
\newcommand{\thistitle}{Lecture 11: Gas Markets}

\input{title.tex}


\section{Introduction to Gas Markets}

\begin{frame}
  \frametitle{Fossl gas: historical perspective}

  Extraction of fossil gas took off in the 1960s with discoveries in the USA, Western Siberia, North Sea and elsewhere, as well as advancing technology to transport, store and use it.


  \centering
  \includegraphics[height=6.7cm]{global-energy-substitution-2024.png}

  \source{\hrefc{https://ourworldindata.org/energy-mix}{Our World in Data, 2024}}


\end{frame}


\begin{frame}
  \frametitle{Fossil gas in comparison to other energy carriers}

  \begin{itemize}
    \item Fossil gas is a \alert{naturally-occuring} fossil fuel (like oil and coal, unlike coal/town gas produced from coal; this is why fossil gas is often call \alert{natural gas})
    \item Gas is \alert{easily storable} in overground tanks or underground geological formations (like oil and coal, unlike electricity)
    \item Originally (i.e. end of 19th century, first half of 20th century) gas was \alert{hard to move around}, so was only used locally (like electricity) or flared
    \item Since mid-20th century gas can be transported and distributed \alert{by pipeline} (like oil), which makes long-distance transport and delivery to households easier than e.g. coal
    \item Since late-20th century gas can be transported as liquified natural gas (LNG) \alert{by ship} (like oil and coal)
      \item Gas is used for energy but also as a \alert{non-energy feedstock} (like oil and coal) for ammonia and other chemicals like methanol and plastics
  \end{itemize}

\end{frame}

\begin{frame}
  \frametitle{Fossil gas value chain}

  \centering
  \includegraphics[height=7.8cm]{gas_value_chain.jpg}

  \source{IGU}
\end{frame}

\begin{frame}
  \frametitle{Fossil gas as a bridge?}

  There is a substantial debate about the role of fossil gas in the Energy Transition.
  \begin{itemize}
    \item Can we avoid fossil gas being used for \alert{geopolitical purposes} by producers?
  \item Can we use fossil gas as a \alert{bridge} from coal to a future fossil-free system? (It should have lower emissions than coal and gas plants can run flexibly to balance VRE; but can we avoid fossil gas and move straight to storage and flexibility?)
  \item Does \alert{methane leakage} in production and distribution outweigh the climate benefits? (Methane is a potent greenhouse gas, and substantial leakage can make it as bad as coal, but leakage can also be detected and regulated.)
  \item Can we retrofit fossil gas infrastructure for \alert{hydrogen}?
    \item How do we replace \alert{feedstock} uses of fossil gas?
  \end{itemize}

\end{frame}

\begin{frame}
  \frametitle{Gas crisis 2021-2023}

  Gas prices had been stable around $\sim$ 20 \euro/MWh, but in late 2021 and early 2022 rose to reach a peak of nearly 350~\euro/MWh. Here is the TTF (Title Transfer Facility) price for the virtual hub in the Netherlands.

  \centering
  \includegraphics[height=6cm]{dutch-ttf-natural-gas-prices-have-dropped-yet-again-v0-m92g79kzoz1b1.png}

  % https://www.reddit.com/r/europe/comments/13rjlvg/dutch_ttf_natural_gas_prices_have_dropped_yet/
  \source{\hrefc{https://www.theice.com/products/27996665/Dutch-TTF-Natural-Gas-Futures/data?marketId=5493476&span=3}{ICE, 2023}}
\end{frame}

\begin{frame}
  \frametitle{Gas crisis 2021-2023}

  The reason is of course reduced supply from Russia as well as additional factors (demand bounceback after pandemic, maintenance, shutdown of Groningen field, etc.).

  \centering
  \includegraphics[height=6.8cm]{eu-russia-2024}

  \source{\hrefc{https://www.bruegel.org/dataset/european-natural-gas-imports}{Bruegel, 2024}}
\end{frame}



\begin{frame}
  \frametitle{Gas crisis 2021-2023}

  \centering
  \includegraphics[height=7.8cm]{eu-lng-2024}

  \source{\hrefc{https://www.bruegel.org/dataset/european-natural-gas-imports}{Bruegel, 2024}}
\end{frame}



\begin{frame}
  \frametitle{Gas crisis 2021-2023}

  LNG ships have flocked to Europe, including one on its way to Asia from the US, which turned around mid-Pacific to return through the Panama canal.



  \centering
  \includegraphics[width=6.8cm]{lng_panama.jpg}
  \includegraphics[width=6.8cm]{lng_armada.jpeg}


  \source{\hrefc{https://gcaptain.com/european-energy-crisis-prompts-lng-carriers-u-turn-back-through-panama-canal/}{Bloomberg}}
\end{frame}


\begin{frame}
  \frametitle{Gas crisis 2021-2023: EU natural gas storage filling level}

  \centering
  \includegraphics[height=7.8cm]{eu_gas_storage-2024}

  \source{\hrefc{https://www.bruegel.org/dataset/european-natural-gas-imports}{Bruegel, 2024}}
\end{frame}

\section{Properties and reserves}

\begin{frame}
  \frametitle{Gaseous fuels introduction}

  \begin{itemize}
  \item \alert{Fossil gas}, also known as \alert{natural gas} (to distinguish it from coal-derived gas), consists primarily of \alert{methane} (CH$_4$).
    \begin{itemize}
    \item \alert{H gas} - high-calorific natural gas ($\sim 87-99\%$ CH$_4$ content $\to$ higher heat value)
    \item \alert{L gas} - low-calorific natural gas ($\sim 80-87\%$ CH$_4$ content, rest nitrogen and carbon dioxide, used to be produced in North Germany \& Netherlands, phased out)
    \end{itemize}
    \item \alert{Liquefied petroleum gas (LPG)} (Autogas in DE) - mainly propane and butane,
    byproduct of oil refinery process
  \item \alert{Town/coal/coking gas} - byproduct of coke plants (mix of CH$_4$, H$_2$, CO, CO$_2$, N$_2$)
    \item \alert{Hydrogen} - used as chemical feedstock, could be used in transport / iron reduction / heating / backup for electricity, could also be produced without CO$_2$ emissions
  \end{itemize}

