Tri-State Generation and
Transmission Association
2013 Annual Report
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Tri-State
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Transmission
Association
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People Colorado, Nebraska, New Mexico and Wyoming.
3
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Tri-State Generation and Transmission Association is a wholesale
electric power supplier owned by the 44 member systems we serve in
Colorado, Nebraska, New Mexico and Wyoming.
1
Member Distribution Systems
BH BIG HORN RURAL ELECTRIC COMPANY
NB NIOBRARA ELECTRIC ASSOCIATION
CB CARBON POWER & LIGHT
NR NORTHERN RIO ARRIBA ELECTRIC COOPERATIVE
Basin, Wyoming
Saratoga, Wyoming
Mountainair, New Mexico
Bayard, Nebraska
Deming, New Mexico
Grants, New Mexico
Montrose, Colorado
Cortez, Colorado
Powell, Wyoming
Gunnison, Colorado
Riverton, Wyoming
Pine Bluffs, Wyoming
Holyoke, Colorado
Española, New Mexico
Hugo, Colorado
Taos, New Mexico
Durango, Colorado
Grant, Nebraska
Mora, New Mexico
Fort Morgan, Colorado
Granby, Colorado
Limon, Colorado
CN CENTRAL NEW MEXICO ELECTRIC COOPERATIVE
CR CHIMNEY ROCK PUBLIC POWER DISTRICT
CO COLUMBUS ELECTRIC COOPERATIVE
CD CONTINENTAL DIVIDE ELECTRIC COOPERATIVE
DM DELTA-MONTROSE ELECTRIC ASSOCIATION
EM EMPIRE ELECTRIC ASSOCIATION
GL GARLAND LIGHT & POWER COMPANY
GC GUNNISON COUNTY ELECTRIC ASSOCIATION
HP HIGH PLAINS POWER
HW HIGH WEST ENERGY
HL HIGHLINE ELECTRIC ASSOCIATION
JM JÉMEZ MOUNTAINS ELECTRIC COOPERATIVE
KC K.C. ELECTRIC ASSOCIATION
KT KIT CARSON ELECTRIC COOPERATIVE
LP LA PLATA ELECTRIC ASSOCIATION
MW THE MIDWEST ELECTRIC COOPERATIVE CORPORATION
MO MORA-SAN MIGUEL ELECTRIC COOPERATIVE
MC MORGAN COUNTY RURAL ELECTRIC ASSOCIATION
MP MOUNTAIN PARKS ELECTRIC
MV MOUNTAIN VIEW ELECTRIC ASSOCIATION
Lusk, Wyoming
Chama, New Mexico
Hay Springs, Nebraska
Cloudcroft, New Mexico
Alliance, Nebraska
Fort Collins, Colorado
Mitchell, Nebraska
Pueblo West, Colorado
Monte Vista, Colorado
Nucla, Colorado
Buena Vista, Colorado
Elephant Butte, New Mexico
Socorro, New Mexico
La Junta, Colorado
Clayton, New Mexico
Springer, New Mexico
Brighton, Colorado
Sidney, Nebraska
Wheatland, Wyoming
Meeker, Colorado
Lingle, Wyoming
Akron, Colorado
NW NORTHWEST RURAL PUBLIC POWER DISTRICT
OC OTERO COUNTY ELECTRIC COOPERATIVE
PH PANHANDLE RURAL ELECTRIC MEMBERSHIP ASSOCIATION
PV POUDRE VALLEY RURAL ELECTRIC ASSOCIATION
RS ROOSEVELT PUBLIC POWER DISTRICT
SI
SAN ISABEL ELECTRIC ASSOCIATION
SV SAN LUIS VALLEY RURAL ELECTRIC COOPERATIVE
SM SAN MIGUEL POWER ASSOCIATION
SC SANGRE DE CRISTO ELECTRIC ASSOCIATION
SR SIERRA ELECTRIC COOPERATIVE
SO SOCORRO ELECTRIC COOPERATIVE
SE SOUTHEAST COLORADO POWER ASSOCIATION
SW SOUTHWESTERN ELECTRIC COOPERATIVE
SP SPRINGER ELECTRIC COOPERATIVE
UN UNITED POWER
WB WHEAT BELT PUBLIC POWER DISTRICT
WL WHEATLAND RURAL ELECTRIC ASSOCIATION
WR WHITE RIVER ELECTRIC ASSOCIATION
WY WYRULEC COMPANY
YW Y-W ELECTRIC ASSOCIATION
Major Tri-State Resources
1
HEADQUARTERS AND OPERATIONS CENTER
10 ESCALANTE GENERATING STATION
2
CRAIG STATION
11
3
NUCLA STATION
Westminster, Colorado
Craig, Colorado
Nucla, Colorado
4BURLINGTON STATION
Burlington, Colorado
5
J.M. SHAFER GENERATING STATION
6
LIMON GENERATING STATION
7
FRANK R. KNUTSON GENERATING STATION
8
RIFLE GENERATING STATION
9
LARAMIE RIVER STATION
2
Fort Lupton, Colorado
Limon, Colorado
Brighton, Colorado
Rifle, Colorado
Wheatland, Wyoming
Prewitt, New Mexico
Farmington, New Mexico
Lordsburg, New Mexico
Springerville, Arizona
12
13
SAN JUAN GENERATING STATION
PYRAMID GENERATING STATION
SPRINGERVILLE GENERATING STATION
14
DAVID A. HAMIL DC TIE
15
CIMARRON SOLAR FACILITY*
Stegall, Nebraska
Springer, New Mexico
16 KIT CARSON WINDPOWER PROJECT*
17
Burlington, Colorado
COLORADO HIGHLANDS WIND*
Fleming, Colorado
*Long-term purchase power arrangements.
WY
GL
BH
HP
HP
HP
NB
WL
NW
WY
RS
9
CB
PH
CR
14
WB
HW
CO
PV
MP
2
WR
17
5
HI
YW
7
1
6
MV
KC
GC
SC
SM
SI
EM
LP
11
NR
KT
SP
10
SW
15
MO
CD
CN
SO
SR
12
SE
SV
JM
13
16
4
DM
3
NE
MC
UN
8
MW
OC
NM
CO
3
2013
By the
Numbers
18.6m
15.3m
TOTAL ENERGY SALES (MwH)
ENERGY SALES
TO MEMBERS (MwH)
1,870mw 897mw
GENERATING CAPACITY, COAL
OWNED GENERATING CAPACITY,
NATURAL GAS/OIL
$1.3b $72.9m
TOTAL OPERATING
REVENUE
NET MARGINS
More than numbers — Tri-State is
NET MARGINS
($ in millions)
POWER PRODUCED
(megawatt-hours in millions)
104.9
13.1
13.3
13.2
12.1
77.1
12.5
72.9
69.9
52.8
2009 2010 2011 2012 2013
4
2009 2010 2011 2012 2013
3.3m 2,666mw 5,348
ENERGY SALES TO
NON-MEMBERS (MwH)
MILES OF
TRANSMISSION LINE
MEMBER PEAK DEMAND
853mw 558mw
12.5m
RENEWABLE
ENERGY RESOURCES
CONTRACTED
GENERATING CAPACITY
POWER PRODUCED
(MwH)
$4.6b
7.1¢
1,531
TOTAL ASSETS
AVERAGE WHOLESALE RATE
TO MEMBERS (per KwH)
EMPLOYEES
(includes subsidiaries)
powered by our hard working people.
TOTAL MEGAWATT-HOUR SALES
(megawatt-hours in millions)
18.6
18.9
19.4
18.7
18.6
2009 2010 2011 2012 2013
MEMBER COINCIDENT
PEAK DEMAND
(megawatts)
2,447
2,568
2,654
2,798
2,666
2009 2010 2011 2012 2013
5
Letter from the Chairman
“On behalf of the board of
directors, I want to thank all
of the dedicated employees at
Tri-State for the efforts they
put forth in 2013.”
On behalf of the board of directors, I want to thank all of the dedicated employees at Tri-State for the efforts they
put forth in 2013. They work tirelessly on behalf of our membership to steward our shared assets and ensure the
association is fulfilling its mission to provide a reliable, cost-based supply of electricity while maintaining a sound
financial position.
Operationally, financially and in all other aspects of our business, staff continues to perform well for the membership.
The cost of wholesale electric power to the membership remains a focus of our board. Despite the cost pressures
facing both the association and the electric utility industry in general, Tri-State has successfully controlled its costs
over the past five years. Since 2009, operating costs per megawatt-hour have held steady, or decreased, on a real, or
inflation adjusted, basis. As we look forward, real operating costs per megawatt hour are forecasted to be flat.
However, we can see how regulatory and compliance obligations continue to place pressure on our costs. Ensuring
we continue to advance our board strategic goals on regulation mitigation, long-term fuel and resource planning
and affordability remain critical to addressing and mitigating these cost pressures.
Tri-State remains financially strong, supported by its “A” financial ratings with “stable” outlooks from the major
rating agencies. As a sign of our financial health and as part of the value of being a cooperative, the board approved
the retirement of capital credits of $10 million. The allocation of capital credits and their retirement is an important
value in our cooperative business model.
In 2013, the association implemented a new rate and a new portfolio of demand response and energy shaping
products. These programs were successful and enrolled more than 150 megawatts of load to help manage risks.
As a board, we continue to address the intrusion into our self-governance by regulatory bodies in two states, which
is not in the best interests of our members. Since Tri-State was founded, the board of directors has determined the
rates at which wholesale power is sold to its members. Our system of governance has served the membership well
and it will in the future, as we work together in cooperation.
Tri-State is a dynamic and complex organization with a great deal of diversity throughout our membership. This has
strong operational advantages, but also requires us to work together to resolve our issues. The board of directors will
continue to support and preserve our governance, and we begin 2014 with a renewed commitment to the principle
of cooperation among cooperatives.
I sincerely thank the board for their continued support. It has been an honor to serve another year as president and
chairman of the board of directors.
RICK GORDON
Chairman
6
General Manager’s Message
“It’s people who are the real
power of our association, and I
would like to acknowledge the
hard work of all our employees
and the guidance from our
board in 2013…”
It’s people who are the real power of our association, and I would like to acknowledge the hard work of all our
employees and the guidance from our board in 2013 as we continued to grow our safety culture, keep the lights on,
contain costs and foster an environment for learning, while supporting the board’s strategic goals that prepare the
association for the future.
Safety is and always will be a top priority in all we do at Tri-State. We concluded the year with an excellent record
of staying safe on the job at our generating plants, field facilities and our other worksites. Tri-State’s key safety
metrics in 2013 were much better than industry averages.
In production, Tri-State’s workforce managed our diverse portfolio of coal-based and natural gas-fired generation,
coupled with purchased federal hydropower and other renewable resources, that continued to effectively meet the
membership’s power requirements during the year. In 2013, Tri-State fully integrated the operations at Colowyo
Mine and New Horizon Mine into its operations, and reduced production costs at Colowyo Mine with the addition
of a highwall miner.
Tri-State’s transmission assets performed reliably and achieved a number of notable accomplishments in 2013. The
association constructed 13 new substations, added 32 miles of line and increased load serving capability and system
performance at 27 existing substations. And as our workforce continues to experience transitions from retirements,
11 new journeyman graduated.
Several new renewable energy purchase agreements were executed in 2013, including the expansion of the Colorado
Highlands Wind farm and the addition of the 150-megawatt Carousel Wind Farm. At year’s end, 52 megawatts
of member renewable energy projects were constructed or under development. Tri-State persists in analyzing our
approach to cost effectively address an expanded Colorado renewable energy mandate passed by the state legislature
in 2013, of which the major components become effective in 2020.
Also in 2013, we had a renewed focus on customer service to our member systems, and instituted an advisory council
on demand response and energy shaping products to support the success of these important initiatives. Tri-State
continues to be engaged with regulators and policy makers regarding over-regulation of utilities in the environmental, energy policy and reliability sectors, and we continue to take steps to support compliance, reduce liabilities,
control costs and create efficiencies in these areas.
On behalf of our employees, we remain steadfast in our commitment to our member systems in not only providing
safe, reliable and affordable electricity, but also as a willing partner with each of our members to ensure that we are
delivering the products and services that bring the most value to the member-owners at the end of the line.
KEN ANDERSON
Executive Vice President and General Manager
7
Powered
by
People
SAFETY
Tri-State’s infrastructure consists of a variety of generating stations, thousands of miles of
COMPETENCY
transmission line, substations, field offices, computer networks and other facilities spread across
D E D I C AT I O N
a massive service territory. Behind those resources are a board and workforce that carry out
EXPERIENCE
their activities and responsibilities determined to deliver on the association’s goals and mission.
FOCUS
The power plants generate the electricity and the transmission lines transport it, but Tri-State is
COMMITMENT
truly powered by people.
8
Tri-State lists approximately $4.6 billion of assets on its balance sheet,
which includes power plants, transmission assets and a variety of properties, facilities, fleet of vehicles and other investments. What is not
immediately accounted for in that inventory is the value of the human
capital Tri-State relies on for the successful operation of the association
on behalf of its member systems.
Tri-State is governed by its board of directors, one from each of the
association’s 44 member systems, and powered by its 1,500-person
workforce, working in tandem with a shared purpose to deliver value to
the 44 member systems and their 1.5 million member-owners in communities across the West.
The association’s board, management and employees share common
principles and values, with safety being the highest priority.
That commitment is embraced and adhered to throughout the entire
organization. Promoting a culture of safety at all of the G&T’s facilities
is foremost in employees’ minds and is stressed every day for the
well-being of each and every person present at a Tri-State worksite.
Safety has and always will be one area where corners won’t be cut and
shortcuts won’t be tolerated.
Tri-State is governed by its
board of directors, one from
each of the association’s 44
member systems, and powered by its 1,500-person workforce, working in tandem with
a shared purpose to deliver
value to the 44 member systems and their 1.5 million
member-owners in communities across the West.
The association’s safety initiatives have been enhanced and fine-tuned
over the years. Some of the more recent improvements include adapting the Occupational Safety and Health Administration’s (OSHA)
Voluntary Protection Program (VPP) elements as the model for our own
safety and health program and the recent introduction of the Tri-State
“Safety Toolbox”—a collection of 12 key safety tools and practices
designed to help employees work safely. The Safety Toolbox has been
distributed to employees at generating stations, transmission field
­facilities and mines.
9
Employee engagement in safety and health is evident in a number of
ways that have produced tangible dividends. Two of Tri-State’s locations
currently participate in the prestigious VPP. 2013 saw Corporate Flight
Operations recertified as a VPP Star site facility as Escalante Station
continued its participation in the program as a Star site facility.
Companies participating in OSHA’s VPP establish a cooperative
working relationship with OSHA by working together to meet stringent safety criteria. Tri-State also experienced large reductions in lost
time accidents and injuries across the entire organization.
As a cooperative, the association is anchored by the seven cooperative
principles. The fifth principle, education, training and information, is
a central element of our culture. Tri-State’s employees are encouraged to
take advantage of a number of educational and training opportunities
made available to increase their knowledge and overall effectiveness.
