Industry: Energy
Product: Tamara
Application: Renewable energy project risks

The Wind Farm Was Scheduled to Connect on Day 930. The Simulation Gives That Date a 2% Chance

A 200 MW onshore wind farm was developed against a fixed grid-connection and power-purchase deadline. The deterministic plan — an eleven-activity most-likely roll-up — put grid connection at day 930. Missing that window did not merely delay revenue; it risked forfeiting the contracted price and triggering liquidated damages, while financing carry accrued throughout. For a project competing on slim margins, the connection date was the business case — and the first thing the developer needed was an honest probability of hitting it.

Rebuilt in Tamara, Vose Software's Monte Carlo project risk tool, with Beta-PERT durations on every activity and six discrete risk events layered on top, the deterministic date dissolves into a distribution: a P50 of day 1109 and a P90 of day 1240, and a probability of connecting by the published day-930 plan of just 2%. The S-curve below is the whole argument — the deterministic plan sits at the very foot of the curve, in the regime a developer commits to only at the cost of the price it was counting on.

The gap between the day-930 plan and the P80 connection is 264 days — about 8.7 months of exposure to lost price and liquidated damages that the deterministic roll-up never quantified.

Why a single critical-path date fails

A bar-chart critical path adds most-likely durations along one assumed-longest chain. Two things break it. First, durations are right-skewed — an activity can finish a little early but can overrun a lot, so the mean simulated connection is 1,113 days against the 930-day plan. Second, with parallel chains (permitting, grid-connection agreement, turbine supply and civil works all branch from the early phases), whichever chain happens to be longest in a given iteration drives the finish, so the project inherits the worst of several paths, not the average of one.

Where the duration risk actually lives

Tamara reports each activity's cruciality — the rank-correlation between its duration and the connection date, i.e. how much its variability actually moves the date.

Permitting and environmental dominates (cruciality 0.63), followed by turbine delivery and erection (0.45) and the turbine supply contract and order (0.32). The action list is clear: permitting certainty and the turbine supply chain together account for most of the connection-date variability, and the two highest-leverage weeks of risk reduction belong there — not on whichever task the team finds easiest to compress.

Activity-level spread

The same simulation places every activity in time as a band, not a bar:

The whiskers widen downstream because uncertainty compounds along the chain: the turbine supply, delivery and erection bars carry the widest whiskers, and because they sit in series the spread compounds toward the connection date.

Schedule risk is revenue risk is cost risk

Every day beyond the deterministic plan carries financing carry plus the liquidated-damages and lost-price exposure of missing the connection window, so the schedule distribution drives the cost distribution. Tamara let the team price a mitigation package — an early turbine reservation, enhanced permitting and stakeholder engagement, and a weather buffer with a secured crane slot — and compare before/after on the same axis:

Without mitigation the all-in cost runs to a mean of $266M and a P90 of $291M, with a 19% probability of breaching the $283M budget. The mitigation package cuts the P80 connection by 85 days (1,194 → 1,109 days), and because schedule drives cost, the overrun probability falls from 19% to 7% — value that lands largely in avoided carry and damages rather than in the activities the package touches directly.

The discrete risks that drive the tail

The six discrete events were modelled as Bernoulli risks. Ranking them by expected schedule impact (probability × delay) gives a clean Pareto:

Four of the six events carry ~80% of the expected discrete-event delay — a permitting/community objection (6.2 weeks expected), a turbine supply-chain delay (5.1), severe-weather lost days (3.9) and a grid-connection re-study (3.7). Once the ranking is visible, the risk-response budget writes itself.

What Tamara changed

• The external commitment moved from the deterministic day-930 date to a risk-informed P80, ending the rolling-promise cycle with the offtaker and the grid operator before it started.
• An 8.7-month schedule contingency was quantified and funded, rather than discovered one slipped milestone at a time as the connection window closed.
• Risk-reduction effort was redirected to permitting and the turbine supply chain — the two highest-cruciality drivers — instead of being spread evenly across the bar chart.
• A mitigation package was approved on its tail-clipping effect, cutting budget-overrun probability from 19% to 7%.

Tamara Functionality Used

• Monte Carlo schedule simulation over the full activity network, with Beta-PERT durations and parallel-path logic.
• Discrete risk-event modelling (Bernoulli occurrence × Triangular impact) layered onto task durations and costs.
• Criticality and cruciality analysis distinguishing how often a task is critical from how much its variability moves the connection date.
• Stochastic Gantt and cumulative S-curve for communicating schedule uncertainty to lenders, offtakers and grid operators.
• Integrated cost–schedule modelling linking connection slip to financing carry and liquidated-damages cost.
• Scenario comparison quantifying a mitigation package's before/after impact on both the P80 connection and the budget-overrun probability.

A renewable project lives or dies on its connection date, and a connection date is a distribution. Tamara is what turns "will we make the window?" into a probability the developer, the lender and the offtaker can all sign.