In the News:
Natural gas-fired and renewable power plants continue to lead capacity additions in Mexico
On May 31, 2022, Mexico’s Ministry of Energy (SENER) released its annual PRODESEN (the National Electric System Development Plan) 2022–2036. This report provides information on recent electricity generation and capacity trends and also provides a business plan for future capacity development based on current Mexico energy policy. Previous PRODESEN reports have been subject to revision.
According to the report, natural gas-fired power plants were the primary source of electricity production in Mexico, generating 62% of the total electricity in 2021, up from 54% in 2015 and 34% in 2005. The report states that in the last five years (2017–2021), the share of Mexico’s electricity generated by renewable sources has grown, while generation from thermal sources such as coal and fuel oil has declined. Renewable generation (hydropower, wind, solar, biomass, and geothermal energy) increased from 16% of total generation in 2017 to 25% in 2021, while generation by fuel oil and coal (combined) has declined from 24% to 9% over the same period.
According to SENER’s report, between 2017 and 2021, Mexico’s installed electric generation capacity increased by 27%, from 68 gigawatts (GW) to 86 GW. Almost one-half of installed capacity additions (9 GW, or 48%) were natural gas-fired power plants, mostly combined cycle (CC) units. In 2021, combined cycle power plants accounted for 39% of Mexico’s total installed capacity. Renewable power plants accounted for 52% of capacity additions in this period (6 GW of solar, 3 GW of wind, and 1 GW of other renewables). Almost 1 GW of fuel oil power plants has been either converted to natural gas or retired.
In the report, SENER forecasts that in the next four years (2022–2025), Mexico will continue to expand both natural gas-fired and renewable electric generation capacity. Almost one-half (7.5 GW, or 45%) of the total 16.6 GW planned capacity additions in this period will be natural gas-fired power plants. Most of these plants will be combined-cycle units (5.7 GW), and 1.8 GW will be peaking power plants (gas turbine (GT) and internal combustion (IC) units). Renewable generation capacity will expand by 9.1 GW and account for 55% of the total capacity additions. Most of the renewable capacity additions will be solar (6.7 GW), followed by wind (1.9 GW), hydro (0.5 GW), and other renewables (0.1 GW).
Longer-term (2026–2036), SENER forecasts that 70% (28 GW) of 39.5 GW of capacity additions will be renewable generation plants (mainly solar, wind, hydro, and battery storage), and 23% (9.2 GW) will be natural gas-fired power plants. Conventional combined cycle natural gas-fired power plants will account for 3.5 GW of capacity expansions. Another 4.4 GW will be combined cycle plants that can run on a blend of natural gas and hydrogen, and 1.4 GW will be efficient co-generation and IC power plants. Nuclear capacity is also forecast to expand in this period, by 2.5 GW, from 1.6 GW in 2022 to 4.1 GW by 2036, accounting for 6% of capacity additions, according to SENER.
The forecast capacity additions in SENER’s PRODESEN report are different from EIA’s projections in the International Energy Outlook 2021, which we released on October 6, 2021. In that report, Mexico is grouped in the Other OECD Americas region, which also includes Chile, Colombia, Puerto Rico, and the U.S. Virgin Islands. In the near term (2022–25), we project that electric capacity in Mexico and Other OECD Americas region grows by 8.5 GW, which is about one-half (51%) of the forecast electricity capacity additions for Mexico in the PRODESEN report. Although the total capacity growth from 2026 to 2036 in the reports is similar, the IEO2021 projects that Mexico and other OECD Americas’ natural gas-fired generation capacity is relatively flat over that period whereas Mexico’s PRODESEN report forecasts growth.
Market Highlights:
(For the week ending Wednesday, July 13, 2022)Prices
- Henry Hub spot price: The Henry Hub spot price rose one dollar from $5.63 per million British thermal units (MMBtu) last Wednesday to $6.63/MMBtu yesterday.
- Henry Hub futures prices: The price of the August 2022 NYMEX contract increased $1.179, from $5.510/MMBtu last Wednesday to $6.689/MMBtu yesterday. The price of the 12-month strip averaging August 2022 through July 2023 futures contracts climbed 81.2 cents to $5.934/MMBtu.
- Select regional spot prices: Natural gas spot prices rose at most locations this report week (Wednesday, July 6 to Wednesday, July 13). Increases ranged from 77 cents at Eastern Gas South in the Appalachia production region to $2.26 at SoCal Citygate in Southern California.
