DIAL-IN INFORMATION: , Access Code 13254# (If you have trouble connecting via phone, please call ) AGENDA

Transcription

1 TO: FROM: FMPA Executive Committee Jason Wolfe/Jim Arntz DATE: October 2, 217 RE: PLACE: ARP Executive Committee Telephonic Rate Workshop Monday, October 9, 217 at 2:PM Florida Municipal Power Agency, 8553 Commodity Circle, Orlando, FL 1 st Floor Conference Room, Orlando, Florida DIAL-IN INFORMATION: , Access Code 13254# (If you have trouble connecting via phone, please call ) Chairman Howard McKinnon, Presiding 1. Call to Order and Roll Call 2. Information Items: a. Natural Gas Markets Update b. Overview of September Loads c. Resource Update for September AGENDA d. Review of September ARP Rate Calculation 3. Member Comments 4. Adjournment The participants in the above referenced public meeting will conduct the public meeting by telephone, via a telephone conference hookup. There will be a speaker telephone made available for any interested person to attend this public meeting and be fully informed of the discussions taking place by telephone conference hookup at FMPA s headquarters, located at 8553 Commodity Circle, Orlando, Florida If anyone chooses to appeal any decision that may be made at this public meeting, such person will need a record of the proceedings and should accordingly ensure that a verbatim record of the proceedings is made, which includes the oral statements and evidence upon which such appeal is based. This public meeting may be continued to a date and time certain, which will be announced at the meeting. Any person requiring a special accommodation to participate in this public meeting because of a disability, should contact FMPA at (47) or 1-(888) , at least two (2) business days in advance to make appropriate arrangements. Any interested person may contact FMPA for more information on this public meeting by calling (85) or (877) or writing to: Open Government Law Compliance Coordinator, Florida Municipal Power Agency, Delta Way, Post Office Box 329, Tallahassee, Florida

2 September 217 Usage (Billed in October 217) Rate Calculation Highlights Natural Gas Prices (Page 2) Natural gas prices ended the month unchanged from the beginning of the month. The average natural gas cost for September was $3.3/MMbtu; which was approximately $.8/MMBtu (3%) above budget. The forward curve for natural gas decreased slightly for the next six months and increased slightly for the following months. Temperatures for the winter season are forecasted to be warmer than average in the primary gas burn regions of the country. Loads and Billing Determinants (Pages 3 4) The major impact on ARP loads during September was Hurricane Irma. All members saw some adverse impact on loads, with Keys Energy experiencing the most significant impact. Despite this, due to a combination of many Participants loads recovering quickly and warmer than normal temperatures, overall ARP load for the month ended up close to budget. The ARP peak for September was approximately 4% above budget and energy sales were approximately 1% below budget. For the fiscal year ended September 3, 217, demand NEL was about 2% above budget and energy NEL was about 1% above budget. Resources and Pool Transactions (Page 5) Key operational issues affecting rates were as follows: Natural Gas: Large combined cycle generation was 7% below budget due to pool sales being less than budgeted. Overall, natural gas fired resources accounted for 86% of total ARP generation. Coal: Stanton 1 and Stanton 2 generated 5% less than anticipated in the budget. Overall, coalfired generation accounted for 9% of ARP generation. The stack at Stanton 2 was damaged during Hurricane Irma, which forced the unit to start its fall outage early. Nuclear: St. Lucie Unit 1 was out 37 hours during Hurricane Irma and Unit 2 ran the entire month. Combined output from the units was about 4% below budget. Pool Transactions: FMPA was a net seller to the Pool for the month, however net Pool sales of 9 GWh were 22% less than the budget amount. Cash Position and Rate Calculation (Pages 6 8) With an estimated 67 days of cash, rates are set using a 43% confidence level for fuel pricing which calculates a demand rate of $17.62/kw month, an energy rate of $21.81/MWh, and a transmission rate of $2.82/kw month. Participant demand and energy rates for September ranged from $73.56/MWh to $51.9/MWh. The spread of $22.47/MWh was larger than normal due to a wider than normal spread in load factors, in part caused by the effects of Hurricane Irma. Key West ended with the highest rate for September due the impacts of Hurricane Irma on its load factor. Newberry had the lowest rate for September due to a storm during the hour of the ARP system peak. For Fiscal Year 217 in total, Participant demand and energy rates ranged from $77.32/MWh to $67.14/MWh, or a spread of $1.18/MWh. ARP Cost Variances Budget to Actual (through August 217) On a $/MWh basis, costs to Participants through August have averaged $76.44/MWh, which was approximately 6% below the YTD target of $81.28/MWh, and are projected to remain below budget for the total FY of 32

3 5. Natural Gas Price in 217 Budget Compared to Current September /2/216 Budget Contract Close 9/5/217 1/4/ Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec of 32

4 25, FMPA - ARP September 217 Daily and Hourly Loads Preliminary Information - Subject to Change - Does not Include CROD Load as of September 3th September 1, HE MW Budgeted Peak 11 MW Daily Loads September 217 Daily Loads September 216 1,4 1,2 2, 1, 8 MWH 15, 1, MW 5, 3 of 32

