T R I - S TAT E
G E N E R AT I O N A N D
T R A N S M I S S I O N A S S O C I AT I O N
2014
ANNUAL
REPORT
Turkey Creek Ranch, CO
TOGETHER
At Tri-State, it is who
we serve that matters.
Vortuba Farm, NE
Sierra Blanca Brewing, NM
Valley Foods, WY
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
Guided by the cooperative principles,
we work with each of our
to ensure communities across
the West have access to
affordable and reliable electricity.
1
BY THE
NUMBERS
2014
2
18.7M
15.4M
3.3M
TOTAL ENERGY
SALES (MWh)
ENERGY SALES
TO MEMBERS (MWh)
ENERGY SALES TO
NON-MEMBERS (MWh)
1,866MW
897MW
863MW
GENERATING CAPACITY,
COAL
OWNED GENERATING
CAPACITY, NATURAL GAS/OIL
$
$
RENEWABLE ENERGY
RESOURCES
$1.4B
$64.2M
2,813MW
TOTAL OPERATING
REVENUE
NET MARGINS
MEMBER PEAK
DEMAND
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
Positioning Statement Metrics, Graphs comparison
TRI-STATE’S OPERATIONAL AND
FINANCIAL STRENGTH PLACES THE
GENERATION AND TRANSMISSION
COOPERATIVE AMONG THE HIGHEST
PERFORMERS IN ITS INDUSTRY.
NET MARGIN
( $ i n m i l l i o n s)
558MW
CONTRACTED
GENERATING CAPACITY
5,396
’11
’12
’13
’14
MILES OF
TRANSMISSION LINE
69.9
52.8
72.9
64.2
P OW E R P R O D U C E D
( m e g awa t t - h o u r s i n m i l l i o n s)
’11
’12
’13
’14
$4.7B
TOTAL ASSETS
12.4M
13.2
12.1
12.5
12.4
TOTA L
M E G AWAT T- H O U R SA L E S
POWER PRODUCED (MWh)
( m e g awa t t - h o u r s i n m i l l i o n s)
’11
’12
’13
’14
7.1¢
AVERAGE WHOLESALE RATE
TO MEMBERS (per kWh)
1,540
EMPLOYEES
(includes subsidiaries)
19.4
18.7
18.6
18.7
M E M B E R CO I N C I D E N TA L
PEAK DEMAND
( m e g awa t t s i n t h o u s a n d s)
’11
’12
’13
’14
2.7
2.8
2.7
2.8
3
Positioning Statement Metrics, Graphs comparison
LETTER FROM
THE CHAIRMAN
Our members were overwhelmingly
supportive of moving forward
together over the past year, and we
saw significant progress in improving
member relations and engagement.
4
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
In many respects 2014 was a pivotal year for Tri-State
The association has reached a preliminary agreement
and our member systems. Among the year’s watershed
that establishes a process for us to pursue a settlement
events was the completion of the association’s $1.6 billion
in a rate protest brought by a few of our New Mexico
debt refinancing in November, which the board authorized
members. A similar agreement regarding rates has also
in August. Tri-State remains financially strong, and the
been reached with a few Colorado members, and we
refinancing ensures Tri-State is well-positioned to meet
continue to see progress in both states. In addition, a
infrastructure needs to serve our members and provides
longstanding dispute in Federal District Court with a few
cash flow savings that will help moderate upward pressure
of our Nebraska members has been resolved.
on the association’s wholesale rates.
Our members were overwhelmingly supportive of
Although Tri-State is no longer a borrower of the
moving forward together over the past year, and we saw
Rural Utilities Service nor the Federal Financing Bank,
significant progress in improving member relations and
the association remains an ardent supporter of the
engagement. These efforts have progressed thanks to the
invaluable federal lending institutions that continue
dedicated work of our great members and a committed,
to be an important source of capital for the nation’s
talented staff. I am confident that Mike and his very
electric cooperatives, including many of Tri-State’s
capable executive team will help us continue to move in
member systems.
a positive direction that will result in a stronger and more
Another key focus of the board during the past year has
unified association in 2015 and beyond.
been to improve relations and address disputes within the
membership. I am pleased to report that a great deal of
progress was made in 2014 toward these goals, thanks
to the hard work of our members, the board and staff.
In a positive step toward resolving issues within our
cooperative family, the board adopted two new dispute
resolution policies. These policies create a specific process
to address member concerns with rates and also support
resolution of other issues within the membership.
The board took significant steps to engage the
membership on the association’s power contracts and
wholesale rate design when it established member
contract and rate committees. The contract committee,
comprised of member system directors and CEOs as
well as Tri-State directors, examined the all-requirements
contracts that the association has with its members in
order to make recommendations to the board. The rate
committee, which also includes member system directors
and CEOs, and Tri-State directors, began an in-depth
review of wholesale rate options and is overseeing a
third-party cost-of-service study that will assist the
committee in making a rate design recommendation
to the board in 2015.
RICK GORDON
CHAIRMAN
5
In 2014, the association bolstered our already strong
We have made significant efforts to improve our support
financial position, ensured the solid performance of our
of and communication with the membership. A member
generation and transmission assets and improved service
relations staff reorganization and the creation of several
to our members. Tri-State also addressed regulatory
member advisory councils have helped Tri-State to better
proposals that could affect our ability to provide reliable
understand our members’ issues, share information,
and affordable electricity to our membership. These
tailor programs and recommend policies to meet the
accomplishments would not have been possible without
board’s goals and serve the members’ needs.
the guidance of our board and the performance of our
dedicated workforce.
Operationally, the association experienced load growth
in 2014, particularly in the oil- and gas-producing
The completion of Tri-State’s debt refinancing in
basins served by several of our member systems. Our
November 2014 was the culmination of many months of
transmission staff oversaw many new power delivery
hard work by Senior Vice President and Chief Financial
infrastructure projects aimed at meeting the growing
Officer Pat Bridges, his finance team and many other
needs of our membership, and generation staff continued
Tri-State employees who were involved in this complex
to ensure the performance and availability of our power
process that greatly benefits the association.
plant facilities. Tri-State’s energy markets staff bolstered
our ability to manage our power and fuel transactions.
In all efforts, attention to cost control remains important
to our work.
Safety is a top priority at Tri-State. Overall, the
association’s safety record remained better than the
national industry average. In July 2014, Craig Station
marked a safety milestone when plant employees
celebrated one million work-hours without a
lost-workday injury.
Tri-State continues to expand our diverse generation
portfolio and address regulatory challenges. While coal
remains the foundation of our power supply, in 2014 more
than 20 percent of the power that Tri-State delivered to
our members was from renewable generation. To ensure
we can utilize all resources, Tri-State took an active role
to address proposed regulations, including assessing
and filing comments on the EPA’s proposed Clean Power
Plan, which, if implemented, could significantly impact
our industry.
I would like to express my gratitude to the board
of directors in selecting me last May to serve as the
association’s executive vice president and general
manager. It is humbling to serve the membership and
support the cooperative business model, and we will
continue to power forward with our members to be
MIKE McINNES
more effective and efficient in 2015.
GENERAL MANAGER
6
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
LETTER FROM THE
GENERAL MANAGER
In 2014, the association bolstered our
already strong finances, ensured the
solid performance of our generation
and transmission assets and
improved service to our members.
7
FINANCIAL
STRENGTH
Q&A
Tri-State’s most significant milestone of 2014 was the completion
of a series of transactions through Nov. 5, 2014, that resulted in the
refinancing of a substantial portion of the association’s debt. This
refinancing will benefit Tri-State and its members for years to come.
Pat Bridges, chief financial officer, led the refinancing effort.
Q: What was the scope of the transactions?
A: The transactions totaled $1.6 billion, included a $750-million private
debt placement, a $500-million public bond offering and $340 million
in CoBank and National Rural Utilities Cooperative Finance Corporation
(CFC) loans.
Q: What is the average rate on new debt?
A: The average interest rate on the new debt is approximately
3.9 percent. This transaction is among the largest completed by an
electric cooperative in U.S. history. In order to strengthen liquidity,
Tri-State also increased its credit facility from $500 million to
$750 million, extended the maturity to 2019 and added several
new banks to the credit facility.
Q: What are some of the drivers that led
to the landmark decision to refinance
Tri-State’s debt?
A: In recent years we have taken significant steps to ensure the
long-term reliability of our power plants. Additionally, we have
transmission assets with very long lives. Nearly all of the association’s
member contract terms expire in 2050, but the bulk of our financing
did not match that time frame. As loans taken out in the 1980s and
1990s have matured, Tri-State was faced with a “front-end loading”
Pat Bridges
Senior Vice President, Chief Financial Officer
of increasing principal payments that were exerting upward pressure
on the association’s rates. The new refinancing extends those higher
principal payments into the future to better match financing to the life
of our assets. This action moderates upward rate pressure and reduces
the amount of future borrowing required for capital needs.
8
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
In today’s complex electric industry, it is more important than ever for
Tri-State to understand and communicate well with our members as
we serve our mission to provide a reliable, cost-based power supply in
accordance with cooperative principles. Tri-State is taking a proactive
approach to meeting our members’ diverse needs, according to
Jennifer Goss, senior vice president, member relations.
Q: How do you view the role of
member relations?
MEMBER
RELATIONS
Q&A
A: Our whole focus is membership driven. Member relations serves
as the advocate for members at Tri-State, and it is our responsibility
to ensure that their interests and views are known and considered as
Tri-State serves its mission to provide our members with reliable and
affordable power.
Q: What were the first changes you made
when you joined Tri-State in 2013?
A: To effectively support our members, the member relations team
needs to know, understand and respect each individual member
system’s goals, values, issues and concerns­—all are unique and all
need to be considered. To help achieve this level of knowledge and
build trust with our members, we started by realigning and renaming
the member services group to member relations, and we combined
our member services and communications teams. Collectively,
staff set forward with a common goal of stronger communication
and engagement.
Q: What steps have been taken with the
members to build stronger relations?
A: Based upon input from our member systems, we’re expanding
Jennifer Goss
Senior Vice President, Member Relations
our programs, tools and offerings to make them more valuable and
relevant. We’ve also reassigned staff to serve as relationship managers
who offer personal service to each of our 44 member systems. We’ve
created topical advisory councils for members, including renewable
and distributed generation, demand response and energy shaping,
and communications, which have proven invaluable for collaboration
between member system staff and Tri-State personnel. In addition,
we established orientation programs for new Tri-State directors
and member system CEOs, as well as our member system boards
of directors, to help build a mutual understanding between the
members and their G&T.
