UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

______________________________

FORM 8-K
_________________________

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): September 17, 2014
EAGLE ROCK ENERGY PARTNERS, L.P.
(Exact name of Registrant as specified in its charter)

Delaware
001-33016
68-0629883
(State or other jurisdiction of incorporation or organization)
Commission File Number
(I.R.S. Employer Identification No.)

1415 Louisiana Street, Suite 2700
Houston, Texas 77002
(Address of principal executive offices, including zip code)

(281) 408-1200
(Registrant's telephone number, including area code)


Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
 




Item 8.01 Other Events

The consolidated balance sheets of Eagle Rock Energy Partners, L.P. and its subsidiaries (collectively the "Partnership") as of December 31, 2013 and 2012, and the related consolidated statements of operations, members’ equity, and cash flows for each of the three years in the period ended December 31, 2013 and the related notes, Item 6. Selected Financial Data and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013 (the “2013 10-K”) which have been retrospectively adjusted for the discontinued operations of the Partnership's Midstream Business, which the Partnership contributed to Regency Energy Partners LP on July 1, 2014, are filed herewith as Exhibit 99.1 and are incorporated herein by reference.
Please note that the Partnership has not further updated the financial information or business discussion for events or activities occurring after the date of the 2013 10-K. You should read the Partnership’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2014 and June 30, 2014 for updated information.


Item 9.01     Financial Statements and Exhibits

(d)         Exhibits.

Exhibit No.     Description

23.1        Consent of KPMG LLP
23.2        Consent of Cawley Gillespie & Associates, Inc.
99.1
Eagle Rock Energy Partners, L.P. Consolidated Financial Statements, related notes, Selected Financial Data and Management's Discussion and Analysis of Financial Condition and Results of Operations




SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
EAGLE ROCK ENERGY PARTNERS, L.P.

 
By:
Eagle Rock Energy GP, L.P.,
 
 
its general partner
 
By:
Eagle Rock Energy G&P, LLC,
 
 
its general partner
 
 
 
Date: September 17, 2014
By:
/s/ Robert M. Haines
 
 
Robert M. Haines
 
 
Vice President and Chief Financial Officer





INDEX TO EXHIBITS

Exhibit No.     Description
23.1        Consent of KPMG LLP
23.2        Consent of Cawley Gillespie & Associates, Inc.
99.1
Eagle Rock Energy Partners, L.P. Consolidated Financial Statements, related notes, Selected Financial Data and Management's Discussion and Analysis of Financial Condition and Results of Operations








EXHIBIT 23.1


Consent of Independent Registered Public Accounting Firm
The Board of Directors of Eagle Rock Energy G&P, LLC and Unitholders of Eagle Rock Energy Partners, L.P.:
We consent to the incorporation by reference in the registration statements on Form S-3 (No. 333‑147244 and No. 333-163554), on Form S-4 (No. 333-177958), and on Form S-8 (No. 333-169472) of Eagle Rock Energy Partners, L.P. and subsidiaries of our report dated March 3, 2014, except as to Notes 1, 3, 11, 12, 17, 18, 19, and 20, which are as of September 17, 2014, with respect to the consolidated balance sheets of Eagle Rock Energy Partners, L.P. and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of operations, members’ equity, and cash flows for each of the years in the three-year period ended December 31, 2013, which report appears in the current report on Form 8‑K of Eagle Rock Energy Partners, L.P. dated September 17, 2014.

/s/ KPMG LLP
Houston, Texas
September 17, 2014








EXHIBIT 23.2


CONSENT OF CAWLEY, GILLESPIE & ASSOCIATES, INC.

The undersigned hereby consents to the inclusion of the information included in this Current Report on Form 8-K with respect to the oil and gas reserves of Eagle Rock Energy Partners, L.P. as of the year ended December 31, 2013. We hereby further consent to all references to our firm included in this Current Report on Form 8-K and to the incorporation by reference in the Registration Statements on Form S-3, No. 333-147244 and No. 333-187553, and the Registration Statement on Form S-8, No. 333-169472, of such information.


/s/ CAWLEY, GILLESPIE & ASSOCIATES, INC.

Fort Worth, Texas
September 17, 2014






EXHIBIT 99.1

 Item 6.              Selected Financial Data.
 
The following table shows selected historical financial data from our audited consolidated financial statements for the five fiscal years from January 1, 2009 to December 31, 2013. The following financial data should be read in conjunction with our consolidated financial statements and the accompanying notes and "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this report.
 
Our historical results of operations for the periods presented below may not be comparable either from period to period or going forward due to the following significant transactions:

•
On May 24, 2010, we completed the sale of our Minerals Business (assets acquired from Montierra and MacLondon Acquisitions) to Black Stone for approximately $171.6 million, and resulted in a pre-tax gain in the disposition of approximately $37.7 million. We used these proceeds to pay down amounts outstanding under our senior secured credit facility. Operations related to these assets for 2010 have been recorded as part of discontinued operations. Financial information for these assets for 2008 and 2009 have been retrospectively adjusted to reflect the assets and liabilities held-for-sale and discontinued operations.

•
On June 30, 2010, we closed our Rights Offering, for which we received gross proceeds of $53.9 million. We used these proceeds to pay down amounts outstanding under our senior secured credit facility.

•
On May 3, 2011, we completed the acquisition of all the outstanding membership interests of CC Energy II L.L.C. ("Crow Creek Energy") for total consideration of $563.7 million including 28.8 million common units valued at $336.1 million, debt assumed of $212.6 million and cash of approximately $15.0 million. As a result, financial results for the periods prior to May 3, 2011 do not include the financial results from these assets.

•
On May 27, 2011, the Partnership, along with its subsidiary, Eagle Rock Energy Finance Corp. ("Finance Corp"), as co-issuer, issued $300 million of 8 3/8% senior unsecured notes (the "Senior Notes") through a private placement. The Senior Notes will mature on June 1, 2019, and interest is payable on each June 1 and December 1, commencing December 1, 2011. These Senior Notes were exchanged for registered notes on February 15, 2012.

•
On May 31, 2012, we announced a program through which we may issue common units, from time to time, with an aggregate market value of $100 million. During 2012, we issued 834,327 common units under this program for net proceeds of approximately $7.3 million. During 2013, we issued 686,759 common units under this program for net proceeds of approximately $5.6 million.

•
On July 13, 2012, the Partnership, along with Finance Corp, issued $250 million of Senior Notes through a private placement. This issuance supplemented our prior $300 million of Senior Notes issued in May 2011. The Senior Notes issued in May 2011 and July 2012 are treated as a single series.

•
On August 17, 2012, we closed an underwritten public offering of 10,120,000 common units for net proceeds of approximately $84.3 million. The net proceeds were used to repay a portion of the outstanding borrowings under our revolving credit facility in advance of funding the Panhandle Acquisition.

•
On March 12, 2013, we closed an underwritten public offering of 10,350,000 common units for net proceeds of approximately $92.3 million.
•
On July 1, 2014, we contributed our business of gathering, compressing, treating, processing, transporting, marketing and trading natural gas, fractionating, transporting and marketing natural gas liquids ("NGLs") and crude oil and condensate logistics and marketing (collectively, the “Midstream Business”) to Regency Energy Partners LP ("Regency") (such contribution, the "Midstream Business Contribution"). As a result of this transaction, the financial statements for all periods have been retrospectively restated to classify the operations of our Midstream Business as discontinued and the assets and liabilities related to our Midstream Business as held for sale.


1

 
Year Ended
December 31,
2013
 
Year Ended
December 31,
2012
 
Year Ended
December 31,
2011
 
Year Ended
December 31,
2010
 
Year Ended
December 31,
2009
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Sales to external customers
$
201,309

 
$
203,205

 
$
204,310

 
$
94,735

 
$
63,633

Commodity risk management gains (losses), net
(3,937
)
 
28,110

 
37,269

 
(4,026
)
 
(53,427
)
Total revenues
197,372

 
231,315

 
241,579

 
90,709

 
10,206

Operating and maintenance expense
41,426

 
41,391

 
32,287

 
24,007

 
20,931

Taxes other than income
12,928

 
15,343

 
15,436

 
8,764

 
7,605

General and administrative expense
53,131

 
50,990

 
42,525

 
34,512

 
34,453

Other operating (income) expense
—

 
—

 
—

 
—

 
(3,552
)
Impairment expense
214,286

 
45,289

 
11,728

 
3,536

 
8,114

Depreciation, depletion and amortization
89,444

 
90,510

 
66,909

 
31,934

 
35,042

Operating (loss) income
(213,843
)
 
(12,208
)
 
72,694

 
(12,044
)
 
(92,387
)
Interest expense, net
19,893

 
21,003

 
22,246

 
31,861

 
(6,189
)
Other expense (income)
30

 
28

 
149

 
(453
)
 
942

(Loss) income from continuing operations before income taxes
(233,766
)
 
(33,239
)
 
50,299

 
(43,452
)
 
(87,140
)
Income tax (benefit) provision
(5,595
)
 
(1,093
)
 
(3,350
)
 
(2,885
)
 
1,812

(Loss) income from continuing operations
(228,171
)
 
(32,146
)
 
53,649

 
(40,567
)
 
(88,952
)
Discontinued operations, net of tax
(49,808
)
 
(118,456
)
 
19,483

 
35,218

 
(65,739
)
Net (loss) income
$
(277,979
)
 
$
(150,602
)
 
$
73,132

 
$
(5,349
)
 
$
(154,691
)
(Loss) income from continuing operations per common unit - diluted
$
(1.50
)
 
$
(0.26
)
 
$
0.45

 
$
(0.49
)
 
$
(1.38
)
 
 
 
 
 
 
 
 
 
 
Balance Sheet Data (at period end):
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
824,451

 
$
982,784

 
$
956,347

 
$
351,594

 
$
351,502

Total assets
$
2,127,550

 
$
2,294,216

 
$
2,045,688

 
$
1,349,397

 
$
1,534,818

Long-term debt
$
757,480

 
$
659,117

 
$
509,193

 
$
530,000

 
$
754,383

Net equity
$
573,879

 
$
868,374

 
$
1,007,347

 
$
579,113

 
$
530,398

 
 
 
 
 
 
 
 
 
 
Cash Flow Data:
 
 
 
 
 
 
 
 
 
Net cash flows provided by (used in):
 
 
 
 
 
 
 
 
 
Operating activities
$
114,243

 
$
75,336

 
$
60,419

 
$
6,716

 
$
(5,344
)
Investing activities
$
(149,868
)
 
$
(152,509
)
 
$
(297,264
)
 
$
141,310

 
$
(6,881
)
Financing activities
$
69,723

 
$
165,471

 
$
(9,834
)
 
$
(175,446
)
 
$
(73,260
)
Discontinued operations
$
(34,047
)
 
$
(89,150
)
 
$
243,507

 
$
28,737

 
$
70,301

Other Financial Data:
 
 
 
 
 
 
 
 
 
Cash distributions per common unit (declared)
$
0.74

 
$
0.88

 
$
0.75

 
$
0.23

 
$
0.10

Adjusted EBITDA(a)
$
119,772

 
$
133,561

 
$
119,240

 
$
26,874

 
$
38,312

________________________
(a)
See Part II Item 6. Selected Financial Data – Non-GAAP Financial Measures for reconciliation of “Adjusted EBITDA” to net cash flows from operating activities and net income (loss).

Non-GAAP Financial Measures
 
We include in this report Adjusted EBITDA, which does not comply with accounting principles generally accepted in the United States ("GAAP"). We provide reconciliations of this non-GAAP financial measure to its most directly comparable financial measures as calculated and presented in accordance with GAAP.
 
We define Adjusted EBITDA as net income (loss) plus or (minus) income tax provision (benefit); interest-net, including gains and losses from interest rate risk management instruments that settled during the period and other expense; depreciation, depletion and amortization expense; impairment expense; other operating expense, non-recurring; other non-cash

2

operating and general and administrative expenses, including non-cash compensation related to our equity-based compensation program; mark-to-market (gains) losses on commodity and interest rate risk management related instruments; gains (losses) on discontinued operations and other (income) expense.  We use Adjusted EBITDA as a measure of our core profitability to assess the financial performance of our assets. Adjusted EBITDA is also used as a supplemental financial measure by external users of our financial statements such as investors, commercial banks and research analysts.  For example, the compliance covenant used by our lenders under our revolving credit facility which is designed to measure our viability and our ability to perform under the terms of our revolving credit facility uses Adjusted EBITDA.  We believe that investors benefit from having access to the same financial measures that our management team uses in evaluating performance.  Adjusted EBITDA is useful in determining our ability to sustain or increase distributions. By excluding unrealized derivative gains (losses), a non-cash, mark-to-market benefit (charge) which represents the change in fair market value of our executed derivative instruments and is independent of our assets’ performance or cash flow generating ability, we believe Adjusted EBITDA provides additional information of our ability to generate cash sufficient to pay interest costs, support our level of indebtedness, make cash distributions to our unitholders and general partner and finance our maintenance capital expenditures. We further believe that Adjusted EBITDA also provides additional information on the underlying performance of our operating assets by isolating the performance of our operating assets from the impact of an unrealized, non-cash measure designed to describe the fluctuating inherent value of a financial asset. Similarly, by excluding the impact of discontinued operations, Adjusted EBITDA provides users of our financial statements additional information on our current assets’ cash generation ability, independently from that of assets which are no longer a part of our operations. Our Adjusted EBITDA definition may not be comparable to Adjusted EBITDA or similarly titled measures as used by other entities, as other entities may not calculate Adjusted EBITDA in the same manner as us. For example, we include in Adjusted EBITDA the actual settlement revenue created from our commodity hedges by virtue of transactions occasionally undertaken by us to reset commodity hedges to higher prices or purchase puts or other similar floors, despite the fact that we exclude from Adjusted EBITDA any charge for amortization of the cost of such commodity hedge reset transactions or puts. 

Adjusted EBITDA does not include interest expense, income taxes or depreciation and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate net income. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income (loss) and net cash flows provided by operating activities determined in accordance with GAAP, as well as Adjusted EBITDA, to evaluate our performance and liquidity.

Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flows provided by operating activities or any other measure of financial performance presented in accordance with GAAP.
 

3

The following table provides a reconciliation of Adjusted EBITDA to net cash flows provided by operating activities and net income (loss):

 
Year Ended
December 31,
2013
 
Year Ended
December 31,
2012
 
Year Ended
December 31,
2011
 
Year Ended
December 31,
2010
 
Year Ended
December 31,
2009
Reconciliation of “Adjusted EBITDA” to net cash flows provided by operating activities and net income (loss):
 
 
 
 
 
 
 
 
 
Net cash flows provided by (used in) operating activities
$
114,243

 
$
75,336

 
$
60,419

 
$
6,716

 
$
(5,344
)
Add (deduct):
 
 
 
 
 
 
 
 
 
Discontinued operations, net of tax
(49,808
)
 
(118,456
)
 
19,483

 
35,218

 
(65,739
)
Depreciation, depletion, amortization and impairment
(303,730
)
 
(135,799
)
 
(78,637
)
 
(35,470
)
 
(43,156
)
Amortization of debt issuance cost
(2,151
)
 
(1,735
)
 
(1,621
)
 
(1,305
)
 
(1,068
)
(Loss) gain from risk management activities, net
(5,041
)
 
23,383

 
25,868

 
(31,161
)
 
(59,774
)
Derivative settlements - operating
(7,478
)
 
(5,368
)
 
22,456

 
25,205

 
(3,067
)
Other
(9,119
)
 
(7,127
)
 
(1,954
)
 
(3,290
)
 
(1,608
)
Accounts receivable and other current assets
(16,118
)
 
24,655

 
(13,924
)
 
(5,039
)
 
(2,689
)
Accounts payable, due to affiliates and accrued liabilities
(774
)
 
(16,717
)
 
26,975

 
3,992

 
6,863

Risk management activities
—

 
6,607

 
15,773

 
—

 
5,648

Other assets and liabilities
1,997

 
4,619

 
(1,706
)
 
(215
)
 
(1,324
)
Net income (loss)
(277,979
)
 
(150,602
)
 
73,132

 
(5,349
)
 
(171,258
)
Add:
 
 
 
 
 
 
 
 
 
Interest expense, net
25,575

 
26,531

 
27,990

 
24,244

 
23,849

Depreciation, depletion, amortization and impairment
303,730

 
135,799

 
78,637

 
35,470

 
43,156

Income tax (benefit) provision
(5,595
)
 
(1,093
)
 
(3,350
)
 
(2,885
)
 
1,812

EBITDA
45,731

 
10,635

 
176,409

 
51,480

 
(102,441
)
Add:
 
 
 
 
 
 
 
 
 
Loss (gain) from risk management activities, net
5,041

 
(23,383
)
 
(25,868
)
 
31,161

 
59,774

Derivative settlements
8,801

 
19,817

 
(16,189
)
 
(24,074
)
 
12,006

Restricted unit compensation expense
10,392

 
7,719

 
4,297

 
4,271

 
5,281

Non-cash mark-to-market Upstream imbalances
(1
)
 
317

 
74

 
(746
)
 
1,505

Discontinued operations, net of tax
49,808

 
118,456

 
(19,483
)
 
(35,218
)
 
65,739

Other operating (income) expense(a)
—

 
—

 
—

 
—

 
(3,552
)
ADJUSTED EBITDA(b)
$
119,772

 
$
133,561

 
$
119,240

 
$
26,874

 
$
38,312

________________________

(a)
Includes $3.6 million due to the recovery of $2.2 million of assets previously written off and the release of $1.4 million of liabilities assumed as part of our purchase price allocation for our acquisitions of Escambia Asset Co. LLC and Redman Energy Holdings, L.P. during the year ended December 31, 2009.
(b)
Adjusted EBITDA excludes amortization of commodity hedge costs (including costs of hedge reset transactions) for the years ended December 31, 2010 and 2009 of $2.2 million and  $12.0 million, respectively.  Including these amortization costs, our Adjusted EBITDA for the years ended December 31, 2010 and 2009, would have been $24.7 million and $26.3 million, respectively.
 

4

Quarterly Financial Data

The following table summarizes our quarterly financial data for 2013:

 
For the Quarters Ended
 
December 31,
2013
 
September 30,
2013
 
June 30,
2013
 
March 31,
2013
 
($ in thousands, except earnings per unit)
Sales of natural gas, NGLs, oil and condensate
$
51,233

 
$
53,318

 
$
49,252

 
$
46,805

Commodity risk management gains (losses), net
(3,561
)
 
(10,878
)
 
17,338

 
(6,836
)
Other revenues
83

 
45

 
76

 
497

Total revenues
47,755

 
42,485

 
66,666

 
40,466

Operating and maintenance expense
14,572

 
12,504

 
13,162

 
14,116

General and administrative expense
12,965

 
13,515

 
13,341

 
13,310

Depreciation, depletion, amortization and impairment expense
174,675

 
83,860

 
23,899

 
21,296

Interest expense, net
(4,578
)
 
(4,647
)
 
(4,499
)
 
(5,065
)
Interest rate risk management losses, net
(338
)
 
(459
)
 
(151
)
 
(156
)
Income tax benefit
(1,335
)
 
(2,155
)
 
(544
)
 
(1,561
)
Other income (expense), net
2

 
3

 
(27
)
 
(8
)
Discontinued operations, net of tax
(10,896
)
 
(21,223
)
 
3,901

 
(21,590
)
Net (loss) income
$
(168,932
)
 
$
(91,565
)
 
$
16,032

 
$
(33,514
)
(Loss) earnings per common unit - Diluted
$
(1.08
)
 
$
(0.59
)
 
$
0.10

 
$
(0.23
)

During our fiscal year ended December 31, 2013, we recorded the following significant items:

•
During the quarters ended June 30, 2013, September 30, 2013 and December 31, 2013, we incurred impairment charges of $1.8 million, $61.4 million and $151.1 million, respectively. See Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview - Impairment for further discussion of our impairment charges during the year ended December 31, 2013.

•
We experienced significant fluctuations in our mark-to-market commodity derivative gains and losses from quarter to quarter as a result of the volatility of commodity prices during 2013.  For example, we recorded mark-to-market gains of $13.5 million during the quarter ended June 30, 2013, while we recorded mark-to-market losses of $12.2 million, $13.7 million and $7.1 million during the quarters ended March 31, 2013, September 30, 2013 and December 31, 2013, respectively.  See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – General Trends and Outlook – Natural Gas Supply and Demand and Crude Oil Supply, Demand and Outlook for further discussion regarding the volatility of commodity prices. 

5

The following table summarizes our quarterly financial data for 2012:
 
For the Quarters Ended
 
December 31,
2012
 
September 30,
2012
 
June 30,
2012
 
March 31,
2012
 
($ in thousands, except earnings per unit)
Sales of natural gas, NGLs, oil and condensate
$
47,885

 
$
51,672

 
$
45,041

 
$
57,121

Commodity risk management gains (losses), net
3,599

 
(4,908
)
 
26,148

 
3,271

Other revenues
374

 
794

 
179

 
139

Total revenues
51,858

 
47,558

 
71,368

 
60,531

Operating and maintenance expense
13,709

 
14,175

 
14,018

 
14,832

General and administrative expense
12,260

 
11,799

 
14,328

 
12,603

Depreciation, depletion, amortization and impairment expense
46,676

 
43,957

 
22,564

 
22,602

Interest expense, net
(4,344
)
 
(4,067
)
 
(3,950
)
 
(3,915
)
Interest rate risk management losses, net
(567
)
 
(1,118
)
 
(1,463
)
 
(1,579
)
Income tax benefit
(1,235
)
 
(237
)
 
(181
)
 
560

Other income (expense), net
(46
)
 
3

 
3

 
12

Discontinued operations, net of tax
(30,654
)
 
(79,577
)
 
46,560

 
(54,785
)
Net (loss) income
$
(55,163
)
 
$
(106,895
)
 
$
61,789

 
$
(50,333
)
(Loss) earnings per unit—diluted
$
(0.39
)
 
$
(0.78
)
 
$
0.46

 
$
(0.40
)

During our fiscal year ended December 31, 2012, we recorded the following significant items:.

•
During the quarters ended June 30, 2012, September 30, 2012 and December 31, 2012 we incurred impairment charges of $0.8 million, $20.1 million and $24.4 million, respectively. See Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Overview - Impairment for further discussion of our impairment charges during the year ended December 31, 2012.

•
We experienced significant fluctuations in our mark-to-market commodity derivative gains and losses from quarter to quarter as a result of the volatility of commodity prices during 2012.  For example, we recorded mark-to-market gains of $17.5 million during the quarter ended June 30, 2012, while we recorded mark-to-market losses of $0.8 million, $14.3 million and $4.3 million during the quarters ended March 31, 2012, September 30, 2012 and December 31, 2012, respectively.  See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview – General Trends and Outlook – Natural Gas Supply and Demand and Crude Oil Supply, Demand and Outlook for further discussion regarding the volatility of commodity prices. 

6

Item 7.                      Management's Discussion and Analysis of Financial Condition and Results of Operations.
 
The following discussion analyzes our financial condition and results of operations and should be read in conjunction with our historical consolidated financial statements and notes included elsewhere in this Annual Report.

OVERVIEW
 
Recent Developments

On December 23, 2013, we announced that we had entered into a definitive agreement to contribute our gathering, compressing, treating, processing, transporting, marketing and trading natural gas; fractionating, transporting and marketing NGLs; and crude oil and condensate logistics and marketing assets and businesses ("Midstream Business") to Regency Energy Partners LP ("Regency") (the "Midstream Business Contribution"). The Midstream Business Contribution was approved by the Partnership's common unitholders on April 29, 2014. On June 27, 2014, the Partnership announced that the Federal Trade Commission had voted to close its investigation into the contribution of its Midstream Business to Regency. As of that date, all significant closing conditions for the transaction were satisfied and the Partnership has classified the assets and liabilities of its Midstream Business as held for sale and the operations as discontinued.

On July 1, 2014, we completed the contribution of our Midstream Business to Regency. The consideration received by us for the contribution of our Midstream Business included: (i) $576.2 million of cash; (ii) 8,245,859 Regency common units (valued at approximately $265.0 million based on the closing price of Regency common units on June 30, 2014) and (iii) the exchange of $498.9 million face amount of newly-issued Regency 8.375% Senior Notes due 2019 for $498.9 million face amount of our existing 8.375% Senior Notes.

Results Overview

As a result of the contribution of our Midstream Business, we are now a domestically-focused, growth-oriented, publicly traded Delaware master limited partnership engaged in developing and producing oil and natural gas property interests. Our interests include operated and non-operated wells located in the Mid-Continent (which includes areas in Oklahoma, Arkansas, and the Texas Panhandle); Permian (which includes areas in West Texas); East Texas; South Texas; Mississippi; and Southern Alabama (which also includes two treating facilities and one natural gas processing plant and related gathering systems).   
 
Results for the year ended December 31, 2013, included the following:

•
revenues, excluding the impact of commodity risk management gains (losses) were $201.3 million for the year ended December 31, 2013, compared to $203.2 million for the year ended December 31, 2012;
•
commodity risk management losses were $3.9 million for the year ended December 31, 2013, compared to gains of $28.1 million for the year ended December 31, 2012;
•
impairment charges were $214.3 million for the year ended December 31, 2013, compared to $45.3 million for the year ended December 31, 2012;
•
operating losses were $213.8 million for the year ended December 31, 2013, compared to $12.2 million for the year ended December 31, 2012;
•
average daily production was 74 MMcfe/d for the year ended December 31, 2013, compared to 83 MMcfe/d for the year ended December 31, 2012; and
•
capital expenditures were $129.1 million for the year ended December 31, 2013, compared to $160.3 million for the year ended December 31, 2012.

Acquisitions

On October 1, 2012, we completed the acquisition of BP America Production Company's ("BP") Texas Panhandle midstream assets (the "Panhandle Acquisition"), including the Sunray and Hemphill processing plants and associated 2,500 mile gathering system.

In addition, on October 1, 2012, we entered into a 20-year, fixed-fee Gas Gathering and Processing Agreement with BP under which we will gather and process BP's natural gas production from the existing wells connected to the acquired

7

gathering system. Furthermore, BP has committed itself to us under the same agreement, and committed its farmees to us under substantially the same terms, with respect to all future natural gas production from new wells drilled within an initial two-year period from closing, subject to mutually-agreed extensions, and within a two-mile radius of any portion of our gathering system serving such BP connected wells. The assets acquired and liabilities assumed as part of the Panhandle Acquisition have been classified as held for sale and the operations have been classified as discontinued.

On May 3, 2011, we completed the Mid-Continent Acquisition -- the acquisition of all of the outstanding membership interests of CC Energy II L.L.C. ("Crow Creek Energy"), a portfolio company of Natural Gas Partners, VIII, L.P. ("NGP VIII"). The oil and natural gas properties acquired from Crow Creek Energy are located in multiple basins across Oklahoma, North Texas and Arkansas (the "Mid-Continent Properties") and provide us with an extensive inventory of low-risk development prospects.

Impairment
 
During the year ended December 31, 2013, we recorded impairment in our Upstream Business of $207.1 million primarily related to certain proved properties in the Cana Shale in the Mid-Continent region and Permian region due to lower reserve forecasts. We also incurred an impairment of 7.2 million for certain leaseholds in out Mid-Continent region unproved properties that we expect to expire undrilled in 2014. During the year ended December 31, 2012, we recorded impairment and other charges in our Upstream Business of $45.3 million, due to (i) certain leaseholds in our unproved properties that we expect to expire undrilled in 2013 and (ii) our proved properties in the Barnett Shale, East Texas and Permian regions that are expected to have reduced cash flows resulting from lower natural gas prices and ongoing relatively high operating costs associated with gas compression. In addition, we recorded a loss on the sale of our properties in the Barnett Shale. During the year ended December 31, 2013, we recorded no impairment charges in our Midstream Businesses. During the year ended December 31, 2012, we recorded impairment charges in our Midstream Business of $131.7 million, due to (i) reduced throughput volumes as our producer customers curtailed their drilling activity in response to the continued depressed natural gas price environment, (ii) the loss of significant gathering contracts on various systems and (iii) the substantial damage incurred at the Yscloskey processing plant as a result of Hurricane Isaac in August 2012. Impairment charges related to our Midstream Business have been recorded as part of discontinued operations within the statements of operations.

Pursuant to GAAP, our impairment analysis does not take into account the value of our commodity derivative instruments, which generally increase as the estimates of future prices decline.  Further declines in commodity prices and other factors could result in additional impairment charges and changes to the fair value of our derivative instruments.

