LIC-18-0010, 2017 Annual Report

2017 Annual Report

ML18092B376
Person / Time
Site:	Fort Calhoun
Issue date:	04/02/2018
From:	Blome B Omaha Public Power District
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
LIC-18-0010
Download: ML18092B376 (37)

Text

Omaha Public Power District 10 CFR 50.71(b)

April 2, 2018 LIC-18-001 0 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 Fort Calhoun Station, Unit No. 1 Renewed Facility Operating License No. DPR-40 NRC Docket No. 50-285

Subject:

2017 Annual Report

References:

None In accordance with 10 CFR 50.71(b), the 2017 Omaha Public Power District (OPPD) Annual Report is enclosed.

If you should have any questions, please contact Mr. Bradley H. Blome at 402-533-6041 .

No commitments to the NRC are made in this letter.

Respectfully,

~\~-

~r~dley H. Blome Director, Licensing and Regulatory Assurance BHB/epm

Enclosure:

OPPD 2017 Annual Report c: K. M. Kennedy, NRC Regional Administrator, Region IV J. D. Parrott, NRC Senior Project Manager R. S. Browder, NRC Senior Health Physicist, Region IV 444 SOUTH 16TH STREET MALL

• OMAHA, NE 68102-2247

• Served at Retail A Served at Wholesale

.. Power Station*

e Wind Generation OPPD Headquarters

• 2017 rated capability OPPD Service Territory Fort Calhoun Station Nuclear plant (ceased operations October 2016)

Colfll Elk City Station Landfill-gas plant, 6.3 megawatts North Omaha Station Coal & natural-gas plant, 557.4 megawatts

~...;;:;_-OPPD Headquarters Jones Street Station Oil plant, 122.6 megawatts Sarpy County Station Oil & natural-gas plant, 316.5 megawatts WIND FARMS 0

.... Cass County Station Natural-gas plant, 322.8 megawatts

1. Ainsworth Nebraska City Station Unit 1 10-megawatt participation agreement Coal plant, 655.9 megawatts

2. Broken Bow I Nebraska City Station Unit 2 18-megawatt participation agreement Coal plant, 664.2 megawatts Broken Bow II 43.9-megawatt participation agreement

3. Petersburg 40.5-megawatt participation agreement

4. Elkhorn Ridge 25-megawatt participation agreement

5. Crofton Bluffs 13.6-megawatt participation agreement Richardson

6. Prairie Breeze 200.6-megawatt participation agreement

7. Flat Water 60-megawatt participation agreement

8. Grande Prairie 400-megawatt participation agreement About OPPD

9. Sholes 160-megawatt participation agreement Omaha Public Power District is a publicly owned electric utility that serves an estimated (2019) population of 833,000 people, more than any other electric utility in the state.

Operating since 1946, the public utility is governed by an elected board of eight directors. While its headquarters is located in Omaha, Neb., OPPD has several other locations in its 13-county, 5,000-square-mile service area in southeast Nebraska.

OPPD utilizes baseload power facilities fueled by coal and natural gas, peaking units fueled by natural gas and oil, and renewable energy, including wind, landfill-gas and hydropower.

Emily )udevine works as an assistant unit Contents operator at Nebraska City Station.

Board Chair and CEO Message ........................................................................ 2 Board of Directors ................................................................... "...................... 3 Senior Management ................................... ..................................................... 3 Operations Review ........................................................................................... 4 Management's Discussion and Analysis (Unaudited) ...................................... 12 Report of Management. ................................................................................. 24 Independent Auditors' Report ............................... ......................................... 25 Statements of Net Position ............................................................................ 26 Statements of Revenues, Expenses and Changes in Net Position ................... 28 Statements of Cash Flows ................ .............................................................. 29 Notes to Financial Statements ........................................................................ 31 Required Supplementary Information ............................................................ 61 Notes to Required Supplementary Information .............................................. 63 Statistics (Unaudited) ................................................................................... .. 64 Investor Relations and Corporate lnformation .......................... inside back cover On the cover The old jones Street Power Stat1on has been converted mto The Breakers, a umque apartment complex that preserves much of the h1stoncal plant's charm

At Omaha Public Power District, we pride ourselves in providing affordable, reliable and environmentally sensitive energy services to our customers. But something else we do, and do as well as any electric utility in the nation, is powering partnerships.

Each day, we partner with customer-owners, business owners, homeowners, community leaders, special interest groups and other stakeholders, even other utilities, to carry out Board Chair and our mission.

Such partnerships have led us to pledge the unprecedented move of having no general CEO Message rate increase through 2021.

Those partnerships take place within OPPD, as well. Inside our utility, various areas have been collaborating to safely and economically decommission Fort Calhoun Nuclear Station. That work has gone smoothly and will continue in the coming years. At Nebraska City Station, our engineers and plant operators have teamed up to make our largest generating station more effident than ever to keep customers' rates low. And at North Omaha Station, three units have been retrofitted to run on natural gas to serve as "peaking stations," called upon at times of peak demand for energy.

President and CEO Timothy J. Burke (left) With the energy landscape changing, we continue down the path of adding more and Board Chair Michael J. Cavanaugh renewables to our generation portfolio. In 2017, renewables represented about 30 percent of our retail sales. The recently announced Sholes Wind Energy Center in Wayne County, Neb., will put us close1 to our goal of at least 50 percent of retail sales coming from renewables. This year, we will develop plans around a community solar project with input from our stakeholders, another example of our valuable partnerships.

We are proud of our public power heritage and the fact that we answer to our customer-owners, providing them with cost-effective and reliable energy. When that reliability is put to the test, employees respond. In june, our team showcased extreme dedication and commitment in response to one of our most destructive storms ever. Within two days, OPPD had restored service to 90 percent of the 76,500 customers who lost power.

That same spirit of teamwork is evident on the economic development front. Our Economic Development team partners with o~ganizations and businesses across the state and country to bolster our region's economy. This past year, more than $1 billion in capital investment projects for OPPD's service territory were announced The biggest was a new data center for Facebook, located just outside the Omaha metro area Abig part of their decision was because of the development of our innovative new rate- 261M-for large customers seeking more renewable energy. The momentum continues for the coming years, with new projects in development.

As this report shows, OPPD remains in a strong financial position.

We will keep powering partnerships just as we will continue leading the way we power the future.

~~ Timothy J. Burke President and CEO

Board of Directors Michael J. Cavanaugh Anne l. McGuire Michael A. Mines Craig C. Moody Chair of the Board Vice Chair of the Board Treasurer Secretary Omaha Police Nurse Educator (retired) Governmental Business Owner Lieutenant (retired) Advisor Real Estate Investor-Manager Thomas S. Barrett Tim W. Gay Mark E. Treinen Rick M. Yoder Board Member Board Member Board Member Board Member Attorney at law Governmental Advisor Business Executive Consultant (retired)

Senior Management Timothy J. Burke Kate W. Brown Jull A. Comstock Mohamad I. Doghman l. Javier Fernandez President & Vice President - Vice President - Vice President - Energy Vice President -

Chief Executive Officer Business Technology Customer Service Delivery & Chief Financial Services &

& Building Services Assistant Secretary Compliance Officer Chief Financial Officer Assistant Secretary Assistant Secretary Assistant Secretary Mary J. Fisher lisa A. Olson Martha l. Sedky Scott M. Focht Vice President - Vice President - Vice President - Senior Director-Energy Production Public Affairs Human Capital Business Strategy &

& Nuclear Assistant Secretary Assistant Secretary Deployment Decommissioning Assistant Secretary

OPERATIONS REVIEW At OPPD, we've long been proud of our motto, "your energy partner."

That's how we see ourselves, and it's a good description of our relationship with our customer-owners. They are farmers in the countryside irrigating fields. They are staples of Omaha's business community looking to add more load. They are families enjoying a dinner together at home.

As a public power utility, we give our customers and community a voice and keep their interests at the forefront as we deliver affordable, reliable and environmentally sensitive energy services.

OPPD's 54.6 mile Arbor Rail line rs one of only a handful of Nebraska locations wrth ready-rail acces5 to both Unron Pacific and Burlington Northern Santa Fe railroads.

That access attracted Midwest Farmers Co-op to locate along the line in Syracuse, Neb. The co-op welcomed its first 11 0-car shuttle last spring.

Bolstering businesses A healthy business climate means additional production lines to keep Facebook began construction of its new good things for those living and up with demand. The expansion data center in Sarpy County last spring.

working in the community, and brings a nearly 30 percent increase energy plays a big role. in energy demand.

OPPD collaborates with com- Partnering with the world-munity groups, such as area cham- renowned University of Nebraska bers of commerce and economic Medical Center and Nebraska development organizations, to serve Medicine, OPPD helped them find businesses' needs. Last year, this ways to use less energy through partnership identified large pieces energy conservation measures of 11 Shovel-ready" land for potential and targeted upgrades, despite an development. That effort helped increase of 2 million square feet produce the area's biggest project of in the campus size.

2017: a new Facebook data center OPPD's low rates and high located just outside Omaha in Sarpy reliability have also played a big County. role in drawing new businesses to Abig reason for Facebook's decision the area, like Omaha-based tech was having OPPD as a strong partner company Flywheel, which hosts in the creation of the new 261M rate, websites and relies on OPPD's elec-which helps large customers meet tricity to be there when it needs it.

their renewable energy goals. OPPD's service territory received OPPD doesn't just work with new national recognition this past year businesses. Long-time customers like for a number of new developments Rotella's Italian Bakery saw expan- and was one of 10 U.S. utilities sions and worked directly with OPPD. named among Site Selection maga-Rotella's, which ships its breads to zine's top utilities in the country.

clients across the U.S., is finishing a More than $1 billion in new capital 56,000-square-foot facility to house investment projects were announced for the area in 2017.

OPPD's Economic Development team played an integral role in attracting Facebook to Nebraska.

Team members, from left, include Brook Aken, jason Esser, T1m O'Brien and Devin Meisinger.

Innovation in our industry OPPD sees the need to transform and embrace challenges by continuing to put an emphasis on innovation. OPPD's new Thermostat For the second year, a team of Program uses smart, Wi-Fi-employees has developed creative enabled thermostats to help ideas and solutions to address the curb energy demand, like the Nest rapidly changing utility landscape Thermostat E, shown here. The program is the company's and push work groups outside their latest Power Forward solution, part of a portfolio of comfort zones. The team evaluated demand-side management programs.

more than 250 ideas in 2017. In 2018, OPPD will launch an innovation lab to identify and explore breakthrough ideas that could generate new value for customers and employees.

For our customers and stakeholders, one of our biggest successes has been the impact to their budgets and bot-tom lines - through our commitment to no general rate increase through 2021. That commitment was made possible partly because of our difficult dectsion to cease operations at Fort Calhoun Nuclear Station (FCS), which is now being decommissioned. Over the past year, FCS employees worked to scrap, repurpose and recycle equip-ment from the plant, began work on the upcoming dry cask storage project and inspected hundreds of used nuclear fuel bundles.

Along with the FCS decision, our Among the decommissioning projects at Fort Calhoun Nuclear Stat1on is an upcoming dry Lean efforts and cost and process (ask storage facility project.

initiatives factored into holding rates steady. I*rom calculated reductions in operations and maintenance to capital demand-side management program. In 2017, renewables represented spending, those combined efforts We will be evaluating adding more about 30 percent of retail sales and have helped the utility fulfill the "smart," Wi-Fi-enabled thermostat that number will only increase when commitment to our ratepayers. manufacturers in the future. Sholes Wind Energy Center begins In late 2017, OPPD unveiled its OPPD will continue to place an operations.