9
MEMBER
DISTRIBUTION
SYSTEMS
JM JÉMEZ MOUNTAINS
ELECTRIC COOPERATIVE
ESPAÑOLA, NEW MEXICO
KC K.C. ELECTRIC
ASSOCIATION
HUGO, COLORADO
KT KIT CARSON
ELECTRIC COOPERATIVE
TAOS, NEW MEXICO
LP LA PLATA
BH BIG HORN RURAL
ELECTRIC COMPANY
BASIN, WYOMING
ELECTRIC ASSOCIATION
DURANGO, COLORADO
SARATOGA, WYOMING
ELECTRIC COOPERATIVE
MOUNTAINAIR, NEW MEXICO
CR CHIMNEY ROCK
PUBLIC POWER DISTRICT
BAYARD, NEBRASKA
CO COLUMBUS ELECTRIC
ELECTRIC ASSOCIATION
MONTROSE, COLORADO
EM EMPIRE ELECTRIC ASSOCIATION
CB CARBON POWER & LIGHT
CN CENTRAL NEW MEXICO
10
DMDELTA-MONTROSE
CORTEZ, COLORADO
GL GARLAND LIGHT &
POWER COMPANY
POWELL, WYOMING
GC GUNNISON COUNTY
ELECTRIC ASSOCIATION
GUNNISON, COLORADO
HP HIGH PLAINS POWER
RIVERTON, WYOMING
COOPERATIVE
HW HIGH WEST ENERGY
DEMING, NEW MEXICO
PINE BLUFFS, WYOMING
CD CONTINENTAL DIVIDE
HL HIGHLINE ELECTRIC
ELECTRIC COOPERATIVE
GRANTS, NEW MEXICO
ASSOCIATION
HOLYOKE, COLORADO
MWTHE MIDWEST ELECTRIC
COOPERATIVE CORPORATION
GRANT, NEBRASKA
MO MORA-SAN MIGUEL
ELECTRIC COOPERATIVE
MORA, NEW MEXICO
MC MORGAN COUNTY RURAL
ELECTRIC ASSOCIATION
FORT MORGAN, COLORADO
MP MOUNTAIN PARKS ELECTRIC
GRANBY, COLORADO
MV MOUNTAIN VIEW
ELECTRIC ASSOCIATION
LIMON, COLORADO
NB NIOBRARA ELECTRIC
ASSOCIATION
LUSK, WYOMING
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
MAJOR
TRI-STATE
RESOURCES
1 HEADQUARTERS AND OPERATIONS CENTER
WESTMINSTER, COLORADO
2 CRAIG STATION
CRAIG, COLORADO
3 NUCLA STATION
NUCLA, COLORADO
4 BURLINGTON STATION
BURLINGTON, COLORADO
5 J.M. SHAFER GENERATING STATION
FORT LUPTON, COLORADO
6 LIMON GENERATING STATION
LIMON, COLORADO
7 FRANK R. KNUTSON GENERATING STATION
BRIGHTON, COLORADO
8 RIFLE GENERATING STATION
NR NORTHERN RIO ARRIBA
ELECTRIC COOPERATIVE
CHAMA, NEW MEXICO
NW NORTHWEST RURAL
PUBLIC POWER DISTRICT
HAY SPRINGS, NEBRASKA
OC OTERO COUNTY
ELECTRIC COOPERATIVE
CLOUDCROFT, NEW MEXICO
PH PANHANDLE RURAL ELECTRIC
MEMBERSHIP ASSOCIATION
ALLIANCE, NEBRASKA
PV POUDRE VALLEY RURAL
ELECTRIC ASSOCIATION
FORT COLLINS, COLORADO
RS ROOSEVELT PUBLIC
POWER DISTRICT
MITCHELL, NEBRASKA
SI SAN ISABEL
ELECTRIC ASSOCIATION
PUEBLO WEST, COLORADO
SV SAN LUIS VALLEY RURAL
ELECTRIC COOPERATIVE
MONTE VISTA, COLORADO
SM SAN MIGUEL
POWER ASSOCIATION
NUCLA, COLORADO
SC SANGRE DE CRISTO
ELECTRIC ASSOCIATION
BUENA VISTA, COLORADO
SR SIERRA ELECTRIC COOPERATIVE
ELEPHANT BUTTE, NEW MEXICO
SO SOCORRO ELECTRIC
COOPERATIVE
SOCORRO, NEW MEXICO
SE SOUTHEAST COLORADO
POWER ASSOCIATION
LA JUNTA, COLORADO
SWSOUTHWESTERN
ELECTRIC COOPERATIVE
CLAYTON, NEW MEXICO
SPSPRINGER
ELECTRIC COOPERATIVE
SPRINGER, NEW MEXICO
UN UNITED POWER
BRIGHTON, COLORADO
WB WHEAT BELT PUBLIC
POWER DISTRICT
SIDNEY, NEBRASKA
WL WHEATLAND RURAL
ELECTRIC ASSOCIATION
WHEATLAND, WYOMING
WR WHITE RIVER
ELECTRIC ASSOCIATION
RIFLE, COLORADO
9 LARAMIE RIVER STATION
WHEATLAND, WYOMING
10 ESCALANTE GENERATING STATION
PREWITT, NEW MEXICO
11 SAN JUAN GENERATING STATION
FARMINGTON, NEW MEXICO
12 PYRAMID GENERATING STATION
LORDSBURG, NEW MEXICO
13 DAVID A. HAMIL DC TIE
STEGALL, NEBRASKA
14 SPRINGERVILLE GENERATING STATION
SPRINGERVILLE, ARIZONA
15 CIMARRON SOLAR FACILITY*
SPRINGER, NEW MEXICO
16 KIT CARSON WINDPOWER PROJECT*
BURLINGTON, COLORADO
17 COLORADO HIGHLANDS WIND*
FLEMING, COLORADO
MEEKER, COLORADO
WY WYRULEC COMPANY
LINGLE, WYOMING
YW Y-W ELECTRIC ASSOCIATION
AKRON, COLORADO
*Long-term power purchase arrangements.
11
2014
IN REVIEW
In addition to Tri-State’s 2014
refinancing and ongoing efforts to
strengthen member relations, the
association had many significant
achievements throughout the year.
The most immediate impact of the refinancing, as
well as from Tri-State’s attention to cost controls,
is that the association’s members will see no change
in the average wholesale rate in 2015.
On the regulatory and environmental front, in 2014
Tri-State proactively addressed the Environmental
Protection Agency’s Clean Power Plan, which is
a proposal to require states to reduce carbon
dioxide emissions from the electric power sector.
The potential impact from this proposal includes
increased electricity prices and less reliable
electricity for families and businesses across
the West.
Tri-State continues to assess the Clean Power
Plan, has filed comments on the proposal with
the EPA and is engaged with the states that would
be required to implement the proposal. Tri-State
is working closely with NRECA and other trade
groups in proactively addressing the potential
legal, reliability and cost impacts of the proposed
Clean Power Plan.
The association continues to be actively engaged in
other environmental and reliability compliance issues
that impact Tri-State and our members’ operations
in order to mitigate the risks these issues present to
the association.
12
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
Numerous highlights and accomplishments during 2014 included:
••
ri-State maintained a safe and secure work environment, with our safety
T
record remaining better than the national average. ••
Employees at Craig Station reached one million work-hours without a
lost-workday injury.
••
he association secured a 30-year extension of the Western Area Power
T
Administration Loveland Area Projects hydropower contract to 2054.
••
he U.S. Department of Energy recognized Tri-State and member
T
San Isabel Electric Association as 2014 Wind Cooperatives
of the Year. ••
In 2014, Tri-State issued a request for proposals for additional renewable
energy resources. The association also continued its planning for the
150-megawatt Carousel Wind Farm, which will be Tri-State’s largest wind
power purchase when the project is completed in 2016. ••
ri-State continues to support its members’ renewable energy goals. At
T
the end of 2014, 16 members had participated in renewable and distributed
energy projects totaling 54 megawatts.
Tri-State maintained a safe and secure work
environment, with our safety record remaining
better than the national average.
••
olstered by the member systems’ outreach and promotion of products to
B
their members in support of the wise use of energy, Tri-State provided the
member systems with $2.1 million in energy efficiency rebates. In addition,
18 member systems were enrolled in the association’s demand response
and energy shaping programs, and 10 member systems were enrolled in
load performance programs.
••
oundation work was completed for the Craig Station Unit 2 selective
F
catalytic reduction system. ••
Escalante Station successfully performed a major outage with turbine
and scrubber upgrades, and the association secured a new five-year fuel
supply agreement that will significantly reduce costs at the New Mexico
power plant. ••
he first phase of gas turbine governor control upgrades was completed at
T
J.M. Shafer Station, and a significant portion of the natural gas combinedcycle power plant’s long-term water supply was secured. 13
14
••
ri-State installed automatic generation control
T
systems on Craig Station Units 1 and 2, and
J.M. Shafer Station. ••
ri-State’s mining operations, Colowyo Mine
T
and New Horizon Mine, were recognized with
awards for safety, innovation, reclamation and
environmental stewardship. ••
ri-State completed a number of significant
T
transmission projects, including construction
and energizing of the Keota substation, the
Gladstone phase shifter transformer upgrade
and the Plaza Waverly loop. ••
t year-end, Tri-State completed and energized
A
19 new delivery
points to the members
and continued to expand and upgrade our
telecommunications network.
••
nder a program to voluntarily transfer
U
member system assets that are 100 kilovolts
or greater to Tri-State, in 2014 the G&T was
halfway through the acquisition of transmission
assets from the membership, with 18 member
transactions fully closed.
••
Four new long-term sales agreements
to non-members were signed in 2014,
and Tri-State extended or established
several small hydropower supply contracts. ••
eeping pace with vacancies created by
K
retiring employees, Tri-State graduated 21
transmission and generation apprentices
to journeymen. ••
ri-State managed and participated in 29
T
electric industry research and development
projects with other utilities, organizations
and universities. ••
The Work of Power campaign was
launched to promote the value and wise
use of electricity, with members actively
participating in
the campaign. ••
he association expanded youth energy
T
education programs through the enhancement
of the Tri-State/American Farm Bureau
Foundation Power UP video game and
delivered its fourth annual energy teachertraining program.
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
BOARD OF
DIRECTORS
Rick Gordon
Chairman
Mountain View Electric
Tony Casados
Vice Chairman
Northern Rio Arriba Electric
Leo Brekel
Secretary
Highline 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
Stuart Morgan
Treasurer
Wheat Belt Public Power
Jack Finnerty
Executive Committee
Wheatland Rural Electric
Matt Brown
Assistant Secretary
High Plains Power
William Mollenkopf
Executive Committee
Empire Electric
Wayne Connell
Assistant Secretary
Central New Mexico Electric
Joe Wheeling
Executive Committee
La Plata Electric
Robert Bledsoe
Jerry Burnett
Richard Clifton
Lucas Cordova, Jr.
Gary Fuchser
Ron Hagan
K.C. Electric
Jémez Mountains Electric
High West Energy
Northwest Rural
Public Power
Carbon Power & Light
from each of its members.
Each director is appointed by his or her local
co-op or public power district 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.
Midwest Electric
15
Jack Hammond
Joseph Herrera
Ronald Hilkey
Ralph Hilyard
Don Keairns
Hal Keeler
Julie Kilty
Gary Merrifield
Thaine Michie
Virginia Mondragon
Chris Morgan
Richard Newman
William Patterson
Tim Rabon
Gary Rinker
Arthur Rodarte
Claudio Romero
Don Russell
Brian Schlagel
Gerald Seward
Jack Sibold
Jim Soehner
Kevin Stuart
Darryl Sullivan
Niobrara Electric
Columbus Electric
Gunnison County Electric
Kit Carson Electric
San Miguel Power
16
Socorro Electric
Wyrulec Co.
United Power
Continental Divide Electric
Y-W Electric
White River Electric
Sangre de Cristo Electric
Delta-Montrose Electric
Big Horn Rural Electric
Chimney Rock Public Power
Roosevelt Public Power
Poudre Valley Rural Electric
Otero County Electric
Morgan County Rural Electric
San Isabel Electric
Mora-San Miguel Electric
Southwestern Electric
Springer Electric
Sierra Electric
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
Jerry Thompson
Carl Trick, II
Bill Wright
Phil Zochol
Garland Light & Power
Southeast Colorado Power
Mountain Parks Electric
Scott Wolfe
San Luis Valley
Rural Electric
Panhandle Rural Electric
EXECUTIVE
MANAGEMENT
Mike McInnes
Executive Vice President
General Manager
Joel Bladow
Senior Vice President
Transmission
Pat Bridges
Senior Vice President
Chief Financial Officer
Tri-State’s highly qualified
leadership team averages
24 years experience in the utility
sector and a total of 250 years
Ellen Connor
Jennifer Goss
Barry Ingold
Brad Nebergall
Ken Reif
Barbara Walz
Senior Vice President
Organizational Services
Chief Technology Officer
Senior Vice President
Energy Management
Senior Vice President
Member Relations
Senior Vice President
General Counsel
of utility experience.
Senior Vice President
Generation
Senior Vice President
Policy & Compliance
Chief Compliance Officer
17
FINANCIAL
HIGHLIGHTS
& FIVE-YEAR
FINANCIAL SUMMARY
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 2014 were 15.4 million
megawatt-hours, which was an increase of 113 thousand
megawatt-hours from 2013. Member electric sales
revenue increased $10.4 million, or 1 percent, to
$1.1 billion. Non-member electric sales revenue increased
$25.4 million, or 14.8 percent, to $197.5 million. The
increase was due to higher average market prices and
Tri-State had an excellent year from a financial perspective.
the recognition of $20 million of previously deferred
Tri-State’s most significant financial highlight in 2014 was
non-member electric sales revenue. Additionally,
a series of debt refinancing transactions in the 4th quarter
Tri-State set a new coincident peak demand record
totaling $1.6 billion which will benefit Tri-State and its
of 2,813 megawatts in July.
members for years to come. The scope of the transactions
included a $750 million private placement, $500 million
of public bond offerings and $340 million in CoBank and
National Rural Utilities Cooperative Finance Corporation
(CFC) loans. Additionally, Tri-State strengthened its
liquidity position by increasing its secured revolving credit
facility from $500 million to $750 million, extending the
maturity to 2019. As of December 31, 2014, Tri-State had
$92.5 million in cash and $652 million available to advance
Operating expenses increased $60.6 million, or
5.3 percent, to $1.2 billion in 2014. The increase in
operating expenses was partly due to an increase in
generation maintenance of $21.8 million, as a result of
an increase in maintenance outages at Escalante and
J.M. Shafer generating stations for turbine overhaul
projects and Laramie River Station for boiler repairs
and turbine overhaul. Purchased power increased
on the revolving credit facility.