How We Evaluate Our Operations
 
Our management uses a variety of financial and operational measures to analyze our performance. We view these measures as important indicators of our profitability and review these measures on a monthly basis for consistency and trend analysis. These measures include volumes, net revenues, operating expenses and Adjusted EBITDA (defined in Part II, Item 6. Selected Financial Data) from our continuing operations.
 
Volumes
 
We continually monitor the production rates of the wells we operate. This information is a critical indicator of the performance of our wells, and we evaluate and respond to any significant adverse changes. We employ an experienced team of engineering and operations professionals to monitor these rates on a well-by-well basis and to design and implement remediation activities when necessary. We also design and implement workover and drilling operations to increase production in order to offset the natural decline of our currently producing wells. Because our rates of return on new workover and drilling activity are determined in part on commodity prices, we may elect to scale back or cancel such activity during periods of low commodity prices. Furthermore, we may elect to shut-in existing production in extreme commodity downturns (i.e., when the realized prices we receive are below our operating costs on a per unit basis).

Net Revenues
 
Commodity Pricing.  Our revenues generally will correlate with changes in crude oil, natural gas, NGL and sulfur prices.
 
Risk Management.  We conduct risk management activities to mitigate the effect of commodity price and interest rate fluctuations on our cash flows. Our primary method of risk management in this respect is entering into derivative contracts.

8

For a further discussion of our risk management activities, see Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
 
Operating Expenses
 
We monitor and evaluate our costs routinely, both on a total cost and unit cost basis. Many of the operating costs we incur are not directly related to the quantity of hydrocarbons that we produce, so we strive to maximize our production rates in order to improve our unit operating costs. The most significant portion of our operating costs is associated with the operation of the Big Escambia Creek treating and processing facilities. These facilities are overseen by members of our engineering and operations staff. The majority of the cost of operating these facilities is independent of their throughput. This includes items such as labor, chemicals, utilities and materials.
 
Adjusted EBITDA
 
See discussion of Adjusted EBITDA in Part II, Item 6. Selected Financial Data.

General Trends and Outlook
 
We expect our business to be affected by the following key trends. This expectation is based on assumptions made by us and information currently available to us; however, our actual results may vary materially from our expectations.

Natural Gas Supply, Demand and Outlook
 
Since 2006, the United States has experienced significant growth in natural gas production due to drilling for gas in shale plays (such as the Haynesville and Marcellus plays), and the production of associated gas from wells drilled in liquids-rich shale and other unconventional plays (such as the Eagle Ford and Granite Wash plays). In response to greater supply, natural gas prices have stayed consistently below $5.00/mmbtu at Henry Hub since 2009, but these relatively low prices have not dampened the intensity of development of these reserves. Given this observation and the large amount of undeveloped gas reserves in these types of plays, we expect operators to continue to aggressively develop them as long as natural gas prices remain at or above an average Henry Hub price around $4.00/mmbtu.

The increase in US natural gas production has been absorbed through a reduction in natural gas imports from Canada via pipelines and from other countries as liquified natural gas ("LNG"), and through an increase in consumption for electricity generation. Because US electricity generation has been relatively flat over this period, almost all of the increase in natural gas-fired generation has come at the expense of coal-fired generation. Despite lower natural gas prices, other uses for natural gas (such as industrial, residential and vehicle uses) have not grown significantly, and we do not expect them to do so in the next few years. Also, it is uncertain whether natural gas can continue to gain market share from coal in the electrical power generation market. Therefore, we believe that continued increases in natural gas production due to ongoing development of domestic oil and gas shale resources will result in sustained low prices (less than $4.50/mmbtu) unless significant new sources of demand arise, such as additional fuel switching in the electrical power generation industry (perhaps due to increased regulation of emissions from coal-fired generators) or the export of natural gas to other markets in the form of LNG.

Crude Oil Supply, Demand and Outlook
 
Crude oil is a global commodity and the majority of the world’s reserves are controlled by foreign governments and state-owned companies. Much of the world’s reserves are in politically unstable regions, particularly in the Middle East and Africa, and supply disruptions (or even the threat of supply disruptions) can cause large increases in the price of crude oil. Since 2000, worldwide petroleum supply has grown at a modest pace, but not all oil producing countries have experienced increases in production. Almost all of the increase can be explained by increases in Saudi Arabia, Russia, Kazakhstan, the United States and Canada. The dramatic growth in United States production is attributable to the development of vast oil and liquids-rich shale plays that require much higher prices to remain viable than do Middle Eastern reserves. We believe that as long as WTI prices remain above $70-80/bbl, many of these plays will generate economic returns and US production growth will continue for the next several years.

The non-Organization for Economic Cooperation and Development ("OECD") countries currently account for almost half of worldwide petroleum consumption, and since 2000, substantially all of the increase in worldwide consumption has occurred in them. Within that group of countries, the leading consumers are China, India, Brazil and Russia, followed by Saudi Arabia, Iran and Indonesia. These seven countries account for 60% of non-OECD consumption and each of them has increased

9

its petroleum consumption over the last decade. The most significant in terms of quantity consumed and consumption growth rate is China.

We believe that the factors that have resulted in flat or declining consumption in the OECD countries (low population growth, an aging population and increased fuel efficiency) are likely to persist, so future oil demand growth will must come from the non-OECD countries. We are optimistic that these countries will continue to increase their rates of oil consumption as their economies continue to grow and mature. The performance of the Chinese economy will continue to be an important factor in global oil demand, and we believe that if it continues to grow modestly and shifts to a more consumer-driven economy, it will provide an important source of demand growth to support oil prices.

As a result of the supply and demand trends, we believe that crude oil prices in the United States will stay in a range between $70 and $100/bbl over the next few years, but we recognize that infrastructure constraints may create short-lived periods of prices below this range.
 
Natural Gas Liquids Supply, Demand and Outlook
 
The high levels of liquids-directed drilling in the United States has resulted in significant increases in the supply of NGLs while demand for the products has remained relatively stable. As a result, NGL prices declined significantly in 2012 and remained low in 2013. Historically, natural gas liquids prices have tended to have a high correlation to crude oil prices, especially for propane and heavier NGLs, This correlation weakened in 2012, and in 2013 was almost non-existent. We do not expect the prices of NGL’s and crude oil to be well-correlated in the short term, and we are uncertain if and when the correlation will resume.

The majority of the NGLs we produce are delivered into the Conway, Kansas hub. During 2013, the difference between NGL prices at the Conway Hub and the Mont Belvieu, Texas hub were relatively modest, and actually improved in the final months of the year By the end of 2013, prices for propane, iso-butane, and normal-butane were trading at Conway at a slight premium to the Mont Belvieu prices.

Ethane comprises the largest volumetric percentage of the typical NGL barrel, and ethane prices historically have been substantially less correlated to crude oil than have the heavier NGLs. Increased supply, driven by drilling in NGL-rich plays, led to multi-year lows in ethane prices during 2012 and these low prices largely continued in 2013. Ethane demand is primarily driven by global petrochemical production, specifically by its use as a feedstock for ethylene production. Ethane's low price relative to heavier ethylene feedstocks has resulted in strong worldwide demand, and chemical manufacturers have recently announced projects to increase their ethylene production capacity using ethane. These projects have long lead-times, however, and we do not expect the demand response to offset the existing supply for several years. .

 Sulfur Supply, Demand and Outlook
 
Much of the natural gas that we produce in the East Texas and Alabama regions contains high, naturally-occurring concentrations of hydrogen sulfide ("SO2"). This is a corrosive, poisonous gas that must be removed from the natural gas stream before it can be processed for NGL extraction or sale. The process of removing the hydrogen sulfide yields a large amount of elemental sulfur, which we sell or otherwise dispose of. The process of removing hydrogen sulfide from natural gas, and similar processes for the removal of hydrogen sulfide from sour crude oils (prior to refining), are the primary sources of sulfur production in the United States and the world.

The primary use of sulfur is the production of sulfuric acid, and one of the major uses of sulfuric acid is the production of phosphoric acid. In turn, phosphoric acid is a key raw material in the manufacture of phosphate fertilizers. Therefore, one of the major factors influencing the demand for sulfur is the demand for fertilizer. The region around Tampa, Florida contains a large amount of fertilizer manufacturing facilities, and Tampa also serves as an export hub for sulfur.

As with many commodities, the developing economies are responsible for much of the global demand growth for fertilizer. Sulfur prices at Tampa in 2013 ranged from a high of $155 per long ton in the second quarter to a low of $75 per long ton in the fourth quarter. Sulfur prices were $110 per long ton in the first quarter of 2014. We expect demand to remain strong relative to supply in 2014, and, that over the next few years, the performance of the emerging economies, uncertain global economic conditions, and the start-up of significant sulfur-producing operations in the Middle East could result in supply/demand imbalances and cause significant price volatility.
  
Impact of Regulation of Greenhouse Gas Emissions
 

10

The operations of and use of the products produced by the natural gas and oil industry are sources of emissions of certain greenhouse gases ("GHG"), namely carbon dioxide and methane. The United States Environmental Protection Agency ("EPA"), by virtue of a 2007 Supreme Court decision, was deemed to have authority to regulate carbon dioxide and other GHG emissions under the Clean Air Act. It is possible that legislation will be proposed to amend the Clean Air Act to exclude GHG, although the probability of the enactment of such legislation is uncertain.
 
The EPA has already promulgated GHG regulations applicable to the natural gas and oil industry. Moreover, the current presidential administration has indicated that it may pursue additional GHG regulation through executive and administrative means in the absence of federal legislation, but the potential scope and content of such regulation are undetermined at this time. Because of the uncertainty of the nature of any potential future federal GHG regulations at this time, we are unable to forecast how future regulation of GHG emissions would negatively impact our operations.  We will continue to monitor regulatory developments and to assess our ability to reasonably predict the economic impact of these developments on our business.
 
The commercial risk associated with the exploration and production of fossil fuels lies in the uncertainty of regulations that may affect our customers, which could affect the demand for crude oil and natural gas.  Such an impact on demand could have an adverse impact on the demand for our services, and could have an impact on our financial condition, results of operations and cash flows. On the other hand, when burned, natural gas produces less greenhouse gas emissions than other fossil fuels, such as refined petroleum products or coal.  As a result, climate change legislation or GHG emissions regulations could create an increased demand for natural gas.

Critical Accounting Policies and Estimates
 
Conformity with GAAP requires management to make estimates and judgments that affect the amounts reported in the financial statements and notes. On an ongoing basis, we make and evaluate estimates and judgments based on management's best available knowledge of previous, current, and expected future events. We base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates, and estimates are subject to change due to modifications in the underlying conditions or assumptions. Currently, we do not foresee any reasonably likely changes to our current estimates and assumptions which would materially affect amounts reported in the financial statements and notes. Below are expanded discussions of our more significant accounting policies, estimates and judgments, i.e., those that reflect more significant estimates and assumptions used in the preparation of our financial statements. See Note 2 to our consolidated financial statements for details about additional accounting policies and estimates made by management.

 Successful Efforts. We utilize the successful efforts method of accounting for our oil and natural gas properties. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells are capitalized. Unproved properties are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the well is determined to be unsuccessful. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well as long as we are making sufficient progress towards assessing the reserves and the economic and operating viability of the project.
 
Depletion of producing oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for acquisition costs using all proved reserves. GAAP authoritative guidance requires that acquisition costs of proved properties be amortized on the basis of all proved reserves (developed and undeveloped) and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves.  Since our units of production depletion and amortization rate are a function of our proved reserves, we experience a higher depletion and amortization rate than we would if we claimed undeveloped or non-producing reserves.
 
Upon sale or retirement of complete fields of depreciable or depleted property, the book value thereof, less proceeds or salvage value, is charged or credited to income.
 
We assess proved oil and natural gas properties for possible impairment when events or circumstances indicate that the recorded carrying value of the properties may not be pre-tax recoverable. We recognize an impairment loss as a result of a triggering event and when the estimated undiscounted pre-tax future cash flows from a property are less than the carrying value. If impairment is indicated, the fair value is compared to the carrying value for determining the amount of the impairment loss to record. Estimated future cash flows are based on management's expectations for the future and include

11

estimates of oil and natural gas reserves and future commodity prices and operating costs. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate property impairment.
 
Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience, drilling plans and average lease-term lives.  Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units of production basis.  Unproved properties (both individually significant and insignificant) are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense.
 
Our estimates of proved reserves are based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions. Annually, and on other occasions, Cawley, Gillespie & Associates, Inc. prepares an estimate of the proved reserves on all our properties, based on information provided by us.
 
Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. We prepare our reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing their reserve reports. The accuracy of our reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. The data for a given reservoir may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Changes in oil and natural gas prices, operating costs and expected performance from a given reservoir also will result in revisions to the amount of our estimated proved reserves.
 
Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of natural gas, natural gas liquids and oil eventually recovered.

Risk Management Activities. We have structured our hedging activities in order to minimize our commodity pricing and interest rate risks and to help maintain compliance with certain financial covenants in our revolving credit facility. These hedging activities rely upon forecasts of our expected operations and financial structure over the next few years. If our operations or financial structure are significantly different from these forecasts, we could be subject to adverse financial results as a result of these hedging activities. We mitigate this potential exposure by retaining an operational cushion between our forecasted transactions and the level of hedging activity executed.  Based on our current Upstream Business production estimates, we have hedged approximately 80% of our 2014 expected hedgeable crude, condensate and natural gas liquids (heavier than ethane) volumes related to our Upstream Business and 96% of our natural gas and ethane production related to our Upstream Business.
 
From the inception of our hedging program, we used mark-to-market accounting for our commodity hedges and interest rate swaps. We record monthly gains and losses on hedge instruments based upon cash settlement information. The settlement amounts vary due to the volatility in the commodity market prices throughout each month. We also record mark-to-market gains and losses monthly based upon the future value through their expiration dates. The expiration dates vary but are currently no later than June 2015 for our interest rate hedges and December 2016 for our commodity hedges. We monitor and review hedging positions regularly. 

Impairment of Long-Lived Assets. We assess our long-lived assets for impairment whenever events or changes in circumstances indicate its carrying amount may not be recoverable.

Examples of events or changes in circumstances include:
 
•
a significant decrease in the market price of a long-lived asset or asset group;
 
•
a significant adverse change in the extent or manner in which a long-lived asset or asset group is being used or in its physical condition;
 

12

•
a significant adverse change in legal factors or in the business climate could affect the value of a long-lived asset or asset group, including an adverse action or assessment by a regulator which would exclude allowable costs from the rate-making process;
 
•
an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset or asset group;
 
•
a current-period operating cash flow loss combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset or asset group; and
 
•
a current expectation that, more likely than not, a long-lived asset or asset group will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.
 
The carrying value of a long-lived asset is determined to not be recoverable when the carrying value of a long-lived asset exceeds our estimate of the undiscounted cash flows expected to result from the use and eventual disposition of the long-lived asset. If the carrying value of a long-lived asset is determined not to be recoverable, the impairment loss is measured as the excess of the carrying value over its fair value.

Asset Retirement Obligations. The recognition of an asset retirement obligation requires that management make numerous estimates, assumptions and judgments regarding such factors as costs of remediation, timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. In periods subsequent to initial measurement of the asset retirement obligation, we must recognize period-to-period changes in the liability resulting from changes in the timing of settlement to changes in the estimate of the costs of remediation. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis and an adjustment in our depreciation, depletion and amortization expense in future periods.
 
Presentation of Financial Information
 
For a description of the presentation of our financial information in this report, please see Part II, Item 6. Selected Financial Data.

13

Year Ended December 31, 2013 Compared with Year Ended December 31, 2012
 
Summary of Consolidated Operating Results
 
Below is a table of a summary of our consolidated operating results for the years ended December 31, 2013 and 2012.

 
 
Year Ended December 31,
 
 
2013
 
2012
 
($ in thousands)
Revenues:
 
 
 
 
Oil and condensate
 
$
106,752

 
$
101,424

Natural gas
 
45,222

 
42,444

Natural gas liquids
 
40,583

 
43,831

Sulfur
 
8,051

 
14,020

Commodity risk management gains (losses), net
 
(3,937
)
 
28,110

Other revenue
 
701

 
1,486

Total revenues
 
197,372

 
231,315

Costs and expenses:
 
 

 
 

Operating and maintenance
 
41,426

 
41,391

Taxes other than income
 
12,928

 
15,343

General and administrative
 
53,131

 
50,990

Impairment and other
 
214,286

 
45,289

Depreciation, depletion and amortization
 
89,444

 
90,510

Total costs and expenses
 
411,215

 
243,523

Total operating loss
 
(213,843
)
 
(12,208
)
Other income (expense):
 
 

 
 

Interest expense, net
 
(18,789
)
 
(16,276
)
Interest rate risk management losses, net
 
(1,104
)
 
(4,727
)
Other (expense) income, net
 
(30
)
 
(28
)
Total other expense
 
(19,923
)
 
(21,031
)
Loss from continuing operations before income taxes
 
(233,766
)
 
(33,239
)
Income tax benefit
 
(5,595
)
 
(1,093
)
Loss from continuing operations
 
(228,171
)
 
(32,146
)
Discontinued operations, net of tax
 
(49,808
)
 
(118,456
)
Net loss
 
$
(277,979
)
 
$
(150,602
)
Adjusted EBITDA(a)
 
$
119,772

 
$
133,561

________________________
(a)
See "Part II, Item 6. Selected Financial Data - Non-GAAP Financial Measures" for a definition and reconciliation to GAAP.



14

 
Year Ended December 31,
 
2013
 
2012
 
 
 
 
Realized average prices:
 
 
 
Oil and condensate (per Bbl)
$
87.34

 
$
85.65

Natural gas (per Mcf)
$
3.53

 
$
2.58

NGLs (per Bbl)
$
35.12

 
$
39.12

Sulfur (per Long ton)
$
76.38

 
$
137.46

Production volumes:
 
 
 

Oil and condensate (Bbl)
1,222,270

 
1,184,200

Natural gas (Mcf)
12,804,475

 
16,442,579

NGLs (Bbl)
1,155,639

 
1,120,522

Total (Mcfe)
27,071,929

 
30,270,911

Sulfur (Long ton)
105,394

 
102,002

 
 
 
 
Capital expenditures
$
129,099

 
$
160,330


Revenue. For the year ended December 31, 2013, our revenues decreased by $1.9 million as compared to the year ended December 31, 2012.  The decrease in revenues was due to the sale of our Barnett properties, lower natural gas volumes, and lower NGL and sulfur prices, partially offset by higher oil and NGL volumes, and higher oil and natural gas prices for the year ended December 31, 2013, compared to the year ended December 31, 2012. Volumes during the year ended December 31, 2013 were negatively impacted by suspended operations at our Flomaton separation and treating facility, increased natural gas fuel consumption at our Big Escambia Creek treating and processing facility, higher than expected decline rates from our 2012 Cana Shale program wells, production delays associated with extended drilling time for certain wells in the Mid-Continent, an unsuccessful development well in the Mid-Continent and less than expected volumes from our Mid-Continent and Permian recompletion projects. Golden Trend and Southeast Cana volumes during the year ended December 31, 2013 were negatively impacted by a third-party processing plant being shutdown for eight days in September. Volumes returned to normal production levels during the month of September. During November and December 2013, revenues were negatively impacted by approximately $1.2 million due to weather related events.

On February 7, 2013, we suspended operations at our Flomaton treating facility in Escambia County, Alabama due to the failure of certain plant equipment and inlet volumes that were insufficient to operate the facility's sulfur recovery unit. To increase inlet volumes of the field to operate the treating facility we attempted to restore production from two wells connected to the facility, but these operations were unsuccessful. We resumed facility operations on April 18, 2013, after repairing the equipment and increasing inlet volumes by diverting production from a nearby operated well; however, on May 24, 2013, we again suspended operations due to equipment failure at the treating facility. We estimate that during the year ended December 31, 2013, we lost revenues of approximately $1.2 million and incurred increased facility expenses of $0.2 million. During the first three months of 2013, we incurred increased operating expenses of approximately $2.4 million related to the production restoration attempts. On July 31, 2013, we received approval from the required percentage of owners of the Big Escambia Creek and Flomaton plants to resume operations by re-routing gas from the Flomaton facility to our Big Escambia Creek facility for treating and processing, while continuing to stabilize and sell the Flomaton field condensate at the Flomaton facility.

In August 2010, our East Texas oil and natural gas production was temporarily shut-in due to an unscheduled shut-down of the Eustace processing facility owned and operated by a third-party. The shut-in negatively impacted our net revenues from January 1, 2011 to March 11, 2011, the date the plant was brought back into service. During the year ended December 31, 2012, we received an $0.8 million settlement from the third-party operator related to this incident, which was recorded as other revenue.

During the year ended December 31, 2012, we completed the following turnarounds at our Alabama processing facilities to make certain repairs and routine inspections of equipment.
•
In March 2012, our Flomaton facility was shut-down for approximately twelve days.
•
In May and June 2012, our Big Escambia Creek facility was shut-down for approximately eight and seven days, respectively.

15

•
In November and December 2012, our Big Escambia Creek facility was shut-down for 24 days, during which time we also installed a new Superclaus reactor within our existing sulfur recovery unit, which was required to reduce the facilities' SO2 emissions.
As a result of these turnarounds, and the shutting-in of wells within the fields that supply natural gas to the processing plants, we estimate the revenue impact due to the loss of production was $8.7 million and that we incurred additional operating expenses of approximately $2.8 million during the year ended December 31, 2012. In addition, these turnarounds reduced our production by approximately 759 MMcfe and 6,799 long ton of sulfur.
Commodity Risk Management Gains (Losses), net. During the year ended December 31, 2013, our commodity risk management losses increased by $32.0 million, as compared to the year ended December 31, 2012. During the year ended December 31, 2013, our losses due to the change in the mark-to-market value of our derivative contracts increased by $17.6 million, as compared to the year ended December 31, 2012, due to increases in the natural gas, NGL and crude oil forward curves. Our gains from derivative contracts that settled during the year ended December 31, 2013 decreased $14.5 million, as compared to the year ended December 31, 2012. This decrease was due to higher natural gas and crude oil index prices, partially offset by lower NGL index prices, in relation to the strike prices of our settled contracts, as compared to the same period in the prior year. In addition, the decrease was due to the higher level of direct NGL product contracts that settled during the year ended December 31, 2012, as compared to the same period in 2013.

Given the uncertainty surrounding future commodity prices, and the general inability to predict future commodity prices as they relate to the strike prices at which we have hedged our exposure, it is difficult to predict the magnitude and impact that marking our hedges to market will have on our income from operations in future periods.

Operating Expenses. Operating expenses, including severance and ad valorem taxes, decreased by $2.4 million for the year ended December 31, 2013 as compared to the year ended December 31, 2012.  The decrease was primarily due to the sale of our Barnett Shale properties, lower severance taxes resulting from decreased sales and from a refund received from the state of Oklahoma for taxes paid in prior years.

General and Administrative Expenses. General and administrative expenses increased by $2.1 million for the year ended December 31, 2013 as compared to the same period in 2012. This increase was primarily due to higher salaries and benefits, which was due to increased equity compensation expense due to additional grants, as well as increased professional fees.

 Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense decreased by $1.3 million for the year ended December 31, 2013 as compared to the same period in 2012.  The decrease was primarily a result of the sale of our Barnett Shale properties and impairment charges recorded during 2013 and 2012.

Impairment and Other. During the year ended December 31, 2013, we recorded an impairment charges of $214.3 million due to certain proved properties in the Cana Shale in the Mid-Continent region and Permian region due to lower reserve forecasts and certain leaseholds in our Mid-Continent region unproved properties that we expect to expire undrilled in 2014. During the year ended December 31, 2012, we incurred impairment and other charges of $45.3 million due to (i) certain unproved property leaseholds that we expected to expire undrilled in 2013 and (ii) our proved properties in the Barnett Shale, East Texas and Permian regions that experienced reduced cash flows resulting from lower natural gas prices and continuing relatively high operating costs associated with gas compression. In addition, we recorded a loss on the sale of our properties in the Barnett Shale in 2012.

Total Other Expense.  Total other expense primarily consisted of gains and losses from our interest rate swaps and interest expense related to our senior secured credit facility and our senior unsecured notes. During July 2012, in conjunction with our issuance of $250.0 million of senior unsecured notes, which increased our fixed interest rate exposure, we terminated the full $200.0 million notional amount of our existing 4.295% and 4.095% fixed rate interest rate swaps. During the year ended December 31, 2013, our interest rate risk management losses decreased by $3.6 million as compared to the year ended December 31, 2012, primarily due to the transactions described above and as a result of a decrease in the forward interest rate curves. Mark-to-market losses from our interest rate risk management activities do not have any impact on cash activities for the period, and are excluded by definition from our calculation of Adjusted EBITDA.

Interest expense increased by $2.5 million during the year ended December 31, 2013, as compared to the year ended December 31, 2012.  Interest expense is shown before the impact of our interest rate derivatives, which convert a portion of our outstanding debt from variable-rate interest obligations to fixed-rate interest obligations.  The increase in interest expense is due

16

to the issuance of the senior unsecured notes, described above, along with increased borrowings under our revolving credit facility.

Income Tax (Benefit) Provision. Income tax benefit for 2013 and 2012 relates to (i) state taxes due by us and (ii) federal taxes due by Eagle Rock Energy Acquisition Co., Inc. and Eagle Rock Energy Acquisition Co. II, Inc. and their wholly owned subsidiary corporations, Eagle Rock Upstream Development Company, Inc. and Eagle Rock Upstream Development Company II, Inc., which are each subject to federal income taxes.

Discontinued Operations. On July 1, 2014, we completed the contribution of our Midstream Business to Regency, and as a result, we have classified the assets and liabilities as held for sale and the operations as discontinued. For the year ended December 31, 2013, the loss from discontinued operations increased by $70.2 million compared to the year ended December 31, 2012. The increase is primarily due to impairment charges incurred within our Midstream Business during the year ended December 31, 2012. We did not incur any impairment charges in our Midstream Business during the year ended December 31, 2013. This decrease was offset by commodity risk management losses incurred during the year ended December 31, 2013 compared to commodity risk management gains incurred during the year ended December 31, 2012. In addition, discontinue operations during the year ended December 31, 2013 includes approximately $4.7 million of accounting, legal and advisory services expenses related to the contribution of our Midstream Business to Regency.

Capital Expenditures.  Capital expenditures decreased by $31.2 million for the year ended December 31, 2013 as compared to the year ended December 31, 2012.   During the year ended December 31, 2013, we drilled and completed thirteen gross operated wells, participated in thirty-one gross non-operated wells and drilled and abandoned one unproductive well on leases in the Mid-Continent region. Additionally, during the year ended December 31, 2013, we conducted ten recompletions, twenty-four capital workovers and eight expense workovers across our operations.

Adjusted EBITDA
 
Adjusted EBITDA, as defined under Item 6. Selected Financial Data - Non-GAAP Financial Measures, from continuing operations decreased by $13.8 million from $133.6 million for the year ended December 31, 2012 to $119.8 million for the year ended December 31, 2013. The following table presents the changes in operations impacting Adjusted EBITDA:

 
Year Ended December 31,
 
2013
 
2012
 
Change
 
($ in thousands)
Revenues - Upstream (a)
$
201,308

 
$
203,522

 
$
(2,214
)
Commodity derivative settlements - Corporate and Other
15,557

 
30,044

 
(14,487
)
Total incremental revenues minus cost of natural gas and NGLs
216,865

 
233,566

 
(16,701
)
 
 
 
 
 
 
Operating expenses - Upstream
54,354

 
56,734

 
(2,380
)
General and administrative expenses (b)
42,739

 
43,271

 
(532
)
Adjusted EBITDA (c)
$
119,772

 
$
133,561

 
$
(13,789
)
_________________________

(a)
Excludes the impact of imbalances.
(b)
Excludes non-cash compensation charges related to our long-term incentive program.
(c)
See "Part II, Item 6. Selected Financial Data - Non-GAAP Financial Measures" for a definition and reconciliation to GAAP.




17

Year Ended December 31, 2012 Compared with Year Ended December 31, 2011
 
Summary of Consolidated Operating Results
 
Below is a table of a summary of our consolidated operating results for the years ended December 31, 2012 and 2011.
 