5 7, ARP Net Energy for Load Energy Budget & Actual 7,, 6, 6,, 5, 5,, MWH 4, 3, 4,, 3,, 2, 2,, 1, 1,, Oct 16 Nov 16 Dec 16 Jan 17 Feb 17 Mar 17 Apr 17 May 17 Jun 17 Jul 17 Aug 17 Sep 17 Monthly Budget MWH Monthly Actual MWH Cumulative Budget MWH Cumulative Actual MWH 1,4, ARP Net Energy for Load Coincident Peak Budget & Actual 14,, 1,2, 12,, 1,, 1,, KW 8, 6, 8,, 6,, 4, 4,, 2, 2,, Oct 16 Nov 16 Dec 16 Jan 17 Feb 17 Mar 17 Apr 17 May 17 Jun 17 Jul 17 Aug 17 Sep 17 Monthly Budget kw Monthly Actual kw Cumulative Budget kw Cumulative Actual kw 4 of 32

6 FMPA All-Requirements Project Resource Stack September 217 MWH Source Actual Budget Variance Contracts 1,47 1,47 Nuclear 24,726 25,92 (1,194) Coal 58,922 62,198 (3,276) Large Combined Cycle Units 497, ,493 (37,39) Small Combined Cycle Units 37,668 36,61 1,67 Peakers 4,77 1,845 2,925 Pool Purchase 1,97 1,97 Pool (Sale) (9,96) (115,42) 24,442 Off Line Auxiliaries (675) (8) 125 Share of KUA Transmission Losses (33) (1,61) 731 SEC Transformer Losses (591) (684) 93 Inadvertent (537) (537) Non Member Sales (4,388) (4,388) Transmission Losses (1,36) (14,4) 4,4 517, ,71 (1,714) 5 of 32

7 FMPA All Requirements Project Rate Calculation Summary Sep 217 Estimated Revenue Requirement Aug Sep Oct Nov Dec Actual Demand $ 19,764 $ 22,985 $ 21,77 $ 2,865 $ 21,645 Energy 15,849 13,285 13,85 11,348 12,724 Transmission KUA Transmission Others 2,278 2,51 1,982 1,616 1,716 Total Revenue Requirement $ 38,88 $ 38,527 $ 36,363 $ 34,48 $ 36,34 True up Balances Demand (Over) Under Collection $ (12,552) $ (15,234) $ (12,15) $ (8,627) $ (1,776) Energy - 6 Day Cash Difference (7,386) (8,561) (1,589) (7,792) (4,213) Transmission (Over) Under Collection $ (19,57) $ (23,194) $ (22,158) $ (16,84) $ (5,639) Billing Determinants Demand - Kw 1,21 1, Energy - MWh 599, , , , ,249 KUA Transmission - Kw Transmission Others - Kw Billed Rate Demand $ / Kw Month Note 1 Energy $ / MWh Transmission - Others $ / Kw Month Note 1 October base rates updated to 218 Budget 6 of 32

8 Rate All in Rate Load Factor Energy Demand Transmission Delivery CP W/O CP With Excluded Excluded BSH Sep % 55.79% CLW Sep % 6.51% FTP Sep % 62.56% GCS Sep % 62.86% HVA Sep % 7.92% JXB Sep % 64.62% KUA Sep % 63.3% KWS Sep % 47.4% LBG Sep % 62.77% NBY Sep % 83.37% OCL Sep % 64.22% STK Sep % 74.2% 7 of 32

9 Demand & Energy Rate ($/MWh) Fiscal 217 Current Month Year to Date Rolling 12 Month (September 217) (Weighted Average) (Weighted Average) KWS FTM BSH CLW FTP GCS LBG KUA OCL JXB HVA STK NBY Max Min Avg Range of 32

