Natural gas storage inventories increased 84 Bcf for the week ending August 30, according to the EIA’s weekly report. This is higher than the market expectation, which was an injection of 76 Bcf.
Working gas storage inventories now sit at 2.941 Tcf, which is 383 Bcf above inventories from the same time last year and 82 Bcf below the five-year average.
Prior to the storage report release, the October 2019 contract was trading at $2.426/MMBtu, roughly $0.019 lower than yesterday’s close. However, prices continued to fall post report, and at the time of writing were trading at $2.400/MMBtu.
Since last Thursday, prices have gained ~$0.10/MMBtu. The main driver of the price increase is the weather forecast. September temperatures are expected to be above average in the South/South Central, driving higher than normal power burn demand. Additionally, Hurricane Dorian shifted course as the storm headed toward the lower 48. Dorian, which made landfall in the Bahamas last weekend, then turned north to move up the East Coast. This change in path caused less rain and cooling in the southeastern portion of the US, and didn’t impact power demand as drastically as if the storm had trended inland. In the coming days, Dorian is expected to bring wind and rain to the Carolinas before traveling back into the Atlantic.
See the chart below for the projections of the end-of-season storage inventories as of November 1, the end of the injection season.
This Week in Fundamentals
The summary below is based on Bloomberg’s flow data and Enverus analysis for the week ending September 5, 2019.
- Dry production didn’t see much movement week over week, decreasing 0.03 Bcf/d on the week.
- Canadian imports increased 0.39 Bcf/d on the week.
- Domestic natural gas demand gained 1.22 Bcf/d week over week. Power demand accounted for nearly the entire change in demand week over week, increasing 1.22 Bcf/d. Res/Com demand decreased 0.01 Bcf/d, while Industrial demand gained 0.02 Bcf/d.
- LNG exports fell 0.44 Bcf/d, mainly due to decreased exports at Sabine Pass. Mexican exports remained relatively flat on the week, gaining only 0.05 Bcf/d.
Total supply increased 0.36 Bcf/d, while total demand increased 0.88 Bcf/d week over week. With demand outpacing supply, expect the EIA to report a slightly weaker injection next week. The ICE Financial Weekly Index report is currently expecting an injection of 82 Bcf. Last year, the same week saw an injection of 69 Bcf; the five-year average is an injection of 78 Bcf.
US crude oil stocks posted a decrease of 4.8 MMBbl from last week. Gasoline and distillate inventories decreased by 2.4 MMBbl and 2.5 MMBbl, respectively. Yesterday afternoon, API reported a crude oil build of 0.4 MMBbl, while reporting gasoline and distillate draws of 0.88 MMBbl and 1.2 MMBbl, respectively. Analysts, to the contrary, were expecting a crude oil draw of 3.5 MMBbl. The most important number to keep an eye on, total petroleum inventories, posted a decrease of 4.9 MMBbl. For a summary of the crude oil and petroleum product stock movements, see the table below.
US crude oil production decreased 100 MBbl/d last week, per the EIA. Crude oil imports were up 0.9 MMBbl/d last week, to an average of 6.9 MMBbl/d. Refinery inputs averaged 17.4 MMBbl/d (27 MBbl/d less than last week’s average), leading to a utilization rate of 94.8%. Prices extend gains due to larger than expected crude draw and total petroleum stocks withdrawal. Prompt-month WTI was trading up $1.18/Bbl, at $57.44/Bbl, at the time of writing.
Prices had a busy week and continued their volatility as the market kept its focus on the developments and news regarding the US-China trade tensions, global economic health and data, and eroding crude demand led by a weakening economic growth. Prices bounced up to their highest of the week last Thursday, only to give up most of their gains before the long weekend due to strengthening of the US dollar. The decline in prices continued as crude futures sank more than 2% on Tuesday, due to the US starting to impose 15% tariffs on some Chinese imports Sunday, while China began placing new duties on US crude oil. Also supporting bearish sentiment and bringing prices down was the US manufacturing data showing activity in August falling for the first time in three years and the lingering fears about a global recession.