\end{frame}


\begin{frame}
  \frametitle{Gaseous fuels properties}

  \centering
  \includegraphics[height=7.8cm]{properties_gaseous_fuels.png}

  \source{Zweifel / Praktiknjo / Erdmann, 2017}
\end{frame}
\begin{frame}
  \frametitle{Natural gas conversion}

    \centering
    \includegraphics[width=14cm]{ng_conversion.png}

    \raggedright
    Nm$^3$: normal cubic metre at 1.013 bar and 0$^\circ$ C, sometimes written cm for cubic metre

    scf: standard cubic foot at 1.013 bar and 60$^\circ$ F = 15.6$^\circ$ C

    MJ, kWh: at lower heating value (LHV)

  \source{Zweifel / Praktiknjo / Erdmann, 2017}
\end{frame}


\begin{frame}
  \frametitle{EU natural gas demand by sector}

\begin{columns}[T]
  \begin{column}{6cm}

    \centering
    \includegraphics[height=7.5cm]{gas_demand_by_sector.png}
  \end{column}
  \begin{column}{6cm}

    \begin{itemize}
      \item Gas demand in EU27 dominated by buildings (i.e. space and water heating), industry (i.e. for heat and including non-energy feedstocks for e.g. ammonia) and power generation
      \item Gas industry expects demand to rise, while scenarios compatible with the Paris Agreement require it to decline in all sectors
    \end{itemize}
  \end{column}
\end{columns}

  %\url{https://twitter.com/ntsafos/status/1487100457935904775}
  \source{Eurostat}
\end{frame}

\begin{frame}
  \frametitle{Natural gas extraction}

  \begin{itemize}
  \item \alert{Conventional natural gas}
  \begin{itemize}
     \item Extracted from gas deposits by conventional means (vertical drilling)
      \item Associated gas - released during oil extraction (often flared but
  can be utilised)
  \end{itemize}

\item \alert{Unconventional natural gas}
  \begin{itemize}
 \item Shale gas ($>$1000 m deep) - extracted by fracking
 \item Coal bed methane - found in coal formations (300-1000 m
   deep)
 \item Methane hydrates - found on ocean seabed
  \end{itemize}
  \end{itemize}
\end{frame}


\begin{frame}
  \frametitle{Global gas resources and reserves}

  Results are in trillion m$^3$ (German Billion) or Tm$^3$ = 10$^{12}$m$^3$.

    \centering
    \includegraphics[height=7.2cm]{ene_total_gas_potential_2019_g.jpg}

  \source{\hrefc{https://www.bgr.bund.de/EN/Themen/Energie/Erdgas/erdgas_node_en.html}{BGR, 2019}}
\end{frame}


\begin{frame}
  \frametitle{Global gas extraction}

    \centering
    \includegraphics[height=7.8cm]{gas-production-by-country-2022.png}

    \source{\hrefc{https://ourworldindata.org/grapher/gas-production-by-country}{Our World in Data, 2024}}
\end{frame}

\begin{frame}
  \frametitle{Russian pipeline imports dominated supply in Central/Eastern Europe}
    \centering
    \includegraphics[height=7.5cm]{Major_russian_gas_pipelines_to_europe.png}

    \source{\hrefc{https://commons.wikimedia.org/wiki/File:Major_russian_gas_pipelines_to_europe.png}{Wikimedia}}
\end{frame}

\begin{frame}
  \frametitle{EU imports of natural gas by source}

  The EU imports $\sim$4000~TWh/a or 400~bcm/a of natural gas through pipelines and LNG.

  \centering
  \includegraphics[height=7cm]{eu-gas-imports-2024}

  \source{\hrefc{https://www.bruegel.org/dataset/european-natural-gas-imports}{Bruegel, 2024}}
\end{frame}

\begin{frame}
  \frametitle{EU LNG imports to member states in Q3 2021}

    \centering
    \includegraphics[height=7cm]{lng_imports-2021.png}

    \source{\hrefc{https://ec.europa.eu/info/news/quarterly-market-reports-confirm-influence-global-gas-prices-eu-third-quarter-2021-2022-jan-17_en}{European Commission, 2021}}
\end{frame}

\section{Gas Pipelines}

\begin{frame}
  \frametitle{European pipeline network}
    \centering
    \includegraphics[height=7.5cm]{european-gas-supply-diw.jpg}

    \source{DIW, 2018}
\end{frame}


\begin{frame}
  \frametitle{Physics of Gas Pipelines}

  The \alert{throughput} $Q$ [m$^3$/h] of a gas pipeline is given by (approximately)
  \begin{equation*}
    Q \sim \sqrt{\frac{P_1^2-P_2^2}{\ell/d^2}}
  \end{equation*}
  %P = N/m2 = kgm-1s-2
  %Q = (kg2m-2s-4/(m/m2))0.5 = doesn't work out - must be constants involved

  % if Q = c formula, what is c?
  % if we have Q = 3 Mm3/h, P1 = 80, P2 = 79, l = 100 km, d = 1.2 m then RHS = 2.2896, so c = 1.3 to get Mm3/h out
  % try for energy.pdf example: P1=70, P2=69.5, l=550 km, d = 0.76, get 0.095 Mm3/h, they have 0.068 sm3/h, so roughly right

  where $P_1$ and $P_2$ are the pressures at the start and end of the pipe, $\ell$ is the length of the pipeline section (between two compressor stations) and $d$ is the diameter. More complicated formulae can account for height differences and pipe roughness.

