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EX-12.1 - EXHIBIT 12.1 RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED STOCK DIVIDENDS - CorEnergy Infrastructure Trust, Inc.corr-2015331x10qexx121.htm
EX-32.1 - EXHIBIT 32.1 SECTION 906 CEO AND CFO CERTIFICATIONS - CorEnergy Infrastructure Trust, Inc.corr-2015331x10qexx321.htm
EX-31.1 - EXHIBIT 31.1 SECTION 302 CEO CERTIFICATION - CorEnergy Infrastructure Trust, Inc.corr-2015331x10qexx311.htm
EX-10.2 - EXHIBIT 10.2(B) MANAGEMENT AGREEMENT - CorEnergy Infrastructure Trust, Inc.corr-2015331x10qexx102b.htm
EXCEL - IDEA: XBRL DOCUMENT - CorEnergy Infrastructure Trust, Inc.Financial_Report.xls
EX-31.2 - EXHIBIT 31.2 SECTION 302 CFO CERTIFICATION - CorEnergy Infrastructure Trust, Inc.corr-2015331x10qexx312.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549 
___________________________________________
FORM 10-Q
 ___________________________________________
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2015
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                     to                    
Commission file number: 001-33292
___________________________________________
CORENERGY INFRASTRUCTURE TRUST, INC.
(Exact name of registrant as specified in its charter)
___________________________________________
Maryland
 
20-3431375
(State or other jurisdiction of incorporation or organization)
 
(IRS Employer Identification No.)
1100 Walnut, Ste. 3350
Kansas City, MO
 
64106
(Address of Principal Executive Offices)
 
(Zip Code)

(816) 875-3705
(Registrant’s telephone number, including area code)

n/a
(Former name, former address and former fiscal year, if changed since last report)
___________________________________________
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).     Yes  x    No  ¨.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
¨
Accelerated filer
x
Non-accelerated filer
¨ (Do not check if a smaller reporting company)
Smaller reporting company
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act)     Yes  ¨    No  x
As of April 30, 2015, the registrant had 46,623,992 common shares outstanding.



CorEnergy Infrastructure Trust, Inc.
FORM 10-Q
FOR THE QUARTER ENDED MARCH 31, 2015
TABLE OF CONTENTS
____________________________________________________________________________________________
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



This report should be read in its entirety. No one section of the report deals with all aspects of the subject matter. It should be read in conjunction with the consolidated financial statements, related notes and with the Management's Discussion & Analysis ("MD&A") included within, as well as provided in the Annual Report on Form 10-K, for the year ended December 31, 2014.

The consolidated unaudited financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information, the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for complete financial statements. In the opinion of Management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three months ended March 31, 2015, are not necessarily indicative of the results that may be expected for the year ended December 31, 2015. For further information, refer to the consolidated financial statements and footnotes thereto included in the CorEnergy Infrastructure Trust, Inc. Annual Report on Form 10-K, for the year ended December 31, 2014.



GLOSSARY OF DEFINED TERMS

Certain of the defined terms used in this report are set forth below:

Administrative Agreement: The Administrative Agreement dated December 1, 2011, as amended effective August 7, 2012, between the Company and Corridor.

Arc Logistics: Arc Logistics Partners LP (NYSE: ARCX)

Arc Terminals: Arc Terminals Holdings LLC, an indirect wholly-owned operating subsidiary of Arc Logistics

ASC: Accounting Standards Codification

BBWS: CorEnergy BBWS, Inc., a wholly-owned subsidiary of CorEnergy

Leeds Path West: Corridor Leads Path West, Inc., a wholly-owned subsidiary of CorEnergy

Code: the Internal Revenue Code of 1986, as amended

CorEnergy: CorEnergy Infrastructure Trust, Inc. (NYSE: CORR)

Corridor Private: Corridor Private Holdings, Inc., an indirect wholly-owned subsidiary of CorEnergy

Corridor: Corridor InfraTrust Management, LLC, the Company's external manager pursuant to the Management Agreement

Corridor MoGas: Corridor MoGas, Inc., a wholly-owned subsidiary of CorEnergy and the holding company of MoGas and UPS

CPI: Consumer Price Index

EIP: the Eastern Interconnect Project

Exchange Act: the Securities Exchange Act of 1934, as amended

FASB: Financial Accounting Standards Board

FERC: Federal Energy Regulatory Commission

Four Wood Corridor: Four Wood Corridor, LLC, a wholly-owned subsidiary of CorEnergy

Four Wood Energy: Four Wood Energy Partners LLC, a wholly-owned subsidiary of Four Wood Capital Partners LLC

GAAP: U.S. generally accepted accounting principles

KeyBank: KeyBank National Association

KeyBank Term Facility: A $70 million secured term credit facility Pinedale LP entered into with KeyBank in December 2012 to finance a portion of our acquisition of the Pinedale LGS, which matures in December 2015 with an option to extend through December 2016.

LDCs: local distribution companies

Lightfoot: collectively, Lightfoot Capital Partners, LP and Lightfoot Capital Partners GP LLC

Liquids Gathering System: owned by Pinedale LP, an approximately 150 miles of pipelines with 107 receipt points and four above-ground central gathering facilities

Management Agreement: the Management Agreement effective July 1, 2013, as amended effective January 1, 2014, between the Company and Corridor




MoGas: MoGas Pipeline LLC, an indirect wholly-owned subsidiary of CorEnergy

MoGas Pipeline System: an approximately 263 mile interstate natural gas pipeline system in and around St. Louis and extending into central Missouri, owned and operated by MoGas

Mowood: Mowood, LLC, an indirect wholly-owned subsidiary of CorEnergy and the holding company of Omega Pipeline Company, LLC

NAREIT: National Association of Real Estate Investment Trusts

NGA: Natural Gas Act of 1938

NGPA: Natural Gas Policy Act of 1978

Omega: Omega Pipeline Company, LLC, a wholly-owned subsidiary of Mowood, LLC

Omega Pipeline: Omega's natural gas distribution system in south central Missouri

Pinedale LGS: the Pinedale Liquids Gathering system, a system of pipelines and central gathering facilities located in the Pinedale Anticline in Wyoming, owned by Pinedale LP and triple-net leased to a wholly-owned subsidiary of Ultra Petroleum

Pinedale Lease Agreement: the December 2012 agreement pursuant to which the Pinedale LGS assets are triple-net leased to a wholly owned subsidiary of Ultra Petroleum

Pinedale LP: Pinedale Corridor, LP

Pinedale GP: the general partner of Pinedale LP

Portland Lease Agreement: the January 2014 agreement pursuant to which the Portland Terminal Facility is triple-net leased to Arc Terminals, a wholly owned subsidiary of Arc Logistics Partners LP

Portland Terminal Facility: a petroleum products terminal located in Portland, Oregon

PNM: Public Service Company of New Mexico, a subsidiary of PNM Resources Inc. (NYSE: PNM)

PNM Lease Agreement: a triple net lease agreement for the Eastern Interconnect Project

Prudential: The Prudential Insurance Company of America

QDI: qualified dividend income

Regions Revolver: the Company’s $90 million revolving line of credit facility with Regions Bank

REIT: real estate investment trust

SEC: Securities and Exchange Commission

SWD: SWD Enterprises, LLC, a wholly-owned subsidiary of Four Wood Energy Partners, LLC

TCA: Tortoise Capital Advisors, L.L.C.

TRS: taxable REIT subsidiary

Ultra Petroleum: Ultra Petroleum Corp. (NYSE: UPL)

Ultra Wyoming: Ultra Wyoming LGS LLC, an indirect wholly-owned subsidiary of Ultra Petroleum

UPS: United Property Systems, LLC, an indirect wholly-owned subsidiary of CorEnergy




VIE: Variable Interest Entity

VantaCore: VantaCore Partners LP



PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CorEnergy Infrastructure Trust, Inc.
CONSOLIDATED BALANCE SHEETS
 
March 31, 2015
 
December 31, 2014
Assets
(Unaudited)
 
 
Leased property, net of accumulated depreciation of $22,048,643 and $19,417,025
$
259,676,456

 
$
260,280,029

Leased property held for sale, net of accumulated depreciation of $6,448,603 and $5,878,933
7,678,246

 
8,247,916

Property and equipment, net of accumulated depreciation of $3,455,219 and $2,623,020
122,004,387

 
122,820,122

Financing notes and related accrued interest receivable, net
20,881,295

 
20,687,962

Other equity securities, at fair value
10,363,438

 
9,572,181

Cash and cash equivalents
26,634,586

 
7,578,164

Accounts and other receivables
8,145,544

 
7,793,515

Intangibles and deferred costs, net of accumulated amortization of $2,665,120 and $2,271,080
4,053,148

 
4,384,975

Prepaid expenses and other assets
722,865

 
732,110

Goodwill
1,718,868

 
1,718,868

Total Assets
$
461,878,833

 
$
443,815,842

Liabilities and Equity
 
 
 
Current maturities of long-term debt
$
3,528,000

 
$
3,528,000

Long-term debt
62,650,000

 
63,532,000

Accounts payable and other accrued liabilities
3,015,434

 
3,935,307

Management fees payable
1,226,155

 
1,164,399

Income Tax Liability
480,637

 

Deferred tax liability
1,147,196

 
1,262,587

Line of credit
565,583

 
32,141,277

Unearned revenue

 
711,230

Total Liabilities
$
72,613,005

 
$
106,274,800

Equity
 
 
 
Series A Cumulative Redeemable Preferred Stock 7.375%, $56,250,000 liquidation preference ($2,500 per share, $0.001 par value), 10,000,000 authorized; 22,500 and 0 issued and outstanding as of March 31, 2015, and December 31, 2014
$
56,250,000

 
$

Capital stock, non-convertible, $0.001 par value; 46,619,681 and 46,605,055 shares issued and outstanding at March 31, 2015, and December 31, 2014 (100,000,000 shares authorized)
46,619

 
46,605

Additional paid-in capital
306,036,447

 
309,950,440

Accumulated retained earnings

 

Accumulated other comprehensive income
177,195

 
453,302

Total CorEnergy Equity
362,510,261

 
310,450,347

Non-controlling Interest
26,755,567

 
27,090,695

Total Equity
389,265,828

 
337,541,042

Total Liabilities and Equity
$
461,878,833

 
$
443,815,842

See accompanying Notes to Consolidated Financial Statements.

6


CorEnergy Infrastructure Trust, Inc.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (UNAUDITED)

 
For The Three Months Ended
 
March 31, 2015
 
March 31, 2014
Revenue
 
 
 
Lease revenue
$
7,336,101

 
$
6,762,408

Sales revenue
2,341,655

 
3,259,530

Financing revenue
660,392

 
25,619

Transportation revenue
3,649,735

 

Total Revenue
13,987,883

 
10,047,557

Expenses
 
 
 
Cost of sales (excluding depreciation expense)
1,248,330

 
2,707,358

Management fees
1,171,974

 
783,868

Acquisition expense and professional fees
1,241,955

 
415,345

Depreciation and amortization expense
4,048,832

 
3,146,978

Transportation, maintenance and general and administrative
991,608

 

Operating expenses
206,360

 
222,741

Other expenses
154,590

 
233,742

Total Expenses
9,063,649

 
7,510,032

Operating Income
$
4,924,234

 
$
2,537,525

Other Income (Expense)
 
 
 
Net distributions and dividend income
$
590,408

 
$
5,056

Net realized and unrealized gain on other equity securities
449,798

 
1,294,182

Interest expense
(1,147,272
)
 
(826,977
)
Total Other Income (Expense)
(107,066
)
 
472,261

Income before income taxes
4,817,168

 
3,009,786

Taxes
 
 
 
Current tax expense
435,756

 
854,075

Deferred tax benefit
(115,391
)
 
(340,562
)
Income tax expense, net
320,365

 
513,513

Net Income
4,496,803

 
2,496,273

Less: Net Income attributable to non-controlling interest
410,175

 
391,114

Net Income attributable to CorEnergy Stockholders
$
4,086,628

 
$
2,105,159

Preferred dividend requirements
737,500

 

Net Income attributable to Common Stockholders
$
3,349,128

 
$
2,105,159

 
 
 
 
Net Income
$
4,496,803

 
$
2,496,273

Other comprehensive income:
 
 
 
Changes in fair value of qualifying hedges attributable to CorEnergy stockholders
(276,107
)
 
(70,620
)
Changes in fair value of qualifying hedges attributable to non-controlling interest
(64,555
)
 
(16,511
)
Net Change in Other Comprehensive Income
$
(340,662
)
 
$
(87,131
)
Total Comprehensive Income
4,156,141

 
2,409,142

Less: Comprehensive income attributable to non-controlling interest
345,620

 
374,603

Comprehensive Income attributable to CorEnergy Stockholders
$
3,810,521

 
$
2,034,539

Earnings Per Common Share:
 
 
 
Basic and Diluted
$
0.07

 
$
0.07

Weighted Average Shares of Common Stock Outstanding:
 
 
 
Basic and Diluted
46,613,258

 
29,973,357

Dividends declared per share
$
0.130

 
$
0.125

See accompanying Notes to Consolidated Financial Statements.

