Reserves Evaluation Report and Discounted Cash Flows for the Tamar Lease

February 8, 2018 at 9:14 PM EST

Revised Reserves Evaluation Report and Discounted Cash Flows for the Tamar Lease

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

39,608

22,765

7,134

-

250,603

-

41,927

208,676

203,647

201,265

198,965

194,592

190,495

Dec 31, 2019.

489

10.65

310,982

60,039

41,260

22,751

5,648

-

263,805

-

45,720

218,086

202,695

195,666

189,033

176,840

165,903

Dec 31, 2020.

476

10.36

310,627

59,970

41,213

21,213

8,759

-

261,898

24,475

49,954

187,469

165,942

156,462

147,723

132,186

118,844

Dec 31, 2021.

474

10.33

309,694

59,790

41,089

21,684

23,795

-

245,514

72,466

38,252

134,796

113,636

104,652

96,561

82,648

71,210

Dec 31, 2022.

489

10.65

315,733

60,956

41,891

21,805

14,138

-

260,724

99,545

32,857

128,322

103,027

92,675

83,567

68,417

56,492

Dec 31, 2023.

489

10.65

317,785

61,352

42,163

21,805

14,598

-

262,193

118,384

29,923

113,886

87,082

76,511

67,423

52,800

41,780

Dec 31, 2024.

489

10.65

321,645

62,097

42,675

21,805

-

-

280,418

131,236

27,837

121,346

88,368

75,835

65,309

48,920

37,098

Dec 31, 2025.

489

10.65

325,199

62,783

43,147

21,805

-

-

283,757

132,798

28,368

122,591

85,024

71,268

59,981

42,976

31,232

Dec 31, 2026.

489

10.65

328,854

63,489

43,632

21,805

-

-

287,192

134,406

29,064

123,722

81,722

66,907

55,031

37,715

26,267

Dec 31, 2027.

489

10.65

333,177

64,323

44,205

21,805

-

-

291,253

136,306

31,049

123,898

77,941

62,328

50,099

32,842

21,920

Dec 31, 2028.

489

10.65

337,739

65,204

44,810

21,805

-

-

295,540

138,313

32,641

124,586

74,642

58,302

45,798

28,717

18,368

Dec 31, 2029.

489

10.65

343,517

66,320

45,577

21,805

-

-

300,969

140,854

33,449

126,666

72,274

55,140

42,330

25,388

15,562

Dec 31, 2030.

489

10.65

353,063

68,163

46,844

21,805

-

-

309,938

145,051

34,748

130,140

70,720

52,699

39,537

22,682

13,324

Dec 31, 2031.

489

10.65

360,059

69,513

47,772

21,805

-

-

316,512

148,128

35,979

132,406

68,525

49,876

36,568

20,067

11,297

Dec 31, 2032.

489

10.65

369,984

71,429

49,089

21,805

14,598

-

311,240

145,660

39,211

126,368

62,286

44,281

31,728

16,654

8,985

Dec 31, 2033.

489

10.65

377,676

72,914

50,109

21,805

20,438

-

312,628

146,310

40,652

125,666

58,991

40,962

28,683

14,401

7,446

Dec 31, 2034.

489

10.65

387,366

74,785

51,395

21,805

-

-

342,170

160,135

39,118

142,916

63,894

43,335

29,655

14,242

7,057

Dec 31, 2035.

489

10.65

396,734

76,594

52,638

21,805

-

-

350,973

164,255

40,196

146,522

62,386

41,329

27,640

12,697

6,029

Dec 31, 2036.

489

10.65

406,030

78,388

53,871

21,805

29,197

-

330,510

154,679

44,207

131,624

53,374

34,537

22,572

9,918

4,513

Dec 31, 2037.

489

10.65

412,629

79,662

54,747

21,805

983

5,847

359,077

168,048

38,975

152,053

58,723

37,113

23,705

9,963

4,345

Dec 31, 2038.

275

5.98

235,943

45,551

31,304

21,805

983

5,847

193,060

90,352

19,314

83,394

30,673

18,935

11,819

4,752

1,986

Dec 31, 2039.