 
Year Ended December 31,
 
2012
 
2011(a)
 
($ in thousands)
Revenues:
 
 
 
Oil and condensate
$
101,424

 
$
94,290

Natural gas
42,444

 
48,038

Natural gas liquids
43,831

 
42,553

Sulfur
14,020

 
17,753

Commodity risk management gains (losses), net
28,110

 
37,269

Other revenue
1,486

 
1,676

Total revenues
231,315

 
241,579

Costs and expenses:
 

 
 

Operating and maintenance
41,391

 
32,287

Taxes other than income
15,343

 
15,436

General and administrative
50,990

 
42,525

Impairment
45,289

 
11,728

Depreciation, depletion and amortization
90,510

 
66,909

Total costs and expenses
243,523

 
168,885

Total operating income (loss)
(12,208
)
 
72,694

Other income (expense):
 

 
 

Interest expense, net
(16,276
)
 
(10,845
)
Interest rate risk management losses, net
(4,727
)
 
(11,401
)
Other expense, net
(28
)
 
(149
)
Total other expense
(21,031
)
 
(22,395
)
(Loss) income from continuing operations before income taxes
(33,239
)
 
50,299

Income tax benefit
(1,093
)
 
(3,350
)
(Loss) income from continuing operations
(32,146
)
 
53,649

Discontinued operations, net of tax
(118,456
)
 
19,483

Net (loss) income
$
(150,602
)
 
$
73,132

Adjusted EBITDA(b)
$
133,561

 
$
119,240

________________________
(a)
Includes operations related to the Mid-Continent Acquisition starting on May 3, 2011.
(b)
See Part II, Item 6. Selected Financial Data – Non-GAAP Financial Measures for a definition and reconciliation to GAAP.




18

 
Year Ended December 31,
 
2012
 
2011 (a)
 

 


Realized average prices:

 


Oil and condensate (per Bbl)
$
85.65

 
$
84.36

Natural gas (per Mcf)
$
2.58

 
$
3.69

NGLs (per Bbl)
$
39.12

 
$
54.58

Sulfur (per Long ton)
$
137.46

 
$
180.46

Production volumes:

 


Oil and condensate (Bbl)
1,184,200

 
1,117,778

Natural gas (Mcf)
16,442,579

 
12,636,473

NGLs (Bbl)
1,120,522

 
805,359

Total (Mcfe)
30,270,911

 
24,175,295

Sulfur (Long ton)
102,002

 
98,372

 
 
 
 
Capital expenditures
$
160,330

 
$
92,660


Revenue. For the year ended December 31, 2012, commodity revenues decreased by $1.1 million as compared to the year ended December 31, 2011.  The addition of production volumes from the acquisition of Crow Creek Energy, which closed on May 3, 2011, positively impacted revenues by $22.3 million during the year ended December 31, 2012. Excluding the acquisition, revenues decreased due to lower volumes and lower natural gas and NGL prices for the year ended December 31, 2012, compared to the year ended December 31, 2011.

In August 2010, our East Texas oil and natural gas production was temporarily shut-in due to an unscheduled shut-down of the Eustace processing facility owned and operated by a third-party. The shut-in negatively impacted our net revenues from January 1, 2011 to March 11, 2011, the date the plant was brought back into service, by approximately $3.9 million (excluding recoveries). We recognized $5.0 million related to our business interruption insurance claim in other revenue, of which $2.0 million was recognized in the three months ended March 31, 2011 and $3.0 million was recognized in the fourth quarter of 2010. The maximum recovery under our business interruption insurance policy is $5.0 million per occurrence. During the three months ended September 30, 2012, we received an $0.8 million settlement from the third-party operator related to this incident, which was recorded as other revenue.

In March 2012, we completed a scheduled turnaround of our Flomaton facility in Escambia County, Alabama to make certain equipment repairs and routine inspections of equipment. During the turnaround, both the Flomaton facility and all wells in the Flomaton and Fanny Church fields were shut-in. The duration of the plant turnaround and the field shut-in was approximately twelve days. We estimate the revenue impact due to the loss of production was approximately $0.5 million and the turnaround expense was approximately $0.6 million.

In May and June 2012, we completed turnarounds of approximately eight and seven days, respectively, of our Big Escambia Creek facility to make certain equipment repairs and routine inspections of equipment. We estimate the net revenue impact due to the loss of production was approximately $3.8 million and the turnaround expense was approximately $0.5 million. The turnarounds reduced our production by approximately 334 MMcfe and 3,400 long ton of sulfur.

In November and December 2012, our Big Escambia Creek oil and natural gas production was temporarily shut-in 24 days to perform a plant turnaround to install a new Superclaus reactor within our existing sulfur recovery unit.  The new reactor was required to reduce the facility's SO2 emissions as required by our existing air emissions permit.  In addition, certain equipment repairs and routine inspections were conducted during the turnaround. We estimate the net revenue impact due to the loss of production was approximately $4.4 million and the turnaround expense was approximately $1.7 million. The turnaround reduced our production by approximately 387 MMcfe and 3,322 long ton of sulfur.

Commodity Risk Management Gains (Losses), net. During the year ended December 31, 2012, our commodity risk management gains increased by $9.2 million, as compared to the year ended December 31, 2011. During the year ended December 31, 2012, our gains due to the change in the mark-to-market value of our derivative contracts decreased by $38.4 million, as compared to the year ended December 31, 2011, due to increases in the natural gas, NGL and crude oil forward curves.  This decrease was offset by an increase in gains of $29.2 million from derivative contracts that settled during the year ended December 31, 2012, as compared to the year ended December 31, 2011, which was due to the settlement of contracts

19

assumed in the Mid-Continent Acquisition and lower natural gas and NGL market prices, in relation to the strike prices of our settled contracts, as compared to the same period in the prior year.

Given the uncertainty surrounding future commodity prices, and the general inability to predict future commodity prices as they relate to the strike prices at which we have hedged our exposure, it is difficult to predict the magnitude and impact that marking our hedges to market will have on our income from operations in future periods.

Operating Expenses. Operating expenses, including severance and ad valorem taxes, increased by $9.0 million for the year ended December 31, 2012 as compared to the year ended December 31, 2011.  The increase was due primarily to higher production expenses related to twelve months of operations of the properties acquired in the Mid-Continent Acquisition during the year ended December 31, 2012 compared to eight months of operations during 2011.

On July 19, 2012, one of our operated wells in Wayne County, Mississippi experienced an uncontrolled flow event during a well workover operation. The incident required the mobilization of our emergency response personnel to control the well's flow and secure the area in coordination with local, county and state emergency management agencies. Various contractors, including well control contractors, were mobilized to assist our response team. The flow from the well was fully controlled and secured on July 24, 2012. We have Control of Well insurance and are currently pursuing reimbursement for this incident. We estimate the cost of the incident to be between $17 and $18 million and have offset amounts paid above our deductible of $150,000 by recording a receivable for reimbursement under our insurance policy. During the year ended December 31, 2012, we received $6.0 million reimbursement for this incident and as of December 31, 2012, we had an additional receivable of $8.8 million related to the expected reimbursement. On February 21, 2013, we received an additional $3.0 million reimbursement for this incident.

General and Administrative Expenses. General and administrative expenses increased by $8.5 million for the year ended December 31, 2012 as compared to the same period in 2011. This increase was primarily due to (i) higher salaries and benefits, which was due to an increase in our headcount due to the Mid-Continent Acquisition and increased equity compensation expense due to additional grants and (ii) increased professional and legal fees. In addition, we also incurred higher insurance expense related to the increase in our insurable property and to higher insurance rates during the year ended December 31, 2013. The increases for the year ended December 31, 2012, were partially offset by higher professional fees incurred during the same period in 2011, primarily associated with the Mid-Continent Acquisition in May 2011.

 Depletion, Depreciation and Amortization. Depletion, depreciation and amortization expense increased by $23.2 million for the year ended December 31, 2012 as compared to the same period in 2011.  The increase was primarily due to depletion and amortization expense incurred during the year ended December 31, 2012 for the properties acquired in the Mid-Continent Acquisition, partially offset by decreases as a result of the impairment charge recorded during the year ended December 31, 2012.
 
Impairment and Other. During the year ended December 31, 2012, we incurred impairment and other charges of $45.3 million due to (i) certain unproved property leaseholds that we expect to expire undrilled in 2013 and (ii) our proved properties in the Barnett Shale, East Texas and Permian regions that experienced reduced cash flows resulting from lower natural gas prices and continuing relatively high operating costs associated with gas compression. In addition, we recorded a loss on the sale of our properties in the Barnett Shale. During the year ended December 31, 2011, we incurred impairment charges of $11.7 million due to (i) certain legacy drilling locations in our unproved properties which we no longer intend to develop based on the performance of offsetting wells, (ii) certain proved properties of the Jourdanton field in South Texas due to lower natural gas prices and relatively high operating costs and (iii) certain drilling locations in our unproved properties which we no longer intend to develop.

Total Other Expense.  Total other expense primarily consisted of gains and losses from our interest rate swaps and interest expense related to our senior secured credit facility and our senior unsecured notes. On June 22, 2011, we terminated a $150 million notional amount 2.56% fixed rate interest rate swap at a total cost of $5.0 million, and extended the maturity of $250 million notional amount of our 4.095% fixed rate interest rate swaps from December 31, 2012 to June 22, 2015, with a fixed rate of 2.95%. During July 2012, in conjunction with our issuance of $250.0 million of senior unsecured notes, which increased our fixed interest rate exposure, we terminated the full $200.0 million notional amount of our existing 4.295% and 4.095% fixed rate interest rate swaps. During the year ended December 31, 2012, our interest rate risk management losses decreased by $6.7 million as compared to the year ended December 31, 2011, due primarily to the transactions described above and a decrease in the forward interest rate curves. Mark-to-market losses from our interest rate risk management activities do not have any impact on cash activities for the period, and are excluded by definition from our calculation of Adjusted EBITDA.


20

Interest expense, net increased by $5.4 million during the year ended December 31, 2012 as compared to the year ended December 31, 2011. Interest expense is shown before the impact of our interest rate derivatives, which convert a portion of our outstanding debt from variable-rate interest obligations to fixed-rate interest obligations.  On May 27, 2011, we issued $300.0 million of senior unsecured notes with a coupon of 8.375% through a private placement, and on June 22, 2011, we entered into an Credit Agreement (as defined below) which as of December 31, 2012 bore interest at LIBOR plus 2.25%.  and on July 13, 2012, we issued an additional $250 million of senior unsecured notes.  The increases in interest expense were due to the transactions discussed above along with increased borrowings under our Credit Agreement.

Income Tax (Benefit) Provision. Income tax provision for 2012 and 2011 relates to (i) state taxes due by us and (ii) federal taxes due by Eagle Rock Energy Acquisition Co., Inc. and Eagle Rock Energy Acquisition Co. II, Inc. and their wholly owned subsidiary corporations, Eagle Rock Upstream Development Company, Inc. and Eagle Rock Upstream Development Company II, Inc., which are each subject to federal income taxes.

Discontinued Operations. On July 1, 2014, we completed the contribution of our Midstream Business to Regency, and as a result such, we have classified the assets and liabilities as held for sale and the operations as discontinued. For the year ended December 31, 2012, discontinued operations decreased by $137.9 million compared to the year ended December 31, 2011. The decrease is primarily due to impairment charges incurred within our Midstream Business during the year ended December 31, 2012. We did not incur any impairment charges in our Midstream Business during the year ended December 31, 2013. This decrease was offset by commodity risk management losses incurred during the year ended December 31, 2013 compared to commodity risk management gains incurred during the year ended December 31, 2012. On May 20, 2011, we sold our Wildhorse Gathering System. During 2011, this system generated income from operations of approximately $0.5 million, which was offset by a loss on the sale of $0.7 million. On May 24, 2010, we completed the sale of our fee mineral and royalty interests as well as our equity investment in Ivory Working Interests, L.P. During the year ended December 31, 2011, we received payments of $0.5 million related to pre-effective date operations and recorded this amount as part of discontinued operations

Capital Expenditures.  Capital expenditures increased by $67.7 million for the year ended December 31, 2012 as compared to the year ended December 31, 2011.   During the year ended December 31, 2012, we drilled and completed twelve gross operated wells and participated in twenty-one gross non-operated wells on leases in the Mid-Continent region. Additionally, during the year ended December 31, 2012, we conducted eleven recompletions, fifteen capital workovers and six expense workovers across our operations.

Adjusted EBITDA
 
Adjusted EBITDA, as defined and reconciled to GAAP under Item 6. Selected Financial Data - Non-GAAP Financial Measures, from continuing operations increased by $14.3 million from $119.2 million for the year ended December 31, 2011 to $133.6 million for the year ended December 31, 2012. The following table presents the changes in operations impacting Adjusted EBITDA:

 
Year Ended December 31,
 
2012
 
2011
 
Change
 
($ in thousands)
Revenues - Upstream (a)
203,522

 
204,384

 
(862
)
Commodity derivative settlements - Corporate and Other
30,044

 
807

 
29,237

Total incremental revenues
233,566

 
205,191

 
28,375

 
 
 
 
 
 
Operating expenses - Upstream
56,734

 
47,723

 
9,011

General and administrative expenses (b)
43,271

 
38,228

 
5,043

Adjusted EBITDA (c)
$
133,561

 
$
119,240

 
$
14,321

_________________________

(a)
Excludes the impact of imbalances
(b)
Excludes non-cash compensation charges related to our long-term incentive program and other non-recurring items.
(c)
See "Part II, Item 6. Selected Financial Data - Non-GAAP Financial Measures" for a definition and reconciliation to GAAP.


21

LIQUIDITY AND CAPITAL RESOURCES
 
Historically, our sources of liquidity have included cash generated from operations, issuances of equity and debt securities, borrowings under our revolving credit facility and asset sales. Our primary cash requirements have included general and administrative expenses, operating expenses, maintenance and growth capital expenditures, short-term working capital needs, interest payments on our outstanding debt, distributions to our unitholders and acquisitions of new assets or businesses.

We believe that our historical sources of liquidity will be sufficient to satisfy our short-term liquidity needs and to fund our committed capital expenditures for at least the next twelve months. Our growth strategy entails expenditures on organic projects and new drilling activity. We also intend to continue to pursue attractive development and acquisition opportunities. Accordingly, we may utilize various available financing sources, including the issuance of equity or debt securities, to fund all or a portion of our organic growth expenditures and potential acquisitions. Our ability to complete future offerings of equity or debt securities and the timing of these offerings will depend upon various factors including prevailing market conditions and our financial condition.

At December 31, 2013, prior to the completion of the Midstream Business Contribution, our liquidity was limited by our amount of debt outstanding and by our debt ratios relative to the covenant levels specified in our revolving credit facility, as discussed further below. We expected the proposed contribution of our Midstream Business to Regency to significantly reduce our leverage and improve our liquidity. We intended to use the net proceeds from the Midstream Business Contribution to reduce debt outstanding under the revolving credit facility. In addition, as part of the consideration for the Midstream Business Contribution, Regency conducted an exchange offer for the full $550 million face value of our outstanding senior unsecured notes. If less than all the senior unsecured notes were tendered for exchange in the exchange offer, Regency agreed to pay us a dollar amount equal to 110% of the difference between $550 million and the face value of the notes tendered. In this scenario, any of our senior unsecured notes that were not tendered for exchange would remain outstanding, and we would use the additional cash proceeds from Regency to repay borrowings under our credit facility or retain excess cash to pursue acquisitions. Our annual interest expense would initially be higher under this scenario than if all of our senior unsecured notes were exchanged. The exchange offer was completed on June 30, 2014, and $498.9 face value of our senior notes were exchanged, with the remaining $51.1 million face value of our senior unsecured notes remaining. In connection with the exchange offer, and having secured a sufficient number of consents as part of the exchange offer, we amended the indenture governing our notes to eliminate substantially all of the restrictive covenants and certain events of default pertaining to our notes.

The completion of the Midstream Business Contribution was subject to regulatory and unitholder approvals. As a result, we provided no assurance that the Midstream Business Contribution would be completed within our anticipated time frame, or at all. If the Midstream Business Contribution was not consummated, we would continue to be constrained in the near-term by limited liquidity and greater risk that our debt ratios may exceed the covenant levels in our revolving credit facility. In this event we would seek to fund our liquidity needs and reduce our debt levels through some combination of reduced spending, equity financings and asset sales. The Midstream Business Contribution was completed on July 1, 2014.

Equity Offerings

On May 31, 2012, we announced a program through which we may issue common units, from time to time, with an aggregate market value of up to $100 million. We are under no obligation to issue equity under the program. We intend to use the net proceeds from any sales under the program for general partnership purposes, which may include, among other things, repayment of indebtedness, acquisitions, capital expenditures and additions to working capital. As of December 31, 2013, 1,521,086 units had been issued under this program for net proceeds of approximately $12.9 million During the year ended December 31, 2013, 686,759 units had been issued under this program for net proceeds of approximately $5.6 million. Issuance costs associated with the program for the year ended December 31, 2013 were $0.4 million. No sales were made under the program during the three months ended December 31, 2013.

During the first quarter of 2013, we closed an underwritten public offering of 10,350,000 common units for net proceeds of approximately $92.3 million. The net proceeds were used to repay a portion of the outstanding borrowings under our revolving credit facility.

Capital Expenditures

The energy business can be capital intensive, requiring significant investment for the acquisition or development of new facilities. We categorize our capital expenditures as (and, as necessary, allocate the attributable portion of our capital expenditures between) either:

22

 
•
growth capital expenditures, which are made to (i) acquire, construct, expand or upgrade our gathering, processing and treating assets or (ii) grow our natural gas, NGL, crude or sulfur production; or
 
•
maintenance capital expenditures, which are made to (i) replace partially or fully depreciated assets, meet regulatory requirements, or maintain the existing operating capacity of our gathering, processing and treating assets or (ii) maintain our natural gas, NGL, crude or sulfur production. With respect to maintenance capital expenditures intended to maintain the Partnership's natural gas, NGL, crude or sulfur production, we estimate these amounts based on current projections and expectations, and do not undertake to adjust any historical amounts based on the actual impact of such expenditures on production. As a result, the included amount of maintenance capital expenditures could fail to maintain production if actual performance does not meet our projections and expectations, including, without limitation, on account of: (i) unanticipated mechanical issues; (ii) unanticipated delays; (iii) poorer than expected production performance of our new wells and recompletions; and/or (iv) unanticipated loss of, or higher than anticipated decline in, existing production.

 The primary impact of this categorization is that we reduce the amount of cash we consider available for distribution by the amount of our maintenance capital expenditures.

As of March 3, 2014, our 2014 capital budget anticipated that we would spend, excluding the potential divestiture of our Midstream Business, approximately $188 million in total, of which $112 million related to growth capital expenditures and $76 million related to maintenance capital expenditures. The allocation by business of our 2014 capital budget is as follows; $124 million ($66 million of growth and $58 million for maintenance) relates to upstream capital expenditures, $61 million ($43 million for growth and $18 million for maintenance) relates to midstream capital expenditures (before taking into consideration the Midstream Business Contribution) and $2 million ($1.4 million for growth and $0.6 million) relates to corporate capital expenditures. We anticipated that our capital spending, for both our Upstream and Midstream businesses, would be made ratably throughout 2014.

Our capital expenditures, were approximately $224.2 million for the year ended December 31, 2013, of which $65.8 million related to maintenance capital expenditures and $158.3 million related to growth capital expenditures. Amounts include capital expenditures related to both our Upstream and Midstream Businesses. Assets and liabilities related to our Midstream Business have been classified as held for sale within the consolidated balance sheets and operations related to our Midstream Business have been classified as discontinued within the consolidated statements of operations.

In order to lower SO2 emissions from our Big Escambia Creek processing facility in Alabama, as required by our existing air emissions permit, our operating subsidiary initiated the first phase of an SO2 emissions reduction project at our Big Escambia Creek processing facility in December 2011. This phase of the project involved adding a Superclaus reactor to the existing sulfur recovery unit to achieve the desired reduction in SO2 emissions. The new unit began operations on December 17, 2012, and through December 31, 2013 had resulted in increased sulfur production and reductions in SO2 emissions to levels well below the required permitted levels. The total cost of this phase to date was approximately $21.0 million net to our interest.

The second and final phase of our SO2 emissions reduction project involves replacing or upgrading certain components of our existing sulfur recovery unit at the Big Escambia Creek processing facility. This phase is designed to improve the operational reliability of the processing facility, further increase the quantity of marketable sulfur recovered from the inlet gas stream, reduce the frequency of facility turnarounds, extend the facility's operating life and achieve cost savings across our operations in Southern Alabama. The improvements to our sulfur recovery unit will also further reduce SO2 emissions, helping to ensure our compliance with the National Ambient Air Quality Standards the Environmental Protection Agency enacted in mid-2010.  In the first of these planned upgrades, we expect to replace the incinerator portion of the sulfur recovery unit in 2015 at a cost of approximately $11.6 million net to our interest.

Distribution Policy
 
Our distribution policy is to distribute to our unitholders, on a quarterly basis, all of our available cash in the manner described below and as further described in our partnership agreement. Available cash generally means, for any quarter ending prior to liquidation, all cash on hand at the end of that quarter less the amount of cash reserves that the general partner determines to establish to:
 
•
provide for the proper conduct of our business, including for future capital expenditures and credit and other needs;


23

•
comply with applicable law or any partnership debt instrument or other agreement; or

•
provide funds for distributions to unitholders and the general partner in respect of any one or more of the next four quarters.
 
The actual distributions we will declare will be subject to our operating performance, prevailing market conditions (including forward oil, natural gas and sulfur prices), the impact of unforeseen events and the approval of our Board of Directors and will be done pursuant to our distribution policy.
 
Revolving Credit Facility
 
On June 22, 2011, we entered into an Amended and Restated Credit Agreement (as amended, the “Credit Agreement”) with Wells Fargo Bank, National Association, as administrative agent and swingline lender, Bank of America, N.A. and The Royal Bank of Scotland plc, as co-syndication agents, BNP Paribas, as documentation agent, and the other lenders who are parties to the Credit Agreement. The Credit Agreement amended and restated our prior $880 million Credit Agreement (the “Prior Credit Agreement”). Upon the effectiveness of the Credit Agreement, all commitments of the lenders party to the Prior Credit Agreement were terminated and all of our loans and other indebtedness under the Prior Credit Agreement were renewed and extended, inclusive of new lender commitments, on the terms and conditions of the Credit Agreement. The Credit Agreement matures on June 22, 2016.
On December 28, 2012, we received increased commitments from our lending group under the Credit Agreement. Aggregate commitments increased from $675 million to $820 million. We have the option to request further increases, subject to the terms and conditions of the Credit Agreement, up to a total aggregate amount of $1.2 billion. Availability under the Credit Agreement is subject to a borrowing base comprised of two components: the upstream component and the midstream component. As of December 31, 2013, our borrowing base totaled approximately $775 million.
As of December 31, 2013, we had approximately $49.2 million of availability under the revolving credit facility.
Senior Unsecured Notes
On May 27, 2011, we completed the sale of $300 million of our 8.375% senior unsecured notes due 2019 through a private placement, which were exchanged for registered notes on February 15, 2012 (the "Senior Notes"). The Senior Notes will mature on June 1, 2019, and interest is payable on June 1 and December 1 each year. We used the net proceeds of approximately $290.3 million to repay borrowings outstanding under our revolving credit facility.
On July 13, 2012, we completed the sale of an additional $250 million of senior notes (the "2012 Senior Notes") through a private placement. After the original discount of $3.7 million and excluding related offering expenses, we received net proceeds of approximately $246.3 million, which were used to repay borrowings outstanding under our revolving credit facility.

In connection with our Midstream Business Contribution with Regency, Regency will conduct an offer to exchange the full $550 million face value of our senior unsecured notes into an equivalent amount of Regency senior unsecured notes with the same tenor, coupon and a comparable covenant package. Should all holders elect to tender their notes in the exchange, we will no longer have any of the senior unsecured notes outstanding.

Debt Covenants
 
On July 23, 2013, the Credit Agreement was amended to allow for a temporary step-up in the Total Leverage Ratio and the Senior Secured Leverage Ratio, as defined therein, through the third quarter of 2014 and the third quarter of 2013, respectively. The amendment also extends the period of time we are subject to the Senior Secured Leverage Ratio from September 30, 2013 to September 30, 2014.

Our revolving credit facility requires us to maintain certain leverage, current and interest coverage ratios. As of December 31, 2013, we were in compliance with all of our debt covenants.
 

24

The following table presents the debt covenant levels specified in our revolving credit facility as of December 31, 2013:

Quarter Ended
Total Leverage Ratio
Senior Secured Leverage Ratio
Interest Coverage Ratio
Current Ratio
December 31, 2013
5.50x
3.15x
2.50x
1.0x
March 31, 2014
5.25x
3.10x
2.50x
1.0x
June 30, 2014
5.00x
3.05x
2.50x
1.0x
September 30, 2014
4.75x
2.95x
2.50x
1.0x
Thereafter
4.50x
NA
2.50x
1.0x

Our actual financial covenant ratios as of December 31, 2013, were as follows:
 
Interest coverage ratio
3.1
Total leverage ratio
5.4
Senior secured leverage ratio
3.06
Current ratio
1.1

As of December 31, 2013, we were in compliance with all of our debt covenants.

On February 26, 2014, we and our lender group amended the revolving credit facility to, among other items, allow for a temporary step-up in the Total Leverage Ratio and Senior Secured Leverage Ratio, and allow for additional liquidity at our election.

For a further discussion of the Credit Agreement amendment, see Note 20 to our consolidated financial statements.

Our long-term target is to maintain our ratio of total outstanding debt to Adjusted EBITDA, or "total leverage ratio," at or below 3.5 to 1.0 on a long-term basis, while acknowledging that at times this ratio may exceed our targeted levels, particularly following acquisitions or major development projects. For example, our total leverage ratio exceeded our long-term target as of December 31, 2013, due in part to: (i) our funding of ongoing drilling and other capital projects and (ii) lower NGL prices and other factors negatively impacting our Adjusted EBITDA. As discussed in previous filings, we conducted a process in 2013 in which we explored a number of alternatives to reduce our leverage ratio. That process culminated in the proposed contribution of our Midstream Business to Regency for total consideration of up to $1.325 billion. We expected the Midstream Business Contribution to substantially improve our liquidity and debt ratios through the elimination of significant debt currently outstanding under our revolving credit facility and the proposed assumption of all of our senior unsecured notes via an exchange offer to be conducted by Regency. The completion of the Midstream Business Contribution was subject to regulatory and unitholder approvals. As a result, we provided no assurance that the Midstream Business Contribution would be completed within our anticipated time frame, or at all. Should the Midstream Business Contribution not be consummated, we intended to explore alternative means to reduce our leverage ratios, which may include asset sales or purchases, equity financings, the separation of our upstream and midstream businesses or other alternatives.

Our Senior Notes were issued under an indenture that contains certain covenants limiting our ability to, among others, pay distributions, repurchase our equity securities, make certain investments, incur additional indebtedness and sell assets.
 
At December 31, 2013, we were in compliance with our covenants under the Senior Notes indenture.

For a further discussion of our revolving credit facility and Senior Notes, see Note 8 to our consolidated financial statements.

Cash Flows

Cash Distributions


25

The Partnership has declared a cash distribution for each quarter since its initial public offering. The table below summarizes these distributions for the last three years. 
Quarter Ended
 
Distribution
per Unit
 
Record Date**
 
Payment Date
March 31, 2011+
 
$
0.1500

 
May 9, 2011
 
May 13, 2011
June 30, 2011+
 
$
0.1875

 
August 5, 2011
 
August 12, 2011
September 30, 2011+
 
$
0.2000

 
November 4, 2011
 
November 14, 2011
December 31, 2011+
 
$
0.2100

 
February 7, 2012
 
February 14, 2012
March 31, 2012+
 
$
0.2200

 
May 8, 2012
 
May 15, 2012
June 30, 2012+
 
$
0.2200

 
August 7, 2012
 
August 14, 2012
September 30, 2012+
 
$
0.2200

 
November 7, 2012
 
November 14, 2012
December 31, 2012+
 
$
0.2200

 
February 7, 2013
 
February 14, 2013
March 31, 2013+*
 
$
0.2200

 
May 7, 2013
 
May 15, 2013
June 30, 2013+*
 
$
0.2200

 
August 7, 2013
 
August 14, 2013
September 30, 2013+*
 
$
0.1500

 
November 7, 2013
 
November 14, 2013
December 31, 2013+*
 
$
0.1500

 
February 7, 2014
 
February 14, 2014
_____________________________
+
The distribution per unit represents distributions made only on common units, including restricted common units issued under our Long-Term Incentive Plan. Since July 30, 2010, the only other class of equity we have outstanding is a non-economic general partner interest.
*
The distribution excludes certain restricted unit grants.
**
The "Record Date" set forth in the table above means the close of business on each of the listed Record Dates.

