise.

Along with tight oil companies, ExxonMobil, Royal Dutch Shell, ConocoPhillips and ChevronTexaco all had 2016 break-even prices below $40 per barrel (Figure 1).

Figure 1. Break-Even Prices for Majors and Tight Oil Companies Were All Less Than $40/Barrel in 2016. Source: Company 10-K and 20-F SEC filings and Labyrinth Consulting Services, Inc.

SEC 10-K and 20-F filings include the standardized measure, a projection of discounted (10%) future net cash flows from production of proved oil and gas reserves. By dividing the standardized measure by the volume of proven reserves, break-even prices can be calculated by subtracting the future cash flow dollar-per-barrel amount from the SEC average price for the year.

How is it possible that ponderous major oil companies have similar break-even prices as much smaller, innovative shale companies? Simple–costs have fallen for everyone since 2014 as oil field service companies competed for limited projects by working at a loss.

In fact, the oil and gas well drilling producer price index fell 45% between March 2014 and January 2017 (Figure 2). As I wrote in an earlier post, sharply lower break-even prices are 10% technology and 90% industry bust.

Figure 2.The Cost of Drilling Oil and Gas Wells Fell 45% After The Oil-Price Collapse;Unconventional Plays Resulted In a 4-fold Increase in Drilling Costs. Source: U.S. Federal Reserve Bank, EIA and Labyrinth Consulting Services, Inc.

And for those who think that unconventional oil and gas are low-cost resources, those plays resulted in a 4-fold increase in the cost of drilling wells between March 2003 and March 2014. That’s why oil cost more than $90 per barrel for 4 years before the price collapse.

So much for technology solving all of our energy problems.

And when you hear about tight oil companies breaking even at $20 to $30 per barrel—that’s not what they told the SEC in filings made just a few weeks ago.

The Downside of Lower Break-Even Prices

The downside of lower break-even oil prices is that companies make a lot less money in the future. Companies must write down reserves whose development costs are greater than their market value at lower oil prices. Figure 3 shows that future net cash flows were on average reduced by about two-thirds in 2016 compared with 2014.

Figure 3. Lower Future Net Cash Flows Are The Downside of Lower Break-Even Oil Prices. Source: Company 10-K and 20-F Filings and Labyrinth Consulting Services, Inc.

Companies are effectively high-grading their assets by writing down wells with poorer performance. Break-even price is lower because only most profitable wells are included in the calculation. Plus, the burden of taxes in addition to property and equipment costs associated with written down assets are removed.

The key take-away is that 85% of lower break-even prices were realized in 2015. Incremental improvement in 2016 was only 15%.

Advances in technology and efficiency are real but falling break-even prices are no miracle and are not a shale company exclusive. Instead of celebrating lower break-even oil prices, we should be lamenting lost future cash flows that an oil industry depression has wiped out.

 

Shale Cost Reductions Are 10% Technology and 90% Industry Bust

I am tired of hearing about the unbelievable impact of technology on collapsing U.S. shale production costs. The truth is that these claims are unbelievable. The savings are real but only about 10% is from advances in technology. About 90% is because the oil industry is in a depression and oil field service companies have slashed prices to survive.

Zero Hedge posted an article yesterday called How OPEC Lost The War Against Shale, In One Chart that featured the chart shown below from a Goldman Sachs note.

Figure 1. Short-cycle shale has engendered a structural deflationary cycle. Source: Zero Hedge and Labyrinth Consulting Services, Inc.

Zero Hedge (and/or Goldman Sachs) erroneously states that “the cost curve has massively flattened and extended as a result of shale productivity.” If I read the chart correctly, the flat portion attributed to “shale” represents ~ 10 mmb/d but tight oil only produces ~3 mmb/d.

This little arithmetic problem and the fact that the entire 2017 cost curve has shifted downward ~$15/barrel from the 2014 curve indicates that the true point and message of the graph is that break-even costs for all producers have fallen almost 25%.

