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the impact of recent and future federal and state regulatory changes, including legislative and regulatory initiatives regarding deregulation and restructuring of the utility industry, environmental laws regulating emissions, discharges, and disposal to air, water, and land, and also changes in tax and other laws and regulations to which Southern Company and its subsidiaries are subject, as well as changes in application of existing laws and regulations;

•	current and future litigation, regulatory investigations, proceedings, or inquiries, including, without limitation, IRS and state tax audits;

•	the effects, extent, and timing of the entry of additional competition in the markets in which Southern Company's subsidiaries operate;

•

variations in demand for electricity and natural gas, including those relating to weather, the general economy and recovery from the last recession, population and business growth (and declines), the effects of energy conservation and efficiency measures, including from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies, and any potential economic impacts resulting from federal fiscal decisions;

•	available sources and costs of natural gas and other fuels;

•	limits on pipeline capacity;

•	effects of inflation;

•

the ability to control costs and avoid cost overruns during the development and construction of facilities, which include the development and construction of generating facilities with designs that have not been finalized or previously constructed, including changes in labor costs and productivity, adverse weather conditions, shortages and inconsistent quality of equipment, materials, and labor, sustaining nitrogen supply, contractor or supplier delay, non-performance under construction, operating, or other agreements, operational readiness, including specialized operator training and required site safety programs, unforeseen engineering or design problems, start-up activities (including major equipment failure and system integration), and/or operational performance (including additional costs to satisfy any operational parameters ultimately adopted by any PSC);

•	the ability to construct facilities in accordance with the requirements of permits and licenses, to satisfy any environmental performance standards and the requirements of tax credits and other incentives, and to integrate facilities into the Southern Company system upon completion of construction;

•	investment performance of Southern Company's employee and retiree benefit plans and the Southern Company system's nuclear decommissioning trust funds;

•	advances in technology;

•	state and federal rate regulations and the impact of pending and future rate cases and negotiations, including rate actions relating to fuel and other cost recovery mechanisms;

•	legal proceedings and regulatory approvals and actions related to Plant Vogtle Units 3 and 4, including Georgia PSC approvals and NRC actions;

•

actions related to cost recovery for the Kemper IGCC, including the ultimate impact of the 2015 decision of the Mississippi Supreme Court, the Mississippi PSC's December 2015 rate order, and related legal or regulatory proceedings, Mississippi PSC review of the prudence of Kemper IGCC costs and approval of further permanent rate recovery plans, actions relating to proposed securitization, satisfaction of requirements to utilize grants, and the ultimate impact of the termination of the proposed sale of an interest in the Kemper IGCC to SMEPA;

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•	the ability to successfully operate the electric utilities' generating, transmission, and distribution facilities and Southern Company Gas' natural gas distribution and storage facilities and the successful performance of necessary corporate functions;

•	the inherent risks involved in operating and constructing nuclear generating facilities, including environmental, health, regulatory, natural disaster, terrorism, and financial risks;

•	the inherent risks involved in transporting and storing natural gas;

•	the performance of projects undertaken by the non-utility businesses and the success of efforts to invest in and develop new opportunities;

•	internal restructuring or other restructuring options that may be pursued;

•	potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to Southern Company or its subsidiaries;

•

the possibility that the anticipated benefits from the Merger cannot be fully realized or may take longer to realize than expected, the possibility that costs related to the integration of Southern Company and Southern Company Gas will be greater than expected, the ability to retain and hire key personnel and maintain relationships with customers, suppliers, or other business partners, and the diversion of management time on integration-related issues;

•	the ability of counterparties of Southern Company and its subsidiaries to make payments as and when due and to perform as required;

•	the ability to obtain new short- and long-term contracts with wholesale customers;

•	the direct or indirect effect on the Southern Company system's business resulting from cyber intrusion or terrorist incidents and the threat of terrorist incidents;

•	interest rate fluctuations and financial market conditions and the results of financing efforts;

•	changes in Southern Company's and any of its subsidiaries' credit ratings, including impacts on interest rates, access to capital markets, and collateral requirements;

•	the impacts of any sovereign financial issues, including impacts on interest rates, access to capital markets, impacts on currency exchange rates, counterparty performance, and the economy in general, as well as potential impacts on the benefits of the DOE loan guarantees;

•	the ability of Southern Company's electric utilities to obtain additional generating capacity (or sell excess generating capacity) at competitive prices;

•	catastrophic events such as fires, earthquakes, explosions, floods, hurricanes and other storms, droughts, pandemic health events such as influenzas, or other similar occurrences;

•	the direct or indirect effects on the Southern Company system's business resulting from incidents affecting the U.S. electric grid, natural gas pipeline infrastructure, or operation of generating or storage resources;

•	the effect of accounting pronouncements issued periodically by standard-setting bodies; and

•	other factors discussed elsewhere herein and in other reports (including the Form 10-K) filed by the registrants from time to time with the SEC.

