Reserves Evaluation Report and Discounted Cash Flows for the Tamar Lease

February 8, 2018 at 9:14 PM EST

Tel Aviv, February 7, 2018. Delek Group (TASE: DLEKG, US ADR: DGRLY) (“the Company”) announces that it hereby issues a revised assessment report of reserves and contingent resources and revised discounted cash flow projections for the Tamar Project, which includes the Tamar and Tamar South-West reservoirs (“Tamar SW”) in the area covered by the I/12 Tamar lease (“Tamar Project” and “Tamar Lease”, respectively), further to section 1.7.4 (i) of the Company's periodic report as at March 31, 2016, as revised and published on May 30, 2017 (Ref. No. 2017-01-033078) ("the Periodic Report"), to the immediate report dated July 2, 2017 (Ref. No. 2017-01-068763) and in light of the review of options for public offerings and/or transactions in the Company's securities, as set out below:

  1. Quantitative data

According to a report that Delek Drilling – Limited Partnership (the “Partnership”) received from Netherland, Sewell and Associates, Inc.  (“NSAI” or the “Reserves Evaluator”), which was prepared in accordance with the guidelines of the Petroleum Resources Management System (SPE-PRMS), as of December 31, 2017 (the “Reserves Report”), the natural gas and condensate reserves in the Tamar Project (which includes, as aforesaid, the Tamar and Tamar SW reservoirs), classified as on-production reserves, remain unchanged compared with the previous Reserves Report, as set out in the immediate report dated July 2, 2017  (the “Previous Reserves Report"), other than actual production, and all as set out below[1]:

Reserve category

Total (100%) of the oil asset (gross)

Total rate attributable to equity holders of the Company (net)[2]

Tamar Reservoir

Tamar SW Reservoir

Total (Tamar and Tamar SW Reservoirs)

Natural gas

BCF

Condensate (million barrels)

Natural gas

BCF

Condensate (million barrels)

Natural gas

BCF

Condensate

(million barrels)

Natural gas

BCF

Condensate

(million barrels)

1P Reserves

(Proved Reserves)

7,040.2

9.2

796.4

1.0

7,836.6

10.2

1,042.1

1.4

Probable Reserves

(Probable reserves)

3,018.0

3.9

203.5

0.3

3,221.5

4.2

428.4

0.5

Total 2P Reserves

(Proved+Probable Reserves)

10,058.2

13.1

999.9

1.3

11,058.1

14.4

1,470.5

1.9

Possible Reserves

(Possible Reserves)

1,851.7

2.4

217.6

0.3

2,069.2

2.7

275.2

0.4

Total 3P Reserves (Proved + Probable + Possible Reserves)

11,909.9

15.5

1,217.5

1.6

13,127.3

17.1

1,745.7

2.3

Warning: Possible reserves are the additional reserves that are not expected to be produced to the same extent as probable reserves. There is a 10% chance that actual volumes produced will be equivalent to or higher than the proved reserves, with the addition of the volume of the probable reserves and possible reserves.

  1. The NSAI report noted, inter alia, a number of assumptions and reservations, including: (a) The estimates, as is customary in the evaluation of reserves pursuant to the SPE-PRMS guidelines, are not adjusted to reflect the risks; (b) NSAI did not visit the oil field and did not check the mechanical operation of the facilities and wells or their state; (c) NSAI did not examine possible exposure arising from environmental issues. However, according to NSAI, as of the date of the Reserves Report, it is unaware of any possible environmental liability that could have a material effect on the volume of the estimated reserves in the Reserves Report, or whether they are commercial, therefore the Reserves Report does not include costs that may arise from such liability; (d) NSAI assumed that the reservoirs will be developed according to the existing development plans, that they will be operated reasonably, that no new regulation will be adopted that could affect the oil rights holders’ ability to produce the reserves and that forecasts for future production will be similar to the actual performance of the reservoirs. 

Forward-looking information: the NSAI estimates of the volume of reserves of natural gas and condensate in the Tamar and Tamar SW reservoirs are forward-looking information as defined in the Securities Law. These estimates are based, among other things, on geological, geophysical, engineering and other information received from the wells and from the Tamar Project Operator, and are NSAI estimates and assumptions only and there can be no certainty in respect thereof. The actual volumes of natural gas and/or condensate produced may be different from these estimates and assumptions, partly due to technical and operational conditions and/or regulatory changes and/or the supply and demand conditions in the natural gas and/or condensate market and/or commercial conditions and/or as a result of actual performance of the reservoirs. The foregoing estimates and assumptions may be updated if additional information becomes available and/or as the result of a range of factors related to oil and natural gas exploration and production, including due to the continued production from the Tamar Project.

