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[February 28, 2014]
(Edgar Glimpses Via Acquire Media NewsEdge) MANAGEMENT'S DISCUSSION & ANALYSIS OF FINANCIAL CONDITIONS & RESULTS OF OPERATIONS This Management's Discussion & Analysis contains forward-looking statements, which are subject to the inherent uncertainties in predicting future results and conditions. Actual results may differ materially from those forecasted. Such statements are based on our current expectations as of the date we filed this report, and we do not undertake to update or revise such forward-looking statements, except as may be required by law. These forward-looking statements include references to our anticipated capital expenditures, liquidity and financing requirements, projected operating results, future environmental matters, and regulatory and other plans. Important factors that could cause actual results to differ materially from those projected in these forward-looking statements are discussed under "Risk Factors." TECO Energy, Inc. is a holding company, and all of its business is conducted through its subsidiaries. In this Management's Discussion & Analysis, "we," "our," "ours" and "us" refer to TECO Energy, Inc. and its consolidated group of companies, unless the context otherwise requires.
OVERVIEW We are an energy-related holding company with regulated electric and gas utility operations in Florida, Tampa Electric and PGS, respectively. In May 2013, we signed an agreement to acquire the largest regulated gas distribution utility in New Mexico which, upon closing would increase our regulated customer base by approximately 50%. Our only remaining unregulated business is TECO Coal, which owns and operates coal production facilities in the Central Appalachian coal production region.
Our regulated utilities, Tampa Electric and PGS, operate in the Florida market.
Tampa Electric serves almost 695,000 retail customers in a 2,000-square-mile service area in West Central Florida and has electric generating plants with a winter peak generating capacity of 4,668 MW. PGS, Florida's largest gas distribution utility, serves approximately 347,000 residential, commercial, industrial and electric power generating customers in all major metropolitan areas of the state, with a total natural gas throughput of almost 1.7 billion therms in 2013.
Our unregulated business, TECO Coal, through its subsidiaries operates surface and underground mines and related coal-processing facilities in eastern Kentucky, southwestern Virginia and Tennessee, producing metallurgical-grade and high-quality steam coals. Sales in 2013 were 5.8 million tons.
In 2012, we sold our ownership interest in TECO Guatemala, which through its subsidiaries, owned a coal-fired generating facility and a 96% ownership interest in an oil-fired peaking power generating plant, both in Guatemala.
PENDING ACQUISITION OF NMGI In May 2013, we announced the signing of an agreement to acquire the regulated natural gas distribution utility NMGC for $950 million including the assumption of $200 million of existing NMGC debt, subject to customary closing adjustments.
Under the terms of the agreement, TECO Energy will acquire NMGI, the owner of NMGC. The transaction is subject to approval by the NMPRC. The federal approval process, a Hart-Scott-Rodino antitrust review, was completed without comment in 2013. The transaction is expected to be accretive to earnings beginning 12 months after closing.
NMGC serves approximately 509,000, primarily residential, customers throughout New Mexico. Upon closing of the transaction, TECO Energy subsidiaries will serve more than 1.5 million regulated electric and gas utility customers in Florida and New Mexico. NMGC has approximately 740 employees, and the majority of its customers are located in the Central Rio Grande Corridor region, which is one of the fastest growing regions in the state. The company serves approximately 60 percent of the state's population with customers in 23 of New Mexico's 33 counties. Customers are served through a combination of approximately 1,600 miles of transmission pipeline and 10,000 miles of distribution lines.
The transaction is supported by a fully committed bridge financing facility. The permanent financing is expected to be a combination of $350 to $400 million of TECO Energy common equity, cash on hand and approximately $250 million of long-term debt at NMGI and NMGC.
As discussed above, the acquisition is subject to approval by the NMPRC. In July 2013, we filed a joint application with NMGC and Continental Energy Systems LLC with the NMPRC for approval of the acquisition. On Dec. 2, 2013, the Hearing Examiner in the application for approval of the acquisition issued an order approving the motion filed by TECO Energy, Inc., NMGC, Continental Energy Systems LLC, the Staff of the NMPRC, and the New Mexico Attorney General's Office (the "Parties") requesting additional time for proceedings in the matter.
On Jan. 10, 2014, the Parties and the Hearing Examiner met to establish a new schedule. The new key dates established in that meeting are: Staff and intervenor testimony due on or before Feb. 28, hearings before the Hearing Examiner to follow on March 24 to 28. The date for a final decision is yet to be determined. With this schedule, closing will likely occur in the third quarter of 2014. Also under this schedule, closing of the transaction will not occur by July 24, 2014, which will trigger the need to file a new Hart-Scott-Rodino Premerger Notification and Report Form with the Department of Justice. Closing of the transaction would be subject to renewed clearance from anti-trust regulators and expiration of the new waiting period under the filings.
40-------------------------------------------------------------------------------- Table of Contents Except where specifically noted and discussed this MD&A excludes the impact of NMGC and related financing activities on our expected financial results throughout the forecast periods presented herein. (See the Item 1A Risk Factors, Financing Activities Related to NMGC, Credit Facility Related to NMGC and TECO Finance Bridge Facility Related to NMGC sections and See Note 22 to the TECO Energy Consolidated Financial Statements.) 2013 PERFORMANCE All amounts included in this MD&A are after tax, unless otherwise noted.
In 2013, our net income attributable to TECO Energy was $197.7 million, or $0.92 per share, compared with $212.7 million, or $0.99 per share, in 2012. Net income from continuing operations was $197.8 million, or $0.92 per share, in 2013, compared with $246.0 million, or $1.14 per share, in 2012.
In 2013, non-GAAP results from continuing operations, which exclude $6.2 million of costs associated with the pending acquisition of NMGC, were $204.0 million, or $0.95 on a per-share basis, compared with $246.0 million, or $1.14 per share, in 2012 when there were no adjustments to GAAP results.
The most significant factor impacting the year-over-year-comparison of results was the impact of weak coal markets, which reduced TECO Coal's earnings by $41.2 million. Tampa Electric and PGS benefited from customer growth of 1.5% and 1.3%, respectively, and therm sales and net income at the gas utility increased. While we expected Tampa Electric's 2013 results to be lower than 2012, initial revenues from its rate settlement became effective in November and significantly mitigated the impact of the rate base and O&M expense growth that had necessitated the company's 2013 rate filing.
Major events in 2013 included Tampa Electric's base rate case settlement, receiving final approval for Tampa Electric's Polk Power Station generation expansion project, and activities toward achieving a successful closing and integration of NMGC in 2014. In September, the FPSC approved a settlement agreement among Tampa Electric and intervenors that resolved all issues in Tampa Electric's 2013 base rate case and provided for additional base rates to become effective in 2017 at the time the generation expansion project commences service, thus eliminating the need for an additional rate case in 2016 and providing revenue clarity for at least four years (see the Tampa Electric section). In 2013, Tampa Electric obtained the final approvals for the conversion of the Polk Power Station Units 2-5 from peaking service to combined cycle. The final air emissions permits were received in January 2014, and construction commenced at that time.
In 2012, net income was $212.7 million, or $0.99 per share, compared with $272.6 million, or $1.27 per share, in 2011. The 2012 full-year net income from continuing operations was $246.0 million, or $1.14 per share, compared with $250.8 million, or $1.17 per share, in 2011. The 2012 full-year loss reported in discontinued operations, which was related to the sale of TECO Guatemala, was $33.3 million, or $0.15 per share, compared with net income of $21.8 million, or $0.10 per share, in 2011.
There were no charges or gains to cause non-GAAP results to differ from net income in 2012 or in 2011.
OUTLOOK Our outlook for 2014 results reflects our expectations that our Florida utilities will deliver strong earnings growth and returns at or above the middle of their allowed ROE ranges, and that TECO Coal results will be about break-even and cash positive. We expect that the combined earnings growth of our two regulated Florida utilities will exceed 13% in 2014. The major driver for Tampa Electric is the expected $50 million of higher base revenues as a result of the 2013 rate settlement. We expect that O&M expenses in 2014 will be lower than 2013, and that continued growth in the local economy will yield annual customer growth similar to 2013. As construction spending on the Polk Power Station increases, Tampa Electric is expected to have higher AFUDC earnings as well. We anticipate that PGS will earn above the midpoint of its allowed ROE range of 9.75% to 11.75%, with continued customer growth as well as volume growth, driven in part by positive trends in the state and local economies and continued interest in converting vehicle fleets to compressed natural gas.
The drivers impacting 2014 are summarized below and discussed in further detail in the individual operating company sections. The discussion below excludes any impact from the acquisition of NMGC or related financing activities. Results from NMGC will depend on the timing of the closing, the interest rate on the debt to be issued and the number of shares sold to finance the transaction, among other factors.
Tampa Electric expects customer growth in 2014 to continue at a pace similar to 2013, with 1.5% higher average number of customers. Total retail energy sales growth is expected to average about 0.5% lower than customer growth due to lower average customer usage. Sales to the lower margin industrial-phosphate customers are expected to be lower in 2014 due to increased self-generation from new generating and transmission facilities owned by these customers, after the in-service dates for these facilities were delayed in 2013. PGS expects customer growth consistent with trends in 2013 when the average number of customers increased 1.2%. PGS expects energy sales volumes to be higher than in 2013, assuming normal weather conditions, as mild winter temperatures reduced natural gas volumes sold in 2013. It also expects to benefit from customers converting from petroleum and other fuel sources to natural gas due to the attractive economics. Interest in compressed natural gas (CNG) vehicle fleets is growing steadily with additional filling stations and more vehicle conversions expected in 2014.
Due to the current very weak domestic and international coal market conditions, we expect TECO Coal's results to be about break even, but cash positive at the middle of the cost and sales guidance ranges in 2014. TECO Coal expects to sell between 5.5 and 6.0 million tons in 2014 with 80% of its sales contracted and priced, 15% of its sales committed but subject to quarterly price adjustments, and 5% unsold. The average selling price across all products is expected to be $80 per ton, which is $5 per ton lower than in 2013, while the fully-loaded, all-in cost of production is expected to be in a range between $79 and $83 per ton, which is lower than the $84 per ton average cost in 2013 and reflects the benefit of actions taken in 2013 to reduce costs.
These forecasts are based on our current assumptions described in each operating company discussion, which are subject to risks and uncertainties (see the Risk Factors section).
41 -------------------------------------------------------------------------------- Table of Contents Our priority for the use of cash is investment in our Florida utilities to support their capital spending programs while maintaining their capital structures and financial integrity, and over time reduction of parent debt. In 2014, we will use cash on hand to fund a portion of the NMGC acquisition. In 2014, we expect to make additional equity contributions to Tampa Electric and PGS of $125 million and $25 million, respectively. Our opportunities to invest capital in Tampa Electric are expected to grow significantly over the next several years as it completes its next increment of new generating capacity. We anticipate capital spending in 2014 to increase to $700 million at the regulated Florida utilities, including the investments in generating capacity additions at Tampa Electric and opportunities to grow the PGS system described below (see the Liquidity, Capital Resources section).
TECO Coal, with its dedicated work force and management team, has delivered strong earnings and cash flow to us for many years. With our focus clearly on growing our regulated operations, we do not consider TECO Coal to be a core holding. The coal business is a commodity business, which, by its nature, is cyclical with earnings volatility, which is not the earnings profile we believe our investors seek. If an opportunity to sell TECO Coal presents itself, we would consider such an offer. In the event of a sale of this business, we could use the proceeds to pay for a portion of the acquisition of NMGC, or repay parent debt. However, at this time a sale of TECO Coal on acceptable terms is uncertain.
We have evaluated trends, strategies and opportunities affecting our regulated utilities, to sharpen the focus on developing longer-range plans to take advantage of emerging growth opportunities and some fundamental changes in our industry. Over time, we expect these initiatives to contribute to organic earnings growth. Some of the areas that we are currently focused on include: • We believe there are opportunities to grow the use of CNG for fleet vehicles. In 2013, the Florida legislature enacted legislation supportive of CNG vehicle conversions through rebates and tax incentives. To date, we have had success working with fleet owners to install 21 CNG filling stations with completed conversions or planned conversions in 2014 of almost 1,000 vehicles of various sizes to CNG. The number of vehicles already converted or committed to conversion will consume almost 10 million therms annually, the equivalent consumption of more than 43,000 typical residential customers. Such conversions offer compelling economics to customers, and expand PGS therm sales without significant capital investment by PGS.
• We are looking closely at Smart Grid applications that have proven technology and offer operating and financial benefits to our overall operations. These include, among other opportunities, transitioning automatic meter reading technology to advanced metering infrastructure, which would include a significant investment in our communications infrastructure but would also result in O&M expense savings.
• We also recognize that there is a growing demand for natural gas generation in Florida over the next decade. We project that Florida may need between 0.8 and 1.25 billion cubic feet per day (Bcf/day) by as early as 2016. Given our expertise in this area, we continue to evaluate opportunities to partner with transmission and end-use natural gas customers.
At PGS, the business model for system expansion evolved over the past several years to focus on extending the system to serve large commercial and industrial customers that are currently using petroleum and propane as fuel under multi-year contracts. The current low natural gas prices and the projections that natural gas prices are going to remain low into the future make it attractive for these customers to convert from fuels that are currently more expensive on a cost per MMBTU basis.
Previously, during periods of robust residential growth, PGS extended its system to serve large residential housing developments, and commercial growth followed the residential development. In the current environment where fewer large residential projects are being developed, commercial and industrial-led expansion allows PGS to continue to provide clean and economical natural gas to areas of the state previously unserved and to be positioned to serve future residential growth.
RESULTS SUMMARY The table below compares our GAAP net income to our non-GAAP results. A reconciliation between GAAP net income and non-GAAP results is contained in the Reconciliation of GAAP net income from continuing operations to non-GAAP results tables for 2013. A non-GAAP financial measure is a numerical measure that includes or excludes amounts, or is subject to adjustments that have the effect of including or excluding amounts that are excluded or included from the most directly comparable GAAP measure (see theNon-GAAP Information section).
42-------------------------------------------------------------------------------- Table of Contents Results Comparisons (millions) 2013 2012 2011 Net income attributable to TECO Energy $ 197.7 $ 212.7 $ 272.6 Net income from continuing operations $ 197.8 $ 246.0 $ 250.8 Non-GAAP results from continuing operations $ 204.0 $ 246.0 $ 250.8 The table below provides a summary of revenues, earnings per share, net income and shares outstanding for the 2013-2011 period.
Earnings Summary (millions) Except per-share amounts 2013 2012 2011 Consolidated revenues $ 2,851.3 $ 2,996.6 $ 3,209.9 Earnings per share - basic Earnings per share from continuing operations $ 0.92 $ 1.14 $ 1.17 Earnings (loss) per share from discontinued operations - (0.15 ) 0.10 Earnings per share attributable to TECO Energy $ 0.92 $ 0.99 $ 1.27 Earnings per share - diluted Earnings per share from continuing operations $ 0.92 $ 1.14 $ 1.17 Earnings (loss) per share from discontinued operations - (0.15 ) 0.10 Earnings per share attributable to TECO Energy $ 0.92 $ 0.99 $ 1.27 Net income from continuing operations $ 197.8 $ 246.0 $ 250.8 Net income (loss) from discontinued operations (0.1 ) (33.3 ) 21.8 Net income attributable to TECO Energy 197.7 212.7 272.6 Charges and (gains)(1) 6.2 - - Non-GAAP results $ 204.0 $ 212.7 $ 272.6 Average common shares outstanding (millions) Basic 215.0 214.3 213.6 Diluted 215.5 215.0 215.1 (1) See the GAAP to non-GAAP reconciliation table that follows.
The following table shows the specific adjustments made to GAAP net income for each segment to develop our 2013 non-GAAP results.
There were no charges or gains in 2012 or 2011 to cause non-GAAP results to differ from net income from continuing operations.
43-------------------------------------------------------------------------------- Table of Contents 2103 Reconciliation of GAAP Net Income to Non-GAAP Results Total Tampa TECO Parent/ Continuing Discontinued Net income impact (millions) Electric PGS Coal other(1) Operations Operations(1) Total GAAP Net income attributable to TECO Energy $ 190.9 $ 34.7 $ 9.0 $ (36.8 ) $ 197.8 $ (0.1 ) $ 197.7 Costs associated with the acquisition of NMGC - - - 6.2 6.2 - 6.2 Total charges - - - 6.2 6.2 6.2 Non-GAAP results $ 190.9 $ 34.7 $ 9.0 $ (30.6 ) $ 204.0 $ (0.1 ) $ 203.9 (1) Certain costs previously included in Parent/other have been recast to Discontinued Operations.