Working Capital

Working capital is the amount by which current assets exceed current liabilities. As of December 31, 2013, working capital, excluding assets and liabilities held for sale, was a negative $52.8 million as compared to a positive $24.1 million as of December 31, 2012.
 
The net decrease in working capital of $28.7 million from December 31, 2012 to December 31, 2013 resulted primarily from the following factors:

•
risk management net working capital balance decreased by a net $17.4 million as a result of changes in current portion of mark-to-market positions as a result of increases to the forward crude oil, natural gas and NGL price curves, partially offset by increases in the interest rate forward curve;

•
accrued liabilities increased by $7.1 million primarily reflecting increases in current asset retirement obligations;
 
•
accounts payable decreased by $11.7 million primarily as a result of activities and timing of payments, including capital expenditure activities; and

•
other current assets decreased by $1.8 million primarily as a result of timing of payments of prepaid expenses; partially offset by

•
trade accounts receivable increased by $14.1 million primarily from the impact of the Panhandle Acquisition; and

•
cash balances and marketable securities increased overall by $0.1 million.
 
Cash Flows for the Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012

Cash Flow from Operating Activities. Cash flows from operating activities increased $38.9 million during the year ended December 31, 2013 as compared to the year ended December 31, 2012. This increase was primarily due to:

•
Timing of cash payments and cash receipts, partially offset by a decrease in our results of operations as a result of increased operating costs and lower commodity risk management settlements as a result of increased oil and natural gas prices; and  


26

•
During the year ended December 31, 2012, we made payments of $6.6 million to terminate certain interest rate swaps, adjust the strike price on an existing WTI crude oil swap and partially unwind certain other commodity derivative contracts. During the year ended December 31, 2013, we did not make any payments to unwind any derivative contracts.

Cash Flows from Investing Activities. Cash flows used in investing activities for the year ended December 31, 2013 were $149.9 million as compared to cash flows used in investing activities of $152.5 million for the year ended December 31, 2012. The decrease was driven by:

•
A decrease in capital expenditures during the year ended December 31, 2013 of $18.0 million as compared to the same period in 2012, in particular, decreased spending on our drilling program; and  

•
Decreased proceeds from the sale of assets of $15.3 million during the year ended December 31, 2013, as compared to the same period in 2012.
    
Cash Flows from Financing Activities. Cash flows provided by financing activities during the year ended December 31, 2013 were $69.7 million as compared to cash flows provided by financing activities of $165.5 million for the year ended December 31, 2012. The decrease was driven by:

•
During the year ended December 31, 2012, we received net proceeds of $22.3 million and $31.8 million, respectively, from the sale of our Senior Notes and the exercise of warrants;

•
Increased distributions of $6.7 million during the year ended December 31, 2013, as compared to the same period in 2012, as a result of an increase in our units outstanding;

•
Proceeds from derivative contracts decreased by $13.1 million during the year ended December 31, 2013, as compared to the same period in 2012; and

•
Net proceeds on our revolving credit facility were $98.3 million during the year ended December 31, 2013, as compared to net proceeds of $127.0 million during the year ended December 31, 2012.

The decrease was partially offset by:

•
Increased net proceeds of $6.2 million from our equity offering during the year ended December 31, 2013, as compared to the same period in 2012.

Cash Flows Year Ended December 31, 2012 Compared to Year Ended December 31, 2011   

Cash Flow from Operating Activities. Cash flows from operating activities increased $14.9 million during the year ended December 31, 2012 as compared to the year ended December 31, 2011. This increase was primarily due to:
 
•
An increase in our results of operations from our Mid-Continent Acquisition and higher commodity prices, which resulted in higher cash flows from the sale of our equity crude oil and NGLs volumes and higher cash flows from the sale of sulfur;  

•
Lower commodity prices also resulted in us realizing net settlement losses on our commodity derivatives during the year ended December 31, 2012; and

•
During the year ended December 31, 2012, we made payments of $6.6 million to to terminate certain interest rate swaps, adjust the strike price on an existing WTI crude oil swap and partially unwind certain other commodity derivative contracts, compared to $15.8 million in payments made during the year ended December 31, 2011.
    
Cash Flows from Investing Activities. Cash flows used in investing activities for the year ended December 31, 2012 were $152.5 million as compared to cash flows used in investing activities of $297.3 million for the year ended December 31, 2011. The increase was driven by:

•
An decrease in net cash outlay of $220.3 million for the Mid-Continent Acquisition during the year ended December 31, 2011; and


27

•
Increased capital expenditures of $91.0 million for capital expenditures, in particular spending related to our increased drilling as a result of our Mid-Continent Acquisition in 2011.  

These increases were partially offset by:

•
Increased proceeds from the sale of assets of $15.4 million during the year ended December 31, 2012, as compared to the same period in 2011.
    
Cash Flows from Financing Activities. Cash flows provided by financing activities during the year ended December 31, 2012 were $165.5 million as compared to cash flows used by financing activities of $9.8 million for the year ended December 31, 2011. The increase was due to:

•
Net borrowings on our revolving credit facility of $127.0 million during the year ended December 31, 2012 as compared to net repayments of $48.5 million to our revolving credit facility during the year ended December 31, 2011;

•
Increased net proceeds of $91.7 million from our equity offering during the year ended December 31, 2012, as compared to the same period in 2011; and

•
Proceeds from derivative contracts increased by $8.2 million during the year ended December 31, 2012, as compared to the same period in 2011.

These increases were partially offset by:

•
During the year ended December 31, 2012 we received net proceeds of $22.9 million from the sale of our Senior Notes compared to net proceeds of $27.7 million during the year ended December 31, 2012;

•
Increased distributions of $44.7 million during the year ended December 31, 2012 as compared to the same period in 2011, as a result of increasing our quarterly distribution and units outstanding; and

•
During the year ended December 31, 2012 we received proceeds of $31.8 million due to the exercise of warrants, as compared to $89.7 million from the exercise of warrants during the same period in 2011.

Hedging Strategy
 
We use a variety of hedging instruments such as fixed-price swaps, costless collars and put options to manage our risks related to our commodity price and interest rate exposure. At times our hedging strategy may involve adjusting strike prices of existing hedges to better reflect current market conditions or to meet other corporate objectives.  In addition, we may also terminate or unwind hedges or portions of hedges when the expected future volumes do not support the level of hedges.  Hedge transactions such as these impact our liquidity in that we are required to pay the present value of the difference between the hedged price and the current futures price.  These transactions also increase our exposure to the counterparties through which we execute the hedges.
  
Off-Balance Sheet Obligations.
 
We have no off-balance sheet transactions or obligations. 


28

Total Contractual Obligations.

The following table summarizes our total contractual cash obligations as of December 31, 2013:
 
 
 
Payments Due by Period
 Contractual Obligations
 
 Total
 
2014
 
2015
 
2016
 
2017-2018
 
Thereafter
 
 
 ($ in millions)
Revolving Credit Facility (including interest)(a) 
 
$
753,491

 
$
18,873

 
$
18,873

 
$
715,745

 
$
—

 
$
—

Senior Notes
 
799,496

 
46,063

 
46,063

 
46,063

 
92,125

 
569,182

Operating leases
 
21,388

 
7,060

 
6,045

 
4,997

 
3,286

 
—

Asset Retirement Obligations
 
58,964

 
13,116

 
1,336

 
2,123

 
9,982

 
32,407

Total contractual obligations
 
$
1,633,339

 
$
85,112

 
$
72,317

 
$
768,928

 
$
105,393

 
$
601,589

__________________________
(a)
These amounts exclude estimates of the effect of our interest rate swap contracts on our future interest obligations. As of December 31, 2013, the fair value of our interest rate swap contracts, which expire on June 22, 2015, totaled a liability of $9.1 million.

The table above includes obligations related to our Midstream Business and liabilities that have been classified as held for sale.

Recent Accounting Pronouncements
 
For a recent accounting pronouncements, please see Note 3 of our consolidated financial statements.

29

EAGLE ROCK ENERGY PARTNERS, L.P.
INDEX TO FINANCIAL STATEMENTS
 


F- 1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Eagle Rock Energy G&P, LLC and Unitholders of Eagle Rock Energy Partners, L.P.:
We have audited the accompanying consolidated balance sheets of Eagle Rock Energy Partners, L.P. and subsidiaries (collectively, the “Partnership”) as of December 31, 2013 and 2012, and the related consolidated statements of operations, members’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2013. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the years in the three‑year period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),Eagle Rock Energy Partners, L.P.’s internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 3, 2014 expressed an unqualified opinion on the effectiveness of the Partnership’s internal control over financial reporting.

/s/ KPMG LLP
Houston, Texas
March 3, 2014, except as to Notes 1, 3, 11, 12, 17, 18, 19, and 20, which are as of September 17, 2014
 





F- 2
EAGLE ROCK ENERGY PARTNERS, L.P.


CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2013 AND 2012
($ in thousands)

 
December 31,
2013
 
December 31,
2012
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
76

 
$
25

Accounts receivable (a)
17,250

 
31,309

Risk management assets
5,559

 
15,750

Prepayments and other current assets
6,123

 
7,962

Assets held for sale
1,259,382

 
1,243,602

Total current assets
1,288,390

 
1,298,648

PROPERTY, PLANT AND EQUIPMENT — Net
824,451

 
982,784

INTANGIBLE ASSETS — Net
3,268

 
3,464

DEFERRED TAX ASSET
1,438

 
1,656

RISK MANAGEMENT ASSETS
3,871

 
(767
)
OTHER ASSETS
6,132

 
8,431

TOTAL
$
2,127,550

 
$
2,294,216

 
 

 
 

LIABILITIES AND MEMBERS' EQUITY
 

 
 

CURRENT LIABILITIES:
 

 
 

Accounts payable
$
50,158

 
$
61,843

Accrued liabilities
23,162

 
16,032

Taxes payable
149

 
46

Risk management liabilities
8,360

 
1,201

Liabilities held for sale
637,738

 
609,099

Total current liabilities
719,567

 
688,221

LONG-TERM DEBT
757,480

 
659,117

ASSET RETIREMENT OBLIGATIONS
37,306

 
35,799

DEFERRED TAX LIABILITY
34,097

 
39,592

RISK MANAGEMENT LIABILITIES
2,826

 
1,700

OTHER LONG TERM LIABILITIES
2,395

 
1,413

COMMITMENTS AND CONTINGENCIES (Note 13)


 


MEMBERS' EQUITY (b)
573,879

 
868,374

TOTAL
$
2,127,550

 
$
2,294,216

________________________ 

(a)
Net of allowance for bad debt of $931 as of December 31, 2013 and $753 as of December 31, 2012.
(b)
156,644,153 and 144,675,751 common units were issued and outstanding as of December 31, 2013 and December 31, 2012, respectively. These amounts do not include unvested restricted common units granted under the Partnership's long-term incentive plan of 2,743,807 and 2,608,035 as of December 31, 2013 and December 31, 2012, respectively.

See accompanying notes to consolidated financial statements.  


F- 3
EAGLE ROCK ENERGY PARTNERS, L.P.


CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
($ in thousands)
 
 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
 REVENUE:
 
 

 
 

 
 
Natural gas, natural gas liquids, oil, condensate, sulfur and helium sales
 
$
200,608

 
$
201,719

 
$
202,634

Commodity risk management gains (losses), net
 
(3,937
)
 
28,110

 
37,269

Other revenue
 
701

 
1,486

 
1,676

Total revenue
 
197,372

 
231,315

 
241,579

COSTS AND EXPENSES:
 
 

 
 

 
 
Operations and maintenance
 
41,426

 
41,391

 
32,287

Taxes other than income
 
12,928

 
15,343

 
15,436

General and administrative
 
53,131

 
50,990

 
42,525

Impairment and other
 
214,286

 
45,289

 
11,728

Depreciation, depletion and amortization
 
89,444

 
90,510

 
66,909

Total costs and expenses
 
411,215

 
243,523

 
168,885

OPERATING (LOSS) INCOME
 
(213,843
)
 
(12,208
)
 
72,694

OTHER INCOME (EXPENSE):
 
 

 
 

 
 
Interest expense, net
 
(18,789
)
 
(16,276
)
 
(10,845
)
Interest rate risk management losses, net
 
(1,104
)
 
(4,727
)
 
(11,401
)
Other expense, net
 
(30
)
 
(28
)
 
(149
)
Total other expense
 
(19,923
)
 
(21,031
)
 
(22,395
)
(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
 
(233,766
)
 
(33,239
)
 
50,299

INCOME TAX BENEFIT
 
(5,595
)
 
(1,093
)
 
(3,350
)
(LOSS) INCOME FROM CONTINUING OPERATIONS
 
(228,171
)
 
(32,146
)
 
53,649

DISCONTINUED OPERATIONS, NET OF TAX
 
(49,808
)
 
(118,456
)
 
19,483

NET (LOSS) INCOME
 
$
(277,979
)
 
$
(150,602
)
 
$
73,132

 
 See accompanying notes to consolidated financial statements.  
 









F- 4
EAGLE ROCK ENERGY PARTNERS, L.P.


CONSOLIDATED STATEMENTS OF OPERATIONS (continued)
FOR THE YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011


 
Year Ended December 31,
 
2013
 
2012
 
2011
NET INCOME PER COMMON UNIT—BASIC AND DILUTED:
 
 
 
 
 
Income (loss) from Continuing Operations
 
 
 
 
 
Common units - Basic
$
(1.50
)
 
$
(0.26
)
 
$
0.47

Common units - Diluted
$
(1.50
)
 
$
(0.26
)
 
$
0.45

Discontinued Operations
 
 
 
 
 
Common units - Basic
$
(0.32
)
 
$
(0.87
)
 
$
0.18

Common units - Diluted
$
(0.32
)
 
$
(0.87
)
 
$
0.17

Net Income (loss)
 
 
 
 
 
Common units - Basic
$
(1.82
)
 
$
(1.13
)
 
$
0.65

Common units - Diluted
$
(1.82
)
 
$
(1.13
)
 
$
0.62

Weighted Average Units Outstanding (in thousands)
 
 
 
 
 
Common units - Basic
153,562

 
135,609

 
110,435

Common units - Diluted
153,562

 
135,609

 
116,941


See accompanying notes to consolidated financial statements.  


F- 5
EAGLE ROCK ENERGY PARTNERS, L.P.


CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
(in thousands, except unit amounts)
 
 
Number of
Common
Units
 
Common
Units
 
Total
BALANCE — January 1, 2011
 
83,425,378

 
$
579,113

 
$
579,113

Net income
 
—

 
73,132

 
73,132

Distributions
 
—

 
(74,512
)
 
(74,512
)
Vesting of restricted units
 
608,122

 
—

 
—

Exercised warrants
 
14,957,540

 
89,745

 
89,745

Repurchase of common units
 
(137,985
)
 
(1,401
)
 
(1,401
)
Equity based compensation
 
—

 
5,145

 
5,145

Units issued for acquisitions
 
28,753,174

 
336,125

 
336,125

BALANCE — December 31, 2011
 
127,606,229

 
1,007,347

 
1,007,347

Net loss
 
—

 
(150,602
)
 
(150,602
)
Distributions
 
—

 
(119,211
)
 
(119,211
)
Vesting of restricted units
 
1,101,323

 
—

 
—

Exercised warrants
 
5,300,588

 
31,804

 
31,804

Repurchase of common units
 
(286,716
)
 
(2,501
)
 
(2,501
)
Equity based compensation
 
—

 
9,882

 
9,882

Common units issued in equity offering
 
10,954,327

 
96,173

 
96,173

Unit issuance costs for equity offering
 
—

 
(4,518
)
 
(4,518
)
BALANCE — December 31, 2012
 
144,675,751

 
868,374

 
868,374

Net loss
 
—

 
(277,979
)
 
(277,979
)
Distributions
 
—

 
(125,911
)
 
(125,911
)
Vesting of restricted units
 
1,203,822

 
—

 
—

Repurchase of common units
 
(272,179
)
 
(1,858
)
 
(1,858
)
Equity based compensation
 
—

 
13,384

 
13,384

Common units issued in equity offering
 
11,036,759

 
102,388

 
102,388

Unit issuance costs for equity offering
 
—

 
(4,519
)
 
(4,519
)
BALANCE — December 31, 2013
 
156,644,153

 
$
573,879

 
$
573,879


 See accompanying notes to consolidated financial statements.  


F- 6
EAGLE ROCK ENERGY PARTNERS, L.P.


CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2013, 2012, AND 2011
($ in thousands)
 
Year Ended December 31,
 
2013
 
2012
 
2011
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
 
 
Net (loss) income
$
(277,979
)
 
$
(150,602
)
 
$
73,132

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
Discontinued operations
49,808

 
118,456

 
(19,483
)
Depreciation, depletion and amortization
89,444

 
90,510

 
66,909

Impairment and other
214,286

 
45,289

 
11,728

Amortization of debt issuance costs
2,151

 
1,735

 
1,621

Loss (gain) from risk management activities, net
5,041

 
(23,383
)
 
(25,868
)
Derivative settlements
7,478

 
5,368

 
(22,456
)
Equity-based compensation
10,392

 
7,719

 
4,297

Loss (gain) on sale of assets
(76
)
 
—

 
(39
)
Other
(1,197
)
 
(592
)
 
(2,304
)
Changes in assets and liabilities—net of acquisitions:
 
 
 
 
 
Accounts receivable
14,280

 
(26,742
)
 
19,636

Prepayments and other current assets
1,838

 
2,087

 
(5,712
)
Risk management activities
—

 
(6,607
)
 
(15,773
)
Accounts payable
1,738

 
14,198

 
(30,023
)
Accrued liabilities
(964
)
 
2,519

 
3,048

Other assets
143

 
(2,985
)
 
2,680

Other current liabilities
(2,140
)
 
(1,634
)
 
(974
)
Net cash provided by operating activities
114,243

 
75,336

 
60,419

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
 
 
Additions to property, plant and equipment
(149,944
)
 
(167,907
)
 
(76,938
)
Acquisitions, net of cash acquired
—

 
—

 
(220,326
)
Proceeds from sale of assets
76

 
15,398

 
—

Net cash used in investing activities
(149,868
)
 
(152,509
)
 
(297,264
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 
 
Proceeds from long-term debt
601,400

 
1,043,750

 
964,279

Repayment of long-term debt
(503,100
)
 
(916,750
)
 
(1,012,779
)
Proceeds from senior notes
—

 
22,889

 
27,683

Payment of debt issuance costs
—

 
(614
)
 
(9,116
)
Proceeds from derivative contracts
1,323

 
14,449

 
6,267

Common units issued in equity offerings
102,388

 
96,173

 
—

Issuance costs for equity offerings
(4,519
)
 
(4,518
)
 
—

Exercise of warrants
—

 
31,804

 
89,745

Repurchase of common units
(1,858
)
 
(2,501
)
 
(1,401
)
Distributions to members and affiliates
(125,911
)
 
(119,211
)
 
(74,512
)
Net cash provided by (used in) financing activities
69,723

 
165,471

 
(9,834
)
CASH FLOWS FROM DISCONTINUED OPERATIONS:
 
 
 
 
 
Operating activities
63,133

 
70,165

 
58,375

Investing activities
(97,180
)
 
(376,161
)
 
(76,672
)
Financing activities
—

 
216,846

 
261,804

Net cash (used in) provided by discontinued operations
(34,047
)
 
(89,150
)
 
243,507

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS
51

 
(852
)
 
(3,172
)
CASH AND CASH EQUIVALENTS—Beginning of period
25

 
877

 
4,049

CASH AND CASH EQUIVALENTS—End of period
$
76

 
$
25

 
$
877

 
 
 
 
 
 
NONCASH INVESTING AND FINANCING ACTIVITIES:
 
 
 
 
 
Units issued for acquisitions
$
—

 
$
—

 
$
336,125

Investments in property, plant and equipment, not paid
$
9,469

 
$
29,568

 
$
31,374

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
 
 
 
 
 
Interest paid—net of amounts capitalized
$
65,309

 
$
45,614

 
$
24,682

Cash paid for taxes
$
59

 
$
1,085

 
$
1,516

See accompanying notes to consolidated financial statements.  

F- 7
EAGLE ROCK ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2013, 2012 AND 2011


NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS
 
Description of Business—Eagle Rock Energy Partners, L.P. ("Eagle Rock Energy" or the "Partnership") is a growth-oriented master limited partnership engaged, as of July 1, 2014, in (a) the exploitation, development, and production of oil and natural gas properties and (b) ancillary gathering, compressing, treating, processing and marketing services with respect to its production of natural gas, natural gas liquids, condensate and crude oil (collectively, the "Upstream Business"). The Partnership's assets, located primarily in South Alabama (where it also operates the associated gathering and processing assets), Texas, Oklahoma, Mississippi and Arkansas, are characterized by long-lived, high-working interest properties with extensive production histories and development opportunities.

On July 1, 2014, the Partnership contributed its business of gathering, compressing, treating, processing, transporting, marketing and trading natural gas, fractionating, transporting and marketing natural gas liquids ("NGLs") and crude oil and condensate logistics and marketing (collectively, the “Midstream Business”) to Regency Energy Partners LP ("Regency") (such contribution, the "Midstream Business Contribution"). The consideration received by the Partnership pursuant to the Midstream Business Contribution included: (i) $576.2 million of cash; (ii) 8,245,859 Regency common units (valued at approximately$265 million based on the closing price of Regency common units on June 30, 2014) and (iii) the exchange of $498.9 million face amount of the Partnership's outstanding unsecured senior notes ("Senior Notes") for an equivalent amount of Regency unsecured senior notes. $51.1 million of the Partnership's Senior Notes did not exchange and remain outstanding. However, the Partnership, having secured a sufficient number of consents as part of the exchange offer, amended the indenture governing its Senior Notes to eliminate substantially all of the restrictive covenants and certain events of default pertaining to its Senior Notes.
Accordingly, upon satisfaction of the significant closing conditions of the Midstream Business Contribution on June 27, 2014, the assets, liabilities and operation of the Midstream Business were classified as held-for-sale and discontinued in the condensed consolidated financial statements. All periods have been retrospectively adjusted to reflect assets and liabilities held-for-sale and operations as discontinued (see Note 16) in the financial statements included in this report. As a result of this transaction, the Partnership now will only report as one segment.
The general partner of Eagle Rock Energy is Eagle Rock Energy GP, L.P., and the general partner of Eagle Rock Energy GP, L.P. is Eagle Rock Energy G&P, LLC, both of which are wholly-owned subsidiaries of the Partnership.


NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
Basis of Presentation and Principles of Consolidation—The accompanying audited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). Eagle Rock Energy is the owner of non-operating undivided interests in certain gas processing plants and gas gathering systems. Eagle Rock Energy owns these interests as tenants-in-common with the majority owner-operator of the facilities. Accordingly, Eagle Rock Energy includes its pro-rata share of assets, liabilities, revenues and expenses related to these assets in its financial statements. The assets and liabilities related to these undivided interests have been classified as held for sale within the audited consolidated balance sheets, while the operations related to these interest have been classified as discontinued within the audited consolidated statements of operations (see Note 18).

All intercompany accounts and transactions are eliminated in the consolidated financial statements.
Use of Estimates—The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Significant estimates are required for proved oil and natural gas reserves, which can affect the carrying value of oil and natural gas properties. The Partnership evaluates its estimates and assumptions on a regular basis. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates and such differences could be material.
Cash and Cash Equivalents—Cash and cash equivalents include certificates of deposit and other highly liquid investments with maturities of three months or less at the time of purchase.

F- 8

 
Concentration and Credit Risk—Concentration and credit risk for the Partnership principally consists of cash and cash equivalents and accounts receivable.
 
The Partnership places its cash and cash equivalents with high-quality institutions and in money market funds. The Partnership derives its revenue from customers primarily in the natural gas industry. Industry concentrations have the potential to impact the Partnership's overall exposure to credit risk, either positively or negatively, in that the Partnership's customers could be affected by similar changes in economic, industry or other conditions. However, the Partnership believes the risk posed by this industry concentration is offset by the creditworthiness of the Partnership's customer base. The Partnership's portfolio of accounts receivable is comprised primarily of mid-size to large domestic corporate entities.  

The following is the activity within the Partnership's allowance for doubtful accounts during the years ended December 31, 2013, 2012 and 2011.

 
2013
 
2012
 
2011
($ in thousands)
 
 
 
 
 
Balance at beginning of period
$
753

 
$
670

 
$
607

Charged to bad debt expense
458

 
175

 
63

Write-offs/adjustments charged to allowance
(280
)
 
(92
)
 
—

Balance at end of period
$
931

 
$
753

 
$
670


The table above does not include amounts related to the Partnership's Midstream Business, as these amounts have been classified as part of assets held for sale within the audited consolidated balance sheets and discontinued operations within the audited consolidated statements of operations (see Note 18).
 
Certain Other Concentrations—The Partnership relies on natural gas producers for its Midstream Business's natural gas and natural gas liquid supply, with the top two producers accounting for 36% of its natural gas supply in the Texas Panhandle area and 25% of its natural gas supply in the Midstream Business' other operating areas for the year ended December 31, 2013. While there are numerous natural gas and natural gas liquid producers, and some of these producers are subject to long-term contracts, the Partnership may be unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. If the Partnership were to lose all or even a portion of the natural gas volumes supplied by these producers and was unable to acquire comparable volumes, the Partnership's results of operations and financial position could be materially adversely affected. These percentages are calculated based on natural gas volumes gathered during the year ended December 31, 2013. For the year ended December 31, 2013, Oneok, Inc. and Chevron Corporation, the Partnership's largest customers, represented 22% and 11%, respectively, of its total sales revenue (including its commodity risk management gains and losses and revenue amounts classified as part of discontinued operations).

Inventory—Inventory is stated at the lower of cost or market, with cost being determined using the average cost method. At December 31, 2013 and December 31, 2012, the Partnership had $1.0 million and $0.8 million, respectively, of crude oil finished goods inventory which is recorded as part of assets held for sale within the audited consolidated balance sheet.

Property, Plant and Equipment—Property, plant and equipment, including amounts classified as held for sale, consists primarily of gas gathering systems, gas processing plants, NGL pipelines, conditioning and treating facilities and other related facilities, and oil and natural gas properties, which are carried at cost less accumulated depreciation, depletion and amortization. The Partnership charges repairs and maintenance against income when incurred and capitalizes renewals and betterments, which extend the useful life or expand the capacity of the assets. The Partnership capitalizes interest costs on major projects during extended construction time periods. Such interest costs are allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. The Partnership calculates depreciation on the straight-line method over estimated useful lives of the Partnership's newly developed or acquired assets. The weighted average useful lives are as follows:
 

F- 9

Plant Assets
20 years
Pipelines and equipment
20 years
Gas processing and equipment
20 years
Office furniture and equipment
5 years

Plant assets, pipelines and equipment, gas process and equipment and certain office furniture and equipment related to the Partnership's Midstream Business have been classified as assets held for sale within the audited consolidated balance sheets. Depreciation expense related to these assets has been recorded as part of discontinued operations within the audited consolidated statements of operations (see Note 18).

Oil and Natural Gas Properties—The Partnership utilizes the successful efforts method of accounting for its oil and natural gas properties. Leasehold costs are capitalized when incurred. Costs incurred to drill and complete development wells are capitalized. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if the well is determined to be unsuccessful. The Partnership carries the costs of an exploratory well as an asset if the well is found to have a sufficient quantity of reserves to justify its capitalization as a producing well as long as the Partnership is making sufficient progress towards assessing the reserves and the economic and operating viability of the project.

Depletion of producing oil and natural gas properties is recorded based on units of production. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for acquisition costs using all proved reserves. Authoritative guidance requires that acquisition costs of proved properties be amortized on the basis of all proved reserves (developed and undeveloped), and that capitalized development costs (wells and related equipment and facilities) be amortized on the basis of proved developed reserves.

Upon sale or retirement of complete fields of depreciable or depleted property, the book value thereof, less proceeds or salvage value, is charged or credited to income.

Costs related to unproved properties include costs incurred to acquire unproved reserves.  Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties.  Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience, drilling plans and average lease-term lives.  Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a units of production basis.  Unproved properties (both individually significant and insignificant) are assessed periodically within specific geographic areas and, if necessary, impairments are charged to expense.

Other Assets— As of December 31, 2013 and 2012, other assets, excluding amounts classified as held for sale (see Note 18), primarily consist of costs associated with debt issuance costs, net of amortization, of $6.1 million and $8.4 million, respectively.

Impairment of Long-Lived Assets—Management evaluates whether the carrying value of non-oil and natural gas long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment, including, but not limited to:

•
significant adverse changes in legal factors or in the business climate;
•
a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast which demonstrates continuing losses associated with the use of a long-lived asset;
•
an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;
•
significant adverse changes in the extent or manner in which an asset is used or in its physical condition;
•
a significant change in the market value of an asset; or
•
a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.


