Streamline Energy Partners
A case study on managing pipeline capacity using incremental cost analysis for use in graduate and executive education.
This case study1 introduces incremental cost pricing principles through an engaging Oil & Gas industry application. The case involves both calculating effective prices and integrating business strategy and business operations into the pricing decision. The teaching note, posted separately, provides a comprehensive solution to the pricing calculations and more background context.
Streamline Energy Partners
Streamline Energy Partners (SEP) is a US-based mid-tier operator in the highly competitive midstream sector of the oil & gas industry. The company was founded in 2007 during the early years of the shale gas revolution and has weathered the ups and downs of several industry cycles. It has acquired or merged with more than one smaller regional pipeline operator and dealt with the adversities arising from the 2014-2016 oil price collapse and the COVID-19 demand shock of 2020. Unlike vertically integrated companies that it competes with, SEP is a pure-play. Its revenue depends almost entirely on the fees earned from transporting natural gas, making asset optimization and contract management critically important concerns for the company’s executives.
The midstream sector faces significant challenges currently, including pipeline overcapacity in key regions, heightened regulatory scrutiny, and the uncertainty surrounding the implications of the energy transition and the AI boom. Despite these pressures, natural gas still remains a widely accepted bridge fuel in the United States2. As such, SEP must make informed decisions about capacity utilization, expansion, and pricing to sustain its profitability.
SEP owns and operates a 200-mile pipeline system transporting natural gas from East Texas to processing facilities along the Gulf Coast. This infrastructure includes a main pipeline, four compressor stations, several upstream receipt points, and downstream delivery connections. Its nameplate capacity, defined as the maximum rated throughput under full compression, is 600 million cubic feet per day (MMcf/d). Current throughput averages 450 MMcf/d. SEP holds long-term contracts covering 400 MMcf/d, at a rate of $0.30 per thousand cubic feet (Mcf).
The following financial and operational information about SEP’s pipeline system operations is relevant for the company’s current dilemma, which forms the focus of this case. All costs below are reported on a monthly basis.
Category A: Direct System Expenses
Pipeline Maintenance: $300,000 base plus $5 per MMcf
Control Room Operations: $180,000
Compression Fuel: $60 per MMcf
Electricity for Pump Stations: $45 per MMcf
Chemical Treatment (corrosion inhibitors, etc.): $25 per MMcf
Operational Personnel: $120,000 base plus $15 per MMcf for overtime work
Metering and Sampling: $10 per MMcf
Pipeline Pigging Operations: Typically performed monthly at $75,000 regardless of volume, with additional runs at $5 per MMcf
Emissions Monitoring: $40,000 base plus $8 per MMcf for variable monitoring requirements
Waste Disposal: $7 per MMcf
Category B: Land and Legal Expenses
Right-of-Way Fees: $120,000 (annual payment of $1.44M divided into monthly installments)
Property Taxes: $75,000
Regulatory Compliance: $85,000
Legal Department Allocation: $70,000
Category C: Corporate Allocations
Administrative Overhead: $250,000 allocation
Information Technology: $60,000
Human Resources: $50,000
Executive Compensation: $90,000
Category D: Financial Expenses
Insurance: $90,000 base plus additional premium based on throughput
Depreciation: $420,000 (calculated on a straight-line basis from the original pipeline cost)
Interest on Debt: $200,000 (financing for original construction and previous upgrades)
Integrity Management Program: $110,000 (required by federal regulations)
On the basis of this revenue and cost structure, the company's most recent monthly financial statement shows the following financial performance:
Revenue: $4,050,000
Total Expenses: $4,495,000
Monthly Operating Income: -$445,000
Note: The revenue calculation is based on actual transported volumes, while some expenses vary with throughput and others remain constant regardless of utilization levels.
SEP’s executive team is concerned about the project’s negative profit margin and is considering four strategic options to improve the financial performance:
Option 1: Renegotiate base contracts
Offer existing customers a reduced rate of $0.28/Mcf if they increase their minimum volume commitments by 15%. Market analysis suggests that producers would accept this offer, bringing the guaranteed volume to 460 MMcf/d. This type of renegotiation would cost approximately $75,000 in legal fees.
Option 2: Pursue spot market contracts
Actively market the remaining capacity at $0.345/Mcf. Due to market volatility, the company expects to secure additional volumes of 85 MMcf/d but would need to hire two additional commercial representatives, each compensated at $15,000/month, and invest in an enhanced nomination system ($50,000 one-time cost, depreciated over 24 months).
Option 3: Expand pipeline capacity
Add compression stations to increase maximum capacity to 750 MMcf/d. This would require:
Capital investment: $12 million (depreciated over 15 years)
Additional maintenance costs: $80,000/month
Additional personnel: $60,000/month
Increased insurance: $30,000/month
Additional regulatory compliance: $25,000/month
Marketing analysis suggests this expansion would allow SEP to secure new long-term contracts for 200 MMcf/d at $0.25/Mcf, while also increasing electricity costs for pump stations to $50/MMcf and compression fuel to $65/MMcf for all volumes.
Option 4: Offer a premium service
Develop a so-called Premium Reliability Service offering guaranteed priority shipping during peak demand periods and enhanced scheduling flexibility for a premium of $0.05/Mcf above the base rate. Market research indicates 150 MMcf/d of current volume would convert to this premium service. This would require the implementation of new scheduling software ($200,000, depreciated over 36 months) and two additional operational staff ($12,000/month each).
Case Discussion Questions
Using the financial and operational data provided, perform a full incremental cost-benefit analysis for each of the four strategic options. Identify relevant changes in revenue and expenses for each case. Make a recommendation stating which option or combination of options SEP should pursue to improve the project’s profitability and asset utilization. It may be helpful to consider the following issues in developing your recommendation: (1) the impact of SEP’s cost structure on the flexibility of its pricing strategy (and also any constraints), (2) the role of exposure to the spot market play in relation to signing long-term contracts, (3) the potential risks of pursuing each strategic option, and (4) the impact of explicitly considering competitive response to your recommended approach.
©Utpal Dholakia, 2025. This case was prepared by Utpal Dholakia to support the learning and application of pricing strategy concepts. It is not meant to serve as an endorsement, an advertisement, a source of primary data, or an illustration of effective or ineffective management, and is written entirely using information available from public sources. Readers of this blog are invited to use the case and the accompanying teaching note for their own and others’ education in academic contexts. However, please reach out if you’d like to use this case in a commercial educational program.
See, for example, Di Odoardo, M., Ngu, J., & Thompson, G. (2025). The bridge: Natural gas’s crucial role as a transitional energy source. Wood Mackenzie, February. Available online at: https://www.woodmac.com/horizons/natural-gas-transitional-energy-source/