10 9 of 32

11 FMPA All Requirements Project September 217 Rate Calculation - FYE 218 Budget Rates and Rate Projection - Schedule B-1 Methodology - Four Month Spread of Rate/Cost & Liquidity Differences Line # Actual / Forecast Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep 1 Demand Rate 2 Member Capacity 2,388 2,434 2,388 2,342 2,388 2,532 2,497 2,497 2,497 2,497 2,497 2,497 2,497 2,497 2,497 2,497 2,497 2,497 2,394 2,394 2,394 2,394 2,394 2,394 2,394 2,394 2,394 2,394 2,394 2,394 3 Contract Capacity 1,47 1,377 1,377 1,375 1,375 1,387 1,52 1,44 1,44 1,44 1,44 1,44 1,44 1,44 1,44 1,44 1,44 1,44 1,618 1,422 1,422 1,422 1,422 1,842 1,422 1,422 1,422 1,422 1,422 1,422 4 ARP Owned Capacity 3,127 2,699 3,26 3,8 2,765 4,26 4,186 4,86 4,244 4,197 4,432 4,262 4,341 4,417 4,215 4,211 4,429 4,225 4,192 4,654 4,25 4,24 4,47 4,334 4,348 4,455 4,224 4,218 4,466 4,233 5 Debt 1,296 1,856 9,776 1,182 1,29 12,2 9,865 9,865 1,837 9,865 9,865 1,167 9,865 9,865 1,167 9,865 9,865 1,242 9,862 9,862 1,834 9,862 9,862 1,164 9,862 9,862 1,164 9,862 9,862 1,239 6 Direct Charges & Other 1,287 1,84 1,357 1,39 1,76 1,932 1,814 1,788 1,893 1,742 1,787 1,887 1,739 1,86 1,915 1,76 1,821 1,96 1,917 1,889 1,995 1,845 1,891 1,991 1,845 1,914 2,24 1,87 1,933 2,3 7 Gas Transportation 2,665 2,656 2,477 2,542 2,684 2,83 3,73 2,537 2,647 2,649 2,44 2,623 2,827 2,922 2,859 2,963 2,956 2,896 3,8 2,552 2,561 2,654 2,45 2,679 2,929 2,938 2,868 2,957 2,965 2,864 Fixed Costs Moved to Energy (1,168) (1,276) (1,637) (1,76) (1,272) (1,973) (1,735) (1,967) (1,757) (1,749) (1,817) (1,758) (1,799) (1,825) (1,762) (1,773) (1,847) (1,765) (1,783) (1,946) (1,86) (1,799) (1,877) (1,831) (1,849) (1,885) (1,812) (1,823) (1,98) (1,815) 8 Non-Rate Revenue (27) (536) (44) 621 (145) (129) (125) (119) (12) (19) (185) (185) (189) (192) (196) (198) (198) (196) (194) (183) (187) (187) (186) (186) (189) (192) (195) (196) (196) (196) 9 Total Demand Costs 19,975 2,5 18,558 2,465 19,764 22,985 21,77 2,865 21,645 2,415 2,387 2,897 2,685 2,894 21,99 2,729 2,927 21,29 21,86 2,644 21,463 2,395 2,381 21,387 2,762 2,98 21,89 2,74 2,938 21, Energy Rate 13 Member Capacity 14 Contract Capacity Direct Charges & Other Purchased Power (199) (193) Fuels 13,717 17,276 14,847 16,574 15,722 14,698 16,363 14,434 15,445 16,218 14,83 12,669 14,247 15,618 17,61 19,79 19,597 17,717 16,42 12,37 14,68 16,61 14,613 13,25 13,493 16,133 16,871 17,853 18,532 16,853 Fixed Costs Moved to Energy 1,168 1,276 1,637 1,76 1,272 1,973 1,735 1,967 1,757 1,749 1,817 1,758 1,799 1,825 1,762 1,773 1,847 1,765 1,783 1,946 1,86 1,799 1,877 1,831 1,849 1,885 1,812 1,823 1,98 1, Non-Rate Revenue (3,614) (4,681) (2,81) (1,985) (1,7) (3,697) (5,312) (5,249) (4,739) (5,135) (5,154) (2,293) (3,812) (3,684) (4,179) (3,926) (3,952) (4,364) (4,642) (2,657) (3,768) (5,139) (4,85) (2,77) (3,747) (4,633) (3,973) (3,286) (3,61) (4,366) 