  Pipeline \alert{capacity} is the maximum thoughput.

  Pipeline pressures can be up to 80 bar, with a diameter of up to 1400 mm (e.g. OPAL pipeline) and covering a distance of up to 6000 km.

  \alert{Compressor stations} along the pipeline compensate for
  pressure losses (0.1 bar per 10 km) due to frictional
  losses/changing elevation and are placed at intervals of 80-400~km.
  Compressors use energy from natural gas, consuming around 10\% of gas over 5000 km.

  Single 80 bar pipeline can transport up to 3 mcm/h (or 26 bcm/a) at speeds up to 40~km/h.

\end{frame}


\begin{frame}
  \frametitle{Economics of Gas Pipelines}

  %3 Mm3/h is 31 MkWh/h = 31 GW and costs 1 MEUR/km, i.e. 33 EUR/MW/km
  %In technology-data we have 79 EUR/MW/km for methane overland pipeline.


  \begin{itemize}
  \item Long-distance gas transport is not necessarily a natural
    monopoly - can have \alert{pipe-to-pipe} competition
    (i.e. parallel pipes) or \alert{pipe-in-pipe} competition (where companies co-own pipeline).
  \item Have strong \alert{economies of scale} (when doubling capacity, costs rise only 66\%).
  \item \alert{Hold-Up Problem:} After realizing a pipeline project,
    the investor finds themself in a strategically weak position based
    on the irreversible nature of the investment (\alert{sunk
      cost}). The pipeline operator's profit depends on the goodwill
    of the contract partner located at the end (beginning) of the
    pipeline.
  \end{itemize}
\end{frame}



\begin{frame}
  \frametitle{Game Theory: Double Marginalisation}

  \begin{itemize}
  \item Two companies: monopolistic gas importer who supplies the
    retail market, and a monopolistic pipeline operator who is also a
    dominant gas producer in the exporting country
  \item In the first step of the game theoretic model the pipeline operator
    optimizes their pipeline capital stock $K$. In the second step the
    import price $p_{imp}(K)$ is determined by negotiations between the
    two monopolists
   \item Both parties optimize independent from each other their profit
    (\alert{non-cooperative game})
   \item Mathematical solution of the model in the opposite order: First the
    condition for the import price is determined, i.e. the result of the
    negotiations between the two monopolists in step two. Then determine $K$.
  \item To determine $p_{imp}(K)$, the gas producer is able to infer the import price
    resulting from gas import's optimisation based on
    the domestic demand curve. It then optimises its
    profit at the given import price.
  \end{itemize}
\end{frame}


\begin{frame}
  \frametitle{Retail Gas Price set by the Monopolistic Gas Importer}

  For linear inverse demand function $p_{retail}(Q) = a - b\cdot Q$ and given import price $p_{imp}$ (importer's marginal cost neglecting other cost elements), the gas retailer optimises its profits.
\begin{columns}[T]
  \begin{column}{5.5cm}

  \begin{tikzpicture}[
    scale=1.7,
    demand/.style={blue, thick},
    supply/.style={red, thick},
    axis/.style={very thick, ->, >=stealth', line join=miter},
    important line/.style={thick}, dashed line/.style={dashed, thin},
    every node/.style={color=black},
    dot/.style={circle,fill=black,minimum size=4pt,inner sep=0pt,
      outer sep=-1pt},
  ]
  % axis
  \draw[axis,<->] (2.5,0) node(xline)[right] {$Q$} -|
  (0,2.5) node(yline)[above] {$p$};
  % demand-supply diagram
  \draw[demand] (0,2) coordinate (demand_1)  node[left] {a} --
           (2,0) coordinate (demand_2) node[right] {};
  \draw[demand,dashed line]
  (0,2)  node{} -- (1,0) node[below]{$\frac{a}{2b}$};
  \node[below] at (2,0) {$\frac{a}{b}$};

  \draw[supply] (0,0.5) -- (2,0.5);

  \draw[dashed line]
  (0,1.25) node[left]{$p_{retail}^*$} -- (0.75,1.25) node[dot]{} -- (0.75,0) node[below]{$Q^*$};

  \draw[dashed line]
  (0,0.5) node[left]{$p_{imp}$} -- (1.5,0.5) node[dot]{} -- (1.5,0) node[below]{$Q_C$};

  \node[right] at (0.35,1.75) {$p_{retail}(Q) = a - b\cdot Q$};

\end{tikzpicture}
  \end{column}

  \begin{column}{8.5cm}

    The retailer maximises their profit as a function of $Q$:
    \begin{equation*}
\max_Q \Pi_{imp}(Q) =      \max_Q Q\cdot (p_{retail} - p_{imp}) = \max_Q Q \cdot(a - b\cdot Q - p_{imp})
    \end{equation*}

    Differentiating by $Q$ to find the maximum:
    \begin{equation*}
      \frac{d\Pi_{imp}}{dQ} = a - p_{imp} - 2\cdot b \cdot Q = 0
    \end{equation*}
    so that the optimal sales volume is $Q^*= \frac{a - p_{imp}}{2b}$ and the profit-maximising retail price is $p_{retail}^* = a - b\cdot Q = \frac{a + p_{imp}}{2}$.

    The monopolist retailer determines the quantity based on the intersection of the marginal revenue curve $a - 2 \cdot b \cdot Q$ (dashed line) and the import price $p_{imp}$ .