325 thousand megawatt-hours, or 4.8 percent,
In order to continue to provide its members with reliable,
expense of $5.4 million, or 1.7 percent, to $327.4 million.
cost-based power, Tri-State added generation and
Depreciation and amortization expense increased
transmission capital improvements of $221.6 million,
$6.9 million, or 5.7 percent, to $128.7 million in 2014 due
increasing electric plant in service from $5.2 billion as of
to additions of equipment throughout the association’s
December 31, 2013 to $5.4 billion as of December 31, 2014.
transmission system and at the generating stations.
Tri-State’s margin of $64.2 million in 2014 provided debt
Interest expense, net of amounts capitalized, decreased
service coverage well in excess of the requirement in its
$7.1 million in 2014, primarily due to a decline in the
bond indenture and helped grow patronage capital equity
weighted average interest rate on the association’s
to $908.7 million and equity as a percentage of total
long-term debt.
which resulted in an increase in purchased power
capitalization to 23.8 percent. True to the cooperative
business model, Tri-State’s board of directors declared
$21 million in patronage capital refunds to its members
during 2014, which makes this the 26th consecutive year
that the association has returned capital credits.
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.
TOTA L O P E R AT I N G R E V E N U E
PAT R O N AG E C A P I TA L R E T I R E M E N TS
( $ i n m i l l i o n s)
’10
’1 1
’12
’13
’14
18
1,218
1,184
1,292
1,341
1,395
( $ i n m i l l i o n s)
’10
’1 1
’12
’13
’14
20.0
20.0
10.0
10.0
20.9
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
FIVE-YEAR FINANCIAL SUMMARY
(Thousands)
2014
2013
2012
2011
2010
Operating revenues
Member electric sales
$1,101,471 $ 1,091,103 $ 1,067,085 $ 1,007,993 $ 981,126
Non-member electric sales 197,497 172,102 162,694 152,806 208,357
Other
96,123
77,958
62,053
23,632
28,694
Operating expenses
Power costs
(850,411) (819,522) (797,136) (727,185) (728,735)
Transmission
(145,396) (138,684) (136,853) (136,825) (121,786)
General and administrative
(28,591) (24,325)
(22,810)
(18,930)
(18,694)
Depreciation and amortization
(128,712) (121,818) (124,861) (105,793) (131,739)
Coal mining
(40,849) (29,889)
(25,027)
(2,562)
—
Other
(19,255) (18,337)
(18,930)
(34,381)
(36,610)
Operating margins
181,877 188,588 166,215 158,755 180,613
Other income
23,333 31,554
35,443
62,378
29,703
Interest expense
(142,357) (149,463) (151,905) (155,022) (147,649)
Income taxes
—
—
—
10
9,738
Net margins including noncontrolling interest
$62,853 $ 70,679 $ 49,753 $ 66,121 $ 72,405
Net loss attributable to noncontrolling interest
1,383
2,233
3,042
3,813
4,739
Net margins attributable to the Association
$64,236 $ 72,912 $ 52,795 $ 69,934 $ 77,144
Electric plant in service (net)
$3,064,063 $ 2,941,860 $ 2,926,700 $ 2,819,499 $ 2,696,137
Construction work in progress
206,097 231,374 152,355 183,178 201,011
Net electric plant 3,270,160 3,173,234 3,079,055 3,002,677 2,897,148
Net other plant
152,577 168,852 162,829 156,667
19,184
Total property, plant and equipment
3,422,7373,342,086 3,241,884 3,159,344 2,916,332
Investments in other associations
117,976 128,227 121,938 117,211 113,436
Restricted cash and investments
39,376 118,124 239,253 241,766 325,019
Intangible assets
32,958
40,283
47,607
54,931
—
Regulatory assets
426,043 248,857 259,387 273,240 180,435
Other assets
260,666 238,343 166,883 166,221 152,113
Total other assets
877,019 773,834 835,068 853,369 771,003
Cash and cash equivalents
92,468 193,057
81,492 117,507 205,452
Restricted cash and investments
9,784 125,731 126,902 194,127 150,196
Accounts receivable
131,416 125,022 133,401 120,527 115,104
Inventories
120,742 119,207 132,612 119,214
94,185
Other current assets
22,224
22,569
19,193
17,985
17,098
Total current assets
376,634 585,586 493,600 569,360 582,035
Total assets
$4,676,390 $ 4,701,506 $ 4,570,552 $ 4,582,073 $ 4,269,370
Long-term debt
$ 3,165,960 $ 3,078,140 $ 3,058,353 $ 3,103,252 $ 2,966,753
Current liabilities
300,627 437,684 390,807 390,352 325,690
Regulatory liabilities
45,000
65,000
65,000
75,000
30,239
Deferred credits, other liabilities and APBO
147,660 141,228 137,483 134,014 112,898
Total liabilities
3,659,247 3,722,052 3,651,643 3,702,618 3,435,580
Patronage capital equity
908,669 865,379 802,467 759,672 709,738
Accumulated other comprehensive income (loss)
(828) 3,335
3,415
3,663
4,069
Noncontrolling interest
109,302 110,740 113,027 116,120 119,983
Total equity 1,017,143 979,454 918,909 879,455 833,790
Total equity and liabilities
$4,676,390 $ 4,701,506 $ 4,570,552 $ 4,582,073 $ 4,269,370
Other data:
Megawatt-hours sold—member
15,426,603 15,313,487 15,717,468 15,421,227 15,026,510
—non-member
3,272,140 3,316,487 3,010,314 3,976,884 3,836,646
System coincident peak demand—megawatts
2,813
2,666
2,798
2,654
2,568
Average member mills/kWh—sales
71.40
71.25
67.89
65.36
64.98
Average member mills/kWh—capital refunds
1.36
0.65
0.64
1.30
1.33
Plant additions (cash)
$ 221,613 $ 212,703 $ 191,651 $ 143,354 $ 232,805
Capital credit allocations received
8,684
10,922
7,845
7,167
6,162
Tri-State patronage capital retirements
20,946
10,000
10,000
20,000
20,000
Long-term debt repaid
1,739,835 196,490 416,780 142,767 220,466
Weighted average long-term debt interest rate
5.0%5.5
%5.8
%6.6
%6.3
%
Equity as a % of total capitalization
23.8%22.8
%22.0
%21.1
%21.1
%
19
Report of Ernst & Young LLP, Independent Registered Public Accounting Firm
The Board of Directors of
Tri-State Generation and Transmission Association, Inc.
We have audited the accompanying consolidated statements of financial position of Tri-State
Generation and Transmission Association, Inc. (the Association) as of December 31, 2014 and
2013, 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, 2014. These financial
statements are the responsibility of the Association’s management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting
Oversight Board (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. We were not engaged to perform an audit of the Association’s internal control
over financial reporting. Our audits included consideration of internal control over financial
reporting as a basis for designing audit procedures that are appropriate in the circumstances, but
not for the purpose of expressing an opinion on the effectiveness of the Association’s internal
control over financial reporting. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our 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, 2014 and 2013, and the consolidated results of its operations and its cash flows for
each of the three years in the period ended December 31, 2014, in conformity with U.S.
generally accepted accounting principles.
Denver, Colorado
March 3, 2015
20
EY
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
As of December 31, (Thousands)
2014
ASSETS
Property, plant and equipment
Electric plant
In service
Construction work in progress
Total electric plant
Less allowances for depreciation and amortization
Net electric plant
Other plant
Accumulated depreciation and depletion
Net other plant
Total property, plant and equipment
Other assets and investments
Investments in other associations
Investments in and advances to coal mines
Restricted cash and investments
Intangible assets
Other noncurrent assets
Total other assets and investments
Current assets
Cash and cash equivalents
Restricted cash and investments
Deposits and advances
Accounts receivable - members
Other accounts receivable
Coal inventory
Materials and supplies
Total current assets
Deferred charges
Regulatory assets Prepayment - NRECA Retirement and Security Plan
Other
Total deferred charges
Total assets
EQUITY AND LIABILITIES
Capitalization
Patronage capital equity
Accumulated other comprehensive income (loss)
Noncontrolling interest
Total equity
Long-term debt
Total capitalization
Current liabilities
Member advances
Accounts payable
Accrued expenses
Accrued interest
Accrued property taxes
Current maturities of long-term debt
Total current liabilities
Deferred credits and other liabilities
Regulatory liabilities
Deferred income tax liability
Intangible liabilities
Asset retirement obligations
Other
Total deferred credits and other liabilities
Accumulated postretirement benefit and postemployment obligations
Total equity and liabilities
2013
$ 5,193,236 $4,965,495
206,097 231,374
5,399,333 5,196,869
(2,129,173) (2,023,635)
3,270,160 3,173,234
210,694 207,440
(58,117) (38,588)
152,577 168,852
3,422,7373,342,086
117,976 128,227
15,016 13,507
39,376 118,124
32,958 40,283
12,531 12,813
217,857 312,954
92,468 193,057
9,784 125,731
22,224 22,569
105,723 93,590
25,693 31,432
40,673 43,730
80,069 75,477
376,634 585,586
426,043 248,857
54,665 60,184
178,454 151,839
659,162 460,880
$4,676,390 $4,701,506
$908,669 $865,379
(828) 3,335
109,302 110,740
1,017,143 979,454
3,165,960 3,078,140
4,183,103 4,057,594
14,576 12,348
103,177 109,807
30,005 30,830
32,517 24,608
26,010 23,503
94,342 236,588
300,627 437,684
45,000 65,000
17,230 11,859
9,424 12,652
53,754 52,585
59,121 60,884
184,529 202,980
8,131
3,248
$ 4,676,390 $4,701,506
The accompanying notes are an integral part of these consolidated statements.
21
CONSOLIDATED STATEMENTS OF OPERATIONS
For the years ended December 31, (Thousands)
2014
20132012
Operating revenues
Member electric sales $ 1,101,471 $ 1,091,103 $ 1,067,085
Non-member electric sales 197,497 172,102
162,694
Other 96,123
77,958
62,053
1,395,091 1,341,163 1,291,832
Operating expenses
Purchased power
Fuel
Production
Transmission
General and administrative
Depreciation and amortization
Coal mining
Other
327,445
293,033
229,933
145,396
28,591
128,712
40,849
19,255
322,059
287,647
209,816
138,684
24,325
121,818
29,889
18,337
310,293
273,169
213,674
136,853
22,810
124,861
25,027
18,930
1,213,214 1,152,575 1,125,617
Operating margins
181,877 188,588
Other income
Interest income Capital credits from cooperatives Other income 11,076
8,684
3,573
17,288
10,922
3,344
24,035
7,845
3,563
23,333
31,554
35,443
Interest expense, net of amounts capitalized 142,357
149,463
151,905
Income taxes —
—
—
Net margins including noncontrolling interest Net loss attributable to noncontrolling interest 62,853
1,383
70,679
2,233
49,753
3,042
Net margins attributable to the Association $
64,236 $
72,912 $
52,795
166,215
The accompanying notes are an integral part of these consolidated statements.
22
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the years ended December 31, (Thousands)
2014
2013
70,679 $
2012
49,753
$
62,853 $
—
(4,194) 278
—
110
—
31
—
(358)
—
(358)
—
Net margins including noncontrolling interest
Other comprehensive loss:
Unrealized gain on securities available for sale
Unrecognized actuarial loss on postretirement benefit obligation
Reclassification adjustment for actuarial (gain)/loss on postretirement
benefit obligation included in net income
Income tax expense related to components of other comprehensive loss
Other comprehensive loss (4,163) Comprehensive income including noncontrolling interest Net comprehensive loss attributable to noncontrolling interest 58,690
1,383
70,599
2,233
49,505
3,042
Comprehensive income attributable to the Association $
60,073 $
72,832 $
52,547
(80)
(248)
The accompanying notes are an integral part of these consolidated statements.
CONSOLIDATED STATEMENTS OF EQUITY
For the years ended December 31, (Thousands)
20142013 2012
Patronage capital equity at beginning of year $ 865,379 $ 802,467 $
Net margins attributable to the Association 64,236
72,912
Retirement of patronage capital (20,946)
(10,000)
759,672
52,795
(10,000)
Patronage capital equity at end of year
908,669 865,379
802,467
Accumulated other comprehensive income at beginning of year
Unrealized gain on securities available for sale Unrecognized actuarial loss on postretirement benefit obligation Reclassification adjustment for actuarial (gain)/loss on
postretirement benefit obligation included in net income 3,335
—
(4,194) 3,415
278
—
31
(358)
Accumulated other comprehensive income at end of year
(828) 3,335
Noncontrolling interest at beginning of year
Net loss attributable to noncontrolling interest Equity distribution to noncontrolling interest 110,740
(1,383) (55) 113,027
(2,233)
(54)
116,120
(3,042)
(51)
Noncontrolling interest at end of year
109,302 110,740
113,027
Total equity at end of year $ 1,017,143 $ 979,454 $
3,663
110
—
(358)
3,415
918,909
The accompanying notes are an integral part of these consolidated statements.