19 Total Energy Costs 11,313 14,164 14,697 16,718 15,849 13,285 13,85 11,348 12,724 13,2 11,675 12,467 12,436 14,163 15,54 17,232 18,19 15,571 13,961 11,826 13,14 13,479 11,862 13,332 12,275 13,723 15,84 16,768 17,235 14, Transmission Rate 22 Transmission 2,64 2,254 3,5 2,366 2,38 2,136 2,66 1,698 1,799 2,215 2,15 1,774 1,99 2,147 2,273 2,266 2,333 2,189 2,4 1,68 1,778 2,188 2,126 1,755 1,889 2,122 2,278 2,269 2,337 2, Transmission - KUA Non-Rate Revenue (11) (11) (11) (12) (12) (85) (84) (82) (83) (86) (86) (83) (83) (84) (85) (85) (85) (85) (84) (82) (83) (86) (86) (83) (83) (84) (85) (85) (85) (85) 25 Total Transmission 2,7 2,34 3,11 2,57 2,475 2,257 2,21 1,835 1,935 2,348 2,283 1,91 2,45 2,282 2,47 2,4 2,467 2,323 2,175 1,817 1,914 2,321 2,259 1,891 2,25 2,257 2,412 2,43 2,471 2, Total Costs 33,988 36,518 36,356 39,69 38,88 38,527 36,363 34,48 36,34 35,765 34,345 35,274 35,166 37,339 39,46 4,361 41,413 39,13 37,222 34,287 36,391 36,195 34,52 36,61 35,62 36,888 38,585 39,875 4,644 38, Day Cash Amount 7,56 72,874 76,46 77,778 76,615 74,89 7,411 7,352 72,69 7,11 69,619 7,44 72,55 76,385 79,47 81,774 8,516 76,325 71,59 7,678 72,586 7,697 71,112 71,672 71,95 75,473 78,46 8,519 78,895 76, Cash Balance 62,728 68,876 74,898 81,614 84,1 83,451 81, 78,144 76,282 75,188 73,844 72,898 72,364 72,394 73,273 74,746 76,63 77,79 77,36 75,782 74,563 74,49 73,156 72,696 72,474 72,365 73,49 74,355 76,14 76, Days Cash on Hand Rate Schedule Confidence Level 65% 58% 58% 58% 5% 43% Cash True - Up - Est 2,632 2, (454) (2,36) (2,451) (2,856) (1,862) (1,94) (1,344) (946) (534) ,473 1,884 1,16 (43) (1,578) (1,219) (514) (893) (46) (222) (19) 684 1,36 1, (237) 39 - To Actual 3,516 3,794 5,823 2,841 1,756 4 Cash Change Next Month 41 Cash Effect - Billing 6,148 6,22 6,716 2,387 (55) (2,451) (2,856) (1,862) (1,94) (1,344) (946) (534) ,473 1,884 1,16 (43) (1,578) (1,219) (514) (893) (46) (222) (19) 684 1,36 1, (237) Billing Determinants 44 Demand 1,7 1,138 1,143 1,18 1,21 1, , ,27 1,124 1,119 1,163 1, , ,31 1,128 1,124 1,168 1,78 45 Energy 436, ,66 52,28 583, , , , , , , , , ,55 467, ,2 562, ,86 515, ,95 378, , ,89 368,12 388,394 49,14 469, , , ,51 56, Transmission Others Transmission KUA Cost per Unit 49 Demand Energy Transmission Others Rate if Cash Effect to Energy 54 Demand Energy Transmission Others % Load Factor All in Rate % Load Factor All in Rate % Load Factor All in Rate Shaded Values are Actuals Under (Over) Collected Demand 153 (4,685) (9,91) (12,552) (15,234) (12,15) (8,627) (1,776) 3,75 1,15 (124) 3,993 4,898 2,587 (1,118) (4,148) (6,995) (6,76) (4,85) 1,14 5,71 2, ,29 5,972 3,413 (516) (3,755) (6,732) (6,627) Under (Over) Collected Transmission , (44) (114) (139) (98) (3) (53) (96) (14) ARP All in Rate Cost / MWh of 32

