Calpine : Reports Second Quarter 2017 Results and Reaffirms 2017 Guidance

Calpine Corporation (NYSE: CPN):

Summary of Second Quarter 2017 Financial Results (in millions):

Reaffirming 2017 Guidance (in millions):

Recent Achievements:

• Power and Commercial Operations:
  — Generated more than 22 million MWh³ in the second quarter of 2017
  — Delivered strong fleetwide starting reliability: 97.7%

• Portfolio Management:
  — Returned our Delta Energy Center to service in simple-cycle steam bypass configuration in June 2017; plan to return the unit to full combined-cycle configuration in fourth quarter of 2017
  — Negotiating Reliability Must Run contracts with CAISO for two natural gas-fired peaking power plants in California

• Balance Sheet Management:
  — As part of our $2.7 billion plan to delever and reduce interest expense, we have paid down approximately $294 million of debt (net) through the second quarter of 2017 out of $850 million paydown planned for 2017

• Strategy:
  — Board of Directors and management in discussions regarding a potential sale of Calpine

Calpine Corporation (NYSE:CPN) today reported Net Loss¹ of $216 million, or $0.61 per diluted share, for the second quarter of 2017 compared to $29 million, or $0.08 per diluted share, in the prior year period. The period-over-period increase in Net Loss was primarily due to higher income tax expense in the current year in jurisdictions where we do not have net operating losses, an unfavorable variance in mark-to-market gain/loss, net, and increases in plant operating expense and depreciation and amortization expense. Cash provided by operating activities for the second quarter of 2017 was $152 million compared to $94 million in the prior year. The increase in cash provided by operating activities in the second quarter of 2017 was primarily due to a decrease in working capital employed resulting from the period-over-period change in net margining requirements associated with our commodity hedging activity, partially offset by a decrease in income from operations, adjusted for non-cash items.

Adjusted EBITDA² for the second quarter of 2017 was $419 million compared to $452 million in the prior year period. The decrease in Adjusted EBITDA was primarily due to lower Commodity Margin², largely driven by a $40 million natural gas transportation billing credit received in the second quarter of 2016 that did not recur in the current year period, as well as higher plant operating expense, primarily due to our retail acquisitions. Adjusted Unlevered Free Cash Flow² for the second quarter of 2017 was $263 million compared to $324 million in the prior year period, and Adjusted Free Cash Flow² was $103 million compared to $158 million in the prior year period. The decreases in Adjusted Unlevered Free Cash Flow and Adjusted Free Cash Flow were primarily driven by lower Adjusted EBITDA, as previously discussed, and higher major maintenance expense and capital expenditures due to the timing of our outage schedule.

Net loss for the first half of 2017 was $272 million, or $0.77 per diluted share, compared to $227 million, or $0.64 per diluted share in the prior year period. The period-over-period increase in Net Loss was primarily due to increases in plant operating expense and depreciation and amortization expense, and a decrease in commodity revenue, net of commodity expense partially offset by a favorable variance in mark-to-market gain/loss, net and a gain recorded in the first half of 2017 for the sale of Osprey Energy Center. Cash provided by operating activities for the first half of 2017 was $246 million compared to $125 million in the prior year period. The increase in cash provided by operating activities in the first half of 2017 was primarily due to a decrease in working capital employed resulting from the period-over-period change in net margining requirements associated with our commodity hedging activity, partially offset by a decrease in income from operations, adjusted for non-cash items.

Adjusted EBITDA for the first half of 2017 was $745 million compared to $826 million in the prior year period. The decrease in Adjusted EBITDA was primarily due to lower Commodity Margin, largely driven by a gas transportation billing credit received in the second quarter of 2016 that did not recur in the current year period, and lower energy margins due to decreased contribution from wholesale hedges and weaker market conditions in the first quarter, as well as higher plant operating expense, primarily due to our retail acquisitions. Adjusted Unlevered Free Cash Flow for the first half of 2017 was $470 million compared to $590 million in the prior year period, and Adjusted Free Cash Flow was $146 million compared to $260 million in the prior year period. The decreases in Adjusted Unlevered Free Cash Flow and Adjusted Free Cash Flow were primarily driven by lower Adjusted EBITDA, as previously discussed, and higher major maintenance expense and capital expenditures due to the timing of our outage schedule.