My business is working with clients who drill onshore U.S. oil and gas wells. Rig rates have fallen 40% since the oil-price collapse. One client had a bid for a drilling rig in September 2014 for $27,000 per day. By the time he signed the contract in March 2015, the rate was only $17,000 per day. Another client recently ran a special high-tech log in a well whose list price was $75,000 but he only paid $15000 after discounts were applied.

Most of the celebration of efficiency and productivity is really about a depression in the oil industry that has resulted in massive price deflation. I estimate that only about 10-12% of the cost reduction is because of technology and most of that was a one-time benefit in the first year or so it was used. Going forward, efficiency gains are a few percent at most.

“Our forecast assumes that productivity declines 8% by the end of 2018…We believe a significant portion of the productivity gains being experienced by the sector outside of the Permian are the result of high grading and will revert in future years. Cost pressures are already surfacing in the Permian, which will dampen capital efficiency going forward.”
—Bernstein E&Ps ( 10 March 2017)

Break-even price is mostly a function of well cost, flow rate and EUR.

I have already addressed well cost. Most companies and analysts routinely exclude G&A (General and Adminstrative costs or overhead), royalty payments, federal income taxes, depreciation and amortization (“EBITDAX”) from their costs. Excluding cost is an excellent way to reduce break-even price except that it does not accurately represent break-even price.

Even if we accept these break-even prices, does anyone knowingly invest in things that don’t make any money? Sorry, I forgot about negative interest rateEuropean bonds.

The EUR used for break-even prices in charts like Goldman Sachs’ are largely unknown but bigger EUR means lower break-even prices.

Companies routinely report EUR in barrels of oil equivalent (BOE) that use a natural gas-to-BOE conversion of 6:1 based on energy content but a value-based conversion including natural gas liquids is 15:1.

For gassy plays like the Eagle Ford and Permian basin, this conversion sleight-of-hand produces ~35% inflation in EUR. It is perfectly legal for reserve reporting but it is a dishonest way to represent break-even price since companies are getting ~$2.50/mmBtu for gas and not the $6.25/mmBtu implied by the 6:1 conversion.

Advances in technology have resulted in higher early production rates increasing net present value. In many cases, however, these are accompanied by increased decline rates and lower EUR. Figure 2 shows an example from the Bakken Shale play.

Figure 2. Comparison of 20-mMonth cumulative production and normalized decline rates for the Bakken Shale play. Source: North Dakota Pipeline Authority, Drilling Info and Labyrinth Consulting Services, Inc.

The chart on the left shows 20-month cumulative production data suggesting that well performance has improved every year. The chart on the right shows decline rates for the same years of production. It shows that, in fact, well performance is decreasing from 2014 through 2016 because of higher decline rates.

Technology does not create energy. The effect of better technology is a bigger spigot that produces the energy faster. The downside of the technology is that it increases the rate of resource depletion.

Costs have come down for all oil and gas producers since the oil-price collapse in 2014. Most of the savings are because of lower oil field service costs and not so much because of improved technology.

 

Oil Prices Plunge: Over-Reaction or Turning Point?

Oil prices plunged yesterday. Is this an over-reaction or a turning point?

WTI futures fell $2.86 from $53.14 to $50.28 per barrel, and Brent futures dropped $3.81 from $55.92 to $52.11 per barrel. WTI is trading below $49 and Brent, below $52 per barrel at this writing.

The official narrative was that a larger-than-expected 8.2 million barrel (mmb) addition to U.S. crude oil inventories pushed prices lower. That explanation is not consistent with larger recent additions to storage that had little effect on oil prices. The timing of the price slump also seems to be at odds with positive developments in the global market balance and demand growth.

Something more fundamental is happening. In part, the price slump reflects a growing realization that the OPEC production cut is unlikely to quickly resolve the problem of outsized global oil inventories. Perhaps more importantly, a major downward shift in the term structure of oil futures contracts suggests that headwinds in the global economy are driving the end of the present oil-price rally.