Thermostat Program, an innovative increased focus on renewable energy, way for customers to help reduce working toward the goal of having at demand at peak times. We part- least SO percent of retail sales come nered with Nest Labs for the new from renewables.

Never resting on reliability Having some of the lowest rates in the country is great, but if you're not there when your customers flip the switch, you're not being a true energy partner. We take every bit as much pride in our reliability as we do in our prices. We use a combination of jake Farrell, supervisor of Land Management, Siting and Records, talks with customers and routine maintenance, new infrastruc- gathers feedback at an event about the Sarpy Transmission Project ture and emerging technologies to ensure reliability. infrastructure as a result of OPPD's drone inspections can be performed In late 2016, OPPD completed one first phase of smart grid and more frequently and at a lower cost, of its largest projects in the last 10 distribution automation. With the helping keep the system reliable and years, the Midwest Transmission infrastructure in place to support our customers' rates low.

Project. Apriority project for the smart communication devices in In 2017, through the Transmis-Southwest Power Pool, the transmis- that area, OPPD will monitor the sion and Dishibution Improvement sion line helps ease congestion and project to understand the impacts Program, crews replaced more than increase capadty in the region. Other this technology could have for 40 miles of cable on our distribution transmission projects began construc- customers in the coming years. system. OPPD inspected and treated tion this year, including the Elkhorn Aerial inspections, one routine about 30,000 wood distribution poles River Valley Transmission Project, process that keeps outages to a mini- to extend their life, and replaced more which will improve reliability for both mum, went high-tech in 2017 when than 300 poles. Crews also replaced a OPPD and the Fremont, Neb., area. OPPD began using its own drone to number of components in our Customers in an area of north inspect transmission lines. Although network and substation systems.

Omaha will see the benefits of new OPPD still uses a helicopter at times, At right, Nebraska City Station workers perform maintenance at OPPD's largest generating station.

Mutual aid partner- more diverse group of employees ftom ships prove invalu- areas of our service territory that have able at times like these, been underrepresented in the past. The and for that reason, OPPD students go through a rigorous curricu-has sent crews as far as New lum and work with OPPD ambassadors York City, Louisiana and before becoming interns when they Caring for our community Mississippi in the past. start their post-high school education.

In September, we again sent This partnership benefits everyone In June, a destructive wind involved, and it ultimately leads to the crews to Jacksonville and storm impacted a third of OPPD's Tampa to help restore power to students becoming OPPD employees.

5,000-square-mile service territory. In Florida customers Hundreds of OPPD employees also two locations, tornadoes did major after Hurricane Irma regularly volunteer their time and damage to transmission lines, even While natural disasters gar- talents in the community.

uprooting 100-year-old trees. It was ner headlines, OPPD employ- Our roles in the community are the fourth-worst storm in terms of ees are out in the community as important as our role of energy outages to ever hit our area. OPPD every day, working to make a partner. Customers expect us to be crews worked long hours, and mutual difference. Our annual Heat there when they need us, whether aid utilities came from near and far to the Streets Run & Walk for they are restoring power or developing help restore power. Assistance came Warmth, a partnership with the leaders of tomorrow. That's what from neighboring utilities, includ- other area utilities, raises makes for a great partnership. And we ing Nebraska Public Power District1 money for the Energy look forward to powering those Lincoln Electric System, Loup River partnerships for years to come.

Assistance Program, Public Power District and South-which helps custom-ern Power, as well as out-of-state ers struggling to pay partners from Iowa, Colorado their energy bills.

and Alabama. In August, OPPD proudly became the first In 2017, OPPD partnered w1th Omaha partner to Omaha's Henry Doorly Zoo and start working with Aquarium to provide tree trimmings Legacy 13, a program from the district's reliability efforts to designed to bring a feed animals.

Account Executive Maurice Kimsey, center, speaks with students at OPPD's Energy Plaza headquarters.

OPPD crews make repairs to distribution lines damaged in a june storm that Impacted one third of our service territory. It was OPPD's fourth-worst storm in terms of outages.

Management's Discussion and Analysis (Unaudited)

USING THIS FINANCIAL REPORT The Financial Report for the Omaha Public Power District (OPPD or Company) includes the Management's Discussion and Analysis, Financial Statements, Notes to Financial Statements, Required Supplementary Information and Notes to Required Supplementary Information. The Financial Statements consist of the Statement of Net Position; the Statement of Revenues, Expenses and Changes in Net Position; and the Statement of Cash Flows. The Financial Statements have been prepared in accordance with generally accepted accounting principles (GAAP) for proprietary funds of governmental entities. Questions concerning any of the information provided in this report should be directed to Investor Relations, 402-636-3286.

Managernenfs Discussion and Analysis (MD&A) -This unaudited information provides an objective and easily readable analysis of OPPD's financial activities based on currently known facts, decisions or conditions. In the MD&A, financial managers present both short-term and long-term analyses of the Company's activities. The MD&A should be read in conjunction with the Financial Statements, Required Supplementary Information and related Notes. This document contains forward-looking statements based on current plans.

Statement of Net Position- This statement reports resources with service capacity (assets) and obligations to sacrifice resources (liabilities). Deferrals result from outflows and inflows of resources that have already taken place but are not recognized in the financial statements as expenses and revenues because they relate to future periods. Net Position is the residual interest in the Company. On the Statement of Net Position, the sum of assets and deferred outflows equals the sum of liabilities, deferred inflows and net position. This statement facilitates the assessment and evaluation of liquidity, financial flexibility and capital structure.

Statement of Revemus, Expenses and Changes in Net Position - All revenues and expenses are accounted for in this statement.

This statement measures the activities for the year and can be used to determine whether the revenues, rates, fees and other charges are adequate to recover expenses.

Statement of Cash Flows - This statement reports all cash receipts and payments summarized by net changes in cash from operating, noncapital financing, capital and related financing, and investing activities.

Notes to Finandal Statements (Notes) -These Notes provide additional detailed information to support the Financial Statements.

Required Supplementary Information and Notes to Required Supplementary Information -This information provides additional detailed disclosures as required by the Governmental Accounting Standards Board.

ORGANIZATION OPPD is a fully integrated, publicly owned electric utility governed by an elected board of eight directors. The Company serves an estimated population of 833,000 in a 13-county, 5,000-square-mile service area in southeast Nebraska.

FINANCIAL POSITION The following table summarizes the financial position as of December 31 (in thousands).

Condensed Statements of Net Position 2017 2016 Current Assets $ 995,921 $ 921,231 Other Long-Term Assets and Special Purpose Funds 1,674,979 1,692,455 Capital Assets 2,531,348 215611394 Total Assets 5,202,248 5,175,080 Deferred Outflows of Resources 2941319 2651988 Total Assets and Deferred Outflows $5A96,567 ~ 5A411068 Current Liabilities $ 489,434 $ 371,957 Long-Term Liabilities 3,829,185 4,013,641 Total Liabilities 4,318,619 4,385,598 Deferred Inflows of Resources 87,423 42,141 Net Position 1,090,525 1,013,329 Total Liabilities, Deferred Inflows and Net Position $5A96,567 $514411068 1; Ul'f'D /l.l~l',jlJAl 1\li'OKI 20 !1

Total Assets and Deferred Outflows Total Assets in 2017 increased $27,168,000 or 0.5% over 2016, primarily due to an increase in Current Assets. The change in Current Assets resulted from increased investment purchases.

Deferred Outflows of Resources in 2017 increased $28,331,000 or 10.7% over 2016, primarily due to the change in the expected earnings on the pension plan and increases to the ash landfill liability.

Total Liabilities, Deferred Inflows and Net Position Total liabilities in 2017 decreased $66,979,000 or 1.5% from 2016, primarily due to the advanced refunding of long-term bonds.

Deferred Inflows of Resources in 2017 increased $45,282,000 or 107.5% over 2016, primarily due to increases in the Rate Stabilization Reserve and the newly established Decommissioning and Benefits Reserve. The Rate Stabilization Reserve increased $8,000,000 over 2016.

The Decommissioning and Benefits Reserve increased $34,500,000 over 2016.

Net Position in 2017 increased $77,196,000 or 7.6% over 2016 based on results of operations.

RESULTS OF OPERATIONS The following table summarizes the operating results for the years ended December 31 (in thousands).

0 eratin Results 2017 2016 Operating Revenues $ 1,104,301 $1,126,476 Operating Expenses (975,386) (1,025,117)

Operating Income 128,915 101,359 Other Income 34,506 12,305 Interest Expense (84,253) (87,914)

Net Income Before Special Item 79,168 25,750 Special Item (1,972) (959,575)

Net Income (Loss) $ 77,196 $ (933,825)

Operating Revenues The following chart illustrates 2017 operating revenues by category and percentage of the total.

2017 Operating Revenues Commercial Industrial 28% 19%

Off-System 15%

other 2%

2017 Compared to 2016 - Total operating revenues were $1,104,301,000 for 2017, a decrease of $22,175,000 or 2.0% from 2016 operating revenues of $1,126,476,000.

• Revenues from retail sales were $911,733,000 for 2017, a decrease of $9,319,000 or l.Oo/o from 2016 revenues of $921,052,000.

The decrease in retail revenues was primarily due to a transfer to the Decommissioning and Benefits Reserve and a decrease in unbilled revenues, which was partially offset by an increase in revenues for the Fuel and Purchased Power Adjustment and a lower transfer to the Rate Stabilization Reserve.

• Revenues from off-system sales were $163,762,000 for 2017, a decrease of $11,744,000 or 6.7% from 2016 revenues of

$175,506,000. The decrease was primarily due to lower sales volumes in the off-system marketplace.

• Other Electric Revenues include connection charges, late payment charges, rent from electric property, wheeling fees and miscellaneous revenues. These revenues were $28,806,000 for 2017, a decrease of $1,112,000 or 3.7% from 2016 revenues of $29,918,000.

Operating Expenses The following chart illustrates 2017 operating expenses by expense classification and percentage of the total.

2017 Operating Expenses Decommissioning Fuel 15% 18%

Payments in Lieu of Taxes 3% Production 8%

Depreciation &

Amortization 15% Transmission

& Distribution 9%

Administrative

& General 12% Customer Purchased Power 3% 17%

2017 Compared to 2016- Total operating expenses were $975,386,000 for 2017, a decrease of $49,731,000 or 4.9% from 2016 operating expenses of $1,025,117,000.

• Fuel expense decreased $16,394,000 or 8.8% from 2016, primarily due to the decision to cease operations at Fort Calhoun Station (FCS) and decreased generation at Nebraska City Station Unit 2 (NC2), partially offset by increased generation at Nebraska City Station Unit 1 (NC1).

• Purchased Power expense increased $46,658,000 or 39.0% over 2016, primarily due to additional renewable energy purchases.

• Production expense decreased $173,209,000 or 68.6% from 2016, due to reduced operations and maintenance expense at FCS as the station transitioned to decommissioning in late 2016.

• Transmission expense increased $4,404,000 or 12.3% over 2016, primarily due to increased outside service costs, increased transmission fees and costs associated with stonn events.

• Distribution expense increased $5,197,000 or 11.6% over 2016, primarily due to increased outside service costs and payroll costs associated with storm events.

• Customer Accounts expense increased $1,255,000 or 7.5% over 2016, primarily due to increased outside service costs and payment processing fees.