“I am pleased to report solid second quarter results, and I am proud of the hard work of our team and the operational excellence of our portfolio,” said Thad Hill, Calpine’s President and Chief Executive Officer. “During the second quarter, we saw stronger power prices for our Texas plants in the constrained Houston zone, and the PJM capacity auction yielded positive prints for our locationally advantaged Mid-Atlantic fleet. In California, our natural gas-fired assets were critical to grid reliability during the recent June heat wave, particularly during the daily evening peaks.

“While these trends support what we believe to be a sound investment thesis for Calpine, the public equity markets have undervalued our business and underappreciated our strong track record of executing on our financial commitments and our stable cash flows. Early this spring, our Board of Directors decided to explore strategic alternatives for the company, seeking to enhance value for our shareholders. At this time, our Board, together with management and financial and legal advisors, are in discussions regarding a potential sale of Calpine."

The Board plans to proceed in a timely manner but has not set a definitive timetable for completion of these discussions. There can be no assurance that these discussions will result in a transaction of any kind, or if a transaction is undertaken, as to terms or timing. Calpine does not intend to disclose developments or provide updates on the status of these discussions unless or until it is determined that further disclosure is appropriate or required by law. Notwithstanding these discussions, the Calpine team remains committed to operational excellence, customer focus and financial discipline.

________

^{1 Reported as Net Loss attributable to Calpine on our Consolidated Condensed Statements of Operations.}

^{2 Non-GAAP financial measure, see “Regulation G Reconciliations” for further details.}

^{3 Includes generation from power plants owned but not operated by Calpine and our share of generation from unconsolidated power plants.}

SUMMARY OF FINANCIAL PERFORMANCE

Second Quarter Results

Adjusted EBITDA for the second quarter of 2017 was $419 million compared to $452 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily related to a $10 million decrease in Commodity Margin and an $18 million increase in plant operating expense⁴, which was largely driven by net portfolio changes including our retail acquisitions. Excluding the benefit from a $40 million natural gas transportation billing credit received in the second quarter of 2016, Commodity Margin would have been up $30 million, primarily due to:

Adjusted Unlevered Free Cash Flow was $263 million in the second quarter of 2017 compared to $324 million in the prior year period. Adjusted Free Cash Flow was $103 million in the second quarter of 2017 compared to $158 million in the prior year period. Adjusted Unlevered Free Cash Flow and Adjusted Free Cash flow decreased primarily due to lower Adjusted EBITDA, as previously discussed, and higher major maintenance expense and capital expenditures due to outage timing.

Year-to-Date Results

Adjusted EBITDA for the first half of 2017 was $745 million compared to $826 million in the prior year period. The year-over-year decrease in Adjusted EBITDA was primarily related to a $32 million decrease in Commodity Margin and a $42 million increase in plant operating expense⁴, which was largely driven by net portfolio changes including our retail acquisitions. The decrease in Commodity Margin was primarily due to:

Adjusted Unlevered Free Cash Flow was $470 million for the first half of 2017 compared to $590 million in the prior year period. Adjusted Free Cash Flow was $146 million for the first half of 2017 compared to $260 million in the prior year period. Adjusted Unlevered Free Cash Flow and Adjusted Free Cash flow decreased primarily due to lower Adjusted EBITDA, as previously discussed, and higher major maintenance expense and capital expenditures due to outage timing.

