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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OPEC Extends Cuts, Oil Prices Fall: What It Means

OPEC extended oil production cuts last week and oil prices plunged.

OPEC’s goal was to keep a floor under current prices but the market expected the cartel to move prices higher through inventory reduction. OPEC was satisfied with greater revenues from higher prices compared to a year ago, but the market wanted deeper production cuts. OPEC takes the long view but the market is concerned with the near term. OPEC extended the cuts and the market reacted with lower prices.

Analysts have created the unfounded but widely accepted belief that OPEC has a strategy that involves a price war with U.S. tight oil producers and a play for greater market share. The cartel’s inaction before last November’s production cuts reflected an unwillingness to repeat the mistake of cutting 14 million barrels per day between 1980 and 1985 with little effect on world over-supply and financial damage for OPEC members.

OPEC’s  members have disparate needs and interests. They are not unified behind any mission statement or over-arching principles except to maximize revenues and minimize losses. IEA calculated that recent production cuts earned the cartel an additional $75 million per day year-over-year in the first quarter of 2017. It also was a gift to competitors so the idea of making deeper cuts had no cost benefit.

Last week’s price plunge was the third time in 2017 that prices have adjusted downward toward the $45 per barrel level suggested by market fundamentals (Figure 1).

Figure 1. Third Deflation of the OPEC Expectation Premium in 2017. Source: EIA, Bloomberg and Labyrinth Consulting Services, Inc.

At first, OPEC did nothing after oil prices collapsed in 2014. When prices fell to $26 per barrel in early 2016, OPEC floated the idea of a production freeze and that established a floor from which prices increased to more than $50 per barrel during the first half of the year (Figure 2).

Figure 2. Oil Markets Continue Testing $55 Ceiling & $45 Floor. Source: EIA, CBOE, Bloomberg and Labyrinth Consulting Services, Inc.

In June 2016, markets lost faith in OPEC’s resolve and prices fell from $51 to below $40 per barrel. OPEC then set another price floor by announcing tentative agreement on a production cut. When prices fell below $43 in November, another price floor was created when OPEC enacted production cuts.

The world price floor moved up almost 75% from $26 to $45 per barrel in just over a year. That looks like success to me. Production cuts were extended last week to reinforce the current $45 floor without helping the competition too much—not to meet market expectations of higher prices.

Oil traders understand this better than analysts and they began unwinding their long positions in February. Net long positions on WTI futures have fallen 25% since then but most of the sell-off has been since April 2017 (Figure 3).

Figure 3. Net Long Futures Positions Have Fallen 17% Since Mid-April 2017 and 25% Since March 2017. Source: CFTC, EIA and Labyrinth Consulting Services, Inc.

Reasons For Lower Prices

Many analysts proclaim that Brent prices will be near $65 by the end of the year. Although IEA and EIA production data suggests good OPEC compliance with the November agreement, global markets remain well supplied.  OPEC shipments to its biggest customers—the U.S. and China—are more than 10% higher than a year ago. Production cuts are not reflected in well-supplied markets nor are global inventories falling much.

Market concerns are valid that U.S. tight oil output may cancel OPEC production cuts. Despite frack crew shortages and limits to pressure pumping equipment, 2017 well completion rates appear strong in the Bakken, Eagle Ford and Permian basin plays (Figure 4).

Figure 4. Increased Tight Oil Well Completion in 2017. Source: EIA and Labyrinth Consulting Services, Inc.

OECD comparative inventory for April was approximately 300 million barrels above the 5-year average. The price vs. comparative inventory yield curve suggests that Brent is as much as $7 per barrel over-valued at $52 per barrel (Figure 5).  If recent withdrawal levels hold, it may take a year to reduce inventories to levels that support $65 Brent prices. On the other hand, EIA forecasts suggest relatively minor OECD inventory drawdowns through year-end and rising inventories in 2018.

Figure 5. Brent is ~ $7 over-valued at $52.31. Source: EIA STEO May 2017 and Labyrinth Consulting Services, Inc.

World production surpluses have been falling for the last year but EIA expects these to start increasing as early as May (Figure 6). Surpluses may persist through the middle of 2018 before decreasing again. Its forecast is for Brent prices to remain less than $60 per barrel through the end of 2018.

Figure 6. EIA Forecasts Production Surplus To Increase in the Second Half of 2017 Through the First Half of 2018. Source: EIA STEO May 2017 and Labyrinth Consulting Services, Inc.

Recent modeling by Macquarie Research supports this view and predicts sub-$60 Brent prices through the second quarter of 2019 (Figure 7).

