NrgEdge Editor

Sharing content and articles for users
Last Updated: June 13, 2016
1 view
Power Generation

According to recent reports in the energy market, Texans in deregulated parts of the state pay an average that surpasses the national average. These same Texas residents also pay higher integrated utility bills.

Texas Legislature gave birth to deregulation and a competitive market to most of it’s state in 2002, allowing residents to pick who they wanted and to compare rates at

Jay Doegey, executive director for Texas Coalition for Affordable Power, says,“Folks living in areas of Texas with electric deregulation have paid more for electricity, on average, than Texans living without deregulation — that’s just a historical fact. But it’s also true that the deregulated market is maturing. The good news for folks living in deregulated areas is that if they shop carefully, they can find plenty of individual deals with good prices.” Currently, there isn’t enough data available to properly compare 2015 costs.

The average costs fell below the national average in 2012-2013 due to the ample supply of cheap natural gas that drives power prices in Texas. That quickly ended in 2014 when the average was .04 cents higher than the nation’s average. The 15 percent of non-deregulated Texans pay less than 11 cents kwh.

The gap between the two markets totals $24 billion from the first 12 years, with an average of $5,100 per household. Reasons for the divide are kinks in the deregulated market, rate comparison confusion, and higher prices from the trusted “name brand” companies that were around before deregulation.

TDU charges have drastically shot through the roof since deregulation. CenterPoint Energy, who is responsible for the transmission and distribution in Houston, has increased monthly charges from an average of $24.61 in 9/03 to $42.41 in 3/16, all of this in addition to the fluctuating rates that change daily.

Article written by HEI contributor Marcela Abarca.

Energy Texas Utility
0 0

Something interesting to share?
Join NrgEdge and create your own NrgBuzz today

Latest NrgBuzz

Equinor Goes “Bigly” in the North Sea

At a time when most of the news in the North Sea is about exits – ExxonMobil has just sold its unoperated upstream assets in Norway and ConocoPhillips has departed the UK section of the North Sea – there are still sparks of brightness in this long-mined offshore area. Equinor’s Johan Sverdrup field which contains some 2.7 billion barrels of oil equivalent has started up, two months ahead of schedule and US$4.3 billion below original cost estimates.

When it hits peak production, this new ‘North Sea giant’ will produce up to 660,000 b/d of crude oil, accounting for a third of all oil production in Norway. When complete, the Johan Sverdrup development will be one of the largest in the Norwegian Continental Shelf. It is a shot in the arm that Norway’s industry needs right now. Equinor has had a good track record in making new discoveries over the past two years, but they all mainly small and cannot outweigh declining production elsewhere. John Sverdrup is very different. Discovered in 2010, Johan Sverdrup straddles two separate production licences, discovered as Avaldsnes by Lundin Petroleum and Aldous Major South by Equinor and the field was renamed to its current form in 2012. Equinor holds a 42.6% stake in the field, with Lundin Norway, Petoro, Aker BP and Total constituting the rest.

The project has been championed as a model of the lower-cost, innovative thinking approach that the Norwegian upstream has taken since the 2014 downturn of the oil and gas industry. With first oil already flowing, it will help reverse the steady decline in Norwegian oil production, which fell to 1.65 million b/d in August, down 3.9% m-o-m and down from the all-time peak of 3.4 million b/d in 2011. Prudence paid off; green-lit in 2015, Equinor and its partners managed to secure significant discounts on services and equipment, resulting a break-even cost of less than US$20/b. The location of John Sverdrup is also crucial; believing the Norwegian Continental Shelf to be fully explored, activity has shifted to the Barents Sea. But though there are some big fields in the Barents coming onstream, exploration there has generally underperformed. So the field has been seen as a cause for hope, discovered in a mature basin 160km from Stavanger that was thought to be completely tapped out

Interestingly, John Sverdrup also has wider implications beyond the oil industry. With production set to reach 440,000 b/d by mid-2020, it will contribute about US$100 billion to the Norwegian state coffers over 50 years. It will inject additional fuel into the Norwegian Oil Fund – the country’s sovereign wealth fund – that recently decided to jettison upstream oil stocks (while keeping downstream oil stocks). This illustrates a dichotomy: while Norway as a whole is supportive of clean energy, oil & gas remains a crucial backbone of the country’s economy. So while the conversation around the North Sea will still centre around decommissioning and departures, Johan Sverdrup is proof that there are still (big) pockets of opportunity underneath these cold waters.