  \end{column}

\end{columns}

\end{frame}

\begin{frame}
  \frametitle{Game Theoretical View of the Pipeline Operator and Extractor}

  Now turn to producer and pipeline operator (e.g. Gazprom) that seeks to maximise its profit knowing the importer's demand function and hence optimal $Q^*$. They can only control $p_{imp}$ given their cost function $c(K)$ (for the costs of extracting and transporting the gas), which depends on the capacity $K$ and is independent of $Q$ or $p_{imp}$. They maximise profit:
  \begin{equation*}
    \max_{p_{imp}}\Pi_{producer}(p_{imp}) =  \max_{p_{imp}} \left(p_{imp} - c(K) \right)\cdot Q =  \max_{p_{imp}} \left(p_{imp} - c(K) \right)\cdot \frac{a-p_{imp}}{2b}
  \end{equation*}
  By solving for the maximum
  \begin{equation*}
    \frac{d\Pi_{producer}}{dp_{imp}} = -\frac{p_{imp}}{b} + \frac{a + c(K)}{2b} = 0
  \end{equation*}
  we find the optimal import price to be $p_{imp}^* = \frac{a + c(K)}{2}$. Note that this is larger than $c(K)$ as long as $a > c(K)$. Plugging this into $Q^* = \frac{a - p_{imp}}{2b}$ we get $Q^* =  \frac{a -c(K)}{4b}$ and into $p_{retail}^* = \frac{a + p_{imp}}{2}$ we get $p_{retail}^* = \frac{3a + c(K)}{4}$.

\end{frame}


\begin{frame}
  \frametitle{Non-Cooperative Solution as Nash equilibrium}


  This solution whereby each game player  knows the strategies of the others but has nothing to gain by changing their own behaviour is a known as a \alert{Nash equilibrium}.

  The profits of the importer are given by
  \begin{equation*}
    \Pi_{imp}^*  = Q^*\cdot (p_{retail}^* - p_{imp}) = \frac{1}{4b} \left(\frac{ a - c(K)}{2}\right)^2
  \end{equation*}
  and for the extractor/pipeline operator by
  \begin{equation*}
    \Pi_{producer}^* =  \left(p_{imp}^*- c(K) \right)\cdot Q^* = \frac{1}{2b} \left(\frac{ a - c(K)}{2}\right)^2
  \end{equation*}
  so in sum:
  \begin{equation*}
    \Pi_{non-coop}^* = \Pi_{imp}^* +  \Pi_{producer}^* = \frac{3}{4b} \left(\frac{ a - c(K)}{2}\right)^2
  \end{equation*}


  Now what happens if they cooperate?
\end{frame}
\begin{frame}
  \frametitle{Solution under Cooperation}

  Suppose now the importer and pipeline operator+extractor \alert{cooperate} to maximise their total profit $\Pi_{coop}$. Now they are a single vertically-integrated monopoly and optimise:
  \begin{equation*}
    \max_{Q}\Pi_{coop}(Q) = \max_{Q} \left(p_{retail} - c(K)\right)\cdot Q =  \max_{Q} \left(a - b\cdot Q - c(K)\right)\cdot Q
  \end{equation*}
  Now we find (like monopoly example with linear cost function from early lecture)
  \begin{equation*}
    Q^* = \frac{ a - c(K)}{2b}, \hspace{0.7cm} p^*_{retail,coop} = \frac{ a + c(K)}{2}
  \end{equation*}
  Since $c(K) < p_{imp}$, this cooperative retail price is lower than the non-cooperative price, so the consumer welfare increases under the cooperative solution.

  In addition, the profits of the two monopolists also increases if they cooperate, so that overall welfare increases:
  \begin{equation*}
    \Pi_{coop}^* = \left(p^*_{retail,coop} - c(K)\right)\cdot Q_{coop}^*  =
    \frac{1}{b} \left(\frac{ a - c(K)}{2}\right)^2
  \end{equation*}
  There is a welfare loss if two monopolists along the value chain
  don't cooperate (\alert{double marginalisation}). What is worse than a monopoly: two monopolies.

\end{frame}



\begin{frame}
  \frametitle{Comparison double marginalisation}

  Perfect competition: no monopolies; single monopoly: importer and pipeline operator cooperate; double monopoly: double marginalisation.

  Dark red: importer surplus, light red: producer surplus.

  \vspace{.8cm}


  \begin{tikzpicture}[
    scale=1.1,
    demand/.style={blue, thick},
    supply/.style={red, thick},
    axis/.style={very thick, ->, >=stealth', line join=miter},
    important line/.style={thick}, dashed line/.style={dashed, thin},
    every node/.style={color=black},
    dot/.style={circle,fill=black,minimum size=4pt,inner sep=0pt,
      outer sep=-1pt},
  ]
  % axis
  \draw[axis,<->] (2.5,0) node(xline)[right] {$Q$} -|
  (0,2.5) node(yline)[above] {$p$};
  % demand-supply diagram
  \draw[demand] (0,2) coordinate (demand_1)  node[left] {a} --
           (2,0) coordinate (demand_2) node[right] {};
  \node[below] at (2,0) {};%$\frac{a}{b}$};

  \draw[supply] (0,0.5) -- (2,0.5)
    node[right] {};%$\frac{dC}{dQ}$};

  \draw[dashed line]
  (0,0.5) node[left]{$p_C = c$} -- (1.5,0.5) node[dot]{} -- (1.5,0) node[below]{$Q_C = \frac{a-c}{b}$};

  \draw[fill=blue, fill opacity=0.3]
  (0,0.5) -- (1.5,0.5) -- (0,2);

  \node[above] at (1.5,2.5) {perfect competition};



  \begin{scope}[xshift=4cm]

  % axis
  \draw[axis,<->] (2.5,0) node(xline)[right] {$Q$} -|
  (0,2.5) node(yline)[above] {$p$};
  % demand-supply diagram
  \draw[demand] (0,2) coordinate (demand_1)  node[left] {a} --
           (2,0) coordinate (demand_2) node[right] {};
  \draw[demand,dashed line]
  (0,2)  node{} -- (1,0) node[below]{};%$\frac{a}{2b}$};
  \node[below] at (2,0) {};%$\frac{a}{b}$};