NON-GAAP INFORMATION From time to time, in this MD&A, we provide non-GAAP results, which present financial results after elimination of the effects of certain identified charges and gains. In 2012 and 2011, there were no charges or gains to cause non-GAAP results to differ from net income from continuing operations. We believe that the presentation of this non-GAAP financial performance provides investors a measure that reflects the company's operations under our business strategy. We also believe that it is helpful to present a non-GAAP measure of performance that clearly reflects the ongoing operations of our business and allows investors to better understand and evaluate the business as it is expected to operate in future periods. Management and the board of directors use this non-GAAP presentation as a yardstick for measuring our performance, making decisions that are dependent upon the profitability of our various operating units and in determining levels of incentive compensation.
The non-GAAP measure of financial performance we use is not a measure of performance under accounting principles generally accepted in the United States and should not be considered an alternative to net income or other GAAP figures as an indicator of our financial performance or liquidity. Our non-GAAP presentation of results may not be comparable to similarly titled measures used by other companies.
While none of the particular excluded items are expected to recur, there may be adjustments to previously estimated gains or losses related to the disposition of assets or additional debt extinguishment activities. We recognize that there may be items that could be excluded in the future. Even though charges may occur, we believe the non-GAAP measure is important in addition to GAAP net income for assessing our potential future performance, because excluded items are limited to those that we believe are not indicative of future performance.
44 -------------------------------------------------------------------------------- Table of Contents OPERATING RESULTS This MD&A utilizes TECO Energy's consolidated financial statements, which have been prepared in accordance with GAAP, and separate non-GAAP measures to analyze the financial condition of the company. Our reported operating results are affected by a number of critical accounting estimates such as those involved in our accounting for regulated activities, asset impairment testing and others (see the Critical Accounting Policies and Estimates section).
The following table shows the segment revenues, net income and earnings per share contributions from continuing operations of our business segments on a GAAP basis (see Note 14 to the TECO Energy Consolidated Financial Statements).
(millions) Except per share amounts 2013 2012 2011 Segment revenues (1) Regulated companies Tampa Electric $ 1,950.5 $ 1,981.3 $ 2,020.6 PGS 393.5 398.9 453.5 Total regulated $ 2,344.0 $ 2,380.2 $ 2,474.1 TECO Coal $ 496.2 $ 608.9 $ 733.0 Net income (2) Regulated companies Tampa Electric $ 190.9 $ 193.1 $ 202.7 PGS 34.7 34.1 32.6 Total regulated 225.6 227.2 235.3 TECO Coal 9.0 50.2 51.5 Parent/other(4) (36.8 ) (31.4 ) (36.0 ) Net income from continuing operations 197.8 246.0 250.8 Net income (loss) from discontinued operations (0.1 ) (33.3 ) 21.8 Net income attributable to TECO Energy $ 197.7 $ 212.7 $ 272.6 Earnings per share - basic (2)(3) Regulated companies Tampa Electric $ 0.89 $ 0.90 $ 0.95 PGS 0.16 0.16 0.15 Total regulated 1.05 1.06 1.10 TECO Coal 0.04 0.23 0.24 Parent/other(4) (0.17 ) (0.15 ) (0.17 ) Earnings per share from continuing operations 0.92 1.14 1.17 Earnings (loss) per share from discontinued operations - (0.15 ) 0.10 Earnings per share attributable to TECO Energy $ 0.92 $ 0.99 $ 1.27 Average shares outstanding - basic 215.0 214.3 213.6 (1) Segment revenues include intercompany transactions that are eliminated in the preparation of TECO Energy's consolidated financial statements.
(2) Segment net income and earnings per share are reported on a basis that includes internally allocated interest costs to the unregulated companies.
Internally allocated interest costs were at a pretax interest rate of 6.00% for 2013 and 2012, and 6.25% for 2011.
(3) The number of shares used in the earnings-per-share calculations is basic shares.
(4) From continuing operations TAMPA ELECTRIC Electric Operations Results Net income in 2013 was $190.9 million compared with $193.1 million in 2012.
Results in 2013 reflected 1.5% customer growth, higher base revenues effective Nov. 1, 2013 as a result of the rate case settlement, and energy sales, weather and customer usage patterns similar to 2012. Higher O&M was partially offset by lower interest expense. Net income included $6.3 million of AFUDC- equity, which represents allowed equity cost capitalized to construction costs, compared with $2.6 million in the 2012 period. Net income also reflected $3.6 million lower earnings on assets recovered through the ECRC due to an FPSC rule revising the return on investment calculation effective Jan. 1, 2013.
45-------------------------------------------------------------------------------- Table of Contents In 2013, total degree days in Tampa Electric's service area were 1% below normal, and 1% below the prior full-year period, reflecting generally milder weather early in the year. Pretax base revenues were $13 million higher than in 2012, primarily due to $10 million of higher base rates effective Nov. 1, 2013, and higher energy sales late in the year due to unusually warm early winter weather. Total net energy for load, which is a calendar measurement of retail energy sales rather than a billing-cycle measurement, decreased 0.4% in 2013 compared with 2012. The energy sales shown in the summary table below reflect the energy sales based on the timing of billing cycles, which can vary from period to period.
O&M expenses, excluding all FPSC-approved cost-recovery clauses, increased $19.4 million in 2013, reflecting $8.2 million of higher accruals for performance-based incentive compensation for all employees based on achievement of financial goals and higher costs to operate and maintain the transmission and distribution systems. Compared to 2012, depreciation and amortization expense increased $0.7 million, reflecting the impact of additions to facilities to serve customers, largely offset by approximately $4.0 million of lower amortization on software retroactive to Jan. 1, 2013, due to the change in life for software agreed to in the base rate case settlement. Interest expense decreased $11.1 million, due to lower long-term debt interest rates and balances and a lower interest rate on customer deposits.
Net income in 2012 was $193.1 million, compared to $202.7 million in 2011.
Results in 2012 reflected a mild winter weather period and an extremely rainy summer period, and lower per-customer average usage, partially offset by 1.2% growth in the average number of customers, higher O&M expense and lower interest expenses. Net income in 2012 included $2.6 million of AFUDC-equity, compared with $1.0 million in the 2011 period.
In 2012, total degree days in Tampa Electric's service area were normal, but almost 3% below the prior year, reflecting mild winter weather and an unusually rainy summer weather pattern (the second wettest summer period on record) offset by higher than normal degree days in the normally mild spring and fall periods, which do not generate significantly higher energy sales. Pretax base revenue was almost $6.0 million lower than in 2011, primarily reflecting lower sales to residential customers from the milder weather, voluntary conservation that typically occurs during periods without extreme weather, and changes in customer usage patterns. In 2012, total net energy for load was 0.3% higher than in 2011.
In 2012, O&M expense, excluding all FPSC-approved cost-recovery clauses, increased $11.8 million reflecting higher generating system maintenance expenses, higher costs to operate and maintain the distribution system and higher pension and other employee benefit expenses, partially offset by lower bad-debt expense. Compared to the 2011 full-year period, depreciation and amortization expense increased $9.6 million, reflecting additions to facilities to serve customers. Interest expense decreased $7.4 million due to lower long-term debt interest rates and balances and a lower interest rate on customer deposits.
Base Rates Prior to Nov. 1, 2013, Tampa Electric's results reflected base rates established in March 2009, when the FPSC awarded $104.0 million higher revenue requirements effective in May 2009 that authorized an ROE mid-point of 11.25%, 54.0% equity in the capital structure, and 2009 13-month average rate base of $3.4 billion.
In a series of subsequent decisions in 2009 and 2010, related to a calculation error and a step increase for combustion turbines and rail unloading facilities that entered service before the end of 2009, base rates increased an additional $33.5 million.
As a result of growth in rate base from required infrastructure added to serve customers, increasing pressure on O&M expense, and an economic recovery that was slower than expected compared to the assumptions in Tampa Electric's last base rate proceeding in 2009, on April 5, 2013, Tampa Electric filed its petition with the FPSC for an increase in base rates and miscellaneous service charges in the amount of $134.8 million. In the petition, Tampa Electric requested an ROE level of 11.25% and a capital structure identical to that approved in 2009, with 54% equity.
After extensive testimony by Tampa Electric and discovery by five intervening parties and the FPSC Staff, on Sept. 6, 2013, Tampa Electric and all of the intervening parties reached a Stipulation and Settlement Agreement resolving all of the issues in the proceeding. On Sept. 11, 2013, the FPSC approved the settlement that authorized base rate increases implemented at four different dates.
Under the settlement agreement, Tampa Electric was granted $57.5 million higher annual base rates effective Nov.1, 2013, an additional $7.5 million effective Nov. 1, 2014, an additional $5.0 million increase effective Nov.1, 2015, and $110 million of higher base rates effective Jan. 1, 2017, or when the Polk 2 - 5 conversion enters commercial service, whichever is later (see the Regulation section).
46 -------------------------------------------------------------------------------- Table of Contents The table below provides a summary of Tampa Electric's revenue and expenses and energy sales by customer type.
Summary of Operating Results (millions) 2013 % Change 2012 % Change 2011 Revenues $ 1,950.5 (1.6 ) $ 1,981.3 (1.9 ) $ 2,020.6 O&M expenses 427.0 13.7 375.7 7.6 349.2 Depreciation and amortization 238.8 0.5 237.6 7.0 221.1 Taxes, other than income 149.7 (1.1 ) 151.3 5.4 143.6 Non-fuel operating expenses 815.5 6.7 764.6 7.0 713.9 Fuel expense 681.9 (1.8 ) 694.7 (5.3 ) 733.5 Purchased power expense 64.6 (38.7 ) 105.3 (16.4 ) 125.9 Total fuel & purchased power expense 746.5 (6.7 ) 800.0 (6.9 ) 859.4 Total operating expenses 1,562.0 (0.2 ) 1,564.6 (0.6 ) 1,573.3 Operating income 388.5 (6.8 ) 416.7 (6.6 ) 447.3 AFUDC equity 6.3 142.3 2.6 160.0 1.0 Net income $ 190.9 (1.1 ) $ 193.1 (4.7 ) $ 202.7 Megawatt-Hour Sales (thousands) Residential 8,470 0.9 8,395 (3.7 ) 8,718 Commercial 6,090 (1.5 ) 6,185 (0.4 ) 6,207 Industrial 2,027 1.2 2,001 10.9 1,804 Other 1,832 0.2 1,828 (0.3 ) 1,835 Total retail 18,418 - 18,409 (0.8 ) 18,564 Sales for resale 222 (16.8 ) 267 (24.2 ) 352 Total energy sold 18,640 (0.2 ) 18,676 (1.3 ) 18,916 Retail customers - (thousands) Average 694.7 1.5 684.2 1.2 675.8 Retail net energy for load 19,178 (0.4 ) 19,255 0.3 19,205 Operating Revenues In 2013, retail MWh sales, as measured on a billing cycle basis shown in the table above, were essentially unchanged from 2012. Similar to 2012, sales in 2013 reflected a mild winter and a rainy summer period and lower per customer usage, partially offset by 1.5% customer growth and improvements in the local economy. Pretax base revenue, which included $10.0 million of higher revenue as a result of the base rate settlement described above, was approximately $13.0 million higher than in 2012. In 2013, total retail net energy for load decreased 0.4%, compared to the 2012 period. In 2013, total degree days in Tampa Electric's service area were 1% below normal, and 1% below 2012, reflecting generally milder weather early in the year.
In 2012, retail MWh sales, as measured on a billing cycle basis shown in the table above, decreased 0.8% despite 1.2% higher average number of customers, an improving local economy and higher sales to the lower margin phosphate-industrial customers. In 2012, total degree days in Tampa Electric's service area were normal, but almost 3% below 2011, reflecting mild winter weather and an unusually rainy summer weather pattern offset by higher than normal degree days in the normally mild spring and fall periods, which do not generate significantly higher energy sales. Pretax base revenue was almost $6.0 million lower than in 2011, primarily reflecting lower sales to residential customers from the milder weather, changes in customer usage patterns and voluntary conservation that typically occurs during periods without extreme weather. In 2012, total net energy for load, which is a calendar measurement of retail energy sales rather than a billing cycle measurement, was 0.3% higher than in 2011.
For the past several years, weather-normalized energy consumption per residential customer declined due to the combined effects of voluntary conservation efforts, economic conditions, improvements in lighting and appliance efficiency, smaller single-family houses and increased multi-family housing.
Sales for resale, which are a decreasing portion of Tampa Electric's energy sales, declined 16.8% in 2013 and 24.2% in 2012, primarily due to changes in Tampa Electric's wholesale rates and reduced demand due to the mild weather.
Customer and Energy Sales Growth Outlook The Florida economy continues to improve following the economic downturn, as evidenced by lower levels of unemployment, and slow improvements in the new housing construction market, which was a major driver of growth in the Florida economy for many years (see the Risk Factors section). In general, economists are forecasting a continued improvement in the unemployment rate in 2014, and an acceleration of improvement in the economy in 2014 and beyond. The 2014 forecast used by Tampa Electric reflects a continuation of the customer growth that was experienced in 2013. Energy sales are expected to reflect continued lower per customer usage in response to increased energy efficiency, voluntary conservation, and economic conditions. The average number of customers increased 1.5% in 2013 and 1.2% in 2012.
47-------------------------------------------------------------------------------- Table of Contents Longer-term, assuming continued economic recovery and resumed growth from population increases and more robust business expansion, Tampa Electric expects average annual customer growth of about 1.5% and weather-normalized average retail energy sales growth about 0.5% lower than customer growth in the near term, and about 0.3% lower than customer growth over the longer-term. This energy sales growth projection reflects increased lighting and appliance efficiency, smaller new single family homes, increased percentage of multi-family homes, changes in usage patterns and changes in population trends.
These growth projections assume continued local area economic growth, normal weather, and a continuation of the current energy market structure.
The economy in Tampa Electric's service area continued to grow in 2013 after modest growth in 2012 and 2011. The Tampa metropolitan area had the largest gain in jobs of 22 metropolitan areas in Florida, with more than 35,000 new jobs led primarily by business services, construction and healthcare related businesses.
The total nonfarm employment in the Tampa metropolitan area increased 3.5% in 2013 following a 1.8% increase in 2012 and 1.2% in 2011. The increase in nonfarm employment compared favorably with the state of Florida's increase of 2.5%. The local Tampa area unemployment rate decreased to 5.7% at the end of 2013 compared with 7.6% at year-end 2012 and 9.5% at year-end 2011. The Tampa area year-end 2013 unemployment rate was below the state of Florida's 6.2% rate and the national rate of 7.0%. The Tampa area, Florida and national unemployment rates were 7.6%, 8.0% and 7.8%, respectively, at year-end 2012, and 9.5%, 9.7% and 8.5%, respectively, at year-end 2011.
Operating Expenses Total pretax operating expenses were 0.2% lower in 2013, driven primarily by higher other operating expenses more than offset by lower fuel and purchased-power expense. Excluding all FPSC-approved cost-recovery clause-related expenses, O&M expenses increased $19.4 million in 2013 reflecting $8.2 million of higher accruals for performance-based incentive compensation for all employees based on achievement of financial goals and higher costs to operate and maintain the transmission and distribution systems.
Total pretax operating expenses decreased 0.6% in 2012 driven primarily by lower fuel and purchased power expenses. Excluding all FPSC approved cost-recovery clause related expenses, which are net-income neutral, O&M expense increased 6.6%, or $11.8 million, driven by higher generating system maintenance expenses, higher costs to operate and maintain the distribution system and higher pension and other employee benefit expenses, partially offset by lower bad-debt expense.
Compared to 2012, depreciation and amortization expense increased $0.7 million in 2013 primarily as a result of approximately $4.0 million of lower amortization on software retroactive to Jan. 1, 2013, due to the change in depreciable life for software agreed to in the base rate case settlement, more than offset by depreciation of additions to facilities to serve customers. In 2014, depreciation expense is expected to increase at more normal levels, similar to those experienced in 2012. Compared to 2011, depreciation and amortization expense increased $9.5 million in 2012, reflecting additions to facilities to serve customers.