Although the overall gloomy economic outlook and the ongoing trade war between the world’s largest economies still persists, the positive news from China’s services sector caused a surge in prices on Wednesday. Oil prices rose more than 4% on Wednesday along with global markets after a private survey showed that activity in China’s services sector grew at the fastest pace in three months in August. Also supporting prices was a possible sign of easing tensions from the Middle East, as Iran stated that Tehran would free seven crew members from the detained British-flagged tanker that was seized by Iran in retaliation for Britain’s previous detention of an Iranian tanker.
Despite the brief support provided by positive news from China’s services sector, the overall global economic outlook remains dim and troublesome as the trade tension between the US and China continues to linger and progressively worsen due to tit-for-tat tariffs imposed by both countries. The supply side unfortunately does not provide too much support to prices either, despite the historical low productions from Iran and Venezuela and the OPEC+ countries’ continuing efforts to reduce supply. OPEC is set to meet on September 12 in Abu Dhabi. Although the market is very much focused on the impact of the US-China trade war on the economy and oil demand, developments from this meeting will be closely watched, as the IEA has already given signals that without further supply reductions, an oil supply glut could resurface again in 2020.
The recent range between $53.00 and $58.00 may hold in the coming week without developments in the US and China trade war, while the long-term range between $50.00 and $61.00 will likely hold without similar developments. China’s attempt to bring tariffs on US crude imports may indicate a shift to utilize Iranian imports. Prices would be pressured if Iran were to increase output because of demand from China or a nuclear deal with France. The market will trade around the news event or Twitter feeds in the coming week, but also will keep an eye out for any news regarding supply cuts from the OPEC meeting.
Petroleum Stocks Chart
Recent commissioning activity on the Kinder Morgan’s new Gulf Coast Express (GCX) project led to a small increase in natural gas deliveries from producers in the Permian Basin. What does that signal for these producers over the short- and long-term? To determine the answer, we used our ProdCast natural gas, crude, and NGL production forecasting software, part of our MarketView FundamentalsⓇ (MVF) solution suite, to compare various growth scenarios versus progress-to-date on GCX and other projects to forecast what producers can expect.
The result: the region likely faces difficult pricing through 2022. Producers will remain hamstrung by pipeline capacity constraints, and it will be at least three years until a number of proposed projects bring permanent relief.
GCX did bring some relief to producers last month. As my colleague Bert Gilbert explained in his recent post, Enverus’ analysis of infrared data collected from NOAA’s Visible Infrared Imaging Radiometer Suite (VIIRS) platform reveals that while August may have been a record month for flaring in the Permian Basin, it also indicates the GCX will have a direct impact in reducing in Permian flaring.
In terms of short-term deliveries, daily natural gas meter flow data from Enverus shows that El Paso Natural Gas began delivering to GCX around Aug. 12, and has averaged ~300 MMcf/d since.
Source: Enverus Trading & Risk
As a result, cash prices at Waha are now trading north of $1.00/MMBtu, an improvement from the negative settlements seen in the first week of August.
However, ProdCast shows that while this upward trend will continue, progress will be slow. Very slow.
Traders eyeing the forward markets at Waha in 2021 and 2022 are wise to have a skeptical bias due to the risks of returning to this negative price territory.
This chart shows the current ProdCast “base-case” forecast for natural gas production, as well as a “high-case” scenario driven by a 20%t improvement in IP rates.
Three of the announced projects have reached Final Investment Decision (FID), which is a clear indication that the project has the financial backing secured to reach completion:
- Gulf Coast Express (1.98 Bcf/d)
- Permian Highway (1.9 Bcf/d)
- Whistler (2.0 Bcf/d)
In the high-case scenario, all three expansion projects are necessary to relieve bottlenecks, which would come in late 2021. However, even in the base case, although the Permian Highway project would provide temporary relief, Whistler must come online to prevent return of constraints in 2022. The fact that three planned projects – Pecos Trail, Bluebonnet, and Permian to Katy (P2K) – have been suspended or delayed due to inability to reach FID will only exacerbate the issue.
