Dynamic electricity pricing is widely advocated for demand-side management, yet its distributional consequences under crisis conditions remain poorly understood. We examine the equity implications of hourly spot pricing during the European energy crisis using metered consumption from 1136 Norwegian households (October 2020–March 2022) linked to socio-demographic surveys. Southern Norwegian wholesale prices nearly tripled (+192%), and mean household electricity costs rose from 484 to 1785 NOK/month. Energy poverty emerged from a zero baseline: no household exceeded the conventional 10% income-burden threshold before the crisis, versus 1.2% during it, and 6.8% exceeded a 6% burden. Impacts were steeply regressive: the mean burden of the lowest-income group reached 7.4%, against 1.9% for the highest — a fourfold gap. SHAP analysis shows that housing characteristics dominate income and price as predictors of consumption, indicating that vulnerability is structural, rooted in the building stock, rather than purely economic. We term this the vulnerability-responsiveness paradox: the households facing the greatest welfare exposure have the least structural capacity to adjust. Counterfactual simulations show that a 1.0 NOK/kWh price cap cuts poverty to 0.3%, and that pairing the cap with targeted retrofits of high-consumption detached homes performs best across cost, poverty, and inequality simultaneously. Crisis pricing policy should combine short-term price caps with structural building-efficiency programmes.
Administrative amendment counts conflate recurrent filings, schedule revisions, and changes in project ownership or specification. This article develops a Frequency-Magnitude-Type framework for interpreting incomplete development records and identifying the additional information needed for monitoring. Applied to Korea's RPS-era generation-licensing pipeline, it combines action-specific filing counts, planned-deadline displacement, and filing types over common project-age windows. Rebuilding the April 2001-June 2026 ledger yields 4804 records and a dated panel of 1813 projects; principal comparisons use 1018 projects with closed three-year windows. Fuel cells and onshore wind show no statistically detectable difference in extension incidence or intensity, whereas onshore wind has 1.44 times the adjusted deadline displacement among projects with positive movement. Project-level joint analysis adds distinctions that separate technology comparisons conceal. Twenty projects record positive deadline movement without a preparation-period extension, and projects with exactly one extension exhibit different displacement distributions. Ownership-transfer tags further distinguish administrative histories within the same frequency groups. Missing deadlines are retained as missing information rather than unchanged schedules. The resulting profiles describe administrative activity, not commissioning, and direct attention to the records needed to investigate it. The historical case thus provides a recording and interpretation framework for monitoring emerging development regimes.
In emerging economies marked by structural transformation and macroeconomic volatility, inaccurate electricity demand forecasting poses dual threats: supply-security risks from underinvestment and fiscal inefficiencies from overinvestment. For Türkiye, where energy planning centers on the 2035 National Energy Plan (UEP-2035), quantifying these risks is essential. This study develops a policy-oriented probabilistic forecasting framework for Türkiye's electricity demand to 2035. It integrates Lasso, Ridge, SVR, and ANN with Monte Carlo simulation (10,000 iterations) on a multivariate dataset (1990–2023). The dataset combines macroeconomic indicators with satellite-derived Nighttime Light (NTL) as a proxy for economic activity. SVR was chosen as the primary model due to its superior cross-validated performance (CV RMSE = 0.029746) and strong predictive-interval coverage on withheld 2019–2023 data. The framework generated probabilistic demand distributions (P10, P50, P90) for 2024–2035. For 2035, P50 estimates range from 485.43 to 518.83 TWh, with the UEP-2035 target of 510.5 TWh between the median and 90th percentile. P90 scenarios show exceedances of 10.0–17.9% above the target, implying 11–22 GW of additional capacity under empirical capacity factors. A non-parametric block-bootstrap test raises the ensemble P50 to 536.5 TWh. It widens the band from 103.0 to 116.9 TWh, indicating central estimates are sensitive to shock-distribution assumptions while policy implications remain directionally informative. By linking probabilistic forecasts to policy benchmarks, this study shifts focus from prediction accuracy to decision robustness. The framework offers a transparent and replicable decision-support tool for energy policy in emerging economies facing data scarcity and macroeconomic uncertainty.
I restrict straight line remaining life depreciation of regulated public utility capital to be consistent with cost-minimizing timing of retirement, with reference to estimated net salvage. I propose that the net sunk costs of original investment and net salvage be expensed at a constant rate, forever. That rate depends on a utility's weighted average cost of capital; its time-value of money.