Johan Sverdrup:

  • Discovery: 2010
  • Location: 160km west of Stavanger, NCS
  • Ownership: Equinor (42.6%), Lundin Norway (20%), Petoro (17.36%), Aker BP (11.57%), Total (8.44%)
  • Size: 2.2-3.2 billion barrels of oil
  • Project: Phase 1, Oct 2019 (440,000 b/d); Phase 2 startup 4Q 20202 (660,000 b/d)
October, 10 2019
  • Canada is one of the world’s top energy producers and is a principal source of U.S. energy imports.

  • Canada is a net exporter of most energy commodities and is a significant producer of natural gas, hydroelectricity, and crude oil and other liquids from oil sands. Energy exports to the United States account for most of Canada’s total energy exports.
  • Canada has abundant and varied natural resources, ranking fourth in 2018 among the top energy producers of petroleum and total liquids in the world, behind only the United States, Saudi Arabia, and Russia. Relatively energy intensive compared with other industrialized countries, Canada’s economy is fueled largely by petroleum and other liquids, natural gas, and hydroelectricity (Figure 1).

Figure 1. Total primary energy consumption in Canada by fuel type, 2018

# figure data

Petroleum and other liquids

Canada’s oil sands have significantly contributed to the recent and expected future growth in the world’s liquid fuel supply, and they comprise most of the country’s proved oil reserves, which rank third globally.

  • The Oil & Gas Journal estimates that as of January 2019, Canada had 167 billion barrels of proved oil reserves, ranking third in the world.[1] Only Venezuela and Saudi Arabia hold higher reserves. In addition, Canada is one of only 3 countries among the top 10 proved reserves holders that is not a member of the Organization of the Petroleum Exporting Countries (OPEC).
Production and consumption
  • In 2018, Canada was the world’s fourth-largest petroleum and other liquids producer and was a net exporter of oil. Nearly all of its crude oil exports are destined for the United States because Canada lacks sufficient export capacity to send its liquids elsewhere.
  • Canada is a major producer of crude oil. Bitumen and upgraded synthetic crude oil produced from the oil sands of Alberta have driven recent growth in Canada’s liquid fuels production. Most of Canada’s proved oil reserves and the expected future growth in the country’s liquid fuels production will be derived from these resources.
  • Canada produced 5.3 million barrels per day (b/d) of petroleum and other liquid fuels in 2018, an increase of more than 300,000 b/d from the previous year. Crude oil (including condensate) accounted for 4.3 million b/d, and the remainder was produced as biofuels, natural gas, and other natural gas liquids (NGL) (Figure 2). Canada’s production is expected to grow modestly in 2019 and 2020 because of export capacity constraints and mandatory production curtailments set by the government of Alberta.

Figure 2. Canada liquid fuels production and consumption

# figure data

  • According to the Canadian Association for Petroleum Producers (CAPP), Canada has 17 refineries with a total crude oil processing capacity of 2.0 million b/d.[2] Eastern Canada’s eight refineries have 1.2 million b/d of capacity or about 60% of total crude oil refining capacity.[3] Because the eastern refineries are not as well connected to domestic crude oil production supplies, these refineries are more dependent on imported crude oil. Western Canada’s nine refineries have a total capacity of 748,000 b/d. In 2018, Phase One of the North West Redwater’s Sturgeon Refinery came online, which is the first refinery built in Canada since 1984.[4]
  • According to Natural Resources Canada, Canadian production of petroleum products reached 1.9 million b/d in 2018.[5] Most petroleum products are refined into motor gasoline (42%) and diesel fuel oil (30%).[6]
Exports and imports
  • Nearly all of Canada’s crude oil exports were sent to the United States in 2018 (see Figure 3). Currently, the largest regional market in the United States for Canadian crude oil exports is the Midwest where almost all Canadian crude oil exports originate from Western Canada.
  • Canada is the largest source of U.S. crude oil and refined products imports. Crude oil imports from Canada accounted for 48% of total U.S. crude oil imports in 2018, averaging 3.7 million b/d. Refined products imported from Canada accounted for 582,000 b/d, or 27% of total U.S. petroleum product imports.
  • Currently, producers face a complex set of market and logistical challenges. Oil supply in Western Canada exceeds the transport capacity of pipelines serving external markets. As export pipelines operate at full capacity and timing of new capacity remains uncertain, producers are increasingly relying on rail transportation to deliver incremental production to the market. The highest monthly volume imported to the United States from Canada was in January 2019 at 406,000 b/d, compared with a total average of 238,000 b/d in 2018.

