antigravity-skills-reference/skills/energy-procurement/references/decision-frameworks.md

Decision Frameworks — Energy Procurement

This reference provides detailed decision trees, evaluation matrices, financial models, and strategic frameworks for electricity and gas procurement, tariff optimization, demand charge management, PPA evaluation, hedging strategy design, and multi-facility portfolio optimization. It is loaded on demand when the agent needs to make or recommend nuanced energy procurement decisions.

All thresholds, price assumptions, and market benchmarks reflect US commercial and industrial electricity and natural gas markets. Adjust for regional markets, current forward curves, and facility-specific tariff structures.

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1. Procurement Strategy Selection

1.1 Pre-Procurement Intelligence Gathering

Before entering any procurement decision — contract renewal, new facility onboarding, or mid-term restructuring — assemble a comprehensive data package.

Data Assembly Checklist

Data Point	Source	Purpose
36 months of 15-minute interval data (kWh and kW)	Utility meter data / MDM system	Load shape analysis, peak identification
Current tariff rate schedule and all applicable riders	Utility tariff book / state PUC	Baseline cost structure
Current supply contract terms, expiration, and auto-renewal provisions	Contract file	Timeline and constraints
Forward energy curves (12, 24, 36 month) for relevant hub	ICE, CME, broker quotes	Market benchmark for pricing evaluation
Capacity market auction results (PJM RPM, ISO-NE FCA)	ISO publications	Future capacity charge forecasting
Facility peak load contribution (PLC) or installed capacity (ICAP) tag	Utility / ISO settlement data	Capacity charge exposure
Historical weather data (HDD/CDD) for facility locations	NOAA / weather service	Weather-normalization of consumption
Pending utility rate cases at state PUC	State PUC docket search	Regulatory risk assessment
Corporate sustainability targets and timeline	Sustainability team	Renewable procurement requirements
Capital budget availability for demand-side investments	Finance team	Investment constraint for demand charge mitigation

1.2 Fixed vs. Index vs. Block-and-Index Decision Tree

Use this decision tree for each facility or portfolio segment independently — one strategy does not fit all sites.

START: What is the organization's tolerance for energy cost variance?

├── Budget variance >10% triggers executive escalation
│   ├── Contract tenor ≤ 24 months?
│   │   └── YES → Fixed-price full requirements
│   │       - Accept the risk premium (5-12% above forward curve)
│   │       - Negotiate volume tolerance band (±10-15%)
│   │       - Ensure contract includes change-of-use provisions
│   │   └── NO (>24 months) → Fixed-price with annual price resets
│   │       - Lock year 1 at fixed, years 2-3 at a formula (forward + adder)
│   │       - This limits the supplier's long-term risk premium
│
├── Budget variance of 5-10% is manageable
│   ├── Facility load factor > 0.70?
│   │   └── YES → Block-and-index
│   │       - Buy fixed blocks = 70-80% of baseload
│   │       - Float remaining 20-30% at index (day-ahead or real-time)
│   │       - Shape blocks to match base load pattern (ATC vs. on-peak only)
│   │   └── NO (load factor < 0.70) → Shaped block-and-index
│   │       - Buy on-peak blocks only (match production schedule)
│   │       - Float off-peak and shoulder at index
│   │       - Supplement with TOU-indexed product for off-peak
│
├── Organization can tolerate >15% variance (energy is <5% of COGS)
│   ├── Internal capability to monitor wholesale markets?
│   │   └── YES → Index pricing with financial hedges
│   │       - Base product: real-time or day-ahead index + supplier adder
│   │       - Layer financial hedges: buy call options for peak months
│   │       - Set a price ceiling through options ($X/MWh cap)
│   │   └── NO → Index with a price cap product
│   │       - Supplier provides index pricing with a contractual ceiling
│   │       - Cap premium is typically $3-7/MWh above forward curve
│   │       - Simpler than managing separate financial hedges

1.3 Layered Procurement Methodology

Layering eliminates single-point market timing risk. The methodology:

Step 1: Determine the hedging horizon. Most C&I buyers layer 18–36 months ahead of the delivery period. For a January 2028 start date, begin buying tranches in July 2026.

Step 2: Set the number of tranches. Standard approaches:

Tranches	Buying Frequency	Volume per Tranche	Best For
4	Quarterly	25%	Default approach, good balance
6	Bimonthly	~17%	Large portfolios, higher granularity
8	Monthly (final 8 months)	12.5%	Aggressive dollar-cost averaging
12	Monthly	~8%	Very large portfolios with dedicated procurement staff

Step 3: Execution rules.

• Execute each tranche at the prevailing market price on the scheduled date — do not try to time within the tranche window.
• Exception: if the forward curve drops into the bottom 20th percentile of the 5-year range, accelerate by buying 2 tranches immediately ("buy the dip" rule).
• Exception: if the forward curve spikes into the top 20th percentile, defer the current tranche by 30 days (skip and catch up later).
• Never defer more than 2 consecutive tranches — rolling deferrals leave you unhedged.

Step 4: Document and report. Maintain a procurement log showing: tranche date, volume procured, price locked, forward curve price at execution, cumulative weighted average price, and remaining open position. Report to finance quarterly.