  1. Discounted cash flows

With regard to the calculation of the discounted cash flows described below, the following is noted: (a) The discounted cash flow is based, among other things, on the weighted average gas prices in the gas sales agreements, which are based on various price formulae that include linkage to the US CPI, the Brent price per barrel, or the electricity generation price[3]. It is noted that price changes may arise, among other things, due to adjustment of prices based on a mechanism set in the Israel Electric Corp. Ltd. (“IEC”) contract[4], and changes in the linkage indices in the gas sales agreements. It is hereby clarified that, as of the publication of this report, it is not possible to estimate the extent of such price adjustment (if adjusted at all) on the first adjustment date (i.e. on July 1, 2021), as set out in the IEC contract, and it is assumed that an adjustment will be made at 50% of the maximum rate of adjustment, i.e. a price reduction of 12.5%. It is further noted that, with regard to discounted cash flows, it was assumed that there would be no price change on the second adjustment date (i.e. on July 1, 2024)  For further information regarding discounted cash flow changes resulting from price adjustments, including as a result of the foregoing change in price adjustment rate, see the sensitivity tables in this section below. It is clarified that these sensitivities were based on the assumption of the foregoing price reduction. It is further noted that we did not take into account any price change due to the motion for certification of a class action filed by an IEC consumer against the Tamar Project: Partners, as set out in section 1.7.38(b) of the Periodic Report and section I of the updated Chapter A (Description of Company’s Businesses), which was included in the Company’s periodic report as at September 30, 2017 published on November 29, 2017 (Ref. No. 2017-01-106212). It is noted that on December 8, 2017, the District Court accepted the motion filed by the Partnership, Noble Energy Mediterranean Ltd.  (" Noble” or the “Operator”), Isramco Negev 2 Limited Partnership and Dor Gas Exploration - Limited Partnership, to subpoena witnesses in the case on behalf of the State and dismissed the foregoing motion to admit additional evidence. As at the date of this report, the testimony of the Applicants’ expert witness has ended and the testimony of the Respondents’ expert witness began on February 5, 2018 and is expected to continue until February 8, 2018. Another two hearings have been set for March 2018, during which the other declarants will be heard. The Partnership’s legal counsel estimate that the chances of the motion for certification succeeding is less than 50%. As aforesaid, at the present time the parties are at the hearing stage of the motion for certification of a class action. If a final and absolute ruling is handed certifying the foregoing class action suit (i.e. if, following approval of the motion for certification of a class action, a final ruling is handed in a subsequent action class action suit), the Partnership’s businesses, as well as the prices at which it, together with the other Tamar partners, will sell natural gas to their customers, may be adversely affected, the extent of which depends on the results of the claim. The Partnership provided the information concerning the gas price to NSAI[5]; (b) Furthermore, the discounted cash flow calculation was based on the price of condensate arising from the Brent price and based on the Brent Crude index and was adjusted to the quality differences, transportation costs and the selling price of condensate in the region; (c) The operating costs that were taken into account are the costs that the Partnership provided to NSAI. These costs include only the direct costs relating to the Project, insurance expenses and the Partnership's estimate of the overheads, and general and administrative expenses which can be attributed directly to the Project. These costs are divided into expenses relating directly to the field and expenses per output unit. The operating costs that the Partnerships provided to NSAI, and which they believe are reasonable, are based, among other things, on the information provided and on NSAI's knowledge from similar projects. These costs have not been adjusted to inflation changes; (d) The capital expenses taken into account when preparing the discounted cash flow exceed the costs approved by the Partners, and it also includes estimated costs of future investments during production with the aim of maintaining and expanding production output. The capital expenses taken into account are the capital expenses that might be required for the maintenance of  production wells, for drilling new wells, and for additional production equipment. The capital expenses provided to NSAI by the Partnership, and which they believe are reasonable, are based, inter alia, on the Tamar Project development plan and on NSAI’s additional knowledge from similar projects, and have not been adjusted for inflation changes; (e)  The abandonment costs that were taken into account are costs that the Partnerships provided to NSAI, based on its assessment of the cost of abandoning wells, platforms and production facilities. These costs do not take into account salvage value of the Tamar Lease and Tamar Project facilities and are not adjusted to inflation changes; (f) The tax calculations take due corporate tax rates into account; (g) Actual production capacity for each of the reserve categories described above could be lower or higher than the production capacity used to estimate the discounted cash flows. Furthermore, NSAI did not conduct sensitivity analysis regarding the production capacity of the wells; (h) The discounted cash flows assumed projected sales volumes for each year of the project based on the production capacity from the reservoirs[6] and assessments regarding the scope of demand in the domestic market in each of the years of the project; (i) The discounted cash flow calculation takes into account revenues from gas exports to the local markets in Egypt and Jordan at total aggregate volumes of 24.6 BCM until 2040, inter alia, based on the export agreements set out in sections 1.7.13(e)(1) and (2) of the Periodic Report[7]; (j) The discounted cash flow calculation takes into account revenues relating to the MOU signed with Union Fenosa Gas SA  (“UFG”) as set out in section 1.7.13(e)(1)c  of the Periodic Report, and execution of the Tamar Expansion Project as stipulated in section 1.7.4(d)(3) of the Periodic Report. As at date of this Report, the Partnership is unable to estimate when such binding contract will be signed, if at all.It is noted that, as of the date of this Report, the Partnership is continuing negotiations with customers on the Egyptian market which, should they mature into binding gas sales agreements, the Partnership estimates could have a substantial impact on the discounted cash flow figures below; (k) The discounted cash flow calculation takes into account the Partnership's assessment regarding the actual rate of royalties to be paid by the Partnerships to the State, at a rate of 11.5%. As at date of issue of this Report, the Tamar partners are holding discussions with the Ministry of Energy regarding the method for calculating the actual rate of royalties payable to the State. Therefore, the actual rate of these royalties is not final and may change, and there is no certainty that the Partnership will succeed in its negotiations to fix a lower rate for royalties in the future. For further information regarding this matter and regarding the arrangements between the parties until the foregoing discussions are concluded, see section 1.7.37(2)(b) of the Periodic Report; (l) The discounted cash flow calculation took into account the oil profits levy applicable to the Partnership and the Company under the law. It is emphasized that calculation of the levy was based on the definitions, formulas and mechanisms set out in the law as these are understood and interpreted by the Company and the Partnership, however, since the law is new and the calculation formulae and mechanisms set out in the law are complex, it is not certain whether this interpretation of the calculation method for the levy will be the same as that adopted by the tax authorities and/or the same as the interpretations of the law by the court, insofar as a ruling is required on these issues. As at the publication date of this Report, these issues have not been discussed in the rulings handed by the courts in Israel. The levy was calculated according to the transitional provisions in the law for a project that started commercial production before the Law came into effect, and through to January 1, 2014, based on the following assumptions: The developer will choose to report in US dollars according to section 13(B) of the Law, all of the developer's payments (such as production costs, investments, and royalties) will be recognized by the tax authorities for calculation of the levy, and calculation of the developers revenues will take into account actual selling prices of the gas; (m) Calculation of the discounted cash flows included expenses and investments that were paid in practice and which are expected to be paid by the Partnerships as from January 1, 2018, as well as revenues from sales of natural gas and condensate produced as from January 1, 2018. It is clarified that revenues received in 2018 for sales of natural gas and condensate produced in 2017 were not included in the discounted cash flows.