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(*)	Average cost of purchased power includes fuel purchased by the Southern Company system for tolling agreements where power is generated by the provider.

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•	the creditworthiness of the counterparties involved and the impact of credit enhancements (such as cash deposits and letters of credit);

•	events specific to a given counterparty; and

•	the impact of Southern Company's nonperformance risk on its liabilities.

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(a)	Amounts are reflected based on final maturity dates. Variable rate interest obligations are estimated based on rates as of September 30, 2016.

(b)	Includes charges recoverable through a natural gas cost recovery mechanism or alternatively billed to marketers and demand charges associated with wholesale gas services.

(c)	Certain operating leases have provisions for step rent or escalation payments and certain lease concessions are accounted for by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms.

(d)	Represents fixed-fee minimum payments for asset management agreements at wholesale gas services.

(e)	Guarantees are provided to certain municipalities and other agencies and certain natural gas suppliers of SouthStar Energy Services, LLC (SouthStar) in support of payment obligations.

(f)	Includes derivative liabilities related to energy-related derivatives.

(g)	Estimated benefit payments for Southern Company Gas' retirement benefit plans are provided through 2018. No mandatory contributions to the plans are anticipated during this period.

(h)	Estimated capital expenditures are provided through 2021.

(i)	Primarily consists of contractual environmental remediation liabilities that are primarily recoverable through base rates or rate rider mechanisms.

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(a)	Represents the Southern Company parent entity.

(b)	Excludes credit agreements (Project Credit Facilities) assumed with the acquisition of certain solar facilities, which are non-recourse to Southern Power Company, the proceeds of which are being used to finance project costs related to such solar facilities currently under construction. See Note (I) to the Condensed Financial Statements under "Southern Power" herein for additional information.

(c)	Southern Company Gas guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.3 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700 million restricted for working capital needs of Nicor Gas.

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(*)	Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016.

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(a)	Includes reductions in capital lease obligations resulting from cash payments under capital leases.

(b)	Represents the Southern Company parent entity.

(c)	Reflects only long-term debt financing activities occurring subsequent to completion of the Merger. The senior notes were issued by Southern Company Gas Capital and guaranteed by Southern Company Gas.

(d)	Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements.

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•	$0.5 billion of 1.55% Senior Notes due July 1, 2018;

•	$1.0 billion of 1.85% Senior Notes due July 1, 2019;

•	$1.5 billion of 2.35% Senior Notes due July 1, 2021;

•	$1.25 billion of 2.95% Senior Notes due July 1, 2023;

•	$1.75 billion of 3.25% Senior Notes due July 1, 2026;

•	$0.5 billion of 4.25% Senior Notes due July 1, 2036; and

•	$2.0 billion of 4.40% Senior Notes due July 1, 2046.

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(a)	Evaluation of disclosure controls and procedures.

(b)	Changes in internal controls over financial reporting.

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(a)	KWHs generated by hydro are excluded from the average cost of fuel, generated.

(b)	Average cost of purchased power includes fuel, energy, and transmission purchased by Alabama Power for tolling agreements where power is generated by the provider.

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(*)	Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016. No short-term debt was outstanding at September 30, 2016.

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(*)	Average cost of purchased power includes fuel purchased by Georgia Power for tolling agreements where power is generated by the provider.

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(*)	Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016.

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(*)	Average cost of purchased power includes fuel purchased by Gulf Power for tolling agreements where power is generated by the provider.

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(*)	Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016.

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(a)	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions.

(b)	Amounts in the Current Cost Estimate include certain estimated post-in-service costs which are expected to be subject to the cost cap.

(c)

The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (e) for additional information.

(d)

Mississippi Power's 2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC as described in "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order." The Current Cost Estimate also reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.

