Prices Slip From Six-Month Highs With Large Crude Oil Inventory Build

Prices Slip From Six-Month Highs With Large Crude Oil Inventory Build

US crude oil stocks posted an increase of 5.5 MMBbl from last week. Gasoline and distillate inventories decreased 2.1 MMBbl and 0.7 MMBbl, respectively. Yesterday afternoon, API reported a crude oil build of 6.9 MMBbl while reporting a gasoline build of 2.2 MMBbl and a distillate draw of 0.87 MMBbl. Analysts, to the contrary, were expecting a crude oil draw of 0.5 MMBbl. The most important number to keep an eye on, total petroleum inventories, posted a large increase of 8.8 MMBbl. For a summary of the crude oil and petroleum product stock movements, see the table below.

US crude oil production increased 100 MBbl/d last week, per the EIA. Crude oil imports were up 1.16 MMBbl/d last week, to an average of 7.1 MMBbl/d. Refinery inputs averaged 16.6 MMBbl/d (505 MBbl/d more than last week), leading to a utilization rate of 90.1%. The crude oil and total petroleum stocks build stopped the price rally and pushed prices down below $66/Bbl. Prices are still getting support from the US government’s decision to cancel Iranian sanction waivers and the unrest in Libya potentially threatening the country’s supply levels. Prompt-month WTI was trading down $0.38/Bbl, at $65.92/Bbl, at the time of writing.

Prices have been rising and rallied to their six-month highs at the beginning of the week, breaking through the $66/Bbl mark on Tuesday. The sharp increase in prices was due to the US government’s decision to drive Iran’s crude exports to zero. The tightening global supply levels and situation in Libya also supported prices.

Prices pierced $66/Bbl after the Trump administration announced that it will not extend sanction waivers to certain countries that import Iranian oil, as well as announcing that all Iranian oil buyers will have to end imports from Iran in about a week or be subject to US sanctions. The Trump administration’s announcement certainly increased the bullish sentiment, as cancellation of waivers can erase as much as 1 MMBbl/d of additional supply in a market that has already been tightening due to OPEC-led supply cuts and declining production in Venezuela. Escalating tensions in Libya continue to threaten supply levels in the near term.

The US government’s goal of reducing Iran’s exports to zero and its latest announcements certainly have increased the possibility of a supply deficit and triggered the price rally. However, this rally may be temporary, as there were already discussions between OPEC and Russia about possibly not extending the supply cuts into the second half of the year, with a potential scenario of increasing the supply levels. After the Iranian sanctions announcement, the OPEC meeting in June becomes even more important, as OPEC (led by Saudi Arabia) and Russia may decide to fill the gap created by the reduction in Iranian and Venezuelan supply levels and try to grab market share from the United States, as the US is showing no signs of slowing down, instead continuously ramping up production. Another risk to prices will be the execution of Iranian sanctions, as Iran already retaliated by threatening to close the Strait of Hormuz, a crucial shipping lane in the global oil trade, which could cause disruptions and be detrimental to global supply levels.

The US government’s announcement on canceling waivers and bringing Iranian exports to zero took prices between $65/Bbl and $68/Bbl range (an area of consolidation from last fall during the price collapse) as previously mentioned here. The market will need further bullish headlines to break through this range whether from further news on sanctions or any supply disruptions from Libya. In the meantime, the possibility of OPEC and Russia ending the supply cuts and potentially increasing supply levels to replace the Iranian and Venezuelan crude, increasing US production and a gloomy global economic and demand growth outlook will keep the pressure on prices. If Iranian sanctions are not fully executed, get lash back or are denounced by countries with waivers at the same time if OPEC decides to end the supply cuts and increase output, prices could trace back to the $60/Bbl range, especially given the weak demand growth projections.