It is noted that there has been a change in the discounted cash flow compared to the discounted cash flow as of June 30, 2017, for the following reasons:

  1. Since the closing of the transaction for the sale of of 9.25% the Partnership's participation rights (out of 100%) in the Tamar Lease to Tamar Petroleum Ltd.  (“Tamar Petroleum”) the Partnership’s direct holdings in the Tamar Lease has decreased from 31.25% to 22% and its indirect holdings in the Tamar Lease has increased due to its holding 40% of Tamar Petroleum shares, so that the Partnership’s total holdings in the Tamar Lease (direct and indirect) is 25.7%. The Company and its investees are entitled to overriding royalties from the Partnership and from Tamar Petroleum due to their share in the Tamar reservoir.
  2. In view of the updated projections for the Power Generation Tariff (primarily due to the update of the NIS to USD exchange rate forecast), the US-CPI and the Brent per barrel price, we have updated the relevant projected sales prices (for natural gas and condensate) that are linked to them.
  3. As of the publication of this report, it is not possible to estimate the extent of such price adjustment (if at all) on the first adjustment date (i.e. on July 1, 2021), as set out in the IEC contract, and it was assumed that an adjustment will be made at 50% of the maximum rate of adjustment, i.e. a price reduction of 12.5%, as well as the effect of such foregoing adjusted price on the Power Generation Tariff and the prices of natural gas in the relevant agreements.