23
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
Amortization of intangible asset
Amortization of NRECA Retirement and Security Plan prepayment
Amortization of debt issuance costs
Capital credit allocations from cooperatives and income from coal mines
under (over) refund distributions
Prepayment - NRECA Retirement and Security Plan
Recognition of 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
Accrued interest
Accrued property taxes
Other
$
2014
62,853 $
20132012
70,679 $
126,693
7,324
5,519
1,356
(6,465) (7,053)
— (71,160
)
(20,000) —
—
(390)
118,776
7,324
5,457
897
49,753
115,958
7,324
—
881
(11,217)
—
(10,000)
(30,380)
(6,460) 3,057
(4,593) (5,923) 7,909
2,507
13,076
7,000
17,524
(4,119)
13,090
(1,061)
(189)
(5,089)
(12,868)
(6,941)
(6,457)
13,111
(16,139)
(153)
(110)
Net cash provided by operating activities
186,853 151,686
92,762
Investing activities
Purchases of plant Changes in deferred charges Proceeds from other investments (221,613) (212,703)
(191,651)
(8,263) (1,849
)
1,290
15,270
1,578
5,487
Net cash used in investing activities
(214,606) Financing activities
Member advances
Payments of long-term debt
Proceeds from issuance of debt
Debt refinancing transaction costs
Decrease in advance payments to RUS
Retirement of patronage capital
Proceeds from investment in securities pledged as collateral
Change in restricted cash and investments
2,227
(1,739,835) 1,674,977
(184,073) 137,727
(20,582) 8,723
48,000
(212,974)
(184,874)
(2,129)
(196,490)
258,873
—
130,257
(10,711)
8,410
(15,357)
(1,385)
(416,780)
390,177
—
123,115
(14,869)
8,483
(32,644)
Net cash provided by (used in) financing activities
(72,836) 172,853
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents - beginning
(100,589) 193,057 111,565
81,492
Cash and cash equivalents - ending $
92,468 $ 193,057 $
Supplemental information:
Cash paid for interest $112,388
$ 124,703 $
56,097
(36,015)
117,507
81,492
142,375
The accompanying notes are an integral part of these consolidated statements.
24
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 – ORGANIZATION
Tri-State Generation and Transmission Association, Inc. (the “Association”) is a taxable wholesale electric power generation
and transmission cooperative organized for the purpose of providing electricity to 44 member distribution systems that serve
major parts of Colorado, Nebraska, New Mexico and Wyoming. The Association also sells a portion of its electric power to other
utilities in the region pursuant to long-term contracts and spot sale arrangements. In 2014, 2013 and 2012, total megawatthours sold were 18.7, 18.6 and 18.7 million, respectively, of which 83, 82 and 84 percent, respectively, were sold to members.
Total revenue from electric sales was $1.3 billion for 2014 and 2013 and $1.2 billion for 2012 of which 85, 86 and 87 percent,
respectively, was from member sales. Energy resources were provided by generation and purchased power, of which 63, 64 and
62 percent were from generation for 2014, 2013 and 2012, respectively.
The Association has entered into substantially similar contracts with each member extending through 2050 for 42 members
and extending through 2040 for the remaining two members, and subject to automatic extension thereafter until either party
provides at least a two year notice of its intent to terminate. Each contract obligates the Association to sell and deliver to the
member and obligates the member to purchase and receive from the Association at least 95 percent of the power it requires
for the operation of its system. Each member may elect to provide up to 5 percent of its requirements from distributed or
renewable generation owned or controlled by the member. As of December 31, 2014, 16 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 and to meet certain long-term debt financial covenants, including a debt service
ratio requirement and an equity to capitalization ratio requirement.
The Association supplies wholesale power to its member distribution systems through the utilization of a portfolio of resources,
including generating facilities, long-term purchase contracts and forward, short-term and spot market energy purchases. The
Association’s generating facilities also include undivided ownership interests in jointly owned generating facilities. See Note 3 Property, Plant and Equipment. In support of its coal generating facilities, the Association has direct ownership and investment
in coal mines.
The Association, including its subsidiaries, employs 1,540 people, of which 362 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, its wholly-owned
and majority-owned subsidiaries, and certain variable interest entities for which the Association or its subsidiaries are the
primary beneficiaries as described in Note 11 - Variable Interest Entities. The consolidated financial statements also include the
Association’s undivided interests in jointly owned facilities.
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.
JOINTLY OWNED FACILITIES: The Association owns undivided interests in three jointly owned generation facilities that are
operated by the operating agent of each facility under joint facility ownership agreements with other utilities as tenants in
common. These projects include the Yampa Project (operated by the Association), the Missouri Basin Power Project (“MBPP”)
(operated by Basin Electric Power Cooperative (“BEPC”)) and the San Juan Project (operated by Public Service Company of
New Mexico). Each participant in these agreements receives a portion of the total output of the generation facilities, which
approximates its percentage ownership. Each participant provides its own financing for its share of each facility and accounts
for its share of the cost of each facility. The operating agent for each of these projects allocates the fuel and operating
expenses to each participant based upon its share of the use of the facility. Therefore, the Association’s share of the plant asset
cost, interest, depreciation and operating expenses is included in the Association’s consolidated financial statements.
25
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
VARIABLE INTEREST ENTITIES: The Association evaluates its arrangements and relationships with other entities, including
its investments in other associations and investments in coal mines, in accordance with the accounting standard related to
consolidation of variable interest entities. This guidance requires the Association to identify variable interests (contractual,
ownership or other financial interests) in other entities and whether any of those entities in which the Association has a
variable interest in, meets the criteria of a variable interest entity. An entity is considered to be a variable interest entity when
its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated
financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. In making
this assessment, the Association considers the potential that its arrangements and relationships with other entities provide
subordinated financial support, the potential for the Association to absorb losses or rights to residual returns of an entity, the
ability to directly or indirectly make decisions about the entity’s activities and other factors. If an entity that the Association has
a variable interest in meets the criteria of a variable interest entity, the Association must determine whether it is the primary
beneficiary of that entity. The primary beneficiary is the entity that has the power to direct the activities of the variable interest
entity that most significantly impact the variable interest entity’s economic performance, and the obligation to absorb losses
or the right to receive benefits from the variable interest entity that could be potentially significant to the variable interest
entity. If the Association is determined to be the primary beneficiary of (has a controlling financial interest in) a variable interest
entity, then the Association would be required to consolidate that entity. In certain situations, it may be determined that
power is shared among multiple unrelated parties such that no one party has the power to direct the activities of a variable
interest entity that most significantly impact the variable interest entity’s economic performance (decisions about those
activities require the consent of each of the parties sharing power). In accordance with the accounting guidance prescribed by
consolidation of variable interest entities, if the determination is made that power is shared among multiple unrelated parties,
then no party is the primary beneficiary. See Note 11 - Variable Interest Entities.
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.
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 2014, 2013 and 2012 and is
included in depreciation and amortization.
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.
In 2009, the Association acquired a controlling interest in the Springerville Unit 3 Partnership LP (“Springerville Partnership”),
26
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
which is the 100 percent owner of Springerville Unit 3 Holding LLC (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. 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 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 in 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 2014, 2013 and 2012 and is included in depreciation and amortization.
In December 2011, the Association recognized goodwill in the amount of $71.9 million related to the acquisition of Thermo
Cogeneration Partnership, LP (“TCP”) and in the amount of $45.5 million related to the acquisition of Colowyo Coal Company
LP (“Colowyo Coal”). 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, the Association is recovering the goodwill costs pursuant to the accounting requirements related to
regulatory accounting. Under this approach, 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 is being amortized over the 25-year remaining life of the
J.M. Shafer Generating Station since this was the primary asset acquired in the acquisition. This results in annual amortization
expense of $2.8 million per year that is included in depreciation and amortization expense. The goodwill of $45.5 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 $1.0 million per year that is included
in depreciation and amortization expense.
In conjunction with the prepayment of long-term debt during 2014, the Association paid transaction costs of $184.1 million
primarily consisting of $165.8 million of make-whole premiums paid to certain lenders. These debt prepayment transaction
costs were approved by the Board of Directors to be recorded as regulatory assets and are being amortized into interest
expense over the 21.4-year average life of the new debt issued.
The Association has deferred the recognition of revenues in several years. 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 after December 31, 2012. During 2008, the Association deferred the recognition of $10 million of non-member
electric sales revenue earned during 2008. This deferred revenue will be refunded to members through reduced rates when
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. $20 million of this deferred revenue
was recognized in non-member electric sales revenue in 2014. The remaining $35 million of deferred revenue will be refunded
to members through reduced rates when recognized in non-member electric sales revenue in future years, but not beyond 2017.
The regulatory asset related to deferred income tax expense is discussed further in Note 2 - Income Taxes.
27
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Regulatory assets and liabilities are as follows (thousands):
2014 2013
Regulatory assets
Deferred income tax expense
Deferred prepaid lease expense - Craig 3 Lease
Deferred prepaid lease expense - Springerville 3 Lease
Goodwill – J.M. Shafer
Goodwill – Colowyo Coal
Deferred debt prepayment transaction costs
$17,230
$11,859
22,656
29,129
95,168
97,459
63,390
66,238
43,526
44,172
184,073
—
426,043
248,857
Regulatory liabilities
Deferred revenues
45,000
65,000
Net regulatory asset
$381,043
$183,857
SEGMENT REPORTING: The Association is organized for the purpose of supplying wholesale power to its member distribution
systems and does so through the utilization of a portfolio of resources, including generating facilities, long-term purchase
contracts and forward, short-term and spot market energy purchases. In support of its coal generating resources, the
Association has direct ownership and investments in coal mines. Resources are allocated and performance is assessed as one
operating segment. Therefore, the Association has one reportable segment for financial reporting purposes.
BUSINESS COMBINATIONS: The Association accounts for business acquisitions by applying the accounting standard related
to business combinations. 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.
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 4.7, 4.8 and
5.4 percent were used for 2014, 2013 and 2012, respectively. The amount of interest capitalized during construction was $15.0,
$13.0 and $15.2 million during 2014, 2013 and 2012, 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.
COAL RESERVES AND DEPLETION: Coal reserves are recorded at cost. Depletion of coal reserves is computed using the
units-of-production method utilizing only proven and probable reserves.
28
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
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 is the lessor under 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 the Association’s power generating
equipment for a stated period of time. The lease revenues from these arrangements are included in other operating revenue
on the consolidated statements of operations. The Association is the lessee under 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. These are included in lease expense on
the consolidated statements of operations. See Note 8 - Leases.
INVESTMENTS IN OTHER ASSOCIATIONS: Investments in other associations include the Association’s investment in
the patronage capital of other cooperatives and these investments are accounted for using the cost method. Under this
method, the Association’s investment in a cooperative increases when a cooperative allocates patronage capital credits to
the Association and it decreases when the Association receives a cash retirement of the allocated capital credits from the
cooperative. A cooperative allocates its patronage capital credits to the Association based upon the Association’s patronage
(amount of business done) with the cooperative.
Investments in other associations are as follows (thousands):
2014 2013
Basin Electric Power Cooperative
National Rural Utilities Cooperative Finance Corporation
CoBank, ACB
Western Fuels Association
Other
$80,250
$76,139
26,695
41,586
5,518
4,937
2,338
2,478
3,175
3,087
Investments in other associations
$117,976
$128,227
INVESTMENTS IN AND ADVANCES TO COAL MINES: The Association has direct ownership and investments in coal mines to
support its coal generating resources. 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. The Association’s investment in Trapper Mining is recorded using the cost method as described in Note 2 Investments In Other Associations. In addition, the Association has ownership in Western Fuels Association (“WFA”), which
is the owner of Western Fuels-Wyoming (“WFW”), the owner and operator of the Dry Fork Mine near Gillette, Wyoming. The
Association, through its ownership in WFA, advances funds to the Dry Fork Mine.
Investments in and advances to coal mines are as follows (thousands):
2014
2013
Investment in Trapper Mine
Advances to Dry Fork Mine
$13,650
$13,235
1,366
272
Investments in and advances to coal mines
$15,016
$13,507
CASH AND CASH EQUIVALENTS: The Association considers highly liquid investments with an original maturity of three months
or less to be cash equivalents.
