Supply Chain Management

Comparing option 1 (building central receiving facility and satellite tanks) against option 2 (building central receiving facility and a huge fleet of trailers), we recommend that Distrigas should implement option 1. Though this option involves making upfront investments in building facilities, overall cost of running the operations for the next 25 years is cheaper than option 2.

Initial Investment Net Present cost Annual Distribution Cost@ 9% Discount Rate Number of operating days Number of Trailers

Option 1 29.34 -25.01 1.46 250 Days 6

Option 2 21.87 -36.58 4.8 120 Days 127

These calculations are based on the assumption that the Descartes ship delivers 1Bcf once in 50days and the trailers empty 1Bcf in 50days. To accommodate for flexibility of earlier arrival of the ship, we recommend that the central tank should have 25% extra capacity. To accommodate for breakdowns of trailers and late arrival of the ship, we recommend an extra trailer.

The downside of this strategy is that Distrigas is building upfront capacity at customer end. In the event that the pipeline companies increase their supplies to utility companies, the overall market for LNG during peak usage period will decrease and Distrigas will be left with unutilized capacity. Distrigas can mitigate such risks by entering into long term contracts such as the one entered between Distrigas and Bostongas.

The utility is charged an excessive penalty for going above their planned gas volume by the gas providers. We can see this by simply comparing what the prices are when the peak demand is more than the average demand with the peak demand being the average demand. The cost of gas can be determined using the following equation:

Cost of Gas = (Base Commodity Charge)(Avg Daily Use) + (12)(4.63)(Peak 1 Day Use)

The results of this are shown in appendix 1.When the peak demand is 240MMcf, the average cost per Mcf is $0.7702, or a 130% increase over the base charge. When the peak demand is equal to the average demand (84MMcf), the average cost per Mcf is $0.4881 or a 45% over the base charge. The average cost can never be equal to the base charge because the maximum daily use is always great than 0. Thus, the need to invest in another system is desirable for the utility.

Distrigas offers competitive rates when compared with pipeline emergency gas and considerably cheaper than pipeline-gas rates. Thus, the utility should use Distrigas as its emergency gas provider when the daily volume of gas goes above 160MMcf. With the given demand numbers, the utility will end up buying 1706MMcf of gas from Distrigas. This was the optimal minimum solution of total cost as determined by using solver. It will save the utility $2,185,885.36 by buying their emergency supply from Distrigas as opposed to their regular supplier, which is important because although the emergency gas required is only 5.56% of the total annual demand, it represents 13.19% of the total cost. If the utility were to go with the emergency pipeline gas at the rate of $1.80/Mcf, then the cost of the emergency gas is $3,070,800. However, the Distrigas option costs only $2,832,011.01, or a savings of $238,788 annually (Appendix 3). The annual cost of the Distigras policy is $21,460,644.64.

Distrigas business strategy should be to project itself as a cost leader, which promises reliability, speed, and the required gas amount when needed, all at an affordable rate. To maintain such a position, it will need to be able to store gas in an economical manner. This means that it will have to invest in the proper infrastructure to store and deliver the gas (tanks, tankers, tractors), and ensure that its rates are comparable with the other options. Unfortunately, there are various risks associated with entering this business. The regular gas transmission companies in the region can turn into a competitive threat by building their own storage facilities and supplying to the gas companies through a network of trailers, or they could increase their overall capacity. Another threat could be a decision of consumers like Boston Gas to build their own storage facilities and thus start sourcing directly from the pipeline-gas providers, to be stored for use during peak periods.

Appendices

Appendix 1: Yearly cost of gas

Peak Demand With Peak demand equal to avg demand

Base Charge ($) 0.3359 0.3359

Demand Charge ($) 4.63 4.63

Total Demand (Mcf) 30,700,000 30,700,000

Peak 1 day demand (Mcf) 240,000 84,109.58904

Total Cost ($) 23,646,530 14,985,258.77

Average cost per Mcf ($) 0.7702 0.4881

% increase over $0.3359 129.30 45.32

Appendix 2: Cost of Excess Demand

Month Date Demand Deviation from 120 (MMcf) >120? Aggregate Excess Demand (MMcf) Cost of Excess Demand ($) Cumulative Cost of Excess Demand ($)

December 1 177 57 57 57 94620 94620

December 2 217 97 97 154 161020 255640

December 3 93 -27 0 154 0 255640

December 4 226 106 106 260 175960 431600

December 5 62 -58 0 260 0 431600

December 6 240 120 120 380 199200 630800

December 7 230 110 110 490 182600 813400

December 8 156 36 36 526 59760 873160

December 9 98 -22 0 526 0 873160

December 10 60 -60 0 526 0 873160

December 11 152 32 32 558 53120 926280

December 12 167 47 47 605 78020 1004300

December 13 192 72 72 677 119520 1123820

December 14 74 -46 0 677 0 1123820

December 15 72 -48 0 677 0 1123820

December 16 222 102 102 779 169320 1293140

December 17 200 80 80 859 132800 1425940

December 18