• Customer Service and Infonnation expense decreased $1,170,000 or 7.7% from 2016, primarily due to decreased outside service costs and customer incentive payments.

1 Administrative and General expense decreased $37,305,000 or 24.4% from 2016, primarily due to decreased employee benefit costs and outside service costs.

1 Depreciation and Amortization expense decreased $8,911,000 or 6.0% from 2016, primarily due to ceasing operations at FCS.

1 Decommissioning expense increased $129,893,000 or 739.0% over 2016, due to increased funding of the Decommissioning Trust.

1 Payments in Lieu of Taxes expense decreased $149,000 or 0.4% from 2016, primarily due to lower retail revenues.

Other Income (Expenses)

Other income (expenses) totaled $34,506,000 in 2017, an increase of $22,201,000 over 2016 income (expenses) of $12,305,000.

Other- Net totaled $10,813,000 in 2017, an increase of $8,584,000 over 2016, primarily due to an increase in insurance proceeds and grants from the Federal Emergency Management Agency to be received in future years.

Allowances for Funds Used During Construction (AFUDC) totaled $2,988,000 in 2017, a decrease of $4,392,000 from 2016, due to lower construction balances subject to AFUDC.

14. UI'PL! AI'-JNLJ.t\1 HLPOR1 201 i

Avariety of products and services are offered to provide value both to the customer and the Company. These products and services totaled $3,903,000 in 2017, an increase of $164,000 over 2016. These products include Geothermal Loop Heat Exchangers, ECO 24/7 services and Residential Surge Protection.

Interest Expense Interest expense was $84,253,000 for 2017, a decrease of $3,661,000 from 2016, primarily due to lower interest payments related to debt refunding activity in 2017 and 2016.

Net Income Before Special Item Net income before the Special Item was $79,168,000 or $53,418,000 higher than 2016, primarily due to a decrease in operating expenses. Changes to the Rate Stabilization Reserve resulted in operating revenues and net income decreasing $8,000,000 and

$26,000,000 in 2017 and 2016, respectively. Changes to the Decommissioning and Benefits Reserve resulted in operating revenues and net income decreasing $34,500,000 and $0 in 2017 and 2016, respectively.

Special Item The Board decision to cease operations at FCS resulted in an impairment and the recognition of a Special Item. This included the fair value adjustments to the Nuclear Fuel Held for Sale in the amount of $1,972,000 for 2017 and the write-off of FCS-related assets and related contract termination fees in the amount of $959,575,000 for 2016.

Net Income (Loss)

Net income after the Special Item was $77,196,000 for 2017 compared to a net loss of $933,825,000 in 2016.

CAPITAL PROGRAM The Company's utility plant assets include production, transmission and distribution, and general plant facilities. The following table summarizes the balance of capital assets as of December 31 (in thousands).

Ca ital Assets 2017 2016 Electric plant $4,350,603 $41305,055 Accumulated depredation and amortization (1,819,255) (lr?43,661)

Total utility plant - net $2,531,348 $2,561,394 Electric system requirements, including the identification of future capital investments, are reviewed annually to ensure current and future load requirements are serviced by a reliable and diverse power supply. Capital investments are financed with revenues from operations, bond proceeds, investment income and cash on hand.

The following table shows actual capital program expenditures, including allowances for funds used during construction, for the last two years and budgeted expenditures for 2018 (in thousands).

Budget Actual Ca ital Pro ram 2018 2017 2016 Transmission and distribution $ 94,000 $ 621280 $ 82,145 Production 18,000 22)24 48,723 General 36,000 151014 11,782 Total $148,000 $ 99,618 $142,650 Actual and budgeted expenditures for 2016 through 2018 include the following:

• Transmission and distribution expenditures include a new 345-kilovolt (kV) transmission line completed in 2017 as part of the Midwest Transmission Project and a new 161/69-kV transmission line currently under construction as part of the Elkhorn River Valley Transmission Project. Transmission and distribution expenditures also include the installation of substation and distribution facilities to maintain system reliability, enhance efficiency and respond to load growth.

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• Production expenditures include equipment to maintain reliability, enhance efficiency and comply with increasing environmental regulations. Budgeted expenditures include a lime optimization system for NC2.

• General plant expenditures include fleet vehicles, construction equipment and information technology equipment. Additional budgeted expenditures include vehicles, telecommunications equipment and information technology upgrades.

Details of the Company's capital asset balances and activity are included in Note 1 in the Notes to Financial Statements.

CASH AND LIQUIDITY Cash Flows There was a decrease in cash and cash equivalents of $3,595,000 during 2017 and an increase of $5,802,000 during 2016.

The following table illustrates the cash flows by activities for the years ended December 31 (in thousands).

Cash Flows 2017 2016 Cash flows from Operating Activities $367,874 $302,271 Cash flows from Noncapital Financing Activities 4,828 Cash flows from Capital and Related Financing Activities (247,306) (274,704)

Cash flows from Investing Activities (124,163) (26,593)

Change in Cash and Cash Equivalents $ (3,595) $ 5,802 Cash flows from operating activities consist of transactions involving changes in current assets, current liabilities and other transactions that affect operating income.

• Cash flows for 2017 increased $65,603,000 over 2016, primarily due to a decrease in cash paid to operations and maintenance suppliers.

Cash flows from noncapital financing activities consist of transactions involving proceeds from federal and state agencies, such as grants.

• Cash flows for 2017 decreased $4,828,000 from 2016, due to a decrease in cash received from federal and state agencies.

Cash flows from capital and related financing activities consist of transactions involving long-term debt and the acquisition and construction of capital assets.

• Cash flows used for 2017 decreased $27,398,000 from 2016, primarily due to a decrease in cash paid for the acquisition of nuclear fuel and interest paid on debt.

Cash flows from investing activities consist of transactions involving purchases and maturities of investment securities and investment income.

• Cash flows used for 2017 increased $97,570,000 over 2016, primarily due to increased purchases of investments partially offset by the increase in maturities and sales of investments.

Financing Sufficient liquidity is maintained to ensure working capital is available for normal operational needs and unexpected, but predictable, risk events. OPPD's liquidity includes cash, marketable securities and a line of credit. Bond offerings also provide a significant source of liquidity for capital investments not funded by revenues from operations.

The financing plan optimizes the debt structure to ensure capital needs are financed, liquidity needs are achieved and the Company's strong financial position is maintained. The 2018 financing plan does not include any bond issues.

One Electric System Revenue Bond issue totaling $220,195,000 was completed in 2017. The proceeds were used to refund previously issued Electric System Revenue Bonds. The lower interest rates on the new debt decreased the debt service payments. Repayments of $45,595,000 of Electric System Revenue Bonds, $160,000 of Electric System Subordinated Revenue Bonds, $3,245,000 of NC2 Separate Electric System Revenue Bonds and $125,000 of Minibonds were made in 2017.

One Electric System Revenue Bond issue totaling $183,340,000 was completed in 2016. The proceeds were used to refund previously issued Electric System Revenue Bonds. The lower interest rates on the new debt decreased the debt service payments. Repayments of $43,065,000 of Electric System Revenue Bonds, $95,000 of Electric System Subordinated Revenue Bonds and $127,000 of Minibonds were made in 2016.

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The Company issued $103,685,000 of NC2 Separate Electric System Revenue Bonds in 2016. The bonds were used to refund previously issued NC2 Separate Electric System Revenue Bonds. There was a principal payment of $3,190,000 made on February 1, 2016, for NC2 Separate Electric System Revenue Bonds.

The Company has in place a Credit Agreement for $250,000,000 that expires on October 1, 2018. The Credit Agreement supports the Commercial Paper Program, in addition to providing another source of working capital, if needed. There were no amounts outstanding under this Credit Agreement as of December 31, 2017 or 2016. There was $150,000,000 of commercial paper outstanding as of December 31, 2017 and 2016.

The following chart illustrates the debt structure and percentage of the total as of December 31, 2017.

2017 Debt Structure Electric System Revenue Bonds 66% Electric System Subordinated Revenue Bonds 16%

Electric Revenue Notes -

Commercial Paper Series 7%

NCl Separate Electric System Minibonds Revenue Bonds 1%

10%

Details of the Company's debt balances and activity are included in Note 5 in the Notes to Financial Statements.

Debt Service Coverage for Electric S.ys.tem Revenue Bonds Debt service coverage for the Electric System Revenue Bonds was 3.42 and 2.20 in 2017 and 2016, respectively. OPPD's senior lien bond indenture provides that additional bonds may not be issued unless estimated net receipts for each future year shall equal or exceed 1.4 times the debt service on all Electric System Revenue Bonds outstanding, including the additional bonds being issued. Transactions in 2017 and 2016 for the NC2 Separate Electric System were not included in the calculation because the Electric System Revenue Bonds are not secured by the revenues from the NC2 Separate Electric System. The Company is in compliance with all debt covenants.

Debt Ratio The debt ratio is a measure of finandal solvency and represents the share of debt to total capitalization (debt and net position}. This ratio does not include the NC2 Separate Electric System Revenue Bonds since this debt is secured by revenues of the NC2 Separate Electric System. The debt ratio was 63.7% and 66.1% at December 31, 2017 and 2016, respectively.

Ratings High credit ratings allow the Company to borrow funds at more favorable interest rates. Both quantitative (financial strength} and qualitative (business and operating characteristics} factors are considered by the credit rating agencies in establishing a company's credit rating. The ratings received from Standard &Poor's Ratings Services (S&P} and Moody's Investors Service (Moody's), independent bond rating agencies for the latest bond issues, were among the highest ratings granted to electric utilities and confirm the agencies' assessment of the Company's strong ability to meet its debt service requirements. S&P and Moody's affirmed OPPD's senior lien debt and subordinated ratings, and both have stable outlooks for OPPD's credit ratings.

The following table summarizes credit ratings in effect on December 31, 2017.

S&:P Moody's Electric System Revenue Bonds AA Aa2 Electric System Subordinated Revenue Bonds AA- Aa3 Electric System Revenue Notes -Commercial Paper Series A-1+ P-1 Minibonds* AA- Aa3 NC2 Separate Electric System Revenue Bonds (2008A, 2015A, 2016A} At A1

• Payment of the principal and interest on the Minibonds, when due, is insured by a financial guaranty bond insurance policy.

ELECTRIC RATES The Company strives to manage costs to align with the mission of providing affordable, reliable and environmentally sensitive energy services to our customers. Residential customers paid an average of 11.49 and 11.47 cents per kilowatt-hour (kWh) in 2017 and 2016, respectively. The national average residential cents per kWh according to the Energy Information Administration (EIA),

U.S. Department of Energy, was 12.90 for 2017 (preliminary year-to-date December 2017) and 12.55 cents per kWh for 2016. Based on the preliminary EIA data for 2017, OPPD residential rates were 10.9% and 8.6% below the national average for 2017 and 2016, respectively.

Retail customers paid an average of 8.92 and 8.94 cents per kWh in 2017 and 2016, respectively. The national average retail cents per kWh according to the EIA, was 10.54 for 2017 (preliminary year-to-date December 2017) and 10.27 cents per kWh for 2016.

Based on the preliminary EIA data for 201 7, OPPD retail rates were 15.4% and 13.0% below the national average for 2017 and 2016, respectively.

There were no general rate or FPPA adjustments in January 2017. There was a general rate adjustment of 4.0% and an FPPA rate decrease of 0.6% implemented in January 2016. The Board approved a 5-year rate restructuring plan that was implemented in June 2016. The restructuring plan included an increase to the fixed service charge and a reduction to the variable charge for energy usage.