Example — 10 MW peak load, 60M kWh annual consumption:

Delivery year: 2028
Hedging start: July 2026
Tranches: 6 (bimonthly, ~10M kWh each)

Tranche 1 (Jul 2026): 10M kWh @ $44.50/MWh  — Forward was $45.20
Tranche 2 (Sep 2026): 10M kWh @ $42.80/MWh  — Forward was $43.10
Tranche 3 (Nov 2026): 10M kWh @ $46.30/MWh  — Forward was $46.30
Tranche 4 (Jan 2027): 10M kWh @ $41.20/MWh  — Forward was $41.50 (buy-the-dip rule: 
                                                 also executed Tranche 5 early)
Tranche 5 (Jan 2027): 10M kWh @ $41.40/MWh  — Accelerated from March
Tranche 6 (May 2027): 10M kWh @ $43.80/MWh  — Forward was $44.00

Weighted average: $43.33/MWh
Range of execution prices: $41.20 - $46.30 ($5.10 spread)
If locked all-at-once in Jul 2026: $44.50/MWh → layering saved $1.17/MWh = $70,200

1.4 RFP Process for Deregulated Markets

Timeline and Phases

Phase	Duration	Key Activities
Pre-RFP Analysis	2-3 weeks	Load data assembly, tariff analysis, market benchmarking, sustainability requirements definition
RFP Design	1-2 weeks	Template creation, supplier longlist development, evaluation criteria weighting
RFP Distribution	1 week	Issue to 5-8 qualified REPs, respond to clarification questions
Bid Window	2-3 weeks	Suppliers develop pricing based on your interval data and requirements
Bid Evaluation	1-2 weeks	Total cost modeling, credit assessment, contract review
Negotiation	1-2 weeks	Shortlist to 2-3, negotiate terms, finalize pricing
Award and Execution	1 week	Sign contract, notify utility of supplier switch (may require 30-60 day lead time)
Total	9-14 weeks

Supplier Evaluation Scoring Matrix

Criterion	Weight	Scoring Guide
Total cost (energy + adder + shaped premium)	35-45%	Lowest total cost = 100 pts. Each 1% above lowest = -5 pts. Model across 3 price scenarios.
Credit quality	15-20%	Investment grade (S&P BBB- or above) = 100 pts. Sub-investment grade = 50 pts. No rating / private = 70 pts with parent guarantee, 30 pts without.
Contract flexibility	10-15%	Volume tolerance ±15% = 100. Volume tolerance ±5% = 50. No tolerance = 0. Early termination available = +20 pts. Change-of-use provisions = +15 pts.
Sustainability services	10-15%	Bundled RECs from named projects = 100. Unbundled RECs available = 60. No REC options = 0. Carbon reporting support = +20 pts.
Market intelligence and advisory	5-10%	Dedicated account manager + regular market updates = 100. Account manager only = 50. Call center support = 0.
Operational capability	5-10%	EDI/API billing integration = 100. Electronic invoicing only = 60. Paper billing = 0. Multi-site consolidated billing = +20 pts.

Bid Comparison Template

For each site, model the annual cost under each supplier's proposal:

Annual Cost = Σ(hourly volume × hourly price) + fixed charges + REC costs + adder fees

Where hourly price depends on product structure:
  Fixed: contract rate for all hours
  Block-and-index: block rate for block volume + index price for excess
  Index: (day-ahead or real-time LMP at load zone) + supplier adder

Always model at three forward price scenarios: base case (current forward curve), low case (forward - 20%), and high case (forward + 30%). A supplier whose index product looks cheapest at base case may be the most expensive at high case.

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2. PPA Evaluation Framework

2.1 Physical PPA Evaluation

Physical PPAs involve direct energy delivery and are appropriate when:

• Your load is in the same ISO as the project
• You want both energy and RECs from a specific named facility
• You can manage the operational complexity of scheduling and balancing

Financial Modeling Framework

Step 1: Establish the baseline (no-PPA scenario). Project your energy costs over the PPA term using forward curves for years 1-5 and a long-term price escalation assumption (typically 2-3%/year) for years 6+.

Step 2: Model PPA cash flows.

Year N PPA Net Value = (Market Price at Hub - PPA Strike Price) × Expected Generation
                     - Basis Cost (Hub to Load Zone)
                     - Curtailment Cost (expected curtailed MWh × strike price)
                     - Balancing Costs (firming residual load not covered by PPA)
                     + REC Value (if RECs would otherwise be purchased separately)

Step 3: Sensitivity analysis — run these scenarios at minimum:

Scenario	Market Price Assumption	Generation Assumption	Basis Assumption
Base	Current forward curve + 2.5%/yr escalation	Developer's P50 estimate	5-year historical average basis
Bull	Forward + 4%/yr escalation	P50 generation	Basis narrows 20%
Bear	Forward + 1%/yr escalation	P75 generation (lower)	Basis widens 30%
Stress	Flat prices for 5 years, then 2%/yr	P90 generation (much lower)	Basis widens 50%

Step 4: Calculate NPV, IRR, and levelized cost of energy (LCOE) under each scenario. A PPA is economically justified if NPV is positive under base and bull cases and the loss under bear case is tolerable (typically <$2M cumulative over the PPA term for a mid-size C&I buyer).