We will present our full analysis in the latest FundamentalEdge Market Outlook, our monthly proprietary market forecast report that delivers supply/demand analysis and forward-looking predictions five years out for crude, natural gas, and NGL market.
Follow this link to access the full report.
Recent commentaries on the magic of the Permian miracle have had some dark musings about how the Permian is beginning to “stall.”
Given all the back and forth in the investment community about “capital discipline” and output growing supply to the detriment of pricing, I thought I’d take a brief look at Estimated Ultimate Recovery (EUR) growth in the Delaware Basin to read the tea leaves.
On a very gross level, median oil EUR across all reservoirs has improved year-over-year as shown below (EUR binned by year of first production, EUR data from Wellcast).
A look at all wells identified by landing zones, with enough months of production to support reasonable EUR calculations over time, looks like this:
The trend is pretty clear—by and large, well EURs have improved over time, although it looks as over the past 12-18 months the uptrend in improvements has moderated. This is probably due to downspacing and the potentially negative effects of parent-child well interference.
Note however, that starting in early 2016 the number of wells that significantly outperformed the median values increased (outlined in red above). This “breakout” of superior performance may be a harbinger of better returns to come—unless the cumulative production values are actually stacked well reporting.
The distribution of wells binned by EUR greater than 500,000 and 1 million Bbl shows year-over-year improvement, but with less acceleration year-over-year for 2017-2018.
If we look at a graph of EUR distributions by reservoir, we get what you see below:
This shows that for the landing zone assignments in Wellcast (Bone Spring Second Sand, etc.) there are relatively smooth distributions of EUR values for all mapped reservoirs, although some reservoirs have been preferentially targeted by operators. For example, the Wolfcamp A Lower has been the most preferred drilling target.
The story of improving EURs over time is generally true at the reservoir level.
Graphing sample size, number, and percentage of wells with greater than 500,000 BO EUR and greater than 1 million BO EUR, it’s clear that some reservoirs deserve the higher drilling densities they’ve seen. The percentage of wells with EURs greater than 500,000 Bbl or even 1 million Bbl is significant. The Wolfcamp Lower A saw 54% of wells with oil EURs of 500,000 Bbls or better, and 15% of well with oil EUR of 1 million Bbl or more.
We can focus on the Bone Spring Second Sand and the Wolfcamp A Lower for a bit of added insight.
Over time, Bone Spring Second Sand EURs have steadily improved, although moving into 2019 there’s a hint of a drop off.
As might be expected, early engineering practices improved over time to deliver growing EUR valuations. Starting around the end of 2016 into early 2017 we began to see wells with exceptional outlier EUR values (circled in pink).
We see the same behavior in the Wolfcamp A Lower.
I attempted to see if there was a generic explanation for the exceptional EUR outliers hidden within the engineering data—lateral length vs. total proppant vs. total fluid, etc.
Both the Bone Spring Second Sand and Wolfcamp A Lower show year-over-year increases in the lateral length drilled, the amount of proppant, and the amount of fluid deployed in completions.
Bone Spring Second Sand EUR as a function of lateral length shows that two lengths—5,500 to 7,000 feet and 8,500 to 9,500 feet, are likely to limit the number of wells with EUR values greater than 700,000 Bbl. However, there’s clear trend toward higher EUR with increased lateral length.
Wolfcamp A Lower EURs also show an increase of EUR with lateral length, but the trend is more subdued, with excellent “outlier” EUR values (2 MMBBL or higher) occurring over the range of 6,000 to 10,000 feet. Laterals longer than 13,000 feet generally yield EUR values that are closer to the median reservoir value.
There’s clearly a positive correlation for increased EUR with both total proppant and total fluid in the Bone Spring Second Sand.
However, there is less of a correlation between total proppant and EUR for the Wolfcamp A Lower.
This is probably best explained by stratigraphy—the Bone Spring Second Sand is encased between two carbonate benches that inhibit frac jobs from exiting the Bone Spring Second Sand. This concentrates all the frac job power within the target.