This plan was designed to be revenue neutral to OPPD. There was an FPPA rate adjustment of 17.0% in January 2018 that amounted to an average increase of 0.3%to customers. There was no general rate adjustment implemented in January 2018. The Company has committed to no general rate adjustments through 2021.

RISK MANAGEMENT Risk-Management Practices The District maintains an Enterprise Risk Management (ERM) program to help ensure strategic objectives are achieved. The program specifies risk-management standards, management responsibilities and controls to help ensure risk exposures are properly identified and managed within agreed upon risk-tolerance levels. Specific risk-mitigation plans and procedures are maintained and periodically reviewed to provide focused and consistent efforts to mitigate various risk exposures. Several cross-functional risk committees and an Executive ERM Committee, which includes the senior management team and legal counsel, are utilized to discuss and analyze the potential risks that could hinder the achievement of the Company's objectives. Additionally, the Company has established criteria for risk escalation and oversight. The risks are evaluated periodically and will be escalated to the appropriate oversight levels, up to and including the Board of Directors, when applicable. An overview of the ERM program is provided to the Board of Directors annually.

OPPD participates in the wholesale marketplace with other electric utilities and power marketers. The Company must be able to offer energy at competitive prices and maintain reliability to successfully compete in this market. Energy market prices may fluctuate substantially in a short period of time due to changes in the supply and demand of electricity, fuel and environmental-related commodities. Policies provide guidelines for transacting in the marketplace with the intent to mitigate market risk. Across-functional risk committee is responsible for identifying, measuring and mitigating various risk exposures related to power marketing and fuel purchase activities.

Fuel expense represents a significant cost and affects the ability to generate and market competitively priced power. To maintain a diverse portfolio of power supply, OPPD uses various fuel types for generation. Fuel policies were established to mitigate volumetric and price risk associated with the forecasted use of fuel for OPPD's generation.

ARate Stabilization Reserve was established in 1999 to assist in stabilizing retail electric rates. The Company added an additional

$8,000,000 and $26,000,000 to the reserve in December 2017 and 2016, respectively. The balance of the reserve was $50,000,000 and $42,000,000 as of December 31, 2017 and 2016, respectively. The balance of the fund was $50,000,000 and $33,000,000 as of December 31, 2017 and 2016, respectively.

ADecommissioning and Benefits Reserve was established in 2016 to assist in funding future decommissioning expenses beyond what was established in the current funding plan in any given year and future pension liabilities above the annual required contribution.

The Company added $34,500,000 and $0 to the reserve in December 2017 and 2016, respectively. The balance of the reserve was

$34,500,000 and $0 as of December 31, 2017 and 2016, respectively. The balance of the fund was $0 as of December 31, 2017 and 2016. The Company added $34,500,000 to the fund in 2018.

The Company promotes ethical business practices and the highest standards in the reporting and disclosure of financial information.

The Sarbanes-Oxley Act (Act) is intended to strengthen corporate governance of publicly traded companies. As a public utility, the Company is not required to comply with the Act, but the application of these requirements, where appropriate, ensures continued H OF'I'L' 111-JI-..JlJI\1 IU I'O irJ /0 I I

public trust in OPPD, protects the interest of its stakeholders and is a sound business practice. One of the most significant requirements of the Act pertains to managemenfs documentation and assessment of internal controls. The Company's management assesses internal controls for significant business processes that impact financial reporting. This assessment includes documenting procedures, risks and controls for these processes, and assessing the effectiveness and operation of the internal controls. In addition, the Company contracts with an independent third-party to administer the receipt, communication and retention of employee concerns regarding business and financial practices.

Other Reserves Other reserves are maintained to recognize potential events that arise in the normal course of business. Additional information about other reserves follows.

• The Electric System Revenue Bond Fund contains a reserve in accordance with OPPD's bond indenture to maintain an amount in reserve equal to the maximum amount required to be paid in interest in any calendar year.

• The Workers' Compensation and Public Liability Reserves are established for the estimated liability for current workers' compensation and public liability claims.

• The Incurred But Not Presented Reserve is an insurance reserve that is required by state law because the Company is self-insured for health care costs. The reserve is based on health insurance claims that have been incurred but not yet presented for payment.

• The Uncollectible Accounts Reserve was established for estimated uncollectible accounts from retail sales and property claims.

REGULATORY AND ENVIRONMENTAL UPDATES Souih\*Vest Power P'ooi (SPP) Integrated Marketpia.ce and Transmission Planning OPPD became a transmission-owning member of SPP on April 1, 2009, and all of the Company's trammission facilities were placed under the SPP Open Access Transmission Tariff (OAIT). In addition to tariff administration services, SPP also provides reliability coordination services, generation reserve sharing, energy market services, balancing authority services and planning authority services.

The SPP Real-Time Energy Imbalance Market, or Day 1 Market, was expanded into a Day 2 Market ilil 2014. The SPP Day 2 Market, also known as the Integrated Marketplace (IM), includes the Day-Ahead Market, Real-Time Market, Ancillary Services Market and Transmission Congestion Rights Market. OPPD actively participates in the IM. It provides a more transparent market by which load is served by the most efficient and economical generation while maintaining the reliability of the grid. The market mechanism rewards low-cost, flexible and reliable providers of electricity. OPPD's generation is in competition with other generation owners to serve load across the SPP footprint.

As the regional transmission expansion planning authority, SPP works with its members and stakeholders to develop transmission projects needed in the footprint to meet the reliability, economic, and public policy needs. One of SPP's regional transmission projects is the Elkhorn River Valley Transmission Project, which is a joint effort between OPPD and the City of Fremont to connect an OPPD substation in Blair with a substation in Fremont. The 23-mile line, consisting of a 161-kV segment and a 69-kV segment, is under construction and is planned to be in service by the fourth quarter of 2018. Once complete, the line will be owned by the Company.

This project is intended to support the growing demand for electricity and improve reliability. OPPD and the City of Fremont will share the costs of the project, with the Company paying 40% of the total costs. Additionally, a portion of the project will receive regional funding under the SPP OATT.

The SPP planning process also identified the need for a 345-kV power line that was built by the Company and Kansas City Power and Light. This transmission project connects a substation at the Nebraska City Station to Sibley, Missouri. The new line was completed and energized in December 2016. The project vl'i.ll receive regional funding under the SPP OATT.

Environmental Matters Environmental matters can have a significant impact on operations and financial results. OPPD complies with all applicable local, state and federal environmental rules and regulations. The items mentioned below include proposed, enacted or enforceable laws, rules and regulations.

The Environmental Protection Agency (EPA) published the Cross-State Air Pollution Rule (CSAPR) requiring designated states, including Nebraska, to significantly improve air quality by reducing generating station emissions that contribute to ozone and fine particle pollution in other states. Specifically, the rule requires significant reductions in sulfur dioxide (S0 2) and nitrous oxide (NOJ emissions crossing state lines.

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The final CSAPR rule established a cap-and-trade system with state- and unit-specific allowance allocations to achieve the desired emission reductions for S02 and NOx. Implementation of Phase I of the final rule began in 2015, and implementation of Phase II began in 2017. As a result of North Omaha Station Units 1, 2 and 3 (N01, N02, and N03) ceasing coal-fired generation, the Company will likely not need to purchase additional allowances in the future to comply with CSAPR.

The EPA issued regulations under Section 316(b) Rule of the Clean Water Act (316(b) Rule). The 316(b) Rule is designed to reduce fish mortality associated with the use of once-through cooling by power generating stations. Facilities are required to choose one of seven options to reduce fish impingement. The Company commenced Entrainment Characterization Studies at FCS, North Omaha Station (NOS), and Nebraska City Station (NCS) in Apri12016. OPPD commenced Comprehensive Technical Feasibility and Cost Evaluation Studies and Non-Water Quality Environmental Impacts Studies in January 2017. Additional studies necessary to determine the Best Technology Available will occur over the next year, and cost for compliance is not expected to be material at this time.

On April17, 2015, the EPA promulgated technical requirements for the Coal Combustion Residuals (CCR) Regulations that impacted landfills and surface impoundments for the safe disposal of coal combustion residuals under Subtitle Dof the Resource Conservation and Recovery Act. The regulations provide design criteria, operating criteria, groundwater monitoring requirements, closure requirements, and recordkeeping and notification requirements associated with CCR landfills and surface impoundments. The regulation became effective on October 19, 2015, and the Company is in compliance with the requirements. The Company continues to assess and implement compliance strategies associated with this regulation by required dates. On September 14, 2017, the EPA granted two petitions for the reconsideration of the CCR rule stating that it will review the existing rule and consider improvements that may help states tailor their CCR permitting programs. On March 15, 2018, the EPA proposed to amend the regulations for the disposal of CCR from electric utilities. The proposed rule establishes risk-based alternatives for implementing the CCR requirements, flexibility in meeting key prescriptive CCR requirements, and relief on uppermost aquifer location restrictions. The public has until April 30, 2018 to submit comments. The cost of compliance with this regulation is not expected to be material.

The EPA issued the Mercury and Air Taxies Standard (MATS), which places strict limitations on emissions of mercury, non-mercury metallic hazardous air pollutants and acid gases. Compliance with the new rule was necessary by April16, 2015, for NC2 and April16, 2016, for North Omaha Station Units 4 and 5 (N04 and NOS) and NCl. N01, N02 and N03 were repurposed from coal to natural gas prior to April16, 2016, which results in this standard no longer applying to these units. No new emissions-control equipment was required to comply with the new requirements for NC2 , although a new mercury-monitoring system was installed. OPPD retrofitted N04, NOS and NCl with basic emission controls. Dry Sorbent Injection and Activated Carbon Injection are being used on all of these units to comply with the MATS rule.

On October 23, 2015, the EPA published a final rule regulating the emission of carbon dioxide (C02) from existing fossil-fuel fired electric generating units under section 111 of the Clean Air Act. On the same date, the EPA also published a final rule for new, modified, or reconstructed fossil fuel-fired electric utility generating units under section 111 of the Clean Air Act. These regulations in the aggregate are known as the Clean Power Plan (CPP). The CPP required states to meet interim and final emissions targets on a state-wide basis starting in 2022. The goal was to reduce C02 emissions from electric generating units by 32% below 2005 levels by the year 2030.

Numerous legal challenges to the CPP have been filed and consolidated in the United States Court of Appeals for the District of Columbia Circuit. On February 9, 2016, the U.S. Supreme Court entered an order staying the implementation of the CPP pending further proceedings. Oral arguments were heard before the District of Columbia Circuit Court on September 27, 2016. On April 3, 2017, the EPA published in the Federal Register a notice that stated it is withdrawing the proposed rules it issued in 2015 in conjunction with the CPP. On October 10, 2017, the EPA issued a Notice of Proposed Rulemaking proposing to repeal the CPP. The public has until April26, 2018, to submit comments. The EPA has indicated an intent to issue a replacement rule by publishing an Advanced Notice of Proposed Rulemaking, with the goal of seeking comment on whether it will promulgate a replacement rule for existing units and what elements the replacement rule would contain. The Company will continue to monitor the regulation and evaluate compliance options as new information is available.

