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Derivative Financial Instruments (All Registrants) | 12 Months Ended
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Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract] |
Derivative Financial Instruments (All Registrants) | Derivative Financial Instruments (All Registrants) The Registrants use derivative instruments to manage commodity price risk, interest rate risk and foreign exchange risk related to ongoing business operations. Commodity Price Risk (All Registrants) To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. Each of the Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and commodity products. The Registrants believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices. Derivative authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include normal purchase normal sale (NPNS), cash flow hedges and fair value hedges. For Generation, all derivative economic hedges related to commodities are recorded at fair value through earnings for the consolidated company, referred to as economic hedges in the following tables. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities. Fair value authoritative guidance and disclosures about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referencing contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. Generation’s use of cash collateral is generally unrestricted, unless Generation is downgraded below investment grade (i.e., to BB+ or Ba1). In the table below, Generation’s energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting column. As of December 31, 2018, $2 million of cash collateral posted with external counterparties and an additional $12 million of cash collateral posted with ComEd, and as of December 31, 2017, $4 million of cash collateral held, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, were associated with accrual positions, or had no positions to offset as of the balance sheet date. Excluded from the tables below are economic hedges that qualify for the NPNS scope exception and other non-derivative contracts that are accounted for under the accrual method of accounting. ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade (i.e., to BB+ or Ba1). Cash collateral held by PECO and BGE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications. In the table below, DPL's economic hedges are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting column. The following table provides a summary of the derivative fair value balances related to commodity contracts recorded by the Registrants as of December 31, 2018:
| Generation |  | ComEd |  | Exelon
Description | Economic Hedges |  | Proprietary Trading |  | Collateral and Netting(a)(d) |  | Subtotal(b) |  | Economic Hedges(c) |  | Total Derivatives
Mark-to-market derivative assets (current assets) | $ | 3,505 |  |  | $ | 105 |  |  | $ | (2,809 | ) |  | $ | 801 |  |  | $ | — |  |  | $ | 801 |
Mark-to-market derivative assets (noncurrent assets) | 1,266 |  |  | 41 |  |  | (862 | ) |  | 445 |  |  | — |  |  | 445 |
Total mark-to-market derivative assets | 4,771 |  |  | 146 |  |  | (3,671 | ) |  | 1,246 |  |  | — |  |  | 1,246 |
Mark-to-market derivative liabilities (current liabilities) | (3,429 | ) |  | (74 | ) |  | 3,056 |  |  | (447 | ) |  | (26 | ) |  | (473 | )
Mark-to-market derivative liabilities (noncurrent liabilities) | (1,203 | ) |  | (20 | ) |  | 972 |  |  | (251 | ) |  | (223 | ) |  | (474 | )
Total mark-to-market derivative liabilities | (4,632 | ) |  | (94 | ) |  | 4,028 |  |  | (698 | ) |  | (249 | ) |  | (947 | )
Total mark-to-market derivative net assets (liabilities) | $ | 139 |  |  | $ | 52 |  |  | $ | 357 |  |  | $ | 548 |  |  | $ | (249 | ) |  | $ | 299 |
__________
(a) | Exelon and Generation net all available amounts allowed under the derivative authoritative guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases, Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above.
(b) | Current and noncurrent assets are shown net of collateral of $121 million and $51 million, respectively, and current and noncurrent liabilities are shown net of collateral of $125 million and $60 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $357 million at December 31, 2018.
(c) | Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
(d) | Of the collateral posted/(received), $(94) million represents variation margin on the exchanges.