Petroleum Stocks Chart

Concerns about OPEC-Led Cuts Possibly Not Extending Pressure Prices Despite Crude Withdrawal

Concerns about OPEC-Led Cuts Possibly Not Extending Pressure Prices Despite Crude Withdrawal

US crude oil stocks posted a decrease of 1.4 MMBbl from last week. Gasoline and distillate inventories decreased 1.2 MMBbl and 0.4 MMBbl, respectively. Yesterday afternoon, API reported a crude oil draw of 3.1 MMBbl alongside a gasoline draw of 3.6 MMBbl and a distillate build of 2.3 MMBbl. Analysts, to the contrary were expecting a crude oil build of 1.7 MMBbl. The most important number to keep an eye on, total petroleum inventories, posted an increase of 2.5 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 down 0.60 MMBbl/d last week, to an average of 6.0 MMBbl/d. Refinery inputs averaged 16.1 MMBbl/d (22 MBbl/d less than last week), leading to a utilization rate of 87.7%. The crude oil inventory draw and China’s first quarter GDP showing a growth gave support to prices. Also supporting prices is the unrest in Libya potentially threatening the country’s supply levels. Russia’s statements on abandoning supply cuts and potentially increasing output for second half of the year is pressuring prices. Prompt-month WTI was trading up $0.11/Bbl, at $64.16/Bbl, at the time of writing.

Prices retracted back from their five-month highs, but still traded in the $63/Bbl-$64/Bbl range last week as tightening supply market and the bearish news on supply cuts for the second half of the year pulled prices in both directions. The move up to near the $65/Bbl mark last week was mainly due to news about Libya and the possible impact of fighting on the country’s crude production levels, bringing supply further down in an already tightening market due to declines in Venezuela and Iran.

The price increase due to news from Libya last week were offset by the fears of a slowdown in global economic growth and Russia’s remarks on supply cuts. The US government announcing tariffs on European goods and the IMF lowering its economic growth forecast both increased the fears about global economic outlook while Russian Energy Minister Alexander Novak’s remarks on the extension of supply cuts into second half of the year being unnecessary put uncertainty what OPEC+ may decide in their upcoming meeting in June.

Bearish sentiment and pressure on prices increased at the start of the week due to concerns about OPEC-led supply cuts potentially not being renewed for the second half of the year. The concerns began after Alexander Novak’s comments last week and reached a new level on Monday after Russian Finance Minister Anton Silunav was quoted by Russian TASS agency as saying that OPEC and Russia could decide to abandon the deal and boost production to fight for market share with the United States. Although tightening supply levels, due to declining Venezuelan and Iranian production, as well as the renewed fighting in Libya support the bullish sentiment, the recent news from Russia certainly put some question marks on supply/demand levels for the second half of the year. Increasing US production and gloomy global economic and demand growth will continue to pressure prices, and this pressure can intensify given any other bearish news on supply cuts from Russia and OPEC.

Last week, WTI prices gave their first indication that the price run may follow a more traditional bullish extension. While trading higher early in the week, prices respected the bearish inventory numbers from the EIA and the headline news and promptly started to retrace some of the week’s gains. The $0.50 decline in WTI during the last 45 minutes of trade on Friday is an indication that some of the bullish elements are taking profits on short-term gains. This profit activity is part of a bull market behavior pattern. Participants need to collect profits before adding to additional commitments, and this usually leads the market to periods of consolidation that have been discussed before. The key this week is how far the declines will go before bullish participants add to existing positions. Further extensions taking prices between $65/Bbl and $68/Bbl (an area of consolidation from last fall during the price collapse) will require more bullish headlines and will likely run into selling. The market will closely watch any news surrounding Iranian sanctions, Libyan supply levels, OPEC-led supply cut news, and US-China trade talks. Any slight shift in sentiment due to fundamentals or bearish news could cause a consolidation phase, with a potential retracement back to the $60/Bbl range.