  \draw[supply] (0,0.5) -- (2,0.5)
    node[right] {};%$\frac{dC}{dQ}$};

  \draw[dashed line]
  (0,1.25) node[left]{$p_M = \frac{a+c}{2}$} -- (0.75,1.25) node[dot]{} -- (0.75,0) node[below]{$Q_M = \frac{a-c}{2b}$};

  \draw[dashed line]
  (0,0.5) node[left]{$p_C$} -- (1.5,0.5) node[dot]{} -- (1.5,0) node[below]{};%{$Q_C$};

  \draw[fill=red, fill opacity=0.3]
  (0,0.5) -- (0.75,0.5) -- (0.75,1.25) -- (0,1.25);
  \draw[fill=blue, fill opacity=0.3]
  (0,1.25) -- (0.75,1.25) -- (0,2);

  \node[above] at (1.5,2.5) {single monopoly};

  \end{scope}


  \begin{scope}[xshift=8cm]

  % axis
  \draw[axis,<->] (2.5,0) node(xline)[right] {$Q$} -|
  (0,2.5) node(yline)[above] {$p$};
  % demand-supply diagram
  \draw[demand] (0,2) coordinate (demand_1)  node[left] {a} --
           (2,0) coordinate (demand_2) node[right] {};
  \node[below] at (2,0) {};%$\frac{a}{b}$};

  \draw[supply] (0,0.5) -- (2,0.5)
    node[right] {};%$\frac{dC}{dQ}$};

  \draw[dashed line]
  (0,1.625) node[left]{$p_{ret} = \frac{3a+c}{4}$} -- (0.375,1.625) node[dot]{} -- (0.375,0) node[below]{$Q_D = \frac{a-c}{4b}$};

  \draw[dashed line]
  (0,1.25) node[left]{$p_{imp} = \frac{a+c}{2}$} -- (0.375,1.25) node[below]{};

  \draw[dashed line]
  (0,0.5) node[left]{$p_C$} -- (1.5,0.5) node[dot]{} -- (1.5,0) node[below]{};%$Q_C$};

  \draw[fill=red, fill opacity=0.3]
  (0,0.5) -- (0.375,0.5) -- (0.375,1.25) -- (0,1.25);
  \draw[fill=red, fill opacity=0.7]
  (0,1.25) -- (0.375,1.25) -- (0.375,1.625) -- (0,1.625);
  \draw[fill=blue, fill opacity=0.3]
  (0,1.625) -- (0.375,1.625) -- (0,2);

  \node[above] at (1.5,2.5) {double monopoly};

  \end{scope}

\end{tikzpicture}
\end{frame}




\begin{frame}
  \frametitle{Decision of Pipeline Investor}

  So how does this effect the investment in capacity $K$?

  Under non-cooperation the pipeline investor makes profit
  \begin{equation*}
    \Pi_{producer}^* = \frac{1}{2b} \left(\frac{ a - c(K)}{2}\right)^2
  \end{equation*}
  whereas for the same capacity, the pipeline investor makes twice as much
  \begin{equation*}
    \Pi_{coop}^* =
    \frac{1}{b} \left(\frac{ a - c(K)}{2}\right)^2
  \end{equation*}

  Since the pipeline investor will increase $K$ until the marginal
  profit equals the marginal cost of extension, this higher profit will lead to a higher optimal capacity $K$.

  $\Rightarrow$ To come closer to social optimum, should a) encourage
  competition and b) encourage cooperation between pipeline investor
  and retailer to avoid double marginalisation.

\end{frame}


\section{Liquified Natural Gas}

\begin{frame}
  \frametitle{History of Liquified Natural Gas (LNG)}

\begin{columns}[T]
  \begin{column}{8cm}


  \centering
  \includegraphics[width=8.5cm]{smil-lng_history.png}
  \end{column}
    \begin{column}{6cm}
      \begin{itemize}
      \item 1959: first (small) LNG shipment in 1959 in \emph{Methane Pioneer}
      \item 1964: exports of LNG from Algeria to UK begin in tankers \emph{Methane Princess/Progress}
       \item 1970s: Japan comes to dominate, because no domestic
         resources and pipeline imports to Japan are not possible
       \item 1984: Japanese imports accounted for 75\% of all LNG trade
       \item 1999: Japan still 66\% of total
      \end{itemize}

    \end{column}
\end{columns}
  \source{Vaclav Smil `Energy Transitions' (2010)}
\end{frame}


\begin{frame}
  \frametitle{History of Liquified Natural Gas (LNG)}

  LNG really took off since 2000 due to remarkable cost reductions (larger and larger tankers).
    LNG imports to Europe from the Middle East, North Africa and Asia are rising fast.

  \centering
  \includegraphics[height=6.6cm]{lng_over_time.png}


  \source{\hrefc{https://www.statista.com/statistics/264000/global-lng-trade-volume-since-1970/}{Statista 2022}}

\end{frame}

\begin{frame}
  \frametitle{LNG imports by source (bn cubic metres per year)}

  Much of recent growth is coming from Asia.