The following table provides a summary of the derivative fair value balances related to commodity contracts recorded by the Registrants as of December 31, 2017:
| Generation |  | ComEd |  | Exelon
Description | Economic Hedges |  | Proprietary Trading |  | Collateral and Netting(a)(d) |  | Subtotal(b) |  | Economic Hedges(c) |  | Total Derivatives
Mark-to-market derivative assets (current assets) | $ | 3,061 |  |  | $ | 56 |  |  | $ | (2,144 | ) |  | $ | 973 |  |  | $ | — |  |  | $ | 973 |
Mark-to-market derivative assets (noncurrent assets) | 1,164 |  |  | 12 |  |  | (845 | ) |  | 331 |  |  | — |  |  | 331 |
Total mark-to-market derivative assets | 4,225 |  |  | 68 |  |  | (2,989 | ) |  | 1,304 |  |  | — |  |  | 1,304 |
Mark-to-market derivative liabilities (current liabilities) | (2,646 | ) |  | (43 | ) |  | 2,480 |  |  | (209 | ) |  | (21 | ) |  | (230 | )
Mark-to-market derivative liabilities (noncurrent liabilities) | (1,137 | ) |  | (10 | ) |  | 975 |  |  | (172 | ) |  | (235 | ) |  | (407 | )
Total mark-to-market derivative liabilities | (3,783 | ) |  | (53 | ) |  | 3,455 |  |  | (381 | ) |  | (256 | ) |  | (637 | )
Total mark-to-market derivative net assets (liabilities) | $ | 442 |  |  | $ | 15 |  |  | $ | 466 |  |  | $ | 923 |  |  | $ | (256 | ) |  | $ | 667 |
__________
(a) | Exelon and Generation net all available amounts allowed under the derivative authoritative guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases, Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit and other forms of non-cash collateral. These are not reflected in the table above.
(b) | Current and noncurrent assets are shown net of collateral of $169 million and $53 million, respectively, and current and noncurrent liabilities are shown net of collateral of $167 million and $77 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $466 million at December 31, 2017.
(c) | Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
(d) | Of the collateral posted/(received), $(117) million represents variation margin on the exchanges.
Economic Hedges (Commodity Price Risk) Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements and other energy-related products marketed and purchased. To manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis. For the years ended December 31, 2018, 2017 and 2016, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the "Net fair value changes related to derivatives" in the Consolidated Statements of Cash Flows.
|  | For the Years Ended December 31,
|  | 2018 |  | 2017 |  | 2016
Income Statement Location |  | Gain (Loss)
Operating revenues |  | $ | (270 | ) |  | $ | (126 | ) |  | $ | (490 | )
Purchased power and fuel |  | (47 | ) |  | (43 | ) |  | 459 |
Total Exelon and Generation |  | $ | (317 | ) |  | $ | (169 | ) |  | $ | (31 | )
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of December 31, 2018, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 89%-92%, 56%-59% and 32%-35% for 2019, 2020 and 2021, respectively. On December 17, 2010, ComEd executed several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note 4 — Regulatory Matters for additional information. PECO’s natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches to achieve system supply reliability at the least cost. PECO’s reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO’s natural gas supply and asset management agreements that are derivatives either qualify for the NPNS scope exception and have been designated as such, or have no mark-to-market balances because the derivatives are index priced. Additionally, in accordance with the 2018 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2018 and previous PGC settlements, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program is designed to cover about 20% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s results of operations and financial position as natural gas costs are fully recovered from customers under the PGC. BGE has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC. The SOS rates charged recover BGE’s wholesale power supply costs and include an administrative fee. BGE’s commodity price risk related to electric supply procurement is limited. BGE locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of BGE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other BGE full requirements contracts are not derivatives. BGE provides natural gas to its customers under a MBR mechanism approved by the MDPSC. Under this mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers. BGE must also secure fixed price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the MBR mechanism. BGE also ensures it has sufficient pipeline transportation capacity to meet customer requirements. BGE’s natural gas supply and asset management agreements qualify for the NPNS scope exception and result in physical delivery. Pepco has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and DCPSC. The SOS rates charged recover Pepco's wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for residential and commercial rate classes. Pepco’s commodity price risk related to electric supply procurement is limited. Pepco locks in fixed prices for its SOS requirements through full requirements contracts. Certain of Pepco’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other Pepco full requirements contracts are not derivatives. DPL has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and the DPSC. The SOS rates charged recover DPL's wholesale power supply costs. In Delaware, DPL is also entitled to recover a Reasonable Allowance for Retail Margin (RARM). The RARM includes a fixed annual margin of approximately $2.75 million, plus an incremental cost component and a cash working capital allowance. In Maryland, DPL charges an administrative fee intended to allow it to recover its administrative