2.2 Virtual PPA (VPPA) Evaluation

VPPAs are financial instruments — no physical energy delivery. The key risks differ:

Basis Risk Analysis

Basis risk is the primary financial risk in a VPPA. It arises because the generator settles at its node price and your load settles at your load zone price.

Quantification method:

1. Obtain 3-5 years of hourly LMP data for the generator's node and your load zone from the ISO.
2. Calculate the hourly basis: Load Zone LMP - Generator Node LMP.
3. Filter to hours when the generator would be producing (solar: daylight hours; wind: use historical generation profile).
4. Calculate the generation-weighted average basis.
5. Model the basis impact on PPA settlement:

Annual Basis Cost = Σ(hourly basis × hourly expected generation)

If generation-weighted average basis = $5/MWh and annual generation = 200,000 MWh:
Annual Basis Cost = $1,000,000/year
Over a 15-year PPA: $15M in basis costs (undiscounted)

Red flags for basis risk:

• Basis spread > $8/MWh generation-weighted average → high risk, negotiate basis hedge or reject
• Basis volatility (standard deviation) > $15/MWh → unpredictable, hard to budget
• Basis trend is widening over the historical period → structural congestion, likely to worsen
• Generator is located behind a known transmission constraint → congestion will increase as more generation is added in that zone

Curtailment Risk Analysis

Curtailment occurs when the ISO orders the generator to reduce output due to transmission constraints or oversupply.

ISO	Technology	Typical Curtailment %	Trend
ERCOT	Wind (West Texas)	3-8%	Increasing as more wind is added
ERCOT	Solar	1-3%	Low but increasing
CAISO	Solar	5-12% (spring)	Increasing due to duck curve
CAISO	Wind	1-3%	Stable
PJM	Wind	<1%	Minimal
PJM	Solar	<1%	Minimal
MISO	Wind	2-5%	Moderate, depends on zone
SPP	Wind	3-7%	Increasing in western zones

Contract protection: Negotiate a curtailment threshold (e.g., first 5% is developer risk) and a compensation mechanism for excess curtailment (developer provides replacement RECs or a price adjustment). Never accept "buyer bears all curtailment risk" on a VPPA — this transfers a risk the buyer cannot manage or influence.

Credit and Accounting Requirements

Requirement	Details
ISDA Master Agreement	Required for VPPA. Negotiate credit thresholds, margin call provisions, and termination values.
Credit support	Investment grade: typically no collateral for first $5-10M notional. Sub-IG: letter of credit or parent guarantee for 2-3 years of potential negative settlement.
Accounting treatment	VPPAs may qualify for hedge accounting (ASC 815) if they meet effectiveness testing requirements. Without hedge accounting, mark-to-market gains/losses flow through the P&L, creating earnings volatility. Consult treasury and accounting early.
Board / CFO approval	VPPAs are multi-year financial commitments. Most organizations require board approval for commitments >$10M notional or >10 years. Present as an energy cost management tool, not a speculative position.

2.3 Physical vs. Virtual PPA Decision Matrix

Factor	Favors Physical PPA	Favors Virtual PPA
Load location	Same ISO as available projects	Load in regulated market or no nearby projects
Energy supply	Need the physical energy (replacing utility supply)	Already have a retail supply contract
Sustainability goal	Want bundled energy + RECs from a specific facility	Need RECs only for Scope 2 reporting
Operational capability	Have energy scheduling and balancing resources	No energy trading or scheduling staff
Balance sheet	Prefer to avoid financial derivative classification	Comfortable with ISDA and mark-to-market
Credit profile	Sub-investment grade (physical may require less credit support)	Investment grade (can post collateral efficiently)
Regulatory environment	Deregulated market with retail choice	Regulated market (VPPA may be the only option for additionality)

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3. Demand Charge Optimization

3.1 Load Analysis Methodology

Step 1: Download 15-minute interval data. Request a minimum of 12 months of 15-minute kW demand data from the utility or your meter data management system. For facilities with sub-metering, obtain interval data at the system level (HVAC, production, compressed air) in addition to the main meter.

Step 2: Identify peak demand intervals. Sort all 15-minute intervals by kW descending. Focus on the top 50 intervals (the top 0.15% of all intervals in a year). These intervals drive your demand charges.

Step 3: Characterize peak drivers. For each of the top 50 intervals, identify:

• Date and time of day
• Day of week
• Outdoor temperature (proxy for HVAC load)
• Production schedule (was the line running?)
• Any anomalous events (equipment startup, testing, maintenance)

Typical findings for manufacturing facilities:

Peak Driver	Frequency in Top 50	Root Cause
Morning ramp-up (6-9 AM)	30-50%	Simultaneous startup of HVAC, compressors, and production lines
Hot afternoon (2-5 PM)	20-35%	HVAC at max coinciding with production peak
Equipment startup after maintenance	10-20%	Inrush current from large motors starting simultaneously
Testing / commissioning	5-10%	New equipment tested during peak periods

Step 4: Calculate the demand charge cost of peak intervals.