OPPD has received and responded to requests for information from the EPA relating to compliance with the Clean Air Act at the North Omaha and NC1 stations. OPPD received a Notice of Violation (NOV) from the EPA in August 2014 alleging a violation of the Clean Air Act by undertaking certain projects at NCl. The Company believes it has complied with all regulations relative to the projects in question and has discussed the matters with EPA. The EPA would have to establish the allegations in the NOV in court. If the EPA establishes a Clean Air Act violation in court, and subject to possible appellate court review, remedies can include civil penalties and a requirement to install pollution-control equipment. OPPD cannot determine at this time whether it will have any future financial obligation with respect to the NOV.

lf OPPf; M\lt'-IU/1.1 1~11'01<1 701 I

Renewable Capability including Purchased Power Contracts Renewable portfolio standards are currently mandated in several states but not in Nebraska. The Company established a goal of providing at least SO percent of retail energy sales from renewable energy sources. The addition of the Grande Prairie wind facility in 2017 added an additional400 megawatts (MW) of renewable capability and enabled the Company to meet the previous goal of 30 percent of retail energy sales from renewable energy sources. The addition of the Sholes Wind Energy Center in 2019 will add an additional160 MW of renewable capability. In addition, the Company has a purchased power contract with the Western Area Power Administration for up to 81.3 MW of hydro power.

The following table shows the renewable generation owned by OPPD and the purchased and future wind capability (in MW).

Capability OPPD-Owned Generation Elk City Station (landfill-gas) 6.3 Purchased Wind Generation*

Ainsworth 10.0 Elkhorn Ridge 25.0 Flat Water 60.0 Petersburg 40.5 Crofton Bluffs 13.6 Broken Bow I 18.0 Broken Bow II 43.9 Prairie Breeze 200.6 Grande Prairie 400.0 Subtotal Purchased Wind Generation 811.6 Total Renewable Generation as of December 31,2017 817.9 2019 Purchased Wind Generation Sholes 160.0 Total Expected Renewable Generation as of December 31, 2019 977.9

• Wind generation listed in ascending order of contract year signing.

Federal Energy legislation The llSth Congress started its two-year legislative session in January 2017. The only major legislation enacted in 2017 was tax reform, which included a provision to repeal the tax-exempt status of advance refunding of bonds. This provision took effect on January 1, 2018.

Comprehensive energy legislation was reintroduced, but it was not enacted. This included legislation that addressed energy efficiency, spent nuclear fuel, cyber security, energy workforce, Public Utility Regulatory Policies Act reform, hydropower, and various other areas.

Lastly, there has been an emphasis in the House of Representatives to look into modernizing energy laws. Several hearings were convened in 2017 to start the process, but no legislation has been enacted. OPPD continues to monitor the status of energy and environmental legislation in Congress and provides input through public power industry groups and the Nebraska Congressional Delegation.

State of Nebraska Energy legislation The Nebraska Legislature introduced three energy-related legislative bills (LB) during the 2017 session. LB 547 allowed for the private development of generation and transmission resources. LB 657 required public power districts to unbundle their rates. LB 660 allowed for customer choice in selecting an energy provider. These bills did not make it to the floor for discussion and were indefinitely postponed. OPPD continues to monitor the status of energy and environmental legislation in the Legislature and provides input, as needed.

l~li'I'D /\1'-lt-..JUAl RII'Clfrl 201 I /1

Fort Calhoun Station Update In August 2012, the Board of Directors authorized management to enter into a long-term operating agreement with Exelon Generation Company, LLC, (Exelon) to provide operating and managerial support at FCS for 20 years. In June 2016, the OPPD Board of Directors approved a recommendation by management to cease operations at FCS by December 31, 2016, and begin the decommissioning process using the safe storage ("SAFSTOR") methodology. The decision was made after a review of the Company's generation resource portfolio, and the station ceased operations on October 24, 2016. Upon completion of a third-party, site-specific cost study, OPPD recorded an increase to the decommissioning liability. The Board of DireLtors also approved a regulatory asset to match the decommissioning expense with the decommissioning funding amounts collected through retail rates.

The Operating Services Agreement with Exelon was terminated in June 2017, and the Licensing Agreement was terminated in December 2017. Ceasing FCS operations is expected to result in an improved competitive position, stable debt service coverage and reduced financial risks.

OPPD entered into an agreement with EnergySolutions Inc. (ESI) in February 2017 for decommissioning support services. OPPD retains the license and management responsibility for the facility, while benefitting from the advisory services provided by ESI. The agreement included both on-site and off-site support by personnel across multiple disciplines as needs are identified, including advice on the safe characterization, packaging, transportation and disposal of nuclear material.

SIGNIFICANT ACCOUNTING ESTIMATES AND ASSUMPTIONS The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions. These estimates and assumptions could affect the reported amounts of assets and liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the reporting period, and the disclosure of contingent assets and liabilities as of the date of the financial statements. Actual results could differ from those estimates.

These estimates could materially impact the financial statements and disclosures based on varying assumptions that could be used.

The financial and operating environment may have a significant effect on the operation of the business and on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting estimates and assumptions has not changed.

The following is a list of accounting estimates and assumptions that are significant to OPPD's financial condition and results of operation and require management's most significant, subjective or complex judgments. Each of these has a higher likelihood of resulting in materially different reported amounts under different conditions or using different assumptions.

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Significant Accounting Estimates Judgments/Uncertainties Affecting Application and Assumptions Nuclear Decommissioning

• Cost estimates for future decommissioning

• Availability of facilities for waste disposal

• Approved methods for waste disposal Environmental Matters

• Approved methods for cleanup

• Governmental regulations and standards

• Cost estimates for future remediation options Regulatory Mechanisms and

• External regulatory requirements Cost Recovery

• Anticipated future regulatory decisions and their impact Retirement Plan and Other

• Assumptions used in computing the Net Pension Liability Postemployment Benefits (OPEB) and OPEB actuarial liability, including discount rate, health care trend rates and expected rate of return on Plan assets

• Plan design Self-Insurance Reserves for Claims for

• Cost estimates for claims Employee-related Health Care Benefits,

• Assumptions used in computing the liabilities Workers' Compensation and Public Liability Uncollectible Accounts Reserve

• Economic conditions affecting customers

• Assumptions used in computing the reserve Unbilled Revenue

• Estimates for customer energy use and prices Depreciation and Amortization Rates of Assets

• Estimates for approximate useful lives lWPI' M'-!Nl_l/11 1\1 1'01{1 201 i  ;; :0

Report of Management The management of Omaha Public Power District (OPPD) is responsible for the preparation of the following financial statements and for their integrity and objectivity. These financial statements conform to generally accepted accounting principles and, where required, include amounts that represent management's best judgments and estimates. OPPD's management also prepared the other information in this Annual Report and is responsible for its accuracy and consistency with the financial statements.

To fulfill its responsibility, management maintains strong internal controls, supported by formal policies and procedures that are communicated throughout the company. Management also maintains a staff of internal auditors who evaluate the adequacy of and investigate the adherence to these controls, policies and procedures. OPPD is committed to conducting business with integrity, in accordance with the highest ethical standards, and in compliance with all applicable laws, rules and regulations. ACode of Ethics has been adopted for the Senior Executive and Financial Officers and the Controller, stating their responsibilities and standards for professional and ethical conduct.

Our independent auditors have audited the financial statements and have rendered an unmodified opinion as to the financial statements' fairness of presentation, in all material respects, in conformity with accounting principles generally accepted in the United States of America. During the audit, they considered internal controls over financial reporting as required by generally accepted auditing standards.

The Board of Directors pursues its oversight with respect to OPPD's financial statements through the Audit Subcommittee, which is comprised solely of non-management directors. The subcommittee meets periodically with the independent auditors, internal auditors and management to ensure that all are properly discharging their responsibilities. The subcommittee reviews the annual audit plan and any recommendations the independent auditors have related to the internal control structure. The Board of Directors, on the recommendation of the Audit Subcommittee, engages the independent auditors who have unrestricted access to the Audit Subcommittee.

~~

Timothy]. Burke President and Chief Executive Officer L. Javi e~r'Ferna~dlez Vice President and Chief Financial Officer

Independent Auditors' Report To the Board of Directors Omaha Public Power District Omaha, Nebraska We have audited the accompanying financial statements of Omaha Public Power District (the "Company"), which comprise the statements of net position as of December 31, 2017 and 2016, and the related statements of revenues, expenses and changes in net position, and cash flows for the years then ended, and the related notes to the financial statements, which collectively comprise the Company's financial statements.

Management's Responsibility for the Financial Statements Management is responsible for the preparation and fair presentation of these finandal statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors' Responsibility Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the finandal statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the finandal statements.

We believe that the audit evidence we have obtained is suffident and appropriate to provide a basis for our audit opinion.

Opinion In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

• Other Matter Required Supplementary Information Accounting principles generally accepted in the United States of America require that the Management's Discussion and Analysis on pages 12 through 23 and the schedule of changes in total pension liability, net pension liability and related ratios, schedule of contributions, and related notes within the Required Supplementary Infonnation section on pages 61 through 63 be presented to supplement the financial statements. Such information, although not a part of the financial statements, is required by the Governmental Accounting Standards Board who considers it to be an essential part of finandal reporting for placing the financial statements in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management's responses to our inquiries, the financial statements, and other knowledge we obtained during our audits of the financial statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with suffident evidence to express an opinion or provide any assurance.

~t~Ltt.,P DELOITIE & TOUCHE LLP Omaha, Nebraska March 29, 2018 Cll'r'DJ\I'JhJlJ/\1 RII'Cll\1 2(11/ )~

Omaha Public Power District Statements of Net Position as of December 31, 2017 and 2016 ASSETS 2017 2016 (thousands)

CURRENT ASSETS Cash and cash equivalents ....................... . . . ...... . . . . . . . ...... . s 10,054 $ 13,649 Electric system revenue fund ........ . .......... . .. ... .. .. . ... . . . ..... . . . 196,146 114,116 Electric system revenue bond fund . ... . .. . ...... . .. . .. ... . . . .. . .......... . 85,490 97,814 Electric system subordinated revenue bond fund . . .. ... .. .. . . . ... . .. .. .. .. . . 6,584 5,666 Electric system construction fund ............. .. .. ... . . .. . ......... . .. .. . . 222,858 221,247 NC2 separate electric system revenue fund ..... .. . ...... . ................. . 14,380 14,080 NC2 separate electric system revenue bond fund ......... . ................. . 17,896 18,013 NC2 separate electric system capital costs fund . ..................... . ...... . 6,738 9,486 Accounts receivable - net .. ... . .. .. ....... . ............ . ...... . ....... . . 130,511 131,425 Fossil fuels - at average cost . .. .. .. . .. ....... ... . ... ....... .... . . . ..... . . 35,039 28,328 Nuclear fuel held for sale .. .. . ... . . ..... ... ... . ............. ..... ...... . 12,453 Materials and supplies - at average cost . ........... ......... . ..... . ....... . 79,008 77,896 Regulatory asset - FCS decommissioning . .. ........ .. .......... . ......... .. 156,000 147,000 Other (Note 2) ...................... ... .. .. .... .. ... . .... .. .......... . 35,211 30!058 Total current assets ................. . ...... .... ...... . *........ . . .... 995,921 921,231 SPECIAL PURPOSE FUNDS - at fair value Electric system revenue bond fund -net of current . . . . . ... . . .. .... .. . . ..... . 47,519 41,083 Segregated fund -rate stabilization (Note 3) ...... . . . . .......... . .. ... . . ... . 50,000 33,000 Segregated fund -other (Note 3) .............. . . . ..... . ............. . .. .. 42,009 36,317 Electric system construction fund - net of current .. ........ .. .... . . .. . .. ... . 20,260 20,481 Decommissioning funds (Note 3) . . . . .... . .. .............. . . ... .. . ....... . 421,257 382,134 Total special purpose funds . . .. . . ..... . . *......... .. ......... . ...... .. 581,045 513,015 UTILITY PLANT - at cost Electric plant ............................. .............. .. ..... . .. .. . . 4,350,603 4,305,055 Less accumulated depreciation and amortization .............. ... ......... . . 1,819,255 1,743,661 Total utility plant - net .................. ... ... . ... .. ... . .... . . .... .. 2,531,348 2!561!394 OTHER LONG-TERM ASSETS Regulatory asset - FCS decommissioning - net of current. .... . .. ........ . ... . . 534,068 717,093 Regulatory assets (Note 2) .... ....... . . ...... ... . . ...... .. ..... . ... . . .. . . 483,716 456,560 Other (Note 2) ............ .......................... . ..... .. ... . ... . . 76,150 5,787 Total other long-term assets . ... ........... . ... ...... .. .......... . .... . 1,093,934 1,179,440 TOTAL ASSETS . .......... ...... . ... ..... .. ..... . ... . ...... . ....... . . 5,202,248 5,175,080 DEFERRED OUTFLOWS OF RESOURCES Unamortized loss on refunded debt ..... .. .. . . ....... . ......... . . ........ . 90,258 90,333 Unrealized pension contributions and losses (Note 6) . ... . ..... . . .. ....... .. . . 192,273 172,695 Ash landfill ...................... . . . . .. . . .............. . .......... . . . 11,788 2,960 Total deferred outflows of resources . .... .. ...... ... .. .. ... . ... .. ... .. . . . 294,319 265,988 TOTAL ASSETS AND DEFERRED OUTFLOWS .... . ..... . .... . . .... .. ..... . $5,496,567 $5,441,068 See notes to finandal statements 2f UI'I'D /1NhiU/\l fUPOI\1 201;