F- 10

For its oil and natural gas long-lived assets, the Partnership reviews its proved properties at the field level when management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a negative revision or unfavorable projection of future oil and natural gas reserves and/or forward prices that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels.

If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset's carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management's intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.  

See Note 5 for further discussion on impairment charges.
 
Revenue Recognition—Revenues associated with sales of natural gas, NGLs, crude oil, condensate and sulfur are recognized when title passes to the customer, which is when the risk of ownership passes to the customer and physical delivery occurs.

Revenues for the Partnership's Midstream Business included the sale of natural gas, NGLs, crude oil, condensate, sulfur and helium and from the compression, gathering, processing, treating and transportation of natural gas. Revenues associated with transportation and processing fees were recognized in the period when the services were provided. These revenues have been classified as discontinued operations within the unaudited condensed consolidated statements of operations.

The Partnership's Upstream Business recognizes natural gas revenues based on the amount of natural gas sold to purchasers. The volumes of natural gas sold may differ from the volumes to which the Partnership is entitled based on its interests in the properties. Differences between volumes sold and volumes based on entitlements create natural gas imbalances. Imbalances are reflected as adjustments to reported natural gas reserves and future cash flows.  For the Upstream Business, as of December 31, 2013 and December 31, 2012, the Partnership had long-term imbalance payables of $0.3 million and $0.6 million, respectively.
 
Transportation and Exchange Imbalances—In the course of transporting natural gas and NGLs for others, the Partnership may receive for redelivery different quantities of natural gas or NGLs than the quantities actually delivered. These transactions result in transportation and exchange imbalance receivables or payables which are recovered or repaid through the receipt or delivery of natural gas or NGLs in future periods, if not subject to cash out provisions. Imbalance receivables are included in accounts receivable and imbalance payables are included in accounts payable on the consolidated balance sheets and marked-to-market using current market prices in effect for the reporting period of the outstanding imbalances. For the Midstream Business, as of December 31, 2013, the Partnership had imbalance receivables totaling $0.7 million and imbalance payables totaling $1.6 million. For the Midstream Business, as of December 31, 2012, the Partnership had imbalance receivables totaling $0.9 million and imbalance payables totaling $2.1 million. Imbalance receivables and payables have been classified as held for sale within the audited consolidated balance sheets. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results in either an upward or downward adjustment, as appropriate, to the cost of natural gas sold, and have been classified as discontinued operations within the audited consolidated statements of operations.

Environmental Expenditures—Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures which relate to an existing condition caused by past operations and do not generate current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated.
 
Income Taxes—Provision for income taxes is primarily applicable to the Partnership's state tax obligations under the Revised Texas Franchise Tax (the “Revised Texas Franchise Tax”) and certain federal and state tax obligations of Eagle Rock Energy Acquisition Co., Inc., Eagle Rock Acquisition Co. II, Inc., Eagle Rock Upstream Development Company, Inc. and Eagle Rock Upstream Development Company II, Inc., all of which are consolidated subsidiaries. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of the tax paying entities for financial reporting and tax purposes.

F- 11

 
In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax. In May 2006, the State of Texas expanded its pre-existing franchise tax to include limited partnerships, limited liability companies, corporations and limited liability partnerships. As a result of the change in tax law, the Partnership's tax status in the State of Texas changed from non-taxable to taxable effective with the 2007 tax year.
 
Since the Partnership is structured as a pass-through entity, it is not subject to federal income taxes. As a result, its partners are individually responsible for paying federal and certain income taxes on their share of the Partnership's taxable income. Since the Partnership does not have access to information regarding each partner's tax basis, it cannot readily determine the total difference in the basis of the Partnership's net assets for financial and tax reporting purposes.
 
Derivatives—Authoritative guidance establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires an entity to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The guidance provides that normal purchase and sale contracts, when appropriately designated, are not subject to the guidance. Normal purchases and sales are contracts which provide for the purchase or sale of something, other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. The Partnership's forward natural gas and crude oil purchase and sales contracts are designated as normal purchases and normal sales, with the exception of certain contracts with our natural gas trading and marketing business. The Partnership uses financial instruments such as swaps, collars and other derivatives to mitigate the risks to cash flows resulting from changes in commodity prices and interest rates. The Partnership recognizes these financial instruments on its consolidated balance sheet at the instrument's fair value with changes in fair value reflected in the consolidated statement of operations, as the Partnership has not designated any of these derivative instruments as hedges. The cash flows from derivatives are reported as cash flows from operating activities unless the derivative contract is deemed to contain a financing element. Derivatives deemed to contain a financing element are reported as a financing activity in the statement of cash flows. See Note 11 for a description of the Partnership's risk management activities.
    
Other Reclassifications—The prior period within the audited consolidated statements of cash flows has been reclassified to conform to current period presentation. Amounts have been reclassified to new rows titled “Loss from risk management activities, net” that combines settled and mark-to-market gains/losses on derivative instruments and “Derivative settlements” that includes cash attributable to derivative instruments that settled during the periods. The revisions to the cash flow presentation had no impact on “Net cash provided by operating activities.”

NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS

In December 2011, the FASB issued new guidance related to disclosure requirements about the nature of an entity's rights of set-off and related arrangements associated with its financial instruments and derivative instruments. The new disclosures are designed to make financial statements that are prepared under U.S. GAAP more comparable to those prepared under IFRS. To better facilitate comparison between financial statements prepared under U.S. GAAP and IFRS, the new disclosures will give financial statement users information about both gross and net exposures. The disclosure requirements are effective for annual reporting periods beginning on or after January 1, 2013, and did not have a material impact on the Partnership's financial statements for the year ended December 31, 2013. See Notes 11 and 12 for the disclosures related to the Partnership's rights of set-off and the gross and net exposure related to its derivative instruments.

In February 2013, the FASB issued new guidance related to obligations resulting from joint and several liability arrangements. The new guidance provides for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. The amendments in this update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013 and is not expected to have a material impact on the Partnership’s consolidated financial statements.

On April 10, 2014, the FASB issued new guidance which amends the definition of a discontinued operation and requires entities to provide additional disclosures about disposal transactions that do not meet the discontinued-operations criteria. Under the new guidance, a discontinued operation is defined as a disposal of a component or group of components that is disposed of or is classified as held for sale and represents a strategic shift that has or will have a major effect on an entity's operations and financial results. The new guidance is effective prospectively for all disposals (except disposals classified as held for sale before the adoption date) or components initially classified as held for sale in periods beginning on or after

F- 12

December 15, 2014, with early adoption permitted. The Partnership decided to early adopt this guidance in relation to its transaction to contribute its Midstream Business to Regency (see Notes 1 and 18).

On May 28, 2014, the FASB issued new guidance related to revenue from contracts with customers. This new guidance outlines a single comprehensive model for entities to use and supersedes most current revenue recognition guidance, including industry-specific guidance. This guidance is effective for annual reporting periods (including interim reporting periods within those periods) beginning after December 15, 2016. Early application of the guidance is not permitted. The Partnership is currently evaluating the potential impact, if any, of the adoption of this new guidance on its financial statements.


NOTE 4. ACQUISITIONS

Acquisition of Midstream Assets in the Texas Panhandle

On October 1, 2012, the Partnership completed the acquisition of two of BP America Production Company's ("BP") gas processing facilities, and the associated gathering systems, that are located in the Texas Panhandle. The aggregate purchase price of the system was $230.6 million, which the Partnership funded from borrowings under its revolving credit facility. The results of the operations of the system have been included in the consolidated financial statements since the acquisition date. The Partnership incurred $0.5 million of acquisition related expenses, which are included within discontinued operations for the year ended December 31, 2012. The Partnership incurred $0.1 million of acquisition related expenses, which are included within discontinued operations for the year ended December 31, 2013.

This acquisition was accounted for under the acquisition method of accounting. Accordingly, the Partnership conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions were expensed as incurred. The initial accounting for the business combinations is not complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates.

The following presents the purchase price allocation for the system assets, based on estimates of fair value (in thousands):
Current assets
$
779

Property, plant, and equipment
206,849

Rights-of-way and easements
27,232

Current liabilities
(1,705
)
Asset retirement obligations
(2,600
)
 
$
230,555

The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of property, plant and equipment, rights-of-way and easements and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of property, plant and equipment include estimates of: (i) replacement costs; (ii) useful and remaining lives; (iii) physical deterioration; and (iv) functional and technical obsolescence. These inputs require significant judgments and estimates by the Partnership's management at the time of the valuation and are the most sensitive and subject to change.
Pro forma data for the years ended December 31, 2012 and 2011 has been deemed to be impracticable as BP did not separately manage its gathering and processing facilities with the activities of the acquired assets being integrated (financially and operationally) within its exploration and production segment. The amounts of revenue and net income generated by the acquired processing plants and gathering systems that are included within the Partnership's audited consolidated statement of

F- 13

operations for the year ended December 31, 2012 are as follows.
 
Revenue
 
Net Income
 
($ in thousands)
Actual from October 1, 2012 to December 31, 2012
$
81,013

 
$
5,057

Assets acquired and liabilities assumed as part of this acquisition have been classified as part of assets and liabilities held for sale within the audited consolidated balance sheets. Operations related to these assets have been classified as part of discontinued operations within the audited consolidated statements of operations.
Acquisition of CC Energy II L.L.C.

On May 3, 2011, the Partnership completed the acquisition (the "Mid-Continent Acquisition") of all of the outstanding membership interests of CC Energy II L.L.C (together with its subsidiaries, "Crow Creek Energy"), a portfolio company of Natural Gas Partners, VIII, L.P. ("NGP VIII"). Crow Creek Energy has oil and natural gas properties located in multiple basins across Oklahoma, north Texas and Arkansas (the "Mid-Continent" properties) and provides the Partnership with an extensive inventory of low-risk development prospects in established plays such as the Golden Trend field and developing plays such as the Cana Shale. The aggregate purchase price has been calculated as follows (in thousands, except unit and per unit amounts):
Number of Partnership Common Units Issued
28,753,174

Closing common unit price on May 3, 2011
$
11.69

Value of common units issued
$
336,125

Crow Creek Energy outstanding debt assumed
212,638

Cash
14,945

Total purchase price
$
563,708

The number of common units of the Partnership issued was determined based on the value of the equity issued to the sellers of $301.9 million divided by $10.50, the ceiling price of the agreed upon range in the contribution agreement between the Partnership and Crow Creek Energy. The cash portion of the acquisition consideration and the repayment of Crow Creek Energy’s outstanding debt were funded through borrowings under the Partnership’s revolving credit facility. In addition, the Partnership incurred $2.3 million of acquisition related expenses, which are included within general and administrative expenses for the year ended December 31, 2011.
This acquisition was accounted for under the acquisition method of accounting. Accordingly, the Partnership conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions were expensed as incurred.

The following presents the purchase price allocation for the Crow Creek Energy assets, based on estimates of fair value (in thousands):
Current assets
$
25,329

Oil and gas properties
572,097

Property, plant and equipment
4,463

Rights-of-way and easements
3,192

Other assets
450

Derivatives
3,355

Current liabilities
(37,032
)
Asset retirement obligations
(4,394
)
Deferred tax liability
(2,312
)
Other liabilities
(1,440
)
 
$
563,708


F- 14

The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of oil and natural gas properties and asset retirement obligation were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimate of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Partnership's management at the time of the valuation and are the most sensitive and subject to change.
The amounts of Crow Creek Energy's revenue and net income included within the Partnership's audited consolidated statement of operations for the year ended December 31, 2011, and the pro forma revenue and net income of the combined entity had the acquisition date been January 1, 2010, are as follows:
 
Revenue
 
Net Income
 
Net Income Per Diluted Common Unit
 
($ in thousands)
 
 
Actual from May 3, 2011 to December 31, 2011
$
68,168

 
$
29,835

 
 
Supplemental pro forma from January 1, 2011 to December 31, 2011
$
1,080,964

 
$
78,591

 
$
0.62


NOTE 5. PROPERTY, PLANT AND EQUIPMENT
 
Fixed assets consisted of the following:
 
December 31,
2013
 
December 31,
2012
 
  ($ in thousands)
Equipment and machinery
$
101

 
$
101

Vehicles and transportation equipment
212

 
212

Office equipment, furniture, and fixtures
1,391

 
913

Computer equipment
12,247

 
9,475

Proved properties
1,156,895

 
1,213,622

Unproved properties
10,022

 
31,823

Construction in progress
6,636

 
3,390

 
1,187,504

 
1,259,536

Less: accumulated depreciation, depletion and amortization
(363,053
)
 
(276,752
)
Net property plant and equipment
$
824,451

 
$
982,784

    
Amounts in the table above do not include the property, plant and equipment related to the Partnership's Midstream Business, as these amounts have been classified as assets held for sale within the audited consolidated balance sheets (See Note 18).

The following table sets forth the total depreciation, depletion, capitalized interest costs and impairment expense by type of asset within the Partnership's audited consolidated statements of operations:
 
Year Ended December 31,
 
2013
 
2012
 
2011
 
  ($ in thousands)
Depreciation
$
2,018

 
$
1,795

 
$
1,493

Depletion
$
87,230

 
$
88,413

 
$
65,380

 
 
 
 
 
 
Impairment expense:
 
 
 
 
 
Proved properties (a)
$
207,085

 
$
38,943

 
$
11,239

Unproved properties (b)
$
7,201

 
$
785

 
$
489


F- 15

__________________________________
(a)
During the year ended December 31, 2013, the Partnership incurred impairment charges related primarily to certain proved properties, primarily in the Cana Shale in the Mid-Continent region and the Permian region, due to lower reserve forecasts. During the year ended December 31, 2012, the Partnership incurred impairment charges related to its proved properties in the Barnett Shale, East Texas and Permian regions that experienced reduced cash flows resulting from lower natural gas prices and continuing high operating costs associated with gas compression. During the year ended December 31, 2011, the Partnership incurred impairment charges related to certain proved properties in the Jourdanton field in South Texas, which included plans for five future drilling locations that the Partnership has determined not to pursue due to the current natural gas price environment.
(b)
During the year ended December 31, 2013, the Partnership incurred impairment charges related to certain leaseholds in the Mid-Continent regions that we expect to expire undrilled in 2014. During the year ended December 31, 2012, the Partnership incurred impairment charges related to certain unproved property leaseholds expected to expire undrilled in 2013. During the year ended December 31, 2011, the Partnership incurred impairment charges related to certain drilling locations in its unproved properties which the Partnership no longer intends to develop based on the performance of offsetting wells.

The table above does not include amounts related to the Partnership's Midstream Business, as these amounts have been classified as part of discontinued operations within the audited consolidated statements of operations (see Note 18).

NOTE 6. ASSET RETIREMENT OBLIGATIONS

The Partnership recognizes asset retirement obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. The Partnership records the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. For its producing oil and natural gas properties, the Partnership makes estimates of property abandonment costs that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to significant revisions in subsequent years due to increases in current abandonment costs, changes in regulatory requirements, technological advances and other factors that may be difficult to predict. The Partnership recognizes asset retirement obligations for its midstream assets in accordance with the term “conditional asset retirement obligation,” which refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the Partnership's control. Although uncertainty about the timing and/or method of settlement may exist and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, the Partnership is required to recognize a liability for the fair value of a conditional asset retirement obligation upon initial recognition if the fair value of the liability can be reasonably estimated. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that covert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of (i) remediation costs, (ii) remaining lives, (iii) future inflation factors and (iv) a credit-adjusted risk free interest rate.

A reconciliation of the Partnership's liability for asset retirement obligations is as follows:
 
2013
 
2012
 
2011
 
 ($ in thousands)
Asset retirement obligations—January 1 
$
38,991

 
$
26,227

 
$
18,072

Additional liabilities
1,076

 
1,400

 
116

Liabilities settled 
(2,240
)
 
(1,664
)
 
(399
)
Revision to liabilities
7,654

 
11,146

 
2,339

Additional liability related to acquisitions
—

 
—

 
4,368

Accretion expense
3,083

 
1,882

 
1,731

Asset retirement obligations—December 31 (a)
$
48,564

 
$
38,991

 
$
26,227

 
_____________________________________
(a)    As of December 31, 2013 and 2012, $11.3 million and $3.2 million, respectively, were included within accrued liabilities in the audited consolidated balance sheets.

The table above does not include the balances or activity related to asset retirement obligations related to the Partnership's Midstream Business, as these amounts have been classified as liabilities held for sale within the audited consolidated balance sheets and discontinued operations within the audited consolidated statements of operations (see Note 18).

NOTE 7. INTANGIBLE ASSETS
 

F- 16

Intangible assets consist of rights-of-way and easements which the Partnership amortizes over the term of the agreement or estimated useful life. The amortization period for the Partnership's rights-of-way and easements is 20 years. Intangible assets consisted of the following: 
 
December 31,
2013
 
December 31,
2012
 
($ in thousands)
Rights-of-way and easements—at cost
$
3,920

 
$
3,920

Less: accumulated amortization
(652
)
 
(456
)
Net intangible assets
$
3,268

 
$
3,464


Amounts in the table above do not include the intangible assets related to the Partnership's Midstream Business, as these amounts have been classified as assets held for sale within the audited consolidated balance sheets (See Note 18).

The following table sets forth the total amortization expense within the Partnership's audited consolidated statements of operations:
        
 
Year Ended December 31,
 
2013
 
2012
 
2011
 
($ in thousands)
Amortization
$
196

 
$
302

 
$
36



The table above does not include amounts related to the Partnership's Midstream Business, as these amounts have been classified as part of discontinued operations within the audited consolidated statements of operations (see Note 18).

Estimated future amortization expense related to the intangible assets at December 31, 2013, is as follows (in thousands):
Year ending December 31,
 
2014
$
196

2015
$
196

2016
$
196

2017
$
196

2018
$
196

Thereafter
$
2,288


The table above does not included amounts related to the Partnership's Midstream Business, as amortization expense ceases once assets have been classified as held for sale.

NOTE 8. LONG-TERM DEBT

Long-term debt consisted of the following:
 
December 31,
2013
 
December 31,
2012
 
($ in thousands)
Revolving credit facility:
$
706,800

 
$
608,500

Senior notes:
 
 
 
8.375% senior notes due 2019
51,120

 
51,120

Unamortized bond discount
(440
)
 
(503
)
Total senior notes
50,680

 
50,617

Total long-term debt
$
757,480

 
$
659,117


F- 17

Amounts in the table above do not include the portion of the unsecured senior notes that were exchanged for Regency unsecured senior notes upon the completion of the Midstream Business Contribution on July 1, 2014 (see Note 1). These notes have been classified as part of liabilities held for sale within the unaudited condensed consolidated balance sheets (see Note 18).
Revolving Credit Facility

On June 22, 2011, the Partnership entered into an Amended and Restated Credit Agreement, as amended on December 28, 2012 (as amended, the “Credit Agreement”) with Wells Fargo Bank, National Association, as administrative and documentation agent and swingline lender, Bank of America, N.A. and The Royal Bank of Scotland plc, as co-syndication agents, and the other lenders who are parties to the Credit Agreement. The Credit Agreement amended and restated the Partnership’s prior $1.2 billion Credit Agreement (the “Prior Credit Agreement”). Upon the effectiveness of the Credit Agreement, all commitments of the lenders party to the Prior Credit Agreement were terminated and all loans and other indebtedness of the Partnership under the Prior Credit Agreement were renewed and extended, inclusive of new lender commitments, on the terms and conditions of the Credit Agreement. The Credit Agreement matures on June 22, 2016.
In connection with the Credit Agreement, the Partnership incurred debt issuance costs of $9.8 million and recorded a charge of $0.4 million to write off a portion of the unamortized debt issuance costs related to the Prior Credit Agreement. As of December 31, 2013, the Partnership had unamortized debt issuance costs of $5.2 million.
On December 28, 2012, the Partnership received increased commitments from its lending group under the Credit Agreement. Aggregate commitments increased from $675 million to $820 million. The Partnership has the option to request further increases in commitments, subject to the terms and conditions of the Credit Agreement, up to an aggregate total amount of $1.2 billion. Availability under the credit facility is subject to a borrowing base comprised of two components: the upstream component and the midstream component. The upstream component of the borrowing base is determined semi-annually as an amount equal to the loan value of the proved oil and gas reserves of the Partnership and its subsidiaries as determined by the lenders party to the Credit Agreement. The midstream component of the borrowing base is determined quarterly as an amount equal to the lesser of (i) 55% of the total borrowing base (subject to increase for certain periods following certain material acquisitions up to 60% of the total borrowing base) and (ii) 3.75 times Consolidated EBITDA (as defined in the Credit Agreement) attributable to the midstream assets of the Partnership and its subsidiaries for the trailing four fiscal quarters. Pro forma adjustments to each component of the borrowing base, and thus total availability under the credit facility, are made upon the occurrence of certain events including material acquisitions and dispositions. Availability under the Credit Agreement is based on the lower of the current borrowing base and the total commitments. As of December 31, 2013, the Partnership had approximately $49.2 million of availability under the credit facility based on its borrowing base on that date. The Partnership currently pays a 0.50% commitment fee (based on the Partnership's borrowing base utilization percentage) per year on the difference between total commitments and the amount drawn under the credit facility. The Credit Agreement includes a sub-limit for the issuance of standby letters of credit for a total of $150.0 million. As of December 31, 2013, the Partnership had $19.2 million of outstanding letters of credit.
At the Partnership's election, interest will accrue on the credit facility at either LIBOR plus a margin ranging from 1.75% to 2.75% (currently 2.50% per annum based on the Partnership's borrowing base utilization percentage) or the base rate plus a margin ranging from 0.75% to 1.75% (currently 1.50% per annum based on the Partnership's borrowing base utilization percentage). The applicable margin is determined based on the utilization of the then existing borrowing base. The borrowings under the Credit Agreement may be prepaid, without any premium or penalty, at any time. The base rate is generally the highest of the federal funds rate plus 0.5%, the prime rate as announced from time to time by the Administrative Agent, or daily LIBOR for a term of one month plus 1.0%. As of December 31, 2013, the weighted average interest rate (excluding the impact of interest rate swaps) on the Partnership's outstanding debt under its revolving credit facility was 2.67%.
The obligations under the Credit Agreement are secured by first priority liens on substantially all of the Partnership’s (and its material subsidiaries') material assets, including a pledge of all of the equity interests of each of the Partnership’s material subsidiaries.
The Credit Agreement requires the Partnership and certain of its subsidiaries to make certain representations and warranties that are customary for credit facilities of this type. The Credit Agreement also contains affirmative and negative covenants that are customary for credit facilities of this type, including compliance with financial covenants. The financial covenants prohibit the Partnership from exceeding defined limits with respect to:

F- 18

•
As of any fiscal quarter-end, the ratio of Consolidated EBITDA (as defined in the Credit Agreement) for the four fiscal quarter period ending with such fiscal quarter to Consolidated Interest Expense (as defined in the Credit Agreement) for such four fiscal quarter period (the "Interest Coverage Ratio").;
•
As of any fiscal quarter-end, the ratio of Total Funded Indebtedness (as defined in the Credit Agreement) to Consolidated EBITDA for the four fiscal quarter period ending with such fiscal quarter (the “Total Leverage Ratio”).;
•
As of the fiscal quarter-end for the fiscal quarters ending December 31, 2013 through September 30, 2014, the ratio of Senior Secured Debt (as defined in the Credit Agreement) to Consolidated EBITDA for the four fiscal quarter period ending with such fiscal quarter (the “Senior Secured Leverage Ratio”).; and
•
As of any fiscal quarter-end the ratio of the Partnership’s consolidated current assets (including availability under the Credit Agreement up to the Loan Limit (as defined within the Credit Agreement), but excluding non-cash assets under the accounting guidance for derivatives) to consolidated current liabilities (excluding non-cash obligations under the accounting guidance for derivatives and current maturities under the Credit Agreement) (the “Current Ratio”).


F- 19

The following table presents the debt covenant levels specified in our revolving credit facility as of December 31, 2013:

Quarter Ended
Total Leverage Ratio
Senior Secured Leverage Ratio
Interest Coverage Ratio
Current Ratio
December 31, 2013
5.50
3.15
2.50
1.0
March 31, 2014
5.25
3.10
2.50
1.0
June 30, 2014
5.00
3.05
2.50
1.0
September 30, 2014
4.75
2.95
2.50
1.0
Thereafter
4.50
NA
2.50
1.0

The following table presents the Partnership's actual covenant ratios as of December 31, 2013:

Interest coverage ratio
3.1
Total leverage ratio
5.4
Senior secured leverage ratio
3.06
Current ratio
1.1

As of December 31, 2013, the Partnership was in compliance with the financial covenants under the Credit Agreement.  The Partnership expects compliance with financial covenants under the Credit Agreement through 2014 because the Midstream Business Contribution will substantially improve the Partnership’s liquidity and debt ratios through the elimination of significant debt currently outstanding under our revolving credit facility and the proposed assumption of all of it's senior unsecured notes via an exchange offer to be conducted by Regency. The completion of the Midstream Business Contribution is subject to regulatory and unitholder approvals. As a result, the Partnership can provide no assurance that the Midstream Business Contribution will be completed within its anticipated time frame, or at all. Should the Midstream Business Contribution not be consummated, the Partnership intends to explore alternative means to reduce its leverage ratios to comply with the financial covenants, which may include asset sales or purchases, equity financings, the separation of its upstream and midstream businesses or other alternatives.

On February 26, 2014, the Partnership and its lender group amended the Credit Agreement to, among other items, allow for a temporary step-up in the Total Leverage Ratio and Senior Secured Leverage Ratio, and allow for additional liquidity at its election. For a further discussion of the Credit Agreement amendment, see Note 22.

Senior Notes

On May 27, 2011, the Partnership, along with its subsidiary, Eagle Rock Energy Finance Corp. ("Finance Corp"), as co-issuer and certain subsidiary guarantors, issued $300.0 million of senior unsecured notes (the "Senior Notes"), that bear a coupon of 8.375%, through a private placement. The Senior Notes will mature on June 1, 2019, and interest is payable on each June 1 and December 1, commencing December 1, 2011. After the original discount of $2.2 million and excluding related offering expenses, the Partnership received net proceeds of approximately $297.8 million, which were used to repay borrowings outstanding under the Prior Credit Agreement.
On July 13, 2012, the Partnership, along with its subsidiary, Finance Corp, as co-issuer and certain subsidiary guarantors, completed the sale of an additional $250.0 million of 8.375% senior unsecured notes due 2019 through a private placement exempt from the registration requirements of the Securities Act of 1933. After the original issue discount of $3.7 million and excluding related offering expenses, the Partnership received net proceeds of approximately $246.3 million, which were used to repay borrowings outstanding under its revolving credit facility. This issuance supplemented the Partnership's prior $300.0 million of Senior Notes issued in May 2011, all of which are treated as a single series. As of December 31, 2013, the Partnership had unamortized debt issuance costs of $1.0 million and an unamortized debt discount of $0.4 million, which is recorded as an offset to the principal amount of the Senior Notes. As discussed above and within Note 1, a portion of the

F- 20

Senior Notes have been classified as part of liabilities held for sale within the audited consolidated balance sheets (see Note 18).
The Senior Notes are general unsecured senior obligations and rank equally in right of payment with all of the Partnership's existing and future senior indebtedness and rank senior in right of payment to any of the Partnership's future subordinated indebtedness. The Senior Notes are effectively junior in right of payment to all of the Partnership's existing and future secured indebtedness and other obligations, including borrowings outstanding under the Partnership's Credit Agreement, to the extent of the value of the assets securing such indebtedness and other obligations. The Senior Notes are jointly and severally guaranteed on a senior unsecured basis by the Partnership's existing and future subsidiaries, who are referred to as the "subsidiary guarantors," that guarantee the Partnership's credit facility or other indebtedness.
The indenture governing the Senior Notes, among other things, restricts the Partnership's ability and the ability of the Partnership's restricted subsidiaries to: (i) incur, assume or guarantee additional indebtedness or issue redeemable stock; (ii) pay dividends on stock, repurchase stock or redeem subordinated debt; (iii) make certain investments; (iv) enter into certain transactions with affiliates; (v) create liens on their assets; (vi) sell or otherwise dispose of certain assets, including capital stock of subsidiaries; (vii) restrict dividends, loans or other asset transfers from the Partnership's restricted subsidiaries; (viii) enter into new lines of business; and (ix) consolidate with or merge with or into, or sell all or substantially all of their properties (taken as a whole) to another person.
The Partnership has the option to redeem all or a portion of the Senior Notes at any time on or after June 1, 2015 at the redemption prices specified in the indenture plus accrued and unpaid interest. The Partnership may also redeem the Senior Notes, in whole or in part, at a "make-whole" redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to June 1, 2015. In addition, the Partnership may redeem up to 35% of the Senior Notes prior to June 1, 2014 under certain circumstances with the net cash proceeds from certain equity offerings at 108.375% of the principal amount of the notes redeemed.
    
