Minimum Volume Commitments
A guide to modelling and evaluating minimum commitment scenarios – by Andrew Taccone
As the name suggests, minimum volume commitments are agreements between upstream producers and another party such as a midstream company. The producer agrees to flow or transport an agreed upon commodity volume (gas, oil, or other products) through the midstream company’s transportation system while the midstream company agrees to leave a fixed amount of space available for the producer within the pipeline.
An everyday example of this situation would be season ticket purchases for a sports team. As a purchaser, you make a conscious decision before the season that you would like to attend all of this year’s home games, so you purchase season tickets to reserve your seats at a fixed price per game. The tickets are prepaid and do not take into account supply and demand for certain games throughout the year. If unforeseen circumstances occur and you are unable to attend one of the games, the tickets can be sold on a secondary market to recuperate your expenses, or the tickets can be considered a sunk cost.
Producers enter into these agreements for two reasons. Since the midstream company is receiving a guarantee of throughput, the producer receives a favorable fixed rate compared to interruptible rates. Additionally, the producer is able to ensure that their anticipated production in an area is able to get to market.
Midstream companies write these agreements because they guarantee future revenue regardless of commodity pricing.
Evaluating Minimum Volume Commitment scenarios
When commodity prices are high, producers can look back at these agreements with a sigh of relief. They have “reserved” space on the pipeline and will not have to pay high interruptible rates for capacity. However, as the laws of supply and demand dictate, when prices begin to decrease due to an increase in the quantity supplied within the market, producers will in-turn cut back on drilling and completions to preserve capital for a more favorable economic environment. This overall change in activity will lower forecasted production in the short-term and put companies at risk of not meeting the minimum volume requirements they agreed to. Decisions around entering into these agreements, and managing production within them, will lead to a variety of management questions:
- How do we determine drilling pace, and the order of wells or locations to meet our firm volume commitments?
- Depending on the chosen development plan, how will field and project level economics be affected?
- If we have multiple points of sale and firm commitment contracts, which contracts do we look to fill first, and how do we do this efficiently?
- If we continue to drill at our current pace with currently more favorable rig and frac crew costs, does it make sense to pay for interruptible FT (firm transportation or pipeline capacity) on top of our firm commitments?
- If we decrease activity or stop drilling/completing wells, how much will we pay in lost pipeline commitments over a certain period of time?
To evaluate each of these situations, we need to consider a number of factors:
- Capital – Investment needed to bring a project to a commercially operable status
- Production forecasts – Projections or estimations related to the future output of a well
- Curtailments – Restriction of gas flows due to volume constraints between the well and point of sale
- Pricing – Internally created or public information, i.e. NYMEX or Henry Hub. Can vary over time.
- Basis differentials – The difference between the base price assumption and the corresponding cash spot price for natural gas in a specified location
- Firm commitment contracts and rates – Minimum commitment contracts and associated throughput rates
- Potential paths to market – Well volumes may be able reach multiple pipelines and sales points associated with different pricing and available throughput
- Resources/Scheduling – Availability of resources such as drilling rigs and frac crews during the time periods needed
- Operational costs – Fixed and variable costs related to operating a well
- Discount rates – Weighted average cost of capital for the company
Capital is one of the most important factors related to evaluating these types of scenarios. The graph below depicts two different capital spend scenarios over an approximately three-year period. The scenario in orange or “scenario 1” represents upfront capital spend during the current year, while the blue line “scenario 2” allocates capital over a number of years. To evaluate which scenario makes more sense in a situation with minimum volume commitments we need to look at some of the additional factors listed above such as production, commitment volumes and pricing.
The graph below shows production related to the two capital scenarios above, with scenario 1 represented in orange and scenario 2 represented in blue. The two capital scenarios yield drastically different upfront production, with rates converging in 2019. In an unconstrained or perfect environment, the orange production curve for scenario 1 would most likely be the best option for a company due to higher production in the current year coupled with a lower discount rate. Unfortunately, it is tough to find a perfect environment and the majority of operators must take into account their minimum commitments and interruptible FT rates associated with flowing additional gas.
In scenario 1, if we had a minimum commitment of approximately 50,000 mcf/d, we would receive preferential transportation rates for production within the contract, but have to pay significantly more for the excess throughput starting in May 2016 for the foreseeable future. Compared to scenario 2, scenario 1 would yield a greater “Total Operating Income” in the current period, but the per-unit cost of production would also be greater.
The second scenario would keep production much flatter, around the 50,000 mcf/d contract for a significantly lower per unit cost, but total operating income would also be lower in the current year. This lower total operating income may raise an internal red flag, but the lower per unit costs would likely translate into higher profit margins over time, especially if internal price forecasts are favorable over the long-term.
Pipeline basis differentials and pricing will also help us in evaluating these two scenarios. If the company has forecasted Gas prices to increase significantly over the next three years, as well as declining differentials, scenario 2 may produce better overall economics compared to scenario 1. This would occur because of the higher net gas price in later years coupled with greater production in these periods compared to scenario 1.
To further evaluate these scenarios, we must also consider resource availability during the evaluation. Scenario 2 may look better from a purely economic standpoint, but it would also require rigs and frac crews to be available on demand or under contract throughout the entire three-year period. In scenario 1 the company would only need resources for the first half of the current year in order for all wells within the program to start producing. These types of managerial decisions are not easy or straightforward, but factors such as the speed related to capital allocation and field development can have significant positive or negative effect on the overall project NPV.
With multiple factors coming into play, this type of scenario analysis is not easy. Companies cannot evaluate these complex situations based on one or two factors alone. Whether planners are using a combination of NPV (net present value) and IRR (internal rate of return) or are using a Net Asset Value model to compare their choices, they must employ tools that will help them rapidly consider multiple options while considering all economic factors, resources and constraints.
Planners must consider these types of situations holistically – with all relevant information incorporated. Failure to do so can lead to inaccurate analysis and result in choosing a scenario that is less optimal for the company and its shareholders.
About the author
Drew Taccone is a Business Development Consultant with 3esi-Enersight operating in the Pittsburgh area. Prior to working for Enersight he worked for Consol Energy and brings over 6 years of experience within the Oil & Gas and Financial industries. Drew has helped our clients within the region model production, economics, and scenario analyses. He can also help answer complex industry specific questions and assist with workflow management and integration.
3esi-Enersight is the world leading provider of solutions for integrated strategy, planning and execution in upstream oil and gas. From the field, to the boardroom, in operations across 6 continents, 3esi-Enersight is empowering E&P organizations to maximize the value of their upstream portfolios and stay ahead of the competition. Our solutions help customers work more efficiently across teams and functions and make better strategy and planning decisions based on data they can trust.