Excluding all FPSC-approved cost-recovery clause-related expenses, O&M expense is expected to decrease in 2014 due to lower employee-related costs, lower storm damage expense accruals, and lower pension expense driven by higher discount rates partially offset by higher costs to operate the system and reliably serve customers. Under the rate settlement approved by the FPSC in September 2013, Tampa Electric discontinued its annual $8 million pretax storm damage expense accrual effective Nov. 1, 2013.
Fuel Prices and Fuel Cost Recovery In November 2013, the FPSC approved cost-recovery rates for fuel and purchased power, capacity, environmental and conservation costs for 2014. The rates include the expected cost for natural gas and coal in 2014, and the net over-recovery of fuel, purchased power and capacity clause expenses.
Total fuel cost decreased in both 2013 and 2012, due to increased natural gas-fired generation and lower costs for natural gas and coal. Purchased-power expense decreased in 2013 and 2012 as the cost-per-MWh decreased, due to lower natural gas prices, which is the primary fuel used by other generators in Florida. Delivered natural gas prices decreased 2% in 2013 after a 14.0% decline in 2012 as a result of low natural gas prices due to mild winter weather and abundant supplies from on-shore domestic natural gas produced from shale formations, and storage inventories above historic averages. Delivered coal costs decreased 5.3% in 2013. The average coal and natural gas costs were $3.38/MMBTU and $5.23/MMBTU, respectively, in 2013.
Natural gas futures as traded on the NYMEX and various forecasts for natural gas prices indicate that natural gas prices are expected to increase in 2014, as fewer new natural gas wells are drilled in on-shore shale gas formations due to the low prices received by the producers, and a shift by the producers to drilling for more oil than natural gas. Cold winter weather early in 2014 and resulting draws on inventories in storage, improved industrial demand from continued improvement in the economy, and the expectation for more-normal weather are expected to contribute to higher prices as well. Beyond 2014, forecasts are for stable to slightly rising natural gas prices for several years due to increased availability of domestic supplies of natural gas. Delivered coal prices decreased 5.3% in 2013 due to lower transportation costs as a result of lower fuel oil prices, and lower prices for coal purchased in the spot market. Tampa Electric's primary coal supplies are from the Illinois Basin, which have been more stable than the Central Appalachian coal-producing region over the past several years. Excluding normal escalation and transportation costs, Tampa Electric's coal prices are expected to remain stable in 2014 due to long-term supply contracts.
Energy Supply Tampa Electric's generation increased in line with energy sales growth in 2013, and purchased power decreased due to higher gas-fired generation by Tampa Electric. Tampa Electric's generation decreased in 2012 due to the mild weather and lower cost natural gas-fired generation available within Florida, which increased MWh purchased but at a lower cost. Lower natural gas prices also contributed to the decrease in purchased-power expense on a per-MW basis.
48-------------------------------------------------------------------------------- Table of Contents Prior to the conversion of the coal-fired Gannon Station to the natural gas-fired Bayside Power Station in 2003, nearly all of Tampa Electric's generation was from coal. Upon completion of that conversion, the mix shifted with the increased use of natural gas. Coal is expected to continue to represent a significant portion of Tampa Electric's fuel mix due to the baseload units at the Big Bend Power Station and the coal gasification unit, Polk Unit 1. Longer term, natural gas prices are expected to remain stable for several years, and we expect to maintain the generation mix at about current levels.
Polk Power Station Units 2 - 5 Combined Cycle Conversion In 2011, Tampa Electric announced that, subject to FPSC approval, it planned to convert four CTs in peaking service at the Polk Power Station to combined cycle with an early 2017 in-service date. In 2012, as required under Florida regulations, Tampa Electric issued a request for proposal to determine its lowest cost option to provide generating capacity beginning in early 2017. The bid process showed that the lowest cost option to serve customers, over the long-term, was Tampa Electric's planned conversion of CTs to combined-cycle operation.
In September 2012, Tampa Electric submitted a petition to the FPSC for a Determination of Need for the conversion of these peaking CTs to combined-cycle service. In December 2012, the FPSC conducted a hearing for the need, and the FPSC made a bench decision to approve the Polk Power Station Units 2 - 5 conversion. In November 2013, the governor of Florida and the Cabinet, acting as the Power Plant Siting Board, approved the construction of the conversion. In January 2014, the final emission permits were received and construction commenced. The capital expenditures for the conversion and the related transmission system improvements to support the additional generating capacity are included in the capital expenditure forecast located in the Capital Expenditures section. Capital spending in 2014 will support engineering and design, equipment procurement and initial construction. (See the Capital Expenditures and Regulation sections.) PGS Operating Results In 2013, PGS reported net income of $34.7 million, compared with $34.1 million in 2012. Results reflected a 1.3% higher average number of customers and higher therm sales to all retail customer classes, due to more-normal first quarter weather and better economic conditions. Sales to power generation customers and off-system sales decreased due to the expiration of two contracts with power generators, new participants in the market, and higher natural gas prices in 2013 compared to 2012. Non-fuel O&M expense increased $4.0 million compared to 2012 due to higher employee related costs, including $1.5 million of higher accruals for performance-based incentive compensation for all employees based on achievement of financial goals, and an insurance recovery that reduced O&M expenses in 2012. Interest expense decreased $1.6 million, due to lower long-term debt interest rates and a lower interest rate on customer deposits.
In 2013, total throughput for PGS was almost 1.7 billion therms, down 10% from 2012 levels due to the lower volumes transported for power generation customers and lower off-system sales. Industrial and power generation customers represented approximately 61% of annual therm volume, commercial customers used approximately 26%, approximately 9% was sold off-system, and the remainder was consumed by residential customers.
In 2012, PGS reported net income of $34.1 million, compared with $32.6 million in 2011. Results in 2012 reflected a 1.2% higher average number of customers, but lower sales to residential customers due to mild winter weather more than offset by higher sales to commercial and industrial customers and power generation customers due to improving economic conditions. Volumes for the low-margin transportation service for electric power generators were higher than in 2011 due to low natural gas prices, which made it more economical to use natural gas for power generation. Non-fuel O&M expense decreased $2.1 million, compared with 2011, due in part to an insurance recovery of legal expenses associated with environmental-contamination claims. In 2011, O&M expense included $2.5 million related to legal expenses associated with environmental-contamination claims. Interest expense decreased $1.0 million due to lower long-term debt interest rates and balances and a lower interest rate on customer deposits. Depreciation expense increased $1.4 million reflecting additions to facilities to serve customers.
In 2012, the total throughput for PGS was almost 1.9 billion therms. Industrial and power generation customers consumed approximately 62% of PGS's annual therm volume, commercial customers used approximately 22%, approximately 12% was sold off system, and the balance was consumed by residential customers.
Residential operations were about 32% of total revenues in each of the past three years. New residential construction, which includes natural gas and conversions of existing residences to natural gas has slowed significantly, compared to the pre-2007 period, due to the weaker Florida housing market. Like most other natural gas distribution utilities, PGS is adjusting to lower per-customer usage due to improving appliance efficiency. As customers replace existing gas appliances with newer, more efficient models, per-customer usage tends to decline.
Natural gas has historically been used in many traditional industrial and commercial operations throughout Florida, including production of products such as steel, glass, ceramic tile and food products. Within the PGS operating territory, large cogeneration facilities utilize gas-fired technology in the production of electric power and steam. PGS has also experienced increased interest in the usage of CNG as an alternative fuel for vehicles. Currently, there are 21 CNG fueling stations connected to the PGS system, and, at this time, an additional six stations are expected to be added in 2014, however the number of new stations may increase as the year progresses. Such initiatives add therm sales, at lower-margin transportation rates, to the gas system without requiring significant capital investment by PGS.
49-------------------------------------------------------------------------------- Table of Contents The actual cost of gas and upstream transportation purchased and resold to end-use customers is recovered through a PGA. Because this charge may be adjusted monthly based on a cap approved by the FPSC annually, PGS normally has a lower percentage of under- or over-recovered gas cost variances than Tampa Electric.
The table below provides a summary of PGS's revenue and expenses and therm sales by customer type.
Summary of Operating Results (millions) 2013 % Change 2012 % Change 2011 Revenues $ 393.5 (1.3 ) $ 398.9 (12.0 ) $ 453.5 Cost of gas sold 142.6 (9.5 ) 157.6 (25.4 ) 211.3 Operating expenses 181.1 6.5 170.0 (1.3 ) 172.2 Operating income 69.8 (2.1 ) 71.3 1.9 70.0 Net income 34.7 1.8 34.1 4.6 32.6 Therms sold - by customer segment Residential 74.4 5.0 70.8 (8.9 ) 77.7 Commercial 438.1 4.0 421.4 3.0 409.2 Industrial 415.1 (10.0 ) 461.3 5.8 436.1 Power generation 744.4 (18.5 ) 913.5 48.7 614.3 Total 1,672.0 (10.4 ) 1,867.0 21.4 1,537.3 Therms sold - by sales type System supply 249.5 (25.4 ) 334.3 (5.4 ) 353.3 Transportation 1,422.5 (7.2 ) 1,532.7 29.5 1,184.0 Total 1,672.0 (10.4 ) 1,867.0 21.4 1,537.3 Customer (thousands) - average 347.4 1.3 342.9 1.2 338.8 In Florida, natural gas service is unbundled for non-residential customers and residential customers that use more than 1,999 therms annually that elect this option, affording these customers the opportunity to purchase gas from any provider. The net result of unbundling is a shift from bundled transportation and commodity sales to transportation-only sales. Because the commodity portion of bundled sales is included in operating revenues at the cost of the gas on a pass-through basis, there is no net earnings impact to the company when a customer shifts to transportation-only sales. PGS markets its unbundled gas delivery services to customers through its "NaturalChoice" program. At year-end 2013, approximately 20,500 out of 35,000 of PGS's eligible non-residential customers had elected to take service under this program.
50-------------------------------------------------------------------------------- Table of Contents PGS Outlook In 2014, PGS expects continued customer growth at rates in line with those experienced in 2013, reflecting its expectations that the housing markets in many areas of the state that it serves are now recovering. Assuming normal weather, therm sales to weather-sensitive customers, especially residential customers, are expected to increase in 2014 compared to 2013 when mild winter weather late in the year limited sales. Excluding all FPSC-approved cost-recovery clause-related expenses, O&M expense is expected to decrease slightly in 2014 primarily due to higher costs to operate the system more than offset by lower employee-related expenses, which includes pension expense driven by higher discount rates in the current interest rate environment and better pension plan asset performance in 2013. Depreciation expense is expected to increase from continued capital investments in facilities to reliably serve customers.
Since its acquisition by TECO Energy in 1997, PGS has expanded its gas distribution system into areas of Florida not previously served by natural gas, such as the lower southwest coast in the Fort Myers and Naples areas and the northeast coast in the Jacksonville area. In 2014, PGS expects capital spending to support moderate residential and commercial customer growth, system expansion to serve large commercial and industrial customers, continued interest in conversion of vehicle fleets to CNG and replacement of cast iron and bare steel pipe.
Due to the current rate of new residential development in Florida, which is considerably slower than the 2005 to 2007 period, the PGS business model for system expansion has evolved to focus on extending the system to serve large commercial or industrial customers that are currently using petroleum and propane as fuel. The current low natural gas prices and the projections that natural gas prices are going to remain low into the future makes it attractive for these customers to convert from fuels that are currently three to four times more expensive on a cost-per-MMBTU basis.
Gas Supplies PGS purchases gas from various suppliers, depending on the needs of its customers. The gas is delivered to the PGS distribution system through three interstate pipelines on which PGS has reserved firm transportation capacity for delivery by PGS to its customers.
Gas is delivered by the FGT through 66 interconnections (gate stations) serving PGS's operating divisions. In addition, PGS's Jacksonville Division receives gas delivered by the Southern Natural Gas Company pipeline through two gate stations located northwest of Jacksonville. PGS also receives gas delivered by Gulfstream Natural Gas Pipeline through six gate stations, and by its affiliate, SeaCoast Gas Transmission LLC, through a single gate station in northeast Florida.
PGS procures natural gas supplies using baseload and swing-supply contracts with various suppliers along with spot market purchases. Pricing generally takes the form of either a variable price based on published indices, or a fixed price for the contract term.
TECO COAL In 2013, TECO Coal recorded net income of $9.0 million on sales of 5.8 million tons, compared with $50.2 million on sales of 6.3 million tons in 2012. The 2013 full-year average net selling price was almost $85 per ton, compared with $95 per ton in 2012. The lower sales volumes and lower selling prices in 2013 reflect the current ongoing weak domestic and international coal markets. The all-in total cost of sales was $84 per ton, compared with $85 per ton in the 2012 period. The cost of sales in the first quarter of 2013 included some higher-cost tons from December 2012 inventory that included costs associated with personnel reductions and with idling certain mining operations. TECO Coal recorded a $3.6 million income tax benefit in 2013 that included a $3.7 million tax depletion benefit and a $1.9 million benefit from the reversal of previously accrued state taxes, compared with a 24% effective income tax rate, or a $15.7 million tax expense, in 2012.
In 2012, TECO Coal recorded net income of $50.2 million on sales of 6.3 million tons, compared with $51.5 million on sales of 8.1 million tons in 2011. Lower sales volumes in 2012 reflect much weaker coal market conditions than in 2011.
Because the 2012 sales were contracted at a time when the markets were much stronger, the 2012 average net per-ton selling price was more than $95 per ton, compared with almost $88 per ton in 2011. The all-in total per-ton cost of sales was more than $85 per ton compared with almost $80 per ton in 2011. The 2012 cost of sales reflected spreading fixed costs over fewer tons, and costs associated with personnel reductions and with idling certain mining operations.
TECO Coal's effective income tax rate was 24% in 2012, compared with 23% in 2011.
TECO Coal Outlook In 2014, we expect TECO Coal's net income to decrease compared with 2013 to about break-even levels from lower contract selling prices. TECO Coal has 80% of its expected 2014 sales of between 5.5 and 6.0 million tons contracted and priced. An additional 15% of expected sales are committed but unpriced and subject to quarterly pricing based on the Asian benchmark price for metallurgical coal. The average selling price across all products is expected to be $80 per ton in 2014, and specialty coal volumes are expected to represent about 70% of total sales.
The all-in total cost of production is expected to be below 2013 levels in a range between $79 and $83 per ton due to actions taken in 2013 and 2012 to reduce mining costs, including converting traditional surface mining operations to lower cost high-wall mining operations, and lower royalty payments and severance taxes, which are a function of selling price. The cash cost of sales, which excludes depreciation and allocated interest, is expected to be about $7 per ton below the all-in cost. In 2014, TECO Coal expects to record tax depletion tax benefits.
Various federal tax overhaul proposals include provisions to eliminate depletion accounting for mineral extraction companies, which would increase TECO Coal's effective income tax rate and reduce net income if those proposals are implemented (see the Risk Factors section).
51-------------------------------------------------------------------------------- Table of Contents In November 2011, TECO Coal announced that it had made a new discovery of an additional 65 million tons of proven and probable metallurgical coal reserves on properties it controls, and an additional estimated 9 million tons of metallurgical coal classified as resource (non-reserve coal deposits) due to seam thickness. There is an additional 14 million tons of coal classified as resource pending further geologic studies (see Item 2 Properties in the TECO Coal section). These metallurgical coal reserves are located below existing reserves and substantially all of these reserves are owned by TECO Coal, which eliminates royalty payments. The coal from these reserves can be transported by conveyor belt to an existing preparation plant, which has adequate capacity, and thus eliminate trucking costs. TECO Coal has received the permit amendments from the state of Kentucky related to surface development activities to access these reserves. TECO Coal performed preliminary surface and infrastructure development in 2012, but does not expect to begin the work required to bring these reserves into production until there are clear indications that the current weak metallurgical coal market conditions are improving (see the Capital Investments section of Liquidity, Capital Resources). TECO Coal allocates its reserves by market category. As a result of this allocation, 40% of the reserves are classified as metallurgical coal, 40% as soft coking/PCI coal and 20% as steam coal. See Item 2 Properties in the TECO Coal section for a discussion of this allocation.
Since 2008, the issuance of permits by the USACE under Section 404 of the Clean Water Act required for surface mining activities in the Central and Northern Appalachian mining regions has been challenged in the courts by various entities. These challenges have been appealed by various mining companies affected on a number of occasions, but very few permits have been issued over the past several years. At this time, TECO Coal has all of the permits required to meet its 2014 sales projections. See the Environmental section, the Section 404 of the Clean Water Act and Coal Surface Mine Permits section for a more detailed discussion of surface mining permit activities.