Over-Reaction

The drop in prices was an over-reaction to recent storage data based on history since the OPEC production cut was finalized in late November 2016. WTI has fallen below the $50 to $55 per barrel range in which oil futures have traded for the last 3 months (Figure 1).

Figure 1. Oil prices have not exceeded $55 per barrel since early 2015. Source: EIA, CBOE and Labyrinth Consulting Services, Inc.

An 8.2  mmb addition to crude oil storage is actually fairly normal during the annual re-stocking season that we are in now (Figure 2). Inventories increased more–10.4 mmb–during this week in 2016 and the 5-year average for this date is 5.3 mmb.

An 8.2 million barrel addition is fairly normal for re-stocking season. Source: EIA and Labyrinth Consulting Services, Inc.

The fact that inventories have been in record territory since the beginning of 2015 has not kept oil futures from going through several rallies or from trading near $55 per barrel since November. The 13.8 mmb addition to storage a month ago was larger than yesterday’s amount yet prices barely responded.

Comparative inventory–the crucial price indicator–only moved up 2.4 mmb (Figure 3). That is because we are in the re-stocking season and compared with previous years, this addition to storage is not that big. Other key measures of gasoline and diesel volumes fell by more than 1 mmb each.

Figure 3. Comparative crude oil plus refined products inventory increased only +2.4 mmb. Source: EIA and Labyrinth Consulting Services, Inc.

And there was some good news this week that the markets ignored. EIA’s Short-Term Energy Outlook (STEO) showed that the global market balance (production minus consumption) moved to a deficit last month. The world consumed almost a million barrels more than it produced in February (Figure 4).

Figure 4. The world liquids market balance (production minus consumption) was -1 mmb/d in February 2017. Source: EIA March 2017 STEO and Labyrinth Consulting Services, Inc.

This is a one-month data point and should not be seen as a trend. Still, it is a positive sign that seems to have been overwhelmed by an otherwise normal addition to U.S. storage.

The March STEO also had good news about world demand. Average liquids consumption growth for 2016 was 1.5 mmb/d and 1.6 mmb/d for the first two months of 2017 (Figure 5).

Figure 5. 2016 global liquids consumption growth: +1.5 mmb/d, early 2017: +1.6 mmb/d. Source: EIA March 2015 STEO and Labyrinth Consulting Services, Inc.

In mid-2016, there were indications that consumption was only growing at only about 1.2 mmb/d but particularly strong year-over-year performance from August through January have brightened that outlook.

Turning Point

Although yesterday’s price plunge may have been an over-reaction, it may also represent a turning point for prices to adjust downward.

I have written for months that global oil inventories must fall before prices can make a sustainable recovery yet they remain near record levels. OECD inventories fell 15 mmb in February but are nearly 550 million barrels above December 2013 levels (Figure 6).

Figure 6. OECD incremental liquids inventories are near record high levels. Source: EIA and Labyrinth Consulting Services, Inc.

Brent was probably $10 over-valued at $55 and WTI was at least $6 over-valued at $54 per barrel as Figure 1 shows.

The other negative weighing on oil prices is the increase in U.S. crude oil production. Output has increased 420,000 b/d since September and EIA forecasts that it will exceed 10 mmb/d by December 2018 (Figure 7). That is higher than 1970 peak production and 1.1 mmb/d more than current levels. In short, this would more than cancel the U.S. decline since oil prices collapsed in late 2014.

Figure 7. EIA U.S. crude oil forecast is 10.1 mmb/d and $59 WTI by December 2018. Source: EIA March 2017 STEO and Labyrinth Consulting Services, Inc.

There has been a change in the term structure of futures contracts since the OPEC production cut was finalized. In the last week, the maximum WTI near-term price has fallen $2.81 to $51.36 per barrel and prices do not reach $52 until mid-2021 (Figure 8).