__________

^{4 Increase in plant operating expense excludes changes in major maintenance expense, stock-based compensation expense, non-cash loss on disposition of assets and other costs. See the table titled “Consolidated Adjusted EBITDA Reconciliation” for the actual amounts of these items for the three and six months ended June 30, 2017 and 2016.}

REGIONAL SEGMENT REVIEW OF RESULTS

Table 1: Commodity Margin by Segment (in millions)

West Region

Second Quarter: Commodity Margin in our West segment decreased by $10 million in the second quarter of 2017 compared to the prior year period. Primary drivers were:

Year-to-Date: Commodity Margin in our West segment increased by $14 million in the first half of 2017 compared to the prior year period. Primary drivers were:

Texas Region

Second Quarter: Commodity Margin in our Texas segment increased by $7 million in the second quarter of 2017 compared to the prior year period. Primary drivers were:

Year-to-Date: Commodity Margin in our Texas segment increased by $2 million in the first half of 2017 compared to the prior year period. Primary drivers were:

East Region

Second Quarter: Commodity Margin in our East segment decreased $7 million in the second quarter of 2017 compared to the prior year period. Primary drivers were:

Year-to-Date: Commodity Margin in our East segment decreased by $48 million in the first half of 2017 compared to the prior year period. Primary drivers were:

LIQUIDITY, CASH FLOW AND CAPITAL RESOURCES

Table 2: Liquidity (in millions)

____________

^{(1) Includes $1 million and $16 million of margin deposits posted with us by our counterparties at June 30, 2017, and December 31, 2016, respectively.}

^{(2) Our ability to use availability under our Corporate Revolving Facility is unrestricted.}

^{(3) Our ability to use corporate cash and cash equivalents is unrestricted. Our $300 million CDHI letter of credit facility is restricted to support certain obligations under PPAs and power transmission and natural gas transportation agreements.}

Liquidity was approximately $1.8 billion as of June 30, 2017. Cash and cash equivalents decreased in the first half of 2017 primarily due to net repayments of debt, consistent with our announced plan to reduce leverage.

Table 3: Cash Flow Activities (in millions)

Cash provided by operating activities in the first half of 2017 was $246 million compared to $125 million in the prior year period. The year-over-year increase was primarily due to a decrease in working capital employed resulting from the period-over-period change in net margining requirements associated with our commodity hedging activity, partially offset by a decrease in income from operations, adjusted for non-cash items.

Cash used in investing activities was $51 million during the first half of 2017 compared to $676 million in the prior year period. The decrease was primarily related to acquisitions, divestitures and capital expenditures. In the first quarter of 2017, we closed on the acquisition of North American Power for $111 million and closed on the sale of Osprey Energy Center, receiving net proceeds of $162 million. In the first quarter of 2016, we purchased Granite Ridge Energy Center for $526 million. There was also a year-over-year decrease of $36 million in capital expenditures, primarily due to lower expenditures on construction projects during the first half of 2017 as compared to 2016.

Cash used in financing activities was $319 million during the first half of 2017 and primarily related to net repayment of debt in accordance with our deleveraging plan.

Managing Our Balance Sheet

We further optimized our capital structure during the first half of 2017, as follows:

2023 First Lien Notes:

— As part of our commitment to reduce debt and interest expense, on March 6, 2017, we redeemed the remaining $453 million of our 7.875% First Lien Notes due in 2023 using cash on hand along with the proceeds from a new $400 million, three-year First Lien Term Loan priced at LIBOR + 1.75% per annum. We intend to repay the 2019 First Lien Term Loan in full by the end of 2018. This accelerates debt reduction and results in substantial annual interest savings of more than $20 million in the interim.

2017 First Lien Term Loan:

— We repaid approximately $150 million of our 2017 First Lien Term Loan using cash on hand during the first quarter of 2017.

Expanding Our Customer Sales Channels

We continue to focus on getting closer to our customers through expansion of our retail platform, which began with the acquisition of Champion Energy in 2015 and was followed by the acquisitions of Calpine Energy Solutions in late 2016 and North American Power in early 2017. Our retail platform geographically and strategically complements our wholesale generation fleet by providing forward liquidity with sufficient margins. The combination of our wholesale origination and retail platform provides Calpine access to both direct and mass market sales channels. Our direct sales efforts aim to provide our larger customers with customized products, leveraging both our successful wholesale origination efforts and Calpine Energy Solutions’ presence among large commercial and industrial organizations to secure new contracts. Our mass market approach relies upon our expanded Champion Energy retail platform to serve the needs of both residential and smaller commercial and industrial customers across the country. We believe that our retail platform is strategically complete and are now focused on integrating it into our business and optimizing its financial performance.