7


CorEnergy Infrastructure Trust, Inc.
CONSOLIDATED STATEMENTS OF EQUITY
 
Capital Stock
Preferred Stock
 
 
 
Additional
Paid-in
Capital
 
Accumulated Other Comprehensive Income
 
Retained
Earnings
 
Non-Controlling
Interest
 
Total
 
Shares
 
Amount
 
Amount
 
Warrants
 
 
 
 
 
Balance at December 31, 2013
24,156,163

 
$
24,156

 
$

 
$
1,370,700

 
$
173,441,019

 
$
777,403

 
$
1,580,062

 
$
28,348,030

 
$
205,541,370

Net Income

 

 

 

 

 

 
7,013,856

 
1,556,157

 
8,570,013

Net change in cash flow hedges

 

 

 

 

 
(324,101
)
 

 
(75,780
)
 
(399,881
)
Total comprehensive income

 

 

 

 

 
(324,101
)
 
7,013,856

 
1,480,377

 
8,170,132

Net offering proceeds from issuance of common stock
22,425,000

 
22,425

 

 

 
141,702,803

 

 

 

 
141,725,228

Dividends

 

 

 

 
(6,734,166
)
 

 
(8,593,918
)
 

 
(15,328,084
)
Common stock issued under director's compensation plan
4,027

 
4

 

 

 
29,996

 

 

 

 
30,000

Distributions to Non-controlling interest

 

 

 

 

 

 

 
(2,737,712
)
 
(2,737,712
)
Reinvestment of dividends paid to stockholders
19,865

 
20

 

 

 
140,088

 

 

 

 
140,108

Warrant expiration

 

 

 
(1,370,700
)
 
1,370,700

 

 

 

 

Balance at December 31, 2014
46,605,055

 
46,605

 

 

 
309,950,440

 
453,302

 

 
27,090,695

 
337,541,042

Net income

 

 

 

 

 

 
4,086,628

 
410,175

 
4,496,803

Net change in cash flow hedges

 

 

 

 

 
(276,107
)
 

 
(64,555
)
 
(340,662
)
Total comprehensive income

 

 

 

 

 
(276,107
)
 
4,086,628

 
345,620

 
4,156,141

Issuance of Series A cumulative redeemable preferred stock, 7.375% - redemption value

 

 
56,250,000

 

 
(2,039,524
)
 

 

 

 
54,210,476

Common stock dividends

 

 

 

 
(1,972,609
)
 

 
(4,086,628
)
 

 
(6,059,237
)
Common stock issued under director's compensation plan
4,484

 
4

 

 

 
29,996

 

 

 

 
30,000

Distributions to Non-controlling interest

 

 

 

 

 

 

 
(680,748
)
 
(680,748
)
Reinvestment of dividends paid to common stockholders
10,142

 
10

 

 

 
68,144

 

 

 

 
68,154

Balance at March 31, 2015 (Unaudited)
46,619,681

 
$
46,619

 
$
56,250,000

 
$

 
$
306,036,447

 
$
177,195

 
$

 
$
26,755,567

 
$
389,265,828

See accompanying Notes to Consolidated Financial Statements.



8


CorEnergy Infrastructure Trust, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
For The Three Months Ended
 
March 31, 2015
 
March 31, 2014
Operating Activities
 
 
 
Net Income
$
4,496,803

 
$
2,496,273

Adjustments to reconcile net income to net cash provided by (used in) operating activities:
 
 
 
Deferred income tax, net
(115,391
)
 
(340,561
)
Depreciation and amortization
4,426,559

 
3,364,803

Net distributions and dividend income, including recharacterization of income
(371,323
)
 
(1,294,182
)
Net realized and unrealized gain on other equity securities
(449,798
)
 
(17,489
)
Unrealized gain on derivative contract
(16,880
)
 

Common stock issued under directors compensation plan
30,000

 

Changes in assets and liabilities:

 
 
(Increase) decrease in accounts and other receivables
(352,029
)
 
127,323

Increase in financing note accrued interest receivable
(200,167
)
 

Increase in prepaid expenses and other assets
(295,441
)
 
(107,057
)
Increase in management fee payable
61,756

 
92,262

Decrease in accounts payable and other accrued liabilities
(821,951
)
 
(84,245
)
Increase in current income tax liability
480,637

 
1,033,247

Increase (decrease) in unearned revenue
(711,230
)
 
2,844,914

Net cash provided by operating activities
$
6,161,545

 
$
8,115,288

Investing Activities

 
 
Acquisition expenditures
(2,041,642
)
 
(41,887,644
)
Purchases of property and equipment
(16,464
)
 

Increase in financing notes receivable
(31,442
)
 
(4,107,955
)
Return of capital on distributions received
29,864

 
491,260

Net cash used in investing activities
$
(2,059,684
)
 
$
(45,504,339
)
Financing Activities
 
 
 
Debt financing costs
(53,705
)
 
(220,000
)
Net offering proceeds
54,137,791

 
45,624,563

Dividends paid
(5,991,083
)
 
(2,990,215
)
Distributions to non-controlling interest
(680,748
)
 

Advances on revolving line of credit
1,945,361

 
1,523,266

Payments on revolving line of credit
(33,521,055
)
 
(1,122,096
)
Principal payment on credit facility
(882,000
)
 
(294,000
)
Net cash provided by financing activities
$
14,954,561

 
$
42,521,518

Net Change in Cash and Cash Equivalents
$
19,056,422

 
$
5,132,467

Cash and Cash Equivalents at beginning of period
7,578,164

 
17,963,266

Cash and Cash Equivalents at end of period
$
26,634,586

 
$
23,095,733

Supplemental information continued on next page.
 
 
 
See accompanying Notes to Consolidated Financial Statements.

9


CorEnergy Infrastructure Trust, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
Continued from previous page.

 
For The Three Months Ended
 
March 31, 2015
 
March 31, 2014
Supplemental Disclosure of Cash Flow Information
 
 
 
Interest paid
$
943,101

 
$
690,570

Income taxes paid (net of refunds)
$
295,901

 
$
(179,172
)
 
 
 
 
Non-Cash Operating Activities
 
 
 
Change in accounts payable and accrued expenses related to prepaid assets and other expense
$
19,096

 
$

 
 
 
 
Non-Cash Investing Activities
 
 
 
Change in accounts payable and accrued expenses related to acquisition expenditures
$
(13,597
)
 
$
78,121

Change in accounts payable and accrued expenses related to issuance of financing and other notes receivable
$
(39,248
)
 
$

 
 
 
 
Non-Cash Financing Activities
 
 
 
Change in accounts payable and accrued expenses related to the issuance of equity
$
(72,685
)
 
$

Change in accounts payable and accrued expenses related to debt financing costs
$
8,509

 
$
(220,000
)
Reinvestment of distributions by common stockholders in additional common shares
$
68,154

 
$
29,305

See accompanying Notes to Consolidated Financial Statements.

10


CorEnergy Infrastructure Trust, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
March 31, 2015
1. INTRODUCTION AND BASIS OF PRESENTATION
Introduction
CorEnergy Infrastructure Trust, Inc. ("CorEnergy"), was organized as a Maryland corporation and commenced operations on December 8, 2005. The Company's common shares are listed on the New York Stock Exchange under the symbol “CORR.” As used in this report, the terms "we", "us", "our" and the "Company" refer to CorEnergy and its subsidiaries.
We are primarily focused on acquiring and financing midstream and downstream real estate assets within the U.S. energy infrastructure sector and concurrently entering into long-term triple-net participating leases with energy companies. We also may provide other types of capital, including loans secured by energy infrastructure assets. Targeted assets include pipelines, storage tanks, transmission lines and gathering systems, among others. These sale-leaseback or real property mortgage transactions provide the energy company with a source of capital that is an alternative to sources such as corporate borrowing, bond offerings, or equity offerings. Many of our leases contain participation features in the financial performance or value of the underlying infrastructure real property asset. The triple-net lease structure requires that the tenant pay all operating expenses of the business conducted by the tenant, including real estate taxes, insurance, utilities, and expenses of maintaining the asset in good working order.
Taxable REIT subsidiaries hold our securities portfolio, operating businesses and certain financing notes receivable as follows:
Corridor Public Holdings, Inc. and its wholly-owned subsidiary Corridor Private Holdings, Inc ("CorPrivate"), hold our securities portfolio.
Mowood Corridor, Inc. and its wholly-owned subsidiary, Mowood, LLC ("Mowood"), which is the holding company for one of our operating companies, Omega Pipeline Company, LLC (“Omega”).
Corridor MoGas, Inc. ("CorMoGas") holds two other operating companies, MoGas Pipeline, LLC ("MoGas") and United Property Systems, LLC ("UPS").
CorEnergy BBWS, Inc. ("BBWS"), CorPrivate and Corridor Leeds Path West, Inc. ("Leeds Path West") hold financing notes receivable.
Basis of Presentation and Use of Estimates
The accompanying consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries and have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) set forth in the Accounting Standards Codification ("ASC"), as published by the Financial Accounting Standards Board ("FASB"), and with the Securities and Exchange Commission (“SEC”) instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The accompanying consolidated financial statements reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of the Company's financial position, results of operations and cash flows for the periods presented. There were no adjustments that, in the opinion of management, were not of a normal and recurring nature. All intercompany transactions and balances have been eliminated in consolidation, and our net earnings are reduced by the portion of net earnings attributable to noncontrolling interests.
The Company consolidates certain entities when it is deemed to be the primary beneficiary in a variable interest entity ("VIE"), as defined in FASB ASC Topic on Consolidation. The Topic on Consolidation requires the consolidation of VIEs in which an enterprise has a controlling financial interest. The equity method of accounting is applied to entities in which the Company is not the primary beneficiary as defined in the Consolidation Topic of FASB ASC, or does not have effective control, but can exercise influence over the entity with respect to its operations and major decisions. This topic requires an ongoing reassessment.
Operating results for the three months ended March 31, 2015, are not necessarily indicative of the results that may be expected for the year ending December 31, 2015. These consolidated financial statements and Management's Discussion and Analysis of the Financial Condition and Results of Operations should be read in conjunction with our Annual Report on Form 10-K, for the year ended December 31, 2014, filed with the SEC on March 16, 2015.
The financial statements included in this report are based on the selection and application of critical accounting policies, which require management to make significant estimates and assumptions. Critical accounting policies are those that are both important to the presentation of our financial condition and results of operations and require management's most difficult, complex or subjective judgments. Note 2 to the Consolidated Financial Statements, included in this report, further details information related to our significant accounting policies.

11



2. SIGNIFICANT ACCOUNTING POLICIES
A. Use of Estimates – The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, recognition of distribution income and disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates.
B. Leased Property – The Company includes assets subject to lease arrangements within Leased property, net of accumulated depreciation, in the Consolidated Balance Sheets. Lease payments received are reflected in Lease revenue on the Consolidated Statements of Income, net of amortization of any off-market adjustments. Costs in connection with the creation and execution of a lease are capitalized and amortized over the lease term. See Note 3 for further discussion.
C. Cash and Cash Equivalents – The Company maintains cash balances at financial institutions in amounts that regularly exceed FDIC insured limits. The Company’s cash equivalents are comprised of short-term, liquid money market instruments.
D. Long-Lived Assets – Property and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful life of the asset. Expenditures for repairs and maintenance are charged to operations as incurred, and improvements, which extend the useful lives of assets, are capitalized and depreciated over the remaining estimated useful life of the asset.
The Company initially records long-lived assets at their purchase price plus any direct acquisition costs, unless the transaction is accounted for as a business combination, in which case the acquisition costs are expensed as incurred. If the transaction is accounted for as a business combination, the Company allocates the purchase price to the acquired tangible and intangible assets and liabilities based on their estimated fair values. See Note 5 for further information.
E. Intangibles and Goodwill – The Company may acquire long-lived assets that are subject to an existing lease contract with the seller or other lessee party and the Company may assume outstanding debt of the seller as part of the consideration paid. If, at the time of acquisition, the existing lease or debt contract is not at current market terms, the Company will record an asset or liability at the time of acquisition representing the amount by which the fair value of the lease or debt contract differs from its contractual value. Such amount is then amortized over the remaining contract term as an adjustment to the related lease revenue or interest expense.
The Company periodically reviews its long-lived assets, primarily real estate and goodwill, for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. The Company’s review involves comparing current and future operating performance of the assets, the most significant of which is undiscounted operating cash flows, to the carrying value of the assets. Based on this analysis, a provision for possible loss is recognized, if any.
Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired in a business combination. Refer to Note 5 for further details. The company will review goodwill for impairment at least annually or whenever events or circumstances indicate the carrying value of an asset may not be recoverable. If the carrying amount of goodwill exceeds its implied fair value, an impairment loss would be recognized for the amount of the excess.
No impairment write-downs were recognized during the three months ended March 31, 2015 and 2014.
F. Investment Securities – The Company’s investments in securities are classified as other equity securities and represent interests in private companies which the Company has elected to report at fair value under the fair value option.
These investments generally are subject to restrictions on resale, have no established trading market and are valued on a quarterly basis. Because of the inherent uncertainty of valuation, the fair values of such investments, which are determined in accordance with procedures approved by the Company’s Board of Directors, may differ materially from the values that would have been used had a ready market existed for the investments.
The Company determines fair value to be the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company has determined the principal market, or the market in which the Company exits its private portfolio investments with the greatest volume and level of activity, to be the private secondary market. Typically, private companies are bought and sold based on multiples of EBITDA, cash flows, net income, revenues, or in limited cases, book value.