costs. DPL locks in fixed prices for its SOS requirements through full requirements contracts. DPL’s commodity price risk related to electric supply procurement is limited. Certain of DPL’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives. DPL provides natural gas to its customers under an Annual GCR mechanism approved by the DPSC. Under this mechanism, DPL’s Annual GCR Filing establishes a future GCR for firm bundled sales customers by using a forecast of demand and commodity costs. The actual costs are trued up against forecast on a monthly basis and any shortfall or excess is carried forward as a recovery balance in the next GCR filing. The demand portion of the GCR is based upon DPL’s firm transportation and storage contracts. DPL has firm deliverability of swing and seasonal storage; a liquefied natural gas facility and firm transportation capacity to meet customer demand and provide a reserve margin. The commodity portion of the GCR includes a commission approved hedging program which is intended to reduce gas commodity price volatility while limiting the firm natural gas customers’ exposure to adverse changes in the market price of natural gas. The hedge program requires that DPL hedge, on a non-discretionary basis, an amount equal to 50% of estimated purchase requirements for each month, including estimated monthly purchases for storage injections. The 50% hedge monthly target is achieved by hedging 1/12th of the 50% target each month beginning 12-months prior to the month in which the physical gas is to be purchased. Currently, DPL uses only exchange traded futures for its gas hedging program, which are considered derivatives, however, it retains the capability to employ other physical and financial hedges if needed. DPL has not elected hedge accounting for these derivative financial instruments. Because of the DPSC-approved fuel adjustment clause for DPL's derivatives, the change in fair value of the derivatives each period, in addition to all premiums paid and other transaction costs incurred as part of the Gas Hedging Program, are fully recoverable and are recorded by DPL as regulatory assets or liabilities. DPL’s physical gas purchases are currently all daily, monthly or intra-month transactions. From time to time, DPL will enter into seasonal purchase or sale arrangements, however, there are none currently in the portfolio. Certain of DPL's full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives. ACE has contracts to procure BGS electric supply that are executed through a competitive procurement process approved by the NJBPU. The BGS rates charged recover ACE's wholesale power supply costs. ACE does not make any profit or incur any loss on the supply component of the BGS it supplies to customers. ACE’s commodity price risk related to electric supply procurement is limited. ACE locks in fixed prices for its BGS requirements through full requirements contracts. Certain of ACE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other ACE full requirements contracts are not derivatives. Proprietary Trading (Commodity Price Risk) Generation also executes commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading portfolio is subject to a risk management policy that includes stringent risk management limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon's RMC monitor the financial risks of the proprietary trading activities. The proprietary trading activities are a complement to Generation's energy marketing portfolio but represent a small portion of Generation's overall revenue from energy marketing activities. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. For the years ended December 31, 2018, 2017 and 2016, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also included in the "Net fair value changes related to derivatives" in the Consolidated Statements of Cash Flows. The Utility Registrants do not execute derivatives for proprietary trading purposes.
|  | For the Years Ended December 31,
|  | 2018 |  | 2017 |  | 2016
Income Statement Location |  | Gain
Operating revenues |  | $ | 17 |  |  | $ | 6 |  |  | $ | 2 |
Interest Rate and Foreign Exchange Risk (All Registrants) The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants also utilize interest rate swaps, which are treated as economic hedges, to manage their interest rate exposure. To manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are treated as economic hedges. Below is a summary of the interest rate and foreign exchange hedge balances as of December 31, 2018:
| Generation |  | Exelon Corporate |  | Exelon
Description |  | Economic Hedges |  | Collateral and Netting(a) |  | Subtotal |  | Economic Hedges |  | Total
Mark-to-market derivative assets (current assets) |  | $ | 5 |  |  | $ | (2 | ) |  | $ | 3 |  |  | $ | — |  |  | $ | 3 |
Mark-to-market derivative assets (noncurrent assets) |  | 8 |  |  | (1 | ) |  | 7 |  |  | — |  |  | 7 |
Total mark-to-market derivative assets |  | 13 |  |  | (3 | ) |  | 10 |  |  | — |  |  | 10 |
Mark-to-market derivative liabilities (current liabilities) |  | (4 | ) |  | 2 |  |  | (2 | ) |  | — |  |  | (2 | )
Mark-to-market derivative liabilities (noncurrent liabilities) |  | (2 | ) |  | 1 |  |  | (1 | ) |  | (4 | ) |  | (5 | )
Total mark-to-market derivative liabilities |  | (6 | ) |  | 3 |  |  | (3 | ) |  | (4 | ) |  | (7 | )
Total mark-to-market derivative net assets (liabilities) |  | $ | 7 |  |  | $ | — |  |  | $ | 7 |  |  | $ | (4 | ) |  | $ | 3 |
__________
(a) | Exelon and Generation net all available amounts allowed under the derivative authoritative guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases, Exelon and Generation may have other offsetting counterparty exposures subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral, which are not reflected in the table above.