These and other resources are provided for by the board of directors
and are aimed at evolving and growing each individual’s contribution
to the organization.
Tri-State’s leadership development programs are also developing the
next generation of leaders through learning and development. We
believe that leaders are developed—not trained. Leadership programs are
focused on people, potential, growth, effectiveness, solutions, culture
and the future. Through its programs, the association is investing in
the human resources that will move the organization forward.
10
Tri-State’s employees are
­encouraged to take advantage
of a number of educational and
training opportunities made
available to increase their
knowledge and overall
effectiveness.
Tri-State’s long-standing ability to reliably and responsibly “keep the
lights on” and deliver value to its member systems through the effective
operation of its power supply network is a direct ref lection of the
­competency, experience and capabilities of its workforce.
The results are apparent in the G&T’s ability to efficiently provide
affordable electricity to its member systems, while upholding a reliable
and well-maintained transmission system. Those efforts are further
enhanced by personnel in energy markets who continuously process
energy transactions while ensuring compliance with complex regulations and mitigating cost and regulatory risks.
Tri-State’s generating fleet of baseload stations, intermediate resources
and peaking plants performed well throughout 2013. The renewable
energy portion of the G&T’s energy portfolio continues to grow, with
the expansion of the Colorado Highlands Wind project to 91 megawatts
in 2013, and the approval by the board of directors to purchase power
from the 150-megawatt Carousel Wind Farm, which is expected to be
available in 2016.
Tri-State’s board and staff
will continue to explore, analyze and pursue renewable
energy resources that provide
value to the membership and
that address the association’s
requirements under established state renewable
portfolio standards.
The association has also pursued contracts for power produced at a
number of small, local hydro facilities in the region, including the
­historic 5-megawatt Boulder Canyon project and an 8-megawatt project
being developed near Ridgway, Colo. Tri-State’s board and staff will
continue to explore, analyze and pursue renewable energy resources
that provide value to the membership and that address the association’s
requirements under established state renewable portfolio standards.
11
Another extremely valuable
investment that generates its
own kind of power is the
asso­ciation’s longstanding
­commitment to youth and
education through a variety
of initiatives aimed at
empowering the leaders
of tomorrow.
At the same time, Tri-State continues to support its members in developing local distributed renewable projects
in their service territories through financial incentive policies and technical support. By year-end, those joint
efforts have resulted in approximately 52 megawatts of projects currently in operation or under development,
ranging from landfill gas, wind, solar and hydro.
As regulatory forces continue to place upward cost pressure on the electric utility industry, the association’s
board, management and employees remain focused on cost containment, which is critical for the financial
health not only of Tri-State, but also its 44 member systems and their member-owners. Tri-State stewards
significant resources for its membership and the G&T remains focused on effective and efficient operations,
making the investments necessary to ensure a reliable power supply and managing costs.
The commitment of Tri-State’s board and activities of its employees stretches beyond maintaining and
enhancing the association’s power supply network on behalf of its member co-ops. Another extremely valuable
investment that generates its own kind of power is the association’s longstanding commitment to youth and
education through a variety of initiatives aimed at empowering the leaders of tomorrow.
The association supports regional competitions, workshops and other events conducted by Future Farmers of
America and 4-H, as well as the National Western Stock Show and Rodeo, which provides college and
­g raduate-level scholarships in agriculture and veterinary medicine. Tri-State’s dedication to educational
­outreach and agricultural programs also includes providing classroom materials and instructive resources, as
well as promoting and sponsoring teacher development conferences and other learning opportunities.
Communication, coordination and collaboration are key tactics employed among the many departments and
functional areas that make up Tri-State’s workforce. Personnel across the organization rely on each other’s
experience and share a mutual trust and dependence to accomplish the task at hand.
That same trust is extended from the board of directors to management and employees—all of whom work in
conjunction with each other as stewards of the member systems’ shared assets to reliably, efficiently and
responsibly deliver on the association’s ongoing purpose and mission.
12
Board of Directors
RICK GORDON
TONY CASADOS
JIM SOEHNER
STUART MORGAN
BILL BIRD
MATT BROWN
MARSHALL COLLINS
JACK FINNERTY
JOE WHEELING
ROBERT BLEDSOE
LEO BREKEL
JERRY BURNETT
RICHARD CLIFTON
WAYNE CONNELL
LUCAS CORDOVA JR.
Chairman
Mountain View Electric
Assistant Secretary
High Plains Power
Highline Electric
Vice Chairman
Northern
Rio Arriba Electric
Executive Committee
Delta-Montrose Electric
High West Energy
Secretary
Y-W Electric
Executive Committee
Wheatland Rural
Electric
Carbon Power & Light
Treasurer
Wheat Belt Public
Power
Executive Committee
La Plata Electric
Central New Mexico
Electric
Assistant Secretary
Otero County Electric
K.C. Electric
Jémez Mountains
Electric
As a wholesale power cooperative, Tri-State is owned and governed by its 44 member
distribution systems, with the board of directors comprised of one representative from each
of its members. Each director is appointed by his or her local co-op to the Tri-State board,
with terms normally running one year. Tri-State’s Board officers serve from April to April
(coinciding with the association’s annual meeting).
The Tri-State board, which meets on a monthly basis, also is divided into four committees—
the Executive Committee (consisting of the six officers of the board along with three at-large
positions), the Engineering and Operations Committee, the Finance Committee and the
External Affairs/Member Relations Committee.
13
Board of Directors
GARY FUCHSER
RON HAGAN
JACK HAMMOND
RALPH HILYARD
DON KEAIRNS
HAL KEELER
JULIE KILTY
GARY MERRIFIELD
THAINE MICHIE
WILLIAM
MOLLENKOPF
Northwest Public Power
Columbus Electric
CHRIS MORGAN
Gunnison Electric
Midwest Electric
Wyrulec Co.
RICHARD NEWMAN
United Power
Niobrara Electric
Sangre de Cristo Electric
Roosevelt Public Power
Poudre Valley Rural
Electric
San Isabel Electric
Empire Electric
DIEGO QUINTANA
GARY RINKER
ART RODARTE
PAT BRIDGES
JENNIFER GOSS
MIKE MCINNES
Mora-San Miguel
Electric
Southwestern Electric
Kit Carson Electric
Senior Management
KEN ANDERSON
Executive
Vice President/
General Manager
14
JOEL BLADOW
Senior Vice President
Transmission
Senior Vice President
Chief Financial Officer
Senior Vice President
Member Relations
Senior Vice President
Production
CLAUDIO ROMERO
DON RUSSELL
BRIAN SCHLAGEL
GERALD SEWARD
J. H. SHERIDAN
JUDY SMITH
KEVIN STUART
JERRY THOMPSON
CARL TRICK, JR.
MARCUS WILSON
DONALD WOLBERG
SCOTT WOLFE
BILL WRIGHT
PHIL ZOCHOL
BRAD NEBERGALL
KEN REIF
JIM SPIERS
BARBARA WALZ
Continental Divide
Electric
Sierra Electric
Socorro Electric
Senior Vice President
Energy Management
Big Horn Electric
Chimney Rock
Public Power
San Luis Valley Electric
Senior Vice President
General Counsel
Morgan County
Rural Electric
Garland Light & Power
Southeast Colorado
Power
Senior Vice President
Business Strategy/
Chief Technical Officer
Springer Electric
Mountain Parks Electric
White River Electric
San Miguel Power
Panhandle Rural
Electric
Senior Vice President
Policy and Compliance/
Chief Compliance
Officer
15
Financial Highlights & Five-Year Financial Summary
Tri-State had an excellent year from a financial perspective and continued to take actions that will keep it financially strong well
into the future. Tri-State’s $72.9 million margin in 2013 provided a debt service coverage well in excess of the requirement in its
Master First Mortgage Indenture and helped grow the association’s equity as a percentage of total capitalization to 23.6 percent.
Tri-State’s liquidity remains strong. As of December 31, 2013, Tri-State had $193 million in cash, $75 million of unused committed lines of credit and a secured revolving credit facility with a total unused commitment of $322 million.
True to the cooperative business model, Tri-State’s board of directors declared a $10 million patronage capital refund to its members
during 2013, which makes this the 25th consecutive year that the association has returned capital credits.
The association maintained its A rating from the three major rating agencies, which is a strong testament to the financial planning
and business decisions made by the Tri-State board of directors and staff.
Tri-State continues to invest in its infrastructure through capital improvements and system upgrades in order to serve the growing
needs of its member distribution systems. Electric plant in service increased $108.9 million from December 31, 2012 to $5.0 billion
as of December 31, 2013.
The association provides power to its member systems and also sells power to other utilities in the region under long-term contracts
and market sale arrangements. Member electric sales for 2013 were 15,313,487 megawatt-hours which was a decrease of 403,981
megawatt-hours from 2012. Despite the decrease in megawatt-hours, member electric sales revenue increased $24.0 million, or
2.3 percent, to $1.1 billion due to a 4.9 percent rate increase effective January 1, 2013.
The 2013 non-member electric sales increased 306,173 megawatt-hours to 3,316,487 megawatt-hours primarily due to increased
2013 firm contractual sales out of Springerville Generating Station Unit 3 after having reduced sales in 2012 as a result of a threemonth outage to repair a damaged turbine at the unit. The increase in sales resulted in non-member electric sales revenue increasing
$9.4 million, or 5.8 percent, to $172.1 million in 2013.
Other operating income increased $13.8 million, or 50.6 percent, to $41.0 million in 2013 primarily due to increased lease revenues
resulting from the resumption of gas tolling arrangements at our Knutson and Limon generating stations on May 1, 2013.
Purchased power expense increased $11.8 million, or 3.8 percent, to $322.1 million in 2013. This increase was due to a 10.7 percent
increase in the average cost of purchased power resulting from higher market prices for electricity, offset by a 7.6 percent decrease
in megawatt-hours purchased. The decrease in purchases resulted from an increase in power generated at our generating stations
primarily due to the increased generation in 2013 from Springerville Generating Station Unit 3.
Fuel and production expenses increased $14.5 and $9.4 million, respectively, due to the increased generation at our coal-fired
generating stations in 2013 primarily due to the increased megawatt-hours generated at Springerville Generating Station Unit 3.
Generation maintenance expense decreased $13.2 million, or 12.6 percent, due to the reduction in 2013 scheduled and unscheduled
maintenance outages at our coal generating stations.
Tri-State’s strong financial position and creditworthiness provide the association with the continued ability to meet the future
needs of the member distribution systems and their member-owners.
TOTAL OPERATING REVENUE
($ in millions)
1,164
1,212
1,176
1,257
PATRONAGE CAPITAL RETIREMENTS
($ in millions)
20.0
1,304
10.0
2009 2010 2011 2012 2013
16
20.0
10.0
10.0
2009 2010 2011 2012 2013
(Thousands)
Operating revenues
Member electric sales
Non-member electric sales
Other
Operating expenses
Power costs
Lease expense
Transmission
General and administrative
Depreciation and amortization
Income taxes
Operating margins
Other income
Other deductions
Interest expense
Other expenses
2013
2012
2011
2010
2009
$1,091,103
172,102
40,994
$1,067,085
162,694
27,217
$1,007,993
152,806
15,381
$981,126
208,357
22,933
$926,428
209,126
28,342
(819,522)
(5,276)
(138,684)
(24,325)
(118,776)
—
(797,136)
(6,714)
(136,853)
(22,810)
(115,958)
—
(727,185)
(19,365)
(136,825)
(18,930)
(105,793)
10
(728,735)
(22,711)
(121,786)
(18,694)
(131,739)
9,738
(669,590)
(71,115)
(115,128)
(16,514)
(104,973)
(7,615)
(147,989)
(8,803)
(150,248)
(8,618)
(154,291)
(11,844)
(147,243)
(11,138)
(97,560)
(5,476)
197,616
29,855
177,525
31,094
168,092
64,164
198,489
32,297
178,961
28,739
Net margins including noncontrolling interest
Net loss attributable to noncontrolling interest
$70,679
2,233
$49,753
3,042
$66,121
3,813
$72,405
4,739
$104,664
210
Plant in service (net)
Construction work in progress
$2,941,860
231,374
$2,926,700
152,355
$2,819,499
183,178
$2,696,137
201,011
$2,661,633
133,111
Net margins attributable to the Association
Total plant
Investments in other associations
Restricted cash and investments
Investment in securities pledged as collateral
Goodwill and intangible assets
Other assets
Total other assets
Cash and cash equivalents
Restricted cash and investments
Investment in securities pledged as collateral
Accounts receivable
Inventories
Other current assets
Total current assets
$72,912
3,173,234
128,227
30,381
16,728
133,586
562,749
871,671
193,057
48,390
9,242
126,408
119,207
22,569
518,873
$52,795
3,079,055
121,938
35,881
25,971
144,403
492,303
820,496
81,492
27,143
9,175
133,401
132,612
19,193
403,016
$69,934
3,002,677
117,211
—
35,145
155,221
495,838
803,415
117,507
—
9,648
120,527
119,214
17,985
384,881
$77,144
2,897,148
113,436
—
—
—
351,732
465,168
205,452
—
—
115,104
94,185
17,098
431,839
$104,874
2,794,744
110,368
—
—
—
407,906
518,274
145,585
—
—
112,243
101,586
16,323
375,737
Total assets
$4,563,778
$4,302,567
$4,190,973
$3,794,155
$3,688,755
Total liabilities
3,584,324
3,383,658
3,311,518
2,960,365
2,906,467
Long-term debt
Current liabilities
Deferred credits and APBO
Patronage capital equity
Noncontrolling interest
Total equity
Total equity and liabilities
Other data:
Megawatt-hours sold—member
—non-member
System coincident peak demand—megawatts
Average member mills/kWh—sales
Average member mills/kWh—capital refunds
Plant additions (cash)
Capital credit allocations received
Tri-State patronage capital retirements
Long-term debt repaid
Weighted average long-term debt interest rate
Equity as a % of total capitalization
$2,940,412
437,684
206,228
868,714
110,740
979,454
$2,790,368
390,807
202,483
805,882
113,027
918,909
$2,712,152
390,352
209,014
763,335
116,120
879,455
$4,190,973
$2,491,538
325,690
143,137
713,807
119,983
833,790
$3,794,155
$2,509,129
263,135
134,203
652,613
129,675
782,288
$4,563,778
$4,302,567
$3,688,755
15,313,487
3,316,487
2,666
71.25
0.65
$230,532
10,922
10,000
196,490
5.1%
23.6%
15,717,468 15,421,227 15,026,510 14,245,565
3,010,314
3,976,884
3,836,646
4,311,891
2,798
2,654
2,568
2,447
67.89
65.36
64.98
65.03
0.64
1.30
1.33
0.70
$195,895 $145,446 $232,805 $298,791
7,845
7,167
6,162
12,712
10,000
20,000
20,000
10,000
416,780
142,767
220,466
171,141
5.2%
5.7%
5.7%
5.9%
23.5%
23.3%
24.0%
22.9%
17
REPORT OF INDEPENDENT AUDITORS
The Board of Directors of Tri-State Generation and Transmission Association, Inc.
