In this dissertation, I explore the costs and benefits of regulatory versus market price setting mechanisms for electricity generation in the United States. This paper is split into two sections. I devote the first section to studying the costs of regulatory distortions in input procurement for U.S coal-fired power plants. The second section (joint with Frank Wolak) quantifies the efficiency gains associated with the introduction of financial trading in California's wholesale electricity markets. In Chapter 1, I begin with the following puzzling fact: during my 1983-1997 sample period, electric utilities subject to output price regulation purchase much of their input coal via long-term contracts, consistently paying contract prices in excess of expected spot market prices. I argue that regulators are less likely to pass through high coal procurement cost realizations to consumers, inducing expected profit maximizing firms under output price regulation to express a willingness to pay for both a lower mean and a lower variance in costs ("as if"' risk aversion). I show descriptively that plants facing higher spot price uncertainty sign coal contracts with a longer duration, and purchase a higher proportion of their required coal from these contracts relative to the spot market. At their observed contracting proportions, I find that plants on average are willing to trade off a 0.22% increase in mean procurement costs for a 10% reduction in the variance of costs. If plants counterfactually purchase all of their required coal from the spot market, I find a roughly 10.5% ($87 million per month over plants) decrease in mean coal procurement costs. However, this reduction in mean costs comes with a significant increase in the variance of costs; even if plants were willing to double their variance in costs, we would only see a 1.7% reduction in mean costs. Policymakers and regulators often argue that there are benefits associated with decreased volatility in input costs; this paper provides the increase in expected costs associated with decreased volatility to be weighed against these benefits. In Chapter 2, I quantify the dynamic productive efficiency gains in input procurement associated with introducing market mechanisms into a formerly price regulated industry. I do so within the context of the U.S coal-fired power generation sector from 1983-2012. I formulate and estimate a dynamic plant-level model of coal purchase and storage decisions. Holding constant the plant's pattern of input prices and output, I find that it costs a regulated plant roughly 3% more per month to procure and store coal relative to the same plant facing market prices. This amounts to roughly $35 million per month saved in procurement costs if all price-regulated coal-fired plants in the U.S instead faced market prices. This regulatory distortion stems both from the fact that the structure of output price regulation: 1) passes through all prudently incurred coal purchases, and 2) provides a working capital allowance for inventories held on-site. Empirically, I find that the first source is more important; changes in when and how much coal a plant buys under output price regulation explains more of the 3% regulatory distortion relative to changes in the level of inventories held. One of the primary concerns regarding output price regulation has been distortions in the level of investment due to the regulated return provided on capital; my findings indicate that regulatory distortions to the timing of capital investments may be costlier. Finally, I switch gears in Chapter 3; with Frank Wolak, I develop an empirical test for the existence of arbitrage with transactions costs and use this test to study the introduction of financial trading in California's wholesale electricity markets. I begin by noting that, with risk neutral traders and zero transactions costs, the expected value of the difference between the current forward price and the spot price of a commodity at the delivery date of the forward contract should be zero. Accounting for the transactions costs associated with trading in these two markets invalidates this result. We develop statistical tests of the null hypothesis that profitable trading strategies exploiting systematic differences between spot and forward market prices exist in the presence of trading costs. We implement these tests using the day-ahead forward and real-time locational marginal prices from California's wholesale electricity market and use them to construct an estimate of the variable cost of trading in this market. During our sample period, we observe the introduction of convergence bidding, which was aimed at reducing the costs associated with exploiting differences between forward and spot prices. Our measures of trading costs are significantly smaller after the introduction of convergence bidding. Estimated trading costs are lower for generation nodes relative to non-generation nodes before explicit virtual bidding and trading costs fell more for non-generation nodes after explicit virtual bidding, eliminating any difference in trading costs across the two types of nodes. We also present evidence that the introduction of convergence bidding reduced the total amount of input fossil fuel energy required to generate the thermal-based electricity produced in California and the total variable of costs of producing this electrical energy. Taken together, these results demonstrate that purely financial forward market trading can improve the operating efficiency of short-term commodity markets.