Coal Markets Prices for metallurgical coal have been very volatile over the past three years, with higher prices in 2010 driven by increased demand from expanding economies in China and India and recovering demand in the U.S. and Europe. During 2010, spot prices for various grades of metallurgical coal produced by TECO Coal and others reportedly ranged from $110 to $180 per short ton. Hard coking coal produced in Australia and sold primarily in Asian markets is the benchmark for metallurgical coal prices worldwide, and it has ranged from $335 per metric ton in the first half of 2011, due to disruptions in supplies from Australia as a result of flooding, to $235 per metric ton in January 2012, to $143 per metric ton in January 2014. The decline in metallurgical coal prices has been driven by oversupply in the market and concerns related to worldwide demand for steel in China and the weak international economy.
In 2012 and 2011, demand for coal used by utilities to generate electricity declined due to low natural gas prices, which made it more economical to generate electricity with natural gas than with coal, mild winter weather, and the slow economic recovery in the United States. Prices for Central Appalachian (CAPP) coal used by utilities did not improve in 2013, and in some periods declined further. Future demand for CAPP coal by utilities is uncertain due to the impact of certain proposed EPA regulations on utilities' ability to burn coal. Various industry reports, and estimates by the EPA, indicated that a number of smaller, older coal-fired utility boilers without current environmental controls would be retired in response to the proposed rules. In December 2011, the United States District Court for the District of Columbia stayed the implementation of the EPA's proposed CSAPR (see the Environmental section). In January 2013, the U.S. Court of Appeals for the District of Columbia Circuit denied the EPA's request for reconsideration of its ruling against CSAPR, significantly reducing the possibility that the rule will be enforced in its current form. Despite the stay of CSAPR in 2011, demand for coal by utilities remains weak.
In 2013, the EPA released draft rules for GHG emissions from new utility power plants which would, if implemented as proposed, essentially eliminate the use of coal as a fuel by requiring the use of carbon capture and sequestration. The EPA is scheduled to release draft rules for GHG emission from existing utility power plants in 2014, which increases the uncertainty of future coal use by utilities.
The significant factors that could influence TECO Coal's results in 2014 include the cost of production, the pricing on uncontracted tons, and customers taking contracted volumes. Longer-term factors that could influence results include inventories at thermal coal users, weather, the ability for utilities to continue to burn coal under new rules proposed by the EPA, the ability to obtain environmental permits for mining operations, general economic conditions, the level of natural gas prices, commodity price changes that impact the cost of production, and changes in environmental regulations (see theEnvironmental Compliance and Risk Factors sections).
PARENT/OTHER In 2013, the cost for Parent/other was $36.8 million, compared with $31.4 million in 2012. The non-GAAP cost from continuing operations for Parent/other in 2013 was $30.6 million, which excluded $6.2 million of costs associated with the pending acquisition of NMGC, compared with $31.4 million in 2012.
In 2012, the cost for Parent/other in continuing operations was $31.4 million, compared with $36.0 million in 2011. Results for 2012 reflect tax items and lower interest expense as a result of the mid-year 2011 debt retirement, and a charge of $0.8 million associated with the early retirement of the remaining $8.8 million of TECO Energy parent debt. The total cost for Parent/other for 2012 was $35.4 million, compared with $36.6 million in the same period in 2011.
Total cost for 2012 includes transaction costs and tax items recorded at Parent related to the TECO Guatemala discontinued operations.
The 2014 non-GAAP cost for Parent/other is expected to be similar to 2013 levels. This forecast excludes any transaction costs, which will be treated as non-GAAP costs, associated with the NMGC acquisition that will be recorded at Parent/other.
52 -------------------------------------------------------------------------------- Table of Contents DISCONTINUED OPERATIONS (TECO GUATEMALA) The 2013 cost of $0.1 million reported in discontinued operations was related to the 2012 sale of TECO Guatemala.
On Sept. 28, 2012, TECO Energy announced that its international power subsidiary, TECO Guatemala, entered into agreements to sell all of its equity interests in the Alborada and San José power stations, and related solid fuel handling and port facilities in Guatemala, for a total purchase price of $227.5 million in cash. On Dec. 19, 2012, the sale closed on the San José Power Station and related facilities and operations for a price of $215.0 million (see Note 19 to the TECO Energy Consolidated Financial Statements). The sale of the Alborada Power Station closed on Sept. 27, 2012, for a price of $12.5 million.
The 2012 losses in discontinued operations of $33.3 million reflect the results from operations of $18.2 million for the generating plants in Guatemala through the closing of the sales, a $28.6 million loss on assets sold including transaction costs, and a $22.9 million charge associated with foreign tax credit write offs.
On Jan. 13, 2009, TECO Guatemala Holdings, LLC's (TGH), a wholly-owned subsidiary of TECO Energy.) delivered a Notice of Intent to the Guatemalan government that it intended to file an arbitration claim against the Republic of Guatemala under the Dominican Republic Central America - United States Free Trade Agreement (DR - CAFTA) alleging a violation of fair and equitable treatment of its investment in EEGSA. On Oct. 20, 2010, TGH filed a Notice of Arbitration with the International Centre for Settlement of Investment Disputes (ICSID) to proceed with its arbitration claim. While TECO Energy and its subsidiaries no longer have assets or operations in Guatemala, TGH has retained its rights under this claim.
TGH filed the arbitration claim with ICSID in 2010, alleging a violation of fair and equitable treatment of its investment in Empresa Eléctrica de Guatemala, S.A. (EEGSA), the largest private distribution company in Central America. TGH's investment was sold on Oct. 21, 2010. The arbitration was prompted by actions of the Guatemalan government in July 2008, which, among other things, unilaterally reset the distribution tariff for EEGSA at levels well below the tariffs in effect at the time that the distribution tariff was reset.
On Dec. 19, 2013, the ICSID tribunal hearing TGH's arbitration claim against the Republic of Guatemala issued an award in the case. The ICSID tribunal found that Guatemala breached its treaty obligation to grant TGH fair and equitable treatment under the terms of the DR-CAFTA, thereby causing damages to TGH for which it is entitled to compensation. In sum, the tribunal found that Guatemala's repudiation of fundamental regulatory principles applying to the tariff review process was arbitrary and breached elementary standards of due process in administrative matters.
The ICSID tribunal unanimously found in favor of TGH and awarded damages of approximately U.S. $21.1 million, plus interest from Oct. 21, 2010, at a rate equal to the prime rate plus 2%. In addition, the tribunal ruled that Guatemala must reimburse TGH for approximately $7.5 million of the costs it incurred in pursuing the arbitration.
Pursuant to ICSID's rules and procedures, each party has 120 days after the date of the award to file an application for its annulment. Pending the outcome of a potential annulment filing, results in 2013 do not reflect any benefit of this decision.
OTHER ITEMS IMPACTING NET INCOME Other Income (Expense) Other income (expense) of $9.9 million in 2013 and of $10.8 million in 2012 included miscellaneous services at the utilities such as lightning surge protection equipment, royalties for coal mined on properties leased by TECO Coal and from the sale of assets no longer in service.
AFUDC equity at Tampa Electric, which is included in Other income (expense), was $6.3 million, $2.6 million and $1.0 million in 2013, 2012 and 2011, respectively. AFUDC is expected to increase in 2014 due to the construction of a reclaimed water pipeline to the Polk Power Station and spending related to the Polk Units 2 - 5 conversion project (see the Liquidity, Capital Resources section).
Interest Expense In 2013, interest expense was $166.9 million compared to $183.5 million in 2012 and $197.4 million in 2011. In 2013, interest expense decreased due to lower debt balances and lower interest rates on debt at TEC as a result of refinancing activities in 2012 (see Financing Activity section). Interest expense also declined due to an FPSC-approved lower interest rate paid on customer deposits at the utilities, effective in August 2012.
Interest expense is expected to increase in 2014, primarily due to increased borrowing at Tampa Electric to support the construction of the Polk Power Station Units 2 - 5 conversion.
Income Taxes The provision for income taxes decreased in 2013, primarily due to lower operating income. The provision for taxes was higher in 2012, primarily due to higher operating income and state income taxes. Income tax expense as a percentage of income from continuing operations before taxes was 35.5% in 2013, 35.9% in 2012 and 36.3% in 2011. We expect our 2014 annual effective tax rate to be approximately 37.0%.
The cash payments for federal income taxes, as required by the federal AMT rules, state income taxes, foreign income taxes and payments (refunds) related to prior years' audits totaled $1.8 million, $7.2 million and $9.4 million in 2013, 2012 and 2011, respectively.
53-------------------------------------------------------------------------------- Table of Contents Due to the NOL carryforward position resulting from the disposition of the generating assets formerly held by, our merchant power subsidiary, cash tax payments for income taxes are limited to approximately 10% of the AMT rate. We expect future cash tax payments to be limited to a similar level and various state taxes. As a result of bonus depreciation, enacted under economic stimulus legislation since 2008, and tax repair technical guidance and regulations released in 2013, we currently project to utilize these NOL carryforwards primarily in the 2015 through 2018 period. Beginning with 2018, we also expect to start using more than $213 million of AMT carry-forward to limit future cash tax payments for federal income taxes to the level of AMT. We currently project minimal cash tax payments over the next five years.
The utilization of the NOL and AMT carryforwards are dependent on the generation of sufficient taxable income in future periods.
For more information on our income taxes, including a reconciliation between the statutory federal income tax rate and the effective tax rate, see Note 4 to the TECO Energy Consolidated Financial Statements.
LIQUIDITY, CAPITAL RESOURCES The table below sets forth the Dec. 31, 2013 consolidated liquidity and cash balances, the cash balances at the operating companies and TECO Energy parent, and amounts available under the TECO Energy/Finance and TEC credit facilities.
Balances as of Dec. 31, 2013 Tampa Electric Unregulated (millions) Consolidated Company Companies Parent Credit facilities $ 675.0 $ 475.0 $ - $ 200.0 Drawn amounts/LCs 84.7 84.7 - - Available credit facilities 590.3 390.3 - 200.0 Cash and short-term investments 185.2 9.8 3.6 171.8 Total liquidity $ 775.5 $ 400.1 $ 3.6 $ 371.8 In 2013, we met our cash needs primarily from internal sources. Cash from operations was $659 million. We paid dividends of $191 million in 2013, and capital expenditures were $532 million. We reduced long-term debt by $52 million, which represents Tampa Electric's purchase in lieu of redemption of HCIDA Pollution Control Revenue Refunding Bonds. TEC supplemented its cash needs in 2013 with moderate use of its credit facility under which $85 million was drawn at year end.
In 2012, we also met our cash needs primarily from internal sources. Cash from operations was $757 million. We paid dividends of $190 million in 2012, and capital expenditures were $505 million. Other sources of cash included $194 million of net sale proceeds, primarily from the sale of our ownership interest in TECO Guatemala (see Discontinued Operations). We reduced long-term debt by $101 million, which included the retirement of $34 million of San José project debt with its sale, $9 million of TECO Energy parent debt and the net effect of TEC refinancing activities. There was no short-term debt outstanding at year-end 2012.
Cash from Operations In 2013, consolidated cash flow from operations was $659 million. The lower cash from operations in 2013 was primarily the result of lower operating results from TECO Coal and the absence of operating cash flows from TECO Guatemala, which was sold at the end of 2012. The 2013 cash from operations reflects pension contributions of $40 million. In 2012, consolidated cash flow from operations was $757 million. Although the timing of recoveries, particularly fuel and purchased power, under FPSC-approved cost-recovery clauses can have a significant impact on cash from operations in any one year, in 2012 the net impact was only $9 million. We had anticipated a more significant impact as the 2012 FPSC-approved clause rates provided for refunds of previous over-recoveries; however, lower than expected actual fuel prices resulted in a net over-recovered balance at the end of 2012. The 2012 cash from operations reflects pension contributions of $37 million.
We made minimal cash payments for state and federal income taxes in 2013 (see the Income Taxes section). Bonus depreciation, enacted under economic stimulus legislation annually since 2008, has significantly reduced federal taxable income at Tampa Electric and PGS. We file a consolidated tax return, and under our tax sharing agreements, each subsidiary's tax payment is determined on a standalone basis. Significant NOL carryforwards are available at TECO Energy parent that can be used to offset taxable income in the consolidated return such that cash payments for federal income taxes are limited to approximately 10% of the AMT rate. During the period of bonus depreciation, taxable income has been reduced significantly by the bonus deductions, and as a result we have utilized our NOL carryforwards less than expected in recent years. TECO Energy parent cash flows have therefore been less than expected through this period, and our projections for the full utilization of the NOL carryforwards has been extended to 2018. Tampa Electric and PGS have realized higher cash flows in recent years as a result of reduced taxes from bonus depreciation, which has supported their capital spending programs. While 2014 will be the final year available for bonus depreciation deductions, we expect that Tampa Electric and PGS will continue to realize significant cash tax savings as a result of the IRS technical guidance on repair deduction for generation activities and Tangible Capitalization Regulations issued in 2013, and that TECO Energy parent will realize the cash benefit of the NOL carryforwards primarily in the 2015 through 2018 period.
We expect cash from operations to increase in 2014, driven by higher operating results primarily at Tampa Electric, net of somewhat lower net recoveries under various regulatory clauses. In November 2013, the FPSC approved fuel-adjustment and other recovery clause rates that provide for refunds to customers of estimated 2013 net over-recoveries of fuel and purchased power over 12 months beginning Jan. 1, 2014 (see the Regulation section).
54-------------------------------------------------------------------------------- Table of Contents Cash from Investing Activities Our investing activities in 2013 resulted in a net use of cash of $522 million, which reflects capital expenditures totaling $532 million.
We expect capital spending for the next several years to be above 2013 levels, primarily due to generating capacity additions at Tampa Electric (see the Capital Expenditures section).
Cash from Financing Activities Our financing activities in 2013 resulted in a net use of cash of $152 million.
Tampa Electric purchased in lieu of redemption $52 million of HCIDA Pollution Control Revenue Refunding Bonds (see the Financing Activity section) and borrowed $84 million under its credit facility. We paid $191 million in common stock dividends, and we received $7 million from exercises of stock options.
Financing Activities Related to the NMGC Acquisition In 2014, we expect to finance the acquisition of NMGC with a mix of cash on hand at TECO Energy parent, the issuance of $350 to $400 million of TECO Energy common stock, and the issuance of $50 million of debt at the NMGC level and $200 million of debt at the NMGI level primarily to repay existing debt upon closing.
We expect to issue the debt and issue the new shares close to the time of closing the transaction, which is expected in the third quarter of 2014; however the terms and conditions of the financing transactions are unknown at this time.
Credit Facility Related to NMGC In connection with the pending acquisition of NMGC, on Dec. 17, 2013, TECO Energy entered into a $125 million bank credit facility (the "NMGC Credit Agreement"). TECO Energy has no rights or obligations to borrow under the NMGC Credit Agreement, which it has entered into solely with the intent of it being assigned to, and assumed by, NMGC upon the closing of the acquisition. Pursuant to the terms of the NMGC Credit Agreement, upon such closing, TECO Energy will designate NMGC as the borrower under the NMGC Credit Agreement and TECO Energy's obligations under the terms of the NMGC Credit Agreement will terminate (see Note 22 to the TECO Energy Consolidated Financial Statements).
TECO Finance Bridge Facility Related to NMGC In June 2013, TECO Energy and TECO Finance entered into a $1.075 billion Senior Unsecured Bridge Credit Agreement (Bridge Facility). The Bridge facility is sized to cover the $950 million purchase price and provide a $125 million credit facility for the operations of NMGC (see Note 22 to the TECO Energy Consolidated Financial Statements).
Cash and Liquidity Outlook In general, we target consolidated liquidity (unrestricted cash on hand plus undrawn credit facilities) of at least $500 million. At Dec. 31, 2013, our consolidated liquidity was $775 million, consisting of $400 million at TEC, $372 million at TECO Energy parent, and $4 million at the other companies.
We expect our sources of cash in 2014 to include cash from operations at levels above 2013, due in large part to higher net income from the regulated Florida operating companies, and long-term debt issuance of $250 - $300 million at TEC.
We plan to use cash in 2014 to fund capital spending estimated at $720 million, to pay dividends to shareholders, and the repayment of $83 million of maturing Tampa Electric debt.