Report on the Financial Statements
We have audited the accompanying consolidated financial statements of Tri-State Generation and Transmission Association, Inc.
(the Association), which comprise the consolidated statements of financial position as of December 31, 2013 and 2012, and the
related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period
ended December 31, 2013, and the related notes to the consolidated financial statements.
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally
accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.
Auditor’s Responsibility
Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accord­
ance with auditing standards generally accepted in the United States and the standards applicable to financial audits contained in
Government Auditing Standards, issued by the Comptroller General of the United States. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial statements are free of 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 financial statements.
We believe that the audit evidence we have obtained is sufficient 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 consolidated financial position
of Tri-State Generation and Transmission Association, Inc. at December 31, 2013 and 2012, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally
accepted accounting principles.
Other Reporting Required by Government Auditing Standards
In accordance with Government Auditing Standards, we have also issued our report dated February 21, 2014 on our consideration
of the Association’s internal control over financial reporting and on our tests of its compliance with certain provisions of laws,
regulations, contracts, and grant agreements and other matters. The purpose of that report is to describe the scope of our testing
of internal control over financial reporting and compliance and the results of that testing, and not to provide an opinion on internal
control over financial reporting or on compliance. That report is an integral part of an audit performed in accordance with Govern­
ment Auditing Standards in considering Tri-State Generation and Transmission Association, Inc.’s internal control over financial
reporting compliance.
February 21, 2014
18
Consolidated Statements of Financial Position
As of December 31, (Thousands)
ASSETS
Electric plant
In service
Construction work in progress
Total electric plant
Less allowances for depreciation and amortization
Net electric plant
Other assets and investments
Investments in other associations
Investments in coal mines
Restricted cash and investments
Investment in securities pledged as collateral
Deferred equity note
Goodwill and intangible assets
Other noncurrent assets
Total other assets and investments
Current assets
Cash and cash equivalents
Restricted cash and investments
Investment in securities pledged as collateral
Deposits and advances
Accounts receivable—members
Other accounts receivable
Coal inventory
Materials and supplies
Total current assets
Deferred charges
2013
2012
$4,965,495
231,374
$4,856,572
152,355
3,173,234
3,079,055
5,196,869
(2,023,635)
5,008,927
(1,929,872)
128,227
176,256
30,381
16,728
7,693
133,586
11,223
121,938
170,949
35,881
25,971
7,796
144,403
11,159
193,057
48,390
9,242
22,569
93,590
32,818
43,730
75,477
81,492
27,143
9,175
19,193
86,651
46,750
61,254
71,358
504,094
518,873
367,577
518,097
403,016
302,399
Total assets
$4,563,778
$4,302,567
EQUITY AND LIABILITIES
Capitalization
Patronage capital equity
Noncontrolling interest
$868,714
110,740
$805,882
113,027
3,919,866
3,709,277
Total patronage capital equity and noncontrolling interest
Long-term debt
Total capitalization
Current liabilities
Member advances
Accounts payable
Accrued expenses
Current maturities of long-term debt
Total current liabilities
Deferred credits and other liabilities
Accumulated postretirement benefit and postemployment obligations
Total equity and liabilities
979,454
2,940,412
918,909
2,790,368
12,348
109,807
78,941
236,588
14,477
93,969
84,308
198,053
$4,563,778
$4,302,567
437,684
202,980
3,248
390,807
199,304
3,179
The accompanying notes are an integral part of these consolidated statements.
19
Consolidated Statements of Operations
For the years ended December 31, (Thousands)
Operating revenues
Member electric sales
Non-member electric sales
Other
Operating expenses
Purchased power
Fuel
Production
Lease expense
Transmission
General and administrative
Generation maintenance
Transmission maintenance
Depreciation and amortization
Income taxes
Operating margins
Other income
Interest income
Capital credits from cooperatives
Other income (loss)
2013
2012
2011
$1,091,103
172,102
40,994
$1,067,085
162,694
27,217
$1,007,993
152,806
15,381
322,059
287,647
118,300
5,276
114,767
24,325
91,516
23,917
118,776
—
310,293
273,169
108,925
6,714
112,006
22,810
104,749
24,847
115,958
—
1,304,199
1,106,583
197,616
16,996
10,922
1,937
29,855
1,256,996
1,079,471
177,525
23,662
7,845
(413)
31,094
1,176,180
273,287
265,917
105,593
19,365
111,795
18,930
82,388
25,030
105,793
(10)
1,008,088
168,092
27,065
7,167
29,932
64,164
Interest and other deductions
Interest expense, net of amounts capitalized
Other deductions
147,989
8,803
150,248
8,618
154,291
11,844
Net margins including noncontrolling interest
Net loss attributable to noncontrolling interest
Net margins attributable to the Association
70,679
2,233
$72,912
49,753
3,042
$52,795
66,121
3,813
$69,934
The accompanying notes are an integral part of these consolidated statements.
20
156,792
158,866
166,135
Consolidated Statements of Comprehensive Income
For the years ended December 31, (Thousands)
2013
2012
2011
Net margins including noncontrolling interest
Other comprehensive income:
Unrealized gain (loss) on securities available for sale
Less: Reclassification adjustment for actuarial gain on postretirement
benefit obligation included in net income
Income tax expense related to components of other comprehensive income
$70,679
$49,753
278
110
(48)
(358)
—
(358)
—
(358)
—
Comprehensive income including noncontrolling interest
Net comprehensive loss attributable to noncontrolling interest
Comprehensive income attributable to the Association
70,599
2,233
$72,832
Other comprehensive income
(80)
(248)
49,505
3,042
$52,547
$66,121
(406)
65,715
3,813
$69,528
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Equity
For the years ended December 31, (Thousands)
2013
2012
2011
Patronage capital equity at beginning of year
Net margins attributable to the Association
Other comprehensive income
Retirements
$805,882
72,912
(80)
(10,000)
$763,335
52,795
(248)
(10,000)
$713,807
69,934
(406)
(20,000)
Noncontrolling interest at beginning of year
Net loss attributable to noncontrolling interest
Equity distribution to noncontrolling interest
$113,027
(2,233)
(54)
$116,120
(3,042)
(51)
$119,983
(3,813)
(50)
Total patronage capital equity and noncontrolling interest at end of year
$979,454
$918,909
$879,455
Patronage capital equity at end of year
Noncontrolling interest at end of year
868,714
110,740
805,882
113,027
763,335
116,120
The accompanying notes are an integral part of these consolidated statements.
21
Consolidated Statements of Cash Flows
For the years ended December 31, (Thousands)
Operating activities
Net margins including noncontrolling interest
Adjustments to reconcile net margins to net cash provided by operating activities:
Depreciation and amortization
Capital credit allocations from cooperatives and income from
coal mines over refund distributions
RS Plan prepayment
Recognition of deferred revenue
Deferred revenue
Change in restricted cash and investments
Changes in operating assets and liabilities:
Accounts receivable
Coal inventory
Materials and supplies
Accounts payable and accrued expenses
Other
Net cash provided by operating activities
Investing activities
Purchases of plant, net of retirements
Acquisition of Thermo Cogeneration Partnership
Acquisition of Colowyo Coal
Changes in deferred charges
Changes in other noncurrent assets
Net cash used in investing activities
Financing activities
Member advances
Payments of long-term debt
Decrease in advance payments to RUS and funds on deposit with trustees
Retirement of patronage capital
Proceeds from issuance of debt
Securities pledged as collateral—defeasance of Colowyo Bonds
Proceeds from investment in securities pledged as collateral
Change in restricted cash and investments
Net cash provided by financing activities
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents—beginning
2013
2012
2011
$70,679
$49,753
$66,121
118,776
115,958
105,793
(7,053)
(71,160)
—
—
(390)
(11,217)
—
(10,000)
—
(30,380)
(5,404)
—
(10,000)
55,000
—
7,000
17,524
(4,119)
11,840
6,446
(12,868)
(6,941)
(6,457)
(3,181)
10,018
94,685
4,397
(4,156)
(551)
862
(2,968)
209,094
(230,532)
—
—
15,980
3,721
(195,895)
—
—
6,391
2,707
(145,446)
(204,260)
(108,069)
(79)
1,301
149,543
(210,831)
(186,797)
(456,553)
(2,129)
(196,490)
130,257
(10,711)
258,873
—
8,410
(15,357)
(1,385)
(416,780)
123,115
(14,869)
390,177
—
8,483
(32,644)
7,563
(142,767)
84,115
(14,779)
270,175
(44,793)
—
—
111,565
81,492
(36,015)
117,507
(87,945)
205,452
172,853
56,097
159,514
Cash and cash equivalents—ending
$193,057
$81,492
$117,507
Supplemental information:
Cash paid for interest
$124,703
$142,375
$130,335
The accompanying notes are an integral part of these consolidated statements.
22
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1—Organization
Tri-State Generation and Transmission Association, Inc. (the “Association”) is a wholesale power supply cooperative. During 2013, it
provided power to 44 member distribution systems that serve major parts of Colorado, Nebraska, New Mexico and Wyoming. The
Association also sells a portion of its power to other utilities in the region under long-term contracts (see Note 12—Commitments
and Contingencies) and market sale arrangements. In 2013, 2012 and 2011, total megawatt-hours sold were 18.6, 18.7 and 19.4
million, respectively, of which 82, 84 and 79 percent, respectively, were sold to members. Total revenue from electric sales was $1.3
billion for 2013 and $1.2 billion for each of the years 2012 and 2011 of which 86, 87 and 87 percent, respectively, were from member
sales. Energy resources were provided by generation and purchased power, of which 64, 62 and 65 percent were from generation for
2013, 2012 and 2011, respectively.
The Association has wholesale power contracts with 42 of its members through the year 2050 and with two of its members through
the year 2040 whereby each member is obligated to purchase at least 95 percent of its requirements from the Association and can
elect to provide up to 5 percent of its requirements from generation owned or controlled by the member. Twelve members have made
such an election. Power is provided to members at rates determined by the Board of Directors. Rates are designed to recover all costs
and provide margins to increase members’ equity.
Undivided interests in the jointly owned facilities of the Yampa Project, the Missouri Basin Power Project (“MBPP”), and the San
Juan Project (“San Juan”) are owned by the Association. Each participant in these facilities provides its own financing. The Association
receives a portion of the total output of the generating stations, which approximates its percentage ownership. The operating agent
for each of these projects allocates to the Association its share of fuel and other operating costs.
The Association, including its subsidiaries, employs 1,531 people, of which 351 are subject to collective bargaining agreements.
None of these agreements expire within one year.
Note 2—Summary of Significant Accounting Policies
Basis of Consolidation:
The consolidated financial statements include the accounts of the Association and its 99 percent interest in Western Fuels-Colorado,
a limited liability company organized for the purpose of acquiring coal reserves and supplying coal to the Association. The consolidated financial statements also include, on a pro rata basis, the Association’s undivided interests in jointly owned facilities (see Note
1—Organization), entities acquired by the Association in acquisitions that are accounted for as business combinations (see Note 3—
Acquisitions) and the Association’s acquisition of the Springerville Unit 3 Partnership assets through the acquisition of a 51 percent
equity interest in the Springerville Partnership (see Note 9—Leases). The net losses and equity attributable to the 49 percent noncontrolling equity interest in the Springerville Partnership are reflected on the consolidated financial statements.
All significant intercompany balances and transactions have been eliminated in consolidation. The accompanying consolidated
statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) as applied to regulated
enterprises and as prescribed by the Rural Utilities Service (“RUS”).
Business Combinations:
The Association accounts for business acquisitions by applying the accounting standard related to business combinations (see Note 3
—Acquisitions). In accordance with this method, the identifiable assets acquired, the liabilities assumed and any noncontrolling
interests in the acquired entities are required to be recognized at their acquisition date fair values. The Association typically engages
an independent valuation firm to determine the acquisition date fair values of most of the acquired assets and assumed liabilities.
The excess of total consideration transferred over the net assets acquired is recognized as goodwill. Acquisition related costs such
as legal fees, accounting services fees and valuation fees, are expensed as incurred. The Association is required to consolidate these
acquired entities. If an acquisition does not result in acquiring a business, the transaction is accounted for as an acquisition of assets.
This method requires measurement and recognition of the acquired net assets based upon the amount of cash transferred and the
amount paid for acquisition-related costs. There is no goodwill recognized in an acquisition of assets.
Use of Estimates:
The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the
financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from
those estimates.
23
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Electric Plant and Depreciation:
Electric plant is stated at cost. The cost of internally constructed assets includes payroll, overhead costs and interest charged during
construction. Interest rates charged during construction of 4.8, 5.4 and 5.4 percent were used for 2013, 2012 and 2011, respectively.
The amount of interest capitalized during construction was $13.0, $15.2 and $13.6 million during 2013, 2012 and 2011, respectively.
At the time that units of electric plant are retired, original cost and cost of removal, net of the salvage value, are charged to the
allowance for depreciation. Replacements of electric plant that involve less than a designated unit value are charged to maintenance
expense when incurred. Electric plant is depreciated based upon estimated depreciation rates and useful lives that are periodically
re-evaluated.
Leases:
The accounting for lease transactions in conformity with GAAP requires management to make various assumptions, including the
discount rate, the fair market value of the leased assets and the estimated useful life, in order to determine whether a lease should be
classified as operating or capital.
The Association has certain power sales arrangements that are required to be accounted for as operating leases since the arrangements
are in substance leases because they convey the right to use power generating equipment for a stated period of time. The contracts
under which sales are made to Public Service Company of Colorado (“PSCO”) out of the Association’s Knutson and Limon gener­
ating stations are such arrangements. Under these contracts, PSCO directs the use of both of the two Knutson generating units
and one of the two Limon generating units over the terms of the contracts under tolling arrangements whereby PSCO provides its
own natural gas for generation of electricity. The arrangements are therefore accounted for as operating leases. The Limon contract
was suspended for a four-year period beginning May 2009 through April 2013 and the Knutson contract was suspended for a threeyear period beginning May 2010 through April 2013 to allow the Association to utilize the output of the turbines. Both turbine
contracts resumed with PSCO under the original tolling arrangements on May 1, 2013 and are in effect through April 30, 2016.
The Association also has a similar tolling arrangement with Shell Energy North America through September 30, 2014 involving
one of the four 40-megawatt units at the Association’s Pyramid Generating Station. On December 2, 2011, the Association acquired
Thermo Cogeneration Partnership in a business combination (see Note 3—Acquisitions) and thereby acquired the J.M. Shafer
Generating Station from which PSCO is purchasing power under a tolling arrangement that is similar to the above arrangements
and is therefore also accounted for as an operating lease by the Association. The revenues from these operating leases of $25.8,
$13.2 and $1.8 million for 2013, 2012 and 2011, respectively, are accounted for as lease revenue and are reflected in other operating
revenue on the consolidated statements of operations. The generating units used in these gas tolling arrangements have a total cost
and accumulated depreciation of $229 and $105 million, respectively, as of December 31, 2013 and of $228 and $100 million,
respectively, as of December 31, 2012.