Monthly Demand Charge = Peak kW × Demand Rate ($/kW)

If normal operating peak is 4,000 kW and the actual peak is 4,800 kW:
Excess peak cost = (4,800 - 4,000) × $15/kW = $12,000/month

With an 80% ratchet:
Minimum billing demand for next 11 months = 4,800 × 0.80 = 3,840 kW
If normal peak drops to 3,500 kW next month, you're still billed at 3,840 kW
Annual ratchet cost = (3,840 - 3,500) × $15/kW × 11 months = $56,100

3.2 Peak Shaving ROI Framework

Battery Energy Storage System (BESS)

Sizing methodology:

1. Determine the target peak reduction (kW to shave).
2. Calculate the required energy capacity: target kW × duration of peak events. For demand charge management, 1-2 hours of duration is typically sufficient.
3. Apply round-trip efficiency (88-92% for lithium-ion): size the battery 10% larger than the calculated energy requirement.

Example — 500 kW peak shaving at a manufacturing plant:

Target reduction: 500 kW
Peak event duration: 2 hours (based on interval data analysis)
Battery size: 500 kW / 1,000 kWh (with 10% efficiency buffer: 500 kW / 1,100 kWh)

Installed cost (2025): $800-$1,200/kWh for C&I BESS
Total capital: $880,000-$1,320,000 (using 1,100 kWh at midpoint $1,000/kWh = $1,100,000)

Annual savings stack:
  Demand charge savings: 500 kW × $15/kW × 12 months = $90,000
  Capacity tag reduction: 500 kW × $60/kW-yr (PJM example) = $30,000
  TOU energy arbitrage: charge off-peak ($0.04/kWh), discharge on-peak ($0.08/kWh)
    1,100 kWh × $0.04/kWh spread × 250 days × 90% efficiency = $9,900
  Demand response revenue: 500 kW × $40/kW-yr (PJM Economic DR) = $20,000

Total annual value: $149,900
Simple payback: $1,100,000 / $149,900 = 7.3 years
With ITC (30% for standalone storage as of IRA): payback = $770,000 / $149,900 = 5.1 years

Decision thresholds:

• Payback < 5 years (with stacked value + incentives): strong economic case, proceed
• Payback 5-7 years: viable if aligned with sustainability goals or if demand charges are rising
• Payback 7-10 years: marginal, requires additional strategic justification
• Payback > 10 years: economics don't support investment without regulatory mandate

Demand Response Program Evaluation

Not all DR programs are equal. Evaluate on these dimensions:

Dimension	Questions to Answer
Revenue certainty	Is payment capacity-based (guaranteed $/kW-yr) or performance-based (paid per curtailment event)?
Dispatch frequency	How many events per year? What is the maximum duration? Can you sustain curtailment for the full duration?
Baseline methodology	How is your curtailment measured? Customer Baseline Load (CBL) using 10-of-10 or adjusted methods? A poorly calculated baseline can understate your curtailment and reduce payments.
Penalty for non-performance	What happens if you can't curtail during an event? Some programs impose penalties 2-3× the capacity payment.
Interaction with other programs	Does DR enrollment affect your capacity tag calculation? Does it conflict with your behind-the-meter generation?
Operational impact	Can your facility actually curtail the committed kW without affecting production quality, safety, or customer commitments?

3.3 Staggered Startup Protocol

The single lowest-cost demand charge reduction strategy — no capital required:

Problem: Morning startup creates a demand spike when HVAC, compressors, lighting, and production equipment all energize simultaneously between 5:30-6:30 AM.

Solution: Stagger equipment startup over a 60-90 minute window:

5:00 AM  — Lighting (50-100 kW)
5:15 AM  — HVAC pre-cooling/heating (500-800 kW, ramps over 30 min)
5:45 AM  — Compressed air system (200-400 kW, staged compressor starts)
6:00 AM  — Production Line 1 (300-500 kW)
6:15 AM  — Production Line 2 (300-500 kW)
6:30 AM  — Auxiliary systems, battery chargers, water heating

Result: Peak during startup drops from 2,200 kW (simultaneous) to 1,600 kW (staggered)
Savings: 600 kW × $15/kW × 12 months = $108,000/year at zero capital cost

Implementation: Program the building automation system (BAS) to enforce startup sequencing. Set hard interlocks that prevent the next system from starting until the prior system has reached steady state.

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4. Market Analysis Framework

4.1 Regulated vs. Deregulated Strategy Map

Your Situation	Primary Strategy	Secondary Strategy
Regulated market, single rate schedule	Demand charge management, on-site generation, tariff schedule optimization	Lobby for utility green tariff, evaluate community solar
Regulated market, multiple rate options	Tariff analysis to select optimal schedule (TOU vs. flat vs. demand-based)	Load shifting to exploit TOU differentials
Deregulated, single site	Competitive supply procurement (RFP to 5-8 REPs)	Layer procurement to manage timing risk
Deregulated, multi-site same ISO	Aggregate sites for portfolio procurement (volume leverage)	Negotiate portfolio-level products (single supplier, blended rate)
Deregulated, multi-site multi-ISO	Procure separately by ISO (market structures differ)	Leverage total volume in supplier negotiations even if contracts are separate
Mixed regulated/deregulated portfolio	Competitive procurement for deregulated sites; demand management for regulated sites	Seek regulatory pilot programs in regulated territories