We expect to continue to make equity contributions to TEC in 2014 in order to support the utilities capital structure and financial integrity. TEC expects to fund its capital needs with a combination of internally generated cash and equity contributions from us, and we anticipate that these contributions will total $150 million in 2014.
Our goal is to reduce leverage at TECO Finance over time as we are able to utilize our NOL carryforwards and as the equity needs of Tampa Electric normalize after the peak capital spending expected over the next several years during the Polk combined cycle conversion project (see the Capital Expenditures section). Our long-term debt maturities for TECO Finance total $191 million in 2015, $250 million in 2016, $300 million in 2017 and $300 million in 2020.
TEC expects to utilize cash from operations and equity contributions from TECO Energy to support its capital spending program, supplemented with incremental long-term debt and utilization of its credit facilities to maintain strong utility capital structures. Our credit facilities contain certain financial covenants (see Covenants in Financing Agreements section). Although we expect the normal utilization of our credit facilities to be low, we estimate that we could fully utilize the total available capacity under our facilities in 2014 and remain within the covenant restrictions.
Our expected cash flow could be affected by variables discussed in the individual operating company sections, such as customer growth, weather and usage changes at our regulated businesses, and coal margins. In addition, actual fuel and other regulatory clause net recoveries will typically vary from those forecasted; however, the differences are generally recovered within the next calendar year. It is possible however, that unforeseen cash requirements and/or shortfalls, or higher capital spending requirements could cause us to fall short of our liquidity target (see the Risk Factors section).
As a result of our significant reduction of parent debt, and reduced business risk, we have improved our debt credit ratings in recent years (see Credit Ratings section). In the unlikely event TEC's ratings were downgraded to below investment grade, counterparties to our derivative instruments could request immediate payment or full collateralization of net liability positions. If the credit risk- 55 -------------------------------------------------------------------------------- Table of Contents related contingent features underlying these derivative instruments were triggered as of Dec. 31, 2013, we could have been required to post additional collateral or settle existing positions with counterparties totaling $0.1 million. In addition, credit provisions in long-term gas transportation agreements of Tampa Electric and PGS would give the transportation providers the right to demand collateral, which we estimate to be approximately $63.7 million.
None of our credit facilities or financing agreements have ratings downgrade covenants that would require immediate repayment or collateralization.
SHORT-TERM BORROWING Credit Facilities At Dec. 31, 2013 and 2012, the following credit facilities and related borrowings existed: Dec. 31, 2013 Dec. 31, 2012 Letters of Letters of Credit Borrowings Credit Credit Borrowings Credit (millions) Facilities Outstanding(1) Outstanding Facilities Outstanding(1) Outstanding Tampa Electric Company: 5-year facility(2) $ 325.0 $ 6.0 $ 0.7 $ 325.0 $ - $ 1.5 1-year accounts receivable facility 150.0 78.0 - 150.0 - - TECO Energy/TECO Finance : 5-year facility(2)(3) 200.0 - - 200.0 - - Total $ 675.0 $ 84.0 $ 0.7 $ 675.0 $ - $ 1.5 (1) Borrowings outstanding are reported as notes payable.
(2) This 5-year facility matures Dec. 17, 2018.
(3) TECO Finance is the borrower and TECO Energy is the guarantor of this facility.
These credit facilities require commitment fees ranging from 12.5 to 25.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Dec. 31, 2013 was 0.56%. There were no outstanding borrowings as Dec. 31, 2012.
At Dec. 31, 2013, TECO Finance had a $200 million bank credit facility in place guaranteed by TECO Energy with a maturity date in December 2018. TEC had a bank credit facility totaling $325 million, also maturing in December 2018. In addition, TEC had a $150 million accounts receivable securitized borrowing facility that was renewed in February 2014 with a maturity date of Feb. 13, 2015. The TECO Finance and TEC bank credit facilities both include sub-limits for letters of credit of $200 million. At Dec. 31, 2013, the TECO Finance credit facility was undrawn and no letters of credit were outstanding. At Dec. 31, 2013, the outstanding borrowings under the TEC credit facilities were $84 million and $0.7 million of letters of credit were outstanding.
The table below sets forth TECO Finance and TEC maximum, minimum, and average credit facility utilization in 2013.
2013 Credit Facility Utilization Maximum Minimum Average Average drawn drawn drawn interest (millions) amount amount amount rate TECO Finance $ - $ - $ - - Tampa Electric Company $ 84.0 $ - $ 5.4 0.59 % 56 -------------------------------------------------------------------------------- Table of Contents Significant Financial Covenants In order to utilize their respective bank credit facilities, TECO Energy, TECO Finance and TEC must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy, TECO Finance, TEC, and the other operating companies have certain restrictive covenants in specific agreements and debt instruments. At Dec. 31, 2013, TECO Energy, TECO Finance, TEC and the other operating companies were in compliance with all applicable financial covenants.
The table that follows lists the significant financial covenants and the performance relative to them at Dec. 31, 2013. Reference is made to the specific agreements and instruments for more details.
(millions, unless otherwise indicated) Calculation at Dec. 31, Instrument Financial Covenant(1) Requirement/Restriction 2013 Tampa Electric Company Credit facility(2) Debt/capital Cannot exceed 65% 45.7% Accounts receivable Debt/capital Cannot exceed 65% 45.7% credit facility(2) 6.25% senior notes 45.7% Debt/capital Cannot exceed 60% $0 liens Limit on liens(3) Cannot exceed $700 outstanding Insurance agreement relating to certain pollution Cannot exceed $483 (7.5% $0 liens bonds Limit on liens(3) of net assets) outstanding TECO Energy/TECO Finance Credit facility(2) Debt/capital Cannot exceed 65% 56.2% TECO Finance 6.75% Restrictions on notes secured debt(4) (5) (5) (1) As defined in each applicable instrument.
(2) See Note 6 to the TECO Energy Consolidated Financial Statements for a description of the credit facilities.
(3) If the limitation on liens is exceeded the company is required to provide ratable security to the holders of these notes.
(4) These restrictions would not apply to first mortgage bonds of Tampa electric if any were outstanding.
(5) The indentures for these notes contain restrictions which limit secured debt of TECO Energy if secured by principal property or capital stock or indebtedness of directly held subsidiaries (with exceptions as defined in the indentures) without equally and ratably securing these notes. At Dec. 31, 2013 neither TECO Energy nor TECO Finance had secured debt outstanding.
Credit Ratings of Senior Unsecured Debt Standard & Poor's (S&P) Moody's Fitch Tampa Electric Company BBB+ A2 A- TECO Energy/TECO Finance BBB Baa1 BBB On Jan. 30, 2014, Moody's upgraded the credit ratings of TECO Energy, TECO Finance and TEC. TECO Energy and TECO Finance senior unsecured debt is rated Baa1, up from Baa2, and TEC's senior unsecured debt is rated A2, up from A3, all with stable outlooks.
On May 30, 2013, Fitch placed the rating of TECO Energy, TECO Finance and TEC on ratings watch negative following the announcement of our agreement to purchase NMGC. On Oct. 9, 2013, Fitch removed TEC from ratings watch negative and affirmed its ratings. S&P, Moody's and Fitch describe credit ratings in the BBB or Baa category as representing adequate capacity for payment of financial obligations. The lowest investment grade credit ratings for S&P is BBB-, for Moody's is Baa3 and for Fitch is BBB-; thus, all three credit rating agencies assign TECO Energy, TECO Finance and TEC's senior unsecured debt investment-grade credit ratings.
A credit rating agency rating is not a recommendation to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Our access to capital markets and cost of financing, including the applicability of restrictive financial covenants, are influenced by the ratings of our securities. In addition, certain of TEC's derivative instruments contain provisions that require TEC's debt to maintain investment grade credit ratings (see Note 12 to the TECO Energy Consolidated Financial Statements). The credit ratings listed above are included in this report in order to provide information that may be relevant to these matters and because downgrades, if any, in credit ratings may affect our ability to borrow and may increase financing costs, which may decrease earnings (see the Risk Factors section). These credit ratings are not necessarily applicable to any particular security that we may offer and therefore should not be relied upon for making a decision to buy, sell or hold any of our securities.
57-------------------------------------------------------------------------------- Table of Contents Summary of Contractual Obligations The following table lists the obligations of TECO Energy and its subsidiaries for cash payments to repay debt, lease payments and unconditional commitments related to capital expenditures. This table does not include contingent obligations, which are discussed in a subsequent table.
Contractual Cash Obligations at Dec. 31, 2013 (millions) Payments Due by Period Total 2014 2015 2016 2017-2018 After 2018 Long-term debt (1) $ 2,923.9 $ 83.3 $ 274.5 $ 333.3 $ 604.2 $ 1,628.6 Operating leases/rentals/capacity payments 93.8 19.8 18.8 17.2 24.6 13.4 Net purchase obligations/commitments (2) (3) 412.0 245.6 91.9 30.3 29.0 15.2 Interest payment obligations 1,581.1 155.0 143.3 126.7 209.3 946.8 Pension plan (4) 131.9 34.2 47.7 23.4 13.2 - Total contractual obligations $ 5,142.7 $ 537.9 $ 558.7 $ 540.4 $ 901.7 $ 2,604.0 (1) Includes debt at TECO Finance, Tampa Electric, and PGS (see Note 7 to the TECO Energy Consolidated Financial Statements for a list of long-term debt and the respective due dates).
(2) The table above excludes payment obligations under contractual agreements of Tampa Electric and PGS for fuel, fuel transportation and power purchases which are recovered from customers under regulatory clauses approved by the FPSC annually (see the Regulation section).
(3) Reflects those contractual obligations and commitments considered material to the respective operating companies, individually. At the end of 2013, these commitments include Tampa Electric's outstanding commitments for major projects and long-term capitalized maintenance agreements for its combustion turbines.
(4) The total includes the estimated minimum required contributions to the qualified pension plan as of the measurement date. Future contributions are included but they are subject to annual valuation reviews, which may vary significantly due to changes in interest rates, discount rate assumptions, plan asset performance, which is affected by stock market performance, and other factors (see Liquidity, Capital Resources section and Note 5 to the TECO Energy Consolidated Financial Statements).
The following table summarizes the letters of credit and guarantees outstanding that are not included in the Contractual Cash Obligations table above and not otherwise included in our Consolidated Financial Statements.
Contingent Obligations at Dec. 31, 2013 (millions) Commitment Expiration After Total(2) 2014 2015 2016 2017 - 2018 2018(1)Letters of credit $ 0.7 $ - $ - $ - $ - $ 0.7 Guarantees Fuel purchase/energy management (2) Fuel sales and transportation Other 101.8 10.0 - - - 91.8 5.5 0.8 0.7 - - 4.0 5.0 - 5.0 - - - Total contingent obligations $ 113.0 $ 10.8 $ 5.7 $ - $ - $ 96.5 (1) These guarantees renew annually and are shown on the basis that they will continue to renew beyond 2018.
(2) The amounts shown are the maximum theoretical amounts guaranteed under current agreements.
58 -------------------------------------------------------------------------------- Table of Contents CAPITAL INVESTMENTS Forecast 2014 - 2018 (millions) Actual 2013 2014 2015 2016-2018 Total Tampa Electric Transmission $ 30 $ 35 $ 20 $ 85 $ 140 Distribution 115 115 110 355 580 Generation 155 140 125 390 655 New generation and transmission 55 200 245 95 540 Other 30 45 40 75 160 Other environmental 40 65 20 40 125 Tampa Electric total 425 600 560 1,040 2,200 Net cash effect of accruals, retentions and AFUDC 5 - - - - Tampa Electric net 430 600 560 1,040 2,200 Peoples Gas 80 100 100 295 495 Unregulated companies 20 20 25 100 145 Total $ 530 $ 720 $ 685 $ 1,435 $ 2,840 (1) Individual line items exclude AFUDC-debt and equity; however total AFUDC is a reconciling item in 2013.
TECO Energy's 2013 capital expenditures of $530 million included $425 million at Tampa Electric, including AFUDC debt and equity. Tampa Electric's capital expenditures in 2013 included $28 million for a reclaimed water pipeline to serve the Polk Power Station, approximately $40 million to improve the Big Bend Station solid fuel handling and flue gas desulphurization systems reliability, for equipment and facilities to meet modest customer growth, generating equipment maintenance, and environmental compliance. Capital expenditures for PGS were approximately $80 million, including approximately $28 million for maintenance of the existing system, $36 million to expand the system and support customer growth, and $13 million for replacement of cast iron and bare steel pipe. TECO Coal's capital expenditures included $20 million primarily for normal mining equipment replacement, and the development of new mines to support continued production.
TECO Energy estimates capital spending to be $720 million for 2014 and approximately $2.1 billion during the 2015 to 2018 period. As described below, this forecast includes $540 million for Tampa Electric's next increment of generation expansion, including transmission system improvements to support the increased plant output.
For 2014, Tampa Electric expects to spend $600 million. For the transmission and distribution systems, Tampa Electric expects to spend $150 million in 2014, including approximately $110 million for normal transmission and distribution system expansion and reliability, and approximately $40 million for transmission and distribution system storm hardening. Capital expenditures for the existing generating facilities of $140 million include approximately $20 million for repair and refurbishments of CTs under long-term agreements with equipment manufacturers, approximately $100 million for generating unit outages in 2014 and advance purchases for 2015 unit outages, $10 million for a reclaimed water pipeline to eliminate ground water usage at the Polk Power Station, and $10 million for the conversion of distillate oil igniters to natural gas. In addition, Tampa Electric expects to spend $65 million for environmental compliance programs and improvements to environmental control equipment in 2014 including approximately $45 million to improve the Big Bend Station solid fuel handling system reliability.
In the 2015 to 2018 period, Tampa Electric expects to spend approximately $315 million annually to support normal system growth and reliability, environmental compliance and improvements to computer systems to serve customers. This level of ongoing capital expenditures reflects the costs for materials and contractors, long-term regulatory requirements for storm hardening, and an active program of transmission and distribution system upgrades which will occur over the forecast period. These programs and requirements include: approximately $20 million annually for repair and refurbishments of CTs under long-term agreements with equipment manufacturers, average annual expenditures of almost $110 million to support generating unit availability and reliability; average annual expenditures of $15 million for environmental compliance; average annual expenditures of more than $30 million for general infrastructure and facilities; average annual expenditures of approximately $25 million for transmission and distribution system storm hardening; approximately $115 million annually for transmission and distribution system capacity improvements to meet expected customer growth and reliability.
Tampa Electric's forecast for capital spending does not include amounts that may be spent on projects that would result in the generation of additional revenues.
Spending on any projects would be justified by an economic analysis that demonstrates a net benefit.
Tampa Electric's capital spending forecast includes amounts related to the conversion of the Polk Units 2 - 5 from peaking service to combined cycle with a January 2017 in-service date. The determination of need was approved by the FPSC in December 2012, the final site certification approval by the FDEP was received in the fourth quarter of 2013, and the final air emissions permits were received in January 2014. Construction commenced in January 2014. The capital expenditures for the conversion and the related transmission system improvements to support the additional generating capacity are included in the "New generation and transmission" line in the Capital Investments table above. The peak capital spending is forecast at $445 million for both the transmission system and plant conversions in the 2014 and 2015 periods.
59-------------------------------------------------------------------------------- Table of Contents Capital expenditures for PGS are expected to be about $100 million in 2014 and $395 million during the 2015 to 2018 period. Included in these amounts is an average of approximately $50 million annually for projects associated with customer growth and system expansion. The remainder represents capital expenditures for ongoing renewal, replacement and system safety, including approximately $12 million annually for the replacement of cast iron and bare steel pipe, which is recovered through a rider clause approved by the FPSC in 2012 (see the Regulation section).
At PGS, higher capital expenditures are focused on extending the system to serve large commercial or industrial customers that are currently using petroleum and propane as fuel under multi-year contracts. The current natural gas prices and the projections that natural gas prices are going to remain low into the future makes it attractive for these customers to convert from fuels that are currently three to four times more expensive on a cost per MMBTU basis.
The unregulated companies expect to invest $20 million in 2014, primarily for normal mining equipment replacement at TECO Coal. The unregulated companies expect to spend $125 million during the 2015 - 2018 period, primarily for coal mine development to maintain production, compliance with new safety requirements under the MINER Act, and for normal coal mining equipment renewal and replacement at TECO Coal.
