THE AES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued) DECEMBER 31, 2017, 2016, AND 2015 145 On December 8, 2017, the Board of Directors declared a quarterly common stock dividend of $0.13 per share payable on February 15, 2018 to shareholders of record at the close of business on February 1, 2018.
Stock Repurchase Program — No shares were repurchased in 2017.
The cumulative repurchases from the commencement of the Program in July 2010 through December 31, 2017 totaled 154.3 million shares for a total cost of $1.9 billion, at an average price per share of $12.12 (including a nominal amount of commissions).
As of December 31, 2017, $246 million remained available for repurchase under the Program.
The common stock repurchased has been classified as treasury stock and accounted for using the cost method.
A total of 155,924,785 and 156,878,891 shares were held as treasury stock at December 31, 2017 and 2016, respectively.
Restricted stock units under the Company's employee benefit plans are issued from treasury stock.
The Company has not retired any common stock repurchased since it began the Program in July 2010.15.
SEGMENTS AND GEOGRAPHIC INFORMATION The segment reporting structure uses the Company's organizational structure as its foundation to reflect how the Company manages the businesses internally and is organized by geographic regions which provides a sociopolitical-economic understanding of our business.
During the third quarter of 2017, the Europe and Asia SBUs were merged in order to leverage scale and are now reported as part of the Eurasia SBU.
The management reporting structure is organized by five SBUs led by our President and Chief Executive Officer: US, Andes, Brazil, MCAC and Eurasia SBUs.
The Company determined that it has five operating and five reportable segments corresponding to its SBUs.
All prior period results have been retrospectively revised to reflect the new segment reporting structure.
In February 2018, we announced a reorganization as a part of our ongoing strategy to simplify our portfolio, optimize our cost structure, and reduce our carbon intensity.
The Company is currently evaluating the impact this reorganization will have on our segment reporting structure.
Corporate and Other — Corporate overhead costs which are not directly associated with the operations of our five reportable segments are included in "Corporate and Other. "
Also included are certain intercompany charges such as self-insurance premiums which are fully eliminated in consolidation.
The Company uses Adjusted PTC as its primary segment performance measure.
Adjusted PTC, a non-GAAP measure, is defined by the Company as pre-tax income from continuing operations attributable to The AES Corporation excluding gains or losses of the consolidated entity due to (a) unrealized gains or losses related to derivative transactions; (b) unrealized foreign currency gains or losses; (c) gains, losses and associated benefits and costs due to dispositions and acquisitions of business interests, including early plant closures; (d) losses due to impairments; (e) gains, losses and costs due to the early retirement of debt; and (f) costs directly associated with a major restructuring program, including, but not limited to, workforce reduction efforts, relocations, and office consolidation.
Adjusted PTC also includes net equity in earnings of affiliates on an after-tax basis adjusted for the same gains or losses excluded from consolidated entities.
The Company has concluded Adjusted PTC better reflects the underlying business performance of the Company and is the most relevant measure considered in the Company's internal evaluation of the financial performance of its segments.
Additionally, given its large number of businesses and complexity, the Company concluded that Adjusted PTC is a more transparent measure that better assists investors in determining which businesses have the greatest impact on the Company's results.
Revenue and Adjusted PTC are presented before inter-segment eliminations, which includes the effect of intercompany transactions with other segments except for interest, charges for certain management fees, and the write-off of intercompany balances, as applicable.
All intra-segment activity has been eliminated within the segment.
Inter-segment activity has been eliminated within the total consolidated results.
The following tables present financial information by segment for the periods indicated (in millions):
## Table 0 ##
Gas Operations Gas Facilities CECONY’s capitalized costs for utility plant, net of accumulated depreciation, for gas facilities, which are primarily distribution facilities, were $5,749 million and $5,196 million at December 31, 2016 and 2015, respectively.
Natural gas is delivered by pipeline to CECONY at various points in or near its service territory and is distributed to customers by the company through an estimated 4,375 miles of mains and 370,924 service lines.
The company owns a natural gas liquefaction facility and storage tank at its Astoria property in Queens, New York.
The plant can store 1,062 MDt of which a maximum of about 240 MDt can be withdrawn per day.
The company has about 1,226 MDt of additional natural gas storage capacity at a field in upstate New York, owned and operated by Honeoye Storage Corporation, a corporation 28.8 percent owned by CECONY and 71.2 percent owned by Con Edison Development.
Gas Sales and Deliveries The company generally recovers the cost of the gas that it buys and then sells to its full-service customers.
It does not make any margin or profit on the gas it sells.
CECONY’s gas revenues are subject to a weather normalization clause and a revenue decoupling mechanism.
As a result, its gas delivery revenues are generally not affected by changes in delivery volumes from levels assumed when rates were approved.
CECONY’s gas sales and deliveries for the last five years were:
## Table 1 ##
(a) Includes 563, 5,362, 6,057, 1,229 and 4,708 MDt for 2012, 2013, 2014, 2015 and 2016, respectively, which are also reflected in firm transportation and other.
For further discussion of the company’s gas operating revenues and its gas results, see “Results of Operations” in Item 7.
For additional segment information, see Note N to the financial statements in Item 8
floating-rate notes to fixed-rates.
This includes notional amounts of offsetting swaps that neutralize our exposure to interest rates on other interest rate swaps.
FOREIGN EXCHANGE RISK Foreign currency fluctuations affect our net investments in foreign subsidiaries and foreign currency cash flows related to third party purchases, intercompany loans, and product shipments.
We are also exposed to the translation of foreign currency earnings to the U. S.  dollar.
Our principal exposures are to the Australian dollar, British pound sterling, Canadian dollar, Chinese renminbi, euro, Japanese yen, and Mexican peso.
We mainly use foreign currency forward contracts to selectively hedge our foreign currency cash flow exposures.
We generally do not hedge more than 12 months forward and generally do not hedge intercompany transactions.
We also have many net investments in foreign subsidiaries that are denominated in euros.
We hedge a portion of these net investments by issuing euro-denominated commercial paper.
As of May 25, 2008, we had issued $472.9 million of eurodenominated commercial paper and foreign exchange forward contracts that we have designated as a net investment hedge and thus deferred net foreign currency transaction losses of $69.6 million to accumulated other comprehensive income (loss).
COMMODITY PRICE RISK Many commodities we use in the production and distribution of our products are exposed to market price risks.
We utilize derivatives to hedge price risk for our principal ingredient and energy costs, including grains (oats, wheat, and corn), oils (principally soybean), non-fat dry milk, natural gas, and diesel fuel.
We manage our exposures through a combination of purchase orders, long-term contracts with suppliers, exchangetraded futures and options, and over-the-counter options and swaps.
We offset our exposures based on current and projected market conditions, and generally seek to acquire the inputs at as close to our planned cost as possible.
As of May 25, 2008, the net notional value of commodity derivatives was $784.8 million, of which $524.8 million relates to agricultural positions and $260.0 million relates to energy positions.
These hedges relate to inputs that generally will be utilized within the next 12 months.
EQUITY INSTRUMENTS Equity price movements affect our compensation expense as certain investments owned by our employees related to our deferred compensation plan are revalued.
We use equity swaps to manage this market risk.
VALUE AT RISK The estimates in the table below are intended to measure the maximum potential fair value we could lose in one day from adverse changes in market interest rates, foreign exchange rates, commodity prices, and equity prices under normal market conditions.
A Monte Carlo value-at-risk (VAR) methodology was used to quantify the market risk for our exposures.
The models assumed normal market conditions and used a 95 percent confidence level.
The VAR calculation used historical interest rates, foreign exchange rates, and commodity and equity prices from the past year to estimate the potential volatility and correlation of these rates in the future.
The market data were drawn from the RiskMetricsTM data set.
The calculations are not intended to represent actual losses in fair value that we expect to incur.
Further, since the hedging instrument (the derivative) inversely correlates with the underlying exposure, we would expect that any loss or gain in the fair value of our derivatives would be generally offset by an increase or decrease in the fair value of the underlying exposures.
The positions included in the calculations were: debt; investments; interest rate swaps; foreign exchange forwards; commodity swaps, futures and options; and equity instruments.
The calculations do not include the underlying foreign exchange and commodities-related positions that are hedged by these market-risk-sensitive instruments.
The table below presents the estimated maximum potential VAR arising from a one-day loss in fair value for our interest rate, foreign currency, commodity, and equity market-risk-sensitive instruments outstanding as of May 25, 2008, and May 27, 2007, and the average fair value impact during the year ended May 25, 2008.
## Table 2 ##