Petroleum Stocks Chart

The Week Ahead For Crude Oil, Gas and NGL Markets – Apr 15, 2019

The Week Ahead For Crude Oil, Gas and NGL Markets – Apr 15, 2019

CRUDE OIL

  • US crude oil inventories posted an increase of 7.0 MMBbl last week, according to the weekly EIA report. Gasoline and distillate inventories decreased 7.7 MMBbl and 0.1 MMBbl, respectively. The total petroleum inventories showed an increase of 4.1 MMBbl. US crude oil production remained the same as the previous week, per EIA. Crude oil imports were down 0.16 MMBbl/d to an average of 6.6 MMBbl/d versus the week prior.
  • WTI opened last week by extending prices higher based on news from Libya that the Libyan National Army launched a campaign to take control of Tripoli, suggesting lower production due to the unrest. This news supported the price rally, along with continued supply reductions from OPEC and non-OPEC participants.
  • Despite the positive bias early in the week, prices started to digest some of the negative elements of the current market as the week progressed. First and foremost was the news that Russian Energy Minister Alexander Novak announced that supply cuts would be unnecessary if the market was expected to be balanced in the second half of the year. This news was met with more negative news, including that the US government may impose tariffs on European goods and the IMF is lowering its global economic growth forecast. The economic announcement regarding growth brought the market back to the reality of how precarious the recent gains remain long term.
  • The CFTC report (positions as of April 9) continued the recent trend with the speculative commitment aiding the recent gains. The Managed Money long component increased length by 26,149 contracts, while the Managed Money short component covered 8,207 contracts. Evidence continues to build that the speculative bulls are adding positions on any type of retracement in spite of another bearish inventory report. The report also identified the Merchant Short position (producers hedging) increased by 38,977 contracts and the refiners (hedging input costs) increased by 30,908 contracts. The refiners increasing their hedges reflects a respect for the recent gains and the bullish condition of a market that continues to rise even when the data affecting the market is bearish.
  • Last week’s close ($63.76) was the sixth consecutive higher close and confirms the bullish sentiment that the WTI maintains. Market internals reflect the bullish bias, with the momentum indicators being bullish but nearing overbought levels. The volume was significantly stronger last week than the previous week, with a significant amount of the increase on Monday. Open interest showed some gains, which is important as these two elements — volume and open interest gains while prices rise — are required for any sustained run in prices.
  • Last week WTI prices gave their first indication that the price run may follow a more traditional bullish extension. While trading higher early in the week, prices respected the bearish inventory numbers from the EIA and the headline news and promptly started to retrace some of the week’s gains. The $0.50 decline in WTI during the last 45 minutes of trade on Friday is indication that some of the bullish elements are taking profits on short-term gains. This profit activity is part of a bull market behavior pattern. Participants need to collect profits before adding to additional commitments, and this usually leads the market to periods of consolidation that have been discussed before.
  • The key this week is how far the declines will go to support before bullish participants add to existing positions. Further extensions taking prices between $65 and $68 (an area of consolidation from last fall during the price collapse) will likely run into selling. Some of that selling was from US producers, and this behavior is likely to continue on price runs allowing the US producer access to higher-priced hedges. Should prices continue a consolidation phase for WTI trade, a potential retracement to the breakout area around $60.00 should be expected.