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For private company investments, value is often realized through a liquidity event. Therefore, the value of the company as a whole (enterprise value) at the reporting date often provides the best evidence of the value of the investment and is the initial step for valuing the Company’s privately issued securities. For any one company, enterprise value may best be expressed as a range of fair values, from which a single estimate of fair value will be derived. In determining the enterprise value of a portfolio company, an analysis is prepared consisting of traditional valuation methodologies including market and income approaches. The Company considers some or all of the traditional valuation methods based on the individual circumstances of the portfolio company in order to derive its estimate of enterprise value.
The fair value of investments in private portfolio companies is determined based on various factors, including enterprise value, observable market transactions, such as recent offers to purchase a company, recent transactions involving the purchase or sale of the equity securities of the company, or other liquidation events. The determined equity values may be discounted when the Company has a minority position, or is subject to restrictions on resale, has specific concerns about the receptivity of the capital markets to a specific company at a certain time, or other comparable factors exist.
The Company undertakes a multi-step valuation process each quarter in connection with determining the fair value of private investments. We have retained an independent valuation firm to provide third party valuation consulting services based on procedures that the Company has identified and may ask them to perform from time to time on all or a selection of private investments as determined by the Company.  The multi-step valuation process is specific to the level of assurance that the Company requests from the independent valuation firm. For positive assurance, the process is as follows:
The independent valuation firm prepares the valuations and the supporting analysis.
The valuation report is reviewed and approved by senior management.
The Audit Committee of the Board of Directors reviews the supporting analysis and accepts the valuations.
G. Financing Notes Receivable – Financing notes receivable are presented at face value plus accrued interest receivable and deferred loan origination costs and net of related direct loan origination fees. The Company reviews its financing notes receivable to determine if the balances are realizable based on factors affecting the collectibility of those balances.  Factors may include credit quality, timeliness of required periodic payments, past due status and management discussions with obligors. The Company evaluates the collectability of both interest and principal of each of its loans to determine whether it is impaired. A loan is considered to be impaired when based on current information and events, the Company determines that it is probable that it will be unable to collect all amounts due according to the existing contractual terms. An insignificant delay or shortfall in amounts of payments does not necessarily result in the loan being identified as impaired. If the Company does determine impairment exists, the amount deemed uncollectible is expensed in the period of determination. The financing notes receivable are discussed more fully in Note 6.
H. Lease Receivable – Lease receivables are determined according to the terms of the lease agreements entered into by the Company and its lessees, as discussed within Note 4. Lease payments by our tenants, have remained timely and without lapse.
I. Accounts Receivable – Accounts receivable are presented at face value net of an allowance for doubtful accounts. Accounts are considered past due based on the terms of sale with the customers. The Company reviews accounts for collectibility based on an analysis of specific outstanding receivables, current economic conditions and past collection experience. At March 31, 2015, and December 31, 2014, the Company determined that an allowance for doubtful accounts was not necessary.
J. Derivative Instruments and Hedging Activities - FASB ASC 815, Derivatives and Hedging (“ASC 815”), provides the disclosure requirements for derivatives and hedging activities with the intent to provide users of financial statements with an enhanced understanding of: (a) how and why an entity uses derivative instruments, (b) how the entity accounts for derivative instruments and related hedged items, and (c) how derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. Further, qualitative disclosures are required that explain the Company's objectives and strategies for using derivatives, as well as quantitative disclosures about the fair value of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative instruments. Accordingly, the Company's derivative assets and liabilities are presented on a gross basis.
As required by ASC 815, the Company records all derivatives on the balance sheet at fair value.  The accounting for changes in the fair value of derivatives depends on the intended use of the derivative, whether the Company has elected to designate a derivative in a hedging relationship and apply hedge accounting and whether the hedging relationship has satisfied the criteria necessary to apply hedge accounting. Derivatives designated and qualifying as a hedge of the exposure to changes in the fair value of an asset, liability, or firm commitment attributable to a particular risk, such as interest rate risk, are considered fair value hedges. Derivatives designated and qualifying as a hedge of the exposure to variability in expected future cash flows, or other types of forecasted transactions, are considered cash flow hedges. Derivatives may also be designated as hedges of the foreign currency exposure of

13


a net investment in a foreign operation. Hedge accounting generally provides for the matching of the timing of gain or loss recognition on the hedging instrument with the recognition of the changes in the fair value of the hedged asset or liability that are attributable to the hedged risk in a fair value hedge or the earnings effect of the hedged forecasted transactions in a cash flow hedge. The Company may enter into derivative contracts that are intended to economically hedge certain of its risks, even though hedge accounting does not apply or the Company elects not to apply hedge accounting.
FASB ASC 820, Fair Value Measurements and Disclosure ("ASC 820"), defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. In accordance with ASC 820, the Company made an accounting policy election to measure the credit risk of its derivative financial instruments that are subject to master netting agreements on a net basis by counterparty portfolio.
K. Fair Value Measurements - Various inputs are used in determining the fair value of the Company’s assets and liabilities. These inputs are summarized in the three broad levels listed below:
Level 1 – quoted prices in active markets for identical investments
Level 2 – other significant observable inputs (including quoted prices for similar investments, market corroborated inputs, etc.)
Level 3 – significant unobservable inputs (including the Company’s own assumptions in determining the fair value of investments)
ASC 820 applies to reported balances that are required or permitted to be measured at fair value under existing accounting pronouncements; accordingly, the standard does not require any new fair value measurements of reported balances. ASC 820 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. As a basis for considering market participant assumptions in fair value measurements, ASC 820 establishes a fair value hierarchy that distinguishes between market participant assumptions based on market data obtained from sources independent of the reporting entity (observable inputs that are classified within Levels 1 and 2 of the hierarchy) and the reporting entity's own assumptions about market participant assumptions (unobservable inputs classified within Level 3 of the hierarchy).
Level 1 inputs utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access. Level 2 inputs are inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly. Level 2 inputs may include quoted prices for similar assets and liabilities in active markets, as well as inputs that are observable for the asset or liability (other than quoted prices), such as interest rates, foreign exchange rates, and yield curves that are observable at commonly quoted intervals. Level 3 inputs are unobservable inputs for the asset or liability, which are typically based on an entity's own assumptions, 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 Company's 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.
L. Revenue Recognition – Specific recognition policies for the Company’s revenue items are as follows:
Lease revenue – Base rent related to the Company’s leased property is recognized on a straight-line basis over the term of the lease when collectibility is reasonably assured. Contingent rent is recognized when it is earned, based on the achievement of specified performance criteria. Rental payments received in advance are classified as unearned revenue and included as a liability within the Consolidated Balance Sheets. Unearned revenue is amortized ratably over the lease period as revenue recognition criteria are met. Rental payments received in arrears are accrued and classified as Lease Receivable and included in assets within the Consolidated Balance Sheets.
Sales revenue – Revenues related to natural gas distribution and performance of management services are recognized in accordance with GAAP upon delivery of natural gas and upon the substantial performance of management and supervision services related to the expansion of the natural gas distribution system. Omega, acting as a principal, provides for transportation services and natural gas supply for its customers. In addition, Omega is paid fees for the operation and maintenance of its natural gas distribution system, including any necessary expansion of the distribution system. Omega is responsible for the coordination, supervision and quality of the expansions while actual construction is generally performed by third party contractors. Revenues from expansion efforts are recognized in accordance with GAAP using either a completed contract or percentage of completion method based on the level and volume of estimates utilized, as well as the certainty or uncertainty of our ability to collect those revenues.
Transportation revenue – MoGas generates revenue from natural gas transportation and recognizes that revenue on firm contracted capacity over the contract period regardless of actual volume. For interruptible or volumetric based

14


transportation, revenue is recognized when physical deliveries of natural gas are made at the delivery point agreed upon by both parties.
Financing revenue – Our financing notes receivable are considered a core product offering and therefore the related income is presented as a component of operating income in the revenue section. For increasing rate loans, base interest income is recorded ratably over the life of the loan, using the effective interest rate. The net amount of deferred loan origination fees and costs are amortized on a straight-line basis over the life of the loan and reported as an adjustment to yield in financing revenue. Participating financing revenues are recorded when specific performance criteria have been met.
M. Cost of Sales – Included in the Company’s cost of sales are the amounts paid for gas and propane, along with related transportation, which are delivered to customers, as well as, the cost of material and labor related to the expansion of the Omega natural gas distribution system.
N. Transportation, maintenance and general and administrative – These expenses are incurred both internally and externally. The internal expenses relate to system control, pipeline operations, maintenance, insurance and taxes. Other internal expenses include payroll cost for employees associated with gas control, field employees, the office manager and the vice presidents of operations and finance. The external costs consist of professional services such as audit and accounting, legal and regulatory and engineering.
O. Asset Acquisition Expenses – Costs incurred in connection with the research of real property acquisitions not expected to be accounted for as business combinations are expensed until it is determined that the acquisition of the real property is probable. Upon such determination, costs incurred in connection with the acquisition of the property are capitalized as described in paragraph (D) above. Deferred costs related to an acquisition that we have determined, based on our judgment, not to pursue are expensed in the period in which such determination is made.
P. Offering Costs – Offering costs related to the issuance of common or preferred stock are charged to additional paid-in capital when the stock is issued.
Q. Debt Issuance Costs – Costs incurred for the issuance of new debt are capitalized and amortized over the debt term. See Note 14 for further discussion.
R. Distributions to Stockholders – Distributions to both common and preferred stockholders are determined by the Board of Directors. Distributions to common stockholders are recorded on the ex-dividend date and distributions to preferred stockholders are recorded when declared by the Board of Directors.
S. Other Income Recognition Specific policies for the Company’s other income items are as follows:
Net distributions and dividend income from investments – Distributions and dividends from investments are recorded on their ex-dates and are reflected as other income within the accompanying Consolidated Statements of Income. Distributions received from the Company’s investments are generally characterized as ordinary income, capital gains and distributions received from investment securities. The portion characterized as return of capital is paid by our investees from their cash flow from operations. The Company records investment income, capital gains and distributions received from investment securities based on estimates made at the time such distributions are received. Such estimates are based on information available from each company and other industry sources. These estimates may subsequently be revised based on information received from the entities after their tax reporting periods are concluded, as the actual character of these distributions is not known until after the fiscal year end of the Company.
Net realized and unrealized gain (loss) from investments – Securities transactions are accounted for on the date the securities are purchased or sold. Realized gains and losses are reported on an identified cost basis. The Company records investment income and return of capital based on estimates made at the time such distributions are received. Such estimates are based on information available from the portfolio company and other industry sources. These estimates may subsequently be revised based on information received from the portfolio company after their tax reporting periods are concluded, as the actual character of these distributions are not known until after our fiscal year end.
T. Federal and State Income Taxation – In 2013 we qualified, and in March 2014 elected (effective as of January 1, 2013), to be treated as a REIT for federal income tax purposes. Because certain of our assets may not produce REIT-qualifying income or be treated as interests in real property, those assets are held in wholly-owned Taxable REIT Subsidiaries ("TRSs") in order to limit the potential that such assets and income could prevent us from qualifying as a REIT.

15


As a REIT, the Company holds and operates certain of our assets through one or more wholly-owned TRSs. Our use of TRSs enables us to continue to engage in certain businesses while complying with REIT qualification requirements and also allows us to retain income generated by these businesses for reinvestment without the requirement of distributing those earnings. In the future, we may elect to reorganize and transfer certain assets or operations from our TRSs to the Company or other subsidiaries, including qualified REIT subsidiaries.
The Company's trading securities and other equity securities are limited partnerships or limited liability companies which are treated as partnerships for federal and state income tax purposes. As a limited partner, the Company reports its allocable share of taxable income in computing its own taxable income. To the extent held by a TRS, the TRS's tax expense or benefit is included in the Consolidated Statements of Income based on the component of income or gains and losses to which such expense or benefit relates. Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. A valuation allowance is recognized if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred income tax asset will not be realized. Due to our decision to structure ourselves as a REIT in December 2012, it is expected that for the three months ended March 31, 2015, and future periods, any deferred tax liability or asset will be related entirely to the assets and activities of the Company's TRSs.
If we cease to qualify as a REIT, the Company, as a C corporation, would be obligated to pay federal and state income tax on its taxable income. Currently, the highest regular marginal federal income tax rate for a corporation is 35 percent. The Company may be subject to a 20 percent federal alternative minimum tax on its federal alternative minimum taxable income to the extent that its alternative minimum tax exceeds its regular federal income tax.
U. Recent Accounting Pronouncements – In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update ("ASU") 2014-08 "Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." Under this guidance, only disposals representing a strategic shift in operations would be presented as discontinued operations. This guidance requires expanded disclosure that provides information about the assets, liabilities, income and expenses of discontinued operations. Additionally, the guidance requires additional disclosure for a disposal of a significant part of an entity that does not qualify for discontinued operations reporting. This guidance will be effective for reporting periods beginning on or after December 15, 2014 with early adoption permitted for disposals or classifications of assets as held-for-sale that have not been reported in financial statements previously issued or available for issuance. It is expected that fewer disposal transactions will meet the new criteria to be reported as discontinued operations. The Company elected early adoption of the standard and the effects of applying the revised guidance did not have a material effect on the consolidated financial statements and related disclosures. Refer to Note 3 for further information.
In May 2014, the FASB issued ASU No. 2014-09 "Revenue from Contracts with Customers." ASU No. 2014-09 adds to the FASB ASC by detailing new guidance in order to make a more clarified set of principles for recognizing revenue from customer contracts. ASU No. 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Management is still in the process of evaluating this amendment and has not selected a transition method, however, does not expect adoption to have a material impact on the Company's consolidated financial statements.
In August 2014, the FASB issued ASU No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU No. 2014-15”) that will require management to evaluate whether there are conditions and events that raise substantial doubt about the Company’s ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Management will be required to provide certain footnote disclosures if it concludes that substantial doubt exists or when its plans alleviate substantial doubt about the Company’s ability to continue as a going concern. ASU No. 2014-15 becomes effective for annual periods beginning in 2016 and for interim reporting periods starting in the first quarter of 2017. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.
In February 2015, the FASB issued ASU No. 2015-02 "Consolidation (Topic 810), Amendments to the Consolidation Analysis." ASU 2015-02 is aimed at asset managers, however, it will also have an effect on all reporting entities that have variable interests in other legal entities. In some cases, consolidation conclusions will change. In other cases, reporting entities will need to provide additional disclosures about entities that currently aren't considered variable interest entities but will be considered VIE's under the new guidance if they have a variable interest in those entities. At the very least, reporting entities will need to re-evaluate their consideration conclusions and potentially revise their documentation. Management is still in the process of evaluating this amendment, however, does not expect adoption to have a material impact on the Company's consolidated financial statements.