12 FMPA All Requirements Project August 217 Rate Calculation - FYE 218 Budget Rates and Rate Projection - Schedule B-1 Methodology - Four Month Spread of Rate/Cost & Liquidity Differences Line # Actual / Forecast Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep 1 Demand Rate 2 Member Capacity 2,388 2,434 2,388 2,342 2,532 2,532 2,497 2,497 2,497 2,497 2,497 2,497 2,497 2,497 2,497 2,497 2,497 2,497 2,394 2,394 2,394 2,394 2,394 2,394 2,394 2,394 2,394 2,394 2,394 2,394 3 Contract Capacity 1,47 1,377 1,377 1,375 1,387 1,387 1,52 1,44 1,44 1,44 1,44 1,44 1,44 1,44 1,44 1,44 1,44 1,44 1,618 1,422 1,422 1,422 1,422 1,842 1,422 1,422 1,422 1,422 1,422 1,422 4 ARP Owned Capacity 3,127 2,699 3,26 3,8 4,586 4,26 4,186 4,86 4,244 4,197 4,432 4,262 4,341 4,417 4,215 4,211 4,429 4,225 4,192 4,654 4,25 4,24 4,47 4,334 4,348 4,455 4,224 4,218 4,466 4,233 5 Debt 1,296 1,856 9,776 1,182 11,67 12,2 9,865 9,865 1,837 9,865 9,865 1,167 9,865 9,865 1,167 9,865 9,865 1,242 9,862 9,862 1,834 9,862 9,862 1,164 9,862 9,862 1,164 9,862 9,862 1,239 6 Direct Charges & Other 1,287 1,84 1,357 1,39 1,84 1,932 1,814 1,788 1,893 1,742 1,787 1,887 1,739 1,86 1,915 1,76 1,821 1,96 1,917 1,889 1,995 1,845 1,891 1,991 1,845 1,914 2,24 1,87 1,933 2,3 7 Gas Transportation 2,665 2,656 2,477 2,542 2,925 2,83 3,73 2,537 2,647 2,649 2,44 2,623 2,827 2,922 2,859 2,963 2,956 2,896 3,8 2,552 2,561 2,654 2,45 2,679 2,929 2,938 2,868 2,957 2,965 2,864 Fixed Costs Moved to Energy (1,168) (1,276) (1,637) (1,76) (2,71) (1,973) (1,735) (1,967) (1,757) (1,749) (1,817) (1,758) (1,799) (1,825) (1,762) (1,773) (1,847) (1,765) (1,783) (1,946) (1,86) (1,799) (1,877) (1,831) (1,849) (1,885) (1,812) (1,823) (1,98) (1,815) 8 Non-Rate Revenue (27) (536) (44) 621 (132) (129) (125) (119) (12) (19) (185) (185) (189) (192) (196) (198) (198) (196) (194) (183) (187) (187) (186) (186) (189) (192) (195) (196) (196) (196) 9 Total Demand Costs 19,975 2,5 18,558 2,465 22,737 22,985 21,77 2,865 21,645 2,415 2,387 2,897 2,685 2,894 21,99 2,729 2,927 21,29 21,86 2,644 21,463 2,395 2,381 21,387 2,762 2,98 21,89 2,74 2,938 21, Energy Rate 13 Member Capacity 14 Contract Capacity Direct Charges & Other Purchased Power (199) (193) Fuels 13,717 17,276 14,847 16,574 15,773 17,759 16,984 15,22 16,1 16,865 15,398 13,89 14,717 15,969 17,87 19,48 19,644 18,93 16,525 12,54 15,22 16,97 14,856 13,624 14,44 16,611 17,614 18,687 19,152 17,557 Fixed Costs Moved to Energy 1,168 1,276 1,637 1,76 2,71 1,973 1,735 1,967 1,757 1,749 1,817 1,758 1,799 1,825 1,762 1,773 1,847 1,765 1,783 1,946 1,86 1,799 1,877 1,831 1,849 1,885 1,812 1,823 1,98 1, Non-Rate Revenue (3,614) (4,681) (2,81) (1,985) (1,445) (4,81) (5,312) (5,249) (4,739) (5,135) (5,154) (2,293) (3,812) (3,684) (4,179) (3,926) (3,952) (4,364) (4,642) (2,657) (3,768) (5,139) (4,85) (2,77) (3,747) (4,633) (3,973) (3,286) (3,61) (4,366) 19 Total Energy Costs 11,313 14,164 14,697 16,718 16,819 15,232 13,78 12,137 13,382 13,651 12,245 12,893 12,98 14,517 15,738 17,562 18,66 15,949 14,67 12,25 13,358 13,84 12,16 13,719 12,842 14,22 15,829 17,68 17,857 15, Transmission Rate 22 Transmission 2,64 2,254 3,5 2,366 2,27 2,136 2,66 1,698 1,799 2,215 2,15 1,774 1,99 2,147 2,273 2,266 2,333 2,189 2,4 1,68 1,778 2,188 2,126 1,755 1,889 2,122 2,278 2,269 2,337 2, Transmission - KUA Non-Rate Revenue (11) (11) (11) (12) (85) (85) (84) (82) (83) (86) (86) (83) (83) (84) (85) (85) (85) (85) (84) (82) (83) (86) (86) (83) (83) (84) (85) (85) (85) (85) 25 Total Transmission 2,7 2,34 3,11 2,57 2,391 2,257 2,21 1,835 1,935 2,348 2,283 1,91 2,45 2,282 2,47 2,4 2,467 2,323 2,175 1,817 1,914 2,321 2,259 1,891 2,25 2,257 2,412 2,43 2,471 2, Total Costs 33,988 36,518 36,356 39,69 41,947 4,474 36,986 34,837 36,962 36,414 34,915 35,7 35,638 37,693 39,244 4,691 41,46 39,481 37,328 34,486 36,735 36,556 34,746 36,997 35,629 37,367 39,33 4,715 41,266 38, Day Cash Amount 7,56 72,874 76,46 81,637 82,421 77,46 71,823 71,799 73,376 71,329 7,615 71,338 73,331 76,937 79,935 82,151 8,941 76,89 71,814 71,221 73,291 71,32 71,743 72,626 72,996 76,697 8,45 81,981 8,224 77, Cash Balance 62,728 68,876 74,898 81,614 84,1 83,59 81,762 79,81 77,341 76,311 74,993 74,13 73,432 73,411 74,188 75,568 77,333 78,41 77,94 76,288 75,78 74,613 73,731 73,283 73,14 73,11 73,9 75,383 77,159 78, Days Cash on Hand Rate Schedule Confidence Level 65% 58% 58% 58% 5% Cash True - Up - Est 2,632 2, (454) (492) (1,747) (2,681) (1,74) (1,3) (1,318) (98) (581) (21) 777 1,38 1,765 1,77 (47) (1,652) (1,21) (465) (882) (448) (143) (3) 79 1,483 1, (268) 39 - To Actual 3,516 3,794 5,823 2,841 4 Cash Change Next Month 41 Cash Effect - Billing 6,148 6,22 6,716 2,387 (492) (1,747) (2,681) (1,74) (1,3) (1,318) (98) (581) (21) 777 1,38 1,765 1,77 (47) (1,652) (1,21) (465) (882) (448) (143) (3) 79 1,483 1, (268) Billing Determinants 44 Demand 1,7 1,138 1,143 1,18 1,21 1, , ,27 1,124 1,119 1,163 1, , ,31 1,128 1,124 1,168 1,78 45 Energy 436, ,66 52,28 583, ,999 52, , , , , , , ,55 467, ,2 562, ,86 515, ,95 378, , ,89 368,12 388,394 49,14 469, , , ,51 56, Transmission Others Transmission KUA Cost per Unit 49 Demand Energy Transmission Others Rate if Cash Effect to Energy 54 Demand Energy Transmission Others % Load Factor All in Rate % Load Factor All in Rate % Load Factor All in Rate Shaded Values are Actuals Under (Over) Collected Demand 153 (4,685) (9,91) (12,552) (12,265) (8,996) (6,45) (54) 5,56 1, ,559 5,344 2,93 (861) (3,957) (6,86) (6,666) (4,737) 1,68 5,743 2, ,37 5,986 3,423 (58) (3,749) (6,728) (6,624) Under (Over) Collected Transmission , (51) (119) (142) (11) (3) (53) (97) (14) ARP All in Rate Cost / MWh of 32