- Prices in California rose this report week, as temperatures in California and the Desert Southwest were above normal. The price at SoCal Citygate in Southern California had one of the largest increases among major hubs this week, rising $2.26 from $5.45/MMBtu last Wednesday to $7.71/MMBtu yesterday. The price at PG&E Citygate in Northern California increased $1.29 from $6.33/MMBtu last Wednesday to $7.62/MMBtu yesterday. Natural gas consumption in the electric power sector in California increased by 0.6 Bcf/d (42%) week over week. Price increases in the Desert Southwest mirrored the SoCal Citygate price. The Natural Gas Intelligence El Paso South Mainline/North Baja price rose $2.25, from $5.48/MMBtu last Wednesday to $7.73/MMBtu yesterday. Natural gas consumption in the Desert Southwest electric power sector increased by 0.3 Bcf/d (14%), according to data from PointLogic. Temperatures in the Phoenix Area remained above 110°F throughout the report week and rose to a weekly high of 115°F on Monday.
- Prices increased in the Appalachia production region even as production was unchanged week over week and demand was slightly lower. The Tennessee Zone 4 Marcellus spot price increased 93 cents from $4.85/MMBtu last Wednesday to $5.78/MMBtu yesterday. The price at Eastern Gas South in southwest Pennsylvania rose 77 cents from $5.00/MMBtu last Wednesday to $5.77/MMBtu yesterday.
- The price at the Waha Hub in West Texas, which is located near Permian Basin production activities, rose 92 cents this report week, from $5.32/MMBtu last Wednesday to $6.24/MMBtu yesterday. The Waha Hub traded 39 cents below the Henry Hub price yesterday, compared with last Wednesday when it traded 31 cents below the Henry Hub price. For the second week in a row, production on the New Mexico side of the Permian Basin declined by 0.1 Bcf/d (3%). Production in the Permian Basin-New Mexico averaged 4.8 Bcf/d this week compared with 5.1 Bcf/d two weeks ago, according to data from PointLogic.
- International futures prices: International natural gas futures prices increased this report week. According to Bloomberg Finance, L.P., weekly average futures prices for liquefied natural gas (LNG) cargoes in East Asia averaged $39.13/MMBtu, and natural gas futures for delivery at the Title Transfer Facility (TTF) in the Netherlands, the most liquid natural gas spot market in Europe, averaged $51.88/MMBtu.
- Natural gas plant liquids prices: The natural gas plant liquids composite price, based off prices at Mont Belvieu, Texas, fell by 13 cents/MMBtu, averaging $11.32/MMBtu for the week ending July 13. Weekly average natural gas prices at the Houston Ship Channel rose 9%, while the price of ethane fell 2%, narrowing the ethane premium to natural gas by 31%. The price of ethylene fell 6%, narrowing the ethylene to ethane spread by 18%. The butane price fell 3%, following the 3% decrease in the Brent crude oil price. The price of isobutane fell 1%, and the price of natural gasoline rose 1%. The propane price fell 1%, reducing the propane discount to crude oil by 6%.
Daily spot prices by region are available on the EIA website.
Supply and Demand
- Supply: According to data from PointLogic, the average total supply of natural gas fell by 0.1% (0.1 Bcf/d) compared with the previous report week. Dry natural gas production decreased by 0.5% (0.5 Bcf/d) compared with the previous report week. Average net imports from Canada increased by 6.4% (0.4 Bcf/d) from last week.
- Demand: Total U.S. consumption of natural gas rose by 2.5% (1.8 Bcf/d) compared with the previous report week, according to data from PointLogic. Natural gas consumed for power generation climbed by 5.0% (2.0 Bcf/d) week over week. Industrial sector consumption decreased by 0.4% (0.1 Bcf/d) week over week. In the residential and commercial sectors, consumption declined by 1.5% (0.1 Bcf/d). Natural gas exports to Mexico increased 1.8% (0.1 Bcf/d). Natural gas deliveries to U.S. LNG export facilities (LNG pipeline receipts) averaged 11.1 Bcf/d, or 0.1 Bcf/d lower than last week.
Liquefied Natural Gas (LNG)
- Pipeline receipts: Natural gas deliveries to LNG export terminals in South Texas were essentially unchanged at 2.3 Bcf/d, while deliveries to LNG export terminals in South Louisiana decreased slightly (1.2%) to 7.7 Bcf/d. Natural gas deliveries to LNG export terminals in the Northeast and Atlantic Coast were relatively unchanged at a combined 1.1 Bcf/d this week. Calcasieu Pass, in Cameron Parish, Louisiana, continues to increase production. Feedgas deliveries to the terminal via the TransCameron Pipeline averaged 1.4 Bcf/d this week and reached a record level of 1.5 Bcf/d on July 8.