NATURAL GAS

  • Natural gas dry production decreased 0.85 Bcf/d, with the majority of the losses coming from Louisiana (-0.42 Bcf/d). Canadian imports decreased 0.21 Bcf/d.
  • Res/Com demand fell 8.27 Bcf/d, while Power and Industrial demand dropped 0.41 Bcf/d and 1.23 Bcf/d, respectively. LNG exports fell 0.26 Bcf/d on the week, while Mexican exports increased 0.10 Bcf/d. For the week, total supply fell 1.34 Bcf/d, while total demand dropped 10.43 Bcf/d.
  • The storage report last week came in with reclassifications and showed an implied flow of 29 Bcf and a net flow of 25 Bcf. Total inventories are now 183 Bcf below last year and 485 Bcf below the five-year average. Based on supply and demand fundamentals, a larger injection is expected this week.
  • The CFTC report (as of April 9) showed the Managed Money long sector reducing positions by 16,130 contracts while the short position increased by 6,204 contracts. This continues the trend of the last few weeks, which has the long traders reducing positions on rallies while the short trade adds to short positions. Should the shorts continue to pressure prices lower, long-term support is just below current prices, and the historical calendar (prices rise during Q2) does not favor declines into May and June.
  • Market internals are developing a bearish bias from neutral the previous week. Prices traded in a smaller range ($0.078) and closed $0.004 below the previous week’s close. Volume increased week over week, and open interest showed a strong gain over the previous week. While total open interest is below historical levels, it does not deny the potential for a directional bias to price movement. Last week’s gains could be construed as the beginning of a short-term directional bias.
  • Last week’s failure to break above the previous week’s high signals that the market has little or no interest in higher prices. Accordingly, a test of major support (over three years) that exists in a well-defined range between $2.522 and $2.560 should be expected in the coming weeks. That said, historical price action allows that the lows in late winter (usually February through April) are established prior to prices firming, as the market enters the primary injection season and the summer power-demand period. If this market is headed for a test of the well-defined support, it is likely to occur before the end of the month. Consider the recent weekly highs between $2.729 and $2.733 to find sellers during the coming week.

NATURAL GAS LIQUIDS

  • ONEOK’s Elk Creek pipeline is expected to be completed by year-end 2019. This pipeline will run from ONEOK’s Riverview terminal in eastern Montana to its facilities in Bushton, Kansas, and is expected to bring an additional 240 MBbl/d to the Conway area. However, when Elk Creek hits the market, downstream fractionation and purity product takeaway at Conway will likely become an issue, as few frac and pipeline projects are expected to come online.
  • Prices were up across the board last week. The largest percentage increase was ethane, which jumped 8.3%, or $0.018, to $0.231. This jump was followed by propane, which was up $0.029 to $0.646, normal butane up $0.023 to $0.767, natural gasoline up $0.030 to $1.309, and isobutane up $0.008 to $0.771.
  • US propane stocks increased ~1.2 MMBbl the week ending April 5. Stocks now sit at 54.4 MMBbl, roughly 18.5 MMBbl and 14.0 MMBbl higher than the same week for April 2018 and April 2017, respectively.

SHIPPING

  • Based on customs manifests, weekly waterborne crude imports are quite low this week, especially to PADD 3, which is only slightly higher than 1 MMBbl/d. Imports to Houston increased to the highest level since mid-February, but that was overshadowed by declines at Corpus Christi, Lake Charles, Mobile, Pascagoula, and Texas City. No bills of lading were filed for arrivals to Morgan City, which is the delivery port for LOOP cargoes. PADD 1 imports were close to 320k bbl/d, while PADD 5 was at 596k bbl/d. PADD 3 crude imports from Iraq were at zero for the second time since mid-March, but only the fifth time since the beginning of 2017.

Chevron breaks A&D Logjam with $50 billion Anadarko buy

Chevron breaks A&D Logjam with $50 billion Anadarko buy

“Coming on the heels of a record low quarter for U.S. M&A activity of a paltry $1.6 billion, Chevron stepped up to the plate with a $50 billion deal to acquire Anadarko,” noted Drillinginfo M&A Analyst Andrew Dittmar.

The offer of $65/share (75% equity, 25% cash) represents a 37% premium to Anadarko’s prior-day close and the deal value of $50 billion consists of $33 billion is cash/stock plus $15 billion in net debt assumed plus $2 billion of book value on non-controlling interest.

“The deal appears to be well received by Wall Street, reversing a trend seen in Q4 2018 that showed buyer’s stock trade down significantly with deal announcements.  Chevron is currently trading down a minor 5% on the news” added Dittmar.