The minimum future lease revenues under these gas tolling arrangements at December 31, 2013 are as follows (thousands):
2014
2015
2016
2017
2018
Thereafter
$ 32,292
31,842
17,822
10,812
10,812
5,408
$108,988
The Association has entered into power purchase arrangements that are required to be accounted for as operating leases since the
arrangements are in substance leases because they convey to the Association the right to use power generating equipment for a stated
period of time. Under these agreements, the Association directs the use of the contracted generating equipment over the terms of
the contracts under tolling arrangements whereby the Association provides its own natural gas for generation of electricity. One such
agreement for the use of 72 megawatts at the Brush Generating Station began October 1, 2009 and is for 10 years. Another agreement
for the use of generating equipment at the Rawhide Generating Station began in June 2008 and ended May 31, 2012. Additionally,
the Association had a 10-year agreement beginning July 1, 2009 with Thermo Cogeneration Partnership for the use of generating
equipment at the J.M. Shafer Generating Station. On December 2, 2011, the Association acquired Thermo Cogeneration Partnership
in a business combination which thereby resulted in the elimination of the J.M. Shafer Generating Station agreement as of this date
(see Note 3—Acquisitions). These tolling arrangements are discussed further in Note 9—Leases.
24
Investments in Other Associations:
Investments in other associations primarily include the Association’s investment in the patronage capital of other cooperatives.
Allocations of capital credits from other cooperatives are based on the Association’s patronage with the cooperatives. Cash retirements
of capital credits from other cooperatives reduce the investment balances. Investments in other associations are as follows (thousands):
Basin Electric Power Cooperative
National Rural Utilities Cooperative Finance Corporation
CoBank, ACB
Western Fuels Association
Other
Investments in other associations
2013
$76,139
41,586
4,937
2,478
3,087
$128,227
2012
$69,829
42,873
4,597
1,777
2,862
$121,938
Investments in Coal Mines:
The Association owns 99 percent of Western Fuels-Colorado which is the owner and operator of the New Horizon Mine near
Nucla, Colorado. In addition, on December 1, 2011, Western Fuels-Colorado acquired Colowyo Coal Company which owns the
Colowyo Mine, a large surface coal mine near Craig, Colorado. See Note 3—Acquisitions for a further discussion of this acquisition.
In addition, the Association has partial ownership in Western Fuels Association (“WFA”), which, through its ownership in Western
Fuels-Wyoming, is the owner and operator of the Dry Fork Mine near Gillette, Wyoming. The Association also owns a 50 percent
undivided ownership in the land and the rights to mine the property known as Fort Union Mine which is located adjacent to the
Dry Fork Mine. The Association and certain participants in the Yampa Project are members of Trapper Mining, Inc. (“Trapper
Mining”) which is organized as a cooperative and is the owner and operator of the Trapper Mine near Craig, Colorado. Investments
in coal mines are as follows (thousands):
Colowyo Mine
Trapper Mine
New Horizon Mine
Dry Fork Mine
Fort Union Mine
Investments in coal mines
2013
$131,916
13,235
28,930
273
1,902
$176,256
2012
$135,909
12,747
18,473
1,791
2,029
$170,949
Deferred Equity Note:
During 1981 and 1982, the Association sold certain tax benefits under the safe harbor leasing provision of the Internal Revenue
Code. The initial proceeds were recorded in deferred credits and are being amortized into income at $715,000 per year through
2024. The unamortized balance at December 31, 2013 and 2012 was $7.6 and $8.3 million, respectively. The 1981 lease included
a $34.7 million deferred equity note, payable annually, that has a balance at December 31, 2013 and 2012 of $7.7 and $7.8 million,
respectively.
Cash and Cash Equivalents:
The Association considers highly liquid investments with an original maturity of three months or less to be cash equivalents.
Restricted Cash and Investments:
Restricted cash and investments represent funds designated by the Association’s Board of Directors for specific uses and funds
restricted by contract or other legal reasons. A portion of the funds is for the payment of debt within one year and is therefore a current
asset on the statements of financial position. The other funds are noncurrent and are included in other assets and investments.
25
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Marketable Securities:
The Association’s investment in fixed maturity securities is classified as either held-to-maturity, available-for-sale or trading.
Investments in debt securities that the Association has both the positive intent and ability to hold to maturity are carried at amortized
cost. Investments in debt securities that the Association does not have the positive intent and ability to hold to maturity are classified
as available-for-sale or trading and are carried at fair value. Classification of debt securities is made at the time of purchase and,
prospectively, that classification is reevaluated as of each balance sheet date. Unrealized holding gains and losses on securities classified as available-for-sale are carried as a separate component of members’ equity. Unrealized holding gains and losses on securities
classified as trading would be reported in margins. The Association does not have any such investments. Realized gains and losses
on sales of investments, and declines in value judged to be other-than-temporary, are recognized on the specific identification basis.
Net realized gains are included in other income and net realized losses are included in other deductions.
The Association holds marketable securities in connection with the directors’ and executives’ elective deferred compensation plans
which consist of investments in stock funds, bond funds and money market funds. At December 31, 2013, the cost and estimated
fair value of the investments based upon their active market value were $1.2 and $1.5 million, respectively, with a net unrealized
gain balance of $254,000. At December 31, 2012, the cost and estimated fair value of the investments were $1.3 and $1.3 million,
respectively, with a net unrealized loss balance of $22,000. The estimated fair value of the investments is included in other noncurrent
assets on the consolidated statements of financial position. The change in the net unrealized gain or loss is reported separately as a
component of comprehensive income as shown on the consolidated statements of comprehensive income.
The Association holds marketable securities to maturity in connection with the December 2011 defeasance of the Colowyo Bonds
which consist of U.S. Treasury Notes and are shown as investment in securities pledged as collateral on the statements of financial
position (the defeasance is discussed further in Note 6—Long-Term Debt). As of December 31, 2013, the defeasance investment of
$26.0 million consists of a principal amount of $25.1 million and an unamortized premium of $900,000. As of December 31, 2012,
the defeasance investment of $35.1 million consists of a principal amount of $33.5 million and an unamortized premium of $1.6
million. A portion of the defeasance investment is for Colowyo Bond debt payments within one year and is, therefore, a current
asset on the consolidated statements of financial position. The remainder of the investment is noncurrent and is included in other
assets and investments.
Derivatives:
The Association is exposed to certain risks in the normal course of operations in providing a reliable and affordable source of
wholesale electricity to the member distribution systems. These risks include commodity price risk which represents the risk of loss
due to changes in market prices that may impact the Association’s financial performance. To manage this exposure, the Association
has entered into physically-delivered forward commodity contracts of various durations. These contracts are evaluated in accordance
with the accounting guidance for derivative instruments and hedging activities. This guidance requires recognition of all qualifying
derivative instruments as either assets or liabilities on the statements of financial position and measurement of those instruments
at fair value, unless exempted. Furthermore, the accounting guidance requires that changes in the fair value of derivatives are to be
recorded in current earnings if the instrument is not designated as a hedge. To the extent that the contracts are considered derivatives,
the Association assesses whether or not the normal purchases or normal sales exception applies. Normal purchases and normal sales
are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will
be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that meet
the requirements of normal purchases or normal sales are documented and exempted from the accounting and reporting requirements
for derivative instruments.
The contracts that do not qualify for the normal purchases or normal sales exception are recorded at fair value and the mark to
market gains/losses are deferred as regulatory liabilities/assets (see Note 2—Accounting for Rate Regulation). Under this regulatory
accounting approach, the process of marking the derivatives to market and deferring the recognition of the mark to market gain/loss
continues until each derivative purchase contract is settled. At the time of the delivery/settlement of each derivative contract, fuel
expense is recognized for the amount actually owed under the contract and the derivative contract fair value asset/liability and the
corresponding derivative regulatory liability/asset are eliminated. Therefore, the mark to market accounting never impacts fuel expense.
This regulatory accounting treatment of mark to market gains and losses results in each of the derivative natural gas purchases being
recognized as an expense at delivery/settlement which matches the cost recovery included in the Association’s rates.
26
During 2011, the Association entered into certain forward purchase agreements for delivery of natural gas in 2012 in order to ensure
an adequate supply of natural gas at a price certain for the generation of electricity. These fixed-price, fixed-quantity physical contracts
were considered derivative instruments and were recorded at fair value. The valuation assumptions utilized to measure the fair value
of these commodity derivatives were observable inputs based on market data obtained from independent sources and are considered
Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs). Specifically, the fair value is
based upon actively quoted prices in the gas market. Hedge accounting treatment was not elected for these natural gas agreements.
The natural gas futures contracts outstanding at December 31, 2011 (for delivery of natural gas in 2012) had a fair value that was
$772,000 below their fixed contract prices and these were recorded in deferred credits and other liabilities. The loss resulting from
the changes in fair value of the derivatives was deferred and accounted for as a regulatory asset rather than as fuel expense. During
2012, the forward natural gas purchase agreements were settled/delivered and recognized in fuel expense for the amount actually
owed under the contracts. The mark to market loss related to these agreements was eliminated from deferred credits and other
liabilities and the corresponding regulatory asset at contract settlement. The change in these accounts was included in the operating
section of the statements of cash flows. As of December 31, 2013 and 2012, the Association had no contracts accounted for as derivatives.
Inventories:
Coal inventories of $25.6 and $44.8 million at December 31, 2013 and 2012, respectively, are stated at LIFO (last-in, first-out) cost.
The remaining coal inventories, other fuel, and materials and supplies inventories are stated at average cost.
SO2 Emission Allowances:
The Association has received an annual allocation of SO2 (sulfur dioxide) emission allowances from the Environmental Protection
Agency as part of a nationwide program to limit SO2 emissions. An allowance provides authority to emit one ton of SO2 . Under this
program, the Association has received more SO2 allowances than it has utilized. The unutilized SO2 allowances have no cost basis
and are therefore not recorded on the balance sheet.
Asset Retirement Obligations:
The Association accounts for current obligations associated with the future retirement of tangible long-lived assets in accordance with
the accounting guidance relating to asset retirement and environmental obligations. This guidance requires that legal obligations
associated with the retirement of long-lived assets be recognized at fair value at the time the liability is incurred and capitalized as
part of the related long-lived asset. Over time, the liability is adjusted to its present value by recognizing accretion expense and the
capitalized cost of the long-lived asset is depreciated in a manner consistent with the depreciation of the underlying physical asset.
In the absence of quoted market prices, the Association determines fair value by using present value techniques in which estimates
of future cash flows associated with retirement activities are discounted using a credit adjusted risk-free rate including a market risk
premium. Upon settlement of an asset retirement obligation, the Association will apply payment against the estimated liability and
incur a gain or loss if the actual retirement costs differ from the estimated recorded liability. Asset retirement obligations are included
in deferred credits and other liabilities.
Coal Mines: The Association has asset retirement obligations for the final reclamation costs and post-reclamation monitoring related
to the New Horizon Mine, the Fort Union Mine and the Colowyo Mine.
Fossil Steam Generation: The Association, including its undivided interest in jointly owned facilities, has asset retirement obligations
related to equipment, dams, ponds, ground water, wells and underground storage tanks at the fossil steam generating stations.
Transmission: The Association has an asset retirement obligation to remove a certain transmission line and related substation assets
resulting from an agreement to relocate the line. This work is scheduled to be completed in 2014.
Aggregate carrying amounts of asset retirement obligations are as follows (thousands):
Asset retirement obligation at beginning of year
Liabilities incurred
Liabilities settled
Accretion expense
Change in cash flow estimate
Asset retirement obligation at end of year
2013
$44,488
4,623
(195)
2,675
994
$52,585
2012
$30,777
10,960
—
2,751
—
$44,488
27
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Association also has asset retirement obligations with indeterminate settlement dates. These are made up primarily of obligations
attached to transmission and other easements that are considered by the Association to be operated in perpetuity and therefore the
measurement of the obligation is not possible. A liability will be recognized in the period in which sufficient information exists to
estimate a range of potential settlement dates as is needed to employ a present value technique to estimate fair value.
Memberships:
There are 44 $5 memberships outstanding at December 31, 2013 and 2012.
Patronage Capital:
Net margins of the Association are treated as advances of capital by the members and are allocated to the members on the basis of
their electricity purchases from the Association. Net losses are not allocated to members, but are offset by future margins. Margins
not distributed to members constitute patronage capital. Patronage capital is held for the account of the Association’s members and
is distributed through patronage capital retirements when the Association’s Board of Directors deems it appropriate to do so, subject
to debt instrument restrictions.
Electric Sales Revenue:
Revenue from electric energy deliveries is recognized when delivered.
Other Operating Revenue:
Other operating revenue consists primarily of wheeling revenue and lease revenue. Wheeling revenue is received when the Association
charges other energy companies for transmitting electricity over the Association’s transmission lines. The lease revenue is primarily
from certain power sales arrangements that are required to be accounted for as operating leases since the arrangements are in substance
leases because they convey to others the right to use power generating equipment for a stated period of time. These leases are discussed
further in Note 2—Leases.
Deferred Revenues:
The Association has deferred the recognition of revenues in accordance with the accounting requirements relating to regulated
operations which is discussed further in Note 2—Accounting for Rate Regulation.
During 2007, the Association deferred the recognition of $20 million of non-member electric sales revenue earned during 2007. $10
million of this deferred revenue was recognized in non-member electric sales revenue in each of the years 2011 and 2012. Therefore,
there are no balances remaining to be recognized at December 31, 2013 and 2012.
During 2008, the Association deferred the recognition of $10 million of non-member electric sales revenue earned during 2008.
The $10 million deferred revenue is included in deferred credits and other liabilities. This deferred revenue will be recognized in
non-member electric sales revenue in future years, but not beyond 2018.
During 2011, the Association deferred the recognition of $55 million of non-member electric sales revenue earned during 2011.
The $55 million deferred revenue is included in deferred credits and other liabilities. This deferred revenue will be recognized in
non-member electric sales revenue in future years, but not beyond 2017.
The total of these deferred revenues is $65.0 million at December 31, 2013 and 2012 and is included in deferred credits and
other liabilities.
Income Taxes:
The Association is a non-exempt cooperative subject to federal and state taxation and, as a cooperative, is allowed a tax exclusion for
margins allocated as patronage capital. The liability method of accounting for income taxes is utilized, whereby changes in deferred
tax assets or liabilities result in the establishment of a regulatory asset or liability. A regulatory asset or liability associated with
deferred income taxes generally represents the future increase or decrease in income taxes payable that will be received or settled
through future rate revenues.