Based on various assumptions, as described above, below is the estimated discounted cash flow as of December 31, 2017, in USD thousands (net of the levy and income tax) attributable to the Company's share (including by way of the Partnership’s holdings in Tamar Petroleum and the overriding royalties paid to the Company and its investees from Tamar Petroleum and the Partnership) in the Tamar Project Reserves, for each of the reserve categories set out above:

Total discounted cash flow from Proved Reserves at December 31, 2017 (in USD thousands, relating to the Company's share)

Cash flow items

Until

Quantity of condensate sales (thousands of barrels)

(100% of the oil asset)

Sales volume (BCM)

(100% of the oil asset)

Revenue

Royalties payable

Royalties receivable

Operating costs

Development costs

Abandonment and restoration costs

Total cash flow before levy and income tax (discounted at 0%)

Taxes

Total discounted cash flow after tax

Levy

Income tax

Discounted at -0%

Discounted at -5%

Discounted at -7.5%[8]

Discounted at -10%

Discounted at -15%

Discounted at -20%

Dec 31, 2018.

484

10.55

298,529

57,634

44,298

22,765

7,134

-

255,293

-

43,006

212,287

207,171

204,748

202,408

197,959

193,791

Dec 31, 2019.

489

10.65

310,982

60,039

46,146

22,751

5,648

-

268,690

-

46,843

221,847

206,191

199,041

192,294

179,890

168,765

Dec 31, 2020.

476

10.36

310,627

59,970

46,093

21,213

8,759

-

266,778

24,931

50,971

190,876

168,957

159,305

150,407

134,588

121,003

Dec 31, 2021.

474

10.33

309,694

59,790

45,954

21,684

23,795

-

250,379

73,902

39,041

137,436

115,861

106,702

98,453

84,267

72,605

Dec 31, 2022.

489

10.65

315,733

60,956

46,851

21,805

14,138

-

265,684

101,438

33,562

130,683

104,922

94,380

85,105

69,675

57,531

Dec 31, 2023.

489

10.65

317,785

61,352

47,155

21,805

14,598

-

267,185

120,638

30,552

115,994

88,694

77,927

68,672

53,777

42,554

Dec 31, 2024.

489

10.65

321,645

62,097

47,728

21,805

-

-

285,471

133,600

28,455

123,416

89,875

77,129

66,423

49,755

37,730

Dec 31, 2025.

489

10.65

325,199

62,783

48,255

21,805

-

-

288,865

135,189

28,993

124,684

86,475

72,485

61,005

43,710

31,765

Dec 31, 2026.

489

10.65

328,854

63,489

48,798

21,805

-

-

292,358

136,823

29,696

125,838

83,120

68,052

55,972

38,360

26,716

Dec 31, 2027.

489

10.65

333,177

64,323

49,439

21,805

-

-

296,487

138,756

31,689

126,042

79,290

63,407

50,966

33,411

22,299

Dec 31, 2028.

489

10.65

337,739

65,204

50,116

21,805

-

-

300,845

140,796

33,291

126,759

75,944

59,319

46,597

29,218

18,689

Dec 31, 2029.

489

10.65

343,517

66,320

50,973

21,805

-

-

306,365

143,379

34,110

128,877

73,536

56,102

43,068

25,832

15,834

Dec 31, 2030.

489

10.65

353,063

68,163

52,390

21,805

-

-

315,485

147,647

35,426

132,412

71,955

53,619

40,227

23,078

13,557

Dec 31, 2031.

489

10.65

360,059

69,513

53,428

21,805

-

-

322,169

150,775

36,671

134,723

69,725

50,749

37,208

20,418

11,495

Dec 31, 2032.

489

10.65

369,984

71,429

54,901

21,805

14,598

-

317,052

148,380

39,922

128,749

63,460

45,115

32,326

16,968

9,154

Dec 31, 2033.