The deal is the sixth largest deal in oil and gas history and the largest deal since Shell bought BG for $82 billion in 2015 to become a global LNG powerhouse.

“Clearly, a large driver of the deal is Anadarko’s prized position in the Delaware Basin where Chevron increases its position by 240,000 net acres to over 1,400,000 net acres.  The Delaware Basin currently provides the best well economics of any shale play in the country” said Dittmar.  Drillinginfo analysis indicates about $12 billion of the $50 billion purchase price is attributed to the Delaware Basin acreage or approximately $50,000 per acre. Chevron also acquires world class midstream assets that includes 12,509 miles of pipeline that tie to key US supply basins.

 

Delaware Basin Strategic Acreage Positions

 

 

Beyond the Permian, Chevron gets overlapping operations in Colorado’s DJ Basin and the deepwater Gulf of Mexico.  In Africa, Chevron establishes new valuable positions in Mozambique, Algeria and Ghana that complement Chevron’s existing positions across Africa.  The acquired Mozambique asset is a world class gas asset that is underway for full scale global LNG development.

“This blockbuster deal portends to jumpstart further consolidation within the Permian Basin and the US shales in general.  As these shales become further de-risked and companies move to full development mode, scale matters. Drillinginfo expects this deal to be the start of further consolidation with the US shales and specifically within the Permian Basin” Dittmar concludes.

IMO 2020 – Potential Impacts and Coker Refinery Case Study

IMO 2020 – Potential Impacts and Coker Refinery Case Study

On January 1st, 2020, the global shipping industry will undergo a radical change, with all ships having to reduce the sulfur content within marine fuels from 3.5% to 0.5%, as mandated by the International Maritime Organization (IMO). As with all radical changes, winners and losers await, meaning there is significant opportunity everywhere.

In this paper, DrillingInfo uses a refinery optimization model to look at the potential effects of this regulation for a single complex refinery with a delayed coking unit.


What does the change mean for refineries?

Bunker fuel provides a valuable outlet for refineries as it has the highest sulfur content specification out of the major refinery products. The heavy bottom of the barrel fractions that have too much sulfur content to become diesel (0.0015% maximum sulfur content), No.2 oil (0.05%), or light sulfur fuel oil (1%) can still generate revenue as long as they meet the 3.5% specification for marine fuel in non-emission control areas (ECAs). Furthermore, the markets for light sulfur fuel oil and other relatively high-sulfur products are small compared to that of 3.5% bunker fuel (Figure 1) so as the new specification takes effect there will not be another “release valve” for high-sulfur fractions above the 0.5% threshold.

With the new IMO specification, the residual fractions that used to go into marine fuels will largely become waste unless they can be further processed and desulfurized. Refineries with delayed coking units stand to benefit from this change as they have the capability to process these fractions into other products, which most refiners lack.


What does a single refinery model look like?

The most standard refinery processing unit is an atmospheric distillation unit (ADU), which separates crude oil into different fractions depending on their volatility. This is the process which splits crude oil into the gases, naphthas, kerosene, gas oils, and residues that it consists of. The yields of these fractions, expressed as a percentage of the crude oil input, and their physical properties, including sulfur content among others, can vary greatly between different crude oil assays. In this case we are particularly interested in a heavy assay that produces a lot of residue, the type that is often refined in the US Gulf Coast, because the ability to process this type of crude gives complex coking refineries their advantage in the market. The yields of a standard Western Canadian Select (WCS) assay are illustrated in Figure 2.

After the fractions exit the ADU, their path through various refinery units is anything but standard. The flows of these fractions through the refinery depend not only on the available processing units and their capacities, but also on product specifications and prices as the refiner will decide how much of each fraction to send into each unit in order to maximize profit. This type of problem – maximizing a profit objective subject to operational constraints – is the perfect application for linear and nonlinear programming.