Figure 3. Canada crude oil exports by destination, 2018

# figure data

Natural gas

Canada is one of the world’s largest producers of dry natural gas and is the source of most U.S. natural gas imports.

  • The Oil & Gas Journal,[7] Canada held 72 trillion cubic feet (Tcf) of proved natural gas reserves at the end of 2018. Most of Canada’s natural gas reserves are traditional resources in the Western Canadian Sedimentary Basin (WCSB), including those associated with the region’s oil fields. Other areas with significant natural gas reserves include offshore fields near the eastern shore of Canada (primarily Newfoundland and Nova Scotia), the Arctic region, and the Pacific coast.
Production and consumption
  • In 2018, Canada produced 5.9 Tcf of dry natural gas and was the fourth-largest producer behind the United States, Russia, and Iran (see Figure 4). Most of Canada’s natural gas production occurs in the prolific WCSB. Although Canadian production of conventional natural gas has been declining, the production of Canadian unconventional natural gas has been rising.
  • Almost all of Canada’s natural gas exports go to the United States. In 2018, 97% of all U.S. natural gas imports came from Canada. Most of Canada’s natural gas exports to the United States originate in Western Canada and are shipped to U.S. markets in the West and Midwest regions.

Figure 4. Canada's dry natural gas production and consumption

# figure data

  • Canada generated an estimated 651 billion kilowatthours (kWh) of electricity in 2017, of which about 60% was hydroelectric. Only China and Brazil produce more hydroelectricity than Canada.[8] Fossil fuel and nuclear plants satisfy most of Canada’s electricity needs not met by hydroelectricity (see Figure 5).
  • The United States imported 52 million megawatthours (MWh) of electricity from Canada in 2018, primarily into the Northeast and Midwest, and exported 73 million MWh, nearly all of which was from the Pacific Northwest. Canada is a net exporter of electricity to the United States, which accounts for a small, although locally important, share of bilateral trade.

Figure 5. Electricity generation by fuel, 2018

# figure data


As government policy attempts to lower domestic coal consumption, up to 50% of Canada’s coal production is exported.

  • Canada’s total proved coal reserves stood at about 6.6 billion short tons in 2018.[9] More than 60% of the reserves are anthracite and bituminous coal. The remaining reserves are subbituminous and lignite coal.[10] Coal resources are located across the country, but they are actively mined and produced in only Alberta, British Columbia, and Saskatchewan.
Production and consumption
  • In 2017, Canada produced 68 million short tons of coal, a slight increase compared with the previous year. About 50% of Canada’s coal production is consumed domestically, a significant departure from more than a decade ago when Canada consumed nearly all of its domestic coal production.
  • In 2018, 49% of coal consumed in Canada was metallurgical coal used for steel manufacturing, and 51% was thermal coal used for electricity generation. Coal generates 9% of total electricity in Canada. In 2018, the government of Canada announced regulations to phase out traditional coal-fired electricity by 2030.[11]
  • Canada exports about half of its coal production. In 2018, Canada was the world's third-largest exporter of metallurgical coal after Australia and the United States. [12] Most of Canada's coal exports go to Asia.
October, 08 2019
Your Weekly Update: 30 September - 4 October 2019

Market Watch  

Headline crude prices for the week beginning 30 September 2019 – Brent: US$59/b; WTI: US$54/b