Figure 8. The term structure of WTI futures contracts has changed. The maximum near-term forward price has fallen $2.81 per barrel in the last week. Source: CME and Labyrinth Consulting Services, Inc.

The term structure of Brent futures has changed also. Near-term forward prices have fallen $3.39 from a week ago to $53.15 per barrel then, fall and do not reach $53 again until late in the third quarter of 2020 (Figure 9).

Figure 9. Figure 8. The term structure of Brent futures contracts has changed. The maximum near-term forward price has fallen $3.39 per barrel in the last week. Source: CME and Labyrinth Consulting Services, Inc.

Although the forward curve of futures contracts is hardly a predictor of oil prices, it appears that a major downward shift in oil prices is occurring. This reflects something far more consequential than a higher-than-expected U.S. crude oil storage report.

Over-Reaction or Turning Point?

In part, this week’s price downturn reflects waning confidence that OPEC production cuts will result in higher prices. Much of the discussion until now has centered on whether OPEC will deliver on the announced cuts or if output increases by Libya and Nigeria will offset those cuts.

There seems to be a growing awareness that global oil markets are incredibly complex, and that there are so many moving parts that a single, simple solution is unlikely.

The problem may be about expectations. Many believe that the OPEC cuts will increase prices but the cuts may be more about establishing a floor under those prices.

There is no good reason why a normal addition to U.S. inventory should affect prices so much. The timing of this price adjustment may be an over-reaction but the direction may also represent a turning point.

A larger issue is the inexorable relationship between stocks and prices. It’s not so much about this week’s change in inventory. It’s about how much inventory needs to be reduced and how long that will take in the most hopeful scenario.

If OECD stocks must fall by approximately 550 million barrels to support $70 prices, it will take more than a year to get there if production is cut by 1 mmb/d. If the production-consumption balance fluctuates, it will take even longer.

The change in the term structure of oil futures contracts suggests that causes for the recent price slump transcend oil market supply-demand fundamentals. Larger forces in the global economy are operating here. These may include reduced levels of credit creation that signal a slow-down in economic growth. If true, lower oil and other commodity prices are likely along with lower oil-demand growth.

For more than two years, the industry has believed that higher prices are possible without extreme reductions in inventories. Great expectations were placed in an OPEC production cut to rescue the industry from a weak oil market.The fallacy lies in thinking that the problem stems from a simple imbalance between production and consumption and is unrelated to a fragile and debt-dependent global economy.

That hope was a dream. It appears that oil markets have woken up from that dream.

 

The Beginning of the End For The Bakken Shale Play

It’s the beginning of the end for the Bakken Shale play.

The decline in Bakken oil production that started in January 2015 is probably not reversible. New well performance has deteriorated, gas-oil ratios have increased and water cuts are rising. Much of the reservoir energy from gas expansion is depleted and decline rates should accelerate. More drilling may increase daily output for awhile but won’t resolve the underlying problem of poorer well performance and declining per-well reserves.

December 2016 production fell 92,000 barrels per day (b/d)–a whopping 9% single-month drop (Figure 1). Over the past two years, output has fallen 285,000 b/d (23%). This was despite an increase in the number of producing wells that reached an all-time high of 13,520 in November. That number fell by 183 wells in December.

Figure 1. Bakken Production Declined 92,000 bopd (9%) in December. Source: North Dakota Department of Mineral Resources and Labyrinth Consulting Services, Inc.

Well Performance Is Declining

Well performance was evaluated for eight operators using standard rate vs. time decline-curve analysis methods. These operators account for 65% of the production and also 65% of producing wells in the Bakken play (Table 1).

Table 1. Operators, Cumulative Oil Production, Total Producing Wells and 2012-2015 Wells Used for Decline-Curve Analysis (DCA) in this study. Source: Drilling Info and Labyrinth Consulting Services, Inc.