Omaha Public Power District Statements of Net Position as of December 31, 2017 and 2016 LIABILITIES 2017 2016 (thousands)

CURRENT LIABILITIES Electric system revenue bonds (Note 5) .................................... . $ 47,495 $ 45,595 Electric system subordinated revenue bonds (Note 5) .. ... ......... ... . ....... . 1,180 95 Electric revenue notes - commercial paper series (Note 5) .... . ... . .. . .. .. . . .. . .... . 150,000 NC2 separate electric system revenue bonds (Note 5) . ....... . ... . . . .... . . .. .. . . . . . 3,220 3,245 Accounts payable .............. .. . ..... . .................... . .. . .. . . .... . .. . 84,934 82,624 Accrued payments in lieu of taxes .. . ........ . ........ . ............. . . . . . .. . .. . 32,933 33,022 Accrued interest .. ..... . .............. . ............ . ... . ........... . . . .... . . 34,708 39,376 Accrued payroll ..... . . .......... . ..... . ... . .............. . .. . ...... . ...... . . 25,062 25,471 Decommissioning... . .................. . . ................... . ...... . ....... . 89,665 124,685 Other (Note 2) .... .................... . . . . . .... .. .. ...... . .. . ..... . . ....... . 20,237 17,844 Total current liabilities ........... ... . . . . . .............. . .. . .............. . 489,434 371,957 LIABILITIES PAYABLE FROM SEGREGATED FUNDS (Note 2) ............. . 30,334 35,626 LONG-TERM DEBT (Note 5)

Electric system revenue bonds - net of current ......... . . ............ . .... .. . 1,352,150 1,412,770 Electric system subordinated revenue bonds - net of current . ........... . ....... . . . 335,940 337,185 Electric revenue notes - commercial paper series ........... . .... ....... . ..... .. .. 150,000 Minibonds .......................................... . .. . ...... . . . .... . ... . . 30,273 29,816 NC2 separate electric system revenue bonds- net of current . . ... .............. ... . 211,995 215,215 Total long-term debt .............. . ... . ....... . .... . ... . ......... . ...... . 1,930,358 2,144,986 Unamortized discounts and premiums .. . . ... . . ... . .. ... ................ . .. . . . . 195,838 193,225 Total long-term debt - net ......... . ... . ....... . .... . ... . ....... . . . ...... . 2,126,196 2,338,211 OTHER LIABILITIES Decommissioning- net of current ..... . .......... . ...... .. ... . .. .. ..... . . . 1,085,668 1,124,912 Pension liability (Note 6) ............. . .......... . .............. ... . .. . .. . 547,945 487,177 Other (Note 2) .................................................. . . . ... . 39,042 27,715 Total other liabilities ................................ ......... . . . . . .. . 1,672,655 1,639,804 COMMITMENTS AND CONTINGENCIES (Note 13)

TOTAL LIABILITIES ....................................... . . . . . ..... . 4,318,619 4,385,598 DEFERRED INFLOWS OF RESOURCES Rate stabilization reserve (Note 7) ............. . . . ...... . ........ . ......... . 50,000 42,000 Decommissioning and benefits reserve (Note 7) . . ........ . ...... . . . ......... . 34,500 Unrealized pension gains (Note 6) ............ . ............... . ........... . 2,810 Unamortized gain on refunded debt. .......... . ............. . . . ........... . 113 141 Total deferred inflows of resources ........ . ............... . . . .......... . . 87,423 42,141 1\i'ET POSITION Net investment in capital assets . .. . . ..... . . . ............. . . . . . .......... . . 619,895 595,498 Restricted ............. . ... . ... . ...... . . . ............. . . . ............ . . 66,014 50,183 Unrestricted ........ .. . ... . ... . .. ..... . ............... . .......... . . . . . . 404,616 367,648 Total net position .. . ... . .. . .... . ................... . .......... . . . .. . 1,090,525 1,013,329 TOTAL LIABILITIES, DEFERRED INFLOWS AND NET POSITION ...... . . . .. . $5,496,567 $5,441,068 U!'I'U ANNIJ/,1 f(li'C>i{ 1 20 I; 2! See notes to finanda/ statements

Omaha Public Power District Statements of Revenues, Expenses and Changes in Net Position for the Years Ended December 31', 2017 and 2016 2017 2016 OPERATING REVENUES (thousands)

Retail sales ........... ... . . .. .......... .. .......... ... ........ . ... . ....... . . $ 911,733 $ 921,052 Off-system sales....... ................. . ...... ...... ...... . ... . ............ . 163,762 175,506 Other electric revenues . . . ... ... ..... . .... . ... ...... ... ..... . . ............... . 28,806 29,918 Total operating revenues . ... .... . . ...................... . . ..... ........ . . . 1,104,301 1,126,476 OPERATING EXPENSES Operations and maintenance Fuel ........................ . . . ............ . . . . . . . ............ . ........ . 170,372 186,766 Purchased power ..... .... .... . .... . ......... . . . . . ............ .... . ... . ... . 166,169 119,511 Production ................... . . . .......... . . . . . . . ....................... . 79,103 252,312 Transmission . ....... ... .... . . . .. .... ..... ... ... .. . .... .. . .. . .... .... .... . 40,085 35,681 Distribution .................... . ...... . . . . . . . ....................... . . . . . 49,947 44,750 Customer accounts .. .. .. .... . .. .. .. . . .. . .. ......... . . . . .. . . ...... . . . . . .. . . 17,973 16,718 Customer service and information .. . .... . . . . . . . . . ................... . . . . . . . . . 14,035 15,205 Administrative and general. ..... ..... .. ............................ .... .... . 115,609 152,914 Total operations and maintenance ..... . . . ......................... . . . ..... . 653,293 823,857 Depreciation and amortization . ...... ............ . ................. . ......... . 140,635 149,546 Decommissioning ........... . ........ . . . . . ..................... . . . ......... . 147,469 17,576 Payments in lieu of taxes ..... ................. . ... .. .......... . .. . .. . ....... . 33,989 34,138 Total operating expenses .. . ....... .... . .... . .. . ..... ..... .. .. . . . ......... . 975,386 1,025,117 OPERATING INCOME ..... ......... .. ... . ..... . .. ... . . . . ... . .. . . . .. ... . . . . . 128,915 101,359 OTHER INCOME (EXPENSES)

Contributions in aid of construction .................................... ....... . 31,064 17,918 Reduction of plant costs recovered through contributions in aid of construction . .. . .. . . (31,064) (17,918)

Decommissioning funds - investment income ... ............. . . . . ...... .. . .. . ... . 11/382 9,374 Decommissioning funds - reinvestment ...... ... . .. .. .... . .. . . ..... ..... .. ... .. . (13,929)

Investment income ....................... . ....... . ... .. . . ....... . .. . . . . . . .. . 5,420 3,512 Allowances for funds used during construction . . ...... . ... . ... ..... ... .. . . ...... . 2,988 7,380 Products and services - net. . .... . . .... . . . ...... .. . . ... . .............. . ... . ... . 3,903 3,739 Other- net (Note 10) ....... . . . ...... ............ . ... . .. . .... ... . ........... . 10/813 2,229 Total other income - net. .... . ................. . . . . ........ ... . ... . ....... . 34/506 12,305 INTEREST EXPENSE ..... ... ....... .. .. .. ...... . ... .... . .... .. . ...... . . ... . 84,253 87,914 NET INCOME BEFORE SPECIAL ITEM . ..... .... .... . .... . .. .... ... .... .. . . . . 79,168 25,750 SPECIAL ITEM (Note 12) .................. . . . . . ......... .. . ... . .......... .. {1,972) (959,575)

NET INCOME (LOSS) ................. .. . ... . . ......... . ... . ..... . . ........ . 77!196 (933,825)

NET POSITION, BEGINNING OF YEAR .. . .............. . ... . ....... ...... .. . 1,013,329 1,947,154 NET POSITION, END OF YEAR .... .... . . .. .... . ....... . .. . . ..... . ......... . $1/090,525 $1,013!329 See notes to financial sfiltements n OI'I'IJ 1\NI\jLJAI 1\f 1'01( 1 20 I i

Omaha Public Power District Statements of Cash Flows for the Years Ended December 31, 2017 and 2016 2017 2016 (thousands)

CASH FLOWS FROM OPERATING ACTIVITIES Cash received from retail customers ......... .... . ......... . . .. .. .. . .. . . ..... . ... .. ... . $ 976,173 $ 972,986 Cash received from off-system counterparties . . . . . . .. . .. . . ..... . ... . . .. . . .. . ... . .. . ... . . . 177,446 149,706 Cash received from insurance companies ..... . ... . . .. . .. . ..... . . . ..... . . . . .... . ....... . 2,008 Cash received from sale of nuclear fuel .. . ... .......... . . . .. ... .. . .. . .. . .. ... .. .. . .. .. . . 15,200 787 Cash received from other sources ......... .... .. ... ... .. . . ... ... ..... . . . ... .. . ....... . 5,425 5,643 Cash paid to operations and maintenance suppliers ..... ....... . ...... .. . . ..... .. .. ... . .. (393,721) (462,671)

Cash paid to off-system counterparties .. ........ .. ... ................. . . .. . ... . ... ... .. (157,184) (102,470)

Cash paid to employees ..... . ............ . . . ......... .. .. .. . . . .. . . .. . ...... . . ...... . (142,088) (155,658)

Cash paid to pension and OPEB obligations ....... ... .... . ................. ........ .... . (81,307) (73,751)

Cash paid for in lieu oftaxes and other taxes ... ........... ............. . .... .......... .. (34,078) (32,301)