28
Accounting for Rate Regulation:
The Association is subject to the accounting requirements related to regulated operations. In accordance with these accounting
requirements, some revenues and expenses have been deferred at the discretion of the Association’s Board of Directors, which has
budgetary and rate-setting authority, if it is probable that these amounts will be refunded or recovered through future rates. Regulatory
assets are costs the Association expects to recover from members based on rates approved by the Board of Directors in accordance
with the Association’s rate policy. Regulatory liabilities represent probable future reductions in rates associated with amounts that
are expected to be refunded to members based on rates approved by the Board of Directors in accordance with the Association’s
rate policy. The Association recognizes regulatory assets and liabilities as expenses or as a reduction in expenses concurrent with
their recovery in rates. Regulatory assets are included in deferred charges. Regulatory liabilities are included in deferred credits and
other liabilities.
The Association was the lessee under five individual lease agreements of Craig Generating Station Unit 3 with a lease term through
2018. Lease expense was recorded on a straight-line basis over the term of the lease based on total scheduled lease payments to be
paid over the life of the lease. Amounts paid in excess of or below recorded lease expense were recorded as prepaid lease expense.
In 2002 through 2006, the Association acquired the equity ownership interests in the five separate leases. The acquisitions of these
equity interests were accounted for under ownership accounting which would ordinarily have required that the balance of the prepaid
lease be recognized as a current expense. However, the current recognition of the prepaid lease expense was deferred under the
accounting requirements related to regulated operations and the amount of the deferral is accounted for as a regulatory asset. The
regulatory asset for the deferred prepaid lease expense is being amortized into expense each year through the remaining original life
of the lease ending in 2018. The amortization of the deferred prepaid lease expense associated with the lease of Craig Generating
Station Unit 3 was $6.5 million in 2013, 2012 and 2011 and is included in depreciation and amortization. The deferred prepaid
lease expense balance was $29.1 and $35.6 million at December 31, 2013 and 2012, respectively, and is included in deferred charges.
The Association was the lessee of the Springerville Generating Station beginning in 2006 for a 34-year lease term. Lease expense
was recorded on a straight-line basis over the term of the lease based on total scheduled lease payments to be paid over the life of the
lease. Amounts paid in excess of or below recorded lease expense were recorded as prepaid lease expense. On December 18, 2009,
the Association acquired a controlling interest in the Springerville Partnership which is the 100 percent owner of the Owner Lessor
in the Springerville Generating Station Unit 3 Lease. Upon the acquisition, the Springerville Partnership and the Owner Lessor
were consolidated by the Association in accordance with the accounting guidance for business combinations and consolidations and
pursuant to this guidance the acquisition was accounted for as an acquisition of assets (see Note 9—Leases). This consolidation results
in the elimination of the Springerville Generating Station Unit 3 Lease expense and therefore, there is no longer lease expense
subsequent to the acquisition. Under the asset acquisition approach used in the accounting for this transaction, the pre-acquisition
prepaid lease balance of $106.7 million would ordinarily have been expensed as a loss on the acquisition of assets. However, the
current recognition of the $106.7 million expense was deferred under the accounting requirements related to regulated operations
and the amount of the deferral is accounted for as a regulatory asset. The regulatory asset for the deferred prepaid lease expense is
being amortized into expense beginning December 18, 2009 through the remaining life of Springerville Generating Station Unit 3
ending in 2056. The amortization of the deferred prepaid lease expense associated with the Springerville Generating Station Unit 3
Lease was $2.3 million in 2013, 2012 and 2011 and is included in depreciation and amortization. The deferred prepaid lease expense
balance was $97.5 and $99.8 million at December 31, 2013 and 2012, respectively, and is included in deferred charges.
The regulatory asset related to deferred income tax expense is discussed further in Note 2—Income Taxes. The regulatory liability
related to deferred revenues is discussed further in Note 2—Deferred Revenues.
Regulatory assets and liabilities are as follows (thousands):
Regulatory assets
Deferred income tax expense
Deferred prepaid lease expense—Craig 3 Lease
Deferred prepaid lease expense—Springerville 3 Lease
Regulatory liabilities
Deferred revenues
Net regulatory asset
2013
2012
$28,966
29,129
97,459
$27,238
35,603
99,750
65,000
65,000
$90,554
$97,591
155,554
65,000
162,591
65,000
29
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Interchange Power:
The Association occasionally engages in interchanges, or non-cash swapping, of energy. Based on the assumption that all energy
interchanged will eventually be received or delivered in-kind, interchanged energy is generally valued at the average cost of fuel to
generate power. Additionally, portions of the energy interchanged are valued per contract with the utility involved in the interchange.
When the Association is in a net energy advance position, the advanced energy balance is recorded as an asset. If the Association
owes energy, the net energy balance owed to others is recorded as a liability. The net activity for the year is included in purchased
power expense. The interchange liability of $2.0 million at December 31, 2013 is included in accounts payable and the interchange
asset of $606,000 at December 31, 2012 is included in deposits and advances. The net interchange activity recorded in purchased
power expense was $2.6 million, $(1.3) million and $853,000 in 2013, 2012 and 2011, respectively.
Evaluation of Subsequent Events:
The Association evaluated subsequent events through February 21, 2014 which represents when the consolidated financial statements
were available to be issued. As of this date, there were no subsequent events that require an adjustment to the consolidated financial
statements or that require disclosure in the consolidated financial statements. The Association has not evaluated subsequent events
after the available to be issued date.
New Accounting Pronouncements:
In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-11,
Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. This amendment requires companies to disclose information
about financial instruments that have been offset and related arrangements to enable users of its financial statements to understand
the effect of those arrangements on its financial condition. The amendment requires both net (offset amounts) and gross information
to be provided in the notes to the financial statements for relevant assets and liabilities that are offset. In January 2013, the FASB
issued ASU 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. This amendment limits the scope of the new balance sheet offsetting disclosure requirements to derivatives (including bifurcated embedded
derivatives), repurchase agreements and reverse repurchase agreements and securities borrowing and lending transactions. ASU
2013-01 was effective for the Association for the fiscal year beginning January 1, 2013. The adoption of these updates did not have
a material impact on the Association’s financial position or results of operations.
In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220): Reporting Amounts Reclassified Out of Accumulated
Other Comprehensive Income. This ASU requires an entity to present on the face of the financial statements or in a single note significant amounts reclassified from each component of accumulated other comprehensive income and the income statement line items
affected by the reclassification. ASU 2013-02 is effective for the Association for the fiscal year beginning January 1, 2014. The
adoption of this update is not expected to have a material impact on the Association’s financial position or results of operations.
In July 2013, the FASB issued ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward,
a Similar Tax Loss, or a Tax Credit Carryforward Exists. This amendment provides authoritative guidance on the financial statement
presentation of unrecognized tax benefits when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists.
ASU 2013-11 is effective for the Association for the fiscal year beginning January 1, 2015 and must be applied on a prospective
basis for all unrecognized tax benefits that exist at the effective date. The adoption of this update is not expected to have a material
impact on the Association’s financial position or results or operations.
Reclassifications:
Certain reclassifications have been made to the prior year financial statements to conform to the 2013 presentations.
Note 3—Acquisitions
Thermo Cogeneration Partnership, LP (“TCP”), owner of J.M. Shafer Generating Station, and Greenhouse Holdings, LLC (“GHH”)
On December 2, 2011, the Association acquired the 100 percent equity interests (including the general and the limited partner
equity interests) in TCP and GHH. TCP owns the J.M. Shafer Generating Station (formerly known as the Fort Lupton Generating
Station), a 272-megawatt natural gas-fired combined cycle power plant located near Fort Lupton, Colorado. TCP is contractually
obligated to sell 150 megawatts of the 272-megawatt net generating capability of the J.M. Shafer Generating Station according to
the terms of a purchase power agreement with the Association (the “Tri-State PPA”) from July 1, 2009 through June 30, 2019 (see
Note 9—Leases). TCP is also contractually obligated to sell the remaining 122 megawatts of the net generating capability of J.M.
Shafer Generating Station to a third party under a separate purchase power agreement (the “PPA”) through June 30, 2019. At the time
of the acquisition, GHH was the owner of a greenhouse facility (“Greenhouse 1”) and land adjacent to the J.M. Shafer Generating
30
Station and leased this greenhouse to a third-party operator. GHH obtained water supply, thermal energy and wastewater discharge
services from TCP pursuant to an ancillary services agreement and sold these services to the Greenhouse 1 operator and to an
adjacent greenhouse that the operator owns. The December 2, 2011 acquisition will effectively allow the Association to expand its
portfolio of generation resources in order to serve the increasing electric power requirements of its members.
The accounting standard for business combinations requires all identifiable assets and assumed liabilities to be measured and
recognized separately from goodwill. This includes measuring and recognizing identifiable intangible assets, or liabilities, if it
arises from contractual or other legal rights (contractual-legal criterion), or is capable of both being separated from the entity and
sold, transferred, licensed, rented or exchanged either on its own or combined with a related contract, identifiable asset or liability
(separability criterion). The PPA met these recognition criteria. Therefore, an intangible asset with a fair value of $55.5 million was
recognized for the amount that the PPA contract terms were above market value at the acquisition date. This finite-lived intangible
asset is included in other assets and investments on the consolidated statements of financial position and will be amortized on a
straight-line basis over the remaining life of the PPA through June 30, 2019 (see Note 4—Goodwill and Intangibles).
The Tri-State PPA contract terms were also above market value at the acquisition date by an estimated amount of $6.4 million. This
contract was a pre-existing contractual relationship between the Association and TCP. According to the accounting standard for
business combinations, this pre-existing relationship is considered effectively settled upon acquisition since the relationship between
the Association and TCP becomes an intercompany relationship as of the acquisition date. Therefore, a gain or loss is required to
be recognized separate from the business combination for the lesser of the amount by which the contract is favorable or unfavorable
compared to current market terms, or the amount of the stated contract’s settlement provisions. Since the Tri-State PPA is not cancelable and does not contain settlement terms, a loss of $6.4 million was recognized at the acquisition date separate from the business
combination accounting. This 2011 loss is included in other income on the Association’s consolidated statements of operations.
The Association paid a total of $210.7 million (net of cash acquired) for all aspects of this transaction. $204.3 million was consideration
transferred by the Association in the business combination and $6.4 million was paid to settle the pre-existing Tri-State PPA
contractual relationship.
The Association followed the acquisition method of accounting in accordance with the accounting standard related to business combinations (see Note 2—Business Combinations). Additionally, since this acquisition included the acquisition of an electric generating
station, J.M. Shafer Generating Station, the accounting prescribed by the RUS for the acquisition of electric plant was also followed.
This required that the electric plant be recorded at its estimated original cost and that the estimated accumulated depreciation from
its original placed in service date until the acquisition date be recorded. The difference between the resulting net book value of the
plant and the fair value of the plant is recorded as an acquisition adjustment, which is included in electric plant in service on the
consolidated statements of financial position.
The fair values of the assets acquired and liabilities assumed in the acquisition on December 2, 2011, as accounted for under the
accounting prescribed by the RUS, are summarized in the following table (thousands):
Current assets (excluding cash acquired) less current liabilities
Original cost of electric plant in service
Accumulated depreciation at time of acquisition
Acquisition adjustment
Materials and supplies inventory
Greenhouse
Land
Intangible asset—PPA premium
Goodwill (Misc. Deferred Debit)
Total net assets acquired
$661
231,000
(126,364)
(32,344)
2,278
761
790
55,541
71,937
$204,260
Goodwill represents the cost of the consideration transferred in excess of the fair value of assets acquired less liabilities assumed.
The goodwill of $71.9 million that was recognized was attributable to a premium paid by the Association for the right to control
the acquired entities as well as synergies expected to be gained from the integration of the J.M. Shafer Generating Station into the
Association’s portfolio of generation resources. The accounting prescribed by the RUS does not include the goodwill concept and
therefore the goodwill is also described as a Miscellaneous Deferred Debit to reflect the RUS accounting. The accounting for the
goodwill is discussed in Note 4—Goodwill and Intangibles.
Acquisition costs were expensed as incurred resulting in recognizing $1.4 million of expense and are included in other deductions.
31
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Subsequent to the acquisition, the Association terminated the current greenhouse lease agreement between GHH and the third
party greenhouse operator. The Association also began the process of removing Greenhouse 1 since this asset provided no future
economic benefit to the Association. As of December 31, 2011, Greenhouse 1 was considered to be fully impaired and worthless.
Therefore, the $761,000 asset value recognized at the acquisition date was expensed in 2011 and is included in other deductions.
Subsequent to the December 2, 2011 acquisition, the results of operations from TCP have been included in the Association’s
consolidated statements of operations. TCP contributed revenues, primarily from the PPA, of $12.1, $12.5 and $1.0 million for
2013, 2012 and 2011, respectively, which are included in other operating revenue. TCP also contributed expenses of $19.3 million,
$16.1 million and $651,000 for 2013, 2012 and 2011, respectively, which are included in operating expenses. Additionally, the
$761,000 write off of the Greenhouse in 2011 is included in other deductions.
Colowyo Coal Company LP (“Colowyo Coal”)
On December 1, 2011, the Association’s 99 percent owned subsidiary, Western Fuels-Colorado, acquired Colowyo Coal by acquiring
100 percent of the equity interests in its owners (Kennecott Colorado Coal Company (“KCCC”) and Rio Tinto White Horse
Company (“RTWHC”)). KCCC (subsequently renamed Axial Basin Coal Company) is the general partner of Colowyo Coal.
RTWHC (subsequently renamed Taylor Creek Holding Company) is the limited partner of Colowyo Coal. Colowyo Coal owns a
large surface coal mine in Moffat County, Colorado and sells the coal it produces through two coal sales agreements to the Craig
Generating Station which is operated by the Association. One coal sales agreement obligates Colowyo Coal to sell coal through
2017 to the Association through Western Fuels-Colorado as agent for the Association for its use at the Craig Generating Station.
The other coal sales agreement obligates Colowyo Coal to sell coal to the other Craig Generating Station owner participants (the
“Yampa Participants”) though 2017. This acquisition will effectively ensure a reliable and affordable supply of coal to the Craig
Generating Station for the expected life of the power plant.
The accounting standard for business combinations requires all identifiable assets and assumed liabilities to be measured and
recognized separately from goodwill. This includes measuring and recognizing identifiable intangible assets, or liabilities, if it
arises from contractual or other legal rights (contractual-legal criterion), or is capable of both being separated from the entity and
sold, transferred, licensed, rented or exchanged either on its own or combined with a related contract, identifiable asset or liability
(separability criterion). The coal sales contract with the Yampa Participants met these recognition criteria. Therefore, an intangible
liability with a fair value of $18.0 million was recognized in the December 1, 2011 acquisition for the amount that the contract
terms were below market at the acquisition date. This finite-lived intangible liability is included in deferred credits and other liabilities
on the consolidated statements of financial position and will be amortized based upon the contracted tonnage with the Yampa
Participants over the remaining life of the coal contract through December 31, 2017 (see Note 4—Goodwill and Intangibles).
The coal sales agreement with the Association also had terms that were below market value at the acquisition date by an estimated
amount of $31.1 million. This contract was a pre-existing contractual relationship between the Association and Colowyo Coal.