(e)

Non-capital Kemper IGCC-related costs incurred during construction were initially deferred as regulatory assets. Some of these costs are now included in rates and are being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at September 30, 2016. The wholesale portion of debt carrying costs, whether deferred or recognized through income, is not included in the Current Cost Estimate and the Actual Costs at September 30, 2016. See "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein for additional information.

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(*)	Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016.

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•	PPA capacity revenues decreased $19 million primarily due to the remarketing of generation capacity into the short-term markets as a result of PPA expirations.

•	PPA energy revenues increased $62 million primarily due to an increase in renewable energy sales from new solar and wind facilities.

•	Revenues not covered by PPAs increased $55 million primarily due to an increase in short-term sales to non-affiliates as a result of the remarketing of generation capacity from expired PPAs.

•	PPA capacity revenues decreased $25 million as a result of a $44 million decrease in non-affiliate capacity revenues primarily due to the remarketing of generation capacity into the short-term markets as a result of PPA expirations, partially offset by a $19 million increase in affiliate capacity revenues due to new PPAs.

•	PPA energy revenues increased $79 million primarily due to a $122 million increase in renewable energy sales arising from new solar and wind facilities, partially offset by a decrease of $43 million in fuel revenues related to natural gas facility PPAs.

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•	Revenues not covered by PPAs increased $46 million due to a $70 million increase in short-term sales to non-affiliates as a result of the remarketing of generation capacity from expired PPAs, partially offset by a $24 million decrease in power pool revenue primarily associated with a reduction in available uncovered capacity.

•	Fuel expense increased $36 million primarily due to a $27 million increase associated with the volume of KWHs generated and a $9 million increase associated with average cost of natural gas per KWH generated.

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•	Purchased power expense increased $11 million due to a $19 million increase associated with the volume of KWHs purchased, partially offset by a $4 million decrease in the average cost of purchased power and a $4 million decrease associated with a PPA expiration.

•	Fuel expense decreased $20 million primarily due to a $42 million decrease associated with the average cost of natural gas per KWH generated, partially offset by a $22 million increase associated with the volume of KWHs generated.

•	Purchased power expense increased $6 million due to a $48 million increase associated with the volume of KWHs purchased, largely offset by a $30 million decrease in the average cost of purchased power and a $12 million decrease associated with a PPA expiration.

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(a)	Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction.

(b)	The Mankato facility is a fully operational 375-MW natural gas-fired combined-cycle facility with an additional 345-MW expansion under development.

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•	51% ownership interest (through 100% ownership of the class A membership interests entitling Southern Power to 51% of all cash distributions and most of the federal tax benefits) in a 100-MW solar facility in Nevada covered with a 20-year PPA, which is expected to close in November 2016;

•	100% ownership interests in two wind facilities in Texas totaling 299 MWs, the majority of which is contracted under PPAs for the first 12 to 14 years of operation and are expected to close before the end of 2016; and

•	100% ownership interest in a 275-MW wind facility in Texas, the majority of which is contracted under a 12-year PPA and is expected to close in January 2017.

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(a)	On March 29, 2016, Southern Power acquired an additional 15% interest in Desert Stateline. As a result, Southern Power and the class B member are entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction.

(b)	The facility has a total of 299 MWs, of which 110 MWs were placed in service in the fourth quarter 2015 and 189 MWs were placed in service during the nine months ended September 30, 2016.

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(*)	Average and maximum amounts are based upon daily balances during the three-month period ended September 30, 2016. No short-term debt was outstanding at September 30, 2016.

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(*)	Subsequent to September 30, 2016, Roserock extended the maturity date of its Project Credit Facility to December 31, 2016.

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(A)	INTRODUCTION

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(B)	CONTINGENCIES AND REGULATORY MATTERS

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(a)	The 2010 Project Estimate is the certificated cost estimate adjusted to include the certificated estimate for the CO2 pipeline facilities approved in 2011 by the Mississippi PSC, as well as the lignite mine and equipment, AFUDC, and general exceptions.

(b)	Amounts in the Current Cost Estimate include certain estimated post-in-service costs which are expected to be subject to the cost cap.

(c)

The 2012 MPSC CPCN Order approved a construction cost cap of up to $2.88 billion, net of the Initial DOE Grants and excluding the Cost Cap Exceptions. The Current Cost Estimate and the Actual Costs include non-incremental operating and maintenance costs related to the combined cycle and associated common facilities placed in service in August 2014 that are subject to the $2.88 billion cost cap and exclude post-in-service costs for the lignite mine. See "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order" herein for additional information. The Current Cost Estimate and the Actual Costs reflect 100% of the costs of the Kemper IGCC. See note (e) for additional information.