29
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
The Association has investments in U.S. Treasury Notes pledged as collateral in connection with the in-substance defeasance
for the principal outstanding and future interest payments on the Coal Contract Receivable Collateralized Bonds (“Colowyo
Bonds”). The balances in these investments are described as investments in securities pledged as collateral in the table below.
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.
The United States Department of Agriculture’s Rural Utilities Service (“RUS”) administers a cushion of credit program under
which RUS borrowers may make voluntary irrevocable deposits into a special account. The amounts in the cushion of credit
(deposits and earned interest) can only be used to make scheduled payments on loans made or guaranteed by the RUS. The
Association participated in this program until the RUS debt was paid off in November 2014. At December 31, 2014 and 2013,
the balance in the cushion of credit program was $0 and $137.7 million, respectively.
The Association received $29.4 million in 2009 from the BNSF Railway Company (“BNSF”) as a reduction of prior coal delivery
shipping charges as the result of the decision of the Surface Transportation Board (“STB”). However, BNSF has appealed
the decision and the funds 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 the $29.4 million
in 2009 in the consolidated statements of operations and still has not as of December 31, 2014. The funds were designated by
the Association’s Board of Directors to be held as restricted cash.
Restricted cash and investments are as follows (thousands):
2014
2013
Funds restricted for payment of debt – Platte County bonds
Investments in securities pledged as collateral
Funds restricted by contract
RUS cushion of credit
$—
$48,000
9,192
9,242
592
390
—
68,099
Restricted cash and investments - current
9,784
125,731
BNSF settlement
Funds restricted by contract
Investments in securities pledged as collateral
RUS cushion of credit
29,381
29,381
1,000
1,000
8,995
18,114
—
69,629
Restricted cash and investments - noncurrent
39,376
118,124
Total restricted cash and investments
$49,160
$243,855
FAIR VALUE: Accounting guidance defines fair value as the price that would be received to sell an asset or paid to transfer a
liability between market participants in the principal or in the most advantageous market when no principal market exists. The
fair value measurements accounting guidance emphasizes that fair value is a market-based measurement, not an entity-specific
measurement. Therefore, a fair value measurement should be determined based on the assumptions that market participants
would use in pricing the asset or liability (market participants are assumed to be independent, knowledgeable, able and willing
to transact an exchange and not under duress). In considering market participant assumptions in fair value measurements,
a three-tier fair value hierarchy for measuring fair value was established which prioritizes the inputs used in measuring fair
value. Level 1 inputs utilize observable market data in active markets for identical assets or liabilities. Level 2 inputs consist of
30
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
observable market data, other than that included in Level 1, that is either directly or indirectly observable. Level 3 inputs consist
of unobservable market data which are typically based on an entity’s own assumptions of what a market participant would use
in pricing an asset or liability as there is little, if any, related market activity. In instances where the determination of the fair
value measurement is based on inputs from different levels of the fair value hierarchy, the level in the fair value hierarchy within
which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement
in its entirety. The assessment of the significance of a particular input to the fair value measurement in its entirety requires
judgment and considers factors specific to the asset or liability.
MARKETABLE SECURITIES: 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.
These securities are classified as available-for-sale securities. At December 31, 2014, the cost and estimated fair value of the
investments based upon their active market value (Level 1 inputs) were $1.1 and $1.4 million, respectively, with a net unrealized
gain balance of $254,000. At December 31, 2013, the cost and estimated fair value of the investments were $1.2 and $1.5 million,
respectively, with a net unrealized gain balance of $254,000. The estimated fair value of the investments is included in other
noncurrent assets on the consolidated statements of financial position. The unrealized gains at December 31, 2014 and 2013 are
reported as a component of accumulated other comprehensive income as of those dates. Changes in the net unrealized gains
or losses are reported as a component of comprehensive income.
The Association holds U.S. Treasury Notes to maturity in connection with the December 2011 defeasance of the Colowyo Bonds
and these are included in restricted cash and investments on the statements of financial position. Since they will be held to
maturity, the notes are carried at amortized cost. As of December 31, 2014, the defeasance investment of $18.2 million consisted
of a principal amount of $16.4 million, an unamortized premium of $371,000 and cash of $1.4 million. As of December 31,
2013, the defeasance investment of $27.4 million consisted of a principal amount of $25.1 million, an unamortized premium of
$900,000 and cash of $1.4 million.
INVENTORIES: Coal inventories at the Association’s owned generating stations are stated at LIFO (last-in, first-out) cost and
were $22.2 and $25.6 million at December 31, 2014 and 2013, respectively. The remaining coal inventories, other fuel, and
materials and supplies inventories are stated at average cost. The Association realized lower coal fuel expense in 2014 and
2013 of $596,000 and $5.1 million, respectively, as a result of a LIFO inventory liquidation.
OTHER DEFERRED CHARGES: The Association makes expenditures for preliminary surveys, plans and investigations for
the purpose of determining the feasibility of contemplated generation and transmission projects. If construction results, the
preliminary survey and investigation expenditures will be reclassified to electric plant - construction work in progress. If the
work is abandoned, the related preliminary survey and investigation expenditures will be charged to the appropriate operating
expense account and, if large, it is expected that the expense would be deferred as a regulatory asset to be recovered in rates.
As of December 31, 2014, preliminary survey and investigation was primarily comprised of expenditures for the Holcomb Station
Project of $82.0 million (see Note 12 - Commitments and Contingencies - Legal) and the Eastern Plains Transmission Project of
$27.3 million.
The Association makes advance payment to the operating agents of jointly owned facilities. See Note 3 - Property, Plant and
Equipment - Jointly Owned Facilities.
The Association accounts for debt issuance costs as deferred debt expense. Deferred debt expense is amortized to expense
using an effective interest method over the life of the respective debt issuance. In October 2014, Tri-State entered into an
agreement with the 2011 Credit Agreement lenders to increase the commitment amount from $500 million to $750 million and
grant a one-year extension of the maturity date to July 26, 2019. As a result of this transaction, the Association recorded an
additional $1.3 million of debt issuance costs in deferred charges that are being amortized to interest expense using an effective
interest method over the life of the modified 2011 Credit Agreement.
31
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
During 2014, the Association refinanced a significant portion of its long-term debt (see Note 5 - Long-Term Debt). Debt
issuance costs of $13.0 million were incurred as a result of this refinancing. These debt issuance costs are included in other
deferred charges and are being amortized to expense using an effective interest method over the weighted average life
of the respective debt issuances.
The following other deferred charges are reflected on the Association’s consolidated statements of financial position
(thousands):
2014
2013
Preliminary survey and investigation
Advances to operating agents of jointly owned facilities
Debt issuance costs
Other
$131,693 $126,572
20,567
12,303
22,254
8,923
3,940
4,041
Total other deferred charges
$178,454
$151,839
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, 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.
Aggregate carrying amounts of asset retirement obligations are as follows (thousands):
2014
2013
Asset retirement obligation at beginning of year
Liabilities incurred
Liabilities settled
Accretion expense
Change in cash flow estimate
$52,585
$44,488
1,366
4,623
(5,729)
(195)
2,250
2,675
3,282
994
Asset retirement obligation at end of year
$53,754
$52,585
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.
32
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
OTHER DEFERRED CREDITS AND OTHER LIABILITIES: The Association received $29.4 million in 2009 from the BNSF as
a reduction of prior coal delivery shipping charges as the result of the decision of the STB. However, BNSF has appealed the
decision. Due to uncertainties regarding the ultimate outcome of this matter, the Association did not recognize the benefit of
the receipt of the $29.4 million in 2009 in the consolidated statements of operations and still has not as of December 31, 2014.
See Note 12 - Commitments and Contingencies - Legal.
The Association has received deposits from various parties and those that may still be required to be returned are a liability
and these are reflected in customer deposits. The Association has received upfront payments from others for the use of optical
fiber and these are reflected in unearned revenue until recognized over the life of the agreement.
The following other deferred credits and other liabilities are reflected on the Association’s consolidated statements of financial
position (thousands):
2014
2013
BNSF rate settlement proceeds not recognized in income
Customer deposits
Unearned revenue
Other deferred credits
$29,381
$29,381
2,464
3,292
4,210
4,546
23,066
23,665
Total other deferred credits and other liabilities
$59,121
$60,884
MEMBERSHIPS: There are 44 $5 memberships outstanding at December 31, 2014 and 2013.
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, should they occur, 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.
ACCOUNTS RECEIVABLE – MEMBERS AND OTHER: Receivables are primarily related to electric sales to members and electric
sales and other transactions with electric utilities. Uncollectible amounts, if any, are identified on a specific basis and charged
to expense in the period determined to be uncollectible.
OTHER OPERATING REVENUE: Other operating revenue consists primarily of wheeling revenue, lease revenue, coal sales
and revenue from supplying steam and water to a paper manufacturer located adjacent to the Escalante Generating Station.
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. Coal sales revenue results from the sale of a portion of the
coal from the Colowyo Mine per a contract ending in 2017 to other joint owners in the Yampa Project. The associated Colowyo
Mine expenses are included in coal mine operating expense, depreciation and interest expense on the consolidated statements
of operations.
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.
33
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 balance of $1.5 and $2.0 million at
December 31, 2014 and 2013, respectively, is included in accounts payable. The net interchange activity recorded in purchased
power expense was $(452,500), $2.6 million and $(1.3) million in 2014, 2013 and 2012, respectively.
EVALUATION OF SUBSEQUENT EVENTS: The Association evaluated subsequent events through March 3, 2015, which
represents when the consolidated financial statements were available to be issued.
NEW ACCOUNTING PRONOUNCEMENTS: 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 did not 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.
In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU 2014-09, Revenue from Contracts with Customers
(Topic 606). This amendment replaces current revenue guidance, based on risks and rewards, with a transfer of control model.
The core principle under this new model states that revenue should be recognized to depict the transfer of promised goods or
services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for
those goods and services. To achieve the core principle, ASU 2014-09 requires the following steps: (1) identify the contract(s)
with the customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate
the transaction price to the performance obligations in the contract, and (5) recognize revenue when (or as) the entity satisfies
a performance obligation. ASU 2014-09 also requires additional quantitative and qualitative disclosures sufficient enough
to enable users of financial information to understand the nature, amount, timing and uncertainty of revenue and cash flows
arising from contracts with customers. ASU 2014-09 is effective for the fiscal year beginning January 1, 2017 for public entities
and January 1, 2018 for nonpublic entities with early application not permitted. The Association is currently considering the
effects of adopting this amendment.
In November 2014, the FASB issued ASU 2014-17, Business Combinations (Topic 805) : Pushdown Accounting. This ASU
provides an acquired entity with an option to apply pushdown accounting in its separate financial statements for each
change-in-control event. If the entity elects pushdown accounting for an individual change-in-control event, that election is
irrevocable. If pushdown accounting is not applied during the reporting period in which the change-in-control event occurs,
an acquired entity still will have the option to apply pushdown accounting in a subsequent period to the most recent changein-control event. ASU 2014-17 was effective upon issuance. The adoption of this update did not have a material impact on the
Association’s financial position or results of operations.
34
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
RECLASSIFICATIONS: Certain reclassifications have been made to the prior year financial statements to conform to the
2014 presentations.
NOTE 3 - PROPERTY, PLANT AND EQUIPMENT
The Association’s property, plant and equipment consists of electric plant and other plant. Both of these are discussed below
and are included on the consolidated statements of financial position.
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):
Annual Depreciation Rate
2014 2013
Generation plant.44% to 3.16%
$3,379,305 $3,267,742
Transmission plant2.00% to 2.88%
1,161,462
1,095,554
General plant3.00% to 33.33%
392,963
358,755
Other2.80% to 5.60%
259,506
243,444
Electric plant in service (at cost) 5,193,236
4,965,495
Construction work in progress
206,097
231,374
Less allowances for depreciation and amortization
(2,129,173) (2,023,635)
Electric plant $3,270,160 $3,173,234
At December 31, 2014, the Association had $67.4 million of commitments to complete construction projects, of which
approximately $56.3, $8.4 and $2.7 million are expected to be incurred in 2015, 2016 and 2017, respectively.
JOINTLY OWNED FACILITIES: The Association’s share in each jointly owned facility is as follows as of December 31, 2014 (these
electric plant in service, accumulated depreciation and construction work in progress amounts are included in the electric plant
table above) (thousands):
Tri-State
Share
Electric Plant
in Service
Accumulated
Depreciation
Construction Work
in Progress
Yampa Project – Craig Station Units 1 and 2 24.00
%
$345,302 $229,960
$ 8,884
MBPP – Laramie River Station
24.13
%387,907288,731 3,770
San Juan Project – San Juan Unit 3
8.20
%73,27555,880 10,289
Total
$806,484
$574,571
$ 22,943
OTHER PLANT: Other plant consists of mine assets (discussed below) and non-utility assets (which consist of piping and
equipment specifically related to providing steam and water from the Escalante Generating Station to a third party for the use
in the production of paper).