Acquisition of North American Power & Gas, LLC

On January 17, 2017, we completed the purchase of North American Power for approximately $105 million, excluding working capital and other adjustments. North American Power is a growing retail energy supplier for homes and small businesses and is primarily concentrated in the Northeast U.S., where Calpine has a substantial power generation presence. Champion Energy also has a substantial retail sales footprint in the Northeast U.S. that is enhanced by the addition of North American Power, which has been integrated into our Champion Energy retail platform. With this acquisition, we now serve residential load in 63 utility service territories as compared to 51 in 2016.

Portfolio Management

East:

Washington Parish: On April 21, 2017, we entered into an agreement with Entergy Louisiana (Entergy), a subsidiary of Entergy Corporation, to construct an approximately 360 MW natural gas-fired peaking power plant on a partially developed site that we own near Bogalusa, Louisiana. Within a short period of time subsequent to the plant commencing commercial operations and meeting certain performance objectives, Entergy will purchase the plant for a fixed payment, including a fair market return. Construction on the facility will not commence until 2019 with COD expected in early 2021. The agreement contains conditions precedent to effectiveness including, but not limited to, approval of the Louisiana Public Service Commission. We plan to fund the project with a construction loan that will be repaid upon receipt of sale proceeds.

York 2 Energy Center: York 2 Energy Center is an 828 MW dual-fuel, combined-cycle project that is co-located with our York Energy Center in Peach Bottom Township, Pennsylvania. Once complete, the power plant will feature two combustion turbines, two heat recovery steam generators and one steam turbine. Due to construction delays, we are now targeting COD in the first half of 2018.

Osprey Energy Center: On January 3, 2017, we completed the sale of Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration.

Texas:

Clear Lake Power Plant: On February 1, 2017, we retired our 400 MW Clear Lake Power Plant due to a lack of adequate compensation in Texas. Built in 1985, Clear Lake utilized an older, less efficient technology.

Guadalupe Peaking Energy Center: In April 2017, we canceled an agreement with Guadalupe Valley Electric Cooperative (GVEC) related to the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our existing Guadalupe Energy Center. In lieu of building the facility, we will now serve GVEC with 200 MW of generating capacity under a 10-year PPA beginning in June 2019.

West:

California Peakers: As a result of the pending expiration of a PPA in December 2017, we informed CAISO of our intent to suspend operations at four of our California peaking natural gas-fired power plants with capacity totaling 186 MW. CAISO has determined that two of these power plants, Yuba City and Feather River energy centers, are needed to continue reliable operation of the power grid. We are currently negotiating Reliability Must Run contracts for these two power plants.

South Point Energy Center: As a result of the denial by the Nevada Public Utility Commission of the sale of South Point Energy Center to Nevada Power Company in February 2017, we terminated the corresponding asset sale agreement in the first quarter of 2017. We are currently assessing our options related to South Point Energy Center.

OPERATIONS UPDATE

Second Quarter Power Operations Achievements:

• Availability Performance:
  — Delivered strong fleetwide starting reliability: 97.7%

• Power Generation:
  — Generated more than 22 million MWh³
  — Four merchant plants achieved greater than 65% net capacity factor: Bosque, Garrison, Freestone and Pasadena

2017 Operating Event at our Delta Energy Center

On January 29, 2017, we experienced an operating event at our Delta Energy Center that resulted in an emergency shutdown of the power plant and significant damage to the steam turbine and steam turbine generator. The unit returned to service in simple-cycle steam bypass configuration in June 2017, and our current plan is to return the unit to full combined-cycle configuration in the fourth quarter of 2017. We anticipate that insurance will cover a significant portion of our losses, after applicable deductibles.