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Total Revenue
Year Ended December 31,	2017	2016	2015
US SBU	$3,229	$3,429	$3,593
Andes SBU	2,710	2,506	2,489
Brazil SBU	542	450	962
MCAC SBU	2,448	2,172	2,353
Eurasia SBU	1,590	1,670	1,875
Corporate and Other	35	77	31
Eliminations	-24	-23	-43
Total Revenue	$10,530	$10,281	$11,260

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Year Ended December 31,
2012	2013	2014	2015	2016
Gas Delivered(MDt)
Firm Sales
Full service	57,595	67,007	75,630	77,197	75,892
Firm transportation of customer-owned gas	52,860	61,139	68,731	72,864	68,442
Total Firm Sales	110,455	128,146	144,361	150,061	144,334
Interruptible Sales (a)	5,961	10,900	10,498	6,332	8,957
Total Gas Delivered to CECONY Customers	116,416	139,046	154,859	156,393	153,291
Transportation of customer-owned gas
NYPA	48,107	48,682	47,548	44,038	43,101
Other (mainly generating plants and interruptible transportation)	108,086	87,379	105,012	104,857	109,000
Off-System Sales	730	4,638	15	389	—
Total Sales	273,339	279,745	307,434	305,677	305,392
Gas Delivered($ in millions)
Firm Sales
Full service	$889	$1,059	$1,141	$956	$933
Firm transportation of customer-owned gas	380	414	453	458	426
Total Firm Sales	1,269	1,473	1,594	1,414	1,359
Interruptible Sales	39	69	91	46	34
Total Gas Delivered to CECONY Customers	1,308	1,542	1,685	1,460	1,393
Transportation of customer-owned gas
NYPA	2	2	2	2	2
Other (mainly generating plants and interruptible transportation)	68	71	70	54	57
Off-System Sales	5	18	—	1	—
Other operating revenues (mainly regulatory amortizations)	32	-17	-36	11	56
Total Sales	$1,415	$1,616	$1,721	$1,528	$1,508
Average Revenue per Dt Sold
Residential	$18.14	$18.52	$16.76	$13.91	$13.96
General	$11.68	$12.05	$12.38	$9.73	$9.47

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Fair Value Impact
In Millions	May 25, 2008	Average During Fiscal 2008	May 27, 2007
Interest rate instruments	$18.9	$14.0	$10.1
Foreign currency instruments	5.0	4.1	3.5
Commodity instruments	6.3	4.7	4.0
Equity instruments	1.2	1.0	0.9

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Question: In the year with largest amount of Gas Delivered($ in millions), what's the sum of Firm sales for Gas Delivered($ in millions)? (in million)
Answer: 1594.0