(d)

Mississippi Power's 2010 Project Estimate included recovery of financing costs during construction rather than the accrual of AFUDC. This approach was not approved by the Mississippi PSC as described in "Rate Recovery of Kemper IGCC Costs – 2013 MPSC Rate Order." The Current Cost Estimate also reflects the impact of a settlement agreement with the wholesale customers for cost-based rates under FERC's jurisdiction. See "FERC Matters" herein for additional information.

(e)

Non-capital Kemper IGCC-related costs incurred during construction were initially deferred as regulatory assets. Some of these costs are now included in rates and are being recognized through income; however, such costs continue to be included in the Current Cost Estimate and the Actual Costs at September 30, 2016. The wholesale portion of debt carrying costs, whether deferred or recognized through income, is not included in the Current Cost Estimate and the Actual Costs at September 30, 2016. See "Rate Recovery of Kemper IGCC Costs – Regulatory Assets and Liabilities" herein for additional information.

(f)	On April 8, 2016, Mississippi Power received approximately $137 million in additional grants from the DOE for the Kemper IGCC (Additional DOE Grants), which are expected to be used to reduce future rate impacts for customers.

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(C)	FAIR VALUE MEASUREMENTS

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(a)	Excludes $7 million associated with certain weather derivatives accounted for based on intrinsic value rather than fair value.

(b)	For additional detail, see the nuclear decommissioning trusts sections for Alabama Power and Georgia Power in this table.

(c)	Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies.

(d)	Includes the investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. As of September 30, 2016, approximately $42 million of the fair market value of Georgia Power's nuclear decommissioning trust funds' securities were on loan to creditors under the funds' managers' securities lending program.

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(D)	STOCKHOLDERS' EQUITY

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(*)	Primarily related to Southern Power Company and excludes redeemable noncontrolling interests. See Note 10 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

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(E)	FINANCING

(a)	Represents the Southern Company parent entity.

(b)	Excluding its subsidiaries. See "Southern Power Project Credit Facilities" below and Note (I) under "Southern Power" for additional information.

(c)	Southern Company Gas guarantees the obligations of Southern Company Gas Capital, which is the borrower of $1.3 billion of these arrangements. Southern Company Gas' committed credit arrangements also include $700 million restricted for working capital needs of Nicor Gas.

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(*)	Subsequent to September 30, 2016, Roserock extended the maturity date of its Project Credit Facility to December 31, 2016.

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(a)	Includes reductions in capital lease obligations resulting from cash payments under capital leases.

(b)	Represents the Southern Company parent entity.

(c)	Reflects only long-term debt financing activities occurring subsequent to completion of the Merger. The senior notes were issued by Southern Company Gas Capital and guaranteed by Southern Company Gas.

(d)	Intercompany loans from Southern Company to Mississippi Power eliminated in Southern Company's Consolidated Financial Statements.

•	$0.5 billion of 1.55% Senior Notes due July 1, 2018;

•	$1.0 billion of 1.85% Senior Notes due July 1, 2019;

•	$1.5 billion of 2.35% Senior Notes due July 1, 2021;

•	$1.25 billion of 2.95% Senior Notes due July 1, 2023;

•	$1.75 billion of 3.25% Senior Notes due July 1, 2026;

•	$0.5 billion of 4.25% Senior Notes due July 1, 2036; and

•	$2.0 billion of 4.40% Senior Notes due July 1, 2046.

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(F)	RETIREMENT BENEFITS

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(G)	INCOME TAXES

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(H)	DERIVATIVES

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Regulatory Hedges — Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the traditional electric operating companies' and Southern Company Gas' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in fuel expense as the underlying fuel is used in operations and ultimately recovered through the respective fuel cost recovery clauses.

•	Cash Flow Hedges — Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.

•	Not Designated — Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income as incurred.

(*)	Southern Company Gas' derivative instruments are comprised of both long and short natural gas positions. A long position is a contract to purchase natural gas and a short position is a contract to sell natural gas. Southern Company Gas' volume represents the net of long natural gas positions of 3.2 billion mmBtu and short natural gas positions of 2.9 billion mmBtu as of September 30, 2016.

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(a)	Represents the Southern Company parent entity.