In this paper we utilize the OptiFlo-Crude model to look at a complex refinery based on a Gulf Coast facility with some modifications made for illustrative purposes. Our refinery has an ADU capacity of 335 MBbl/d, and it has the following units: vacuum distillation unit (VDU), hydrotreaters for naphtha (NHT), kerosene (KHT), and gas oils (GOHT), light naphtha isomerization (LNIS), hydrocracking unit (HCU), fluidized catalytic converter (FCC), reformer (RFO), alkylation unit (ALK), and delayed coking unit (DCU).

A typical refinery blends different assays together to maximize profit while considering the physical properties of the assays together with the state of the transportation network (bottlenecks, cost of transport, crude availability, etc.). While this blending is very important on a macro scale and is being modelled at DrillingInfo, for this single refinery case we consider only the WCS assay.


How does the refinery operate with current specifications and prices?

In the base case scenario, the selected refinery’s operations are optimized given today’s 3.5% maximum sulfur specification for bunker fuel. The past 12-month average prices for end products are used as inputs. Figure 3 illustrates the basic flow diagram for this refinery, from the ADU into the other units.

The optimal product outputs for this refinery are displayed in Table 1. On a volume basis, the outputs are 42% diesel, 35% gasoline, 8% jet fuel, and a combined 15% for all other products. Some demand constraints were imposed on the model to avoid overproduction that would flood a low-demand market with supply. For example, the 3.5 MBbl/d of light sulfur fuel oil produced at this refinery already makes up more than 6% of US production of this product (Figure 1) so the light sulfur fuel oil output was limited to 1% of the refinery’s production.


What happens when IMO regulations are implemented and the price of bunker fuel rises?

In scenario 2, the IMO 2020 regulations are implemented and the price of the new bunker fuel is set accordingly. Since the maximum sulfur specification of the new bunker fuel (0.5%) lies between that of No.2 oil (0.05%) and light sulfur fuel oil (1%), its price is set using an average of these two prices weighted by the strictness of the specification. The resulting price is $74.07/Bbl compared to $85.32 for diesel, $81.98 for No.2 oil, $65.29 for light sulfur fuel oil, and $62.11 for the current 3.5% sulfur bunker fuel.

The optimal product outputs for this refinery are displayed in Table 2. Interestingly, this refinery increases bunker fuel production from 7.2 MBbl/d in the base case to 23.2 MBbl/d with the new specification and price as it reduces the production of diesel by 17.4 MBbl/d.

The spec change and price increase in bunker fuel caused the refinery to shift hydrotreated lower sulfur fractions away from the diesel pool and into bunker fuel. The composition of bunker fuel (Figure 4) changed from mostly ADU/VDU fractions in the base case to mostly DCU/GOHT fractions in scenario 2. The light gas oil (1.4% wt. sulfur), heavy gas oil (2.3%), light vacuum gas oil (3%), heavy vacuum gas oil (3.7%), and heavy cycle gas oil (2%) could be blended together to meet the old 3.5% specification, but the new specification required hydrotreated heavy vacuum gas oil (close to 0%) blended with light cycle (1.1%) and heavy cycle (2%) gas oils coming out of the DCU.

Despite higher pricing, the estimated revenue of this refinery decreases from $27.44 million in the base case to $27.23 million in scenario 2. If we impose a maximum limit of 7.2 MBbl/d on bunker fuel production based on the base case, this refinery still reduces diesel production and increases the production of waste from zero to 0.5 Mkg/d, further reducing revenue to $27.18 million. This happens because the refinery does not have enough capacity to desulfurize the residual gas oils enough to blend them into a product.


What happens when distillate prices respond?

If refiners do start to shift production away from diesel, its price is expected to rise providing incentive to meet market demand. Given the opportunity cost of producing the new bunker fuel, the price of diesel must rise by $13/Bbl for this particular refinery to return diesel production to roughly equal to the base case. To avoid other readjustments of fraction flows, the prices of jet fuel and gasoline must also rise slightly, by less than $1/Bbl. The optimal outputs of this scenario are displayed in Table 3.