The Association owns 99 percent of Western Fuels-Colorado, a limited liability company organized for the purpose of acquiring
coal reserves and supplying coal to the Association, which is the owner and operator of the New Horizon Mine near Nucla,
Colorado. Western Fuels-Colorado also owns Colowyo Coal Company LP (“Colowyo Coal”), which is the owner and operator of
the Colowyo Mine, a large surface coal mine near Craig, Colorado. The Association also owns a 50 percent undivided ownership
in the land and the rights to mine the property known as Fort Union Mine. The Association’s share of the coal provided from
these mines is primarily used by the Association for generation at its generating facilities. The expenses related to this coal
used by the Association are included in fuel expense on the consolidated statements of operations.
35
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Other plant assets are as follows (thousands):
2014
2013
Colowyo Mine assets
New Horizon Mine assets
Fort Union Mine assets
Accumulated depreciation and depletion
$152,549 $150,847
44,812
43,364
2,007
1,903
(52,580) (33,365)
Net mine assets
146,788
162,749
Non-utility assets
Accumulated depreciation
11,326
11,326
(5,537)
(5,223)
Net non-utility assets
5,789
6,103
Net other plant
$152,577
$168,852
NOTE 4 –INTANGIBLES
INTANGIBLE ASSETS: The December 2011 acquisition of TCP resulted in the Association recording an intangible asset in the
amount of $55.5 million relating to a contractual obligation that TCP has to a third party under a purchase power agreement
(the “PPA”). The $55.5 million intangible asset represents the amount that the PPA contract terms were above market value at
the acquisition date and 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 in each of the years 2014, 2013 and 2012 and will be recognized over each of the next five years and thereafter as
follows (thousands):
2015
$7,324
20167,324
20177,324
20187,324
20193,662
$32,958
INTANGIBLE LIABILITIES: The December 2011 acquisition of Colowyo Coal resulted in the Association recording an intangible
liability of $18.0 million relating to a contractual obligation that Colowyo Coal has to sell coal to the other owner participants in
the Yampa Project (the “Yampa Participants”) through 2017. The $18.0 million intangible liability represents the amount that the
coal sale contract terms were below market at the acquisition date and is being amortized based upon the contracted tonnage
with the Yampa Participants over the remaining life of the coal contract ending December 31, 2017. The intangible liability
balance of $9.4 and $12.7 million as of December 31, 2014 and 2013, 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 operating revenue.
An amortization benefit of $3.2, $2.5 and $2.6 million was recognized in 2014, 2013 and 2012, respectively, and the recognition
of the benefit over the next three years is estimated to be as follows (thousands):
2015
$3,125
20163,125
20173,174
36
$9,424
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
NOTE 5 – 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 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. 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, including a debt service ratio requirement and an equity to capitalization ratio requirement.
Long-term debt consists of the following (thousands):
20142013
Mortgage notes payable
2% RUS, due through 2017
5% RUS, due through 2026
1.95% to 10.81% FFB, 4.19% average for 2014, due through 2047
3.66% to 8.08% CFC, 5.96% average for 2014, due through 2028
2.63% to 6.17% CoBank, ACB, 4.35% average for 2014, due through 2042
First Mortgage Bonds, Series 2014E-1, 3.70% due 2024
First Mortgage Bonds, Series 2014E-2, 4.70% due 2044
First Mortgage Bonds, Series 2010A, 6.00% due 2040
First Mortgage Obligation, Series 2014B, Tranche 1, 3.90%, due through 2033
First Mortgage Obligation, Series 2014B, Tranche 2, 4.30%, due through 2039
First Mortgage Obligation, Series 2014B, Tranche 3, 4.45%, due through 2045
First Mortgage Obligation, Series 2009C, Tranche 1, 6.00%, due through 2019
First Mortgage Obligation, Series 2009C, Tranche 2, 6.31%, due through 2021
Variable rate CFC, as determined by CFC, 2.90% average for 2014,
due through 2026
Variable rate CFC, LIBOR-based term loan, 1.48% average for 2014,
due through 2049
Variable rate CoBank, ACB, LIBOR-based term loan, 1.74% average for 2014,
due through 2044
Variable rate Grantor Trust Obligations, as determined by CFC, 0.48% average
for 2014, due through 2017
Variable rate, 2011 Credit Agreement, LIBOR-based revolving credit,
1.25% average for 2014, due through 2019
$—
$ 165
—
4,988
—
1,316,042
92,977
114,924
287,798
228,835
249,897
—
248,688
—
499,322
499,323
180,000
—
20,000
—
550,000
—
135,714
162,857
110,000
110,000
687
728
102,220
—
102,220
—
—
17,205
Pollution control revenue bonds
Platte County, WY Daily Adjustable Rate Series 1984, 0.05% average
for 2014, due 2014
City of Gallup, NM, 5.00%, Series 2005, due through 2017
Moffat County, CO Variable Rate Demand Series 2009, 0.06% average
for 2014, due 2036
50,000
130,000
—
48,000
16,155
21,160
46,800
46,800
Springerville certificates
Series A, 6.04%, due through 2018
Series B, 7.14%, due through 2033
126,635
160,774
421,429
422,566
Colowyo Coal
Colowyo Bonds, 10.19%, due through 2016
Mine Equipment Loans, 7.75%, due through 2014
17,224
25,895
—
1,883
Other
2,536
2,583
Total debt
$3,260,302
Less current maturities
Long-term debt
$3,165,960
$3,314,728
(94,342)
(236,588)
$3,078,140
37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In 2014, the Association refinanced a significant portion of its outstanding long-term debt through a series of various debt
issuances. On September 30, 2014, the Association prepaid all amounts due directly to the Rural Utilities Service in the
aggregate amount of $4.3 million. On October 30, 2014, the Association issued the Series 2014 E-1 and Series 2014 E-2 first
mortgage obligations in an aggregate amount of $500 million. The Series 2014 E-1 and Series 2014 E-2 were issued with
Securities and Exchange Commission registration rights. On October 31, 2014, the Association issued the Series 2014B first
mortgage obligations through a private placement of secured notes in three separate tranches totaling $750 million. Also,
on October 31, 2014, the Association issued fixed rate and variable rate notes to CoBank, ACB (“CoBank”) in the amounts
of $68.3 million and $102.2 million, respectively, and fixed rate and variable rate notes to National Rural Utilities Cooperative
Finance Corporation (“CFC”) in the amounts of $68.3 million and $102.2 million, respectively. Proceeds from these issuances
totaled $1.59 billion. On November 5, 2014, the Association used the proceeds to prepay all outstanding long-term debt due
to the Federal Financing Bank (“FFB”) in an aggregate principal amount of $1.26 billion, certain amounts due to CFC totaling
$68.9 million and amounts due under grantor trust certificates totaling $12.9 million. Along with the prepayment of the
FFB debt, the Association also terminated any outstanding commitments from the FFB.
In conjunction with the prepayment of long-term debt during 2014, the Association paid transaction costs of $184.1 million
primarily consisting of $165.8 million of make-whole premiums paid to certain lenders. These debt prepayment transaction
costs were approved by the Board of Directors to be recorded as regulatory assets.
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. (“Bank of America”). In December 2014,
the letter of credit from Bank of America was extended for an additional 364 days to mature in January 2016.
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
8 - 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. Both lines of credit were
terminated in October 2014.
In July 2011, the Association entered into an agreement (the “2011 Credit Agreement”) with Bank of America as administrative
agent and 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 five 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. In October 2014, the 2011 Credit Agreement was further
amended to increase the total commitment to $750 million and to extend the term for one year to expire in July 2019.
Annual maturities of total debt at December 31, 2014 are as follows (thousands):
2015
$94,342
201692,882
2017109,618
201880,146
2019149,295
Thereafter2,734,019
38
$3,260,302
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
NOTE 6 – FAIR VALUE OF LONG-TERM DEBT
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). The carrying amounts and fair values of the Association’s
long-term debt are as follows (thousands):
20142013
CarryingEstimated
Amount
Fair Value
CarryingEstimated
Amount
Fair Value
RUS
FFB
CFC
First Mortgage Bonds,
Series 2014E-1 and E-2
First Mortgage Bonds, Series 2010A
First Mortgage Obligations,
Series 2014B
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
$
— $
—
$
5,153 $
5,876
—
— 1,316,053 1,382,915
195,884 258,180 115,652 124,556
$ 3,260,302 $3,716,513
498,585 524,293
499,322 632,365
—
499,323
—
567,630
750,000 784,126
—
—
245,714 277,061
62,955 63,197
50,000 49,323
—
—
390,018 398,839
548,064 709,278
17,224 17,127
—
—
2,536
2,724
272,857
115,960
130,000
17,205
228,835
583,340
25,895
1,883
2,572
314,902
116,377
128,016
17,128
224,580
746,766
26,389
1,908
2,976
$3,314,728 $ 3,660,019
NOTE 7 – INCOME TAXES
The Association had no income tax expense or benefit in 2014, 2013 and 2012.
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.
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.
39
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Components of the Association’s net deferred tax liability are as follows (thousands):
2014 2013
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
$38,218
$40,225
131,935
58,333
3,834
3,834
830
1,377
16,933
24,460
3,547
4,761
46,026
46,867
241,323
179,857
Deferred tax liabilities
Basis differences – property, plant and equipment
Capital credits from other associations
Deferred debt prepayment transaction costs
152,497
158,789
36,790
32,927
69,266
—
258,553
191,716
$ (17,230)
Net deferred tax liability
$ (11,859)
The $5.3 million increase in the net deferred tax liability from $11.9 million at December 31, 2013 to $17.2 million at December
31, 2014 is not recognized as a tax expense in 2014 due to the Association’s regulatory accounting treatment of deferred taxes.
Instead, the tax expense is deferred and reflected as an increase in the regulatory asset established for deferred income tax
expense. The accounting for regulatory assets is discussed further in Note 2 - Accounting for Rate Regulation. The regulatory
asset account for deferred income tax expense has a balance of $17.2 million and $11.9 million at December 31, 2014 and
2013, respectively.
The reconciliation between the statutory federal income tax rate and the effective tax rate is as follows:
Federal income tax expense at statutory rate State income tax expense, net of federal benefit Patronage exclusion Asset retirement obligations Postretirement medical actuarial gains and losses Various book tax differences Regulatory treatment of deferred taxes Effective tax rate 2014
35.00% 2.63 (37.63) 1.40 2.44 4.52 (8.36)
0.00%
2013
35.00%
2.63
(37.63)
(6.74)
0.18
8.93
(2.37)
0.00%
2012
35.00%
2.63
(37.63)
(7.38)
(2.45)
8.27
1.56
0.00%
The Association had a taxable loss of $197.2 million for 2014. At December 31, 2014, the Association has a federal net operating
loss carryforward of $350.6 million which, if not utilized, will expire between 2030 and 2034. The future reversal of existing
temporary differences will more-likely-than-not enable the realization of the net operating loss carryforward. The Association
has $3.8 million of alternative minimum tax credit carryforwards at December 31, 2014 to offset future regular taxes payable
and the credit carryforwards have no expiration date.
The authoritative guidance for income taxes addresses the determination of whether tax benefits claimed or expected to be
claimed on a tax return should be recorded in the financial statements. The Association may recognize the tax benefit from
an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing
authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a
position should be measured based on the largest benefit that has a greater than 50 percent likelihood of being realized upon
ultimate settlement.
40
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
The Association files a U.S. federal consolidated income tax return and income tax returns in state jurisdictions where required.
The statute of limitations remains open for federal and state returns for the years 2011 forward. The Association does not have
any liabilities recorded for uncertain tax positions.
NOTE 8 – LEASES
LESSOR - GAS TOLLING ARRANGEMENTS: The Association is the lessor under 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. These arrangements include sales contracts to a third party
out of the Association’s J.M. Shafer, Knutson and Limon generating stations. Under the first of these contracts, the third party
directs the use of 122 megawatts of the 272-megawatt net generating capability of the J.M. Shafer Generating Station through
June 30, 2019 under a tolling arrangement whereby the third party provides its own natural gas for generation of electricity.