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In April 2015, the FASB issued ASU No. 2015-03 "Interest-Imputation of Interest" to simplify presentation of debt issuance costs. The amendments in this update require debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU No. 2015-03 is effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period. Management is still in the process of evaluating this amendment, however, does not expect adoption to have a material impact on the Company's consolidated financial statements.
3. LEASED PROPERTIES
Pinedale LGS
Our subsidiary, Pinedale Corridor, LP ("Pinedale LP"), owns a system of gathering, storage, and pipeline facilities (the "Liquids Gathering System" or "Pinedale LGS"), with associated real property rights in the Pinedale Anticline in Wyoming.
Physical Assets
The Pinedale LGS consists of more than 150 miles of pipelines with 107 receipt points and four above-ground central gathering facilities. The system is leased to and used by Ultra Petroleum Corp. ("Ultra Petroleum") as a method of separating water, condensate and associated flash gas from a unified stream and subsequently selling or treating and disposing of the separated products. Prior to entering the Pinedale LGS, a commingled hydrocarbon stream is separated into wellhead natural gas and a liquids stream. The wellhead natural gas is transported to market by a third party. The remaining liquids, primarily water, are transported by the Pinedale LGS to one of its four central gathering facilities where they pass through a three-phase separator which separates condensate, water and associated natural gas. Condensate is a valuable hydrocarbon commodity that is sold by Ultra Petroleum; water is transported to disposal wells or a treatment facility for re-use; and the natural gas is sold or otherwise used by Ultra Petroleum for fueling on-site operational equipment.
The asset is depreciated for book purposes over an estimated useful life of 26 years. The amount of depreciation recognized for the leased property for the three months ended March 31, 2015 and 2014, was $2.2 million and $2.2 million, respectively.
See Note 4 for further information regarding the Pinedale Lease Agreement (as defined therein).
Non-Controlling Interest Partner
Prudential Financial, Inc. ("Prudential") funded a portion of the Pinedale LGS acquisition and, as a limited partner, holds 18.95 percent of the economic interest in Pinedale LP. The general partner, Pinedale GP, holds the remaining 81.05 percent of the economic interest.
Debt
Pinedale LP borrowed $70 million pursuant to a secured term credit facility with KeyBank National Association serving as a lender and the administrative agent on behalf of other lenders participating in the credit facility ("KeyBank Term Facility"). The credit facility will remain in effect through December 2015, with an option to extend through December 2016. The credit facility is secured by the Pinedale LGS. See Note 14 for further information regarding the credit facility.
Portland Terminal Facility
The Portland Terminal Facility is a rail and marine facility adjacent to the Willamette River in Portland, Oregon which is triple-net leased to Arc Terminals Holdings LLC ("Arc Terminals"), an indirect wholly-owned subsidiary of Arc Logistics Partners LP ("Arc Logistics"). The 39-acre site has 84 tanks with a total storage capacity of approximately 1,500,000 barrels. The Portland Terminal Facility is capable of receiving, storing and delivering crude oil and refined petroleum products. Products are received and delivered via railroad or marine (up to Panamax size vessels). The marine facilities are accessed through a neighboring terminal facility via an owned pipeline. The Portland Terminal Facility offers heating systems, emulsions and an on-site product testing laboratory as ancillary services.
At the acquisition date we anticipated funding an additional $10 million of terminal-related improvement projects in support of Arc Terminals’ commercial strategy to optimize the Portland Terminal Facility and generate stable cash flows, including: i) upgrade a portion of the existing storage assets; ii) enhance existing terminal infrastructure; and iii) develop, design, engineer and construct throughput expansion opportunities. As of March 31, 2015, additional spending on terminal-related projects totaled approximately $7.8 million.

17


The asset is depreciated for book purposes over an estimated useful life of 30 years. The amount of depreciation recognized for the leased property for each of the three months ended March 31, 2015 and 2014, was $407 thousand and $274 thousand, respectively.
See Note 4 for further information regarding the Portland Lease Agreement related to the Portland Terminal Facility assets.
LEASED PROPERTY HELD FOR SALE
Eastern Interconnect Project (EIP)
Physical Assets
The EIP transmission assets are utilized by the lessee to move electricity across New Mexico between Albuquerque and Clovis. The physical assets include 216 miles of 345 kilovolt (unaudited) transmission lines, towers, easement rights, converters and other grid support components. Originally, the assets were depreciated for book purposes over an estimated useful life of 20 years. Pursuant to the Purchase Agreement discussed in Note 4, the Company reevaluated the residual value used to calculate its depreciation of EIP, and determined that a change in estimate was necessary. The change in estimate resulted in higher depreciation expenses beginning in November of 2012 through the expiration of the lease in April 2015.
The amount of depreciation expense related to the EIP leased property for the three months ended March 31, 2015 and 2014, was $570 thousand and $570 thousand, respectively.
EIP Leased Property Held for Sale consists of the following:
EIP Leased Property Held for Sale
 
 
March 31, 2015
 
December 31, 2014
Leased asset
 
$
14,126,849

 
$
14,126,849

Less: accumulated depreciation
 
(6,448,603
)
 
(5,878,933
)
Net leased asset held for sale
 
$
7,678,246

 
$
8,247,916

See Note 4 for further information regarding the Purchase Agreement with PNM and the PNM Lease Agreement related to the EIP transmission assets.

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4. LEASES
As of March 31, 2015, the Company had three significant leases. The table below displays the impact of leases on total leased properties and total lease revenues for the periods presented.

 
As a Percentage of
 
 
Leased Properties
 
Lease Revenues
 
 
As of
 
As of
 
For the Three Months Ended

 
March 31, 2015
 
December 31, 2014
 
March 31, 2015
 
March 31, 2014
 
Pinedale LGS
 
78.68%
 
79.17%
 
70.36%
 
75.07%
 
Portland Terminal Facility
 
17.93%
 
17.24%
 
20.68%
 
15.49%
 
Public Service of New Mexico (1)
 
2.87%
 
3.07%
 
8.70%
 
9.44%
 
(1) See additional discussion of the PNM lease under the heading Lease of Property Held for Sale, below.

Pinedale LGS
Pinedale LP entered into a long-term triple-net lease agreement on December 20, 2012, relating to the use of the Pinedale LGS (the “Pinedale Lease Agreement”) with Ultra Wyoming LGS, LLC (“Ultra Wyoming”), an indirect wholly-owned subsidiary of Ultra Petroleum. The Pinedale Lease Agreement has a fifteen year initial term and may be extended for additional five-year terms at the sole discretion of Ultra Wyoming. Ultra Wyoming utilizes the Pinedale LGS to gather and transport a commingled stream of oil, natural gas and water, then further utilizes the Pinedale LGS to separate this stream into its separate components. Ultra Wyoming's obligations under the Pinedale Lease Agreement are guaranteed by Ultra Petroleum and Ultra Petroleum's operating subsidiary, Ultra Resources, Inc. (“Ultra Resources”), pursuant to the terms of a related parent guaranty. Annual rent for the initial term under the Pinedale Lease Agreement is a minimum of $20 million (as adjusted annually for changes based on the Consumer Price Index (“CPI”), subject to annual maximum adjustments of 2 percent). Additionally, the Pinedale Lease Agreement has a variable rent component based on the volume of liquid hydrocarbons and water that flowed through the Pinedale LGS in a prior month, subject to Pinedale LP not being in default under the Pinedale Lease Agreement. For 2015, the quarterly rent increased by $85 thousand to $5.2 million based on the CPI adjustment as specified in the lease terms. Total annual rent may not exceed $27.5 million during the initial fifteen-year term.
As of March 31, 2015, and December 31, 2014, approximately $780 thousand and $796 thousand, respectively, of net deferred lease costs are included in the accompanying Consolidated Balance Sheets. The deferred costs are amortized over the 15 year life of the Pinedale Lease Agreement. For each of the three months ended March 31, 2015 and 2014, $15 thousand is included in amortization expense within the Consolidated Statements of Income.

The assets, which comprise the Pinedale LGS, include real property and land rights to which the purchase consideration was allocated based on relative fair values and equaled $122.3 million and $105.7 million, respectively, at the time of acquisition.  The land rights are being depreciated over the 26 year life of the related land lease with associated depreciation expense expected to be approximately $4.1 million for each of the next five years.

In view of the fact that Ultra Petroleum leases a substantial portion of the Company's net leased property, which is a significant source of revenues and operating income, its financial condition and ability and willingness to satisfy its obligations under its lease with the Company are expected to have a considerable impact on the results of operation going forward.
Ultra Petroleum is currently subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act") and is required to file with the SEC annual reports containing audited financial statements and quarterly reports containing unaudited financial statements. The audited financial statements and unaudited financial statements of Ultra Petroleum can be found on the SEC's website at www.sec.gov. The Company makes no representation as to the accuracy or completeness of the audited and unaudited financial statements of Ultra Petroleum, but has no reason not to believe the accuracy or completeness of such information. In addition, Ultra Petroleum has no duty, contractual or otherwise, to advise the Company of any events that might have occurred subsequent to the date of such financial statements which could affect the significance or accuracy of such information. Summary Consolidated Balance Sheets and Consolidated Statements of Operations for Ultra Petroleum are provided below.

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Ultra Petroleum Corp.
Summary Consolidated Balance Sheets
(in thousands)
 
March 31, 2015
 
December 31, 2014
 
(Unaudited)
 
 
Current assets
$
270,073

 
$
277,138

Non-current assets
3,995,957

 
3,948,552

Total Assets
$
4,266,030

 
$
4,225,690

 
 
 
 
Current liabilities
$
346,179

 
$
445,718

Non-current liabilities
3,682,624

 
3,568,312

Total Liabilities
$
4,028,803

 
$
4,014,030

 
 
 
 
Shareholder's equity (deficit)
237,227

 
211,660

Total Liabilities and Shareholder's Equity
$
4,266,030

 
$
4,225,690

 
 
 
 

Ultra Petroleum Corp.
Summary Consolidated Statements of Operations
(in thousands)
 
For The Three Months Ended
 
March 31, 2015
 
March 31, 2014
 
(Unaudited)
 
 
Revenues
$
219,309

 
$
326,299

Expenses
189,347

 
154,829

Operating Income
29,962

 
171,470

Other (Expense), net
(6,795
)
 
(69,751
)
Income before income tax (benefit) provision
23,167

 
101,719

Income tax (benefit) provision
(2,022
)
 
4

Net Income
$
25,189

 
$
101,715

Portland Terminal Facility
LCP Oregon entered into the Portland Lease Agreement on January 21, 2014. Arc Logistics has guaranteed the obligations of Arc Terminals under the Portland Lease Agreement. The Portland Lease Agreement grants Arc Terminals substantially all authority to operate the Portland Terminal Facility. During the initial fifteen-year term, Arc Terminals will make base monthly rental payments as well as variable rent payments based on the volume of liquid hydrocarbons that flowed through the Portland Terminal Facility in the prior month in excess of a designated threshold of 12,500 barrels per day of oil equivalent. Variable rent is capped at 30 percent of total rent, which would be the equivalent of the Portland Terminal Facility’s expected throughput capacity.
Base rent as of March 31, 2015 had increased to $480 thousand per month due to approximately $7.8 million in completed construction projects at the Portland Terminal Facility. Total planned construction was estimated at inception to be $10 million (unaudited). During the three months ended March 31, 2015, $173 thousand in incremental base rent was received due to construction completed as of the quarter end.
Arc Logistics is a fee-based, growth-oriented Delaware limited partnership formed by Lightfoot Capital Partners, LP and Lightfoot Capital Partners GP LLC, collectively, ("Lightfoot") to own, operate, develop and acquire a diversified portfolio of complementary energy logistics assets. Arc Logistics’ public disclosures filed with the SEC indicate that Arc Logistics is principally engaged in the terminaling, storage, throughput and transloading of crude oil and petroleum products with energy logistics assets strategically located in the East Coast, Gulf Coast and Midwest regions of the U.S. Arc Terminals is a wholly-owned subsidiary of Arc Logistics.
Arc Logistics is currently subject to the reporting requirements of the Exchange Act and is required to file with the SEC annual reports containing audited financial statements and quarterly reports containing unaudited financial statements. The audited financial statements and unaudited financial statements of Arc Logistics can be found on the SEC's web site at www.sec.gov. The Company makes no representation as to the accuracy or completeness of the audited and unaudited financial statements of Arc Logistics but has no reason to doubt the accuracy or completeness of such information. In addition, Arc Logistics has no duty,

20


contractual or otherwise, to advise the Company of any events that might have occurred subsequent to the date of such financial statements which could affect the significance or accuracy of such information. None of the information in the public reports of Arc Logistics that are filed with the SEC is incorporated by reference into, or in any way form, a part of this filing.
The future contracted minimum rental receipts for all net leases as of March 31, 2015, are as follows:
Future Minimum Lease Receipts
Years Ending December 31,
 