According to the accounting standard for business combinations, this pre-existing relationship is considered effectively settled
upon acquisition since the relationship between the Association and Colowyo Coal becomes an intercompany relationship as of the
acquisition date. Therefore, a gain or loss is required to be recognized separate from the business combination for the lesser of the
amount by which the contract is unfavorable or favorable compared to current market terms, or the amount of the stated contract’s
settlement provisions. Since the coal sales contract with the Association is not cancelable and does not contain settlement terms, a
gain of $31.1 million was recognized separate from the business combination accounting. This 2011 gain is included in other income
on the Association’s consolidated statements of operations.
The Colowyo Bonds assumed in the acquisition are required to be recorded at their acquisition date fair value. It was determined
that the fair value of the Colowyo Bonds was $41.9 million, which was $7.4 million greater than the $34.5 million outstanding debt
balance. Additionally, the Association assumed debt associated with the financing of mine equipment used at the mine. This debt
was recorded at its $7.7 million outstanding debt balance which was estimated to be approximately equal to fair value. The acquisition
debt is shown in Note 6—Long-Term Debt.
The accounting for the business combination includes the accounting for deferred income taxes related to the acquisition. See Note 8
—Income Taxes for further discussion of the accounting for income taxes by the Association.
32
The Association, through Western Fuels-Colorado, paid cash in the net amount of $77.0 million for all aspects of this transaction.
$108.1 million was considered to have been transferred by the Association in the business combination (net of cash acquired). This
was offset by the receipt of $31.1 million that was considered to have been paid by Colowyo Coal to the Association to settle the
pre-existing unfavorable coal sales agreement. Other consideration in the business combination includes liabilities assumed.
The Association followed the acquisition method of accounting in accordance with the accounting standard related to business
combinations (see Note 2—Business Combinations). The fair values of the assets acquired and liabilities assumed in the acquisition
on December 1, 2011, including the accounting for deferred income taxes and certain other tax matters, are summarized in the
following table (thousands):
Assets
Current assets (excluding cash acquired) less current liabilities
Building and land improvements
Non-mineral land
Fee land outside of permitted mine plan
Personal property
Mineral rights
Deferred tax assets
Deferred tax regulatory asset
Goodwill (Misc. Deferred Debit)
Total assets acquired
Liabilities
Colowyo Bonds
Premium on Colowyo Bonds
Mine equipment loans
Colowyo Bonds and mine equipment loans accrued interest
Asset retirement obligation
Intangible liability—coal contracts below market terms with Yampa
Participants
Deferred tax liabilities
Total liabilities assumed
Cash consideration transferred (net of cash acquired)
$15,696
8,230
4,520
10,071
61,730
54,980
18,706
10,881
28,353
$213,167
$34,475
7,455
7,956
478
24,304
17,950
12,480
$105,098
$108,069
Goodwill represents the cost of the total consideration transferred in excess of the fair value of assets acquired less liabilities assumed.
The goodwill of $28.4 million that was recognized was attributable to a premium paid by Western Fuels-Colorado for the right
to control the acquired entities in order to ensure a reliable and affordable supply of coal for the Craig Generating Station for the
expected life of the power plant and also to having an established workforce in place. The accounting prescribed by the RUS does
not include the goodwill concept and therefore the goodwill is also described as a Miscellaneous Deferred Debit to reflect the RUS
accounting. The accounting for the goodwill is discussed in Note 4—Goodwill and Intangibles.
Acquisition costs were expensed as incurred resulting in recognizing $2.2 million in expense and are included in other deductions.
Subsequent to the December 1, 2011 acquisition, the results of operations from Colowyo Coal have been included in the Association’s
consolidated statements of operations. Approximately 68 percent of the total mine expenses relate to providing coal to the Association
for use at the Craig Generating Station. The incremental increase in these expenses over the expense of the Association purchasing
the coal from Colowyo Coal prior to the acquisition is $15.4, $22.2 and $1.0 million for 2013, 2012 and 2011, respectively, and
these are included in fuel expense. The remaining mine operation efforts relate to selling coal to the Yampa Participants for their
use at the Craig Generating Station and the net losses of $2.3 million, $5.5 million and $120,000 for 2013, 2012 and 2011, respectively, are included in other income (loss).
33
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 4—Goodwill and Intangibles
Goodwill and Intangible Assets:
During 2011, the Association recognized goodwill in the amount of $71.9 million related to the acquisition of TCP and GHH and
$28.4 million related to the acquisition of Colowyo Coal (see Note 3—Acquisitions). Goodwill represents an asset recognized in a
business combination that is initially measured as the excess of the fair value of the acquired business over the fair value of the net
identifiable assets acquired. Goodwill is generally treated under GAAP as an indefinite lived asset that is not subject to amortization and is instead required to be evaluated annually for impairment. However, during 2012, the Association adopted a regulatory
accounting approach for recovering the goodwill costs pursuant to the accounting requirements related to regulated operations (see
Note 2—Accounting for Rate Regulation). Under this approach (effective January 1, 2012), the goodwill amounts are being amortized over specific time periods for recovery in rates. The goodwill of $71.9 million related to the acquisition of TCP and GHH is
being amortized over the 25-year remaining life of the J.M. Shafer Generating Station. This results in annual amortization expense
of $2.8 million per year that is included in depreciation and amortization expense. The goodwill of $28.4 million related to the
acquisition of Colowyo Coal is being amortized over the 44-year remaining life of the Craig Generating Station since the coal mine
was acquired primarily for its use. This results in annual amortization expense of $644,000 per year that is included in depreciation
and amortization expense. The total goodwill amortization expense that will be recognized over each of the next five years and
thereafter is as follows (thousands):
2014
2015
2016
2017
2018
Thereafter
$ 3,493
3,493
3,493
3,493
3,493
75,838
$93,303
During 2011, the Association recognized an intangible asset in the amount of $55.5 million related to its acquisition of TCP and
GHH (see Note 3—Acquisitions). This finite-lived asset represents the amount that the PPA contract terms were above market
value at the December 2, 2011 acquisition date. An intangible asset with a finite life is subject to amortization over its remaining
economic useful life on a straight-line basis unless there is a method other than straight-line that is reliably determined and best
reflects how that asset or liability is consumed. The $55.5 million PPA intangible asset is being amortized on a straight-line basis
over the remaining life of the PPA through June 30, 2019. The straight-line method is consistent with the terms of the PPA as this
contract is for a fixed amount of capacity at a fixed capacity rate that stays constant over the term of the contract.
The amortization of the PPA intangible asset is accounted for as a reduction of the revenue generated by the PPA and is included
in other operating revenue. The amortization was $7.3 million, $7.3 million and $610,000 in 2013, 2012 and 2011, respectively.
Amortization will be recognized over each of the next five years and thereafter as follows (thousands):
2014
2015
2016
2017
2018
Thereafter
$ 7,324
7,324
7,324
7,324
7,324
3,663
$40,283
The carrying amounts of goodwill and intangible assets are presented in the consolidated statements of financial position. The
accounting prescribed by the RUS does not include the goodwill concept and therefore the goodwill is also described as a Miscellaneous
Deferred Debit to reflect the RUS accounting. The carrying amounts are comprised of the following (thousands):
Goodwill (Misc. Deferred Debit)—TCP
Goodwill (Misc. Deferred Debit)—Colowyo Coal
Intangible asset—TCP PPA premium
Total
34
2013
$66,238
27,065
40,283
$133,586
2012
$69,087
27,709
47,607
$144,403
Intangible Liabilities:
During 2011, Western Fuels-Colorado recognized an intangible liability in the amount of $18.0 million related to its acquisition
of Colowyo Coal (see Note 3—Acquisitions). This finite-lived liability relates to the amount that the coal contract with the Yampa
Participants was below market value at the December 1, 2011 acquisition date. The intangible liability recognized in the Colowyo
Coal acquisition is being amortized based upon the contracted tonnage with the Yampa Participants over the remaining life of
the coal contract ending in 2017. The intangible liability balance of $12.7 and $15.1 million as of December 31, 2013 and 2012,
respectively, is included in deferred credits and other liabilities.
The amortization of the Colowyo Coal intangible liability is accounted for as an increase in other income. The amortization benefit
of $2.5 million, $2.6 million and $211,000 was recognized in 2013, 2012 and 2011, respectively, and is estimated to be recognized
over each of the next four years as follows (thousands):
2014
2015
2016
2017
$ 3,125
3,125
3,125
3,277
$12,652
Note 5—Electric Plant
The Association’s investment in electric plant and the related annual rates of depreciation or amortization calculated using the
straight-line method are as follows (thousands):
Generation plant
Transmission plant
General plant
Other
Annual Depreciation Rate
.44% to 3.16%
2.0% to 2.88%
3.0% to 33.33%
2.8% to 5.60%
Electric plant in service (at cost)
Construction work in progress
Less allowances for depreciation and amortization
Electric plant
2013
2012
$3,267,742
1,095,554
358,755
243,444
$3,235,179
1,035,369
344,761
241,263
$3,173,234
$3,079,055
4,965,495
231,374
(2,023,635)
4,856,572
152,355
(1,929,872)
At December 31, 2013, the Association had $83.8 million of commitments to complete construction projects of which approximately
$78.7, $3.1 and $2.0 million are expected to be incurred in 2014, 2015 and 2016, respectively.
The Purchase Option and Development Agreement was executed on July 26, 2007 between the Association and Sunflower Electric
Power Corporation (“Sunflower”) and other Sunflower parties. The agreement calls for the Association to make option payments
totaling $55 million to Sunflower and/or the other Sunflower parties in exchange for the development rights to develop a new coalfired generating unit or units at Sunflower’s existing single-unit Holcomb Station in western Kansas. Upon execution, $25 million
was paid. In 2008, $5 million was paid and the remainder will be paid on the purchase date. The purchase date will be designated
by the Association, Sunflower and the other parties to the Purchase Option and Development Agreement after the Association
exercises its option to acquire the development rights. The purchase date cannot currently be estimated due to legal uncertainties
surrounding the status of the necessary air permits. The original air permit application was denied by the Kansas Department of
Health and Environment (“KDHE”) in October 2007 and the Association and Sunflower appealed the denial to the Kansas courts.
Subsequent to the denial of the air permit, Sunflower entered into an agreement with the governor of Kansas that could result in the
KDHE issuing a permit for one new coal-fired generating unit at Holcomb Station of 895 megawatts. As a result of the agreement,
Sunflower and the Association withdrew their appeal of the denial of the original air permit application. The KDHE issued the
new permit on December 16, 2010. The Sierra Club filed an appeal of the new permit with the Kansas Court of Appeals on January
14, 2011 and the case was immediately transferred to the Kansas Supreme Court. The Kansas Supreme Court remanded the permit
to the KDHE to consider a limited issue. The KDHE is considering that issue and further KDHE action is pending. Excluding the
cost of land and water rights, the cost of developing the units incurred by the Association as of December 31, 2013 is $77.3 million
which is included in deferred charges on the consolidated statements of financial position. The Association is unable to project the
ultimate outcome of this matter, but it intends to pursue the revised air permit process to conclusion. The Association is unable to
project when the air permit application process may conclude.
35
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6—Long-Term Debt
The mortgage notes payable and pollution control revenue bonds are secured on a parity basis by a Master First Mortgage Indenture,
Deed of Trust and Security Agreement except for one $67.9 million unsecured note. Substantially all the assets, rents, revenues and
margins of the Association are pledged as collateral. The Springerville certificates are secured by the assets of Springerville Generating
Station Unit 3 (see Note 9—Leases). The Colowyo Bonds are secured by funds deposited with the trustee as part of the in-substance
defeasance discussed later in this note and an unconditional guarantee of the Association. All long-term debt contains certain
restrictive financial covenants and consists of the following (thousands):
Mortgage notes payable
2% RUS, due through 2017
5% RUS, due through 2026
1.95% to 10.81% FFB, 4.38% average for 2013,
due through 2047
4.50% to 9.05% CFC, 6.17% average for 2013,
due through 2022
2.63% to 6.17% CoBank, ACB, 4.62% average for 2013,
due through 2042
First Mortgage Bonds, Series 2010A, 6.00% due 2040
First Mortgage Obligation, Series 2009C, Tranche 1,
6.00%, due 2019
First Mortgage Obligation, Series 2009C, Tranche 2,
6.31%, due 2021
Variable rate CFC, as determined by CFC, 2.90%
average for 2013, due through 2026
Variable rate Grantor Trust Obligations, as determined
by CFC, 0.50% average for 2013, due 2017
Variable rate, 2011 Credit Agreement, LIBOR based
revolving credit, 1.48% average for 2013, due 2018
Pollution control revenue bonds
Platte County, WY Daily Adjustable Rate Series 1984,
0.11% average for 2013, due 2014
City of Gallup, NM, 5.00%, Series 2005, due through 2017
Moffat County, CO Variable Rate Demand Series 2009,
0.11% average for 2013, due 2036
Springerville certificates
Series A, 6.04%, due 2018
Series B, 7.14%, due 2033
Colowyo Coal
Colowyo Bonds, 10.19%, due 2016
Mine Equipment Loans, 7.75%, due 2014
Other
Less advance payments to RUS
Total debt
Less current maturities
Long-term debt
36
2013
2012
$165
4,988
$215
6,472
1,317,760
1,283,032
114,939
135,232
228,835
499,323
167,807
499,325
162,857
190,000
110,000
110,000
728
766
17,205
21,025
130,000
65,000
48,000
21,160
48,000
25,988
46,800
46,800
160,774
422,566
193,300
423,630
25,895
1,883
850
(137,728)
34,044
4,920
850
(267,985)
3,177,000
(236,588)
$2,940,412
2,988,421
(198,053)
$2,790,368
The Platte County bonds may be “put” back for remarketing at any time and may be converted to a long-term fixed rate at the option
of the Association. A $49.1 million letter of credit with National Rural Utilities Cooperative Finance Corporation (“CFC”) secures
payment of these bonds and as of December 31, 2013 had an expiration date of July 28, 2014.
In February 2009, the Association refunded the Moffat County, CO Weekly Adjustable Rate Series 1984 Bonds and issued the
$46.8 million Moffat County, CO, Variable Rate Demand Pollution Control Revenue Refunding Bonds, Series 2009 (“Series 2009
Bonds”) with a 364-day, direct pay letter of credit provided by Bank of America, N.A. In November 2013, the letter of credit from
Bank of America, N.A. was extended for an additional 364 days to mature in January 2015.
The Association has a 51 percent equity interest in the Springerville Partnership that was accounted for as an acquisition of assets
and is consolidated in accordance with the accounting guidance for business combinations and consolidations (see Note 9—Leases).
Therefore, 100 percent of the assets, liabilities and expenses of the Springerville Partnership are included in the consolidated financial statements of the Association. This includes 100 percent of the Tri-State Generation and Transmission Association, Inc. 2003
Series A and Series B Pass Through Trust Certificates which, along with owner equity, provided funding for the construction of
Springerville Generating Station Unit 3.