- Vessels departing U.S. ports: U.S. LNG exports increased by four vessels this week from last week. Twenty-three LNG vessels (seven from Sabine Pass, five from Corpus Christi, four each from Calcasieu Pass and Cameron, two from Cove Point, and one from Elba Island) with a combined LNG-carrying capacity of 84 Bcf departed the United States between July 7 and July 13 according to shipping data provided by Bloomberg Finance, L.P.
- Export terminals: Calcasieu Pass, operated by Venture Global Calcasieu Pass, LLC, in Cameron Parish, Louisiana, received approval from the Federal Energy Regulatory Commission (FERC) to commission Liquefaction Block 9. With this authorization, Calcasieu Pass has commissioned all nine blocks of two liquefaction trains each.
Rig Count
- According to Baker Hughes, for the week ending Tuesday, July 6, the natural gas rig count was unchanged from a week ago at 153 rigs. The number of oil-directed rigs increased by 2 rigs to 597 rigs. The Granite Wash and the Permian each added one rig. The total rig count now stands at 752 rigs, the highest level since March 20, 2020, and 273 rigs more than the same week last year.
Storage
- The net injections into storage totaled 58 Bcf for the week ending July 8, compared with the five-year (2017–2021) average net injections of 55 Bcf and last year's net injections of 49 Bcf during the same week. Working natural gas stocks totaled 2,369 Bcf, which is 319 Bcf (12%) lower than the five-year average and 252 Bcf (10%) lower than last year at this time.
- According to The Desk survey of natural gas analysts, estimates of the weekly net change to working natural gas stocks ranged from net injections of 43 Bcf to 69 Bcf, with a median estimate of 56 Bcf.
- The average rate of injections into storage is 4% lower than the five-year average so far in the refill season (April through October). If the rate of injections into storage matched the five-year average of 8.3 Bcf/d for the remainder of the refill season, the total inventory would be 3,326 Bcf on October 31, which is 319 Bcf lower than the five-year average of 3,645 Bcf for that time of year.
Other Market Drivers
- The Electric Reliability Council of Texas (ERCOT) issued an appeal to Texans to conserve electricity Monday, July 11, between 2:00 p.m. and 8:00 p.m. in response to extreme hot weather. Daytime temperatures in the Houston Area exceeded 100°F. ERCOT avoided rolling black- or brown-outs as a result.
- Energy Transfer, operator of the Old Ocean Pipeline, shut in the 0.2 Bcf/d system following a fire on Thursday on a section of the system in Fort Bend County, Texas. The pipeline carries natural gas from the Permian Basin to the Houston area.
See also:
Data source: Mexico Secretaria de Energia (SENER) (Ministry of Energy) PRODESEN reports 2021 and 2022 Note: *Other natural gas includes gas turbines, internal combustion, and efficient cogeneration, **other thermal includes coal and nuclear, and ***other renewables include biomass and geothermal capacity and generation.
Data for 2021 include estimates for July‒December 2021.
Data source: Mexico Secretaria de Energia (SENER) (Ministry of Energy) PRODESEN reports 2021 and 2022Note: *Other natural gas includes gas turbines, internal combustion, and efficient cogeneration. **CC and hydrogen are natural gas-fired combined cycle (CC) power plants that can run on a blend of natural gas and hydrogen.