Figure 7. Macquarie Forecasts Brent Prices Below $60 Through the Second Quarter of 2019. Source: Macquarie Research and Labyrinth Consulting Services, Inc.

Although OPEC cuts appear to be real, Macquarie sees U.S., Russia and Brazil production growth as bearish drivers on price. Maintaining OPEC cuts beyond the end of 2017 will be difficult and recent talk of selling half of U.S. strategic reserves potentially puts an additional 300 million barrels of oil on an already over-supplied market.

READ MORE ON FORBES

 

Strong Natural Gas Prices And Tight Supply In 2017

A year ago, most analysts were bearish about natural gas prices.   I wrote that natural gas prices might double and they did. Today, most analysts are again bearish about gas prices and again, I think that they are probably wrong at least for 2017.

The mainstream narrative is that new pipeline capacity—notably the Rover Pipeline—out of the Marcellus and Utica shale plays will unleash a torrent of pent-up supply. That is because over-production in these plays has saturated the northeastern U.S. markets and 2016 wellhead prices averaged about $0.88/mmBtu less than Henry Hub prices (Figure 1). New take-away capacity to higher-priced markets will fix that problem but gas prices will plummet later in 2017 because of increased output.

Figure 1. Marcellus Wellhead Prices Were $0.88 per mmBtu Less Than Henry Hub Prices in 2016. Source: MarcellusGas.Org, EIA and Labyrinth Consulting Services, Inc.

Systematic overproduction turned the northeastern U.S. from the highest-margin market to the lowest by 2013. With a second chance to at least be on par with national pricing, shale gas companies will, according to the narrative, over-produce the entire U.S. market to a loss once again. Smart.

Conventional Gas, Shale Gas and Net Imports

There are three components to gas supply: conventional gas production, shale gas production, and imports. These must be understood to establish a context for a potential supply increase from the Marcellus and Utica shale plays.

There is no doubt that low prices resulted in a 4.26 bcf/d (billion cubic feet of gas per day) decline in gas production from September 2015 through October 2016 (Figure 2).

Figure 2. U.S. Gas Production Fell 4.26 bcf/d From September 2015 to October 2016. Source EIA Natural Gas Monthly and Weekly Updates, and Labyrinth Consulting Services, Inc.

Since 2008, conventional gas production has been in terminal decline and has fallen 26 bcf/d. It is currently falling about 3 bcf/d each year. Shale gas–including associated gas from tight oil—now makes up more than two-thirds of domestic supply. That means that shale gas output must grow by more than 3 bcf/d each year to offset falling conventional supply.

But annual shale gas production growth slowed from almost 7 bcf/d in the first quarter of 2015 to less than 2 bcf/d in the first quarter of 2017 (Figure 3).

Figure 3. Shale Gas Growth Has Slowed from Almost 7 bcf/d in the First Quarter of 2015 to Less Than 2 bcf/d in the First Quarter of 2017. Source: EIA Natural Gas Weekly Update and Labyrinth Consulting Services, Inc.

If shale gas production growth doubles in 2017, then supply will be flat but considerably lower than 2015 levels when over-supply crushed gas prices. Gas supply must increase well beyond what is likely this year in order for prices to fall much below current levels of about $3.25 per mmBtu.

Considerable supply potential exists. The shale gas horizontal rig count has more than doubled—from 76 to 167 rigs—since June 2016 with higher gas prices (Figure 4). How quickly can that potential be converted into supply?

Figure 4. Shale Gas Rig Count Has More Than Doubled Since June 2016 With Higher Gas Prices. Source: EIA and Labyrinth Consulting Services, Inc.

EIA’s latest production forecast suggests that it may happen very quickly. The May STEO projects gas growth of 5.6 bcf/d in 2017 which includes an additional 3.5 bcf/d between April and the end of the year (Figure 5).

Figure 5. EIA Forecast is for a 5.6 Bcf/d Gas Production Increase in 2017 with Prices Rising to $3.43 By December. Source: EIA May 2017 STEO and Labyrinth Consulting Services, Inc.

Although that may be unreasonably aggressive, it is noteworthy that the overall supply balance (red and blue fill in the figure) remains in deficit for most of the year, and that spot prices continue to increase, ending the year at almost $3.50/mmBtu. Net imports (the third component of total supply in addition to shale gas and conventional gas) are forecast to average -0.3 bcf/d in 2017 compared to +1.7 bcf/d in 2016.