The following table provides a summary of the interest rate and foreign exchange hedge balances recorded by the Registrants as of December 31, 2017:
| Generation |  | Exelon Corporate |  | Exelon
Description | Derivatives Designated as Hedging Instruments |  | Economic Hedges |  | Collateral and Netting(a) |  | Subtotal |  | Derivatives Designated as Hedging Instruments |  | Total
Mark-to-market derivative assets (current assets) | $ | — |  |  | $ | 10 |  |  | $ | (7 | ) |  | $ | 3 |  |  | $ | — |  |  | $ | 3 |
Mark-to-market derivative assets (noncurrent assets) | 3 |  |  | — |  |  | — |  |  | 3 |  |  | 3 |  |  | 6 |
Total mark-to-market derivative assets | 3 |  |  | 10 |  |  | (7 | ) |  | 6 |  |  | 3 |  |  | 9 |
Mark-to-market derivative liabilities (current liabilities) | (2 | ) |  | (7 | ) |  | 7 |  |  | (2 | ) |  | — |  |  | (2 | )
Mark-to-market derivative liabilities (noncurrent liabilities) | — |  |  | (2 | ) |  | — |  |  | (2 | ) |  | — |  |  | (2 | )
Total mark-to-market derivative liabilities | (2 | ) |  | (9 | ) |  | 7 |  |  | (4 | ) |  | — |  |  | (4 | )
Total mark-to-market derivative net assets (liabilities) | $ | 1 |  |  | $ | 1 |  |  | $ | — |  |  | $ | 2 |  |  | $ | 3 |  |  | $ | 5 |
__________
(a) | Exelon and Generation net all available amounts allowed under the derivative authoritative guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases, Exelon and Generation may have other offsetting counterparty exposures subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral, which are not reflected in the table above.
Economic Hedges (Interest Rate and Foreign Exchange Risk) Exelon and Generation execute these instruments to mitigate exposure to fluctuations in interest rates or foreign exchange but for which the fair value or cash flow hedge elections were not made. On July 1, 2018, Exelon de-designated its fair value hedges related to interest rate risk and Generation de-designated its cash flow hedges related to interest rate risk. The amount deferred in AOCI associated with the previously designated cash flow hedges will be reclassified into earnings as the underlying forecasted transaction occurs. The result of this de-designation is that all economic hedges for interest rate swaps will be recorded at fair value through earnings going forward, referred to as economic hedges in the following tables. The following table provides notional amounts outstanding held by Exelon and Generation at December 31, 2018 related to interest rate swaps and foreign currency exchange rate swaps.
|  | Generation |  | Exelon Corporate |  | Exelon
Foreign currency exchange rate swaps |  | $ | 268 |  |  | $ | — |  |  | $ | 268 |
Interest rate swaps |  | 620 |  |  | 800 |  |  | 1,420 |
Total |  | $ | 888 |  |  | $ | 800 |  |  | $ | 1,688 |
The following table provides notional amounts outstanding held by Exelon and Generation at December 31, 2017 related to interest rate swaps and foreign currency exchange rate swaps.
|  | Generation |  | Exelon Corporate |  | Exelon
Foreign currency exchange rate swaps |  | $ | 94 |  |  | $ | — |  |  | $ | 94 |
Interest rate swaps(a) |  | 1 |  |  | — |  |  | 1 |
Total |  | $ | 95 |  |  | $ | — |  |  | $ | 95 |
__________
(a) | On July 1, 2018, Exelon and Generation de-designated its fair value and cash flow hedges. The table excludes amounts of $800 million of fixed-to-floating hedges that were previously designated as fair value hedges by Exelon and $636 million of floating-to-fixed hedges that were previously designated as cash flow hedges by Exelon and Generation as of December 31, 2017.