4.2 Forward Curve Analysis

What the forward curve tells you:

• Market consensus on future energy prices (adjusted for risk premium)
• Seasonal price patterns (summer/winter spreads)
• Year-over-year price trajectory (escalation or decline)

What the forward curve does NOT tell you:

• Actual future spot prices (forwards are not forecasts — they include a risk premium)
• Short-term price spikes (forwards are averages, not tails)
• Regulatory changes, plant retirements, or transmission additions not yet priced in

Using forward curves for procurement decisions:

Forward Curve Position	Procurement Action
Bottom 20% of 5-year range	Accelerate buying — lock more volume at favorable prices
20th-40th percentile	Proceed with scheduled layering — prices are reasonable
40th-60th percentile	Maintain default layering schedule
60th-80th percentile	Slow buying — defer non-critical tranches 30 days
Top 20% of 5-year range	Defer where possible, increase index exposure, evaluate financial hedges instead of physical locks

4.3 Capacity Market Exposure

In organized capacity markets (PJM, ISO-NE, NYISO), capacity charges are a significant cost component — $30–$120/kW-yr depending on the zone and auction results.

PJM Reliability Pricing Model (RPM):

• Auction held 3 years ahead of delivery year (Base Residual Auction)
• Incremental auctions adjust quantities closer to delivery
• Your capacity obligation is based on your PLC (Peak Load Contribution)
• PLC is set by your metered load during the 5 highest system coincident peak hours (5CP) in the prior delivery year

Managing capacity exposure:

1. Track PJM system peak alerts. PJM issues "hot weather alerts" and "emergency alerts" when system peaks are expected. Curtail discretionary load during these hours to reduce your PLC for the following year.
2. Install peak notification systems. Subscribe to PJM's demand response alerts. Deploy load curtailment controls that can drop 10-20% of facility load within 30 minutes of a peak alert.
3. Behind-the-meter generation. Running backup generators during coincident peak hours reduces your metered load and thus your PLC. Ensure generators are permitted for non-emergency operation and emissions-compliant.
4. Capacity tag trading. In some markets, capacity obligations can be traded or offset through financial instruments. Your supplier may offer capacity tag management as a service.

Example — capacity charge impact:

Facility peak: 5,000 kW
PLC (measured during prior year 5CP hours): 4,200 kW
PJM BRA clearing price for your zone: $85/MW-day

Annual capacity charge: 4,200 kW × $85/MW-day × 365 / 1,000 = $130,305/year

If you had curtailed 500 kW during the 5CP hours:
Reduced PLC: 3,700 kW
Annual capacity charge: 3,700 kW × $85/MW-day × 365 / 1,000 = $114,793/year
Savings: $15,512/year from 5 hours of load curtailment

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5. Hedging Strategy Design

5.1 Hedging Instruments Available to C&I Buyers

Instrument	Complexity	Capital Required	Protection
Fixed-price contract (through REP)	Low	None (embedded in price)	Full price certainty for contracted volume
Block purchases (through REP)	Low-Medium	None	Price certainty on base load; variable load exposed
Financial swap (through broker/bank)	Medium	ISDA + possible margin	Converts floating price to fixed on specified volume
Call option (through broker/bank)	Medium-High	Premium ($/MWh upfront)	Price ceiling at strike + premium; unlimited downside benefit retained
Heat rate call option	High	Premium	Protects against gas-to-power price spike (useful when gas drives marginal power price)
Collar (sell put, buy call)	Medium-High	Reduced premium (put proceeds offset call cost)	Ceiling and floor — limits both upside and downside

5.2 Hedging Strategy by Risk Profile

Risk Profile	Hedge Ratio	Instruments	Monitoring
Conservative (budget certainty paramount)	80-95% hedged	Fixed-price contracts, financial swaps	Monthly mark-to-market review
Moderate (balanced cost/risk)	60-80% hedged	Block-and-index, layered procurement	Monthly forward curve review, quarterly hedge adjustment
Aggressive (cost minimization focus)	30-60% hedged	Index with call options for tail risk	Weekly market monitoring, daily during volatility events
Speculative (never recommended for C&I)	<30% hedged	Index with no protection	Real-time monitoring (impractical for most C&I buyers)

5.3 Option Pricing and Evaluation

When buying call options to cap index pricing exposure, evaluate:

Option value = Max(0, Spot Price - Strike Price) × Volume

Cost: Premium per MWh × Contracted Volume
Annual premium for a $50/MWh cap on day-ahead pricing: $2-5/MWh (varies by market volatility)

Example — protecting 50,000 MWh annual index volume:
  Call option strike: $50/MWh
  Premium: $3/MWh
  Total premium cost: $150,000/year

  If spot averages $42/MWh: option expires worthless, total cost = $42 + $3 = $45/MWh
  If spot averages $65/MWh: option pays $15/MWh, effective cost = $65 - $15 + $3 = $53/MWh
  If spot spikes to $200/MWh (weather event): option pays $150/MWh, effective cap = $53/MWh

  Maximum effective rate: strike + premium = $53/MWh regardless of market price

When to use options vs. fixed contracts:

• Options when you want to participate in downside moves but protect against spikes
• Fixed contracts when the premium for options exceeds the cost of just locking in a fixed price (this happens when volatility is high and options are expensive)

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6. Sustainability Procurement Alignment

6.1 Mapping Procurement to RE100 and SBTi

RE100 progress calculation:

RE% = (Renewable MWh procured) / (Total electricity consumption MWh) × 100

Acceptable renewable MWh sources (in order of additionality):
1. On-site generation (strongest claim)
2. Physical PPA with new project (strong additionality)
3. Virtual PPA with RECs from new project (good additionality)
4. Utility green tariff (varies by program design)
5. Unbundled RECs (weakest claim — RE100 tightening requirements)

SBTi trajectory alignment:

• SBTi requires absolute Scope 2 emissions reductions on a defined trajectory (typically 4.2%/year for 1.5°C alignment).
• Lock in long-term renewable procurement (PPAs) that deliver emission reductions year over year.
• Avoid procurement strategies that increase fossil dependence (long-term fixed contracts with fossil-heavy grid mix and no REC component).

6.2 Cost-Effective Sustainability Procurement Path

Target RE%	Least-Cost Strategy
0-25%	Unbundled national wind RECs ($1-3/MWh). Cheapest entry point.
25-50%	Utility green tariff + unbundled RECs. Green tariffs are often $0.005-$0.015/kWh premium.
50-75%	VPPA with new wind/solar project. Fixed cost, long-term REC supply, additionality.
75-90%	Physical PPA or additional VPPA to cover remaining gap. On-site solar where feasible.
90-100%	Match remaining unhedged load with project-specific RECs or small on-site installations. The last 10% is the most expensive per MWh.

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7. Multi-Facility Portfolio Optimization

7.1 Portfolio Aggregation Strategy

When to aggregate:

• 3+ sites in the same ISO/utility territory
• Total volume > 20 GWh/year (attracts competitive supplier attention)
• Sites have complementary load profiles (some peak summer, others peak winter)

Aggregation benefits:

• Volume leverage: 5-15% lower supply pricing than individual site procurement
• Load diversity: combined portfolio has higher load factor than individual sites, reducing supplier risk premium
• Administrative efficiency: single contract, single invoice, single relationship

When NOT to aggregate:

• Sites in different ISOs with different market structures (PJM and ERCOT should be procured separately)
• One site has unique requirements (e.g., real-time pricing needed for a demand response strategy) that would constrain the entire portfolio
• Sites have vastly different contract expiration dates (stagger expirations to avoid all-at-once recontracting risk)

7.2 Portfolio-Level Risk Metrics

Track at the portfolio level, not just site-by-site:

Metric	Formula	Target
Portfolio hedge ratio	(Hedged MWh / Total expected MWh) × 100	60-80%
Weighted average procurement price	Σ(site MWh × site $/MWh) / Total MWh	Within 5% of portfolio benchmark
Supplier concentration	Largest supplier MWh / Total MWh	<50% (avoid single-supplier dependence)
Contract expiration clustering	% of portfolio MWh expiring in any 12-month period	<40% (stagger expirations)
Renewable coverage	Renewable MWh / Total MWh	On track to target
Portfolio load factor	Total kWh / (Sum of site peak kW × hours)	Track trend, higher is better

7.3 Site Prioritization for Demand-Side Investment

With limited capital for demand charge mitigation, prioritize sites using this scoring model:

Factor	Weight	Scoring
Demand charges as % of total bill	30%	>35% = 100, 25-35% = 70, 15-25% = 40, <15% = 10
Peak-to-average ratio	25%	>2.5 = 100, 2.0-2.5 = 70, 1.5-2.0 = 40, <1.5 = 10
Available demand reduction (kW)	20%	>1000 kW = 100, 500-1000 = 70, 200-500 = 40, <200 = 10
Utility demand rate ($/kW)	15%	>$20 = 100, $15-$20 = 70, $10-$15 = 40, <$10 = 10
Capacity market exposure	10%	PJM/ISO-NE (high) = 100, NYISO = 70, MISO = 40, none = 0

Investment priority: highest composite score first. A site scoring >80 is a strong candidate for battery storage or demand response. A site scoring <40 has limited demand charge optimization potential — focus on supply-side procurement instead.

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8. Natural Gas Procurement

8.1 Gas Procurement Structures

Natural gas procurement for C&I consumers (boilers, CHP, process heat, backup generation) follows similar principles to electricity but with distinct market mechanics.

Structure	Description	Best For
Firm fixed-price	Locked $/therm or $/MMBtu for contract term	Budget certainty, large heating loads
Index (first-of-month)	Monthly NYMEX Henry Hub settlement + basis + adder	Cost optimization, risk-tolerant buyers
Index (daily)	Daily Gas Daily midpoint + basis + adder	High-flexibility loads, interruptible processes
Baseload block + index	Fixed block covers base heating/process load, index covers variable	Facilities with both base process heat and weather-variable HVAC
Swing contract	Volume flexibility (50-130% of nominated quantity)	Facilities with highly variable gas consumption

8.2 Basis Differentials for Natural Gas

Natural gas prices vary by delivery point. Henry Hub (Louisiana) is the benchmark, but delivered cost depends on the basis differential between Henry Hub and your local city gate or utility delivery point.