Net cash provided from operating activities .... ... ........ .. . ... . . . . . . ...... . .. . . ..... . . 367,874 302,271 CASH FLOWS FROM NONCAPITAL FINANCING ACTMTIES Proceeds from federal and state agencies ..... ............ ...... . . .... .......... . .. ..... . 4,828 Net cash provided from noncapital financing activities ..... .... ... ... . . .. . ..... . . . ....... . 4,828 CASH FLOWS FROM CAPITAL AND RELATED FINANCING ACTMTI.ES Proceeds from long-term borrowings . .. . ..... . . .... .. ... .. .. ....... . .. . . .. . . . . . .. ... . . . 428 5,760 Principal reduction of debt. ............ . ........... . .. . .. .... ..... . ... . .. . ... . .. . ... . (49,125) (46,477)

Interest paid on debt .............. .. ... . .. . ....... . ..... . ... . . . . . . .. ..... . ... ... . . . (87,198) (96,483)

Acquisition and construction of capital assets ......... .. . . .. ... .... . .... .. . .. .. .. ..... . . (144,135) (149,647)

Contributions in aid of construction and other reimbursements . . . . . ...... . . . ... . . . . . ... . . . . 32,724 29,320 Acquisition of nuclear fuel. ........ . ......... .. ....... . ... .. . .. . .... . .... . .. .. . .. ... . (17,177)

Net cash used for capital and related financing activities . . . ..... . . . . .. . . . .... . .. . . .. . . . . . . . (247,306) (274,704)

CASH FLOWS FROM INVESTING ACTMTI.ES Purchases of investments .......................... . . . ... . . . . .. ... . . . . . . . ..... . ... . . . (1,436,950) (1,245,733)

Maturities and sales of investments .. . ...................... . .. . ... . ... . .......... . : .. . 1,33§,139 1,216,074 Purchases of investments for decommissioning funds ........ .. . .... . ... . ..... .. . . . . .. . . . . (373,190) (308,730)

Maturities and sales of investments in decommissioning funds .. . .. . ... . ... . . . ........ . ... . 336,087 299,949 Investment income ........................ . . .. .. .. .. ... ... . . ... .. . ..... .. ... . .. . . . . 14,751 11,847 Net cash used for investing activities ...... . ..... ... .. . .. . .. . . .. . .. ... .. .. ..... .. . ..... . (124,163) (26,593)

CHANGE IN CASH AND CASH EQUIVALENTS .. . .. . . .... . .... . . ... . ...... . ..... . . . . . (3,S95) 5,802 CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR. . . . .. . ... . . ... .. . ... . ....... . 13,649 7,847 CASH AND CASH EQUIVALENTS, END OF YEAR ... . . ... . . . ....... . . . . . . . . . . .. . . . .. . $ 10,054 $ 13,649 See notes to financial statements t)l' l*l' i\I'J I'>!Ui\1 IUI'Ok 1 )C! I I 2~

Omaha Public Power District Statements of Cash Flows for the Years Ended December 31, 2017 and 2016 The following table provides a reconciliation of the statements of cash flows from operating activities to operating income as of December 31.

2017 2016 (thousands)

Operating income . ...... ........................... . ........................ . . . $ 128,915 $ 101,359 Adjustments to reconcile operating income to net cash provided from operating activities:

Depreciation, amortization and decommissioning ........ . . .. .. .. . . . .. . . ... ...... . 125,799 147,691 Amortization of nuclear fuel. .... . . ...... . . . . ........................ . ..... ... . 21,693 Changes in assets and liabilities:

Accounts receivable .. . ........ . .... . . ... . . . ................................. . 3,923 (28,964)

Fossil fuels .......... ...................... . ...... .. ... ......... .......... .. . (6,711) 3,333 Materials and supplies .. .... ...... .. . .. .. . . . ...... .. .. .. .. ..... ........... ... . 9,369 594 Accounts payable .... . ..... ......... ... .. .. . ........................... . . ... . (10,273) (17,237)

Accrued payments in lieu of taxes and other taxes . .. .. . ... ................... . . .. .. . (89) 1,837 Accrued payroll .............. . .... . .. . . .. .. . ....... ...... . .. . ............. . .. . .. . . (409) (1,125)

SPP and other special deposits . ......... . .. . ............. ....................... . ... . (28) 1,000 Rate stabilization reserve ...... .. .. ........ . .......... . ......... . . .......... ...... .. . 8,000 26,000 Decommissioning ancl benefits reserve . ........ .... ....... .. . .......... .. . . .... . 34,500 Regulatory assets ............................ ....... . ......... ....... .. ... .. . ..... . 51,281 25,579 Other ............................. ........ .. ..... . .. ... .... ....... ..... .. . ..... . 23,597 20,511 Net cash provided from operating activities .......... . ............. . ......... . $ 367,874 $302,271 The following table summarizes the supplemental disclosure of noncash capital, financing and investing activities as of December 31.

2017 2016 (thousands)

NONCASH CAPITAL, FINANCING AND INVESTING ACfMTIES Bond proceeds transferred directly to irrevocable trust to defease outstanding bonds ... . ... . $ 256,159 $336,699 Utility plant additions from outstanding liabilities ............... .... . ......... .. ... . . 14,582 11,216 Net amortization of debt related expenses, premiums and discounts ................ . . . . . 9,818 8,209 Allowances for funds used during construction .. . . .. . . ......... .. .... . .. ... .... . . . . . 2,988 7,380 Unrealized gains/(losses) on investments ............. . .. . .. . . . . . . . . . .. . ..... . .. . 1,016 (118)

See notes to finandal statements 3t. Ul'l'll 1\NI--JU;\L IU I'ClkT 201 I

Notes to Financial Statements as of *and for the Years Ended December 31, 2017 and 2016

1.

SUMMARY

OF SIGNIFICANT ACCOUNTING POLICIES Organization and Business- The Omaha Public Power District (OPPD or Company), a political subdivision of the state of Nebraska, is a public utility engaged in the generation, transmission and distribution of electric power and energy and other related activities.

The Board of Directors is authorized to establish rates. OPPD is generally not liable for federal and state income or ad valorem taxes on property; however, payments in lieu of taxes are made to various local governments.

Basis of Accounting- The financial statements are presented in accordance with generally accepted accounting principles (GAAP) for proprietary funds of governmental entities. Accounting records are maintained generally in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and all applicable pronouncements of the Governmental Accounting Standards Board (GASB).

OPPD applies the accounting policies established in the GASB Codification Section RelO, Regulated Operations. This guidance permits an entity with cost-based rates to include costs in a period other than the period in which the costs would be charged to expense by an unregulated entity if it is probable that these costs will be recovered through rates charged to customers. This guidance also permits an entity to defer revenues by recognizing liabilities to cover future expenditures. The guidance applies to OPPD because the rates of the Company's regulated operations are established and approved by the governing board.

If, as a result of changes in regulation or competition, the ability to recover these assets and to satisfy these liabilities would not be assured, OPPD would be required to write off or write down such regulatory assets and liabilities unles~ some form of transition cost recovery continues through established rates. In addition, any impairment to the carrying costs of deregulated plant and inventory assets would be determined. There were no write-downs of regulatory assets for the year ended December 31, 2017. As a result of the Board decision in June 2016 to cease operations at Fort Calhoun Station (FCS), the related assets were determined to be in1paired and the regulatory assets for outage and depreciation costs were written off. There were no other write-downs of remaining regulatory assets for the year ended December 31, 2016. See Utility Plant and Regulatory Assets and Liabilities sections of Note 1 and Note 12.

Classification of Revenues and Expenses- Revenues and expenses related to providing energy services in connection with the Company's principal ongoing operations are classified as operating. All other revenues and expenses are classified as non-operating and reported as other income (expenses) on the Statements of Revenues, Expenses and Changes in Net Position.

Revenue Recognition- Electric operating revenues are recognized as earned. Meters are read and bills are rendered on a cycle basis.

Revenues earned after meters are read are estimated and accrued as unbilled revenues at the end of each accounting period.

Cash and Cash Equivalents- The operating fund account is called the Electric System Revenue Fund (Note 3). Highly liquid investments for the Electric System Revenue Fund with an original maturity of three months or less are considered cash equivalents.

Restricted cash and cash equivalents, if any, are included in the Special Purpose Fund balances.

Accounts Receivable - Accounts Receivable includes outstanding amounts from customers and an estimate for unbilled revenues. An estimate is made for the Reserve for Uncollectible Accounts for retail customers based on an analysis of Accounts Receivable, economic conditions affecting customers and historical write-offs net of recoveries. Additional amounts may be included based on the credit risks of significant parties. Accounts Receivable includes $48,832,000 and $49,881,000 in unbilled revenues as of December 31, 2017 and 2016, respectively. Accounts Receivable was reported net of the Reserve for Uncollectible Accounts of $1,505,000 and $1,500,000 as of December 31, 2017 and 2016, respectively.

Nuclear Fuel Held for Sale- The Company maintained nuclear fuel held for sale, which was valued at fair value until October 2017 when it was sold (Note 12).

Materials and Supplies -The Company maintains inventories that are valued at average cost. FCS materials and supplies are valued at the lower of cost or fair value (Note 12).

Utility Plant- Utility plant is stated at cost, which includes property additions, replacements of property units and betterments.

Maintenance and replacement of minor items are charged to operating expenses. Costs of depreciable units of electric plant retirements are eliminated from electric plant accounts by charges, less salvage plus removal expenses, to the accumulated depreciation account. Electric plant includes both tangible and intangible assets. Intangible assets include costs related to regulatory licenses, software licenses and other rights to use property. Electric plant includes construction work in progress of $39,738,000 and

$25,617,000 as of December 31, 2017 and 2016, respectively.

01'1-'D ANh!lJAI IU-1'01( l 2lll i 3',

Notes to Financial Statements as of and for the Years Ended December 31, 2017 and 2016 The following table summarizes electric plant balances as of December 31, 2016, activity for 2017 and balances as of December 31, 2017, (in thousands).

2016 Additions Retirements 2017 Electric plant $4,305,055 $ 97,571 $(52,023) $4,350,603 Less accumulated depreciation and amortization 1,743,661 127,617 (52,023) 1,819,255 Electric plant - net $2,561,394 $(30,046) $ $2,531,348 Long-lived assets, such as property, plant and equipment, are periodically reviewed for impairment or whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When the magnitude of the decline in service utility is significant and not part of the asset's normal life cycle, the asset is considered impaired.

As a result of the Board decision in June 2016 to cease operations at FCS, the Electric Plant in Service in the amount of $852,237,000 and the Accumulated Depreciation Reserve in the amount of $564,002,000 were written off as of December 31, 2016, in accordance with GAAP, and recorded to the Special Item on the Statements of Revenues, Expenses and Changes in Net Position (Note 12). There were no other write-downs for impairments to utility plant for the years ended December 31, 2017 and 2016.

Allowances for funds used during construction (AFUDC) approximates OPPD's current weighted average cost of debt. AFUDC was capitalized as a component of the cost of utility plant. The allowance for construction work in progress was computed at 3.3% and 3.4% for years ended December 31, 2017 and 2016, respectively. There was no AFUDC for nuclear fuel for the year ended December 31, 2017, due to the impairment of nuclear fuel in 2016 (Note 12). The allowance for nuclear fuel was 3.4% for the year ended December 31, 2016.