  \centering
  \includegraphics[height=7cm]{lng_by_region.png}

 \source{BP Statistical Review of World Energy 2019}
\end{frame}
\begin{frame}
  \frametitle{Transportation Cost of Hydrocarbons}

  60~\$/toe is around 5~\$/MWh, 1.5~\$/MMBtu, 0.05~\$/Nm$^3$

    \centering
    \includegraphics[height=6.9cm]{pipeline_vs_lng.png}

  \source{Zweifel / Praktiknjo / Erdmann, 2017}
\end{frame}

\begin{frame}
  \frametitle{Liquified Natural Gas (LNG) Process Chain}

    \centering
    \includegraphics[width=13cm]{lng_chain.png}

  \begin{columns}[T]
    \begin{column}{11cm}
    Boiling point of methane -162$^\circ$C; $\sim$600 times volume reduction

    \includegraphics[width=11cm]{lng_processing.png}
    \end{column}
    \begin{column}{3cm}
    \includegraphics[height=3cm]{lng_boiling.png}
    \end{column}
  \end{columns}
    \source{BV 2009 / GIIGNL, Osaka Gas}
\end{frame}
\begin{frame}
  \frametitle{Major LNG Trading Flows in 2018}

    \centering
    \includegraphics[height=7.5cm]{lng_flows.png}

  \source{Source: GIIGNL, 2019}
\end{frame}
\begin{frame}
  \frametitle{Major LNG Trading Flows in 2018}

    \centering
    \includegraphics[width=14cm]{lng_flows.jpg}

  \source{Source: Platts}
\end{frame}

\begin{frame}
  \frametitle{Cost Structure of LNG Process Chain}

  Costs for a standard LNG chain of 3.5-4.8 mn tons/a (4.8-6.6 bn m$^3$/a), totalling $\sim 0.06$\euro/m$^3$
  \ra{1.1}
  \begin{table}[!t]
    \begin{tabular}{ll}
      \toprule
          {\bf Liquefaction plant} & \\
          Investment outlay & 900 M\euro \\
          Operating expenses & 0.04 \euro/m$^3$ \\
       \midrule
          {\bf Tanker fleet} & e.g. 2 vessels with 135 kt each\\
          Investment outlay & 360 M\euro{} for both \\
          Operating expenses & 0.014 \euro/m$^3$ \\
       \midrule
          {\bf Regasification plant w. storage} & e.g. storage 3*80k m$^3$ (Cartagena)\\
          Investment outlay & 320 M\euro \\
          Operating expenses & 0.015 \euro/m$^3$ \\
       \midrule
           {\bf Own gas energy requirement} & 1/3 of transport gas\\
           \bottomrule
    \end{tabular}
  \end{table}

  \source{Zweifel / Praktiknjo / Erdmann (2017), after Cayrade (2014)}
\end{frame}

\begin{frame}
  \frametitle{LNG Project Cost Comparison}
    \centering
    \includegraphics[height=7.5cm]{lng_project_costs.png}

    \source{Songhurst, OIES, 2018}
\end{frame}

\begin{frame}
  \frametitle{LNG Impact on Global Gas Markets}


  \begin{itemize}
  \item   LNG trade leads to integration of regional gas markets
    \item LNG supply chain is more flexible
\item LNG helps to develop more remote gas fields
\item Diversification helps mitigate the holdup problem
  \end{itemize}
\end{frame}


\section{Gas Storage}

\begin{frame}
  \frametitle{Gas storage technologies}

      \centering
    \includegraphics[height=7.5cm]{gas_storage.png}

\end{frame}


\begin{frame}
  \frametitle{Gas storage facilities: Underground}

  \alert{Porous rock storage}
  \begin{itemize}
  \item uses existing geological underground formations (e.g. depleted oil and gas fields, aquifers)
    \item relatively inexpensive (but higher investment costs for aquifers)
\item large storage volume, but more cushion gas required
\item low injection and withdrawal rate
  \end{itemize}

  \alert{Cavern storage}
  \begin{itemize}
  \item artificial hollows carved out in underground rock or salt formations
    \item higher investment
\item less cushion gas required
\item higher withdrawal rate; fast switching between injection and withdrawal mode
\item provide short-term flexibility
  \end{itemize}
\end{frame}


\begin{frame}
  \frametitle{Gas storage facilities: Above-ground}

  \alert{LNG storage}
    \begin{itemize}
  \item Insulated tanks at LNG terminals
  \item No cushion gas needed
\item High injection/withdrawal rates
    \end{itemize}

    \alert{Gas tanks}
      \begin{itemize}
  \item Low or high pressure
    \item Not economical for high volumes
\item Local storage
      \end{itemize}

      \alert{Line pack}
        \begin{itemize}
  \item Gas stored inside pipeline through increased pressure
  \item Used to balance daily demand fluctuations
        \end{itemize}
\end{frame}

\begin{frame}
  \frametitle{Gas storage facilities in Germany}

  Max. usable working gas volume on 31.12.2018, in TWh. See \hrefc{https://agsi.gie.eu/}{AGSI website} for latest.

      \centering
      \includegraphics[height=7.3cm]{gas_storage_de.png}

      \source{BNetzA, 2019}

\end{frame}

\begin{frame}
  \frametitle{Merchant Use of a Gas Storage}
        \centering
        \includegraphics[height=7.5cm]{gas_storage_over_time.jpg}

        \source{Prof. Erdmann}

\end{frame}


\begin{frame}
  \frametitle{EU27: Filling level development}

  The filling level follows seasonal patterns; 2021-3 have been exceptional due to cold spring in 2021, low domestic production
  and low Russian supplies.


  \centering
  \includegraphics[height=6.5cm]{eu_gas_storage-2023}

  \source{\hrefc{https://www.bruegel.org/dataset/european-natural-gas-imports}{Bruegel, 2023}}
\end{frame}


\begin{frame}
  \frametitle{Value of gas storage}

  \begin{itemize}
  \item   Storage buffers supply and (daily \& seasonally fluctuating) demand
  \item Value of storage is determined by the cost of alternative sources of flexibility (transportation and capacity charges):
  production swings, take-or-pay, interruptible contracts, spot market
\item   \alert{System value} from ability to inject a certain amount of gas in summer and withdraw it in winter
\item Compensated by price during withdrawal minus price during injection, i.e. arbitrage with \alert{seasonal spread} (difference in seasonal price)
  \item  Ability to utilise the storage volume more than once (inject and withdraw gas) during the season to profit from short-term price volatility
  \end{itemize}

\end{frame}


\section{Wholesale Markets for Gas}

\begin{frame}
  \frametitle{Dynamics of Gas Market Development}

  \centering
  \includegraphics[height=7.8cm]{dynamics_gas_markets.png}

  \source{Energy Charter Secretariat (2007) with reference to Konoplyanik}
\end{frame}




\begin{frame}
  \frametitle{Regulatory push for move from LTC to spot market}

  The European Union's Third Energy Package, which entered into force
  in 2009, sought to promote an internal gas and electricity market.