Amount
2015
 
$
19,886,910

2016
 
26,515,880

2017
 
26,515,880

2018
 
26,515,880

2019
 
26,623,475

Thereafter
 
225,236,893

Total
 
$
351,294,918

Lease of Property Held for Sale
Public Service Company of New Mexico ("PNM")
The EIP leased asset held for sale is leased on a triple net basis through April 1, 2015, (the "PNM Lease Agreement") to PNM, an independent electric utility company serving approximately 500 thousand customers (unaudited) in New Mexico. PNM is a subsidiary of PNM Resources Inc. (NYSE: PNM) ("PNM Resources").
At the time of acquisition, the rate of the PNM Lease Agreement was determined to be above market rates for similar leased assets and the Company recorded an intangible asset of $1.1 million for this premium which is being amortized as a reduction to lease revenue over the remaining lease term. See Note 13 below for further details of the intangible asset.
On November 1, 2012, the Company entered into a definitive Purchase Agreement with PNM to sell the Company’s 40 percent undivided interest in the EIP upon termination of the PNM Lease Agreement on April 1, 2015, for $7.7 million. Upon execution of the Agreement, the schedule of the lease payments under the PNM Lease Agreement was changed so that the last scheduled semi-annual lease payment was received by the Company on October 1, 2012. Additionally, PNM's remaining basic lease payments due to the Company were accelerated. The semi-annual payments of approximately $1.4 million that were originally scheduled to be paid on April 1, and October 1, 2013, were received by the Company on November 1, 2012. The three remaining lease payments due April 1, 2014, October 1, 2014, and April 1, 2015, were paid in full on January 2, 2014. For the three months ended March 31, 2015 and 2014, revenue of $638 thousand was included in lease revenue on the income statement.
PNM Resources is currently subject to the reporting requirements of the Exchange Act and is required to file with the SEC annual reports containing audited financial statements and quarterly reports containing unaudited financial statements. The financial statements of PNM Resources can be found on the SEC's web site at www.sec.gov. The Company makes no representation as to the accuracy or completeness of the audited and unaudited financial statements of PNM Resources but has no reason to doubt the accuracy or completeness of such information. In addition, PNM Resources has no duty, contractual or otherwise, to advise the Company of any events that might have occurred subsequent to the date of such financial statements which could affect the significance or accuracy of such information. None of the information in the public reports of PNM Resources that are filed with the SEC is incorporated by reference into, or in any way form, a part of this filing.
5. MOGAS TRANSACTION
On November 24, 2014, our wholly owned taxable REIT subsidiary, Corridor MoGas, executed a Purchase Agreement (the “MoGas Purchase Agreement”) with Mogas Energy, LLC (“Seller”) to acquire all of the equity interests of two entities, MoGas Pipeline, LLC ("MoGas") and United Property Systems, LLC ("UPS") (collectively, the "MoGas Transaction"). MoGas is the owner and operator of an approximately 263 mile interstate natural gas pipeline system in and around St. Louis and extending into central Missouri. The pipeline system, regulated by the Federal Energy Regulatory Commission ("FERC"), delivers natural gas to both investor-owned and municipal local distribution systems and has eight firm transportation customers. The pipeline system receives natural gas at three receipt points and delivers that natural gas at 22 delivery points. UPS owns 10.28 acres of real property that includes office and storage space which is leased to MoGas. A portion of that land is also leased to an operator of a small cement

21


plant owned by a third party. The combined purchase price of MoGas and UPS was $125 million, funded by a combination of equity proceeds and revolving credit facility, as further discussed in Note 14 to these Consolidated Financial Statements.
On November 17, 2014, the Company completed a follow-on equity offering of 14,950,000 shares of common stock, raising approximately $102 million in gross proceeds at $6.80 per share (net proceeds of approximately $96 million after underwriters' discount). Then on November 24, 2014, the Company borrowed $32 million (net proceeds of approximately $29 million after $3 million in fees). The total cash proceeds of $125 million were then used to capitalize Corridor MoGas, $90 million of which was in the form of a term note, who then concurrently used the cash to fund the purchase price to the Seller, $7 million of which, was placed in an indemnity escrow account. The Purchase Agreement describes the circumstances under which escrowed funds are to be released and the party to receive such released funds. Currently the Company has no reason to believe that any of the funds in escrow will be returned.
The Company is accounting for the acquisition under the acquisition method in accordance with ASC 805, Business Combinations (“ASC 805”), and the initial accounting for this business combination is final and complete. The Company's assessment of the fair values and the allocation of purchase price to the identified tangible and intangible assets is its best estimate of fair value. The following table summarizes the acquisition date fair values of the assets acquired and liabilities assumed, which the Company determined using Level 1, Level 2 and Level 3 inputs:
Acquisition Date Fair Values
 
Amount
Leased Property:
 
Land
$
210,000

Buildings and improvements
1,188,000

Total Leased Property
$
1,398,000

 
 
Property and Equipment:
 
Land
$
580,000

Depreciable property:
 
Natural Gas Pipeline
119,081,732

Vehicles and Trailers
378,000

Office Equipment
43,400

Total Property and Equipment
$
119,503,132

 
 
Goodwill
$
1,718,868

Cash and cash equivalents
4,098,274

Accounts receivable
1,357,905

Prepaid assets
125,485

Accounts payable and other accrued liabilities
(3,781,664
)
 
 
Net assets acquired
$
125,000,000

The fair values of land, depreciable property and goodwill were determined using internally developed models that were based on market assumptions and comparable transportation data as well as external valuations performed by unrelated third parties. The market assumptions used as inputs to the Company’s fair value model include replacement construction costs, leasing assumptions, growth rates, discount rates, terminal capitalization rates and transportation yields. The Company uses data on its existing portfolio of investments as well as similar market data from third party sources, when available, in determining these Level 3 inputs. The carrying value of cash and cash equivalents, accounts receivable, prepaid assets and accounts payable and other accrued liabilities, approximate fair value due to their short term, highly liquid nature.
Goodwill represents the excess of the purchase price over the fair value of the net assets acquired. Management believes that goodwill in the transaction results from various benefits. The pipeline system interconnects with three receipt points, the Panhandle Eastern, Rockies Express and Mississippi River Transmission Pipelines, which allows MoGas the flexibility to source natural gas from a variety of gas producing regions in the U.S. This advantageous position enhances operational efficiency, and allows MoGas customers to procure natural gas in times of peak demand and scarce supply. Two of the largest MoGas customers are also two large suppliers of natural gas for the St. Louis area. Additionally, the characteristics of the tangible assets and operations acquired in the MoGas Transaction are consistent with Company investment criteria and strategy. Some of these criteria include investments that are fixed asset intensive, with long depreciable lives, capable of providing stable cash flows due to limited commodity price

22


sensitivity, as well as experienced management teams capable of effectively and efficiently operating the assets now and through possible future growth opportunities. Goodwill related to this acquisition is deductible for income tax purposes.
Pro Forma Financial Information
For comparative purposes, the following table illustrates the effect on the Consolidated Statements of Income and Comprehensive Income as well as earnings per share - basic and diluted as if the Company had consummated the MoGas Transaction as of January 1, 2014:
 
Three months ended March 31, 2014
Total Revenue (1)
$
13,328,988

Total Expenses (2)
8,935,739

Operating Income
4,393,249

Other Income (Expense) (3)
(999,479
)
Tax Benefit (Expense) (4)
160,326

Net Income
3,554,096

Less: Net Income attributable to non-controlling interest
391,114

Net Income attributable to CORR Stockholders
$
3,162,982

Earnings per share:
 
Basic and Diluted
$
0.07

Weighted Average Shares of Common Stock Outstanding:
 
Basic and Diluted (5)
44,923,357

(1) Includes elimination adjustments for intercompany sales and rent.
(2) Includes adjustments for an increase in management fee payable, elimination of intercompany purchases and rent, depreciation, and other miscellaneous expenses.
(3) Includes adjustments for interest expense and other miscellaneous income.
(4) Includes an adjustment for a deferred tax benefit.
(5) Shares outstanding were adjusted for the November 17, 2014, follow-on equity offering mentioned above.
6. FINANCING NOTES RECEIVABLE     
Black Bison Financing Note Receivable
On March 13, 2014, our wholly-owned subsidiary, Corridor Bison, LLC ("Corridor Bison") entered into a Loan Agreement with Black Bison Water Services, LLC ("Black Bison WS"). Black Bison WS's initial loan draw in the amount of $4.3 million was used to acquire real property in Wyoming and to pay loan transaction expenses. Corridor Bison agreed to loan Black Bison WS up to $11.5 million (the "Black Bison Loan") to finance the acquisition and development of real property that will provide water sourcing, water disposal, or water treating and recycling services for the oil and natural gas industry.
On July 23, 2014, the Company increased its secured financing to Black Bison WS from $11.5 million to $15.3 million. The Company executed an amendment to the Loan Agreement to increase the loan to $12 million, and entered into an additional loan for $3.3 million from a taxable REIT subsidiary of the Company, CorEnergy BBWS, Inc. ("CorEnergy BBWS"), on substantially the same terms (the "TRS Loan" and, together with the Black Bison Loan, as amended, the "Loans"). The purpose of the increase in the secured financing was to fund the acquisition and development of real property and related equipment that will provide water sourcing, water disposal, or water treating and recycling services for the oil and natural gas industry. There were no other material changes to the terms of the loan agreement. In connection with the Amendment and the TRS Loan, the Company fully funded the remainder of the $15.3 million capacity of the combined Loans.
Interest initially accrues on the outstanding principal amount of both Loans at an annual base rate of 12 percent, which base rate will increase by 2 percent of the current base rate per year. In addition, starting in April 2015 and continuing for each month thereafter, the outstanding principal of the Loans will bear variable interest calculated as a function of the increase in volume of water treated by Black Bison WS during the particular month. The base interest plus variable interest, paid monthly, is capped at 19 percent per annum. The Loans mature on March 31, 2024 and are amortized by quarterly payments which were set to begin on March 31, 2015. Annual prepayments based upon free cash flows of the Borrower and its affiliates will commence in April 2015. The Loans are secured by the real property and equipment held by Black Bison WS and the outstanding equity in Black Bison WS and its affiliates. The Loans are also guarantied by all affiliates of Black Bison WS. Due to reduced drilling activity in Black Bison WS’s area of operations, Black Bison WS requested, and the Company has granted, a waiver of certain financial covenants. One of those waivers will remain in place through December 31, 2015. In addition, the Company has not yet received

23


the first amortization payment from Black Bison WS, which was due March 31, 2015. The Company has no reason to believe the notes receivable with Black Bison are not fully collectible as of March 31, 2015.
As a condition to the Black Bison Loan, Corridor Bison acquired a Warrant to purchase a number of equity units, which as of March 13, 2014 represented 15 percent of the outstanding equity of Black Bison Intermediate Holdings, LLC ("Intermediate Holdings"). Corridor Bison paid $34 thousand for the Warrant, which amount was determined to represent the fair value of the Warrant as of the date of purchase. Corridor Bison capitalized approximately $13 thousand in asset acquisition expenses in relation to the Warrant. The exercise price of the Warrant was $3.16 per unit. The exercise price increases at a rate of 12 percent per annum.
In anticipation of the July 2014 modifications to the Black Bison agreements described above, Corridor Bison assigned to CorEnergy BBWS its rights and obligations in the Warrant dated March 13, 2014. As a condition of the TRS Loan, the parties entered into an Amended and Restated Warrant, pursuant to which the amount available to purchase thereunder was increased to a number of equity units, which as of July 23, 2014 represented 18.72 percent of the outstanding equity of Intermediate Holdings. CorEnergy BBWS paid an additional $51 thousand for this increase in the amount that could be purchased pursuant to the Amended and Restated Warrant. CorEnergy BBWS capitalized $25 thousand in asset acquisition expenses in relation to the Warrant. Including capitalized asset acquisition costs, the Company paid approximately $123 thousand for the Warrant, which is fair valued at $125 thousand as of March 31, 2015. The amount paid was determined to be the current value of the incremental amount that could be purchased under the Amended and Restated Warrant. Furthermore, the warrant qualifies as a derivative, with all changes in fair value reflected in the consolidated statements of income and comprehensive income in the current period.

Four Wood Financing Note Receivable

On December 31, 2014, our wholly-owned subsidiary, Four Wood Corridor, LLC (“Four Wood Corridor”), entered into a Loan Agreement with SWD Enterprises, LLC (“SWD Enterprises”), a wholly-owned subsidiary of Four Wood Energy, pursuant to which Four Wood Corridor made a loan to SWD Enterprises for $4.0 million. Concurrently, our TRS, Corridor Private entered into a TRS Loan Agreement with SWD Enterprises, pursuant to which Corridor Private made a loan to SWD Enterprises for $1.0 million. The proceeds of the REIT loan and the TRS loan were used by SWD Enterprises and its affiliates to finance the acquisition of real and personal property that provides saltwater disposal services for the oil and natural gas industry, and to pay related expenses.
For the REIT loan from Four Wood Corridor, interest will initially accrue on the outstanding principal at an annual base rate of 12 percent. For the TRS loan from Corridor Private, interest will initially accrue on the outstanding principal at an annual base rate of 13 percent. The base rates of both loans will increase by 2 percent of the current base rate per year. In addition, for both loans, starting in January 2016 and continuing for each month thereafter, the outstanding principal of the Loans will bear variable interest calculated as a function of the increase in volume of water treated by SWD Enterprises during the particular month. The base interest plus variable interest, paid monthly, is capped at 19 percent per annum for the REIT loan and 20 percent per annum for the TRS Loan. The Loans mature on December 31, 2024, and are to be amortized by quarterly payments beginning March 31, 2016, and annual prepayments based upon free cash flows of the Borrower and its affiliates commencing on January 15, 2016. The Loans are secured by the real property and equipment held by SWD Enterprises and the outstanding equity in SWD Enterprises and its affiliates. The Loans are also guaranteed by all affiliates of SWD Enterprises. The Company believes the notes receivable with SWD Enterprises are fully collectible as of March 31, 2015.
7. VARIABLE INTEREST ENTITIES

The Company's variable interest in Variable Interest Entities ("VIE" or "VIEs") currently are in the form of equity ownership and loans provided by the Company to a VIE. The Company examines specific criteria and uses its judgment when determining if the Company is the primary beneficiary of a VIE and is therefore required to consolidate the investments. Factors considered in determining whether the Company is the primary beneficiary include risk- and reward-sharing, experience and financial condition of the other partner(s), voting rights, involvement in day-to-day capital and operating decisions, representation on a VIE's executive committee or Board of Directors, whether or not the Company has the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, existence of unilateral kick-out rights or voting rights, and level of economic disproportionality between the Company and the other partner(s).
Consolidated VIEs
As of March 31, 2015, the Company does not have any investments in VIEs that qualify for consolidation.