Scheduled maturities of long-term debt as of December 31, 2013, were as follows: 
 
Principal Amount
 
($ in thousands)
2014
$
—

2015
—

2016
706,800

2017
—

2018
—

2019 and after
550,000

 
$
1,256,800


The table above includes the maturity of amounts that have been classified as part of liabilities held for sale within the audited consolidated balance sheets (See Note 18).

NOTE 9. MEMBERS’ EQUITY

At December 31, 2013, there were 156,644,153 common units outstanding. In addition, there were 2,743,807 unvested restricted common units outstanding.

On June 1, 2010, the Partnership launched its rights offering to the holders of its common and general partner units as of close of business on May 27, 2010, the record date. Each Right entitled the holder (including holders of Rights acquired during the subscription period) to purchase (i) one common unit and (ii) one warrant to purchase one additional common unit at $6.00 on certain specified days beginning on August 15, 2010 and ending on May 15, 2012. During the years ended December 31, 2012 and 2011 5,300,588 and 14,957,540 warrants, respectively, were exercised for an equivalent number of newly issued common units. The final exercise date for the warrants was May 15, 2012, and on that date the remaining unexercised warrants expired.


F- 21

On May 31, 2012, the Partnership announced a program through which it may issue common units, from time to time, with an aggregate market value of up to $100 million. The Partnership is under no obligation to issue equity under the program. As of December 31, 2013, 686,759 units had been issued under this program for net proceeds of approximately $5.6 million.

On August 17, 2012, the Partnership closed an underwritten public offering of 10,120,000 common units, which included the full exercise of the underwriters' option to purchase additional common units to cover over-allotments, for net proceeds of approximately $84.3 million.

On March 12, 2013, the Partnership closed an underwritten public offering of 10,350,000 common units for net proceeds of approximately $92.3 million.

The Partnership has declared a cash distribution for each quarter since its initial public offering. The table below summarizes these distributions for the last three years. 
Quarter Ended
 
Distribution
per Unit
 
Record Date**
 
Payment Date
March 31, 2011+
 
$
0.1500

 
May 9, 2011
 
May 13, 2011
June 30, 2011+
 
$
0.1875

 
August 5, 2011
 
August 12, 2011
September 30, 2011+
 
$
0.2000

 
November 4, 2011
 
November 14, 2011
December 31, 2011+
 
$
0.2100

 
February 7, 2012
 
February 14, 2012
March 31, 2012+
 
$
0.2200

 
May 8, 2012
 
May 15, 2012
June 30, 2012+
 
$
0.2200

 
August 7, 2012
 
August 14, 2012
September 30, 2012+
 
$
0.2200

 
November 7, 2012
 
November 14, 2012
December 31, 2012+
 
$
0.2200

 
February 7, 2013
 
February 14, 2013
March 31, 2013+*
 
$
0.2200

 
May 7, 2013
 
May 15, 2013
June 30, 2013+*
 
$
0.2200

 
August 7, 2013
 
August 14, 2013
September 30, 2013+*
 
$
0.1500

 
November 7, 2013
 
November 14, 2013
December 31, 2013+*
 
$
0.1500

 
February 7, 2014
 
February 14, 2014
_____________________________
+
The distribution per unit represents distributions made only on common units, including restricted common units issued under our Long Term Incentive Plan. Since July 30, 2010, the only other class of equity we have outstanding is a non-economic general partner interest.
*
The distribution excludes certain restricted unit grants.
**
The "Record Date" set forth in the table above means the close of business on each of the listed Record Dates.

NOTE 10. RELATED PARTY TRANSACTIONS
   
The following table summarizes transactions between the Partnership and affiliated entities:
 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
Affiliates of NGP:
 
($ in thousands)
Natural gas purchases from affiliates
 
$
2,938

 
$
2,713

 
$
6,097

Payable as of December 31,
 
$
18

 
$
428

 
 
    
The transactions above are all related to the Partnership's Midstream Business and have been classified as part of discontinued operations within the consolidated statements of operations and liabilities held for sale within the consolidated balance sheet (see Note 18).    

In connection with the closing of the acquisition of certain fee minerals, royalties, overriding royalties and non-operated working interest properties from Montierra Minerals & Production, L.P. ("Montierra") and NGP-VII Co-Investment Opportunities, L.P. ("Co-Invest") on April 30, 2007, the Partnership entered into registration rights agreements with Montierra and Co-Invest. In the registration rights agreements, the Partnership agreed, for the benefit of Montierra and Co-Invest, to register the common units it holds, the common units issuable upon conversion of the subordinated units that it holds and any

F- 22

common units or other equity securities issuable in exchange for the common units and subordinated units it holds. The registration rights agreement is still in effect and the Partnership is in compliance with all obligations of the agreement.

On May 3, 2011, the Partnership completed the Mid-Continent Acquisition. Due to Crow Creek Energy being a portfolio company of NGP VIII and NGP's ownership interest in the Partnership and Board of Directors representation, the Board of Directors of the general partner of the Partnership's general partner, authorized its Conflicts Committee to review, evaluate, and, if determined appropriate, approve the Mid-Continent Acquisition, due to the potential conflict of interest among the Partnership, the NGP and the Partnership's public unitholders. The Conflicts Committee, consisting of independent directors of the Partnership, determined that the Mid-Continent Acquisition was fair and reasonable to the Partnership and its public unitholders and recommended to the Board of Directors that the transaction be approved and authorized. In determining the consideration for the acquisition of Crow Creek Energy, the Conflicts Committee, with the assistance of a third-party, considered the valuation of the properties involved in the transaction, the valuation of the units to be offered as consideration in the transaction and the cash flows of Crow Creek Energy.

In connection with the closing of the Mid-Continent Acquisition, the Partnership entered into a registration rights agreement ("Registration Rights Agreement") with NGP VIII. The Registration Rights Agreement grants NGP VIII and certain of its affiliates registration rights with respect to the common units acquired pursuant to the Partnership's acquisition of Crow Creek Energy and their outstanding warrants to purchase common units that were previously acquired by NGP VIII and certain of its affiliates in connection with the Partnership's previously completed recapitalization transaction. Pursuant to the Registration Rights Agreement, NGP VIII and certain of its affiliates have the ability to demand that the Partnership register for resale their common units acquired pursuant to the acquisition of Crow Creek Energy and their existing warrants to purchase common units. This registration may be an underwritten offering at the discretion of NGP VIII and certain of its affiliates. NGP VIII and certain of its affiliates may demand up to four such registrations, subject to an increase to up to seven if the registration rights are amended. Additionally, the Registration Rights Agreement provides that NGP VIII and certain of its affiliates have piggyback registration rights in certain circumstances, which would require inclusion of their common units and warrants on registration statements that the Partnership files, subject to certain customer exceptions. There are no limits on the number of times NGP VIII and certain of its affiliates can exercise these piggyback registration rights.

NOTE 11. RISK MANAGEMENT ACTIVITIES
 
Interest Rate Swap Derivative Instruments

To mitigate its interest rate risk, the Partnership enters into various interest rate swaps. These swaps convert the variable-rate term loan into a fixed-rate obligation. The purpose of entering into these swaps is to eliminate interest rate variability by converting LIBOR-based variable-rate payments to fixed-rate payments. Amounts received or paid under these swaps were recorded as reductions or increases in interest expense.

For accounting purposes, the Partnership has not designated any of its interest rate derivative instruments as hedges; instead it marks these derivative contracts to fair value (see Note 12).  Changes in fair values of the interest rate derivative instruments are recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within other income (expense).

The following table sets forth certain information regarding the Partnership's various interest rate swaps as of December 31, 2013:
Effective Date
 
Expiration
Date
 
Notional
Amount
 
Fixed
Rate 
6/22/2011
 
6/22/2015
 
$
250,000,000

 
2.95
%

 Commodity Derivative Instruments - Corporate
 
The prices of crude oil, natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors which are beyond the Partnership's control.  These risks can cause significant changes in the Partnership's cash flows and affect its ability to achieve its distribution objectives and comply with the covenants of its revolving credit facility.  In order to manage the risks associated with changes in the future prices of crude oil, natural gas and NGLs on its forecasted equity production, the Partnership engages in risk management activities that take

F- 23

the form of commodity derivative instruments.  The Partnership has determined that it is necessary to hedge a substantial portion of its expected production in order to meaningfully reduce its future cash flow volatility.  The Partnership generally limits its hedging levels to less than its total expected future production. While hedging at this level of production does not eliminate all of the volatility in the Partnership's cash flows, it allows the Partnership to mitigate the risk of situations where a modest loss of production would not put it in an over-hedged position.  At times, the Partnership's strategy may involve entering into hedges with strike prices above current future prices or resetting existing hedges to higher price levels in order to meet its cash flow objectives or to stay in compliance with the covenants under its revolving credit facility.  In addition, the Partnership may also terminate or unwind hedges or portions of hedges when the expected future volumes do not support the level of hedges.  Expected future production for its Upstream Business is derived from the proved reserves, adjusted for price-dependent expenses and revenue deductions.  The Partnership applies the appropriate contract terms to these projections to determine its expected future equity share of the commodities.
 
The Partnership uses fixed-price swaps, costless collars and put options to achieve its hedging objectives. Historically, the Partnership has hedged its expected future commodity volumes either with derivatives of the same commodity ("direct hedges") or with derivatives of another commodity which the Partnership expects will correlate well with the underlying commodity ("proxy hedges"). For example, the Partnership will often hedge the changes in future NGL prices using crude oil hedges because NGL prices have been highly correlated to crude oil prices and hedging NGLs directly is usually less attractive due to the relative illiquidity in the NGL forward market. The Partnership may use natural gas hedges to hedge a portion of its expected future ethane production because forward prices for ethane are often heavily discounted from its current prices. Also, natural gas prices provide support for ethane prices because in many processing plants ethane can be recombined with the residue gas stream and sold as natural gas. When the Partnership uses proxy hedges, it converts the expected volumes of the underlying commodity to equivalent volumes of the hedged commodity. In the case of NGLs hedged with crude oil derivatives,
these conversions are based on the historical relationship of the prices of the two commodities and management's judgment
regarding future price relationships of the commodities. In the case where ethane is hedged with natural gas derivatives, the
conversion is based on the thermal content of ethane. In recent quarters, the correlation of price changes in crude oil and NGLs
has weakened relative to longer-term averages as NGL prices have fallen while crude index prices have risen. This dynamic has
negatively impacted our hedging objectives

For accounting purposes, the Partnership has not designated any of its commodity derivative instruments as hedges; instead it marks these derivative contracts to fair value (see Note 12).  Changes in fair values of the commodity derivative instruments are recorded as an adjustment to the mark-to-market gains (losses) on risk management transactions within revenue.
 
By using derivative instruments to economically hedge exposure to changes in commodity prices, the Partnership exposes itself to counterparty credit risk. Historically, the Partnership's corporate derivative counterparties have all been participants or affiliates of participants within its revolving credit facility (see Note 8), which is secured by substantially all of the assets of the Partnership. Therefore, the Partnership is not currently required to post any collateral, nor does it require collateral from its counterparties. The Partnership minimizes the credit risk in derivative instruments by limiting exposure to any single counterparty and monitoring the creditworthiness of its counterparties on an ongoing basis. In addition, the Partnership's derivative contracts for certain counterparties are subject to counterparty netting agreements governing such derivatives, and when possible, the Partnership nets the open positions of each counterparty. See Note 12 for the impact to the Partnership's audited consolidated balance sheets of the netting of these derivative contracts.

The Partnership's commodity derivative counterparties as of December 31, 2013, not including counterparties of its marketing and trading business, included BNP Paribas, Wells Fargo Bank, National Association, Comerica Bank, Bank of Nova Scotia, The Royal Bank of Scotland plc, Bank of America N.A., J Aron and Company (an affiliate of Goldman Sachs), ING Capital Markets LLC, BBVA Compass Bank, Royal Bank of Canada, Regions Financial Corporation and CITIBANK, N.A.

The following tables set forth certain information regarding the Partnership's commodity derivatives. Within the table, some trades of the same commodities with the same tenors have been aggregated and shown as weighted averages.

Commodity derivatives, as of December 31, 2013, that will mature during the years ended December 31, 2014, 2015 and 2016:

F- 24

Underlying
 
Type
 
Notional
Volumes
(units) (a)
 
Floor
Strike
Price
($/unit)(b)
 
Cap
Strike
Price
($/unit)(b)
Portion of Contracts Maturing in 2014
 
 
 
 
 
 
 
 
Natural Gas
 
Swap (Pay Floating/Receive Fixed)
 
11,760,000

 
$
4.51

 
 
Crude Oil
 
Swap (Pay Floating/Receive Fixed)
 
1,248,000

 
$
96.14

 
 
Crude Oil
 
Swap (Pay Fixed/Receive Floating)
 
199,140

 
$
92.53

 
 
Propane
 
Swap (Pay Floating/Receive Fixed)
 
9,576,000

 
$
1.06

 
 
IsoButane
 
Swap (Pay Floating/Receive Fixed)
 
2,268,000

 
$
1.31

 
 
Normal Butane
 
Swap (Pay Floating/Receive Fixed)
 
4,132,800

 
$
1.30

 
 
Portion of Contracts Maturing in 2015
 
 
 
 
 
 
 
 
Natural Gas
 
Swap (Pay Floating/Receive Fixed)
 
10,800,000

 
$
4.07

 
 
Crude Oil
 
Costless Collar
 
480,000

 
$
90.00

 
$
97.55

Crude Oil
 
Swap (Pay Floating/Receive Fixed)
 
630,000

 
$
89.78

 
 
Portion of Contracts Maturing in 2016
 
 
 
 
 
 
 
 
Natural Gas
 
Swap (Pay Floating/Receive Fixed)
 
9,480,000

 
$
4.25

 
 
Crude Oil
 
Swap (Pay Floating/Receive Fixed)
 
936,000

 
$
84.66

 
 
_______________________
(a)
Volumes of natural gas are measured in MMbtu, volumes of crude oil are measured in barrels, and volumes of natural gas liquids are measured in gallons.
(b)
Amounts represent the weighted average price. The weighted average prices are in $/MMbtu for natural gas, $/barrel for crude oil and $/gallon for natural gas liquids.

The table above does not include derivative contracts that have been classified as assets and liabilities held for sale within the audited consolidated balance sheet (see Note 18).

Commodity Derivative Instruments - Marketing & Trading

Prior to the consummation of the Midstream Business Contribution, the Partnership conducted natural gas marketing and trading activities intended to capitalize on favorable price differentials between various receipt and delivery locations. This business was contributed to Regency as part of the Midstream Business Contribution completed on July 1, 2014. The assets and liabilities associated with this business have been classified as held for sale within the consolidated balance sheets and the operations as discontinued within the consolidated statements of operations (see Note 18).



F- 25

Fair Value of Interest Rate and Commodity Derivatives
 
Fair values of interest rate and commodity derivative instruments not designated as hedging instruments in the consolidated balance sheet as of December 31, 2013 and December 31, 2012:
 
As of
December 31, 2013
 
Derivative Assets
 
Derivative Liabilities
 
Balance Sheet Classification
 
Fair Value
 
Balance Sheet Classification
 
Fair Value
 
($ in thousands)
Interest rate derivatives - liabilities
Current assets
 
$
—

 
Current liabilities
 
$
(6,210
)
Interest rate derivatives - liabilities
Long-term assets
 
—

 
Long-term liabilities
 
(2,885
)
Commodity derivatives - assets
Current assets
 
6,841

 
Current liabilities
 
1,043

Commodity derivatives - assets
Long-term assets
 
4,669

 
Long-term liabilities
 
202

Commodity derivatives - assets
Assets held for sale
 
6,017

 
Liabilities held for sale
 
1,973

Commodity derivatives - liabilities
Current assets
 
(1,282
)
 
Current liabilities
 
(3,193
)
Commodity derivatives - liabilities
Long-term assets
 
(798
)
 
Long-term liabilities
 
(143
)
Commodity derivatives - liabilities
Assets held for sale
 
(824
)
 
Liabilities held for sale
 
(5,658
)
Total derivatives
 
 
$
14,623

 
 
 
$
(14,871
)
 
 
 
 
 
 
 
 
 
As of
December 31, 2012
 
Derivative Assets
 
Derivative Liabilities
 
Balance Sheet Classification
 
Fair Value
 
Balance Sheet Classification
 
Fair Value
 
($ in thousands)
Interest rate derivatives - liabilities
Current assets
 
$
(4,844
)
 
Current liabilities
 
$
(1,201
)
Interest rate derivatives - liabilities
Long-term assets
 
(7,002
)
 
Long-term liabilities
 
(1,700
)
Commodity derivatives - assets
Current assets
 
21,547

 
Current liabilities
 
—

Commodity derivatives - assets
Long-term assets
 
7,963

 
Long-term liabilities
 
—

Commodity derivatives - assets
Assets held for sale
 
27,010

 
Liabilities held for sale
 
19

Commodity derivatives - liabilities
Current assets
 
(953
)
 
Current liabilities
 
—

Commodity derivatives - liabilities
Long-term assets
 
(1,728
)
 
Long-term liabilities
 
—

Commodity derivatives - liabilities
Assets held for sale
 
(700
)
 
Liabilities held for sale
 
(49
)
Total derivatives
 
 
$
41,293

 
 
 
$
(2,931
)
            
The following table sets forth the location of gains and losses for derivatives not designated as hedging instruments within the Partnership's audited consolidated statement of operations (in thousands):
Amount of Gain (Loss) Recognized in Income on Derivatives
 
Year Ended December 31,
 
 
 
2013
 
2012
 
2011
Interest rate derivatives
Interest rate risk management losses, net
 
$
(1,104
)
 
$
(4,727
)
 
$
(11,401
)
Commodity derivatives
Commodity risk management gains (losses), net
 
(3,937
)
 
28,110

 
37,269

Commodity derivatives
Discontinued operations
 
(14,596
)
 
29,784

 
(4,759
)
Commodity derivatives -trading
Discontinued operations
 
315

 
(192
)
 
772

 
Total
 
$
(19,322
)
 
$
52,975

 
$
21,881

 

NOTE 12. FAIR VALUE OF FINANCIAL INSTRUMENTS


F- 26

Fair value is 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 (exit price). The Partnership utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk inherent in the inputs to the valuation technique. The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
 
The three levels of the fair value hierarchy are as follows:
 
Level 1 – Quoted prices are available in active markets for identical assets and liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis.
 
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the market place throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
 
Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value.
 
As of December 31, 2013, the Partnership has recorded its interest rate swaps and commodity derivative instruments (see Note 11), which includes crude oil, natural gas and NGLs, at fair value. The Partnership reviews the classification of the inputs at the end of each period and has classified the inputs to measure the fair value of its interest rate swaps, crude oil derivatives and natural gas derivatives as Level 2.  In prior periods, the Partnership has classified the inputs to measure its NGL derivatives as Level 3 as the NGL market was considered to be less liquid and thinly traded. As of September 30, 2011, the Partnership concluded that the inputs for its NGL derivatives were considered to be more observable due to the NGL market being more liquid through the term of our contracts and has classified these inputs as Level 2. The following table discloses the fair value of the Partnership's derivative instruments as of December 31, 2013 and 2012: 
 
As of
December 31, 2013
 
Level 1
 
Level 2
 
Level 3
 
Netting (a)
 
Total
 
($ in thousands)
Assets:
 
 
 
 
 
 
 
 
 
Crude oil derivatives
$
—

 
$
6,151

 
$
—

 
$
(1,716
)
 
$
4,435

Natural gas derivatives
—

 
6,562

 
—

 
(1,567
)
 
4,995

NGL derivatives
—

 
42

 
—

 
(42
)
 
—

Total 
$
—

 
$
12,755

 
$
—

 
$
(3,325
)
 
$
9,430

 
 
 
 
 
 
 
 
 
 
Liabilities:
 

 
 

 
 

 
 

 
 

Crude oil derivatives
$
—

 
$
(1,792
)
 
$
—

 
$
1,716

 
$
(76
)
Natural gas derivatives
—

 
(2,503
)
 
—

 
1,567

 
(936
)
NGL derivatives
—

 
(1,121
)
 
—

 
42

 
(1,079
)
Interest rate swaps
—

 
(9,095
)
 
—

 
—

 
(9,095
)
Total 
$
—

 
$
(14,511
)
 
$
—

 
$
3,325

 
$
(11,186
)
____________________________
(a)
Represents counterparty netting under agreement governing such derivative contracts.

F- 27

 
As of
December 31, 2012
 
Level 1
 
Level 2
 
Level 3
 
Netting (a)
 
Total
 
($ in thousands)
Assets:
 
 
 
 
 
 
 
 
 
Crude oil derivatives
$
—

 
$
5,615

 
$
—

 
$
(1,208
)
 
$
4,407

Natural gas derivatives
—

 
20,571

 
—

 
(1,473
)
 
19,098

NGL derivatives
—

 
3,324

 
—

 
—

 
3,324

Interest rate swaps
—

 
—

 
—

 
(11,846
)
 
(11,846
)
Total 
$
—

 
$
29,510

 
$
—

 
$
(14,527
)
 
$
14,983

 
 
 
 
 
 
 
 
 
 
Liabilities:
 

 
 

 
 

 
 

 
 

Crude oil derivatives
$
—

 
$
(1,208
)
 
$
—

 
$
1,208

 
$
—

Natural gas derivatives
—

 
(1,473
)
 
—

 
1,473

 
—

Interest rate swaps
—

 
(14,747
)
 
—

 
11,846

 
(2,901
)
Total 
$
—

 
$
(17,428
)
 
$
—

 
$
14,527

 
$
(2,901
)
____________________________
(a)
Represents counterparty netting under agreement governing such derivative contracts.
 
The tables above do not include the fair value of the derivative contracts that have been classified as assets and liabilities held for sale within the audited consolidated balance sheet (see Note 18).

The Partnership values its Level 3 NGL derivatives using forward curves, interest rate curves, and volatility parameters, when applicable. In addition, the impact of counterparty credit risk is factored into the value of derivative assets, and the Partnership's credit risk is factored into the value of derivative liabilities.

Gains and losses losses related to the interest rate derivatives are recorded as part of interest rate risk management gains and losses in the audited consolidated statements of operations.  Gains and losses related to the Partnership's commodity derivatives are recorded as a component of revenue in the audited consolidated statements of operations. 
 
Fair Value of Assets and Liabilities Measured on a Non-recurring Basis

For periods in which impairment charges have been incurred, the Partnership is required to write down the value of the
impaired asset to its fair value. See Note 5 for a further discussion of the impairment charges recorded during the year ended. The following table discloses the fair value of the Partnership's assets measured at fair value on a nonrecurring basis for the year ended December 31, 2013:
 
December 31,
2013
 
Level 1
 
Level 2
 
Level 3
 
Total Losses
 
($ in thousands)
Proved properties
$
91,346

 
$
—

 
$
—

 
$
91,346

 
$
207,085


The Partnership calculated the fair value of the impaired assets using discounted cash flow analysis to determine the excess of the asset's carrying value over its fair value. Significant inputs to the valuation of fair value of the proved properties included estimates of (i) reserves, (ii) future operating and development costs (iii) forward commodity prices and (iv) a discount rate reflective of the Partnership's cost of capital. For the other assets impaired by the partnership during the year ended December 31, 2013, the assets were fully written down and are thus not included in the table above. See Notes 5 for a further discussion of the impairment charges.

The carrying amount of cash equivalents is believed to approximate their fair values because of the short maturities of these instruments. The fair value of accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments.
 

F- 28

As of December 31, 2013, the outstanding debt associated with the Credit Agreement bore interest at a floating rate; as such, the Partnership believes that the carrying value of this debt approximates its fair value. The outstanding debt associated with the Senior Notes bears interest at a fixed rate; based on the market price of the Senior Notes as of December 31, 2013 and 2012, the Partnership estimates that the fair value of the Senior Notes, including amounts classified as held for sale, is $599.5 million and $561.0 million, respectively. Fair value of the senior notes was estimated based on prices quoted from third-party financial institutions, which are characteristic of Level 2 fair value measurement inputs.

NOTE 13. COMMITMENTS AND CONTINGENT LIABILITIES
 
Litigation—The Partnership is subject to lawsuits which arise from time to time in the ordinary course of business, such as the interpretation and application of contractual terms related to the calculation of payment for liquids and natural gas proceeds. The Partnership had no accruals as of December 31, 2013 and 2012 related to legal matters, and current lawsuits are not expected to have a material adverse effect on our financial position, results of operations or cash flows. The Partnership has been indemnified up to a certain dollar amount for two lawsuits. If there ultimately is a finding against the Partnership in these two indemnified cases, the Partnership would expect to make a claim against the indemnification up to limits of the indemnification.

Insurance—The Partnership covers its operations and assets with insurance which management believes is consistent with that in force for other companies engaged in similar commercial operations with similar type properties.  This insurance includes: (1) commercial general liability insurance covering liabilities to third parties for bodily injury, property damage and pollution arising out of Eagle Rock Energy operations; (2) workers’ compensation liability coverage for employees to required statutory limits; (3) automobile liability insurance covering liability to third parties for bodily injury and property damage arising out of the operation of all owned, hired and non-owned vehicles by its employees on company business; (4) property insurance covering the replacement cost of all owned real and personal property, including coverage for losses due to boiler and machinery breakdown, earthquake, flood and consequent business interruption/extra expense; (5) control of well/operator's extra expense insurance for operated and non-operated wells in the Upstream Business; and (6) corporate liability insurance including coverage for Directors and Officers and Employment Practices liabilities.  In addition, the Partnership maintains excess liability insurance providing limits in excess of the established primary limits for commercial general liability and automobile liability insurance.
 
All coverages are subject to industry accepted policy terms, conditions, limits and deductibles comparable to that obtained by other energy companies with similar operations. The cost of insurance for the energy industry continued to fluctuate over the past year, reflecting the changing conditions in the insurance markets. 

Environmental—The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, the Partnership must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Partnership's combined results of operations, financial position or cash flows. At December 31, 2013 and 2012, the Partnership had accrued approximately $2.5 million and $2.6 million, respectively, for environmental matters. Environmental accruals related to the Partnership's Midstream Business have been classified as liabilities held-for-sale within the unaudited condensed consolidated balance sheet (see Note 18).
    
Retained Revenue Interest—Certain assets of the Partnership's Upstream Business are subject to retained revenue interests.  These interests were established under purchase and sale agreements that were executed by the Partnership's predecessors in title.  The terms of these agreements entitle the owners of the retained revenue interests to a portion of the revenues received from the sale of the hydrocarbons above specified base oil and natural gas prices.  These retained revenue interests do not represent a real property interest in the hydrocarbons.  The Partnership's reported revenues are reduced to account for the retained revenue interests on a monthly basis.
 

F- 29

The retained revenue interests affect the Partnership's interest at the Big Escambia Creek, Flomaton and Fanny Church fields in Escambia County, Alabama. With respect to the Partnership's Flomaton and Fanny Church fields, these retained revenue interests are in effect for any calendar year in which the Partnership surpasses certain average net production rates. The Partnership did not surpass such rates in 2013 and does not anticipate exceeding these rates in future years. With respect to the Partnership's Big Escambia Creek field, the retained revenue interest commenced in 2010 and continues through the end of 2019.
 
Other Commitments—The Partnership utilizes assets under operating leases for its corporate office, certain rights-of-way and facilities locations, vehicles and in several areas of its operations. Rental expense from continuing operations, including leases with no continuing commitment, amounted to approximately $2.4 million, $3.8 million and $1.1 million for the years ended December 31, 2013, 2012 and 2011, respectively. Rental expense for leases with escalation clauses is recognized on a straight-line basis over the initial lease term. At December 31, 2013, commitments under long-term non-cancelable operating leases for the next five years are as follows (in thousands):

Year ending December 31,
 
2014
$
7,060

2015
$
6,045

2016
$
4,997

2017
$
2,848

2018
$
438


The table above includes obligations related to the Partnership's Midstream Business. The assets and liabilities of the Partnership's Midstream Business have been classified as held for sale within the audited consolidated balance sheets, while the operations of the Partnership's Midstream Business have been classified as discontinued within the audited consolidated statements of operations.