  • News that Saudi production was ‘fully back online’ dropped global benchmarks back to their pre-attack range, moving the oil markets back to the question of how to ‘manage supply’ in the face of the inexorable rises in US output
  • Saudi Aramco stated that its production capacity has risen back to 11.3 mmb/d and will hit 12 mmb/d by November; output for October was expected to rise back to 9.89 mmb/d after falling to 5 mmb/d in the aftermath of the attacks
  • However, there have been some signs of the outage causes some kinks in the Saudi system – JXTG Nippon Oil reports that its scheduled cargos were switched from light crude to heavy and medium for October
  • A week after the UK-flagged ship was released by Iran, there are more shipping woes surrounding Iran as the US imposed penalties on four Chinese shipping companies for carrying Iranian crude post-waiver
  • There was also a new (unwelcome) development in the US trade war with China, as the US mulls capping the amount of American money that can flow into China; coupled with a sputtering Indian economy, the health of the global economy and global oil demand is in peril
  • Despite the unstoppable rise of US crude production, it appears that this has been mainly on the back of improved productivity, as the active US rig count fell once again by 8 sites (6 oil and 2 gas), bringing the total count down to 860, down 194 sites y-o-y
  • With no upside in sight, there is little room for oil prices to go but sideways or down; we expect that crude prices should be able to at least stay in their current range with Brent at US$58-60/b and WTI and US$53-55/b

Headlines of the week


  • As rumoured, ExxonMobil is looking to exit Norwegian upstream, selling its non-operating assets to Var Energi AS for some US$4.5 billion, covering over 20 fields with a combined production of 150,000 boe/d
  • Reports suggest that ExxonMobil may be selling its 64% stake in the Ca Voi Xanh (Blue Whale) offshore project in Vietnam on fears that it taps into the same basin claimed by China as part of its Southeast Asia nine-dashed line
  • Sudan has urged international firms operating there to speed up exploration and production operations, despite ongoing grouses over unpaid liftings
  • Equinor’s plans for the Great Australian Bight – with some 1.9 billion potential barrels of oil – will be decided by the offshore regulator by mid-November
  • Kazakhstan is seeking an additional US$1 billion from the partners of the 425,000 b/d Karachaganak oil and gas project – including Shell, Eni and Chevron – the latest in a long line of spats over taxes and costs beginning 2012
  • A Canadian federal court has halted plans by the Alberta province to cut off crude oil pipeline flows to British Columbia, which came about due to disagreements over the planned expansion of the Trans Mountain Pipeline
  • The first ever onshore drilling campaign in Timor-Leste in nearly 50 years will begin as Timor Resources starts a campaign in the Viqueque formation
  • Indonesia’s PT Medco Energi has announced plans to almost triple its output from 120,000 b/d to 300,000 b/d over the next 5-10 years, betting on higher prices and supporting that goal by acquiring existing onshore wells
  • An underwater leak at the YYA-1 well in the Offshore North West Java block operated by Pertamina has finally been fixed after two months


  • While many major refineries are already producing low sulfur fuel oil to comply with the new IMO standards, some light crude from the UK and West Africa is being marketed as a straight replacement, requiring only minor blending
  • Sinopec continues to make strides in meeting the IMO requirements, with its Qilu refinery in Shandong expected to begin producing LSFO this month
  • A key shareholder of Marathon Petroleum – hedge fund Elliot Management Corp – has called for the company to be spun off into three businesses, covering its current retail, refining and midstream operations
  • Efforts to improve the chronic underperformance of Mexican refineries appear to be paying off, with utilisation rising to 50% from 38% in August
  • A shortfall of LPG from Saudi Arabia – where refining runs were lowered after recent attacks – has led India to turn to UAE to make up the shortfall

Natural Gas/LNG

  • Kinder Morgan’s Gulf Coast Express Pipeline has begun commercial service, delivering natural gas from Waha area in the Permian Basin to Agua Dulce near Corpus Christi on the Texas Gulf Coast, with a capacity for 2 bcf/d
  • Kosmos Energy hopes that its new Yakaar-2 well offshore Senegal is a ‘world-class’ discovery that will support the Yakaar-Teranga LNG project
  • Equinor has struck new gas in the Orn well near the Marulk field in the Norwegian Sea, with initial estimates suggesting 50-88 million boe in place


  • Saudi Aramco will launch its IPO around October 20 – estimated at an initial US$2 trillion – a short timeline that has left investors scrambling
October, 08 2019