24


Unconsolidated VIE
At March 31, 2015, the Company's recorded investment in Black Bison WS and Intermediate Holdings, collectively a VIE that is unconsolidated, was $15.7 million. The Company's maximum exposure to loss associated with the investment is limited to the Company's outstanding notes receivable, related accrued interest receivable and the fair value of the Warrant, discussed in Note 6, totaling $15.7 million and $15.9 million as of March 31, 2015, and December 31, 2014, respectively. While this entity is a VIE, the Company has determined that the power to direct the activities of the VIE that most significantly impact the VIE's economic performance is not held by the Company, therefore the VIE is not consolidated.
8. INCOME TAXES
Deferred income taxes reflect the net tax effect of temporary differences between the carrying amount of assets and liabilities for financial reporting and tax purposes. Components of the Company’s deferred tax assets and liabilities as of March 31, 2015, and December 31, 2014, are as follows:
Deferred Tax Assets and Liabilities
 
 
March 31, 2015
 
December 31, 2014
Deferred Tax Assets:
 
 
 
 
Net operating loss carryforwards
 
$
(1,033,385
)
 
$
(679,692
)
Cost recovery of leased and fixed assets
 
(795,444
)
 
(1,042,207
)
Sub-total
 
$
(1,828,829
)
 
$
(1,721,899
)
Deferred Tax Liabilities:
 
 
 
 
Basis reduction of investment in partnerships
 
$
2,661,415

 
$
2,842,332

Net unrealized gain on investment securities
 
314,610

 
142,154

Sub-total
 
2,976,025

 
2,984,486

Total net deferred tax liability
 
$
1,147,196

 
$
1,262,587

For the quarter ended March 31, 2015, the total deferred tax liability presented above relates to assets held in the Company's TRSs. The Company recognizes the tax benefits of uncertain tax positions only when the position is “more likely than not” to be sustained upon examination by the tax authorities based on the technical merits of the tax position. The Company’s policy is to record interest and penalties on uncertain tax positions as part of tax expense. Tax years subsequent to the year ending November 30, 2007, remain open to examination by federal and state tax authorities.
Total income tax expense differs from the amount computed by applying the federal statutory income tax rate of 35 percent for the three months ended March 31, 2015, and March 31, 2014, to income or loss from operations and other income and expense for the years presented, as follows:
Income Tax Expense (Benefit)
 
 
For the Three Months Ended
 
 
March 31, 2015
 
March 31, 2014
Application of statutory income tax rate
 
$
1,553,434

 
$
918,346

State income taxes, net of federal tax benefit
 
37,051

 
42,979

Federal Tax Attributable to Income of Real Estate Investment Trust
 
(1,270,120
)
 
(447,812
)
Total income tax expense
 
$
320,365

 
$
513,513

Total income taxes are computed by applying the federal statutory rate of 35 percent plus a blended state income tax rate, which was approximately 3.92 percent for the three months ended March 31, 2015 and 3.11 percent for the three months ended March 31, 2014. CorEnergy BBWS does not record a provision for state income taxes because it operates only in Wyoming, which does not have state income tax. Because and MoGas primarily only operate in the state of Missouri, a blended state income tax rate of 5 percent was used for the operations of our Mowood Corridor, Inc. and MoGas TRSs for the three months ended March 31, 2015 and 2014. The restructuring done in December 2012 causes us to hold and operate certain of our assets through one or more TRSs. A TRS is a subsidiary of a REIT that is subject to applicable corporate income tax. For the three months ended March 31, 2015, all of the income tax expense presented above relates to the assets and activities held in the Company's TRSs. The components of income tax expense include the following for the periods presented:

25


Components of Income Tax Expense (Benefit)
 
 
For the Three Months Ended
 
 
March 31, 2015
 
March 31, 2014
Current tax expense
 
 
 
 
Federal
 
$
391,946

 
$
784,377

State (net of federal tax benefit)
 
43,810

 
69,698

Total current tax expense
 
435,756

 
854,075

Deferred tax benefit
 
 
 
 
Federal
 
(108,632
)
 
(313,843
)
State (net of federal tax benefit)
 
(6,759
)
 
(26,719
)
Total deferred tax benefit
 
(115,391
)
 
(340,562
)
Total income tax expense, net
 
$
320,365

 
$
513,513

As of December 31, 2014, the TRSs had a net operating loss of $1.7 million. The net operating loss may be carried forward for 20 years. If not utilized, this net operating loss will expire in the year ending December 31, 2033 and 2034. For the three months ended March 31, 2015, the TRSs incurred a total net operating loss of approximately $882 thousand, resulting in a total net operating loss of approximately $2.6 million.
The aggregate cost of securities for federal income tax purposes and securities with unrealized appreciation and depreciation, were as follows:
Aggregate Cost of Securities for Income Tax Purposes
 
 
March 31, 2015
 
December 31, 2014
Aggregate cost for federal income tax purposes
 
$
5,152,653

 
$
4,218,986

Gross unrealized appreciation
 
7,649,287

 
7,436,696

Net unrealized appreciation
 
$
7,649,287

 
$
7,436,696

9. PROPERTY AND EQUIPMENT
Property and equipment consists of the following:
Property and Equipment
 
 
March 31, 2015
 
December 31, 2014
Land
 
$
580,000

 
$
580,000

Natural gas pipeline
 
124,313,621

 
124,297,157

Vehicles and trailers
 
506,958

 
506,958

Office equipment and computers
 
59,027

 
59,027

Gross property and equipment
 
125,459,606

 
125,443,142

Less: accumulated depreciation
 
(3,455,219
)
 
(2,623,020
)
Net property and equipment
 
$
122,004,387

 
$
122,820,122


The amounts of depreciation of property and equipment recognized for the three months ended March 31, 2015 and 2014, were $832 thousand and $71 thousand, respectively.
10. CONCENTRATIONS
Mowood, Omega
Omega had a ten-year agreement (the "DOD Agreement") with the Department of Defense (“DOD”) to provide natural gas and gas distribution services to Fort Leonard Wood. The DOD Agreement expired January 31, 2015. On January 28, 2015, the DOD awarded Omega a 6 month bridge agreement with very similar terms and conditions as the original agreement for Omega to continue providing natural gas and gas distribution services until a new 10 year agreement is reached.

26


Revenue related to the DOD contract accounted for 91 percent of our sales revenue for each of the three months ended March 31, 2015 and 2014. Omega performs management and supervision services related to the expansion of the natural gas distribution system used by the DOD. The amount due from the DOD accounts for 94 percent and 88 percent of the consolidated accounts receivable balances as of March 31, 2015, and December 31, 2014, respectively.
Omega’s contracts for its supply of natural gas are concentrated among select providers. Purchases from its largest supplier of natural gas accounted for 96 percent of our cost of sales for the three months ended March 31, 2015. This compares to 77 percent for the three months ended March 31, 2014.
MoGas
MoGas generates revenue from the transportation of natural gas to a concentrated group of customers. Transportation revenue relating to MoGas' largest customer accounted for 66 percent of the contracted capacity for three months ended March 31, 2015.
11. MANAGEMENT AGREEMENT
On December 1, 2011, the Company executed a Management Agreement with Corridor InfraTrust Management, LLC (“Corridor”). Under the Management Agreement, Corridor (i) presents the Company with suitable acquisition opportunities consistent with the investment policies and objectives of the Company, (ii) is responsible for the day-to-day operations of the Company, and (iii) performs such services and activities relating to the assets and operations of the Company as may be appropriate. A new Management Agreement between the Company and Corridor was approved by the Board of Directors and became effective July1, 2013. The new agreement did not change in any respect the terms for determination or payment of compensation for the Manager, does not have a specific term, and will remain in place unless terminated by the Company or the Manager in the manner permitted pursuant to the agreement. The new management agreement was amended as of January 1, 2014, to change the methodology for calculating the quarterly management fee.
The terms of the Management Agreement include a quarterly management fee equal to 0.25 percent (1.00 percent annualized) of the value of the Company’s Managed Assets as of the end of each quarter. For purposes of the Management Agreement, “Managed Assets” means the total assets of the Company (including any securities receivables, other personal property or real property purchased with or attributable to any borrowed funds) minus (A) the initial invested value of all non-controlling interests, (B) the value of any hedged derivative assets, (C) any prepaid expenses, and (D) all of the accrued liabilities other than (1) deferred taxes and (2) debt entered into for the purpose of leverage. For purposes of the definition of Managed Assets, the Company’s securities portfolio will be valued at then current market value. For purposes of the definition of Managed Assets, other personal property and real property assets will include real and other personal property owned and the assets of the Company invested, directly or indirectly, in equity interests in or loans secured by real estate or personal property (including acquisition related costs and acquisition costs that may be allocated to intangibles or are unallocated), valued at the aggregate historical cost, before reserves for depreciation, amortization, impairment charges or bad debts or other similar noncash reserves. See additional discussion regarding changes to the Management Agreement in Note 20, Subsequent Events.
The Management Agreement also includes a quarterly incentive fee of 10 percent of the increase in distributions paid over a threshold distribution equal to $0.125 per share per quarter. The Management Agreement also requires at least half of any incentive fees to be reinvested in the Company’s common stock.
The Company pays Corridor, as the Company's Administrator pursuant to an Administrative Agreement, a fee equal to an annual rate of 0.04 percent of aggregate average daily managed assets, with a minimum annual fee of $30 thousand.
Tortoise Capital Advisors, L.L.C. (“TCA”) is compensated by Corridor to provide investment services related to the monitoring and disposition of our current securities portfolio.

27


12. FAIR VALUE OF OTHER SECURITIES
The inputs or methodology used for valuing securities are not necessarily an indication of the risk associated with investing in those securities. The following tables provide the fair value measurements of applicable Company assets and liabilities by level within the fair value hierarchy as of March 31, 2015, and December 31, 2014. These assets and liabilities are measured on a recurring basis.
March 31, 2015
 
 
March 31, 2015
 
Fair Value
 
 
 
Level 1
 
Level 2
 
Level 3
Assets:
 
 
 
 
 
 
 
 
Other equity securities
 
$
10,363,438

 
$

 
$

 
$
10,363,438

Total Assets
 
$
10,363,438

 
$

 
$

 
$
10,363,438

December 31, 2014
 
 
December 31, 2014
 
Fair Value
 
 
 
Level 1
 
Level 2
 
Level 3
Assets:
 
 
 
 
 
 
 
 
Other equity securities
 
9,572,181

 

 

 
9,572,181

Total Assets
 
$
9,572,181

 
$

 
$

 
$
9,572,181

The changes for all Level 3 securities measured at fair value on a recurring basis using significant unobservable inputs for the three months ended March 31, 2015 and 2014, are as follows:
Level 3 Rollforward
For The Three Months Ended March 31, 2015
 
Fair Value Beginning Balance
 
Acquisitions
 
Disposals
 
Total Realized and Unrealized Gains Included in Net Income
 
Return of Capital Adjustments Impacting Cost Basis of Securities
 
Fair Value Ending Balance
 
Changes in Unrealized Gains, Included In Net Income, Relating to Securities Still Held (1)
Other equity securities
 
$
9,217,181

 
$

 

 
$
679,798

 
$
341,459

 
$
10,238,438

 
$
679,798

Warrant investment
 
355,000

 

 

 
(230,000
)
 

 
125,000

 
(230,000
)
Total
 
$
9,572,181

 
$

 
$

 
$
449,798

 
$
341,459

 
$
10,363,438

 
$
449,798

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
For The Three Months Ended March 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other equity securities
 
$
23,304,321

 
$

 
$

 
$
1,294,182

 
$
(491,260
)
 
$
24,107,243

 
$
1,294,182

Total
 
$
23,304,321

 
$

 
$

 
$
1,294,182

 
$
(491,260
)
 
$
24,107,243

 
$
1,294,182

(1) Located in Net realized and unrealized gain on other equity securities in the Consolidated Statements of Income
The Company utilizes the beginning of reporting period method for determining transfers between levels. There were no transfers between levels 1, 2 or 3 for the three months ended March 31, 2015, and March 31, 2014.
In accordance with ASC 820, the Company fair values their derivative financial instruments. Please refer to Note 15, Interest Rate Hedge Swaps, for more information.
Valuation Techniques and Unobservable Inputs
The Company’s other equity securities, which represent securities issued by private companies, are classified as Level 3 assets. Significant judgment is required in selecting the assumptions used to determine the fair values of these investments. See Note 2, Significant Accounting Policies, for additional discussion.
For the three months ended March 31, 2015, the Company’s Warrant Investment was valued using a binomial option pricing model. The key assumptions used in the binomial model are the fair value of equity of the underlying business; the Warrant's strike price; the expected volatility of equity; the time to the Warrant's expiry; the risk-free rate, and the expected dividend yields. Due to the inherent uncertainty of determining the fair value of the Warrant Investment, which does not have a readily available market, the assumptions used the binomial model to value the Company’s Warrant Investment were based on Level 2 and Level 3 inputs.