Estimated ultimate recovery (EUR) decreased over time for most operators and 2015 EUR was lower for all operators than in any previous year (Figure 2). This suggests that well performance has deteriorated despite improvements in technology and efficiency.

Figure 2. Bakken EUR (Estimated Ultimate Recovery) Has Generally Decreased Over Time. Source: Drilling Info and Labyrinth Consulting Services, Inc.

Figure 3 shows Bakken EUR and the commercial core area in green. The map on the left shows all wells with 12-months of production history and the map on the right, all wells with first production in 2015 and 2016.

Most 2015-2016 drilling was focused around the commercial core area. The fact that EURs from these core-centered locations were lower than earlier, less favorably located wells indicates that the commercial core is showing signs of depletion and well interference.

Figure 3. Bakken EUR map showing all wells with 12-months of production and all wells with first production in 2015 and 2016. Source: Drilling Info and Labyrinth Consulting Services, Inc.

Well-level analysis indicates a fairly systematic steepening of decline rates over time. Figure 4 shows Continental Resources wells with first production in 2012 and 2015. 2012 wells have a shallow, super-harmonic (b-exponent = 1.3) decline rate but 2015 wells have a steeper, weakly hyperbolic (b-exponent=0.2) decline rate.

Oil reserves for 2012 wells averaged 343,000 barrels but only 229,000 barrels for 2015 wells–a 33% decrease in well performance. Steeper decline rates result in lower EURs.

Figure 4. Well-level analysis shows steeper decline rates for more recent wells than for older wells. Source: Drilling Info and Labyrinth Consulting Services, Inc.

In fact, a successive increase in oil production decline rates can be seen for all of the major operators evaluated in this study. Decline rates for 2014, 2015 and 2016 are higher than for previous years for these operators despite higher initial rates (Figure 5).

Figure 5. Oil production decline rates for recent years are greater than for previous years for the top 8 Bakken producers. Source: Drilling Info and Labryinth Consulting Services, Inc.

Gas-oil ratios (GOR) for most operators increased from 2012 through 2014 and then, decreased for wells with first production in 2015 (Figure 6).*

Figure 6. Bakken gas-oil ratios generally increased over time but then decreased in 2016. Source: Drilling Info and Labyrinth Consulting Services, Inc.

Changing GOR is important because it suggests decreasing reservoir energy. The Bakken has a solution gas drive mechanism. Initially, oil is produced by liquid expansion across the pressure drop from the reservoir to the well bore. Later, gas dissolved in the oil expands and this is the mechanism that lifts oil to the surface.

Rapidly increasing GOR in the Bakken probably indicates partial reservoir depletion and subsequently decreasing GOR suggests more advanced depletion accompanied by declining reservoir pressure, declining oil production and increasing water cut (Figure 7).

Figure 7. Increasing gas-oil ratio indicates partial reservoir depletion–Decreasing gas-oil ratio indicates advanced depletion. Source: Schlumberger and Labyrinth Consulting Services, Inc.

The sequence of events summarized in Figure 7 is demonstrated in Bakken field production shown below in Figure 8. Gas increased before oil production peaked in December 2014 and continued increasing through March 2016, and then declined.

Figure 8. Bakken gas production increased as oil production peaked and then it declined. Source: Drilling Info and Labyrinth Consulting Services, Inc.

Water cut—water as a percent of total liquid produced—has increased for most operators over time (Figure 9) and this provides additional support for progressive Bakken depletion.

Figure 9. Bakken water cut has generally increased over time. Source: Drilling Info and Labyrinth Consulting Services, Inc.

Company Performance, Break-Even Prices and Future Drilling Locations

Well performance for the 8 key operators shown above in Table 1 provides a framework for company performance and break-even prices for the Bakken play.

Reserves were estimated for more than 4,400 wells with first production in 2012 through 2015 using standard rate vs. time methods. Decline-curve analysis (DCA) was used to evaluate wells with at least 12 months of production history for key operators. Production group DCA was done separately by operator and year of first production for oil, gas and water.

