Gas Price Pendulum® – Natural Gas Price Influences

This figure shows Solomon’s long-term natural gas pricing outlook to 2025.

  • Solomon considers more than a dozen primary natural gas supply and demand price drivers in our price assessments. Some have both a supply and a demand influence, such as political and environmental policies (i.e., carbon emissions legislation, well fraccing bans, offshore moratoriums)—these generally favour upward price movements.
  • The supply and demand drivers are shown along with their directional influence on the forecast gas price. The size of the font used for each driver reflects its relative influence on the gas price; the larger the font, the greater the impact.
  • The shift to low-cost liquids-rich supply in the Eagle Ford and Marcellus Shale Gas plays exerts the most downward pressure on gas prices. Demand growth for power generation and LNG exports provides the most upside influence.
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Natural Gas Full-Cycle Resource Cost (Cost Curve)

This chart illustrates Solomon’s view of North American natural gas remaining resource in trillions of cubic feet (Tcf), sorted by break-even gas price. Solomon believes this changing supply cost, represented by the break-even gas price, is a key influence on long-term natural gas prices in North America and that lower-cost gas supply will be developed first.

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Western Canada Full-Cycle New Gas Cost, Excludes NGL

  • Solid colors on chart show Full-Cycle Supply Cost for New Gas:
    • Field Operating Cost (lifting costs)
    • Royalties – very low, <10%
    • Overhead (grey) – low
    • Finding & Development (Capital Cost), the biggest component:
      • Dark blue = Drilling & Completions
      • Light blue = other (land, seismic, facilities)
    • Cost of Capital amount needed for producer to earn a 15% return on capital (F&D) BT
  • Note the value gap (grey hatch area) when the Alberta gas price (black line) has been lower than the cost for new gas, and producers earn no return.
  • Old gas developed 5+ years ago, can still have positive cash flow at low gas prices.
  • roducers cannot survive at these low prices. The cash costs, such as OpEx, Royalty, and G&A, are 1.50–2.00 CAD/Mcf, and most producers barely have cash flow.

Note: 2012 may be misleading due to low drilling activity (when maintenance capital, which adds no reserves, becomes a large portion of total capital).

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Gas Price Volatility vs New Well Productivity

This figure illustrates that gas price volatility has declined primarily due to an increase in new gas well productivity.

  • Solomon’s price models include a modest volatility factor—impacted by swings in natural gas demand—that results in changes to rig count and production. As producers continue to enhance productivity, rig activity required to meet yearly production declines and incremental demand growth is reduced.
  • Although gas price volatility is impacted by some exogenous factors (hurricanes and overall financial liquidity), Solomon believes that the increasing supply responsiveness from new high-productivity shale- and tight-gas wells has lowered NYMEX Henry Hub price volatility.
  • Going forward, lower gas-price volatility will limit upside gas pricing inertia:
    • Volatile prices will benefit cost-disciplined producers.
    • Low-price volatility will benefit gas consumers.
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Henry Hub Gas Price Forecast

This chart provides Solomon’s Henry Hub natural gas price forecast through 2025. Major assumptions driving price until 2025 include:

  • GDP at 2.2% per year. Real GDP between 2000 and 2015 has averaged 2.0% per year in the US and 2.2% per year in Canada.
  • Normalised weather to 10-year average.
  • Inflation at 2.2% per year, which is in line with US Federal and Bank of Canada targets.
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AECO Gas Price Outlook

This chart provides Solomon’s October 2017 AECO natural gas nominal price forecast. TransCanada’s settlement with Eastern Triangle LDC expires in 2020, which Solomon believes will lead to a move away from an integrated system (distinct eastern triangle and long-haul systems). Solomon believes that post-2020, the potential for competitive tolls on the long-haul portion could create excess economic capacity, providing for a narrowing of Henry Hub-AECO basis.

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Overall Gas Basis Differentials, Oct 2017

This figure shows Solomon’s forecast for the annual gas price basis differentials in nominal United States dollars per million British thermal units (USD/MM Btu) for the pricing points examined. Solomon expects that growth of Appalachia production going forward will be more measured. This will continue to moderate Appalachia basis towards a balanced market. Infrastructure enhancements in Appalachia are currently under construction. AECO basis is expected to remain flat as new economic capacity on the TransCanada Mainline becomes available, providing relief to an oversupplied Western Canada market. Post-2020, AECO basis narrows as TransCanada Mainline reconfigures long-haul tolling and LNG export projects provide an outlet for Western Canada production.

As market natural gas price basis differentials narrow, the value of long-haul transportation routes will decline. Solomon expects the trend of increased gas well initial productivity rates will maintain lower gas price volatility and flatten gas price basis differentials across North America. LNG exports will introduce increased volatility as exports continue to grow. Normal weather in 2017–2018 will provide strength for pricing in New York and New England. Chicago is expected to be an oversupplied dumping ground for producing region gas supplies and will be priced below Henry Hub for the forecast period.

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Dawn–AECO Gas Basis Differentials, Oct 2017

  • Increased availability of US Northeast shale gas reduces requirements for western Canada supply, which utilizes high-cost marginal pipe.
  • Dawn maintains premium to Appalachia supply to continue to attract supply.
  • As Appalachia connectivity to New England is enhanced, Dawn prices firm to compete.
  • Well-supplied Midwest and US Northeast markets limit Dawn price upside.
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