28


These inputs, including the expected volatility and the fair value of equity of the underlying business, may vary significantly from period-to-period, and accordingly, the fair value as of March 31, 2015 may differ materially from the amount that the Company may ultimately realize.
At March 31, 2014, the Company’s investments in private companies were valued using one or a combination of the following valuation techniques: (i) analysis of valuations for publicly traded companies in a similar line of business (“public company analysis”), (ii) analysis of valuations for comparable M&A transactions (“M&A analysis”) and (iii) discounted cash flow analysis.
The public company analysis utilizes valuation multiples for publicly traded companies in a similar line of business as the portfolio company to estimate the fair value of such investment. Typically, the Company’s analysis focuses on the ratio of enterprise value to earnings before interest expense, income tax expense, depreciation and amortization (“EBITDA”) which is commonly referred to as an EV/EBITDA multiple. The Company selects a range of multiples given the trading multiples of similar publicly traded companies and applies such multiples to the portfolio company’s EBITDA to estimate the portfolio company’s trailing, proforma, projected or average (as appropriate) EBITDA to estimate the portfolio company’s enterprise value and equity value. The Company also selects a range of trading market yields of similar public companies and applies such yields to the portfolio company’s estimated distributable cash flow. When calculating these values, the Company applies a discount, when applicable, to the portfolio company’s estimated equity value for the size of the company and the lack of liquidity in the portfolio company’s securities. The M&A analysis utilizes valuation multiples for historical M&A transactions for companies or assets in a similar line of business as the portfolio company to estimate the fair value of such investment. Typically, the Company’s analysis focuses on EV/EBITDA multiples. The Company selects a range of multiples based on EV/EBITDA multiples for similar M&A transactions or similar companies and applies such ranges to the portfolio company’s analytical EBITDA to estimate the portfolio company’s enterprise value.
The discounted cash flow ("DCF") analysis is used to estimate the equity value for the portfolio company based on estimated DCF of such portfolio company. Such cash flows include an estimate of terminal value for the portfolio company. A present value of these cash flows is determined by using estimated discount rates (based on the Company’s estimate for weighted average cost of capital for such portfolio company).
Under all of these valuation techniques, the Company estimated operating results of its portfolio companies (including EBITDA). These estimates utilize unobservable inputs such as historical operating results, which may be unaudited, and projected operating results, which were based on expected operating assumptions for such portfolio company. The Company also consulted with management of the portfolio companies to develop these financial projections. These estimates were sensitive to changes in assumptions specific to such portfolio company as well as general assumptions for the industry. Other unobservable inputs utilized in the valuation techniques outlined above include: possible discounts for lack of marketability, selection of publicly-traded companies, selection of similar M&A transactions, selected ranges for valuation multiples, selected range of yields and expected required rates of return and weighted average cost of capital. The various inputs were weighted as appropriate, and other factors may have been weighted into the valuation, including recent capital transactions of the Company.
Changes in EBITDA multiples, or discount rates may change the fair value of the Company’s portfolio investments. Generally, a decrease in EBITDA multiples or DCF multiples, or an increase in discount rates, when applicable, may result in a decrease in the fair value of the Company’s portfolio investments.
Quantitative Table for Valuation Techniques Used as of March 31, 2014
The following table summarizes the significant unobservable inputs that the Company used to value its portfolio investments categorized as Level 3 as of March 31, 2014:

29


Significant Unobservable Inputs Used To Value Portfolio Investments
March 31, 2014
 
 
 
 
 
 
Unobservable Inputs
 
Range
 
Weighted Average
Assets at Fair Value
 
Fair Value
 
Valuation Technique
 
 
Low
 
High
 
Other equity securities, at fair value
 
$
24,107,243

 
Public company historical EBITDA analysis
 
Historical EBITDA Valuation Multiples
 
9.6x
 
10.6x
 
10.1x
 
 
 
 
Public company projected EBITDA analysis
 
Projected EBITDA Valuation Multiples
 
8.3x
 
9.3x
 
8.8x
 
 
 
 
M&A company analysis
 
EV/LTM 2012 EBITDA
 
8.3x
 
9.3x
 
8.8x
 
 
 
 
Discounted cash flow
 
Weighted Average Cost of Capital
 
9.5x
 
14.0%
 
11.8%
As of March 31, 2015, the Company’s investment in Lightfoot is its only remaining private company investment. Lightfoot in turn owns a combination of public and private investments. Therefore Lightfoot was valued using a combination of the following valuation techniques: (i) public share price of private companies' investments discounted for a lack of marketability, with the discount estimated at 16.6 percent to 21.3 percent and (ii) discounted cash flow analysis using an estimated discount rate of 12.0 percent to 14.0 percent. Due to the inherent uncertainty of determining the fair value of investments that do not have a readily available market value, the fair value of the Company’s investment may fluctuate from period to period. Additionally, the fair value of the Company’s investment may differ from the values that would have been used had a ready market existed for such investment and may differ materially from the values that the Company may ultimately realize.
As of both March 31, 2015 and March 31, 2014, the Company held a 6.7 percent equity interest in Lightfoot. As of March 31, 2014, the Company held a 11.1 percent equity interest in Vantacore.
Certain condensed combined financial information of the unconsolidated affiliate, Lightfoot, is presented in the following tables (in thousands).
 
 
March 31, 2015
 
December 31, 2014
Assets
 
 
 
 
Current assets
 
$
21,854

 
$
25,783

Noncurrent assets
 
382,670

 
382,957

Total Assets
 
$
404,524

 
$
408,740

Liabilities
 
 
 
 
Current liabilities
 
$
14,099

 
$
14,318

Noncurrent liabilities
 
114,008

 
113,810

Total Liabilities
 
$
128,107

 
$
128,128

 
 
 
 
 
Partner's equity
 
276,417

 
280,612

Total liabilities and partner's equity
 
$
404,524

 
$
408,740

 
 
For The Three Months Ended
 
 
March 31, 2015
 
March 31, 2014
Revenues
 
$
13,557

 
$
13,213

Operating expenses
 
15,128

 
13,584

Other income (expenses)
 
3,834

 
3,770

Net income
 
$
2,263

 
$
3,399

 
 
 
 
 
EBITDA
 
$
8,034

 
$
7,500


The following section describes the valuation methodologies used by the Company for estimating fair value for financial instruments not recorded at fair value, but fair value is included for disclosure purposes only, as required under disclosure guidance related to the fair value of financial instruments.

30


Cash and Cash Equivalents — The carrying value of cash, amounts due from banks, federal funds sold and securities purchased under resale agreements approximates fair value.
Escrow Receivable — The escrow receivable due to the Company as of March 31, 2015, which relates to the sale of VantaCore, is anticipated to be released upon satisfaction of certain post-closing obligations and the expiration of certain time periods (50 percent to be released 12 months after the October 1, 2014 closing date (i.e. October 1, 2015), and the other 50 percent released 18 months after close (i.e. April 1, 2016)). The fair value of the escrow receivable is reflected net of a discount for the potential that the full amount due to the Company would not be realized.
Financing Notes Receivable — Based on the interest rates for similar financial instruments, the carrying value of the financing notes receivable are considered to approximate fair value.
Long-term Debt — The fair value of the Company’s long-term debt is calculated, for disclosure purposes, by discounting future cash flows by a rate equal to the expected market rate for an equivalent transaction.
Line of Credit — The carrying value of the line of credit approximates the fair value due to its short-term nature.
Carrying and Fair Value Amounts
 
 
 
 
 
 
 
 
 
 
 
 
Level within fair value hierarchy
 
March 31, 2015
 
December 31, 2014
 
 
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Financial Assets:
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
Level 1
 
$
26,634,586

 
$
26,634,586

 
$
7,578,164

 
$
7,578,164

Escrow receivable
 
Level 2
 
$
2,438,500

 
$
2,438,500

 
$
2,438,500

 
$
2,438,500

Financing notes receivable
 
Level 2
 
$
20,881,295

 
$
20,881,295

 
$
20,687,962

 
$
20,687,962

Financial Liabilities:
 
 
 
 
 
 
 
 
Long-term debt
 
Level 2
 
$
66,178,000

 
$
66,178,000

 
$
67,060,000

 
$
67,060,000

Line of credit
 
Level 2
 
$
565,583

 
$
565,583

 
$
32,141,277

 
$
32,141,277

13. INTANGIBLES
The Company recorded an intangible lease asset, related to the PNM Lease Agreement, for the fair value of the amount by which the remaining contractual lease payments exceed market lease rates at the time of acquisition. The intangible lease asset was being amortized on a straight-line basis over the life of the lease term, which expired on April 1, 2015. Quarterly amortization of the intangible lease asset totaling $73 thousand for each of the three-month periods ended March 31, 2015, and March 31, 2014, is reflected in the accompanying Consolidated Statements of Income as a reduction to lease revenue. These same amounts are included in Amortization expense in the accompanying Consolidated Statements of Cash Flows. Refer to Note 4 for further discussion around the PNM Purchase Agreement.
Intangible Lease Asset
 
 
March 31, 2015
 
December 31, 2014
Intangible lease asset
 
$
1,094,771

 
$
1,094,771

Accumulated amortization
 
(1,094,771
)
 
(1,021,784
)
Net intangible lease asset
 
$


$
72,987


31


14. CREDIT FACILITIES
Pinedale Facility
On December 20, 2012, Pinedale LP closed on a $70 million secured term credit facility with KeyBank serving as a lender and as administrative agent on behalf of other lenders participating in the credit facility. Outstanding balances under the KeyBank Term Facility will generally accrue interest at a variable annual rate equal to LIBOR plus 3.25 percent (3.43 percent as of March 31, 2015). The credit facility will remain in effect through December 31, 2015, with an option to extend through December 31, 2016. The credit facility is secured by the Pinedale LGS. Pinedale LP is obligated to pay all accrued interest monthly and is further obligated to make monthly principal payments, which began on March 7, 2014, in the amount of $294 thousand or 0.42 percent of the principal balance as of March 1, 2014. Principal payments totaling approximately $3.5 million are required in 2015. In the event the Company exercises its option to extend the term an additional year, principal payments totaling $3.5 million would be required in 2016 with the remaining principal balance due at maturity. The registrant has provided to KeyBank a guarantee against certain inappropriate conduct by or on behalf of Pinedale LP or us. The credit agreement contains, among other restrictions, specific financial covenants including the maintenance of certain financial coverage ratios and a minimum net worth requirement. The Company is required to maintain a restricted collateral account into which Ultra Wyoming makes all lease payments under the Pinedale Lease Agreement. Payments of principal and interest pursuant to the credit facility are drawn by KeyBank directly from the restricted collateral account prior to transferring the remaining cash to the Pinedale LP operating account. The balance in the restricted collateral account at March 31, 2015 was $0. As of March 31, 2015, Pinedale LP was in compliance with all of the financial covenants of the secured term credit facility.
Pinedale LP's credit facility with KeyBank limits distributions by Pinedale LP to the Company. Distributions by Pinedale LP to the Company are permitted to the extent required for the Company to maintain its REIT qualification, so long as Pinedale LP's obligations to KeyBank have not been accelerated following an Event of Default (as defined in the credit facility).  The KeyBank Term Facility also requires that Pinedale LP maintain minimum net worth levels and certain leverage ratios, which along with other provisions of the credit facility limit cash dividends and loans to the Company.  At March 31, 2015, the net assets of Pinedale LP were $141.7 million.
As of March 31, 2015 and December 31, 2014, approximately $371 thousand and $501 thousand, respectively, in net deferred debt issuance costs related to the KeyBank Term Facility are included in the accompanying Consolidated Balance Sheets. The deferred costs will be amortized over the anticipated three-year term of the KeyBank Term Facility. For each of the three months ended March 31, 2015 and 2014, respectively, $129 thousand is included in interest expense within the accompanying Consolidated Statements of Income.
The Company has executed interest rate swap derivatives to add stability to our interest expense and to manage our exposure to interest rate movements on our LIBOR based borrowings. Interest rate swaps involve the receipt of variable-rate amounts from a counterparty in exchange for us making fixed-rate payments over the life of the agreements without exchange of the underlying notional amount. See Note 15 for further information regarding interest rate swap derivatives.
Additional Credit Facilities of the REIT
On September 26, 2014, the Company entered into a $30 million revolving credit facility (the "Regions Revolver") with certain lenders and Regions Bank, as an agent for such lenders, then on November 24, 2014, increased the credit facility, to $90 million in conjunction with the MoGas Transaction. There were no borrowings on the line between September 26, 2014, and November 24, 2014. The facility has a maturity of November 24, 2018. For the first six months, subsequent to the increase, the facility will bear interest on the outstanding balance at a rate of LIBOR plus 3.50 percent. On and after May 24, 2015, the interest rate will be determined by a pricing grid where the applicable interest rate is anticipated to be LIBOR plus 2.75 percent to 3.50 percent, depending on the company's leverage ratio at such time.
As of March 31, 2015, and December 31, 2014, approximately $1.2 million and $1.3 million, respectively, in net deferred debt issuance costs related to the Regions Revolver are included in the accompanying Consolidated Balance Sheets. For the three months ended March 31, 2015 and 2014, approximately $190 thousand and $0, respectively, is included in interest expense within the accompanying Consolidated Statements of Income. On January 28, 2015, the Company extinguished the outstanding balance on the Regions Revolver, leaving a $0 balance. As of March 31, 2015, the Company was in compliance of all covenants of the Regions Revolver.