The capital expenditure forecast beyond 2014 does not include additional investment to develop the metallurgical coal reserves that TECO Coal announced in November 2011. Based on current market conditions, TECO Coal does not expect to make additional investments to develop these reserves until metallurgical coal prices improve to a level to support that investment. In 2012, TECO Coal obtained the necessary permit amendments from the state of Kentucky related to surface development activities to access these reserves, and further evaluated detailed mining plans and potential markets for this high-volatile metallurgical coal. TECO Coal completed utility relocation and preliminary surface work to bring these reserves into production. Based on previous estimates, subject to development of final plans, the cost to develop these reserves is estimated to be approximately $160 million over approximately a three year period.
If the U.S. Congress or the Florida Legislature enacted a national or Florida RPS, additional capital spending for renewable generating resources to meet the requirements of an RPS would likely be needed (see the Environmental Compliance section). Depending on the final federal or state rules, Tampa Electric may need to invest capital to develop additional sources of renewable power generation.
The forecast of capital expenditures shown above is based on our current estimates and assumptions for normal maintenance capital at the operating companies; capital expenditures to support normal system reliability and growth at Tampa Electric and PGS; the replacement of cast iron and bare steel pipe at PGS; the programs for transmission and distribution system storm hardening and transmission system reliability requirements; generating capacity expansion at Tampa Electric and incremental investments above normal maintenance capital to expand the PGS system and production capacity at TECO Coal. Actual capital expenditures could vary materially from these estimates due to changes in costs for materials or labor or changes in plans (see the Risk Factors section).
Financing Activity Our year-end 2013 consolidated capital structure was 56% debt and 44% common equity. The debt-to-total-capital ratio has improved significantly over the past six years, primarily due to the repayment of more than $1.0 billion of parent and parent guaranteed debt, consisting of $779 million in 2007, a net $189 million in 2010, $64 million in 2011, and $9 million in 2012, as well as the increase in retained earnings. At Dec. 31, 2013, Tampa Electric's year-end capital structure was 45% debt and 55% common equity.
In 2013 and 2012, we raised $6.7 million and $3.9 million, respectively, of equity, primarily through the exercise of stock options.
On Sept. 3, 2013, Tampa Electric purchased in lieu of redemption $51.6 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 B (the Series 2007 B HCIDA Bonds). On Mar. 26, 2008, the HCIDA had remarketed the Series 2007 B HCIDA Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The Series 2007 B HCIDA Bonds bore interest at a term rate of 5.15% per annum from March 26, 2008 to Sept. 1, 2013. Tampa Electric is responsible for payment of the interest and principal associated with the Series 2007 B HCIDA Bonds.
On Dec. 5, 2012, TECO Energy redeemed $8.8 million of 6.75% Notes due May 15, 2015. The redemption price was equal to $1,141.86 per $1,000 principal amount of notes redeemed, plus accrued and unpaid interest on the redeemed notes up to the redemption date. In connection with this transaction, $0.8 million of premiums were expensed, and are included in "Loss on debt extinguishment" on the Consolidated Statements of Income and as part of the "Cash flows from operating activities" in the Consolidated Statements of Cash Flows for 2012.
On Oct. 1, 2012, Tampa Electric redeemed $147.1 million of HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Project), Series 2002 due Oct.
1, 2013 and Oct. 1, 2023 (2002 Bonds) at a redemption price equal to 100% of the principal amount of the 2002 Bonds to be redeemed, plus accrued and unpaid interest to Oct. 1, 2012. Before the optional redemption, the $60.7 million of 2002 Bonds due Oct. 1, 2013 bore interest at 5.10% and the $86.4 million of 2002 Bonds due Oct. 1, 2023 bore interest at 5.50%.
On Sept. 28, 2012, TEC completed an offering of $250 million aggregate principal amount of 2.60% Notes due 2022. The 2.60% Notes were sold at 99.878% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts and commissions and estimated offering expenses) of approximately $247.7 million. Net proceeds were used to repay the 2002 Bonds. The remaining net proceeds were used to repay short-term debt and for general corporate purposes.
At any time prior to June 15, 2022, TEC may redeem all or any part of the 2.60% Notes at its option at a redemption price equal to the greater of (i) 100% of the principal amount of 2.60% Notes to be redeemed or (ii) the sum of the present values of the remaining payments of principal and 60-------------------------------------------------------------------------------- Table of Contents interest on the 2.60% Notes to be redeemed, discounted to the redemption date on a semiannual basis at an applicable treasury rate, plus 15 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after June 15, 2022, TEC may at its option redeem the 2.60% Notes, in whole or in part, at 100% of the principal amount of the 2.60% Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.
On June 5, 2012, TEC completed an offering of $300 million aggregate principal amount of 4.10% Notes due 2042. The 4.10% Notes were sold at 99.724% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, and estimated offering expenses and before settlement of interest rate swaps) of approximately $296.2 million. Net proceeds were used to repay maturing long-term debt, to repay short-term debt and for general corporate purposes. At any time prior to Dec. 15, 2041, TEC may redeem all or any part of the 4.10% Notes at its option and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of 4.10% Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the 4.10% Notes to be redeemed, discounted at an applicable treasury rate, plus 25 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Dec. 15, 2041, TEC may at its option redeem the 4.10% Notes, in whole or in part, at 100% of the principal amount of the 4.10% Notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption.
On March 15, 2012, Tampa Electric purchased in lieu of redemption $86 million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (the $86 million Bonds). On March 19, 2008, the HCIDA remarketed the $86 million Bonds in a term-rate mode pursuant to the terms of the Loan and Trust Agreement governing those bonds. The $86 million Bonds bore interest at a term rate of 5.00% per annum from March 19, 2008 to March 15, 2012. Tampa Electric is responsible for payment of the interest and principal associated with the $86 million Bonds. Regularly scheduled principal and interest payments, when due, are insured by Ambac Assurance Corporation.
On Sept. 27, 2012, TECO Energy announced that its international power subsidiary, TECO Guatemala, entered into agreements to sell all of the equity interests in the Alborada and San José power stations and related facilities and operations in Guatemala. The sale of the Alborada Power Station closed on Sept.
27, 2012, for a selling price of $12.5 million. The sale of the San José Power Station and related facilities and operations in Guatemala closed on Dec. 19, 2012 for a price of $215.0 million. TECO Energy utilized $25.3 million of the proceeds to repay the San José Power Station project debt at closing (see Discontinued Operations section and Note 19 to the TECO Energy Consolidated Financial Statements).
CRITICAL ACCOUNTING POLICIES AND ESTIMATES The preparation of consolidated financial statements requires management to make various estimates and assumptions that affect revenues, expenses, assets, liabilities, and the disclosure of contingencies. The policies and estimates identified below are, in the view of management, the more significant accounting policies and estimates used in the preparation of our consolidated financial statements. These estimates and assumptions are based on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and judgments under different assumptions or conditions. See Note 1 to the TECO Energy Consolidated Financial Statements for a description of our significant accounting policies and the estimates and assumptions used in the preparation of the consolidated financial statements.
Deferred Income Taxes We use the asset and liability method in the measurement of deferred income taxes. Under the asset and liability method, we estimate our current tax exposure and assess the temporary differences resulting from differing treatment of items, such as depreciation, for financial statement and tax purposes. These differences are reported as deferred taxes measured at current rates in the consolidated financial statements. Management reviews all reasonably available current and historical information, including forward-looking information, to determine if it is more likely than not that some or the entire deferred tax asset will not be realized. If we determine that it is likely that some or all of a deferred tax asset will not be realized, then a valuation allowance is recorded to report the balance at the amount expected to be realized.
At Dec. 31, 2013, we had a net deferred income tax liability of $343.7 million, attributable primarily to property-related items, AMT credit carry forwards and operating loss carry forwards. Based primarily on historical income levels and the company's expectations for steady future earnings growth, management has determined that the deferred tax assets associated with operating losses and AMT credit carryforwards recorded at Dec. 31, 2013, will be realized in future periods.
We believe that the accounting estimate related to deferred income taxes, and any related valuation allowance, is a critical estimate for the following reasons: 1) realization of the deferred tax asset is dependent upon the generation of sufficient taxable income, both operating and capital, in future periods; 2) a change in the estimated valuation reserves could have a material impact on reported assets and results of operations; and 3) administrative actions of the IRS or the U.S. Treasury or changes in law or regulation could change our deferred tax levels, including the potential for elimination or reduction of our ability to utilize the deferred tax assets.
The FASB has guidance that prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return, and also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. See further discussion of uncertainty in income taxes and other tax items in Note 4 to the TECO Energy Consolidated Financial Statements.
61 -------------------------------------------------------------------------------- Table of Contents Employee Postretirement Benefits TECO Energy sponsors a defined benefit pension plan (pension plan) that covers substantially all employees. In addition, the company has an unfunded non-qualified, non-contributory supplemental executive retirement benefit plan available to certain members of senior management. Several statistical and other factors, which attempt to anticipate future events, are used in calculating the expense and liability related to these plans. Key factors include assumptions about the expected rates of return on plan assets, salary increases and discount rates. These factors are determined by the company within certain guidelines and with the help of external consultants. The company considers market conditions, including changes in investment returns and interest rates, in making these assumptions.
The company believes that the accounting related to employee postretirement benefits is a critical accounting estimate for the following reasons: 1) a change in the estimated benefit obligation could have a material impact on reported assets, AOCI and results of operations; and 2) changes in assumptions could change the annual pension funding requirements, having a significant impact on the company's annual cash requirements.
Pension plan assets (plan assets) are invested in a mix of equity and fixed-income securities. The expected return on assets assumption was based on expectations of long-term inflation, real growth in the economy, fixed income spreads and equity premiums consistent with the company's portfolio, with provision for active management and expenses paid from the trust. The discount rate assumption used to determine the 2013 benefit expense and Dec. 31, 2013, benefit obligation was based on a cash flow matching technique developed by the company's outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement dates to meet the plan's year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate. The compensation increase assumption was based on the same underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases. Holding all other assumptions constant, a 1% decrease in the assumed rate of return on plan assets would have increased 2013 after-tax pension cost by approximately $3.1 million. Likewise, a 1% decrease in the discount rate assumption would have increased 2013 after-tax pension cost approximately $2.8 million. For 2014, a 1% decrease in the discount rate assumption would result in an approximately $1.6 million after-tax increase in the expected pension cost. A 1% decrease in the assumed rate of return on plan assets would result in an approximately $3.5 million after-tax increase in expected pension cost.
Unrecognized actuarial gains and losses for the pension plan are being recognized over a period of approximately 12 years, which represents the expected remaining service life of the employee group. Unrecognized actuarial gains and losses arise from several factors including experience and assumption changes in the obligations and from the difference between expected return and actual returns on plan assets. These unrecognized gains and losses will be systematically recognized in future net periodic pension expense in accordance with applicable accounting guidance for pensions. The company's policy is to fund the plan based on the required contribution determined by its actuaries within the guidelines set by the ERISA, as amended.
In July 2012, the president signed into law the MAP-21. MAP-21 provides funding relief for pension plan sponsors by stabilizing discount rates used in calculating the required minimum pension contributions and increasing PBGC premium rates to be paid by plan sponsors. The company expects the required minimum pension contributions to be lower than the levels previously projected; however, the company plans on funding at levels above the required minimum pension contributions under MAP-21.
In addition, the company currently provides certain postretirement health care and life insurance benefits for substantially all employees retiring after age 50 who meet certain service requirements. In March 2010, the Patient Protection and Affordable Care Act and a companion bill, the Health Care and Education Reconciliation Act, combined the Health Care Reform Acts, were signed into law.
Among other things, both acts reduce the tax benefits available to an employer that receives the Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TECO Energy reduced its deferred tax asset by recording a corresponding charge and a regulatory tax asset in the first quarter of 2010 and recorded a true-up of the deferred tax asset in the fourth quarter of 2012. The company implemented an EGWP for its post-65 retiree prescription drug plan effective Jan. 1, 2013. The EGWP is a private Medicare Part D plan designed to provide benefits that are at least equivalent to Medicare Part D. The EGWP reduces net periodic benefit cost by taking advantage of rebate and discount enhancements provided under the Health Care Reform Acts.
As a result, the company no longer receives Medicare Part D subsidy payments beginning with the 2013 plan year.
The Health Care Reform Acts contain other provisions that may impact TECO Energy's obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. TECO Energy does not currently believe the excise tax or other provisions of the Health Care Reform Acts will materially increase its postretirement benefit obligation. TECO Energy will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position.
The key assumptions used in determining the amount of obligation and expense recorded for postretirement benefits other than pension (OPEB), under the applicable accounting guidance, include the assumed discount rate and the assumed rate of increases in future health care costs. Since 2009 the company has determined the discount rate for the OPEB using that individual plan's projected benefit cash flow rather than using the same discount rate that was determined for the pension plan. In estimating the health care cost trend rate, the company considers its actual health care cost experience, future benefit structures, industry trends, and advice from its outside actuaries. The company assumes that the relative increase in health care cost will trend downward over the next several years, reflecting assumed increases in efficiency in the health care system and industry wide cost-containment initiatives.
62-------------------------------------------------------------------------------- Table of Contents The assumed health care cost trend rate for medical costs was 7.50% in 2013 and decreases to 4.50% in 2025 and thereafter. A 1% increase in the health care trend rates would have produced a $0.2 million after-tax increase in the aggregate service and interest cost for 2013, and a $6.8 million increase in the accumulated postretirement benefit obligation as of Dec. 31, 2013.
The actuarial assumptions used in determining the company's pension and OPEB retirement benefits may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, or longer or shorter life spans of participants. While the company believes that the assumptions used are appropriate, differences in actual experience or changes in assumptions may materially affect the company's financial position or results of operations.
See the discussion of employee postretirement benefits in Note 5 to the TECO Energy Consolidated Financial Statements.
Evaluation of Assets for Impairment In accordance with accounting guidance for long-lived assets, the company assesses whether there has been an impairment of its long-lived assets and certain intangibles held and used when such indicators exist. The company normally reviews all long-lived assets in the last quarter of each year to ensure that any gradual change over the year and the seasonality of the markets are considered when determining which assets require an impairment analysis.
However, in the case of a triggering event, such as a significant market disruption or sale of a business, the values of related long-lived assets are reviewed. We believe the accounting estimates related to asset impairments are critical estimates for the following reasons: 1) the estimates are highly susceptible to change, as management is required to make assumptions based on expectations of the results of operations for significant/indefinite future periods and/or the then current market conditions in such periods; 2) markets can experience significant uncertainties; 3) the estimates are based on the ongoing expectations of management regarding probable future uses and holding periods of assets; and 4) the impact of an impairment on reported assets and earnings could be material. The company's assumptions relating to future results of operations or other recoverable amounts are based on a combination of historical experience, fundamental economic analysis, observable market activity and independent market studies. Our expectations regarding uses and holding periods of assets are based on internal long-term budgets and projections, which give consideration to external factors and market forces, as of the end of each reporting period. The assumptions made are consistent with generally accepted industry approaches and assumptions used for valuation and pricing activities.
See Note 20 to the TECO Energy Consolidated Financial Statements for discussion of the company's treatment of impairment of long-lived assets for the year ended Dec. 31, 2013.
Regulatory Accounting Tampa Electric's and PGS's retail businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric's wholesale business is regulated by the FERC. As a result, the regulated utilities qualify for the application of accounting guidance for certain types of regulation. This guidance recognizes that the actions of a regulator can provide reasonable assurance of the existence of an asset or liability. Regulatory assets and liabilities arise as a result of a difference between GAAP and the accounting principles imposed by the regulatory authorities. Regulatory assets generally represent incurred costs that have been deferred, as their future recovery in customer rates is probable.
Regulatory liabilities generally represent obligations to make refunds to customers from previous collections for costs that are not likely to be incurred.
As a result of regulatory treatment and corresponding accounting treatment, we expect that the impact on utility costs and required investment associated with future changes in environmental regulations would create regulatory assets.
Current regulation in Florida allows utility companies to recover from customers prudently incurred costs (including, for required capital investments, depreciation and a return on invested capital) for compliance with new environmental regulations through the ECRC (see the Environmental Compliance and Regulation sections).