  The components included ownership unbundling (generation and supply
  from transmission) and a (non-binding) push to move away from
  long-term contracts to spot pricing in the gas market.

  \alert{Why?}

  LTC prices are intransparent and showed big differences between
  regions. It was hoped liberalisation would encourage competition,
  create more market liquidity and bring down prices for consumers.

\end{frame}



\begin{frame}
  \frametitle{Long-term gas supply contracts in Europe}

  LTCs in decline for past 15 years; note that LTCs not just for pipeline import, but also LNG.

      \centering
    \includegraphics[width=14cm]{ltc-share.png}

    \source{\hrefc{https://link.springer.com/content/pdf/10.1007/s11151-019-09697-3.pdf}{Chyong, 2019}}
\end{frame}

\begin{frame}
  \frametitle{Vertical Integration or Long-Term Contracts}


  In a world without vertical integration of (foreign) gas supplier and (domestic) gas importer, \alert{long-term gas contracts} necessary in order to secure cash-flows required for pipeline (and other gas infrastructure) investments.

  Selection of Gazprom's long term contracts 2007:
  \begin{itemize}
  %\item  Gaz de France – until 2030
    \item  E.ON Ruhrgas – until 2035, 20 bcm/year
  \item Wintershall  – until 2030
  %\item Gazum – until 2025 (Finland)
      \item ENI – 2035, 3 bcm/year (Italy)
  \end{itemize}

  Gazprom as shareholder of European gas companies 2007:
    \begin{itemize}
  \item Wingas (50\% minus 1 share, 100\% since 2013): 2000 km Gas transmission lines, Natural gas storages in Germany with 2 bcm gas volume
\item   Europolgaz (48\%), Eesti Gas (37.2\%), Lietuvos Dujos (37.1\%), Latvijas Gaze (34\%), Gasum (25\%), VNG (10.52\%), Interconnector (10\%)
    \end{itemize}
\end{frame}

\begin{frame}
  \frametitle{Take-or-Pay-Clause in Long Term Contracts}

  A long-term contract (LTC) must specify both \alert{volume} and \alert{price}. Both are associated with risks.
  For a \alert{take-or-pay} contract, the \alert{volume risk} is taken by the
  importer. If they use less than the contracted \alert{minimum take},
  they have to pay for it anyway.


      \centering
    \includegraphics[height=4cm]{take-pay.png}

    \raggedright
    The \alert{price risk} is taken by the exporter, who may \alert{index the price} according to the heating oil price (common up to 2010s) or to spot market prices (more common today).

\end{frame}


\begin{frame}
  \frametitle{Volume Flexibility Under Long Term Contracts}

      \centering
    \includegraphics[height=7cm]{ltc-volume}

  \source{European Commission, Energy sector inquiry 2005-2006}

\end{frame}




\begin{frame}
  \frametitle{Price-Indexing}

  \alert{Price-indexing} refers to determining the price of long-term contracts based on other indices.

\begin{columns}[T]
  \begin{column}{9cm}

     \centering
     \includegraphics[height=7cm]{price-index.jpg}

  \end{column}
  \begin{column}{5cm}

    This example shows a 6/1/3 rule (6/3/3 is more typical for long-term gas contracts).

    \begin{itemize}
    \item 6 months: period over which we take average for price.
    \item 1 month: time lag to allow for calculation.
    \item 3 months: delivery period to which price applies.
    \end{itemize}
  \end{column}
\end{columns}

\source{WINGAS}
\end{frame}


\begin{frame}
  \frametitle{In past, gas often linked to oil}


  In 2004, oil-derivatives dominated the price indexation in the European Union:

     \centering
     \includegraphics[width=14cm]{eu-oil-indexation-2004.png}



  \source{\hrefc{https://ec.europa.eu/competition/sectors/energy/2005_inquiry/full_report_part1.pdf}{EC 2007 Energy Sector Enquiry}}
\end{frame}


\begin{frame}
  \frametitle{In past, gas often linked to oil}


  In 2004, there was a wide variety of products used for indexation in different regions.

     \centering
     \includegraphics[height=6.8cm]{variety-oil-indexation.png}



  \source{\hrefc{https://ec.europa.eu/competition/sectors/energy/2005_inquiry/full_report_part1.pdf}{EC 2007 Energy Sector Enquiry}}
\end{frame}


\begin{frame}
  \frametitle{In Germany in past, strong coupling with heating oil}

  Because heating oil was a substitute for gas, the light heating oil Rheinschiene (HEL-Rhein) was used.

     \centering
     \includegraphics[height=6.8cm]{german-oil-coupling}

  \source{BAFA}
\end{frame}


\begin{frame}
  \frametitle{Today: stronger link to gas spot prices}

  But since early 2010s more contracts are linked to gas spot prices such as the TTF virtual hub in the Netherlands. (BAFA is Germanborder import price.)

     \centering
     \includegraphics[height=6.5cm]{ttf-bafa.png}


  \source{\hrefc{https://www.igu.org/wp-content/uploads/2017/03/Komlev_IGU_-March_7_Final.pdf}{Gazprom}}
\end{frame}

\begin{frame}
  \frametitle{Move from oil-indexing to gas-on-gas competition}

\begin{columns}[T]
  \begin{column}{9cm}

     \centering
     \includegraphics[height=7.5cm]{europe-price.png}

  \end{column}
  \begin{column}{5cm}
    \begin{itemize}
    \item Move from oil-price-indexing (OPE) to gas-on-gas competition (GOG), e.g. based on hub pricing at TTF
      \item Share of oil-indexation in Europe dropped from 78\% in 2005 to 22\% in 2019
    \end{itemize}
  \end{column}
\end{columns}
  \source{Gazprom; Wholesale Gas Price Survey 2020 Edition}
\end{frame}


\begin{frame}
  \frametitle{Third-Party Access to Gas Infrastructure}

  Non-discriminatory (effective and transparent) access to gas transportation systems is a crucial prerequisite for a liquid market for natural gas.