(b)	Swaption at RE Tranquillity LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

(c)	Swaption at RE Roserock LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information. Subsequent to September 30, 2016, Roserock extended the maturity date of its swaption to December 31, 2016.

(d)	Swaption at RE Garland Holdings LLC. See Note 12 to the financial statements of Southern Company and Note 2 to the financial statements of Southern Power in Item 8 of the Form 10-K for additional information.

(e)	Amortizing notional amount.

(f)	Represents the mandatory settlement date. Settlement will be based on a 15-year amortizing swap.

(g)	Represents the mandatory settlement date. Settlement will be based on a 12-year amortizing swap.

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(*)	Includes any cash/financial collateral pledged or received.

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(*)	Georgia Power, Mississippi Power, and Southern Power include current liabilities related to derivatives in other current liabilities.

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(a)	As of December 31, 2015, none of the registrants offset fair value amounts for multiple derivative instruments executed with the same counterparty in the balance sheets; therefore, gross and net amounts of derivative assets and liabilities presented in the balance sheets are the same.

(b)	Includes gross amounts subject to netting terms that are not offset in the balance sheets and any cash/financial collateral pledged or received.

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(a)	Georgia Power includes other regulatory liabilities, current in other current liabilities.

(b)	Georgia Power includes other regulatory liabilities, deferred in other deferred credits and liabilities.

(*)	Georgia Power includes other regulatory liabilities, current in other current liabilities.

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(*)	The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.

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(*)	The reclassification from accumulated OCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.

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(I)	ACQUISITIONS

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(a)	In addition to the 20-year and 12-year PPAs, the facility has a 10-year contract with Allianz Risk Transfer (Bermuda) Ltd.

(b)	Southern Power owns 100% of the class A membership interests and a wholly-owned subsidiary of the seller owns 100% of the class B membership interests. Southern Power and the class B member are entitled to 51% and 49%, respectively, of all cash distributions from the project. In addition, Southern Power is entitled to substantially all of the federal tax benefits with respect to the transaction.

(c)	The Mankato facility is a fully operational 375-MW natural gas-fired combined-cycle facility with an additional 345-MW expansion under development.

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•	51% ownership interest (through 100% ownership of the class A membership interests entitling Southern Power to 51% of all cash distributions and most of the federal tax benefits) in a 100-MW solar facility in Nevada covered with a 20-year PPA, which is expected to close in November 2016;

•	100% ownership interests in two wind facilities in Texas totaling 299 MWs, the majority of which is contracted under PPAs for the first 12 to 14 years of operation and are expected to close before the end of 2016; and

•	100% ownership interest in a 275-MW wind facility in Texas, the majority of which is contracted under a 12-year PPA and is expected to close in January 2017.

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(a)	Affiliate PPA approved by the FERC.

(b)	On March 29, 2016, Southern Power acquired an additional 15% interest in Desert Stateline. As a result, Southern Power and the class B member are entitled to 66% and 34%, respectively, of all cash distributions from Desert Stateline. In addition, Southern Power will continue to be entitled to substantially all of the federal tax benefits with respect to the transaction.

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(a)	Attributable to Southern Company.

(b)

Segment net income (loss) for the traditional electric operating companies includes pre-tax charges for estimated probable losses on the Kemper IGCC of $88 million ($54 million after tax) and $150 million ($93 million after tax) for the three months ended September 30, 2016 and 2015, respectively. See Note (B) under "Integrated Coal Gasification Combined Cycle – Kemper IGCC Schedule and Cost Estimate" for additional information.

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Transporting and storing natural gas involves risks that may result in accidents and other operating risks and costs. Southern Company Gas' natural gas distribution and storage activities involve a variety of inherent hazards and operating risks, such as leaks, accidents, explosions, and mechanical problems, which could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution, and impairment of its operations.

•	Southern Company Gas' natural gas business faces increasing competition. The natural gas business is highly competitive and increasingly complex. Southern Company Gas is facing increasing competition from other companies that supply energy, including electric, oil, and propane providers and, in some cases, energy marketing and trading companies.

•

Southern Company Gas may experience reported net income volatility due to mark-to-market accounting. Southern Company Gas utilizes hedging instruments to lock in economic value in its wholesale natural gas segment, which are not designated as hedges for accounting purposes. The difference in accounting treatment for the underlying position and the financial instrument used to hedge the value of the contract can cause volatility in reported net income while the positions are open due to mark-to-market accounting.

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