Rover Pipeline

The Rover Pipeline was certificated for construction in mid-February and will connect gas from the Utica and Southwestern Marcellus shale plays to the Defiance Hub in northwestern Ohio (Figure 6). There is a gas surplus (~1.8 bcf/d) in Ohio so this pipeline is a gas exit route to the Dawn Hub in Ontario, and to the Midwest and Gulf Coast via interconnecting Vector, Panhandle Eastern and ANR pipelines. There, it will compete with existing supply and result in lower prices.

Figure 6. Rover Pipeline Route Connecting Utica and Southwestern Marcellus Shale Plays With the Defiance Hub. Source: Energy Transfer and Labyrinth Consulting Services, Inc.

Although Rover is scheduled to reach Defiance in November, it is unlikely that any gas will move beyond there before 2018. It will not, therefore, have any effect on gas supply in 2017. Depending on how much gas ultimately is sent to Canada, it may have limited effect on U.S. supply in 2018.

What Could Go Wrong?

The consensus of experts has been consistently wrong about natural gas supply for decades. That’s why LNG import terminals were built following gas shortages in the 1970s only to be shuttered after imports from Canada, fuel switching to coal and nuclear, and gas industry deregulation resulted in 15 years of stable gas supply.

By the early 2000s, import terminals were re-opened as Canadian gas production began to decline and domestic output failed to rally even with much higher gas-directed rig counts. The shale revolution ended all of that and now, those import terminals are being re-designed to export LNG. Gas export will likely prove to be fully out-of-phase with future gas supply once again.

That is why I am skeptical when experts now declare an impending gas over-supply. Gas prices remain well above $3/mmBtu after one of the warmest winters on record, and most data suggests that supply will remain tight at least through the end of 2017.

What could go wrong with that hypothesis? Weather, of course, and Morgan Stanley has astutely pointed out that 2016 rainfall in California may displace some natural gas with hydro for electric power generation. They and PointLogic note that some cooler summer forecasts might further reduce gas demand.

At the same time, EIA expects higher-than-average consumption for Summer 2017 (Figure 7) and the Browning World Climate Bulletin predicts a warmer-than-average summer with early El Niño onset.

Figure 7. EIA Forecasts Higher-Than-Average Consumption for Summer 2017. Source: EIA May 2017 STEO and Labyrinth Consulting Services, Inc

Morgan Stanley supposes that associated gas from tight oil plays will be a major factor in increased gas supply. This ignores the considerable  dysfunction in the pressure pumping business where frack crews commonly lag demand by at least 6 months. Rig count increases will probably not translate into production gains as quickly as many oil-price bears assume. Gas pipelines out of the Permian basin remain problematic and most gas from the Eagle Ford will go to Mexico.

Morgan Stanley’s belief that significant expansion of production in the Haynesville Shale will occur is based on incorrect sub-$3.00 break-even prices. Exco–the second largest Haynesville producer–shows a maintenance spending level of about $3.50 in their 2016 10-K after writing off all proved undeveloped reserves in accordance with the SEC 5-year rule.

It also seems unlikely that losses in major gas-producing areas including Texas, Oklahoma, Wyoming, Arkansas, Utah, Louisiana and the OCS Gulf of Mexico will be quickly offset by gains in Ohio, Pennsylvania and West Virginia especially considering frack crew availability (Figure 8).

Figure 8. Unlikely That OH, PA & WV Gains Will Offset TX, OK, WY, AR & OCS Losses in 2017. Source: EIA and Labyrinth Consulting Services, Inc.

Comparative inventories indicate that the mid-cycle price trend has moved upward from $3.00 to $3.60 (or higher) since mid-March reflecting market perception of tight supply (Figure 9). The mid-cycle price—where the trend line intersects the y-axis—represents the median price that the market deems necessary to maintain supply throughout the present price cycle. If this trend persists, it is possible that year-end gas prices will be in the $3.50 to $4.00 range.

Figure 9. Gas Mid-Cycle Price Has Shifted To $3.60/mmBtu or Higher. Black arrows show progression from higher to lower price trend and back again. Source: EIA and Labyrinth Consulting Services, Inc.

At the same time, it is likely that prices will be substantially lower in 2018 once the Rover and other pipelines are operating and frack crews begin catching up with drilling levels. That possibility is reflected in inverted natural gas forward curves (Figure 10). Note that the price for futures contracts drops sharply in January 2017.

Figure 10. Henry Hub Forward Curves Are Inverted and Rising. Source: CME and Labyrinth Consulting Services, Inc.

Although forward curves should never be viewed as a price forecast, they reflect current market expectations. Those expectations seem clear and are supported by all available data: natural gas supply should remain fairly tight through 2017 and will probably increase some time in 2018 and that will result in lower gas prices. Understand the uncertainties and plan accordingly.

 

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.