Common basis differentials (approximate):

Delivery Point	Typical Basis to Henry Hub	Driver
Chicago (NGPL Midcontinent)	-$0.10 to +$0.15/MMBtu	Pipeline capacity from Gulf to Midwest
New York (Transco Zone 6 NY)	+$0.50 to +$3.00/MMBtu	Winter constraint on pipelines into NYC
New England (Algonquin)	+$1.00 to +$8.00/MMBtu (winter)	Severe pipeline constraints, competes with LNG
California (SoCal Border)	-$0.50 to +$1.50/MMBtu	Varies with West Coast supply/demand
Appalachia (Dominion South)	-$1.50 to -$0.30/MMBtu	Oversupply from Marcellus shale production
Texas (HSC)	-$0.05 to +$0.20/MMBtu	Close to production, minimal basis

Key insight: A facility in New England on index pricing faces dramatically different winter risk than a facility in Texas. Basis in New England during a cold snap can exceed $15/MMBtu, tripling the delivered gas cost. New England gas procurement requires winter hedging with firm pipeline capacity or LNG backup — index pricing without protection is reckless in that market.

8.3 Gas-Electric Interdependency

For facilities with both electricity and natural gas loads, recognize the coupling:

• When gas prices spike, electricity prices spike. Natural gas is the marginal fuel for electricity generation in most US ISOs. A $2/MMBtu increase in Henry Hub translates to approximately $10-$15/MWh increase in wholesale electricity prices (depending on the average heat rate of marginal gas plants, typically 7,000-8,000 BTU/kWh).

• CHP economics are gas-price dependent. A CHP system generating electricity at a heat rate of 6,500 BTU/kWh has a fuel cost of $6.50 × gas price per MWh. At gas $3/MMBtu, generation cost is $19.50/MWh. At gas $8/MMBtu, generation cost is $52/MWh. If your grid electricity cost exceeds your CHP generation cost, run the CHP. If grid electricity drops below CHP cost (e.g., during spring shoulder months with mild weather and low grid demand), consider shutting down CHP and buying from the grid.

• Dual-fuel hedging: When hedging gas and electricity simultaneously, recognize that fixing gas costs and leaving electricity at index (or vice versa) creates a cross-commodity basis risk. If gas prices drop but electricity stays high (due to transmission constraints or non-gas generation tightness), your gas hedge underperforms while your electric bill remains high. Consider hedging both commodities on a correlated basis — many energy suppliers offer combined gas+electric portfolio management.

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9. Tariff Optimization in Regulated Markets

9.1 Rate Schedule Selection

In regulated markets, the available tariff options may seem limited, but switching between rate schedules can save 5-15% on the total bill without changing consumption.

Step 1: Identify available rate schedules for your demand level and voltage. Most utilities offer 2-4 rate options for large C&I customers:

• Standard demand rate (flat energy + demand charge)
• Time-of-use rate (lower off-peak energy, higher on-peak energy + demand)
• Real-time pricing pilot (if available)
• Interruptible service rate (lower cost, utility can curtail during emergencies)

Step 2: Model 12 months of actual interval data against each available rate schedule.

For each rate schedule:
  Monthly cost = Σ(energy_charge_component) + demand_charge + customer_charge + riders

Where:
  energy_charge_component = Σ(kWh_per_interval × applicable_rate_per_kWh)
  demand_charge = max(15-min kW interval in month) × demand_rate
  For TOU rates: separate on-peak demand charge may apply

Step 3: Compare annual totals.

Rate Schedule	Annual Energy	Annual Demand	Annual Fixed	Annual Total	vs. Current
Current (GS-3)	$580,000	$312,000	$24,000	$916,000	baseline
TOU (GS-3-TOU)	$545,000	$298,000	$24,000	$867,000	-$49,000 (-5.3%)
RTP pilot	$510,000	$312,000	$36,000	$858,000	-$58,000 (-6.3%)
Interruptible	$565,000	$250,000	$24,000	$839,000	-$77,000 (-8.4%)

Step 4: Evaluate non-financial factors.

• TOU: requires ability to shift load or accept higher on-peak costs
• RTP: requires market monitoring and tolerance for price volatility
• Interruptible: requires ability to curtail load on short notice (typically 30-60 min)

9.2 Rate Case Monitoring and Response

When to intervene in a rate case:

Impact Level	Annual Cost Increase	Recommended Action
<$50K	Negligible for large C&I	Monitor only — track filing through settlement
$50K-$200K	Material but not critical	Join existing intervenor group (OIEC, etc.)
$200K-$500K	Significant	Individual intervention with regulatory counsel
>$500K	Critical	Full intervention with expert witnesses, rate design testimony

Rate case timeline (typical):

Month 0: Utility files rate case with state PUC
Month 1-2: Intervenors file to participate
Month 3-4: Discovery (interrogatories, data requests to utility)
Month 5-7: Intervenor testimony filed
Month 8-9: Hearings
Month 10-12: PUC issues order
Month 13-15: New rates take effect (may be retroactive to filing date)

What to challenge in a rate case:

1. Rate of return on equity (ROE): Utilities typically request 10-11% ROE. Current authorized ROEs are trending down (9-10%). Challenge excessive ROE requests.
2. Rate base additions: Utilities earn their ROE on their rate base (invested capital). Challenge excessive or imprudent capital investments included in the rate base.
3. Cost allocation between rate classes: Utilities allocate total revenue requirement across residential, commercial, and industrial rate classes. Ensure your rate class is not subsidizing residential or other classes above cost causation.
4. Rate design: Even if the total revenue is approved, fight for demand-based rate design (rewards load factor management) rather than pure volumetric rates (punishes high-consumption customers regardless of load shape).