For the years ended December 31, 2018, 2017 and 2016, Exelon and Generation recognized the following net pre-tax mark-to-market gains (losses) in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows.
|  |  |  | For the Years Ended December 31,
|  |  |  | 2018 |  | 2017 |  | 2016
|  | Income Statement Location |  | Gain (Loss)
Generation |  | Operating Revenues |  | $ | 7 |  |  | $ | (6 | ) |  | $ | (10 | )
Generation |  | Purchased Power and Fuel |  | (9 | ) |  | — |  |  | — |
Generation |  | Interest Expense |  | (7 | ) |  | (3 | ) |  | — |
Total Generation |  |  |  | $ | (9 | ) |  | $ | (9 | ) |  | $ | (10 | )
|  |  |  | For the Years Ended December 31,
|  |  |  | 2018 |  | 2017 |  | 2016
|  | Income Statement Location |  | Gain (Loss)
Exelon |  | Operating Revenues |  | $ | 7 |  |  | $ | (6 | ) |  | $ | (10 | )
Exelon |  | Purchased Power and Fuel |  | (9 | ) |  | — |  |  | — |
Exelon |  | Interest Expense |  | (4 | ) |  | (3 | ) |  | — |
Total Exelon |  |  |  | $ | (6 | ) |  | $ | (9 | ) |  | $ | (10 | )
Fair Value Hedges (Interest Rate Risk) For derivative instruments that qualify and are designated as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in earnings immediately. Exelon had no fixed-to-floating swaps designated as fair value hedges as of December 31, 2018 and had $800 million notional amounts designated as fair value hedges as of December 31, 2017. Exelon and Generation include the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps as follows:
|  |  | Year Ended December 31,
| Income Statement Location |  | 2018 |  | 2017 |  | 2016 |  | 2018 |  | 2017 |  | 2016
| Loss on Swaps |  | Gain on Borrowings
Exelon | Interest expense |  | $ | (11 | ) |  | $ | (13 | ) |  | $ | (9 | ) |  | $ | 20 |  |  | $ | 28 |  |  | $ | 23 |
During the years ended December 31, 2018, 2017 and 2016, the impact on the results of operations due to ineffectiveness from fair value hedges were gains of $9 million, $15 million and $14 million, respectively. Cash Flow Hedges (Interest Rate Risk) For derivative instruments that qualify and are designated as cash flow hedges, the gain or loss on the effective portion of the derivative will be deferred in AOCI and reclassified into earnings when the underlying transaction occurs. Exelon and Generation have no floating-to-fixed swaps designated as cash flow hedges as of December 31, 2018, and had $636 million notional amounts designated as cash flow hedges as of December 31, 2017. The tables below provide the activity of OCI related to cash flow hedges for the years ended December 31, 2018 and 2017, containing information about the changes in the fair value of cash flow hedges and the reclassification from AOCI into results of operations. The amounts reclassified from AOCI, when combined with the impacts of the hedged transactions, result in the ultimate recognition of net revenues or expenses at the contractual price.
|  |  |  | Total Cash Flow Hedge AOCI Activity, Net of Income Tax |
|  |  |  | Generation |  | Exelon |
For the Year Ended December 31, 2018 |  | Income Statement Location |  | Total Cash Flow Hedges |  | Total Cash Flow Hedges |
AOCI derivative loss at December 31, 2017 |  |  |  | $ | (16 | ) |  | $ | (14 | ) |
Effective portion of changes in fair value |  |  |  | 11 |  |  | 11 |  |
Reclassifications from AOCI to net income |  | Interest expense |  | 1 |  |  | 1 |  |
AOCI derivative loss at December 31, 2018 |  |  |  | $ | (4 | ) |  | $ | (2 | ) |
|  |  |  | Total Cash Flow Hedge AOCI Activity, Net of Income Tax |
|  |  |  | Generation |  | Exelon |
For the Year Ended December 31, 2017 |  | Income Statement Location |  | Total Cash Flow Hedges |  | Total Cash Flow Hedges |
AOCI derivative loss at December 31, 2016 |  |  |  | $ | (19 | ) |  | $ | (17 | ) |
Effective portion of changes in fair value |  |  |  | (1 | ) |  | (1 | ) |
Reclassifications from AOCI to net income |  | Interest expense |  | 4 |  | (a) | 4 |  | (a)
AOCI derivative loss at December 31, 2017 |  |  |  | $ | (16 | ) |  | $ | (14 | ) |
__________
(a) | Amount is net of related income tax expense of $1 million for the year ended December 31, 2017.