At December 31, 2013, the Association had two unused committed lines of credit totaling $75 million with scheduled expirations
for $25 million in 2014 and $50 million in 2016. In January 2014, both lines of credit were extended to 2017.
In July 2011, the Association entered into an agreement (the “2011 Credit Agreement”) with Bank of America N.A. (“Bank of
America”) as Administrative Agent and CoBank, ACB (“CoBank”) and Bank of America as Joint Lead Arrangers for a secured
revolving credit facility with a total commitment of $500 million for a term of 5 years that was to expire in July 2016. In November
2013, the term of the 2011 Credit Agreement was extended for two years to expire in July 2018.
On December 1, 2011, the Association’s subsidiary, Western Fuels-Colorado, purchased Colowyo Coal (see Note 3—Acquisitions).
As a result of the acquisition, the Coal Contract Receivable Collateralized Bonds (“Colowyo Bonds”) with an interest rate of 10.19
percent and totaling $41.9 million, in the par amount of $34.5 million plus a premium of $7.4 million to reflect the fair market
value as of December 1, 2011, were added to the Association’s long-term debt. The debt was recorded at the acquisition date fair
value per the accounting standard for business combinations. On December 20, 2011, Colowyo Coal entered into an in-substance
defeasance for the $34.5 million principal outstanding and for the $10.3 million of total future interest payments on the Colowyo
Bonds by purchasing U.S. Treasury Notes with a principal amount of $42.0 million for a price of $44.8 million. The in-substance
defeasance does not relieve Colowyo Coal and the Association of liability for the Colowyo Bonds and therefore the bonds continue
to be shown as debt on the consolidated statements of financial position.
RUS allows borrowers to make advance payments that will be used to pay future debt. These advances are irrevocable and can only
be used to pay RUS or Federal Financing Bank (“FFB”) debt. The advance payments earn interest at a 5 percent rate. The amounts
advanced to RUS are $138 and $268 million as of December 31, 2013 and 2012, respectively.
At December 31, 2013, the Association had FFB commitments to advance additional construction funds of $463 million.
Annual maturities of total debt at December 31, 2013 are as follows (thousands):
2014
2015
2016
2017
2018
Thereafter
$  236,588
190,329
165,029
187,845
162,131
2,235,078
$3,177,000
37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 7—Fair Values of Financial Instruments
The fair values of long-term debt were estimated using discounted cash flow analyses based on the Association’s current incremental
borrowing rates for similar types of borrowing arrangements. These valuation assumptions utilize observable inputs based on market
data obtained from independent sources and are therefore considered Level 2 inputs (quoted prices for similar assets, liabilities
(adjusted) and market corroborated inputs). Fair values of marketable securities are presented in Note 2—Marketable Securities and
the fair values of derivative instruments are presented in Note 2—Derivatives. The carrying amounts and fair values of the Association’s
long-term debt are as follows (thousands):
2013
RUS
FFB
CFC
First Mortgage Bonds,
Series 2010A
First Mortgage Obligations,
Series 2009C
Pollution control revenue bonds
2011 Credit Agreement
Grantor Trust Obligations
CoBank, ACB
Springerville certificates
Colowyo Bonds
Mine Equipment Loans
Other
Less: Advance payments to RUS
Carrying
Amount
Estimated
Fair Value
2012
Carrying
Amount
Estimated
Fair Value
$5,153
1,317,760
115,667
$5,876
1,385,103
124,575
$6,687
1,283,032
135,998
$7,656
1,500,764
149,330
499,323
567,630
499,325
667,360
272,857
115,960
130,000
17,205
228,835
583,340
25,895
1,883
850
299,537
116,377
128,016
17,128
224,580
672,690
26,389
1,908
769
300,000
120,788
65,000
21,025
167,807
616,930
34,044
4,920
850
337,740
121,550
63,316
20,533
175,680
738,015
34,893
5,100
761
3,314,728
(137,728)
$3,177,000
3,570,578
(137,728)
$3,432,850
3,256,406
(267,985)
$2,988,421
3,822,698
(267,985)
$3,554,713
Note 8—Income Taxes
Under the liability method, deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts
of assets and liabilities for financial reporting purposes and for income tax purposes. Components of the Association’s net deferred
tax liability are as follows (thousands):
Deferred tax assets
Safe harbor lease receivables
Net operating loss carryforwards
Alternative minimum tax credit carryforwards
Deferred debt charges
Deferred revenues
Colowyo Coal—coal contract intangible liability
Other
Deferred tax liabilities
Asset basis differences including safe harbor assets
Depreciation
Capital credits from other associations
Net deferred tax liability
38
2013
2012
$40,225
58,333
3,834
1,377
24,460
4,761
46,867
$42,005
39,008
3,834
2,129
24,460
5,691
43,519
125,922
32,867
32,927
114,130
26,468
30,179
$(11,859)
$(10,131)
179,857
191,716
160,646
170,777
The $1.7 million increase in the net deferred tax liability from $10.1 million at December 31, 2012 to $11.9 million at December 31,
2013 is not recognized as a tax expense in 2013 due to the Association’s regulatory accounting treatment of deferred taxes. Instead,
the tax expense is deferred and ref lected as an increase in the regulatory asset established for deferred income tax expense. The
regulatory asset account for deferred income tax expense has a balance of $29.0 million and $27.2 million at December 31, 2013 and
2012, respectively. The regulatory asset balance includes $17.1 million related to the 2011 acquisition of Colowyo Coal (see Note 3
—Acquisitions). The accounting for regulatory assets is discussed further in Note 2—Accounting for Rate Regulation.
The Association had a taxable loss of $48.4 million for 2013. At December 31, 2013, the Association has a net operating loss
carryforward of $155.0 million which, if not utilized, will expire between 2030 and 2033. The future reversal of existing temporary
differences will more-likely-than-not enable the realization of the net operating loss carryforward.
The Association had no income tax expense or benefit in 2013 and 2012 and had a $10,000 income tax benefit in 2011. The
Association has $3.8 million of alternative minimum tax credit carryforwards at December 31, 2013 to offset future regular taxes
payable and the credit carryforwards have no expiration date.
Note 9—Leases
Springerville Generating Station Unit 3 Lease:
In October 2003, the Association entered into a series of agreements to develop a 418-megawatt, coal-fired generating facility near
Springerville, Arizona, called Springerville Generating Station Unit 3 and for the Association to act as the construction agent for
the benefit of Springerville Unit 3 Holding LLC (the “Owner Lessor”). The agreements also called for the Association to be the
lessee of the unit under the Springerville Generating Station Unit 3 Lease. On July 28, 2006, the construction of the facility was
completed and this operating lease commenced. The Association is committed to make semiannual lease payments to the Owner
Lessor for a 34-year lease term extending through July 2040. The semiannual lease payments are comprised of amounts equal to the
long-term and short-term bond commitments as well as the repayment of equity funds to the Owner Lessor. In turn, the Owner
Lessor is obligated to pay principal and interest on the bonds with the lease payment proceeds received from the Association.
On December 18, 2009, the Association acquired a 49 percent equity interest (including the 1 percent general partner equity interest)
in the Springerville Partnership which is the 100 percent owner of the Owner Lessor. On December 22, 2010, the Association
increased its equity interest in the Springerville Partnership to 51 percent by acquiring an additional 2 percent equity interest in
the Springerville Partnership. Upon the December 18, 2009 acquisition, the Springerville Partnership and the Owner Lessor were
consolidated by the Association in accordance with the accounting guidance for business combinations and consolidations and pursuant
to this guidance the acquisition was accounted for as an acquisition of assets. The Association’s consolidation of the Springerville
Partnership and the Owner Lessor results in 100 percent of the Springerville Generating Station Unit 3 Lease expense being eliminated. Therefore, there is no longer lease expense subsequent to the acquisition. Instead, 100 percent of the assets, liabilities and
expenses of the Springerville Partnership and the Owner Lessor (consisting solely of the Springerville Generating Station Unit 3
assets, debt and related expenses) are included in the consolidated financial statements of the Association.
Upon reaching a 51 percent equity ownership interest in the Springerville Partnership at December 22, 2010, the Association’s
commitments for Springerville Generating Station Unit 3 Lease payments reflect the amount of the payments less the debt com­
mitments for the Springerville certificates reflected in Note 6—Long-Term Debt and the amount of the payments that come back
to the Association as the 51 percent equity owner of the Springerville Partnership. The lease payment commitments relating to
repayment of 49 percent of the equity funds at December 31, 2013 are as follows (thousands):
2014
2015
2016
2017
2018
Thereafter
$     55
56
59
—
4,413
184,470
$189,053
In the 29th year of the lease and at the end of the 34-year lease term, the Association will have an option to acquire any remaining
portion not previously purchased of the leased facility for a fair market value price determined in October 2003 as of each of those
dates. Alternatively, at the end of the 34-year lease term, the Association will have an option to renew the lease for a term of up to
42 months and a second option to extend the lease for an additional term of up to 54 months.
39
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In accordance with the Facility Lease Agreement and other related agreements, the Association has provided guarantees to the
Owner Lessor for certain events that extend through the term of the lease. These include customary general and tax indemnities
as well as protection for the Owner Lessor against changes in regulatory law that would have a detrimental impact on the lease
assumptions. Subsequent to the acquisitions of 51 percent of the equity interests in 2009 and 2010, the Association only has guarantees
to others with respect to the 49 percent equity interest owner. The Association believes that the likelihood of these guarantee events
occurring is remote and therefore no liability is recorded as of December 31, 2013 and 2012.
Generating Stations with Gas Tolling Arrangements:
The Association has entered into power purchase arrangements that are required to be accounted for as operating leases since the
arrangements are in substance leases because they convey to the Association the right to use power generating equipment for a stated
period of time. Under these agreements, the Association directs the use of the contracted generating equipment over the terms of
the contracts under tolling arrangements whereby the Association provides its own natural gas for generation of electricity. One such
agreement for the use of 72 megawatts at the Brush Generating Station is for 10 years beginning October 1, 2009. Another agreement
for the use of generating equipment at the Rawhide Generating Station began in June 2008 and ended in May 2012. This agreement
allowed the Association to toll natural gas for 100 megawatts of power from the combustion turbines beginning in 2008 with a
decline to 50 megawatts in June 2011. Additionally, the Association had a 10-year agreement with Thermo Cogeneration Partnership
to toll natural gas at the J.M. Shafer Generating Station for 150 megawatts which began on July 1, 2009. On December 2, 2011,
the Association acquired Thermo Cogeneration Partnership in a business combination which thereby resulted in the elimination of
the J.M. Shafer agreement as of this date (see Note 3—Acquisitions). The Association’s operating lease commitments for these gas
tolling arrangements at December 31, 2013 are as follows (thousands):
2014
2015
2016
2017
2018
Thereafter
$ 5,200
5,359
5,519
5,678
5,855
6,031
$33,642
Note 10—Related Parties
Yampa Project:
The Association acts as the operating agent for participants of the Yampa Project and related common facilities.
Basin Electric Power Cooperative (“BEPC”):
BEPC is a wholesale power supply cooperative of which the Association is a member. The Association purchased power from BEPC
at a cost of $136, $138 and $94.2 million in 2013, 2012 and 2011, respectively. The Association’s investment in BEPC was $76.1
and $69.8 million at December 31, 2013 and 2012, respectively, and is included in investments in other associations. The Association’s
share of BEPC capital credit allocations was $6.3, $5.5 and $3.9 million in 2013, 2012 and 2011, respectively, and is included in
capital credits from cooperatives.
National Rural Utilities Cooperative Finance Corporation:
Investments in other associations includes a $41.6 and $42.9 million investment in CFC as of December 31, 2013 and 2012,
respectively. At December 31, 2013 and 2012, the total outstanding debt owed to CFC was $116 and $136 million, respectively.
The Association’s share of CFC capital credit allocations was $800,000, $874,000 and $1.3 million for 2013, 2012 and 2011,
respectively, and is included in capital credits from cooperatives.
CoBank, ACB (“CoBank”):
Investments in other associations includes a $4.9 and $4.6 million investment in CoBank as of December 31, 2013 and 2012,
respectively. At December 31, 2013 and 2012, the total outstanding debt owed to CoBank was $229 and $168 million, respectively.
The Association’s share of CoBank capital credit allocations was $1.4 million, $794,000 and $798,000 for 2013, 2012 and 2011,
respectively, and is included in capital credits from cooperatives.
40
Western Fuels Association:
WFA is a non-profit membership corporation organized for the purpose of acquiring and supplying fuel resources to its members,
which include the Association and BEPC. WFA supplies fuel to MBPP through contracts with coal companies and through its
ownership in Western Fuels-Wyoming, which owns and operates the Dry Fork Mine. The Association also receives coal supplies
directly from WFA for the Escalante Generating Station in New Mexico and spot coal for the Springerville Generating Station in
Arizona. The Association’s share of coal purchases from WFA was $71.7, $71.7 and $84.4 million in 2013, 2012 and 2011, respectively.
The Association advanced funds to WFA, through MBPP, for mine and equipment purchases and mine development costs. The
fund advance balance of $273,000 and $1.8 million at December 31, 2013 and 2012, respectively, is included in investments in coal
mines. The Association’s membership interest in WFA, including interest through MBPP in WFA, totals $2.5 and $1.8 million at
December 31, 2013 and 2012, respectively, and is included in investments in other associations. The Association’s share of WFA
capital credit allocations of $1.2 million for 2013 and $0 for 2012 and 2011 is included in capital credits from cooperatives.
Trapper Mining:
The Association and certain participants in the Yampa Project own Trapper Mining. Organized as a cooperative, Trapper Mining
supplied 24, 25 and 28 percent of the coal for the Yampa Project in 2013, 2012 and 2011, respectively. The Association’s share of
coal purchases from Trapper Mining was $16.9, $11.2 and $18.5 million in 2013, 2012 and 2011, respectively. The Association’s
membership interest in Trapper Mining of $13.2 and $12.7 million at December 31, 2013 and 2012, respectively, is included in
investments in coal mines. The Association’s investment in Trapper Mining is recorded using the equity method and income of
$531,000 in 2013 and 2012 and of $714,000 in 2011 is included in capital credits from cooperatives.
Note 11—Employee Benefit Plans
Defined Benefit Plan:
Substantially all of the Association’s 1,531 employees participate in the National Rural Electric Cooperative Association Retirement
Security Plan (“RS Plan”) except for the 225 employees of Colowyo Coal that was acquired December 1, 2011 (see Note 3—
Acquisitions). The RS Plan is a defined benefit pension plan qualified under Section 401 and tax-exempt under Section 501(a)
of the Internal Revenue Code. It is considered a multiemployer plan under the accounting standards for compensation-retirement
benefits. The plan sponsor’s Employer Identification Number is 53-0116145 and the Plan Number is 333.
A unique characteristic of a multiemployer plan compared to a single employer plan is that all plan assets are available to pay benefits
to any plan participant. Separate asset accounts are not maintained for participating employers. This means that assets contributed
by one employer may be used to provide benefits to employees of other participating employers.