Results are summarized in the following tables.

Table 2. Summary tables of key operator EUR and break-even prices and economic assumptions. Source: Drilling Info and Labyrinth Consulting Services, Inc.

None of the key operators’ average well breaks even at current Bakken wellhead prices of $42.50 per barrel although ConocoPhillips ($43.08 break-even price) is very close. EOG, XTO and Marathon all break even at prices less than $50 per barrel but other operators need higher oil prices to break even. It is worth noting that Bakken wellhead prices are about $10 per barrel less than WTI benchmark prices.

Current well density was calculated by measuring the area of the $50 commercial area (406,000 BOE cutoff) and dividing by the number of horizontal wells within that area. There are 5,500 producing wells within the 1.2 million acre commercial area shown in Figure 10. That equates to a current well density of 215 acres per well.

Figure 10. Bakken EUR map showing the $50 (406,000 BOE EUR) commercial area and well density table. Source: Drilling Info and Labyrinth Consulting Services, Inc.

Tight oil operators describe infill spacing of 40 to 120 acres per well favoring the lower end of that range. Current well density in the Bakken core of 215 acres per well suggests substantial infill locations remain yet declining EURs, increasing water cut and falling GOR do not support further infill drilling.

The Bakken is unique because of the extraordinary lengths of lateral wellbores compared with other tight oil plays. Laterals are commonly more than 10,000 feet in length and often approach 12,000 feet.

Figure 11 shows lateral lengths in the Bakken. It is clear that within the commercial core area, most laterals exceed 8,000 feet. Available evidence suggests that current well density is sufficient  to fully drain reservoir volumes. That implies that further drilling will not result in producing new oil volumes but will interfere with and cannibalize production from existing wells.

Figure 11. Bakken lateral length map. Source: Drilling Info and Labyrinth Consulting Services, Inc.

The Downside of Technology

The Bakken play represents the fullest application of modern horizontal drilling and hydraulic fracturing technologies. The Middle Bakken and Three Forks reservoirs are tight, naturally fractured sandstones that respond exceptionally well to long laterals and multi-stage fracture stimulation. Field rules allowed long laterals well before these were feasible in other plays.

The downside of efficiency and technology is that depletion has accelerated. Resulting higher initial rates masked underlying field decline that is becoming apparent only in wells with first production in 2015. The evidence for depletion is compelling but pressure data is not publicly available and is needed to complete the case.

The most appealing aspect of resource plays is their apparent lack of risk. Source rocks are the drilling target so finding oil and gas is given. Because the plays are continuous accumulations, there is no need to map and define a trap. Since the reservoirs are tight, seals are not an issue either. But commercial risk should be more of a concern for investors than it seems to be so far.

The downside is that there is no way to stay away from water and it is produced from day one in large volumes. The Bakken has produced 1.5 billion barrels of water along with its 2.2 billion barrels of oil over the decades. Where are they putting it and what does that cost?

Investors should be worried. As analysts cheered the resilience of shale plays after the 2014 price collapse, nearly a billion barrels of Bakken oil were produced at a loss–about 40% of total production since the 1960s.Vast volumes of oil were squandered at low prices for the sake of cash flow to support unmanageable debt loads and to satisfy investors about production growth. The clear message is that investors do not understand the uncertainties of tight oil and shale gas plays.

And all major Bakken producers continue to lose money at current wellhead prices. If observations presented here hold up, there may be nowhere for the Bakken to go but down. Higher oil prices may not help much because the best days for the play are behind us. Future profits were sacrificed for short-term objectives that lost the companies and their shareholders money.

The early demise of the Bakken should serve as a warning about the future of other tight oil plays.

 


*Statoil and Marathon depart somewhat from this general observation. GOR for these companies is lower than average and peaked earlier than most operators although Marathon’s GOR has been relatively flat.

Sincere thanks to Lynn Pittinger for his many useful comments during research for this post.