13 All in Rate 6% Load Factor at Various Confidence Levels $ per MWH % CL 5% CL 7% CL 8% CL 9% CL Apr 17 May Jun Jul Aug Sep Oct Nov Dec Jan 18 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan 19 Feb Mar Apr May Jun Jul Aug Sep 6% Load Factor Apr 17 May Jun Jul Aug Sep Oct Nov Dec Jan 18 Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan 19 Feb Mar Apr May Jun Jul Aug Sep 1.% % % % % % Load Factor 1.% % % % % % Load Factor 1.% % % % % of 32

14 9/2/217 9:49 AM Florida Municipal Power Agency All-Requirements Project Statement of Revenues, Expenses, & Changes in Fund Net Assets For the Eleven Months Ending Thursday, August 31, 217 Whole Thousands (US$) Actual YTD August Budget YTD August (Over)Under YTD Percent (Over) Under REVENUES Demand Revenues Demand - Members 226,22 254,99 28, % Customer Charge & Other (431) (176.89%) Interest Income 1, (1,145) (756.52%) Total Demand Revenue 228, ,34 27, % Energy Revenues Energy 143, ,735 (19,261) (15.44%) Sale of Physical Natural Gas 4,52 11, 6, % Sale of Interchange Energy 23,199 36,82 13, % Other (1) (.21%) Total Energy Revenue 172,61 172, % Transmission Revenues Transmission - Others 22,264 2,767 (1,497) (7.21%) - KUA 2,166 2, % Standby Transmission (123) (28.76%) Low Voltage Delivery % Seminole Transmission Agreement % Total Transmission Revenue 25,531 24,12 (1,519) (6.33%) TOTAL REVENUES 425, ,234 26, % Expenses Demand Cost Centers Capacity Purchsed from Participants 26,271 25,19 (1,81) (4.29%) Capacity Purchased from Others 15,597 15,355 (242) (1.57%) ARP Plant Fixed O&M 37,347 42,972 5, % Debt, Leases & R&R 114, , % Fixed Administrative &General 16,949 2,165 3, % Gas Transportation 28,887 36,78 7, % Variable O&M to Energy (1,77) (14,228) (3,521) 24.75% Total Demand Expense 228, ,488 12, % Energy Cost Centers Firm Energy Purchased from Others 1, (1,46) (15.76%) Variable Administrative & General % Non-Firm Energy Purchases % Fuels 148,71 169,9 21, % Non-Fuel Variable O&M 1,77 14,228 3, % Total Energy Expense 162,45 186,396 24, % Transmission Cost Centers Transmission - Others 23,564 21,757 (1,87) (8.3%) - KUA 2,166 2, % Total Transmission Expense 25,73 24,23 (1,77) (7.1%) TOTAL EXPENSES 416, ,97 35, % NET INCOME BEFORE FAS 71 9, (9,53) ( %) 13 of 32

15 Florida Municipal Power Agency All-Requirements Project 9/3/17 Reconciled General Ledger Balance Total Operations & Maintenance Fund O&M Account 88,451, LOC Balance (5,,.) Interest Rate Margin Balance. New Edge Cash Balance. JP Morgan Cash Balance. Capital Expense Transfer. Total Cash Available for Rate Setting 83,451, of 32

16 Collateral Posting Required & Lines of Credit All-Requirements Project Close of Business 9/29/217 Natural Gas Hedges and Interest Rate Swaps $ Market Value of Positions $ Margin / Posting Threshold $ Collateral Posting Required FGU / NewEdge (Storage Agreement) Gas Hedges - NewEdge Natural Gas Hedges - - JPMorgan Natural Gas Hedges (13,333) (1,,) - Interest Rate Swaps (24,611,72) (22,,) - Total Posting Required Required Collateral Postings: Funded with draws on Lines of Credit Funded with use of ARP O&M Cash & Investments Potential funding from ARP O&M Cash & Investments if notified Total Posting Funded (1) JPMorgan Line of Credit 75,, Wells Fargo Line of Credit 25,, $ Lines of Credit - Total 1,, JPMorgan Draw for Discount Pricing 5,, Draws for Collateral Posting Uses of Lines of Credit 5,, $ Lines of Credit - Available, net 95,, Benchmarks: Prompt month Natural Gas $ Price: 3.2 (1) Represents potential posting liability. However, not required to move funds until $1,, (per Swap) over threshold. 15 of 32