NOTE 14. EMPLOYEE BENEFIT PLAN
 
The Partnership offers a defined contribution benefit plan to its employees. For the three years ended December 31, 2012, the plan provided for a dollar for dollar matching contribution by the Partnership of up to 4% of an employee's contribution and 50% of additional contributions up to an additional 2%. Additionally, the Partnership may, at its sole discretion and election, contribute up to 6% of a participating employee's base salary annually, subject to vesting requirements. Expenses under the plan for the years ended December 31, 2013, 2012 and 2011 were approximately $1.2 million, $0.8 million and $0.3 million, respectively.

NOTE 15. INCOME TAXES
 
The Partnership's provision for income taxes relates to (i) state taxes for the Partnership and (ii) federal taxes for Eagle Rock Energy Acquisition Co., Inc, (acquiring entity of Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P. and certain assets owned by NGP Income Co-Investment Opportunities Fund II, L.P. (collectively the "Redman Acquisition") in 2007)  and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of certain entities acquired in the Stanolind Acquisition in 2008) and their wholly owned corporations, Eagle Rock Upstream Development Company, Inc., (successor entity of certain entities acquired in the Redman acquisition) and Eagle Rock Upstream Development Company II, Inc. (successor entity of certain entities acquired in the Stanolind acquisition), which are subject to federal income taxes (the “C Corporations”).   In addition, the Partnership has become a taxable entity in the state of Texas. On May 18, 2006, the State of Texas enacted House Bill 3 which revised the pre-existing state franchise tax. In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses.


F- 30

The Partnership's federal and state income tax provision is summarized below (in thousands): 
 
For the Year Ended December 31,
 
2013
 
2012
 
2011
Current:
 
 
 
 
 
Federal
$
(105
)
 
$
621

 
$
1,092

State
—

 
18

 
61

Total current provision
(105
)
 
639

 
1,153

Deferred:
 
 
 
 
 
Federal
(3,837
)
 
(2,776
)
 
(3,862
)
State
(1,653
)
 
1,044

 
(641
)
Total deferred
(5,490
)
 
(1,732
)
 
(4,503
)
Total (benefit) provision for income taxes
$
(5,595
)
 
$
(1,093
)
 
(3,350
)

The effective rates for the years ended December 31, 2013, 2012 and 2011 are shown in the table below.  For 2011, the effective tax rate is attributable to the state and federal taxes being applied to their book income. In 2013 and 2012, the federal and state based income taxes were applied against book losses which resulted in effective tax rates of 2.4% and 3.3%, respectively.   A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows (in thousands):

 
For the Year Ended December 31,
 
2013
 
2012
 
2011
Pre-tax net book income (loss) from continuing operations
(233,766
)
 
(33,239
)
 
50,299

State income tax current and deferred
(1,653
)
 
1,062

 
(580
)
Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities
(4,160
)
 
(2,155
)
 
(2,232
)
Tax attributes used
218

 
—

 
(538
)
Benefit for income taxes from continuing operations
$
(5,595
)
 
$
(1,093
)
 
$
(3,350
)
Effective income tax rate on continuing operations
2.4
%
 
3.3
%
 
(6.7
)%

Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2013 and 2012 are as follows (in thousands):
 
December 31, 2013
 
December 31, 2012
Deferred Tax Assets:
 
 
 
Statutory depletion carryover
$
1,438

 
$
1,599

AMT credit carryforward
—

 
57

Total Deferred Tax Assets
1,438

 
1,656

 
 
 
 
Deferred Tax Liabilities:
 
 
 
Property, plant, equipment & amortizable assets
(2,011
)
 
(3,177
)
Hedging transactions
—

 
(271
)
Book/tax differences from partnership investment
(32,086
)
 
(36,144
)
Total Deferred Tax Liabilities
(34,097
)
 
(39,592
)
Total Net Deferred Tax Liabilities
(32,659
)
 
(37,936
)
Current portion of total net deferred tax liabilities
—

 
—

Long-term portion of total net deferred tax liabilities
$
(32,659
)
 
$
(37,936
)

The largest single component of the Partnership's deferred tax liabilities is related to federal income taxes of the C Corporations described above, where the book/tax differences were created by the Redman and Stanolind Acquisitions. These

F- 31

book/tax temporary differences will be reduced as allocation of built-in gain in proportion to the assets contributed brings the book and tax basis closer together over time. This net deferred tax liability was recognized in conjunction with the purchase accounting adjustments for long term assets.  

Due to the enactment of the Revised Texas Franchise Tax, the Partnership recorded a net deferred tax liability related to the book/tax differences in property, plant and equipment and hedging transactions.

     In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2013, based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Partnership will realize the benefits of these deductible differences. The amount of deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced. The AMT credit carryforward presented above does not have an expiration date.

The Partnership adopted authoritative guidance related to accounting for uncertainty in income taxes on January 1, 2007.  The Partnership has taken a position which is deemed to be “more likely than not” to be upheld upon review, if any, with respect to the deductibility of certain costs for the purpose of its franchise tax liability on a state franchise return.   The Partnership has recorded a provision for the portion of this tax liability equal to the probability of recognition. In addition, the Partnership has accrued interest and penalties associated with these liabilities and has recorded these amounts within its state deferred income tax expense. The amount stated below relates to the tax returns filed for 2013, 2012 and 2011, which are still open under current statute.

A reconciliation of the beginning and ending amount of the unrecognized tax benefits (liabilities) is as follows (in thousands): 
 
2013
 
2012
 
2011
Balance at beginning of period                                                                                                               
$
(830
)
 
$
(735
)
 
$
(569
)
Increases related to current year tax positions 
(128
)
 
(53
)
 
(132
)
Increases related to tax interest and penalties
(39
)
 
(42
)
 
(34
)
Decreases related to statutory limitations
267

 
—

 
—

Decreases related to tax interest and penalties
81

 
—

 
—

Balance at end of period                                                                                                          
$
(649
)
 
$
(830
)
 
$
(735
)

NOTE 16. EQUITY-BASED COMPENSATION
 
Eagle Rock Energy G&P, LLC, the general partner of the general partner of the Partnership, has a long-term incentive plan, as amended (“LTIP”), for its employees, directors and consultants who provide services to the Partnership and its subsidiaries and affiliates. The LTIP provides for the issuance of an aggregate of up to 7,000,000 common units, to be granted either as options, restricted units or phantom units, of which, as of December 31, 2013, a total of 913,794 common units remained available for issuance. Grants under the LTIP are made at the discretion of the board and to date have only been made in the form of restricted units. Distributions declared and paid on outstanding restricted units, where such restricted units are eligible to receive distributions, are paid directly to the holders of the restricted units. No options or phantom units have been issued to date.

The restricted units granted are valued at the market price as of the date issued. The weighted average fair value of the units granted during the years ended December 31, 2013, 2012 and 2011 was $9.16, $9.50 and $10.13, respectively. The awards generally vest over three years on the basis of one third of the award each year. The Partnership recognizes compensation expense on a straight-line basis over the requisite service period for the restricted unit grants. During the restriction period, distributions associated with the granted awards will be distributed to the awardees.
 
A summary of the restricted common units’ activity for the year ended December 31, 2013 is provided below:

F- 32

 
Number of
Restricted
Units
 
Weighted
Average
Fair Value
Outstanding at December 31, 2012
2,608,035

 
$
9.38

Granted
1,623,939

 
$
9.16

Vested
(1,203,822
)
 
$
8.98

Forfeited
(284,345
)
 
$
9.90

Outstanding at December 31, 2013
2,743,807

 
$
9.37

    
For the years ended December 31, 2013, 2012 and 2011, non-cash compensation expense of approximately $10.4 million, $7.7 million and $4.3 million, respectively, was recorded related to the granted restricted units as general and administrative expense on the consolidated statements of operations.
 
As of December 31, 2013, unrecognized compensation costs related to the outstanding restricted units under the LTIP totaled approximately $17.1 million. The remaining expense is to be recognized over a weighted average of 1.6 years.

In connection with the vesting of certain restricted units during the years ended December 31, 2013, 2012 and 2011, 272,179, 286,716 and 137,985, respectively, of the newly-vested common units were cancelled by the Partnership in satisfaction of $1.9 million, $2.5 million and $1.4 million, respectively, of minimum employee tax liability paid by the Partnership. Pursuant to the terms of the LTIP, these cancelled units are available for future grants under the LTIP.

NOTE 17. EARNINGS PER UNIT
 
Basic earnings per unit is computed by dividing the net income (loss) by the weighted average number of units outstanding during a period. To determine net income (loss) allocated to each class of ownership (common and restricted common units), the Partnership first allocates net income (loss) in accordance with the amount of distributions made for the quarter by each class, if any. The remaining net income is allocated to each class in proportion to the class weighted average number of units outstanding for a period, as compared to the weighted average number of units for all classes for the period, with the exception of net losses. Net losses are allocated to just the common units.

As of December 31, 2013, 2012 and 2011, the Partnership had unvested restricted common units outstanding, which are considered dilutive securities. These units will be considered in the diluted weighted average common unit outstanding number in periods of net income. In periods of net losses, these units are excluded from the diluted weighted average common unit outstanding number.

Any warrants outstanding during the period are considered to be dilutive securities. These outstanding warrants will be considered in the diluted weighted average common units outstanding number in periods of net income, except if the exercise price of the outstanding warrants is greater than the average market price of the common units for such periods. In periods of net losses, the outstanding warrants are excluded from the diluted weighted average common units outstanding.

        


F- 33

The following table presents the Partnership's calculation of basic and diluted units outstanding for the periods indicated:
 
Year Ended December 31,
 
2013
 
2012
 
2011
 
(in thousands)
Weighted average units outstanding during period:
 
 
 
 
 
Common units - Basic
153,562

 
135,609

 
110,435

Effect of Dilutive Securities:
 
 
 
 
 
Warrants
—

 
—

 
5,727

Restricted Units
—

 
—

 
779

Common units - Diluted
153,562

 
135,609

 
116,941

 
The restricted common units granted under the LTIP, as discussed in Note 16, contain non-forfeitable rights to the distributions declared by the Partnership and therefore meet the definition of participating securities. Participating securities are required to be included in the computation of earnings per unit pursuant to the two-class method. For the year ended December 31, 2011, the Partnership determined that it is more dilutive to apply the two-class method versus the treasury stock method in calculating dilutive earnings per unit. Thus, the unvested restricted common units are included in the computation of the diluted weighted average common unit outstanding calculation, but the denominator in the computation of diluted earnings per common unit only includes the basic weighted average common units outstanding and weighted average warrants outstanding.

The following table presents the Partnership's basic income per unit for the year ended December 31, 2013:
 
 
Total
 
Common Units
 
Restricted Common Units
 
 
($ in thousands, except for per unit amounts)
Loss from continuing operations
 
$
(228,171
)
 
 
 
 
Distributions
 
117,294

 
$
115,351

 
$
1,943

Assumed loss from continuing operations after distribution to be allocated
 
(345,465
)
 
(345,465
)
 
—

Assumed allocation of loss from continuing operations
 
(228,171
)
 
(230,114
)
 
1,943

Discontinued operations, net of tax
 
(49,808
)
 
(49,808
)
 
—

Assumed net loss to be allocated
 
$
(277,979
)
 
$
(279,922
)
 
$
1,943

 
 
 
 
 
 
 
Basic loss from continuing operations per unit
 
 
 
$
(1.50
)
 
 
Basic discontinued operations per unit
 
 
 
$
(0.32
)
 
 
Basic and diluted loss per unit
 
 
 
$
(1.82
)
 
 
 
 
 
 
 
 
 
Diluted loss from continuing operations per unit
 
 
 
$
(1.50
)
 
 
Diluted discontinued operations per unit
 
 
 
$
(0.32
)
 
 
Diluted income per unit
 
 
 
$
(1.82
)
 
 


F- 34

The following table presents the Partnership's basic and diluted income per unit for the year ended December 31, 2012:
 
 
Total
 
Common Units
 
Restricted Common Units
 
 
($ in thousands, except for per unit amounts)
Loss from continuing operations
 
$
(32,146
)
 
 
 
 
Distributions
 
124,235

 
$
121,504

 
$
2,731

Assumed loss from continuing operations after distribution to be allocated
 
(156,381
)
 
(156,381
)
 
—

Assumed allocation of loss from continuing operations
 
(32,146
)
 
(34,877
)
 
2,731

Discontinued operations, net of tax
 
(118,456
)
 
(118,456
)
 
—

Assumed net loss to be allocated
 
$
(150,602
)
 
$
(153,333
)
 
$
2,731

 
 
 
 
 
 
 
Basic loss from continuing operations per unit
 
 
 
$
(0.26
)
 
 
Basic discontinued operations per unit
 
 
 
$
(0.87
)
 
 
Basic net loss per unit
 
 
 
$
(1.13
)
 
 
 
 
 
 
 
 
 
Diluted loss from continuing operations per unit
 
 
 
$
(0.26
)
 
 
Diluted discontinued operations per unit
 
 
 
$
(0.87
)
 
 
Diluted net loss per unit
 
 
 
$
(1.13
)
 
 
    

The following table presents the Partnership's basic and diluted income per unit for the year ended December 31, 2011:
 
 
Total
 
Common Units
 
Restricted Common Units
 
 
($ in thousands, except for per unit amounts)
Income from continuing operations
 
$
53,649

 
 
 
 
Distributions
 
89,062

 
$
87,525

 
$
1,537

Assumed loss from continuing operations after distribution to be allocated
 
(35,413
)
 
(35,413
)
 
—

Assumed allocation of income from continuing operations
 
53,649

 
52,112

 
1,537

Discontinued operations, net of tax
 
19,483

 
19,483

 
—

Assumed net income to be allocated
 
$
73,132

 
$
71,595

 
$
1,537

 
 
 
 
 
 
 
Basic income from continuing operations per unit
 
 
 
$
0.47

 
 
Basic discontinued operations per unit
 
 
 
$
0.18

 
 
Basic net income per unit
 
 
 
$
0.65

 
 
 
 
 
 
 
 
 
Diluted income from continuing operations per unit
 
 
 
$
0.45

 
 
Diluted discontinued operations per unit
 
 
 
$
0.17

 
 
Diluted net income per unit
 
 
 
$
0.62

 
 


F- 35

NOTE 18.   DIVESTITURE RELATED ACTIVITIES

As discussed in Note 1, on July 1, 2014, the Partnership completed the contribution of its Midstream Business to Regency. As a result of this transaction, the assets and liabilities of the Partnership's Midstream Business have been classified as held for sale and the operations as discontinued(See Note 1).

On December 20, 2012, the Partnership sold its Barnett Shale properties (which was accounted for in its Upstream Business). The Partnership received net proceeds of $14.8 million, which resulted in a loss on the sale of $4.5 million. The loss is included within impairment expense in the audited consolidated statement of operations. In addition, as this transaction did not meet the criteria for discontinued operations, the operations related to these assets are not included in the discontinued operations table below.

On May 20, 2011, the Partnership sold its Wildhorse Gathering System, which was part of its Midstream Business. The Partnership received net proceeds of $5.7 million.

On May 24, 2010, the Partnership completed the sale of its Minerals Business. During the year ended December 31, 2011, the Partnership received payments related to pre-effective date operations and recorded this amount as part of discontinued operations for the period.
  

The following is the reconciliation of the major classes of assets and liabilities classified as held for sale.
 
December 31,
2013
 
December 31,
2012
 
($ in thousands)
Assets held-for-sale
 
 
 
Accounts Receivable
$
128,713

 
$
107,423

Property, plant and equipment
1,004,317

 
985,422

Intangible assets
102,352

 
108,051

Other current assets
5,663

 
19,495

Other long-term assets
18,337

 
23,211

Total assets held-for-sale
$
1,259,382

 
$
1,243,602

 
 
 
 
Liabilities held-for-sale
 
 
 
Long-term debt
$
494,582

 
$
493,986

Accounts payable and accrued liabilities
119,966

 
98,630

Other current liabilities
9,471

 
3,762

Other long-term liabilities
13,719

 
12,721

Total liabilities held-for-sale
$
637,738

 
$
609,099



F- 36

The following table represents the reconciliation of major classes of line items classified as discontinued operations for the years ended December 31, 2013, 2012 and 2011:
 
 
Midstream Business
 
Wildhorse System
 
Minerals Business
 
 
($ in thousands)
Year Ended December 31, 2013:
 
 
 
 
 
 
Class of statement of operations line item of discontinued operations:
 
 
 
 
 
 
Revenues
 
$
997,907

 
$
—

 
$
—

Cost of natural gas, natural gas liquids, condensate and helium
 
790,618

 
—

 
—

Operations, maintenance and taxes other than income
 
101,121

 
—

 
—

General and administrative
 
28,083

 
—

 
—

Depreciation, amortization and impairment
 
77,726

 
—

 
—

Interest expense
 
(49,973
)
 
—

 
—

Other income
 
287

 
—

 
—

Loss from discontinued operations before taxes
 
(49,327
)
 
—

 
—

Income tax expense
 
481

 
—

 
—

Discontinued operations, net of tax
 
$
(49,808
)
 
$
—

 
$
—

Year Ended December 31, 2012:
 
 
 
 
 
 
Class of statement of operations line item of discontinued operations:
 
 
 
 
 
 
Revenues
 
$
752,644

 
$
—

 
$
—

Cost of natural gas, natural gas liquids, condensate and helium
 
532,719

 
—

 
—

Operations, maintenance and taxes other than income
 
82,526

 
—

 
—

General and administrative
 
19,004

 
—

 
—

Depreciation, amortization and impairment
 
202,249

 
—

 
—

Interest expense
 
(35,202
)
 
—

 
—

Other expense
 
(10
)
 
—

 
—

Loss from discontinued operations before taxes
 
(119,066
)
 
—

 
—

Income tax expense (benefit)
 
(610
)
 
—

 
—

Discontinued operations, net of tax
 
$
(118,456
)
 
$
—

 
$
—

Year Ended December 31, 2011:
 
 
 
 
 
 
Class of statement of operations line item of discontinued operations:
 
 
 
 
 
 
Revenues (a)
 
$
818,329

 
$
6,859

 
$
456

Cost of natural gas, natural gas liquids, condensate and helium
 
633,184

 
5,474

 
—

Operations, maintenance and taxes other than income
 
64,473

 
772

 
—

General and administrative
 
12,473

 
—

 
—

Depreciation, amortization and impairment
 
69,262

 
65

 
—

Interest expense
 
(18,777
)
 
—

 
—

Other expense
 
(35
)
 
—

 
—

Income from discontinued operations before taxes
 
20,125

 
548

 
456

Loss from the sale
 
—

 
(718
)
 
—

Income tax expense (benefit)
 
918

 
10

 
—

Discontinued operations, net of tax
 
$
19,207

 
$
(180
)
 
$
456

_____________________________
(a)
During the year ended December 31, 2011, the Partnership received payments related to pre-effective date operations from its Minerals Business and recorded this amount as part of discontinued operations for the period.

Allocation of interest expense

Per accounting guidance provided by the FASB related to discontinued operations, interest on debt that is to be assumed by the buyer and interest on debt that is required to be repaid as a result of a disposal transaction should be allocated

F- 37

to discontinued operations. Per the Partnership's Credit Agreement, as a result of the contribution of the Midstream Business, the Partnership is required to pay down outstanding debt to the amount of the upstream portion of the borrowing base. Thus, interest expense in the table above includes the the interest expense related to the portion of the Partnership's unsecured Senior Notes exchanged for Regency unsecured senior notes on July 1, 2014 (see Note 1) and interest related to the difference between the total amount outstanding under the Credit Agreement and the upstream portion of the borrowing base.


NOTE 19. SUBSIDIARY GUARANTORS
 
The Partnership has issued registered debt securities guaranteed by its subsidiaries.  As of December 31, 2013, all guarantors were wholly-owned or available to be pledged and such guarantees were joint and several and full and unconditional.  Although the guarantees of our subsidiary guarantors are considered full and unconditional, the guarantees are subject to certain customary release provisions. Such guarantees will be released in the following circumstances:

•
in connection with any sale or other disposition of all or substantially all of the properties or assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of us;
•
in connection with any sale or other disposition of capital stock of that guarantor to a person that is not (either before or after giving effect to such transaction) an issuer or a restricted subsidiary of us, such that, the guarantor ceases to be a restricted subsidiary of us as a result of the sale or other disposition;
•
if we designate any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the applicable provisions of the indenture;
•
upon legal defeasance or satisfaction and discharge of the indenture;
•
upon the liquidation or dissolution of such guarantor provided no default or event of default has occurred that is continuing;
•
at such time as such guarantor ceases to guarantee any other indebtedness of either of the issuers or any guarantor; or
•
upon such guarantor consolidating with, merging into or transferring all of its properties or assets to us or another guarantor, and as a result of, or in connection with, such transaction such guarantor dissolving or otherwise ceasing to exist.

In accordance with Rule 3-10 of Regulation S-X, the Partnership has prepared Condensed Consolidating Financial Statements as supplemental information.  The following condensed consolidating balance sheets at December 31, 2013 and December 31, 2012, condensed consolidating statements of operations for the years ended December 31, 2013, 2012 and 2011, and condensed consolidating statements of cash flows for the years ended December 31, 2013, 2012 and 2011, present financial information for Eagle Rock Energy as the Parent on a stand-alone basis (carrying any investments in subsidiaries under the equity method), financial information for the co-issuer and the subsidiary guarantors, which are all 100% owned by the Parent, on a stand-alone basis, and the consolidation and elimination entries necessary to arrive at the information for the Partnership on a consolidated basis.  The subsidiary guarantors are not restricted from making distributions to the Partnership. Pursuant to the Contribution of the Midstream Business, all of the Partnership's Midstream Subsidiaries were contributed to Regency on July 1, 2014 and released from their guarantees under the indenture and Credit Agreement.


F- 38

 Condensed Consolidating Balance Sheet
December 31, 2013
 
Parent Issuer
 
Co-Issuer
 
Subsidiary Guarantors
 
Non-guarantor investments
 
Consolidating
Entries
 
Total
 
($ in thousands)
ASSETS:
 
 
 
 
 
 
 
 
 
 
 
Accounts receivable – related parties
$
691,588

 
$
—

 
$
—

 
$
—

 
$
(691,588
)
 
$
—

Assets held for sale
8,762

 
—

 
1,250,620

 
—

 
—

 
$
1,259,382

Other current assets
6,927

 
1

 
22,080

 
—

 
—

 
29,008

Total property, plant and equipment, net
2,318

 
—

 
822,133

 
—

 
—

 
824,451

Investment in subsidiaries
1,133,217

 
—

 
—

 
908

 
(1,134,125
)
 
—

Total other long-term assets
10,012

 
—

 
4,697

 
—

 
—

 
14,709

Total assets
$
1,852,824

 
$
1

 
$
2,099,530

 
$
908

 
$
(1,825,713
)
 
$
2,127,550

LIABILITIES AND EQUITY:
 
 
 
 
 
 
 
 
 
 
 
Accounts payable – related parties
$
—

 
$
—

 
$
691,588

 
$
—

 
$
(691,588
)
 
$
—

Liabilities held for sale
500,291

 
—

 
137,447

 
—

 
—

 
$
637,738

Other current liabilities
15,688

 
—

 
66,141

 
—

 
—

 
81,829

Other long-term liabilities
5,486

 
—

 
71,138

 
—

 
—

 
76,624

Long-term debt
757,480

 
—

 
—

 
—

 
—

 
757,480

Equity
573,879

 
1

 
1,133,216

 
908

 
(1,134,125
)
 
573,879

Total liabilities and equity
$
1,852,824

 
$
1

 
$
2,099,530

 
$
908

 
$
(1,825,713
)
 
$
2,127,550


Condensed Consolidating Balance Sheet
December 31, 2012
 
Parent Issuer
 
Co-Issuer
 
Subsidiary
Guarantors
 
Non-guarantor investments
 
Consolidating Entries
 
Total
 
($ in thousands)
ASSETS:
 
 
 
 
 
 
 
 
 
 
 
Accounts receivable – related parties
$
660,898

 
$
—

 
$
—

 
$
—

 
$
(660,898
)
 
$
—

Assets held for sale
23,176

 
—

 
1,220,426

 
—

 
—

 
1,243,602

Other current assets
18,896

 
1

 
36,149

 
—

 
—

 
55,046

Total property, plant and equipment, net
2,657

 
—

 
980,127

 
—

 
—

 
982,784

Investment in subsidiaries
1,324,293

 
—

 
—

 
958

 
(1,325,251
)
 
—

Total other long-term assets
7,677

 
—

 
5,107

 
—

 
—

 
12,784

Total assets
$
2,037,597

 
$
1

 
$
2,241,809

 
$
958

 
$
(1,986,149
)
 
$
2,294,216

LIABILITIES AND EQUITY:
 
 
 
 
 
 
 
 
 
 
 
Accounts payable – related parties
$
—

 
$
—

 
$
660,898

 
$
—

 
$
(660,898
)
 
$
—

Liabilities held for sale
497,424

 
—

 
111,675

 
—

 
—

 
609,099

Other current liabilities
6,704

 
—

 
72,418

 
—

 
—

 
79,122

Other long-term liabilities
5,978

 
—

 
72,526

 
—

 
—

 
78,504

Long-term debt
659,117

 
—

 
—

 
—

 
—

 
659,117

Equity
868,374

 
1

 
1,324,292

 
958

 
(1,325,251
)
 
868,374

Total liabilities and equity
$
2,037,597

 
$
1

 
$
2,241,809

 
$
958

 
$
(1,986,149
)
 
$
2,294,216



F- 39

Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2013
 
Parent Issuer
 
Co-Issuer
 
Subsidiary Guarantors
 
Non-guarantor investments
 
Consolidating
Entries
 
Total
 
($ in thousands)
Total revenues
$
(3,937
)
 
$
—

 
$
201,309

 
$
—

 
$
—

 
$
197,372

Operations and maintenance
—

 
—

 
41,426

 
—

 
—

 
41,426

Taxes other than income
—

 
—

 
12,928

 
—

 
—

 
12,928

General and administrative
13,145

 
—

 
39,986

 
—

 
—

 
53,131

Depreciation, depletion and amortization
454

 
—

 
88,990

 
—

 
—

 
89,444

Impairment and other
—

 
—

 
214,286

 
—

 
—

 
214,286

Loss from operations
(17,536
)
 
—

 
(196,307
)
 
—

 
—

 
(213,843
)
Interest expense, net
(17,891
)
 
—

 
(898
)
 
—

 
—

 
(18,789
)
Other non-operating income
9,025

 
—

 
9,298

 
—

 
(18,323
)
 
—

Other non-operating expense
(6,904
)
 
—

 
(12,553
)
 
—

 
18,323

 
(1,134
)
Loss before income taxes
(33,306
)
 
—

 
(200,460
)
 
—

 
—

 
(233,766
)
Income tax benefit
(1,653
)
 
—

 
(3,942
)
 
—

 
—

 
(5,595
)
Equity in earnings of subsidiaries
(191,071
)
 
—

 
—

 
—

 
191,071

 
—

Income (loss) from continuing operations
(222,724
)
 
—

 
(196,518
)
 
—

 
191,071

 
(228,171
)
Discontinued operations, net of tax
(55,255
)
 
—

 
5,457

 
(10
)
 
—

 
(49,808
)
Net loss
$
(277,979
)
 
$
—

 
$
(191,061
)
 
$
(10
)
 
$
191,071

 
$
(277,979
)

Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2012
 
Parent Issuer
 
Co-Issuer
 
Subsidiary Guarantors
 
Non-guarantor investments
 
Consolidating Entries
 
Total
 
($ in thousands)
Total revenues
$
28,110

 
$
—

 
$
203,205

 
$
—

 
$
—

 
$
231,315

Operations and maintenance
—

 
—

 
41,391

 
—

 
—

 
41,391

Taxes other than income
—

 
—

 
15,343

 
—

 
—

 
15,343

General and administrative
8,745

 
—

 
42,245

 
—

 
—

 
50,990

Depreciation, depletion and amortization
296

 
—

 
90,214

 
—

 
—

 
90,510

Impairment
—

 
—

 
45,289

 
—

 
—

 
45,289

Income (loss) from operations
19,069

 
—

 
(31,277
)
 
—

 
—

 
(12,208
)
Interest expense, net
(16,299
)
 
—

 
23

 
—

 
—

 
(16,276
)
Other non-operating income
9,039

 
—

 
10,961

 
—

 
(20,000
)
 
—

Other non-operating expense
(12,189
)
 
—

 
(12,566
)
 