Unbundling for gas TSOs (see EU Gas Directive 2009/73/EC):
Transmission and distribution activities are separated from the rest of the value chain
  \begin{itemize}
  \item Ownership unbundling
\item Independent system operator (ISO)
\item Independent transmission operator (ITO)
  \end{itemize}

  Certification to ensure compliance with unbundling requirements for transmission system owner or TSO controlled by person(s) from third country(ies)

  `Gazprom clause'
\end{frame}

\begin{frame}
  \frametitle{Gas Network Access Models}

  \alert{Point-to-point system}  (used in Germany until 2006)
    \begin{itemize}
  \item  gas traders book specific transportation route from an entry to an exit point
  \item distance-based or flatrate fee
   \item somewhat intransparent, high costs
    \end{itemize}

    \alert{Entry-exit system} (used in Germany since 2006)
    \begin{itemize}
  \item   entry and exit capacities are booked separately
  \item entry fee and exit fee – no distance-related fee
  \item traders with  entry capacities can sell gas to traders with exit capacities
    \item each exit point can be supplied from any entry point
    \end{itemize}

  Entry-exit system enables wholegas gas trading on virtual trading point (\alert{virtual hub}) / market area level: gas is traded independently of its location in a market area.
\end{frame}


\begin{frame}
  \frametitle{Point-to-point model}

  \begin{itemize}
    \item Shippers specify entry and exit points and the transportation path.
      \item Actual physical flow may differ from the contracted path.
      \item Entry and exit capacities cannot be separated from each other and from the gas (commodity) transaction.
      \item Led to intransparency and high costs.
  \end{itemize}


  \centering
     \includegraphics[height=4.5cm]{p2p-model.png}

  \source{Hewicker \& Kesting, 2009}
\end{frame}


\begin{frame}
  \frametitle{Entry-exit model (used in Germany since 2006)}

  \begin{itemize}
  \item Shippers book entry and exit capacity independently from each other.
\item    No need to specify transportation path or distance.
\item    Contracts for entry and exit capacities are independent from each other and from commodity transactions.
\item     Entry and exit tariffs are set independently for each entry/exit point
\item    All network operators in a network zone cooperate and set tariffs on a cost-reflective basis.
  \end{itemize}


  \centering
     \includegraphics[height=3.5cm]{entry-exit-model.png}

  \source{Hewicker \& Kesting, 2009}
\end{frame}


\begin{frame}
  \frametitle{Gas hubs both physical and virtual}

  \alert{Physical gas hubs} where many pipelines meet e.g.
  \begin{itemize}
  \item  Henry Hub (USA) – connecting point of 14 pipelines
    \item Zeebrugge (Belgium)
    \item Baumgarten (CEGH, Austria)
  \end{itemize}


  \alert{Virtual gas hubs} for trading, e.g.
  \begin{itemize}
  \item NBP, National Balancing Point (UK)
    \item TTF, Title Transfer Facility (Netherlands)
  \end{itemize}

  \vspace{1cm}

  (Cf. electricity grids with physical substations versus bidding zones.)
\end{frame}


\begin{frame}
  \frametitle{European gas regions, markets and hubs}

      \centering
    \includegraphics[height=7.5cm]{gas_hubs.png}

    \source{OIES (2017) with reference to www.worldatlasbook.com and P. Heather}

\end{frame}



\begin{frame}
  \frametitle{Transmission tariffs in August 2017}


      \centering
      \includegraphics[height=7.5cm]{entry-exit-tariffs.png}


      \source{\hrefc{https://ec.europa.eu/energy/sites/ener/files/documents/quo_vadis_report_16feb18.pdf}{European Commission, 2018}}
\end{frame}

\section{Hydrogen network}


\begin{frame}
  \frametitle{German planned Wasserstoff-Kernnetz: hydrogen core network}


\begin{columns}[T]
  \begin{column}{7cm}

     \centering
     \includegraphics[height=7.5cm]{kernnetz.png}
  \end{column}
  \begin{column}{7cm}
    \begin{itemize}
    \item As of 2024 hydrogen is only used within industrial facilities (like refineries and ammonia production), there is no hydrogen market.
    \item There are some small-diameter pipelines of a few 100 kms.
     \item Clean hydrogen (green or blue) could be used in the future for steel production, ammonia, other chemicals and for power generation.
    \item The gas transmission network operators (FNB Gas) have suggested a plan for a \alert{Kernnetz} (left), completed by 2032.
    \end{itemize}
  \end{column}
\end{columns}

  \source{\hrefc{https://fnb-gas.de/wasserstoffnetz-wasserstoff-kernnetz/}{FNB Gas, 2023}}

\end{frame}


\begin{frame}
  \frametitle{Germany hydrogen core network}

  \begin{itemize}
  \item Cost of the Kernnetz is estimate to be €19.8 billion, length around 9,700 km, of which 60\% is \alert{repurposed gas pipelines}.
    \item Network operators get 6.69\% guaranteed return on equity.
    \item Since it is unclear how much supply or demand there will be, the network charges could be very high at the beginning (high costs divided by small demand), so the network charges will be capped (level is not clear).
    \item Money needed above the network charges will be paid out of a separate government-run account.
    \item If there is money left in the account in 2055, government will cover 76\%, network operators 24\%.
  \end{itemize}



\end{frame}

\end{document}