Although most products are back to roughly the same level of production as the base case, the output of new bunker fuel is significantly reduced as waste production is increased. It’s interesting to note that while volume of jet fuel increases, the mass of jet fuel is the same as the base case and the volume swell is entirely due to a change in specific gravity caused by changes in its fraction composition. The expected revenue for this refinery rises from $27.44 million in the base case to $29.13 million in scenario 3.

These results illustrate why the price of diesel must rise in response to the IMO 2020 sulfur regulations and why the change is expected to benefit complex coking refineries. The $13.00 (or 15%) rise in diesel price is specific to this refinery with this crude oil assay and will vary with other refinery and assay configurations.


Refinery modelling on a macro scale

DrillingInfo OptiFlo-Crude is a nonlinear programming model that considers the entire US refining network on a macro scale, linking production (upstream) to refining demand and exports (downstream) via all the transportation paths (midstream) across the country.  By understanding the demand for specific barrels by specific refineries based on the crude oil composition and refinery operations, we can predict how crude will flow, what price a certain barrel will command in the market, what pipelines and routes will be under/over utilized, where additional infrastructure is needed, where bottlenecks will emerge, and what slate of refined products will be produced in the US.

Contact us today for an introduction!

Injection Lower Than Expected, Prices Show Little Reaction

Injection Lower Than Expected, Prices Show Little Reaction

Natural gas storage inventories increased 25 Bcf, with an implied flow of 29 Bcf, for the week ending April 5, according to the EIA’s weekly report. This injection is well below the market expectation, which was an inventory increase of 38 Bcf. This week also came with reclassifications in the Pacific and South Central regions. In the Pacific, gas stocks showed a reclassification of a 1 Bcf decrease, and South Central stocks showed a 2 Bcf drop.

Working gas storage inventories now sit at 1.155 Tcf, which is 183 Bcf below inventories at the same time last year and 485 Bcf below the five-year average.

At the time of this writing, the May 2019 contract was trading at $2.689/MMBtu, $0.011 below yesterday’s close of $2.670/MMBtu. The little reaction to the bullish report shows that the market is content with injections at this point in the season. Prices are likely to show more volatility later in the season if inventory levels are low and injections are below expectations.

This injection season started much earlier than last year. Looking at the past two weeks for the same time last year, we had draws totaling 48 Bcf. This year, we have injections totaling 48 Bcf, nearly a 100 Bcf difference in inventories. The difference in inventories can mainly be attributed to the longer winter last year, which ran through most of April. With more injections expected throughout April 2019, prices will likely stay below $3/MMBtu as inventory levels close the gap on the five-year average.

See the chart below for 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 DI analysis for the week ending April 11, 2019.

Supply:

  • Dry gas production decreased 1.07 Bcf/d on the week. The decrease stems mainly from declines in the South Central/Gulf region, which fell 1.06 Bcf/d. The big drop in the region was Louisiana, which fell 0.51 Bcf/d.
  • Canadian net imports decreased 0.34 Bcf/d on the week.

Demand:

  • Domestic natural gas demand decreased 8.72 Bcf/d week over week. Res/Com demand continued its decline into the summer season, falling 7.66 Bcf/d week over week, while Industrial demand fell 1.23 Bcf/d and Power demand gained 0.17 Bcf/d.
  • LNG exports fell 0.67 Bcf/d week over week due to maintenance at the port of Sabine on trains 1 and 2. Mexican exports increased 0.05 Bcf/d.

Total supply is down 1.41 Bcf/d, while total demand decreased 9.64 Bcf/d week over week. With the decrease in demand greater than the decrease in supply, expect the EIA to report a stronger injection next week. The ICE Financial Weekly Index report is currently expecting an injection of 94 Bcf. Last year, the same week saw a draw of 36 Bcf; the five-year average is an injection of 27 Bcf.