—

 
20,000

 
(4,755
)
Loss before income taxes
(380
)
 
—

 
(32,859
)
 
—

 
—

 
(33,239
)
Income tax provision (benefit)
1,041

 
—

 
(2,134
)
 
—

 
—

 
(1,093
)
Equity in earnings of subsidiaries
(113,200
)
 
—

 
—

 
—

 
113,200

 
—

(Loss) income from continuing operations
(114,621
)
 
—

 
(30,725
)
 
—

 
113,200

 
(32,146
)
Discontinued operations, net of tax
(35,981
)
 
—

 
(82,457
)
 
(18
)
 
—

 
(118,456
)
Net loss
$
(150,602
)
 
$
—

 
$
(113,182
)
 
$
(18
)
 
$
113,200

 
$
(150,602
)


F- 40

Condensed Consolidating Statement of Operations
For the Year Ended December 31, 2011
 
Parent Issuer
 
Co-Issuer
 
Subsidiary Guarantors
 
Non-guarantor investments
 
Consolidating
Entries
 
Total
 
($ in thousands)
Total revenues
$
37,269

 
$
—

 
$
204,310

 
$
—

 
$
—

 
$
241,579

Operations and maintenance
—

 
—

 
32,287

 
—

 
—

 
32,287

Taxes other than income
—

 
—

 
15,436

 
—

 
—

 
15,436

General and administrative
1,002

 
—

 
41,523

 
—

 
—

 
42,525

Depreciation, depletion and amortization
196

 
—

 
66,713

 
—

 
—

 
66,909

Impairment
—

 
—

 
11,728

 
—

 
—

 
11,728

Income from operations
36,071

 
—

 
36,623

 
—

 
—

 
72,694

Interest expense, net
(10,856
)
 
—

 
11

 
—

 
—

 
(10,845
)
Other non-operating income
8,798

 
—

 
5,588

 
—

 
(14,386
)
 
—

Other non-operating expense
(28,589
)
 
—

 
2,653

 
—

 
14,386

 
(11,550
)
Income (loss) before income taxes
5,424

 
—

 
44,875

 
—

 
—

 
50,299

Income tax provision (benefit)
(579
)
 
—

 
(2,771
)
 
—

 
—

 
(3,350
)
Equity in earnings of subsidiaries
92,295

 
—

 
—

 
—

 
(92,295
)
 
—

Income (loss) from continuing operations
98,298

 
—

 
47,646

 
—

 
(92,295
)
 
53,649

Discontinued operations, net of tax
(25,166
)
 
—

 
44,659

 
(10
)
 
—

 
19,483

Net income (loss)
$
73,132

 
$
—

 
$
92,305

 
$
(10
)
 
$
(92,295
)
 
$
73,132



F- 41

Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2013
 
Parent Issuer
 
Co-Issuer
 
Subsidiary Guarantors
 
Non-guarantor investments
 
Consolidating Entries
 
Total
 
($ in thousands)
Net cash flows (used in) provided by operating activities
$
(34,610
)
 
$
—

 
$
148,853

 
$
—

 
$
—

 
$
114,243

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
 
Additions to property, plant and equipment
(115
)
 
—

 
(149,829
)
 
—

 
—

 
(149,944
)
Proceeds from sale of asset
—

 
—

 
76

 
—

 
—

 
76

Net cash flows used in investing activities
(115
)
 
—

 
(149,753
)
 
—

 
—

 
(149,868
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
 
Proceeds from long-term debt
601,400

 
—

 
—

 
—

 
—

 
601,400

Repayment of long-term debt
(503,100
)
 
—

 
—

 
—

 
—

 
(503,100
)
Proceeds from derivative contracts
1,323

 
—

 
—

 
—

 
—

 
1,323

Common unit issued in equity offerings
102,388

 
—

 
—

 
—

 
—

 
102,388

Issuance costs for equity offerings
(4,519
)
 
—

 
—

 
—

 
—

 
(4,519
)
Repurchase of common units
(1,858
)
 
—

 
—

 
—

 
—

 
(1,858
)
Distributions to members and affiliates
(125,911
)
 
—

 
—

 
—

 
—

 
(125,911
)
Net cash flows provided by financing activities
69,723

 
—

 
—

 
—

 
—

 
69,723

Net cash flows used in discontinued operations
(35,431
)
 
—

 
1,343

 
41

 
—

 
(34,047
)
Net increase (decrease) in cash and cash equivalents
(433
)
 
—

 
443

 
41

 
—

 
51

Cash and cash equivalents at beginning of year
1,670

 
1

 
(1,832
)
 
186

 
—

 
25

Cash and cash equivalents at end of year
$
1,237

 
$
1

 
$
(1,389
)
 
$
227

 
$
—

 
$
76



F- 42

Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2012
 
Parent Issuer
 
Co-Issuer
 
Subsidiary Guarantors
 
Non-guarantor Investments
 
Consolidating Entries
 
Total
 
($ in thousands)
Net cash flows (used in) provided by operating activities
$
(108,061
)
 
$
—

 
$
183,397

 
$
—

 
$
—

 
$
75,336

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
 
Additions to property, plant and equipment
(1,551
)
 
—

 
(166,356
)
 
—

 
—

 
(167,907
)
Proceeds from sale of asset
—

 
—

 
15,398

 
—

 
—

 
15,398

Contributions to subsidiaries
(236,971
)
 
—

 
—

 
—

 
236,971

 
—

Net cash flows used in investing activities
(238,522
)
 
—

 
(150,958
)
 
—

 
236,971

 
(152,509
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
 
Proceeds from long-term debt
1,043,750

 
—

 
—

 
—

 
—

 
1,043,750

Repayment of long-term debt
(916,750
)
 
—

 
—

 
—

 
—

 
(916,750
)
Proceed from senior notes
22,889

 
—

 
—

 
—

 
—

 
22,889

Payments of debt issuance cost
(614
)
 
—

 
—

 
—

 
—

 
(614
)
Proceeds from derivatives contracts
14,449

 
—

 
—

 
—

 
—

 
14,449

Common unit issued in equity offerings
96,173

 
—

 
—

 
—

 
—

 
96,173

Issuance costs for equity offerings
(4,518
)
 
—

 
—

 
—

 
—

 
(4,518
)
Exercise of warrants
31,804

 
—

 
—

 
—

 
—

 
31,804

Repurchase of common units
(2,501
)
 
—

 
—

 
—

 
—

 
(2,501
)
Distributions to members and affiliates
(119,211
)
 
—

 
—

 
—

 
—

 
(119,211
)
Net cash flows provided by financing activities
165,471

 
—

 
—

 
—

 
—

 
165,471

Net cash flows provided by (used in) discontinued operations
181,463

 
—

 
(33,699
)
 
57

 
(236,971
)
 
(89,150
)
Net (decrease) increase in cash and cash equivalents
351

 
—

 
(1,260
)
 
57

 
—

 
(852
)
Cash and cash equivalents at beginning of year
1,319

 
1

 
(572
)
 
129

 
—

 
877

Cash and cash equivalents at end of year
$
1,670

 
$
1

 
$
(1,832
)
 
$
186

 
$
—

 
$
25



F- 43

Condensed Consolidating Statement of Cash Flows
For the Year Ended December 31, 2011
 
Parent Issuer
 
Co-Issuer
 
Subsidiary Guarantors
 
Non-guarantor Investments
 
Consolidating Entries
 
Total
 
($ in thousands)
Net cash flows provided by operating activities
$
9,318

 
$
—

 
$
51,101

 
$
—

 
$
—

 
$
60,419

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
 
Additions to property, plant and equipment
(389
)
 
—

 
(76,549
)
 
—

 
—

 
(76,938
)
Acquisitions, net of cash acquired
—

 
—

 
(220,326
)
 
—

 
—

 
(220,326
)
Contribution to subsidiaries
(227,583
)
 
—

 
—

 
—

 
227,583

 
—

Net cash flows used in investing activities
(227,972
)
 
—

 
(296,875
)
 
—

 
227,583

 
(297,264
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
 
Proceeds from long-term debt
964,279

 
—

 
—

 
—

 
—

 
964,279

Repayment of long-term debt
(1,012,779
)
 
—

 
—

 
—

 
—

 
(1,012,779
)
Proceed from senior notes
27,683

 
—

 
—

 
—

 
—

 
27,683

Payments of debt issuance cost
(9,116
)
 
—

 
—

 
—

 
—

 
(9,116
)
Proceeds from derivative contracts
6,267

 
—

 
—

 
—

 
—

 
6,267

Exercise of Warrants
89,745

 
—

 
—

 
—

 
—

 
89,745

Repurchase of common units
(1,401
)
 
—

 
—

 
—

 
—

 
(1,401
)
Distributions to members and affiliates
(74,512
)
 
—

 
—

 
—

 
—

 
(74,512
)
Contributions from parent
—

 
—

 
227,583

 
—

 
(227,583
)
 
—

Net cash flows provided by financing activities
(9,834
)
 
—

 
227,583

 
—

 
(227,583
)
 
(9,834
)
Net cash flows provided by discontinued operations
224,917

 
—

 
18,504

 
86

 
—

 
243,507

Net increase (decrease) in cash and cash equivalents
(3,571
)
 
—

 
313

 
86

 
—

 
(3,172
)
Cash and cash equivalents at beginning of year
4,890

 
1

 
(885
)
 
43

 
—

 
4,049

Cash and cash equivalents at end of year
$
1,319

 
$
1

 
$
(572
)
 
$
129

 
$
—

 
$
877


NOTE 20. SUBSEQUENT EVENTS

Amendments to Credit Agreement

In February 2014, the Partnership entered into an amended credit agreement with its lender group which allowed for greater liquidity under the senior secured credit facility and for greater covenant flexibility for the first quarter of 2014. Specifically, the amendment provides for: (i) an increase in the Total Leverage Ratio and Senior Secured Leverage Ratio (as defined in the Credit Agreement) to 5.85x and 3.40x, respectively, for the quarter ended March 31, 2014; (ii) the exclusion of fees and expenses associated with the strategic review and disposition of the Partnership’s Midstream Business from the calculation of Consolidated EBITDA (as defined in the Credit Agreement); (iii) deferring the redetermination of the Upstream Component of the Borrowing Base (both as defined in the Credit Agreement) until June 1, 2014; and (iv) the option for the Partnership, at its election, to expand the multiplier for the Midstream Component of the Borrowing Base from 3.75x to 4.00x.

On May 28, 2014 the Partnership and its lender group further amended the Credit Agreement to allow for greater liquidity and certain covenant relief through the second quarter of 2014. The amendment, among other items, provided for an increase in the midstream component of the Credit Agreement's total borrowing base and provided for an increase in the Total Leverage Ratio and Senior Secured Leverage Ratio (as defined in the Credit Agreement) for the quarter ended June 30, 2014. The amendment also provided that (i) effective June 1, 2014, the upstream component of the borrowing base of the Credit

F- 44

Agreement will decrease from $380 million to $330 million as part of the Partnership's regular semi-annual redetermination by its commercial lenders, (ii) the next borrowing base redetermination will be September 1, 2014, and (iii) that such reduction would automatically reduce aggregate commitments of the lenders under the Credit Agreement, with further automatic reductions in such aggregate commitments in amounts equal to, and upon, any future reductions in the borrowing base.
Contribution of the Midstream Business
On July 1, 2014, the Partnership closed the Midstream Business Contribution (see Note 1). In addition, in connection with the Midstream Business Contribution, Regency agreed to indemnify the Partnership for losses arising from the Midstream Business, including potential losses associated with these laws and regulations, and the Partnership agreed to use commercially reasonable efforts to mitigate such losses.
Amendment to Senior Note Indenture
Following the close of the Midstream Business Contribution, $51.1 million of the Partnership's Senior Notes remain outstanding; however, the Partnership amended the indenture governing such outstanding unsecured senior notes to eliminate substantially all of the restrictive covenants and certain events of default pertaining to its Senior Notes.


NOTE 21. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
 
Oil and Natural Gas Reserves
 
Users of this information should be aware that the process of estimating quantities of proved oil and natural gas reserves is very complex, and requires significant subjective decisions in the evaluation of the available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and changing operating and market conditions. As a result, revisions to reserve estimates may occur from time to time. Although reasonable effort is made to ensure the reported reserve estimates are accurate, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
 
There are numerous uncertainties inherent in estimating the quantities of proved reserves, the future rates of production and the timing of development expenditures. Reserves data represent estimates only and should not be construed as being exact. Moreover, the Standardized Measure of Oil and Gas (“SMOG”) should not be construed as the current market value of the proved oil and natural gas reserves or as the costs that would be incurred to obtain equivalent reserves. A market value determination would include many additional factors including (a) anticipated future changes in natural gas and crude oil prices, production and development costs, (b) an allowance for return on investment, (c) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities, and (d) other business risks.
 
Proved Reserves Summary
 
The following table illustrates the Partnership's estimated net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by Cawley, Gillespie and Associates. Oil and natural gas liquids prices applied for 2013 are based on an average of the prior twelve months first-of-month spot prices of West Texas Intermediate ($96.94 per barrel) and are adjusted for quality, transportation fees, and regional price differentials. Likewise, natural gas prices applied for 2013 are based on an average of the prior twelve months first-of-month spot prices of Henry Hub natural gas ($3.66 per MMBtu) and are adjusted for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines.  

As shown in the following reconciliation table, the Partnership recognized significant negative revisions to its estimates of proved natural gas reserves in 2013. These negative revisions were due in large part to the Partnership's decision to remove a number of undeveloped locations from its Five Year Development Plan. These undeveloped locations were expected to generate lower-than-acceptable economic performance given our current outlook for commodity prices, and/or were undeveloped locations on non-operated acreage for which we lacked reasonable certainty of development. These undeveloped locations were recategorized as probable reserves. We also recategorized some undeveloped locations as contingent resources because our revised production and cost forecasts indicated these locations were non-commercial under SEC guidelines at the time of determination.



F- 45


 
Proved Reserves
 
Oil
(MBbls)
 
Gas
(MMcf)
 
Natural Gas
Liquids (MBbls)
Proved reserves, January 1, 2011
8,696

 
38,382

 
6,176

Extensions and discoveries
215

 
14,523

 
903

Purchase of minerals in place
3,830

 
198,826

 
4,815

Production
(1,118
)
 
(12,636
)
 
(805
)
Revision of previous estimates
(101
)
 
(5,073
)
 
258

Proved reserves, December 31, 2011
11,522

 
234,022

 
11,347

Extensions and discoveries
1,405

 
31,524

 
2,136

Purchase of minerals in place
104

 
128

 
18

Production
(1,184
)
 
(16,443
)
 
(1,121
)
Sales of mineral in place
—

 
(13,331
)
 
—

Revision of previous estimates
1,137

 
(41,471
)
 
486

Proved reserves, December 31, 2012
12,984

 
194,429

 
12,866

Extensions and discoveries
2,712

 
29,137

 
3,180

Production
(1,222
)
 
(12,804
)
 
(1,156
)
Revision of previous estimates
(932
)
 
(33,536
)
 
(253
)
Proved reserves, December 31, 2013
13,542

 
177,226

 
14,637

 
 
 
 
 
 
Proved Developed Reserves
 
 
 
 
 
Proved developed reserves, January 1, 2011
8,299

 
29,686

 
5,758

Proved developed reserves, December 31, 2011
10,271

 
165,269

 
9,307

Proved developed reserves, December 31, 2012
10,993

 
136,545

 
10,445

Proved developed reserves, December 31, 2013
10,153

 
126,950

 
10,766

 
 
 
 
 
 
Proved Undeveloped Reserves
 
 
 
 
 
Proved undeveloped reserves, January 1, 2011
397

 
8,696

 
418

Proved undeveloped reserves, December 31, 2011
1,251

 
68,753

 
2,040

Proved undeveloped reserves, December 31, 2012
1,991

 
57,884

 
2,421

Proved undeveloped reserves, December 31, 2013
3,389

 
50,276

 
3,871

 
The primary drivers behind the changes to our proved reserves for the years ended December 31, 2011, 2012 and 2013 are described in more detail below.

2011:

•
purchases of minerals in place were significant in 2011 and were almost entirely related to the Crow Creek Acquisition;

•
extensions and discoveries were related to drilling by us and other operators on our Crow Creek assets, primarily in the Cana Play and Golden Trend area in Oklahoma; and

•
revisions to previous estimates were relatively small and were primarily due to reductions caused by changes in condensate and NGL yields at our Big Escambia Creek field, and well performance at our Ward Estes and Ginger fields, partially offset by higher prices which extended the economic life and reserves of some wells.

2012:

•
Purchase of minerals in place were insignificant in 2012;


F- 46

•
extensions and discoveries were primarily related to drilling by us and other operators in the Golden Trend area and the nearby SCOOP Play in Oklahoma;

•
sales of minerals in place were related to the sale of our Barnett Shale assets in December 2012; and

•
revisions to previous estimates were primarily the result of lower natural gas prices which reduced the economic life and reserves of many wells.

2013:

•
Purchases and sales of minerals in place did not occur in 2013;

•
extensions and discoveries were primarily related to drilling by us and other operators in the Golden Trend area and the nearby SCOOP Play in Oklahoma; and

•
revisions to previous estimates were primarily the result of updating our Five Year Development Plan to recategorize as probable reserves those undeveloped wells that we are not reasonably certain of drilling in five years due to their expected economic performance, or because they are operated by others and we do have assurance from the operators of their intent to develop them; and because we recategorized other proved undeveloped reserves as contingent resources due to revised performance expectations and other factors. All of these revisions were primarily in the Mid-Continent Region.

Capitalized Costs Relating to Oil and Natural Gas Producing Activities
 
The following table illustrates the total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization at December 31, 2013, 2012 and 2011:
 
 
As of
December 31, 2013
 
As of
December 31, 2012
 
As of
December 31, 2011
($ in thousands)
 
 
 
 
 
Proved properties
$
1,156,895

 
$
1,213,622

 
$
1,050,872

Unproved properties—excluded from depletion
10,022

 
31,823

 
91,363

Gross oil and gas properties
1,166,917

 
1,245,445

 
1,142,235

Accumulated depreciation, depletion, amortization
(353,679
)
 
(269,376
)
 
(190,833
)
Net oil and gas properties
$
813,238

 
$
976,069

 
$
951,402

 
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
 
Costs incurred in property acquisition, exploration and development activities were as follows for the years ended December 31, 2013, 2012 and 2011:
 
 
Year Ended December 31,
 
2013
 
2012
 
2011
($ in thousands)
 
 
 
 
 
Property acquisition costs, proved
$
—

 
$
2,582

 
$
465,088

Property acquisition costs, unproved
—

 
—

 
103,337

Development costs
124,032

 
135,692

 
90,418

Total costs
$
124,032

 
$
138,274

 
$
658,843

 
    
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following information has been developed utilizing authoritative guidance procedures and is based on oil and natural gas reserves estimated by the Partnership's independent reserves engineer. It can be used for some comparisons, but should not be

F- 47

the only method used to evaluate the Partnership or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flow be viewed as representative of the current value of the Partnership.
 
The Partnership believes that the following factors should be taken into account when reviewing the following information:
 
•
future costs and selling prices will probably differ from those required to be used in these calculations;
 
•
due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations; and
 
•
a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues.
 
Under the Standardized Measure, future cash inflows were estimated by applying year-end oil and natural gas prices to the estimated future production of year-end proved reserves. Estimates of future income taxes were computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows were reduced to present value amounts by applying a 10% discount factor.
 
The Partnership's hydrocarbon reserves in Alabama and East Texas contain hydrogen sulfide that must be removed from the natural gas stream before the hydrocarbons are sold. As part of the process to remove the hydrogen sulfide, the Partnership produces and sells elemental sulfur. The Partnership generated revenue from the sale of sulfur of $8.1 million, $14.0 million and $17.8 million in 2013, 2012 and 2011, respectively. The cost of removing the sulfur is included in the future production costs in the Standardized Measure table below. In prior years, the Partnership included the expected revenues from the sale of sulfur as part of the Standardized Measure computation. The Partnership changed that practice in 2013 and now includes only the sale of hydrocarbons in the computation. The Standardized Measure presented as of December 31, 2012 and 2011 in the following table has been adjusted to reflect this change in methodology. No reserve volumes have been booked for sulfur, and the impact of sulfur revenues on the economic limit of reserves in prior years is considered immaterial.
  
The Standardized Measure is as follows as of December 31, 2013, 2012 and 2011:
 
As of
December 31, 2013
 
As of
December 31, 2012
 
As of
December 31, 2011
 
 
 
(As Adjusted)
 
(As Adjusted)
($ in thousands)
 
 
 
 
 
Future cash inflows
$
2,423,350

 
$
2,279,735

 
$
2,516,812

Future production costs
(737,468
)
 
(767,004
)
 
(845,530
)
Future development costs
(318,778
)
 
(354,690
)
 
(315,019
)
Future net cash flows before income taxes
1,367,104

 
1,158,041

 
1,356,263

Future income tax (expense) benefit
(1,212
)
 
(1,086
)
 
(1,831
)
Future net cash flows before 10% discount
1,365,892

 
1,156,955

 
1,354,432

10% annual discount for estimated timing of cash flows
(715,386
)
 
(621,826
)
 
(711,846
)
Total standardized measure of discounted future net cash flows
$
650,506

 
$
535,129

 
$
642,586


The tables below present the Partnership’s previously-disclosed SMOG values, the revised values (which exclude sulfur revenues), and the differences between them for years ending December 31, 2012 and 2011.  The differences between the two sets of values are most pronounced in the future cash inflows and future production costs.  The change in future cash inflows is due to a shortening of the economic life of certain properties when sulfur revenues are excluded. The change in future production costs is the result of the exclusion of sulfur revenues, which were historically shown as an offset to the cost to transport and market the sulfur.  In some prior years, the cost to transport and market the sulfur exceeded the total sulfur revenues, resulting in a net cost. In other prior years, sulfur revenues exceeded the cost to transport and market the sulfur, resulting in net positive cash flows. In order to maintain consistency across periods and to show only hydrocarbon revenues as future cash inflows, the Partnership reported the net impact from the sale of sulfur in all periods within future production costs.

The following summarizes the revisions to the Standardized Measure for fiscal years 2012 and 2011:

F- 48

 
As of
December 31, 2012
 
As Reported
 
Revisions
 
As Adjusted
($ in thousands)
 
 
 
 
 
Future cash inflows
$
2,315,266

 
$
(35,531
)
 
$
2,279,735

Future production costs
(669,896
)
 
(97,108
)
 
(767,004
)
Future development costs
(359,154
)
 
4,464

 
(354,690
)
Future net cash flows before income taxes
1,286,216

 
(128,175
)
 
1,158,041

Future income tax (expense) benefit
(1,321
)
 
235

 
(1,086
)
Future net cash flows before 10% discount
1,284,895

 
(127,940
)
 
1,156,955

10% annual discount for estimated timing of cash flows
(680,855
)
 
59,029

 
(621,826
)
Total standardized measure of discounted future net cash flows
$
604,040

 
$
(68,911
)
 
$
535,129


 
As of
December 31, 2011
 
As Reported
 
Revisions
 
As Adjusted
($ in thousands)
 
 
 
 
 
Future cash inflows
$
2,562,650

 
$
(45,838
)
 
$
2,516,812

Future production costs
(742,749
)
 
(102,781
)
 
(845,530
)
Future development costs
(317,405
)
 
2,386

 
(315,019
)
Future net cash flows before income taxes
1,502,496

 
(146,233
)
 
1,356,263

Future income tax (expense) benefit
(2,379
)
 
548

 
(1,831
)
Future net cash flows before 10% discount
1,500,117

 
(145,685
)
 
1,354,432

10% annual discount for estimated timing of cash flows
(778,520
)
 
66,674

 
(711,846
)
Total standardized measure of discounted future net cash flows
$
721,597

 
$
(79,011
)
 
$
642,586



F- 49

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
 
The following is a summary of the changes in the Standardized Measure of discounted future net cash flows for the Partnership's proved oil and natural gas reserves for the years ended December 31, 2013, 2012 and 2011:
 
 
Year Ended December 31,
 
2013
 
2012
 
2011
 
 
 
(As Adjusted)
 
(As Adjusted)
($ in thousands)
 
 
 
 
 
Beginning of year
$
535,129

 
$
642,586

 
$
284,687

Sale of oil and gas produced, net of production costs
(150,457
)
 
(132,451
)
 
(138,860
)
Net changes in prices and production costs
2,720

 
(78,247
)
 
143,023

Extensions, discoveries and improved recovery, less related costs
136,464

 
66,460

 
40,832

Previously estimated development costs incurred during the period
21,470

 
53,111

 
90,418

Net changes in future development costs
107,951

 
36,914

 
(119,121
)
Revisions of previous quantity estimates
(103,351
)
 
(76,434
)
 
(34,497
)
Purchases of property
—

 
2,811

 
324,652

Sales of property
—

 
(5,063
)
 
—

Accretion of discount
49,233

 
60,734

 
26,225

Net changes in income taxes
(36
)
 
317

 
(519
)
Other
51,383

 
(35,609
)
 
25,746

End of year
$
650,506

 
$
535,129

 
$
642,586


The following summarizes the revisions to the changes in the Standardized Measure for fiscal years 2012 and 2011.
 
Year Ended December 31, 2012
 
As Reported
 
Revisions
 
As Adjusted
($ in thousands)
 
 
 
 
 
Beginning of year
$
721,597

 
$
(79,011
)
 
$
642,586

Sale of oil and gas produced, net of production costs
(132,451
)
 
—

 
(132,451
)
Net changes in prices and production costs
(76,759
)
 
(1,488
)
 
(78,247
)
Extensions, discoveries and improved recovery, less related costs
66,460

 
—

 
66,460

Previously estimated development costs incurred during the period
53,111

 
—

 
53,111

Net changes in future development costs
36,503

 
411

 
36,914

Revisions of previous quantity estimates
(85,176
)
 
8,742

 
(76,434
)
Purchases of property
2,811

 
—

 
2,811

Sales of property
(5,063
)
 
—

 
(5,063
)
Accretion of discount
67,956

 
(7,222
)
 
60,734

Net changes in income taxes
564

 
(247
)
 
317

Other
(45,513
)
 
9,904

 
(35,609
)
End of year
$
604,040

 
$
(68,911
)
 
$
535,129


F- 50

 
Year Ended December 31, 2011
 
As Reported
 
Revisions
 
As Adjusted
($ in thousands)
 
 
 
 
 
Beginning of year
$
333,993

 
$
(49,306
)
 
$
284,687

Sale of oil and gas produced, net of production costs
(138,860
)
 
—

 
(138,860
)
Net changes in prices and production costs
170,917

 
(27,894
)
 
143,023

Extensions, discoveries and improved recovery, less related costs
40,832

 
—

 
40,832

Previously estimated development costs incurred during the period
90,418

 
—

 
90,418

Net changes in future development costs
(117,783
)
 
(1,338
)
 
(119,121
)
Revisions of previous quantity estimates
(26,447
)
 
(8,050
)
 
(34,497
)
Purchases of property
324,652

 
—

 
324,652

Accretion of discount
30,728

 
(4,503
)
 
26,225

Net changes in income taxes
(621
)
 
102

 
(519
)
Other
13,768

 
11,978

 
25,746

End of year
$
721,597

 
$
(79,011
)
 
$
642,586

 

Results of Operations
 
The following are the results of operations for the Partnership's oil and natural gas producing activities for the years ended December 31, 2013, 2012 and 2011:
 
 
Year Ended December 31,
 
 
2013
 
2012
 
2011
($ in thousands)
 
 
 
 
 
 
Revenues:
 
 
 
 
 
 
Sales to third parties
 
$
146,210

 
$
135,842

 
$
138,383

Intercompany sales
 
47,048

 
53,343

 
48,203

Total revenues
 
193,258

 
189,185

 
186,586

Costs and expenses:
 
 
 
 
 
 
Production costs
 
54,354

 
56,734

 
47,726

General and administrative
 
11,419

 
12,162

 
11,124

Depreciation, depletion, and amortization
 
87,456

 
88,777

 
65,531

Impairment and other
 
214,286

 
45,289

 
11,728

Total costs and expenses
 
367,515

 
202,962

 
136,109

Total result of operations
 
$
(174,257
)
 
$
(13,777
)
 
$
50,477

 
* * * *


F- 51
(MM) (NASDAQ:EROC)
Historical Stock Chart
From Jun 2024 to Jul 2024 Click Here for more (MM) Charts.
(MM) (NASDAQ:EROC)
Historical Stock Chart
From Jul 2023 to Jul 2024 Click Here for more (MM) Charts.