Contributions in Aid of Construction (CIAC) - Payments are received from customers for construction costs, primarily relating to the expansion of the electric system. FERC guidelines are followed in recording CIAC. These guidelines direct the reduction of utility plant assets by the amount of contributions received toward the construction of utility plant. CIAC is recorded as other income and offset by an expense in the same amount representing the recovery of plant costs. CIAC primarily includes payments for transmission, distribution and generating station assets. This allows for compliance with GASB Codification Section N50, Nonexchange Transactions, while continuing to follow FERC guidelines.

The following table summarizes the sources of CIAC as of December 31 (in thousands).

2017 2016 Transmission and distribution $ 21,021 $14,678 Nebraska City Station Unit 2 (NC2) participants 6,678 1,495 NC2 turbine replacement 3,365 1,769 FCS dry cask storage ____ill)

Total $ 31,064 $17,918 Depreciation and Amortization- Depreciation for assets is computed on the straight-line basis at rates based on the estimated useful lives of the various classes of property. Depreciation expense for depreciable property averaged approximately 3.0% and 3.3%

for the years ended December 31, 2017 and 2016, respectively. Depreciation is calculated using the following estimated lives:

• Generation 40 to 70 years

• Transmission and Distribution 15 to 75 years

• General 6 to 25 years Amortization of nuclear fuel was based on the cost thereof, and was recorded as nuclear fuel expense of $21,771,000 for the year ended December 31, 2016. Amortization was prorated by fuel assembly in accordance with the thermal energy that each assembly produced through October 2016 when FCS ceased operations (Note 12).

The FCS regulatory asset for recovery costs incurred in 2012 and 2013 were deferred as a regulatory asset based on Board approval.

These recovery costs were not included in the impairment, but will continue to be amortized (and collected through retail rates) through 2023 as these costs benefit current and future ratepayers. The amortization was $14,836,000 and $1,854,000 for the years ended December 31, 2017 and 2016, respectively. Prior to the transition to decommission FCS in November 2016, this expense was amortized as an operating expense (Note 12).

32 OPI'D Al\lhlliAl RIPC!Irl 201/

Intangible assets are amortized over their expected useful life. Amortization of intangible assets is included with depreciation and amortization expense in these financial statements. The amortization was $4,509,000 and $5,855,000 for the years ended December 31, 2017 and 2016, respectively.

NC2 was placed in commercial operation in 2009. Half of the unit's output is sold under 40-year Participation Power Agreements (PPAs). Certain participants funded their share of construction costs with NC2 Separate Electric System Revenue Bonds. These participants are billed for the debt service related to these bonds. The amounts recovered for debt service for the electric plant construction and other costs are included in off-system sales revenues. The revenues related to principal repayment will equal related depreciation and other deferred NC2 expenses over the 40-year term of the PPAs. Aregulatory asset was established to equate expenses and the amount included in off-system sales revenues for principal repayment in order to maintain revenue neutrality in the interim years. This regulatory asset will increase annually until2030 when principal repayments begin exceeding depreciation and other deferred expenses. After 2030, the regulatory asset will be reduced annually by recognizing deferred depreciation and other deferred expenses until its elimination in 2049, which is the end of the initial term of the PPAs.

In 2004, the Board of Directors approved a change in the depreciation estimate for FCS production plant assets to 2043. This estimate was 10 years beyond the term of FCS's operating license. Aregulatory asset was established for the difference in depredation expense resulting from the use of the estimated economic life of the asset versus the license term. The reduction in depredation expense was recorded each year as a regulatory asset in deferred charges until June 30, 2016. The Regulatory Asset for FCS Deferred Depreciation in the amount of $79,793,000 was written off as of December 31, 2016, as a result of the Board decision to cease operations at FCS and recorded to the Special Item on the Statements of Revenues, Expenses and Changes in Net Position (Note 12).

Also as a result of the Board decision in June 2016 to cease operations at FCS, there was a write-off of the accumulated depreciation reserve related to FCS assets. The write-off was $564,002,000 as of December 31, 2016, and recorded to the Special Item on the Statements of Revenues, Expenses and Changes in Net Position (Note 12).

The Board of Directors approved a resolution in June 2014 for the Future Power Generation Plan (Plan). The Plan included changes to the generation portfolio, including the retirement in 2016 of North Omaha Station Units 1, 2 and 3 (N01, N02 and N03), to comply with existing and future environmental regulations. The estimated useful lives of NOl, N02 and N03 were reduced as a result of the planned future retirement. NOl and N02 were fully depreciated as of April 2016. As a result of the June 2016 Board resolution to cease operations at FCS, a decision was made to retain N01, N02 and N03 using natural gas for capacity purposes through at least 2018.

The useful life of N03 was extended through 2018 beginning in July 2016. Subsequent to the FCS resolution, OPPD completed its 2016 Integrated Resource Plan. This plan, filed with the Western Area Power Administration in late February 2017, reflects the retention ofN01, N02 and N03 on natural gas through December 31, 2021. The useful life ofN03 was extended through 2021 beginning in March 2017. Depreciation expense for N03 was $646,000 and $3,506,000 for the years ended December 31, 2017 and 2016, respectively.

Nuclear Fuel Disposal Costs- Permanent disposal of spent nuclear fuel is the responsibility of the federal government under an agreement entered into with the Department of Energy (DOE). Under the agreement, there was a fee of one mill per kilowatt-hour on net electricity generated and sold from FCS. The collection of this fee was suspended in May 2014 until the DOE completes a fee adequacy study that complies with the Nuclear Waste Policy Act or until Congress enacts an alternative fuel-management plan. As a result of the suspension, there were no nuclear fuel disposal fees paid in 2017 or 2016.

The agreement required the federal government to begin accepting high-level nuclear waste by January 1998; however, the DOE does not have a storage facility. In May 1998, the United States Court of Appeals confirmed the DOE's statutory obligation to accept spent fuel by 1998, but rejected the request that a move-fuel order be issued. In March 2001, OPPD, along with a number of other utilities, filed suit against the DOE in the United States Court of Federal Claims, alleging breach of contract.

In 2006, the DOE agreed to reimburse OPPD for allowable costs for managing and storing spent nuclear fuel and high-level waste incurred due to the DOE's delay in accepting waste. Applications are submitted periodically to the DOE for reimbursement of costs incurred for the storage of high-level nuclear waste.

Nuclear Decommissioning- Based on the decommissioning plan established in 1983, the Board of Directors approved the collection of nuclear decommissioning costs using an independent engineering study of the costs to decommission FCS. The Company established a Decommissioning Funding Plan for FCS in 1990 in compliance with Nuclear Regulatory Commission (NRC) regulations.

Its purpose is to accumulate funds to decommission the radiated portions of FCS as defined by the NRC. The NRC's funding requirement is based on a defined cost formula and adjusted annually. The Company established a Supplemental Decommissioning Funding Plan for FCS in 1992 to accumulate funds to fully decommission FCS. This includes funds for additional costs beyond the NRC minimum that are needed to decommission the radiated plant, the fuel facility and the non-radiated plant.

UI'I'D J\~INlJ/\1 IU:I'Oin /Crl I 3?

Notes to Financial Statements as of and for the Years Ended December 31, 2017 and 2016 Based on cost estimates, inflation rates and fund earnings projections, no funding was necessary from 2001 through 2013 for either plan. However, an analysis by the Company and an outside consultant determined that additional funding was needed for the Supplemental Decommissioning Trust Fund beginning in 2014 to meet the estimated cost to fully decommission FCS. OPPD temporarily suspended funding for the Supplemental Decommissioning Trust Fund in September 2015 to reduce expenditures and the related impact on rates. In December 2015, the Board of Directors authorized the use of regulatory accounting to match the decommissioning expense to the amount funded. Funding resumed in January 2017. The annual funding amount was $147,469,000 and $0 for the years ended December 31, 2017 and 2016, respectively (Note 12). The Supplemental Decommissioning Trust Fund was reduced by $119,727,000 and $575,000 for the years ended December 31, 2017 and 2016, for expenditures incurred after ceasing operations and beginning the decommissioning process at FCS.

The estimated current cost to decommission the plant for the NRC-required obligations is $1,175,333,000 and $1,249,597,000 as of December 31, 2017 and 2016, respectively. These estimated costs are based upon a third-party, site-specific cost study (Note 12).

The decommissioning cost liability, which includes a current and long-term portion on the Statements of Net Position, is adjusted annually for inflation and any significant changes in the cost estimate.

Decommissioning Trust Funds are reported at fair value. Investment income was $9,699,000 and $9,275,000 for the years ended December 31, 2017 and 2016, respectively. The fair value of the Decommissioning Trust Funds increased $1,683,000 and $99,000 for the years ended December 31, 2017 and 2016, respectively.

Pension -Information about the fiduciary net position of the OPPD Retirement Plan and additions to/deductions from the fiduciary net position have been determined on the same basis as they are reported for purposes of measuring the net pension liability, deferred outflows of resources, deferred inflows of resources and pension expense. Benefit payments are recognized when distributed in accordance with the benefit terms. Investments are reported at fair value (Note 6).

Regulatory Assets and Uabilities -Rates for regulated operations are established and approved by the Board of Directors. The provisions of GASB Codification Section Re10, Regulated Operations, are applied. This guidance provides that regulatory assets are rights to additional revenues or deferred expenses, which are expected to be recovered through customer rates over some future period.

Regulatory liabilities are reductions in earnings (or costs recovered) to cover future expenditures.

The Company adopted the GASB accounting standards for the financial accounting and reporting of pension plans in 2015. These standards required the Company to recognize a liability for the net pension obligation on the Statement of Net Position. In December 2014, the Board of Directors authorized the use of regulatory accounting for pension costs to establish a regulatory asset to match the pension expense to the amounts funded and the cost recovery through rates.

The Board of Directors authorized the use of regulatory accounting in 2012 for significant, unplanned operations and maintenance costs at FCS incurred to address concerns from the NRC and enhance operations. These recovery costs are being amortized over a 10-year period that commenced in 2013 with FCS's return to service, as they continue to benefit future ratepayers (Note 12).

As previously noted, an NC2 regulatory asset was established to maintain revenue neutrality for transactions with participants who funded their share of construction costs with NC2 Separate Electric System Revenue Bonds. NC2 depreciation and other deferred expenses will equal the amount included in off-system sales revenue for principal repayments.

The Board of Directors also authorized the use of regulatory accounting for debt issuance costs in 2012 because of new accounting standards that would have required these costs to be expensed in the period incurred. These costs are amortized over the life of the associated bond issues consistent with the rate methodology.

AFuel and Purchased Power Adjustment (FPPA) was implemented in the retail rate structure in 2010. The Board of Directors authorized the use of regulatory accounting to maintain revenue neutrality by matching retail revenues attributed to fuel and purchased power costs with the actual costs incurred. This regulatory asset represents the rights to additional revenues based on incurred expenses due to under-recoveries of fuel and purchased power costs. This regulatory asset or FPPA, included in Other Current Assets, was $8,826,000 and $2,118,000 as of December 31, 2017 and 2016, respectively (Note 2). The FPPA regulatory assets were reduced for customer collections of $2,118,000 and $8,233,000 for the years ended December 31, 2017 and 2016, respectively.

The Board of Directors authorized the use of regulatory accounting for the unfunded supplemental decommissioning costs in December 2015. The use of regulatory accounting allows the matching of decommissioning expense to the amounts funded.

The unfunded portion of the liability based on NRC-required obligations was recorded as a Deferred Decommissioning Regulatory Asset (Note 12).