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10. Emergency Procurement Protocols

10.1 Supplier Default / Bankruptcy

If your retail energy provider files for bankruptcy or fails to perform:

Immediate actions (24-48 hours):

1. Verify your account status with the utility. If the supplier defaults, your account reverts to the utility's Provider of Last Resort (POLR) service or standard offer service. You will NOT lose power — the grid keeps delivering regardless of supplier status.
2. Determine the POLR rate. In most states, the POLR rate is set quarterly based on wholesale market prices plus a premium (10-20% above competitive supply). This may be higher or lower than your current contract rate.
3. Contact 2-3 alternative suppliers immediately. Explain the situation — they will offer expedited enrollment (5-10 business days vs. normal 30-60 day switch process).
4. Review your contract for supplier default provisions, including any deposits or prepayments that may be at risk in the bankruptcy estate.

Medium-term (2-4 weeks):

1. Execute a new supply contract with the best available alternative supplier.
2. File a claim in the bankruptcy proceeding for any prepayments, deposits, or damages.
3. Review your supplier qualification criteria — consider adding financial covenants (minimum credit rating, tangible net worth requirements) to future contracts.

10.2 Force Majeure Events

When a force majeure event (natural disaster, grid emergency, pandemic) disrupts your energy supply or operations:

Assessment framework:

Event Type	Energy Impact	Procurement Response
Hurricane/severe weather	Physical damage to generation/T&D, price spikes	Activate backup generation, curtail non-essential load, document for insurance
Grid emergency (EEA3)	Rolling blackouts, extreme prices	Maximum load curtailment, DR activation, generator deployment
Supplier force majeure claim	Supplier attempts to suspend contract	Review FM clause narrowly — "market price increase" is NOT force majeure; "physical inability to deliver" may be
Pandemic/operational shutdown	Facility closed, consumption drops dramatically	Invoke volume tolerance provisions, negotiate contract suspension, evaluate early termination

10.3 Contract Termination Decision Matrix

When evaluating whether to terminate a supply contract early:

Early Termination Fee (ETF) = Σ(remaining months × monthly volume × |contract price - current market price|)

If contract price > current market:
  You owe the supplier (you're paying above market)
  ETF = remaining months × volume × (contract price - market) × discount factor

If contract price < current market:
  Supplier owes you (you have a favorable contract)
  You would NOT terminate — the contract is in-the-money

Decision: Terminate if ETF < cumulative savings from alternative contract + risk reduction value

Example — mid-term exit evaluation:

Current contract: $0.062/kWh, 18 months remaining, 50 GWh remaining
Current market: $0.055/kWh (market has dropped since contract signing)
ETF: 50,000 MWh × ($0.062 - $0.055) = $350,000

Alternative contract: $0.054/kWh for 18 months
Savings from alternative: 50,000 MWh × ($0.062 - $0.054) = $400,000

Net benefit of termination: $400,000 savings - $350,000 ETF = $50,000

Decision: Marginal. Factor in:
  - Renegotiation risk (can you lock $0.054 before market moves?)
  - Administrative cost of switching suppliers
  - Relationship cost with current supplier
  - If net benefit < $100K, generally not worth the disruption

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11. Seasonal Procurement Calendar

A disciplined procurement calendar ensures no critical deadlines are missed and procurement activities align with market conditions.

Month	Activity	Deadline
January	Annual energy budget review, lock natural gas hedges for next winter	Jan 31 for winter gas
February	Q1 forward curve review, PPA pipeline assessment	—
March	Begin RFP preparation for contracts expiring in Q4 or Q1 next year	—
April	Issue RFPs for fall contract starts, review summer DR enrollment	Apr 15 for PJM DR enrollment
May	Evaluate bids, begin summer peak preparation (generator testing, BAS settings)	May 31 for summer rate elections
June	Summer peak demand management begins, monitor 5CP forecasts (PJM)	—
July	Peak season monitoring, execute Q3 procurement tranches	Jul 15 for ERCOT 4CP mgmt
August	Peak season monitoring, finalize fall contract awards	Aug 31 for ISO-NE FCA positions
September	Post-summer review, capacity tag assessment, RE100 progress check	Sep 30 for Q4 procurement
October	Begin winter gas hedging, review heating load forecasts	Oct 31 for winter gas locks
November	Budget season — prepare next year's energy cost forecast	Nov 15 for budget submission
December	Year-end RE100 reconciliation, REC inventory check, contract renewals	Dec 31 for REC vintage retirement