489

10.65

377,676

72,914

56,042

21,805

20,438

-

318,561

149,086

41,378

128,096

60,132

41,755

29,238

14,680

7,590

Dec 31, 2034.

489

10.65

387,366

74,785

57,480

21,805

-

-

348,255

162,983

39,863

145,409

65,008

44,091

30,172

14,490

7,180

Dec 31, 2035.

489

10.65

396,734

76,594

58,870

21,805

-

-

357,205

167,172

40,958

149,075

63,473

42,049

28,121

12,918

6,134

Dec 31, 2036.

489

10.65

406,030

78,388

60,249

21,805

29,197

-

336,888

157,664

44,988

134,237

54,434

35,222

23,020

10,115

4,603

Dec 31, 2037.

489

10.65

412,629

79,662

61,229

21,805

983

5,847

365,559

171,081

39,768

154,709

59,748

37,762

24,119

10,137

4,421

Dec 31, 2038.

275

5.98

235,943

45,551

35,011

21,805

983

5,847

196,767

92,087

19,767

84,913

31,231

19,280

12,034

4,838

2,022

Dec 31, 2039.

164

3.58

144,093

27,819

21,382

21,805

983

5,847

109,020

51,021

9,565

48,434

16,966

10,230

6,240

2,400

961

Dec 31, 2040.

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Dec 31, 2041.

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Dec 31, 2042.

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Dec 31, 2043.

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Dec 31, 2044.

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Dec 31, 2045.

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Dec 31, 2046.

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Dec 31, 2047.

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Dec 31, 2048.

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Dec 31, 2049.

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Dec 31, 2050.

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Dec 31, 2051.

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Dec 31, 2052.

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Dec 31, 2053.

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Dec 31, 2054.

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Dec 31, 2055.

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Total

10,186

222

7,297,058

1,408,775

1,082,788

480,903

141,254

17,541

6,331,361

2,547,348

778,515

3,005,496

1,936,168

1,618,469

1,384,075

1,070,484

876,399

Total discounted cash flow from Probable Reserves as of December 31, 2017 (in USD thousands for the Company's share)

Cash flow items

Until

Quantity of condensate sales (thousands of barrels)

(100% of the oil asset)

Sales volume (BCM)

(100% of the oil asset)

Revenue

Royalties payable

Royalties receivable

Operating costs

Development costs[9]

Abandonment and restoration costs

Total cash flow before levy and income tax (discounted at 0%)

Taxes

Total discounted cash flow after tax

Levy

Income tax

Discounted at -0%

Discounted at -5%

Discounted at -7.5%[10]

Discounted at -10%

Discounted at -15%

Discounted at -20%

Dec 31, 2018.

-

-

-

-

-

-

-

-

-

-

2

(2)

(2)

(2)

(2)

(2)

(2)

Dec 31, 2019.

-

-

-

-

-

-

-

-

-

-

2

(2)

(2)

(2)

(2)

(2)

(2)

Dec 31, 2020.

-

-

-

-

-

-

-

-

-

-

3

(2)

(2)

(2)

(2)

(1)

(1)

Dec 31, 2021.

-

-

-

-

-

-

-

-

-

(1)

3

(2)

(1)

(1)

(1)

(1)

(1)

Dec 31, 2022.

-

-

(108)

(21)

(16)

-

(14,598)

-

14,496

6,534

(1,524)

9,486

7,616

6,851

6,177

5,057

4,176

Dec 31, 2023.

-

-

(108)

(21)

(16)

-

(14,598)

-

14,495

7,943

(1,521)

8,073

6,173

5,423

4,779

3,743

2,962

Dec 31, 2024.

-

-

(110)

(21)

(16)

-

-

-

(105)

(49)

653

(708)

(516)

(443)

(381)

(286)

(217)

Dec 31, 2025.

-

-

(111)

(21)

(16)

-

-

-

(106)

(50)

653

(709)

(492)

(412)

(347)

(249)

(181)

Dec 31, 2026.

-

-

(112)

(22)

(17)

-

14,598

-

(14,705)

(6,882)

2,224

(10,047)

(6,636)

(5,433)

(4,469)

(3,063)

(2,133)

Dec 31, 2027.

-

-

(114)

(22)

(17)

-

14,598

-

(14,707)

(6,883)

1,887

(9,711)

(6,109)

(4,885)

(3,927)

(2,574)

(1,718)

Dec 31, 2028.