2017 FINANCIAL OUTLOOK

____________

^{(1) Maintenance capital expenditures exclude major construction and development projects.}

^{(2) Includes commitment, letter of credit and other bank fees from consolidated and unconsolidated investments, net of capitalized interest and interest income.}

^{(3) Includes projected major maintenance expense of $275 million and maintenance capital expenditures of $160 million.}

As detailed above, today we are reaffirming our 2017 Adjusted EBITDA and Adjusted Free Cash Flow guidance ranges and are introducing guidance for Adjusted Unlevered Free Cash Flow. We expect Adjusted EBITDA of $1.8 billion to $1.95 billion, Adjusted Unlevered Free Cash Flow of $1.355 billion to $1.505 billion and Adjusted Free Cash Flow of $710 million to $860 million in 2017.

INVESTOR CONFERENCE CALL AND WEBCAST

We will host a conference call to discuss our financial and operating results for the second quarter on Friday, July 28, 2017, at 10 a.m. Eastern time / 9 a.m. Central time. A listen-only webcast of the call may be accessed through our website at www.calpine.com, or by dialing (800) 446-1671 in the U.S. or (847) 413-3362 outside the U.S. The confirmation code is 45310747. A recording of the call will be made available for a limited time on our website or by dialing (888) 843-7419 in the U.S. or (630) 652-3042 outside the U.S. and providing confirmation code 45310747. Presentation materials to accompany the conference call will be posted on our website on July 28, 2017.

ABOUT CALPINE

Calpine Corporation is America’s largest generator of electricity from natural gas and geothermal resources with operations in competitive power markets. Our fleet of 80 power plants in operation or under construction represents approximately 26,000 megawatts of generation capacity. Through wholesale power operations and our retail businesses Calpine Energy Solutions and Champion Energy, we serve customers in 25 states, Canada and Mexico. Our clean, efficient, modern and flexible fleet uses advanced technologies to generate power in a low-carbon and environmentally responsible manner. We are uniquely positioned to benefit from the secular trends affecting our industry, including the abundant and affordable supply of clean natural gas, environmental regulation, aging power generation infrastructure and the increasing need for dispatchable power plants to successfully integrate intermittent renewables into the grid. Please visit www.calpine.com to learn more about how Calpine is creating power for a sustainable future.

Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, has been filed with the Securities and Exchange Commission (SEC) and is available on the SEC’s website at www.sec.gov.

FORWARD-LOOKING INFORMATION

In addition to historical information, this release contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this release. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. We believe that the forward-looking statements are based upon reasonable assumptions and expectations. However, you are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to:

• Financial results that may be volatile and may not reflect historical trends due to, among other things, seasonality of demand, fluctuations in prices for commodities such as natural gas and power, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability and extent to which we hedge risks;
• Laws, regulations and market rules in the wholesale and retail markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate;
• Our ability to manage our liquidity needs, access the capital markets when necessary and comply with covenants under our Senior Unsecured Notes, First Lien Notes, First Lien Term Loans, Corporate Revolving Facility, CCFC Term Loans and other existing financing obligations;
• Risks associated with the operation, construction and development of power plants, including unscheduled outages or delays and plant efficiencies;
• Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements, variables associated with the injection of water to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources;
• Competition, including from renewable sources of power, interference by states in competitive power markets through subsidies or similar support for new or existing power plants, and other risks associated with marketing and selling power in the evolving energy markets;
• Structural changes in the supply and demand of power resulting from the development of new fuels or technologies and demand-side management tools (such as distributed generation, power storage and other technologies);
• The expiration or early termination of our PPAs and the related results on revenues;
• Future capacity revenue may not occur at expected levels;
• Natural disasters, such as hurricanes, earthquakes, droughts, wildfires and floods, acts of terrorism or cyber-attacks that may affect our power plants or the markets our power plants or retail operations serve and our corporate offices;
• Disruptions in or limitations on the transportation of natural gas or fuel oil and the transmission of power;
• Our ability to manage our counterparty and customer exposure and credit risk, including our commodity positions;
• Our ability to attract, motivate and retain key employees;
• Present and possible future claims, litigation and enforcement actions that may arise from noncompliance with market rules promulgated by the SEC, CFTC, FERC and other regulatory bodies; and
• Other risks identified in this press release, in our Annual Report on Form 10-K for the year ended December 31, 2016, and in other reports filed by us with the SEC.

Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this release. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise.

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^{(1) Includes amortization recorded in Commodity revenue and Commodity expense associated with intangible assets and amortization recorded in interest expense associated with debt issuance costs and discounts.}

^{(2) On April 3, 2017, we completed the purchase of the King City Cogeneration Plant lease in exchange for a three-year promissory note with a discounted value of $57 million. We recorded a net increase to property, plant and equipment, net on our Consolidated Condensed Balance Sheet of $15 million due to the increased value of the promissory note as compared to the carrying value of the lease.}

REGULATION G RECONCILIATIONS

In addition to disclosing financial results in accordance with U.S. GAAP, the accompanying second quarter 2017 earnings release contains non-GAAP financial measures. Commodity Margin, Adjusted Free Cash Flow, Adjusted Unlevered Free Cash Flow and Adjusted EBITDA are non-GAAP financial measures that we use as measures of our performance and liquidity. These non-GAAP measures should be viewed as a supplement to and not a substitute for our U.S. GAAP measures of performance and liquidity, and the financial results calculated in accordance with U.S. GAAP and reconciliations from these results should be carefully evaluated.

Commodity Margin includes revenues recognized on our wholesale and retail power sales activity, electric capacity sales, renewable energy credit sales, steam sales, realized settlements associated with our marketing, hedging, optimization and trading activity, fuel and purchased energy expenses, commodity transmission and transportation expenses and environmental compliance expenses. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin is not a measure calculated in accordance with U.S. GAAP and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with U.S. GAAP. Commodity Margin does not intend to represent income (loss) from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies.

Adjusted Free Cash Flow represents cash flows from operating activities including the effects of maintenance capital expenditures, adjustments to reflect the Adjusted Free Cash Flow from unconsolidated investments and to exclude the noncontrolling interest and other miscellaneous adjustments such as the effect of changes in working capital. Adjusted Unlevered Free Cash Flow is calculated on the same basis as Adjusted Free Cash Flow but excludes the effect of cash interest, net, and operating lease payments, thus capturing the performance of our business independent of its capital structure. Adjusted Free Cash Flow and Adjusted Unlevered Free Cash Flow are presented because we believe they are useful measures of liquidity to assist in comparing financial results from period to period on a consistent basis and to readily view operating trends, as measures for planning and forecasting overall expectations and for evaluating actual results against such expectations and in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial results. Adjusted Free Cash Flow and Adjusted Unlevered Free Cash Flow are liquidity measures and are not intended to represent cash flows from operations, the most directly comparable U.S. GAAP measure, and are not necessarily comparable to similarly titled measures reported by other companies.

Adjusted EBITDA represents net loss attributable to Calpine before net (income) attributable to the noncontrolling interest, interest, taxes, depreciation and amortization, and is also adjusted for the effects of impairment losses, gains or losses on sales, dispositions or retirements of assets, any mark-to-market gains or losses from accounting for derivatives, adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, stock-based compensation expense, operating lease expense, non-cash gains and losses from foreign currency translations, major maintenance expense, gains or losses on the repurchase, modification or extinguishment of debt, non-cash GAAP-related adjustments to levelize revenues from tolling agreements and any unusual or non-recurring items plus adjustments to reflect the Adjusted EBITDA from our unconsolidated investments. We adjust for these items in our Adjusted EBITDA as our management believes that these items would distort their ability to efficiently view and assess our core operating trends. We believe that investors commonly adjust EBITDA information to eliminate the effects of restructuring and other expenses, which vary widely from company to company and impair comparability. Adjusted EBITDA is not intended to represent net income (loss) as defined by U.S. GAAP as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. We are presenting Adjusted EBITDA along with a reconciliation to Adjusted Unlevered Free Cash Flow to demonstrate the relationship between our traditional performance measure, Adjusted EBITDA, and our new liquidity measure, Adjusted Unlevered Free Cash Flow.