32


On May 8, 2013, the Company entered into a $20 million revolving line of credit with KeyBank. The primary term of the facility was three years with the option for a one-year extension. Outstanding balances under the revolving credit facility (the "KeyBank Revolver") accrued interest at a variable annual rate equal to LIBOR plus 4.0 percent or the Prime Rate plus 2.75 percent. The facility was for the purpose of funding general working capital needs and if necessary, to provide short-term financing for the acquisition of additional real property assets. The amount available to be drawn under this facility was subject to a borrowing base limitation. The agreement was terminated on September 26, 2014.
As of March 31, 2015, and December 31, 2014, approximately $0 in net deferred debt issuance costs, related to the KeyBank Revolver, are included in the accompanying Consolidated Balance Sheets. The deferred costs were initially amortized over the anticipated four-year term of the Key Bank Revolver facility. For the three months ended March 31, 2015 and 2014, $0 and $16 thousand, respectively, is included in interest expense within the accompanying Consolidated Statements of Income. Upon termination, the remaining unamortized deferred debt issuance costs totaling approximately $161 thousand were expensed in full.
MoGas Credit Facility
In conjunction with the MoGas Transaction, MoGas and UPS, as co-borrowers, entered into a revolving credit agreement dated November 24, 2014 (the “MoGas Revolver”), with certain lenders, including Regions Bank as agent for such lenders. Pursuant to the MoGas Revolver, the co-borrowers may borrow, prepay and reborrow loans up to $3.0 million outstanding at any time. Interest accrues under the MoGas Revolver at the same rate and pursuant to the same terms as it accrues under the Regions Revolver. As of March 31, 2015, there were no outstanding borrowings against the MoGas Revolver. As of March 31, 2015, the co-borrowers are in compliance of all covenants of the MoGas Revolver.
Mowood/Omega Credit Facility
On October 15, 2013, Mowood and Omega entered into a new Revolving Note Payable Agreement (“2013 Note Payable Agreement”), replacing a prior $1.3 million secured Note Payable Agreement (as amended), under which interest accrued and was payable monthly at LIBOR plus 4.00 percent and which expired on October 29, 2013. The 2013 Note Payable Agreement had a maximum borrowing base of $1.5 million. Borrowings on the 2013 Note Payable Agreement are secured by Mowood’s and Omega's assets. Interest accrued at the Prime Lending Rate as published in the Wall Street Journal, plus 0.5 percent (3.75% as of March 31, 2015), was payable monthly, and in full, with accrued interest, on the termination date of October 15, 2014.

On October 15, 2014, Mowood and Omega renewed the 2013 Note Payable Agreement by entering into a Revolving Note Payable Agreement ("2014 Note Payable Agreement"), extending the maturity date to January 31, 2015. Then on January 30, 2015, Mowood and Omega modified the 2014 Note Payable Agreement to extend the maturity date to July 31, 2015. The 2014 Note Payable Agreement has the same terms as the 2013 Note Payable Agreement and includes an unused credit line fee of 20 basis points per month. As of March 31, 2015, there were $566 thousand in outstanding borrowings under the 2014 Note Payable Agreement. The 2014 Note Payable Agreement contains various restrictive covenants, with the most significant relating to minimum consolidated fixed charge ratio, the incidence of additional indebtedness, member distributions, extension of guaranties, future investments in other subsidiaries and change in ownership. Mowood and Omega were in compliance with the various covenants of the 2014 Note Payable Agreement as of March 31, 2015.
15. INTEREST RATE HEDGE SWAPS
Derivative Financial Instruments
Currently, the Company uses interest rate swaps to manage its interest rate risk. The valuation of these instruments is determined using widely accepted valuation techniques including discounted cash flow analysis on the expected cash flows of each derivative. This analysis reflects the contractual terms of the derivatives, including the period to maturity, and uses observable market-based inputs, including forward interest rate curves. The fair values of interest rate swaps are determined using the market standard methodology of netting the discounted future fixed cash payments and the discounted expected variable cash receipts.  The variable cash receipts are based on an expectation of future interest rates (forward curves) derived from observable market interest rate forward curves.
To comply with the provisions of ASC 820, the Company incorporates credit valuation adjustments to appropriately reflect both its own nonperformance risk and the respective counterparty's nonperformance risk in the fair value measurements. In adjusting the fair value of its derivative contracts for the effect of nonperformance risk, the Company has considered the impact of netting and any applicable credit enhancements, such as collateral postings, thresholds, mutual puts, and guarantees. In conjunction with the FASB's fair value measurement guidance in ASC 820, the Company made an accounting policy election to measure the credit risk of its derivative financial instruments that are subject to master netting agreements on a net basis by counterparty portfolio.

33


Although the Company has determined that the majority of the inputs used to value its derivatives fall within Level 2 of the fair value hierarchy, the credit valuation adjustments associated with its derivatives utilize Level 3 inputs, such as estimates of current credit spreads to evaluate the likelihood of default by itself and its counterparties. However, as of March 31, 2015, the Company has assessed the significance of the impact of the credit valuation adjustments on the overall valuation of its derivative positions and has determined that the credit valuation adjustments are not significant to the overall valuation of its derivatives. As a result, the Company has determined that its derivative valuations in their entirety are classified in Level 2 of the fair value hierarchy.
The table below presents the Company's hedged derivative asset measured at fair value on a recurring basis as well as their classification on the Consolidated Balance Sheets as of March 31, 2015 and December 31, 2014, aggregated by the level in the fair value hierarchy within which those measurements fall. Hedges that are valued as receivable by the Company are considered Asset Derivatives and those that are valued as payable by the Company are considered Liability Derivatives.
Derivative Financial Instruments Measured At Fair Value on a Recurring Basis
 
 
Balance Sheet
Classification
 
 
Fair Value Hierarchy
Balance Sheet Line Item
 
 
 
Level 1
 
Level 2
 
Level 3
 
 
 
 
 
March 31, 2015
Hedged derivative asset
 
Assets
 
 
$

 
$
28,025

 
$

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2014
Hedged derivative asset
 
Assets
 
 
$

 
$
351,807

 
$

 
 
 
 
 
 
 
 
 
 
Level 1 – quoted prices in active markets for identical investments
Level 2 – other significant observable inputs (including quoted prices for similar investments, market corroborated inputs, etc.)
Level 3 – significant unobservable inputs (including the Company’s own assumptions in determining the fair value of investments)
Risk Management Objective of Using Derivatives
The Company is exposed to certain risk arising from both its business operations and economic conditions. The Company principally manages its exposures to a wide variety of business and operational risks through management of its core business activities. The Company manages economic risks, including interest rate, liquidity, and credit risk primarily by managing the amount, sources, and duration of its debt funding and the use of derivative financial instruments. Specifically, the Company enters into derivative financial instruments to manage exposures that arise from business activities that result in the receipt or payment of future known and uncertain cash amounts, the value of which are determined by interest rates. The Company's derivative financial instruments are used to manage differences in the amount, timing, and duration of the Company's known or expected cash receipts and its known or expected cash payments principally related to the Company's investments and borrowings.
Cash Flow Hedges of Interest Rate Risk
The Company's objectives in using interest rate derivatives are to add stability to interest expense and to manage its exposure to interest rate movements. To accomplish this objective, the Company primarily uses interest rate swaps and caps as part of its interest rate risk management strategy. Interest rate swaps designated as cash flow hedges involve the receipt of variable amounts from a counterparty in exchange for the Company making fixed-rate payments over the life of the agreements without exchange of the underlying notional amount.  Interest rate caps designated as cash flow hedges involve the receipt of variable amounts from a counterparty if interest rates rise above the strike rate on the contract in exchange for an upfront premium.
The effective portion of changes in the fair value of derivatives designated and that qualify as cash flow hedges is recorded in Accumulated Other Comprehensive Income (“AOCI”) and is subsequently reclassified into earnings in the period that the hedged forecasted transaction affects earnings. The Company elected to designate its interest rate swaps as cash flow hedges in April 2013. During the three months ended March 31, 2015, such derivatives were used to hedge the variable cash flows associated with existing variable-rate debt. The ineffective portion of the change in fair value of the derivatives is recognized directly in earnings. During the three months ended March 31, 2015, there was a loss due to ineffectiveness of approximately $1 thousand recorded in earnings. Ineffectiveness resulted from interest rate swaps that did not have a fair value of zero at inception of the hedging relationship. During the three months ended March 31, 2014, there was a loss due to ineffectiveness of approximately $170 recorded in earnings.
Amounts reported in AOCI related to derivatives will be reclassified to interest expense as interest payments are made on the Company's variable-rate debt. Over the next 12 months, the Company estimates that an additional $201 thousand will be reclassified as an increase to interest expense.

34


As of March 31, 2015, the Company had the following outstanding interest rate derivatives that were designated as cash flow hedges of interest rate risk:
Outstanding Derivatives Designated as Cash Flow Hedges of Interest Rate Risk
Interest Rate Derivative
 
Number of Instruments
 
Notional Amount Outstanding
 
 
 
 
 
Floating Rate Received
 
Fixed Rate Paid
 
 
 
Effective Date
 
Termination Date
 
 
Interest Rate Swap
 
2
 
$52,500,000
 
February 5, 2013
 
December 5, 2017
 
1-month US Dollar LIBOR
 
0.865%
Non-Designated Hedges
Derivatives not designated as hedges are not speculative and are used to manage the Company's exposure to interest rate movements and other identified risks. Changes in the fair value of derivatives not designated in hedging relationships are recorded directly in earnings and were equal to net losses of approximately $0 for the three months ended March 31, 2015, and March 31, 2014, respectively.
Tabular Disclosure of the Effect of Derivative Instruments on the Income Statement
The tables below present the effect of the Company's derivative financial instruments on the Income Statement for the three months ended March 31, 2015, and March 31, 2014.
 
For The Three Months Ended
Derivatives in Cash Flow Hedging Relationship
March 31, 2015
March 31, 2014
Amount of Gain (Loss) Recognized in AOCI on Derivative (Effective Portion)
$
(414,082
)
$
(161,889
)
Amount of Gain (Loss) Reclassified from AOCI on Derivatives (Effective Portion) Recognized in Net Income1
(73,420
)
(74,758
)
Amount of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion, Amounts Excluded from Effectiveness Testing)1
(779
)
(170
)
(1) Included in "Interest Expense" on the face of the Income Statement
 
 
Tabular Disclosure of Offsetting Derivatives
The table below presents a gross presentation, the effects of offsetting, and a net presentation of the Company's derivatives as of March 31, 2015, and December 31, 2014. The net amounts of derivative assets or liabilities can be reconciled to the tabular disclosure of fair value. The tabular disclosure of fair value provides the location that derivative assets and liabilities are presented on the Balance Sheets. There were no offsetting derivative liabilities as of March 31, 2015, and December 31, 2014.
Offsetting Derivatives
 
 
Gross Amounts of Recognized Assets
 
Gross Amounts Offset in the Balance Sheets
 
Net Amounts of Assets presented in the Balance Sheets
 
Gross Amounts Not
Offset in the Balance Sheet
 
 
 
 
 
 
 
 
 
 
 
 
 
Financial Instruments
 
Cash Collateral Received
 
Net Amount
Offsetting Derivative Assets as of March 31, 2015
 
$
28,025

 
$

 
$
28,025

 
$

 
$

 
$
28,025

 
 
 
 
 
 
 
 
 
 
 
 
 
Offsetting Derivative Assets as of December 31, 2014
 
$
351,807

 
$

 
$
351,807

 
$

 
$

 
$
351,807

Credit-Risk Related Contingent Features
The Company has agreements with some of its derivative counterparties that contain a provision where if the Company defaults on any of its indebtedness, including default where repayment of the indebtedness has not been accelerated by the lender, then the Company could also be declared in default on its derivative obligations.
As of March 31, 2015, the Company did not have any derivatives that were in a net liability position. Therefore, the credit risk-related contingent features discussed above would not apply as of March 31, 2015.

35


16. STOCKHOLDER'S EQUITY
PREFERRED STOCK
The Company's authorized preferred stock consists of 10 million shares having a par value of $0.001 per share. A description of the Company's only outstanding series of cumulative redeemable preferred stock is set forth below.
On January 27, 2015, the Company sold, in an underwritten public offering, 2,250,000 depositary shares, each representing 1/100th of a share of 7.375% Series A Cumulative Redeemable Preferred Stock ("Series A Preferred"). Pursuant to this offering, the Company issued 22,500 whole shares of Series A Preferred and received net cash proceeds of approximately $54.2 million. The depositary shares pay an annual dividend of $1.84375 per share, equivalent to 7.375% of the $25.00 liquidation preference. The depositary shares may be redeemed on or after January 27, 2020, at the Company’s option, in whole or in part, at the $25.00 liquidation preference plus all accrued and unpaid dividends to, but not including, the date of redemption. The depositary shares have no stated maturity, are not subject to any sinking fund or mandatory redemption and are not convertible into any other securities of the Company except in connection with certain changes of control. Holders of the depositary shares generally have no voting rights, except for limited voting rights if the Company fails to pay dividends for six or more quarters (whether or not consecutive) and in certain other circumstances. The depositary shares representing the Series A Preferred trade on the NYSE under the ticker “CORRPrA." The aggregate par value of the preferred shares at March 31, 2015 is $23. See Note 20, Subsequent Events, for further information regarding the declaration of a dividend on the 7.375% Series A Cumulative Redeemable Preferred Stock.
COMMON STOCK
As of March 31, 2015, the Company had 46,619,681of common shares issued and outstanding. See Note 20, Subsequent Events, for further information regarding the declaration of a dividend on the common stock.
SHELF REGISTRATION
On January 23, 2015, we had a new shelf registration statement declared effective by the SEC, pursuant to which we may publicly offer additional securities consisting of senior and/or subordinated debt securities, shares of preferred stock (or depositary shares representing fractional interests therein), shares of common stock, warrants or rights to purchase any of the foregoing securities, and units consisting of two or more of these classes or series of securities, with an aggregate offering price of up to $300.0 million. As of March 31, 2015, we had issued an aggregate of 10,142 shares of common stock under the Company’s dividend reinvestment plan that reduced availability under this new shelf registration by approximately $68 thousand, leaving remaining availability of approximately $299.9 million of maximum aggregate offering price of securities as of such date.
17. EARNINGS PER SHARE
The following table sets forth the computation of basic and diluted earnings per share:
Earnings Per Share
 
For The Three Months Ended
 
March 31, 2015
 
March 31, 2014
Net income attributable to CorEnergy stockholders
$
4,086,628

 
$
2,105,159

Less: preferred dividend requirements
737,500

 

Net income attributable to common stockholders
3,349,128

 
2,105,159

Basic and diluted weighted average shares (1)
46,613,258