-

-

(115)

(22)

(17)

-

-

-

(110)

(51)

(22)

(37)

(22)

(17)

(13)

(8)

(5)

Dec 31, 2029.

-

-

(117)

(23)

(17)

-

-

-

(112)

(52)

(22)

(37)

(21)

(16)

(13)

(7)

(5)

Dec 31, 2030.

-

-

(120)

(23)

(18)

-

-

-

(115)

(54)

(22)

(39)

(21)

(16)

(12)

(7)

(4)

Dec 31, 2031.

-

-

(123)

(24)

(18)

-

-

-

(117)

(55)

(23)

(40)

(21)

(15)

(11)

(6)

(3)

Dec 31, 2032.

-

-

(126)

(24)

(19)

-

(14,598)

-

14,478

6,776

(1,594)

9,297

4,582

3,258

2,334

1,225

661

Dec 31, 2033.

-

-

(129)

(25)

(19)

-

-

-

(123)

(58)

129

(194)

(91)

(63)

(44)

(22)

(12)

Dec 31, 2034.

-

-

(132)

(25)

(20)

-

-

-

(126)

(59)

61

(128)

(57)

(39)

(27)

(13)

(6)

Dec 31, 2035.

-

-

(135)

(26)

(20)

-

14,598

-

(14,727)

(6,892)

1,632

(9,467)

(4,031)

(2,670)

(1,786)

(820)

(390)

Dec 31, 2036.

-

-

(138)

(27)

(21)

-

(29,197)

-

29,065

13,602

(3,291)

18,754

7,605

4,921

3,216

1,413

643

Dec 31, 2037.

-

-

(141)

(27)

(21)

-

(983)

(5,847)

6,697

3,134

3,035

527

204

129

82

35

15

Dec 31, 2038.

214

4.67

184,248

35,571

27,340

-

(983)

(5,847)

182,848

85,573

24,925

72,350

26,611

16,427

10,254

4,122

1,723

Dec 31, 2039.

325

7.07

284,555

54,937

42,224

-

(983)

(5,847)

278,674

130,419

36,450

111,804

39,164

23,614

14,405

5,539

2,219

Dec 31, 2040.

489

10.65

436,684

84,307

64,798

21,805

14,598

-

380,772

178,201

49,259

153,312

51,146

30,122

17,957

6,605

2,535

Dec 31, 2041.

489

10.65

444,859

85,885

66,011

21,805

14,598

-

388,582

181,856

49,904

156,822

49,826

28,662

16,699

5,875

2,161

Dec 31, 2042.

489

10.65

453,034

87,463

67,224

21,805

-

-

410,989

192,343

48,952

169,694

51,349

28,851

16,427

5,528

1,949

Dec 31, 2043.

407

8.87

384,066

74,148

56,990

21,805

-

-

345,103

161,508

40,890

142,704

41,125

22,569

12,558

4,042

1,366

Dec 31, 2044.

397

8.65

381,572

73,667

56,620

21,805

-

-

342,720

160,393

40,991

141,336

38,791

20,793

11,307

3,481

1,127

Dec 31, 2045.

361

7.86

353,158

68,181

52,404

21,805

-

-

315,576

147,689

37,670

130,216

34,038

17,821

9,470

2,789

865

Dec 31, 2046.

295

6.43

294,129

56,785

43,645

21,805

-

-

259,183

121,298

31,050

106,835

26,596

13,601

7,064

1,990

592

Dec 31, 2047.

226

4.91

228,909

44,193

33,967

21,805

-

-

196,877

92,139

23,427

81,312

19,278

9,630

4,887

1,317

375

Dec 31, 2048.

173

3.76

178,286

34,420

26,455

21,805

-

-

148,516

69,506

17,309

61,701

13,932

6,797

3,371

869

237

Dec 31, 2049.

158

3.45

166,650

32,174

24,729

21,805

983

5,847

130,569

61,106

15,340

54,123

11,639

5,546

2,689

663

173

Dec 31, 2050.

97

2.12

104,411

20,158

15,493

21,805

983

5,847

71,110

33,279

8,064

29,766

6,096

2,838

1,344

317

79

Dec 31, 2051.

70

1.53

76,566

14,782

11,361

21,805

983

5,847

44,509

20,830

5,337

18,342

3,578

1,627

753

170

41

Dec 31, 2052.

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

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