| Spot Prices ($/MMBtu) | Thu, 07-Jul |
Fri, 08-Jul |
Mon, 11-Jul |
Tue, 12-Jul |
Wed, 13-Jul |
|---|---|---|---|---|---|
| Henry Hub |
5.86 |
6.39 |
6.76 |
6.79 |
6.63 |
| New York |
5.51 |
5.27 |
6.32 |
6.06 |
6.03 |
| Chicago |
5.72 |
5.94 |
6.42 |
6.40 |
6.45 |
| Cal. Comp. Avg.* |
5.96 |
6.38 |
7.03 |
7.21 |
7.12 |
| Futures ($/MMBtu) | |||||
| August contract | 6.297 |
6.034 |
6.426 |
6.163 |
6.689 |
| September contract |
6.262 |
5.967 |
6.319 |
6.021 |
6.589 |
| Data source: Natural Gas Intelligence and CME Group as compiled by Bloomberg, L.P. *Avg. of NGI's reported prices for: Malin, PG&E Citygate, and Southern California Border Avg. |
|||||
| U.S. natural gas supply - Gas Week: (7/7/22 - 7/13/22) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| Marketed production | 108.1 |
108.6 |
106.3 |
| Dry production | 96.0 |
96.5 |
93.6 |
| Net Canada imports | 5.9 |
5.5 |
5.1 |
| LNG pipeline deliveries | 0.1 |
0.1 |
0.1 |
| Total supply | 102.0 |
102.1 |
98.7 |
|
Data source: PointLogic | |||
| U.S. natural gas consumption - Gas Week: (7/7/22 - 7/13/22) | |||
|---|---|---|---|
Average daily values (billion cubic feet) |
|||
this week |
last week |
last year |
|
| U.S. consumption | 71.8 |
70.1 |
68.8 |
| Power | 41.7 |
39.7 |
39.2 |
| Industrial | 20.9 |
20.9 |
21.4 |
| Residential/commercial | 9.3 |
9.4 |
8.3 |
| Mexico exports | 5.9 |
5.8 |
6.5 |
| Pipeline fuel use/losses | 6.7 |
6.6 |
6.4 |
| LNG pipeline receipts | 11.1 |
11.2 |
10.9 |
| Total demand | 95.5 |
93.7 |
92.6 |
|
Data source: PointLogic | |||
| Rigs | |||
|---|---|---|---|
Tue, July 05, 2022 |
Change from |
||
last week |
last year |
||
| Oil rigs | 597 |
0.3% |
57.9% |
| Natural gas rigs | 153 |
0.0% |
51.5% |
| Note: Excludes any miscellaneous rigs | |||
| Rig numbers by type | |||
|---|---|---|---|
Tue, July 05, 2022 |
Change from |
||
last week |
last year |
||
| Vertical | 27 |
8.0% |
80.0% |
| Horizontal | 682 |
0.0% |
57.5% |
| Directional | 43 |
0.0% |
38.7% |
| Data source: Baker Hughes Company | |||
| Working gas in underground storage | ||||
|---|---|---|---|---|
Stocks billion cubic feet (Bcf) |
||||
| Region | 2022-07-08 |
2022-07-01 |
change |
|
| East | 501 |
482 |
19 |
|
| Midwest | 586 |
562 |
24 |
|
| Mountain | 143 |
138 |
5 |
|
| Pacific | 249 |
240 |
9 |
|
| South Central | 890 |
890 |
0 |
|
| Total | 2,369 |
2,311 |
58 |
|
| Data source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | ||||
| Working gas in underground storage | |||||
|---|---|---|---|---|---|
Historical comparisons |
|||||
Year ago (7/8/21) |
5-year average (2017-2021) |
||||
| Region | Stocks (Bcf) |
% change |
Stocks (Bcf) |
% change |
|
| East | 540 |
-7.2 |
568 |
-11.8 |
|
| Midwest | 659 |
-11.1 |
650 |
-9.8 |
|
| Mountain | 180 |
-20.6 |
169 |
-15.4 |
|
| Pacific | 249 |
0.0 |
276 |
-9.8 |
|
| South Central | 994 |
-10.5 |
1,027 |
-13.3 |
|
| Total | 2,621 |
-9.6 |
2,688 |
-11.9 |
|
| Data source: U.S. Energy Information Administration Form EIA-912, Weekly Underground Natural Gas Storage Report | |||||
| Temperature – heating & cooling degree days (week ending Jul 07) | ||||||||
|---|---|---|---|---|---|---|---|---|
HDDs |
CDDs |
|||||||
| Region | Current total |
Deviation from normal |
Deviation from last year |
Current total |
Deviation from normal |
Deviation from last year |
||
| New England | 1 |
-1 |
-10 |
43 |
10 |
11 |
||
| Middle Atlantic | 0 |
0 |
-2 |
60 |
11 |
2 |
||
| E N Central | 0 |
-1 |
-3 |
65 |
15 |
2 |
||
| W N Central | 0 |
-3 |
-1 |
79 |
15 |
11 |
||
| South Atlantic | 0 |
0 |
0 |
106 |
14 |
20 |
||
| E S Central | 0 |
0 |
0 |
113 |
24 |
39 |
||
| W S Central | 0 |
0 |
0 |
140 |
22 |
37 |
||
| Mountain | 1 |
-8 |
1 |
73 |
1 |
-18 |
||
| Pacific | 3 |
-3 |
3 |
30 |
-6 |
-27 |
||
| United States | 1 |
-2 |
-1 |
78 |
10 |
7 |
||
|
Data source: National Oceanic and Atmospheric Administration Note: HDDs=heating degree days; CDDs=cooling degree days | ||||||||
Average temperature (°F)
7-day mean ending Jul 07, 2022
Data source: National Oceanic and Atmospheric Administration
Deviation between average and normal temperature (°F)
7-day mean ending Jul 07, 2022
Data source: National Oceanic and Atmospheric Administration