Under the other contracts, the third party directs the use of both of the two Knutson Generating Station units and one of
the two Limon Generating Station units over the terms of the contracts under tolling arrangements whereby the third party
provides its own natural gas for generation of electricity. The Limon contract was suspended for a four-year period beginning
May 2009 through April 2013 and the Knutson contract was suspended for a three-year period beginning May 2010 through
April 2013 to allow the Association to utilize the output of the turbines. Both turbine contracts resumed with the third party
under the original tolling arrangements on May 1, 2013 and are in effect through April 30, 2016. The Association also had a
similar tolling arrangement with a third party through September 30, 2014 involving one of the four 40-megawatt units at
the Association’s Pyramid Generating Station. The revenues from these operating leases of $30.6, $25.8 and $13.2 million
for 2014, 2013 and 2012, 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 $232 and $108 million, respectively, as of December 31, 2014, and of $229 and $105 million,
respectively, as of December 31, 2013.
The minimum future lease revenues under these gas tolling arrangements at December 31, 2014 are as follows (thousands):
2015
$32,409
201618,389
201711,379
201811,379
20195,690
$79,246
LESSEE - GAS TOLLING ARRANGEMENT: The Association is the lessee under a power purchase arrangement that is required
to be accounted for as an operating lease since the arrangement is in substance a lease because it conveys to the Association
the right to use power generating equipment for a stated period of time. Under this agreement, the Association directs the use
of 72 megawatts at the Brush Generating Station for a 10-year term ending December 31, 2019 and provides its own natural
gas for generation of electricity. The expense for the Brush operating lease of $5.3 million for each of the years 2014, 2013 and
2012 is included in other operating expenses on the consolidated statements of operations. The Association’s operating lease
commitments for this gas tolling arrangement at December 31, 2014 are as follows (thousands):
2015
$5,359
20165,519
20175,678
20185,855
20196,031
$28,442
41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 9 – RELATED PARTIES
BASIN ELECTRIC POWER COOPERATIVE: BEPC is a wholesale power supply cooperative of which the Association is a
member. The Association purchased power from BEPC at a cost of $133, $136 and $138 million in 2014, 2013 and 2012,
respectively. The Association’s investment in BEPC was $80.3 and $76.1 million at December 31, 2014 and 2013, respectively,
and is included in investments in other associations. The Association’s share of BEPC capital credit allocations was $5.0,
$6.3 and $5.5 million in 2014, 2013 and 2012, respectively, and is included in capital credits from cooperatives.
NATIONAL RURAL UTILITIES COOPERATIVE FINANCE CORPORATION: Investments in other associations includes a
$26.7 and $41.6 million investment in CFC as of December 31, 2014 and 2013, respectively. At December 31, 2014 and 2013,
the total outstanding debt owed by the Association to CFC was $196 and $116 million, respectively. The Association’s share of
CFC capital credit allocations was $637,000, $800,000 and $874,000 for 2014, 2013 and 2012, respectively, and is included in
capital credits from cooperatives.
COBANK, ACB: Investments in other associations includes a $5.5 and $4.9 million investment in CoBank as of December 31,
2014 and 2013, respectively. At December 31, 2014 and 2013, the total outstanding debt owed by the Association to CoBank
was $390 and $229 million, respectively. The Association’s share of CoBank capital credit allocations was $2.3 million,
$1.4 million and $794,000 for 2014, 2013 and 2012, respectively, and is included in capital credits from cooperatives.
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 Unit 3 in Arizona. The Association’s share of coal purchases from WFA was
$74.7, $71.7 and $71.7 million in 2014, 2013 and 2012, respectively.
The Association advanced funds to WFA, through MBPP, for mine and equipment purchases and mine development costs. The
fund advance balance of $1.4 million and $272,000 at December 31, 2014 and 2013, respectively, is included in investments in
and advances to coal mines. The Association’s membership interest in WFA totals $2.3 and $2.5 million at December 31, 2014
and 2013, respectively, and is included in investments in other associations. The Association’s share of WFA capital credit
allocations of $(177,000) for 2014, $1.2 million for 2013 and $0 for 2012 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 35, 24 and 25 percent of the coal for the Yampa Project in 2014, 2013 and 2012,
respectively. The Association’s share of coal purchases from Trapper Mining was $30.6, $16.9 and $11.2 million in 2014, 2013 and
2012, respectively. The Association’s membership interest in Trapper Mining of $13.7 and $13.2 million at December 31, 2014 and
2013, respectively, is included in investments in and advances to coal mines. The Association’s share of Trapper Mining capital
credit allocations of $532,000 in each of the years 2014, 2013 and 2012 is included in capital credits from cooperatives.
NOTE 10 – EMPLOYEE BENEFIT PLANS
DEFINED BENEFIT PLAN: Substantially all of the Association’s 1,540 employees participate in the National Rural Electric
Cooperative Association Retirement Security Plan (“RS Plan”) except for the 216 employees of Colowyo Coal. 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.
42
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
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 2014, 2013 and 2012 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 $21.5, $92.6 and $24.9 million in 2014, 2013 and 2012, respectively. Contributions in 2013 were significantly higher
than those in 2014 and 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
was 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. 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 362 bargaining unit employees
that are made in accordance with collective bargaining agreements that will be in effect through April 3, 2016.
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, 2014, and over 80 percent funded at
January 1, 2013, 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 362 bargaining unit employees. For all of the eligible non-bargaining unit
employees, other than the 216 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, $2.9 and
$3.0 million in 2014, 2013 and 2012, 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 postretirement 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, 2014, are contributory (with retiree premium contributions equivalent to employee
premiums, adjusted annually) and contain other cost-sharing features such as deductibles.
43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The postretirement medical benefit and postemployment medical benefit obligations are determined by an independent
actuary and are included in accumulated postretirement benefit and postemployment obligations on the consolidated
statements of financial position as follows (thousands):
2014 2013
Postretirement medical benefit obligation at beginning of year
Service cost
Interest cost
Benefit payments
Actuarial loss
$2,957
$2,888
582
134
256
136
(276)
(201)
4,194
—
Postretirement medical benefit obligation at end of year
$7,713
Postemployment medical benefit obligation at end of year
418
291
Total postretirement and postemployment medical obligations
at end of year
$8,131
$2,957
$3,248
In accordance with the accounting standard related to postretirement benefits other than pensions, actuarial gains and losses
are not recognized in income but are instead recorded in accumulated other comprehensive income on the consolidated
statements of financial position. If the unrecognized amount is in excess of 10 percent of the projected benefit obligation,
amounts are reclassified out of accumulated other comprehensive income and included in net income as the excess amount
is amortized over the average remaining service lives of the active plan participants. Unrecognized actuarial gains and losses
have been determined per actuarial studies for the postretirement medical benefit obligation.
The net unrecognized actuarial gains and losses related to the postretirement medical benefit obligation are included in
accumulated other comprehensive income as follows (thousands):
2014 2013
Actuarial gain included in accumulated other comprehensive
income at beginning of year
Reclassification adjustment included in income
Actuarial loss per actuarial study
$3,081
$3,439
31
(358)
(4,194)—
Actuarial gain (loss) included in accumulated other
comprehensive income at end of year
$ (1,082)
$3,081
The assumptions used in the 2014 actuarial study performed for the Association’s postretirement medical benefit obligation
were as follows:
Weighted-average discount rate
3.65%
Initial health care cost trend (2014)
8.00%
Ultimate health care cost trend
4.50%
Year that the rate reached the ultimate health care cost trend rate 2023
Expected return on plan assets (unfunded)N/A
Average remaining service lives of active plan participants (years) 11.79
Changes in the assumed health care cost trend rates would impact the accumulated postretirement medical benefit obligation
and the net periodic postretirement medical benefit expense as follows (thousands):
1% Increase
Accumulated postretirement medical benefit obligation
Net periodic postretirement medical benefit expense
44
$ 685
$ 123
1% Decrease
$
$
(600)
(104)
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
The following are the expected future benefits to be paid related to the postretirement medical benefit obligation (thousands):
2015
$355
2016414
2017481
2018519
2019 and thereafter3,729
$5,498
NOTE 11 – VARIABLE INTEREST ENTITIES
The following is a description of the Association’s financial interests in variable interest entities that the Association considers
significant. This includes an entity for which the Association is determined to be the primary beneficiary and therefore
consolidates and also entities for which the Association is not the primary beneficiary and therefore does not consolidate.
Consolidated Variable Interest Entity:
Springerville Partnership: The Association owns a 51 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 of the Springerville Generating
Station Unit 3. The Association, as general partner, has the full exclusive and complete right, power and discretion to operate,
manage and control the affairs of the Springerville Partnership and take certain actions necessary to maintain the Springerville
Partnership in good standing without the consent of the limited partners. Additionally, the Owner Lessor has historically not
demonstrated an ability to finance its activities without additional financial support. The financial support is provided by the
Association’s remittance of lease payments in order to permit the Owner Lessor, the holder of the Springerville Generating
Station Unit 3 assets, to pay the debt obligations and equity returns of the Springerville Partnership. The Association has
the primary risk (expense) exposure in operating the Springerville Generating Station Unit 3 assets and is responsible for
100 percent of the operation, maintenance and capital expenditures of Springerville Generating Station Unit 3 and the
decisions related to those expenditures including budgeting, financing and dispatch of power. Based on all these facts,
it was determined that the Association was the primary beneficiary of the Owner Lessor. Therefore, the Springerville
Partnership and Owner Lessor have been consolidated by the Association.
The Association’s consolidated statements of financial position include the Springerville Partnership’s net electric plant of
$874.4 and $895.4 million at December 31, 2014 and 2013, respectively, the long-term debt of $548.1 and $583.3 million at
December 31, 2014 and 2013, respectively, and the 49 percent noncontrolling equity interest in the Springerville Partnership
of $109.3 and $110.7 million at December 31, 2014 and 2013, respectively.
The Association’s consolidated statements of operations include the Springerville Partnership’s depreciation and amortization
expense of $21.0 million for both 2014 and 2013 and interest expense of $34.1 and $35.9 million for 2014 and 2013, respectively.
The net losses attributable to the 49 percent noncontrolling equity interest in the Springerville Partnership are reflected on
the Association’s consolidated statements of operations. The revenue associated with the Springerville Partnership lease has
been eliminated in consolidation. Income, losses and cash flows of the Springerville Partnership are allocated to the general and
limited partners based on their equity ownership percentages.
Unconsolidated Variable Interest Entities:
Western Fuels Association: WFA is a not-for-profit membership corporation organized for the purpose of acquiring and
supplying fuel resources to its members, which includes the Association. WFA supplies fuel to MBPP for the use of the Laramie
River Station through its ownership in Western Fuels-Wyoming. 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 Unit 3 in Arizona.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The pricing structure of the coal supply agreements with WFA is designed to recover the mine operating costs of the mine
supplying the coal and therefore the coal sales agreements provide the financial support for the mine operations. There isn’t
sufficient equity at risk for WFA to finance its activities without additional financial support. Therefore, WFA is considered a
variable interest entity in which the Association has a variable interest. The power to direct the activities that most significantly
impact WFA’s economic performance (acquiring and supplying fuel resources) is held by the members who are represented
on the WFA board of directors whose actions require joint approval. Therefore, since there is shared power over the significant
activities of WFA, the Association is not the primary beneficiary of WFA and the entity is not consolidated. The Association’s
investment in WFA, accounted for using the cost method, was $2.3 million at December 31, 2014 and is included in investments
in other associations (see Note 2 - Investments in Other Associations and Note 9 - Western Fuels Association).
Western Fuels - Wyoming: WFW, the owner and operator of the Dry Fork Mine in Gillette, WY, was organized for the purpose
of acquiring and supplying coal, through long-term coal supply agreements, to be used in the production of electric energy
at the Laramie River Generating Station (owned by the participants of MBPP) and at the Dry Fork Station (owned by BEPC).
WFA owns 100 percent of the class AA shares and 75 percent of the class BB shares of WFW, while the participants of MBPP
own the remaining 25 percent of class BB shares of WFW (of which the Association has a 24.1 percent undivided interest).
The pricing structure of the coal supply agreements is designed to recover the costs of production of the Dry Fork Mine and
therefore the coal supply agreements provide the financial support for the operation of the Dry Fork Mine. There isn’t sufficient
equity at risk at WFW for it to finance its activities without additional financial support. Therefore, WFW is considered a
variable interest entity in which the Association has a variable interest. The power to direct the activities that most significantly
impact WFW’s economic performance (which includes operations, maintenance and reclamation activities) is shared with
the equity interest holders since each member has representation on the WFW board of directors whose actions require joint
approval. Therefore, the Association is not the primary beneficiary of WFW and the entity is not consolidated.