The Wolfcamp A Lower is more than 500 feet thick, is interbedded, and is not bounded by focusing carbonate benches above it and below it, meaning frac jobs are a bit more likely to disperse their energy away from the target being drilled.
Until the spacing “secret sauce” is better understood, accounting for offset interference and variables in engineering and completion practices (and hopefully, geology) to define variables with better than .6r correlation coefficients with EUR will be a challenge.
However, given the steady increase of EUR values—both basin-wide and by reservoir, as well as hints that exceptional outlier values may become the next EUR “norm,” it’s premature to claim that Permian output is declining.
Have a perspective on EUR values?
Please send me a message at firstname.lastname@example.org.
(Note: EUR data and landing zone play identification names were obtained from the Enverus Drillinginfo Wellcast product. Only wells with six months or more of production history were included in the analysis.)
The US has become the largest producer and exporter of propane. Despite this growth, some parts of the US are still importing the heating and cooking fuel. This dislocation is caused by the Jones Act, a federal law passed in 1920 requiring goods shipped between US ports to be transported on US-built ships and operated by US crews.
Over the past 10 years, US production of propane and other natural gas liquids (NGLs), such as ethane and butane, has surged, making the US the world’s largest producer of NGLs. Without a concurrent increase in domestic demand, the US has seen a marked increase in exports, becoming the world’s largest exporter of propane. Propane, along with butane, is referred to as liquefied petroleum gas (LPG), and these hydrocarbons are transported on LPG tankers.
Despite the growth in US exports, some parts of the US are still importing propane. Without any Jones Act-compliant tankers to carry LPG (or LNG for that matter), the only option for Hawaii and Puerto Rico and others is to look abroad. This is also the case for areas without pipeline or rail capacity to deliver the fuel to local markets, such as in New Hampshire. Hawaii and Puerto Rico receive propane cargoes throughout the year to fulfill demand for cooking fuel and other applications, while New Hampshire’s demand is more seasonal, as the fuel has replaced oil for heating purposes.
The observed imports of propane were sourced from a variety of locations. New Hampshire’s Blackline Midstream terminal in Newington sourced propane from Norway and West Africa for its recent imports. Puerto Rico has recently imported propane from Trinidad as well as Equatorial Guinea.
Many customs manifests list their origin point as the Dominican Republic, including the most recent cargoes arriving to Hawaii aboard the LPG tanker Pertusola. The Dominican Republic does not produce a significant amount of hydrocarbons, and those manifests are explicit in that the origin of their cargo is Equatorial Guinea. That cargo was transferred to the Pertusola by the LPG tanker BW Empress, floating offshore of the DR in Ocoa Bay. AIS data from VesselTracker, analyzed by Enverus, suggests that the transfer occurred around June 16, after the Pertusola discharged a cargo from Sunoco Logistics’ Marcus Hook terminal near Philadelphia at the San Pedro De Macoris terminal east of San Juan. The BW Empress is still positioned in Ocoa Bay and is involved in the transshipment of propane from larger tankers arriving from the US and other locations such as Equatorial Guinea onto smaller tankers capable of delivering to ports around the Caribbean. The Pertusola traveled through the Panama Canal and proceeded to Hawaii, where it has since discharged at various islands in the state.
Hawaii’s propane imports are probably the best example of the dislocations caused by the Jones Act in the propane market. Much of the state’s supply in 2018 originated from Trinidad, but production is on the decline in that country. Since the end of 2018, Hawaii has received propane from Argentina as well as cargoes originated in areas such as Equatorial Guinea that were transferred to tankers offshore of the Dominican Republic, similar to the tanker Pertusola mentioned above.
While Hawaii sources propane from offshore West Africa, millions of barrels of US propane are passing by the state every month as they head to Asian markets. The map to the right shows the tracks of tankers loaded with US propane and butane from Enterprise’s Houston and Targa’s Galena Park terminals as they head through the Pacific to destinations in South Korea, Japan, and China.
With no LPG tankers under construction in the US, these dislocations are likely to continue, limiting the ability of US citizens in Hawaii and Puerto Rico, and even New England, to benefit from the shale boom in the same way as citizens of other countries.