We periodically assess the probability of recovery of the regulatory assets by considering factors such as regulatory environment changes, recent rate orders to other regulated entities in the same jurisdiction, the current political climate in the state, and the status of any pending or potential deregulation legislation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. We believe the application of regulatory accounting guidance is a critical accounting policy since a change in these assumptions may result in a material impact on reported assets and the results of operations (see the Regulation section and Notes 1 and 3 to the TECO Energy Consolidated Financial Statements).
RECENTLY ISSUED ACCOUNTING STANDARDS Unrecognized Tax Benefits In July 2013, the FASB issued guidance regarding the presentation of unrecognized tax benefits in the statement of position when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. It requires that an unrecognized tax benefit be presented as a reduction to a deferred tax asset for net operating loss carryforwards, similar tax losses or tax credit carryforwards, with certain exceptions. The guidance is effective for interim and annual reporting periods beginning on or after Dec. 15, 2013. The guidance will have no effect on the company's results of operations, financial position or cash flows.
63 -------------------------------------------------------------------------------- Table of Contents Comprehensive Income In February 2013, the FASB issued guidance requiring improved disclosures of significant reclassifications out of AOCI and their corresponding effect on net income. The guidance is effective for interim and annual reporting periods beginning on or after Dec. 15, 2012. The company has adopted this guidance as required. It has no effect on the company's results of operations, financial position or cash flows.
INFLATION The effects of general inflation on our results have not been significant for the past several years. The annual average rate of inflation, as measured by the CPI-U, as reported by the U.S. Department of Labor, was 1.5% in 2013 after a 1.7% increase in 2012, and a 3.0% increase in 2011. This is lower than the 2.4% average annual increase over the past ten years. This is the first time the CPI has gone up less than 2.0% for consecutive years since 1997-98.
The current economic outlook and the pace of economic recovery have caused the outlook for inflation in 2014 to be higher than in 2013, but lower than in 2011, when oil and commodity prices rose sharply. Reports published by the Federal Reserve Bank of Chicago and others indicate that CPI-U has been below desired levels and is expected to be less than 2.0% in 2014.
ENVIRONMENTAL COMPLIANCE Environmental Matters Our businesses have significant environmental considerations. Tampa Electric operates stationary sources with air emissions regulated by the Clean Air Act, and material Clean Water Act implications and impacts by federal and state legislative initiatives. TEC, through its Tampa Electric and PGS divisions, is a PRP for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites. Additionally, TECO Coal has considerations concerning wastewater management and environmental permitting.
Air Quality Control Emission Reductions Tampa Electric has undertaken major steps to dramatically reduce its air emissions through a series of voluntary actions, including technology selection (e.g., IGCC) and conversion of coal-fired units to natural-gas fired combined cycle; implementation of a responsible fuel mix taking into account price and reliability impacts to its customers; a substantial capital expenditure program to add BACT emissions controls; implementation of additional controls to accomplish early reductions of certain emissions; and enhanced controls and monitoring systems for certain pollutants.
Tampa Electric, through voluntary negotiations in 1999 with the EPA, the U.S.
Department of Justice and the FDEP, signed a Consent Decree and Consent Final Judgment, as settlement of federal and state litigation to dramatically decrease emissions from its power plants. Tampa Electric has fulfilled the obligations of the Consent Decree, and the court terminated the Consent Decree on Nov. 22, 2013. Termination of the Consent Final Judgment is in progress and is expected to be completed during the first half of 2014.
The emission reduction requirements of these agreements resulted in the repowering of the coal-fired Gannon Power Station to natural gas, which was renamed as the H. L. Culbreath Bayside Power Station (Bayside Power Station), enhanced availability of flue-gas desulfurization systems (scrubbers) at Big Bend Station to help reduce SO2, and installation of SCR systems for NOx reduction on Big Bend Units 1 through 4. Cost recovery for the SCRs began for each unit in the year that the unit entered service through the ECRC (see the Regulation section).
As a result of the actions taken under the consent decree, emissions of all pollutant types have been significantly reduced. Since 1998, Tampa Electric has reduced annual SO2, NOx and PM emissions from its facilities by 164,000 tons (94%), 63,000 tons (91%) and 4,500 tons (87%), respectively.
Reductions in mercury emissions also have occurred due to the repowering of the Gannon Power Station to the Bayside Power Station. At the Bayside Power Station, where mercury levels have decreased 99% from 1998 levels, there are virtually zero mercury emissions. Additional mercury reductions have been achieved from the installation of the SCRs at Big Bend Power Station, which have led to a system-wide reduction of mercury emissions of more than 90% from 1998 levels.
CAIR/CSAPR As a result of all its completed emission reduction actions, Tampa Electric has achieved emission reduction levels called for in Phase I and Phase II of CAIR.
In July 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated CAIR on emissions of SO2 and NOx. The federal appeals court reinstated CAIR in December 2008 as an interim solution. In July 2011, the EPA issued the final CAIR replacement rule, called the CSAPR. The final CSAPR focused on reducing SO2 and NOx in 27 eastern states that contribute to ozone and/or fine particle pollution in other states. Compliance with CSAPR, which would be measured at the individual power plant level, would require the addition of scrubbers or SCRs on most coal-fired power plants. In addition, the rule utilized intrastate emissions allowance trading and limited interstate emissions allowance trading to achieve compliance. All of Tampa Electric's conventional coal-fired units are already equipped with scrubbers and SCRs, and the Polk Unit 1 IGCC unit removes SO2 in the gasification process.
64-------------------------------------------------------------------------------- Table of Contents The EPA has estimated that the implementation of CSAPR would result in the retirement of primarily, smaller, older coal-fired power stations that do not currently have state-of-the-art air pollution control equipment already installed. The retirement of these units or switching to other fuels for compliance with this rule is likely to reduce overall demand for coal, which could reduce sales at TECO Coal.
On Dec. 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit granted the motion to stay the implementation of CSAPR in all aspects, which had been scheduled to take effect Jan. 1, 2012, and ordered the reinstatement of CAIR pending the outcome of the litigation. On Aug. 21, 2012, the court vacated the rule entirely and remanded it back to the EPA while leaving the CAIR in place. In January 2013, the Court of Appeals rejected the request for a rehearing. On June 24, 2013, the U.S. Supreme Court granted the United States' and environmental group petitions asking the Court to review the D.C. Circuit's decision. EPA has announced that it intends to propose a new rule to address Clean Air Act requirements to reduce the interstate transport of ozone by October 2014. The rule would replace parts of CSAPR, which the U.S. Court of Appeals for the District of Columbia struck down in 2012. EPA acknowledges that the proposal could be influenced by the outcome of the CSAPR appeal to the U.S.
Supreme Court.
Hazardous Air Pollutants (HAPS) Maximum Achievable Control Technology (MACT) The EPA published proposed rules under National Emission Standards for HAPS on May 3, 2011, pursuant to a court order. These rules are expected to reduce mercury, acid gases, organics, and certain non-mercury metals emissions and require MACT. The final Utility MACT rules, now called Mercury Air Toxics Standards (MATS), were published in December 2011 with implementation called for in early 2015 with extensions to early 2016 or 2017 under certain specific criteria. A potential outcome of the MATS rule is the retirement of smaller, older coal-fired power plants that do not already have emissions controls installed.
All of Tampa Electric's conventional coal-fired units are already equipped with scrubbers and SCRs, and the Polk Unit 1 IGCC unit emissions are minimized in the gasification process. Tampa Electric is uniquely positioned to be able to meet the new standards without considerable impacts, compared to others who have not taken similar early actions. Therefore, Tampa Electric expects the co-benefits of these control devices for mercury removal to minimize the impact of this rule and expects that it will be in compliance with MATS with nominal additional capital investment.
The retirement of coal-fired generating units as a result of the implementation of this rule could reduce demand for sales at TECO Coal.
Carbon Reductions and GHG Tampa Electric has historically supported voluntary efforts to reduce carbon emissions and has taken significant steps to reduce overall emissions at Tampa Electric's facilities. Since 1998, Tampa Electric has reduced its system wide emissions of CO2 by approximately 20%, bringing emissions to near 1990 levels.
Tampa Electric expects emissions of CO2 to remain near 1990 levels until the addition of the next base load unit, which is scheduled to be in service in January 2017 (see the Tampa Electric and Capital Expenditures sections). Tampa Electric estimates that the repowering to natural gas and the shut-down of the Gannon Station coal-fired units resulted in an annual decrease in CO2 emissions of approximately 4.8 million tons below 1998 levels. During this same time frame, the numbers of retail customers and retail energy sales have risen by approximately 30% and 15%, respectively.
Tampa Electric's power plants currently emit approximately 16 million tons of CO2 per year. Assuming a projected long-term average annual load growth of more than 1.0%, Tampa Electric could emit approximately 17 million tons of CO2 (an increase of approximately 6%) by 2020 if natural gas-fired peaking and combined-cycle generation additions are used to meet customer demand.
In 2010, the EPA issued its Final Rule on the mandatory reporting of GHGs, requiring facilities that emit 25,000 metric tons or more of CO2, or its equivalent, per year to begin collecting GHG data under a new reporting system on Jan. 1, 2010, with the first annual report due Sept. 28, 2011. Tampa Electric complied with the mandatory reporting requirement, in large part through the methods and procedures already utilized and continues to submit annual reports as required. The rule also required natural gas distribution, underground coal mining facilities, and electric transmission and distribution companies, including PGS, TECO Coal and Tampa Electric, that emit 25,000 metric tons or more of CO2, or its equivalent, per year to begin collecting GHG data under a new reporting system on Jan. 1, 2011, with the first annual report due Sept. 28, 2012. Tampa Electric complied with the reporting requirement and continues to submit annual reports as required.
In December 2009, the EPA published the final Endangerment Finding in the Federal Register. Although the finding was technically made in the context of GHG emissions from new motor vehicles and did not, in itself, impose any requirements on industry or other entities, EPA claims that the finding triggered GHG regulation of a variety of sources under the Clean Air Act (CAA).
Related to utility sources, the EPA's "tailoring rule," which addresses the GHG emission threshold triggers that would require permitting review of new and/or major modifications to existing stationary sources of GHG emissions, became effective Jan. 2, 2011. While this rule does not have an immediate impact on Tampa Electric's ongoing operations, GHG permitting was recently completed for Tampa Electric's next base load unit, the Polk Unit 2 - 5 conversion to combined cycle.
In June 2013, President Barack Obama announced his "Climate Action Plan" a broad package of mostly administrative initiatives aimed at reducing GHG emissions by approximately 17 percent below 2005 levels by 2020. EPA regulation of GHG emissions from new and existing power plants are the plan's primary elements.
These regulations were anticipated long before the president's announcement, however the president provided additional details on both timing and substance.
With respect to new power plants, pursuant to the directive, EPA released a re-proposed rule in September 2013 and is taking comments on the proposal until March 10, 2014. The president also directed EPA to issue a draft rule for existing power plants by June 1, 2014, to finalize the rule by June 1, 2015, and to require states to submit implementation plans by June 30, 2016. Because both rules will be subjected to litigation, legal challenges could also have material impact on both the timing and substance of EPA's new climate rules.
65-------------------------------------------------------------------------------- Table of Contents Tampa Electric expects that the costs to comply with new environmental regulations would be eligible for recovery through the ECRC. If approved as prudent, the costs required to comply with CO2 emissions reductions would be reflected in customers' bills. If the regulation allowing cost recovery is changed and the cost of compliance is not recovered through the ECRC, Tampa Electric could seek to recover those costs through a base-rate proceeding, but cannot predict whether the FPSC would grant such recovery. Tampa Electric's current solid-fuel energy generation was about 55% of its total system output in 2013, compared to being approximately 84% of its output in 2001. This is due to the conversion of the coal-fired Gannon Power Station into the natural gas-fired Bayside Power Station. However, solid fuel-fired facilities remain a significant component of Tampa Electric's diverse generation fleet and additional solid fuel units could be considered in the future.
In the case of TECO Coal, there are not yet federal limits on GHG emissions for this sector, and it is unclear if future requirements for GHG emissions reductions would directly impact it as a carbon-based fuel provider or the end users of its products. In either case, these requirements could make the use of coal more expensive or less desirable, which could impact TECO Coal's margins and profitability.
Water Supply and Quality The EPA's final Clean Water Act Section 316(b) rule took effect in 2004. The rule established aquatic protection requirements for existing facilities that withdraw 50 million gallons or more of water per day from rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters for cooling purposes.
Tampa Electric uses water from Tampa Bay at its Bayside and Big Bend facilities as cooling water. Both plants use mesh screens to reduce the adverse impacts to aquatic organisms, and Big Bend units 3 and 4 use proprietary fine-mesh screens, BACT, to further reduce impacts to aquatic organisms. Subsequent to promulgation of the rule, a number of states, environmental groups and others sought judicial review of the rule. In 2007, the U.S. Court of Appeals for the Second Circuit overturned and remanded several provisions of the rule to the EPA for revisions.
Among other things, the court rejected the EPA's use of "cost-benefit" analysis and suggested some ways to incorporate cost considerations. The Supreme Court agreed to review the Second Circuit's decision and heard arguments in December 2008. The EPA decided to rewrite the rule, and proposed a new rule in the summer of 2013. After several delays, the final rule is scheduled for April 2014. The full impact of the new regulations will depend on subsequent legal proceedings, the results of studies and analyses performed as part of the rules' implementation, and the actual requirements established by state regulatory agencies.
On Dec. 6, 2010, the EPA published its final rule, setting numeric nutrient criteria for Florida's lakes and flowing waters. The rule, as published, is being challenged in the courts by numerous parties, including the state of Florida. The rule sets numeric limits for nitrogen and phosphorous in lakes and streams and for nitrate plus nitrite in springs. The EPA promulgated the rule pursuant to the terms of a consent decree approved by the court in Florida Wildlife Federation v. Jackson, 08-0324 (N.D. Fla.), in which environmentalists sued the EPA for allegedly violating a duty under the Federal Water Pollution Control Act (Clean Water Act or Act) to set the numeric criteria. In response to comments raising numerous implementation concerns, the EPA decided to delay the effective date of the criteria until 15 months after publication. The EPA announced that, in the interim, it would undertake a series of implementation steps in Florida, including an "education and outreach rollout," training meetings, and the development of guidance materials to coincide with the expected comment period on proposed site-specific alternative criteria. On Nov.
30, 2012, the EPA approved the FDEP rule in its entirety. The EPA proposed additional criteria in December 2012, including a re-proposal of streams criteria that were previously invalidated by the court. In January 2014, the EPA consent decree was revised allowing only the FDEP criteria to be implemented in Florida. Streams criteria may still directly affect Polk Power Station's cooling reservoir discharge to surface water, which may require the station to reduce the amount of nutrients in the cooling reservoir water before discharge.
After the completion of a study into wastewater discharges by the electric utility industry in 2009, the EPA announced its intent to revise the existing steam electric effluent limit guidelines (ELGs) that place technology-based limits on wastewater discharges. The rulemaking will focus on wastewater discharges from scrubbers, fly ash and bottom ash sluicing processes, leachate from ponds and landfills containing CCRs, IGCC processes, and flue gas mercury controls. The EPA is evaluating a suite of technology options which include treatment processes for wastewater discharges as well as the conversion to dry handling of fly ash and bottom ash to allow for zero discharge of transport water. Final impacts will vary depending on the mandated technology, the volume of wastewater to be treated and the pollutant limits. Tightened limits are anticipated for mercury, selenium, trace metals, and chlorides. New guidelines will likely add stricter limits to future NPDES permits in 2014-2019 (based on the five-year permit cycle).
Section 404 of the Clean Water Act and Coal Surface Mine Permits Since 2008, the issuance of permits by the USACE under Section 404 of the Clean Water Act required for surface mining activities in the Central and Northern Appalachian mining regions has been challenged in the courts by various environmental groups.
On April 1, 2010, the EPA issued new guidance on environmental permitting requirements for Appalachian mountaintop removal and other surface mining projects. The guidance limits conductivity (level of mineral salts) in water discharges into streams from permitted areas, and was effective immediately on an interim basis. In July 2011, the EPA made this guidance final without modification. Because the EPA's standards appear to be unachievable under most circumstances, surface mining activity could be substantially curtailed since most new and pending permits would likely be rejected. This guidance could also be extended to discharges from deep mines and preparation plants, which could result in a substantial curtailing of those activities as well.