Trapper Mining, Inc.: Trapper Mining is a cooperative organized for the purpose of mining, selling and delivering coal from
the Trapper Mine to the Craig Generating Station Units 1 and 2 through long-term coal supply agreements. Trapper Mining is
jointly owned by the participants of the Yampa Project (the owners of the Craig Generating Station Units 1 and 2), of which
the Association has a 26.57 percent cooperative member interest in Trapper Mining. The pricing structure of the coal supply
agreements is designed to recover the costs of production of the Trapper Mine and therefore the coal supply agreements
provide the financial support for the operation of the Trapper Mine. There isn’t sufficient equity at risk for Trapper Mining to
finance its activities without the additional financial support. Therefore, Trapper Mining is considered a variable interest entity in
which the Association has a variable interest. The power to direct the activities that most significantly impact Trapper Mining’s
economic performance (which includes operations, maintenance and reclamation activities) is shared with the cooperative
members since each member has representation on the Trapper Mining board of directors whose actions require joint approval.
Therefore, the Association is not the primary beneficiary of Trapper Mining and the entity is not consolidated. The Association
records its investment in Trapper Mining using the cost method. The Association’s membership interest in Trapper Mining was
$13.7 million at December 31, 2014 (see Note 2 - Investments In and Advances To Coal Mines and Note 9 - Trapper Mining).
NOTE 12 – COMMITMENTS AND CONTINGENCIES
SALES: The Association has delivery obligations under resource-contingent power sales contracts with Public Service Company
of Colorado totaling 125 megawatts in the summer season and 175 megawatts in the winter season. These contracts expire in
2016 and 2017. The Association also 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 and
(3) a resource-contingent firm power sales contract with PacifiCorp committing 25 megawatts through 2020.
COAL PURCHASE REQUIREMENTS: The Association is committed to purchase coal for its generating plants under long-term
contracts that expire between 2017 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.
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TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
The projection of contractually committed purchases is based upon estimated future prices. At December 31, 2014, the annual
minimum coal purchases under these contracts are as follows (thousands):
2015
$101,266
2016103,760
2017106,790
2018103,390
2019104,686
Thereafter145,212
$665,104
ELECTRIC POWER PURCHASE AGREEMENTS: The Association’s principal long-term electric power purchase contracts are
with Western Area Power Administration (“WAPA”) and Basin. WAPA, one of four power marketing administrations of the
U.S. Department of Energy, markets and supplies cost-based hydroelectric power and related services primarily to cooperatives
and municipal electric systems located in 15 states in the central and western United States. WAPA markets and transmits the
power to the Association under three contracts, one relating to WAPA’s Loveland Area Project (terminates September 30,
2024), and two contracts relating to WAPA’s Salt Lake City Area Integrated Projects (terminate September 30, 2024). The
Association is currently working to enter into a new contract relating to the Loveland Area Project which will run through
September 2054. The Association also expects to enter into two new contracts related to Salt Lake City Area Integrated
Projects which will extend the term of those existing contracts.
The Association’s purchases of hydroelectric-based electric power from WAPA are made at cost-based rates under longstanding federal law under which WAPA sells power to cooperatives and municipal electric systems and certain other
preference customers. The Association utilizes a portion of its electric purchases from Basin to supply power to the
Association’s Nebraska members, which are primarily located east of the electrical grid separation and are generally
isolated from our generating facilities that are located west of the separation. The Association has a contract with Basin
for a term ending December 31, 2050, to supply the electrical requirements of its Nebraska members in excess of power
supplied by WAPA.
Costs under the above electric power purchase agreements for the years ended December 31 were as follows (thousands):
2014
WAPA
$91,639
Basin 132,649
2013
2012
$91,038 $ 87,122
136,223 137,853
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.
LEGAL: 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. In November 2012, three of the Association’s member
systems located in New Mexico filed protests of the Association’s rates with the NMPRC. 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 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
47
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 subsequently ordered the A-37 rate filing to be consolidated with
the A-38 rate filing described below. On September 10, 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. In August 2014, the
Association and the New Mexico member systems executed a preliminary mediation agreement providing for a temporary
rate rider through no later than December 31, 2015 (unless terminated earlier as provided in the preliminary mediation
agreement) and a suspension of the procedural schedule related to the rate protest to allow the parties time to proceed
with more extensive discussions on a global settlement. The Association filed notice of the temporary rate rider with the
NMPRC and it became effective on October 2, 2014. The temporary rate rider is applied in conjunction with the 2012 wholesale
rate to recover additional revenue from the New Mexico member systems in an annualized amount of $7 million per year, which
was prorated beginning October 2 for 2014. In 2014 and 2013, the overall impact of the New Mexico member systems paying
a lower rate was approximately $16.4 million and $15.6 million, respectively. As part of the global settlement, the parties seek
to establish a permanent wholesale rate going forward, address the issue of our rate regulation in New Mexico, evaluate the
payment of capital credits, evaluate the buyout methodology for member systems and perform a cost of service study. The
Association cannot predict the outcome of this matter or if a global settlement will be reached, although the Association does
not believe this proceeding is likely to have a material adverse effect on the Association’s financial condition, future results of
operations or cash flows.
On March 4, 2013, three of the Association’s Colorado member systems and several of their large industrial customers
filed a complaint at the Colorado Public Utilities Commission (“COPUC”) alleging that the A-37 rate design was unjust and
unreasonable. On April 4, 2013, the Association filed a motion to dismiss the complaint arguing lack of jurisdiction by the
COPUC over the Association’s wholesale rates. The COPUC assigned the matter to an Administrative Law Judge (“ALJ”). The
ALJ bifurcated the case into deciding first, whether the COPUC had the jurisdiction to hear such a case against the Association,
who has been historically regulated by its membership through its Board of Directors, and secondly to hear the facts in the case
depending on jurisdiction. The ALJ conducted a hearing in July 2013 and ruled on September 11, 2013 denying the Association’s
motion to dismiss. In October 2013, the Association appealed the ALJ’s decision to the full commission and on December 18,
2013, the commission granted in part and denied in part the Association’s motion contesting the ALJ’s decision and remanded
the case to the ALJ to hold a hearing on limited issues. In November 2014, the Association and three Colorado member systems
executed a preliminary agreement providing for a temporary rate rider effective December 1, 2014 and to continue through no
later than December 31, 2015, available to all non-New Mexico member systems and a suspension of the procedural schedule
related to the complaint. The ALJ entered a decision on November 28, 2014 holding this matter in abeyance until December
31, 2015 to give the parties time to work toward a global settlement and permanent rate. The Association cannot predict the
outcome of this matter or if a global settlement will be reached, although the Association does not believe this proceeding is
likely to have a material adverse effect on the Association’s financial condition, future results of operations or cash flows.
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 coal-fired 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
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TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
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 issued an
addendum to the permit on May 30, 2014. The Sierra Club filed an appeal with the Kansas Court of Appeals on June 27, 2014.
On November 3, 2014, the Kansas Supreme Court granted a pending motion to transfer the case from the Court of Appeals
and KDHE subsequently filed the record on appeal. Excluding the cost of land and water rights, the cost of developing the
units incurred by the Association as of December 31, 2014 is $82.0 million, which is included in other deferred charges on the
consolidated statements of financial position. The Association is unable to project the ultimate outcome of this matter or when
the air permit application process may conclude.
In June 2011, a wildfire in New Mexico, known as the Las Conchas Fire, burned for five days in northern New Mexico, primarily on
national forest service land in the Santa Fe National Forest. Six plaintiff groups, comprised of property owners in the area of the
Las Conchas Fire, have filed separate lawsuits against the Association’s member system, Jemez Mountains Electric Cooperative,
Inc. (“JMEC”) in the Thirteenth District Court, Sandoval County in the State of New Mexico. Plaintiffs allege that the fire ignited
when a tree growing outside the right of way fell onto a distribution line owned by JMEC as a result of high winds. On January
7, 2014, the court allowed all parties and related parties to amend their complaints to include the addition of the Association
as a party defendant. The allegations in each case are similar. Plaintiffs allege that the Association owed them independent
duties to inspect and maintain the right of way for JMEC’s distribution line and that the Association is also jointly liable for any
negligence by JMEC under “joint venture” and alter ego theories. On December 29, 2014, a demand letter was received from
the U.S. Department of Justice for costs incurred as a result of the fire, alleging the “joint venture” theory. JMEC settled with
the subrogated insurers, executing and funding the deal on December 30, 2014. On February 7, 2015, the court dismissed the
subrogated insurers’ claims against the Association with prejudice. Settlement demands have been received from two plaintiffs
claiming damages in the amount of approximately $34.4 million and $23.9 million, respectively, focusing mainly on damages
arising from flooding subsequent to the fire. In conjunction with the demands, the two plaintiffs have requested mediation. Trial
is currently set for three weeks commencing May 2, 2015. The Association maintains $100 million in liability insurance coverage
for this matter. Although the Association cannot predict the outcome of these matters at this point in time, the Association
intends to vigorously defend these matters and does not expect them to have a material adverse effect on the Association’s
financial condition, future results of operations or cash flows.
In February 2013, WildEarth Guardians (“WEG”) filed suit against the United States Office of Surface Mining, Reclamation and
Enforcement (“OSM”) in the United States District Court for the District of Colorado, alleging OSM’s failure to involve the public
and address the economic impacts of coal mining throughout the Rocky Mountain West prior to mine plan approval. The suit
alleges unlawful mine plan approval of mines located in Colorado, Montana, New Mexico and Wyoming. The court granted
intervention to several mine owners, including Colowyo Coal and Trapper Mining, of which the Association is a member. The
Colowyo Mine plan in WEG’s suit was approved in 2007. In February 2014, the court agreed to sever the claims and transfer
venue for the mines located outside of Colorado. In August 2014, WEG submitted its opening brief on the part of the case that
remains in Colorado as Civil Action No. 1:13-cv-00518-JLK. OSM’s responsive brief was filed on October 7, 2014, and Trapper
Mining and Colowyo Coal, as interveners, each filed a responsive brief on October 20, 2014. WEG has asked the court to
declare that OSM’s approval of the mine plans violated the National Environmental Policy Act and for the court to vacate the
approvals until OSM demonstrates compliance with the act. Federal respondents and respondent-interveners have requested
oral argument. Because of the early nature of the proceedings, the Association is unable to project the outcome of this matter
although the Association does not believe it is likely to have a material adverse effect on the Association’s financial condition,
future results of operations or cash flows.
49
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On October 19, 2004, WFA and BEPC filed a complaint with the STB alleging that the shipping rates instituted by BNSF for
the transportation of coal to the Laramie River Generating Station were unreasonably high and asked the STB to set reasonable
rates. 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 were 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, 2014. Instead, the $29.4 million was recorded as a liability and is included in
other deferred credits and other liabilities as of December 31, 2014, 2013 and 2012. On May 11, 2010, the Court of Appeals
decided two of the three issues in favor of WFA and BECP. On the third issue, the Court of Appeals remanded the decision
back to the STB directing the STB to explain in greater detail why its methodology for allocating variable costs did not double
count certain revenue. On June 15, 2012, the STB provided the detailed recommendation on its allocation and affirmed its
earlier decision, and BNSF subsequently appealed the STB decision to the Court of Appeals. On January 31, 2014, the Court
of Appeals remanded the case back to the STB noting that the STB, under the previous remand, should have also considered
whether to apply alternative average total cost to the allocation or provided a reasonable explanation for its actions. On
January 28, 2015, BNSF, WFA and BEPC filed a joint petition at the STB asking the STB to hold the remanded case in abeyance.
In this filing, the parties informed the STB that they had reached a preliminary settlement agreement that called for the
dismissal of the case. The parties also informed the STB that the preliminary agreement was contingent upon the parties’
development and execution of a rail transportation contract.
On February 9, 2015, Delta-Montrose Electric Association (“DMEA’’), a member of the Association, filed a petition for
declaratory order with the Federal Energy Regulatory Commission (“FERC”) seeking a declaratory order from FERC finding
that its wholesale power contract with the Association is subject to FERC jurisdiction because the Association has paid off
all RUS debt and is now a FERC jurisdictional public utility; that the wholesale power contract cannot be read to preclude
DMEA from purchasing power from a “qualifying resource” pursuant to the provisions of the Public Utilities Regulatory Policy
Act (“PURPA”) and FERC regulations thereunder; and that DMEA has the right under FERC’s PURPA regulations to negotiate
its purchase power price from a “qualifying resource” and to reduce its purchases from the Association by that amount.
Comments are due related to such petition on March 11, 2015. Because of the early nature of the proceedings, the Association
is unable to project the outcome of this matter although the Association does not believe it is likely to have a material adverse
effect on the Association’s financial condition, future results of operations or cash flows.
50
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION
DESIGN: Watermark (www.watermark.agency)
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.
WY
NE
CO
NM
P.O. BOX 33695, DENVER, CO 80233
WWW.TRISTATE.COOP