The Association’s contributions to the RS Plan in each of the years 2013, 2012 and 2011 represented less than 5 percent of the
total contributions made each year to the plan by all participating employers. The Association made contributions to the RS Plan
of $92.6, $24.9 and $24.2 million in 2013, 2012 and 2011, respectively. Contributions in 2013 are significantly higher than those
in 2012 due to the Association’s election to exercise the prepayment option offered to participating employers in 2013.
In December 2012, the National Rural Electric Cooperative Association approved an option to allow participating cooperatives in
the RS Plan to make a contribution prepayment and reduce future required contributions. The prepayment amount is a cooperative’s
share, as of January 1, 2013, of future contributions required to fund the RS Plan’s unfunded value of benefits earned to date using
RS Plan actuarial valuation assumptions. The prepayment amount is equal to approximately 2.5 times a cooperative’s annual RS
Plan required contribution as of January 1, 2013. After making the prepayment, the annual contribution is reduced by approximately
25 percent, retroactive to January 1, 2013. The reduced annual contribution is expected to continue for approximately 15 years.
However, changes in interest rates, asset returns and other plan experience different from expected, plan assumption changes and
other factors may have an impact on future contributions and the 15-year period.
In May 2013, the Association elected to make a contribution prepayment of $71.2 million to the RS Plan. In accordance with RUS
guidance, this contribution prepayment was determined to be a long-term prepayment and therefore recorded in deferred charges
and amortized beginning January 1, 2013 over the 13-year period calculated by subtracting the Association’s average age of its
workforce from the Association’s normal retirement age under the RS Plan.
The Association’s contributions to the RS Plan include contributions for substantially all of the 351 bargaining unit employees that
are made in accordance with collective bargaining agreements that will be in effect through April 3, 2016.
41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In the RS Plan, a “zone status” determination is not required, and therefore not determined, under the Pension Protection Act
(“Act”) of 2006. In addition, the accumulated benefit obligations and plan assets are not determined or allocated separately by
individual employer. In total, the RS Plan was over 80 percent funded at January 1, 2013 and between 65 and 80 percent funded
at January 1, 2012 based on the Act funding target and the Act actuarial value of assets on those dates.
Because the provisions of the Act do not apply to the RS Plan, funding improvement plans and surcharges are not applicable.
Future contribution requirements are determined each year as part of the actuarial valuation of the plan and may change as a result
of plan experience.
Defined Contribution Plan:
The Association has a qualified savings plan for eligible employees who may make pre-tax and after-tax contributions totaling up
to 100 percent of their eligible earnings subject to certain limitations under federal law. The Association makes no contributions for
the 351 bargaining unit employees. For all of the eligible non-bargaining unit employees, other than the 225 employees of Colowyo
Coal, the Association contributes 1 percent of an employee’s eligible earnings. For the employees of Colowyo Coal, the Association
contributes 7 percent of an employee’s eligible earnings and also matches an employee’s contributions up to 5 percent. The Association
made contributions to the plan of $2.9 million, $3.0 million and $895,000 in 2013, 2012 and 2011, respectively.
Postretirement Benefits Other Than Pensions:
The Association sponsors three medical plans for all non-bargaining unit employees of the Association. Two of the plans provide post­
retirement medical benefits to full-time non-bargaining unit employees and retirees who receive benefits under those plans, who have
attained age 55, and who elect to participate. All three of these non-bargaining unit medical plans offer postemployment medical
benefits to employees on long-term disability. The plans were unfunded at December 31, 2013, are contributory (with retiree premium
contributions equivalent to employee premiums, adjusted annually) and contain other cost-sharing features such as deductibles.
The postretirement medical benefit liability balances of $3.0 and $2.9 million at December 31, 2013 and 2012, respectively, are
included in accumulated postretirement benefit and postemployment obligations. In 2010, there was a $4.7 million actuarial gain
determined by an actuarial study performed in 2010 (actuarial studies are performed every five years or earlier if plan facts warrant it).
$4.2 million of the gain was not recognized in net margins during 2010 because it was in excess of 10 percent of the projected
benefit obligation. Instead, it was reported separately as a component of other comprehensive income at December 31, 2010. The
unrecognized gain is amortized over the average remaining service lives of the active plan participants which results in an annual
recognition of the gain of $358,000 beginning in 2011.
The postemployment medical benefit liability balance of $291,000 at December 31, 2013 and 2012 is included in accumulated
postretirement benefit and postemployment obligations. The liability balance was determined by an actuarial study performed in
2010 (actuarial studies are performed every five years or earlier if plan facts warrant it).
Note 12—Commitments and Contingencies
Sales:
The Association has delivery obligations under resource-contingent firm power sales contracts with PSCO totaling 125 megawatts
in the summer season and 175 megawatts in the winter season. These contracts expire in 2016 and 2017. Also with PSCO, the
output of the two gas turbines at Knutson Generating Station and one gas turbine at the Limon Generating Station has been sold
under two contracts for a total of 210 megawatts in tolling capacity sales that expire in 2016. The tolling arrangements at Knutson
and Limon are accounted for as operating leases and the lease revenues are reflected in other operating revenue on the statements of
operations. The Limon turbine contract was suspended for a period of four years beginning in May 2009 and the Knutson turbine
contract was suspended for a period of three years beginning in May 2010 to allow the Association to utilize the output of the turbines.
Both of these turbine contracts with PSCO resumed on May 1, 2013 and are in effect through April 30, 2016. Tri-State also has an
agreement to sell 122 megawatts in tolling capacity to PSCO through June 30, 2019 from the J.M. Shafer Generating Station.
In addition, the Association has (1) a resource-contingent firm power sales contract of 100 megawatts to Salt River Project through
August 31, 2036, (2) a firm power sales contract committing up to 13 megawatts to BEPC through 2025, (3) a resource-contingent
firm power sales contract with PacifiCorp committing 25 megawatts through 2020, (4) a resource-contingent firm power sales
contract with Shell Energy North America of 50 megawatts through September 30, 2014 and (5) a resource-contingent tolling
power sales contract with Shell Energy North America of 40 megawatts from the Pyramid Generating Station through September
30, 2014. The tolling contract at Pyramid is accounted for as an operating lease and the lease revenue is reflected in other operating
revenue on the statements of operations.
42
Purchase Requirements:
The Association is committed to purchase coal for its generating plants under long-term contracts that expire between 2014 and
2034. These contracts require the Association to purchase a minimum quantity of coal at prices that are subject to escalation clauses
that reflect cost increases incurred by the suppliers and market conditions. The projection of contractually committed purchases
is based upon estimated future prices. At December 31, 2013, the annual minimum coal purchases under these contracts are as
follows (thousands):
2014
2015
2016
2017
2018
Thereafter
$111,523
76,166
81,010
83,387
79,986
225,264
$657,336
Indemnities:
The Association agreed to indemnify certain lessors and purchasers of the tax benefits under the safe harbor leases (see Note 2—
Deferred Equity Note) should certain disqualifying events occur, the most significant being the failure of the Association to maintain
its status as a taxable entity. Certain other safe harbor leases, not acquired by the Association, also contain indemnity responsibilities
that were assumed in 1992. Should a disqualifying event occur related to 2013 or prior, specified payments must be made to the
lessors and purchasers of $12.1 million, decreasing ratably through expiration in 2024.
Environmental:
The Association’s electric generation facilities are subject to various operating permits and must operate within guidelines imposed by
numerous environmental regulations. The Association believes these facilities are currently in compliance with such regulatory and
operating permit requirements with one exception. At the Nucla Generating Station, a deviation of the operating permit regarding
Emission Unit P106 occurred in the fall of 2011. This deviation was addressed and the facility is currently in compliance with its
operating permit. The Association cannot predict whether the State of Colorado will commence an enforcement action with respect
to this deviation, but no such action has yet been taken.
Deregulation:
The operating environment of the electric utility industry has moved toward partially regulated competition with the passage of the
1992 Energy Policy Act and subsequent Federal Energy Regulatory Commission orders that deregulate sales among power resellers.
As a result, end-user deregulation was left to the states, and the Association is actively monitoring proposed legislation. The effects
of potential legislation on the financial position or results of operations of the Association are not known at this time.
Legal:
On October 19, 2004, WFA and BEPC filed a complaint with the Surface Transportation Board (“STB”) alleging that the shipping
rates instituted by the BNSF Railway Company (“BNSF”) for the delivery of coal to the Laramie River Station were unjust and
unreasonable. On July 27, 2009, the STB issued its final decision, upholding the complaint and ordering refunds and shipping rate
reductions to WFA and BEPC. On September 2, 2009, BNSF appealed the STB decision to the United States Court of Appeals for
the DC Circuit. Notwithstanding the appeal, BNSF refunded certain amounts and reduced shipping rates. Those reductions were
passed on to WFA’s and BEPC’s members, including the Association. However, those reductions are subject to refund in the event
BNSF is ultimately successful in its appeal. Due to uncertainties regarding the ultimate outcome of this matter, the Association did
not recognize the benefit of the receipt of $29.4 million in 2009 in the consolidated statements of operations and still has not as of
December 31, 2013. Instead, the $29.4 million was recorded as a liability and is included in deferred credits and other liabilities at
December 31, 2013 and 2012. To the extent that the issue related to the cash receipt is ultimately resolved in favor of the Association,
the benefit will be recorded as a reduction in fuel expense at that time. The Court of Appeals affirmed the District Court Decision
on May 11, 2010 but remanded a single technical issue to the STB for reconsideration. On or about December 2, 2010, BNSF filed
a Petition for Certiorari with the United States Supreme Court. On May 16, 2011, the Supreme Court denied the Petition for
Certiorari. The issue remanded to the STB is pending. The Association is unable to project the outcome of this matter.
43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On September 28, 2009, five of the Association’s Nebraska members filed suit in the United States District Court for the District
of Nebraska alleging that the Association, inter alia, had breached its member contracts with those five members. The suit seeks a
separate rate to be applied to the five members and/or an order of the Court permitting the five members to withdraw from the
Association on terms to be determined by the Court. On August 19, 2010, the Nebraska court granted the Association’s motion
and transferred venue of the case to the District of Colorado. The Association denies the claims and intends to assert all available
defenses. Trial has been set for May 19, 2014. The Association is unable to project the outcome of the litigation.
On October 19, 2012, the Association gave notice, as required by New Mexico statutes, to the New Mexico Public Regulation
Commission (“NMPRC”) of its new A-37 wholesale rate which was scheduled to become effective on January 1, 2013. The rate
would have increased revenue collected from the Association’s 44 member systems by approximately 4.9 percent and from its 12 New
Mexico member systems by approximately 6.7 percent. On November 7, 2012, Continental Divide Electric Cooperative, Inc. and
Kit Carson Electric Cooperative, Inc. filed protests of the Association’s rates. On November 8, 2012, Springer Electric Cooperative
did the same. On December 20, 2012, the NMPRC suspended the rate filing in New Mexico and appointed a Hearing Examiner to
conduct a hearing and establish reasonable Rate Schedules pursuant to New Mexico statutes. Also on January 25, 2013, the Association
filed a Complaint for Declaratory and Injunctive Relief in the Federal District Court in New Mexico asking the Court to declare
the actions of the NMPRC to be in violation of the Commerce Clause of the United States Constitution. The Association intends
to vigorously pursue rate recovery and its Federal challenge to the actions of the NMPRC. On January 25, 2013, the Association
made an additional filing at the NMPRC seeking interim rate recovery from its New Mexico member systems during the pendency
of the NMPRC proceedings on the original rate filing. The NMPRC denied the filing on March 13, 2013. The Association
appealed that denial to the New Mexico Supreme Court. A decision by the Court is pending. On June 25, 2013, the Association
filed to withdraw the A-37 rate. On July 3, 2013, the NMPRC denied the filing to withdraw and ordered the A-37 rate filing to be
consolidated with the A-38 rate filing described below. On September 20, 2013, the Association gave notice, as required by New
Mexico statutes, to the NMPRC of its new A-38 wholesale rate which was scheduled to become effective on January 1, 2014. The
A-38 rate modified the rate design but did not increase the general revenue requirement. On December 11, 2013, the NMPRC suspended the A-38 rate filing and assigned the consolidated A-37 and A-38 rate filings to a Hearing Examiner. On March 4, 2013,
three of the Association’s Colorado member systems filed a complaint at the Colorado Public Utilities Commission (“COPUC”)
alleging that the A-37 rate design was unjust and unreasonable. The Association filed a motion to dismiss the complaint. The
COPUC assigned the matter to an Administrative Law Judge (“ALJ”). The ALJ conducted a hearing and ruled on September 11,
2013 that the COPUC had jurisdiction to hear the complaint. The Association appealed that decision to the full COPUC. On
January 3, 2014, the COPUC granted in part and denied in part the motion to dismiss. It remanded the case to the ALJ to hold a
hearing on limited issues. A hearing date has not been scheduled. The Association cannot predict the outcome of these matters.
44
Tri-State/Member System Consolidated Financial Data
(Unaudited)
(Thousands)
2012
Members
Tri-State
Less eliminations
System consolidation
2011
2010
2009
2008
Members Only (Thousands)
Revenues
Operating margins
Net margins
Plant in service (net)
Total assets
Long-term debt
Equity
Equity as a % of assets
Average retail rate (mills/kWh)
Total
Assets
$3,671,439
4,302,567
(903,840)
$7,070,166
6,774,705
6,310,130
6,114,287
4,804,894
2012
$1,555,060
34,896
95,411
2,309,196
3,671,439
1,566,279
1,685,963
45.9
102.5
Equity
$1,685,963
918,909
(802,712)
$1,802,160
1,740,494
1,659,874
1,570,976
1,301,958
2011
$1,473,907
34,163
114,156
2,187,086
3,442,389
1,446,019
1,620,956
47.1
99.3
Net
Margins
$95,411
52,795
(52,795)
$95,411
114,156
115,773
130,560
138,924
2010
$1,437,195
33,274
115,773
2,124,009
3,320,321
1,403,054
1,536,068
46.3
98.9
Equity as %
of Assets
45.9
21.4
25.5
25.7
26.3
25.7
27.1
2009
$1,355,178
23,530
130,560
2,061,546
3,171,371
1,363,741
1,441,528
45.5
99.1
2008
$1,290,934
36,664
138,924
1,958,336
2,934,692
1,275,200
1,302,436
44.4
95.9
Source: Members’ RUS Financial and Operating Reports. Due to the unavailability of the 2013 Member Financial information, the numbers being reported here are the 2012
and prior years’ information.
45
Tri-State Generation and Transmission Association, Inc. is committed to a policy of considering individuals
without regard to race, color, sex, sexual orientation, religion, national origin or age in decisions involving
hiring, promoting, transferring, training or any other terms or conditions of employment. Furthermore,
Tri-State will take affirmative action in the hiring, promoting, transferring and training of special disabled
veterans of the Vietnam era and disabled individuals.
46
P.O. Box 33695, Denver, CO 80233 / www.tristate.coop