This guidance was challenged in the courts by a number of coal mining industry-related organizations, states and municipalities relating to the stringency of the standards as well as the focus on the coal industry and the Appalachian region in particular. In July 2012, the U. S. District Court for the District of Columbia ruled that the EPA had exceeded its statutory authority in establishing the water quality guidance discussed above in the manner in which it was done. Following the outcome of this court decision, pending appeals by the EPA, few, if any, new permits have been issued by USACE.
66-------------------------------------------------------------------------------- Table of Contents Superfund and Former Manufactured Gas Plant Sites TEC, through its Tampa Electric and PGS divisions, is a PRP for certain superfund sites and, through its PGS division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of Dec. 31, 2013, TEC has estimated its ultimate financial liability to be $40.4 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under "Other" on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer prices.
The estimated amounts represent only the portion of the cleanup costs attributable to TEC. The estimates to perform the work are based on TEC's experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries.
In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC's actual percentage of the remediation costs.
Factors that could impact these estimates include the ability of other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings.
Coal Combustion Residuals Recycling and Disposal The combustion of coal at two of Tampa Electric's power-generating facilities, the Big Bend and Polk Power stations, produces ash and other by-products, collectively known as CCRs. The CCRs produced at Big Bend include fly ash, FGD gypsum, boiler slag, bottom ash and economizer ash. The CCRs produced at the Polk Power Station include gasifier slag and sulfuric acid. Overall, over 97% of all CCRs produced at these facilities were marketed to customers for beneficial use in commercial and industrial products. The remaining 3% were either disposed of onsite or shipped offsite to nearby industrial waste landfills in Central Florida.
In response to a coal ash pond failure at another utility in December 2008, the EPA proposed new regulations for the management and disposal of CCRs. These proposed rules include two potential designations of CCRs. One designation would categorize CCRs destined for disposal as hazardous wastes. This is the most significant for TEC, because hazardous waste landfills are currently prohibited in Florida by state law, so CCRs destined for disposal would have to be shipped out of state as hazardous waste at significantly increased costs. In addition, the hazardous designation could require improvements to Tampa Electric's current ash management practices and interim storage and handling facilities for CCRs inside its power stations, even though permanent onsite disposal would not be allowed. The other proposed rule would set minimum standards for the final disposal of CCRs under regulations similar to those in place for municipal non-hazardous solid waste. This proposal would not be as disruptive as the former, since it would allow for the continued operation of Tampa Electric's existing, lined ash ponds. However, this latter proposal would place additional management requirements on these existing disposal units, which would eventually reach the end of their useful life and need to be replaced. The EPA's current schedule would result in a final proposed rule in 2014, although expected litigation would likely delay the rule's effective date.
Renewable Energy Renewables are a component of Tampa Electric's environmental portfolio. Tampa Electric's renewable energy program offers to sell renewable energy as an option to customers and utilizes energy generated in the state from renewable sources (e.g. biomass and solar). To date, more than 62 million kWh of renewable energy have been produced by Tampa Electric and other renewable energy generating sources within Florida to support participating customer requirements.
Tampa Electric has installed over 100 kW of solar panels to generate electricity from the sun at six community sites including two schools, Tampa Electric's Manatee Viewing Center, the Museum of Science and Industry, Tampa's Lowry Park Zoo and the Florida Aquarium. Tampa Electric's largest solar panel array, rated at 43.8 kW, is located at Tampa Electric's Manatee Viewing Center in Apollo Beach, Florida. The electricity the photovoltaic array generates, which flows to Tampa Electric's grid, could offset the carbon dioxide emissions produced by seven typical-size cars in a year. The company continues to evaluate opportunities for additional solar panel installations.
Conservation Energy conservation is becoming increasingly important in a period of volatile energy prices and in the GHG emissions reduction debate. In December 2009, the FPSC established new aggressive demand-side-management (DSM) goals for 2010-2019 for all investor-owned electric utilities. For Tampa Electric, the summer and winter demand goals are 138 and 109 MWs, respectively, and the annual energy goal is 360 gigawatt-hours. Even though these goals are set as a 10-year program, a review of the goals is required every five years. Tampa Electric's programs are scheduled to be reviewed by the FPSC in 2014.
During 2013, Tampa Electric continued to offer its customers a comprehensive array of residential and commercial programs that enabled the company to meet its required DSM goals, reduce weather-sensitive peak demand and conserve energy. This strategy continues to allow Tampa Electric to delay construction of future generation facilities. Since their inception, the company's conservation programs have reduced the summer peak demand by 319 MW and the winter peak demand by 719 MW. These programs and their costs are approved annually by the FPSC with the costs recovered through a clause on the customer's bill. In addition, PGS offers programs that enable customers to reduce their energy consumption with the costs also recovered through a clause on the customer's bill.
67 -------------------------------------------------------------------------------- Table of Contents REGULATION Tampa Electric's and PGS's retail operations are regulated by the FPSC, which has jurisdiction over retail rates, quality of service and reliability, issuances of securities, planning, siting and construction of facilities, accounting and depreciation practices, and other matters.
In general, the FPSC's pricing objective is to set rates at a level that provides an opportunity for the utility to collect total revenues (revenue requirements) equal to its cost to provide service, plus a reasonable return on invested capital.
For both Tampa Electric and PGS, the costs of owning, operating and maintaining the utility systems, excluding fuel and conservation costs as well as purchased power and certain environmental costs for the electric system, are recovered through base rates. These costs include O&M expense, depreciation and taxes, as well as a return on investment in assets used and useful in providing electric and natural gas distribution services (rate base). The rate of return on rate base, which is intended to approximate the individual company's weighted cost of capital, primarily includes its costs for debt, deferred income taxes at a zero-cost rate and an allowed ROE. Base rates are determined in FPSC revenue requirement and rate setting hearings which occur at irregular intervals at the initiative of Tampa Electric, PGS, the FPSC or other parties.
Tampa Electric is also subject to regulation by the FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services, and accounting practices.
Federal, state and local environmental laws and regulations cover air quality, water quality, land use, power plant, substation and transmission line siting, noise and aesthetics, solid waste and other environmental matters (see the Environmental Compliance section).
Tampa Electric - Base Rates In 2011, 2012 and 2013 prior to Nov. 1, the rates and allowed ROE in effect for Tampa Electric had been established in 2009 and in a series of subsequent decisions in 2009 and 2010. The allowed ROE during this period was a range of 10.25% to 12.25%, with a midpoint of 11.25%.
As a result of growth in rate base from required infrastructure added to serve customers, increasing pressure on O&M expense, and an economic recovery that was slower than expected compared to the assumptions in Tampa Electric's last base rate proceeding in 2009, on April 5, 2013, Tampa Electric filed its petition with the FPSC for an increase in base rates and miscellaneous service charges in the amount of $134.8 million. In the petition, Tampa Electric requested an ROE level of 11.25% and a capital structure identical to that approved in 2009, with 54% equity.
After extensive testimony by Tampa Electric and discovery by five intervening parties and the FPSC Staff, on Sept. 6, 2013, Tampa Electric and all of the intervening parties reached a Stipulation and Settlement Agreement resolving all of the issues in the proceeding.
On Sept. 11, 2013, the FPSC approved the Settlement that authorized base rate increases implemented at four different dates.
1. Nov. 1, 2013: $57.5 million increase 2. Nov. 1, 2014: Additional $7.5 million increase ($65 million versus current rates) 3. Nov. 1, 2015: Additional $5 million increase ($70 million versus current rates) 4. Jan. 1, 2017: Implementation of a Generation Base Rate Adjustment representing a $110 million additional increase on Jan. 1, 2017, or on the in-service date of the Polk 2-5 conversion, whichever is later.
The Settlement authorized an ROE of 10.25% and equity ratio of 54%, with a provision that ROE becomes 10.50% if at any time during the agreement the six month average 30-year US Treasury Bond yield increases 75 basis points. Base rates will not change if the ROE trigger were to take effect; however, for purposes of cost recovery clauses, AFUDC and surveillance reporting, there would be an adjustment to reflect the 10.50%.
As part of the settlement, Tampa Electric discontinued its annual $8 million storm damage expense accrual at Nov. 1, 2013 and the company will utilize a 15-year amortization period for all software retroactive to Jan. 1, 2013. The company will not be able to file for new base rates to be effective sooner than Jan. 1, 2018, subject to a bilateral opportunity for Tampa Electric or Interveners to initiate a rate proceeding if actual reported ROE falls below a floor of 9.25% or above a ceiling of 11.25%, subject to the 25 basis point incremental ROE if triggered. Lastly, the company is required to file a depreciation study no fewer than 60 days but no more than one year before filing its next base rate request.
The Settlement also contained various changes with respect to rate design. The company will implement a new Commercial and Industrial Service Rider (CISR) and an Economic Development Rate. The new Economic Development Rate will be implemented on a pilot basis for a three-year period and limited by the maximum amount of economic development expenditures as specified in Commission rules, which is approximately $3 million. The current lock-in period for interruptible credits will extend from three to six years and the Standby Generator credit will be adjusted from $4.00 to $4.75.
68-------------------------------------------------------------------------------- Table of Contents FERC Audit On Nov. 6, 2012, Tampa Electric received notification from the FERC that its accounting practices and financial reporting processes would be audited, along with compliance with the FERC's records retention requirements. This was considered a routine audit by the FERC staff, though it had been approximately 20 years since Tampa Electric last had a FERC accounting audit.
No material issues have been identified as a result of the audit, and Tampa Electric expects to have an exit audit conference with the FERC staff in 2014, and thereafter to receive a letter from the FERC describing the results of the completed audit.
Tampa Electric Cost-Recovery Clauses In November 2013, the FPSC approved Tampa Electric's rates for the various cost-recovery clauses for the period January 2014 through December 2014. Tampa Electric's fuel filing reflected continued historically low natural gas prices as well as good unit performance more than offset by a lower projected recovery of 2013 fuel costs, which resulted in Tampa Electric seeking a $2.40 increase in its fuel charges for 2014 for a residential customer using 1,000 kWh per month.
As of Jan. 1, 2014, the total bill for a residential customer using 1,000 kWh is $109.61, compared to the November 2013 bill of $108.26, which includes the base rate increase discussed above, an increase of $1.35.
Utility Competition - Electric Tampa Electric's retail electric business is substantially free from direct competition with other electric utilities, municipalities and public agencies.
At the present time, the principal form of competition at the retail level consists of self-generation available to larger users of electric energy. Such users may seek to expand their alternatives through various initiatives, including legislative and/or regulatory changes that would permit competition at the retail level. Tampa Electric intends to retain and expand its retail business by managing costs and providing high quality service to retail customers.
Unlike the retail electric business, Tampa Electric competes in the wholesale power market with other energy providers in Florida, including other IOUs, municipal and other utilities, as well as co-generators or other unregulated power generators with uncontracted excess capacity. Entities compete to provide energy on a short-term basis (i.e., hourly or daily) and on a longer term basis.
Competition in these markets is primarily based on having available energy to sell to the wholesale market and the price. In Florida, available energy for the wholesale market is affected by the state's PPSA, which sets the state's electric energy and environmental policy and governs the building of new generation involving steam capacity of 75 MW or more, that requires that applicants demonstrate that a plant is needed prior to receiving construction and operating permits. The effect of the PPSA has been to limit the number of unregulated generating units with excess capacity for sale in the wholesale power markets in Florida.
FPSC rules promote cost-competitiveness in the building of new steam generating capacity by requiring IOUs, such as Tampa Electric, to issue RFPs prior to filing a petition for Determination of Need for construction of a power plant with a steam cycle greater than 75 MW. The rules, which allow independent power producers and others to bid to supply the new generating capacity, provide a mechanism for expedited dispute resolution, allow bidders to submit new bids whenever the IOU revises its cost estimates for its self-build option, require IOUs to disclose the methodology and criteria to be used to evaluate the bids, and provide more stringent standards for the IOUs to recover cost overruns in the event the self-build option is deemed the most cost-effective.
Tampa Electric is not a major participant in the wholesale market because it uses lower cost coal-fired generation to serve its retail customers rather than the wholesale market. Over the past three years, gross revenues from wholesale sales, which include fuel that is a pass-through cost, have averaged approximately 2% of Tampa Electric's total revenue.
In many areas of the country there is growing use of rooftop solar panels, small wind turbines and other small scale methods of power generation, called distributed generation, by individual residential, commercial and industrial customers, or by third-party developers. Distributed generation is encouraged and supported by various special interest groups, tax incentives, renewable portfolio standards and special rates designed to support such generation. Tampa Electric offers rebate programs of up to $1.5 million annually to encourage development of solar installations and third-party developers offer attractive financing and leasing arrangements to encourage project development. In Florida, third parties that are not subject to regulation by the FPSC are not permitted to make direct sales of electricity to end use customers. The allowance of direct third party sales would take action by the Florida legislature, which is not expected in its 2014 session.
PGS Rates PGS's rates and allowed ROE range of 9.75% to 11.75%, with a midpoint of 10.75%, and an equity ratio of 54.7%, which was established in 2009, are in effect until such time as changes are occasioned by an agreement approved by the FPSC or other FPSC actions as a result of rate or other proceedings initiated by PGS, FPSC or other interested parties.
As a result of the unprecedented cold winter weather in 2010, in the second quarter of 2010, PGS projected it would earn above the top of its ROE cap of 11.75% in 2010. PGS recorded a $9.2 million pretax total provision related to the 2010 earnings above the top of the range. In December 2010, PGS and the Office of Public Counsel entered into a stipulation and settlement agreement requesting FPSC approval that $3.0 million pretax of the provision to be refunded to customers in the form of a credit on customers' bills in 2011, and the remainder be applied to accumulated depreciation reserves. On Jan. 25, 2011 the FPSC approved the stipulation.
PGS Cost-Recovery Clauses PGS recovers the costs it pays for gas supply and interstate transportation for system supply through the PGA clause. This clause is designed to recover the costs incurred by PGS for purchased gas, and for holding and using interstate pipeline capacity for the transportation of gas it delivers to its customers.
These charges may be adjusted monthly based on a cap approved annually during an FPSC hearing. The cap is based on estimated costs of purchased gas and pipeline capacity, and estimated customer usage for a calendar year recovery period, with a true-up adjustment to reflect the variance of actual costs and usage to projected charges for prior periods. In November 2013, the FPSC approved PGS' request for its PGA cap factor of $0.9185 per therm effective January 2014 69-------------------------------------------------------------------------------- Table of Contents through December 2014. In addition to its base rates and PGA clause charges, PGS customers (except interruptible customers) also pay a per-therm conservation charge for all gas. This charge is intended to permit PGS to recover costs incurred in developing and implementing energy conservation programs, which are mandated by Florida law and approved and supervised by the FPSC. PGS is permitted to recover, on a dollar-for-dollar basis, prudently incurred expenditures made in connection with these programs if it demonstrates the programs are cost-effective for its ratepayers.
In 2012, the FPSC approved a Cast Iron/Bare Steel Pipe Replacement Rider to recover the cost of accelerating the replacement of cast iron and bare steel distribution lines in the PGS system. Utilities nationwide have been encouraged by the U.S. Department of Transportation to replace this older infrastructure as a safety measure. The FPSC approved PGS' request to accelerate the replacement program of approximately 5%, or 500 miles, of the PGS system at a cost of approximately $80 million over a 10-year period.
Utility Competition - Gas Although PGS is not in direct competition with any other regulated distributors of natural gas for customers within its service areas, there are other forms of competition. At the present time, the principal form of competition for residential and small commercial customers is from companies providing other sources of energy, including electricity, propane and fuel oil. PGS has taken actions to retain and expand its natural gas distribution business, including managing costs and providing high quality service to customers.
In Florida, gas service is unbundled for all non-residential customers. PGS has a "NaturalChoice" program, offering unbundled transportation service to all eligible customers and allowing non-residential customers and residential customers using more than 1,999 therms annually to purchase commodity gas from a third party but continue to pay PGS for the transportation. As a result, PGS receives its base rate for distribution regardless of whether a customer decides to opt for transportation-only service or continue bundled service. PGS had approximately 20,500 transportation-only customers as of Dec. 31, 2013, out of approximately 35,000 eligible customers.
Competition is most prevalent in the large commercial and industrial markets. In recent years, these classes of customers have been targeted by companies seeking to sell gas directly by transporting gas through other facilities and thereby by-passing PGS facilities, or by other utilities seeking to expand existing distribution systems to new customers previously unserved by another utility. In response to this competition, PGS has developed various programs, including the provision of transportation services at discounted rates.
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