During the years ended December 31, 2018, 2017 and 2016, the impact on the results of operations as a result of ineffectiveness from cash flow hedges was immaterial. The estimated amount of existing gains and losses that are reported in AOCI at the reporting date that are expected to be reclassified into earnings within the next twelve months is immaterial. Proprietary Trading (Interest Rate and Foreign Exchange Risk) Generation also executes derivative contracts for proprietary trading purposes to hedge risk associated with the interest rate and foreign exchange components of underlying commodity positions. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. For the years ended December 31, 2018, 2017 and 2016, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses).
|  | For the Years Ended December 31,
|  | 2018 |  | 2017 |  | 2016
Income Statement Location |  | Loss
Operating revenues |  | $ | — |  |  | $ | (1 | ) |  | $ | (1 | )
Credit Risk, Collateral and Contingent-Related Features (All Registrants) The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. For commodity derivatives, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis. The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2018. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below exclude credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX and Nodal commodity exchanges. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $43 million, $30 million, $24 million, $28 million, $7 million and $5 million as of December 31, 2018, respectively.
Rating as of December 31, 2018 | Total Exposure Before Credit Collateral |  | Credit Collateral (a) |  | Net Exposure |  | Number of Counterparties Greater than 10% of Net Exposure |  | Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade | $ | 795 |  |  | $ | — |  |  | $ | 795 |  |  | 1 |  |  | $ | 153 |
Non-investment grade | 133 |  |  | 45 |  |  | 88 |  |  | — |  |  | — |
No external ratings |  |  |  |  |  |  |  |  |
Internally rated — investment grade | 181 |  |  | 1 |  |  | 180 |  |  | — |  |  | — |
Internally rated — non-investment grade | 92 |  |  | 6 |  |  | 86 |  |  | — |  |  | — |
Total | $ | 1,201 |  |  | $ | 52 |  |  | $ | 1,149 |  |  | 1 |  |  | $ | 153 |
Net Credit Exposure by Type of Counterparty | December 31, 2018
Financial institutions | $ | 12 |
Investor-owned utilities, marketers, power producers | 737 |
Energy cooperatives and municipalities | 324 |
Other | 76 |
Total | $ | 1,149 |
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(a) | As of December 31, 2018, credit collateral held from counterparties where Generation had credit exposure included $17 million of cash and $35 million of letters of credit. The credit collateral does not include non-liquid collateral.
ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on daily, updated forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price on a given day, the suppliers are required to post collateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of December 31, 2018, ComEd’s net credit exposure to suppliers was immaterial. ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 4 — Regulatory Matters for additional information. PECO’s unsecured credit used by electric suppliers represents PECO’s net credit exposure. As of December 31, 2018, PECO had no material net credit exposure to electric suppliers. PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. As of December 31, 2018, PECO had no material credit exposure under its natural gas supply and asset management agreements with investment grade suppliers. BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 4 — Regulatory Matters for additional information. BGE’s full requirement wholesale electric power agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier, or its guarantor, to meet its credit requirements with a certain amount of unsecured credit. As of December 31, 2018, BGE had no material net credit exposure to suppliers. BGE’s regulated gas business is exposed to market-price risk. At December 31, 2018, BGE had credit exposure of $3 million related to off-system sales which is mitigated by parental guarantees, letters of credit, or right to offset clauses within other contracts with those third-party suppliers. Pepco’s, DPL's and ACE's power procurement contracts provide suppliers with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents Pepco’s, DPL's and ACE's net credit exposure. As of December 31, 2018, Pepco’s, DPL's and ACE's net credit exposures to suppliers were immaterial. Pepco is permitted to recover its costs of procuring energy through the MDPSC-approved and DCPSC-approved procurement tariffs. DPL is permitted to recover its costs of procuring energy through the MDPSC-approved and DPSC-approved procurement tariffs. ACE is permitted to recover its costs of procuring energy through the NJBPU-approved procurement tariffs. Pepco’s, DPL's and ACE's counterparty credit risks are mitigated by their ability to recover realized energy costs through customer rates. See Note 4 — Regulatory Matters for additional information. DPL’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the DPSC. DPL’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the GCR, which allows DPL to adjust rates annually to reflect realized natural gas prices. To the extent that the fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder. As of December 31, 2018, DPL's credit exposure under its natural gas supply and asset management agreements was immaterial. Collateral (All Registrants) As part of the normal course of business, Generation routinely enters into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below. The aggregate fair value of all derivative instruments with credit-risk related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:
| For the Years Ended December 31,
Credit-Risk Related Contingent Feature | 2018 |  | 2017
Gross fair value of derivative contracts containing this feature(a) | $ | (1,723 | ) |  | $ | (926 | )
Offsetting fair value of in-the-money contracts under master netting arrangements(b) | 1,105 |  |  | 577 |
Net fair value of derivative contracts containing this feature(c) | $ | (618 | ) |  | $ | (349 | )
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(a) | Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting agreements.
(b) | Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.
(c) | Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.
Generation had cash collateral posted of $418 million and letters of credit posted of $367 million, and cash collateral held of $47 million and letters of credit held of $44 million as of December 31, 2018 for external counterparties with derivative positions. Generation had cash collateral posted of $497 million and letters of credit posted of $293 million and cash collateral held of $35 million and letters of credit held of $33 million at December 31, 2017 for external counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e., to BB+ by S&P or Ba1 by Moody's), Generation would have been required to post additional collateral of $2.1 billion and $1.8 billion as of December 31, 2018 and 2017, respectively. These amounts represent the potential additional collateral required after giving consideration to offsetting derivative and non-derivative positions under master netting agreements. Generation’s and Exelon’s interest rate swaps contain provisions that, in the event of a merger, if Generation’s debt ratings were to materially weaken, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of December 31, 2018, Generation’s and Exelon's swaps were in an asset position with a fair value of $7 million and $3 million, respectively. See Note 24 — Segment Information for additional information regarding the letters of credit supporting the cash collateral. Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. Under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of December 31, 2018, ComEd held approximately $38 million in collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd's ZEC contracts, collateral postings are required to cover a percentage of the ZEC contract value. ComEd’s REC contracts require collateral postings that are either a fixed price per REC or a percentage of the REC contract value. As of December 31, 2018, ComEd held approximately $31 million in collateral from suppliers for REC and ZEC contract obligations. Under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of December 31, 2018, ComEd held approximately $19 million in collateral from suppliers for the long-term renewable energy contracts. If ComEd lost its investment grade credit rating as of December 31, 2018, it would have been required to post approximately $7 million of collateral to its counterparties. See Note 4 — Regulatory Matters for additional information. PECO’s natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of December 31, 2018, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of December 31, 2018, PECO could have been required to post approximately $39 million of collateral to its counterparties. PECO’s supplier master agreements that govern the terms of its DSP Program contracts do not contain provisions that would require PECO to post collateral. BGE’s natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon BGE’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of December 31, 2018, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of December 31, 2018, BGE could have been required to post approximately $69 million of collateral to its counterparties. DPL's natural gas procurement contracts contain provisions that could require DPL to post collateral. To the extent that the fair value of the natural gas derivative transaction in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The DPL obligations are standalone, without the guaranty of PHI. If DPL lost its investment grade credit rating as of December 31, 2018, DPL could have been required to post an additional amount of approximately $11 million of collateral to its natural gas counterparties. BGE's, Pepco's, DPL's and ACE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require BGE, Pepco, DPL or ACE to post collateral.

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- Definition The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts. + References Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Accounting Standards Codification -Topic 815 -URI http://asc.fasb.org/topic&trid=2229140 + Details
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