17 INTEREST RATE SWAPS Bond Swap Credit Credit Posting Counterparty Issue MTM Available Used Required Bank of America / Merrill Lynch #2 ARP 28C (5,227,998) (32,,) (5,227,998) Goldman Sachs ARP 28C (5,236,253) (16,,) (5,236,253) JP Chase #1 ARP 28C (32,29) (34,,) (32,29) JP Chase #2 (Bear Stearns Swaps) ARP 28C (1,637,99) ARP 28C (393,447) (6,,) (393,447) Morgan Stanley ARP 28C (5,113,62) (32,,) (5,113,62) UBS AG ARP 28C (1,87,82) (1,,) (1,87,82) Wells Fargo ARP 28C (5,162,662) (36,,) (5,162,662) (24,611,72) (22,,) (24,611,72) Benchmarks Prompt NG 9/29/217 November is Prompt Month /22/ /15/ /8/ /1/217 October is Prompt Month /25/ /18/ /11/ /4/217 September is Prompt Month /28/ /21/ /14/ /7/ /3/217 August is Prompt Month /23/ /16/ /9/ /2/ /26/217 July is Prompt Month /19/ /12/ /5/ /28/217 June is Prompt Month of 32

18 4.5 Daily FMPA Gas Price September FGT Zone 3 Daily Price City Gate Delivered Price Billed FGU Gas Cost 17 of 32

19 18 of 32

20 Member Usage Date September 217 Excluded Resources Number of days in month for Load Factor Calculation 3 Member Energy Demand Co-Incident Peak Time Load Factor Resource Energy Demand BSH 9/1/217 2,337,82 5,82 9/1/17 3: PM 55.79% CLW St. Lucie 1,319, 1,98 CLW 9/1/217 9,9,58 21,66 9/1/17 3: PM 63.64% FTP St. Lucie 9,229, 13,174 FTM 9/1/217 3,541,661 8,77 9/1/17 3: PM 56.49% GCS St. Lucie 1,67, 1,522 FTP 9/1/217 52,377,132 18,965 9/1/17 3: PM 66.76% JXB St. Lucie 4,442,59 6,35 GCS 9/1/217 9,724,872 2,651 9/1/17 3: PM 65.4% KUA St. Lucie 5,6, 8,148 HVA 9/1/217 2,11,976 4,134 9/1/17 3: PM 7.92% LBG St. Lucie 1,49,773 2,15 JXB 9/1/217 68,289,26 143,569 9/1/17 3: PM 66.6% STK St. Lucie 1,344, 1,919 KUA 9/1/ ,542,48 331,937 9/1/17 3: PM 63.83% NBY St. Lucie 111, KWS 9/1/217 47,471,338 14,165 9/1/17 3: PM 47.4% FTM St. Lucie 23, LBG 9/1/217 46,238,839 11,23 9/1/17 3: PM 63.46% NBY 9/1/217 3,388,94 5,619 9/1/17 3: PM 83.77% TOTAL 24,726, 35,486 OCL 9/1/ ,413, ,945 9/1/17 3: PM 64.22% STK 9/1/217 6,2,364 11,31 9/1/17 3: PM 78.7% Total Net Energy for Load (NEL) 521,537,653 1,157,352 Excluded Resources (24,726,) (35,486) Billing Determinants 496,811,653 1,121,866 Total Net Energy for Load (NEL) 521,537,653 Less CROD NEL (3,541,661) NEL per Resource Stack 517,995,992 mem monthly: mv 9 allrq schedule Original Budget NEL 528,711, 1,17, Over (Under) Budget (7,173,347) 5,352 Percent Over (Under) Budget -1.36% 4.55% 19 of 32

21 7 Bushnell September 217 1,4 6 1,2 5 1, Bushnell MW ARP MW Sep 1 Sep 3 Sep 5 Sep 7 Sep 9 Sep 11 Sep 13 Sep 15 Sep 17 Sep 19 Sep 21 Sep 23 Sep 25 Sep 27 Sep % Non Coincident Peak Load Factor 55.79% Coincident Peak Load Factor Bushnell BSH Peak ARP ARP Peak 2 of 32

22 25 Clewiston September 217 1,4 2 1,2 1, Clewiston MW ARP MW Sep 1 Sep 3 Sep 5 Sep 7 Sep 9 Sep 11 Sep 13 Sep 15 Sep 17 Sep 19 Sep 21 Sep 23 Sep 25 Sep 27 Sep % Non Coincident Peak Load Factor 63.64% Coincident Peak Load Factor Clewiston CLW Peak ARP ARP Peak 21 of 32