164

3.58

144,093

27,819

19,118

21,805

983

5,847

106,756

49,962

9,288

47,506

16,641

10,034

6,121

2,354

943

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

968,157

480,903

141,254

17,541

6,216,730

2,501,363

762,729

2,952,639

1,902,213

1,590,112

1,359,848

1,051,771

861,096

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)

(14)

-

(14,598)

-

14,497

6,517

(1,520)

9,500

7,627

6,861

6,187

5,065

4,182

Dec 31, 2023.

-

-

(108)

(21)

(14)

-

(14,598)

-

14,497

7,919

(1,515)

8,092

6,188

5,437

4,791

3,752

2,969

Dec 31, 2024.

-

-

(110)

(21)

(15)

-

-

-

(103)

(48)

653

(708)

(515)

(442)

(381)

(285)

(216)

Dec 31, 2025.

-

-

(111)

(21)

(15)

-

-

-

(104)

(49)

653

(708)

(491)

(412)

(347)

(248)

(180)

Dec 31, 2026.

-

-

(112)

(22)

(15)

-

14,598

-

(14,704)

(6,881)

2,224

(10,046)

(6,636)

(5,433)

(4,469)

(3,063)

(2,133)

Dec 31, 2027.

-

-

(114)

(22)

(15)

-

14,598

-

(14,705)

(6,882)

1,887

(9,710)

(6,108)

(4,885)

(3,926)

(2,574)

(1,718)

Dec 31, 2028.

-

-

(115)

(22)

(15)

-

-

-

(108)

(51)

(22)

(36)

(22)

(17)

(13)

(8)

(5)

Dec 31, 2029.

-

-

(117)

(23)

(16)

-

-

-

(110)

(51)

(22)

(37)

(21)

(16)

(12)

(7)

(5)

Dec 31, 2030.

-

-

(120)

(23)

(16)

-

-

-

(113)

(53)

(22)

(38)

(21)

(15)

(12)

(7)

(4)

Dec 31, 2031.

-

-

(123)

(24)

(16)

-

-

-

(115)

(54)

(22)

(39)

(20)

(15)

(11)

(6)

(3)

Dec 31, 2032.

-

-

(126)

(24)

(17)

-

(14,598)

-

14,480

6,777

(1,594)

9,298

4,583

3,258

2,334

1,225

661

Dec 31, 2033.

-

-

(129)

(25)

(17)

-

-

-

(121)

(57)

129

(193)

(91)

(63)

(44)

(22)

(11)

Dec 31, 2034.

-

-

(132)

(25)

(18)

-

-

-

(124)

(58)

61

(127)

(57)

(39)

(26)

(13)

(6)

Dec 31, 2035.

-

-

(135)

(26)

(18)

-

14,598

-

(14,725)

(6,891)

1,632

(9,466)

(4,031)

(2,670)

(1,786)

(820)

(389)

Dec 31, 2036.

-

-

(138)

(27)

(18)

-

(29,197)

-

29,067

13,603

(3,291)

18,754

7,605

4,921

3,216

1,413

643

Dec 31, 2037.

-

-

(141)

(27)

(19)

-

(983)

(5,847)

6,699

3,135

3,035

528

204

129

82

35

15

Dec 31, 2038.

214

4.67

184,248

35,571

24,446

-

(983)

(5,847)

179,954

84,218

24,571

71,165

26,175

16,158

10,086

4,055

1,695

Dec 31, 2039.

325

7.07

284,555

54,937

37,754

-

(983)

(5,847)

274,204

128,327

35,903

109,973

38,523

23,228

14,169

5,449

2,182

Dec 31, 2040.

489

10.65

436,684

84,307

57,938

21,805

14,598

-

373,912

174,991

48,420

150,502

50,209

29,570

17,628

6,484

2,489

Dec 31, 2041.

489

10.65

444,859

85,885

59,023

21,805

14,598

-

381,594

178,586

49,049

153,959

48,917

28,139

16,394

5,768

2,122

Dec 31, 2042.

489

10.65

453,034

87,463

60,107

21,805

-

-

403,873

189,012

48,082

166,779

50,466

28,355

16,144

5,433

1,915

Dec 31, 2043.

407

8.87

384,066

74,148

50,957

21,805

-

-

339,069

158,685

40,152

140,233

40,413

22,179

12,341

3,972

1,342

Dec 31, 2044.

397

8.65

381,572

73,667