Commodity Margin Reconciliation

The following tables reconcile income (loss) from operations to Commodity Margin for the three and six months ended June 30, 2017 and 2016 (in millions):

_________

^{(1) Includes $(24) million and $(20) million of lease levelization and $44 million and $27 million of amortization expense for the three months ended June 30, 2017 and 2016, respectively.}

^{(2) Includes $(46) million and $(42) million of lease levelization and $104 million and $54 million of amortization expense for the six months ended June 30, 2017 and 2016, respectively.}

Consolidated Adjusted EBITDA Reconciliation

In the following table, we have reconciled our Adjusted EBITDA to our Commodity Margin, both of which are non-GAAP measures, for the three and six months ended June 30, 2017 and 2016. Reconciliations for both Adjusted EBITDA and Commodity Margin to comparable U.S. GAAP measures are provided above. Amounts below are shown exclusive of the noncontrolling interest (in millions):

_________

^{(1) Shown net of major maintenance expense, stock-based compensation expense, non-cash loss on dispositions of assets and other costs.}

^{(2) Shown net of stock-based compensation expense and other costs.}

^{(3) Shown net of operating lease expense, amortization and other costs.}

In the following table, we have reconciled our net loss attributable to Calpine to Adjusted EBITDA for the three and six months ended June 30, 2017 and 2016, as reported under U.S. GAAP (in millions). We also reconciled Adjusted EBITDA to Adjusted Unlevered Free Cash Flow to demonstrate the relationship between our traditional performance measure, Adjusted EBITDA, and our new liquidity measure, Adjusted Unlevered Free Cash Flow.

____________

^{(1) Excludes depreciation and amortization expense attributable to the non-controlling interest.}

^{(2) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for each of the three and six months ended June 30, 2017 and 2016.}

^{(3) Includes $86 million and $151 million in major maintenance expense for the three and six months ended June 30, 2017, respectively, and $59 million and $109 million in maintenance capital expenditures for the three and six months ended June 30, 2017, respectively. Includes $81 million and $146 million in major maintenance expenditures for the three and six months ended June 30, 2016, respectively, and $41 million and $81 million in maintenance capital expenditures for the three and six months ended June 30, 2016, respectively.}

^{(4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income.}

^{(5) Adjusted Free Cash Flow, as reported, excludes changes in working capital, such that it is calculated on the same basis as our guidance.}

Adjusted Unlevered Free Cash Flow Reconciliation

In the following table, we have reconciled our cash flows from operating activities to our Adjusted Unlevered Free Cash Flow for the three and six months ended June 30, 2017 and 2016 (in millions).

_________

^{(1) Maintenance capital expenditures exclude major construction and development projects.}

^{(2) Adjustment excludes $3 million and $35 million in amortization of acquired derivatives contracts for three months ended June 30, 2017 and 2016, respectively, and $(10) million and $45 million in amortization of acquired derivatives contracts for the six months ended June 30, 2017 and 2016, respectively.}

^{(3) Other primarily represents miscellaneous items excluded from Adjusted Free Cash Flow that are included in cash flow from operations.}

^{(4) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income.}

^{(5) Includes $86 million and $151 million in major maintenance expense for the three and six months ended June 30, 2017, respectively, and $59 million and $109 million in maintenance capital expenditures for the three and six months ended June 30, 2017, respectively. Includes $81 million and $146 million in major maintenance expense for the three and six months ended June 30, 2016, respectively, and $41 million and $81 million in maintenance capital expenditures for the three and six months ended June 30, 2016, respectively.}

Adjusted Unlevered Free Cash Flow Reconciliation for Guidance (in millions)

____________

^{(1) Maintenance capital expenditures exclude major construction and development projects.}

^{(2) Includes commitment, letter of credit and other bank fees from both consolidated and unconsolidated investments, net of capitalized interest and interest income.}

^{(3) Includes projected major maintenance expense of $275 million and maintenance capital expenditures of $160 million.}

OPERATING PERFORMANCE METRICS

The table below shows the operating performance metrics for the periods presented:

________

^{(1) Excludes generation from unconsolidated power plants and power plants owned but not operated by us.}

^{(2) Generation, average availability and steam adjusted heat rate exclude power plants and units that are inactive.}

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