23 1 Fort Meade September 217 1, ,2 1, Fort Meade MW ARP MW Sep 1 Sep 3 Sep 5 Sep 7 Sep 9 Sep 11 Sep 13 Sep 15 Sep 17 Sep 19 Sep 21 Sep 23 Sep 25 Sep 27 Sep % Non Coincident Peak Load Factor 56.49% Coincident Peak Load Factor Fort Meade FTM Peak ARP ARP Peak 22 of 32

24 12 Fort Pierce September 217 1,4 1 1,2 8 1, Fort Pierce MW ARP MW Sep 1 Sep 3 Sep 5 Sep 7 Sep 9 Sep 11 Sep 13 Sep 15 Sep 17 Sep 19 Sep 21 Sep 23 Sep 25 Sep 27 Sep % Non Coincident Peak Load Factor 66.76% Coincident Peak Load Factor Fort Pierce FTP Peak ARP ARP Peak 23 of 32

25 25 Green Cove Springs September 217 1,4 2 1,2 1, Green Cove Springs MW ARP MW Sep 1 Sep 3 Sep 5 Sep 7 Sep 9 Sep 11 Sep 13 Sep 15 Sep 17 Sep 19 Sep 21 Sep 23 Sep 25 Sep 27 Sep % Non Coincident Peak Load Factor 65.4% Coincident Peak Load Factor Green Cove Springs GCS Peak ARP ARP Peak 24 of 32

26 6 Havana September 217 1,4 5 1,2 4 1, Havana MW ARP MW Sep 1 Sep 3 Sep 5 Sep 7 Sep 9 Sep 11 Sep 13 Sep 15 Sep 17 Sep 19 Sep 21 Sep 23 Sep 25 Sep 27 Sep % Non Coincident Peak Load Factor 7.92% Coincident Peak Load Factor Havana HVA Peak ARP ARP Peak 25 of 32

27 16 Beaches Energy September 217 1,4 14 1,2 12 1, Beaches Energy MW ARP MW Sep 1 Sep 3 Sep 5 Sep 7 Sep 9 Sep 11 Sep 13 Sep 15 Sep 17 Sep 19 Sep 21 Sep 23 Sep 25 Sep 27 Sep % Non Coincident Peak Load Factor 66.6% Coincident Peak Load Factor Beaches Energy JXB Peak ARP ARP Peak 26 of 32

28 4 Kissimmee Utility Authority September 217 1,4 35 1,2 3 1, Kissimmee Utility Authority MW ARP MW Sep 1 Sep 3 Sep 5 Sep 7 Sep 9 Sep 11 Sep 13 Sep 15 Sep 17 Sep 19 Sep 21 Sep 23 Sep 25 Sep 27 Sep % Non Coincident Peak Load Factor 63.83% Coincident Peak Load Factor Kissimmee Utility Authority KUA Peak ARP ARP Peak 27 of 32

29 16 Keys Energy Services September 217 1,4 14 1,2 12 1, Keys Energy Services MW ARP MW 2 2 Sep 1 Sep 3 Sep 5 Sep 7 Sep 9 Sep 11 Sep 13 Sep 15 Sep 17 Sep 19 Sep 21 Sep 23 Sep 25 Sep 27 Sep % Non Coincident Peak Load Factor 47.4% Coincident Peak Load Factor Keys Energy Services KWS Peak ARP ARP Peak 28 of 32

30 12 Leesburg September 217 1,4 1 1,2 8 1, Leesburg MW ARP MW Sep 1 Sep 3 Sep 5 Sep 7 Sep 9 Sep 11 Sep 13 Sep 15 Sep 17 Sep 19 Sep 21 Sep 23 Sep 25 Sep 27 Sep % Non Coincident Peak Load Factor 63.46% Coincident Peak Load Factor Leesburg LBG Peak ARP ARP Peak 29 of 32

31 9 Newberry September 217 1, ,2 1, Newberry MW ARP MW Sep 1 Sep 3 Sep 5 Sep 7 Sep 9 Sep 11 Sep 13 Sep 15 Sep 17 Sep 19 Sep 21 Sep 23 Sep 25 Sep 27 Sep % Non Coincident Peak Load Factor 83.77% Coincident Peak Load Factor Newberry NBY Peak ARP ARP Peak 3 of 32

32 3 Ocala September 217 1,4 25 1,2 2 1, Ocala MW ARP MW Sep 1 Sep 3 Sep 5 Sep 7 Sep 9 Sep 11 Sep 13 Sep 15 Sep 17 Sep 19 Sep 21 Sep 23 Sep 25 Sep 27 Sep % Non Coincident Peak Load Factor 64.22% Coincident Peak Load Factor Ocala OCL Peak ARP ARP Peak 31 of 32

33 16 Starke September 217 1,4 14 1,2 12 1, Starke MW ARP MW Sep 1 Sep 3 Sep 5 Sep 7 Sep 9 Sep 11 Sep 13 Sep 15 Sep 17 Sep 19 Sep 21 Sep 23 Sep 25 Sep 27 Sep % Non Coincident Peak Load Factor 78.7% Coincident Peak Load Factor Starke STK Peak ARP ARP Peak 32 of 32